<PAGE>   1
                                                                      EXHIBIT 99


          CONSOLIDATED
   CNG    NATURAL GAS
          COMPANY


          CONSOLIDATED
   CNG    NATURAL GAS
          COMPANY


          CONSOLIDATED
   CNG    NATURAL GAS
          COMPANY


          CONSOLIDATED
   CNG    NATURAL GAS
          COMPANY


          CONSOLIDATED
   CNG    NATURAL GAS
          COMPANY


          CONSOLIDATED             1997 Financial
   CNG    NATURAL GAS                   Report
          COMPANY


          CONSOLIDATED
   CNG    NATURAL GAS
          COMPANY


          CONSOLIDATED
   CNG    NATURAL GAS
          COMPANY


          CONSOLIDATED
   CNG    NATURAL GAS
          COMPANY


          CONSOLIDATED
   CNG    NATURAL GAS
          COMPANY


          CONSOLIDATED
   CNG    NATURAL GAS
          COMPANY


          CONSOLIDATED
   CNG    NATURAL GAS
          COMPANY


          CONSOLIDATED
   CNG    NATURAL GAS
          COMPANY


          CONSOLIDATED
   CNG    NATURAL GAS
          COMPANY                       Appendix I
<PAGE>   2
 
                               TABLE OF CONTENTS
 
<TABLE>
<CAPTION>
                                                              Page
                                                              ----
<S>                                                           <C>
Management's Discussion and Analysis of Financial Condition
  and Results of Operations.................................    1
Selected Financial Data.....................................   18
Report of Independent Accountants...........................   19
Consolidated Statement of Income for the Years 1995 through
  1997......................................................   21
Consolidated Balance Sheet at December 31, 1996 and 1997....   22
Consolidated Statement of Cash Flows for the Years 1995
  through 1997..............................................   24
Notes to Consolidated Financial Statements..................   25
</TABLE>
<PAGE>   3
 
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
 
RESULTS OF OPERATIONS
 
NET INCOME
Net income in 1997 was $304.4 million, or $3.21 a share, compared with net
income of $298.3 million, or $3.17 a share, in 1996. Net income in 1995 was
$21.3 million, or $.23 a share. Basic earnings per share reported for each year
reflects the Company's adoption of Statement of Financial Accounting Standards
(SFAS) No. 128 (see page 4, "New Accounting Standards").
     Earnings for 1997, 1996 and 1995 include special charges in each year.
During the fourth quarter of 1997, the Company recorded a non-cash charge to
write down the cost of its Canadian oil producing properties, amounting to $6.7
million after taxes, or $.07 a share. Excluding this item, net income for 1997
would have been $311.1 million, or $3.28 a share. Excluding the impact of
charges related to workforce reduction programs totaling $9.9 million after
taxes, or $.10 a share, 1996 net income would have been $308.2 million, or $3.27
a share. The Company recorded non-cash charges during 1995 to write down the
cost of gas and oil producing properties amounting to $145.0 million after
taxes, or $1.56 a share, and to write down coal properties amounting to $20.3
million after taxes, or $.22 a share. Also in 1995, the Company recorded charges
totaling $25.6 million after taxes, or $.27 a share, for workforce reductions.
Excluding these special items, net income for 1995 would have been $212.3
million, or $2.28 a share. Reference is made to Notes 4 and 5 to the
consolidated financial statements, page 30, for details of these special
charges.
 
     1997
The favorable impact of higher gas and oil production and continued cost
containment efforts more than offset the effects of warmer weather and lower
average wellhead prices for gas and oil. Weather in the Company's retail service
areas was 1.9% colder than normal and 4.3% warmer than 1996. Normal weather
represents a measure of temperature experienced over an historical time frame,
the length of which may differ depending on the regulatory jurisdiction.
 
     1996
Higher wellhead prices for natural gas and oil, increased gas and oil
production, colder weather, cost controls and the full year impact of new rates
in place for most of the Company's gas distribution customers contributed to the
improved results. Weather in the Company's retail service areas was 5.6% colder
than normal and 5.5% colder than 1995.
 
     1995
The favorable effects of new rates in place for most of the Company's gas
distribution and transmission customers, colder weather and lower aggregate wage
and benefit costs in the latter part of the year resulting from the workforce
reduction programs more than offset the impact of low wellhead prices for
natural gas and lower gas and oil production.
 
OPERATING REVENUES
Operating revenues include revenues from gas and oil sales, transportation and
storage of gas, brokering activities, by-product operations and wholesale
electric sales. Total operating revenues in 1997 were $5,710.0 million, an
increase of $1,915.7 million compared to $3,794.3 million in 1996. Significantly
increased sales of gas and electricity by the energy marketing services
operations was the primary reason for the revenue growth. Consistent with
industry conditions, these operations generate high sales volumes at low
margins.
     Regulated gas sales revenues of $1,851.0 million in 1997 were up $98.8
million compared to 1996, despite sales volumes decreasing 22.0 billion cubic
feet (Bcf) to 272.0 Bcf. The decline in volumes was due to warmer weather and
the effect of the displacement of sales volumes to other suppliers, including
CNG
 
                                        1
<PAGE>   4
 
Retail Services Corporation (CNG Retail). Sales revenues attributable to the
Company's residential and commercial customers increased during 1997 as higher
average sales rates, reflecting the recovery of previously deferred purchased
gas costs, more than offset reduced volumes compared to 1996. The impact of
lower sales volumes for the Company's industrial customers more than offset
higher average sales rates for that customer class during 1997.
     Nonregulated gas sales revenues increased $1,246.6 million in 1997 to
$2,339.1 million, with sales volumes increasing 411.6 Bcf to 807.7 Bcf. The
increases in both revenues and volumes during 1997 were attributable chiefly to
the energy marketing services operations. The increases also reflect higher gas
production at CNG Producing Company (CNG Producing).
     Gas transportation and storage revenues rose $14.4 million in 1997 compared
to the prior year, to $479.5 million, reflecting both higher gas transportation
and storage service revenues. Wholesale electricity sales by the energy
marketing services operations increased $485.1 million in 1997 due chiefly to
higher volumes. Other operating revenues increased $70.8 million in 1997 to
$445.8 million. Revenues from oil brokering were up $39.7 million, while
revenues from the sale of oil and condensate production increased $33.5 million.
In both cases, the impact of higher volumes more than offset a decline in oil
prices.
     Total operating revenues in 1996 increased $487.0 million from $3,307.3
million in 1995. Regulated gas sales revenues in 1996 increased $154.8 million
to $1,752.2 million, with sales volumes increasing 4.1 Bcf to 294.0 Bcf due
mainly to colder weather. Nonregulated gas sales revenues increased $94.8
million in 1996, while sales volumes decreased 160.5 Bcf to 396.1 Bcf. The
effect of higher prices, coupled with the impact of higher production by the
exploration and production operations, more than offset the effect of reduced
transaction volumes of the energy marketing services component. Gas
transportation and storage revenues of $465.1 million in 1996 were up $8.7
million over 1995. The increase was due to higher transportation revenues as a
result of increased volumes and rates. Wholesale electricity revenues of the
energy marketing services component were up $87.7 million in 1996 due to higher
quantities of electricity sold. Other operating revenues increased $141.0
million in 1996, to $375.0 million, due chiefly to an increase of $108.8 million
in revenues from oil and condensate production and brokering.
 
OPERATING EXPENSES
Operating expenses, including income taxes, increased to $5,311.8 million in
1997, compared to $3,402.1 million and $3,160.8 million in 1996 and 1995,
respectively. Excluding the impact of impairments of gas and oil producing
properties in 1997 and 1995 and workforce reduction charges in 1996 and 1995,
operating expenses would have been $5,305.1 million, $3,392.2 million and
$2,990.2 million for the years 1997, 1996 and 1995, respectively.
     Purchased gas consistently represents the largest operating expense
category for the Company. Purchased gas costs were $2,960.2 million in 1997,
$1,615.0 million in 1996 and $1,590.1 million in 1995. This expense is
influenced primarily by changes in gas sales requirements, the price and mix of
gas supplies, and the timing of recoveries of deferred purchased gas costs.
Increased volume requirements in connection with nonregulated gas sales and the
recognition of previously deferred purchased gas costs contributed to the
increase in 1997. For 1996, the effect of higher average purchase prices more
than offset the impact of decreased volume requirements in connection with
nonregulated gas sales and the deferral of purchased gas costs by the regulated
subsidiaries.
     Electricity, liquids and capacity purchased expense includes the cost of
electricity, oil, condensate and by-products purchased for resale and pipeline
capacity not associated with gas purchased. This expense increased $523.0
million in 1997 and $193.1 million in 1996 due primarily to electricity
purchased for resale by the energy marketing services component and oil
purchased for resale by CNG Producing.
     Excluding the effect in 1996 of workforce reduction charges, combined
operation and maintenance expense increased $24.4 million in 1997. This increase
was due largely to adjustments of reserves for pipeline settlements and
receivables recorded during 1997 by the energy marketing services component, in
addition to higher royalty expense and production-related costs. These costs
were partially offset by lower employment costs. Maintenance expense increased
slightly in 1997.
 
                                        2
<PAGE>   5
 
     Excluding the effect of 1996 and 1995 workforce reduction charges totaling
$15.2 million and $42.6 million, respectively, combined operation and
maintenance expense increased $77.2 million in 1996. This increase was due in
large part to increased royalty expense, partially offset by lower employee-
related costs and reductions in certain administrative expenses. Maintenance
expense increased $4.2 million in 1996 to $90.1 million.
     Total depreciation and amortization expense increased $25.9 million in 1997
and $47.6 million in 1996 due largely to higher gas and oil production volumes
each year. Depreciation expense for the regulated subsidiaries increased in both
1997 and 1996 due principally to the increased level of plant investment.
     Taxes, other than income taxes, were up $4.8 million in 1997 due in part to
higher excise taxes, and decreased $.7 million in 1996 due largely to lower
excise and payroll taxes.
     Income taxes decreased $8.8 million in 1997, due largely to a lower
effective tax rate, and increased $152.8 million in 1996. The 1996 increase was
due to higher pretax earnings compared to 1995.
 
OTHER INCOME
Total other income was $13.5 million in 1997, compared to $9.3 million in 1996
and total other deductions of $20.5 million in 1995. Excluding the write-down of
coal properties of $31.3 million, total other income in 1995 would have been
$10.8 million. Interest revenues decreased slightly in 1997, and declined $6.8
million in 1996 compared to 1995 due largely to the lower level of temporary
cash investments in 1996. The increase in "Other-net" in 1997 of $4.3 million
compared to 1996 is due largely to a charge of $5.0 million recognized in
connection with an early extinguishment of debt in December 1996. Increased
earnings from the Company's equity investments and losses related to minor
property dispositions at certain regulated subsidiaries in 1995 that did not
recur in 1996, partially offset by the debt extinguishment charge, were the
primary reasons for the increase in "Other-net" of $5.4 million in 1996 compared
to 1995.
 
INTEREST CHARGES
Interest on long-term debt increased $3.1 million in 1997. This increase was due
largely to a full year of interest expense related to the $300 million of
debentures issued in the fourth quarter of 1996, partially offset by the effects
of the redemption in early 1997 of $100 million of debentures and the early
extinguishment of $53.1 million of debt in late 1996. Interest on long-term debt
increased $6.0 million in 1996 due primarily to debenture sales of $150 million
each in April 1995, October 1996 and December 1996. Other interest expense
increased $1.9 million in 1997. Other interest expense declined $7.5 million in
1996 due largely to lower interest expense related to customer refunds.
 
FOURTH QUARTER RESULTS
Net income for the fourth quarter of 1997 was $89.4 million compared to $88.0
million in 1996. On a basic earnings per share basis, the 1997 quarter was $.94
compared with $.93 in 1996. However, the 1997 fourth quarter reflects a special
charge for the impairment of oil producing properties totaling $6.7 million
after taxes, or $.07 per share, while the 1996 quarter includes special charges
for workforce reductions totaling $7.8 million after taxes, or $.08 per share.
The Company's 1997 average gas wellhead price was $2.54 per thousand cubic feet
(Mcf), down $.08 per Mcf, and average oil wellhead prices declined $2.90 per
barrel, to $15.69. These negative factors were partially offset by the impact of
weather that was 2.2% colder than in 1996.
 
                                        3
<PAGE>   6
 
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                QUARTERS ENDED DECEMBER 31,                     1997        1996
-----------------------------------------------------------------------------------
                                                                  (In Millions)
<S>                                                           <C>         <C>
Operating revenues..........................................  $ 1,850.1   $ 1,229.2
Operating expenses..........................................   (1,689.4)   (1,066.4)
                                                              ---------   ---------
Operating income before income taxes........................      160.7       162.8
Income taxes................................................      (40.8)      (46.1)
Other income/expenses-net...................................      (30.5)      (28.7)
                                                              ---------   ---------
Net income..................................................  $    89.4   $    88.0
                                                              =========   =========
Earnings per common share--basic (in dollars)...............       $.94        $.93
Earnings per common share--diluted (in dollars).............       $.92        $.91
-----------------------------------------------------------------------------------
</TABLE>
 
NEW ACCOUNTING STANDARDS
In 1997, the Financial Accounting Standards Board (FASB) issued SFAS No. 128,
"Earnings per Share," which established new requirements for computing and
presenting earnings per share. The Company has adopted the provisions of SFAS
No. 128 for the year ended December 31, 1997, and has restated earnings per
share amounts for all prior periods presented in conformity with the new
standard. The adoption of SFAS No. 128 did not have a material effect on the
Company's earnings per share for any of the periods presented. Reference is made
to Note 2 to the consolidated financial statements, page 28, regarding SFAS No.
128.
     Also in 1997, the FASB issued SFAS No. 130, "Reporting Comprehensive
Income," and SFAS No. 131, "Disclosures about Segments of an Enterprise and
Related Information." SFAS No. 130 establishes standards for the reporting and
display of comprehensive income and its components. The Company is required to
adopt the provisions of SFAS No. 130 beginning with its consolidated financial
statements for the three months ending March 31, 1998. SFAS No. 131 requires
certain disclosures about segment information in interim and annual financial
statements and related information about products and services, geographic areas
and major customers. The Company must adopt the provisions of SFAS No. 131 for
its consolidated financial statements for the year ending December 31, 1998. The
adoptions of SFAS Nos. 130 and 131 are not expected to have a material effect on
the Company's financial position, results of operations or cash flows.
 
COMPONENTS OF THE BUSINESS
Due to the regulated nature of the distribution and transmission components of
the Company's business, operating results can be affected by regulatory delays
when price increases are sought through general rate filings to recover certain
higher costs of operations. Weather is also an important factor since a major
portion of the gas sold or transported by the distribution and transmission
operations is ultimately used for space heating.
 
                                        4
<PAGE>   7
 
     Operating results for each of the Company's business components follow.
Reference is made to Note 19 to the consolidated financial statements, page 45,
for additional disaggregated information.
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
            OPERATING INCOME BEFORE INCOME TAXES              1997(a)   1996(b)   1995(c)
-----------------------------------------------------------------------------------------
                                                                     (In Millions)
<S>                                                           <C>       <C>       <C>
Distribution................................................  $266.6    $258.4    $ 207.5
Transmission................................................   178.4     178.8      150.4
Exploration and production..................................   142.8     133.2     (200.5)
Energy marketing services...................................   (17.1)     (9.1)      (5.7)
Other(d)....................................................    (9.3)     (3.2)       2.9
Corporate and eliminations..................................   (16.2)    (10.1)      (5.1)
                                                              ------    ------    -------
  Total.....................................................  $545.2    $548.0    $ 149.5
                                                              ======    ======    =======
</TABLE>
 
(a) Amount for the exploration and production operations includes the impact of
    the write-down of oil producing properties in Canada amounting to $10.4
    million.
 
(b) Amounts for the distribution, transmission, exploration and production,
    energy marketing services and corporate components include the effect of
    workforce reduction charges totaling $8.2 million, $5.1 million, $.6
    million, $.3 million and $1.0 million, respectively.
 
(c) Amount for the exploration and production operations includes the impact of
    the write-down of gas and oil producing properties in the United States
    amounting to $226.2 million. Amounts for the distribution, transmission,
    exploration and production, energy marketing services and corporate
    components include the effect of workforce reduction charges totaling $22.3
    million, $6.0 million, $7.7 million, $.5 million and $4.6 million,
    respectively.
 
(d) Includes Consolidated LNG, CNG Research and CNG Coal. Amounts for 1997 and
    1996 include CNG International and CNG Products and Services. Amounts for
    1997 also include CNG Retail.
--------------------------------------------------------------------------------
 
DISTRIBUTION
"Distribution" represents the results of the four retail gas distribution
subsidiaries, including their minor gas and oil production activities.
     Sales growth in the Company's residential service areas in Ohio,
Pennsylvania and West Virginia has generally been limited since such areas have
experienced minimal population growth, and the vast majority of households in
these areas already use natural gas for space heating. Opportunity for growth in
the retail sales market is expected to continue at Virginia Natural Gas, Inc.
(Virginia Natural Gas), due to customer conversions from other energy sources
and the past and potential future expansion of its service territory. Since the
Company's acquisition of this subsidiary in 1990, it has experienced an annual
customer growth rate of about 4%, compared to a growth rate of less than 1% for
the other distribution subsidiaries.
     Similar to the unbundling in recent years of the services provided by gas
pipeline companies, gas distribution companies are adapting to the deregulation
and unbundling of the retail energy market. Under open access programs, natural
gas suppliers other than the local gas utility can use the utility's existing
lines to deliver gas to customers.
     In early 1997, the Company formed a new nonregulated subsidiary, CNG
Retail, to market natural gas, electricity, and consumer products and services
to residential, commercial and small industrial customers, including those
within the Company's traditional service territories. CNG Retail is expected to
enable the Company to take advantage of emerging deregulated energy markets for
both gas and electricity.
     During the spring of 1997, The Peoples Natural Gas Company (Peoples Natural
Gas) opened its system in Pennsylvania to customer choice. In addition, on July
2, 1997, the Public Utilities Commission of Ohio (PUCO) approved The East Ohio
Gas Company's (East Ohio Gas) "Energy Choice" pilot program which will allow
approximately 15% of East Ohio Gas's residential and small business customers
the opportunity to purchase their natural gas from competing suppliers, if they
so choose.
 
                                        5
<PAGE>   8
 
     DISTRIBUTION OPERATING INCOME BEFORE INCOME TAXES
 
     1997
Excluding workforce reduction charges during 1996, operating income before
income taxes of $266.6 million in 1997 was unchanged from the prior year. The
effect of warmer weather in 1997 offset the impact of lower operation and
maintenance expenses during the year. Weather in the Company's retail service
areas was 1.9% colder than normal but 4.3% warmer than 1996.
 
     1996
Excluding workforce reduction charges amounting to $8.2 million in 1996 and
$22.3 million in 1995, operating income before income taxes for those years
would have been $266.6 million and $229.8 million, respectively. Improved
results for 1996 reflect colder weather, cost control efforts and the full year
impact of general rate increases that went into effect in the latter part of
1995 at Peoples Natural Gas, Hope Gas, Inc. (Hope Gas) and East Ohio Gas.
Weather in the Company's retail service areas was 5.5% colder than 1995 and 5.6%
colder than normal.
 
     1995
Excluding workforce reduction charges, operating income before income taxes in
1995 was up $70.8 million. In addition to the general rate increases placed into
effect in late 1994 and 1995, colder weather, the addition of new customers,
higher transport volumes and lower wage and benefit costs in the latter part of
the year due to the workforce reduction programs contributed favorably to 1995
results. Weather was 2.2% colder than 1994 and .5% colder than normal.
 
     DISTRIBUTION OPERATING REVENUES
Operating revenues increased $121.1 million in 1997, to $2,026.6 million. Gas
sales revenues increased $101.1 million as higher average sales rates,
reflecting the recovery of previously deferred purchased gas costs, more than
offset the effect of reduced sales volumes. Gas transportation and storage
revenues increased $21.5 million in 1997 due to both higher volumes and rates.
     Revenues in 1996 increased $160.3 million to $1,905.5 million. Gas sales
revenues were up $152.3 million reflecting both higher average sales prices and
higher sales volumes. Average sales prices increased due to the impact of both
higher unit purchased gas costs passed through to customers and higher rates in
place for most of the Company's distribution customers. Colder weather was a
major factor in the increased sales volumes. Gas transportation and storage
revenues increased $10.1 million resulting from both higher volumes and rates.
 
