<PAGE>
                                                                      Exhibit 99
 
CNG CONSOLIDATED
    NATURAL GAS
    COMPANY


CNG CONSOLIDATED
    NATURAL GAS
    COMPANY


CNG CONSOLIDATED
    NATURAL GAS
    COMPANY


CNG CONSOLIDATED
    NATURAL GAS
    COMPANY


CNG CONSOLIDATED
    NATURAL GAS
    COMPANY


CNG CONSOLIDATED      1996 Financial
    NATURAL GAS            Report
    COMPANY

CNG CONSOLIDATED
    NATURAL GAS
    COMPANY


CNG CONSOLIDATED
    NATURAL GAS
    COMPANY


CNG CONSOLIDATED
    NATURAL GAS
    COMPANY


CNG CONSOLIDATED
    NATURAL GAS
    COMPANY


CNG CONSOLIDATED
    NATURAL GAS
    COMPANY


CNG CONSOLIDATED
    NATURAL GAS
    COMPANY


CNG CONSOLIDATED
    NATURAL GAS
    COMPANY


CNG CONSOLIDATED
    NATURAL GAS      Appendix I
    COMPANY


<PAGE>
 
 
                               TABLE OF CONTENTS
                                                                            PAGE
                                                                            ----
Management's Discussion and Analysis of Financial Condition and Results of
 Operations...............................................................     1
Selected Financial Data...................................................    16
Report of Independent Accountants.........................................    17
Consolidated Statement of Income for the Years 1994 through 1996..........    19
Consolidated Balance Sheet at December 31, 1995 and 1996..................    20
Consolidated Statement of Cash Flows for the Years 1994 through 1996......    22
Notes to Consolidated Financial Statements................................    23
<PAGE>
 
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
 
RESULTS OF OPERATIONS
 
NET INCOME
Net income in 1996 was $298.3 million, or $3.16 a share, compared with net
income of $21.3 million, or $.23 a share, in 1995. Net income in 1994 was
$183.2 million, or $1.97 a share.

Earnings for both 1995 and 1996 reflect the impact of special charges in those
years. Excluding the impact of charges related to workforce reduction programs
totaling $9.9 million after taxes, or $.10 a share, 1996 net income would have
been $308.2 million, or $3.26 a share. Earnings for 1995 included the effects
of three special charges. During the first quarter, the Company recorded a
non-cash charge to write down the cost of gas and oil producing properties,
amounting to $145.0 million after taxes, or $1.56 a share. In the second
quarter, the Company recognized a non-cash charge of $20.3 million after
taxes, or $.22 a share, in connection with a write-down of coal properties. In
addition, during 1995 the Company recorded charges totaling $25.6 million
after taxes, or $.27 a share, for workforce reductions. Excluding these
special items, net income for 1995 would have been $212.3 million, or $2.28 a
share. Reference is made to Notes 3 and 4 to the consolidated financial
statements, pages 27 and 28, for details of the special charges recognized in
1995 and 1996.

Higher wellhead prices for natural gas and oil, increased gas and oil
production, colder weather, cost controls and the full year impact of new
rates in place for most of the Company's gas distribution customers
contributed to the improved results for 1996. Weather in the Company's retail
service areas was 5.6 percent colder than normal and 5.5 percent colder than
1995. Normal weather represents a measure of temperature experienced over an
historical time frame, the length of which may differ depending on the
regulatory jurisdiction.

During 1995, the favorable effects of new rates in place for most of the
Company's gas distribution and transmission customers, colder weather and
lower aggregate wage and benefit costs in the latter part of the year
resulting from the workforce reduction programs more than offset the impact of
continued low wellhead prices for natural gas and lower gas and oil
production. Weather in the Company's retail service territories was .5 percent
colder than normal and 2.2 percent colder than in 1994.

Warmer than normal weather, higher operating costs, lower average wellhead gas
prices, reduced gas production and higher interest expense affected results
for 1994.
 
OPERATING REVENUES
Operating revenues include revenues from gas and oil sales, transportation and
storage of gas, brokering activities, by-product operations and, beginning in
1995, wholesale electric sales. Total operating revenues in 1996 were $3,794.3
million, an increase of $487.0 million compared to 1995 operating revenues of
$3,307.3 million.

Regulated gas sales revenues of $1,752.2 million in 1996 were up $154.8
million compared to 1995, with sales volumes increasing 4.1 billion cubic feet
(Bcf) to 294.0 Bcf. Revenues and volumes from the Company's residential
customers increased in 1996 reflecting colder weather compared to 1995, while
revenues and volumes declined for the industrial customer class. While gas
sales volumes for the Company's commercial customer group declined in 1996,
revenues increased compared to 1995 reflecting higher average sales rates.

Nonregulated gas sales revenues increased $94.8 million in 1996, while sales
volumes decreased 160.5 Bcf compared to 1995. The effect of higher gas sales
prices, coupled with the impact of higher production, more than offset the
effect of reduced transaction volumes of the energy marketing services
component.

Gas transportation and storage revenues increased $8.7 million in 1996
compared to the prior year, to $465.1 million. The increase was due to higher
gas transportation revenues, which increased $13.4 million due to higher
volumes and rates. Lower storage service revenues partly offset this increase.
Other operating revenues increased $228.7 million in 1996 to $484.5 million.
The increase over 1995 was due
 
                                       1
<PAGE>
 
chiefly to an increase of $108.8 million in revenues from oil and condensate
production and brokering from the exploration and production operations and an
additional $87.7 million of wholesale electric sales by the energy marketing
services component.

Total operating revenues in 1995 increased $271.3 million from $3,036.0
million in 1994. Regulated gas sales revenues in 1995 decreased $81.9 million
from 1994, to $1,597.4 million, with sales volumes increasing 4.9 Bcf to 289.9
Bcf. Colder weather compared with 1994 led to the increase in sales volumes
while lower unit purchased gas costs reflected in revenues was responsible for
the decline in sales revenue. Nonregulated gas sales revenues increased $274.1
million in 1995, with sales volumes increasing 223.8 Bcf over the 1994 period
to 556.6 Bcf. These increases were attributable to the growth of the Company's
energy marketing services component. The increased volumes sold more than
offset the effects of lower wellhead prices and production at the exploration
and production operations. Gas transportation and storage revenues were $456.4
million in 1995, up $46.8 million over 1994. The increase was due principally
to higher transportation revenues, which increased $39.5 million due to both
increased volumes and rates. Other operating revenues increased $32.3 million
in 1995, to $255.8 million, reflecting wholesale sales of electricity of $21.8
million by the energy marketing services component.
 
OPERATING EXPENSES
Operating expenses, including taxes, increased 8 percent in 1996, to $3,402.1
million. Operating expenses in 1995 were $3,160.8 million, up 14 percent from
$2,775.1 million in 1994. Excluding the impact of the workforce reduction
charges in 1996 and 1995 and the impairment of gas and oil producing
properties in 1995, operating expenses for 1996 and 1995 would have been
$3,392.2 million and $2,990.2 million, respectively.

Purchased gas consistently represents the largest operating expense item for
the Company. Purchased gas costs were $1,615.0 million in 1996, $1,590.1
million in 1995 and $1,424.0 million in 1994. This expense is influenced
primarily by changes in gas sales requirements, the price and mix of gas
supplies, and the timing of recoveries of deferred purchased gas costs. During
1996, the effect of higher average purchase prices more than offset the impact
of decreased volume requirements in connection with nonregulated gas sales and
the deferral of purchased gas costs by the regulated subsidiaries. Total
purchased gas expense was higher in 1995 due primarily to increased volume
requirements associated with nonregulated gas sales. This factor more than
offset lower unit purchased gas costs, which reflected the nationwide decline
in gas prices during 1995.

Transport capacity and other purchased products expense includes the cost of
pipeline capacity not associated with gas purchased and the cost of liquids,
by-products and, beginning in 1995, electricity purchased for resale. This
expense increased $193.1 million in 1996 due chiefly to electricity purchased
for resale by the energy marketing services component and oil purchased for
resale by CNG Producing Company (CNG Producing). This expense increased $46.5
million in 1995 primarily due to increased transport capacity purchased from
other pipeline companies and electricity purchased for resale totaling $19.6
million.

Excluding the effect of the 1996 and 1995 workforce reduction charges of $15.2
million and $42.6 million, respectively, combined operation and maintenance
expense increased $77.2 million in 1996 due in large part to increased royalty
expense in 1996 resulting from higher gas and oil wellhead prices and
production. The increase in 1996 was partially offset by lower payroll costs
and reductions in certain administrative expenses. Maintenance expense
increased $4.2 million in 1996 to $90.1 million.

Excluding the effect of the workforce reduction charges, combined operation
and maintenance expense increased $7.5 million in 1995. Higher customer-
related expenses, slightly higher overhead costs and the regulator-mandated
adjustment for certain previously deferred costs in connection with the
settlement of CNG Transmission Corporation's (CNG Transmission) rate case were
factors contributing to the $10.8 million increase in operation expense. Lower
royalties paid as a result of both lower gas wellhead prices and production
and the benefits of the workforce reduction programs in the latter part of
1995 helped to minimize the increase. Maintenance expense declined $3.3
million, to $85.9 million, in 1995.
 
                                       2
<PAGE>
 
Total depreciation and amortization expense increased $47.6 million in 1996
due largely to higher gas and oil production volumes. Depreciation and
amortization charges were down $22.7 million in 1995 due to lower amortization
charges for the Company's exploration and production operations. Amortization
of gas and oil producing properties declined in 1995 primarily as the result
of the lower investment following the impairment of these properties in the
first quarter. Reserve additions and lower production also contributed to the
lower charges in 1995. Depreciation expense for the regulated subsidiaries was
higher in both 1996 and 1995 due principally to the increased level of plant
investment.

Taxes, other than income taxes, decreased $.7 million in 1996 due in large
part to lower excise and payroll taxes and decreased $.9 million in 1995 due
chiefly to lower revenue-based taxes.

Income taxes increased $152.8 million in 1996 compared to 1995 due to higher
pretax earnings. Income taxes decreased $79.4 million in 1995 compared to the
prior year due mainly to lower pretax earnings.
 
OTHER INCOME
Total other income was $9.3 million in 1996, compared to total other
deductions of $20.5 million in 1995 and total other income of $9.7 million in
1994. Excluding the write-down of coal properties of $31.3 million, 1995 total
other income would have been $10.8 million. Interest revenues declined $6.8
million in 1996 compared to the prior year due largely to the lower level of
temporary cash investments in 1996. Interest revenues increased $4.1 million
in 1995 due primarily to the higher level of temporary cash investments during
that year. Interest revenues were up $1.7 million in 1994, reflecting CNG
Transmission's billing of Federal Energy Regulatory Commission (FERC) Order
636 transition costs in late 1993 and August 1994. The increase in "Other-net"
of $5.4 million in 1996 compared to 1995 reflects increased earnings from the
Company's equity investments and losses related to minor property dispositions
at certain regulated subsidiaries in 1995 that did not recur in 1996,
partially offset by a charge of $5.0 million recognized in connection with an
early extinguishment of debt in December 1996. The decline in "Other-net" in
1995 compared to 1994 was due largely to the property dispositions in that
year.
 
INTEREST CHARGES
Interest on long-term debt increased $6.0 million in 1996 due primarily to
debenture sales of $150 million each in April 1995, October 1996 and December
1996. Interest on long-term debt was up $7.0 million in 1995 due chiefly to
interest expense related to the April 1995 debenture issuance. Other interest
expense declined $7.5 million in 1996 compared to the prior year due largely
to lower interest expense related to customer refunds. Other interest expense
increased in 1995 as a result of higher interest rates on commercial paper
borrowings. The amounts of interest expense capitalized in 1996 and 1995 were
lower than in 1994 due to the lower investment in unproved properties held by
the exploration and production operations.
 
FOURTH QUARTER RESULTS
The Company's net income for the fourth quarter of 1996 was $88.0 million
compared with $87.4 million earned in the 1995 fourth quarter, an increase of
$.6 million. On a per share basis, the 1996 quarter was $.93 compared with
$.94 in 1995. The 1996 quarter, however, reflects special charges for
workforce reductions totaling $7.8 million after taxes, or $.08 per share. The
Company's average gas wellhead price was $2.62 per thousand cubic feet (Mcf),
up $.51 per Mcf compared with the 1995 quarter, while gas production increased
40 percent over 1995. These positive factors were partially offset by the
effect of weather which was 7.8 percent warmer than in the 1995 fourth quarter
and the charge recognized in connection with an early extinguishment of debt
(see "Capital Resources and Liquidity," page 13).
 
                                       3
<PAGE>
 
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Quarters Ended December 31,                                    1996      1995
--------------------------------------------------------------------------------
<S>                                                          <C>        <C>
                                                               (In Millions)
Operating revenues.......................................... $ 1,229.2  $ 935.5
Operating expenses..........................................  (1,066.4)  (775.0)
                                                             ---------  -------
Operating income before income taxes........................     162.8    160.5
Income taxes................................................     (46.1)   (44.6)
Other income/expenses-net...................................     (28.7)   (28.5)
                                                             ---------  -------
Net income.................................................. $    88.0  $  87.4
                                                             =========  =======
Per common share (in dollars)...............................      $.93     $.94
Average shares outstanding (thousands)......................    94,882   93,442
--------------------------------------------------------------------------------
</TABLE>
 
NEW ACCOUNTING STANDARDS
Effective January 1, 1996, the Company adopted the provisions of Statement of
Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." The
adoption of SFAS No. 121 did not have a material effect on the Company's
financial position, results of operations or cash flows. Reference is made to
Note 1 to the consolidated financial statements, page 23, regarding SFAS No.
121.

In October 1995, the Financial Accounting Standards Board (FASB) issued SFAS
No. 123, "Accounting for Stock-Based Compensation." Although the Company has
not changed its accounting method for stock-based compensation as permitted by
this standard, it has included the disclosures pursuant to SFAS No. 123 in
Note 10 to the consolidated financial statements, page 34.
 
COMPONENTS OF THE BUSINESS
Due to the regulated nature of the distribution and transmission components of
the Company's business, operating results can be affected by regulatory delays
when price increases are sought through general rate filings to recover
certain higher costs of operations. Weather is also an important factor since
a major portion of the gas sold or transported by the distribution and
transmission operations is ultimately used for space heating.

The following presents the operating results for each of the Company's
business components. Reference is made to Note 18 to the consolidated
financial statements, page 43, for additional disaggregated information
pertaining to the Company's operations.
 
                                       4
<PAGE>
 
OPERATING INCOME BEFORE INCOME TAXES
Operating income before income taxes for the Company's business components for
the last three years is shown in the table below.
<TABLE>
-------------------------------------------------------------------------------------------------
<CAPTION>
Operating Income Before Income Taxes                                      1996*   1995**   1994
-------------------------------------------------------------------------------------------------
<S>                                                                       <C>     <C>     <C>
                                                                             (In Millions)
Distribution............................................................. $258.4  $207.5  $159.0
Transmission.............................................................  178.8   150.4   146.3
Exploration and production...............................................  133.2  (200.5)   34.0
Energy marketing services................................................   (9.1)   (5.7)     --
Other***.................................................................   (3.2)    2.9     7.6
Corporate and eliminations...............................................  (10.1)   (5.1)   (3.5)
                                                                          ------  ------  ------
 Total................................................................... $548.0  $149.5  $343.4
                                                                          ======  ======  ======
</TABLE>
  * Amounts for the distribution, transmission, exploration and production,
    energy marketing services and corporate components include the effect of
    workforce reduction charges totaling $8.2 million, $5.1 million, $.6
    million, $.3 million and $1.0 million, respectively.
 ** Amount for the exploration and production operations includes the impact
    of the write-down of gas and oil producing properties amounting to $226.2
    million. Amounts for the distribution, transmission, exploration and
    production, energy marketing services and corporate components include the
    effect of workforce reduction charges totaling $22.3 million, $6.0
    million, $7.7 million, $.5 million and $4.6 million, respectively.
*** Includes Consolidated LNG, CNG Research and CNG Coal. Amounts for 1996
    include CNG International and CNG Products and Services. CNG Energy
    Services, CNG Power and CNG Power Services are included in the 1994
    amounts.
-------------------------------------------------------------------------------
 
DISTRIBUTION
"Distribution" represents the results of the five retail gas distribution
subsidiaries, including their minor gas and oil production activities.
Effective January 1, 1997, West Ohio Gas Company (West Ohio Gas) was merged
with The East Ohio Gas Company (East Ohio Gas)(see "State Regulatory Issues,"
page 12).

Sales growth in the Company's residential service areas in Ohio, Pennsylvania
and West Virginia has generally been limited since such areas have experienced
minimal population growth, and the vast majority of households in these areas
already use natural gas for space heating. Opportunity for growth in the
retail sales market is expected to continue at Virginia Natural Gas, Inc.
(Virginia Natural Gas), due to customer conversions from other energy sources
and the past and potential future expansion of its service territory. Since
the Company's acquisition of this subsidiary in 1990, it has experienced an
annual customer growth rate of about 4 percent, well above the 1 percent rate
for the other distribution subsidiaries.

