<PAGE>   1
                                                                      Exhibit 99

LOGO CONSOLIDATED NATURAL GAS COMPANY

LOGO CONSOLIDATED NATURAL GAS COMPANY

LOGO CONSOLIDATED NATURAL GAS COMPANY

LOGO CONSOLIDATED NATURAL GAS COMPANY

LOGO CONSOLIDATED NATURAL GAS COMPANY

LOGO CONSOLIDATED NATURAL GAS COMPANY

LOGO CONSOLIDATED NATURAL GAS COMPANY

LOGO CONSOLIDATED NATURAL GAS COMPANY

LOGO CONSOLIDATED NATURAL GAS COMPANY

LOGO CONSOLIDATED NATURAL GAS COMPANY

LOGO CONSOLIDATED NATURAL GAS COMPANY

LOGO CONSOLIDATED NATURAL GAS COMPANY

LOGO CONSOLIDATED NATURAL GAS COMPANY

LOGO CONSOLIDATED NATURAL GAS COMPANY



                   1998 Financial
                        Report
                     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..............................................................................      21
Report of Independent Accountants....................................................................      22
Consolidated Statement of Income for the Years 1996 through 1998.....................................      23
Consolidated Balance Sheet at December 31, 1997 and 1998.............................................      24
Consolidated Statement of Cash Flows for the Years 1996 through 1998.................................      26
Consolidated Statement of Comprehensive Income for the Years 1996 through 1998.......................      27
Notes to Consolidated Financial Statements...........................................................      28
</TABLE>

<PAGE>   3

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS

(All per share references, unless indicated, are stated as basic earnings per
share. Prior year amounts have been restated, as applicable, to present
continuing operations separate from discontinued operations.)

SUBSEQUENT EVENT

On February 22, 1999, Consolidated Natural Gas Company (the Company) and
Dominion Resources, Inc. (DRI) announced that a definitive merger agreement
(merger agreement) was approved by the boards of directors of both companies.
Under the terms of the merger agreement, DRI intends to acquire all of the
Company's shares of common stock in a stock-for-stock transaction. Reference is
made to Note 19 to the consolidated financial statements, page 52, regarding
this subsequent event.

RESULTS OF OPERATIONS

NET INCOME
Net income in 1998 was $238.8 million, or $2.52 a share, compared with net
income of $304.4 million, or $3.21 a share, in 1997. Net income in 1996 was
$298.3 million, or $3.17 a share. These results, however, reflect the Company's
decision to discontinue its wholesale energy trading and marketing operations in
1998 (see Note 2 to the consolidated financial statements, page 30). The Company
recognized a loss on discontinued operations in 1998 of $48.9 million, or $.51 a
share. Losses from discontinued operations during 1997 and 1996 totaled $14.5
million and $11.1 million, respectively, or $.15 and $.12 a share.

INCOME FROM CONTINUING OPERATIONS
Income from continuing operations was $287.7 million, $318.9 million and $309.4
million for 1998, 1997 and 1996, respectively. On a per share basis, income from
continuing operations was $3.03 in 1998, compared to $3.36 and $3.29 in 1997 and
1996, respectively.

      1998
Income from continuing operations declined $31.2 million in 1998. The effects of
warm winter weather and lower average wellhead prices for gas and oil were only
partially mitigated by ongoing cost reduction efforts and the impact of higher
oil production. Weather in the Company's retail service areas was 17.8% warmer
than normal and 19.3% warmer than 1997. The warmer than normal weather in 1998
reduced earnings by $.47 per share. Normal weather represents a measure of
temperature experienced over an historical time frame, the length of which may
differ depending on the regulatory jurisdiction. When compared to normal, 1998
was the second warmest year in the Company's history.

      1997
Income from continuing operations in 1997 increased $9.5 million from the prior
year. 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 both gas and oil. Weather in the Company's retail
service areas was 1.9% colder than normal but 4.3% warmer than 1996.

      1996
Income from continuing operations in 1996 reflected 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. Weather in the Company's retail service
areas was 5.6% colder than normal and 5.5% colder than 1995.

                                        1
<PAGE>   4

OPERATING REVENUES
Operating revenues include revenues from gas and oil sales, transportation and
storage of gas, gas and oil trading activities and by-product operations. Total
operating revenues in 1998 were $2,760.4 million, a decrease of $416.7 million
from 1997.
     Regulated gas sales revenues declined $477.3 million during 1998 compared
to the prior year, to $1,373.7 million. Regulated sales volumes declined 64.9
billion cubic feet (Bcf), to 207.1 Bcf, due chiefly to warmer weather in 1998.
Residential customers switching to transport service also caused a decline in
sales volumes. In addition, lower average sales rates for all three major
customer classes--residential, commercial and industrial--reflecting lower
purchased gas costs contributed to the decline in revenues.
     Nonregulated gas sales revenues increased $61.0 million in 1998, to $494.4
million, with sales volumes increasing 36.1 Bcf, to 207.1 Bcf. The increased
sales volumes in 1998 were due to gas sales by CNG Retail Services Corporation
(CNG Retail), in its first full year of operation, and CNG Field Services
Company (CNG Field Services).
     Gas transportation and storage revenues rose $53.8 million, to $545.9
million, in 1998. This improvement includes a $47.6 million increase associated
with gas transportation revenues due largely to customers switching from sales
to transport service at certain of the distribution subsidiaries.
     Other operating revenues declined $54.2 million in 1998, to $346.4 million,
due primarily to lower revenues from oil production and oil trading activities
as a result of declining oil prices during 1998.
     Regulated gas sales revenues of $1,851.0 million in 1997 were up $97.3
million compared to 1996, despite sales volumes decreasing 22.2 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 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.
     Nonregulated gas sales revenues increased $37.3 million in 1997 to $433.4
million, with sales volumes increasing 11.3 Bcf to 171.0 Bcf. The increases in
revenues and volumes reflect higher gas production at CNG Producing Company (CNG
Producing). Gas transportation and storage revenues rose $12.5 million in 1997
compared to the prior year, to $492.1 million, reflecting both higher gas
transportation and storage service revenues. Other operating revenues increased
$74.6 million in 1997 to $400.6 million. Revenues from oil trading 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.

OPERATING EXPENSES
Operating expenses, including income taxes, decreased to $2,392.9 million in
1998, compared to $2,766.7 million and $2,555.7 million in 1997 and 1996,
respectively.
     Purchased gas consistently represents the largest operating expense
category for the Company. Purchased gas costs were $900.4 million in 1998,
$1,114.1 million in 1997 and $963.2 million in 1996. This expense is influenced
primarily by changes in gas sales requirements, the price of gas supplies, and
the timing of recoveries of deferred purchased gas costs. The decline in 1998
was due primarily to decreased volume requirements in connection with the warm
weather in 1998, while lower average purchase prices also contributed to the
decrease. The recognition of previously deferred purchased gas costs and volumes
sold by CNG Retail were the primary factors for the increase from 1996 to 1997.
     Liquids, capacity and other products purchased expense includes the cost of
oil, condensate and by-products purchased for resale, electricity purchased for
resale by CNG Retail, and pipeline capacity not associated with gas purchased.
During 1998, this expense decreased $65.2 million due primarily to lower average
purchase prices for oil traded by CNG Producing and less pipeline capacity
purchased by CNG Transmission Corporation (CNG Transmission). This expense
increased $31.2 million in 1997 due primarily to increased oil trading activity
by CNG Producing.


                                       2
<PAGE>   5

     Combined operation and maintenance expense decreased $48.8 million in 1998
due largely to lower royalty expense, lower amortization expense related to
abandoned facilities and lower general and administrative expenses. The decline
in 1998 was partially offset by workforce reduction charges recognized in the
fourth quarter of 1998 due principally to the plan to reorganize the management
structure of the Company's regulated operations. Excluding the effect of
workforce reduction charges included in the 1996 amounts, combined operation and
maintenance expense increased $14.8 million in 1997. This increase was due in
part to higher royalty expense and production-related costs. These costs were
partially offset by lower employment costs.
     Total depreciation and amortization (DD&A) expense increased $5.3 million
in 1998 due to higher oil production volumes and $21.7 million in 1997 due
largely to higher gas and oil production volumes.
     Taxes, other than income taxes, declined $14.3 million in 1998 due chiefly
to the timing of the recognition of certain tax expense by one of the
distribution subsidiaries and were up $2.9 million in 1997 due in part to higher
excise taxes.
     Income taxes declined $26.7 million in 1998 due to lower pretax income and
a lower effective tax rate. Income taxes decreased $6.0 million in 1997 due
largely to a lower effective tax rate.

OTHER INCOME
Total other income was $34.7 million in 1998, compared to $12.4 million in 1997
and $9.0 million in 1996. "Other-net" increased $20.8 million during 1998 due
principally to increased earnings from equity investments at CNG International.
The increase in "Other-net" in 1997 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. Interest revenues increased $1.5 million in 1998 and decreased
slightly in 1997.

INTEREST CHARGES
Interest on long-term debt increased $1.4 million in 1998 and $3.1 million in
1997. The 1998 increase was primarily due to a full year of interest expense on
the $300 million of debentures issued in the fourth quarter of 1997, partially
offset by reduced interest expense in 1998 resulting from the redemption of the
convertible subordinated debentures. The increase in 1997 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 redemption in early 1997
of $100 million of debentures and the early extinguishment of $53.1 million of
debt in late 1996. Other interest expense increased $13.9 million in 1998 due
primarily to interest on commercial paper borrowings. Other interest expense
increased $2.4 million in 1997.

FOURTH QUARTER RESULTS
Net income for the fourth quarter of 1998 was $95.0 million, or $1.00 per share,
compared to $89.4 million, or $.94 per share, in 1997. Income from continuing
operations for the fourth quarter of 1998 was $97.2 million, or $1.02 per share,
compared to $89.1 million, or $.94 per share, in the prior year quarter. Results
for 1998 reflect lower operating costs which helped offset significantly lower
wellhead prices and warmer weather in that year. Also, the prior year quarter
included a non-cash charge of $6.7 million after taxes, or $.07 per share,
related to an impairment of Canadian oil producing properties. The change in
other income/expenses--net reflects higher equity income from CNG International
and gains on asset dispositions in 1998, while the 1997 fourth quarter includes
a charge in connection with the decision to sell and write down the carrying
value of the Company's interests in four independent power projects. The
Company's 1998 average gas wellhead price was $2.17 per thousand cubic feet
(Mcf), down $.37 per Mcf, while average oil wellhead prices declined $5.95 per
barrel compared to the prior year quarter, to $9.74 per barrel. Weather in the
fourth quarter of 1998 was 16.1% warmer than the prior year quarter.


                                       3
<PAGE>   6

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------
Quarters Ended December 31,                                      1998       1997 
----------------------------------------------------------------------------------
                                                                 (In Millions) 
<S>                                                            <C>         <C>    
Operating revenues........................................     $ 807.4     $940.9 
Operating expenses........................................      (654.4)    (781.2)
                                                                ------     ------ 
Operating income before income taxes......................       153.0      159.7 
Income taxes..............................................       (45.2)     (41.3)
Other income/expenses-net.................................       (10.6)     (29.3)
                                                                ------     ------ 
Income from continuing operations.........................        97.2       89.1 
Income (loss) from discontinued operations................        (2.2)        .3
                                                                ------     ------ 
Net income................................................      $ 95.0      $89.4
                                                                ======      =====
Earnings (loss) per common share--basic (in dollars)
   Continuing operations..................................      $ 1.02      $ .94 
   Discontinued operations................................        (.02)        --
                                                                ------     ------ 
Net income................................................      $ 1.00      $ .94
                                                                ======     ====== 
Earnings (loss) per common share--diluted (in dollars)
   Continuing operations..................................      $ 1.01      $ .92 
   Discontinued operations................................        (.02)        --
                                                                ------     ------ 
Net income................................................      $  .99      $ .92
                                                                ======     ====== 
----------------------------------------------------------------------------------
</TABLE>

NEW ACCOUNTING STANDARDS
During 1998, the Company adopted Statement of Financial Accounting Standards
(SFAS) No. 130, "Reporting Comprehensive Income," SFAS No. 131, "Disclosures
about Segments of an Enterprise and Related Information," and SFAS No. 132,
"Employers' Disclosures about Pensions and Other Postretirement Benefits." SFAS
No. 130 establishes standards for the reporting and display of comprehensive
income and its components. Reference is made to the Consolidated Statement of
Comprehensive Income, page 27. Reference is also made to Notes 1 and 18 to the
consolidated financial statements, pages 28 and 48, regarding SFAS No. 131. SFAS
No. 132 revises the Company's disclosures about pension and other postretirement
benefit plans. Reference is made to Note 7 to the consolidated financial
statements, page 34, regarding SFAS No. 132. The adoption of SFAS Nos. 130, 131
and 132 did not have a material effect on the Company's financial position,
results of operations or cash flows.
     Also during 1998, the American Institute of Certified Public Accountants
(AICPA) issued Statement of Position (SOP) 98-1, "Accounting for the Costs of
Computer Software Developed or Obtained for Internal Use," and SOP 98-5,
"Reporting on the Costs of Start-Up Activities." SOP 98-1 establishes standards
for accounting for costs incurred in developing or procuring computer software
for internal use. SOP 98-5 requires that costs for start-up activities be
expensed as incurred. The provisions of each SOP are effective beginning January
1, 1999, and the adoption of each SOP is not expected to have a material effect
on the Company's financial position, results of operations or cash flows.
     The Financial Accounting Standards Board issued SFAS No. 133, "Accounting
for Derivative Instruments and Hedging Activities," in 1998. SFAS No. 133
establishes new accounting standards for derivative instruments and for hedging
activities. The provisions of SFAS No. 133 are effective beginning January 1,
2000. The adoption of SFAS No. 133 is not expected to have a material effect on
the Company's financial position, results of operations or cash flows.

SEGMENTS OF THE BUSINESS
Due to the regulated nature of the distribution and transmission segments of the
Company's business, operating results can be affected by regulatory delays when
price increases are sought through general rate filings to recover certain
higher costs of operations. Weather is also an important factor since a major

                                       4
<PAGE>   7

portion of the gas sold or transported by the distribution and transmission
operations is ultimately used for space heating.
     Operating results for each of the Company's business segments, which
include affiliated transactions, follow. Reference is made to Note 18 to the
consolidated financial statements, page 48, for additional segment information.

<TABLE>
<CAPTION>
---------------------------------------------------------------------
OPERATING INCOME BEFORE INCOME TAXES      1998       1997      1996 
---------------------------------------------------------------------
                                                (In Millions) 
<S>                                      <C>        <C>       <C>    
Distribution.........................    $208.2     $266.6    $258.4 
Transmission.........................     183.6      180.9     181.6 
Exploration and production...........     116.6      142.8     133.2 
Other (a)............................      (1.4)      (7.3)      (.9)
Corporate and eliminations...........      (9.9)     (16.3)    (10.3)
                                         ------     ------    ------ 
   Total.............................    $497.1     $566.7    $562.0
                                         ======     ======    ======
</TABLE>
--------------------------------------------------------------------------------
(a)  Includes CNG International, CNG Products and Services, CNG Power, CNG Field
     Services (formerly CNG Storage Services), Consolidated LNG, CNG Research
     and CNG Coal. Amounts for 1998 and 1997 also include CNG Retail.


DISTRIBUTION
"Distribution" represents the results of the four retail gas distribution
subsidiaries: The East Ohio Gas Company (East Ohio Gas), The Peoples Natural Gas
Company (Peoples Natural Gas), Virginia Natural Gas, Inc. (Virginia Natural Gas)
and Hope Gas, Inc. (Hope Gas).
     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, 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 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.
     CNG Retail, created in 1997, markets 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, Peoples Natural Gas opened its system in
Pennsylvania to customer choice. In addition, on July 2, 1997, the Public
Utilities Commission of Ohio approved East Ohio Gas' "Energy Choice" (EOG Energy
Choice) pilot program which allows approximately 15% of East Ohio Gas'
residential and small business customers the opportunity to purchase their
natural gas from competing suppliers, if they so choose.

      DISTRIBUTION OPERATING INCOME BEFORE INCOME TAXES

      1998
Operating income before income taxes declined $58.4 million in 1998, to $208.2
million, compared to 1997. The impact of warmer weather in 1998 was partially
mitigated by lower operation expenses and the timing of the recognition of
excise tax expense. Weather in the Company's retail service areas was 17.8%
warmer than normal and 19.3% warmer than 1997. The 1998 period also included a
$4.5 million charge for workforce reduction costs recognized in the fourth
quarter in connection with the Company's plan to reorganize and centralize the
management of its regulated operations.

                                       5
<PAGE>   8

      1997
Operating income before income taxes was $266.6 million in 1997, up $8.2 million
from the prior year. However, the 1996 period included workforce reduction
charges of $8.2 million. 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 and 4.3% warmer than
1996.

      1996
Operating income before income taxes increased $50.9 million in 1996. 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 and East Ohio Gas. Weather in the
Company's retail service areas was 5.5% colder than 1995 and 5.6% colder than
normal. Operating results for 1996 and 1995 include workforce reduction charges
of $8.2 million and $22.3 million, respectively.

      DISTRIBUTION OPERATING REVENUES
Operating revenues decreased $414.8 million, to $1,611.8 million, in 1998.
Average sales rates and volumes declined in 1998 compared to the prior year.
Sales rates declined due to the pass-through of lower purchased gas costs. Lower
volumes in 1998 reflected warmer weather during the year and the impact of
former residential sales customers who now purchase gas from other suppliers,
including CNG Retail. Gas transportation and storage revenues increased $44.0
million in 1998 due to both higher volumes and rates. The increase in gas
transportation volumes reflects the switch by residential customers from sales
to transport service.
     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.

