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

Earnings and Dividends

1995 Compared to 1994

Earnings per common share in 1995 were $2.64 compared to $1.76 in 1994. The
increase in earnings was primarily due to a one-time charge of $0.66 per share
in the third quarter of 1994 associated with the Company's Voluntary Retirement
Incentive Program (VRIP) and Voluntary Separation Incentive Program (VSIP).
Earnings also increased by $0.22 per share due to increased electric sales, by
$0.19 per share due to the Company's ongoing emphasis on cost control, by $0.12
per share due to the gain on the sale of Conowingo Power Company (COPCO), and by
$0.04 per share due to reduced financing costs. These increases were partially
offset by $0.14 per share due to additional costs incurred as a result of the
shutdown of Salem Generating Station (Salem), by $0.14 per share due to
increased taxes and by $0.07 per share due to revenues recorded in 1994 from the
receipt of nuclear fuel from Shoreham Generating Station (Shoreham).

The Company increased its annual common stock dividend by 7.4% to $1.74 per
share, effective with the dividend paid in December 1995.

Operating Revenues

Increases/(decreases) in electric sales and operating revenues by class of
customer for 1995 compared to 1994 are set forth below:

                       Electric Sales     Electric Revenues
                       Millions of kWh       Millions of $

Residential                      43           $   31
Small Commercial and
     Industrial                 191               32
Large Commercial and
     Industrial                 129                4
Other                            69                1
                              -----           ------
     Service Territory          432               68
Interchange Sales              (272)              (5)
Sales to Other Utilities      4,002               88
                              -----           ------
     Total                    4,162            $ 151
                              =====           ======

Electric revenues increased $151 million in 1995 compared to 1994 primarily due
to increased sales to other utilities and higher retail sales due to favorable
weather in the third and fourth quarters of 1995. The increase in electric
revenues from residential sales was also attributable to higher fuel-clause
revenues resulting from yearly changes in the Company's Energy Cost Adjustment
(ECA).

Gas revenues decreased $5 million in 1995 compared to 1994 primarily due to
lower interruptible sales and sales of gas to the Company's electric generating
units because of reduced spot market rates. This decrease was partially offset
by higher fuel-clause revenues and increased transportation revenues related to
higher levels of gas transported for customers purchasing their own gas on the
spot market.

Fuel and Energy Interchange Expense

Fuel and energy interchange expense increased $59 million in 1995 compared to
1994 primarily due to increased output needed to meet service-territory customer
demand, higher levels of sales to other utilities and replacement power costs
required by the shutdown of Salem. These increases were partially offset by net
credits to expense from the retention by the Company of a share of the energy
savings resulting from the operation of Limerick Generating Station (Limerick)
and from certain energy sales to other utilities. The increases were further
offset by lower purchased gas costs resulting from reduced output.

Other Operating and Maintenance Expenses

Other operating and maintenance expenses decreased by $268 million in 1995
compared to 1994 primarily due to the one-time charge in 1994 associated with
VRIP and VSIP. The decrease was also due to other continuing cost-control
efforts, including the savings associated with VRIP and VSIP, lower customer
expenses as a result of improved collection processes and lower nuclear
generating station charges resulting from shorter refueling and maintenance
outages at Company-owned nuclear generating units. These decreases were
partially offset by increased process reengineering costs and maintenance
expenses at Salem.

Depreciation Expense

Depreciation expense increased in 1995 compared to 1994 primarily due to
additions to plant in service.

Income Taxes

Income taxes charged to operations increased $163 million in 1995 compared to
1994 primarily due to increases in operating income.

Allowance for Funds Used During Construction

Allowance for Funds Used During Construction (AFUDC) increased in 1995 compared
to 1994 primarily due to an increase in the 1995 AFUDC rate.

Other Income and Deductions

Other income and deductions increased $16 million in 1995 compared to 1994
primarily due to the gain recognized on the sale of COPCO, partially offset by
revenues recorded in 1994 from the receipt of nuclear fuel from Shoreham.

Total Interest Charges

Total interest charges increased primarily due to the July 1994 issuance of
Monthly Income Preferred Securities, Series A (recorded in the financial
statements as Company Obligated Mandatorily Redeemable Preferred Securities of a
Partnership, which holds Solely Subordinated Debentures of the Company).

Preferred Stock Dividends

Preferred stock dividends decreased primarily due to redemptions of preferred
stock in the third quarter of 1994 with the proceeds from the issuance of
Monthly Income Preferred Securities, Series A.

                                       13
<PAGE>


1994 Compared to 1993

Earnings per common share in 1994 were $1.76 compared to $2.45 in 1993. The
decrease in earnings was primarily due to a one-time charge of $0.66 per share
associated with VRIP and VSIP. Also contributing to the decrease in earnings
were other strategic and non-recurring operating and maintenance charges which
decreased 1994 earnings by $0.13 per share. These decreases were partially
offset by savings from the Company's ongoing debt and preferred stock
refinancing and redemption program, which increased earnings by $0.14 per share.

Operating Revenues

Increases/(decreases) in electric sales and operating revenues by class of
customer for 1994 compared to 1993 are set forth below:

                         Electric Sales   Electric Revenues
                        Millions of kWh     Millions of $

Residential                     160          $   15
Small Commercial and
     Industrial                 335              28
Large Commercial and
     Industrial                 (88)            (21)
Other                            20             (25)
                              -----          ------
     Service Territory          427              (3)
Interchange Sales               311               9
Sales to Other Utilities      1,369              13
                              -----          ------
     Total                    2,107          $   19
                              =====          ======

Electric revenues increased $19 million in 1994 compared to 1993 primarily due
to increased sales to other utilities and increased interchange sales. These
increases were partially offset by lower revenue margins obtained on these
sales.

Gas revenues increased $33 million in 1994 compared to 1993 primarily due to
higher fuel-clause revenues.

Fuel and Energy Interchange Expense

Fuel and energy interchange expense increased $44 million in 1994 compared to
1993 primarily due to increased electric output associated with interchange
sales and increased sales to other utilities. A portion of this increase was
deferred pending regulatory action. The increase was also attributable to an
increase in gas fuel costs.

Other Operating and Maintenance Expenses

Other operating and maintenance expenses increased $304 million in 1994 compared
to 1993 primarily due to a one-time, pre-tax charge of $254 million in the third
quarter of 1994 for VRIP and VSIP. In addition, other operating and maintenance
expenses increased due to higher environmental, customer and employee-related
charges, and other strategic and non-recurring operating and maintenance
charges. These increases were partially offset by lower generating station
charges resulting from fewer and shorter refueling and maintenance outages.

Depreciation Expense

Depreciation expense increased in 1994 compared to 1993 due to additions to
plant in service.

Income Taxes

Income taxes charged to operations decreased in 1994 compared to 1993 primarily
due to the charge for VRIP and VSIP and lower operating income. These decreases
were partially offset by lower interest expense allocated to operations.

Other Taxes

Other taxes increased in 1994 compared to 1993 primarily due to an increase in
the real estate tax base and increased Pennsylvania gross receipts tax resulting
from higher operating revenues.

Allowance for Funds Used During Construction

AFUDC decreased in 1994 compared to 1993 primarily due to a decrease in the 1994
AFUDC rate, partially offset by an increase in Construction Work in Progress.

Total Interest Charges

Total interest charges decreased in 1994 compared to 1993 primarily due to the
Company's ongoing program to refinance and redeem higher-cost, long-term debt.

Preferred Stock Dividends

Preferred stock dividends decreased in 1994 compared to 1993 primarily due to
the reduced number of preferred shares outstanding and the refinancing of
higher-cost preferred stock.

Liquidity and Capital Resources

The Company's capital resources are primarily provided by internally generated
cash flows from utility operations and, to the extent necessary, external
financing. Such capital resources are generally used to fund the Company's
construction program, to repay outstanding debt and to make preferred and common
stock dividend payments.

In 1995 and each of the preceding five years, internally generated cash exceeded
the Company's capital requirements and dividend payments, thereby improving the
Company's financial condition. Contributing to the Company's improved cash
position were a reduction in interest expense and dividend requirements
associated with the Company's ongoing program to reduce debt and refinance
higher-cost, long-term debt and preferred stock, and increased revenues from the
sale of capacity and energy to other utilities. Net cash provided by operating
activities for 1995 was $1.3 billion. For the period 1996 through 1999, the
Company expects that internally generated cash will exceed its capital and
dividend requirements.

The Company expects its level of capital investment in utility plant to remain
relatively stable since it has sufficient electric generating capacity to meet
the anticipated needs of its service territory well into the next decade. The
Company also expects to fund all new business initiatives through internally
generated funds. Construction program expenditures for 1995 were $480 million
and are estimated to be $538 million in 1996 and $1.2 billion for the period
1997 to 1999. As a result of its prior investments in scrubbers for Eddystone
and Cromby Generating Stations and its investment in nuclear generating
capacity, the Company believes that com-

                                       14
<PAGE>

pliance with the Clean Air Act will have significantly less impact on the
Company's capital requirements than on other Pennsylvania utilities which are
more dependent on coal-fired generation. Certain facilities under construction
and to be constructed may require permits and licenses which the Company has no
assurance will be granted.

During 1995, the Company utilized cash from operations, proceeds from the sale
of COPCO and $100 million from the sale of an undivided interest in trade
receivables to reduce the Company's debt by $401 million. Also during 1995, $349
million of long-term debt and Company obligated mandatorily redeemable preferred
securities of a partnership were sold or exchanged to refund debt and preferred
stock carrying less-favorable after-tax rates of interest and dividends. These
transactions resulted in a reduction of approximately $33 million in annualized
interest and preferred stock dividends.

The Company meets its short-term liquidity requirements primarily through the
issuance of commercial paper, borrowings under a revolving credit agreement and
bank lines of credit. The Company did not have any commercial paper or
short-term debt outstanding at December 31, 1995.

At December 31, 1995, the Company's embedded cost of debt was 7.1% with 14.5% of
the Company's long-term debt having floating rates. The coverage ratios under
the Company's mortgage indenture and Amended and Restated Articles of
Incorporation as of December 31, 1995, were 4.94 and 2.74 times, respectively,
compared with minimum issuance requirements of 2.00 and 1.50 times,
respectively. The Company believes that its internal sources of funds will be
sufficient to cover its fixed charges for 1996. 

As of December 31, 1995, the Company's capital structure consisted of 46.6%
common equity; 6.1% preferred stock and Company obligated mandatorily redeemable
preferred securities of a partnership (which comprised 3.1% of the Company's
total capitalization structure); and 47.3% long-term debt. The Company's capital
structure as of December 31, 1994, consisted of 43.5% common equity; 6.0%
preferred stock and Company obligated mandatorily redeemable preferred
securities of a partnership (which comprised 2.2% of the Company's total
capitalization structure); and 50.5% long-term debt.

Outlook

The Company's financial condition and its future operating results are dependent
on a number of factors affecting the Company and the utility industry in
general. Among these factors are increased competition in electric and gas
markets, regulation and operation of nuclear generating facilities, sales to
other utilities, accounting issues and other factors including weather and
compliance with environmental regulations.

Due to the Company's substantial investment in Limerick, which represents 54% of
the Company's investment in electric plant, any regulatory changes which do not
provide for the recovery of the Company's investment in Limerick could result in
substantial write-downs of assets. This may adversely affect the Company's
financial condition and future results of operations.

Competition

Over the last few years, legislative and regulatory initiatives and market
forces have laid the foundation for the continued development of competition in
the electric utility industry. As a result, the electric utility industry is
reviewing the potential impacts of a major transition from a traditional rate
regulated environment based on cost recovery to some combination of a
competitive marketplace and modified regulation of certain market segments.
Although a competitive environment may create new opportunities for revenue
growth, it may also reduce the margin on certain classes of energy sales and may
result in customer and revenue losses. Increased competition may limit high-cost
utilities' ability to recover capital investment through rates, resulting in
stranded investment and the potential write-down of assets. Potential
competition has resulted in increased focus on cost-cutting and consideration of
strategic alternatives, including mergers and restructuring of operations.

The Energy Policy Act of 1992 (Energy Act) was enacted to promote competition
among utility and nonutility generators in the wholesale electric generation
market. The Energy Act allows the Federal Energy Regulatory Commission (FERC) to
order owners of electric transmission systems to provide third parties with
transmission access for wholesale power transactions. During 1995, the FERC
issued proposed rules which, if adopted, would require that all public utilities
have on file with the FERC nondiscriminatory open-access transmission tariffs
for network and point-to-point services, including separate rates for ancillary
services. The FERC's proposed rules would also provide for recovery of
legitimate and verifiable wholesale stranded investment. These proposals further
expressed the FERC's strong expectation that state regulatory commissions
provide for similar full recovery of legitimate and verifiable stranded
investment that could result if state regulatory commissions ordered retail
competition and direct access. The Company filed comments in response to the
FERC's proposal. The comments, while generally supportive, suggested several
adjustments to ensure full stranded investment recovery. An order from the FERC
is expected in the first half of 1996.

The Company also filed a tariff for network and point-to-point services and a
market-based rate tariff that would allow the Company to sell wholesale energy
at market-based rates outside the Pennsylvania-New Jersey-Maryland
Interconnection Association (PJM) control area. These tariffs would be available
to wholesale buyers and sellers of electricity, although the Company would
continue to make sales within the PJM control area under its existing
FERC-approved cost-based tariffs. The market-based rate tariff is not expected
to affect the applicability of Statement of Financial Accounting Standards
(SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," to
the Company's operations.

During 1995, the Company proposed other initiatives to the FERC, including a
plan to increase wholesale electric competition in the Mid-Atlantic region
served by the PJM. The objectives of the Company's plan are to enable the PJM
companies to offer comparable open access to their transmission facilities, to
adapt the existing PJM regional wholesale energy market to increased
competition, and to preserve those elements of power pooling which are still
beneficial.

