13

Management's Discussion and Analysis of Financial Condition and Results of
Operations

General

In December 1996, Pennsylvania Governor Tom Ridge signed into law the
Electricity Generation Customer Choice and Competition Act (Competition Act)
which provides for the restructuring of the electric utility industry in
Pennsylvania, including retail competition for generation beginning in 1999. The
Company estimates that its stranded costs resulting from retail electric
generation competition mandated by the Competition Act at December 31, 1998 will
be $7.1 billion.

The Company intends to seek recovery of these stranded costs and to securitize
that recovery in accordance with the provisions of the Competition Act. The
proceeds of the securitization will be used to reduce stranded costs and related
capitalization.

The Company believes that the Competition Act and other regulatory initiatives
that provide for competition for generation services will significantly affect
the Company's future financial condition and results of operations. At this time
the Company cannot predict whether those changes will materially affect the
market prices of its publicly traded securities. See "Outlook-Competition Act."

Discussion of Operating Results

Earnings and Dividends

Earnings per common share were $2.24 in 1996 as compared with $2.64 and $1.76 in
1995 and 1994, respectively. The $0.40 per share decrease in 1996 earnings was
primarily due to higher Salem Generating Station (Salem) outage-related
replacement power and maintenance costs which reduced earnings by $0.27 per
share. Earnings also decreased by $0.18 per share in 1996 due to lower electric
revenues resulting from less favorable weather conditions compared to last year,
by $0.12 per share due to the gain recognized in 1995 on the sale of Conowingo
Power Company (COPCO), by $0.11 per share due to higher customer expenses, and
by $0.06 per share due to the accelerated depreciation of assets associated with
Limerick Generating Station (Limerick). These decreases were partially offset by
$0.18 per share due to the Company's continuing cost control initiatives, by
$0.09 per share due to savings resulting from the Company's ongoing debt and
preferred stock refunding and refinancing program, and by $0.08 per share due to
higher revenues resulting from increased sales to other utilities.

The $0.88 per share increase in 1995 earnings was primarily due to a one-time
charge of $0.66 in 1994 associated with the Company's voluntary retirement and
separation incentive programs. Earnings also increased $0.22 per share in 1995
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
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, 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).

<PAGE>
14

Significant Operating Items

<TABLE>
<CAPTION>
Revenue and Expense Items as a
percentage of Total Operating
Revenues                                                                                 Percentage Dollar Changes
 1994       1995       1996                                                              1996-1995    1995-1994
<S>        <C>        <C>                                                                   <C>        <C>
  90%        90%        90%      Electric                                                     2%         4%
  10%        10%        10%      Gas                                                          4%        (1%)
 ---        ---        ---                                                                 ----       -----
 100%       100%       100%      Total Operating Revenues                                     2%         4%
 ===        ===        ===                                                                 ====       ====
  17%        18%        23%      Fuel and Energy Interchange                                 27%         8%
  38%        30%        30%      Other Operation and Maintenance                              2%       (18%)
  11%        11%        11%      Depreciation                                                 7%         3%
   6%         9%         8%      Income Taxes                                               (14%)       70%
   7%         8%         7%      Other Taxes                                                 (5%)        1%
 ---        ---        ---                                                                 ----       -----
  79%        76%        79%      Total Operating Expenses                                     6%        (1%)
 ===        ===        ===                                                                 ====       ====
  21%        24%        21%      Operating Income                                           (10%)       21%
 ===        ===        ===                                                                 ====       ====
  --         --         --       Allowance for Other Funds Used During Construction         (29%)       41%
 ===        ===        ===                                                                 ====       ====
  --          1%        --       Total Other Income and Deductions                          (70%)      111%
 ===        ===        ===                                                                 ====       ====
  11%        11%        10%      Total Interest Charges                                      (8%)        3%
 ===        ===        ===                                                                 ====       ====
  (1%)       (1%)       (1%)     Allowance for Borrowed Funds Used During Construction      (23%)        5%
 ---        ---        ---                                                                 ----       -----
  10%        10%         9%      Net Interest Charges                                        (8%)        3%
 ===        ===        ===                                                                 ====       ====
  11%        15%        12%      Net Income                                                 (15%)       43%
 ===        ===        ===                                                                 ====       ====
                                 Preferred Stock Dividends                                  (22%)      (38%)
                                                                                           ====       ====
                                 Earnings Applicable to Common Stock                        (15%)       51%
                                                                                           ====       ====
                                 Earnings per Average Common Share                          (15%)       50%
                                                                                           ====       ====
</TABLE>


Operating Revenues

Total operating revenues increased in 1996 by $98 million to $4,284 million.
This represented an $80 million increase in electric revenues and an $18 million
increase in gas revenues over 1995. The increase in electric revenues was
primarily due to increased sales to other utilities and was partially offset by
decreased retail sales due to less favorable weather conditions. The increase in
gas revenues was primarily due to increased sales to retail customers from more
favorable weather conditions in the first half of 1996 and higher levels of firm
sales resulting from customers switching from transportation service to firm
service. These increases were partially offset by decreased sales and
transportation revenues resulting from unusually mild weather in December 1996.