Similar to the unbundling in recent years of the services provided by gas
pipeline companies, gas distribution companies are now preparing for the
expected deregulation and unbundling of the retail energy market. To this end,
on September 25, 1996, East Ohio Gas filed a proposal with the Public
Utilities Commission of Ohio (PUCO) to permit open access for all of its Ohio
customers. If approved, open access service to customers who do not already
have such an option--small business and residential customers--would be phased
in. 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.
Under this proposal, Ohio customers would also have the option of continuing
to purchase natural gas from East Ohio Gas. In addition, The Peoples Natural
Gas Company (Peoples Natural Gas) plans to open its system to customer choice
in Pennsylvania during the spring of 1997. Peoples Natural Gas has begun a
customer information campaign to educate customers about their new options for
unbundled service.

In addition to the initiatives at East Ohio Gas and Peoples Natural Gas, in
early 1997 the Company formed a new nonregulated unit, CNG Retail Services
Corporation. This subsidiary was created to market natural gas, electricity,
and related products and services to residential, commercial and small
industrial customers, including those within the Company's traditional service
territories. This new subsidiary is expected to enable the Company to take
full advantage of emerging deregulated energy markets for both gas and
electricity.
 
                                       5
<PAGE>
 
  OPERATING INCOME BEFORE INCOME TAXES
Excluding workforce reduction charges amounting to $8.2 million in 1996 and
$22.3 million in 1995, operating income before income taxes for the gas
distribution operations for 1996 and 1995 would have been $266.6 million and
$229.8 million, respectively. Improved results for 1996 reflect colder
weather, cost control efforts and the full year impact of general rate
increases that went into effect in the latter part of 1995 at Peoples Natural
Gas, Hope Gas, Inc. (Hope Gas) and East Ohio Gas. Overall, weather in the
Company's retail service areas was 5.5 percent colder than 1995 and 5.6
percent colder than normal.

Excluding workforce reduction charges, operating income before income taxes
for the gas distribution operations in 1995 was up $70.8 million from 1994. In
addition to the general rate increases placed into effect in late 1994 and in
1995 at four distribution subsidiaries, colder weather, the addition of new
customers, higher transport volumes and lower wage and benefit costs in the
latter part of the year due to the workforce reduction programs contributed
favorably to 1995 results. Overall, weather in the Company's retail service
territories was 2.2 percent colder than 1994 and .5 percent colder than
normal.

Operating income before income taxes for the gas distribution operations
declined $7.9 million in 1994 due principally to warmer weather and higher
costs of operations. Overall, weather in the Company's retail service area was
3 percent warmer than 1993 and 4 percent warmer than normal. Two subsidiaries
were granted rate increases and another began collecting higher rates, subject
to refund. However, the increases were placed into effect in the latter part
of the year and did not have a significant impact on 1994 results.
 
  OPERATING REVENUES
Operating revenues of the gas distribution operations increased $160.3 million
in 1996 compared to 1995, to $1,905.5 million. Gas sales revenues were up
$152.3 million reflecting both higher average sales prices and higher sales
volumes. Average sales prices increased due to the impact of both higher unit
purchased gas costs passed through to customers and higher rates in place for
most of the Company's distribution customers. Colder weather was a major
factor in the increased sales volumes. Gas transportation and storage revenues
increased $10.1 million resulting from both higher volumes and rates.

Revenues of the gas distribution operations in 1995 declined $60.4 million
from the prior year. Gas sales revenues declined $81.0 million as lower
average sales prices more than offset the impact of higher sales volumes. The
lower average sales prices were the result of lower unit purchased gas costs
reflected in the rates charged to customers. Rate increases in late 1994 and
in 1995, however, helped hold down the decline in sales revenues. Gas
transportation and storage revenues increased $20.4 million in 1995 due to
both increased 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                                        1996  1995  1994
--------------------------------------------------------------------------------
<S>                                                            <C>   <C>   <C>
                                                               (In Billion Cubic
                                                                     Feet)
Sales......................................................... 294.2 289.9 285.0
Transportation................................................ 174.2 164.8 151.1
                                                               ----- ----- -----
  Throughput.................................................. 468.4 454.7 436.1
                                                               ===== ===== =====
--------------------------------------------------------------------------------
</TABLE>
Colder weather and the net addition of approximately 17,000 residential and
commercial customers during 1996 contributed to the 1 percent increase in gas
sales volumes compared to the prior year. Residential gas sales volumes
increased 6.2 Bcf, to 218.7 Bcf, in 1996. Commercial sales decreased 3.0 Bcf
while volumes transported to these customers were up 7.2 Bcf. Deliveries to
industrial customers
 
                                       6
<PAGE>
 
were higher in 1996, increasing .6 Bcf to 138.8 Bcf. Sales to industrial
customers declined .4 Bcf to 6.9 Bcf, while transportation volumes increased
1.0 Bcf to 131.9 Bcf. Transportation to off-system customers increased 1.2 Bcf
in 1996.

Gas sales volumes were up 2 percent in 1995, reflecting colder weather and the
net addition of about 24,800 residential and commercial customers. Residential
and commercial gas sales increased 6.6 Bcf and .4 Bcf, respectively, compared
to 1994. While industrial sales volumes declined 2.1 Bcf, transportation
volumes to those customers increased 9.8 Bcf. Gas transported for commercial
customers was 29.8 Bcf in 1995, up 5.4 Bcf compared to 1994. Transportation to
off-system customers declined 1.5 Bcf in 1995.
 
TRANSMISSION
"Transmission" includes the results of the gas transmission, storage, by-
product and certain other activities of CNG Transmission and, prior to April
1, 1995, the activities of CNG Storage Service Company (CNG Storage). CNG
Storage was formed primarily to engage in the sale, lease or brokerage of gas
storage capacity obtained from third parties including the sale or lease of
base gas. The results of CNG Storage were not significant to the transmission
operations. Gas and oil production activities of CNG Transmission are included
in exploration and production operations.

Changing regulatory policies intended to increase competition in the natural
gas industry have been the principal factor affecting transmission operations
over the past several years. With the implementation of Order 636 effective
October 1, 1993, CNG Transmission abandoned its traditional sales service
which consisted of various elements of gas sales, transportation and storage
that were offered and priced as a single bundled service. Customers now have
even greater access to the Company's pipeline and storage capacity, together
with a range of options available with respect to gas transportation and
storage services.
 
  OPERATING INCOME BEFORE INCOME TAXES
Excluding workforce reduction charges of $5.1 million in 1996 and $6.0 million
in 1995, operating income before income taxes for the gas transmission
operations for 1996 and 1995 would have been $183.9 million and $156.4
million, respectively. Cost control efforts and increased gas transportation
and by-products revenues contributed to improved results in 1996.

Excluding workforce reduction charges, operating income before income taxes of
the gas transmission operations increased $10.1 million in 1995 compared to
1994. Higher rates resulting from CNG Transmission's general rate filing which
became effective July 1, 1994, and cost controls were the major factors for
the improved results in 1995.

Operating income before income taxes increased $2.9 million in 1994 and
reflected the first full year of applying the straight fixed variable rate
design under which operating income is less influenced by changes in
throughput than in the past. Significant factors affecting 1994 operating
results included increased transportation and storage service revenues,
competition from other pipelines, and higher operating costs not yet reflected
in rates.
 
  OPERATING REVENUES
Total operating revenues of the gas transmission operations were $32.4 million
higher in 1996 compared to 1995. Gas transportation and storage revenues
increased $9.7 million due to higher gas transportation revenues, which
increased $14.9 million due to higher volumes and rates. This increase was
partly offset by decreased storage service revenues. Revenues from the sale of
by-products increased $9.7 million due chiefly to higher sales rates.

Total operating revenues of the gas transmission operations increased $11.7
million in 1995 to $471.0 million. Gas transportation and storage revenues
increased $27.4 million in 1995 due primarily to higher transportation
revenues, which increased $24.3 million as higher rates more than offset
slightly lower transport volumes. Revenues from the sale of by-products
declined $10.2 million, due to the overall decline in volumes of products
sold.
 
                                       7
<PAGE>
 
  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
takes advantage of 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. The Company's pipelines are part of an interconnected gas
transmission system which will 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). In addition, such a network allows
the Company to manage its gas supply requirements in an efficient and flexible
manner.

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, operating income for the transmission operations is not
significantly influenced by changes in throughput due to the straight fixed
variable rate design.

Total throughput for the gas transmission operations, consisting entirely of
transportation volumes and including intercompany activity, was 758.4 Bcf,
744.0 Bcf, and 748.4 Bcf for the years 1996, 1995 and 1994, respectively.
Throughput during the first quarter of 1996 was up 12 percent compared to the
prior year quarter due in part to colder weather while throughput for the
remainder of the year was lower than in 1995. First quarter 1995 throughput
was lower than the prior year period due to warmer weather, while throughput
was up for the balance of 1995 compared to 1994.
 
EXPLORATION AND PRODUCTION
"Exploration and production" includes the results of CNG Producing and the gas
and oil production activities of CNG Transmission.
 
  OPERATING INCOME BEFORE INCOME TAXES
Operating income before income taxes for the exploration and production
operations in 1996 was $133.2 million, compared with an operating loss before
income taxes of $200.5 million in 1995. However, the 1996 results include
workforce reduction charges of $.6 million while 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
$133.8 million and $33.4 million for 1996 and 1995, respectively. 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.

Excluding special items, operating results for 1995 would have been slightly
lower than operating income before income taxes of $34.0 million in 1994. The
impact of continued low gas wellhead prices and lower gas and oil production
slightly offset the favorable impact of higher oil wellhead prices, a $7.5
million reduction in production-related expenses, and reductions in overhead
costs in 1995. In addition, depreciation and amortization expense was $32.1
million lower in 1995 resulting from the impairment of gas and oil producing
properties, the effect of gas and oil reserve additions, and lower production.
Reserves equivalent to 210 Bcf of gas were added in 1995.

Exploration and production operating income before income taxes in 1994
decreased $13.3 million. The effect of the decline in total operating revenues
due to lower prices and production was partially offset by decreases in
royalty expense and depreciation and amortization of $9.4 million and $21.2
million, respectively. The lower level of royalty expense is attributable
primarily to reduced gas and oil production during 1994. Lower production,
together with the recognition of additional proved gas and
 
                                       8
<PAGE>
 
oil reserves in the Gulf of Mexico, resulted in lower depreciation and
amortization expense for 1994. Reserves equivalent to 190 Bcf of gas at Viosca
Knoll 826, a deep-water project in the Gulf of Mexico in which the Company
holds a 50 percent interest, were added in 1994 and represent the largest
single addition of reserves in the Company's history.
 
  GAS AND OIL PRODUCTION AND PRICES
The following table sets forth the Company's gas and oil production and
average wellhead prices for the exploration and production operations for the
last three years:
<TABLE>
--------------------------------------------------------------------------------
<CAPTION>
Production                                                1996    1995    1994
--------------------------------------------------------------------------------
<S>                                                      <C>     <C>     <C>
GAS (BCF)
Nonregulated............................................   144.5   102.6   113.7
Regulated*..............................................     3.0     4.6     5.8
                                                         ------- ------- -------
  Total.................................................   147.5   107.2   119.5
                                                         ======= ======= =======
OIL (000 BBLS)
Nonregulated............................................ 4,765.9 3,131.7 3,333.0
Regulated*..............................................      --    17.2    23.8
                                                         ------- ------- -------
  Total................................................. 4,765.9 3,148.9 3,356.8
                                                         ======= ======= =======
AVERAGE WELLHEAD PRICES
(NONREGULATED ONLY)
Gas (per Mcf)...........................................  $ 2.46  $ 1.89  $ 2.16
Oil (per Bbl)...........................................  $17.60  $16.04  $14.45
</TABLE>
 
*Cost-of-service. East Ohio Gas sold all of its remaining gas and oil reserves
during 1995. Hope Gas sold all of its remaining gas reserves to CNG Producing
during 1996. At December 31, 1996, the Company's remaining cost-of-service gas
reserves were held by Peoples Natural Gas.
--------------------------------------------------------------------------------
The Company's average gas wellhead price in 1996 was $2.46 per Mcf, up $.57
from $1.89 in 1995. Gas production in 1996 was 147.5 Bcf, up 38 percent from
1995. The increase in gas production during 1996 was due partially to the
impact of two significant Gulf of Mexico projects which commenced production
in the 1996 first quarter, Popeye and Main Pass 225. Production also benefited
from the effect of production enhancement efforts at existing Company-operated
fields. Average oil wellhead prices were $17.60 per barrel in 1996, up $1.56
from 1995, while oil production increased 51 percent from the prior year. The
increase in oil production in 1996 was due in large part to production from
the Popeye project.

Consistent with prices nationwide, the Company's gas wellhead prices in 1995
were below prior year levels for most of the period as the average gas price
of $1.89 per Mcf was $.27 less than the 1994 price. As a result of continued
weak gas prices, the Company voluntarily shut in a portion of its production
at various times during 1995 which, in addition to normal declines at certain
properties, resulted in a decline in production compared to 1994. While
average oil wellhead prices rose $1.59 per barrel in 1995, oil production was
lower than 1994 due primarily to normal production declines at older
properties.
 
  OPERATING REVENUES
Total operating revenues for the exploration and production operations
increased 75 percent in 1996, to $632.3 million. Of the $159.3 million
increase in gas sales revenues in 1996, $90.8 million was due to higher
average gas prices and $68.5 million reflected increased volumes. Revenues
from oil and condensate production and brokering increased $108.9 million in
1996, with $77.7 million of the increase attributable to increased volumes and
the remaining increase due to higher rates. Revenues from oil brokering
increased $74.6 million while revenues from the sale of oil and condensate
production increased $34.3 million.
 
                                       9
<PAGE>
 
Total operating revenues decreased $127.9 million in 1995, to $361.5 million.
Gas sales revenues declined $134.0 million, reflecting the continued low level
of gas wellhead prices and lower production compared to 1994. Revenues from
oil and condensate production and brokering increased $10.5 million in 1995.
Revenues from oil brokering were up $8.8 million due to both higher volumes
sold and higher rates, while revenues from oil and condensate production were
up $1.7 million as higher rates more than offset the effect of lower volumes.
 
ENERGY MARKETING SERVICES
"Energy marketing services" represents the results of CNG Energy Services
Corporation (CNG Energy Services) and CNG Power Services Corporation (CNG
Power Services). These subsidiaries, which are under a single management team,
were reported as one business component beginning in 1995. The results for
these subsidiaries were included in the "Other" component in 1994.

CNG Energy Services markets Company-owned gas production and arranges gas
supplies, transportation, storage and related services for customers. CNG
Energy Services also holds the Company's ownership interests in seven
independent power plants. CNG Power Services purchases and resells electricity
at market-based rates.

The energy marketing services component reported an operating loss before
income taxes of $9.1 million in 1996 compared to an operating loss before
income taxes of $5.7 million in 1995. The 1996 and 1995 results include
workforce reduction charges totaling $.3 million and $.5 million,
respectively. In addition to higher overhead costs, the 1996 loss occurred in
part because this component contracted for quantities of natural gas to supply
power plants during the summer air-conditioning season; these quantities
proved to be too high when third quarter 1996 weather turned cooler than
expected. Reduced transaction volumes during 1996 also adversely impacted 1996
operating results. Total throughput for this component was 427.1 Bcf in 1996
as compared to 570.8 Bcf in 1995. Power marketing, which includes the sale of
wholesale electricity, increased to 4,958,000 megawatt-hours in 1996 compared
to 1,948,000 megawatt-hours in 1995.

In addition to depressed gas margins throughout the year, 1995 operating
results also reflected a $5.3 million pretax charge recognized by CNG Energy
Services in December 1995 in connection with a mark-to-market valuation of
exchange-traded futures contracts used to manage price risk exposure related
to its stored gas inventories.

Income recognized in connection with CNG Energy Service's investments in 1996
and 1995 totaled $5.8 million and $3.9 million, respectively. These amounts
are not included in operating income or loss before income taxes but are
reflected in "Other income" for the component.
 
LIMITATION ON CAPITALIZED COSTS
As indicated in Note 1 to the consolidated financial statements, CNG Producing
and CNG Transmission follow the full cost method of accounting for their gas
and oil producing activities prescribed by the Securities and Exchange
Commission (SEC). Reference is made to Note 3 to the consolidated financial
statements, page 27, regarding the Company's recognition under the SEC full
cost rules of an impairment of its gas and oil producing properties at March
31, 1995. No additional impairment of these properties was required during the
remainder of 1995 or during 1996.

There are a number of factors, including prices, that determine whether or not
an impairment is required. Gas wellhead prices were strong during the fourth
quarter of 1996, and continued to be firm in the early part of 1997. However,
since gas wellhead prices are subject to sudden fluctuations, the 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 the price decline.
 
INTERNATIONAL ACTIVITIES
In January 1996, the Company formed a new subsidiary, CNG International
Corporation (CNG International). The purpose of CNG International is to engage
in energy-related activities outside the United States.
 