                                       15
<PAGE>

While the Energy Act encourages competition on a wholesale level, the Energy Act
prohibits the FERC from ordering wheeling for sales to retail customers.
Currently, a number of states, including Pennsylvania, are assessing the issue
of retail competition with varying outcomes. For instance, California has
aggressively promoted the concept of retail competition while Maryland has
stated that it is strongly opposed to such measures. While assessing their
position, many issues must be considered which will require significant
deliberation and may result in legal challenges. These issues include the
recovery of any resulting stranded investment, the impact of interjurisdictional
sales and whether such change is enacted by regulatory or legislative action.

In August 1995, after seeking input from Pennsylvania utilities and interest
groups, the Pennsylvania Public Utility Commission (PUC) staff issued a report
recommending against retail electric power competition at this time. The PUC
also issued an order inviting further comments and establishing hearings on
competition issues with the expectation of submitting a report to the
Pennsylvania legislature and the Governor in the second quarter of 1996. In
November 1995, the Company submitted testimony which proposes five major
initiatives to reduce the costs of electricity while preserving the reliability
and universal service that is essential to Pennsylvania citizens. These
initiatives are: 1) improvements in the PJM interconnection to incorporate an
independent system operator, provide for wholesale energy exchange based on a
market bidding mechanism, provide a regional transmission tariff, and expand
participation in the wholesale energy market to others, including firms that are
not traditional utilities; 2) performance-based regulation to increase utility
accountability by linking utility earnings to performance rather than historic
costs; 3) flexible pricing to allow utilities to offer customers a variety of
service options tailored to individual requests, and to bring certain rates
closer to market levels; 4) accelerated depreciation and other cost mitigation
measures that challenge the utilities to reduce possible stranded investment
associated with existing generation assets; and 5) competitive bidding of new
generation to ensure that needs are met as efficiently as possible. The Company
believes that these proposed initiatives will allow the PUC to improve the
efficiency of the electric industry, while continuing to assure the availability
of reliable service for all customers at reasonable rates, without significant
adverse consequences on the financial condition of electric utilities.

The Company believes that retail competition should not be adopted if it
represents a mere shifting of costs from one class of customers to another or to
shareholders, and that retail competition does not currently provide a net
benefit. Regulatory changes permitting retail competition may also create
stranded investment if the FERC's position of allowing full recovery of stranded
investment as described in its proposal is not adopted. Investments by the
Company in assets which would not be recoverable from customers, including its
investment in nuclear facilities, may have to be written down, which would have
a material adverse effect on the Company's financial condition and results of
operations. The Company is not able to predict whether retail competition will
be implemented and, if implemented, what impact it would have on the Company's
financial condition or results of operations.

The gas industry is also undergoing structural changes in response to FERC
policies designed to increase competition in this market. This has included
requirements that interstate gas pipelines unbundle their gas sales service from
other regulated tariff services, such as transportation and storage. In
anticipation of these policies, the Company has modified its gas purchasing
arrangements to enable the purchase of gas and transportation at lower cost, and
has become more active in the area of gas transportation.

In 1995, the Company introduced to regulators and industry analysts its
Competitive Breakthrough Strategy, which is an integrated strategy designed to
improve the efficiency, financial condition and rate stability of the Company
through a broad array of initiatives, including but not limited to,
reengineering of processes, expense reduction and containment, development of
new revenue opportunities, reduction of exposure to asset write-downs and
reduction of existing debt.

As part of its Competitive Breakthrough Strategy, in October 1995, the Company
filed a petition for a declaratory accounting order with the PUC requesting
approval to increase Limerick-related depreciation and amortization by $100
million per year and decrease depreciation and amortization of other Company
assets by approximately $10 million per year, effective October 1, 1996. The
requested order would not affect rates charged to customers. The Company
expects, but cannot be assured, that the net increased depreciation and
amortization would be offset by the reduced costs and increased revenues
generated by the Company's Competitive Breakthrough Strategy. For further
details see note 3 of Notes to Consolidated Financial Statements.

The Company has realized wage and benefit savings of approximately $60 million
in 1995 as a result of the Company's VRIP and VSIP. The Company expects VRIP and
VSIP to provide savings in wages and benefits to the Company of approximately
$100 million annually beginning in 1996.

To take advantage of emerging opportunities in the telecommunications field, in
1995, the Company's Board of Directors created a new strategic business unit,
the Telecommunications Group. The business unit has initiated several joint
ventures in newly emerging wireless personal communications services businesses
and other competitive telecommunications opportunities. The telecommunications
field presents the Company with many opportunities to expand its business,
generate additional revenue and provide greater shareholder value. The Company
possesses a highly skilled technical staff and a substantial infrastructure
which will enable it to successfully participate in the ever-changing
telecommunications industry.

As a result of competitive pressures, the Company has negotiated long-term
contracts with many of its larger-volume industrial customers. Although these
agreements have resulted in lower revenues from this class of customers, they
have permitted the Company to maintain this segment of its customer base.

During 1995, there were an unprecedented number of mergers in the utility
industry and this trend is expected to continue. In August 1995, the Company
proposed a merger with PP&L Resources, Inc., an electric utility with operations
in northeast Pennsylvania. In November, PP&L Resources declined the Company's
final offer and the Company withdrew its proposal. The Company will continually
evaluate all

                                       16
<PAGE>

opportunities to improve its strategic and competitive position but, because of
its strong stand-alone position, is not compelled to pursue such opportunities
at any cost.

Regulation and Operation of Nuclear Generating Facilities

The Company's financial condition and results of operations are in part
dependent on the continued successful operation of its nuclear generating
facilities. The Company's nuclear generating facilities represent approximately
45% of its installed generating capacity. Because of the Company's substantial
investment in and reliance on its nuclear generating units, any changes in
regulations by the Nuclear Regulatory Commission (NRC) requiring additional
investments or resulting in increased operating costs of nuclear generating
units could adversely affect the Company.

During 1995, Company-operated nuclear plants operated at an 88% weighted-average
capacity factor and Company-owned nuclear plants, including Salem, operated at a
72% weighted-average capacity factor and produced 50% of the Company's output
including purchased power. Nuclear generation is the most cost-effective way for
the Company to meet customer needs and commitments for sales to other utilities.
Continued operation of the nuclear plants above 60% of capacity is necessary to
avoid penalties under the ECA. In addition, the terms of the 1991 settlement of
the Limerick Unit No. 2 rate case afford the Company the opportunity, through
sales to other utilities and the efficient operation of Limerick, to increase
earnings. See note 3 of Notes to Consolidated Financial Statements for a
description of the ECA and the terms of the Limerick Unit No. 2 rate case
settlement.

Public Service Electric and Gas Company (PSE&G), the operator of Salem Units No.
1 and No. 2, which are 42.59% owned by the Company, removed the units from
service on May 16, 1995 and June 7, 1995, respectively. PSE&G informed the NRC
at that time that it had determined to keep the Salem units shut down pending
review and resolution of certain equipment and management issues, and NRC
agreement that each unit is sufficiently prepared to restart. Salem Units No. 1
and No. 2 are expected to be out of service until the second and third quarters
of 1996, respectively. The Company expects to incur and expense at least $85
million in 1996 for increased costs related to the shutdown. Under Pennsylvania
law, the PUC may investigate outages of electric generating units which exceed
120 days or if the annual capacity factor is less than 50% to determine whether
to deny the recovery of replacement power costs. See note 24 of Notes to
Consolidated Financial Statements.

The Financial Accounting Standards Board is currently reviewing the accounting
for closure and removal costs of production facilities including the
recognition, measurement and classification of decommissioning costs for nuclear
generating stations, and will issue an Exposure Draft in 1996. The Company will
review the Exposure Draft to determine the effect on its financial condition and
results of operations. See note 4 of Notes to Consolidated Financial Statements.

The Company may seek to recover through rates capital costs and any increased
operating costs, including those associated with NRC regulation of the Company's
nuclear generating stations and environmental compliance and remediation,
although such recovery is not assured. To the extent that such amounts are not
recovered, they would be charged against income.

Sales to Other Utilities

At December 31, 1995, the Company had 1,199 megawatts (MW) of installed
generating capacity available for sales to other utilities. In the ordinary
course of business, the Company enters into commitments to buy and sell power.
During 1995, the Company entered into an agreement to purchase energy associated
with 300 MW from 1996 through 2000 from an unaffiliated utilitiy. The Company's
future results of operations are dependent in part on its ability to
successfully market this generation. See note 4 of Notes to Consolidated
Financial Statements. 

In the wholesale market, the Company has increased its sales to other utilities,
but increased competition has reduced the Company's margin on these sales. The
Company has agreements with other utilities to sell energy and/or capacity. The
Company has long-term agreements over the next five years with unaffiliated
utilities to sell energy associated with 1,185 MW of capacity. These power sales
agreements extend from 1996 to 2023. The Company expects these wholesale sales
to generate approximately $300 million of revenue in 1996.

Accounting Issues

The Company continues to account for its operations in accordance with SFAS No.
71 which is appropriate for companies that meet three criteria in order to
account for the economic impacts of rate regulation: 1) third-party regulation
of rates; 2) cost-based rates; and 3) a reasonable assumption that costs will be
recoverable from customers through rates. Discontinuance of SFAS No. 71 would
result in a charge against income from the elimination of regulatory assets
created by the regulatory process as well as certain plant costs that may no
longer be recoverable. The impact of such events could have a material adverse
effect on the Company's financial condition and results of operations. Continued
application of SFAS No. 71 is periodically assessed by the Company.

At December 31, 1995, the Company had deferred on its balance sheet certain
regulatory assets for which recovery has been approved by the PUC. These
regulatory assets include $300 million associated with Limerick Units No. 1 and
No. 2, $248 million associated with the Company's non-pension postretirement
benefits and $2.0 billion associated with recoverable deferred income taxes. For
more details on these regulatory assets see notes 3, 7 and 14 of Notes to
Consolidated Financial Statements.

At December 31, 1995, the Company had deferred on its balance sheet certain
regulatory assets for which current recovery has not yet been approved. Any
deferred costs that are not ultimately recovered through base rates would be
charged against income. These regulatory assets include $107 million for the
effect on deferred income taxes of the change in the statutory federal income
tax rate from 34% to 35% in 1993, and $91 million of operating and maintenance
expenses, depreciation and accrued carrying charges on its investment in
Limerick Unit No. 2 and 50% of Limerick common facilities, deferred pursuant to
a Declaratory Order of the PUC. See notes 3 and 14 of Notes to Consolidated
Financial Statements. These and other regulatory assets are deferred pursuant to
PUC action. In October 1995, the Company filed a petition for a declaratory
accounting order

                                       17
<PAGE>

with the PUC requesting approval to, among other things, amortize $91 million of
operating and maintenance expenses, depreciation and accrued carrying charges on
its investment in Limerick Unit No. 2 and 50% of Limerick common facilities. The
petition requests that these deferred costs be amortized over a nine-year period
beginning October 1996. The requested order would not affect customer rates.

The Company will adopt SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of," in the first
quarter of 1996. Upon adoption, the Company does not expect SFAS No. 121 to have
an effect upon the Company's financial condition or results of operations.
Significant changes in the regulatory environment, abandonment of cost-based
rates, or losses of major customers that result in stranded investment are
events that may necessitate a review of the Company's assets for impairment.

The Company will adopt SFAS No. 123, "Accounting for Stock-Based Compensation,"
in the first quarter of 1996, but will continue to use the intrinsic value based
method of accounting prescribed by Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees," supplemented by SFAS No. 123's
required footnote disclosures. Adoption of SFAS No. 123 will not have an effect
upon the Company's financial condition or results of operations.

Other Factors

Annual and quarterly operating results can be significantly affected by weather.

Inflation affects the Company through increased operating costs and increased
capital costs for utility plant. During periods of high inflation, the Company
could be adversely affected if it is unable to offset increasing costs with
improved productivity or rate increases. In addition, the replacement costs of
the Company's utility plant are significantly higher than the historical costs
reflected in the financial statements. The Company has agreed not to seek a
retail electric base rate increase before April 1, 1999, except under specified
circumstances. Therefore, the effects of future inflation and other potential
cost increases may not be subject to rate recovery. See note 3 of Notes to
Consolidated Financial Statements.

The Company's operations have in the past and may in the future require
substantial capital expenditures in order to comply with environmental laws.
Additionally, under federal and state environmental laws, the Company is
generally liable for the costs of remediating environmental contamination of
property now or formerly owned by the Company and of property contaminated by
hazardous substances generated by the Company. The Company owns or leases a
number of real estate parcels, including parcels on which its operations or the
operations of others may have resulted in contamination by substances which are
considered hazardous under environmental laws. The Company is currently involved
in a number of proceedings relating to sites where hazardous substances have
been deposited and may be subject to additional proceedings in the future.

The Company has identified 23 sites where former manufactured gas plant
activities may have resulted in site contamination. Past activities at several
sites have resulted in actual site contamination. The Company is presently
engaged in performing various levels of activities at these sites, including
initial evaluation to determine the existence and nature of the contamination,
detailed evaluation to determine the extent of the contamination and the
necessity and possible methods of remediation, and implementation of
remediation. Seven of the sites are currently in the detailed evaluation or
remediation stage.

As of December 31, 1995 and 1994, the Company had accrued $27 and $24 million,
respectively, for environmental investigation and remediation costs that
currently can be reasonably estimated. The Company expects to expend $8 million
for such activities in 1996. The Company cannot currently predict whether it
will incur other significant liabilities for any additional investigation and
remediation costs at these or additional sites identified by the Company,
environmental agencies or others, or whether all such costs will be recoverable
through rates or from third parties.