     DISTRIBUTION THROUGHPUT
Since distribution sales largely represent retail sales for space heating,
changes in sales volumes from one period to another are primarily a function of
the weather. In addition to sales service, the distribution operations provide
gas transportation services to a wide range of customers, primarily commercial
and industrial end users. Therefore, the volume of gas transported can be
affected by changes in both economic and market conditions.
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                  DISTRIBUTION THROUGHPUT                     1997     1996     1995
-------------------------------------------------------------------------------------
                                                              (In Billion Cubic Feet)
<S>                                                           <C>      <C>      <C>
Sales.......................................................  272.7    294.2    289.9
Transportation..............................................  189.4    174.2    164.8
                                                              -----    -----    -----
     Throughput.............................................  462.1    468.4    454.7
                                                              =====    =====    =====
-------------------------------------------------------------------------------------
</TABLE>
 
     Warmer weather and the effect of the displacement of sales volumes to other
suppliers, including CNG Retail, were the reasons for the decrease in gas sales
volumes compared to 1996. Residential gas sales volumes decreased 10.9 Bcf, to
207.8 Bcf, in 1997. Commercial sales decreased 7.1 Bcf while volumes transported
to these customers were up 9.0 Bcf. Deliveries to industrial customers were
lower in 1997, decreasing .5 Bcf to 138.3 Bcf. Sales to industrial customers
declined 2.6 Bcf to 4.3 Bcf, while transporta-
 
                                        6
<PAGE>   9
 
tion volumes increased 2.1 Bcf to 134.0 Bcf. Transportation to off-system
customers increased 4.1 Bcf in 1997.
     In 1996, colder weather and the net addition of approximately 17,000
residential and commercial customers contributed to the slight increase in gas
sales volumes compared to 1995. Residential gas sales volumes increased 6.2 Bcf,
to 218.7 Bcf, in 1996. Commercial sales decreased 3.0 Bcf while volumes
transported to these customers were up 7.2 Bcf. Deliveries to industrial
customers were higher in 1996, increasing .6 Bcf to 138.8 Bcf. Sales to
industrial customers declined .4 Bcf to 6.9 Bcf, while transportation volumes
increased 1.0 Bcf to 131.9 Bcf. Transportation to off-system customers increased
1.2 Bcf in 1996.
 
TRANSMISSION
"Transmission" includes the results of the gas transmission, storage, by-product
and certain other activities of CNG Transmission Corporation (CNG Transmission).
Gas and oil production activities of CNG Transmission are included in
exploration and production operations.
 
     TRANSMISSION OPERATING INCOME BEFORE INCOME TAXES
 
     1997
Excluding workforce reduction charges in 1996, operating income before income
taxes declined $5.5 million in 1997, to $178.4 million. However, the 1997
results include a charge amounting to $5.8 million recognized in the fourth
quarter in connection with CNG Transmission's withdrawal from participation in a
gas storage development project.
 
     1996
Excluding workforce reduction charges of $5.1 million in 1996 and $6.0 million
in 1995, operating income before income taxes for those years would have been
$183.9 million and $156.4 million, respectively. Cost control efforts and
increased gas transportation and by-products revenues contributed to the
improved results in 1996.
 
     1995
Excluding workforce reduction charges, operating income before income taxes
increased $10.1 million in 1995. Higher rates resulting from CNG Transmission's
general rate filing, which became effective July 1, 1994, and cost controls were
the major factors for the improved results in 1995.
 
     TRANSMISSION OPERATING REVENUES
Total operating revenues declined $16.4 million in 1997, to $487.0 million. Gas
transportation revenues declined $15.7 million due to both lower volumes and
rates, and revenues from the sale of by-products decreased $3.7 million due
primarily to lower sales rates. These decreases were partially offset by an
increase of $2.8 million in gas storage service revenues.
     Total operating revenues were $32.4 million higher in 1996 compared to
1995. Gas transportation and storage revenues increased $9.7 million due to
higher gas transportation revenues, which increased $14.9 million due to higher
volumes and rates. This increase was partly offset by decreased storage service
revenues. Revenues from the sale of by-products increased $9.7 million due
chiefly to higher sales rates.
 
     TRANSMISSION THROUGHPUT
The changing regulatory environment has created a number of opportunities for
pipeline companies to expand and serve new markets. The Company has taken
advantage of selected market expansion opportunities, concentrating its efforts
primarily in the Northeast and along the East Coast. This expansion is supported
by the Company's network of underground storage facilities and the location and
nature of its gridlike pipeline system as a link between the country's major
longline gas pipelines and the increasing energy demands of East Coast markets.
CNG Transmission's pipeline and storage facilities will continue to enable
retail end users to take advantage of the accessibility of supplies nationwide
in the evolving
 
                                        7
<PAGE>   10
 
deregulation of the gas industry at the retail level (see "Distribution," page
5, and "Gas and Electric Industry Developments," page 11).
     Variations in weather conditions can also have a significant impact on the
throughput of the transmission operations, since a substantial portion of the
gas deliveries of these operations is ultimately used by space-heating
customers. Also, transmission operations provide transportation services to a
wide range of customers, including commercial and industrial end users, electric
power generators, and local utility companies. Therefore, the volume of gas
transported can also be affected by changes in economic and market conditions.
However, due to the straight fixed variable rate design, operating income for
the transmission operations is not significantly influenced by changes in
throughput.
     Total throughput for the gas transmission operations, consisting entirely
of transportation volumes and including intercompany activity, was 732.8 Bcf,
758.4 Bcf, and 744.0 Bcf for the years 1997, 1996 and 1995, respectively.
 
EXPLORATION AND PRODUCTION
"Exploration and production" (E&P) includes the results of CNG Producing and the
gas and oil production activities of CNG Transmission.
 
     E&P OPERATING INCOME BEFORE INCOME TAXES
 
     1997
Operating income before income taxes in 1997 was $142.8 million, compared to
$133.2 million in 1996. However, the 1997 results include a non-cash charge of
$10.4 million related to the Company's impairment of Canadian oil producing
properties. In addition, workforce reduction charges totaling $.6 million are
reflected in the 1996 results. Excluding these items, 1997 operating income
would have been $153.2 million, an increase of $19.4 million compared to the
prior year. The 1997 results reflect increased gas and oil production that more
than offset the impact of lower average wellhead prices for gas and oil, higher
royalty expense, increased operating costs related to bringing certain new
production on line and increased workover activity. During 1997, the Company
added 315 Bcf of gas equivalent from additions, revisions, and purchases of gas
and oil reserves.
 
     1996
Operating income before income taxes in 1996, excluding $.6 million of workforce
reduction charges, was $133.8 million, compared with an operating loss before
income taxes of $200.5 million in 1995. However, the 1995 results reflect a
non-cash charge of $226.2 million for the impairment of gas and oil producing
properties and workforce reduction charges totaling $7.7 million. Excluding
these special items, operating income before income taxes would have been $33.4
million for 1995. The effects of higher gas and oil wellhead prices and higher
gas and oil production contributed to the significantly improved operating
results in 1996. Higher prices and production also resulted in increased royalty
expense and higher production-related costs compared to the prior year. The
Company added 272 Bcf of gas equivalent from additions, revisions, and purchases
of gas and oil reserves in 1996.
 
     1995
Excluding special items described above, operating results for 1995 would have
been slightly lower than the prior year. The impact of low gas wellhead prices
and lower gas and oil production slightly offset the favorable impact of higher
oil wellhead prices, a $7.5 million reduction in production-related expenses,
and reductions in overhead costs in 1995. In addition, depreciation and
amortization expense was $32.1 million lower in 1995 resulting from the
impairment of gas and oil producing properties, the effect of gas and oil
reserve additions, and lower production. Reserves equal to 210 Bcf of gas
equivalent were added in 1995.
 
                                        8
<PAGE>   11
 
     GAS AND OIL PRODUCTION AND PRICES
The following table sets forth the Company's gas and oil production and average
wellhead prices for the E&P operations for the last three years:
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                         PRODUCTION                            1997      1996      1995
-----------------------------------------------------------------------------------------
<S>                                                           <C>       <C>       <C>
GAS (BCF)
Nonregulated................................................    155.3     144.5     102.6
Regulated*..................................................      2.8       3.0       4.6
                                                              -------   -------   -------
     Total..................................................    158.1     147.5     107.2
                                                              =======   =======   =======
OIL (000 BBLS)
Nonregulated................................................  7,312.0   4,765.9   3,131.7
Regulated*..................................................       --        --      17.2
                                                              -------   -------   -------
     Total..................................................  7,312.0   4,765.9   3,148.9
                                                              =======   =======   =======
AVERAGE WELLHEAD PRICES
(NONREGULATED ONLY)
Gas (per Mcf)...............................................   $ 2.43    $ 2.46    $ 1.89
Oil (per Bbl)...............................................   $16.07    $17.60    $16.04
</TABLE>
 
* Cost-of-service. Hope Gas sold all of its remaining gas reserves to CNG
  Producing during 1996. At December 31, 1997 and 1996, the Company's remaining
  cost-of-service gas reserves were held by Peoples Natural Gas.
--------------------------------------------------------------------------------
     The Company's average gas wellhead price was $2.43 per Mcf in 1997, down
from $2.46 in 1996. Gas production for 1997 was 158.1 Bcf, an increase of 10.6
Bcf compared to the prior year. Production from several new fields in the Gulf
of Mexico contributed to the 1997 increase. Oil wellhead prices averaged $16.07
a barrel during 1997, down $1.53 from 1996, while production increased 53%
compared to the prior year. The increase in oil production in 1997 is due
largely to the impact of Neptune, one of the Company's deep-water projects in
the Gulf of Mexico which began production in March 1997.
     The Company's average gas wellhead price in 1996 was $2.46 per Mcf, up $.57
from $1.89 in 1995. Gas production in 1996 was 147.5 Bcf, up 38% from 1995. The
increase in gas production during 1996 was due partially to the impact of two
significant Gulf of Mexico projects which commenced production in the 1996 first
quarter, Popeye and Main Pass 225. Production also benefited from the effect of
production enhancement efforts at existing Company-operated fields. Average oil
wellhead prices were $17.60 per barrel in 1996, up $1.56 from 1995, while oil
production increased 51% from the prior year. The increase in oil production in
1996 was due in large part to production from the Popeye project.
 
     E&P OPERATING REVENUES
Total operating revenues were $705.7 million in 1997, an increase of $73.4
million compared to 1996. Gas sales revenues decreased $.5 million, as increased
sales volumes were more than offset by the effect of lower average gas prices.
Revenues from oil and condensate production and brokering increased $73.0
million in 1997, with higher sales volumes more than offsetting the impact of
lower rates. Revenues from oil brokering rose $39.7 million and revenues from
oil and condensate production increased $33.3 million.
     Total operating revenues increased 75% in 1996, to $632.3 million. Of the
$159.3 million increase in gas sales revenues in 1996, $90.8 million was due to
higher average gas prices and $68.5 million reflected increased volumes.
Revenues from oil and condensate production and brokering increased $108.9
million in 1996, with $77.7 million of the increase attributable to increased
volumes and the remaining increase due to higher rates. Revenues from oil
brokering increased $74.6 million while revenues from the sale of oil and
condensate production increased $34.3 million.
 
                                        9
<PAGE>   12
 
ENERGY MARKETING SERVICES
"Energy marketing services" represents the results of CNG Energy Services
Corporation (CNG Energy Services) and CNG Power Services Corporation (CNG Power
Services). CNG Energy Services markets Company-owned gas production and arranges
gas supplies, transportation, storage and related services for large volume
customers. CNG Energy Services also holds the Company's ownership interests in
six independent power plants. CNG Power Services purchases and resells
electricity at market-based prices.
     The energy marketing services component reported an operating loss before
income taxes of $17.1 million in 1997, an increased loss of $8.0 million
compared to 1996. The higher operating loss in 1997 was due chiefly to charges
recorded in connection with the establishment of reserves for pipeline
settlements and receivables. Reduced gross margins and higher overhead costs
also contributed to the 1997 operating loss. Total throughput for this component
was 856.4 Bcf in 1997, an increase of 429.3 Bcf compared to 1996. Electricity
marketed in 1997 totaled 25.2 million megawatt-hours, an increase of 20.2
million megawatt-hours over the prior year.
     This component reported operating losses before income taxes of $9.1
million in 1996 and $5.7 million in 1995. The 1996 and 1995 results include
workforce reduction charges totaling $.3 million and $.5 million, respectively.
In addition to higher overhead costs, the 1996 loss occurred in part because
this component contracted for quantities of natural gas to supply power plants
during the summer air-conditioning season; these quantities proved to be too
high when third quarter 1996 weather turned cooler than expected. Reduced
transaction volumes during 1996 also adversely impacted 1996 operating results.
Total throughput for this component was 427.1 Bcf in 1996 compared to 570.8 Bcf
in 1995. Power marketing, which includes the sale of wholesale electricity,
increased to 5.0 million megawatt-hours in 1996 compared to 1.9 million
megawatt-hours in 1995.
     In addition to depressed gas margins throughout the year, 1995 operating
results also reflected a $5.3 million pretax charge recognized by CNG Energy
Services in December 1995 in connection with a mark-to-market valuation of
exchange-traded futures contracts used to manage price risk exposure related to
its stored gas inventories.
     Income recognized in connection with CNG Energy Services investments in
1997, 1996 and 1995 totaled $8.2 million, $5.8 million and $3.9 million,
respectively. In addition, this component recorded a charge of $7.0 million in
the fourth quarter of 1997 in connection with the decision to sell and write
down the carrying value of its interests in four independent power projects.
These amounts are not included in operating income or loss before income taxes
but are reflected in "Other income" for the component.
 
OTHER
"Other" in the operating income table on page 5 represents the results of
Consolidated System LNG Company (Consolidated LNG), CNG Research Company (CNG
Research) and CNG Coal Company (CNG Coal) for all three years, CNG International
Corporation (CNG International) and CNG Products and Services Corporation (CNG
Products and Services) for 1997 and 1996, and CNG Retail for 1997 only.
     This segment reported an operating loss before income taxes of $9.3 million
in 1997 and $3.2 million in 1996 and operating income of $2.9 million in 1995.
Results for 1997 and 1996 reflect start-up costs incurred in connection with CNG
International, which reported pretax operating losses of $6.8 million and $3.8
million, respectively. Start-up costs of CNG Retail and CNG Products and
Services are reflected in their combined pretax operating losses of $3.8 million
and $1.5 million in 1997 and 1996, respectively. Helping to offset these
start-up costs somewhat is pretax operating income for Consolidated LNG of $1.4
million, $2.6 million and $3.7 million for the years 1997, 1996 and 1995,
respectively, reflecting the recognition of deferred income pursuant to a
regulatory order.
 
INTERNATIONAL ACTIVITIES
During December 1997, CNG International acquired 12.5% ownership interests in
two gas utility holding companies, Sodigas Pampeana and Sodigas Sur, and a 20%
ownership interest in an electric utility holding company, Buenos Aires Energy
Company (BAECO), from CEI Citicorp Holdings S.A. in Argentina. The gas utility
holding companies have ownership interests in two gas distribution companies,
Camuzzi Gas
 
                                       10
<PAGE>   13
 
Pampeana and Camuzzi Gas del Sur, and BAECO has an ownership interest in an
electric distribution company, EDEA. The service territories of these companies
span from Buenos Aires province to the southernmost tip of Argentina. Camuzzi
Argentina S.A. will maintain majority ownership interests in the holding
companies. At December 31, 1997, CNG International's investments in the
Argentine holding companies totaled $79.1 million.
     In December 1996, CNG International and El Paso Energy Corporation entered
into a joint venture to own and operate the Australian pipeline assets formerly
held by Tenneco Energy. CNG International owns 30% of Epic Energy Pty Ltd. (Epic
Energy), an Australian entity formed to hold the investment's operating assets.
The primary operating assets of the venture include two major long-distance
natural gas pipelines from Australia's Cooper Basin. CNG International's net
investment in Epic Energy totaled $30.9 million at December 31, 1997.
 
LIMITATION ON CAPITALIZED COSTS
As indicated in Note 1 to the consolidated financial statements, CNG Producing
and CNG Transmission follow the full cost method of accounting for their gas and
oil producing activities prescribed by the Securities and Exchange Commission
(SEC). Reference is made to Note 4 to the consolidated financial statements,
page 30, regarding the Company's recognition under the SEC full cost rules of
impairments of its gas and oil producing properties at December 31, 1997 and
March 31, 1995.
     There are a number of factors, including prices, that determine whether or
not an impairment is required. Because gas wellhead prices are subject to sudden
and seasonal fluctuations, an impairment of these gas and oil properties is a
possibility at any quarterly measurement date, unless other factors such as
lower production costs or proved reserve additions mitigate the impact of a
price decline.
 
FEDERAL AND STATE REGULATORY MATTERS
 
     GAS AND ELECTRIC INDUSTRY DEVELOPMENTS
In the current gas industry environment, competition at the retail level is
receiving increased attention by state regulators. Governments in two of the
states in which the Company operates distribution subsidiaries have enacted or
considered legislation regarding deregulation of natural gas at the retail
level. In Ohio, a 1996 law established customer choice as a state policy in the
supply of natural gas services, and allows retail customers to obtain gas from
an array of suppliers. The PUCO has proposed rules to implement the law.
Legislation is being considered in Pennsylvania that would completely unbundle
gas utility merchant functions by January 1999. One aspect of the proposal would
permit the Pennsylvania Public Utility Commission (PUC) to certify marketers, in
addition to gas utilities, as suppliers of last resort, creating competition in
a traditional gas utility function. The proposal requires the PUC to review and
act by September 1998 on plans submitted by gas utilities.
     In addition to the further deregulation of the gas industry, the emerging
unbundling of services provided by electric utilities may ultimately result in
the convergence of both industries to create one overall, highly competitive
marketplace for a customer's total energy needs. During 1995 and 1996,
regulators at the federal and state levels finalized initiatives to promote
increased competition in the electric industry. These initiatives included
issuance in 1996 of FERC Order Nos. 888 and 889 (Orders 888 and 889). By
requiring open access to the national electric transmission grid, Order 888
fosters increased competition in both the generation of electricity and the
supply of bulk power to major wholesale customers. A companion order, Order 889,
addresses the timing, information access and other administrative details
associated with the FERC deregulation initiative.
     Other signs of an increasingly deregulated electric utility environment
include retail competition plans adopted in several states, pilot retail
wheeling programs and pro-competition legislation proposed at both the federal
and state levels. While no legislation has been enacted in Ohio regarding
electric competition at the retail level, a legislative study committee report
issued in January 1998 calls for full customer choice by 2000. In Pennsylvania,
the Electric Generation Customer Choice and Competition Act enacted in late 1996
requires a transition to a competitive electric market at the retail level
beginning in 1999, with full competition by 2001. In February 1998, the Virginia
General Assembly passed an electric industry restruc-
 
                                       11
<PAGE>   14
 
turing bill calling for wholesale competition beginning in 2001 and retail
competition in 2004 and sent the bill to the Virginia Senate for consideration.
In West Virginia, a bill introduced in February 1998 would authorize the Public
Service Commission (PSC) to prescribe and implement a plan to deregulate the
electric industry that must balance fairly the interests of customers, electric
utilities and the state's economy.
     Reflecting the evolution to a more competitive energy environment, the pace
and size of business combinations among natural gas and electric utilities
continued to increase during 1997. These business combinations have generally
been initiated to provide benefits from economies of scale, to reduce costs by
the elimination of duplicate facilities and processes, and to improve the
strategic and competitive position of the surviving entity. Recent and pending
regulatory actions may serve to further facilitate more business combinations in
the energy industry. The FERC has streamlined its regulatory review process
regarding pending mergers. In addition, the SEC has recommended legislation to
conditionally repeal the Public Utility Holding Company Act of 1935 (PUHCA), to
which the Company is subject, in conjunction with legislation which would grant
the various state regulatory commissions greater oversight authority of
companies currently subject to the PUHCA. Legislation has been introduced which
would completely repeal the PUHCA, while another group has proposed a
comprehensive energy reform program to address market power issues, particularly
regarding the electric industry. If legislation to repeal or significantly
modify the provisions of the PUHCA becomes law, certain federal restrictions
related to diversification activities, including business combinations, for gas
and electric companies subject to the PUHCA may be eased.
     Through its actions in recent years, the Company believes it is
well-positioned to compete in an evolving and increasingly deregulated energy
marketplace. The creation of CNG Retail and the ongoing development of the
energy marketing services component and participation in international
investments, coupled with streamlining and restructuring of its existing
distribution, transmission and exploration and production operations, reflects
the Company's proactive approach to meeting the demands of a more competitive
and dynamic business environment.
 