                                      10
<PAGE>
 
In December 1996, CNG International and El Paso Energy Corporation (El Paso)
entered into a joint venture to own and operate the Australian pipeline assets
formerly held by Tenneco Energy. CNG International and El Paso each own 30
percent of Epic Energy Pty Ltd. (Epic Energy), an Australian entity formed to
hold the investment's operating assets. The remaining 40 percent ownership
interest in Epic Energy is held equally among four Australian investors--
Allgas Energy, AMP Investments, Axion Funds Management and Hastings Funds
Management. The primary operating assets of the venture include two major
long-distance natural gas pipelines from Australia's Cooper Basin. One of the
pipelines carries gas from the city of Moomba south to Adelaide, while the
other was recently built and will carry gas from the city of Ballera east to
Wallumbilla, Queensland. CNG International's net investment in Epic Energy
totaled $38.7 million at December 31, 1996 and will be accounted for under the
equity method.

A marketing alliance formed in late 1994 among CNG Energy Services and two
Canadian firms, Hydro-Quebec and Noverco, was terminated in December 1996. The
informal alliance created by the three companies did not evolve into a formal
partnership due principally to regulatory impediments.
 
FEDERAL AND STATE REGULATORY MATTERS
 
  GAS AND ELECTRIC INDUSTRY DEVELOPMENTS
In the post-Order 636 gas industry environment, competition at the retail
level is receiving increased attention by state regulators. Several states
have commenced proceedings to evaluate restructuring of the natural gas
industry at the retail level. These proceedings have generally focused on
unbundling, incentive ratemaking, market-based rates and customer choice (see
"Distribution," page 5).

In addition to the further deregulation of the gas industry, the emerging
unbundling of services provided by electric utilities may ultimately result in
the convergence of both industries to create one overall, highly competitive
marketplace for a customer's total energy needs. During 1995 and 1996,
regulators at the federal and state levels finalized initiatives to promote
increased competition in the electric industry. These initiatives included
issuance in April 1996 of FERC Order Nos. 888 and 889 (Orders 888 and 889). By
requiring open access to the national electric transmission grid, Order 888
fosters increased competition in both the generation of electricity and the
supply of bulk power to major wholesale customers. A companion order, Order
889, addresses the timing, information access and other administrative details
associated with the FERC deregulation initiative. Other signs of an
increasingly deregulated electric utility environment include retail
competition plans adopted in several states, pilot retail wheeling programs
and pro-competition legislation proposed at both the federal and state levels.

Reflecting the evolution to a more competitive energy environment, the pace
and size of business combinations among natural gas and electric utilities
increased significantly during 1996. These business combinations have
generally been initiated to provide benefits from economies of scale, to
reduce costs by the elimination of duplicate facilities and processes, and to
improve the strategic and competitive position of the surviving entity. Recent
and pending regulatory actions may serve to further facilitate more business
combinations in the energy industry. The FERC has streamlined its regulatory
review process regarding pending mergers. In addition, the SEC has recommended
legislation to conditionally repeal the Public Utility Holding Company Act of
1935 (PUHCA), to which the Company is subject, in conjunction with legislation
which would grant the various state regulatory commissions greater oversight
authority of companies currently subject to the PUHCA. If legislation to
repeal or significantly modify the provisions of the PUHCA becomes law,
certain restrictions related to diversification activities, including business
combinations, for gas and electric companies subject to the PUHCA may be
eased.

Through its actions in recent years, the Company believes it is well-
positioned to compete in an evolving and increasingly deregulated energy
marketplace. The creation in 1997 of CNG Retail Services Corporation and the
ongoing development of the energy marketing services component, in conjunction
with streamlining and restructuring of its existing distribution, transmission
and exploration and production operations, reflects the Company's proactive
approach to meeting the demands of a more competitive and dynamic business
environment.
 
                                      11
<PAGE>
 
  FERC ORDER 636
With FERC approval, CNG Transmission implemented Order 636 effective October
1, 1993, in accordance with the terms of a comprehensive stipulation and
agreement (Settlement) reached with customers and others. Accordingly, from
late 1993 through 1996 CNG Transmission direct billed transition costs to
customers and affiliates totaling $178.6 million, net of refunds. Amounts
remaining to be collected at December 31, 1996 in connection with these direct
billings are not significant.

The Settlement also allows CNG Transmission to file with the FERC for rate
increases to recover both stranded and new facilities costs related to the
implementation of Order 636. The recovery of $5.0 million of stranded costs
was included in the settlement agreement approved by the FERC November 29,
1995 regarding its December 1993 general rate filing. Certain additional
stranded costs have been deferred in accordance with the Settlement pending
CNG Transmission's general rate filing in 1997. Through 1996, CNG Transmission
has incurred $8.0 million of new facilities costs related to Order 636, and
expects to incur up to $22.0 million in additional costs for such facilities.

Based on management's current estimates, the operating environment under Order
636 and any uncertainties pertaining to the recovery of remaining transition
costs should not have a material adverse effect on the Company's financial
position, results of operations or cash flows. Reference is made to Note 2 to
the consolidated financial statements for additional information regarding
Order 636 transition costs.
 
  STATE REGULATORY ISSUES
On September 25, 1996, Virginia Natural Gas filed an expedited rate
application with the Virginia State Corporation Commission requesting an
annual revenue increase of $13.9 million. The requested rate increase reflects
the recovery of higher operating costs and additional investment in facilities
required to serve customers on Virginia Natural Gas' system. The new rates
went into effect, subject to refund, on October 25, 1996.

On December 19, 1996, the PUCO approved the Company's merger of West Ohio Gas
into East Ohio Gas effective January 1, 1997. The merger is part of an overall
objective to improve the cost-effectiveness of the distribution operations and
to better position the Company for competing in the future energy environment.
 
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
41, for a detailed description of environmental matters.

Estimates of liability in the environmental area are based on current
environmental laws and regulations and existing technology. The exact nature
of environmental issues which the Company may encounter in the future cannot
be predicted. Additional environmental liabilities may result in the future as
more stringent environmental laws and regulations are implemented and as the
Company obtains more specific information about its existing sites and
production facilities. At present, no estimate of any such additional
liability, or range of liability amounts, can be made. However, the amount of
any such liabilities could be material.
 
EFFECTS OF INFLATION
Although inflation rates have been 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.
 
                                      12
<PAGE>
 
FINANCIAL CONDITION
 
DIVIDEND AND COMMON STOCK MATTERS
In December 1996, the Board of Directors continued the quarterly dividend on
the common stock at 48.5 cents a share. Total dividends paid to common
shareholders in 1996 were $183.0 million compared with $180.8 million in 1995
and $180.4 million in 1994.

During 1996, a total of 1,372,716 original issue shares were issued through
various Company-sponsored plans, including 768,531 shares acquired by
employees through the exercise of outstanding stock options.

Under the Company's stock repurchase plan, up to 4 million shares of the
outstanding common stock can be repurchased. The shares may be purchased in
the open market from time-to-time, depending on market conditions. The Company
may also acquire shares of its common stock through certain provisions of the
various stock incentive plans. The shares repurchased or acquired are held as
treasury stock and are available for reissuance for general corporate purposes
or in connection with various employee benefit plans. No treasury shares were
held by the Company at December 31, 1995. During 1996, no open market
purchases were made by the Company. The Company acquired 146,667 shares in
1996 through the provisions of its employee incentive plans at a cost of
$8,144,000, or an average price of $55.53 a share. All of these shares were
sold before year-end to the Company's benefit plans.
 
CAPITAL SPENDING
The current capital spending program for 1997 is estimated at $525.9 million,
a 6.1 percent decrease compared with total capital spending in 1996. The
estimated 1997 budget has been allocated as follows: distribution, $150.3
million; transmission, $82.7 million; exploration and production, $231.4
million; energy marketing services, $5.6 million; and corporate and other,
$55.9 million. The decreased level of capital expenditures anticipated for
1997 assumes slightly lower spending for exploration and production
operations, reflecting reduced spending on deep-water projects and increased
conventional drilling, both onshore and offshore. Transmission and
distribution operations expenditures will primarily be limited to spending for
enhancements and improvements in the pipeline system and related facilities.
The "corporate and other" category includes expenditures to upgrade
information systems technology, primarily to centralize and consolidate
services and financial systems, and to invest in selected international
projects.

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. Although the Company does not expect to require long-term
financing in 1997 to support capital spending, it may turn to the market to
take advantage of other opportunities and 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 was $407.2 million, $552.7
million and $631.3 million for the years 1996, 1995 and 1994, respectively.
The decline in net cash provided by operating activities in 1996 was due in
part to the deferral of purchased gas costs in excess of costs currently
recovered in rates and the payment of customer refunds during the period.
Lower gas wellhead prices and rate-related refunds made to customers were the
principal reasons for the lower cash flows from operations in 1995.

During October 1996, the Company sold $150 million of 6 7/8% Debentures Due
October 15, 2026. The Debentures are noncallable but will be redeemed at par
at the option of the holder on October 15, 2006. In December 1996, the Company
sold $150 million of 6 5/8% Debentures Due December 1, 2008. The net proceeds
from these sales were, and will be, used to finance, in part, 1996 and 1997
capital expenditures and to reduce short- and/or long-term debt.
 
                                      13
<PAGE>
 
During December 1996, the Company called for redemption $53.125 million
principal amount of the 8 5/8% Debentures Due December 1, 2011. In connection
with the call, the Company placed funds into an irrevocable trust in December
1996 for the sole purpose of paying the principal amount and related call
premium and accrued interest. As such, the debt was removed from the
Consolidated Balance Sheet at December 31, 1996. Payment was made from the
trust on February 1, 1997. This transaction resulted in a charge amounting to
$5.0 million in 1996.

The Company has shelf registrations with the SEC for the sale of up to $50
million of debt securities. In addition, the Company anticipates filing a new
shelf registration during 1997 which would allow it to sell up to an
additional $950 million of debt and/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 1996 was 7.27 percent, compared with 7.69 percent for 1995 and 7.74
percent for 1994. The long-term debt to capitalization ratio was 39.3 percent
at the end of 1996, and 38.7 percent and 34.5 percent at year-end 1995 and
1994, respectively. Under the provisions of one of the indentures covering the
Company's outstanding senior debenture issues, the ratio cannot exceed 60
percent. The Company's senior debentures are rated A1 by Moody's Investors
Service, AA- by Standard & Poor's, AA- by Duff and Phelps, and AA by Fitch
Investors Service.

At December 31, 1996, the Company had two short-term credit agreements with a
group of banks, for $475 million and $300 million. The Company made no
borrowings under these agreements during 1996 and there were no amounts
outstanding under any credit agreements at December 31, 1996 or 1995.

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 1996, of which $374 million was
outstanding at year-end. The Company may utilize unused portions of its credit
agreements to provide support for commercial paper notes.

In the normal course of business, certain of the nonregulated subsidiaries
utilize derivatives to manage exposure to price risk in connection with the
production, purchase and sale of natural gas and oil, purchase and sale of
electricity, and for stored gas inventories. The use of derivatives exposes
the Company to market risk and credit risk. Market risk represents the
potential loss that can be caused by a change in the market value of a
particular commitment. Although the use of derivatives generally reduces
market risk exposure due to unfavorable price fluctuations, risk management
activities, while not significant, can result in the assumption of a limited
degree of price risk in certain isolated transactions. Credit risk relates to
the risk of loss that the Company would incur as a result of nonperformance by
counterparties pursuant to the terms of their contractual obligations. The
Company does not have a significant exposure to any individual counterparty to
its energy price risk management activities. Management has operating
procedures in place to evaluate market and credit risks and believes that the
Company's exposure to risks associated with derivatives is not material in
relation to the Company's financial position, results of operations or cash
flows. Reference is made to Notes 1 and 15 to the consolidated financial
statements, pages 23 and 39, regarding energy price risk management
activities.
 
FORWARD-LOOKING INFORMATION
Certain matters discussed in this document, including Management's Discussion
and Analysis of Financial Condition and Results of Operations, are "forward-
looking statements" intended to qualify for the safe harbors from liability
established by the Private Securities Litigation Reform Act of 1995. These
forward-looking statements can generally be identified as such because the
context of the statement will include words such as the Company "believes,"
"anticipates," "expects" or words of similar import. Similarly, statements
that describe the Company's future plans, objectives or goals are also
forward-looking statements. Such statements may address future events and
conditions concerning capital expenditures, earnings, litigation, rate and
other regulatory matters, liquidity and capital resources, and financial
accounting matters. Actual results in each instance could differ materially
from those currently anticipated in such statements, due to factors such as:
natural gas and electric industry restructuring, including
 
                                      14
<PAGE>
 
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 markets in which the Company operates; and other circumstances
affecting anticipated revenues and costs.
 
SUMMARY OF FINANCIAL DATA
The Company's Summary of Financial Data is on page 16.
 
                                      15
<PAGE>
 
SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------
Summary of Financial Data (Thousand $)         1996*        1995*          1994       1993       1992
--------------------------------------------------------------------------------------------------------
<S>                                          <C>          <C>           <C>        <C>        <C>
EARNINGS
Gas sales................................... $2,844,709   $2,595,103    $2,402,861 $2,615,036 $1,951,545
Gas transportation, storage and other.......    949,600      712,222       633,167    569,049    569,305
  Total operating revenues..................  3,794,309    3,307,325     3,036,028  3,184,085  2,520,850
Purchased gas...............................  1,614,983    1,590,137     1,424,020  1,594,373    990,604
Transport capacity and other purchased
 products...................................    346,747      153,577       107,094     79,001     73,001
Operation and maintenance...................    789,356**    739,612***    689,575    677,666    657,825
Depreciation and amortization...............    304,171      256,636       279,317    294,648    287,840
Impairment of gas and oil producing
 properties.................................         --      226,209            --         --         --
Taxes, other than income taxes..............    191,078      191,698       192,617    181,053    169,315
  Operating income before income taxes......    547,974      149,456       343,405    357,344    342,265
Income taxes................................    155,830        2,943        82,427     99,906     68,623
Other income-net............................      9,304       10,760         9,694     10,531      4,749
Write-down of coal properties...............         --       31,266            --         --         --
Interest charges............................    103,175      104,663        87,501     79,475     83,433
Income before change in accounting
 principle..................................    298,273       21,344       183,171    188,494    194,958
Cumulative effect of applying SFAS No. 109..         --           --            --     17,422         --
  Net income................................    298,273       21,344       183,171    205,916    194,958
Per share of common stock
  Income before change in accounting
    principle...............................      $3.16         $.23         $1.97      $2.03      $2.19
  Cumulative effect of applying SFAS
    No. 109.................................         --           --            --        .19         --
  Net income................................      $3.16         $.23         $1.97      $2.22      $2.19
Average common shares outstanding........... 94,434,336   93,246,114    92,999,693 92,808,156 89,127,805
Return on average stockholders' equity......      14.0%         1.0%          8.4%       9.6%       9.7%
Times fixed charges earned..................       4.76         1.21          3.53       3.95       3.41
--------------------------------------------------------------------------------------------------------
DIVIDENDS--CASH
Paid per common share.......................      $1.94        $1.94         $1.94      $1.92      $1.90
  Payout ratio..............................      61.4%       843.5%         98.5%      86.5%      86.8%
Declared per common share...................      $1.94        $1.94         $1.94     $1.925     $1.905
--------------------------------------------------------------------------------------------------------
ASSETS
Total assets................................ $6,000,605   $5,418,293    $5,518,673 $5,437,188 $5,158,871
Property, plant and equipment
  Total investment..........................  8,304,205    7,929,350     7,676,956  7,346,028  7,087,102
  Accumulated depreciation..................  4,226,905    4,016,945     3,650,310  3,429,760  3,212,202
Capital expenditures and acquisitions.......    560,293      439,393       437,785    342,569    441,518
--------------------------------------------------------------------------------------------------------
CAPITAL STRUCTURE
Total common stockholders' equity........... $2,205,152   $2,045,818    $2,184,334 $2,176,432 $2,132,838
Long-term debt..............................  1,426,315    1,291,811     1,151,973  1,158,648  1,111,956
                                             ----------   ----------    ---------- ---------- ----------
  Total capitalization...................... $3,631,467   $3,337,629    $3,336,307 $3,335,080 $3,244,794
                                             ==========   ==========    ========== ========== ==========
Long-term debt ratio........................      39.3%        38.7%         34.5%      34.7%      34.3%
Shares of common stock outstanding at year-
 end........................................ 94,933,631   93,591,623    93,027,847 92,933,828 92,557,017
Common stockholders' equity per share.......     $23.23       $21.86        $23.48     $23.42     $23.04
--------------------------------------------------------------------------------------------------------
</TABLE>
  *Certain amounts and ratios are not comparable with prior years due to special
   charges.
 **Includes special charges for workforce reduction costs of $15,195,000.
***Includes special charges for workforce reduction costs of $42,555,000.
--------------------------------------------------------------------------------
 
                                       16
<PAGE>
 
 
                       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 19
through 50 of this Appendix I to the proxy statement for the 1997 annual meeting
of stockholders present fairly, in all material respects, the financial position
of Consolidated Natural Gas Company and subsidiaries (the Company) at December
31, 1996 and 1995, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1996, in conformity
with generally accepted accounting principles. These financial statements are
the responsibility of the Company's management; our responsibility is to express
an opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted auditing
standards which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
 