For a discussion of other contingencies, see notes 3 and 4 of Notes to
Consolidated Financial Statements.

                                       18
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS

To the Shareholders and Board of Directors
PECO Energy Company:


     We have audited the accompanying consolidated balance sheets of PECO Energy
Company and Subsidiary Companies as of December 31, 1995 and 1994, and the
related consolidated statements of income, cash flows, and changes in common
shareholders' equity and preferred stock for each of the three years in the
period ended December 31, 1995. These financial statements are the
responsibility of the Companies' management. Our responsibility is to express an
opinion on these financial statements based on our audits.

     We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

     In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of PECO Energy
Company and Subsidiary Companies as of December 31, 1995 and 1994, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1995, in conformity with generally
accepted accounting principles.


Coopers & Lybrand LLP

2400 Eleven Penn Center
Philadelphia, Pennsylvania
February 2,1996

<PAGE>
Consolidated Statements of Income

<TABLE>
<CAPTION>
For the Years Ended December 31,                            1995            1994            1993
                                                                             Thousands of Dollars
<S>                                                 <C>             <C>            <C>
Operating Revenues
Electric                                             $ 3,775,326     $ 3,624,797     $ 3,605,425
Gas                                                      410,830         415,835         382,704
                                                     -----------     -----------     -----------
     Total Operating Revenues                          4,186,156       4,040,632       3,988,129
                                                     -----------     -----------     -----------

Operating Expenses
Fuel and Energy Interchange                              762,762         703,590         659,580
Other Operating                                          943,476         937,849         851,254
Early Retirement and Separation
  Programs                                                  --           254,106            --
Maintenance                                              307,797         327,714         364,409
Depreciation                                             457,254         442,101         424,952
Income Taxes                                             396,897         234,033         354,391
Other Taxes                                              314,071         311,689         298,132
                                                     -----------     -----------     -----------
     Total Operating Expenses                          3,182,257       3,211,082       2,952,718
                                                     -----------     -----------     -----------
Operating Income                                       1,003,899         829,550       1,035,411
                                                     -----------     -----------     -----------

Other Income and Deductions
Allowance for Other Funds Used
  During Construction                                     14,371          10,180          11,885
Gain on Sale of Subsidiary                                58,745            --              --
Income Taxes                                             (34,820)        (15,291)        (11,808)
Other, net                                                  (444)         23,121          11,980
                                                     -----------     -----------     -----------
     Total Other Income and Deductions                    37,852          18,010          12,057
                                                     -----------     -----------     -----------
Income Before Interest Charges                         1,041,751         847,560       1,047,468
                                                     -----------     -----------     -----------

Interest Charges
Long-Term Debt                                           386,205         387,279         432,707
     Company Obligated Mandatorily Redeemable
     Preferred Securities of a Partnership, which
     holds Solely Subordinated Debentures of the
     Company                                              20,987           8,570            --
Short-Term Debt                                           37,506          36,987          36,002
                                                     -----------     -----------     -----------
     Total Interest Charges                              444,698         432,836         468,709
Allowance for Borrowed Funds Used During
     Construction                                        (12,679)        (11,989)        (11,889)
                                                     -----------     -----------     -----------
     Net Interest Charges                                432,019         420,847         456,820
                                                     -----------     -----------     -----------
Net Income                                               609,732         426,713         590,648
Preferred Stock Dividends                                 23,217          37,298          49,058
                                                     -----------     -----------     -----------
Earnings Applicable to Common Stock                  $   586,515     $   389,415     $   541,590
                                                     ===========     ===========     ===========
Average Shares of Common Stock
     Outstanding (Thousands)                             221,859         221,554         221,072
                                                     ===========     ===========     ===========
Earnings per Average Common Share (Dollars)          $      2.64     $      1.76     $      2.45
                                                     ===========     ===========     ===========
Dividends per Common Share (Dollars)                 $      1.65     $     1.545     $      1.43
                                                     ===========     ===========     ===========
</TABLE>
 See Notes to Consolidated Financial Statements.

                                       20
<PAGE>
CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
For the Years Ended December 31,                                 1995            1994            1993
                                                                                 Thousands of Dollars
<S>                                                      <C>             <C>             <C>
Cash Flows from Operating Activities
Net Income                                                $   609,732     $   426,713     $   590,648
Adjustments to reconcile Net Income to Net Cash
          provided by Operating Activities:
     Depreciation and Amortization                            531,299         517,681         507,069
     Deferred Income Taxes                                    183,514         (23,306)        139,846
     Gain on Sale of Subsidiary                               (58,745)           --              --
     Early Retirement and Separation Programs                    --           254,106            --
     Deferred Energy Costs                                    (71,104)        (33,205)        (24,308)
     Amortization of Leased Property                           42,900          61,900          58,400
     Changes in Working Capital:
          Accounts Receivable                                  (8,198)         23,508          31,102
          Inventories                                         (10,872)         18,210          11,222
          Accounts Payable                                     (4,686)          5,342             777
          Other Current Assets and Liabilities                  9,641          52,940         (34,694)
     Other Items affecting Operations                          40,649          (9,175)        (18,287)
                                                          -----------     -----------     -----------
Net Cash Flows from Operating Activities                    1,264,130       1,294,714       1,261,775
                                                          -----------     -----------     -----------

Cash Flows from Investing Activities
Investment in Plant                                          (577,908)       (570,903)       (568,076)
Proceeds from Sale of Subsidiary                              150,000            --              --
Increase in Other Investments                                 (60,541)        (17,951)        (16,214)
                                                          -----------     -----------     -----------
Net Cash Flows from Investing Activities                     (488,449)       (588,854)       (584,290)
                                                          -----------     -----------     -----------

Cash Flows from Financing Activities
Change in Short-Term Debt                                     (11,499)       (107,851)          8,850
Issuance of Common Stock                                       15,585           2,308          29,346
Issuance of Preferred Stock                                      --              --           142,700
Retirement of Preferred Stock                                 (78,105)       (238,800)       (187,330)
Issuance of Company Obligated Mandatorily Redeemable
     Preferred Securities of a Partnership                     81,032         221,250            --
Issuance of Long-Term Debt                                    182,540         245,100       1,994,765
Retirement of Long-Term Debt                                 (575,713)       (397,763)     (2,148,963)
Loss on Reacquired Debt                                        12,302          22,125         (69,884)
Dividends on Preferred and Common Stock                      (390,340)       (377,883)       (366,081)
Change in Dividends Payable                                     5,626          (3,249)         (1,114)
Expenses of Issuing Long-Term Debt and Preferred Stock           (577)         (9,150)        (24,820)
Capital Lease Payments                                        (42,900)        (61,900)        (58,400)
                                                          -----------     -----------     -----------
Net Cash Flows from Financing Activities                     (802,049)       (705,813)       (680,931)
                                                          -----------     -----------     -----------

(Decrease)/Increase in Cash and Cash Equivalents              (26,368)             47          (3,446)
Cash and Cash Equivalents at beginning of period               46,970          46,923          50,369
                                                          -----------     -----------     -----------
Cash and Cash Equivalents at end of period                $    20,602     $    46,970     $    46,923
                                                          ===========     ===========     ===========
</TABLE>

                                       21
<PAGE>
CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
At December 31,                                                1995             1994
                                                                Thousands of Dollars
<S>                                                    <C>             <C>
Assets
Utility Plant, at Original Cost
Electric                                               $ 13,441,880     $ 13,283,888
Gas                                                         954,180          895,946
Common                                                      299,899          234,769
                                                       ------------     ------------
                                                         14,695,959       14,414,603
     Less Accumulated Provision for Depreciation          4,623,707        4,242,576
                                                       ------------     ------------
                                                         10,072,252       10,172,027
Nuclear Fuel, net                                           191,084          184,161
Construction Work in Progress                               494,194          472,512
Leased Property, net                                        180,425          174,565
                                                       ------------     ------------
     Net Utility Plant                                   10,937,955       11,003,265
                                                       ------------     ------------

Current Assets
Cash and Temporary Cash Investments                          20,602           46,970
Accounts Receivable, net
     Customers                                               75,220           96,987
     Other                                                   71,997           49,854
Inventories, at average cost
     Fossil Fuel                                             78,260           72,732
     Materials and Supplies                                 123,387          118,230
Deferred Energy Costs                                        55,883          (15,486)
Other                                                        60,868           58,069
                                                       ------------     ------------
     Total Current Assets                                   486,217          427,356
                                                       ------------     ------------

Deferred Debits and Other Assets
Recoverable Deferred Income Taxes                         2,077,426        2,138,079
Deferred Limerick Costs                                     390,433          413,885
Deferred Non-Pension Postretirement Benefits Costs          248,085          261,912
Investments                                                 296,948          236,587
Loss on Reacquired Debt                                     308,577          320,879
Other                                                       214,979          263,308
                                                       ------------     ------------
     Total Deferred Debits and Other Assets               3,536,448        3,634,650
                                                       ------------     ------------

Total Assets                                           $ 14,960,620     $ 15,065,271
                                                       ============     ============
</TABLE>


                                       22
<PAGE>

CONSOLIDATED BALANCE SHEETS (CONTINUED)

<TABLE>
<CAPTION>
At December 31,                                                  1995             1994
                                                                  Thousands of Dollars
<S>                                                     <C>              <C>
Capitalization and Liabilities
Capitalization
Common Shareholders' Equity
     Common Stock                                        $  3,506,313     $  3,490,728
     Other Paid-In Capital                                      1,326            1,271
     Retained Earnings                                      1,023,708          810,507
                                                         ------------     ------------
                                                            4,531,347        4,302,506
Preferred and Preference Stock
     Without Mandatory Redemption                             199,367          277,472
     With Mandatory Redemption                                 92,700           92,700
Company Obligated Mandatorily Redeemable Preferred
     Securities of a Partnership, which holds Solely
     Subordinated Debentures of the Company                   302,282          221,250
Long-Term Debt                                              4,198,283        4,785,631
                                                         ------------     ------------
     Total Capitalization                                   9,323,979        9,679,559
                                                         ------------     ------------

Current Liabilities
Notes Payable, Bank                                              --             11,499
Long-Term Debt Due Within One Year                            401,003          201,213
Capital Lease Obligations Due Within One Year                  60,320           60,476
Accounts Payable                                              299,731          308,832
Taxes Accrued                                                 107,621           87,185
Deferred Income Taxes                                          17,072          (12,002)
Interest Accrued                                               88,047           93,159
Dividends Payable                                              20,722           15,096
Other                                                          82,775           85,649
                                                         ------------     ------------
     Total Current Liabilities                              1,077,291          851,107
                                                         ------------     ------------

Deferred Credits and Other Liabilities
Capital Lease Obligations                                     120,105          114,089
Deferred Income Taxes                                       3,312,649        3,225,915
Unamortized Investment Tax Credits                            351,569          374,100
Pension Obligation for Early Retirement Plans                 216,283          238,250
Non-Pension Postretirement Benefits Obligation                326,251          354,458
Other                                                         232,493          227,793
                                                         ------------     ------------
     Total Deferred Credits and Other Liabilities           4,559,350        4,534,605
                                                         ------------     ------------

Commitments and Contingencies (Notes 3 and 4)

Total Capitalization and Liabilities                     $ 14,960,620     $ 15,065,271
                                                         ============     ============
</TABLE>

                                       23

<PAGE>
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDERS' EQUITY AND
PREFERRED STOCK

<TABLE>
<CAPTION>
                                                                              Other
                                                   Common Stock              Paid-In      Retained          Preferred Stock
All Amounts in Thousands                      Shares        Amount           Capital      Earnings         Share       Amount
<S>                                         <C>         <C>                 <C>          <C>           <C>           <C>
Balance at January 1, 1993                    220,534     $3,459,131         $1,214       $561,824         6,536      $653,602

Net Income                                                                                 590,648
Cash Dividends Declared
     Preferred Stock
       (at specified annual rates)                                                         (49,919)
     Common Stock ($1.43 per share)                                                       (316,162)
Expenses of Capital Stock Activity                                                          (5,625)
Capital Stock Activity
     Long-Term Incentive Plan Issuances           983         29,346                        (7,039)
     Preferred Stock Issuances                                                                             1,427       142,700
     Preferred Stock Redemptions                                                                          (1,873)     (187,330)
                                              -------     ----------         ------       --------         -----      --------
Balance at December 31, 1993                  221,517      3,488,477          1,214        773,727         6,090       608,972

Net Income                                                                                 426,713
Cash Dividends Declared
     Preferred Stock
       (at specified annual rates)                                                         (35,706)
     Common Stock ($1.545 per share)                                                      (342,177)
Expenses of Capital Stock Activity                                                         (11,662)
Capital Stock Activity
     Long-Term Incentive Plan Issuances            92          2,251                          (388)
     Preferred Stock Issuances                                                   57
     Preferred Stock Redemptions                                                                          (2,388)     (238,800)
                                              -------     ----------         ------       --------         -----      --------
Balance at December 31, 1994                  221,609      3,490,728          1,271        810,507         3,702       370,172

Net Income                                                                                 609,732
Cash Dividends Declared
     Preferred Stock
       (at specified annual rates)                                                         (24,253)
     Common Stock ($1.65 per share)                                                       (366,087)
Expenses of Capital Stock Activity                                                          (4,035)
Capital Stock Activity
     Long-Term Incentive Plan Issuances           563         15,585                        (2,156)
     Preferred Stock Issuances                                                   55
     Preferred Stock Redemptions                                                                            (781)      (78,105)
                                              -------     ----------         ------       --------         -----      --------
Balance at December 31, 1995                  222,172    $ 3,506,313    $     1,326    $ 1,023,708         2,921   $   292,067
                                              =======    ===========    ===========    ===========         =====   ===========
</TABLE>

                                       24

<PAGE>
1. Significant Accounting Policies

General

The consolidated financial statements of PECO Energy Company (Company) include
the accounts of its utility subsidiary companies, all of which are wholly owned.
Accounting policies are in accordance with those prescribed by the regulatory
authorities having jurisdiction, principally the Pennsylvania Public Utility
Commission (PUC) and the Federal Energy Regulatory Commission (FERC). The
Company has unconsolidated subsidiaries which are not material.