      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     1998    1997    1996
---------------------------------------------------
                           (In Billion Cubic Feet)
<S>                         <C>     <C>     <C>  
Sales .................     207.6   272.7   294.2
Transportation.........     198.9   189.4   174.2
                            -----   -----   -----
      Throughput.......     406.5   462.1   468.4
                            =====   =====   =====
---------------------------------------------------
</TABLE>
       Gas sales volumes declined in 1998 compared to the prior year primarily
as a result of warmer weather and the continued displacement of sales volumes to
other suppliers. Residential gas sales volumes declined 47.9 Bcf in 1998, to
159.9 Bcf. The distribution subsidiaries transported 14.6 Bcf of gas in 1998,
compared to 2.7 Bcf in 1997, on behalf of former residential sales customers who
now purchase gas from other suppliers, including CNG Retail. Sales to commercial
customers declined 15.4 Bcf to 44.3 Bcf while volumes transported to these
customers decreased .3 Bcf to 43.0 Bcf, both declines being attributable to the
warm weather. Total deliveries to industrial customers decreased 2.6 Bcf, to
135.7 Bcf. Industrial transport volumes were down .8 Bcf to 133.2 Bcf, while
sales volumes declined 1.8 Bcf to 2.5 Bcf. Off-system transport volumes were
down 1.3 Bcf in 1998, to 8.1 Bcf.
     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 in 1997 compared to 1996. 

                                       6
<PAGE>   9

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 transportation volumes increased 2.1 Bcf to 134.0 Bcf.
Transportation to off-system customers increased 4.1 Bcf in 1997.

TRANSMISSION
"Transmission" includes the results of the gas transmission, storage, by-product
and certain other activities of CNG Transmission and the by-products business of
CNG Power. Gas and oil production activities of CNG Transmission are included in
the exploration and production segment.

      TRANSMISSION OPERATING INCOME BEFORE INCOME TAXES

      1998
Operating income before income taxes was $183.6 million in 1998, an increase of
$2.7 million compared to the prior year. The 1998 results include the impact of
the favorable resolution of a regulatory contingency amounting to $13.9 million
and a charge for workforce reduction costs of $1.1 million. Also, the 1997
results included a charge amounting to $5.8 million recognized in connection
with CNG Transmission's withdrawal from participation in a gas storage
development project.

      1997
Operating income before income taxes declined slightly in 1997, to $180.9
million. While the 1997 period included the charge for the storage project
indicated above, 1996 results included a $5.1 million charge for workforce
reduction costs.

      1996
Operating income before income taxes was $181.6 million in 1996. Cost control
efforts and increased gas transportation and by-products revenues contributed to
the improved results in 1996. Workforce reduction charges for these operations
were about the same in 1996 and 1995.

      TRANSMISSION OPERATING REVENUES
Total operating revenues increased $3.2 million during 1998, to $502.5 million.
Gas transportation revenues increased $4.1 million, as higher average rates more
than offset lower volumes, and gas storage service revenues increased $3.0
million. Revenues from the sale of by-products declined $18.2 million due to
lower sales rates. Higher other operating revenues for 1998 include $13.9
million relating to the favorable resolution of a regulatory contingency.
     Total operating revenues declined $17.8 million in 1997, to $499.3 million.
Gas transportation revenues declined $15.7 million due to both lower volumes and
rates, and revenues from the sale of by-products decreased $5.1 million due
primarily to lower sales rates. These decreases were partially offset by an
increase of $2.8 million in gas storage service revenues.

      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.
A further expansion project in conjunction with East Ohio Gas and others will
provide additional capacity at minimal cost. 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 deregulation of the gas
industry at the retail level (see "Distribution," page 5, and "Gas and Electric
Industry Developments," page 11).


                                       7
<PAGE>   10

     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, was 612.5 Bcf, 732.8 Bcf and 758.4 Bcf for the years
1998, 1997 and 1996, 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

      1998
Operating income before income taxes in 1998 was $116.6 million, a decline of
$26.2 million from 1997. Results for 1998 reflect the impact of lower average
gas and oil wellhead prices and lower gas production, partially offset by higher
oil production. Both oil and gas production were negatively impacted during the
third quarter of 1998 due to four hurricanes and tropical storms that forced
temporary shutdowns of oil and natural gas wells in the Gulf of Mexico. These
storms also delayed development efforts at the Nautilus complex, delaying
initial production at that location until the first quarter of 1999. During
1998, CNG Producing added 374 Bcf of gas equivalent from additions, revisions,
and purchases of gas and oil reserves and also purchased 39 Bcf of gas reserves
from an affiliate, Peoples Natural Gas. The 1997 results include a non-cash,
pretax charge of $10.4 million related to the Company's impairment of its
Canadian oil producing properties.

      1997
Operating income before income taxes in 1997 was $142.8 million, up $9.6 million
from 1996. As noted above, the 1997 results include an impairment charge of
$10.4 million. 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 was $133.2 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 in 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.

      GAS AND OIL PRODUCTION, PRICES AND OTHER INFORMATION
The following table sets forth the Company's gas and oil production, average
wellhead prices and other information for the E&P operations for the last three
years:

                                       8
<PAGE>   11

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------
                                                                  1998      1997      1996
-------------------------------------------------------------------------------------------
<S>                                                             <C>       <C>       <C>  
GAS (BCF)
Nonregulated................................................      154.9     155.3     144.5
Regulated*..................................................        2.6       2.8       3.0
                                                                  -----     -----     -----
   Total....................................................      157.5     158.1     147.5
                                                                  =====     =====     =====
OIL (000 BBLS)
Nonregulated................................................    7,894.7   7,312.0   4,765.9
                                                                =======   =======   =======
AVERAGE WELLHEAD PRICES--NONREGULATED
Gas (per Mcf)...............................................     $ 2.26    $ 2.43    $ 2.46
Oil (per Bbl)...............................................     $11.54    $16.07    $17.60


OTHER E&P DATA--NONREGULATED
DD&A (per Mcf equivalent)...................................       $.89      $.88      $.93
Average production (lifting) cost (per Mcf equivalent)......       $.31      $.33      $.32
</TABLE>

*    Cost-of-service. Cost-of-service gas reserves were held solely by Peoples
     Natural Gas and sold to CNG Producing during 1998.
--------------------------------------------------------------------------------
     The Company's average gas wellhead price was $2.26 per Mcf in 1998, down
$.17 from 1997 but still favorable compared to industry-wide prices in 1998 due
to a market price hedging program. For 1999, the Company has used derivatives to
effectively sell forward approximately 102.3 Bcf of gas production as of
February 1, 1999 at an average price of $2.25 per Mcf. Gas production in 1998
was down .6 Bcf, to 157.5 Bcf, compared to 1997. Average oil wellhead prices
were $11.54 per barrel in 1998, down $4.53 from 1997, while oil production
increased nearly 600,000 barrels, to 7.9 million barrels. The increase in oil
production in 1998 was due in part to a full year of production at Neptune, a
deep-water project in the Gulf of Mexico which began production in March 1997.
     The Company's average gas wellhead price was $2.43 per Mcf in 1997, down
slightly from 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 was due
largely to the impact of Neptune.

      E&P OPERATING REVENUES
Total operating revenues for the E&P operations were $631.1 million in 1998, a
decline of $74.6 million from 1997. Gas sales revenues decreased $9.4 million
due to both lower volumes and lower average gas prices compared to 1997.
Revenues from oil and condensate production and trading declined $71.9 million
in 1998 as the effect of lower average sales prices outweighed the impact of
higher sales volumes. Revenues from oil trading decreased $45.6 million and
revenues from oil and condensate production declined $26.3 million. Other
operating revenues increased $6.7 million in 1998.
     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 trading increased $73.0 million
in 1997, with higher sales volumes more than offsetting the impact of lower
rates. Revenues from oil trading rose $39.7 million and revenues from oil and
condensate production increased $33.3 million.

OTHER
This component, as described in the operating results table on page 5, reported
operating losses before income taxes of $1.4 million, $7.3 million and $.9
million in 1998, 1997 and 1996, respectively. Start-up costs of CNG Retail and
CNG Products and Services are reflected in their combined losses of $5.3
million, $3.8 million and $1.5 million in 1998, 1997 and 1996, respectively.
Partially offsetting the 1998 losses was $8.8 million of pretax operating income
from CNG Field Services. Also helping to offset start-up costs somewhat was
pretax operating income from Consolidated LNG of $.2 million, $1.4 million and


                                       9
<PAGE>   12

$2.6 million for the years 1998, 1997 and 1996, respectively, reflecting the
recognition of deferred income pursuant to a regulatory order.

     Results of this component for 1998, 1997 and 1996 also reflect the
operations of CNG International, which had pretax operating losses of $4.7
million, $6.8 million and $3.8 million, respectively. However, earnings from CNG
International's operations are attributable to investments in foreign utilities
and pipelines which are accounted for under the equity method and are excluded
from the operating income amounts. CNG International reported net income of $2.5
million for 1998 and reported net losses of $3.8 million in 1997 and $2.6
million in 1996.

DISCONTINUED OPERATIONS
During April 1998, management approved a plan to discontinue the Company's
wholesale trading and marketing of natural gas and electricity, including
integrated energy management. On July 31, 1998, the sale of the capital stock of
CNG Energy Services Corporation, formerly a wholly-owned subsidiary of the
Company, to Sempra Energy Trading, a subsidiary of Sempra Energy, was finalized.
Included in the transaction were contracts for the purchase and sale of natural
gas as well as rights to natural gas pipeline and storage capacity, mainly in
the Northeast and Mid-Atlantic regions, and related working capital. Proceeds of
$37.4 million were received from the sale of the stock, as adjusted for working
capital items. The Company's transition out of the wholesale gas business was
substantially complete at December 31, 1998.
     Losses from discontinued operations, net of applicable tax benefits, were
$17.2 million, $14.5 million and $11.1 million for the years 1998, 1997 and
1996, respectively. In addition, during 1998 the Company recognized a loss on
disposal of the discontinued operations, including a provision for operating
losses during the phase out period, of $31.7 million, net of applicable tax
benefit.

INTERNATIONAL ACTIVITIES
During December 1997, CNG International acquired ownership interests in two gas
utility holding companies, Sodigas Pampeana S.A. and Sodigas Sur S.A., and 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 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. In March 1998 CNG
International purchased additional interests in Sodigas Pampeana S.A., Sodigas
Sur S.A. and BAECO from Loma Negra, bringing the Company's ownership interests
in these entities to 21.55%, 21.55% and 25%, respectively. Camuzzi Argentina
S.A. maintains majority ownership interests in the holding companies. At
December 31, 1998, CNG International's investments in the Argentine holding
companies totaled $122.8 million.
     In March 1998 CNG International purchased a 33.3% ownership interest in the
Dampier-to-Bunbury Natural Gas Pipeline (DBNGP) in Western Australia from the
Western Australia Government. One of CNG International's partners in the
purchase was El Paso Energy Corporation (El Paso), which also holds a 33.3%
ownership interest. In connection with their investments in DBNGP, CNG
International and El Paso formed DBNGP Finance Company LLC (DBNGP Finance).
DBNGP Finance is owned 50% by CNG International and 50% by EPED Holding Company,
a wholly-owned subsidiary of El Paso. Subsequent to the formation of DBNGP
Finance, the equity ownership interests of CNG International and El Paso in
DBNGP were transferred to this entity.
     In October 1998 DBNGP Finance borrowed $250 million under a Senior Term
Loan Facility (Term Loan). The Term Loan matures October 2, 2001, can be
extended in one-year increments to October 2, 2003, and will bear interest at a
variable rate. Of the gross proceeds received by DBNGP Finance under the Term
Loan, $100 million was distributed to CNG International. In connection with the
Term Loan, CNG International entered into an Equity Contribution Agreement with
DBNGP Finance. CNG International is contractually obligated to make equity
contributions to DBNGP Finance equal to the Term Loan proceeds distributed to
CNG International, plus interest on such proceeds, in the event that DBNGP


                                       10
<PAGE>   13

Finance is unable to service this debt. The Company is contractually obligated
to cause CNG International to make such contributions.

     CNG International's investments in Australia at December 31, 1998,
including DBNGP Finance, totaled $77.6 million.

LIMITATION ON CAPITALIZED COSTS
As indicated in Note 1 to the consolidated financial statements, the Company
follows the full cost method of accounting for its gas and oil producing
activities prescribed by the Securities and Exchange Commission (SEC). Reference
is made to Note 5 to the consolidated financial statements, page 33, regarding
the Company's recognition under the SEC full cost rules of an impairment of its
gas and oil producing properties at December 31, 1997.
     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
Gas industry competition at the retail level is receiving increased attention
from both regulators and legislators. Governments in three 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. Implementation of the law, which allows retail customers
to obtain gas from an array of suppliers, is under way. In Pennsylvania, pending
legislation would unbundle gas utility merchant functions and permit the
Pennsylvania Public Utility Commission to certify marketers, in addition to gas
utilities, as suppliers of last resort, creating competition in a traditional
gas utility function. Most recently, Virginia has begun to consider gas
unbundling legislation.
     In addition to restructuring of the gas industry, the emerging unbundling
of services provided by electric utilities is leading toward the convergence of
the two industries to create one overall, highly competitive marketplace for a
customer's total energy needs. Regulators and legislators at the federal level
and in many states are considering, or are already implementing, initiatives to
promote increased competition in the electric industry. A major development was
the issuance in 1996 of FERC 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. The companion order, Order 889, addresses the timing,
information access and other administrative details associated with the FERC
deregulation initiative. Congress also is considering legislation intended to
facilitate the move to competition in the electric industry.
     Although progress status varies, pro-competition electric legislation is at
least under consideration in many states. In Ohio, leaders of the General
Assembly have predicted passage in 1999 of a bill to assure customer choice. In
Pennsylvania, the 1996 Electric Generation Customer Choice and Competition Act
required the transition to a competitive retail electric market to begin in
January 1999, with full competition by 2001. In Virginia, the General Assembly
may enact a restructuring bill which would phase in retail competition starting
on January 1, 2002. Regulators and legislators in West Virginia are also
debating issues related to electric industry restructuring.
     Reflecting the evolution to a more competitive energy environment, the pace
and size of business combinations among natural gas and electric utilities has
increased in recent years (reference is made to Note 19 to the consolidated
financial statements, page 52, regarding the Company's proposed merger with
DRI). 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.


                                       11
<PAGE>   14

     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, Congress has
considered legislation to conditionally repeal the Public Utility Holding
Company Act of 1935 (PUHCA), to which the Company is subject. While it seems
unlikely that Congress will enact PUHCA legislation on a stand-alone basis, it
appears more likely that any comprehensive electric restructuring bill will
include a PUHCA repeal provision. If legislation to repeal or significantly
modify the provisions of the PUHCA becomes law, certain federal restrictions
related to diversification activities, including business combinations, for gas
and electric companies subject to the PUHCA may be eased.
     To focus the distribution and transmission operations on being more
responsive to customer needs and to enable them to more effectively seize growth
opportunities in the competitive marketplace, the Company announced a
significant reorganization of the management structure of its regulated
businesses in December 1998. The new structure brings all five regulated
subsidiaries--CNG Transmission, East Ohio Gas, Peoples Natural Gas, Virginia
Natural Gas and Hope Gas--under the leadership of a single management team. This
new team will manage by business process rather than by company. However, all
five companies will remain separate legal entities and will retain their names.

      FEDERAL AND STATE REGULATORY ISSUES
On April 29, 1998, the Virginia State Corporation Commission issued a final
order in connection with the September 25, 1996 expedited rate application of
Virginia Natural Gas. The order resulted in an annual revenue increase of $7.2
million, retroactive to October 25, 1996, the date new rates went into effect
subject to refund. Customer refunds resulting from the order were made in 1998.
The order reflects an imputed return on equity of 10.9%. In its filing, Virginia
Natural Gas had requested a $13.9 million increase in annual revenues and a
return on equity of 11.3%.
     On July 28, 1998, the Public Service Commission of West Virginia approved a
settlement agreement filed by Hope Gas in connection with its January 5, 1998
general rate filing. The new rates became effective November 1, 1998. Under the
settlement, Hope Gas is not permitted to request an increase in rates prior to
January 1, 2002, nor is it obligated to file for new rates after that date. The
approved settlement agreement grants Hope Gas a combined $6.5 million annual
revenue increase for both base rates and gas costs. Hope Gas had originally
proposed a $14.5 million annual increase in revenues.
     On November 24, 1998, the FERC approved a settlement filed by CNG
Transmission in connection with its July 1, 1997 general rate filing. The
settlement resolves the outstanding issues in the case and maintains the
preexisting level of annual revenues. The settlement reflects an imputed return
on equity of 10.7%. CNG Transmission made interim customer refunds amounting to
$39.2 million in December 1998, and expects to make a final settlement refund of
approximately $19 million by the end of the first quarter of 1999. In its
filing, CNG Transmission had requested a $71 million increase in annual revenues
and a return on equity of 14.5%.

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

                                       12
<PAGE>   15

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 1998, the Board of Directors continued the quarterly dividend on the
common stock at $.485 a share. Total dividends paid to common shareholders in
1998 were $185.9 million compared with $184.6 million in 1997 and $183.0 million
in 1996.
     During 1998, a total of 335,333 original issue shares were issued through
various Company-sponsored plans, including 282,273 shares acquired by employees
through the exercise of outstanding stock options.
     Under the Company's stock repurchase plan, up to 10 million shares of the
Company's common stock can be repurchased in the open market. Shares may also be
purchased 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. In January 1998, the Company purchased approximately 4.6
million shares of its common stock in a private transaction for use in
satisfying the conversion rights of debentures called for redemption (see "Call
of Debentures," Page 14). 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 nonqualified benefit plans via a grantor trust. At December 31, 1998 and
1997, a total of 495,123 and 659 shares, respectively, were being held as
treasury stock.