     Total operating revenues increased in 1995 by $146 million to $4,186
million. This represented a $151 million increase in electric revenues and a $5
million decrease in gas revenues over 1994. The increase in electric revenues
was primarily due to increased sales to other utilities and higher retail sales
due to favorable weather conditions. 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). The decrease
in gas revenues was 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 gas on the spot market.

     Increases/(decreases) in electric sales and operating revenues by class of
customer for 1996 compared to 1995 and 1995 compared to 1994 are set forth
below:











<TABLE>
<CAPTION>
                                        1996 - 1995                        1995 - 1994
                                 Electric         Electric           Electric         Electric
                                   Sales          Revenues             Sales          Revenues
                            (Millions of kWh)  (Millions of $)   (Millions of kWh) (Millions of $)
<S>                               <C>           <C>                  <C>          <C>
Residential                          (86)          $  (14)              18           $   20
House Heating                        121                5             (241)             (12)
Small Commercial
  and Industrial                     291               19               50               20
Large Commercial
  and Industrial                    (555)             (37)            (205)             (13)
Other                                 42                3               69                1
Unbilled                            (862)             (69)             740               54
  Service Territory               (1,049)             (93)             431               70
Interchange Sales                    439                9             (272)              (6)
Sales to Other Utilities           6,202              164            4,002               87
  Total                            5,592           $   80            4,161           $  151
</TABLE>
<PAGE>
                                                                              15

Fuel and Energy Interchange Expense

     Fuel and energy interchange expenses increased in 1996 by $210 million to
$973 million. The increase was primarily due to interchange purchases needed for
increased sales to other utilities, increased replacement power costs resulting
from the shutdown of Salem and a net credit to expense in 1995 from certain
energy sales to other utilities. Fuel and energy interchange expense as a
percentage of operating revenues increased from 18% to 23% principally due to
increased replacement power costs resulting from the shutdown of Salem.

     Fuel and energy interchange expenses increased in 1995 by $59 million to
$763 million. The increase was primarily due to increased customer demand,
higher levels of sales to other utilities and replacement power costs resulting
from 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 and from certain energy sales to other
utilities. The increases were further offset by lower purchased gas costs
resulting from reduced output. Fuel and energy interchange expense as a
percentage of operating revenues increased from 17% to 18% principally due to
increased interchange purchases.

Other Operating and Maintenance Expenses

     Other operating and maintenance expenses increased in 1996 by $23 million
to $1,274 million due to higher customer expenses, higher contractor costs and
higher nuclear generating station charges resulting from the shutdown of Salem.
These increases were partially offset by lower operating costs at the
Company-operated nuclear generating stations and lower administrative and
general expenses resulting from the Company's ongoing cost-control efforts.

     Other operating and maintenance expenses decreased in 1995 by $268 million
to $1,251 million. The decrease was primarily due to the charge in 1994
associated with the early retirement and separation programs, lower customer
expenses 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. Other operating and maintenance expenses
decreased as a percentage of operating revenues from 38% to 30% primarily due to
the charge in 1994 associated with the early retirement and separation programs.

Depreciation Expense

     Effective October 1, 1996, the Company increased depreciation and
amortization on assets associated with Limerick by $100 million per year and
decreased depreciation and amortization on other Company assets by $10 million
per year.

     Depreciation expense increased in 1996 by $32 million to $489 million. The
increase was primarily due to the accelerated depreciation of assets associated
with Limerick which began in October 1996, and accounted for $23 million, or
one-quarter of the expected net annual increase of $90 million. Depreciation
expense also increased due to additions to plant in service.

     Depreciation expense increased in 1995 by $15 million to $457 million. The
increase was primarily due to additions to plant in service.

Income Taxes

     Income taxes decreased in 1996 by $54 million to $343 million. The decrease
was primarily due to lower operating income.

     Income taxes increased in 1995 by $163 million to $397 million. The
increase was primarily due to increases in operating income.