PRICE WATERHOUSE LLP
 
600 Grant Street
Pittsburgh, Pennsylvania 15219-9954
February 18, 1997
 
                                      17
<PAGE>
 
                    (THIS PAGE WAS INTENTIONALLY LEFT BLANK)
 
                                       18
<PAGE>
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
For the Years Ended December 31,                                 1996        1995        1994
-------------------------------------------------------------------------------------------------
                                                                   (Thousands of Dollars)
<S>                                                           <C>         <C>         <C>
OPERATING REVENUES
Regulated gas sales.........................................  $1,752,223  $1,597,379  $1,679,235
Nonregulated gas sales......................................   1,092,486     997,724     723,626
                                                              ----------  ----------  ----------
  Total gas sales...........................................   2,844,709   2,595,103   2,402,861
Gas transportation and storage..............................     465,110     456,370     409,632
Other.......................................................     484,490     255,852     223,535
                                                              ----------  ----------  ----------
  Total operating revenues (Note 2).........................   3,794,309   3,307,325   3,036,028
                                                              ----------  ----------  ----------
OPERATING EXPENSES
Purchased gas...............................................   1,614,983   1,590,137   1,424,020
Transport capacity and other purchased products.............     346,747     153,577     107,094
Operation expense (Note 4)..................................     699,289     653,731     600,421
Maintenance.................................................      90,067      85,881      89,154
Depreciation and amortization (Note 3)......................     304,171     256,636     279,317
Impairment of gas and oil producing properties (Note 3).....          --     226,209          --
Taxes, other than income taxes..............................     191,078     191,698     192,617
                                                              ----------  ----------  ----------
  Subtotal..................................................   3,246,335   3,157,869   2,692,623
                                                              ----------  ----------  ----------
  Operating income before income taxes......................     547,974     149,456     343,405
Income taxes (Note 7).......................................     155,830       2,943      82,427
                                                              ----------  ----------  ----------
  Operating income..........................................     392,144     146,513     260,978
                                                              ----------  ----------  ----------
OTHER INCOME (DEDUCTIONS)
Interest revenues...........................................       2,281       9,095       5,006
Write-down of coal properties (Note 3)......................          --     (31,266)         --
Other-net...................................................       7,023       1,665       4,688
                                                              ----------  ----------  ----------
  Total other income (deductions)...........................       9,304     (20,506)      9,694
                                                              ----------  ----------  ----------
  Income before interest charges............................     401,448     126,007     270,672
                                                              ----------  ----------  ----------
INTEREST CHARGES
Interest on long-term debt..................................     101,814      95,823      88,788
Other interest expense......................................       7,224      14,732       7,992
Allowance for funds used during construction................      (5,863)     (5,892)     (9,279)
                                                              ----------  ----------  ----------
  Total interest charges....................................     103,175     104,663      87,501
                                                              ----------  ----------  ----------
NET INCOME..................................................  $  298,273  $   21,344  $  183,171
                                                              ==========  ==========  ==========
  Earnings per share of common stock........................       $3.16        $.23       $1.97
  Average common shares outstanding (thousands).............      94,434      93,246      93,000
-------------------------------------------------------------------------------------------------
</TABLE>
The Notes to Consolidated Financial Statements are an integral part of this
statement.
 
                                       19
<PAGE>
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
------------------------------------------------------------------------------
<TABLE>
<CAPTION>
At December 31,                                             1996         1995
------------------------------------------------------------------------------
                                                      (Thousands of Dollars)
<S>                                                   <C>          <C>
ASSETS
PROPERTY, PLANT AND EQUIPMENT (Note 3)
Gas utility and other plant.......................... $ 4,848,392  $ 4,710,086
Accumulated depreciation and amortization............  (1,840,129)  (1,785,965)
                                                      -----------  -----------
   Net gas utility and other plant...................   3,008,263    2,924,121
                                                      -----------  -----------
Exploration and production properties................   3,455,813    3,219,264
Accumulated depreciation and amortization............  (2,386,776)  (2,230,980)
                                                      -----------  -----------
   Net exploration and production properties.........   1,069,037      988,284
                                                      -----------  -----------
   Net property, plant and equipment.................   4,077,300    3,912,405
                                                      -----------  -----------
CURRENT ASSETS
Cash and temporary cash investments..................      44,524       36,277
Accounts receivable
 Customers...........................................     647,207      522,391
 Unbilled revenues and other.........................     161,525      144,253
 Allowance for doubtful accounts.....................     (15,167)     (10,306)
Inventories, at cost
 Gas stored--current portion (Note 8)................     170,513      112,429
 Materials and supplies (average cost method)........      33,070       35,815
Unrecovered gas costs (Note 2).......................     108,016       25,123
Deferred income taxes--current (net).................          --       20,993
Prepayments and other current assets.................     243,333      181,686
                                                      -----------  -----------
   Total current assets..............................   1,393,021    1,068,661
                                                      -----------  -----------
REGULATORY AND OTHER ASSETS
Unamortized abandoned facilities (Note 9)............      15,791       28,672
Other investments....................................     149,858       60,939
Deferred charges and other assets (Notes 2, 4, 6, 7,
 15 and 16)..........................................     364,635      347,616
                                                      -----------  -----------
   Total regulatory and other assets.................     530,284      437,227
                                                      -----------  -----------
   Total assets...................................... $ 6,000,605  $ 5,418,293
                                                      ===========  ===========
------------------------------------------------------------------------------
</TABLE>
The Notes to Consolidated Financial Statements are an integral part of this
statement.
 
                                       20
<PAGE>
  
------------------------------------------------------------------------------
<TABLE>
<CAPTION>
At December 31,                                             1996         1995
------------------------------------------------------------------------------
                                                      (Thousands of Dollars)
<S>                                                   <C>          <C>
STOCKHOLDERS' EQUITY AND LIABILITIES
CAPITALIZATION
Common stockholders' equity (Note 10)
 Common stock, par value $2.75 per share
   Authorized, 1996--400,000,000 shares, 1995--
   200,000,000 shares
   Issued, 1996--94,933,631 shares, 1995--93,591,623
   shares............................................ $   261,068  $   257,377
 Capital in excess of par value......................     537,002      478,535
 Retained earnings (Note 12).........................   1,424,624    1,309,906
 Unearned compensation...............................     (17,542)          --
                                                      -----------  -----------
   Total common stockholders' equity.................   2,205,152    2,045,818
Long-term debt (Note 13).............................   1,426,315    1,291,811
                                                      -----------  -----------
   Total capitalization..............................   3,631,467    3,337,629
                                                      -----------  -----------
CURRENT LIABILITIES
Current maturities on long-term debt.................     104,000       10,250
Commercial paper (Note 14)...........................     374,000      336,000
Accounts payable.....................................     535,296      410,296
Estimated rate contingencies and refunds (Note 2)....      21,602       59,363
Amounts payable to customers.........................          --       40,315
Taxes accrued........................................      97,336      114,335
Deferred income taxes--current (net) (Note 7)........      36,096           --
Dividends declared...................................      46,043       45,392
Other current liabilities............................     150,047       95,339
                                                      -----------  -----------
   Total current liabilities.........................   1,364,420    1,111,290
                                                      -----------  -----------
DEFERRED CREDITS
Deferred income taxes (Note 7).......................     681,334      672,266
Accumulated deferred investment tax credits..........      28,838       31,031
Deferred credits and other liabilities (Notes 7 and
 15).................................................     294,546      266,077
                                                      -----------  -----------
   Total deferred credits............................   1,004,718      969,374
                                                      -----------  -----------
COMMITMENTS AND CONTINGENCIES (Note 17)
                                                      -----------  -----------
 
   Total stockholders' equity and liabilities........ $ 6,000,605  $ 5,418,293
                                                      ===========  ===========
------------------------------------------------------------------------------
</TABLE>
 
                                       21
<PAGE>
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------
For the Years Ended December 31,                                   1996       1995       1994
-------------------------------------------------------------------------------------------------
                                                                    (Thousands of Dollars)
<S>                                                              <C>        <C>        <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income...................................................... $ 298,273  $  21,344  $ 183,171
Adjustments to reconcile net income to net cash
 provided by operating activities
  Depreciation and amortization.................................   304,171    256,636    279,317
  Impairment of gas and oil producing properties................        --    226,209         --
  Write-down of coal properties.................................        --     31,266         --
  Deferred income taxes-net.....................................    63,230    (48,767)   (60,744)
  Investment tax credit.........................................    (2,201)    (2,198)    (2,567)
  Changes in current assets and current liabilities
   Accounts receivable-net......................................  (139,179)  (116,529)    81,896
   Inventories..................................................   (55,339)    77,024    (48,566)
   Unrecovered gas costs........................................   (82,893)   (11,988)     5,467
   Accounts payable.............................................    94,131     69,761     11,198
   Estimated rate contingencies and refunds.....................   (37,761)   (24,041)    25,948
   Amounts payable to customers.................................   (40,315)   (55,825)    68,538
   Taxes accrued................................................   (16,999)    19,922    (17,685)
   Other-net....................................................    (6,006)    13,643     (2,901)
  Changes in other assets and other liabilities.................    28,305     92,553    108,219
  Other-net.....................................................      (252)     3,714         37
                                                                 ---------  ---------  ---------
   Net cash provided by operating activities....................   407,165    552,724    631,328
                                                                 ---------  ---------  ---------
CASH FLOWS USED IN INVESTING ACTIVITIES
Plant construction and other property additions.................  (439,489)  (434,739)  (416,051)
Proceeds from dispositions of property, plant and
 equipment-net..................................................     9,079     14,066        164
Cost of other investments-net...................................   (87,735)    (7,464)   (14,902)
                                                                 ---------  ---------  ---------
   Net cash used in investing activities........................  (518,145)  (428,137)  (430,789)
                                                                 ---------  ---------  ---------
CASH FLOWS PROVIDED BY (OR USED IN) FINANCING ACTIVITIES
Issuance of common stock........................................    37,726     19,058        279
Issuance of debentures..........................................   299,567    148,899         --
Repayments of long-term debt....................................   (68,750)        --         --
Unsecured loan repayment........................................    (4,000)    (4,000)        --
Commercial paper borrowings (or repayments)-net.................    37,853   (103,399)   (15,601)
Dividends paid..................................................  (183,020)  (180,782)  (180,415)
Other-net.......................................................      (149)        (9)        (1)
                                                                 ---------  ---------  ---------
   Net cash provided by (or used in) financing activities.......   119,227   (120,233)  (195,738)
                                                                 ---------  ---------  ---------
   Net increase in cash and temporary cash investments..........     8,247      4,354      4,801
CASH AND TEMPORARY CASH INVESTMENTS AT JANUARY 1................    36,277     31,923     27,122
                                                                 ---------  ---------  ---------
CASH AND TEMPORARY CASH INVESTMENTS AT DECEMBER 31.............. $  44,524  $  36,277  $  31,923
                                                                 =========  =========  =========
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for
  Interest (net of amounts capitalized)......................... $ 109,602  $ 102,663  $  91,011
  Income taxes (net of refunds)................................. $ 108,742  $  58,949  $ 154,860
Non-cash financing activities
  Conversion of 7 1/4% Convertible Subordinated Debentures...... $      --  $      --  $   3,795
  Issuance of common stock under benefit plans.................. $  25,570  $   1,121  $     666
-------------------------------------------------------------------------------------------------
</TABLE>
The Notes to Consolidated Financial Statements are an integral part of this
statement.
 
                                       22
<PAGE>
 
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 subsidiary companies
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 (the
Company) within this framework are summarized in this Note.
 
USE OF ESTIMATES
The consolidated financial statements reflect certain estimates and
assumptions made by management that affect the reported amounts of assets and
liabilities, the disclosure of contingent assets and liabilities at the date
of the financial statements, and the reported amounts of revenues and expenses
for the periods presented.
 
PRINCIPLES OF CONSOLIDATION
The Parent Company owns all of the capital stock of its subsidiaries. The
consolidated financial statements represent the accounts of the Company after
the elimination of intercompany transactions.

The Company follows the equity method of accounting for investments in
partnerships and corporate joint ventures when the Company is able to
influence the financial and operating policies of the investee. For all other
investments, the cost method is applied.
 
REVENUE RECOGNITION
Revenues from gas sales and transportation services are recognized in the same
period in which the related gas 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 of gas 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.
 
ENERGY PRICE RISK MANAGEMENT ACTIVITIES
In the normal course of business, certain of the nonregulated subsidiaries
utilize commodity futures and option contracts and derivative financial
instruments to manage exposure to price risk in connection with the
production, purchase and sale of natural gas and oil, purchase and sale of
electricity, and for stored gas inventories. Derivative financial instruments
may also be used from time to time to manage foreign currency risk in
connection with certain contractual commitments. Exchange-traded instruments
which permit settlement by physical delivery of the commodity under contract
are not considered derivative financial instruments under SFAS No. 119,
"Disclosure about Derivative Financial Instruments and Fair Value of Financial
Instruments." The derivative financial instruments utilized by the
subsidiaries include over-the-counter (OTC) commodity price swap agreements,
OTC foreign currency swap agreements and OTC options which require settlement
in cash. Under the price swap agreements, the subsidiaries make payments to,
or receive payments from, counterparties generally based on the difference
between fixed
 
                                      23
<PAGE>
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

and variable gas and oil prices or on prices at different receipt points as
specified in the contracts. Under foreign currency swap agreements, payments
are made to, or received from, counterparties generally based on the
difference in the current foreign exchange rate. Settlement takes place under
the swap agreements on a monthly basis, and amounts received or paid are
recognized as an adjustment to gas and oil sales revenues, purchased gas
expense or transport capacity costs in that month to correspond with the
recognition of the related physical transaction.

For derivative financial instruments or exchange-traded contracts that qualify
(based on correlation to price movements of gas and oil) and are designated as
hedges, related gains or losses are deferred and subsequently recognized in
income, as revenues or expense, in the same period the hedged transaction
occurs. The value of derivatives that do not qualify for hedge accounting
treatment are marked-to-market each period, with gains and losses recognized
in the operating income of that period.

Margin accounts for open futures contracts are recorded in the Consolidated
Balance Sheet under "Prepayments and other current assets." Deferred losses or
gains are reflected in the Consolidated Balance Sheet under "Deferred charges
and other assets" and "Deferred credits and other liabilities," respectively.
Cash flows from price risk management activities are reported in the
Consolidated Statement of Cash Flows as an operating activity--consistent with
the category of the cash flows from the underlying physical transaction.
 
PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION
 
  GAS UTILITY AND OTHER PLANT
The property, plant and equipment accounts are stated at the cost incurred or,
where required by regulatory authorities, "original cost." Additions and
betterments are charged to the property accounts at cost. Upon normal
retirement of a plant asset, its cost is charged to accumulated depreciation
together with costs of removal less salvage. The costs of maintenance, repairs
and replacing minor items are charged principally to expense as incurred.
 
  EXPLORATION AND PRODUCTION PROPERTIES
CNG Producing and CNG Transmission follow the full cost method of accounting
for gas and oil producing activities prescribed by the SEC. Under the full
cost method, all costs directly associated with property acquisition,
exploration, and development activities are capitalized, with the principal
limitation that such amounts not exceed the present value of estimated future
net revenues to be derived from the production of proved gas and oil reserves.
If net capitalized costs exceed the estimated value at the end of any
quarterly period, then a permanent write-down of the assets must be recognized
in that period.

The gas producing activities of Peoples Natural Gas are subject to cost-of-
service rate regulation and are exempt from the accounting methods prescribed
by the SEC.
 
  DEPRECIATION AND AMORTIZATION
Depreciation and amortization are recorded over the estimated service lives of
plant assets by application of the straight-line method or, in the case of gas
and oil producing properties, the unit-of-production method.

Under the full cost method of accounting, amortization is also accrued on
estimated future costs to be incurred in developing proved gas and oil
reserves, and on estimated dismantlement and abandonment costs net of
projected salvage values. However, the costs of investments in unproved
properties and major development projects are excluded from amortization until
it is determined whether or not proved reserves are attributable to such
properties.
 
  ACCOUNTING FOR IMPAIRMENTS
Effective January 1, 1996, the Company adopted the provisions of SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets
to Be Disposed Of." This standard requires
 
                                      24
<PAGE>
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

that long-lived assets and certain intangibles be reviewed for impairment when
events or changes in circumstances indicate that the carrying amount of an
asset may not be recoverable. If the aggregate estimated future cash flows to
be derived from an asset are less than its carrying amount, an impairment must
be recognized. The Company's gas and oil producing activities that are subject
to the SEC's full cost accounting method will continue to be evaluated for
impairment under SEC Regulation S-X. SFAS No. 121 also requires the write-off
of a regulatory asset if and when it is no longer probable that future
revenues will provide for the recovery of the carrying value of the asset. The
adoption of SFAS No. 121 did not have a material effect on the Company's
financial position, results of operations or cash flows.
 