CAPITAL SPENDING
The current capital spending program for 1999 is estimated at $524.5 million, a
31% decrease compared with total capital spending in 1998. The estimated 1999
budget has been allocated as follows: exploration and production, $337.0
million; distribution, $128.4 million; transmission, $51.3 million; and
corporate and other, $7.8 million. The decreased level of capital expenditures
planned for 1999 anticipates lower spending for international projects, which
will be evaluated on a case-by-case basis. Exploration and production operations
reflect increased spending on deep-water projects and increased conventional
onshore and offshore drilling. 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.
     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 1999 to
support capital spending, and may also utilize the capital markets to take
advantage of other opportunities, including exploration and production
acquisitions, or to increase its financial flexibility.

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 from continuing operations was $767.4 million,
$784.1 million and $424.9 million for the years 1998, 1997 and 1996,
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 

                                       13
<PAGE>   16
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.

     In October 1998, the Company sold $200 million of 6% Debentures Due October
15, 2010. The proceeds were 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 $338.3 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 1998 was 6.96%, compared with 7.20% for 1997 and 7.27% for 1996. The
long-term debt to capitalization ratio was 36.5%, 39.7% and 39.3% at the end of
1998, 1997 and 1996, 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 A2 by Moody's Investors
Service, AA-- by Standard & Poor's, AA-- by Duff and Phelps, and AA by Fitch
Investors Service.
     At December 31, 1998, 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 1998 and there were no amounts outstanding under any credit
agreements at December 31, 1998 or 1997.
     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 1998, of which $558.9 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
In January 1998 the Company called for redemption the entire principal amount
outstanding of its 7-1/4% Convertible Subordinated Debentures, totaling $246.2
million. These debentures were convertible into shares of the Company's common
stock at an initial conversion price of $54 per share. The redemption price was
102.18% of the principal amount plus accrued interest payable on February 23,
1998. In anticipation of the call, in January 1998 the Company purchased
approximately 4.6 million shares of its common stock in a private transaction to
satisfy the potential conversion obligation. 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 were sold in two
underwritten offerings during February and March 1998.

YEAR 2000 TECHNOLOGY ISSUE
Similar to all business entities, the Company will be impacted by the inability
of some computer application software programs to distinguish between the year
1900 and 2000 due to a commonly-used programming convention.
     In the early 1990s, the Company identified business systems in need of
technology updates to successfully adapt to changes in the business climate and
the emerging competitive marketplace. These changes required the Company to move
toward common, integrated systems and computing platforms. Accordingly, many
systems representing older technology, which were not year 2000 ready, were
targeted for replacement. This plan is being executed through major initiatives
such as a company-wide implementation of Oracle Financial Applications, the
development of a new revenue and customer information system for the
distribution subsidiaries called "CAMP," and the development and implementation
of applications for gas control management and asset and facilities mapping.
Through these initiatives over 75 application systems, including associated
technical infrastructure, are being replaced.
     In 1997, the Company formalized its approach to year 2000 issues with the
creation of a Year 2000 Project Office (Project Office) at the corporate level
to coordinate company-wide year 2000 activities. All of the Company's operating
subsidiaries are participating in this effort under the direction of the Project
Office.


                                       14
<PAGE>   17

     The Company is addressing year 2000 issues via a systematic methodology
that mitigates risk and incorporates a thorough due diligence process. This
strategy recognizes that the definition of "year 2000 compliance" varies broadly
depending on the industry, component, vendor, and/or device. The Company's
strategy prioritizes the critical areas of the business to eliminate any
potential impact on safety, and to mitigate or eliminate any adverse effect on
revenues, assets, customer service and the environment that may result from the
date change event.

      PROJECT DESCRIPTION AND ACTIVITIES
The major areas of focus of the Company's year 2000 efforts include application
systems, process control components, technical infrastructure, physical
infrastructure, and business partner and vendor relationships.
These project areas are summarized below:
     Application Systems. Application systems encompass all automated systems,
including those developed internally and those purchased from vendors. These
systems include traditional business applications, as well as operations and
engineering applications.
     Process Control Components (embedded technology). Process control devices
automate certain production, transportation and delivery functions in connection
with natural gas, oil and liquids. These devices, such as flow computers and
pressure regulators, generally include embedded computer technology.
     Technical Infrastructure. This category represents the underlying technical
architecture which supports the Company's application systems, e-mail, and
similar infrastructure. This infrastructure includes mainframe hardware and
software, application servers, local and wide area networks, desktop personal
computers and telecommunications.
     Physical Infrastructure. This category represents the Company's physical
plant, including office buildings. Building infrastructure such as elevators,
HVAC systems, security and fire alarm systems are examples of components
included in this category.
     Business Partner and Vendor Relationships. This area involves analysis of
critical business partner and vendor relationships and third party commitment to
addressing year 2000 issues via discussion, contract reviews and additional
detailed assessment as considered necessary.
     For each of the areas described above, the Company employs a five-phase
process methodology as follows:

      (1)  Inventory: In this phase, the Company compiles comprehensive
           inventories of each of the major project areas.
      (2)  Assessment and Analysis: This phase is performed to determine the
           extent to which year 2000 issues exist in any of the inventoried
           areas and, if so, whether the issue is controllable (can be remedied
           by the Company) or non-controllable (is dependent upon vendor
           representation and/or remediation and can only be tested by the
           Company).
      (3)  Repair and Replacement: Renovations, replacements, and upgrades are
           made during this phase to remedy year 2000 issues.
      (4)  Testing: During this phase, independent testing is performed to 
           ensure year 2000 issues have been mitigated.
      (5)  Continuity Planning: This phase is focused on ensuring continuity of
           major and critical business processes that could be affected by year
           2000 events. This effort includes "zero-day" (December 31, 1999),
           contingency, and recovery planning in combination to consider and
           mitigate the effects of unknown internal and external year 2000
           risks.

     The Company utilizes a multi-vendor strategy to maximize the effectiveness
of its year 2000 efforts. The Company's primary external consultants include
Compuware Inc. (analysis and renovation of mainframe and client/server
application systems, tools for testing of application systems and professional
services for application systems test planning) and Keane, Inc. (process control
component analysis, test planning and execution; operations and engineering
application systems inventory and analysis; continuity planning; and
facilities/physical infrastructure inventory and analysis).


                                       15
<PAGE>   18

PROJECT STATUS
The following summarizes the Company's progress in the major project areas
through December 31, 1998:

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------
                                                 PHASE
-----------------------------------------------------------------------------------------
  PROJECT AREA       Inventory     Assessment      Repair/       Testing      Continuity
                                                   Replace                     Planning
-----------------------------------------------------------------------------------------
<S>                 <C>            <C>           <C>            <C>           <C>   
  APPLICATION        Complete      Complete      In progress    In progress   In progress
  SYSTEMS
-----------------------------------------------------------------------------------------
  PROCESS CONTROL    Complete      Complete      In progress    In progress   In progress
  COMPONENTS
-----------------------------------------------------------------------------------------
  TECHNICAL          Complete      Complete      In progress    In progress   In progress
  INFRASTRUCTURE
-----------------------------------------------------------------------------------------
  PHYSICAL           In progress   In progress   In planning    In planning   In planning
  INFRASTRUCTURE
-----------------------------------------------------------------------------------------
  BUSINESS           Ongoing       Ongoing       Not            Not           In progress
  PARTNERS AND       process       process       applicable     applicable
  SUPPLIERS
-----------------------------------------------------------------------------------------
</TABLE>

     Application Systems. During the assessment phase, approximately 80
application systems were identified requiring some degree of repair or
replacement. However, the Company's actions to upgrade to newer, more functional
versions of vendor software have mitigated many existing year 2000 issues. These
upgrade activities will continue through mid-1999. Repair and replacement
activities for internally developed application systems began in March 1998 and
are substantially complete at year end 1998, with testing continuing through
mid-1999. Reference is made to "Risks," page 17, for information on the status 
of CAMP.
     Process Control Components. For process control components inventoried by
the Company, approximately 43% are not date sensitive, and therefore are not
affected by year 2000 issues. For date sensitive components, the Company
estimates a year 2000 failure rate of approximately 10% to 12%. Replacement of a
small number of non-compliant components will continue through early 1999, while
testing of components believed to be year 2000 ready continues and is
approximately 44% complete.
     Technical Infrastructure. Technical infrastructure has been analyzed
directly with vendors and via the use of an external vendor research database
service. This information is being used to guide year 2000 upgrades of
infrastructure as necessary. Repair, replacement and testing activities are
approximately 92% complete for all categories of technical infrastructure, while
efforts in the critical area of application servers are 93% complete. The
Company had completed a substantial portion of year 2000 upgrades by the end of
1998, and is continuing with testing into 1999.
     The Company has developed plans to determine the status of year 2000
readiness of its desktop personal computers. Inventory activities began in
December 1998, and are expected to continue through February 1999, after which
any repair or replacement activities will commence. Updated desktop
infrastructure continues to be deployed that is year 2000 ready concurrent with
the implementation of many new application systems described above. The Company
plans to confirm year 2000 readiness of this infrastructure via testing, which
is expected to be completed by mid-1999.

                                       16
<PAGE>   19

     Physical Infrastructure. The Company has completed the inventorying of
non-gas related physical infrastructure components that may be subject to year
2000 problems, and is currently verifying its inventory of gas-related
facilities. Critical physical infrastructure components that are related to
process control have been inventoried and assessed in the process control area
of the project. Repair activities, if necessary, will follow the verification
process. Where facilities are leased, the Company is identifying and working
with building managers/lessors to ensure they are actively addressing the year
2000 issue as a primary effort in continuity planning.
     Business Partner and Vendor Relationships. Strategic business partner and
vendor relationships have been given priority in the inventory phase, and
assessment continues via questionnaires and interviews. Over 1,000 strategic
relationships had been identified and queried by the end of 1998. The Company
will continue to prioritize, identify and assess business partner and vendor
relationships until significant areas of risk have been identified and
mitigated, and is also preparing contingency plans in the event mitigation
efforts are not successful. The Company had performed a preliminary analysis of
all significant relationships by the end of 1998, including the year 2000 status
of operations in Argentina and Australia in which the Company has investments.
     Continuity Planning. The Company has completed development of a continuity
planning methodology and has identified critical business processes. Business
continuity managers have been identified and will be trained in the continuity
planning methodology in early 1999. Continuity plans are expected to be
developed commencing February 1999, drawing upon an extensive inventory of
contingency and recovery plans already in operation.

Costs
Based upon project status as described above, the Company expects to spend a
total of approximately $22.6 million in connection with its Project Office
efforts, its use of external consultants and the remediation of affected
application systems. This estimate includes $6.8 million of capitalized costs
for hardware and software used (or expected to be used) in the testing phase,
and for application system and technical infrastructure replacements. This
estimate excludes costs incurred or expected to be incurred in connection with
the development and installation of major new application systems which are
expected to be year 2000 ready, the Company's potential share of year 2000 costs
that may be incurred by partnerships and joint ventures in which the Company
participates but is not the operator, and internal labor costs other than those
of the core Project Office. As of December 31, 1998, the Company has incurred
costs approximating $5.4 million (of which $1.5 million has been capitalized) in
connection with its year 2000 efforts. Total costs incurred as of December 31,
1998, as a proportion of the total year 2000 budget, is not indicative of the
overall completion rate of the project, which is estimated to be over 50%.

Risks
Significant progress has been made in the development of CAMP for use at Hope
Gas and EOG Energy Choice. However, previous technical difficulties and delays
have caused the Company to invoke a contingency plan which involves renovation
of the current revenue application system for the other distribution
subsidiaries and 20 related application systems to make such systems year 2000
ready. These current systems collectively address the business processes which
were to be handled by CAMP. Renovation activities have been completed in
connection with this contingency plan and implementation, including testing, is
scheduled to be completed by August 1999. Under a worst case scenario, the
current revenue application systems would not be year 2000 ready by the end of
1999 for the other distribution subsidiaries and CAMP would not be successfully
implemented or year 2000 ready at Hope Gas and EOG Energy Choice. The estimate
of $22.6 million referred to above includes approximately $2.3 million of costs
in connection with the CAMP contingency plan. Concurrent with this effort, the
Company is continuing the development of CAMP and has capitalized $53.0 million
related to this project as of December 31, 1998. The CAMP core software is a
licensed product of the Company's independent accountants,
PricewaterhouseCoopers LLP (PwC), and PwC is the primary information systems
consultant on this project.

                                       17
<PAGE>   20

     If a material year 2000 problem is not corrected in a timely manner, an
interruption in, or a failure of, certain normal business activities or
operations of the Company could occur. Such instances could materially and
adversely affect the Company's financial position, cash flows and/or results of
operations. Due to the uncertainty inherent in the year 2000 issue, including
the uncertainty of year 2000 readiness of third party vendors, business partners
and customers, the Company cannot determine at this time whether the
consequences of any year 2000 failures will have a material impact on its
financial position, cash flows or results of operations. However, the Company's
Project Office activities and the implementation of new application systems are
expected to reduce the risk of a material year 2000 failure.

PRICE RISK MANAGEMENT ACTIVITIES
In the normal course of business, certain of the Company's operations are
subject to market risk and credit risk in connection with the production,
purchase and sale of natural gas and oil and stored gas inventories. In
addition, the Company's foreign equity investments are subject to foreign
currency risk. Reference is made to Note 15 to the consolidated financial
statements, Page 45, regarding the fair value of the Company's long-term debt
which is comprised of fixed-rate instruments.

      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 all subsidiaries.
     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 respect to
its counterparties that management believes minimize overall credit risk. Such
policies include the evaluation of a prospective counterparty's financial
condition, collateral requirements where deemed necessary, and the use of
standardized agreements which facilitate the netting of cash flows associated
with a single counterparty. 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, 1998, the Company
believes it unlikely that a material adverse effect on its financial position,
results of operations or cash flows would occur as a result of counterparty
nonperformance.
     The Company uses over-the-counter (OTC) price swap agreements,
exchange-traded futures contracts, and option contracts to manage market risk
inherent in the production, purchase and sale of natural gas and oil and stored
gas inventories. The level of market risk exposure from these activities is
maintained within risk management guidelines.

      USE OF DERIVATIVES--NATURAL GAS
Information as of December 31, 1998 and 1997 for derivatives that are sensitive
to changes in natural gas prices 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
these disclosures exclude information about the Company's natural gas commodity
purchase and sale commitments which are sensitive to changes in natural gas
prices, and information related to firm transportation and storage agreements
for which the Company must make specified minimum payments each month.
Therefore, the information presented regarding the use of derivatives by the
Company does not reflect the earnings impact of the physical transactions that
may offset the financial gains and losses arising from the use of derivatives.

                                       18
<PAGE>   21

     The following table presents net notional quantities and weighted average
settlement prices by expected maturity date for futures contracts used to hedge
natural gas price risk. All of the contracts included in the table below have
been designated as hedges of the future production, purchase and/or sale of
natural gas. At December 31, 1998, the Company held no futures contracts with
maturity dates extending beyond 2001.

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------
                                                                   Expected Maturity Date               Unrealized
                                                                 ---------------------------              Gain
Exchange-Traded Futures Contracts                                1999      2000        2001     Total  at 12/31/98
--------------------------------------------------------------------------------------------------------------------
                                                                                                      (In Thousands)
<S>                                                              <C>       <C>        <C>     <C>     <C>    
Contract volumes (in 10,000 mmbtu), purchased (sold).........    (7,048)     314          51  (6,683)   $16,418
Weighted average settlement price (per mmbtu)................     $2.18    $2.17       $2.29
--------------------------------------------------------------------------------------------------------------------
</TABLE>

       At December 31, 1997, the Company held futures contracts related to
natural gas purchase and sale commitments and storage inventory covering 2.9 Bcf
of gas on a net basis maturing through 2000 having a net unrealized loss of $1.1
million.
     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, 1998, the Company had not entered into any price swap
agreements extending beyond 2003. All of the swap agreements included in the
table below have been entered into to hedge the risk of market price changes in
connection with the future production, purchase and/or sale of natural gas. 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.

PRICE SWAP AGREEMENTS
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------
                                                  Expected Maturity Date                
                                         ---------------------------------------
(Quantities in 10,000 mmbtu)                                                                      Fair Value
(Rates per mmbtu)                        1999    2000       2001      2002   2003    Total       at 12/31/98 
--------------------------------------------------------------------------------------------------------------
                                                                                                (In Thousands) 
<S>                                      <C>     <C>         <C>     <C>     <C>     <C>           <C>      
Pay Fixed, Receive Variable
---------------------------
Net notional quantities.............     7,922   4,734       3,958                   16,614        $(23,491)
   Weighted average pay rate........      $.99    $.97       $1.31
   Weighted average receive rate....      $.78    $.88       $1.24                                          


Receive Fixed, Pay Variable
---------------------------
Net notional quantities.............     4,540   2,708       1,854   1,718   1,704   12,524        $ 13,388 
   Weighted average pay rate........     $1.27   $1.68       $2.12   $2.22   $2.27
   Weighted average receive rate....     $1.57   $1.68       $2.08   $2.23   $2.28
--------------------------------------------------------------------------------------------------------------
</TABLE>
       At December 31, 1997, the Company had price swap agreements of varying
duration outstanding to exchange monthly payments on net notional quantities of
gas over the ensuing five years. Net notional quantities and related fair value
at that date for swap agreements in which the Company pays a fixed price in
exchange for a variable price totaled 324.5 Bcf and $(26.3) million,
respectively. For swap agreements in which the Company pays a variable price in
exchange for a fixed price, net notional quantities and related fair value at
December 31, 1997 totaled 297.2 Bcf and $28.7 million, respectively.