Allowance for Funds Used During Construction

     Allowance for funds used during construction (AFUDC) decreased in 1996 by
$7 million to $20 million. The decrease was primarily due to an adjustment in
1995. Also contributing to the decrease was a decrease in the 1996 AFUDC rate.

     AFUDC increased in 1995 by $5 million to $27 million. The increase was
primarily due to an increase in the AFUDC rate, and an adjustment in 1995.

Other Income and Deductions

     Other income and deductions decreased in 1996 by $23 million to $1 million.
The decrease was primarily due to the gain recognized in 1995 on the sale of
COPCO.

     Other income and deductions increased in 1995 by $16 million to $24
million. The increase was primarily due to the gain 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 decreased in 1996 by $36 million to $409 million.
The decrease was primarily due to the Company's ongoing program to reduce and
refinance higher-cost, long-term debt. This decrease was partially offset by the
replacement of preferred stock with Monthly Income Preferred Securities
(recorded in the financial statements as Company Obligated Mandatorily
Redeemable Preferred Securities of a Partnership), Series B, in the fourth
quarter of 1995.

     Total interest charges increased in 1995 by $12 million to $445 million.
The increase was primarily due to the July 1994 issuance of Monthly Income
Preferred Securities, Series A.

Preferred Stock Dividends

     Preferred stock dividends decreased in 1996 by $5 million to $18 million.
The decrease was primarily due to the replacement of preferred stock with
Monthly Income Preferred Securities, Series B in the fourth quarter of 1995.

     Preferred stock dividends decreased in 1995 by $14 million to $23 million.
The decrease was primarily due to the replacement of preferred stock with
Monthly Income Preferred Securities, Series A in the third quarter of 1994.

<PAGE>
16

Discussion of 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
capital requirements, to repay maturing debt and to make preferred and common
stock dividend payments.

     In 1996 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 financial condition 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 sales to other utilities.

     The Company expects that its future liquidity and capital resources will be
reduced as a result of the Competition Act. The Company is pursuing a strategy
to reduce its stranded costs and the associated capitalization roughly in
proportion to the current capitalization, which would reduce the Company's
liquidity and capital resource requirements. The Company cannot predict the
level of stranded cost recovery which will be permitted under the Competition
Act, the impact of any such recovery on the Company's capitalization or whether
internally generated cash will continue to meet or exceed the Company's capital
requirements and dividend payments.

     As of December 31, 1996, the Company's capital structure consisted of 49.1%
common equity; 6.3% preferred stock and Company obligated mandatorily redeemable
preferred securities (which comprised 3.2% of the Company's total capitalization
structure); and 44.6% long-term debt.

     The Company expects its level of capital investment in generation utility
plant to decrease in future years to mitigate costs in anticipation of
competition. Total construction program expenditures, primarily for utility
plant were $534 million in 1996 and are estimated to be $560 million in 1997 and
$1,225 million for the period 1998 to 2000. The Company's construction program
is subject to periodic review and revision to reflect changes in economic
conditions 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.

     The Company has undertaken a number of new ventures, principally through
its Telecommunications Group, some of which require significant cash
commitments. For the period 1997 through 2000, the Company plans to invest
approximately $200-$300 million in such ventures.

     Cash flows from operations were $1,172 million in 1996, substantially
consistent with the 1995 and 1994 levels. Cash flows consisted of earnings,
non-cash charges of depreciation and deferred income taxes.

     Cash flows used in investing activities were $663 million as compared to
$465 million in 1995 and $589 million in 1994. While the Company's construction
program has been relatively stable, the Company has made significant investments
in diversified activities and other obligations. Net funds used in these
activities were $114 million, consisting of $58 million for telecommunications
ventures, $44 million for nuclear plant decommissioning trust funds and $12
million for other deposits and ventures. In 1995 and 1994, funds used in similar
activities were $82 million and $18 million, respectively. 1995 cash flows
benefited from the sale of COPCO.

     Cash flows used in financing activities were $501 million in 1996 as
compared to $802 million in 1995 and $706 million in 1994. The decrease in 1996
is primarily due to less available cash permitting fewer retirements of higher
cost debt. In 1995 higher available cash resulting from the sale of COPCO
permitted a higher level of debt retirement than in 1994. In 1996 the debt
retirement program has resulted in a reduction of $12 million in annualized
interest.

     The Company meets its short-term liquidity requirements primarily through
the issuance of commercial paper, borrowings under a revolving credit agreement
and lines of credit. The Company had $288 million of short-term debt including
$200 million of commercial paper outstanding at December 31, 1996.