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.
  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: 1994--3 3/8% to 8 1/4%; 1995--5 3/4% to 8
3/8% 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
 
  PENSION PROGRAM
The Company has qualified noncontributory defined benefit pension plans
covering substantially all employees. Benefits payable under the plans are
based primarily on each employee's years of service, age and base salary
during the five years prior to retirement. Net pension costs are determined by
an independent actuary, and the plans are funded on an annual basis to the
extent such funding is deductible under federal income tax regulations. Plan
assets consist primarily of equity securities, fixed income securities and
insurance contracts. The pension program also includes the payment of
supplemental pension benefits to certain retirees depending on retirement
dates, and the payment of benefits to certain retired executives under
company-sponsored nonqualified employee benefit plans. Certain of these
nonqualified benefit plans have been partially funded through contributions to
a grantor trust.
 
  OTHER POSTRETIREMENT BENEFITS
In addition to pension plans, the Company sponsors defined benefit
postretirement plans covering both salaried and hourly employees and certain
dependents. The plans provide medical benefits as well as life insurance
coverage. These benefits are provided through insurance companies and other
providers with the annual cash outlays based on the claim experience of the
related plans.

Employees who retire on or after attaining age 55 and having rendered at least
15 years of service, or employees retiring on or after attaining age 65, are
eligible to receive benefits under the plans. The plans are both contributory
and noncontributory, depending on age, retirement date, the plan elected by
the employee, and whether the employee is covered under a collective
bargaining agreement. Most of the medical plans contain cost-sharing features
such as deductibles and coinsurance. For certain of the contributory medical
plans, retiree contributions are adjusted annually.
 
                                      25
<PAGE>
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
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 deemed probable.
 
EARNINGS PER SHARE
Earnings per share of common stock is computed based on the weighted average
number of common shares outstanding during the period. Under the methods
prescribed by generally accepted accounting principles, the assumed exercise
of outstanding stock options and conversion of the Company's outstanding
convertible subordinated debentures are not considered to have a dilutive
effect on earnings per share.
 
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. 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, 1995 and 1996 as follows:
-------------------------------------------------------------------------------
<TABLE>
<CAPTION> 
December 31,                                                    1996     1995
-------------------------------------------------------------------------------
                                                               (In Thousands)
<S>                                                           <C>      <C>
Regulatory assets:
 Unrecovered gas costs (Note 1).............................. $108,016 $ 25,123
 Order 636 transition costs (Note 2).........................   27,727   37,021
 Workforce reduction costs (Note 4)..........................   11,139   16,379
 Other postretirement benefits (Note 6)......................   58,966   68,026
 Deferred income taxes (Note 7)..............................  101,825  105,159
 Abandoned facilities (Note 9)...............................   15,791   28,672
 Environmental-related expenditures (Note 16)................   11,047   13,932
 Other.......................................................   21,357   26,571
                                                              -------- --------
  Total regulatory assets.................................... $355,868 $320,883
                                                              ======== ========
Regulatory liabilities:
 Amounts payable to customers (Note 1)....................... $     -- $ 40,315
 Estimated rate contingencies and refunds (Note 2)...........   21,602   59,363
 Income taxes refundable to customers-net (Note 7)...........   57,867   61,678
                                                              -------- --------
  Total regulatory liabilities............................... $ 79,469 $161,356
                                                              ======== ========
-------------------------------------------------------------------------------
</TABLE>
 
                                      26
<PAGE>
 
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 the
Company's regulated operations ceased to meet the requirements of SFAS No. 71,
the Company would be required to assess the carrying value of certain assets
and liabilities previously subject to regulation.
 
ESTIMATED RATE CONTINGENCIES AND REFUNDS
Certain increases in prices by the Company and other rate-making issues are
subject to final modification in regulatory proceedings. The related
accumulated provisions pertaining to these matters were $24,239,000 and
$6,851,000 at December 31, 1995 and 1996, including interest. These amounts
are reported in the Consolidated Balance Sheet under "Estimated rate
contingencies and refunds" together with $35,124,000 and $14,751,000,
respectively, which are primarily refunds received from suppliers and
refundable to customers under regulatory procedures.
 
ORDER 636 TRANSITION COSTS
As approved by the FERC, CNG Transmission has billed its customers, including
certain affiliates, a total of $178.6 million, representing unrecovered
purchased gas costs and unrecovered sales-related transportation costs,
resulting from its transition to restructured services under Order 636. Of the
total amount billed by CNG Transmission to the distribution subsidiaries, the
portion remaining to be recovered from their customers at December 31, 1996 is
not material to the Company's financial position, results of operations or
cash flows.

The distribution subsidiaries have incurred or are expected to incur
additional obligations to upstream pipeline companies for transition costs
under Order 636. The total estimated liability for such costs was $37,021,000
and $27,727,000 at December 31, 1995 and 1996, respectively. Additional
amounts are likely to be accrued in the future once the pipeline companies
receive final FERC approval to recover these costs. Based on management's
current estimates, the distribution subsidiaries' portion of such costs is not
expected to be material.

Based on regulatory actions in two jurisdictions and the past rate-making
treatment of similar costs in the other jurisdictions, management believes
that the distribution subsidiaries should generally be able to pass through
all Order 636 transition costs to their customers.
 
3. PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION
 
IMPAIRMENT OF GAS AND OIL PRODUCING PROPERTIES
As described in Note 1, certain of the subsidiaries follow the full cost
method of accounting for gas and oil producing activities as prescribed by the
SEC. Under these rules, the Company recognized an impairment of its gas and
oil producing properties at March 31, 1995, due primarily to the decline in
gas wellhead prices. The non-cash charge amounted to $226,209,000 and reduced
1995 net income by $145,000,000, or $1.56 per share.
 
DEPRECIATION AND AMORTIZATION
Amortization of capitalized costs under the full cost method of accounting for
the Company's exploration and production operations amounted to $1.15 per Mcf
equivalent of gas and oil produced in 1994, $.98 in 1995, and $.93 in 1996.
The 1995 amount includes the effect of the write-down of the gas and oil
producing properties noted above.
 
                                      27
<PAGE>
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Costs of unproved properties capitalized under the full cost method of
accounting that are excluded from amortization at December 31, 1996, and the
years in which such excluded costs were incurred, follow:
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
                                           Incurred in Years Ended December 31,
                              DECEMBER 31, -------------------------------------
                                  1996        1996      1995      1994    Prior
--------------------------------------------------------------------------------
                                                (In Thousands)
<S>                           <C>          <C>       <C>       <C>      <C>
Property acquisition costs...   $23,867      $13,762   $ 3,938   $3,153   $3,014
Exploration costs............    21,420       11,967     6,090    1,642    1,721
Capitalized interest.........     4,134          946     1,245      992      951
                                -------    --------- --------- -------- --------
  Total......................   $49,421      $26,675   $11,273   $5,787   $5,686
                                =======    ========= ========= ======== ========
--------------------------------------------------------------------------------
</TABLE>

There are no significant properties, as defined by the SEC, excluded from
amortization at December 31, 1996. As gas and oil reserves are proved through
drilling or as properties are judged to be impaired, excluded costs and any
related reserves are transferred on an ongoing, well-by-well basis into the
amortization calculation.
 
WRITE-DOWN AND SUBSEQUENT SALE OF COAL PROPERTIES
In early 1995, the Company initiated an evaluation of the possible disposition
of the coal reserves and related properties owned by CNG Coal Company (CNG
Coal). These reserves had been acquired in the late 1960s and 1970s to meet
expected long-term gas supply needs through coal gasification. However, due to
gas industry deregulation, excess gas supplies nationwide, and both low demand
and prices for coal, the Company concluded that it was not economically
feasible to develop such reserves, nor were these assets aligned with the
Company's longer-term strategy.

A property appraisal was completed during the second quarter of 1995 by an
independent geological firm, which indicated that a write-down was warranted.
Accordingly, at June 30, 1995, the cost of these properties was written down
resulting in a pretax charge amounting to $31,266,000. This charge reduced
1995 net income by $20,323,000, or 22 cents per share, but had no effect on
the Company's cash flow. In July 1996, CNG Coal completed the sale of its coal
properties to a subsidiary of Cyprus Amax Minerals Company. Sale proceeds
consist of an initial cash payment, cash to be received in the form of equal
annual installments, and payments to be received from the future production of
the coal reserves. The proceeds from the sale approximated the book value of
these properties.
 
4. WORKFORCE REDUCTION COSTS
 
Workforce reduction programs approved during 1995 by the Board of Directors
consisted of a voluntary early retirement program and an involuntary separation
program. The early retirement incentives included five additional years of age
and service for determining pension benefits. The early retirement program was
offered at six subsidiaries from April 1 through May 31, 1995, and at a seventh
subsidiary from July 1 through August 31, 1995. Eligible employees at each
subsidiary were required to retire before December 31, 1995. The involuntary
separation program involved severance benefit payments to affected employees.

In January 1996, unions at two subsidiaries approved the adoption of a workforce
reduction program that consisted of a voluntary early retirement program and a
voluntary separation program. The early retirement incentives were similar to
those offered at other subsidiaries during 1995. The early retirement program
was offered from February 1 through March 31, 1996, with eligible employees
retiring effective April 1, 1996. The voluntary separation program involved
severance benefit payments to affected employees. In September 1996, the Board
of Directors approved a separate voluntary early retirement program for West
Ohio Gas. The program included early retirement incentives similar to those

                                     28
<PAGE>
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

offered previously at other subsidiaries and was offered from October 1
through November 29, 1996, with eligible employees retiring effective December
1, 1996.

During 1995 and 1996, a total of 571 and 119 eligible employees, respectively,
elected to accept the early retirement offer and an additional 217 and 57,
respectively, were separated from the Company in conjunction with these
programs. In addition, during the fourth quarter of 1996 the Company recorded
a provision for severance and related benefits to be paid to affected
employees in connection with the Company's efforts to combine and streamline
certain business functions. As a result of these workforce reduction programs,
the Company recorded charges to "Operation expense" in the 1995 and 1996
Consolidated Statements of Income amounting to $42,555,000 and $15,195,000,
respectively. These charges reduced 1995 and 1996 net income by $25,618,000,
or 27 cents per share, and $9,855,000, or 10 cents per share, respectively.
The portion of the 1996 charges recognized in the fourth quarter amounted to
$11,816,000 and reduced net income for the quarter by $7,786,000, or 8 cents
per share. In addition, certain of the regulated subsidiaries have deferred,
as a regulatory asset, a portion of their workforce reduction costs pending
recovery in future rates. The balance of these deferrals was $11,139,000 at
December 31, 1996. The total workforce reduction costs include the impact of
curtailment accounting for the pension and postretirement benefit plans.
Details of the costs are shown in the following table.
-------------------------------------------------------------------------
<TABLE>
<CAPTION>
                                    1996                        1995
                          --------------------------  ---------------------------
                          Amounts   Amounts   Total   Amounts   Amounts    Total
                          Expensed  Deferred  Costs   Expensed  Deferred   Costs
---------------------------------------------------------------------------------
                                            (In Thousands)
<S>                       <C>       <C>      <C>      <C>       <C>       <C>
Pension and nonqualified
benefit plans:
  Special termination
  benefits..............  $ 4,436     $--    $ 4,436  $30,284   $ 6,893   $37,177
  Curtailment gain-net..     (792)     --       (792)  (5,891)     (277)   (6,168)
Postretirement benefit
plans:
  Special termination
  benefits..............       --      --         --    1,086        62     1,148
  Curtailment loss-net..    1,292      --      1,292    6,008     9,656    15,664
Severance and other.....   10,259      91     10,350   11,068        45    11,113
                          -------     ---    -------  -------   -------   -------
  Total.................  $15,195     $91    $15,286  $42,555   $16,379   $58,934
                          =======     ===    =======  =======   =======   =======
---------------------------------------------------------------------------------
</TABLE>
 
5. PENSION COSTS
 
Net pension cost, as determined by an independent actuary, included the
following components:
------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Years Ended December 31,                          1996       1995       1994
------------------------------------------------------------------------------
                                                       (In Thousands)
<S>                                             <C>        <C>        <C>
Service cost--benefits earned during the
period......................................... $  23,741  $  23,741  $ 28,509
Interest cost on projected benefit obligation..    67,426     62,125    59,006
Return on plan assets..........................  (205,481)  (265,460)  (33,363)
Net amortization and deferral..................    86,522    162,002   (60,228)
Curtailment and special termination benefits...     3,644     24,393        --
Special voluntary retirement programs..........       800        800       800
                                                ---------  ---------  --------
  Net pension cost (or credit)................. $ (23,348) $   7,601  $ (5,276)
                                                =========  =========  ========
------------------------------------------------------------------------------
</TABLE>
 
                                      29
<PAGE>
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In 1989, Peoples Natural Gas offered special retirement incentives to certain
salaried and hourly employees. The additional pension payments resulting from
these incentives are being paid from the assets of the applicable pension
plans. The estimated cost of these additional benefits, amounting to
approximately $8,000,000, was deferred and is being amortized to expense over
a 10-year period which began October 1, 1990, in accordance with the rate-
making treatment approved by the Pennsylvania Public Utility Commission.

The following table sets forth the funded status of the plans, as determined
by an independent actuary, at December 31, 1995 and 1996:
-------------------------------------------------------------------------------
<TABLE>
<CAPTION>
                                                              Plans Where
                               Plans Where Assets        Accumulated Benefits
                           Exceed Accumulated Benefits       Exceed Assets
                           ----------------------------  ----------------------
December 31,                      1996           1995         1996        1995
-------------------------------------------------------------------------------
                                            (In Thousands)
<S>                        <C>            <C>            <C>         <C>
Actuarial present value
of:
  Vested benefit
   obligation............  $     708,224  $     711,644  $   22,111  $   25,203
                           =============  =============  ==========  ==========
  Accumulated benefit
   obligation............  $     737,868  $     740,890  $   26,627  $   28,858
                           =============  =============  ==========  ==========
  Projected benefit
   obligation............  $     927,531  $     952,260  $   32,420  $   36,044
Plan assets at fair
 value...................      1,539,039      1,395,778          --          --
                           -------------  -------------  ----------  ----------
  Plan assets in excess
   of (or less than)
   projected benefit
   obligation............        611,508        443,518     (32,420)    (36,044)
Unrecognized net loss (or
 gain)...................       (501,869)      (354,370)     (2,076)      1,358
Unrecognized net
 obligation (or asset)...        (67,980)       (77,300)     19,864      21,396
Unrecognized prior
 service cost............          5,227          5,634       1,617       2,341
Recognition of minimum
 liability...............             --             --     (13,612)    (17,909)
                           -------------  -------------  ----------  ----------
  Prepaid pension cost
  (or pension liability).  $      46,886  $      17,482  $  (26,627) $  (28,858)
                           =============  =============  ==========  ==========
-------------------------------------------------------------------------------
</TABLE>
The projected benefit obligation at December 31, 1995 and 1996, was determined
using an annual discount rate of 7.0% and 7.5%, respectively, and an average
assumed annual rate of salary increase of 5.5%. The expected long-term rate of
return on plan assets was 8.0% per annum at December 31, 1995 and 9.0% at
December 31, 1996.

The Company applied the provisions of SFAS No. 87 to certain nonqualified
employee benefit plans effective July 1, 1995. The minimum liability
recognized relating to both the Company's nonqualified employee benefit and
supplemental pension plans was $17,909,000 and $13,612,000 at December 31,
1995 and 1996. The related intangible asset recognized as of those dates
amounted to $15,605,000 and $11,486,000, respectively. These amounts are
included in the Consolidated Balance Sheet under "Deferred credits and other
liabilities" and "Deferred charges and other assets." Adjustments of the
minimum liability and intangible asset due to changes in assumptions or the
financial status of the plans resulted in a charge to retained earnings of
$262,000 at December 31, 1995, and a credit to retained earnings of $116,000
at December 31, 1996.
 