      USE OF DERIVATIVES--OTHER
At December 31, 1998, the Company was not a party to price swap agreements,
futures or option contracts in connection with the production or sale of crude
oil.
     At December 31, 1997, the Company held futures contracts expiring in 1998
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. Also at December 31, 1997, the Company had a foreign currency swap
agreement with an aggregate notional amount of $51.0 million and an unrealized
gain of $4.5 million. The Company terminated its involvement in this swap
agreement during 1998 in connection with the sale of its wholesale marketing
business.

                                       19
<PAGE>   22

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 the Company's proposed merger with DRI, capital
expenditures, earnings, risk management, litigation, the year 2000 technology
issues and costs, environmental matters, rate and other regulatory matters,
liquidity and capital resources, and financial accounting and reporting 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.
     Risks in connection with the Company's year 2000 efforts include the
Company's ability to successfully identify, correct and test, in a timely
manner, potential year 2000 problems which could have a significant impact on
specific business functions or processes, and the ability of third party
vendors, business partners and customers to ensure year 2000 readiness of their
systems and business operations.

SUMMARY OF FINANCIAL DATA
The Company's Summary of Financial Data is on page 21.


                                       20
<PAGE>   23


<TABLE>
<CAPTION>

SELECTED FINANCIAL DATA
----------------------------------------------------------------------------------------------------------------
SUMMARY OF FINANCIAL DATA (THOUSAND $)                1998         1997        1996(b)      1995(b)       1994
----------------------------------------------------------------------------------------------------------------
<S>                                                 <C>         <C>          <C>         <C>          <C>       
EARNINGS (a)
Gas sales........................................   $1,868,110  $2,284,384   $2,149,771  $1,837,159   $2,402,861
Gas transportation, storage and other............      892,296     892,726      805,687     666,416      633,167
   Total operating revenues......................    2,760,406   3,177,110    2,955,458   2,503,575    3,036,028
Purchased gas....................................      900,401   1,114,080      963,217     864,591    1,424,020
Liquids, capacity and other products purchased...      145,277     210,575      179,307      87,434      107,094
Operation and maintenance........................      708,378     757,220      757,321     719,273      689,575
Depreciation and amortization....................      329,913     324,638      302,883     255,949      279,317
Impairment of gas and oil producing properties...           --      10,351           --     226,209           --
Taxes, other than income taxes...................      179,299     193,584      190,683     190,716      192,617
   Operating income before income taxes..........      497,138     566,662      562,047     159,403      343,405
Income taxes.....................................      129,649     156,269      162,315       7,381       82,427
Other income-net.................................       34,700      12,442        8,975      10,661        9,694
Write-down of coal properties....................           --          --           --      31,266           --
Interest charges.................................      114,478     103,927       99,325     102,584       87,501
Income from continuing operations................      287,711     318,908      309,382      28,833      183,171
DISCONTINUED OPERATIONS (Note 2)
Loss from discontinued energy marketing services       (17,238)    (14,528)     (11,109)     (7,489)          --
   operations, net of applicable tax benefit.....
Loss from disposal of energy marketing services        
   operations, including provision for operating
   losses during the phase out period, net of 
   applicable tax benefit........................      (31,707)         --           --          --           --
NET INCOME.......................................      238,766     304,380      298,273      21,344      183,171
EARNINGS PER COMMON SHARE--BASIC
Income from continuing operations................        $3.03       $3.36        $3.29        $.31        $1.97
Loss from discontinued operations................         (.18)       (.15)        (.12)       (.08)          --
Loss from disposal of discontinued operations....         (.33)         --           --          --           --
NET INCOME.......................................        $2.52       $3.21        $3.17        $.23        $1.97
EARNINGS PER COMMON SHARE--DILUTED
Income from continuing operations................        $3.00       $3.30        $3.24        $.31        $1.97
Loss from discontinued operations................         (.18)       (.15)        (.11)       (.08)          --
Loss from disposal of discontinued operations....         (.33)         --           --          --           --
NET INCOME.......................................        $2.49       $3.15        $3.13        $.23        $1.97
Return on average stockholders' equity...........        10.0%       13.3%        14.0%        1.0%         8.4%
Times fixed charges earned.......................         4.03        4.90         5.04        1.32         3.53
----------------------------------------------------------------------------------------------------------------
DIVIDENDS--CASH
Paid per common share............................        $1.94       $1.94        $1.94       $1.94        $1.94
   Payout ratio..................................        77.0%       60.4%        61.2%      843.5%        98.5%
Declared per common share........................        $1.94       $1.94        $1.94       $1.94        $1.94
----------------------------------------------------------------------------------------------------------------
ASSETS
Total assets.....................................   $6,361,900  $6,313,694   $6,000,605  $5,418,293   $5,518,673
Property, plant and equipment
   Total investment..............................    9,172,465   8,714,758    8,304,205   7,929,350    7,676,956
   Accumulated depreciation......................    4,734,001   4,491,955    4,226,905   4,016,945    3,650,310
Capital expenditures and acquisitions............      762,916     609,373      560,293     439,393      437,785
----------------------------------------------------------------------------------------------------------------
CAPITAL STRUCTURE
Total common stockholders' equity................   $2,399,608  $2,358,318   $2,205,152  $2,045,818   $2,184,334
Long-term debt...................................    1,379,729   1,552,890    1,426,315   1,291,811    1,151,973
                                                     ---------   ---------    ---------   ---------    ---------
   Total capitalization..........................   $3,779,337  $3,911,208   $3,631,467  $3,337,629   $3,336,307
                                                    ==========  ==========   ==========  ==========   ==========
Long-term debt ratio.............................        36.5%       39.7%        39.3%       38.7%        34.5%
Shares outstanding at year-end...................   95,449,428  95,622,622   94,933,631  93,591,623   93,027,847
Common stockholders' equity per share............       $25.14      $24.66       $23.23      $21.86       $23.48
----------------------------------------------------------------------------------------------------------------
</TABLE>

(a)  Amounts for the years 1995 through 1997 have been restated, as applicable,
     to present continuing operations separate from discontinued operations.
(b)  Certain amounts and ratios are not comparable with prior years due to
     special charges.

                                       21
<PAGE>   24

                        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 23
through 58 of this Appendix I to the proxy statement for the 1999 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, 1998 and 1997, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 1998, 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.



PRICEWATERHOUSECOOPERS LLP



600 Grant Street 
Pittsburgh, Pennsylvania 15219-9954 
February 9, 1999, except for Note 19, 
which is as of February 22, 1999


                                       22
<PAGE>   25



CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
  For the Years Ended December 31,                                           1998          1997          1996 
-------------------------------------------------------------------------------------------------------------------
                                                                                  (Thousands of Dollars) 
<S>                                                                         <C>           <C>           <C>        
OPERATING REVENUES
Regulated gas sales.....................................................    $1,373,691    $1,851,001    $1,753,667 
Nonregulated gas sales..................................................       494,419       433,383       396,104
                                                                            ----------    ----------    ---------- 
     Total gas sales....................................................     1,868,110     2,284,384     2,149,771 
Gas transportation and storage..........................................       545,933       492,080       479,588 
Other...................................................................       346,363       400,646       326,099
                                                                            ----------    ----------    ---------- 
     Total operating revenues (Note 4)..................................     2,760,406     3,177,110     2,955,458
                                                                            ----------    ----------    ---------- 
OPERATING EXPENSES
Purchased gas...........................................................       900,401     1,114,080       963,217 
Liquids, capacity and other products purchased..........................       145,277       210,575       179,307 
Operation expense (Note 6)..............................................       618,010       666,612       667,254 
Maintenance.............................................................        90,368        90,608        90,067 
Depreciation and amortization (Note 5)..................................       329,913       324,638       302,883 
Impairment of gas and oil producing properties (Note 5).................            --        10,351            -- 
Taxes, other than income taxes..........................................       179,299       193,584       190,683
                                                                            ----------    ----------    ---------- 
     Subtotal...........................................................     2,263,268     2,610,448     2,393,411
                                                                            ----------    ----------    ---------- 
     Operating income before income taxes...............................       497,138       566,662       562,047 
Income taxes (Note 8)...................................................       129,649       156,269       162,315
                                                                            ----------    ----------    ---------- 
     Operating income...................................................       367,489       410,393       399,732
                                                                            ----------    ----------    ---------- 
OTHER INCOME
Interest revenues.......................................................         3,165         1,663         2,024 
Other-net...............................................................        31,535        10,779         6,951
                                                                            ----------    ----------    ---------- 
     Total other income.................................................        34,700        12,442         8,975
                                                                            ----------    ----------    ---------- 
     Income before interest charges.....................................       402,189       422,835       408,707
                                                                            ----------    ----------    ---------- 
INTEREST CHARGES
Interest on long-term debt..............................................       106,307       104,927       101,814 
Other interest expense..................................................        19,659         5,774         3,374 
Allowance for funds used during construction............................       (11,488)       (6,774)       (5,863)
                                                                            ----------    ----------    ---------- 
     Total interest charges.............................................       114,478       103,927        99,325
                                                                            ----------    ----------    ---------- 
INCOME FROM CONTINUING OPERATIONS.......................................       287,711       318,908       309,382 
DISCONTINUED OPERATIONS (Note 2)
Loss from discontinued energy marketing services operations,
   net of applicable tax benefit........................................       (17,238)      (14,528)      (11,109)
Loss from disposal of energy marketing services operations,
   including provision for operating losses during the phase out period,
   net of applicable tax benefit........................................       (31,707)           --            --
                                                                            ----------    ----------    ---------- 
                                                                                                               
NET INCOME..............................................................     $ 238,766     $ 304,380     $ 298,273
                                                                             =========-    =========-    =========
EARNINGS PER COMMON SHARE--BASIC
   Income from continuing operations (Note 3)...........................         $3.03         $3.36         $3.29 
   Loss from discontinued operations....................................          (.18)         (.15)         (.12)
   Loss from disposal of discontinued operations........................               
                                                                                  (.33)           --            --
                                                                            ----------    ----------    ---------- 
NET INCOME..............................................................         $2.52         $3.21         $3.17
                                                                            ==========    ==========    ========== 
EARNINGS PER COMMON SHARE--DILUTED
   Income from continuing operations (Note 3)...........................         $3.00         $3.30         $3.24 
   Loss from discontinued operations....................................          (.18)         (.15)         (.11)
   Loss from disposal of discontinued operations........................               
                                                                                  (.33)           --            --
                                                                            ----------    ----------    ---------- 
NET INCOME..............................................................         $2.49         $3.15         $3.13
                                                                            ==========    ==========    ========== 
-------------------------------------------------------------------------------------------------------------------
</TABLE>
The Notes to Consolidated Financial Statements are an integral part of this
statement.


                                       23
<PAGE>   26


CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
At December 31,                                                        1998           1997 
-------------------------------------------------------------------------------------------------
                                                                      (Thousands of Dollars) 
<S>                                                                    <C>            <C>        
ASSETS
PROPERTY, PLANT AND EQUIPMENT (Note 5)
Gas utility and other plant......................................      $5,091,793     $5,004,139 
Accumulated depreciation and amortization........................      (1,999,484)    (1,949,483)
                                                                       ----------     ---------- 
      Net gas utility and other plant............................       3,092,309      3,054,656
                                                                       ----------     ---------- 
Exploration and production properties............................       4,080,672      3,710,619 
Accumulated depreciation and amortization........................      (2,734,517)    (2,542,472)
                                                                       ----------     ---------- 
      Net exploration and production properties..................       1,346,155      1,168,147
                                                                       ----------     ---------- 
      Net property, plant and equipment..........................       4,438,464      4,222,803
                                                                       ----------     ---------- 

CURRENT ASSETS
Cash and temporary cash investments..............................         135,453         65,035 
Accounts receivable
   Customers.....................................................         363,503        804,015 
   Unbilled revenues and other...................................         221,833        176,787 
   Allowance for doubtful accounts...............................         (23,039)       (29,590)
Inventories, at cost
   Gas stored--current portion (Note 9)...........................        120,665        139,157 
   Materials and supplies (average cost method)..................          27,940         30,256 
Unrecovered gas costs (Note 4)...................................          34,860         55,062 
Deferred income taxes--current (net) (Note 8).....................         21,786             -- 
Prepayments and other current assets.............................         258,899        212,919
                                                                       ----------     ---------- 
      Total current assets.......................................       1,161,900      1,453,641
                                                                       ----------     ---------- 

REGULATORY AND OTHER ASSETS
Other investments................................................         302,307        223,900 
Deferred charges and other assets (Notes 4, 6, 7, 8 and 16)......         459,229        413,350
                                                                       ----------     ---------- 
      Total regulatory and other assets..........................         761,536        637,250
                                                                       ----------     ---------- 

      Total assets...............................................      $6,361,900     $6,313,694
                                                                       ==========     ========== 
-------------------------------------------------------------------------------------------------
</TABLE>

The Notes to Consolidated Financial Statements are an integral part of this
statement.


                                       24
<PAGE>   27


<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------
At December 31,                                                                 1998           1997 
------------------------------------------------------------------------------------------------------------
                                                                               (Thousands of Dollars) 
<S>                  <C>                                                          <C>             <C>      
STOCKHOLDERS' EQUITY AND LIABILITIES
CAPITALIZATION
Common stockholders' equity (Note 10)
   Common stock, par value $2.75 per share
      Authorized--400,000,000 shares
      Issued, 1998--95,944,551 shares, 1997--95,623,281 shares...........        $  263,848      $  262,964 
   Capital in excess of par value........................................           571,972         566,755 
   Retained earnings (Note 12)...........................................         1,591,543       1,539,587 
   Treasury stock, at cost (1998--495,123 shares, 1997--659 shares)......           (26,359)            (38)
   Unearned compensation.................................................            (1,396)        (10,950)
                                                                                -----------     -----------
      Total common stockholders' equity..................................         2,399,608       2,358,318 
Long-term debt (Note 13).................................................         1,379,729       1,552,890
                                                                                -----------     -----------
      Total capitalization...............................................         3,779,337       3,911,208
                                                                                -----------     -----------
CURRENT LIABILITIES
Current maturities on long-term debt.....................................           111,125         154,000 
Commercial paper (Note 14)...............................................           558,900         238,700 
Accounts payable.........................................................           423,695         651,365 
Estimated rate contingencies and refunds (Note 4)........................            78,266          29,112 
Amounts payable to customers (Note 4)....................................            48,339             880 
Taxes accrued............................................................           122,788         125,056 
Deferred income taxes--current (net) (Note 8).............................               --          13,735 
Dividends declared.......................................................            46,277          46,377 
Other current liabilities................................................           154,947         127,016
                                                                                -----------     -----------
      Total current liabilities..........................................         1,544,337       1,386,241
                                                                                -----------     -----------

DEFERRED CREDITS
Deferred income taxes (Note 8)...........................................           780,928         712,118 
Accumulated deferred investment tax credits..............................            24,475          26,658 
Deferred credits and other liabilities (Notes 4, 7 and 8)................           232,823         277,469
                                                                                -----------     -----------
      Total deferred credits.............................................         1,038,226       1,016,245
                                                                                -----------     -----------

COMMITMENTS AND CONTINGENCIES (Note 17)
                                                                                -----------     -----------
      Total stockholders' equity and liabilities.........................       $ 6,361,900     $ 6,313,694
                                                                                ===========     ===========
------------------------------------------------------------------------------------------------------------
</TABLE>



                                       25
<PAGE>   28



CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------
  For the Years Ended December 31,                                      1998       1997       1996 
-------------------------------------------------------------------------------------------------------
                                                                          (Thousands of Dollars) 
<S>                                                                   <C>        <C>         <C>       
CASH FLOWS FROM OPERATING ACTIVITIES
Income from continuing operations...................................  $ 287,711  $ 318,908   $ 309,382 
Adjustments to reconcile income from continuing operations to net 
  cash provided by operating activities
     Depreciation and amortization..................................    329,913    324,638     302,883 
     Impairment of gas and oil producing properties.................         --     10,351          -- 
     Pension cost (credit)-net......................................    (56,496)   (46,011)    (24,317)
     Stock award amortization.......................................      7,460      8,209       7,774 
     Deferred income taxes-net......................................     17,901      4,186      62,164 
     Investment tax credit..........................................     (2,171)    (2,193)     (2,201)
     Changes in current assets and current liabilities
        Accounts receivable-net.....................................      4,244    (14,953)    (54,040)
        Inventories.................................................     (2,584)    38,125     (55,277)
        Unrecovered gas costs.......................................     20,202     52,954     (82,893)
        Accounts payable............................................     92,795     (1,511)      3,064 
        Estimated rate contingencies and refunds....................     49,154      7,510     (37,761)
        Amounts payable to customers................................     47,459        880     (40,315)
        Taxes accrued...............................................       (614)    23,834     (17,063)
        Other-net...................................................    (40,282)     3,517       6,791 
     Changes in other assets and other liabilities..................     14,716     55,750      46,985 
     Other-net......................................................     (2,015)       (70)       (252)
                                                                      ---------  ---------   --------- 
                                                                         