     At December 31, 1996, the Company's embedded cost of debt was 6.9% with
12.8% of the Company's long-term debt having floating rates. The coverage ratios
under the Company's mortgage indenture and Articles of Incorporation as of
December 31, 1996, were 4.39 and 2.50 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 1997.

Outlook

     The Company's future financial condition and its future operating results
are substantially dependent upon the effects of the Competition Act and other
competitive initiatives. Additional factors that affect the Company's financial
condition and future operating results include operation of nuclear generating
facilities, sales to other utilities, accounting issues, inflation, weather and
compliance with environmental regulations.

Competition Act

     The Competition Act was enacted in December 1996, providing for the
restructuring of the electric utility industry in Pennsylvania. The Competition
Act requires the unbundling of electric services into separate generation,
transmission and distribution services with open retail competition for
generation. Electric distribution and transmission services will remain
regulated by the Pennsylvania Public Utility Commission (PUC). The Competition
Act requires utilities to submit to the PUC restructuring plans, including their
stranded costs which will result from competition. Stranded costs include
regulatory assets, nuclear decommissioning costs and long-term purchased power
commitments, for which full recovery is allowed, and other costs, including
investment in generating plants, spent-fuel disposal, retirement costs and
reorganization costs, for which an opportunity for recovery is allowed in an
amount determined by the PUC as just and reasonable. These costs, after
mitigation by the utility, are to be recovered through the competitive
transition charge (CTC) approved by the PUC and collected from distribution
customers for up to nine years (or for an alternative period determined by the
PUC for good cause shown). During that period, the utility is subject to a rate
cap which provides that total charges to customers cannot exceed the rates in
place as of December 31, 1996, subject to certain exceptions.

<PAGE>
                                                                              17

     Full electric generation competition will be phased in, in three steps,
beginning January 1, 1999. Direct retail access is to be phased in for one-third
of each customer class by January 1, 1999, for an additional one-third by
January 1, 2000 and for all remaining customers by January 1, 2001.

     The Competition Act also authorizes the PUC to approve by adopting a
Qualified Rate Order (QRO) the issuance by a utility, a finance subsidiary of a
utility or a third party assignee of a utility of Transition Bonds as a
mechanism to mitigate stranded investment and reduce customer rates. Under the
Competition Act, proceeds of Transition Bonds are required to be used
principally to reduce qualified stranded costs and the related capitalization of
the utility. The Transition Bonds are repayable from the irrevocable Intangible
Transition Charges (ITC) which are collected in lieu of CTC. The maximum
maturity of the Transition Bonds is ten years.

     On January 22, 1997, the Company filed an Application with the PUC for a
QRO authorizing the issuance of $3.9 billion of Transition Bonds to fund $3.6
billion of stranded costs and $277 million of transaction and use of proceeds
costs. The Company has requested expedited review of its Application under the
Competition Act, which requires the PUC to complete its review of the
Application and issue a final determination within 120 days.

     The Application, which has been filed in advance of the Company's required
restructuring filing, seeks recovery of $3.6 billion of the Company's estimated
$7.1 billion (at December 31, 1998) total stranded costs through the issuance of
the Transition Bonds covered by the Application. The Company's estimate of total
stranded costs includes $3.9 billion of generation assets, $560 million of
unfunded and as yet unrecorded decommissioning expenses and $2.6 billion of
regulatory assets. Recovery of the portion of the Company's stranded costs not
covered by the Application will be requested by the Company in its restructuring
filing, which is presently anticipated to be made on April 1, 1997. To the
extent the Company is not ultimately permitted by the PUC to recover its retail
electric stranded costs, this amount could result in a charge against earnings.

     The Application sets forth the Company's proposal for the issuance of
Transition Bonds. The proposal provides for (i) the sale by the Company to an
unrelated special purpose entity (SPE) of the intangible transition property
authorized under the Competition Act, which represents the right to recover
through the ITC the $3.9 billion of stranded costs and related transaction and
use of proceeds costs, and (ii) the issuance by the SPE of the Transition Bonds.
The Company believes that such a transaction would result in the exclusion of
the ITC from the Company's revenues and off-balance sheet treatment of the
Transition Bonds; however, such accounting treatment will be subject to
Securities and Exchange Commission review.

     The Company proposes using the proceeds it receives from the SPE, resulting
from the issuance of the Transition Bonds, to pay estimated transaction and use
of proceeds costs of $277 million, to settle deferred fuel balances of $240
million and to reduce capitalization by approximately $3.4 billion. The
capitalization reduction is expected to be proportionate to the Company's
current capitalization. Specific securities to be retired and the manner in
which they are to be retired have not been determined and will depend on market
conditions at the time of issuance of Transition Bonds.