                                      30
<PAGE>
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
6. OTHER POSTRETIREMENT BENEFITS
 
Net periodic postretirement benefit cost, as determined by an independent
actuary, included the following components:
<TABLE>
-------------------------------------------------------------------------------
<CAPTION>
Years Ended December 31,                              1996     1995     1994
-------------------------------------------------------------------------------
                                                         (In Thousands)
<S>                                                  <C>      <C>      <C>
Service cost--benefits attributed to service during
the period.......................................... $11,940  $11,549  $12,708
Interest cost on accumulated postretirement benefit
obligation..........................................  26,450   28,017   24,380
Return on plan assets...............................    (645)    (145)     (28)
Amortization of transition obligation...............  11,801   14,420   14,420
Curtailment and special termination benefits........   1,292    7,094       --
Net amortization and deferral.......................   2,283      380        4
                                                     -------  -------  -------
  Net periodic postretirement benefit cost.......... $53,121  $61,315  $51,484
                                                     =======  =======  =======
-------------------------------------------------------------------------------
</TABLE>
The following table reconciles the plans' combined funded status, as
determined by an independent actuary, with amounts included in the
Consolidated Balance Sheet at December 31, 1995 and 1996:
<TABLE>
-------------------------------------------------------------------------------
<CAPTION>
December 31,                                                1996       1995
-------------------------------------------------------------------------------
                                                            (In Thousands)
<S>                                                       <C>        <C>
Accumulated postretirement benefit obligation:
  Retirees............................................... $ 280,593  $ 271,209
  Fully eligible active plan participants................    16,882     25,475
  Other active plan participants.........................    80,960     88,235
                                                          ---------  ---------
    Total accumulated postretirement benefit obligation..   378,435    384,919
Plan assets at fair value................................    53,153     12,127
                                                          ---------  ---------
  Accumulated postretirement benefit obligation in excess
  of plan assets.........................................  (325,282)  (372,792)
Unrecognized prior service cost..........................    (6,591)   (20,887)
Unrecognized net loss....................................    54,088     64,166
Unrecognized transition obligation.......................   188,248    230,853
                                                          ---------  ---------
  Accrued postretirement benefit liability............... $ (89,537) $ (98,660)
                                                          =========  =========
-------------------------------------------------------------------------------
</TABLE>
As permitted, the Company elected to amortize the accumulated postretirement
benefit obligation existing at January 1, 1993 (transition obligation) over a
20-year period. The weighted average discount rate used in determining the
accumulated postretirement benefit obligation at December 31, 1995 and 1996,
was 7.0% and 7.5%, respectively. The average assumed annual rate of salary
increase for the applicable life insurance plans was 5.0% for 1995 and 5.5%
for 1996.

The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation for the medical plans is 8.0% for 1997,
declining gradually to 5.0% in 2003 and remaining at that level thereafter.
The health care cost trend rate assumption has a significant effect on the
amounts reported. If the health care cost trend rate were increased by 1% in
each year, the accumulated postretirement benefit obligation as of December
31, 1996, would be increased by $36.4 million. A 1% change would also increase
the aggregate of the service and interest cost components of net periodic
postretirement benefit cost for 1996 by $5.4 million.

The majority of the estimated postretirement benefit costs and the transition
obligation is attributable to the rate-regulated subsidiaries. Pending the
expected recovery of SFAS No. 106 costs and related deferrals in regulatory
proceedings, these subsidiaries have deferred the differences between SFAS
No. 106 costs and amounts included in rates. In general, the rate-regulated
subsidiaries have obtained
 
                                      31
<PAGE>
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, 1995 and 1996, was $68,026,000 and
$58,966,000, respectively, which is included in the Consolidated Balance Sheet
under "Deferred charges and other assets."

The FERC and certain state regulatory authorities have indicated that when
SFAS No. 106 costs are recovered in rates, amounts collected must be deposited
in irrevocable trust funds dedicated for the sole purpose of paying
postretirement benefits. Accordingly, four subsidiaries fund postretirement
benefit costs via voluntary employees' beneficiary associations (VEBAs). The
remaining subsidiaries do not prefund postretirement benefit costs, but rather
pay claims as presented. Assets held by the VEBAs consist primarily of short-
term fixed income securities.
 
7. INCOME TAXES
 
"Income taxes" in the Consolidated Statement of Income include the following:
<TABLE>
--------------------------------------------------------------------------------
<CAPTION>
Years Ended December 31,                             1996      1995      1994
--------------------------------------------------------------------------------
                                                         (In Thousands)
<S>                                                <C>       <C>       <C>
Current provision
  Federal......................................... $ 80,962  $ 44,705  $126,362
  State...........................................   13,839     9,203    19,376
Deferred income taxes-net
  Federal.........................................   60,758   (47,146)  (50,443)
  State...........................................    2,472    (1,621)  (10,301)
Investment tax credit.............................   (2,201)   (2,198)   (2,567)
                                                   --------  --------  --------
  Total........................................... $155,830  $  2,943  $ 82,427
                                                   ========  ========  ========
--------------------------------------------------------------------------------
</TABLE>
Income taxes differed from the amounts shown in the next table that were
computed by applying the statutory federal income tax rate of 35% to reported
income before taxes. The reasons for the differences follow:
<TABLE>
-------------------------------------------------------------------------------
<CAPTION>
Years Ended December 31,                             1996     1995      1994
-------------------------------------------------------------------------------
                                                        (In Thousands)
<S>                                                <C>       <C>      <C>
Income before taxes............................... $454,103  $24,287  $265,598
                                                   ========  =======  ========
Computed "expected" tax expense................... $158,936  $ 8,500  $ 92,959
Increases (or reductions) in tax resulting from:
  Production tax credit...........................   (9,344)  (8,472)   (7,987)
  Investment tax credit...........................   (2,201)  (2,198)   (2,567)
  State income taxes..............................   10,602    4,928     5,899
  Miscellaneous...................................   (2,163)     185    (5,877)
                                                   --------  -------  --------
    Total income taxes............................ $155,830  $ 2,943  $ 82,427
                                                   ========  =======  ========
  Effective tax rate..............................    34.3%    12.1%     31.0%
-------------------------------------------------------------------------------
</TABLE>
The current and noncurrent deferred income taxes reported in the Consolidated
Balance Sheet at December 31, 1996, 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:
 
                                      32
<PAGE>
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
<TABLE>
-------------------------------------------------------------------------------
<CAPTION>
                                                               1996
                                                   ----------------------------
                                                     Deferred   Deferred income
December 31,                                       income taxes taxes--current
-------------------------------------------------------------------------------
                                                          (In Thousands)
<S>                                                <C>          <C>
Deferred tax liabilities:
  Excess of tax over book depreciation............   $516,241       $    --
  Exploration and intangible well drilling costs..    215,415            --
  Unrecovered gas costs...........................         --        38,863
  Other...........................................     76,906            --
                                                     --------       -------
    Total liabilities.............................    808,562        38,863
                                                     --------       -------
Deferred tax assets:
  Tax basis step-up in connection with acquisition
  of subsidiary...................................     19,170            --
  Deferred investment tax credits.................     17,114            --
  Overheads capitalized for tax purposes..........     13,747            --
  Supplier and other refunds......................         --           277
  Other...........................................     77,197         2,490
  Valuation allowance.............................         --            --
                                                     --------       -------
    Total assets..................................    127,228         2,767
                                                     --------       -------
    Total deferred income taxes...................   $681,334       $36,096
                                                     ========       =======
-------------------------------------------------------------------------------
</TABLE>
A regulatory liability amounting to $57,867,000 has been recorded 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
$101,825,000 has been recorded at December 31, 1996. These amounts are
included in the Consolidated Balance Sheet under "Deferred credits and other
liabilities" and "Deferred charges and other assets," respectively.
 
8. 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 1996, the current cost of replacing the inventory of "Gas
stored--current portion" exceeded the amount stated on a LIFO basis by
approximately $196,474,000 at December 31, 1996. Virginia Natural Gas and CNG
Energy Services value their stored gas inventory under the weighted average
cost method.

A portion of gas in underground storage used as a pressure base and for
operational balancing is included in "Property, Plant and Equipment" in the
amounts of $126,393,000 and $126,366,000 at December 31, 1995 and 1996,
respectively.
 
9. UNAMORTIZED ABANDONED FACILITIES
 
In 1988, Consolidated LNG received FERC approval for the abandonment of its
interest in liquefied natural gas facilities at Cove Point, Maryland. In
connection with the abandonment, Consolidated LNG recorded a deferred asset in
accordance with the provisions of SFAS No. 90, "Accounting for Abandonments
and Disallowances of Plant Costs." This deferred asset, which represents the
present value of allowable costs expected to be recovered, is being amortized
over the 10-year recovery period which began March 1, 1988, as prescribed in
the FERC order.
 
                                      33
<PAGE>
 
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,
 1993...................   92,934   $255,568 $413,801  $40,280 $454,081  $1,466,783   $      --       --    $    --
Net income..............       --         --       --       --       --     183,171          --       --         --
Cash dividends declared
 Common stock ($1.94 per
 share).................       --         --       --       --       --    (180,461)         --       --         --
Common stock issued
 Conversion of
  debentures............       70        193    3,669       --    3,669          --          --       --         --
 Stock awards-net.......       16         45      621       --      621          --          --       --         --
 Stock options..........        8         21      258       --      258          --          --       --         --
Purchase of treasury
 stock..................       --         --       --       --       --          --          --       (6)      (257)
Sale of treasury stock..       --         --       (1)      --       (1)         --          --        6        257
Pension liability
 adjustment.............       --         --       --       --       --         386          --       --         --
                           ------   -------- --------  ------- --------  ----------   ---------     ----    -------
Balance at December 31,
 1994...................   93,028    255,827  418,348   40,280  458,628   1,469,879          --       --         --
Net income..............       --         --       --       --       --      21,344          --       --         --
Cash dividends declared
 Common stock ($1.94 per
  share)................       --         --       --       --       --    (181,055)         --       --         --
Common stock issued
 Stock options..........      217        596    7,453       --    7,453          --          --       --         --
 System Thrift Plans....      213        586    7,586       --    7,586          --          --       --         --
 DRP*...................      104        287    3,837       --    3,837          --          --       --         --
 Stock awards-net.......       30         81    1,040       --    1,040          --          --       --         --
Purchase of treasury
 stock..................       --         --       --       --       --          --          --      (17)      (634)
Sale of treasury stock..       --         --       (9)      --       (9)         --          --       17        634
Pension liability
 adjustment
 (Note 5)...............       --         --       --       --       --        (262)         --       --         --
                           ------   -------- --------  ------- --------  ----------   ---------     ----    -------
Balance at December 31,
 1995...................   93,592    257,377  438,255   40,280  478,535   1,309,906          --       --         --
Net income..............       --         --       --       --       --     298,273          --       --         --
Cash dividends declared
 Common stock ($1.94 per
  share)................       --         --       --       --       --    (183,671)         --       --         --
Common stock issued
 Stock options..........      769      2,113   29,662       --   29,662          --          --       --         --
 Performance shares-net.      378      1,040   16,336       --   16,336          --     (17,376)      --         --
 Stock awards-net.......       98        270    4,404       --    4,404          --      (4,560)      --         --
 DRP*...................       97        268    4,688       --    4,688          --          --       --         --
 Amortization and
  adjustment............       --         --    3,520       --    3,520          --       4,394       --         --
Purchase of treasury
 stock..................       --         --       --       --       --          --          --     (147)    (8,144)
Sale of treasury stock
 and other..............       --         --     (143)      --     (143)         --          --      147      8,144
Pension liability
 adjustment
 (Note 5)...............       --         --       --       --       --         116          --       --         --
                           ------   -------- --------  ------- --------  ----------   ---------     ----    -------
Balance at December 31,
 1996...................   94,934   $261,068 $496,722  $40,280 $537,002  $1,424,624   $(17,542)       --    $    --
                           ======   ======== ========  ======= ========  ==========   =========     ====    =======
-------------------------------------------------------------------------------------------------------------------
</TABLE>
*Dividend Reinvestment Plan.
 
                                       34
<PAGE>
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
SHAREHOLDER RIGHTS PLAN
During 1995, the Board of Directors adopted a shareholder rights plan and on
January 23, 1996, declared a dividend of one right (Right) for each share of
common stock outstanding at the close of business on February 28, 1996. Each
Right would entitle the holder to purchase from the Company one-half of one
share of common stock at a price of $175 per share ($87.50 per half-share),
subject to adjustment (Purchase Price), if certain conditions are met in
connection with a possible acquisition of the common stock of the Company by a
third party. If the Rights become exercisable, each holder may exercise a
Right and receive common stock (or, in certain cases, cash, property or other
securities) of the Company or common stock of the acquiring company having a
value equal to twice the Right's then current Purchase Price.

Also, under certain conditions, the Board of Directors may exchange the
Rights, in whole or in part, at an exchange ratio of one share of common stock
(and/or other securities, cash or other assets having the same value as a
share of common stock) per Right, subject to adjustment, or may redeem the
Rights in whole at a price of $0.01 per Right. Until a Right is exercised or
exchanged for common stock, the holder, as such, is not a stockholder of the
Company. Unless earlier exercised or redeemed, the Rights will expire on
February 28, 2006.
 
UNISSUED SHARES
At December 31, 1996, 305,066,369 shares of common stock were unissued. Of
these, a total of 14,738,762 shares have been registered with the SEC for
possible issuance under various benefit plans. Shares acquired by these plans
can consist of original issue shares, treasury shares or shares purchased in
the open market. In addition, 2,001,512 shares have been registered with the
SEC for possible issuance to shareholders under the Dividend Reinvestment Plan
and 4,559,353 shares are registered for issuance upon conversion of the
Company's convertible subordinated debentures.
 
TREASURY STOCK
Under a stock repurchase plan approved by the Board of Directors, the Company
can purchase in the open market up to 4,000,000 shares of its common stock.
The Company may also acquire shares of its common stock through certain
provisions of the Company's various stock incentive plans. Shares repurchased
or acquired are held as treasury stock and are available for reissuance for
general corporate purposes or in connection with various employee benefit
plans. When treasury shares are reissued, the difference between the market
value at reissuance and the cost of shares is reflected in "Capital in excess
of par value." The cost of any shares held as treasury stock is shown as a
reduction in common stockholders' equity in the Consolidated Balance Sheet. No
treasury shares were held at December 31, 1995 or 1996.
 
1991 STOCK INCENTIVE PLAN
The 1991 Stock Incentive Plan (1991 Plan) provides for the granting of stock
awards, stock options and other stock-based awards to employees of the
Company. The maximum number of shares available for issuance in each calendar
year is determined in accordance with a formula contained in the plan. During
1996, 4,036,272 shares were available for issuance under the plan.

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

Stock options granted under the plan allow the purchase of common shares at a
price not less than fair market value at the date of grant and not less than
par value. The options generally are exercisable in
 
                                      35
<PAGE>
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

four equal annual installments commencing with the second anniversary of the
grant and expire after 10 years from the date of grant.

Stock appreciation rights may also be granted, either alone or in tandem with
stock options. These rights permit the recipient to receive, upon exercise,
the excess of the fair market value of a share on the date of exercise over
the grant price. The grant price is generally the fair market value of the
stock on the date of grant. As of December 31, 1996, no stock appreciation
rights have been granted under the plan.

The 1991 Plan also provides for the granting of performance awards, dividend
equivalents, or other awards which may be based on, or related to, shares of
the Company's common stock. The granting of stock awards constitutes a non-
cash financing activity of the Company.
 
1995 EMPLOYEE STOCK INCENTIVE PLAN
The 1995 Employee Stock Incentive Plan (1995 Plan) was established in
conjunction with the Long-Term Strategic Incentive Program described below.
This plan provides for the granting of stock-based awards to certain key
employees similar to those granted under the 1991 Plan. During 1996, 4,000,000
shares were available for issuance under the plan.
 
  LONG-TERM STRATEGIC INCENTIVE PROGRAM
In December 1995, the Board of Directors approved the Long-Term Strategic
Incentive Program. Grants under this program, consisting of performance
restricted stock awards (performance shares) and stock options, are expected
to be made every three years. Performance shares will vest contingent upon
attainment of certain strategic business results over a three-year period.
Stock options granted under this program vest after three years and will be
exercisable for one day. The exercise period can be extended from the vesting
date up to 10 years from the grant date for all or a portion of the options if
certain strategic business results are attained over the vesting period.
Awards under this program utilize shares available under both the 1991 Plan
and the 1995 Plan.
 
1997 STOCK INCENTIVE PLAN
The 1997 Stock Incentive Plan (1997 Plan) will be submitted for approval by
the Company's shareholders at the May 1997 Annual Meeting. The provisions of
the 1997 Plan will be similar to those of the 1991 Plan. During 1997, the
total number of shares expected to be available for grant under the 1997 Plan
will be 5,248,469 shares.
 
LONG-TERM INCENTIVE PLAN
The Long-Term Incentive Plan, which provided for the issuance of common shares
to key employees as either restricted stock awards or stock options,
terminated by its terms on November 9, 1991. However, the provisions of the
plan continue with respect to any restricted stock awards and stock options
granted prior to the termination date. The terms and conditions of the options
granted under this plan are similar to those under the 1991 Plan.
 
ACCOUNTING FOR STOCK AWARDS AND STOCK OPTIONS
In October 1995, the FASB issued SFAS No. 123, "Accounting for Stock-Based
Compensation." As permitted by the standard, the Company has elected to
continue to follow existing accounting guidance, Accounting Principles Board
Opinion No. 25 and related interpretations (APB No. 25), for stock-based
compensation. However, SFAS No. 123 requires companies electing to follow
existing accounting rules to disclose in a note the pro forma effects as if
the fair value based method of accounting had been applied. The Company
recorded compensation expense of $2,154,000, $751,000 and $8,650,000 for the
years ended December 31, 1994, 1995 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.
 