The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.

Revenues

Customers' meters are read and bills are prepared on a cyclical basis. At the
end of each month, the Company accrues an estimate for the unbilled amount of
energy delivered or services provided to customers.

Fuel and Energy Cost Adjustment Clauses

The Company's classes of service are subject to fuel adjustment clauses designed
to recover or refund the differences between actual costs of fuel, energy
interchange, and purchased power and gas, and the amounts of such costs included
in base rates. Differences between the amounts billed to customers and the
actual costs recoverable are deferred and recovered or refunded in future
periods by means of prospective adjustments to rates. Generally, such rates are
adjusted every twelve months. In addition to reconciling fuel costs and
revenues, the Company's Energy Cost Adjustment (ECA), established by the PUC,
incorporates a nuclear performance standard which allows for financial bonuses
or penalties depending upon whether the Company's system nuclear capacity factor
exceeds or falls below a specified range (see note 3).

Nuclear Fuel

Nuclear fuel is capitalized and charged to fuel expense on the unit of
production method. Estimated costs of nuclear fuel disposal are charged to fuel
expense as the related fuel is consumed. The Company's share of nuclear fuel at
Peach Bottom Atomic Power Station (Peach Bottom) and Salem Generating Station
(Salem) is accounted for as a capital lease. Nuclear fuel at Limerick Generating
Station (Limerick) is owned.

Depreciation and Decommissioning

The annual provision for depreciation is provided over the estimated service
lives of plant on the straight-line method. Annual depreciation provisions for
financial reporting purposes, expressed as a percent of average depreciable
utility plant in service, were approximately 2.80% in 1995, 2.77% in 1994 and
2.75% in 1993. See note 3 for information concerning the Company's petition to
the PUC for a declaratory accounting order to change the estimated depreciable
lives of certain of the Company's electric plant.

The Company's share of the 1990 estimated costs for decommissioning nuclear
generating stations currently included in electric base rates is being charged
to operations over the expected service life of the related plant. The amounts
recovered from customers are deposited in trust accounts and invested for
funding of future costs. These amounts, and investment earnings thereon, are
credited to accumulated depreciation (see note 4).

Income Taxes

The Company uses an asset and liability approach for financial accounting and
reporting of income taxes. The effects of the Alternative Minimum Tax (AMT) are
normalized. Investment Tax Credit (ITC) is deferred and amortized to income over
the estimated useful life of the related utility plant. ITC related to plant in
service, not included in rate base, is accounted for on the flow-through method
(see note 14).

Allowance for Funds Used During Construction (AFUDC)

AFUDC is the cost, during the period of construction, of debt and equity funds
used to finance construction projects. AFUDC is recorded as a charge to
Construction Work in Progress, and the credits are to Interest Charges for the
cost of borrowed funds and to Other Income and Deductions for the remainder as
the allowance for other funds. The rates used for capitalizing AFUDC, which
averaged 9.88% in 1995, 7.74% in 1994 and 9.39% in 1993, are computed under a
method prescribed by regulatory authorities. AFUDC is not included in regular
taxable income and the depreciation of capitalized AFUDC is not tax deductible.



Nuclear Outage Costs

Incremental nuclear maintenance and refueling outage costs are accrued over the
unit operating cycle. For each unit, an accrual for incremental nuclear
maintenance and refueling outage expense is estimated based upon the latest
planned outage schedule and estimated costs for the outage. Differences between
the accrued and actual expense for the outage are recorded when such differences
are known.

Capitalized Software Costs

Software projects which exceed $5 million are capitalized. At December 31,1995
and 1994, capitalized software costs totaled $50 million and $51 million (net of
$19 million and $10 million accumulated amortization), respectively. Such
capitalized amounts are amortized ratably over the expected lives of the
projects when they become operational, not to exceed ten years.

Gains and Losses on Reacquired Debt

Gains and losses on reacquired debt are deferred and amortized to interest
expense over the stated life of the reacquired debt.

Reclassifications

Certain prior-year amounts have been reclassified for comparative purposes.
These reclassifications had no effect on net income.


                                       25
<PAGE>
2. Nature of Operations and Segment Information

The Company is an operating utility which provides electric and gas service to
the public in southeastern Pennsylvania. The total area served by the Company
covers 2,107 square miles. Electric service is supplied to an area of 1,972
square miles with a population of 3.7 million, including 1.6 million in the City
of Philadelphia. Approximately 94% of the retail electric service area and 64%
of retail kilowatthour sales are in the suburbs around Philadelphia, and 6% of
the retail service area and 36% of such sales are in the City of Philadelphia.
Natural gas service is supplied to a 1,475-square-mile area of southeastern
Pennsylvania adjacent to Philadelphia with a population of 1.9 million.

<TABLE>
<CAPTION>
For the Years Ended December 31,                     1995           1994           1993
                                                                   Thousands of Dollars
<S>                                           <C>           <C>            <C>
Electric Operations
Operating revenues:
Residential                                   $ 1,401,296    $ 1,369,617    $ 1,354,061
Small commercial and industrial                   738,910        706,808        678,896
Large commercial and industrial                 1,147,190      1,142,903      1,163,997
Other                                             136,988        136,002        161,290
                                              -----------    -----------    -----------
     Service territory                          3,424,384      3,355,330      3,358,244
Interchange sales                                  17,488         23,017         14,269
Sales to other utilities                          333,454        246,450        232,912
                                              -----------    -----------    -----------
     Total operating revenues                   3,775,326      3,624,797      3,605,425
                                              -----------    -----------    -----------
Operating expenses, excluding depreciation      2,405,876      2,429,452      2,228,507
Depreciation                                      430,993        415,854        400,851
                                              -----------    -----------    -----------
     Operating income                         $   938,457    $   779,491    $   976,067
                                              ===========    ===========    ===========
Utility plant additions                       $   435,400    $   457,728    $   458,125
                                              ===========    ===========    ===========

Gas Operations
Operating revenues:
Residential                                   $    15,482    $    16,048    $    15,032
House heating                                     240,147        235,407        205,483
Commercial and industrial                         129,223        133,124        124,224
Other                                               3,639         13,971         15,172
                                              -----------    -----------    -----------
     Subtotal                                     388,491        398,550        359,911
Other revenues (including transported
     for customers)                                22,339         17,285         22,793
                                              -----------    -----------    -----------
     Total operating revenues                     410,830        415,835        382,704
                                              -----------    -----------    -----------
Operating expenses, excluding depreciation        319,127        339,529        299,259
Depreciation                                       26,261         26,247         24,101
                                              -----------    -----------    -----------
     Operating income                         $    65,442    $    50,059    $    59,344
                                              ===========    ===========    ===========
Utility plant additions                       $    63,192    $    67,090    $    72,481
                                              ===========    ===========    ===========

Identifiable Assets* at December 31,
Electric                                      $10,408,105    $10,410,461    $10,395,488
Gas                                               785,881        768,279        727,690
Nonallocable assets                             3,766,634      3,886,531      3,909,149
                                              -----------    -----------    -----------
     Total assets                             $14,960,620    $15,065,271    $15,032,327
                                              ===========    ===========    ===========
</TABLE>


*Includes utility plant less accumulated depreciation, inventories and allocated
common utility property.

                                       26
<PAGE>
3. Rate Matters

Limerick

Under its electric tariffs, the Company is recovering $285 million of deferred
Limerick costs representing carrying charges and depreciation associated with
50% of Limerick common facilities. These costs are included in base rates and
are being recovered over the life of Limerick. The Company is also recovering
$137 million of Limerick Unit No. 1 costs over a ten-year period without a
return on investment. At December 31, 1995, the unrecovered portion of these
balances were $240 million and $59 million, respectively.

Under its electric tariffs, the Company is allowed to retain for shareholders
any proceeds above the average energy cost for sales of 399 megawatts (MW) of
near-term excess capacity and/or associated energy. In addition, beginning April
1994, the Company became entitled to share in the benefits which result from the
operation of both Limerick Units No. 1 and No. 2 through the retention of 16.5%
of the energy savings, subject to certain limits. During 1995, 1994 and 1993,
the Company recorded as revenue net of fuel costs $79, $68 and $38 million,
respectively, as a result of the sale of the 399 MW of capacity and/or
associated energy and the Company's share of Limerick energy savings.

Pursuant to a PUC Declaratory Order, the Company deferred certain operating and
maintenance expenses, depreciation and accrued carrying charges on its capital
investment in Limerick Unit No. 2 and 50% of Limerick common facilities. At
December 31, 1995 and 1994, such costs included in Deferred Limerick Costs
totaled $91 million.

Petition for Declaratory Accounting Order

In October 1995, the Company filed a petition for a declaratory accounting order
with the PUC requesting approval to change the estimated depreciable lives of
certain of the Company's electric plant. The petition requests the approval to
reduce the terminal dates by ten years, for depreciation accrual purposes only,
of Limerick Units No. 1 and No. 2 and associated common facilities, to utilize
new life spans for various categories of electric production plant, and to
change remaining life estimates for transmission, distribution, general and
common plant. The petition also requests approval to amortize over a nine-year
period $331 million of deferred Limerick costs representing $240 million of
carrying charges and depreciation associated with 50% of Limerick common
facilities and $91 million of unrecovered Limerick Unit No. 2 Declaratory Order
costs. If approved, the proposed changes will increase depreciation and
amortization on assets associated with Limerick by approximately $100 million
per year and decrease depreciation and amortization on other Company assets by
approximately $10 million per year, for a net increase in depreciation and
amortization of approximately $90 million per year. The requested order will not
affect rates charged to customers. The changes would be effective October 1,
1996.

Recovery of Non-Pension Postretirement Benefits Costs

Effective January 1995, in accordance with a PUC Joint Petition, the Company
increased electric base rates by $25 million per year to recover the increased
costs, including the annual amortization of the transition obligation (over 18
years) deferred in 1994 and 1993, associated with the implementation of
Statement of Financial Accounting Standards (SFAS) No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions," (see note 7). The
Joint Petition provides that the Company will not file for an increase in retail
electric service rates before April 1, 1999, except under specified
circumstances for items such as energy cost adjustments, changes in state taxes,
changes in federal taxes, demand side management surcharges, and increases in
nuclear plant decommissioning expense or funding requirements and spent nuclear
fuel disposal expenses. Subsequent to January 1, 1995, retail electric
non-pension postretirement benefits expense in excess of the amount allowed to
be recovered under the Joint Petition may not be deferred for future rate
recovery. During 1995, the Company deposited $59.6 million in trust accounts to
fund its retail electric non-pension postretirement benefits costs. These costs
include amounts charged to operating expense or capitalized on and after January
1, 1995.

In accordance with the Joint Petition, any of the parties to the Joint Petition
may elect to void the settlement in the event current rate recovery of
non-pension postretirement benefits expense is ultimately disallowed as a result
of the Office of Consumer Advocate's appeal to the Supreme Court of Pennsylvania
of cases involving other Pennsylvania utilities. In such event, the Company
would refund to customers, with interest, any increased base rate amounts
collected.

In December 1994, the PUC approved the Company's petition for an accounting
order associated with gas utility operations permitting recognition of $2.8
million of non-pension postretirement benefits costs annually and recognition of
$1.5 million of environmental costs annually for the remediation of sites of
former manufactured gas plant facilities using a cost of removal methodology, in
exchange for a reduction in depreciation rates to reflect the results of a
current life study. During 1995, the Company deposited $3.8 million in trust
accounts to fund its gas non-pension postretirement benefits costs. The
accounting order did not result in any increase in rates to customers (see note
7).

Energy Cost Adjustment

The Company is subject to a PUC-established electric ECA which, in addition to
reconciling fuel costs and revenues, incorporates a nuclear performance standard
which allows for financial bonuses or penalties depending on whether the
Company's system nuclear capacity factor exceeds or falls below a specified
range. The bonuses or penalties are based upon average system replacement energy
costs. If the capacity factor is within the range of 60-70%, there is no bonus
or penalty. If the capacity factor exceeds the specified range, progressive
incremental bonuses are earned and, if the capacity factor falls below the
specified range, progressive incremental penalties are incurred.

For the year ended December 31, 1995, the Company's system nuclear capacity
factor was 72%, for which the Company recorded an immaterial bonus in 1995
income. The Company-operated units performed at a capacity factor of 88%, but
the overall factor was adversely affected by the Salem shutdown (see note 24).
For the years ended December 31, 1994 and 1993, the Company's system nuclear
capacity factors were 82% and 78%, respectively, which entitled the Company to
bonuses reflected in 1994 and 1993 income of $14 and $10 million, respectively.

                                       27


<PAGE>
4. Commitments and Contingencies

Construction Expenditures

Construction expenditures are estimated to be $538 million for 1996 and $1.2
billion for the period 1997 to 1999. For the period 1996 to 1999, the Company
expects that all of its capital needs will be provided through internally
generated funds. Construction expenditure estimates are reviewed and revised
periodically to reflect changes in economic conditions, revised load forecasts
and other appropriate factors. Certain facilities under construction and to be
constructed may require permits and licenses which the Company has no assurance
will be granted.

The Company's operations have in the past and may in the future require
substantial capital expenditures in order to comply with environmental laws.