     FEDERAL AND STATE REGULATORY ISSUES
On July 1, 1997, CNG Transmission filed a general rate filing with the FERC
requesting an annual revenue increase of $71 million, related surcharges of
approximately $12 million, and permission to establish market-based pricing for
some of its transportation and storage services. The filing seeks to accelerate
recovery of part of the Company's investment in gathering facilities which will
enable CNG Transmission to fully unbundle its gathering facilities by January 1,
2001 in accordance with prior rate case settlements. The filing reflects a
proposed rate of return on equity of 14.5%. On July 31, 1997 the FERC accepted
in part, and rejected in part, the filing. The FERC's actions included
permission to place increased rates into effect January 1, 1998, subject to
refund, the establishment of hearing procedures and rejection of the proposal to
establish market based rates.
     On July 2, 1997, the PUCO approved East Ohio Gas's "Energy Choice" program
(see "Distribution," page 5).
     On January 5, 1998, Hope Gas filed with the Public Service Commission of
West Virginia for a $14.5 million annual revenue increase. The rate increase
request is intended to cover improvements and extensions made to its pipeline
system. If approved, the new rates would become effective November 1, 1998.
 
ENVIRONMENTAL MATTERS
The Company is subject to various federal, state and local laws and regulations
relating to the protection of the environment. These laws and regulations govern
both current and future operations and potentially extend to plant sites
formerly owned or operated by the subsidiaries, or their predecessors.
     Reference is made to Note 17 to the consolidated financial statements, page
43, for a detailed description of environmental matters.
     Estimates of liability in the environmental area are based on current
environmental laws and regulations and existing technology. The exact nature of
environmental issues which the Company may encoun-
 
                                       12
<PAGE>   15
 
ter in the future cannot be predicted. Additional environmental liabilities may
result in the future as more stringent environmental laws and regulations are
implemented and as the Company obtains more specific information about its
existing sites and production facilities. At present, no estimate of any such
additional liability, or range of liability amounts, can be made. However, the
amount of any such liabilities could be material.
 
EFFECTS OF INFLATION
Although inflation rates have been low to moderate in recent years, any change
in price levels has an effect on operating results due to the capital intensive
and regulated nature of the Company's major business components. The Company
attempts to minimize the effects of inflation through cost control, productivity
improvements and regulatory actions where appropriate.
 
FINANCIAL CONDITION
 
DIVIDEND AND COMMON STOCK MATTERS
In December 1997, the Board of Directors continued the quarterly dividend on the
common stock at 48.5 cents a share. Total dividends paid to common shareholders
in 1997 were $184.6 million compared with $183.0 million in 1996 and $180.8
million in 1995.
     During 1997, a total of 773,283 original issue shares were issued through
various Company-sponsored plans, including 612,158 shares acquired by employees
through the exercise of outstanding stock options.
     Under the Company's stock repurchase plan, authorization was granted during
1997 to increase the maximum amount of outstanding common stock that can be
repurchased from 4 million shares to 10 million shares. The shares may be
purchased in the open market from time-to-time, depending on market conditions,
or in private transactions. The Company may also acquire shares of its common
stock through certain provisions of the various stock incentive plans. The
shares repurchased or acquired are held as treasury stock and are available for
reissuance for general corporate purposes or in connection with various employee
benefit plans. No treasury shares were held by the Company at December 31, 1996.
The Company acquired 220,462 shares in 1997 at a cost of $12.3 million, or an
average price of $55.73 a share, primarily to fund certain non-qualified benefit
plans via a grantor trust. At December 31, 1997, a total of 659 shares were
being held as treasury stock. On January 15, 1998, the Company purchased
approximately 4.6 million shares of its common stock in a private transaction to
be used to satisfy the conversion rights of debentures called for redemption
(see "Call of Debentures," page 14).
 
CAPITAL SPENDING
The current capital spending program for 1998 is estimated at $714.7 million, a
17% increase compared with total capital spending in 1997. The estimated 1998
budget has been allocated as follows: distribution, $145.7 million;
transmission, $61.5 million; exploration and production, $312.7 million; energy
marketing services, $25.3 million; international, $151.6 million; and corporate
and other, $17.9 million. The increased level of capital expenditures planned
for 1998 anticipates higher spending for unregulated businesses. Exploration and
production operations reflect increased spending on deep-water projects and
increased conventional onshore and offshore drilling. Expenditures for
international operations reflect expected continued expansion of investment
opportunities in Australia and Latin America. Transmission and distribution
operations expenditures will primarily be limited to spending for enhancements
and improvements in the pipeline system and related facilities. The "corporate
and other" category includes expenditures to upgrade information systems
technology, primarily to centralize and consolidate services and financial
systems.
     Funds required for the capital spending program, as well as for other
general corporate purposes, are expected to be obtained principally from
internal cash generation. The Company may require long-term financing in 1998 to
support capital spending, and may also utilize the capital markets to take
advantage of other opportunities, including possible exploration and production
acquisitions, or to increase its financial flexibility.
 
                                       13
<PAGE>   16
 
CAPITAL RESOURCES AND LIQUIDITY
Because of the seasonal nature of the regulated subsidiaries' heating business,
a substantial portion of the Company's cash receipts are realized in the first
half of the year. However, cash requirements for capital expenditures,
dividends, debt retirements and other working capital needs do not track this
pattern of cash receipts. Consequently, additional cash needs are satisfied
through the sale of short-term commercial paper notes or by the issuance of
long-term debt. As shown in the Consolidated Statement of Cash Flows, net cash
provided by operating activities was $742.1 million, $407.2 million and $552.7
million for the years 1997, 1996 and 1995, respectively. The increase in net
cash provided by operating activities in 1997 was due in part to higher gas
sales revenues in 1997, including the recovery of previously deferred purchased
gas costs by the distribution subsidiaries, and the payment of customer refunds
in 1996 that did not recur in 1997. The decline in net cash provided by
operating activities in 1996 was due in part to the deferral of purchased gas
costs in excess of costs currently recovered in rates and the payment of
customer refunds during the period.
     In December 1997, the Company sold $300 million of 6.8% Debentures Due
December 15, 2027. The debentures are redeemable, as a whole or in part, at the
option of the Company at any time. The proceeds will be used for general
corporate purposes including capital expenditures, reduction of short-term debt,
repurchase of Company stock, and the acquisition, retirement or redemption of
debt securities.
     The Company has a shelf registration with the SEC which would allow it to
sell up to an additional $700 million of debt or equity securities. The amount
and timing of any future sale of these securities will depend on capital
requirements, including financing necessary to enable the Company to pursue
asset acquisition opportunities, and financial market conditions.
     The Company's embedded long-term debt cost, excluding current maturities,
at year-end 1997 was 7.20%, compared with 7.27% for 1996 and 7.69% for 1995. The
long-term debt to capitalization ratio was 39.7%, 39.3% and 38.7% at the end of
1997, 1996 and 1995, respectively. Under the provisions of one of the indentures
covering the Company's outstanding senior debenture issues, the ratio cannot
exceed 60%. The Company's senior debentures are rated A1 by Moody's Investors
Service, AA- by Standard & Poor's, AA- by Duff and Phelps, and AA by Fitch
Investors Service.
     At December 31, 1997, the Company had a short-term credit agreement with a
group of banks for $775 million. The Company made no borrowings under this
agreement during 1997 and there were no amounts outstanding under any credit
agreements at December 31, 1997 or 1996. On February 13, 1998, the Company
entered into a $250 million short-term credit agreement with a bank. Borrowings
under the agreement are in the form of revolving credits which may be used for
general corporate purposes.
     The Company utilizes short-term borrowings to finance gas inventories and
other working capital requirements. Funds from the sale of commercial paper
notes were used for these purposes in 1997, of which $238.7 million was
outstanding at year-end. The Company may utilize unused portions of its credit
agreements to provide support for commercial paper notes.
 
     CALL OF DEBENTURES
The Company's 7 1/4% Convertible Subordinated Debentures, due December 15, 2015,
were convertible into shares of the Company's common stock at an initial
conversion price of $54 per share. On January 23, 1998, the Company called for
redemption the entire principal amount outstanding totaling $246.2 million. The
redemption price was 102.18% of the principal amount plus accrued interest
payable on February 23, 1998. In anticipation of the call of this debt, on
January 15, 1998, the Company purchased approximately 4.6 million shares of its
common stock in a private transaction to satisfy the conversion obligation to
holders of the Convertible Subordinated Debentures who chose to convert. This
right to convert expired on February 13, 1998, and approximately 1.6 million of
the acquired shares were issued on conversion. The remaining acquired shares are
expected to be sold in underwritten offerings during 1998. The Company will
record an expense in the first quarter of 1998 in connection with the redemption
of the Convertible Subordinated Debentures, but such expense is not expected to
be material.
 
                                       14
<PAGE>   17
 
YEAR 2000 TECHNOLOGY ISSUE
Similar to all business entities, the Company will be impacted by the inability
of computer application software programs to distinguish between the year 1900
and 2000 due to a commonly-used programming convention. Unless such programs are
modified or replaced prior to 2000, calculations and interpretations based on
date-based arithmetic or logical operations performed by such programs may be
incorrect.
     Management is continuing to assess the Company's exposure on this issue,
including the impact on software programs and on automated process control
systems used in the operations of the Company's business. Concurrent with this
assessment, the Company is making renovations to its existing software programs
and automated process control systems to become Year 2000 compliant. While the
Company's assessment of its exposure is expected to be completed during 1998,
renovation and replacement of existing programs will continue through 1999. The
Company has budgeted approximately $10.0 million for these Year 2000 compliance
efforts.
     In addition to the activities described above, the Company is currently
replacing many of its financial and operating software programs with new
programs that will be Year 2000 compliant. These new programs have significantly
reduced the costs expected to be incurred to become Year 2000 compliant.
 
PRICE RISK MANAGEMENT ACTIVITIES
In the normal course of business, certain of the nonregulated subsidiary
operations are subject to market risk and credit risk in connection with the
production, purchase and sale of natural gas and oil, purchase and sale of
electricity, and stored gas inventories. In addition, certain of the Company's
activities, including foreign equity investments, are subject to foreign
currency risk. Reference is made to Note 16 to the consolidated financial
statements, page 42, regarding the fair value of the Company's long-term debt
which is comprised of fixed rate instruments.
 
     MARKET RISK
Price risk management activities expose the Company to market risk. Market risk
represents the potential loss that can be caused by the change in market value
of a particular commitment. The Company has appropriate operating procedures in
place that are administered by experienced management to help ensure that proper
internal controls are maintained. In addition, the Company has established an
independent function at the Corporate level to monitor compliance with the price
risk management policies of CNG Energy Services. These policies include
value-at-risk and notional contract and stop loss limit structures designed to
maintain exposure levels within the parameters established by management.
 
     CREDIT RISK
Price risk management activities also expose the Company to credit risk. Credit
risk represents the potential loss that the Company would incur as a result of
nonperformance by counterparties pursuant to the terms of their contractual
obligations. The Company maintains credit policies with regards to its
counterparties that management believes minimize overall credit risk. Such
policies include the evaluation of a prospective counterparty's financial
condition, collateral requirements where deemed necessary, and the use of
standardized agreements which facilitate the netting of cash flows associated
with a single counterparty. The Company also monitors the financial condition of
existing counterparties on an ongoing basis. Considering the system of internal
controls in place and credit reserve levels at December 31, 1997, the Company
believes it is unlikely that a material adverse effect on its financial
position, results of operations or cash flows would occur as a result of
counterparty nonperformance.
     Price risk management activities are conducted by two of the Company's
subsidiaries, CNG Energy Services and CNG Producing.
 
     CNG ENERGY SERVICES
CNG Energy Services engages in wholesale energy marketing activities in the
United States and Canada. It provides energy risk management products and
services to gas and electric utilities, municipals, large industrial end users,
oil and gas producers, and other energy marketers, and to CNG Producing Company
 
                                       15
<PAGE>   18
 
for its production and sale of natural gas. CNG Energy Services uses
over-the-counter (OTC) price swap agreements, exchange-traded futures contracts,
and option contracts to manage market risk inherent in its marketing and energy
risk management activities. The level of market risk exposure from these
activities is maintained within risk management guidelines. CNG Energy Services
also has a foreign currency swap agreement effective through April 2005 to
manage foreign exchange rate risk in connection with the payment of demand
charges for pipeline capacity in Canada.
     Tables disclosing fair value and related information at December 31, 1997
for derivatives that are sensitive to changes in natural gas prices and foreign
exchange rates follow. Net notional quantities are used to calculate the
payments and quantities to be exchanged under the contractual terms of the
futures contracts and swap agreements and are not a measure of the Company's
exposure to the use of these derivatives.
     It should also be noted that the tables do not include information about
CNG Energy Services' natural gas and electricity commodity purchases and sales
commitments which are sensitive to changes in natural gas and electricity
prices, and information related to firm transportation and storage agreements
for which CNG Energy Services must make specified minimum payments each month.
Therefore, the information presented regarding the use of derivatives by CNG
Energy Services does not reflect the earnings impact of the physical
transactions that may offset the financial gains and losses arising from the use
of derivatives.
     The following table presents net notional quantities and weighted average
settlement prices by expected maturity date for futures contracts utilized to
manage natural gas price risk. At December 31, 1997, CNG Energy Services held no
futures contracts with maturity dates extending beyond 2000.
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                                                       Expected Maturity Date              Unrealized
                                                      ------------------------            Gain (Loss)
         Exchange-Traded Futures Contracts             1998     1999     2000    Total    at 12/31/97
-------------------------------------------------------------------------------------------------------
                                                                                         (In Thousands)
<S>                                                   <C>      <C>      <C>      <C>     <C>
Contract volumes (in 10,000 mmbtu), purchased
  (sold)............................................   (537)     144      105    (288)      $(1,090)
Weighted average settlement price (per mmbtu).......  $2.30    $2.35    $2.15
-------------------------------------------------------------------------------------------------------
</TABLE>
 
     The following table presents natural gas price swap information for
agreements in which the Company is obligated to pay or receive a fixed price in
exchange for receiving or paying a variable price at a location, and those in
which the Company pays or receives an amount based on prices at different
locations. At December 31, 1997, CNG Energy Services had not entered into any
price swap agreements extending beyond 2002. The weighted average variable pay
and receive forward prices are based upon quotes obtained from third party
brokers and dealers that are active in the respective markets.
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
          Price Swap Agreements                    Expected Maturity Date
      (Quantities in 10,000 mmbtu)         --------------------------------------              Fair Value
            (Rates per mmbtu)               1998    1999    2000    2001    2002    Total     at 12/31/97
-----------------------------------------------------------------------------------------------------------
                                                                                             (In Thousands)
<S>                                        <C>      <C>     <C>     <C>     <C>     <C>      <C>
Pay Fixed, Receive Variable
Net notional quantities..................  27,840   2,805   1,488     231      90   32,454      $(26,294)
  Weighted average pay rate..............   $0.46   $0.55   $0.30   $1.06   $0.41
  Weighted average receive rate..........   $0.36   $0.58   $0.31   $1.12   $0.47
Receive Fixed, Pay Variable
Net notional quantities..................  25,065   3,628     759     270           29,722      $ 28,749
  Weighted average pay rate..............   $0.53   $0.59   $0.43   $0.37
  Weighted average receive rate..........   $0.65   $0.59   $0.43   $0.34
-----------------------------------------------------------------------------------------------------------
</TABLE>
 
                                       16
<PAGE>   19
 
     The following table presents notional amounts and weighted average exchange
rates, by expected maturity date, for the foreign currency swap agreement:
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                                       Expected Maturity Date
   Foreign Currency Swap     ------------------------------------------                            Fair Value
Pay Fixed, Receive Variable   1998     1999     2000     2001     2002    Thereafter    Total      at 12/31/97
----------------------------------------------------------------------------------------------------------------
                                                                                            (In Thousands)
<S>                          <C>      <C>      <C>      <C>      <C>      <C>          <C>       <C>
Notional amounts
  (US$ In Thousands)......   $5,581   $6,861   $6,789   $6,611   $6,470    $18,679     $50,991       $4,528
Weighted average pay rate
  (US$/Can$)..............     0.71     0.70     0.68     0.67     0.66       0.63        0.66
Weighted average receive
  rate (US$/Can$).........     0.70     0.71     0.72     0.72     0.72       0.73        0.72
----------------------------------------------------------------------------------------------------------------
</TABLE>
 
     Information regarding the fair value of OTC and exchange-traded options
contracts held by CNG Energy Services is not presented at December 31, 1997,
since the use of these derivatives was not significant.
 
     CNG PRODUCING
CNG Producing uses price swap agreements and exchange-traded futures and options
contracts to manage commodity price risk in connection with the production and
sale of crude oil. CNG Producing's price risk management activities related to
the production and sale of natural gas are executed through intercompany
transactions with CNG Energy Services.
     At December 31, 1997, CNG Producing held futures contracts covering the
sale of 1,750,000 barrels of oil with a weighted average settlement price of
$18.24 per barrel and an aggregate unrealized gain of approximately $4.4
million. All of these contracts expire during 1998. These contracts qualify and
have been designated as hedges of crude oil production, with any gains or losses
from market price changes expected to be generally offset by the earnings impact
of the related physical transaction. The fair value of options contracts and
price swap agreements held by CNG Producing at December 31, 1997 is not
presented since the use of these financial instruments was not significant.
 
FORWARD-LOOKING INFORMATION
Certain matters discussed in this Management's Discussion and Analysis of
Financial Condition and Results of Operations and elsewhere herein are
"forward-looking statements" intended to qualify for the safe harbors from
liability established by the Private Securities Litigation Reform Act of 1995.
These forward-looking statements can generally be identified as such because the
context of the statement will include words such as the Company "believes,"
"anticipates," "expects" or words of similar import. Similarly, statements that
describe the Company's future plans, objectives or goals are also
forward-looking statements. Such statements may address future events and
conditions concerning capital expenditures, earnings, risk management,
litigation, rate and other regulatory matters, liquidity and capital resources,
and financial accounting matters. Actual results in each instance could differ
materially from those currently anticipated in such statements, due to factors
such as: natural gas and electric industry restructuring, including ongoing
state and federal activities; the weather; demographics; general economic
conditions and specific economic conditions in the Company's distribution
service areas; developments in the legislative, regulatory and competitive
environment in which the Company operates; and other circumstances affecting
anticipated revenues and costs.
 
SUMMARY OF FINANCIAL DATA
The Company's Summary of Financial Data is on page 18.
 
                                       17
<PAGE>   20
 
SELECTED FINANCIAL DATA
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
SUMMARY OF FINANCIAL DATA (THOUSAND $)      1997       1996(a)      1995(a)        1994         1993
-------------------------------------------------------------------------------------------------------
<S>                                      <C>          <C>          <C>          <C>          <C>
EARNINGS
Gas sales..............................  $4,190,158   $2,844,709   $2,595,103   $2,402,861   $2,615,036
Electricity sales, gas transportation,
  storage and other....................   1,519,862      949,600      712,222      633,167      569,049
     Total operating revenues..........   5,710,020    3,794,309    3,307,325    3,036,028    3,184,085
Purchased gas..........................   2,960,204    1,614,983    1,590,137    1,424,020    1,594,373
Electricity, liquids and capacity
  purchased............................     869,670      346,747      153,577      107,094       79,001
Operation and maintenance..............     798,620      789,356()    739,612()    689,575      677,666
Depreciation and amortization..........     330,144      304,171      256,636      279,317      294,648
Impairment of gas and oil producing
  properties...........................      10,351           --      226,209           --           --
Taxes, other than income taxes.........     195,845      191,078      191,698      192,617      181,053
     Operating income before
       income taxes....................     545,186      547,974      149,456      343,405      357,344
Income taxes...........................     147,053      155,830        2,943       82,427       99,906
Other income-net.......................      13,516        9,304       10,760        9,694       10,531
Write-down of coal properties..........          --           --       31,266           --           --
Interest charges.......................     107,269      103,175      104,663       87,501       79,475
Income before change in accounting
  principle............................     304,380      298,273       21,344      183,171      188,494
Cumulative effect of applying SFAS No.
  109..................................          --           --           --           --       17,422
     Net income........................     304,380      298,273       21,344      183,171      205,916
Earnings per common share--basic(b)
     Income before change in accounting
       principle.......................       $3.21        $3.17         $.23        $1.97        $2.03
     Cumulative effect of applying SFAS
       No. 109.........................          --           --           --           --          .19
     Net income........................       $3.21        $3.17         $.23        $1.97        $2.22
Earnings per common share--diluted(b)
     Income before change in accounting
       principle.......................       $3.15        $3.13         $.23        $1.97        $2.02
     Cumulative effect of applying SFAS
       No. 109.........................          --           --           --           --          .19
     Net income........................       $3.15        $3.13         $.23        $1.97        $2.21
Return on average stockholders'
  equity...............................       13.3%        14.0%         1.0%         8.4%         9.6%
Times fixed charges earned.............        4.59         4.76         1.21         3.53         3.95
-------------------------------------------------------------------------------------------------------
DIVIDENDS--CASH
Paid per common share..................       $1.94        $1.94        $1.94        $1.94        $1.92
     Payout ratio......................       60.4%        61.2%       843.5%        98.5%        86.5%
Declared per common share..............       $1.94        $1.94        $1.94        $1.94       $1.925
-------------------------------------------------------------------------------------------------------
ASSETS
Total assets...........................  $6,313,694   $6,000,605   $5,418,293   $5,518,673   $5,437,188
Property, plant and equipment
     Total investment..................   8,714,758    8,304,205    7,929,350    7,676,956    7,346,028
     Accumulated depreciation..........   4,491,955    4,226,905    4,016,945    3,650,310    3,429,760
Capital expenditures and
  acquisitions.........................     609,373      560,293      439,393      437,785      342,569
-------------------------------------------------------------------------------------------------------
CAPITAL STRUCTURE
Total common stockholders' equity......  $2,358,318   $2,205,152   $2,045,818   $2,184,334   $2,176,432
Long-term debt.........................   1,552,890    1,426,315    1,291,811    1,151,973    1,158,648
                                         ----------   ----------   ----------   ----------   ----------
     Total capitalization..............  $3,911,208   $3,631,467   $3,337,629   $3,336,307   $3,335,080
                                         ==========   ==========   ==========   ==========   ==========
Long-term debt ratio...................       39.7%        39.3%        38.7%        34.5%        34.7%
Shares outstanding at year-end.........  95,622,622   94,933,631   93,591,623   93,027,847   92,933,828
Common stockholders' equity per
  share................................      $24.66       $23.23       $21.86       $23.48       $23.42
</TABLE>
 
--------------------------------------------------------------------------------
(a) Certain amounts and ratios are not comparable with prior years due to
    special charges.
(b) Prior year per share amounts have been restated in conformity with SFAS No.
    128.
--------------------------------------------------------------------------------
 
                                       18
<PAGE>   21
 
                       REPORT OF INDEPENDENT ACCOUNTANTS
 
To the Board of Directors and Stockholders of
Consolidated Natural Gas Company
 
In our opinion, the consolidated financial statements appearing on pages 21
through 52 of this Appendix I to the proxy statement for the 1998 annual meeting
of stockholders present fairly, in all material respects, the financial position
of Consolidated Natural Gas Company and subsidiaries (collectively, the Company)
at December 31, 1997 and 1996, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 1997, in
conformity with generally accepted accounting principles. These financial
statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
generally accepted auditing standards which require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for the opinion expressed
above.
 