        Net cash provided by continuing operations..................    767,393    784,124     424,924 
Net cash provided by (or used in) discontinued operations...........     44,735    (42,016)    (17,759)
                                                                      ---------  ---------   --------- 
        Net cash provided by operating activities...................    812,128    742,108     407,165
                                                                      ---------  ---------   --------- 
CASH FLOWS USED IN INVESTING ACTIVITIES
Plant construction and other property additions.....................   (561,654)  (514,705)   (434,247)
Proceeds from dispositions of property, plant and equipment-net.....     (1,267)     1,056       9,067 
Cost of other investments-net.......................................   (104,233)   (86,763)    (88,214)
                                                                      ---------  ---------   --------- 
        Net cash used in continuing operations......................   (667,154)  (600,412)   (513,394)
Net cash provided by (or used in) discontinued operations...........     35,605     (6,256)     (4,751)
                                                                      ---------  ---------   --------- 
        Net cash used in investing activities.......................   (631,549)  (606,668)   (518,145)
                                                                      ---------  ---------   --------- 
CASH FLOWS PROVIDED BY (OR USED IN) FINANCING ACTIVITIES
Issuance of common stock............................................     11,719     28,722      37,726 
Issuance of debentures..............................................    196,888    294,945     299,567 
Repayments of long-term debt........................................   (327,323)  (119,625)    (72,750)
Commercial paper-net................................................    318,159   (134,368)     37,853 
Dividends paid......................................................   (185,858)  (184,608)   (183,020)
Purchase of treasury stock..........................................   (280,863)   (12,286)     (8,144)
Sale of treasury stock..............................................    162,763     12,266       8,142 
Other-net                                                                (2,987)        25        (147)
                                                                      ---------  ---------   --------- 
        Net cash provided by (or used in) financing activities......   (107,502)  (114,929)    119,227
                                                                      ---------  ---------   --------- 
        Net increase in cash and temporary cash investments.........     73,077     20,511       8,247 
CASH AND TEMPORARY CASH INVESTMENTS AT JANUARY 1....................     65,035     44,524      36,277
                                                                      ---------  ---------   --------- 
CASH AND TEMPORARY CASH INVESTMENTS AT DECEMBER 31..................  $ 138,112  $  65,035   $  44,524
                                                                      =========- =========   =========
Continuing operations...............................................  $ 135,453  $  49,566   $  21,583 
Discontinued operations.............................................      2,659     15,469      22,941
                                                                      ---------  ---------   --------- 
        Total cash and temporary cash investments at December 31....  $ 138,112  $  65,035   $  44,524
                                                                      =========  =========   =========
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for
   Interest (net of amounts capitalized)............................  $ 121,924  $ 114,314   $ 109,602 
   Income taxes (net of refunds)....................................  $  92,380  $ 126,372   $ 108,742 
Non-cash financing activities
   Issuance of common stock under benefit plans.....................  $    (240) $   2,742   $  25,570 
   Conversion of 7-1/4% Convertible Subordinated Debentures.........  $  88,467  $      40   $      -- 
--------------------------------------------------------------------------------------------------------
</TABLE>

The Notes to Consolidated Financial Statements are an integral part of this
statement.

                                       26
<PAGE>   29

CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------
  For the Years Ended December 31,                          1998         1997         1996
---------------------------------------------------------------------------------------------
                                                             (Thousands of Dollars) 

<S>                                                        <C>          <C>          <C>     
NET INCOME...........................................      $238,766     $304,380     $298,273
OTHER COMPREHENSIVE INCOME, NET OF TAX
      Pension liability adjustment..................             60         (309)         116
      Foreign currency translation adjustment.......         (1,112)      (4,166)          --
                                                           --------     --------     --------
COMPREHENSIVE INCOME................................       $237,714     $299,905     $298,389
                                                           ========     ========     ========
---------------------------------------------------------------------------------------------
</TABLE>

The Notes to Consolidated Financial Statements are an integral part of this
statement.

                                       27
<PAGE>   30
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.

SEGMENT INFORMATION
In 1998, the Company adopted the provisions of SFAS No. 131, "Disclosures about
Segments of an Enterprise and Related Information." SFAS No. 131 supersedes SFAS
No. 14, "Financial Reporting for Segments of a Business Enterprise," and
replaces an "industry segment" disclosure approach with a "management" approach.
SFAS No. 131 requires the internal organization used by management for making
operating decisions and assessing performance to be the basis of the Company's
reportable segments.

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


                                       28
<PAGE>   31

CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     For derivatives that qualify (based on correlation to price movements of
gas and oil) and are designated as hedges, related gains or losses are deferred
and subsequently recognized in income, as revenues or expense, in the same
period the hedged transaction occurs.
     Under the OTC price swap agreements, the Company makes payments to, or
receives payments from, counterparties generally based on the difference between
fixed and variable gas and oil prices or on prices at different receipt points
as specified in the contracts. Settlement takes place under the swap agreements
on a monthly basis for the portion of the swap that has expired, and amounts
received or paid are recognized as an adjustment to gas and oil sales revenues,
purchased gas expense or transport capacity costs in the applicable settlement
month.
     Cash flows from price risk management activities are reported in the
Consolidated 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. Maintenance, repairs and related costs are
charged principally to expense as incurred.

      EXPLORATION AND PRODUCTION PROPERTIES
The Company follows the full cost method of accounting for gas and oil producing
activities prescribed by the 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.

      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 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. 

                                       29
<PAGE>   32

CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

     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: 1998--5-1/2% to 7-1/8%; 1997--5-5/8% to
7-5/8% and 1996--5-1/2% to 8-1/8%. 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
The Company has qualified noncontributory defined benefit pension plans covering
substantially all employees. Benefits payable under the plans are based
primarily on each employee's years of service, age and base salary during the
five years prior to retirement. Net pension costs are determined by an
independent actuary, and the plans are funded on an annual basis to the extent
such funding is deductible under federal income tax regulations. Plan assets
consist primarily of equity securities, fixed income securities and insurance
contracts. The pension program also includes the payment of supplemental pension
benefits to certain retirees and the payment of benefits to certain retired
executives under company-sponsored nonqualified employee benefit plans. Certain
of these nonqualified plans are funded through contributions to a grantor trust.
     The Company also sponsors defined benefit postretirement plans, covering
both salaried and hourly employees and certain dependents, that provide medical
and life insurance coverage benefits. These benefits are provided through
insurance companies and other providers with the annual cash outlays based on
the claim experience of the related plans. Employees who retire on or after
attaining age 55 and having rendered at least 15 years of service, or employees
retiring on or after attaining age 65, are eligible to receive benefits under
the plans. The plans are both contributory and noncontributory, depending on
age, retirement date, the plan elected by the employee, and whether the employee
is covered under a collective bargaining agreement. Most of the medical plans
contain cost-sharing features such as deductibles and coinsurance. For certain
of the contributory medical plans, retiree contributions and cost-sharing
features are adjusted annually.

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.

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.   DISCONTINUED OPERATIONS

During April 1998, management approved a plan to discontinue the Company's
wholesale trading and marketing of natural gas and electricity, including
integrated energy management. On July 31, 1998, the 


                                       30
<PAGE>   33

CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

sale of the capital stock of CNG Energy Services Corporation, formerly a
wholly-owned subsidiary of the Company, to Sempra Energy Trading, a subsidiary
of Sempra Energy, was finalized. Included in the transaction were contracts for
the purchase and sale of natural gas as well as rights to natural gas pipeline
and storage capacity, mainly in the Northeast and Mid-Atlantic regions, and
related working capital. Proceeds of $37.4 million were received from the sale
of the stock, as adjusted for working capital items. The Company's transition
out of the wholesale gas business was substantially complete at December 31,
1998. The remaining net liabilities associated with discontinued operations at
December 31, 1998 were not material.
     The results of operations of these activities for the years ended December
31, 1998, 1997 and 1996 are classified as "Discontinued Operations" in the
Consolidated Statement of Income. Cash flows in connection with operating and
investing activities for discontinued operations are reported separately in the
Consolidated Statement of Cash Flows. There were no cash flows provided by, or
used in, financing activities related to discontinued operations for the years
ended December 31, 1998, 1997 or 1996.
     Summarized results of operations of the discontinued operations are as
follows:
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------
Years Ended December 31,                          1998          1997           1996 
-----------------------------------------------------------------------------------------
                                                            (In Thousands) 
<S>                                              <C>           <C>             <C>       
Total operating revenues....................     $ 792,586     $ 2,532,910     $ 838,851 
Operating expenses..........................      (818,105)     (2,554,386)     (852,924)
                                                 ---------      ----------     --------- 
   Operating loss before income taxes.......       (25,519)        (21,476)      (14,073)
Income tax benefit..........................         9,011           9,216         6,485 
Other income................................            80           1,074           329 
Interest charges............................          (810)         (3,342)       (3,850)
                                                 ---------     -----------     --------- 
Loss from discontinued operations...........     $ (17,238)    $   (14,528)    $ (11,109)
                                                 =========     ===========     =========
Loss from disposal before income taxes......     $ (48,263)    $        --     $      -- 
Income tax benefit..........................        16,556              --            --  
                                                  --------     -----------     --------- 
                                                                       
Net loss from disposal......................     $ (31,707)    $        --     $      --
                                                 =========     ===========     =========
-----------------------------------------------------------------------------------------
</TABLE>

3.   EARNINGS PER SHARE

In 1997, the Company adopted the provisions of SFAS No. 128, "Earnings per
Share," and restated earnings per share (EPS) amounts for all prior annual and
quarterly periods presented. The adoption of SFAS No. 128 did not have a
material effect on the Company's EPS for any of the periods presented.
     A reconciliation of the income from continuing operations and common stock
share amounts used in the calculation of basic and diluted EPS for each of the
years ended December 31, 1998, 1997 and 1996 follows (income and share amounts
in thousands):

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
                                                                         Income From
                                                                          Continuing            Per Share
                                                                          Operations    Shares    Amount
-----------------------------------------------------------------------------------------------------------
<S>                                                                       <C>             <C>       <C>   
For the year ended December 31, 1998
BASIC EPS..............................................................    $287,711       94,836    $ 3.03
                                                                           ========       ======    ======
Effect of dilutive securities:
   Exercise of stock options...........................................                      511
   Vesting of performance shares.......................................                      374
   Conversion of 7-1/4% Convertible Subordinated Debentures............       1,578          614
                                                                           --------          ---
DILUTED EPS............................................................    $289,289       96,335    $ 3.00
                                                                           ========       ======    ======
-----------------------------------------------------------------------------------------------------------
</TABLE>
                                       31
<PAGE>   34

CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------

                                                                             Income From
                                                                             Continuing             Per Share
                                                                             Operations    Shares     Amount
---------------------------------------------------------------------------------------------------------------
<S>                                                                          <C>           <C>       <C>  
For the year ended December 31, 1997
BASIC EPS..............................................................       $318,908     94,868     $3.36
                                                                              ========     ======     =====
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............................................................       $331,036    100,460     $3.30
                                                                              ========    =======     =====
---------------------------------------------------------------------------------------------------------------
For the year ended December 31, 1996
BASIC EPS..............................................................       $309,382     94,076     $3.29
                                                                              ========     ======     =====
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............................................................       $321,205     99,215     $3.24
                                                                              ========     ======     =====
---------------------------------------------------------------------------------------------------------------
</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.

4.   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 subsidiaries resulted in the recognition of regulatory assets and
liabilities at December 31, 1998 and 1997 as follows:

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------
  December 31,                                                       1998        1997
---------------------------------------------------------------------------------------
                                                                      (In Thousands)
<S>                                                                 <C>         <C>    
Regulatory assets:
   Unrecovered gas costs (Note 1)............................      $ 34,860    $ 55,062
   Order 636 transition costs................................         6,461      17,020
   Workforce reduction costs (Note 6)........................         9,275       8,832
   Other postretirement benefits (Note 7)....................        52,142      55,070
   Deferred income taxes (Note 8)............................       102,797     103,323
   Environmental-related expenditures (Note 16)..............         7,291       7,322
   Other                                                             11,642      19,215
                                                                   --------    --------
     Total regulatory assets.................................      $224,468    $265,844
                                                                   ========    ========
Regulatory liabilities:
   Amounts payable to customers (Note 1).....................       $48,339    $    880
   Estimated rate contingencies and refunds..................        78,266      29,112
   Income taxes refundable to customers-net (Note 8).........        27,170      55,035
                                                                   --------    --------
     Total regulatory liabilities............................      $153,775    $ 85,027
                                                                   ========    ========
---------------------------------------------------------------------------------------
</TABLE>
                                       32

<PAGE>   35


CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

     The Company assesses on an ongoing basis the recoverability of costs
recognized as regulatory assets and its ability to continue to apply SFAS No. 71
to its regulated operations. In the event that all or a portion of these
operations 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 $59.9 million and $15.7 million at
December 31, 1998 and 1997, including interest. These amounts are reported in
the Consolidated Balance Sheet under "Estimated rate contingencies and refunds"
together with $18.4 million and $13.4 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 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 $6.5 million and $17.0 million at December 31, 1998 and 1997,
respectively. Additional amounts, if any, to be accrued in the future are not
expected to be material. These transition costs are being passed through to
customers of the Company's distribution subsidiaries.

5.   PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION

IMPAIRMENT OF GAS AND OIL PRODUCING PROPERTIES
As described in Note 1, the Company follows the full cost method of accounting
for gas and oil producing activities. Under these rules, the Company recognized
an impairment of its Canadian oil producing properties at December 31, 1997, 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.

DEPRECIATION AND AMORTIZATION
Amortization of capitalized costs under the full cost method of accounting for
the Company's exploration and production operations amounted to $.89 per Mcf
equivalent of gas and oil produced in 1998, $.88 in 1997 and $.93 in 1996.
     Costs of unproved properties capitalized under the full cost method of
accounting that are excluded from amortization at December 31, 1998, and the
years in which such excluded costs were incurred, follow:

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------
                                    DECEMBER 31, Incurred in Years Ended December 31,
                                                 -------------------------------------
                                      1998        1998      1997       1996     Prior
--------------------------------------------------------------------------------------
                                                   (In Thousands)
<S>                                  <C>        <C>        <C>        <C>       <C>   
Property acquisition costs...        $ 59,315   $20,874    $31,164    $4,181    $3,096
Exploration costs............          48,679    23,469     18,121     2,316     4,773
Capitalized interest.........           9,995     1,604      5,363     1,181     1,847
                                    ---------   -------    -------    ------    ------
     Total...................       $ 117,989   $45,947    $54,648    $7,678    $9,716
                                    =========   =======    =======    ======    ======
--------------------------------------------------------------------------------------
</TABLE>
       There are no significant properties, as defined by the SEC, excluded from
amortization at December 31, 1998. 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.


                                       33
<PAGE>   36

CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6.   WORKFORCE REDUCTION COSTS

During the fourth quarter of 1998, the Company recorded a provision for
severance and other employee-related costs in connection with actions to improve
efficiencies and reorganize business processes at both its corporate and
regulated subsidiaries. The Company anticipates that these actions will be
substantially completed during 1999.
     During 1996, unions at two subsidiaries implemented a workforce reduction
program that consisted of a voluntary early retirement program and a voluntary
separation program. A voluntary early retirement program for West Ohio Gas (now
a division of East Ohio Gas) was also offered during 1996. In conjunction with
these programs, 119 eligible employees elected to accept early retirement offers
and an additional 57 were separated from the Company. 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 its workforce reduction programs, the Company recorded
charges in 1998 and 1996 amounting to $9.4 million and $15.2 million,
respectively. These charges reduced 1998 and 1996 net income by $6.1 million, or
$.06 per share, and $9.9 million, or $.10 per share, respectively. In addition,
certain of the regulated subsidiaries have deferred, as a regulatory asset, a
portion of workforce reduction costs from previous years' programs pending
recovery in rates. The balance of these deferrals was $9.3 million at December
31, 1998.