Nuclear Insurance

The Price-Anderson Act sets the limit of liability of approximately $8.9 billion
for claims that could arise from an incident involving any licensed nuclear
facility in the nation. The limit is subject to change to reflect the effects of
inflation and changes in the number of licensed reactors. All utilities with
nuclear generating units, including the Company, have obtained coverage for
these potential claims through a combination of private insurances of $200
million and mandatory participation in a financial protection pool. Under the
Price-Anderson Act, all nuclear reactor licensees can be assessed up to $79
million per reactor per incident, payable at no more than $10 million per
reactor per incident per year. This assessment is subject to inflation and state
premium taxes. In addition, Congress could impose revenue raising measures on
the nuclear industry to pay claims.

Although the Nuclear Regulatory Commission (NRC) requires the maintenance of
property insurance on nuclear power plants in the amount of $1.06 billion or the
amount available from private sources, whichever is less, the Company maintains
coverage in the amount of its $2.75 billion proportionate share for each
station. The Company's insurance policies provide coverage for decontamination
liability expense, premature decommissioning and loss or damage to its nuclear
facilities. In the event of an accident, insurance proceeds must first be used
for reactor stabilization and site decontamination. If the decision is made to
decommission the facility, a portion of the insurance proceeds will be allocated
to a fund which the Company is required by the NRC to maintain to provide for
decommissioning the facility. The Company is unable to predict the timing of the
availability of insurance proceeds to the Company for the Company's bondholders,
and the amount of such proceeds which would be available. Under the terms of the
various insurance agreements, the Company could be assessed up to $46 million
for losses incurred at any plant insured by the insurance companies. The Company
is self-insured to the extent that any losses may exceed the amount of insurance
maintained. Any such losses, if not recovered through the ratemaking process,
could have a material adverse effect on the Company's financial condition and
results of operations.

The Company is a member of an industry mutual insurance company which provides
replacement power cost insurance in the event of a major accidental outage at a
nuclear station. The premium for this coverage is subject to assessment for
adverse loss experience. The Company's maximum share of any assessment is $14
million per year.

Nuclear Decommissioning and Spent Fuel Storage

As a component of the PUC's April 19, 1990 electric base rate order, the PUC
recognized a revised decommissioning cost estimate based upon total cost. The
Company's share of this revised cost is $643 million expressed in 1990 dollars
to be collected over the life of each generating unit. Under current rates, the
Company collects and expenses approximately $20 million annually from customers
for decommissioning the Company's nuclear units. The expense is accounted for as
a component of depreciation expense and accumulated depreciation. At December
31, 1995, $216 million was included in accumulated depreciation. In order to
fund future decommissioning costs, the Company has recorded $223 million in
trust accounts which are included as an Investment in the Company's Consolidated
Balance Sheet and include both net realized and unrealized gains. At December
31, 1995, net realized gains of $9 million were recognized as Other Income in
the Company's Consolidated Statement of Income and net unrealized gains of $19
million were recognized as a Deferred Credit in the Company's Consolidated
Balance Sheet. The most recent estimate of the Company's share of the cost to
decommission its nuclear units is approximately $1.2 billion in 1995 dollars.
Any increase in the 1990 decommissioning cost estimate being recovered in base
rates is to be recoverable in the Company's next base rate case. As a result,
the Company expects to receive recovery of a higher level of decommissioning
expense in its next base rate proceeding.

The Financial Accounting Standards Board (FASB) is currently reviewing the
accounting for closure and removal costs of production facilities including the
recognition, measurement and classification of decommissioning costs for nuclear
generating stations, and will issue an Exposure Draft in 1996. The Company will
review the Exposure Draft to determine the effect on its financial condition and
results of operations. If current electric utility industry accounting practices
for decommissioning are changed, annual provisions for decommissioning could
increase and the estimated cost for decommissioning could be recorded as a
liability rather than as accumulated depreciation with recognition of an
increase in the cost of the related asset.

Under the Nuclear Waste Policy Act of 1982 (NWPA), the U.S. Department of Energy
(DOE) is required to begin taking possession of all spent nuclear fuel generated
by the Company's nuclear units for long-term storage by no later than 1998.
Under the NWPA, the DOE is authorized to assess utilities for the cost of
nuclear fuel disposal. The current cost of such disposal is one mill ($.001) per
kilowatthour of net nuclear generation. The fee may be adjusted prospectively in
order to ensure full cost recovery.

The DOE has stated that it is under no legal obligation to begin accepting spent
fuel absent an operational repository or other facility constructed under the
NWPA. The DOE acknowledges, however, that it may have created the expectation of
such a commitment on the part of utilities by issuing certain regulations and
projected waste acceptance schedules. In June 1994, a number of utilities and
state agencies, including the PUC, filed a lawsuit against the DOE seeking a
determination of the DOE's legal obligation to accept fuel by 1998. The DOE has
stated that it will not be able to open a permanent, high-level nuclear waste
storage facility until 2015, at the earliest. The DOE stated that the delay was
a result of federal budget cuts, the DOE seeking new data about the suitability
of the proposed repository site at Yucca

                                       28

<PAGE>
4. Commitments and Contingencies (Continued)

Mountain, Nevada, opposition to this location for the repository and the DOE's
revision of its civilian nuclear waste program. The DOE stated that it would
seek legislation from Congress for the construction of a temporary storage
facility which would accept spent nuclear fuel from utilities in 1998 or soon
thereafter. Although progress is being made at Yucca Mountain and several
communities have expressed interest in providing a temporary storage site, the
Company cannot predict when the temporary storage facilities or permanent
repository will become available. The DOE is exploring options to address delays
in the currently projected waste acceptance schedules which include offsetting a
portion of the financial burden associated with the costs of continued on-site
storage of spent fuel after 1998 and the issuance by the DOE to utilities of
multi-purpose canisters for on-site storage.

Peach Bottom and Limerick have on-site facilities with the capacity to store
spent nuclear fuel discharged from the units through the early 2000s.
Life-of-plant storage capacity could be provided by the construction of on-site
dry cask storage facilities. Salem has recently expanded spent fuel storage
capacity through 2008 for Unit No. 1 and 2012 for Unit No. 2. Public Service
Electric and Gas (PSE&G) is the operator of Salem, which is 42.59% owned by the
Company.

The Company is currently recovering in rates costs for nuclear decommissioning
and decontamination and spent fuel storage. The Company believes that the
ultimate costs of decommissioning and decontamination and spent fuel disposal
will continue to be recoverable through rates, although such recovery is not
assured.

Energy Purchases

In the ordinary course of business, the Company enters into commitments to buy
and sell energy. During 1995, the Company entered into a long-term agreement to
purchase 300 MW in 1996 through 2000. At December 31, 1995, these purchases
result in commitments of approximately $44 million for 1996, $45 million for
1997, $48 million for 1998, $51 million for 1999 and $52 million for 2000. These
purchases will be utilized through a combination of sales to jurisdictional
customers, long-term sales to other utilities and spot sales.

Environmental Issues

The Company's operations have in the past and may in the future require
substantial capital expenditures in order to comply with environmental laws.
Additionally, under federal and state environmental laws, the Company is
generally liable for the costs of remediating environmental contamination of
property now or formerly owned by the Company and of property contaminated by
hazardous substances generated by the Company. The Company owns or leases a
number of real estate parcels, including parcels on which its operations or the
operations of others may have resulted in contamination by substances which are
considered hazardous under environmental laws. The Company is currently involved
in a number of proceedings relating to sites where hazardous substances have
been deposited and may be subject to additional proceedings in the future.

The Company has identified 23 sites where former manufactured gas plant
activities may have resulted in site contamination. Past activities at several
sites have resulted in actual site contamination. The Company is presently
engaged in performing various levels of activities at these sites, including
initial evaluation to determine the existence and nature of the contamination,
detailed evaluation to determine the extent of the contamination and the
necessity and possible methods of remediation, and implementation of
remediation. Seven of the sites are currently in the detailed evaluation or
remediation stage.

As of December 31, 1995 and 1994, the Company had accrued $27 and $24 million,
respectively, for environmental investigation and remediation costs that
currently can be reasonably estimated. The PUC approved the recognition of $1.5
million of environmental costs annually for the remediation of sites of former
manufactured gas plant facilities effective January 1, 1995 (see note 3). The
Company cannot currently predict whether it will incur other significant
liabilities for additional investigation and remediation costs at these or
additional sites identified by the Company, environmental agencies or others, or
whether all such costs will be recoverable through rates or from third parties.

Litigation

The Company is involved in litigation, the ultimate outcome of which, while
uncertain, is not expected to have a material adverse effect on the Company's
financial condition or results of operations.

5. Changes in Accounting

In March 1995, the FASB issued SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of," which requires
that long-lived assets and certain identifiable intangibles held and used by an
entity be reviewed for impairment whenever events or changes in circumstances
indicate that the carrying amount of an asset may not be recoverable. The new
standard is effective for fiscal years beginning after December 15, 1995. The
Company will adopt SFAS No. 121 in the first quarter of 1996. Upon adoption, the
Company does not expect SFAS No. 121 to have an effect upon the Company's
financial condition or results of operations.

In October 1995, the FASB issued SFAS No. 123, "Accounting for Stock-Based
Compensation," which encourages entities to recognize compensation costs for
stock-based employee compensation plans using the fair value based method of
accounting defined in SFAS No. 123, but allows for the continued use of the
intrinsic value based method of accounting prescribed by Accounting Principles
Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees." Entities
electing to continue with the accounting prescribed by APB Opinion No. 25 are
required to disclose pro forma net income and earnings per share as if the fair
value based method of accounting had been applied. The new standard is effective
for fiscal years beginning after December 15, 1995. The Company will adopt SFAS
No. 123 in the first quarter of 1996, but will continue to use the intrinsic
value based method of accounting prescribed by APB Opinion No. 25 supplemented
by SFAS No. 123's required footnote disclosures. Adoption of SFAS No. 123 will
not have an effect upon the Company's financial condition or results of
operations.

                                       29
<PAGE>
6. Retirement Benefits

The Company and its subsidiaries have a non-contributory trusteed retirement
plan applicable to all regular employees. The benefits are based primarily upon
employees' years of service and average earnings prior to retirement. The
Company's funding policy is to contribute, at a minimum, amounts sufficient to
meet the Employee Retirement Income Security Act requirements. Approximately
74%, 85% and 71% of pension costs were charged to operations in 1995, 1994 and
1993, respectively, and the remainder, associated with construction labor, to
the cost of new utility plant.

Pension costs for 1995, 1994 and 1993 included the following components:

<TABLE>
<CAPTION>
                                                         1995          1994          1993
                                                                     Thousands of Dollars
<S>                                                <C>           <C>           <C>
Service cost - benefits earned during the period    $  19,710     $  33,403     $  33,673
Interest cost on projected benefit obligation         147,261       136,690       134,658
Actual return on plan assets                         (456,057)       12,946      (226,240)
Amortization of transition asset                       (4,538)       (4,538)       (4,538)
Amortization and deferral                             300,214      (161,955)       87,733
                                                    ---------     ---------     ---------
     Net pension cost                               $   6,590     $  16,546     $  25,286
                                                    =========     =========     =========
</TABLE>


The changes in net periodic pension costs in 1995, 1994 and 1993 were as
follows:

<TABLE>
<CAPTION>
                                                          1995        1994        1993
                                                                  Thousands of Dollars
<S>                                                    <C>       <C>          <C>
Change in number, characteristics and salary levels
     of participants and net actuarial gain            $ 1,486     $(6,004)    $  (756)
Change in plan provisions                               (8,305)     (1,777)        --
Change in actuarial assumptions                         (3,136)       (959)        --
                                                       -------     -------     ------- 
        Net change                                     $(9,955)    $(8,740)    $  (756)
                                                       =======     =======     ======= 
</TABLE>

Plan assets consist principally of common stock, U.S. government obligations and
other fixed income instruments. In determining pension costs, the assumed
long-term rate of return on assets was 9.5% for 1995, 1994 and 1993.

The weighted-average discount rate used in determining the actuarial present
value of the projected benefit obligation was 7.25% at December 31, 1995, 8.25%
at December 31, 1994, and 7% at December 31, 1993. The average rate of increase
in future compensation levels ranged from 4% to 6% at December 31, 1995, from
4.25% to 6.25% at December 31, 1994, and from 4% to 6% at December 31, 1993.

Prior service cost is amortized on a straight-line basis over the average
remaining service period of employees expected to receive benefits under the
plan.

The funded status of the plan at December 31, 1995 and 1994 is summarized as
follows:

<TABLE>
<CAPTION>
                                                                            1995            1994
                                                                            Thousands of Dollars
<S>                                                                <C>             <C> 
Actuarial present value of accumulated plan benefit obligations:
Vested benefit obligation                                           $(1,746,685)    $(1,505,552)
Accumulated benefit obligation                                       (1,838,661)     (1,632,666)

Projected benefit obligation for services rendered to date          $(2,097,300)    $(1,814,209)
Plan assets at fair value                                             2,088,950       1,741,271
                                                                    -----------     ----------- 
     Funded status                                                       (8,350)        (72,938)
Unrecognized transition asset                                           (44,789)        (49,327)
Unrecognized prior service costs                                         68,223          73,338
Unrecognized net gain                                                  (265,472)       (230,105)
                                                                    -----------     ----------- 
     Pension liability                                              $  (250,388)    $  (279,032)
                                                                    ===========     =========== 
</TABLE>

                                       30
<PAGE>
7. Non-Pension Postretirement Benefits

The Company provides certain health care and life insurance benefits for retired
employees. Company employees become eligible for these benefits if they retire
from the Company with ten years of service. These benefits and similar benefits
for active employees are provided by an insurance company whose premiums are
based upon the benefits paid during the year.