PRICE WATERHOUSE LLP
 
600 Grant Street
Pittsburgh, Pennsylvania 15219-9954
February 17, 1998
 
                                       19
<PAGE>   22
 
                    (THIS PAGE WAS INTENTIONALLY LEFT BLANK)
 
                                       20
<PAGE>   23
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
            FOR THE YEARS ENDED DECEMBER 31,                 1997         1996         1995
----------------------------------------------------------------------------------------------
                                                                 (Thousands of Dollars)
<S>                                                       <C>          <C>          <C>
OPERATING REVENUES
Regulated gas sales.....................................  $1,851,001   $1,752,223   $1,597,379
Nonregulated gas sales..................................   2,339,157    1,092,486      997,724
                                                          ----------   ----------   ----------
     Total gas sales....................................   4,190,158    2,844,709    2,595,103
Gas transportation and storage..........................     479,505      465,110      456,370
Electricity sales.......................................     594,532      109,446       21,768
Other...................................................     445,825      375,044      234,084
                                                          ----------   ----------   ----------
     Total operating revenues (Note 3)..................   5,710,020    3,794,309    3,307,325
                                                          ----------   ----------   ----------
OPERATING EXPENSES
Purchased gas...........................................   2,960,204    1,614,983    1,590,137
Electricity, liquids and capacity purchased.............     869,670      346,747      153,577
Operation expense (Note 5)..............................     708,012      699,289      653,731
Maintenance.............................................      90,608       90,067       85,881
Depreciation and amortization (Note 4)..................     330,144      304,171      256,636
Impairment of gas and oil producing properties (Note
  4)....................................................      10,351           --      226,209
Taxes, other than income taxes..........................     195,845      191,078      191,698
                                                          ----------   ----------   ----------
     Subtotal...........................................   5,164,834    3,246,335    3,157,869
                                                          ----------   ----------   ----------
     Operating income before income taxes...............     545,186      547,974      149,456
Income taxes (Note 8)...................................     147,053      155,830        2,943
                                                          ----------   ----------   ----------
     Operating income...................................     398,133      392,144      146,513
                                                          ----------   ----------   ----------
OTHER INCOME (DEDUCTIONS)
Interest revenues.......................................       2,178        2,281        9,095
Write-down of coal properties (Note 4)..................          --           --      (31,266)
Other-net...............................................      11,338        7,023        1,665
                                                          ----------   ----------   ----------
     Total other income (deductions)....................      13,516        9,304      (20,506)
                                                          ----------   ----------   ----------
     Income before interest charges.....................     411,649      401,448      126,007
                                                          ----------   ----------   ----------
INTEREST CHARGES
Interest on long-term debt..............................     104,927      101,814       95,823
Other interest expense..................................       9,116        7,224       14,732
Allowance for funds used during construction............      (6,774)      (5,863)      (5,892)
                                                          ----------   ----------   ----------
     Total interest charges.............................     107,269      103,175      104,663
                                                          ----------   ----------   ----------
NET INCOME..............................................  $  304,380   $  298,273   $   21,344
                                                          ==========   ==========   ==========
     Earnings per common share--basic (Note 2)..........       $3.21        $3.17         $.23
     Earnings per common share--diluted (Note 2)........       $3.15        $3.13         $.23
</TABLE>
 
--------------------------------------------------------------------------------
The Notes to Consolidated Financial Statements are an integral part of this
statement.
 
                                       21
<PAGE>   24
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                      AT DECEMBER 31,                            1997          1996
---------------------------------------------------------------------------------------
                                                               (Thousands of Dollars)
<S>                                                           <C>           <C>
ASSETS
 
PROPERTY, PLANT AND EQUIPMENT (Note 4)
Gas utility and other plant.................................  $ 5,004,139   $ 4,848,392
Accumulated depreciation and amortization...................   (1,949,483)   (1,840,129)
                                                              -----------   -----------
     Net gas utility and other plant........................    3,054,656     3,008,263
                                                              -----------   -----------
Exploration and production properties.......................    3,710,619     3,455,813
Accumulated depreciation and amortization...................   (2,542,472)   (2,386,776)
                                                              -----------   -----------
     Net exploration and production properties..............    1,168,147     1,069,037
                                                              -----------   -----------
     Net property, plant and equipment......................    4,222,803     4,077,300
                                                              -----------   -----------
 
CURRENT ASSETS
Cash and temporary cash investments.........................       65,035        44,524
Accounts receivable
  Customers.................................................      804,015       647,207
  Unbilled revenues and other...............................      176,787       161,525
  Allowance for doubtful accounts...........................      (29,590)      (15,167)
Inventories, at cost
  Gas stored--current portion (Note 9)......................      139,157       170,513
  Materials and supplies (average cost method)..............       30,256        33,070
Unrecovered gas costs (Note 3)..............................       55,062       108,016
Prepayments and other current assets........................      212,919       243,333
                                                              -----------   -----------
     Total current assets...................................    1,453,641     1,393,021
                                                              -----------   -----------
 
REGULATORY AND OTHER ASSETS
Other investments...........................................      223,900       149,858
Deferred charges and other assets (Notes 3, 5, 6, 7, 8, 10
  and 17)...................................................      413,350       380,426
                                                              -----------   -----------
     Total regulatory and other assets......................      637,250       530,284
                                                              -----------   -----------
     Total assets...........................................  $ 6,313,694   $ 6,000,605
                                                              ===========   ===========
</TABLE>
 
--------------------------------------------------------------------------------
The Notes to Consolidated Financial Statements are an integral part of this
statement.
 
                                       22
<PAGE>   25
 
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                      AT DECEMBER 31,                            1997          1996
---------------------------------------------------------------------------------------
                                                               (Thousands of Dollars)
<S>                                                           <C>           <C>
STOCKHOLDERS' EQUITY AND LIABILITIES
CAPITALIZATION
Common stockholders' equity (Note 11)
  Common stock, par value $2.75 per share
     Authorized-- 400,000,000 shares
     Issued, 1997--95,623,281 shares, 1996--94,933,631
     shares.................................................  $   262,964   $   261,068
  Capital in excess of par value............................      566,755       537,002
  Retained earnings (Note 13)...............................    1,539,587     1,424,624
  Treasury stock, at cost (1997--659 shares)................          (38)           --
  Unearned compensation.....................................      (10,950)      (17,542)
                                                              -----------   -----------
     Total common stockholders' equity......................    2,358,318     2,205,152
Long-term debt (Note 14)....................................    1,552,890     1,426,315
                                                              -----------   -----------
     Total capitalization...................................    3,911,208     3,631,467
                                                              -----------   -----------
CURRENT LIABILITIES
Current maturities on long-term debt........................      154,000       104,000
Commercial paper (Note 15)..................................      238,700       374,000
Accounts payable............................................      651,365       535,296
Estimated rate contingencies and refunds (Note 3)...........       29,112        21,602
Amounts payable to customers................................          880            --
Taxes accrued...............................................      125,056        97,336
Deferred income taxes--current (net) (Note 8)...............       13,735        36,096
Dividends declared..........................................       46,377        46,043
Other current liabilities...................................      127,016       150,047
                                                              -----------   -----------
     Total current liabilities..............................    1,386,241     1,364,420
                                                              -----------   -----------
DEFERRED CREDITS
Deferred income taxes (Note 8)..............................      712,118       681,334
Accumulated deferred investment tax credits.................       26,658        28,838
Deferred credits and other liabilities (Notes 3, 6, 7 and
  8)........................................................      277,469       294,546
                                                              -----------   -----------
     Total deferred credits.................................    1,016,245     1,004,718
                                                              -----------   -----------
COMMITMENTS AND CONTINGENCIES (Note 18)
                                                              -----------   -----------
     Total stockholders' equity and liabilities.............  $ 6,313,694   $ 6,000,605
                                                              ===========   ===========
</TABLE>
 
--------------------------------------------------------------------------------
 
                                       23
<PAGE>   26
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
              FOR THE YEARS ENDED DECEMBER 31,                      1997                1996                1995
-----------------------------------------------------------------------------------------------------------------------
                                                                               (Thousands of Dollars)
<S>                                                           <C>                 <C>                 <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income..................................................      $ 304,380           $ 298,273           $  21,344
Adjustments to reconcile net income to net cash provided by
  operating activities
    Depreciation and amortization...........................        330,144             304,171             256,636
    Impairment of gas and oil producing properties..........         10,351                  --             226,209
    Write-down of coal properties...........................             --                  --              31,266
    Pension cost (credit)...................................        (49,841)            (28,604)              7,105
    Stock award amortization................................          9,620               8,436                 620
    Deferred income taxes-net...............................          1,881              63,230             (48,767)
    Investment tax credit...................................         (2,193)             (2,201)             (2,198)
    Changes in current assets and current liabilities
       Accounts receivable-net..............................       (160,887)           (139,179)           (116,529)
       Inventories..........................................         34,170             (55,339)             77,024
       Unrecovered gas costs................................         52,954             (82,893)            (11,988)
       Accounts payable.....................................        119,625              94,131              69,761
       Estimated rate contingencies and refunds.............          7,510             (37,761)            (24,041)
       Amounts payable to customers.........................            880             (40,315)            (55,825)
       Taxes accrued........................................         27,720             (16,999)             19,922
       Other-net............................................          6,984              (6,006)             13,643
    Changes in other assets and other liabilities...........         48,880              48,473              84,828
    Other-net...............................................            (70)               (252)              3,714
                                                                  ---------           ---------           ---------
       Net cash provided by operating activities............        742,108             407,165             552,724
                                                                  ---------           ---------           ---------
CASH FLOWS USED IN INVESTING ACTIVITIES
Plant construction and other property additions.............       (520,961)           (439,489)           (434,739)
Proceeds from dispositions of property, plant and
  equipment-net.............................................          1,056               9,079              14,066
Cost of other investments-net...............................        (86,763)            (87,735)             (7,464)
                                                                  ---------           ---------           ---------
       Net cash used in investing activities................       (606,668)           (518,145)           (428,137)
                                                                  ---------           ---------           ---------
CASH FLOWS PROVIDED BY (OR USED IN) FINANCING ACTIVITIES
Issuance of common stock....................................         28,722              37,726              19,058
Issuance of debentures......................................        294,945             299,567             148,899
Repayments of long-term debt................................       (119,625)            (72,750)             (4,000)
Commercial paper-net........................................       (134,368)             37,853            (103,399)
Dividends paid..............................................       (184,608)           (183,020)           (180,782)
Other-net...................................................              5                (149)                 (9)
                                                                  ---------           ---------           ---------
       Net cash provided by (or used in) financing
       activities...........................................       (114,929)            119,227            (120,233)
                                                                  ---------           ---------           ---------
       Net increase in cash and temporary cash
       investments..........................................         20,511               8,247               4,354
CASH AND TEMPORARY CASH INVESTMENTS AT JANUARY 1............         44,524              36,277              31,923
                                                                  ---------           ---------           ---------
CASH AND TEMPORARY CASH INVESTMENTS AT DECEMBER 31..........      $  65,035           $  44,524           $  36,277
                                                                  =========           =========           =========
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for
    Interest (net of amounts capitalized)...................      $ 114,314           $ 109,602           $ 102,663
    Income taxes (net of refunds)...........................      $ 126,372           $ 108,742           $  58,949
Non-cash financing activities
    Issuance of common stock under benefit plans............      $   2,742           $  25,570           $   1,121
    Conversion of 7 1/4% Convertible Subordinated
      Debentures............................................      $      40           $      --           $      --
</TABLE>
 
--------------------------------------------------------------------------------
The Notes to Consolidated Financial Statements are an integral part of this
statement.
 
                                       24
<PAGE>   27
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
Methods of allocating costs to accounting periods by the subsidiaries subject to
federal or state accounting and rate regulation may differ from methods
generally applied by nonregulated companies. However, when the accounting
allocations prescribed by regulatory authorities are used for ratemaking, the
economic effects thereof determine the application of generally accepted
accounting principles. Significant accounting policies of Consolidated Natural
Gas Company (the Parent Company) and subsidiaries (collectively, the Company)
within this framework are summarized in this Note.
 
USE OF ESTIMATES
The consolidated financial statements reflect certain estimates and assumptions
made by management that affect the reported amounts of assets and liabilities,
the disclosure of contingent assets and liabilities at the date of the financial
statements, and the reported amounts of revenues and expenses for the periods
presented.
 
PRINCIPLES OF CONSOLIDATION
The Parent Company owns all of the capital stock of its subsidiaries. The
consolidated financial statements represent the accounts of the Company after
the elimination of intercompany transactions.
     The Company follows the equity method of accounting for investments in
partnerships and corporate joint ventures when the Company is able to influence
the financial and operating policies of the investee. For all other investments,
the cost method is applied.
 
REVENUE RECOGNITION
Revenues from sales and transportation services are recognized in the same
period in which the related volumes are delivered to customers. The Company
bills and recognizes sales revenues from residential and certain commercial and
industrial customers on the basis of scheduled meter readings. In addition,
revenues are recorded for estimated deliveries of gas to these customers from
the meter reading date to the end of the accounting period. For wholesale and
other commercial and industrial customers, revenues are based upon actual
deliveries to the end of the period.
 
UNRECOVERED GAS COSTS
Where permitted by regulatory authorities, the Company defers the difference
between the cost of gas (including certain related costs) and the amount of such
costs included in current rates. The differences are accounted for as either
unrecovered gas costs or amounts payable to customers. Unrecovered amounts are
recognized as purchased gas costs in future periods when the costs are recovered
through adjusted rates.
 
PRICE RISK MANAGEMENT ACTIVITIES
In the normal course of business, certain of the nonregulated subsidiaries
utilize derivative financial instruments and derivative commodity instruments to
manage exposure to price risk in connection with the production, purchase and
sale of natural gas and oil, purchase and sale of electricity, and for stored
gas inventories. Derivative financial instruments are also used to manage
foreign currency risk in connection with certain contractual commitments. The
derivatives utilized by the subsidiaries include exchange-traded futures and
options contracts, which permit settlement by physical delivery of the
commodity, and OTC commodity price swap agreements, OTC foreign currency swap
agreements and OTC options which require settlement in cash.
     For derivatives that qualify (based on correlation to price movements of
gas and oil) and are designated as hedges, related gains or losses are deferred
and subsequently recognized in income, as revenues or expense, in the same
period the hedged transaction occurs. The value of derivatives that do not
qualify for hedge accounting treatment are marked-to-market each period, with
gains and losses recognized in the
 
                                       25
<PAGE>   28
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
operating income of that period. The market prices used to value these
derivatives are based on closing prices quoted by an exchange and OTC quotations
when exchange quotes are not available.
     Under the OTC price swap agreements, the subsidiaries make payments to, or
receive payments from, counterparties generally based on the difference between
fixed and variable gas and oil prices or on prices at different receipt points
as specified in the contracts. Under foreign currency swap agreements, payments
are made to, or received from, counterparties generally based on the difference
in the current foreign exchange rate. Settlement takes place under the swap
agreements on a monthly basis for the portion of the swap that has expired, and
amounts received or paid are recognized as an adjustment to gas and oil sales
revenues, purchased gas expense or transport capacity costs in the applicable
settlement month.
     Margin accounts for open futures contracts are recorded in the Consolidated
Balance Sheet under "Prepayments and other current assets." Deferred losses or
gains are reflected in the Consolidated Balance Sheet under "Prepayments and
other current assets" and "Other current liabilities," respectively. Cash flows
from price risk management activities are reported in the Consolidated Statement
of Cash Flows as an operating activity--consistent with the category of the cash
flows from the underlying physical transaction.
 
PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION
 
     GAS UTILITY AND OTHER PLANT
The property, plant and equipment accounts are stated at the cost incurred or,
where required by regulatory authorities, "original cost." Additions and
betterments are charged to the property accounts at cost. Upon normal retirement
of a plant asset, its cost is charged to accumulated depreciation together with
costs of removal less salvage. The costs of maintenance, repairs and replacing
minor items are charged principally to expense as incurred.
 
     EXPLORATION AND PRODUCTION PROPERTIES
CNG Producing and CNG Transmission follow the full cost method of accounting for
gas and oil producing activities prescribed by the SEC. Under the full cost
method, all costs directly associated with property acquisition, exploration,
and development activities are capitalized, with the principal limitation that
such amounts not exceed the present value of estimated future net revenues to be
derived from the production of proved gas and oil reserves. If net capitalized
costs exceed the estimated value at the end of any quarterly period, then a
permanent write-down of the assets must be recognized in that period. The
limitation test is performed separately for each cost center, with cost centers
established on a country-by-country basis.
     The gas producing activities of Peoples Natural Gas are subject to
cost-of-service rate regulation and are exempt from the accounting methods
prescribed by the SEC.
 
     DEPRECIATION AND AMORTIZATION
Depreciation and amortization are recorded over the estimated service lives of
plant assets by application of the straight-line method or, in the case of gas
and oil producing properties, the unit-of-production method.
     Under the full cost method of accounting, amortization is also accrued on
estimated future costs to be incurred in developing proved gas and oil reserves,
and on estimated dismantlement and abandonment costs net of projected salvage
values. However, the costs of investments in unproved properties and major
development projects are excluded from amortization until it is determined
whether or not proved reserves are attributable to such properties.
 
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
The subsidiaries subject to cost-of-service rate regulation capitalize the
estimated costs of funds used during the construction of major projects. Under
regulatory practices, those companies are permitted to include the costs
capitalized in rate base for rate-making purposes when the completed facilities
are placed in
 
                                       26
<PAGE>   29
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
service. The remaining subsidiaries capitalize interest costs as part of the
cost of acquiring certain assets. Generally, interest is capitalized on unproved
properties and major construction and development projects on which amortization
is not yet being recognized.
     In determining the allowance for funds used during construction, the
following ranges of rates reflect the pretax cost of borrowed funds used to
finance construction expenditures: 1997--5 5/8% to 7 5/8%; 1996--5 1/2% to 8
1/8% and 1995--5 3/4% to 8 3/8%. Equity funds capitalized in those years were
not significant.
 
INCOME TAXES
The current provision for income taxes represents amounts paid or currently
payable. Investment tax credits which were required to be deferred by regulatory
authorities are being amortized as credits to income over the estimated service
lives of the related properties.
 
PENSION AND OTHER BENEFIT PROGRAMS
 
     PENSION PROGRAM
The Company has qualified noncontributory defined benefit pension plans covering
substantially all employees. Benefits payable under the plans are based
primarily on each employee's years of service, age and base salary during the
five years prior to retirement. Net pension costs are determined by an
independent actuary, and the plans are funded on an annual basis to the extent
such funding is deductible under federal income tax regulations. Plan assets
consist primarily of equity securities, fixed income securities and insurance
contracts. The pension program also includes the payment of supplemental pension
benefits to certain retirees depending on retirement dates, and the payment of
benefits to certain retired executives under company-sponsored nonqualified
employee benefit plans. Certain of these nonqualified benefit plans are funded
through contributions to a grantor trust.
 