                                      36
<PAGE>
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

A summary of the Company's stock option activity under the plans described
above for the years ended December 31, 1994 through 1996, follows:
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
                                                                Weighted Average
                                                     Number       Option Price
                                                   of Shares       Per Share
--------------------------------------------------------------------------------
                                                 (In Thousands)
<S>                                              <C>            <C>
Shares under option:
  At January 1, 1994............................     1,962           $41.90
  Granted.......................................       651           $43.98
  Exercised.....................................        (8)          $36.51
  Cancelled.....................................       (48)          $42.89
                                                     -----
  At December 31, 1994..........................     2,557           $42.43

  Granted.......................................     1,078           $37.32
  Exercised.....................................      (217)          $35.88
  Cancelled.....................................      (470)          $41.14
                                                     -----
  At December 31, 1995..........................     2,948           $41.25

  Granted*......................................     3,534           $45.53
  Exercised.....................................      (769)          $41.37
  Cancelled*....................................      (196)          $43.13
                                                     -----
  At December 31, 1996..........................     5,517           $43.90
                                                     =====
</TABLE>
*Includes 3,006,000 options granted and 65,000 options cancelled in connection
with the Long-Term Strategic Incentive Program.
 
Options were exercisable for the purchase of 691,421 shares, 1,048,064 shares,
and 673,305 shares at December 31, 1994, 1995 and 1996, respectively.
Effective January 2, 1997, additional options for the purchase of 515,000
shares were granted to eligible employees.
--------------------------------------------------------------------------------
 
The following table summarizes information about stock options outstanding at
December 31, 1996.
--------------------------------------------------------------------------------
<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>
$32.50 --$40                  1,080         7.39 YRS.         $36.86          177           $36.27
$40.125--$50                  4,040         8.43 YRS.         $44.83          370           $44.72
$50.125--$56.875                397         7.43 YRS.         $52.70          126           $50.66
------------------------------------------------------------------------------------------------------
</TABLE>
 
The weighted average fair value of stock options granted during each of the
years 1995 and 1996 was $5.50 and $5.84, respectively. The fair value of each
option grant is estimated on the date of grant using the Black-Scholes option-
pricing model with the following weighted average assumptions for grants in
1995 and 1996, respectively: dividend yield of 5.0 percent and 4.3 percent,
expected volatility of 19.2 percent and 17.5 percent, risk-free interest rates
of 6.9 percent and 5.4 percent, and expected lives of 4.9 years for both
years. If compensation expense for the Company's stock options granted in 1995
and 1996 had been determined based on the fair value at the grant dates for
such awards in accordance with SFAS No. 123, the effect on the Company's net
income and earnings per share for each of the years ended December 31, 1995
and 1996 would have been immaterial.
 
                                      37
<PAGE>
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The Company granted stock awards totaling 17,000 shares in 1994, 34,000 shares
in 1995, and 103,000 shares in 1996 with weighted average market prices per
share on award dates of $41.35, $39.15, and $47.43, respectively. In addition,
404,000 performance shares were issued during 1996 at a weighted average
market price of $45.87 per share.
 
11. PREFERRED STOCK
 
During 1996, amendments to the Company's Certificate of Incorporation were
approved to eliminate the existing authorized shares of cumulative preferred
stock and to authorize a new class of preferred stock. Accordingly, the
existing 2,500,000 authorized shares of preferred stock of $100 par value were
eliminated and replaced with 5,000,000 authorized shares of a new class of
preferred stock of $100 par value. There were no shares of preferred stock
issued or outstanding at December 31, 1995 or 1996.
 
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, $613,562,000 of consolidated
retained earnings was free from such restrictions at December 31, 1996. The
indenture also imposes dividend limitations on the subsidiaries, but at
December 31, 1996, these limitations did not restrict their ability to pay
dividends to the Company.
 
13. LONG-TERM DEBT
 
Long-term debt, excluding current maturities, follows:
-------------------------------------------------------------------------------
<TABLE>
<CAPTION>
December 31,                                                1996        1995
-------------------------------------------------------------------------------
                                                            (In Thousands)
<S>                                                      <C>         <C>
Debentures
  6 5/8%, Due December 1, 2008.......................... $  150,000  $       --
  6 7/8%, Due October 15, 2026..........................    150,000          --
  7 3/8%, Due April 1, 2005.............................    150,000     150,000
  6 5/8%, Due December 1, 2013..........................    150,000     150,000
  5 3/4%, Due August 1, 2003............................    150,000     150,000
  5 7/8%, Due October 1, 1998...........................    150,000     150,000
  8 3/4%, Due October 1, 2019...........................    150,000     150,000
  8 3/4%, Due June 1, 1999..............................    100,000     100,000
  9 3/8%, Due February 1, 1997..........................         --     100,000
  8 5/8%, Due December 1, 2011..........................     31,250      93,750
  Unamortized debt discount, less premium...............     (7,429)     (8,304)
Convertible Subordinated Debentures
  7 1/4%, Due December 15, 2015.........................    246,205     246,205
  Unamortized debt discount.............................     (1,711)     (1,840)
9.94% Unsecured loan due January 1, 1999................      8,000      12,000
                                                         ----------  ----------
  Total................................................. $1,426,315  $1,291,811
                                                         ==========  ==========
-------------------------------------------------------------------------------
</TABLE>
The aggregate principal amounts of the Company's debentures maturing in the
years 1997 through 2001 are: $100,000,000; $150,000,000; $107,125,000;
$15,830,000 and $19,625,000.
 
                                      38
<PAGE>
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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.

During the 1996 fourth quarter, the Company called for redemption $53,125,000
principal amount of the 8 5/8% Debentures Due December 1, 2011. In connection
with the call, the Company placed funds into an irrevocable trust in December
1996 for the sole purpose of paying the principal amount and related call
premium and accrued interest. As such, the debt has been removed from the
Consolidated Balance Sheet at December 31, 1996. Payment was made from the
trust on February 1, 1997. This transaction resulted in a 1996 charge of
$5,012,000.

The Company's 7 1/4% Convertible Subordinated Debentures, which mature on
December 15, 2015, are convertible into shares of the Company's common stock
at any time prior to maturity at an initial conversion price of $54 per share.
Under additional terms of the issue, on December 15, 2000, the Company is
obligated to purchase, at the option of the holder, any debenture then
outstanding for 100% of the principal amount plus accrued interest.

The 9.94% unsecured loan due January 1, 1999, is an obligation of Virginia
Natural Gas. This $20,000,000 loan, which is being repaid in five annual
installments of $4,000,000 each beginning January 1, 1995, has been guaranteed
by the Company.
 
14. SHORT-TERM BORROWINGS
 
The weighted average interest rate on the Company's commercial paper notes
outstanding at December 31, 1995 and 1996, was 5.79% and 5.70%, respectively.

The Company has a $475,000,000 credit agreement and a $300,000,000 credit
agreement with a group of banks. Borrowings under these agreements 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. These agreements
may be used for general corporate purposes, including the support of
commercial paper notes. The agreements are currently scheduled to expire on
June 27, 1997; however, the Company expects that the agreements will be
renewed or replaced by comparable agreements. A facility fee is charged under
the agreements but is not considered significant. There were no borrowings
under these agreements at December 31, 1996.
 
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, 1995 and 1996:
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
                                             1996                  1995
                                     --------------------- ---------------------
                                      Carrying              Carrying
December 31,                           Amount   Fair Value   Amount   Fair Value
--------------------------------------------------------------------------------
                                                   (In Thousands)
<S>                                  <C>        <C>        <C>        <C>
Long-term debt...................... $1,539,455 $1,563,440 $1,312,205 $1,368,002
--------------------------------------------------------------------------------
</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.
 
                                      39
<PAGE>
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
DERIVATIVE FINANCIAL INSTRUMENTS AND ENERGY PRICE RISK MANAGEMENT ACTIVITIES
 
  FUTURES AND OPTIONS CONTRACTS
The Company's energy price risk management activities include exchange-traded
futures and options contracts which can be settled through the purchase or
delivery of commodities. CNG Producing uses futures and options to manage
commodity price risk in connection with the production and sale of crude oil,
while CNG Energy Services uses such instruments to manage similar risk
regarding gas and electricity purchase and sale commitments and stored gas
inventories.

At December 31, 1996, CNG Producing's price risk management activities
included crude oil futures contracts under hedging activities maturing through
December 1997 covering 444,000 barrels of oil. Also at December 31, 1996, CNG
Energy Services had natural gas futures contracts related to gas purchase and
sale commitments and gas storage inventory covering 2.5 Bcf of gas on a net
basis maturing through December 1998.

For contracts used by the Company that qualify and have been designated as
hedges, any gains or losses resulting from market price changes are expected
to be generally offset by the related physical transaction. The Company's net
unrealized gain related to futures contracts was approximately $2,300,000 at
December 31, 1996. The net unrealized loss at December 31, 1996, related to
options contracts was not material to the Company's financial position,
results of operations or cash flows.
 
  SWAP AGREEMENTS
In addition to exchange-traded futures and options contracts, the nonregulated
subsidiaries enter into OTC price swap agreements to manage their exposure to
commodity price risk under existing sales commitments. At December 31, 1996,
CNG Energy Services had swap agreements of varying duration outstanding with
several counterparties to exchange monthly payments on net notional quantities
of 33.5 Bcf of gas over the ensuing 2 years. In addition, CNG Producing
Company had one swap outstanding at December 31, 1996, to exchange payments on
net notional quantities of approximately 1 million barrels of oil through
December 1997. 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 these
swap agreements was approximately $1,100,000 at December 31, 1996. Profits
expected on anticipated sales related to the hedged transactions should
generally offset the estimated unrealized losses on the swap agreements.

CNG Energy Services also has a 10-year foreign currency swap agreement to
manage foreign exchange rate risk in connection with the payment of demand
charges for pipeline capacity in Canada. The aggregate notional amount
underlying this swap agreement was approximately $64,500,000 at December 31,
1996. The unrealized gain related to the foreign currency swap agreement was
approximately $7,300,000 at December 31, 1996.
 
  MARKET AND CREDIT RISK
The use of derivatives exposes the Company to market risk and credit risk.
Market risk represents the potential loss that can be caused by a change in
the market value of a particular commitment. Although the use of derivatives
generally reduces market risk exposure due to unfavorable price fluctuations,
such risk management activities, while not significant, can also result in the
assumption of a limited degree of price risk in certain isolated transactions.
Credit risk relates to the risk of loss that the Company would incur as a
result of nonperformance by counterparties pursuant to the terms of their
contractual obligations. The Company does not have a significant exposure to
any individual counterparty to its energy price risk management activities.
Management has operating procedures in place to evaluate market and credit
risks and believes that the Company's exposure to risks associated with
derivatives is not material in relation to the Company's financial position,
results of operations or cash flows.
 
                                      40
<PAGE>
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
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 surveys
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 have been assessed as of this date.
Pursuant to the Order and Agreement, CNG Transmission is performing sampling,
testing and analysis, and conducting a program of remediation at some of its
Pennsylvania facilities. Total remediation costs in connection with these
sites and the Order and Agreement are not expected to be material with respect
to the Company's financial position, results of operations or cash flows.
Based on current information, the Company has recognized a gross estimated
liability amounting to $15,220,000 at December 31, 1996, for future costs
expected to be incurred to remediate or mitigate hazardous substances at these
sites and at facilities covered by the Order and Agreement.

Inasmuch as certain environmental-related expenditures are expected to be
recoverable in future regulatory proceedings, a regulatory asset amounting to
$11,047,000 at December 31, 1996, is included in the Consolidated Balance
Sheet under the caption "Deferred charges and other assets." Also, uncontested
claims amounting to $2,375,000 at December 31, 1996, 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,                                    1996    1995   1994
--------------------------------------------------------------------------------
                                                              (In Thousands)
<S>                                                        <C>     <C>    <C>
Recurring costs for ongoing operations.................... $4,174  $3,094 $3,479
Mandated remediation and other compliance costs...........   (419)  2,307    214
Voluntary remediation costs...............................  2,705   1,630    507
Other.....................................................      3      79     28
                                                           ------  ------ ------
  Total................................................... $6,463  $7,110 $4,228
                                                           ======  ====== ======
--------------------------------------------------------------------------------
</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 by May 31, 1995, to reduce nitrogen oxide
emissions. Compliance required capital expenditures to similarly retrofit some
of the compressor engines along the Company's pipeline system. The Company has
completed the installation of emission control equipment and the installation
and testing of compressor engines and related equipment required by the 1990
amendments. The 1990 amendments may also require installation of Maximum
Available Control Technology (MACT) at certain of the Company's compressor
stations to control the emissions of certain hazardous air pollutants. The
Company
 
                                      41
<PAGE>
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

is participating with industry groups and the Environmental Protection Agency
in the development of these regulations but is unable to estimate the cost of
installing MACT, if required.

The Company expended $23.3 million in 1994, $11.3 million in 1995, and $6.8
million in 1996 to comply with the 1990 amendments. The total capital
expenditures required to comply with the 1990 amendments are expected to be
recoverable through future regulatory proceedings.

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

The Company discovered in the course of conducting a routine environmental
survey at East Ohio Gas that some of its practices for collecting and handling
pipeline fluids that may have been contaminated with polychlorinated biphenyls
(PCBs) may not have complied with environmental regulations. The appropriate
agencies have been notified as part of the federal self-disclosure process and
discussions are continuing with the agencies to gain approval of revised
collection and handling procedures. A thorough investigation of all collection
and handling practices at East Ohio Gas is continuing and the Company
anticipates providing the results of this investigation to the appropriate
agencies in 1997. The discrepancies in the procedures were primarily in
connection with recordkeeping and did not involve spills, leaks, or other
mishandling of PCB contaminated fluids and did not damage the environment. The
Company anticipates that penalties, if any, incurred in connection with this
matter may be mitigated as a result of the Company's self disclosure. The
amount of any liabilities in connection with this matter is not expected to be
material with respect to the Company's financial position, results of
operations or cash flows.

Estimates of liability in the environmental area are based on current
environmental laws and regulations and existing technology. The exact nature
of environmental issues which the Company may encounter in the future cannot
be predicted. Additional environmental liabilities may result in the future as
more stringent environmental laws and regulations are implemented and as the
Company obtains more specific information about its existing sites and
production facilities. At present, no estimate of any such additional
liability, or range of liability amounts, can be made. However, the amount of
any such liabilities could be material.
 
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 1994 through 1996 was not material, and future rental
payments required under leases in effect at December 31, 1996, are not
material.

It is estimated that the Company's 1997 capital spending program will amount
to $525,900,000, and that approximately $231,000,000 of that amount will be
directed to gas and oil producing activities. In connection with the capital
spending program, the Company has entered into certain contractual
commitments. Contractual commitments in the ordinary course of business
include requirements by CNG Energy Services to purchase capacity on
nonaffiliated pipelines to meet both committed and anticipated future long-
term customer gas supply needs.

The Company has claims and suits 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.
 
 
                                      42
<PAGE>
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

18. DISAGGREGATED INFORMATION
 
In addition to operating in all phases of the natural gas business, the
Company explores for and produces oil and provides a variety of energy
marketing services.

Distribution represents the retail gas distribution subsidiaries. These
subsidiaries sell gas and/or provide transportation services to residential,
commercial and industrial customers in Ohio, Pennsylvania, Virginia and West
Virginia, and are subject to price regulation by their respective state
utility commissions.

Transmission operations include the activities of CNG Transmission, an
interstate pipeline company regulated by the FERC which provides gas
transportation, storage and related services to affiliates and to utilities
and end users in the Midwest, the Mid-Atlantic states and the Northeast.
Transmission operations also include, prior to April 1, 1995, the activities
of CNG Storage. CNG Storage is engaged in providing natural gas storage
facilities and a wide range of storage-related services to affiliates and
other customers, including the sale or lease of base gas, and the sale, lease
or brokerage of gas storage capacity obtained from third parties.

Exploration and production includes the results of CNG Producing and the gas
and oil production activities of CNG Transmission. These operations are
located throughout the United States and in the Gulf of Mexico. CNG Producing
also owns a working interest in a heavy oil program in Alberta, Canada.

Energy marketing services is comprised of CNG Energy Services and subsidiaries
(including CNG Storage), and CNG Power Services. CNG Energy Services markets
Company-owned gas production and arranges gas supplies, transportation,
storage and related services throughout North America. CNG Energy Services
also holds the Company's ownership interests in seven independent power
plants. CNG Power Services is the power marketing subsidiary that purchases
and resells electricity at market-based rates. The results of these
subsidiaries were included in the "Other" component in 1994.

The activities of CNG International, CNG Products and Services Company (CNG
Products and Services), Consolidated LNG, CNG Research Company and CNG Coal
are included in the "Other" category. CNG International was formed in 1996 to
engage in energy-related activities outside of the United States. CNG Products
and Services began operations in 1996 and provides certain energy-related
services to customers of the Company's distribution subsidiaries and others.

Transactions between affiliates are recognized at prices which approximate
market value. Significant transactions between the operating components are
eliminated to reconcile the disaggregated information to consolidated amounts.
Identifiable assets of each component are those assets that are used in its
operations.
 