7.   PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS

The following table provides reconciliations of the changes in the Company's
pension and other postretirement benefit plan obligations and asset fair values
for each of the years ended December 31, 1998 and 1997, and a statement of the
funded status as of December 31, 1998 and 1997:

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------
                                                      Pension               Other Postretirement
                                                  Benefit Plans                Benefit Plans
                                                --------------------        --------------------
Years Ended December 31,                        1998            1997          1998         1997 
----------------------------------------------------------------------------------------------------
                                                                    (In Thousands) 
<S>                                              <C>             <C>           <C>          <C>      
Change in benefit obligation:
Benefit obligation--January 1..............      $1,037,728     $  959,951     $358,748     $378,435 
Service cost..............................           24,852         21,374       10,021        9,901 
Interest cost.............................           69,320         68,635       23,714       25,854 
Participant contributions.................               --             --        3,027        3,000 
Plan amendments...........................               --             --         (569)      (6,723)
Actuarial (gain) loss.....................           60,981         55,378      (11,331)     (29,342)
Curtailment (gain)........................           (1,658)            --         (130)          -- 
Benefit payments..........................          (67,539)       (67,610)     (21,407)     (22,377)
                                                 ----------      ---------     --------     -------- 
Benefit obligation--December 31............      $1,123,684     $1,037,728     $362,073     $358,748
                                                 ==========     ==========     ========     ========

Change in plan assets:
Fair value of plan assets--January 1.......      $1,804,852     $1,539,039     $ 79,740     $ 53,153 
Actual return on plan assets..............          328,928        330,296        5,207        2,972 
Employer contributions....................            2,911          3,127       45,326       42,992 
Participant contributions.................               --             --        3,027        3,000 
Benefit payments..........................          (67,539)       (67,610)     (21,407)     (22,377)
                                                 ----------      ---------     --------     -------- 
Fair value of plan assets--December 31.....      $2,069,152     $1,804,852     $111,893     $ 79,740
                                                 ==========     ==========     ========     ========
----------------------------------------------------------------------------------------------------
</TABLE>



                                       34
<PAGE>   37


CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------
                                                          Pension              Other Postretirement
                                                      Benefit Plans               Benefit Plans
                                                     -----------------         --------------------
December 31,                                         1998         1997          1998          1997 
--------------------------------------------------------------------------------------------------------
                                                                    (In Thousands) 
<S>                                                   <C>           <C>          <C>           <C>       
FUNDED STATUS:                          
Funded status--December 31 ...................        $945,468      $767,124     $(250,180)    $(279,008)
Unrecognized net obligation (asset) ..........         (33,195)      (40,237)      158,231       170,102 
Unrecognized (gain) loss-net .................        (774,732)     (649,740)       11,711        24,253 
Unrecognized prior service cost ..............           4,755         5,720        (5,562)       (6,178)
                                                      --------      --------     ---------     --------- 
Net amount recognized ........................        $142,296      $ 82,867     $ (85,800)    $ (90,831)
                                                      ========      ========     =========     ========= 
--------------------------------------------------------------------------------------------------------
</TABLE>

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

<TABLE>
<S>                                                   <C>           <C>          <C>           <C>       

Prepaid benefit cost.........................        $159,317       $97,527         $  --     $     -- 
Accrued benefit liability......................       (28,536)      (27,607)      (85,800)     (90,831)
Intangible asset...............................         9,006        10,346            --           -- 
Accumulated other comprehensive income.........         2,509         2,601            --           --
                                                     --------      --------      --------     -------- 
Net amount recognized..........................      $142,296      $ 82,867      $(85,800)    $(90,831)
                                                     ========      ========      ========     ======== 
--------------------------------------------------------------------------------------------------------
</TABLE>

     The Company has nonqualified pension and supplemental pension plans which
do not have "plan assets" as defined by generally accepted accounting
principles. The total projected benefit obligation for these plans was $33.3
million and $32.3 million at December 31, 1998 and 1997, respectively, and is
included in the table above. The minimum liability recognized relating to these
plans was $11.5 million and $12.9 million at December 31, 1998 and 1997. The
related intangible asset recognized as of those dates amounted to $9.0 million
and $10.3 million, respectively. Adjustments of the minimum liability and
intangible asset due to changes in assumptions or the financial status of these
plans resulted in a credit (charge) to other comprehensive income of $.1
million, $(.3) million and $.1 million for the years ended December 31, 1998,
1997 and 1996, respectively.
     The majority of estimated other postretirement benefit costs (SFAS No. 106
costs) and related transition obligation is attributable to the rate-regulated
subsidiaries. Pending the expected recovery of SFAS No. 106 costs and related
deferrals in regulatory proceedings, these subsidiaries have deferred the
differences between SFAS No. 106 costs and amounts included in rates. The
rate-regulated subsidiaries have obtained approval for recovery in rates from
their respective regulatory commissions for the increased level of expense
resulting from SFAS No. 106. The amount of SFAS No. 106 costs deferred at
December 31, 1998 and 1997, was $52.1 million and $55.1 million, respectively.
     The FERC and certain state regulatory authorities have indicated that when
SFAS No. 106 costs are recovered in rates, amounts collected must be deposited
in irrevocable trust funds dedicated for the sole purpose of paying
postretirement benefits. Accordingly, 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. 

                                       35
<PAGE>   38

CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
     Weighted average assumptions used in the determination of the benefit
obligations include the following:

<TABLE>
<CAPTION>
-------------------------------------------------------------------
                                                        Other
                                        Pension     Postretirement
                                     Benefit Plans   Benefit Plans
                                     -------------  --------------
December  31,                         1998     1997   1998    1997
-------------------------------------------------------------------
<S>                                    <C>      <C>    <C>     <C> 
Discount rate.....................     6.5%     7.0%   6.5%    7.0%
Expected return on plan assets....     9.0%     9.0%   6.5%    6.5%
Rate of compensation increase.....     5.5%     5.5%   5.5%    5.5%
-------------------------------------------------------------------
</TABLE>

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

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------
                                                                                        Other Postretirement
                                                   Pension Benefit Plans                  Benefit Plans
                                             ------------------------------        --------------------------------
Years Ended December 31,                     1998         1997         1996        1998        1997       1996 
-------------------------------------------------------------------------------------------------------------------
                                                                       (In Thousands) 
<S>                                          <C>          <C>          <C>          <C>         <C>        <C>     
Service cost............................     $ 24,852     $ 21,374     $ 23,741     $10,021     $9,901     $11,940 
Interest cost...........................       69,320       68,635       67,426      23,714     25,854      26,450 
Expected return on assets...............     (131,640)    (118,671)    (108,753)     (4,413)    (2,859)       (645)
Prior service cost amortization.........          965        1,125        1,128        (406)      (408)       (406)
Actuarial (gain) loss...................      (11,315)     (10,402)      (3,545)        206        271       2,689 
Transition obligation amortization......       (7,042)      (7,929)      (7,789)     11,302     11,418      11,801 
Curtailment and special
   termination benefits.................       (1,658)          --        3,644        (215)        --       1,292 
Special voluntary retirement
   programs.............................          800          800          800          --         --          --   
                                             --------     --------     --------     -------     ------     ------- 
                                                                                          
Net periodic benefit cost (credit)......     $(55,718)    $(45,068)    $(23,348)    $40,209    $44,177     $53,121
                                             ========     ========     ========     =======    =======     =======
-------------------------------------------------------------------------------------------------------------------
</TABLE>

     For measurement purposes, a 6.5% annual rate of increase in the per capita
cost of covered health care benefits was assumed for 1999. The rate was assumed
to decrease gradually to 4% for 2003 and remain at that level thereafter.
     Assumed health care cost trend rates have a significant effect on the
amounts reported for the postretirement health care plans. A 1% change in the
assumed health care cost trend rate would have the following effects on 1998
service and interest cost and the accumulated postretirement benefit obligation
at December 31, 1998:

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------
                                                                                   1% Increase  1% Decrease 
                                                                                        (In Thousands)
<S>                                                                                     <C>         <C>      
Effect on aggregate service and interest cost components of net
   periodic cost.................................................................       $ 4,014     $ (3,587)

Effect on the health care component of the accumulated postretirement
   benefit obligation............................................................       $28,564     $(25,247)
-------------------------------------------------------------------------------------------------------------
</TABLE>


                                       36
<PAGE>   39

CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


8.   INCOME TAXES

"Income taxes" in the Consolidated Statement of Income include the following:

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------
Years Ended December 31,                                              1998         1997         1996 
-------------------------------------------------------------------------------------------------------
                                                                             (In Thousands) 
<S>                                                                   <C>         <C>           <C>     
Income tax expense attributable to continuing operations:
   Current provision
     Federal....................................................      $96,295     $136,095      $88,447 
     State......................................................       17,624       18,181       13,904 
   Deferred income taxes-net
     Federal....................................................       21,390        4,175       59,619 
     State......................................................       (3,489)          11        2,546 
   Investment tax credit........................................       (2,171)      (2,193)      (2,201)
                                                                     --------     --------     --------
Income tax expense attributable to continuing operations........      129,649      156,269      162,315 
Income tax benefit attributable to discontinued operations......      (25,567)      (9,216)      (6,485)
                                                                     --------     --------     --------
     Total......................................................     $104,082     $147,053     $155,830
                                                                     ========     ========     ========
-------------------------------------------------------------------------------------------------------
</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
pretax income from continuing operations. The reasons for the differences
follow:

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------
Years Ended December 31,                                            1998         1997          1996 
--------------------------------------------------------------------------------------------------------
                                                                            (In Thousands) 
<S>                                                                  <C>           <C>          <C>     
Income before taxes--continuing operations......................     $417,360      $475,177     $471,697
                                                                     ========      ========     ========
Computed  "expected"  tax expense--continuing operations........     $146,076      $166,312     $165,094 
Increases (or reductions) in tax resulting from:
   Production tax credit.......................................       (11,351)      (10,359)      (9,344)
   Investment tax credit.......................................        (2,171)       (2,193)      (2,201)
   State income taxes..........................................         9,188        11,825       10,693 
   Miscellaneous...............................................       (12,093)       (9,316)      (1,927)
                                                                     ---------     ---------    ---------
Income taxes attributable to continuing operations.............      $129,649      $156,269     $162,315
                                                                     ========      ========     ========
   Effective tax rate..........................................          31.1%         32.9%        34.4% 
--------------------------------------------------------------------------------------------------------
</TABLE>


                                       37
<PAGE>   40


CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

     The current and noncurrent deferred income taxes reported in the
Consolidated Balance Sheet at December 31, 1998 and 1997 represent the net
expected future tax consequences attributable to 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>
------------------------------------------------------------------------------------------------------------------
                                                                1998                           1997
                                                    -----------------------------   ------------------------------
                                                      Deferred    Deferred Income     Deferred    Deferred Income
December 31,                                        Income Taxes   Taxes-Current    Income Taxes   Taxes-Current
------------------------------------------------------------------------------------------------------------------
                                                                           (In Thousands)
<S>                                                     <C>             <C>             <C>                <C>    
Deferred tax liabilities:
   Excess of tax over book depreciation..........       $ 559,430       $       --      $ 537,684          $    --
   Exploration and intangible well drilling
      costs......................................         244,832               --        225,111               --
   Unrecovered gas costs.........................              --           15,908             --           19,424
   Net pension credits...........................          78,212               --         52,420               --
   Other                                                   36,145               --         25,721               --
                                                        ---------       ----------      ---------        ---------
     Total liabilities...........................         918,619           15,908        840,936           19,424
                                                        ---------       ----------      ---------        ---------
Deferred tax assets:
   Tax basis step-up in connection with
      acquisition of subsidiary..................          18,096               --         18,619               --
   Deferred investment tax credits...............          14,443               --         15,854               --
   Overheads capitalized for tax purposes........          11,138               --          8,226               --
   Supplier and other refunds....................              --           18,503             --              187
   Other                                                   94,014           19,191         86,119            5,502
   Valuation allowance...........................              --               --             --               --
                                                        ---------       ----------      ---------        ---------
     Total assets................................         137,691           37,694        128,818            5,689
                                                        ---------       ----------      ---------        ---------
     Total deferred tax liability (asset)........       $ 780,928       $  (21,786)     $ 712,118        $  13,735
                                                        =========       ==========      =========        =========
------------------------------------------------------------------------------------------------------------------
</TABLE>

       A regulatory liability amounting to $27.2 million has been recorded at
December 31, 1998 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 $102.8 million has been recorded at December 31, 1998.

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 1998, the current cost of replacing the inventory of "Gas
stored--current portion" exceeded the amount stated on a LIFO basis by
approximately $171.3 million at December 31, 1998. Virginia Natural Gas and CNG
Retail 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, 1998 and 1997.


                                       38
<PAGE>   41


CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


10.  COMMON STOCKHOLDERS' EQUITY

A summary of the changes in stockholders' equity follows:
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------------
                                 Common Stock          Capital in Excess
                                   Issued                of Par Value                                        Treasury
                              -----------------    ------------------------                                   Stock
                                Number    Value                                 Retained     Unearned     Number
                              of Shares  at Par    Paid-In   Other    Total     Earnings  Compensation  of Shares     Cost 
----------------------------------------------------------------------------------------------------------------------------
                                                                     (In Thousands) 
<S>                              <C>    <C>       <C>       <C>      <C>       <C>       <C>             <C>        <C>   
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..         --        --        --       --        --         --            --      (147)   (8,144)
Sale of treasury stock and            
  other.....................         --        --      (143)      --      (143)        --            --       147     8,144
Pension liability adjustment
  (Note 7)..................                                                              
                                     --        --        --       --        --        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..         --        --        --       --        --         --            --      (220)  (12,286)
Sale of treasury stock and            
  other.......................       --        --       154       --       154         --            --       219    12,248
Pension liability adjustment
  (Note 7)..................         --        --        --       --        --       (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)       (1)      (38)

Net income..................         --        --        --       --        --    238,766            --        --        -- 
Cash dividends declared
  Common stock ($1.94 per
    share)..................         --        --        --       --        --   (185,758)           --        --        -- 
Common stock issued
  Stock options.............        282       777    11,548       --    11,548         --            --        --        -- 
  Stock awards-net..........         32        86     1,364       --     1,364         --        (1,283)       --        -- 
  Performance shares-net....          8        21       402       --       402         --          (423)       --        -- 
  Amortization and adjustment        --        --    (2,393)      --    (2,393)        --        11,321        --        -- 
Purchase of treasury stock..         --        --        --       --        --         --            --    (5,081) (280,326)
Sale of treasury stock and           --        --    (3,863)      --    (3,863)        --           (61)    2,949   163,290 
other.......................
Conversion of debentures....         --        --    (1,841)      --    (1,841)        --            --     1,638    90,715 
Pension liability adjustment
  (Note 7)..................         --        --        --       --        --         60            --        --        -- 
Cumulative translation
  adjustment................                                                              
                                     --        --        --       --        --     (1,112)           --        --        --
                                 ------ --------- --------- -------- --------- ----------    ----------    ------  -------- 
Balance at December 31, 1998     95,945 $ 263,848 $ 531,692 $ 40,280 $ 571,972 $1,591,543    $   (1,396)     (495) $(26,359)
                                 ====== ========= ========= ======== ========= ==========    ==========    ======  ======== 
                                                                                              
----------------------------------------------------------------------------------------------------------------------------
</TABLE>

*Dividend Reinvestment Plan.


                                       39
<PAGE>   42


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. 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, 1998, 304,055,449 shares of common stock were unissued. Shares
have been registered with the SEC for possible issuance under various benefit
plans or to shareholders under the Dividend Reinvestment Plan. Shares acquired
pursuant to these plans can consist of original issue shares, treasury shares or
shares purchased in the open market. In addition, at December 31, 1998, the
Company has a shelf registration with the SEC which would allow it to sell up to
an additional $338.3 million of debt or equity securities.

TREASURY STOCK
Under a 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." At December 31, 1998
and 1997, a total of 495,123 and 659 shares, respectively, 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, 1998. 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, 1998.

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 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, 1998, 6,235,017 shares were authorized for issuance under the 1997 Plan.


                                       40
<PAGE>   43


CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

     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 10 years from the date of grant.
     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 or performance stock
credits) 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 permitted by generally accepted accounting principles, the Company follows
Accounting Principles Board Opinion No. 25 and related interpretations (APB No.
25) for accounting for stock-based compensation. The Company granted stock
awards, including performance shares, totaling 54,000 shares in 1998, 98,000
shares in 1997, and 507,000 shares in 1996 with weighted average market prices
per share on award dates of $49.54, $52.53 and $46.19, respectively. The Company
recorded compensation expense of $9.4 million, $9.7 million and $8.7 million for
the years ended December 31, 1998, 1997 and 1996, 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.
     In addition, performance stock credits equal to 475,400 shares of common
stock were granted January 4, 1999, related to the 1999-2001 performance period.


                                       41
<PAGE>   44


CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


     A summary of stock option activity for the years ended December 31, 1996
through 1998, follows:

<TABLE>
<CAPTION>
----------------------------------------------------------------------
                                                    Weighted Average
                                        Number        Option Price
                                      of Shares         Per Share
----------------------------------------------------------------------
                                   (In Thousands) 
<S>                                 <C>               <C>
Shares under option:
     At January 1, 1996..........       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
     Granted (3).................         914              $58.34
     Exercised ..................        (309)             $41.73
     Cancelled (3)...............        (307)             $51.32
                                        -----              ------
     At December 31, 1998........       5,505              $47.73
                                        =====              ======
</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.
(3) Includes 106,750 tri-annual options granted and 96,114 tri-annual options
cancelled.

Options were exercisable for the purchase of 734,741 shares, 599,534 shares and
673,305 shares at December 31, 1998, 1997 and 1996, respectively. Effective
January 4, 1999, additional options for the purchase of 3,662,000 shares were
granted to eligible employees.

--------------------------------------------------------------------------------
     The following table summarizes information about stock options outstanding
at December 31, 1998.
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------
                                                                                 
                                         Options Outstanding                    Options Exercisable
                           ---------------------------------------------   --------------------------- 
                                         Weighted Average    Weighted                      Weighted
                             Number         Remaining         Average        Number         Average
Range of Exercise Prices   Outstanding   Contractual Life Exercise Price   Exercisable  Exercise Price
------------------------------------------------------------------------------------------------------
                         (In Thousands)                                  (In Thousands)
<S>                        <C>           <C>               <C>              <C>         <C>   
$34.75--$40.00                  549         5.48 YRS.         $37.06          230           $36.69
$40.01--$50.00                3,088         6.58 YRS.         $44.97          440           $44.93
$50.01--$59.94                1,868         7.69 YRS.         $56.00           65           $50.87
------------------------------------------------------------------------------------------------------
</TABLE>



                                       42
<PAGE>   45


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 1996 through 1998 and the weighted-average assumptions
used to compute fair values under the Black-Scholes option-pricing model:

<TABLE>
<CAPTION>
--------------------------------------------------------------------
Years Ended December 31,                   1998     1997     1996
--------------------------------------------------------------------
<S>                                      <C>      <C>      <C>   
Option fair value......................  $10.49   $ 8.96   $ 5.84
Assumptions
     Dividend yield....................    3.3%     3.6%     4.3%
     Expected volatility...............   19.8%    16.8%    17.5%
     Risk-free interest rate...........    5.7%     6.4%     5.4%
     Expected option life (years)......    4.8      4.8      4.9
--------------------------------------------------------------------
</TABLE>

       If compensation expense for the Company's stock options granted during
1996 through 1998 had been determined based on the fair value at the grant dates
for such awards, the effect on the Company's net income and EPS for each of the
years would have been as follows:

<TABLE>
<CAPTION>
----------------------------------------------------------
Years Ended December 31,         1998     1997     1996
----------------------------------------------------------
<S>                             <C>      <C>      <C>   
NET INCOME (In Millions):
     As reported.............   $238.8   $304.4   $298.3
     Pro forma...............   $231.7   $298.8   $294.1

BASIC EPS:
     As reported.............    $2.52    $3.21    $3.17
     Pro forma...............    $2.44    $3.15    $3.13

DILUTED EPS:
     As reported.............    $2.49    $3.15    $3.13
     Pro forma...............    $2.42    $3.10    $3.08
----------------------------------------------------------
</TABLE>

11.  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, 1998 or 1997.