     Adoption by the PUC of the requested QRO and issuance of $3.9 billion of
Transition Bonds at current interest rates would result in an estimated 2.9%
reduction in the Company's retail electric rates. The Company estimates that the
consummation of the transaction as proposed in the Application would reduce the
Company's annual revenues by approximately $650 million and the Company's annual
operating expenses by $501 million, resulting in an estimated reduction in
annual net income of $149 million. The reduction in revenue results from the
elimination of the revenue requirements of stranded costs, and the reduction in
operating expenses results from decreases in depreciation, interest expense and
associated income taxes. The impact on the Company's earnings per share will
depend on the price at which shares of the Company's Common Stock are purchased.
If Common Stock is purchased at a price above book value ($20.88 at December 31,
1996), earnings per share will be reduced.

     Under the Competition Act, the Company expects that its rates for
transmission and distribution services will be capped at their current levels
for 4.5 years and the generation portion of rates for up to nine years. In
recognition of the capping of rates at current levels, at December 31, 1996, the
PUC approved the Company's request to roll-in and eliminate the ECA. The Company
cannot predict whether the PUC will issue the requested QRO, the level of
stranded cost recovery authorized by any QRO or the amount of Transition Bonds,
if any, ultimately issued pursuant to any QRO. The Company believes that once
the issues surrounding the recovery of its stranded costs are resolved, it will
be able to compete effectively in the generation market primarily because of its
marketing efforts and its low generation costs.









Other Competitive Initiatives

     During 1996, the Federal Energy Regulatory Commission (FERC) issued Order
No. 888 which requires public utilities to file open-access transmission tariffs
for wholesale transmission services in accordance with non-discriminatory terms
and conditions established by the FERC. The FERC's new rules provide for the
recovery of legitimate and verifiable wholesale stranded costs. The Company does
not have any stranded costs related to this portion of its business.

     In response to Order No. 888, the Company and the other members of the
Pennsylvania-New Jersey-Maryland Interconnection Association (PJM) submitted to
the FERC separate filings proposing to restructure PJM. The Company proposed
five major initiatives to reduce the costs of electricity while preserving the
reliability and universal service that is essential to Pennsylvania citizens. In
November 1996, the FERC issued an order rejecting both of the PJM restructuring
filings. The FERC identified two issues that remain to be resolved: independence
of the independent system operator; and open access transmission pricing tariffs
that are nondiscriminatory. The FERC directed the parties to refile their
proposals, preferably as one proposal, resolving these issues by December 31,
1996, with tariffs to be effective March 1, 1997. On December 31, 1996, the PJM
member companies, including the Company, filed a joint compliance filing with
the FERC. The filing was not a complete consensus but included competing
proposals in certain areas such as transmission rate structure and transmission
constraint/congestion control. The PJM member companies requested the FERC to
choose between the options for implementation during the interim period. The
FERC is expected to rule on this filing in the first quarter of 1997.

<PAGE>
18

     The Company received approval for its transmission service tariff covering
network and point-to-point services and a market-based rate energy sales tariff
that allows the Company to sell wholesale energy at market-based rates outside
the PJM control area. During the latter part of 1996, the Company also requested
approval from the FERC to remove the existing cost-based cap on prices charged
for power purchased by the Company in anticipation of later resale in the
wholesale market and certain changes regarding the terms of the buy-for-resale
agreements. The transactions covered under the original market-based rate tariff
were rolled into the more recent request. Approval of the new tariff provisions
will allow the Company to purchase and re-sell energy at market-based rates both
within PJM and outside PJM.

     The gas industry is continuing to undergo structural changes in response to
FERC policies designed to increase competition. 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 changes, the Company has modified its gas purchasing arrangements to
enable the purchase of gas and transportation at lower cost. During 1996 the
Company, through a wholly owned subsidiary, successfully participated in a pilot
program outside the Company's gas service territory to market natural gas and
other services.

     As a result of competitive pressures, the Company has continued to
negotiate long-term contracts with many of its larger-volume industrial
customers. Although these agreements have resulted in reduced margins, they have
permitted the Company to retain these customers. During 1996, energy sales under
long-term contracts were 8% of total electric sales.

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.