                                      43
<PAGE>
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table presents disaggregated information pertaining to the
Company's operations:
 
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
                                                   Exploration    Energy               Corporate
                                                       and      Marketing                 and
                         Distribution Transmission Production    Services    Other    Eliminations   Total
-------------------------------------------------------------------------------------------------------------
                                                          (In Thousands)
<S>                      <C>          <C>          <C>          <C>         <C>       <C>          <C>
1996
Operating revenues
 Nonaffiliated..........  $1,902,551   $  383,108  $  292,964   $1,206,848  $  8,838   $      --   $3,794,309
 Affiliated.............       2,961      120,292     339,323      149,635     9,834    (622,045)          --
                          ----------   ----------  ----------   ----------  --------   ---------   ----------
  Total.................   1,905,512      503,400     632,287    1,356,483    18,672    (622,045)   3,794,309
Other operating
 expenses...............   1,572,959      264,542     333,336    1,363,871    21,780    (614,324)   2,942,164
Depreciation and
 amortization...........      74,132       60,107     165,715        1,681        48       2,488      304,171
                          ----------   ----------  ----------   ----------  --------   ---------   ----------
Operating income before
 income taxes...........  $  258,421   $  178,751  $  133,236   $   (9,069) $ (3,156)  $ (10,209)  $  547,974
                          ==========   ==========  ==========   ==========  ========   =========   ==========
Capital expenditures....  $  143,050   $   85,904  $  247,103   $   35,531  $ 42,570   $   6,135   $  560,293
Identifiable assets.....  $2,902,917   $1,481,612  $1,232,992   $  473,766  $ 94,608   $(185,290)  $6,000,605
-------------------------------------------------------------------------------------------------------------
1995
Operating revenues
 Nonaffiliated..........  $1,738,947   $  365,888  $  174,442   $1,020,789  $  7,259   $      --   $3,307,325
 Affiliated.............       6,280      105,138     187,012       87,611    10,168    (396,209)          --
                          ----------   ----------  ----------   ----------  --------   ---------   ----------
  Total.................   1,745,227      471,026     361,454    1,108,400    17,427    (396,209)   3,307,325
Other operating
 expenses...............   1,466,776      261,091     438,477    1,113,014    14,543    (392,668)   2,901,233
Depreciation and
 amortization...........      70,972       59,552     123,492        1,072        --       1,548      256,636
                          ----------   ----------  ----------   ----------  --------   ---------   ----------
Operating income before
 income taxes...........  $  207,479   $  150,383  $ (200,515)  $   (5,686) $  2,884   $  (5,089)  $  149,456
                          ==========   ==========  ==========   ==========  ========   =========   ==========
Capital expenditures....  $  160,480   $   81,557  $  176,789   $   19,567  $     --   $   1,000   $  439,393
Identifiable assets.....  $2,645,004   $1,483,631  $1,155,092   $  317,490  $ 54,425   $(237,349)  $5,418,293
-------------------------------------------------------------------------------------------------------------
1994
Operating revenues
 Nonaffiliated..........  $1,804,317   $  348,141  $  411,876   $       --  $471,694   $      --   $3,036,028
 Affiliated.............       1,296      111,147      77,564           --    44,966    (234,973)          --
                          ----------   ----------  ----------   ----------  --------   ---------   ----------
  Total.................   1,805,613      459,288     489,440           --   516,660    (234,973)   3,036,028
Other operating
 expenses...............   1,579,259      259,078     299,872           --   508,303    (233,206)   2,413,306
Depreciation and
 amortization...........      67,401       53,944     155,558           --       736       1,678      279,317
                          ----------   ----------  ----------   ----------  --------   ---------   ----------
Operating income before
 income taxes...........  $  158,953   $  146,266  $   34,010   $       --  $  7,621   $  (3,445)  $  343,405
                          ==========   ==========  ==========   ==========  ========   =========   ==========
Capital expenditures....  $  146,882   $  108,647  $  166,022   $       --  $ 15,198   $   1,036   $  437,785
Identifiable assets.....  $2,595,615   $1,543,790  $1,372,747   $       --  $283,799   $(277,278)  $5,518,673
-------------------------------------------------------------------------------------------------------------
</TABLE>
 
19. SUPPLEMENTARY FINANCIAL INFORMATION--UNAUDITED
 
(A)GAS AND OIL PRODUCING ACTIVITIES (EXCLUDING COST-OF-SERVICE RATE-REGULATED
ACTIVITIES)
This information has been prepared in accordance with SFAS No. 69,
"Disclosures about Oil and Gas Producing Activities," and related SEC
pronouncements. Statement No. 69 is a comprehensive, standard set of required
disclosures about the gas and oil producing activities of publicly traded
companies. The following disclosures exclude the gas and oil producing
activities subject to cost-of-service rate regulation. Certain disclosures
about these gas and oil activities, which are exempt from the accounting
methods prescribed by the SEC, are included under "Cost-of-Service Properties"
in this Note (A).
 
                                      44
<PAGE>
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
  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,                                                  1996       1995
--------------------------------------------------------------------------------
                                                              (In Thousands)
<S>                                                        <C>        <C>
Capitalized costs of
  Proved properties....................................... $3,057,682 $2,871,560
  Unproved properties.....................................    317,462    270,315
                                                           ---------- ----------
    Subtotal..............................................  3,375,144  3,141,875
                                                           ---------- ----------
Accumulated depreciation of
  Proved properties.......................................  2,224,471  2,090,498
  Unproved properties.....................................    134,481    116,256
                                                           ---------- ----------
    Subtotal..............................................  2,358,952  2,206,754
                                                           ---------- ----------
    Net capitalized costs................................. $1,016,192 $  935,121
                                                           ========== ==========
--------------------------------------------------------------------------------
</TABLE>
As described in Note 3, the Company was required to recognize an impairment of
its gas and oil producing properties during 1995. The non-cash charge amounted
to $226,209,000 and is reflected in the amounts included above.
 
  TOTAL COSTS INCURRED
The following costs were incurred by subsidiaries in their gas and oil
producing activities during the years 1994 through 1996:
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Years Ended December 31,                                1996     1995     1994
--------------------------------------------------------------------------------
                                                            (In Thousands)
<S>                                                   <C>      <C>      <C>
Property acquisition costs
  Proved properties.................................. $ 42,880 $  5,824 $  4,000
  Unproved properties................................   17,911    9,686   18,998
                                                      -------- -------- --------
    Subtotal.........................................   60,791   15,510   22,998
Exploration costs....................................   49,622   50,974   48,514
Development costs....................................  125,139  102,574   82,020
                                                      -------- -------- --------
    Total............................................ $235,552 $169,058 $153,532
                                                      ======== ======== ========
--------------------------------------------------------------------------------
</TABLE>
 
                                      45
<PAGE>
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
 
  RESULTS OF OPERATIONS
The elements of the "results of operations for gas and oil producing
activities" that follow are as required and defined by the FASB. The Company
cautions that these standardized disclosures do not represent the 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,                             1996     1995       1994
-------------------------------------------------------------------------------
                                                         (In Thousands)
<S>                                                <C>      <C>        <C>
Revenues (net of royalties) from:
  Sales to nonaffiliated companies................ $ 84,239 $  60,139  $201,820
  Transfers to other operations...................  289,892   150,930    55,007
                                                   -------- ---------  --------
    Total.........................................  374,131   211,069   256,827
                                                   -------- ---------  --------
Less:Production (lifting) costs...................   55,679    40,812    42,723
   Depreciation and amortization..................  157,358   117,163   150,936
   Impairment of producing properties.............       --   226,209        --
   Income tax expense.............................   49,367   (68,615)   15,446
                                                   -------- ---------  --------
Results of operations............................. $111,727 $(104,500) $ 47,722
                                                   ======== =========  ========
-------------------------------------------------------------------------------
</TABLE>
 
  COMPANY-OWNED RESERVES (NON-COST-OF-SERVICE RESERVES)
Estimated net quantities of proved gas and oil (including condensate) reserves
in the United States and Canada at December 31, 1994 through 1996, and changes
in the reserves during those years, are shown in the two schedules which
follow:
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Years Ended December 31,                                      1996   1995  1994
--------------------------------------------------------------------------------
                                                                 (In Bcf)
<S>                                                           <C>    <C>   <C>
PROVED DEVELOPED AND UNDEVELOPED RESERVES*--GAS
  At January 1...............................................   985   901   885
  Changes in reserves
    Extensions, discoveries and other additions..............   124   167   111
    Revisions of previous estimates..........................     5    17    16
    Production...............................................  (145) (103) (114)
    Purchases of gas in place................................    96     7     8
    Sales of gas in place....................................   (25)   (4)   (5)
                                                              -----  ----  ----
  At December 31............................................. 1,040   985   901
                                                              =====  ====  ====
PROVED DEVELOPED RESERVES*--GAS
  At January 1...............................................   717   730   761
  At December 31.............................................   900   717   730
</TABLE>
 
*Net before royalty.
-------------------------------------------------------------------------------
Included in the caption "Extensions, discoveries and other additions" for 1995
are 110 Bcf of proved undeveloped reserves for which development costs will be
incurred in future years. The preceding proved developed and undeveloped gas
reserves at December 31, 1994 through 1996, include United States reserves of
900, 984 and 1,039 Bcf which, together with the Canadian reserves and the gas
reserves
 
                                      46
<PAGE>
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

reported under "Cost-of-Service Properties," are as contained in reports of
Ralph E. Davis Associates, Inc., independent geologists.
-------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Years Ended December 31,                                  1996    1995    1994
-------------------------------------------------------------------------------
                                                          (In Thousand Bbls)
<S>                                                      <C>     <C>     <C>
PROVED DEVELOPED AND UNDEVELOPED RESERVES*--OIL
  At January 1.......................................... 45,791  46,255  27,596
  Changes in reserves
    Extensions, discoveries and other additions.........  5,976   1,965  24,709
    Revisions of previous estimates.....................  2,711   1,117  (2,791)
    Production.......................................... (4,766) (3,132) (3,333)
    Purchases of oil in place...........................    804     163      77
    Sales of oil in place...............................    (59)   (577)     (3)
                                                         ------  ------  ------
  At December 31........................................ 50,457  45,791  46,255
                                                         ======  ======  ======
PROVED DEVELOPED RESERVES*--OIL
  At January 1.......................................... 19,838  20,379  21,936
  At December 31........................................ 24,989  19,838  20,379
</TABLE>
 
*Net before royalty.
-------------------------------------------------------------------------------
Included in the caption "Extensions, discoveries and other additions" for 1994
are 22,305 thousand barrels of proved undeveloped reserves for which
development costs will be incurred in future years. The foregoing proved
developed and undeveloped oil reserves at December 31, 1994 through 1996,
include United States reserves of 40,918, 39,964 and 41,818 thousand barrels,
respectively. These, together with the Canadian reserves and the oil reserves
reported under "Cost-of-Service Properties," are as contained in reports of
Ralph E. Davis Associates, Inc.
 
  STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN
The following tabulation has been prepared in accordance with the FASB's rules
for disclosure of a standardized measure of discounted future net cash flows
relating to Company-owned proved gas and oil reserve quantities.
-------------------------------------------------------------------------------
<TABLE>
<CAPTION>
December 31,                                      1996       1995       1994
-------------------------------------------------------------------------------
                                                        (In Thousands)
<S>                                            <C>        <C>        <C>
Future cash inflows........................... $4,022,381 $2,668,837 $2,303,024
Less:Future development and production costs..    711,067    659,532    626,344
     Future income tax expense................  1,049,234    602,158    490,079
                                               ---------- ---------- ----------
Future net cash flows.........................  2,262,080  1,407,147  1,186,601
Less annual discount (10% a year).............    830,083    565,404    482,109
                                               ---------- ---------- ----------
Standardized measure of discounted future net
cash flows.................................... $1,431,997 $  841,743 $  704,492
                                               ========== ========== ==========
-------------------------------------------------------------------------------
</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.
 
                                      47
<PAGE>
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

The following tabulation is a summary of changes between the total
standardized measure of discounted future net cash flows at the beginning and
end of each year.
-------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Years Ended December 31,                         1996       1995       1994
-------------------------------------------------------------------------------
                                                      (In Thousands)
<S>                                           <C>         <C>        <C>
Standardized measure of discounted future
   net cash flows at January 1............... $  841,743  $ 704,492  $ 768,263
Changes in the year resulting from
  Sales and transfers of gas and oil produced
   during the year, less production costs....   (318,583)  (170,257)  (214,104)
  Prices and production and development costs
   related to future production..............    632,118    150,634   (153,962)
  Extensions, discoveries and other
   additions,
   less production and development costs.....    295,236    181,664    144,342
  Previously estimated development costs
   incurred during the year..................     62,706     62,958     46,568
  Revisions of previous quantity estimates...    106,800      8,336      4,228
  Accretion of discount......................    119,555     98,736    108,417
  Income taxes...............................   (306,290)   (70,927)    33,029
  Purchases and sales of proved reserves in
   place-net.................................    112,601      1,794      4,122
  Other (principally timing of production)...   (113,889)  (125,687)   (36,411)
                                              ----------  ---------  ---------
Standardized measure of discounted future
   net cash flows at December 31............. $1,431,997  $ 841,743  $ 704,492
                                              ==========  =========  =========
-------------------------------------------------------------------------------
</TABLE>
 
  COST-OF-SERVICE PROPERTIES
As previously stated, activities subject to cost-of-service rate regulation
are excluded from the foregoing information. At December 31, 1995 and 1996,
net capitalized costs of cost-of-service properties amounted to $14,809,000
and $10,015,000, respectively. Related proved reserves of gas and oil are
located in the United States, and amounted to 71, 56 and 43 Bcf of gas at
December 31, 1994 through 1996, and 256 thousand barrels of oil at December
31, 1994. There were no cost-of-service oil reserves at December 31, 1995 or
1996. East Ohio Gas sold all of its remaining gas and oil reserves during
1995. Hope Gas sold all of its remaining gas reserves to CNG Producing during
1996. At December 31, 1996, the Company's remaining cost-of-service gas
reserves were held by Peoples Natural Gas. Gas production for the years 1994
through 1996 amounted to 6, 4 and 3 Bcf, respectively. Oil production for 1994
and 1995 amounted to 24 and 17 thousand barrels, respectively.

Future revenues associated with production of the foregoing gas and oil
reserves would be based upon cost-of-service ratemaking and historical asset
costs, with rate of return levels determined by various state regulatory
commissions.
 
                                      48
<PAGE>
 
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 1995 and 1996
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 (a)   Second (b)  Third (c)  Fourth (d)
-------------------------------------------------------------------------------------
                                                   (In Thousands)
<S>                                  <C>         <C>         <C>        <C>
1996
Total operating revenues...........  $1,315,084  $ 654,950   $595,057   $1,229,218
Operating income before income
taxes..............................     302,176     71,949     11,045      162,804
Net income (loss)..................     180,800     34,617     (5,118)      87,974
Earnings (loss) per share of common
stock (e)..........................        1.92        .37       (.05)         .93
1995
Total operating revenues...........  $1,191,637  $ 664,972   $515,142   $  935,574
Operating income before income
taxes..............................     (15,918)     2,999      1,956      160,419
Net income (loss)..................     (21,396)   (33,512)   (11,215)      87,467
Earnings (loss) per share of common
stock..............................        (.23)      (.36)      (.12)         .94
</TABLE>
 
(a) The 1996 first quarter includes charges related to workforce reductions
    that reduced operating income before income taxes by $3,379,000 and net
    income by $2,069,000, or $.02 per share (see Note 4 to the consolidated
    financial statements). The 1995 first quarter includes the effect of an
    impairment of gas and oil producing properties that reduced operating
    income before income taxes by $226,209,000 and net income by $145,000,000,
    or $1.56 per share (see Note 3 to the consolidated financial statements).
(b) The 1995 second quarter includes charges related to workforce reductions
    that reduced operating income before income taxes by $36,412,000 and net
    income by $23,668,000, or $.25 per share. Net income was also reduced by
    the write-down of coal properties amounting to $20,323,000, or $.22 per
    share (see Notes 3 and 4 to the consolidated financial statements).
(c) The 1995 third quarter includes charges related to workforce reductions
    that reduced operating income before income taxes by $3,457,000 and net
    income by $2,343,000, or $.02 per share (see Note 4 to the consolidated
    financial statements).
(d) The 1996 fourth quarter includes charges related to workforce reductions
    that reduced operating income before income taxes by $11,816,000 and net
    income by $7,786,000, or $.08 per share (see Note 4 to the consolidated
    financial statements).
(e) 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 outstanding. In addition, first quarter fully diluted earnings per
    share was $1.86.
-----------------------------------------------------------------------------
 
                                      49
<PAGE>
 
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)
 
(C) COMMON STOCK MARKET PRICES AND RELATED MATTERS
At December 31, 1996, there were 35,816 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 1995 and
1996 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
1996--High...................................... $47 1/8 $52 1/4 $57 1/8 $59 5/8
    --Low....................................... $41 1/2 $43 1/2 $49     $51 1/8
1995--High...................................... $38 3/4 $40     $41     $46 1/4
    --Low....................................... $33 5/8 $37 1/8 $35 3/4 $37 3/8
Dividends Declared per Share
1996............................................   $.485   $.485   $.485   $.485
1995............................................   $.485   $.485   $.485   $.485
--------------------------------------------------------------------------------
</TABLE>
 
                                      50