     OTHER POSTRETIREMENT BENEFITS
In addition to pension plans, the Company sponsors defined benefit
postretirement plans covering both salaried and hourly employees and certain
dependents. The plans provide medical benefits as well as life insurance
coverage. These benefits are provided through insurance companies and other
providers with the annual cash outlays based on the claim experience of the
related plans.
     Employees who retire on or after attaining age 55 and having rendered at
least 15 years of service, or employees retiring on or after attaining age 65,
are eligible to receive benefits under the plans. The plans are both
contributory and noncontributory, depending on age, retirement date, the plan
elected by the employee, and whether the employee is covered under a collective
bargaining agreement. Most of the medical plans contain cost-sharing features
such as deductibles and coinsurance. For certain of the contributory medical
plans, retiree contributions are adjusted annually.
 
ENVIRONMENTAL EXPENDITURES
Environmental-related expenditures associated with current operations are
generally expensed as incurred. Expenditures for the assessment and/or
remediation of environmental conditions related to past operations are charged
to expense or are deferred pending probable recovery in future rate-making
proceedings. In this connection, a liability is recognized when the assessment
or remediation effort is probable and the future costs are estimable. Estimated
future costs for the abandonment and restoration of gas and oil properties are
accrued currently through charges to depreciation.
     Claims for recovery of environmental-related costs from insurance carriers
and other third parties or through regulatory procedures are recognized
separately as assets when future recovery is considered probable.
 
                                       27
<PAGE>   30
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
TEMPORARY CASH INVESTMENTS
Temporary cash investments consist of short-term, highly liquid investments that
are readily convertible to cash and present no significant interest rate risk.
For purposes of the Consolidated Statement of Cash Flows, temporary cash
investments are considered to be cash equivalents.
 
2.  EARNINGS PER SHARE
 
In February 1997, the FASB issued SFAS No. 128, "Earnings per Share," which
establishes new requirements for computing and presenting earnings per share.
The Company has adopted the provisions of SFAS No. 128 for the year ended
December 31, 1997, and has restated earnings per share amounts for all prior
annual and quarterly periods presented as required by the new standard. The
adoption of SFAS No. 128 did not have a material effect on the Company's
earnings per share for any of the periods presented.
     A reconciliation of the income and common stock share amounts used in the
calculation of basic and diluted earnings per share (EPS) for each of the years
ended December 31, 1997, 1996 and 1995 follows (net income and share amounts in
thousands):
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                                                                                     Per Share
                                                              Net Income   Shares     Amount
----------------------------------------------------------------------------------------------
<S>                                                           <C>          <C>       <C>
For the year ended December 31, 1997
BASIC EPS...................................................   $304,380     94,868     $3.21
                                                               ========    =======     =====
Effect of dilutive securities:
     Exercise of stock options..............................                   674
     Vesting of performance shares..........................                   359
     Conversion of 7 1/4% Convertible Subordinated
       Debentures...........................................     12,128      4,559
                                                               --------    -------
DILUTED EPS.................................................   $316,508    100,460     $3.15
                                                               ========    =======     =====
----------------------------------------------------------------------------------------------
For the year ended December 31, 1996
BASIC EPS...................................................   $298,273     94,076     $3.17
                                                               ========    =======     =====
Effect of dilutive securities:
     Exercise of stock options..............................                   482
     Vesting of performance shares..........................                    98
     Conversion of 7 1/4% Convertible Subordinated
       Debentures...........................................     11,823      4,559
                                                               --------    -------
DILUTED EPS.................................................   $310,096     99,215     $3.13
                                                               ========    =======     =====
----------------------------------------------------------------------------------------------
For the year ended December 31, 1995
BASIC EPS...................................................   $ 21,344     93,246     $ .23
                                                               ========    =======     =====
Effect of dilutive securities:
     Exercise of stock options..............................                    67
                                                               --------    -------
DILUTED EPS.................................................   $ 21,344     93,313     $ .23
                                                               ========    =======     =====
----------------------------------------------------------------------------------------------
</TABLE>
 
     Performance shares are considered contingent shares as defined by SFAS No.
128. Although such shares are issued and outstanding, they are excluded from the
calculation of basic earnings per share.
 
3.  RATE MATTERS
 
The Company accounts for its regulated operations in accordance with SFAS No.
71, "Accounting for the Effects of Certain Types of Regulation." When the
accounting allocations prescribed by regulatory authorities are used for
ratemaking, the allocation of costs among accounting periods by the Company's
regulated
 
                                       28
<PAGE>   31
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
subsidiaries resulted in the recognition of regulatory assets and liabilities at
December 31, 1997 and 1996 as follows:
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                        DECEMBER 31,                               1997              1996
-----------------------------------------------------------------------------------------------
                                                                       (In Thousands)
<S>                                                           <C>               <C>
Regulatory assets:
     Unrecovered gas costs (Note 1).........................     $ 55,062          $108,016
     Order 636 transition costs (Note 3)....................       17,020            27,727
     Workforce reduction costs (Note 5).....................        8,832            11,139
     Other postretirement benefits (Note 7).................       55,070            58,966
     Deferred income taxes (Note 8).........................      103,323           101,825
     Abandoned facilities (Note 10).........................        2,271            15,791
     Environmental-related expenditures (Note 17)...........        7,322            11,047
     Other..................................................       16,944            21,357
                                                                 --------          --------
           Total regulatory assets..........................     $265,844          $355,868
                                                                 ========          ========
Regulatory liabilities:
     Amounts payable to customers (Note 1)..................     $    880          $     --
     Estimated rate contingencies and refunds (Note 3)......       29,112            21,602
     Income taxes refundable to customers-net (Note 8)......       55,035            57,867
                                                                 --------          --------
           Total regulatory liabilities.....................     $ 85,027          $ 79,469
                                                                 ========          ========
</TABLE>
 
--------------------------------------------------------------------------------
 
     The Company assesses on an ongoing basis the recoverability of costs
recognized as regulatory assets and its ability to continue to apply SFAS No. 71
to its regulated operations. In the event that all or a portion of the Company's
regulated operations ceased to meet the requirements of SFAS No. 71, the Company
would be required to assess the carrying value of certain assets and liabilities
previously subject to regulation.
 
ESTIMATED RATE CONTINGENCIES AND REFUNDS
Certain increases in prices by the Company and other rate-making issues are
subject to final modification in regulatory proceedings. The related accumulated
provisions pertaining to these matters were $15.7 million and $6.9 million at
December 31, 1997 and 1996, including interest. These amounts are reported in
the Consolidated Balance Sheet under "Estimated rate contingencies and refunds"
together with $13.4 million and $14.7 million, respectively, which are primarily
refunds received from suppliers and refundable to customers under regulatory
procedures.
 
ORDER 636 TRANSITION COSTS
The distribution subsidiaries have incurred or are expected to incur obligations
to upstream pipeline companies for costs resulting from the pipeline companies'
transition to restructured services under FERC Order 636. The total estimated
liability for such costs was $17.0 million and $27.7 million at December 31,
1997 and 1996, respectively. Additional amounts may be accrued in the future if
the pipeline companies receive final FERC approval to recover such costs. Based
on management's current estimates, the distribution subsidiaries' portion of
such additional costs is not expected to be material. Due to regulatory actions
in two jurisdictions and the past rate-making treatment of similar costs in the
other jurisdictions, management believes that the distribution subsidiaries
should generally be able to pass through all Order 636 transition costs to their
customers.
 
                                       29
<PAGE>   32
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
4.  PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION
 
IMPAIRMENTS OF GAS AND OIL PRODUCING PROPERTIES
As described in Note 1, certain of the subsidiaries follow the full cost method
of accounting for gas and oil producing activities as prescribed by the SEC.
Under these rules, at December 31, 1997, the Company recognized an impairment of
its Canadian oil producing properties due primarily to the decline in market
prices for heavy oil production. This non-cash charge amounted to $10.4 million
and reduced 1997 net income by $6.7 million, or $.07 per share.
     The Company recognized an impairment of its United States gas and oil
producing properties at March 31, 1995, due primarily to the decline in gas
wellhead prices. The non-cash charge amounted to $226.2 million and reduced 1995
net income by $145.0 million, or $1.56 per share.
 
DEPRECIATION AND AMORTIZATION
Amortization of capitalized costs under the full cost method of accounting for
the Company's exploration and production operations amounted to $.88 per Mcf
equivalent of gas and oil produced in 1997, $.93 in 1996, and $.98 in 1995.
     Costs of unproved properties capitalized under the full cost method of
accounting that are excluded from amortization at December 31, 1997, and the
years in which such excluded costs were incurred, follow:
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                                                              Incurred in Years Ended December 31,
                                              DECEMBER 31,   ---------------------------------------
                                                  1997         1997       1996      1995      Prior
----------------------------------------------------------------------------------------------------
                                                                  (In Thousands)
<S>                                           <C>            <C>        <C>        <C>       <C>
Property acquisition costs..................    $48,975      $37,858    $ 5,855    $2,753    $2,509
Exploration costs...........................     41,366       29,682      3,826     4,654     3,204
Capitalized interest........................      6,925        2,458      1,098     1,461     1,908
                                                -------      -------    -------    ------    ------
     Total..................................    $97,266      $69,998    $10,779    $8,868    $7,621
                                                =======      =======    =======    ======    ======
</TABLE>
 
--------------------------------------------------------------------------------
 
     There are no significant properties, as defined by the SEC, excluded from
amortization at December 31, 1997. As gas and oil reserves are proved through
drilling or as properties are judged to be impaired, excluded costs and any
related reserves are transferred on an ongoing, well-by-well basis into the
amortization calculation.
 
WRITE-DOWN AND SUBSEQUENT SALE OF COAL PROPERTIES
In early 1995, the Company initiated an evaluation of the possible disposition
of the coal reserves and related properties owned by CNG Coal. A property
appraisal was completed by an independent geological firm, which indicated that
a write-down was warranted. Accordingly, the cost of these properties was
written down in 1995 resulting in a pretax charge amounting to $31.3 million.
This charge reduced 1995 net income by $20.3 million, or 22 cents per share, but
had no effect on the Company's cash flow. In 1996, CNG Coal completed the sale
of its coal properties to a subsidiary of Cyprus Amax Minerals Company. The
proceeds from the sale approximated the remaining book value of the properties.
 
5.  WORKFORCE REDUCTION COSTS
 
During 1996, unions at two subsidiaries implemented a workforce reduction
program that consisted of a voluntary early retirement program and a voluntary
separation program. The early retirement incentives were similar to those
offered by the Company during 1995. The early retirement program was offered
from February 1 through March 31, 1996, with eligible employees retiring
effective April 1, 1996. The voluntary separation program involved severance
benefit payments to affected employees. A separate voluntary early
 
                                       30
<PAGE>   33
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
retirement program for West Ohio Gas (now a division of East Ohio Gas) was
offered from October 1 through November 29, 1996, with eligible employees
retiring effective December 1, 1996. The program included early retirement
incentives similar to those offered previously at other subsidiaries.
     Workforce reduction programs implemented during 1995 consisted of a
voluntary early retirement program and an involuntary separation program. The
early retirement incentives included five additional years of age and service
for determining pension benefits and were offered at seven subsidiaries during
1995. Eligible employees at each subsidiary were required to retire before
December 31, 1995. The involuntary separation program involved severance benefit
payments to affected employees.
     During 1996 and 1995, a total of 119 and 571 eligible employees,
respectively, elected to accept the early retirement offer and an additional 57
and 217, respectively, were separated from the Company in conjunction with these
workforce reduction programs. In addition, during the fourth quarter of 1996 the
Company recorded a provision for severance and related benefits to be paid to
affected employees in connection with the Company's efforts to combine and
streamline certain business functions. As a result of these workforce reduction
programs, the Company recorded charges to "Operation expense" in the 1996 and
1995 Consolidated Statements of Income amounting to $15.2 million and $42.6
million, respectively. These charges reduced 1996 and 1995 net income by $9.9
million, or 10 cents per share, and $25.6 million, or 27 cents per share,
respectively. The portion of the 1996 charges recognized in the fourth quarter
amounted to $11.8 million and reduced net income for the quarter by $7.8
million, or 8 cents per share. In addition, certain of the regulated
subsidiaries have deferred, as a regulatory asset, a portion of their workforce
reduction costs pending recovery in future rates. The balance of these deferrals
was $8.8 million at December 31, 1997. The total workforce reduction costs
include the impact of curtailment accounting for the pension and postretirement
benefit plans. Details of the costs incurred during 1996 and 1995 are shown in
the following table.
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                                                 1996                                  1995
                                    -------------------------------       -------------------------------
                                     Amounts     Amounts     Total         Amounts     Amounts     Total
                                    Expensed    Deferred     Costs        Expensed    Deferred     Costs
---------------------------------------------------------------------------------------------------------
                                                               (In Thousands)
<S>                                 <C>         <C>         <C>           <C>         <C>         <C>
Pension and nonqualified
  benefit plans:
     Special termination
        benefits..................   $ 4,436       $--      $ 4,436        $30,284     $ 6,893    $37,177
     Curtailment gain-net.........      (792)       --         (792)        (5,891)       (277)    (6,168)
Postretirement benefit plans:
     Special termination
        benefits..................        --        --           --          1,086          62      1,148
     Curtailment loss-net.........     1,292        --        1,292          6,008       9,656     15,664
Severance and other...............    10,259        91       10,350         11,068          45     11,113
                                     -------       ---      -------        -------     -------    -------
     Total........................   $15,195       $91      $15,286        $42,555     $16,379    $58,934
                                     =======       ===      =======        =======     =======    =======
---------------------------------------------------------------------------------------------------------
</TABLE>
 
                                       31
<PAGE>   34
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
6.  PENSION COSTS
 
Net pension cost, as determined by an independent actuary, included the
following components:
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                YEARS ENDED DECEMBER 31,                         1997                1996                1995
--------------------------------------------------------------------------------------------------------------------
                                                                                (In Thousands)
<S>                                                        <C>                 <C>                 <C>
Service cost--benefits earned during the period..........      $  21,374           $  23,741           $  23,741
Interest cost on projected benefit obligation............         68,635              67,426              62,125
Return on plan assets....................................       (330,296)           (205,481)           (265,460)
Net amortization and deferral............................        194,419              86,522             162,002
Curtailment and special termination benefits.............             --               3,644              24,393
Special voluntary retirement programs....................            800                 800                 800
                                                               ---------           ---------           ---------
     Net pension cost (or credit)........................      $ (45,068)          $ (23,348)          $   7,601
                                                               =========           =========           =========
</TABLE>
 
--------------------------------------------------------------------------------
     The following table sets forth the funded status of the plans, as
determined by an independent actuary, at December 31, 1997 and 1996:
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                                                       Plans Where Assets                          Plans Where
                                                       Exceed Accumulated                     Accumulated Benefits
                                                            Benefits                              Exceed Assets
                                              -------------------------------------   -------------------------------------
                DECEMBER 31,                        1997                1996                1997                1996
---------------------------------------------------------------------------------------------------------------------------
                                                                             (In Thousands)
<S>                                           <C>                 <C>                 <C>                 <C>
Actuarial present value of:
     Vested benefit obligation..............     $  755,169          $  708,224           $ 22,368            $ 22,111
                                                 ==========          ==========           ========            ========
     Accumulated benefit obligation.........     $  788,265          $  737,868           $ 27,607            $ 26,627
                                                 ==========          ==========           ========            ========
     Projected benefit obligation...........     $1,005,439          $  927,531           $ 32,289            $ 32,420
Plan assets at fair value...................      1,804,852           1,539,039                 --                  --
                                                 ----------          ----------           --------            --------
     Plan assets in excess of (or less than)
        projected benefit obligation........        799,413             611,508            (32,289)            (32,420)
Unrecognized net gain.......................       (648,048)           (501,869)            (1,692)             (2,076)
Unrecognized net obligation (or asset)......        (58,660)            (67,980)            18,423              19,864
Unrecognized prior service cost.............          4,822               5,227                898               1,617
Recognition of minimum liability............             --                  --            (12,947)            (13,612)
                                                 ----------          ----------           --------            --------
     Prepaid pension cost (or pension
        liability)..........................     $   97,527          $   46,886           $(27,607)           $(26,627)
                                                 ==========          ==========           ========            ========
---------------------------------------------------------------------------------------------------------------------------
</TABLE>
 
     The projected benefit obligation at December 31, 1997 and 1996, was
determined using an annual discount rate of 7.0% and 7.5%, respectively, and an
average assumed annual rate of salary increase of 5.5%. The expected long-term
rate of return on plan assets was 9.0% per year at December 31, 1997 and 1996.
     The minimum liability recognized relating to both the Company's
nonqualified employee benefit and supplemental pension plans was $12.9 million
and $13.6 million at December 31, 1997 and 1996. The related intangible asset
recognized as of those dates amounted to $10.3 million and $11.5 million,
respectively. These amounts are included in the Consolidated Balance Sheet under
"Deferred credits and other liabilities" and "Deferred charges and other
assets." Adjustments of the minimum liability and intangible asset due to
changes in assumptions or the financial status of the plans resulted in a charge
to retained earnings of $.3 million at December 31, 1997, and a credit to
retained earnings of $.1 million at December 31, 1996.
 
                                       32
<PAGE>   35
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
7.  OTHER POSTRETIREMENT BENEFITS
 
Net periodic postretirement benefit cost, as determined by an independent
actuary, included the following components:
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                YEARS ENDED DECEMBER 31,                         1997                1996                1995
--------------------------------------------------------------------------------------------------------------------
                                                                                (In Thousands)
<S>                                                        <C>                 <C>                 <C>
Service cost--benefits attributed to service during the
  period.................................................       $ 9,901             $11,940             $11,549
Interest cost on accumulated postretirement benefit
  obligation.............................................        25,854              26,450              28,017
Return on plan assets....................................        (2,972)               (645)               (145)
Amortization of transition obligation....................        11,418              11,801              14,420
Curtailment and special termination benefits.............            --               1,292               7,094
Net amortization and deferral............................           (24)              2,283                 380
                                                                -------             -------             -------
     Net periodic postretirement benefit cost............       $44,177             $53,121             $61,315
                                                                =======             =======             =======
--------------------------------------------------------------------------------------------------------------------
</TABLE>
 
     The following table reconciles the plans' combined funded status, as
determined by an independent actuary, with amounts included in the Consolidated
Balance Sheet at December 31, 1997 and 1996:
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                        DECEMBER 31,                                 1997                1996
---------------------------------------------------------------------------------------------------
                                                                         (In Thousands)
<S>                                                           <C>                  <C>
Accumulated postretirement benefit obligation:
     Retirees...............................................      $ 279,555           $ 280,593
     Fully eligible active plan participants................          7,615              16,882
     Other active plan participants.........................         71,578              80,960
                                                                  ---------           ---------
           Total accumulated postretirement benefit
            obligation......................................        358,748             378,435
Plan assets at fair value...................................         79,740              53,153
                                                                  ---------           ---------
     Accumulated postretirement benefit obligation in excess
       of plan assets.......................................       (279,008)           (325,282)
Unrecognized prior service cost.............................         (6,178)             (6,591)
Unrecognized net loss.......................................         24,253              54,088
Unrecognized transition obligation..........................        170,102             188,248
                                                                  ---------           ---------
     Accrued postretirement benefit liability...............      $ (90,831)          $ (89,537)
                                                                  =========           =========
---------------------------------------------------------------------------------------------------
</TABLE>
 
     The Company is amortizing the accumulated postretirement benefit obligation
that existed at January 1, 1993 (transition obligation) over a 20-year period.
The weighted average discount rate used in determining the accumulated
postretirement benefit obligation at December 31, 1997 and 1996, was 7.0% and
7.5%, respectively. The average assumed annual rate of salary increase for the
applicable life insurance plans was 5.5% for both 1997 and 1996.
     The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation for the medical plans is 6.5% for 1998,
declining gradually to 4.5% in 2003 and remaining at that level thereafter. The
health care cost trend rate assumption has a significant effect on the amounts
reported. If the health care cost trend rate were increased by 1% in each year,
the accumulated postretirement benefit obligation as of December 31, 1997, would
be increased by $30.9 million. A 1% change would also increase the aggregate of
the service and interest cost components of net periodic postretirement benefit
cost for 1997 by $4.5 million.
     The majority of the estimated postretirement benefit costs and the
transition obligation is attributable to the rate-regulated subsidiaries.
Pending the expected recovery of SFAS No. 106 costs and related deferrals in
regulatory proceedings, these subsidiaries have deferred the differences between
SFAS No. 106 costs and amounts included in rates. The rate-regulated
subsidiaries have obtained approval for recovery in rates from
 
                                       33
<PAGE>   36
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
their respective regulatory commissions for the increased level of expense
resulting from SFAS No. 106. The amount of SFAS No. 106 costs deferred at
December 31, 1997 and 1996, was $55.1 million and $59.0 million, respectively,
which is included in the Consolidated Balance Sheet under "Deferred charges and
other assets."
     The FERC and certain state regulatory authorities have indicated that when
SFAS No. 106 costs are recovered in rates, amounts collected must be deposited
in irrevocable trust funds dedicated for the sole purpose of paying
postretirement benefits. Accordingly, four subsidiaries fund postretirement
benefit costs via voluntary employees' beneficiary associations (VEBAs). The
remaining subsidiaries do not prefund postretirement benefit costs, but rather
pay claims as presented. Assets held by the VEBAs consist primarily of
short-term fixed income securities.
 