The transition obligation resulting from the adoption of SFAS No. 106 was $505
million at January 1, 1993, which represented the previously unrecognized
accumulated non-pension postretirement benefit obligation. The transition
obligation is being amortized on a straight-line basis over an allowed 20-year
period. As a result of the Voluntary Retirement Incentive Program (VRIP) and the
Voluntary Separation Incentive Program (VSIP), the Company accelerated
recognition of $177 million of its non-pension postretirement benefits
obligation (see note 22). Effective January 1, 1995, the Company was permitted
by the PUC to recover non-pension postretirement benefits costs associated with
the Company's retail electric and gas operations, including the annual
amortization of the transition obligation (over 18 years) deferred in 1994 and
1993 (see note 3).

The transition obligation was determined by application of the terms of medical,
dental and life insurance plans, including the effects of established maximums
on covered costs, together with relevant actuarial assumptions and health care
cost trend rates, which are projected to range from 9% in 1996 to 5% in 2002.
The effect of a 1% annual increase in these assumed cost trend rates would
increase the accumulated postretirement benefit obligation by $63 million and
the annual service and interest costs by $7 million.

Total costs for all plans amounted to $71, $81 and $83 million in 1995, 1994 and
1993, respectively.

The net periodic benefits costs for 1995 and 1994 included the following
components:

<TABLE>
<CAPTION>
                                                        1995         1994
                                                     Thousands of Dollars

<S>                                                 <C>          <C>     
Service cost - benefits earned during the period    $  8,681     $ 17,056
Interest cost on projected benefit obligation         48,641       41,196
Amortization of the transition obligation             14,882       22,659
Actual return on plan assets                          (2,075)        --
Deferred asset gain                                    1,359         --
                                                    --------     --------
     Net periodic postretirement benefits costs     $ 71,488     $ 80,911
                                                    ========     ========
</TABLE>


The funded status of the plan at December 31, 1995 and 1994 is summarized as
follows:

<TABLE>
<CAPTION>
                                                                                    1995          1994
                                                                                  Thousands of Dollars
<S>                                                                            <C>           <C>      
Accumulated postretirement benefit obligation:
Retirees                                                                       $ 628,804     $ 566,128
Fully eligible active plan participants                                            4,199         7,895
Other active plan participants                                                    41,863        16,006
                                                                               ---------     ---------
     Total                                                                       674,866       590,029
Plan assets at fair value                                                        (66,735)       (1,200)
                                                                               ---------     ---------
     Accumulated postretirement benefit obligation in excess of plan assets      608,131       588,829
Unrecognized transition obligation                                              (252,990)     (267,871)
Unrecognized net gain                                                            (28,890)       33,500
                                                                               ---------     ---------
     Accrued postretirement benefits cost recognized on the balance sheet      $ 326,251     $ 354,458
                                                                               =========     =========
</TABLE>

Measurement of the accumulated postretirement benefits obligation was based on a
7.5% and 8.5% assumed discount rate as of December 31, 1995 and 1994,
respectively.


                                       31

<PAGE>

8. Accounts Receivable

Accounts receivable at December 31, 1995 and 1994 included unbilled operating
revenues of $148 and $100 million, respectively. Accounts receivable at December
31, 1995 and 1994 were net of an allowance for uncollectible accounts of $21 and
$17 million, respectively.

The Company is party to an agreement with a financial institution whereby it can
sell on a daily basis and with limited recourse an undivided interest in up to
$425 million of designated accounts receivable until November 14, 2000. At
December 31, 1995 and 1994, the Company had sold a $425 million and $325 million
interest in accounts receivable, respectively. The Company retains the servicing
responsibility for these receivables.

By terms of this agreement, under certain circumstances, a portion of deferred
Limerick costs may be included in the pool of eligible receivables. At December
31, 1995, $30 million of deferred Limerick costs were included in the pool of
eligible receivables.

9. Common Stock

At December 31, 1995 and 1994, common stock without par value consisted of
500,000,000 shares authorized and 222,172,216 and 221,608,984 shares
outstanding, respectively. At December 31, 1995, there were 5,800,841 shares
reserved for issuance under the dividend reinvestment and stock purchase plan.

The Company maintains a Long-Term Incentive Plan (LTIP) for certain full-time
salaried employees of the Company. The types of long-term incentive awards which
may be granted under the LTIP are non-qualified options to purchase shares of
the Company's common stock, dividend equivalents and shares of restricted common
stock. Pursuant to the LTIP, 2,591,765 shares of stock were authorized for
issuance upon exercise of options at December 31, 1995.

The following table summarizes option activity during 1995, 1994 and 1993:
<TABLE>
<CAPTION>
                                     1995           1994           1993
<S>                             <C>            <C>            <C>      
Balance at January 1            2,651,397      1,961,882      2,445,833
Options granted                   850,700        909,000        533,800
Options exercised                (561,232)       (90,885)      (981,551)
Options cancelled                (349,100)      (128,600)       (36,200)
                                ---------      ---------      ---------
     Balance at December 31     2,591,765      2,651,397      1,961,882
                                =========      =========      =========

Exercisable at December 31      1,813,565      1,865,397      1,447,282
                                =========      =========      =========
</TABLE>

Options were exercised at average option prices of $23.91 per share, $22.91 per
share and $22.66 per share in 1995, 1994 and 1993, respectively. The average
exercise prices of shares under option were $26.16 per share, $26.73 per share
and $25.12 per share at December 31, 1995, 1994 and 1993, respectively.

                                       32
<PAGE>
10. Preferred and Preference Stock

At December 31, 1995 and 1994, Series Preference Stock consisted of 100,000,000
shares authorized, of which no shares were outstanding. At December 31, 1995 and
1994, cumulative Preferred Stock, no par value, consisted of 15,000,000 shares
authorized.
<TABLE>
<CAPTION>
                                       Current                   Shares                       Amount
                                    Redemption                Outstanding               Thousands of Dollars
                                     Price (a)            1995           1994           1995            1994
<S>                                     <C>            <C>            <C>           <C>              <C>    
Series (without mandatory redemption)
$4.68                                   104.00         150,000        150,000       $ 15,000         $15,000
$4.40                                   112.50         274,720        274,720         27,472          27,472
$4.30                                   102.00         150,000        150,000         15,000          15,000
$3.80                                   106.00         300,000        300,000         30,000          30,000
$7.96(b)                                   (c)         618,954      1,400,000         61,895         140,000
$7.48                                      (d)         500,000        500,000         50,000          50,000
                                                     ---------      ---------        -------         -------
                                                     1,993,674      2,774,720        199,367         277,472
Series (with mandatory redemption)(e)
$6.12                                      (f)         927,000        927,000         92,700          92,700
                                                     ---------      ---------       --------        --------
     Total preferred stock                           2,920,674      3,701,720       $292,067        $370,172
                                                     =========      =========       ========        ========
<FN>
(a)  Redeemable, at the option of the Company, at the indicated dollar amounts
     per share, plus accrued dividends.
(b)  Ownership of this series of preferred stock is evidenced by depositary
     receipts, each representing one-fourth of a share of preferred stock. On
     December 19, 1995, the Company issued Series B Company Obligated
     Mandatorily Redeemable Preferred Securities of a Partnership in exchange
     for 3,124,183 depositary receipts, which together with the underlying 7.96%
     cumulative preferred stock, were cancelled (see note 11).
(c)  None of the shares of this series are subject to redemption prior to
     October 1,1997.
(d)  None of the shares of this series are subject to redemption prior to April
     1, 2003.
(e)  There are no annual sinking fund requirements in the period 1996-1998.
     Annual sinking fund requirements in 1999 are $18,540,000.
(f)  None of the shares of this series are subject to redemption prior to August
     1, 1999.
</FN>
</TABLE>

11. Company Obligated Mandatorily Redeemable Preferred Securities of a
    Partnership (COMRPS)

At December 31, 1995 and 1994, PECO Energy Capital, L.P. (Partnership), a
Delaware limited partnership of which a wholly owned subsidiary of the Company
is the sole general partner, had outstanding two series of cumulative COMRPS,
each with a liquidation value of $25 per security. Each series is supported by
the Company's deferrable interest subordinated debentures, held by the
Partnership, which bear interest at rates equal to the distribution rates on the
securities. The interest paid by the Company on the debentures is included in
Interest Charges in the Consolidated Statements of Income and is deductible for
income tax purposes.

<TABLE>
<CAPTION>
                                                     Shares                      Amount
                      Distribution                Outstanding              Thousands of Dollars
At December 31,           Rate               1995            1994           1995         1994
<S>                      <C>            <C>             <C>             <C>          <C>     
Series
A                        9.00%          8,850,000       8,850,000       $221,250     $221,250
B (a)                    8.72%          3,124,183           --            81,032        --
                                       ----------       ---------       --------     --------
     Total                             11,974,183       8,850,000       $302,282     $221,250
                                       ==========       =========       ========     ========
<FN>
(a)  On December 19, 1995, the Company exchanged Trust Receipts, each
     representing a 8.72% COMRPS, Series B, representing limited partnership
     interests, for depositary shares each representing a one-fourth interest in
     a share of $7.96 Cumulative Preferred Stock of the Company. The premium
     paid on the exchange is being accreted over the contractual life of the
     COMRPS. The Trust Receipts were issued by PECO Energy Capital Trust I, the
     sole assets of which are 8.72% COMRPS, Series B. Each holder of Trust
     Receipts is entitled to withdraw the corresponding number of 8.72% COMRPS,
     Series B from the Trust in exchange for the Trust Receipts so held.
</FN>
</TABLE>

                                       33
<PAGE>
12. Long-Term Debt

<TABLE>
<CAPTION>
At December 31,                                          Series          Due         1995            1994
                                                                                     Thousands of Dollars
<S>                                           <C>                <C>          <C>             <C>
First and refunding mortgage bonds (a)                   6-1/8%         1997      $75,000         $75,000
                                                         5-3/8%         1998      225,000         225,000
                                                  7-1/2%-9-1/4%         1999      325,000         325,000
                                                            10%         2000         --            30,069
                                                      5-5/8%-8%    2001-2005    1,355,000       1,355,000
                                                        10-1/4%    2006-2010       48,750          52,813
                                                            (b)    2011-2015      154,200         154,200
                                                 8-7/8%-10-1/2%    2016-2020       34,000         203,431
                                                  6-5/8%-8-3/4%    2021-2024    1,607,130       1,607,130
                                                                               ----------      ----------
     Total first and refunding mortgage bonds                                   3,824,080       4,027,643
Notes payable - banks                                       (c)    1996-1998      167,000         167,000
Revolving credit and term loan agreements                   (d)    1996-1997      350,000         525,000
Pollution control notes                                     (e)    1996-2029      169,005         161,465
Medium-term notes                                           (f)    1996-2005      121,800         134,200
Sinking fund debentures -
     PECO Energy Power Company, a subsidiary             4-1/2%         1995         --             9,750
Unamortized debt discount and premium, net                                        (32,599)        (38,214)
                                                                               ----------      ----------
     Total long-term debt                                                       4,599,286       4,986,844
Due within one year (g)                                                           401,003         201,213
                                                                               ----------      ----------
     Long-term debt included in capitalization (h)                             $4,198,283      $4,785,631
                                                                               ==========      ==========
<FN>
(a)  Utility plant is subject to the lien of the Company's mortgage.
(b)  Floating rates, which were an average annual interest rate of 3.295% at
     December 31,1995.
(c)  The Company has entered into interest rate swap agreements to fix the
     effective interest rates on these notes. At December 31, 1995 and 1994, the
     Company had two interest rate swap agreements outstanding with commercial
     banks, for a total notional principal amount of $167 million, respectively.
     These agreements are subject to performance by the commercial banks, which
     are counterparties to the interest rate swaps. The Company does not
     anticipate nonperformance by the counterparties. The average annual
     interest rate for these notes, giving effect to the interest rate swaps,
     was 10.51% at December 31,1995.
(d)  On October 3, 1994, borrowings by the Company under its $525 million
     revolving credit and term loan agreement with a group of banks converted to
     a term loan. The loan was due in six semi-annual installments commencing
     April 3, 1995. During 1995, $175 million was retired; $175 million was
     refinanced with another group of banks under a new term loan agreement and
     $175 million was outstanding at December 31, 1995. The average annual rate
     for the $175 million outstanding under the original revolving credit and
     term loan agreement was 6.416% and the average rate for the $175 million
     outstanding under the new term loan was 6.081% at December 31, 1995. The
     Company also has a $400 million revolving credit and term loan agreement
     with a group of banks which terminates in 2000. There is an annual
     commitment fee of 0.125% on the unused amount. At December 31, 1995, no
     amount was outstanding under this agreement.
(e)  Floating rates, which were an average annual interest rate of 3.728% at
     December 31,1995.
(f)  Medium-term notes collateralized by mortgage bonds. The average annual
     interest rate was 8.413% at December 31,1995.
(g)  Long-term debt maturities, including mandatory sinking fund requirements,
     in the period 1997-2000 are as follows: 1997 - $266,063,000; 1998 -
     $241,463,000; 1999 - $359,063,000; 2000 - $22,603,000.
(h)  The annualized interest on long-term debt at December 31, 1995, was $327
     million, of which $281 million was associated with mortgage bonds and $46
     million was associated with other long-term debt.
</FN>
</TABLE>

                                       34
<PAGE>

13. Short-Term Debt

<TABLE>
<CAPTION>
                                                       1995            1994            1993
        Thousands of Dollars
<S>                                               <C>          <C>             <C>
Average borrowings                                 $ 17,560     $   130,539     $   113,193
Average interest rates, computed on daily basis        6.25%          4.03%           3.35%
Maximum borrowings outstanding                     $182,000     $   418,600     $   368,400
Average interest rates, at December 31                  --%           6.73%           3.45%
</TABLE>

The Company has a $300 million commercial paper program which is supported by
the $400 million revolving credit agreement discussed in note 12; at December
31, 1995, no amounts were outstanding. At December 31, 1995, the Company had
formal and informal lines of credit with banks aggregating $221 million. No
short-term debt was outstanding against these lines at that date. During 1995,
the Company discontinued its compensating balance arrangements for these credit
lines.