     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 in the second quarter of 1995. 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 reported that Unit No. 2 is
expected to return to service in the second quarter of 1997 and Unit No. 1 is
expected to return to service in the summer of 1997. It is the Company's belief
that the earliest that Unit No. 1 will return to service is late in the third
quarter of 1997. The Company expects to incur and expense at least $95 million
in 1997 for increased costs related to the shutdown. As of December 31, 1996 and
1995, the Company had incurred and expensed $149 million and $50 million,
respectively, for replacement power and maintenance costs related to the
shutdown of Salem. See note 4 of Notes to Consolidated Financial Statements.
During 1996, Company-operated nuclear plants operated at an 89% weighted-average
capacity factor and Company-owned nuclear plants operated at a 68%
weighted-average capacity factor. The Company-owned nuclear plants produced 43%
of the Company's output, including purchased power, despite the shutdown of both
Salem units during 1996. Nuclear generation is the most cost-effective way for
the Company to meet customer needs and commitments for sales to other utilities.

Sales to Other Utilities

     In the ordinary course of business, the Company enters into commitments to
buy and sell power. As of December 31, 1996, the Company entered into long-term
agreements to purchase from unaffiliated utilities, primarily in 1997, energy
associated with 2,200 megawatts (MW) of capacity. These purchases will be
utilized through a combination of sales to jurisdictional customers, long-term
sales to other utilities and open market sales. The Company's future results of
operations are dependent in part on its ability to successfully market the rest
of 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. As of December 31, 1996, the Company has entered into long-term
agreements with unaffiliated utilities to sell energy associated with 1,460 MW
of capacity, of which 725 MW of these agreements are for 1997 and the remainder
run through 2022.

Accounting Issues

     The Company accounts for all of its regulated operations in accordance with
Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the
Effect of Certain Types of Regulation" which requires the Company to record the
financial statement effects of the rate regulation to which the Company is
currently subject. Use of SFAS No. 71 is applicable to the utility operation of
the Company which meet the following criteria: 1) third-party regulation of
rates; 2) cost-based rates; and 3) a reasonable assumption that all costs will
be recoverable from customers through rates.

     By January 1, 1999, the date when market competition is introduced for
retail generation under the Competition Act, the Company expects it will no
longer meet the criteria of SFAS No. 71 for this separable portion of its
operations. When the Company determines that the criteria required by SFAS No.
71 are no longer satisfied, the Company will adopt the provisions of SFAS No.
101, "Regulated Enterprises Accounting for the Discontinuance of Application of
FASB Statement No. 71." SFAS No. 101 requires the elimination of all effects of
any actions of regulators that have been recognized as assets and liabilities
pursuant to SFAS No. 71 and a determination of impairment of plant assets under
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of."

     In its January 22, 1997 Application, the Company estimated total stranded
costs of $7.1 billion, including $2.6 billion of regulatory assets, and $3.9
billion of plant assets.

     Given the stranded cost recovery provisions of the Competition Act, the
Company believes that it will be given the opportunity for full recovery of its
regulatory assets. In addition, as of December 31, 1996 there is no impairment
of plant costs under SFAS No. 121.

     For 1996, the Company believes that its wholesale operations continue to
meet the criteria for the continued application


<PAGE>
                                                                              19

of SFAS No. 71. Due to the market-based pricing of generation provisions of the
PJM restructuring proposal, it is anticipated that, upon acceptance of the
proposal by the FERC, the Company's wholesale energy sales operations would no
longer be subject to the provisions of SFAS No. 71. The Company does not believe
that the discontinuance of SFAS No. 71 for its wholesale energy sales operations
would result in a charge against income. Based on projections of the Company's
retail load growth, the Company believes all of the owned generation capacity
will be necessary to meet its retail load.

     In 1996, the Financial Accounting Standards Board (FASB) issued SFAS No.
125, "Accounting for Transfers and Servicing of Financial Assets and
Extinguishments of Liabilities," which is currently effective for transfers and
servicing of financial assets and extinguishment of liabilities occurring after
December 31, 1996. Adoption of SFAS No. 125 is not expected to have a material
effect on the Company's financial condition or results of operation.

     During 1996, the FASB issued the Exposure Draft "Accounting for Certain
Liabilities Related to Closure or Removal of Long-Lived Assets." The FASB has
recently taken under consideration the expansion of the scope of the project to
include closure or removal liabilities that are incurred at any time in the
operating life of the related long-lived asset. The Exposure Draft originally
included only liabilities incurred in the acquisition, construction, development
or early operation of a long-lived asset. The FASB plans to issue either a final
Statement or a revised Exposure Draft in the second quarter of 1997. Until such
time that the final Statement is issued or a revised Exposure Draft is issued,
the Company is unable to determine what, if any, effect the final Statement
might have on its financial condition or results of operations. See note 4 of
Notes to Consolidated Financial Statements.