8.  INCOME TAXES
 
"Income taxes" in the Consolidated Statement of Income include the following:
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                  YEARS ENDED DECEMBER 31,                      1997       1996       1995
--------------------------------------------------------------------------------------------
                                                                      (In Thousands)
<S>                                                           <C>        <C>        <C>
Current provision
  Federal...................................................  $128,825   $ 80,962   $ 44,705
  State.....................................................    18,540     13,839      9,203
Deferred income taxes-net
  Federal...................................................     2,806     60,758    (47,146)
  State.....................................................      (925)     2,472     (1,621)
Investment tax credit.......................................    (2,193)    (2,201)    (2,198)
                                                              --------   --------   --------
  Total.....................................................  $147,053   $155,830   $  2,943
                                                              ========   ========   ========
--------------------------------------------------------------------------------------------
</TABLE>
 
     Income taxes differed from the amounts shown in the next table that were
computed by applying the statutory federal income tax rate of 35% to reported
income before taxes. The reasons for the differences follow:
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                YEARS ENDED DECEMBER 31,                     1997        1996        1995
-------------------------------------------------------------------------------------------
                                                                    (In Thousands)
<S>                                                        <C>         <C>         <C>
Income before taxes......................................  $451,433    $454,103    $ 24,287
                                                           ========    ========    ========
Computed "expected" tax expense..........................  $158,002    $158,936    $  8,500
Increases (or reductions) in tax resulting from:
     Production tax credit...............................   (10,359)     (9,344)     (8,472)
     Investment tax credit...............................    (2,193)     (2,201)     (2,198)
     State income taxes..................................    11,450      10,602       4,928
     Miscellaneous.......................................    (9,847)     (2,163)        185
                                                           --------    --------    --------
           Total income taxes............................  $147,053    $155,830    $  2,943
                                                           ========    ========    ========
     Effective tax rate..................................     32.6%       34.3%       12.1%
-------------------------------------------------------------------------------------------
</TABLE>
 
     The current and noncurrent deferred income taxes reported in the
Consolidated Balance Sheet at December 31, 1997 and 1996 represent the net
expected future tax consequences attributable to
 
                                       34
<PAGE>   37
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
temporary differences between the carrying amounts of nontax assets and
liabilities and their tax bases. These temporary differences and the related tax
effect were as follows:
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
                                                         1997                             1996
                                            ------------------------------   ------------------------------
                                              Deferred     Deferred income     Deferred     Deferred income
               December 31,                 income taxes    taxes-current    income taxes    taxes-current
<S>                                         <C>            <C>               <C>            <C>
-----------------------------------------------------------------------------------------------------------
 
<CAPTION>
                                                                    (In Thousands)
<S>                                         <C>            <C>               <C>            <C>
Deferred tax liabilities:
     Excess of tax over book
        depreciation......................    $537,684         $    --         $516,241         $    --
     Exploration and intangible well
        drilling costs....................     225,111              --          215,415              --
     Unrecovered gas costs................          --          19,424               --          38,863
     Other................................      78,603              --           76,906              --
                                              --------         -------         --------         -------
           Total liabilities..............     841,398          19,424          808,562          38,863
                                              --------         -------         --------         -------
Deferred tax assets:
     Tax basis step-up in connection with
        acquisition of subsidiary.........      18,619              --           19,170              --
     Deferred investment tax credits......      15,854              --           17,114              --
     Overheads capitalized for tax
        purposes..........................       8,226              --           13,747              --
     Supplier and other refunds...........          --             187               --             277
     Other................................      86,581           5,502           77,197           2,490
     Valuation allowance..................          --              --               --              --
                                              --------         -------         --------         -------
           Total assets...................     129,280           5,689          127,228           2,767
                                              --------         -------         --------         -------
           Total deferred income taxes....    $712,118         $13,735         $681,334         $36,096
                                              ========         =======         ========         =======
-----------------------------------------------------------------------------------------------------------
</TABLE>
 
     A regulatory liability amounting to $55.0 million has been recorded at
December 31, 1997 representing the reduction to previously recorded deferred
income taxes associated with rate-regulated activities that are expected to be
refundable to customers, net of certain taxes collectible from customers. Also,
a regulatory asset corresponding to the recognition of additional deferred
income taxes not previously recorded because of past rate-making practices
amounting to $103.3 million has been recorded at December 31, 1997. These
amounts are included in the Consolidated Balance Sheet under "Deferred credits
and other liabilities" and "Deferred charges and other assets," respectively.
 
9.  GAS STORED
 
The distribution subsidiaries, except Virginia Natural Gas, value their stored
gas inventory under the LIFO method. Based upon the average price of gas
purchased during 1997, the current cost of replacing the inventory of "Gas
stored--current portion" exceeded the amount stated on a LIFO basis by
approximately $200.5 million at December 31, 1997. Virginia Natural Gas and CNG
Energy Services value their stored gas inventory under the weighted average cost
method.
     A portion of gas in underground storage used as a pressure base and for
operational balancing is included in "Property, Plant and Equipment" in the
amount of $126.4 million at December 31, 1997 and 1996.
 
10.  UNAMORTIZED ABANDONED FACILITIES
 
In 1988, Consolidated LNG received FERC approval for the abandonment of its
interest in liquefied natural gas facilities at Cove Point, Maryland. In
connection with the abandonment, Consolidated LNG recorded a deferred asset in
accordance with the provisions of SFAS No. 90, "Accounting for Abandonments and
 
                                       35
<PAGE>   38
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
Disallowances of Plant Costs." This deferred asset, which represents the present
value of allowable costs expected to be recovered, has been amortized over a
10-year recovery period which will end February 28, 1998, as prescribed in the
FERC order.
 
11.  COMMON STOCKHOLDERS' EQUITY
 
A summary of the changes in stockholders' equity follows:
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
                                   Common Stock              Capital in Excess
                                      Issued                   of Par Value
                               ---------------------   -----------------------------
<S>                            <C>          <C>        <C>        <C>       <C>        <C>          <C>
                                 Number      Value                                      Retained      Unearned
                               of Shares     at Par    Paid-In     Other     Total      Earnings    Compensation
----------------------------------------------------------------------------------------------------------------
 
<CAPTION>
                                                                (In Thousands)
<S>                            <C>          <C>        <C>        <C>       <C>        <C>          <C>
Balance at December 31,
  1994.......................    93,028     $255,827   $418,348   $40,280   $458,628   $1,469,879     $     --
Net income...................        --           --         --        --         --       21,344           --
Cash dividends declared
  Common stock ($1.94 per
    share)...................        --           --         --        --         --     (181,055)          --
Common stock issued
  Stock options..............       217          596      7,453        --      7,453           --           --
  System Thrift Plans........       213          586      7,586        --      7,586           --           --
  DRP*.......................       104          287      3,837        --      3,837           --           --
  Stock awards-net...........        30           81      1,040        --      1,040           --           --
Purchase of treasury stock...        --           --         --        --         --           --           --
Sale of treasury stock.......        --           --         (9)       --         (9)          --           --
Pension liability
  adjustment.................        --           --         --        --         --         (262)          --
                                 ------     --------   --------   -------   --------   ----------     --------
Balance at December 31,
  1995.......................    93,592      257,377    438,255    40,280    478,535    1,309,906           --
Net income...................        --           --         --        --         --      298,273           --
Cash dividends declared
  Common stock ($1.94 per
    share)...................        --           --         --        --         --     (183,671)          --
Common stock issued
  Stock options..............       769        2,113     29,662        --     29,662           --           --
  Performance shares-net.....       378        1,040     16,336        --     16,336           --      (17,376)
  Stock awards-net...........        98          270      4,404        --      4,404           --       (4,560)
  DRP*.......................        97          268      4,688        --      4,688           --           --
  Amortization and
    adjustment...............        --           --      3,520        --      3,520           --        4,394
Purchase of treasury stock...        --           --         --        --         --           --           --
Sale of treasury stock and
  other......................        --           --       (143)       --       (143)          --           --
Pension liability adjustment
  (Note 6)...................        --           --         --        --         --          116           --
                                 ------     --------   --------   -------   --------   ----------     --------
Balance at December 31,
  1996.......................    94,934      261,068    496,722    40,280    537,002    1,424,624      (17,542)
Net income...................        --           --         --        --         --      304,380           --
Cash dividends declared
  Common stock ($1.94 per
    share)...................        --           --         --        --         --     (184,942)          --
Common stock issued
  Stock options..............       612        1,683     23,615        --     23,615           --           --
  DRP*.......................        62          171      3,244        --      3,244           --           --
  Stock awards-net...........        25           69      1,318        --      1,318           --       (1,350)
  Conversion of debentures...         1            2         38        --         38           --           --
  Performance shares-net.....       (11)         (29)      (106)       --       (106)          --          135
  Amortization and
    adjustment...............        --           --      1,490        --      1,490           --        7,807
Purchase of treasury stock...        --           --         --        --         --           --           --
Sale of treasury stock and
  other......................        --           --        154        --        154           --           --
Pension liability adjustment
  (Note 6)...................        --           --         --        --         --         (309)          --
Cumulative translation
  adjustment.................        --           --         --        --         --       (4,166)          --
                                 ------     --------   --------   -------   --------   ----------     --------
Balance at December 31,
  1997.......................    95,623     $262,964   $526,475   $40,280   $566,755   $1,539,587     $(10,950)
                                 ======     ========   ========   =======   ========   ==========     ========
 
<CAPTION>
                                   Treasury Stock
                               ----------------------
                                 Number
                               of Shares      Cost
-------------------------------------------------------------
 
<S>                            <C>          <C>
Balance at December 31,
  1994.......................       --      $     --
Net income...................       --            --
Cash dividends declared
  Common stock ($1.94 per
    share)...................       --            --
Common stock issued
  Stock options..............       --            --
  System Thrift Plans........       --            --
  DRP*.......................       --            --
  Stock awards-net...........       --            --
Purchase of treasury stock...      (17)         (634)
Sale of treasury stock.......       17           634
Pension liability
  adjustment.................       --            --
                                  ----      --------
Balance at December 31,
  1995.......................       --            --
Net income...................       --            --
Cash dividends declared
  Common stock ($1.94 per
    share)...................       --            --
Common stock issued
  Stock options..............       --            --
  Performance shares-net.....       --            --
  Stock awards-net...........       --            --
  DRP*.......................       --            --
  Amortization and
    adjustment...............       --            --
Purchase of treasury stock...     (147)       (8,144)
Sale of treasury stock and
  other......................      147         8,144
Pension liability adjustment
  (Note 6)...................       --            --
                                  ----      --------
Balance at December 31,
  1996.......................       --            --
Net income...................       --            --
Cash dividends declared
  Common stock ($1.94 per
    share)...................       --            --
Common stock issued
  Stock options..............       --            --
  DRP*.......................       --            --
  Stock awards-net...........       --            --
  Conversion of debentures...       --            --
  Performance shares-net.....       --            --
  Amortization and
    adjustment...............       --            --
Purchase of treasury stock...     (220)      (12,286)
Sale of treasury stock and
  other......................      219        12,248
Pension liability adjustment
  (Note 6)...................       --            --
Cumulative translation
  adjustment.................       --            --
                                  ----      --------
Balance at December 31,
  1997.......................       (1)     $    (38)
                                  ====      ========
</TABLE>
 
--------------------------------------------------------------------------------
* Dividend Reinvestment Plan.
 
                                       36
<PAGE>   39
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
SHAREHOLDER RIGHTS PLAN
During 1995, the Board of Directors adopted a shareholder rights plan and on
January 23, 1996, declared a dividend of one right (Right) for each share of
common stock outstanding at the close of business on February 28, 1996. Each
Right would entitle the holder to purchase from the Company one-half of one
share of common stock at a price of $175 per share ($87.50 per half-share),
subject to adjustment (Purchase Price), if certain conditions are met in
connection with a possible acquisition of the common stock of the Company by a
third party. If the Rights become exercisable, each holder may exercise a Right
and receive common stock (or, in certain cases, cash, property or other
securities) of the Company or common stock of the acquiring company having a
value equal to twice the Right's then current Purchase Price.
     Also, under certain conditions, the Board of Directors may exchange the
Rights, in whole or in part, at an exchange ratio of one share of common stock
(and/or other securities, cash or other assets having the same value as a share
of common stock) per Right, subject to adjustment, or may redeem the Rights in
whole at a price of $0.01 per Right. Until a Right is exercised or exchanged for
common stock, the holder, as such, is not a stockholder of the Company. Unless
earlier exercised or redeemed, the Rights will expire on February 28, 2006.
 
UNISSUED SHARES
At December 31, 1997, 304,376,719 shares of common stock were unissued. Shares
have been registered with the SEC for possible issuance under various benefit
plans. Shares acquired by these plans can consist of original issue shares,
treasury shares or shares purchased in the open market. Shares have also been
registered with the SEC for possible issuance to shareholders under the Dividend
Reinvestment Plan and for issuance upon conversion of the Company's convertible
subordinated debentures. In addition, the Company has a shelf registration with
the SEC which would allow it to sell up to an additional $700 million of debt or
equity securities at December 31, 1997.
 
TREASURY STOCK
Under a stock repurchase plan approved by the Board of Directors, the Company
can purchase in the open market up to 10,000,000 shares of its common stock. The
Company may also acquire shares of its common stock through certain provisions
of the Company's various stock incentive plans. Shares repurchased or acquired
are held as treasury stock and are available for reissuance for general
corporate purposes or in connection with various employee benefit plans. When
treasury shares are reissued, the difference between the market value at
reissuance and the cost of shares is reflected in "Capital in excess of par
value." The cost of any shares held as treasury stock is shown as a reduction in
common stockholders' equity in the Consolidated Balance Sheet. No treasury
shares were held at December 31, 1996. At December 31, 1997, a total of 659
shares were being held as treasury stock.
 
PRE-1997 STOCK AWARD AND OPTION PLANS
Prior to 1997, stock awards, stock options and other stock-based awards were
granted to employees under the Long-Term Incentive Plan, the 1991 Stock
Incentive Plan (1991 Plan) and the 1995 Employee Stock Incentive Plan (1995
Plan). The Long-Term Incentive Plan terminated by its terms on November 9, 1991.
In addition, there were no shares authorized for issuance under either the 1991
Plan or the 1995 Plan at December 31, 1997. However, the provisions of these
plans continue with respect to stock awards granted whose restrictions have not
yet lapsed and stock options granted which have not been exercised at December
31, 1997.
 
1997 STOCK INCENTIVE PLAN
The 1997 Stock Incentive Plan (1997 Plan) provides for the granting of stock
awards, stock options and other stock-based awards to employees and Directors of
the Company effective January 1, 1997, including
 
                                       37
<PAGE>   40
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
grants made on or after that date pursuant to the Long-Term Strategic Incentive
Program described below. The maximum number of shares authorized for issuance in
each calendar year is determined in accordance with a formula contained in the
1997 Plan. At December 31, 1997, 5,832,110 shares were available for issuance
under the 1997 Plan.
     Stock awards granted under the plan may be in the form of restricted stock
or deferred stock. Shares issued as restricted stock awards are held by the
Company until the attached restrictions lapse. Deferred stock awards generally
consist of a right to receive shares at the end of specified deferral periods.
The market value of the stock award on the date granted is recorded as
compensation expense over the applicable restriction or deferral period.
     Stock options granted under the plan allow the purchase of common shares at
a price not less than fair market value at the date of grant and not less than
par value. These options, other than tri-annual options granted under the
Long-Term Strategic Incentive Program, generally are exercisable in four equal
annual installments commencing with the second anniversary of the grant and
expire after ten years from the date of grant.
     Stock appreciation rights may also be granted, either alone or in tandem
with stock options. These rights permit the recipient to receive, upon exercise,
the excess of the fair market value of a share on the date of exercise over the
grant price. The grant price is generally the fair market value of the stock on
the date of grant. As of December 31, 1997, no stock appreciation rights have
been granted under the plan.
     The granting of stock awards constitutes a non-cash financing activity of
the Company.
 
     LONG-TERM STRATEGIC INCENTIVE PROGRAM
Grants under the Long-Term Strategic Incentive Program, consisting of
performance restricted stock awards (performance shares) and stock options, are
expected to be made every three years, with the first such grants made on
January 2, 1996.
     Performance shares will vest contingent upon attainment of certain
strategic business results over a three-year period. The market value of the
performance shares on the grant date, as adjusted quarterly for changes in the
current market price of the Company's common stock, is recorded as compensation
expense over the three-year vesting period.
     Stock options granted under this program (tri-annual options) vest after
three years and will be exercisable from the vesting date until ten years from
the grant date if certain strategic business results are attained during the
vesting period. However, the exercise period will be reduced to one day for all
or a portion of the options granted if such results are not achieved. As the
number of options are known and the option price equals the market price at the
grant date, no compensation expense is recognized for these options under
generally accepted accounting principles.
 
ACCOUNTING FOR STOCK AWARDS AND STOCK OPTIONS
As allowed by SFAS No. 123, "Accounting for Stock-Based Compensation," the
Company continues to follow Accounting Principles Board Opinion No. 25 and
related interpretations (APB No. 25), for accounting for stock-based
compensation. The Company granted stock awards totaling 43,000 shares in 1997,
103,000 shares in 1996, and 34,000 shares in 1995 with weighted average market
prices per share on award dates of $51.89, $47.43, and $39.15, respectively. In
addition, performance shares totaling 55,000 shares in 1997 and 404,000 shares
in 1996 were issued at a weighted average market price of $53.02 and $45.87 per
share, respectively. The Company recorded compensation expense of $9.7 million,
$8.7 million and $.8 million for the years ended December 31, 1997, 1996 and
1995, respectively, in connection with its performance shares, restricted stock
and other stock compensation awards. In accordance with APB No. 25, no
compensation expense has been recognized for the Company's stock options.
 
                                       38
<PAGE>   41
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
     A summary of the Company's stock option activity under the plans described
above for the years ended December 31, 1995 through 1997, follows:
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                                                                                    Weighted Average
                                                                  Number              Option Price
                                                                 of Shares              Per Share
-----------------------------------------------------------------------------------------------------
                                                              (In Thousands)
<S>                                                           <C>                   <C>
Shares under option:
     At January 1, 1995.....................................       2,557                 $42.43
     Granted................................................       1,078                 $37.32
     Exercised..............................................        (217)                $35.88
     Cancelled..............................................        (470)                $41.14
                                                                   -----
     At December 31, 1995...................................       2,948                 $41.25
     Granted(1).............................................       3,534                 $45.53
     Exercised..............................................        (769)                $41.37
     Cancelled(1)...........................................        (196)                $43.13
                                                                   -----
     At December 31, 1996...................................       5,517                 $43.90
     Granted(2).............................................         885                 $54.09
     Exercised..............................................        (612)                $41.33
     Cancelled(2)...........................................        (583)                $45.74
                                                                   -----
     At December 31, 1997...................................       5,207                 $45.73
                                                                   =====
</TABLE>
 
(1) Includes 3,006,000 tri-annual options granted and 65,000 tri-annual options
    cancelled.
 
(2) Includes 332,084 tri-annual options granted and 367,883 tri-annual options
    cancelled.
 