14. Income Taxes

<TABLE>
<CAPTION>
For the Years Ended December 31,                 1995          1994          1993
                                                             Thousands of Dollars
<S>                                        <C>          <C>            <C>
Included in operating income:
Federal
     Current                                $ 170,042     $ 164,472     $ 117,535
     Deferred                                 159,970        (2,691)      113,054
     Investment tax credit, net               (21,679)       28,006        43,344
State
     Current                                   72,177        77,754        70,740
     Deferred                                  16,387       (33,508)        9,718
                                            ---------     ---------     ---------
                                              396,897       234,033       354,391
                                            ---------     ---------     ---------
Included in other income and deductions:
Federal
     Current                                   20,754         1,989        (3,650)
     Deferred                                   7,556         9,722        15,926
State
     Current                                    6,909           409        (1,615)
     Deferred                                    (399)        3,171         1,147
                                            ---------     ---------     ---------
                                               34,820        15,291        11,808
                                            ---------     ---------     ---------
     Total                                  $ 431,717     $ 249,324     $ 366,199
                                            =========     =========     =========
</TABLE>

In accordance with SFAS No. 109, "Accounting for Income Taxes," the Company has
recorded an accumulated net deferred income tax liability and pursuant to SFAS
No. 71, "Accounting for the Effects of Certain Types of Regulation," a
corresponding recoverable deferred income tax asset of $2.1 billion at December
31, 1995 and 1994.

The accumulated net deferred income tax liability reflects the tax effect of
anticipated revenues and reverses as the related temporary differences reverse
over the life of the related depreciable assets concurrent with the recovery of
their cost in rates. Also included in the accumulated deferred income tax
liability are other accumulated deferred income taxes, principally associated
with liberalized tax depreciation, established in accordance with the ratemaking
policies of the PUC based on flow-through accounting.

The Internal Revenue Service (IRS) has completed and settled its examinations of
the Company's federal income tax returns through 1986. The 1987 through 1990
federal income tax returns have been examined and the IRS subsequently issued an
assessment that the Company has appealed. The Company does not expect the
ultimate resolution of the assessment and its appeal to have a material effect
upon the Company's financial condition or results of operations.

ITC and other general business credits were fully utilized for tax purposes at
December 31, 1994 and reduced federal income taxes currently payable by $43 and
$60 million in 1994 and 1993, respectively.

At December 31, 1995, the Company had an AMT credit of $76 million available for
an indefinite carryforward period against future federal income taxes payable to
the extent that regular federal income taxes payable exceeds the AMT payable.

                                       35

<PAGE>

The tax effect of temporary differences which gives rise to the Company's net
deferred tax liability as of December 31,1995 and 1994 are as follows: 

<TABLE>
<CAPTION>
                                                     Liability or (Asset)

                                                       1995         1994
                                                     Millions of Dollars
<S>                                                 <C>        <C> 
Nature of temporary difference
Utility plant
     Accelerated depreciation                       $ 1,387     $ 1,377
     Deferred ITC                                       351         374
     AMT credits                                        (84)       (176)
Other plant related temporary differences             1,283       1,305
Taxes recoverable through future rates, net             857         882
Deferred debt refinancing costs                         130         132
Other, net                                             (243)       (306)
                                                    -------     -------
     Deferred income taxes per the balance sheet    $ 3,681     $ 3,588
                                                    =======     =======
</TABLE>

The net deferred tax liability shown above as of December 31, 1995 and 1994 is
comprised of $4.053 and $4.127 billion of deferred tax liabilities, partly
offset by $372 and $539 million of deferred tax assets, respectively.

Amendments to Pennsylvania tax law changed the corporate income tax rate from
12.25% to 11.99% for 1994 and 9.99% for 1995 and thereafter. This change
resulted in a $6 and $2 million decrease in Income Taxes in the Consolidated
Statements of Income for the years ended December 31, 1995 and 1994,
respectively. These changes also resulted in a $174 million decrease in the
Deferred Income Taxes liability on the December 31, 1994 Consolidated Balance
Sheet. The decrease in the Deferred Income Taxes liability is returned to
customers through the State Tax Adjustment Clause in the year realized.

The Omnibus Budget Reconciliation Act of 1993 changed the federal income tax
rate for corporations to 35% from 34%, effective January 1, 1993. This change
resulted in a $107 million increase in the Deferred Income Taxes liability and
regulatory asset in 1993, and is included in the December 31, 1995 and 1994
Consolidated Balance Sheets. The Company expects to receive recovery of all
taxes when paid.

Provisions for deferred income taxes consist of the tax effects of the following
timing differences:

<TABLE>
<CAPTION>
                                                                   1995          1994          1993
                                                                                Thousands of Dollars
<S>                                                           <C>           <C>           <C>      
Depreciation and amortization                                 $  32,287     $  85,772     $  78,324
Deferred energy costs                                            30,073        13,777        19,013
Retirement and separation programs                               15,733       (82,008)         --
Incremental nuclear maintenance and refueling outage costs        8,079        (2,751)         (827)
Uncollectible accounts                                           (1,991)      (23,096)          625
Reacquired debt                                                  (3,266)      (12,954)       28,959
Unrecovered revenue                                                  (5)       (2,239)         (806)
Environmental clean-up costs                                      2,433        (3,949)       (2,479)
Obsolete inventory                                                6,362        (6,192)       (6,887)
Limerick plant disallowances and phase-in plan                    2,507        12,894        17,073
AMT credits                                                      91,399          --            --
Other                                                               (97)       (2,560)        6,850
                                                              ---------     ---------     ---------
     Total                                                    $ 183,514     $ (23,306)    $ 139,845
                                                              =========     =========     =========
</TABLE>

                                       36
<PAGE>
14. Income Taxes (Continued)

The total income tax provisions differed from amounts computed by applying the
federal statutory tax rate to income and adjusted income before income taxes as
shown below:

<TABLE>
<CAPTION>
                                                                 1995             1994             1993
                                                                                   Thousands of Dollars
<S>                                                       <C>              <C>              <C>        
Net income                                                $   609,732      $   426,713      $   590,648
Total income tax provisions                                   431,717          249,324          366,199
                                                          -----------      -----------      -----------
     Income before income taxes                             1,041,449          676,037          956,847
Deduct: allowance for funds used during construction           27,050           22,169           23,774
                                                          -----------      -----------      -----------
     Adjusted income before income taxes                  $ 1,014,399      $   653,868      $   933,073
                                                          ===========      ===========      ===========

Income taxes on above at federal statutory rate of 35%    $   355,040      $   228,854      $   326,576
Increase (decrease) due to:
Depreciation timing differences not normalized                 14,127           12,767            9,721
Limerick plant disallowances and phase-in plan                   (736)            (530)           5,094
State income taxes, net of federal income tax benefits         61,799           31,086           51,994
Amortization of ITC                                           (13,604)         (14,570)         (13,470)
Prior period income taxes                                       1,791          (14,524)          (3,942)
Other, net                                                     13,300            6,241           (9,774)
                                                          -----------      -----------      -----------
     Total income tax provisions                          $   431,717      $   249,324      $   366,199
                                                          ===========      ===========      ===========

Provisions for income taxes as a percent of:
Income before income taxes                                       41.5%            36.9%            38.3%
Adjusted income before income taxes                              42.6%            38.1%            39.2%
</TABLE>

15. Taxes, Other Than Income - Operating

<TABLE>
<CAPTION>
For the Years Ended December 31,   1995        1994        1993
                                           Thousands of Dollars
<S>                            <C>         <C>         <C>     
Gross receipts                 $165,172    $160,704    $155,407
Capital stock                    42,444      39,957      38,990
Real estate                      71,600      77,571      71,445
Payroll                          30,109      31,556      31,490
Other                             4,746       1,901         800
                               --------    --------    --------
     Total                     $314,071    $311,689    $298,132
                               ========    ========    ========
</TABLE>
16. Leases

Leased property included in Utility Plant at December 31, was as follows:

<TABLE>
<CAPTION>
                                 1995          1994
                               Thousands of Dollars
<S>                         <C>           <C>      
Nuclear fuel                $ 494,051     $ 445,338
Electric plant                  2,076         2,110
                            ---------     ---------
Gross leased property         496,127       447,448
Accumulated amortization     (315,702)     (272,883)
                            ---------     ---------
  Net leased property       $ 180,425     $ 174,565
                            =========     =========
</TABLE>

The nuclear fuel obligation is amortized as the fuel is consumed. Amortization
of leased property totaled $43, $62 and $58 million for the years ended December
31, 1995, 1994 and 1993, respectively. Other operating expenses included
interest on capital lease obligations of $10, $7 and $8 million in 1995,1994 and
1993, respectively.

                                       37
<PAGE>
16. Leases (Continued)

Minimum future lease payments as of December 31, 1995 were:

<TABLE>
<CAPTION>
For the Year Ending December 31,                 Capital Leases   Operating Leases               Total
                                                                                  Thousands of Dollars
<S>                                                    <C>                <C>                 <C>     
1996                                                   $ 56,403           $ 51,226            $107,629
1997                                                     58,234             50,503             108,737
1998                                                     52,094             46,821              98,915
1999                                                     23,906             44,549              68,455
2000                                                     10,839             43,688              54,527
Remaining years                                             777            557,441             558,218
                                                      ---------           --------            --------
     Total minimum future lease payments              $ 202,253           $794,228            $996,481
                                                      ---------           ========            ========
Imputed interest (rates ranging from 6.0% to 17.0%)     (21,828)
                                                      ---------
Present value of net minimum future lease payments     $180,425
                                                       ========
</TABLE>

Rental expense under operating leases totaled $115, $101 and $99 million in
1995, 1994 and 1993, respectively.

17. Jointly Owned Electric Utility Plant

The Company's ownership interests in jointly owned electric utility plant at
December 31, 1995 were as follows:

<TABLE>
<CAPTION>
                                                                                                           Transmission and
                                                                     Production Plants                          Other Plant
                                          Peach Bottom             Salem          Keystone         Conemaugh
                                                          Public Service
                                           PECO Energy  Electric and Gas      Pennsylvania      Pennsylvania        Various
Operator                                       Company           Company  Electric Company  Electric Company      Companies
<S>                                         <C>             <C>               <C>                <C>           <C>
Participating interest                          42.49%            42.59%            20.99%            20.72%     21% to 43%

Company's share (Thousands of Dollars)
Utility plant                                $ 748,790       $ 1,214,381         $ 109,363         $ 164,239       $ 88,272
Accumulated depreciation                       299,822           403,384            53,223            57,472         29,602
Construction work in progress                   35,218            72,744             5,363            19,388          1,900
</TABLE>

The Company's participating interests are financed with Company funds and, when
placed in service, all operations are accounted for as if such participating
interests were wholly owned facilities.

18. Cash and Cash Equivalents

For purposes of the Statements of Cash Flows, the Company considers all highly
liquid debt instruments purchased with a maturity of three months or less to be
cash equivalents. The following disclosures supplement the accompanying
Statements of Cash Flows:

<TABLE>
<CAPTION>
                                           1995         1994         1993
                                                     Thousands of Dollars
<S>                                     <C>         <C>         <C>     
Cash paid during the year:
Interest (net of amount capitalized)    $449,664    $437,096    $474,735
Income taxes (net of refunds)            257,677     205,316     182,751
Noncash investing and financing:
Capital lease obligations incurred       112,917      41,710      42,484
</TABLE>

                                       38

<PAGE>

19. Investments

<TABLE>
<CAPTION>
At December 31,                                          1995        1994
                                                     Thousands of Dollars
<S>                                                 <C>         <C>      
Trust accounts for decommissioning nuclear plants   $ 222,655   $ 175,326
Energy services and other ventures                     40,779      42,298
Nonutility property                                    26,816      19,609
Emission allowances                                     6,347        --
Gas exploration and development joint ventures            219        (722)
Other deposits                                            132          76
                                                    ---------   ---------
     Total                                          $ 296,948   $ 236,587
                                                    =========   =========
</TABLE>

20. Financial Instruments

Fair values of financial instruments, including liabilities, are estimated based
on quoted market prices for the same or similar issues. The carrying amounts and
fair values of the Company's financial instruments as of December 31, 1995 and
1994 were as follows:

<TABLE>
<CAPTION>
Thousands of Dollars                                                   1995                       1994
                                                            Carrying          Fair      Carrying          Fair
                                                              Amount         Value        Amount         Value
<S>                                                       <C>           <C>           <C>           <C>       
Cash and temporary cash investments                       $   20,602    $   20,602    $   46,970    $   46,970
Long-Term debt (including amounts due within one year)     4,599,286     4,773,700     4,986,844     4,730,005
Trust accounts for decommissioning nuclear plants            222,655       222,655       175,326       175,326
</TABLE>

Financial instruments which potentially subject the Company to concentrations of
credit risk consist principally of temporary cash investments and customer
accounts receivable. The Company places its temporary cash investments with
high-credit, quality financial institutions. At times, such investments may be
in excess of the Federal Deposit Insurance Corporation limit. Concentrations of
credit risk with respect to customer accounts receivable are limited due to the
Company's large number of customers and their dispersion across many industries.