12.  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, $493.1 million of consolidated retained
earnings was free from such restrictions at December 31, 1998. The indenture
also imposes dividend limitations on the subsidiaries, but at December 31, 1998,
these limitations did not restrict their ability to pay dividends to the
Company.


                                       43
<PAGE>   46



CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13.  LONG-TERM DEBT

Long-term debt, excluding current maturities, follows:

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------
December 31,                                                   1998            1997 
-------------------------------------------------------------------------------------
                                                                  (In Thousands) 
Debentures
<S>                                                          <C>            <C>      
     6%,     Due October 15, 2010.....................       $200,000       $     -- 
     6.8%,   Due December 15, 2027....................        300,000        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 
     8-3/4%, Due October 1, 2019......................        142,875        150,000 
     8-3/4%, Due June 1, 1999.........................             --        100,000 
     8-5/8%, Due December 1, 2011.....................             --         15,625 
     Unamortized debt discount, less premium..........        (13,146)       (11,319)
Convertible Subordinated Debentures                                                  
     7-1/4%, Due December 15, 2015....................             --        246,165 
     Unamortized debt discount........................             --         (1,581)
9.94% Unsecured loan due January 1, 1999..............             --          4,000
                                                           ----------     ---------- 
          Total.......................................     $1,379,729     $1,552,890
                                                           ==========     ==========
-------------------------------------------------------------------------------------
</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 aggregate principal amounts of the Company's debentures maturing in the
years 1999 through 2003 are: $107.1 million; $7.1 million; $7.1 million; $7.1
million and $157.1 million.
     In January 1998 the Company called for redemption the entire principal
amount outstanding of its 7-1/4% Convertible Subordinated Debentures, totaling
$246.2 million. These debentures were convertible into shares of the Company's
common stock at an initial conversion price of $54 per share. The redemption
price was 102.18% of the principal amount plus accrued interest payable on
February 23, 1998. In anticipation of the call, in January 1998 the Company
purchased approximately 4.6 million shares of its common stock in a private
transaction to satisfy the potential conversion obligation. 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 were sold in two
underwritten offerings during February and March, 1998.
     In March 1998, CNG International purchased a 33.3% ownership interest in
the Dampier-to-Bunbury Natural Gas Pipeline (DBNGP) in Western Australia from
the Western Australia Government. One of CNG International's partners in the
purchase was El Paso Energy Corporation (El Paso), which also holds a 33.3%
ownership interest. In connection with their investments in DBNGP, CNG
International and El Paso formed DBNGP Finance Company LLC (DBNGP Finance).
DBNGP Finance is owned 50% by CNG International and 50% by EPED Holding Company,
a wholly-owned subsidiary of El Paso. Subsequent to the formation of DBNGP
Finance, the equity ownership interests of CNG International and El Paso in
DBNGP were transferred to this entity.
     In October 1998, DBNGP Finance borrowed $250.0 million under a Senior Term
Loan Facility (Term Loan). The Term Loan matures October 2, 2001, can be
extended in one-year increments to October 2, 2003, and bears interest at a
variable rate. Of the gross proceeds received by DBNGP Finance under the


                                       44
<PAGE>   47

CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Term Loan, $100.0 million was distributed to CNG International. In connection
with the Term Loan, CNG International entered into an Equity Contribution
Agreement with DBNGP Finance. CNG International is contractually obligated to
make equity contributions to DBNGP Finance equal to the Term Loan proceeds
distributed to CNG International, plus interest on such proceeds, in the event
that DBNGP Finance is unable to service this debt. The Company is contractually
obligated to cause CNG International to make such equity contributions.

14.  SHORT-TERM BORROWINGS

The weighted average interest rate on the Company's commercial paper notes
outstanding at December 31, 1998 and 1997, was 5.22% and 6.21%, 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 25, 1999; 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, 1998.

15.  FINANCIAL INSTRUMENTS

Fair Values
The estimated fair value of the Company's long-term debt, including current
maturities, was as follows at December 31, 1998 and 1997:

<TABLE>
<CAPTION>
---------------------------------------------------------------------------
                              1998                        1997
                      --------------------        --------------------
                      Carrying        Fair        Carrying        Fair
December 31,           Amount        Value         Amount        Value
---------------------------------------------------------------------------
                                        (In Thousands)
<S>                    <C>           <C>           <C>           <C>       
Long-term debt....     $1,504,000    $1,584,633    $1,719,790    $1,789,577
---------------------------------------------------------------------------
</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
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 price swap agreements and options, which require settlement
in cash. These instruments are used to manage commodity price risk regarding the
production, purchase and sale of natural gas and oil and for stored gas
inventories.

      FUTURES CONTRACTS
At December 31, 1998, the Company had natural gas futures contracts related to
gas purchase and sale commitments and gas storage inventory covering 66.8 Bcf of
gas on a net basis maturing through 2001. As these contracts 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
$16.4 million at December 31, 1998. 


                                       45
<PAGE>   48


CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


      SWAP AGREEMENTS
In addition to futures and options contracts, the Company enters into OTC price
swap agreements to manage its exposure to commodity price risk under existing
sales commitments. At December 31, 1998, the Company 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, 1998 related to those swap agreements in
which the Company pays a fixed price in exchange for a variable price totaled
166.1 Bcf, while net notional quantities related to agreements in which the
Company pays a variable price in exchange for a fixed price totaled 125.2 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 $10.1
million at December 31, 1998. Profits expected on anticipated sales related to
the hedged transactions should generally offset the estimated unrealized losses
on the swap agreements.

      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 all subsidiaries.
     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 respect to
its counterparties that management believes minimize overall credit risk. Such
policies include the evaluation of a prospective counterparty's financial
condition, collateral requirements where deemed necessary, and the use of
standardized agreements which facilitate the netting of cash flows associated
with a single counterparty. 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, 1998, the Company
believes it unlikely that a material adverse effect on its financial position,
results of operations or cash flows would occur as a result of counterparty
nonperformance.

16.  ENVIRONMENTAL MATTERS

The Company is subject to various federal, state and local laws and regulations
relating to the protection of the environment. These laws and regulations govern
both current and future operations and potentially extend to plant sites
formerly owned or operated by the subsidiaries, or their predecessors.
     The Company has taken a proactive position with respect to environmental
concerns. As part of normal business operations, subsidiaries periodically
monitor their properties and facilities to identify and resolve potential
environmental matters, and the Company conducts general environmental audits on
a continuing basis at its operating facilities to monitor compliance with
environmental laws and regulations. As part of this process, voluntary surveys
at subsidiary sites have been conducted to determine the extent of any possible
soil contamination 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 



                                       46
<PAGE>   49

CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

have been assessed. Pursuant to the Order and Agreement, CNG Transmission
continues to perform sampling, testing and analysis, and conducts 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. The Company has recognized an estimated liability amounting to
$10.0 million at December 31, 1998, for future costs expected to be incurred to
remediate or mitigate hazardous substances at these sites and at facilities
covered by the Order and Agreement.
     Inasmuch as certain environmental-related expenditures are expected to be
recoverable in future regulatory proceedings, a regulatory asset has been
recognized amounting to $7.3 million at December 31, 1998. Also, uncontested
claims amounting to $1.5 million at December 31, 1998, 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,                                   1998      1997     1996 
--------------------------------------------------------------------------------------
                                                                 (In Thousands)
<S>                                                         <C>       <C>      <C>    
Recurring costs for ongoing operations..................    $2,595    $3,430   $4,174 
Mandated remediation and other compliance costs.........     3,538     1,473     (419)
Voluntary remediation costs.............................        11       228    2,705 
Other...................................................       195        14        3
                                                            ------    ------   ------
     Total..............................................    $6,339    $5,145   $6,463
                                                            ======    ======   ======
--------------------------------------------------------------------------------------
</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 and to acquire Title
V permits for major facilities. Progress is on schedule for these permits, with
no major expenditures anticipated.
     The 1990 amendments will also require installation of Maximum Available
Control Technology (MACT) to control the emissions of certain hazardous air
pollutants from compressor engines. The Company cannot estimate what its
expenditures for MACT-related controls will be. However, the mandated controls
will not affect a large number of its compressor engines and the related costs
are not expected to be material.
     Additionally, the Company may be required, under an Environmental
Protection Agency nitrogen oxide state implementation program call, to include
additional compressor engines in the control mandates for the 1990 Amendments.
The estimated costs of such federal and/or state imposed hardware additions are
not expected to be material.
     The total capital expenditures required to comply with the 1990 amendments
are expected to be recoverable through future regulatory proceedings.
     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 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. 


                                       47
<PAGE>   50

CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

17.  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 1996 through 1998 was not material, and future rental payments required
under leases in effect at December 31, 1998, are not material.
     It is estimated that the Company's 1999 capital spending program will
amount to $524.5 million, and that approximately $337.0 million of that amount
will be directed to gas and oil producing activities. In connection with the
capital spending program, the Company has entered into certain contractual
commitments.
     The Company has claims and suits arising in the ordinary course of business
pending against it, but, in the opinion of management and counsel, the ultimate
liability will not have a material effect on its financial position, results of
operations or cash flows.

18.  SEGMENT INFORMATION

As indicated in Note 1, in 1998 the Company adopted the provisions of SFAS No.
131. The Company is organized primarily on the basis of products and services
sold in the United States.
     The operations of the four retail gas distribution subsidiaries have been
aggregated into the "Distribution" segment. These subsidiaries sell gas and/or
provide transportation services to residential, commercial and industrial
customers in Ohio, Pennsylvania, 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. Transmission operations
also include the by-products business of CNG Power.
     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.
     The activities of CNG International, CNG Field Services, CNG Retail, CNG
Products and Services Company (CNG Products and Services), CNG Power,
Consolidated LNG, CNG Research Company and CNG Coal are included in the "Other"
category. CNG International engages in energy-related activities outside of the
United States and holds equity investments in Australia, Argentina 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 provides certain energy-related services to customers of the Company's
distribution subsidiaries and others.
     The accounting policies of the segments are the same as those described in
the "Summary of Significant Accounting Policies." Transactions between
affiliates are recognized at prices which approximate market value. Significant
transactions between the operating components are eliminated to reconcile the
segment information to consolidated amounts. 



                                       48
<PAGE>   51

CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


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

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------------
                                                                      Exploration                       Corporate
                                                                          and                              and
                                    Distribution     Transmission     Production         Other         Eliminations        Total 
-----------------------------------------------------------------------------------------------------------------------------------
                                                                       (In Thousands) 
<S>                                 <C>              <C>              <C>             <C>              <C>              <C>        
1998
Operating revenues
Nonaffiliated
   Regulated gas sales ..........   $ 1,372,568      $        --      $        --     $     1,123      $        --      $ 1,373,691
   Nonregulated gas sales .......            --               --          369,736         124,683               --          494,419
   Gas transportation and storage       197,888          347,600              436               9               --          545,933
   Liquid sales .................            --               --          204,030              --               --          204,030
   Other ........................        35,498           54,887           34,042          12,899            5,007          142,333
                                    -----------      -----------      -----------     -----------      -----------      -----------
     Total nonaffiliated ........     1,605,954          402,487          608,244         138,714            5,007        2,760,406
Affiliated ......................         5,855          100,060           22,860          23,684         (152,459)              --
                                    -----------      -----------      -----------     -----------      -----------      -----------
     Total operating revenues ...     1,611,809          502,547          631,104         162,398         (147,452)       2,760,406
Operating expenses
Purchased gas ...................       835,222           46,559           39,972         125,223         (146,575)         900,401
Liquids, capacity and other
   products purchased ...........            --           24,662          115,397           5,218               --          145,277
Operation expense ...............       311,154          128,701          156,024          25,406           (3,275)         618,010
Maintenance .....................        50,579           28,011            9,823             245            1,710           90,368
Depreciation and amortization ...        75,064           57,343          185,902           6,769            4,835          329,913
Taxes, other than income taxes ..       131,575           33,684            7,344             916            5,780          179,299
                                    -----------      -----------      -----------     -----------      -----------      -----------
     Operating income before
        income taxes ............       208,215          183,587          116,642          (1,379)          (9,927)         497,138
                                    -----------      -----------      -----------     -----------      -----------      -----------
Income taxes ....................        58,314           60,708           23,117            (300)         (12,190)         129,649
Interest revenues ...............           703            4,394            1,118           2,379           (5,429)           3,165
Equity in earnings of equity
   investees ....................            --            8,667            4,791          11,917               --           25,375
Other revenues-net ..............         6,678            1,122              250           1,699           (3,589)           6,160
Interest charges ................        46,847           25,098           21,650           8,249           12,634          114,478
                                    -----------      -----------      -----------     -----------      -----------      -----------
Income from continuing 
 operations......................   $   110,435      $   111,964      $    78,034     $     6,667      $   (19,389)     $   287,711
                                    ===========      ===========      ===========     ===========      ===========      ===========
-----------------------------------------------------------------------------------------------------------------------------------
Other significant non-cash items:
   Pension cost (credit)-net ....   $   (42,529)     $   (15,801)     $     1,423     $       213      $       198      $   (56,496)
   Stock award amortization .....   $     1,039      $       634      $     1,708     $       322      $     3,757      $     7,460
-----------------------------------------------------------------------------------------------------------------------------------
Investment in equity investees ..   $        --      $    36,785      $    47,834     $   210,608      $        --      $   295,227
Total assets ....................   $ 2,946,758      $ 1,553,518      $ 1,523,936     $   350,258      $   (12,570)     $ 6,361,900
Capital expenditures ............   $   146,563      $    56,748      $   352,781     $   193,118      $    11,903      $   761,113
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>



                                       49
<PAGE>   52


CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                                                                          Exploration                    Corporate
                                                                              and                           and        
                                          Distribution    Transmission     Production     Other        Eliminations      Total 
------------------------------------------------------------------------------------------------------------------------------------
                                                                          (In Thousands) 
<S>                                       <C>            <C>             <C>           <C>             <C>              <C>        
1997
Operating revenues
Nonaffiliated
   Regulated gas sales .................  $ 1,844,221    $        --     $        --   $     6,780     $        --      $ 1,851,001
   Nonregulated gas sales ..............           --             --         396,282        37,101              --          433,383
   Gas transportation and storage ......      153,904        337,475             701            --              --          492,080
   Liquid sales ........................           --             --         275,902            --              --          275,902
   Other ...............................       24,577         60,639          27,287         5,787           6,454          124,744
                                          -----------    -----------     -----------   -----------     -----------      -----------
     Total nonaffiliated ...............    2,022,702        398,114         700,172        49,668           6,454        3,177,110
Affiliated .............................        3,859        101,179           5,508        12,962        (123,508)              --
                                          -----------    -----------     -----------   -----------     -----------      -----------
     Total operating revenues ..........    2,026,561        499,293         705,680        62,630        (117,054)       3,177,110
Operating expenses
Purchased gas ..........................    1,158,721          8,592          31,535        34,817        (119,585)       1,114,080
Liquids, capacity and other
   products purchased ..................           --         53,203         157,101           271              --          210,575
Operation expense ......................      324,150        133,681         166,990        34,056           7,735          666,612
Maintenance ............................       50,533         28,426           9,604            47           1,998           90,608
Depreciation and amortization ..........       77,389         62,258         181,356           406           3,229          324,638
Impairment of gas and oil
   producing properties ................           --             --          10,351            --              --           10,351
Taxes, other than income taxes .........      149,198         32,263           5,917           347           5,859          193,584
                                          -----------    -----------     -----------   -----------     -----------      -----------
     Operating income before
        income taxes ...................      266,570        180,870         142,826        (7,314)        (16,290)         566,662
                                          -----------    -----------     -----------   -----------     -----------      -----------
Income taxes ...........................       74,699         64,512          31,686        (2,940)        (11,688)         156,269
Interest revenues ......................        1,172          2,011           1,330         2,322          (5,172)           1,663
Equity in earnings of equity
   investees ...........................           --          8,929           3,275         5,462              --           17,666
Other revenues-net .....................       (2,152)           (86)            217        (6,996)          2,130           (6,887)
Interest charges .......................       48,419         24,051          22,372         1,983           7,102          103,927
                                          -----------    -----------     -----------   -----------     -----------      -----------
Income from continuing operations ......  $   142,472    $   103,161     $    93,590   $    (5,569)    $   (14,746)     $   318,908
                                          ===========    ===========     ===========   ===========     ===========      ===========
------------------------------------------------------------------------------------------------------------------------------------
Other significant non-cash items:
   Impairment of gas and oil
     producing properties ..............  $        --    $        --     $    10,351   $        --     $        --      $    10,351
   Pension cost (credit)-net ...........  $   (33,335)   $   (12,819)    $     1,257   $        81     $    (1,195)     $   (46,011)
   Stock award amortization ............  $     1,201    $       836     $     1,847   $       279     $     4,046      $     8,209
------------------------------------------------------------------------------------------------------------------------------------
Investment in equity investees .........  $        --    $    34,518     $    38,558   $   143,122     $        --      $   216,198
Total assets ...........................  $ 2,879,312    $ 1,501,640     $ 1,360,068   $   827,497     $  (254,823)     $ 6,313,694
Capital expenditures ...................  $   147,213    $    49,300     $   299,897   $    95,801     $    10,906      $   603,117
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                       50
<PAGE>   53

CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------------------
                                                                         Exploration                  Corporate
                                                                            and                          and
                                          Distribution   Transmission    Production       Other       Eliminations     Total 
-------------------------------------------------------------------------------------------------------------------------------
                                                                            (In Thousands) 
<S>                                       <C>            <C>            <C>           <C>            <C>            <C>        
1996
Operating revenues
Nonaffiliated
   Regulated gas sales .................. $ 1,746,650    $        --    $        --   $     7,017    $        --    $ 1,753,667
   Nonregulated gas sales ...............          --             --        396,104            --             --        396,104
   Gas transportation and storage .......     132,486        346,570            532            --             --        479,588
   Liquid sales .........................          --             --        202,907            --             --        202,907
   Other ................................      26,377         65,713         26,456         1,878          2,768        123,192
                                          -----------    -----------    -----------   -----------    -----------    -----------
     Total nonaffiliated ................   1,905,513        412,283        625,999         8,895          2,768      2,955,458
Affiliated ..............................         (1)        104,891         6,288         13,299       (124,477)            --
                                          -----------    -----------    -----------   -----------    -----------    -----------
     Total operating revenues ...........   1,905,512        517,174        632,287        22,194       (121,709)     2,955,458
Operating expenses
Purchased gas ...........................   1,025,186          7,421         51,691            --       (121,081)       963,217
Liquids, capacity and other
   products purchased ...................          --         63,599        115,708            --             --        179,307
Operation expense .......................     352,706        142,265        147,851        22,369          2,063        667,254
Maintenance .............................      53,774         24,494         10,791            11            997         90,067
Depreciation and amortization ...........      74,132         60,394        165,715           154          2,488        302,883
Taxes, other than income taxes ..........     141,293         37,403          7,299           545          4,143        190,683
                                          -----------    -----------    -----------   -----------    -----------    -----------
     Operating income before
        income taxes ....................     258,421        181,598        133,232          (885)       (10,319)       562,047
                                          -----------    -----------    -----------   -----------    -----------    -----------
Income taxes ............................      76,334         63,105         34,609         1,760        (13,493)       162,315
Interest revenues .......................       1,051          4,244          4,359         2,073         (9,703)         2,024
Equity in earnings of equity
   investees ............................          --          7,199          1,967         3,792             --         12,958
Other revenues-net ......................        (503)           177            125            53         (5,859)        (6,007)
Interest charges ........................      44,853         23,962         20,130         1,842          8,538         99,325
                                          -----------    -----------    -----------   -----------    -----------    -----------
Income from continuing operations ....... $   137,782    $   106,151    $    84,944   $     1,431    $   (20,926)   $   309,382
                                          ===========    ===========    ===========   ===========    ===========    ===========
-------------------------------------------------------------------------------------------------------------------------------
Other significant non-cash items:
   Pension cost (credit)-net ............ $   (19,142)   $    (6,494)   $     1,900   $        --    $      (581)   $   (24,317)
   Stock award amortization ............. $       876    $       546    $     1,225   $        --    $     5,127    $     7,774
-------------------------------------------------------------------------------------------------------------------------------
Investment in equity investees .......... $        --    $    34,389    $    31,460   $    72,820    $        --    $   138,669
Total assets ............................ $ 2,900,620    $ 1,496,976    $ 1,264,453   $   519,861    $  (181,305)   $ 6,000,605
Capital expenditures .................... $   143,050    $    85,904    $   271,392   $    48,570    $     6,135    $   555,051
-------------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                       51
<PAGE>   54


CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

19.  SUBSEQUENT EVENT

On February 22, 1999, the Company and Dominion Resources, Inc. (DRI) announced
that a definitive merger agreement (merger agreement) was approved by the boards
of directors of both companies. Under the terms of the merger agreement, DRI
intends to acquire all of the Company's shares of common stock in a
stock-for-stock transaction. Pursuant to the merger agreement, each share of the
Company's common stock will be converted into 1.52 shares of DRI common stock.
The transaction is conditioned, among other things, upon approvals of
shareholders of both companies, opinions of independent accountants that the
transaction will be treated as a pooling of interests for accounting purposes,
approvals of various federal regulatory agencies and the completion of
regulatory processes in states where the combined company will operate. DRI is a
holding company with businesses in regulated and competitive electric power,
natural gas and oil development and selected financial services. DRI's principal
business subsidiary is Virginia Electric and Power Company, a regulated public
utility engaged in the generation, transmission, distribution and sale of
electric energy in Virginia and northeastern North Carolina.

20.  SUPPLEMENTARY FINANCIAL INFORMATION--UNAUDITED

(A) GAS AND OIL PRODUCING ACTIVITIES (EXCLUDING COST-OF-SERVICE RATE-REGULATED
ACTIVITIES)
The following disclosures exclude the Company's gas producing activities subject
to cost-of-service rate regulation. Certain disclosures about these activities
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,                   1998          1997
-----------------------------------------------------
                                    (In Thousands)
<S>                           <C>          <C>       
Capitalized costs of
   Proved properties ......   $3,594,042   $3,293,851
   Unproved properties ....      389,977      328,174
                              ----------   ----------
     Subtotal .............    3,984,019    3,622,025
                              ----------   ----------
Accumulated depreciation of
   Proved properties ......    2,542,026    2,367,105
   Unproved properties ....      160,222      146,417
                              ----------   ----------
     Subtotal .............    2,702,248    2,513,522
                              ----------   ----------
     Net capitalized costs    $1,281,771   $1,108,503
                              ==========   =========
-----------------------------------------------------
</TABLE>
       As described in Note 5, 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.


                                       52
<PAGE>   55


CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

      TOTAL COSTS INCURRED
The following costs were incurred by subsidiaries in their gas and oil producing
activities during the years 1996 through 1998:

<TABLE>
<CAPTION>
------------------------------------------------------------------
  Years Ended December 31,         1998         1997        1996
------------------------------------------------------------------
                                         (In Thousands)
<S>                             <C>          <C>          <C>     
Property acquisition costs
   Proved properties .......    $ 20,597     $ 14,142     $ 42,880
   Unproved properties .....      29,512       43,951       17,911
                                --------     --------     --------
     Subtotal ..............      50,109       58,093       60,791
Exploration costs ..........     115,429      101,891       49,622
Development costs ..........     176,220      118,746      125,139
                                --------     --------     --------
     Total .................    $341,758     $278,730     $235,552
                                ========     ========     ========
------------------------------------------------------------------
</TABLE>

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

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------
  Years Ended December 31,                              1998       1997*       1996*
----------------------------------------------------------------------------------------
                                                              (In Thousands)
<S>                                                    <C>         <C>         <C>     
Revenues (net of royalties) from:
   Sales to nonaffiliated companies..............      $357,729    $403,233    $360,973
   Transfers to other operations.................        24,785       7,973      13,158
                                                       --------    --------    --------
     Total.......................................       382,514     411,206     374,131
                                                       --------    --------    --------
Less: Production (lifting) costs.................        62,937      65,286      55,679
       Depreciation and amortization.............       176,587     172,046     157,358
       Impairment of producing properties........            --      10,351          --
       Income tax expense........................        40,977      48,987      49,367
                                                       --------    --------    --------
Results of operations............................      $102,013    $114,536    $111,727
                                                       ========    ========    ========
</TABLE>
*Certain amounts reclassified to reflect discontinued operations.
--------------------------------------------------------------------------------


                                       53
<PAGE>   56


CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

      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, 1996 through 1998, and changes
in the reserves during those years, are shown in the two schedules which follow:

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------
  Years Ended December 31,                                   1998     1997     1996 
--------------------------------------------------------------------------------------
                                                                    (In Bcf) 
<S>                                                           <C>      <C>        <C> 
PROVED DEVELOPED AND UNDEVELOPED RESERVES*--GAS
     At January 1.........................................    1,141    1,040      985 
     Changes in reserves
        Extensions, discoveries and other additions.......      214      210      124 
        Revisions of previous estimates...................       70       31        5 
        Production........................................     (155)    (155)    (145)
        Purchases of gas in place**.......................       43       29       96 
        Sales of gas in place.............................       --      (14)     (25)
                                                              -----    -----    ------
     At December 31.......................................    1,313    1,141    1,040
                                                              =====    =====    =====

PROVED DEVELOPED RESERVES*--GAS
     At January 1.........................................      925      900      717 
     At December 31.......................................    1,052      925      900 
</TABLE>

 *Net before royalty.
**Amount for 1998 includes 39 Bcf of reserves transferred by sale to CNG
  Producing from an affiliate, Peoples Natural Gas.
--------------------------------------------------------------------------------


     The preceding proved developed and undeveloped gas reserves at December 31,
1998, 1997 and 1996, include United States reserves of 1,312, 1,140 and 1,039
Bcf which, together with the Canadian reserves and the gas reserves 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,                                   1998       1997      1996 
-----------------------------------------------------------------------------------------
                                                                 (In Thousand Bbls) 
<S>                                                           <C>        <C>       <C>    
PROVED DEVELOPED AND UNDEVELOPED RESERVES*--OIL
     At January 1.........................................    50,627     50,457    45,791 
     Changes in reserves
        Extensions, discoveries and other additions.......    11,275      4,582     5,976 
        Revisions of previous estimates...................     2,960      1,741     2,711 
        Production........................................    (7,895)    (7,312)   (4,766)
        Purchases of oil in place.........................       107      1,182       804 
        Sales of oil in place.............................        --        (23)      (59)
                                                              ------     ------    ------
                                                                   
     At December 31.......................................    57,074     50,627    50,457
                                                              ======     ======    ======
PROVED DEVELOPED RESERVES*--OIL
     At January 1.........................................    37,568     24,989    19,838 
     At December 31.......................................    42,750     37,568    24,989 
</TABLE>

*Net before royalty.
--------------------------------------------------------------------------------

     The foregoing proved developed and undeveloped oil reserves at December 31,
1998, 1997 and 1996 include United States reserves of 51,230, 44,160 and 41,818
thousand barrels, respectively. These, together with the Canadian reserves, are
as contained in reports of Ralph E. Davis Associates, Inc.


                                       54
<PAGE>   57

CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

     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,                                                        1998          1997           1996
                                                                               (In Thousands)
<S>                                                                  <C>            <C>           <C>       
Future cash inflows.............................................     $2,562,741     $3,197,532    $4,022,381
Less:  Future development and production costs..................        756,352        658,281       711,067
       Future income tax expense................................        482,585        766,233     1,049,234
                                                                     ----------     ----------    ----------
Future net cash flows...........................................      1,323,804      1,773,018     2,262,080
Less annual discount (10% a year)...............................        435,540        606,509       830,083
                                                                     ----------     ----------    ----------
Standardized measure of discounted future net cash flows........      $ 888,264     $1,166,509    $1,431,997
                                                                     ==========     ==========    ==========
------------------------------------------------------------------------------------------------------------
</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 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. 



                                       55
<PAGE>   58

CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

     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,                                          1998           1997            1996 
------------------------------------------------------------------------------------------------------------
                                                                              (In Thousands) 
<S>                                                                <C>             <C>             <C>       
Standardized measure of discounted future
   net cash flows at January 1................................     $1,166,509      $1,431,997      $ 841,743 
Changes in the year resulting from
   Sales and transfers of gas and oil produced
     during the year, less production costs...................       (319,577)       (345,920)      (318,583)
   Prices and production and development costs
      related to future production............................       (657,675)       (660,014)       632,118 
   Extensions, discoveries and other additions,
      less production and development costs...................        144,595         256,366        295,236 
   Previously estimated development costs
      incurred during the year................................         71,172          38,409         62,706 
   Revisions of previous quantity estimates...................         38,015         101,352        106,800 
   Accretion of discount......................................        166,707         209,210        119,555 
   Income taxes...............................................        180,611         159,528       (306,290)
   Purchases and sales of proved reserves in place-net........         35,639          40,815        112,601 
   Other (principally timing of production)...................         62,268         (65,234)      (113,889)
                                                                    ---------      ----------     ----------   
Standardized measure of discounted future
   net cash flows at December 31..............................      $ 888,264      $1,166,509     $1,431,997
                                                                    =========      ==========     ==========
------------------------------------------------------------------------------------------------------------
</TABLE>

      COST-OF-SERVICE PROPERTIES
As previously stated, activities subject to cost-of-service rate regulation,
consisting solely of gas reserves and related production, are excluded from the
foregoing information. In December 1998, Peoples Natural Gas, a subsidiary,
transferred by sale all of its remaining gas production properties to CNG
Producing, a nonregulated subsidiary. At December 31, 1997, net capitalized
costs of cost-of-service properties amounted to $8.4 million. Related proved
reserves of gas are located in the United States and amounted to 42 and 43 Bcf
at December 31, 1997 and 1996. Gas production for the years 1998, 1997 and 1996
amounted to 2, 3 and 3 Bcf, respectively.



                                       56
<PAGE>   59

CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(B)  Quarterly Financial Data
A summary of the quarterly results of operations for the years 1998 and 1997
follows. Because a major portion of the gas sold or transported by the Company's
distribution and transmission operations is ultimately used for space heating,
both revenues and earnings are subject to seasonal fluctuations, and third
quarter results are usually the least significant of the year for the Company.
Seasonal fluctuations are further influenced by the timing of price relief
granted under regulation to compensate for certain past cost increases.

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------
                                                                                  Quarter
                                                                 -----------------------------------------------
                                                                 First        Second       Third       Fourth 
----------------------------------------------------------------------------------------------------------------
                                                                                (In Thousands) 
<S>                                                               <C>          <C>          <C>         <C>      
1998
Total operating revenues.....................................     $999,165     $530,428     $423,448    $807,365 
Operating income before income taxes.........................     $234,850     $ 83,710     $ 25,516    $153,062 
Income from continuing operations............................     $138,033     $ 46,814     $  5,627    $ 97,237 
Discontinued operations (Note 2)
   Loss from discontinued energy marketing services
     operations, net of applicable tax benefit...............    $ (17,238)    $     --     $     --    $     -- 
   Income (loss) from disposal of energy marketing
     services operations, including provision for
     operating losses during the phase out period,
     net of applicable tax or tax benefit....................    $ (42,900)    $ 10,989     $  2,425    $ (2,221)
Net income...................................................    $  77,895     $ 57,803     $  8,052    $ 95,016 

Earnings per common share--basic*
   Income from continuing operations.........................    $    1.48     $    .49     $    .06    $   1.02 
   Loss from discontinued operations.........................         (.18)          --           --          -- 
   Income (loss) from disposal of discontinued
     operations..............................................         (.46)         .12          .02        (.02)
                                                                 ---------     --------     --------     ------- 
Net income...................................................    $     .84     $    .61     $    .08    $   1.00
                                                                 =========     ========     ========    ======== 

Earnings per common share--diluted*
   Income from continuing operations.........................        $1.45         $.49         $.06       $1.01 
   Loss from discontinued operations.........................         (.18)          --           --          -- 
   Income (loss) from disposal of discontinued
     operations..............................................         (.45)         .11          .02        (.02)
                                                                 ---------     --------     --------     ------- 
Net income                                                           $ .82         $.60         $.08       $ .99
                                                                 =========     ========     ========    ======== 
----------------------------------------------------------------------------------------------------------------
</TABLE>


                                       57
<PAGE>   60



CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------
                                                                                   Quarter
                                                                  -------------------------------------------------
                                                                  First         Second       Third        Fourth
-------------------------------------------------------------------------------------------------------------------
                                                                                 (In Thousands) 
<S>                                                               <C>            <C>          <C>          <C>     
1997
Total operating revenues.....................................     $1,143,768     $629,418     $462,980     $940,944
Operating income before income taxes.........................     $  283,358     $ 90,130     $ 33,536     $159,638
Income from continuing operations............................     $  173,028     $ 48,036     $  8,761     $ 89,083
Discontinued operations (Note 2)
   Income (loss) from discontinued energy marketing
     services operations, net of applicable tax or tax
     benefit.................................................     $   (1,537)    $ (9,051)    $ (4,223)       $ 283
Net income...................................................     $  171,491     $ 38,985     $  4,538     $ 89,366
Earnings per common share--basic*
   Income from continuing operations.........................          $1.83        $ .51        $ .09         $.94
   Income (loss) from discontinued operations................           (.02)        (.10)        (.04)          --
                                                                  ----------     --------     --------     --------
Net income...................................................          $1.81        $ .41        $ .05         $.94
                                                                  ==========     ========     ========     ========
Earnings per common share--diluted*
   Income from continuing operations.........................          $1.76        $ .50        $ .09         $.92
   Income (loss) from discontinued operations................           (.02)        (.09)        (.04)          --
                                                                  ----------     --------     --------     --------
Net income...................................................          $1.74        $ .41        $ .05         $.92
                                                                  ==========     ========     ========     ========
-------------------------------------------------------------------------------------------------------------------
</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, 1998, there were 33,121 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 1998 and
1997 follow. Restrictions on the payment of dividends are discussed in Note 12.

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------
                                                      Quarter
                                    ----------------------------------------------
                                      First      Second      Third       Fourth
----------------------------------------------------------------------------------
<S>                                 <C>         <C>          <C>         <C>      
Market Price Range
1998--High.......................   $60 1/2     $60 1/8      $59         $55 15/16
    --Low........................   $53 1/4     $54 15/16    $41 11/16   $50 7/16
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

Dividends Declared per Share
1998.............................   $.485       $.485        $.485       $.485
1997.............................   $.485       $.485        $.485       $.485
----------------------------------------------------------------------------------
</TABLE>


                                       58