Options were exercisable for the purchase of 599,534 shares, 673,305 shares, and
1,048,064 shares at December 31, 1997, 1996 and 1995, respectively. Effective
January 2, 1998, additional options for the purchase of 529,500 shares were
granted to eligible employees.
--------------------------------------------------------------------------------
 
     The following table summarizes information about stock options outstanding
at December 31, 1997.
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
                                              Options Outstanding                         Options Exercisable
                              ---------------------------------------------------   --------------------------------
<S>                           <C>               <C>                <C>              <C>               <C>
                                                Weighted Average      Weighted                           Weighted
                                  Number            Remaining         Average           Number           Average
  Range of Exercise Prices      Outstanding     Contractual Life   Exercise Price     Exercisable     Exercise Price
--------------------------------------------------------------------------------------------------------------------
 
<CAPTION>
                              (In Thousands)                                        (In Thousands)
<S>                           <C>               <C>                <C>              <C>               <C>
$34.75--$40.00                       712            6.33 YRS.          $37.12             205             $36.59
$40.01--$50.00                     3,369            7.42 YRS.          $44.92             310             $44.95
$50.01--$59.94                     1,126            8.35 YRS.          $54.01              85             $50.77
--------------------------------------------------------------------------------------------------------------------
</TABLE>
 
                                       39
<PAGE>   42
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
     The following table presents the weighted-average fair value of stock
options granted during 1995 through 1997 and the weighted-average assumptions
used to compute fair values under the Black-Scholes option-pricing model:
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                  YEARS ENDED DECEMBER 31,                     1997      1996      1995
----------------------------------------------------------------------------------------
<S>                                                            <C>       <C>       <C>
Option fair value...........................................   $8.96     $5.84     $5.50
Assumptions
     Dividend yield.........................................    3.6%      4.3%      5.0%
     Expected volatility....................................   16.8%     17.5%     19.2%
     Risk-free interest rate................................    6.4%      5.4%      6.9%
     Expected option life (years)...........................     4.8       4.9       4.9
----------------------------------------------------------------------------------------
</TABLE>
 
     If compensation expense for stock options granted during 1995 through 1997
had been determined based on the fair value at the grant dates for such awards
in accordance with SFAS No. 123, the effect on the Company's net income and
earnings per share for each of the years would have been as follows:
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                  YEARS ENDED DECEMBER 31,                     1997      1996      1995
----------------------------------------------------------------------------------------
<S>                                                           <C>       <C>       <C>
NET INCOME (In Millions):
     As reported............................................  $304.4    $298.3    $ 21.3
     Pro forma..............................................  $298.8    $294.1    $ 20.7
BASIC EPS:
     As reported............................................  $ 3.21    $ 3.17    $  .23
     Pro forma..............................................  $ 3.15    $ 3.13    $  .22
DILUTED EPS:
     As reported............................................  $ 3.15    $ 3.13    $  .23
     Pro forma..............................................  $ 3.10    $ 3.08    $  .22
----------------------------------------------------------------------------------------
</TABLE>
 
12.  PREFERRED STOCK
 
The Company's authorized preferred stock consists of 5,000,000 shares at a par
value of $100 each. There were no shares of preferred stock issued or
outstanding at December 31, 1997 or 1996.
 
13.  DIVIDEND RESTRICTIONS
 
One of the Company's indentures relating to senior debenture issues contains
restrictions on dividend payments by the Company and acquisitions of its capital
stock. Under the indenture provisions, $720.4 million of consolidated retained
earnings was free from such restrictions at December 31, 1997. The indenture
also imposes dividend limitations on the subsidiaries, but at December 31, 1997,
these limitations did not restrict their ability to pay dividends to the
Company.
 
                                       40
<PAGE>   43
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
14.  LONG-TERM DEBT
 
Long-term debt, excluding current maturities, follows:
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                        DECEMBER 31,                             1997          1996
--------------------------------------------------------------------------------------
                                                                   (In Thousands)
<S>                                                           <C>           <C>
Debentures
     6.8%, Due December 15, 2027............................  $  300,000    $       --
     6 5/8%, Due December 1, 2008...........................     150,000       150,000
     6 7/8%, Due October 15, 2026...........................     150,000       150,000
     7 3/8%, Due April 1, 2005..............................     150,000       150,000
     6 5/8%, Due December 1, 2013...........................     150,000       150,000
     5 3/4%, Due August 1, 2003.............................     150,000       150,000
     5 7/8%, Due October 1, 1998............................          --       150,000
     8 3/4%, Due October 1, 2019............................     150,000       150,000
     8 3/4%, Due June 1, 1999...............................     100,000       100,000
     8 5/8%, Due December 1, 2011...........................      15,625        31,250
     Unamortized debt discount, less premium................     (11,319)       (7,429)
Convertible Subordinated Debentures
     7 1/4%, Due December 15, 2015..........................     246,165       246,205
     Unamortized debt discount..............................      (1,581)       (1,711)
9.94% Unsecured loan due January 1, 1999....................       4,000         8,000
                                                              ----------    ----------
     Total..................................................  $1,552,890    $1,426,315
                                                              ==========    ==========
--------------------------------------------------------------------------------------
</TABLE>
 
     Discounts and premiums and the expenses incurred in connection with the
issuance of debentures are being amortized on a basis which will equitably
distribute the amount to "Interest on long-term debt" over the life of each
debenture issue.
     The Company's 7 1/4% Convertible Subordinated Debentures, due December 15,
2015, were convertible into shares of the Company's common stock at an initial
conversion price of $54 per share. On January 23, 1998, the Company called for
redemption the entire principal amount outstanding totaling $246.2 million. The
redemption price was 102.18% of the principal amount plus accrued interest
payable on February 23, 1998. In anticipation of the call of this debt, on
January 15, 1998, the Company purchased approximately 4.6 million shares of its
common stock in a private transaction to satisfy the conversion obligation to
holders of the Convertible Subordinated Debentures who chose to convert. The
right to convert expired on February 13, 1998, and approximately 1.6 million of
the acquired shares were issued on conversion. The remaining acquired shares are
expected to be sold in underwritten offerings during 1998.
     In late 1996, the Company called for redemption $53.1 million principal
amount of the 8 5/8% Debentures Due December 1, 2011. In connection with the
call, the Company placed funds into an irrevocable trust in December 1996 for
the sole purpose of paying the principal amount and related call premium and
accrued interest. As such, the debt was removed from the Consolidated Balance
Sheet at December 31, 1996. Payment was made from the trust on February 1, 1997.
This transaction resulted in a 1996 charge to "Other Income" of $5.0 million.
     The aggregate principal amounts of the Company's debentures maturing in the
years 1998 through 2002 are: $150.0 million; $107.1 million; $7.1 million; $7.1
million and $7.1 million.
     The 9.94% unsecured loan due January 1, 1999, is an obligation of Virginia
Natural Gas. This $20.0 million loan, which is being repaid in five annual
installments of $4.0 million each beginning January 1, 1995, has been guaranteed
by the Company.
 
                                       41
<PAGE>   44
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
15.  SHORT-TERM BORROWINGS
 
The weighted average interest rate on the Company's commercial paper notes
outstanding at December 31, 1997 and 1996, was 6.21% and 5.70%, respectively.
     The Company has a $775.0 million credit agreement with a group of banks.
Borrowings under this agreement are in the form of revolving credits and may, at
the option of the Company, be structured either as syndicated loans by a group
of participating banks or money market loans by individual banks. The loans may
be borrowed, paid or repaid and reborrowed on a few days notice. Varying
interest rate options are available for syndicated loans, while the interest
rate on money market loans is determined from quotes rendered by the
participating banks. This agreement may be used for general corporate purposes,
including the support of commercial paper notes. This agreement is currently
scheduled to expire on June 26, 1998; however, the Company expects that the
agreement will be renewed or replaced by a comparable agreement. A facility fee
is charged under this agreement but is not considered significant. There were no
borrowings under this agreement at December 31, 1997.
     On February 13, 1998, the Company entered into a $250.0 million short-term
credit agreement with a bank. Borrowings under the agreement are in the form of
revolving credits which may be used for general corporate purposes.
 
16.  FINANCIAL INSTRUMENTS
 
FAIR VALUES
The estimated fair value of the Company's long-term debt, including current
maturities, was as follows at December 31, 1997 and 1996:
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                                                    1997                          1996
                                           -----------------------       -----------------------
                                            Carrying       Fair           Carrying       Fair
              December 31,                   Amount       Value            Amount       Value
------------------------------------------------------------------------------------------------
                                                              (In Thousands)
<S>                                        <C>          <C>              <C>          <C>
Long-term debt...........................  $1,719,790   $1,789,577       $1,539,455   $1,563,440
------------------------------------------------------------------------------------------------
</TABLE>
 
     The fair values were estimated based upon closing transactions and/or
quotations for the Company's debentures as of those dates. Temporary cash
investments and commercial paper notes are stated at amounts which approximate
fair value due to the short maturities of those financial instruments.
 
DERIVATIVES AND PRICE RISK MANAGEMENT ACTIVITIES
 
     FUTURES AND OPTIONS CONTRACTS
The Company's price risk management activities include exchange-traded futures
and options contracts, which can be settled through the purchase or delivery of
commodities, and OTC options, which require settlement in cash. CNG Energy
Services uses such instruments to manage commodity price risk regarding gas and
electricity purchase and sale commitments and stored gas inventories, while CNG
Producing uses them to manage risk in connection with the production and sale of
crude oil.
     At December 31, 1997, CNG Energy Services had natural gas futures contracts
related to gas purchase and sale commitments and gas storage inventory covering
2.9 Bcf of gas on a net basis maturing through 2000. Also at December 31, 1997,
CNG Producing held crude oil futures contracts maturing through 1998 covering
1,750,000 barrels of oil.
     For contracts used by the Company that qualify and have been designated as
hedges, any gains or losses resulting from market price changes are expected to
be generally offset by the related physical transaction. The Company's net
unrealized gain related to futures contracts was approximately $5.1 million at
December 31, 1997.
 
                                       42
<PAGE>   45
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
     SWAP AGREEMENTS
In addition to futures and options contracts, CNG Energy Services and CNG
Producing enter into OTC price swap agreements to manage their exposure to
commodity price risk under existing sales commitments.
     At December 31, 1997, CNG Energy Services had swap agreements of varying
duration outstanding with several counterparties to exchange monthly payments on
net notional quantities of gas over the ensuing five years. Net notional
quantities at December 31, 1997 related to those swap agreements in which CNG
Energy Services pays a fixed price in exchange for a variable price totaled
324.5 Bcf, while net notional quantities related to agreements in which CNG
Energy Services pays a variable price in exchange for a fixed price totaled
297.2 Bcf. Net notional quantities or amounts do not represent the quantities or
amounts exchanged by the parties and, thus, are not a measure of the exposure of
the Company through its use of derivatives. The amounts exchanged are calculated
on the basis of monthly notional quantities and other terms of the agreements.
The Company's net unrealized loss related to swap agreements was approximately
$4.7 million at December 31, 1997. Profits expected on anticipated sales related
to the hedged transactions should generally offset the estimated unrealized
losses on the swap agreements.
     CNG Energy Services also has a foreign currency swap agreement effective
through April 2005 to manage foreign exchange rate risk in connection with the
payment of demand charges for pipeline capacity in Canada. The aggregate
notional amount underlying this swap agreement was approximately $51.0 million
at December 31, 1997. The unrealized gain related to this swap agreement was
$4.5 million at December 31, 1997.
 
     MARKET AND CREDIT RISK
Price risk management activities expose the Company to market risk. Market risk
represents the potential loss that can be caused by the change in market value
of a particular commitment. The Company has appropriate operating procedures in
place that are administered by experienced management to help ensure that proper
internal controls are maintained. In addition, the Company has established an
independent function at the Corporate level to monitor compliance with the price
risk management policies of CNG Energy Services. These policies include
value-at-risk and notional contract and stop loss limit structures designed to
maintain exposure levels within the parameters established by management.
     Price risk management activities also expose the Company to credit risk.
Credit risk represents the potential loss that the Company would incur as a
result of nonperformance by counterparties pursuant to the terms of their
contractual obligations. The Company maintains credit policies with regard to
its counterparties that management believes minimize overall credit risk. Such
policies include the evaluation of a prospective counterparty's financial
condition, collateral requirements where deemed necessary, and the use of
standardized agreements which facilitate the netting of cash flows associated
with a single counterparty. The Company also monitors the financial condition of
existing counterparties on an ongoing basis. Considering the system of internal
controls in place and credit reserve levels at December 31, 1997, the Company
believes it is unlikely that a material adverse effect on its financial
position, results of operations or cash flows would occur as a result of
counterparty nonperformance.
 
17.  ENVIRONMENTAL MATTERS
 
The Company is subject to various federal, state and local laws and regulations
relating to the protection of the environment. These laws and regulations govern
both current and future operations and potentially extend to plant sites
formerly owned or operated by the subsidiaries, or their predecessors.
     The Company has taken a proactive position with respect to environmental
concerns. As part of normal business operations, subsidiaries periodically
monitor their properties and facilities to identify and resolve potential
environmental matters, and the Company conducts general environmental surveys on
a continuing basis at its operating facilities to monitor compliance with
environmental laws and regulations.
 
                                       43
<PAGE>   46
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
As part of this process, voluntary surveys at subsidiary sites have been
conducted to determine the extent of any possible soil contamination due to
hazardous substances, such as mercury, and when contamination has been
discovered remediation efforts are undertaken. Further, on August 16, 1990, CNG
Transmission entered into a Consent Order and Agreement with the Commonwealth of
Pennsylvania Department of Environmental Resources (DER) in which CNG
Transmission has agreed with the DER's determination of certain violations of
the Pennsylvania Solid Waste Management Act, the Pennsylvania Clean Streams Law
and the rules and regulations promulgated thereunder. No civil penalties had
been assessed as of December 31, 1997. Pursuant to the Order and Agreement, CNG
Transmission continues to perform sampling, testing and analysis, and conducting
a program of remediation at some of its Pennsylvania facilities. Total
remediation costs in connection with these sites and the Order and Agreement are
not expected to be material with respect to the Company's financial position,
results of operations or cash flows. Based on current information, the Company
has recognized a gross estimated liability amounting to $10.9 million at
December 31, 1997, for future costs expected to be incurred to remediate or
mitigate hazardous substances at these sites and at facilities covered by the
Order and Agreement.
     Inasmuch as certain environmental-related expenditures are expected to be
recoverable in future regulatory proceedings, a regulatory asset amounting to
$7.3 million at December 31, 1997, is included in the Consolidated Balance Sheet
under the caption "Deferred charges and other assets." Also, uncontested claims
amounting to $1.5 million at December 31, 1997, were recognized for
environmental-related costs probable for recovery through joint-interest
operating agreements.
     The total amounts included in operating expenses for remediation and other
environmental-related costs, and the components of such costs, are as follows:
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                  YEARS ENDED DECEMBER 31,                            1997               1996          1995
---------------------------------------------------------------------------------------------------------------
                                                                               (In Thousands)
<S>                                                           <C>                     <C>           <C>
Recurring costs for ongoing operations......................         $3,430             $4,174        $3,094
Mandated remediation and other compliance costs.............          1,473               (419)        2,307
Voluntary remediation costs.................................            228              2,705         1,630
Other.......................................................             14                  3            79
                                                                     ------             ------        ------
     Total..................................................         $5,145             $6,463        $7,110
                                                                     ======             ======        ======
</TABLE>
 
--------------------------------------------------------------------------------
     CNG Transmission and certain of the distribution subsidiaries are subject
to the Federal Clean Air Act (Clean Air Act) and the Federal Clean Air Act
Amendments of 1990 (1990 amendments) which added significantly to the existing
Clean Air Act requirements. As a result of the 1990 amendments, these
subsidiaries were required to install Reasonably Available Control Technology at
some compressor stations to reduce nitrogen oxide emissions. Compliance required
capital expenditures to similarly retrofit some of the compressor engines along
the Company's pipeline system. The Company has completed the installation of
emission control equipment and the installation and testing of compressor
engines and related equipment required by the 1990 amendments. In addition,
several of the subsidiaries are required by the Clean Air Act Amendments to
acquire Title V permits for major facilities. Progress is on schedule for these
permits, with no major expenditures anticipated. The 1990 amendments may also
require installation of Maximum Available Control Technology (MACT) to control
the emissions of certain hazardous air pollutants. The Company is participating
with industry groups and the Environmental Protection Agency (EPA) in the
development of these regulations but is unable to estimate the cost of
installing MACT, if required.
     The Company expended de minimis amounts in 1997, $6.8 million in 1996 and
$11.3 million in 1995, to comply with the 1990 amendments. The total capital
expenditures required to comply with the 1990 amendments are expected to be
recoverable through future regulatory proceedings.
     The Company has determined that it is associated with 16 former
manufactured gas plant sites, five of which are currently owned by 
subsidiaries. Studies conducted by other utilities at their former
 
                                       44
<PAGE>   47
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
manufactured gas plants have indicated that their sites contain coal tar and
other potentially harmful materials. None of the 16 former sites with which the
Company is associated is under investigation by any state or federal
environmental agency, and no investigation or action is currently anticipated.
At this time it is not known if, or to what degree, these sites may contain
environmental contamination. Therefore, the Company is not able to estimate the
cost, if any, that may be required for the possible remediation of these sites.
     The Company discovered in the course of conducting a routine environmental
survey at East Ohio Gas that some of its practices for collecting and handling
pipeline fluids that may have been contaminated with polychlorinated biphenyls
(PCBs) may not have complied with environmental regulations. The appropriate
agencies have been notified as part of the federal self-disclosure process and
discussions are continuing with the agencies to gain approval of revised
collection and handling procedures. The discrepancies in the procedures were
primarily in connection with recordkeeping and did not involve spills, leaks, or
other mishandling of PCB contaminated fluids and did not damage the environment.
A thorough investigation of all collection and handling practices at East Ohio
Gas has been conducted and the Company provided the results of this
investigation to the EPA in 1997. One partial penalty assessment has been
received from the EPA, and the Company has entered into a Consent Agreement
Consent Order with the EPA. The penalty assessment was developed by EPA under
its Voluntary Disclosure Policy of April 22, 1995 and was approximately one
thousand dollars. The Company anticipates that additional penalties incurred in
connection with this matter will be mitigated as a result of the Company's self
disclosure. The amount of any liabilities in connection with this matter is not
expected to be material with respect to the Company's financial position,
results of operations or cash flows.
     Estimates of liability in the environmental area are based on current
environmental laws and regulations and existing technology. The exact nature of
environmental issues which the Company may encounter in the future cannot be
predicted. Additional environmental liabilities may result in the future as more
stringent environmental laws and regulations are implemented and as the Company
obtains more specific information about its existing sites and production
facilities. At present, no estimate of any such additional liability, or range
of liability amounts, can be made. However, the amount of any such liabilities
could be material.
 
18.  COMMITMENTS AND CONTINGENCIES
 
Lease arrangements of the Company are principally for office space, business
machines and transportation equipment. None of these arrangements, individually
or in the aggregate, are material capital leases. Rental expense incurred in the
years 1995 through 1997 was not material, and future rental payments required
under leases in effect at December 31, 1997, are not material.
     It is estimated that the Company's 1998 capital spending program will
amount to $714.7 million, and that approximately $312.7 million of that amount
will be directed to gas and oil producing activities. In connection with the
capital spending program, the Company has entered into certain contractual
commitments. Contractual commitments in the ordinary course of business include
requirements by CNG Energy Services to purchase capacity on nonaffiliated
pipelines to meet both committed and anticipated future long-term customer gas
supply needs.
     The Company has claims and suits arising in the ordinary course of business
pending against it but, in the opinion of management and counsel, the ultimate
liability will not have a material effect on its financial position, results of
operations or cash flows.
 
19.  DISAGGREGATED INFORMATION
 
In addition to operating in all phases of the natural gas business, the Company
explores for and produces oil and provides a variety of energy marketing
services.
 
                                       45
<PAGE>   48
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
     Distribution represents the retail gas distribution subsidiaries. These
subsidiaries sell gas and/or provide transportation services to residential,
commercial and industrial customers in Ohio, Pennsylvania, Virginia and West
Virginia, and are subject to price regulation by their respective state utility
commissions.
     Transmission operations include the activities of CNG Transmission, an
interstate pipeline company regulated by the FERC which provides gas
transportation, storage and related services to affiliates and to utilities and
end users in the Midwest, the Mid-Atlantic states and the Northeast. CNG
Transmission also holds a 16% general partnership interest in the Iroquois Gas
Transmission System, L.P., a limited partnership that owns and operates an
interstate natural gas pipeline that transports Canadian gas to utility and
power generation customers in New York and New England.
     Exploration and production includes the results of CNG Producing and the
gas and oil production activities of CNG Transmission. These operations are
located throughout the United States and in the Gulf of Mexico. CNG Producing
also owns a working interest in a heavy oil program in Alberta, Canada.
     Energy marketing services is comprised of CNG Energy Services and CNG Power
Services. CNG Energy Services markets Company-owned gas production and arranges
gas supplies, transportation, storage and related services throughout North
America. CNG Energy Services also holds the Company's ownership interests in six
independent power plants. CNG Power Services is the power marketing subsidiary
that purchases and resells electricity at market-based prices.
     The activities of CNG International, CNG Retail, CNG Products and Services,
Consolidated LNG, CNG Research and CNG Coal are included in the "Other"
category. CNG International was formed in 1996 to engage in energy-related
activities outside of the United States and holds equity investments in
Australia and Latin America. CNG Retail was established in 1997 to pursue
opportunities arising from the deregulation of the energy industry at the retail
level. CNG Products and Services began operations in 1996 and provides certain
energy-related services to customers of the Company's distribution subsidiaries
and others.
     Transactions between affiliates are recognized at prices which approximate
market value. Significant transactions between the operating components are
eliminated to reconcile the disaggregated information to consolidated amounts.
Identifiable assets of each component are those assets that are used in its
operations.
 