21. Nuclear Fuel Agreement with Long Island Power Authority (LIPA)

In 1993, the Company entered into an agreement with LIPA and other parties to
receive $46 million as compensation for accepting slightly irradiated nuclear
fuel from Shoreham Nuclear Power Station. The Company received the payments in
installments as the shipments of nuclear fuel were accepted. The Company also
earned a $4 million bonus as a result of receiving all shipments prior to the
September 5, 1994 target date. 

The payments from LIPA, net of related costs of $4 million, were recognized in
income. The Company recognized $26 and $20 million as Other Income in the
Consolidated Statements of Income for the years ended December 31, 1994 and
1993, respectively.

22. Voluntary Retirement and Separation Incentive Programs

The Company incurred a one-time, pre-tax charge of $254 million ($145 million
net of taxes) in the third quarter of 1994 as a result of voluntary retirement
and separation programs approved by the Company's Board of Directors in April
1994. Pursuant to these programs 1,474 employees elected to retire and 1,008
employees elected to voluntarily separate from the Company. The retirements and
separations took place in stages through December 31, 1995. As a result of the
programs, in 1994 the Company accelerated recognition of $177 million of its
non-pension postretirement benefits obligation. The Company recorded a
corresponding regulatory asset and is recovering this amount in rates as a
component of non-pension postretirement benefits expense. The recognition of the
$177 million of non-pension postretirement benefits obligation and corresponding
regulatory asset did not impact earnings.

                                       39

<PAGE>
23. Sale of Subsidiary

On June 19, 1995, the Company completed the sale of Conowingo Power Company
(COPCO) to Delmarva Power & Light Company (Delmarva) for $150 million. The
transaction also included a ten-year contract for the Company to sell power to
Delmarva.

The Company's gain on the sale of $59 million ($27 million net of taxes) was
recorded in the second quarter of 1995.

24. Shutdown of Salem Generating Station

PSE&G removed Salem Units No. 1 and No. 2 from service on May 16, 1995 and June
7, 1995, respectively. PSE&G informed the NRC at that time that it had
determined to keep the Salem units shut down pending review and resolution of
certain equipment and management issues, and NRC agreement that each unit is
sufficiently prepared to restart. PSE&G has informed the Company that Salem
Units No. 1 and No. 2 are expected to be out of service until the second and
third quarters of 1996, respectively. As of December 31, 1995, the Company had
incurred and expensed approximately $50 million of replacement power and
operating and maintenance costs.

25. Quarterly Data (Unaudited)

The data shown below include all adjustments which the Company considers
necessary for a fair presentation of such amounts:

<TABLE>
<CAPTION>
                      Operating Revenues           Operating Income               Net Income
Millions of Dollars   1995          1994          1995          1994          1995          1994
<S>                 <C>           <C>           <C>           <C>           <C>           <C>   
Quarter ended
March 31            $1,059        $1,128        $  257        $  260        $  152        $  159
June 30                959           952           233           203           154           116
September 30         1,125         1,041           292           128           184            22
December 31          1,044           920           222           238           120           129
</TABLE>

<TABLE>
<CAPTION>
                    Earnings Applicable           Average Shares                  Earnings
                      to Common Stock               Outstanding              Per Average Share
Millions of Dollars   1995        1994           1995          1994          1995         1994
<S>                   <C>         <C>           <C>           <C>        <C>          <C>     
Quarter ended
March 31              $146        $149          221.7         221.5      $   0.66     $   0.67
June 30                148         105          221.8         221.5          0.67         0.48
September 30           178          13          221.9         221.6          0.80         0.06
December 31            115         123          221.9         221.6          0.52         0.55
</TABLE>

1994 third quarter results include a pre-tax charge of $254 million ($145
million net of taxes), or $0.66 per share, as a result of VRIP and VSIP (see
note 22).

1995 second quarter results include a pre-tax gain of $59 million ($27 million
net of taxes), or $0.12 per share, as a result of the sale of COPCO (see note
23).

                                       40
<PAGE>
Financial Statistics

Summary of Earnings and Financial Condition

<TABLE>
<CAPTION>
For the Years Ended December 31,                1995       1994       1993       1992       1991       1990
                                                                                        Millions of Dollars
<S>                                          <C>       <C>        <C>         <C>        <C>        <C>    
Income Data
Operating Revenues                           $ 4,186    $ 4,041    $ 3,988    $ 3,963    $ 4,019    $ 3,787
Operating Income                               1,004        830      1,035      1,033      1,081        768
Income from Continuing Operations                610        427        591        479        535        106
Net Income                                       610        427        591        479        535        214
Earnings Applicable to Common Stock              587        389        542        418        469        124
Earnings per Average Common Share
     from Continuing Operations
     (Dollars)                                  2.64       1.76       2.45       1.90       2.15       0.07
Earnings per Average Common Share
     (Dollars)                                  2.64       1.76       2.45       1.90       2.15       0.58
Dividends per Common Share (Dollars)            1.65      1.545       1.43      1.325      1.225       1.45
Common Stock Equity (Per Share)                20.40      19.41      19.25      18.24      17.69      16.71
Average Shares of Common Stock
     Outstanding (Millions)                    221.9      221.6      221.1      220.2      218.2      214.4

At December 31,

Balance Sheet Data
Net Utility Plant, at Original Cost          $10,758    $10,829    $10,763    $10,691    $10,599    $10,591
Leased Property, net                             181        174        194        210        224        241
Total Current Assets                             486        427        515        550        783        745
Total Deferred Debits and Other
     Assets                                    3,536      3,635      3,560      1,127        918        939
                                             -------    -------    -------    -------    -------    -------
     Total Assets                            $14,961    $15,065    $15,032    $12,578    $12,524    $12,516
                                             =======    =======    =======    =======    =======    =======

Common Shareholders' Equity                  $ 4,531    $ 4,303    $ 4,263    $ 4,022    $ 3,892    $ 3,624
Preferred and Preference Stock
     Without Mandatory Redemption                199        277        423        423        423        423
     With Mandatory Redemption                    93         93        187        231        315        331
Company Obligated Mandatorily
     Redeemable Preferred Securities
     of a Partnership                            302        221       --         --         --         --
Long-Term Debt                                 4,199      4,786      4,884      5,204      5,416      5,831
                                             -------    -------    -------    -------    -------    -------
     Total Capitalization                      9,324      9,680      9,757      9,880     10,046     10,209
Total Current Liabilities                      1,077        850        954        830        824        784
Total Deferred Credits and
     Other Liabilities                         4,560      4,535      4,321      1,868      1,654      1,523
                                             -------    -------    -------    -------    -------    -------
     Total Capitalization and Liabilities    $14,961    $15,065    $15,032    $12,578    $12,524    $12,516
                                             =======    =======    =======    =======    =======    =======
</TABLE>

                                       41
<PAGE>

Operating Statistics
<TABLE>
<CAPTION>
For the Years Ended December 31,                 1995          1994          1993          1992          1991          1990
Electric Operations
<S>                                       <C>           <C>           <C>           <C>           <C>           <C>        
Output (Millions of Kilowatthours)
Fossil                                         10,792        11,239        10,352         8,082         7,376         7,913
Nuclear                                        25,499        28,195        27,026        24,428        25,735        23,715
Hydro                                           1,425         1,970         1,699         1,803         1,388         2,266
Pumped storage output                           1,741         1,596         1,478         1,597         1,653         1,437
Pumped storage input                           (2,507)       (2,256)       (2,192)       (2,217)       (2,355)       (2,059)
Purchase and interchange                       13,945         6,164         6,447         8,675         8,603         5,787
Internal combustion                               175           106            56            29            79           152
Other                                            --            --            --            --            --             180
                                          -----------   -----------   -----------   -----------   -----------   -----------
     Total electric output                     51,070        47,014        44,866        42,397        42,479        39,391
                                          ===========   ===========   ===========   ===========   ===========   ===========

Sales (Millions of Kilowatthours)
Residential                                    10,859        10,817        10,657         9,894        10,311         9,815
Small commercial and industrial                 6,299         6,108         5,773         5,367         5,284         5,066
Large commercial and industrial                15,976        15,847        15,935        15,770        16,177        16,554
Other                                             860           791           771           962         1,029         1,010
                                          -----------   -----------   -----------   -----------   -----------   -----------
     Service territory                         33,994        33,563        33,136        31,993        32,801        32,445
Interchange sales                                 496           768           457         1,231         1,612         2,751
Sales to other utilities                       14,041        10,039         8,670         6,699         5,445         1,865
                                          -----------   -----------   -----------   -----------   -----------   -----------
     Total electric sales                      48,531        44,370        42,263        39,923        39,858        37,061
                                          ===========   ===========   ===========   ===========   ===========   ===========

Number of Customers, December 31,
Residential                                 1,321,379     1,350,210     1,341,873     1,333,926     1,324,795     1,320,126
Small commercial and industrial               141,653       143,605       142,363       141,253       140,901       140,305
Large commercial and industrial                 3,394         3,603         3,742         3,972         4,162         4,344
Other                                             959           944           888           857           840           817
                                          -----------   -----------   -----------   -----------   -----------   -----------
     Total electric customers               1,467,385     1,498,362     1,488,866     1,480,008     1,470,698     1,465,592
                                          ===========   ===========   ===========   ===========   ===========   ===========

Operating Revenues (Millions of Dollars)
Residential                               $     1,401   $     1,369   $     1,354   $     1,305   $     1,342   $     1,230
Small commercial and industrial                   739           707           679           670           641           595
Large commercial and industrial                 1,147         1,143         1,164         1,223         1,279         1,247
Other                                             137           136           161           168           171           167
                                          -----------   -----------   -----------   -----------   -----------   -----------
     Service territory                          3,424         3,355         3,358         3,366         3,433         3,239
Interchange sales                                  17            23            14            32            43            82
Sales to other utilities                          334           247           233           199           187            81
                                          -----------   -----------   -----------   -----------   -----------   -----------
     Total electric revenues                    3,775         3,625         3,605         3,597         3,663         3,402
                                          -----------   -----------   -----------   -----------   -----------   -----------

Operating Expenses
Operating expenses, excluding
     depreciation                               2,406         2,430         2,228         2,237         2,253         2,325
Depreciation                                      431           416           401           391           380           338
                                          -----------   -----------   -----------   -----------   -----------   -----------
     Total operating expenses                   2,837         2,846         2,629         2,628         2,633         2,663
                                          -----------   -----------   -----------   -----------   -----------   -----------
Electric Operating Income                 $       938   $       779   $       976   $       969   $     1,030   $       739
                                          ===========   ===========   ===========   ===========   ===========   ===========

Average Use per Residential Customer
 (Kilowatthours)
Without electric heating                        6,908         6,736         6,727         6,259         6,707         6,376
With electric heating                          17,189        17,527        17,096        16,298        16,201        16,038
Total                                           8,130         8,041         7,970         7,443         7,801         7,464
Electrical Peak Load, Demand
     (Thousands of Kilowatts)                   7,244         7,227         7,100         6,617         7,096         6,755
Net Electric Generating Capacity -
     Year-End Summer Rating
     (Thousands of Kilowatts)                   9,078         8,956         8,877         8,836         8,766         8,766
Cost of Fuel per Million Btu              $      0.87   $      0.89   $      0.90   $      0.82   $      0.92   $      1.13
Btu per net Kilowatthour Generated             10,705        11,617        10,675        10,657        10,849        10,844
</TABLE>
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<PAGE>
<TABLE>
<CAPTION>
For the Years Ended December 31,              1995      1994      1993      1992      1991       1990

Gas Operations
<S>                                       <C>       <C>       <C>       <C>       <C>       <C>     
Sales (Millions of Cubic Feet)
Residential                                  1,516     1,636     1,637     1,819     1,746     1,778
House heating                               31,848    31,974    30,687    29,750    26,423    25,303
Commercial and industrial                   19,422    21,520    22,943    21,497    20,492    23,228
Other                                        1,184     5,079     5,656     2,146       534     1,567
                                          --------  --------  --------  --------  --------  --------
     Total gas sales                        53,970    60,209    60,923    55,212    49,195    51,876
Gas transported for customers               48,531    29,801    22,946    22,060    21,414    24,413
                                          --------  --------  --------  --------  --------  --------
     Total gas sales and gas transported   102,501    90,010    83,869    77,272    70,609    76,289
                                           =======    ======    ======    ======    ======    ======

Number of Customers, December 31,
Residential                                 56,533    57,122    59,573    59,859    62,444    63,267
House heating                              295,481   287,481   277,500   269,577   260,473   254,564
Commercial and industrial                   33,308    32,292    31,573    30,956    30,204    29,456
                                          --------  --------  --------  --------  --------  --------
     Total gas customers                   385,322   376,895   368,646   360,392   353,121   347,287
                                           =======   =======   =======   =======   =======   =======

Operating Revenues (Millions of Dollars)
Residential                               $     15  $     16  $     15  $     16  $     17  $     18
House heating                                  240       236       205       202       192       201
Commercial and industrial                      129       133       124       121       124       145
Other                                            4        14        15         3         2         5
                                          --------  --------  --------  --------  --------  --------
     Subtotal                                  388       399       359       342       335       369
Other revenues (including transported
     for customers)                             22        17        23        23        21        16
                                          --------  --------  --------  --------  --------  --------
     Total gas revenues                        410       416       382       365       356       385
                                          --------  --------  --------  --------  --------  --------
Operating Expenses
Operating expenses, excluding
     depreciation                              319       340       299       278       284       336
Depreciation                                    26        26        24        23        21        20
                                          --------  --------  --------  --------  --------  --------
     Total operating expenses                  345       366       323       301       305       356
                                          --------  --------  --------  --------  --------  --------
Gas Operating Income                      $     65  $     50  $     59  $     64  $     51  $     29
                                          ========  ========  ========  ========  ========  ========
</TABLE>

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