Other Factors

     Annual and quarterly operating results can be significantly affected by
weather. Since the Company's peak demand is in the summer months, temperature
variations in summer months are generally more significant than during winter
months.

     Inflation affects the Company through increased operating costs and
increased capital costs for utility plant. As a result of the rate cap imposed
by the Competition Act and the elimination of the ECA, the Company may have
limited opportunity to pass the costs of inflation through to customers.

     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 27 sites where former manufactured gas plant
(MGP) activities have or may have resulted in 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. Eight of the sites are currently under some degree of active study
or remediation.

     As of December 31, 1996 and 1995, the Company had accrued $28 and $27
million, respectively, for environmental investigation and remediation costs,
including $16 and $13 million, respectively, for MGP investigation and
remediation that currently can be reasonably estimated. The Company expects to
expend $7 million for such activities in 1997. 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 from third parties.

Forward-Looking Statements

     Except for the historical information contained herein, certain of the
matters discussed in this Report are forward-looking statements which are
subject to risks and uncertainties. The factors that could cause actual results
to differ materially include those discussed herein as well as those listed in
notes 3 and 4 of Notes to Consolidated Financial Statements and other factors
discussed in the Company's filings with the Securities and Exchange Commission.
Readers are cautioned not to place undue reliance on these forward-looking
statements, which speak only as of the date of this Report. The Company
undertakes no obligation to publicly release any revision to these
forward-looking statements to reflect events or circumstances after the date of
this Report.

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


<PAGE>

20



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, 1996 and 1995, 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, 1996. 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, 1996 and 1995, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1996, in conformity with generally
accepted accounting principles.




/s/ Coopers & Lybrand LLP

2400 Eleven Penn Center
Philadelphia, Pennsylvania
February 3, 1997
<PAGE>
                                                                              21

Consolidated Statements of Income
<TABLE>
<CAPTION>

For the Years Ended December 31,                              1996             1995             1994
                                                                                Thousands of Dollars
<S>                                                    <C>              <C>              <C>
Operating Revenues
Electric                                               $ 3,854,836      $ 3,775,326      $ 3,624,797
Gas                                                        428,814          410,830          415,835
                                                       -----------      -----------      -----------
     Total Operating Revenues                            4,283,650        4,186,156        4,040,632
                                                       -----------      -----------      -----------

Operating Expenses
Fuel and Energy Interchange                                972,380          762,762          703,590
Other Operating                                            949,495          943,476          937,849
Early Retirement and Separation Programs                        --               --          254,106
Maintenance                                                324,727          307,797          327,714
Depreciation                                               489,001          457,254          442,101
Income Taxes                                               343,105          396,897          234,033
Other Taxes                                                299,546          314,071          311,689
                                                       -----------      -----------      -----------
     Total Operating Expenses                            3,378,254        3,182,257        3,211,082
                                                       -----------      -----------      -----------
Operating Income                                           905,396        1,003,899          829,550
                                                       -----------      -----------      -----------

Other Income and Deductions
Allowance for Other Funds Used During Construction          10,222           14,371           10,180
Gain on Sale of Subsidiary                                      --           58,745               --
Income Taxes                                                 3,004          (34,820)         (15,291)
Other, net                                                  (1,976)            (444)          23,121
                                                       -----------      -----------      -----------
     Total Other Income and Deductions                      11,250           37,852           18,010
                                                       -----------      -----------      -----------
Income Before Interest Charges                             916,646        1,041,751          847,560

Interest Charges
Long-Term Debt                                             328,557          386,205          387,279
Company Obligated Mandatorily Redeemable
     Preferred Securities of a Partnership, which
     holds Solely Subordinated Debentures of the
     Company                                                26,723           20,987            8,570
Short-Term Debt                                             53,886           37,506           36,987
                                                       -----------      -----------      -----------
     Total Interest Charges                                409,166          444,698          432,836
Allowance for Borrowed Funds Used During
     Construction                                           (9,725)         (12,679)         (11,989)
                                                       -----------      -----------      -----------
     Net Interest Charges                                  399,441          432,019          420,847
                                                       -----------      -----------      -----------