                                       46
<PAGE>   49
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
     The following table represents disaggregated information pertaining to the
Company's operations:
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                                                                Exploration     Energy                   Corporate
                                                                    and       Marketing                     and
                                  Distribution   Transmission   Production     Services      Other      Eliminations     Total
---------------------------------------------------------------------------------------------------------------------------------
                                                                          (In Thousands)
<S>                               <C>            <C>            <C>           <C>          <C>          <C>            <C>
1997
Operating revenues
Nonaffiliated
  Regulated gas sales...........   $1,844,221     $       --    $       --    $       --   $    6,780    $       --    $1,851,001
  Nonregulated gas sales........           --             --        48,379     2,259,436       31,342            --     2,339,157
  Gas transportation and
    storage.....................      153,503        318,086           701         7,215           --            --       479,505
  Electricity sales.............           --             --            --       594,253          279            --       594,532
  Other.........................       23,695         47,853       300,370        68,400        5,507            --       445,825
                                   ----------     ----------    ----------    ----------   ----------    ----------    ----------
    Total nonaffiliated.........    2,021,419        365,939       349,450     2,929,304       43,908            --     5,710,020
Affiliated......................        5,142        121,037       356,230       176,463       15,257      (674,129)           --
                                   ----------     ----------    ----------    ----------   ----------    ----------    ----------
  Total operating revenues......    2,026,561        486,976       705,680     3,105,767       59,165      (674,129)    5,710,020
Other operating expenses........    1,682,602        246,617       381,475     3,116,964       68,100      (661,068)    4,834,690
Depreciation and amortization...       77,389         61,920       181,356         5,884          366         3,229       330,144
                                   ----------     ----------    ----------    ----------   ----------    ----------    ----------
Operating income before income
  taxes.........................   $  266,570     $  178,439    $  142,849    $  (17,081)  $   (9,301)   $  (16,290)   $  545,186
                                   ==========     ==========    ==========    ==========   ==========    ==========    ==========
Capital expenditures............   $  147,213     $   49,251    $  293,337    $   12,865   $   95,801    $   10,906    $  609,373
Identifiable assets.............   $2,879,960     $1,482,652    $1,314,468    $  757,028   $  288,006    $ (408,420)   $6,313,694
---------------------------------------------------------------------------------------------------------------------------------
1996
Operating revenues
Nonaffiliated
  Regulated gas sales...........   $1,745,206     $       --    $       --    $       --   $    7,017    $       --    $1,752,223
  Nonregulated gas sales........           --             --        66,126     1,026,360           --            --     1,092,486
  Gas transportation and
    storage.....................      132,134        331,637           532           807           --            --       465,110
  Electricity sales.............           --             --            --       109,446           --            --       109,446
  Other.........................       25,211         51,471       226,306        70,235        1,821            --       375,044
                                   ----------     ----------    ----------    ----------   ----------    ----------    ----------
    Total nonaffiliated.........    1,902,551        383,108       292,964     1,206,848        8,838            --     3,794,309
Affiliated......................        2,961        120,292       339,323       149,635        9,834      (622,045)           --
                                   ----------     ----------    ----------    ----------   ----------    ----------    ----------
  Total operating revenues......    1,905,512        503,400       632,287     1,356,483       18,672      (622,045)    3,794,309
Other operating expenses........    1,572,959        264,542       333,336     1,363,871       21,780      (614,324)    2,942,164
Depreciation and amortization...       74,132         60,107       165,715         1,681           48         2,488       304,171
                                   ----------     ----------    ----------    ----------   ----------    ----------    ----------
Operating income before income
  taxes.........................   $  258,421     $  178,751    $  133,236    $   (9,069)  $   (3,156)   $  (10,209)   $  547,974
                                   ==========     ==========    ==========    ==========   ==========    ==========    ==========
Capital expenditures............   $  143,050     $   85,904    $  247,103    $   35,531   $   42,570    $    6,135    $  560,293
Identifiable assets.............   $2,902,917     $1,481,612    $1,232,992    $  473,766   $   94,608    $ (185,290)   $6,000,605
---------------------------------------------------------------------------------------------------------------------------------
1995
Operating revenues
Nonaffiliated
  Regulated gas sales...........   $1,594,397     $   (4,275)   $       --    $       --   $    7,257    $       --    $1,597,379
  Nonregulated gas sales........           --             --        57,778       939,946           --            --       997,724
  Gas transportation and
    storage.....................      122,175        333,185           423           587           --            --       456,370
  Electricity sales.............           --             --            --        21,768           --            --        21,768
  Other.........................       22,375         36,978       116,241        58,488            2            --       234,084
                                   ----------     ----------    ----------    ----------   ----------    ----------    ----------
    Total nonaffiliated.........    1,738,947        365,888       174,442     1,020,789        7,259            --     3,307,325
Affiliated......................        6,280        105,138       187,012        87,611       10,168      (396,209)           --
                                   ----------     ----------    ----------    ----------   ----------    ----------    ----------
  Total operating revenues......    1,745,227        471,026       361,454     1,108,400       17,427      (396,209)    3,307,325
Other operating expenses........    1,466,776        261,091       438,477     1,113,014       14,543      (392,668)    2,901,233
Depreciation and amortization...       70,972         59,552       123,492         1,072           --         1,548       256,636
                                   ----------     ----------    ----------    ----------   ----------    ----------    ----------
Operating income before income
  taxes.........................   $  207,479     $  150,383    $ (200,515)   $   (5,686)  $    2,884    $   (5,089)   $  149,456
                                   ==========     ==========    ==========    ==========   ==========    ==========    ==========
Capital expenditures............   $  160,480     $   81,557    $  176,789    $   19,567   $       --    $    1,000    $  439,393
Identifiable assets.............   $2,645,004     $1,483,631    $1,155,092    $  317,490   $   54,425    $ (237,349)   $5,418,293
---------------------------------------------------------------------------------------------------------------------------------
</TABLE>
 
                                       47
<PAGE>   50
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
20.  SUPPLEMENTARY FINANCIAL INFORMATION--UNAUDITED
 
(A) GAS AND OIL PRODUCING ACTIVITIES (EXCLUDING COST-OF-SERVICE RATE-REGULATED
ACTIVITIES)
This information has been prepared in accordance with SFAS No. 69, "Disclosures
about Oil and Gas Producing Activities," and related SEC pronouncements.
Statement No. 69 is a comprehensive, standard set of required disclosures about
the gas and oil producing activities of publicly traded companies. The following
disclosures exclude the gas and oil producing activities subject to
cost-of-service rate regulation. Certain disclosures about these gas and oil
activities, which are exempt from the accounting methods prescribed by the SEC,
are included under "Cost-of-Service Properties" in this Note (A).
 
     CAPITALIZED COSTS
The aggregate amounts of costs capitalized by subsidiaries for their gas and oil
producing activities, and related aggregate amounts of accumulated depreciation
and amortization, follow:
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                        DECEMBER 31,                                 1997                 1996
-----------------------------------------------------------------------------------------------------
                                                                          (In Thousands)
<S>                                                           <C>                  <C>
Capitalized costs of
  Proved properties.........................................      $3,293,851           $3,057,682
  Unproved properties.......................................         328,174              317,462
                                                                  ----------           ----------
     Subtotal...............................................       3,622,025            3,375,144
                                                                  ----------           ----------
Accumulated depreciation of
  Proved properties.........................................       2,367,105            2,224,471
  Unproved properties.......................................         146,417              134,481
                                                                  ----------           ----------
     Subtotal...............................................       2,513,522            2,358,952
                                                                  ----------           ----------
     Net capitalized costs..................................      $1,108,503           $1,016,192
                                                                  ==========           ==========
</TABLE>
 
--------------------------------------------------------------------------------
     As described in Note 4, the Company recognized an impairment of its
Canadian oil producing properties at December 31, 1997. The non-cash charge
amounted to $10.4 million and is reflected in the amounts included above.
 
     TOTAL COSTS INCURRED
The following costs were incurred by subsidiaries in their gas and oil producing
activities during the years 1995 through 1997:
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                YEARS ENDED DECEMBER 31,                         1997                1996                1995
--------------------------------------------------------------------------------------------------------------------
                                                                                (In Thousands)
<S>                                                        <C>                 <C>                 <C>
Property acquisition costs
  Proved properties......................................      $ 14,142            $ 42,880            $  5,824
  Unproved properties....................................        43,951              17,911               9,686
                                                               --------            --------            --------
     Subtotal............................................        58,093              60,791              15,510
Exploration costs........................................       101,891              49,622              50,974
Development costs........................................       118,746             125,139             102,574
                                                               --------            --------            --------
     Total...............................................      $278,730            $235,552            $169,058
                                                               ========            ========            ========
</TABLE>
 
--------------------------------------------------------------------------------
 
     RESULTS OF OPERATIONS
The elements of the "results of operations for gas and oil producing activities"
that follow are as required and defined by the FASB. The Company cautions that
these standardized disclosures do not represent the
 
                                       48
<PAGE>   51
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
results of operations based on its historical financial statements. In addition
to requiring different determinations of revenues and costs, the disclosures
exclude the impact of interest expense and corporate overheads.
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                YEARS ENDED DECEMBER 31,                         1997                1996                1995
--------------------------------------------------------------------------------------------------------------------
                                                                                (In Thousands)
<S>                                                        <C>                 <C>                 <C>
Revenues (net of royalties) from:
  Sales to nonaffiliated companies.......................      $111,181            $ 84,239            $  60,139
  Transfers to other operations..........................       300,025             289,892              150,930
                                                               --------            --------            ---------
     Total...............................................       411,206             374,131              211,069
                                                               --------            --------            ---------
Less: Production (lifting) costs.........................        65,286              55,679               40,812
      Depreciation and amortization......................       172,046             157,358              117,163
      Impairment of producing properties.................        10,351                  --              226,209
      Income tax expense.................................        48,987              49,367              (68,615)
                                                               --------            --------            ---------
Results of operations....................................      $114,536            $111,727            $(104,500)
                                                               ========            ========            =========
</TABLE>
 
--------------------------------------------------------------------------------
 
     COMPANY-OWNED RESERVES (NON-COST-OF-SERVICE RESERVES)
Estimated net quantities of proved gas and oil (including condensate) reserves
in the United States and Canada at December 31, 1995 through 1997, and changes
in the reserves during those years, are shown in the two schedules which follow:
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                YEARS ENDED DECEMBER 31,                         1997                1996                1995
--------------------------------------------------------------------------------------------------------------------
                                                                                   (In Bcf)
<S>                                                        <C>                 <C>                 <C>
PROVED DEVELOPED AND UNDEVELOPED RESERVES* -- GAS
  At January 1...........................................        1,040                 985                 901
  Changes in reserves
     Extensions, discoveries and other additions.........          210                 124                 167
     Revisions of previous estimates.....................           31                   5                  17
     Production..........................................         (155)               (145)               (103)
     Purchases of gas in place...........................           29                  96                   7
     Sales of gas in place...............................          (14)                (25)                 (4)
                                                                ------              ------               -----
  At December 31.........................................        1,141               1,040                 985
                                                                ======              ======               =====
PROVED DEVELOPED RESERVES* -- GAS
  At January 1...........................................          900                 717                 730
  At December 31.........................................          925                 900                 717
*Net before royalty.
</TABLE>
 
--------------------------------------------------------------------------------
     Included in the caption "Extensions, discoveries and other additions" for
1995 are 110 Bcf of proved undeveloped reserves for which development costs will
be incurred in future years. The preceding proved developed and undeveloped gas
reserves at December 31, 1997, 1996 and 1995, include United States reserves of
1,140, 1,039 and 984 Bcf which, together with the Canadian reserves and the gas
reserves
 
                                       49
<PAGE>   52
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
reported under "Cost-of-Service Properties," are as contained in reports of
Ralph E. Davis Associates, Inc., independent geologists.
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                  YEARS ENDED DECEMBER 31,                       1997         1996         1995
--------------------------------------------------------------------------------------------------
                                                                       (In Thousand Bbls)
<S>                                                           <C>          <C>          <C>
PROVED DEVELOPED AND UNDEVELOPED RESERVES* -- OIL
  At January 1..............................................    50,457       45,791       46,255
  Changes in reserves
     Extensions, discoveries and other additions............     4,582        5,976        1,965
     Revisions of previous estimates........................     1,741        2,711        1,117
     Production.............................................    (7,312)      (4,766)      (3,132)
     Purchases of oil in place..............................     1,182          804          163
     Sales of oil in place..................................       (23)         (59)        (577)
                                                                ------       ------       ------
  At December 31............................................    50,627       50,457       45,791
                                                                ======       ======       ======
PROVED DEVELOPED RESERVES* -- OIL
  At January 1..............................................    24,989       19,838       20,379
  At December 31............................................    37,568       24,989       19,838
*Net before royalty.
</TABLE>
 
--------------------------------------------------------------------------------
 
     The foregoing proved developed and undeveloped oil reserves at December 31,
1997, 1996 and 1995 include United States reserves of 44,160, 41,818 and 39,964
thousand barrels, respectively. These, together with the Canadian reserves, are
as contained in reports of Ralph E. Davis Associates, Inc.
 
     STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES
THEREIN
The following tabulation has been prepared in accordance with the FASB's rules
for disclosure of a standardized measure of discounted future net cash flows
relating to Company-owned proved gas and oil reserve quantities.
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                      DECEMBER 31,                              1997                1996                1995
-------------------------------------------------------------------------------------------------------------------
                                                                               (In Thousands)
<S>                                                       <C>                 <C>                 <C>
Future cash inflows.....................................     $3,197,532          $4,022,381          $2,668,837
Less: Future development and production costs...........        658,281             711,067             659,532
       Future income tax expense........................        766,233           1,049,234             602,158
                                                             ----------          ----------          ----------
Future net cash flows...................................      1,773,018           2,262,080           1,407,147
Less annual discount (10% a year).......................        606,509             830,083             565,404
                                                             ----------          ----------          ----------
Standardized measure of discounted future net cash
  flows.................................................     $1,166,509          $1,431,997          $  841,743
                                                             ==========          ==========          ==========
</TABLE>
 
--------------------------------------------------------------------------------
     In the foregoing determination of future cash inflows, sales prices for gas
were based on contractual arrangements or market prices at each year-end. Prices
for oil were based on average prices received from sales in the month of
December each year. Future costs of developing and producing the proved gas and
oil reserves reported at the end of each year shown were based on costs
determined at each such year-end, assuming the continuation of existing economic
conditions. Future income taxes were computed by applying the appropriate
year-end or future statutory tax rate to future pretax net cash flows, less the
tax basis of the properties involved, and giving effect to tax deductions, or
permanent differences and tax credits.
     It is not intended that the FASB's standardized measure of discounted
future net cash flows represent the fair market value of the Company's proved
reserves. The Company cautions that the disclosures shown are based on estimates
of proved reserve quantities and future production schedules which are
inherently
 
                                       50
<PAGE>   53
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
imprecise and subject to revision, and the 10% discount rate is arbitrary. In
addition, present costs and prices are used in the determinations and no value
may be assigned to probable or possible reserves.
     The following tabulation is a summary of changes between the total
standardized measure of discounted future net cash flows at the beginning and
end of each year.
 
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                YEARS ENDED DECEMBER 31,                        1997                1996                1995
-------------------------------------------------------------------------------------------------------------------
                                                                               (In Thousands)
<S>                                                       <C>                 <C>                 <C>
Standardized measure of discounted future net cash flows
  at January 1..........................................     $1,431,997          $  841,743           $ 704,492
Changes in the year resulting from
  Sales and transfers of gas and oil produced during the
     year, less production costs........................       (345,920)           (318,583)           (170,257)
  Prices and production and development costs related to
     future production..................................       (660,014)            632,118             150,634
  Extensions, discoveries and other additions, less
     production and development costs...................        256,366             295,236             181,664
  Previously estimated development costs incurred during
     the year...........................................         38,409              62,706              62,958
  Revisions of previous quantity estimates..............        101,352             106,800               8,336
  Accretion of discount.................................        209,210             119,555              98,736
  Income taxes..........................................        159,528            (306,290)            (70,927)
  Purchases and sales of proved reserves in place-net...         40,815             112,601               1,794
  Other (principally timing of production)..............        (65,234)           (113,889)           (125,687)
                                                             ----------          ----------           ---------
Standardized measure of discounted future net cash flows
  at December 31........................................     $1,166,509          $1,431,997           $ 841,743
                                                             ==========          ==========           =========
-------------------------------------------------------------------------------------------------------------------
</TABLE>
 
     COST-OF-SERVICE PROPERTIES
As previously stated, activities subject to cost-of-service rate regulation are
excluded from the foregoing information. At December 31, 1997 and 1996, net
capitalized costs of cost-of-service properties amounted to $8.4 million and
$10.0 million, respectively. Related proved reserves of gas are located in the
United States and amounted to 42, 43 and 56 Bcf at December 31, 1997, 1996 and
1995. There were no cost-of-service oil reserves at December 31, 1997, 1996 or
1995. Gas production for the years 1997, 1996 and 1995 amounted to 3, 3 and 4
Bcf, respectively. Oil production for 1995 amounted to 17,000 barrels.
     Future revenues associated with production of the foregoing gas reserves
would be based upon cost-of-service ratemaking and historical asset costs, with
rate of return levels determined by various state regulatory commissions.
 
(B) QUARTERLY FINANCIAL DATA
A summary of the quarterly results of operations for the years 1997 and 1996
follows. Per share amounts for the first three quarters of 1997 and all 1996
quarters have been restated in connection with the Company's adoption of SFAS
No. 128. Because a major portion of the gas sold or transported by the Company's
distribution and transmission operations is ultimately used for space heating,
both revenues and earnings are subject to seasonal fluctuations, and third
quarter results are usually the least significant of the year for
 
                                       51
<PAGE>   54
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)
 
the Company. Seasonal fluctuations are further influenced by the timing of price
relief granted under regulation to compensate for certain past cost increases.
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                                                                                Quarter
                                             -----------------------------------------------------------------------------
                                                   First              Second               Third              Fourth
--------------------------------------------------------------------------------------------------------------------------
                                                                            (In Thousands)
<S>                                          <C>                 <C>                 <C>                 <C>
1997
Total operating revenues...................     $1,698,599          $1,030,854          $1,130,477          $1,850,090
Operating income before income taxes.......        280,688              76,990              26,859             160,649
Net income.................................        171,491              38,985               4,538              89,366
Earnings per common share -- basic.........           1.81                 .41                 .05                 .94
Earnings per common share -- diluted*......           1.74                 .41                 .05                 .92
1996
Total operating revenues...................     $1,315,084          $  654,950          $  595,057          $1,229,218
Operating income before income taxes.......        302,176              71,949              11,045             162,804
Net income (loss)..........................        180,800              34,617              (5,118)             87,974
Earnings (loss) per common
  share -- basic...........................           1.93                 .37                (.05)                .93
Earnings (loss) per common
  share -- diluted*........................           1.87                 .37                (.05)                .91
</TABLE>
 
* The sum of the quarterly amounts does not equal the year's amount because the
  quarterly calculations are based on a changing number of average shares.
--------------------------------------------------------------------------------
 
(C) COMMON STOCK MARKET PRICES AND RELATED MATTERS
At December 31, 1997, there were 35,498 holders of the Company's common stock.
The principal market for the stock is the New York Stock Exchange. Quarterly
price ranges and dividends declared on the common stock for the years 1997 and
1996 follow. Restrictions on the payment of dividends are discussed in Note 13.
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                                                                                 Quarter
                                                -------------------------------------------------------------------------
                                                     First              Second             Third              Fourth
-------------------------------------------------------------------------------------------------------------------------
<S>                                             <C>                <C>                <C>                <C>
Market Price Range
1997--High....................................       $  57 3/4          $  54 7/8          $  60 11/16        $  60 15/16
      --Low...................................       $  49 5/8          $  47 3/8          $  53 9/16         $  52 5/16
1996--High....................................       $  47 1/8          $  52 1/4          $  57 1/8          $  59 5/8
      --Low...................................       $  41 1/2          $  43 1/2          $  49              $  51 1/8
Dividends Declared per Share
1997..........................................       $ .485             $ .485             $ .485             $ .485
1996..........................................       $ .485             $ .485             $ .485             $ .485
</TABLE>
 
--------------------------------------------------------------------------------
 
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