Net Income                                                 517,205          609,732          426,713
Preferred Stock Dividends                                   18,036           23,217           37,298
                                                       -----------      -----------      -----------
Earnings Applicable to Common Stock                    $   499,169      $   586,515      $   389,415
                                                       ===========      ===========      ===========
Average Shares of Common Stock
     Outstanding (Thousands)                               222,490          221,859          221,554
                                                       ===========      ===========      ===========
Earnings per Average Common Share (Dollars)            $      2.24      $      2.64      $      1.76
                                                       ===========      ===========      ===========
Dividends per Common Share (Dollars)                   $     1.755      $      1.65      $     1.545
                                                       ===========      ===========      ===========
</TABLE>

See Notes to Consolidated Financial Statements.
<PAGE>
22

Consolidated Balance Sheets
<TABLE>
<CAPTION>

At December 31,                                                1996             1995
                                                                Thousands of Dollars
<S>                                                    <C>              <C>
Assets

Utility Plant, at Original Cost
Electric                                               $ 13,622,380     $ 13,441,880
Gas                                                       1,005,507          954,180
Common                                                      317,065          299,899
                                                       ------------     ------------
                                                         14,944,952       14,695,959
     Less Accumulated Provision for Depreciation          5,046,950        4,623,707
                                                       ------------     ------------
                                                          9,898,002       10,072,252
Nuclear Fuel, net                                           199,579          191,084
Construction Work in Progress                               661,871          494,194
Leased Property, net                                        182,088          180,425
                                                       ------------     ------------
     Net Utility Plant                                   10,941,540       10,937,955
                                                       ------------     ------------


Current Assets
Cash and Temporary Cash Investments                          29,235           20,602
Accounts Receivable, net
     Customers                                               19,159           75,220
     Other                                                   74,377           71,997
Inventories, at average cost
     Fossil Fuel                                             84,633           78,260
     Materials and Supplies                                 119,743          123,387
Deferred Energy Costs-Gas                                    30,013           (3,722)
Other                                                        63,234           60,868
                                                       ------------     ------------
     Total Current Assets                                   420,394          426,612
                                                       ------------     ------------


Deferred Debits and Other Assets
Recoverable Deferred Income Taxes                         2,325,721        2,425,311
Deferred Limerick Costs                                     361,762          390,433
Deferred Non-Pension Postretirement Benefits Costs          233,492          248,085
Deferred Energy Costs-Electric                               92,021           59,605
Investments                                                 432,574          318,448
Loss on Reacquired Debt                                     283,853          308,577
Other                                                       169,262          193,479
                                                       ------------     ------------
     Total Deferred Debits and Other Assets               3,898,685        3,943,938
                                                       ------------     ------------

Total Assets                                           $ 15,260,619     $ 15,308,505
                                                       ============     ============
</TABLE>

See Notes to Consolidated Financial Statements.
<PAGE>
                                                                              23
Consolidated Balance Sheets (Continued)

<TABLE>
<CAPTION>
At December 31,                                                 1996            1995
                                                                Thousands of Dollars
<S>                                                      <C>             <C>
Capitalization and Liabilities

Capitalization
Common Shareholders' Equity
     Common Stock                                        $ 3,517,614     $ 3,506,313
     Other Paid-In Capital                                     1,326           1,326
     Retained Earnings                                     1,127,041       1,023,708
                                                         -----------     -----------
                                                           4,645,981       4,531,347
Preferred and Preference Stock
     Without Mandatory Redemption                            199,367         199,367
     With Mandatory Redemption                                92,700          92,700
Company Obligated Mandatorily Redeemable Preferred
     Securities of a Partnership, which holds Solely
     Subordinated Debentures of the Company                  302,182         302,282
Long-Term Debt                                             3,935,514       4,198,283
                                                         -----------     -----------
     Total Capitalization                                  9,175,744       9,323,979
                                                         -----------     -----------

Current Liabilities
Notes Payable, Bank                                          287,500              --
Long-Term Debt Due Within One Year                           283,303         401,003
Capital Lease Obligations Due Within One Year                 49,347          60,320
Accounts Payable                                             212,966         299,731
Taxes Accrued                                                 71,482         107,621
Interest Accrued                                              82,006          88,047
Dividends Payable                                             22,407          20,722
Other                                                         94,353          74,847
                                                         -----------     -----------
     Total Current Liabilities                             1,103,364       1,052,291
                                                         -----------     -----------

Deferred Credits and Other Liabilities
Capital Lease Obligations                                    132,741         120,105
Deferred Income Taxes                                      3,745,242       3,685,534
Unamortized Investment Tax Credits                           336,132         351,569
Pension Obligation                                           224,454         216,283
Non-Pension Postretirement Benefits Obligation               315,058         326,251
Other                                                        227,884         232,493
                                                         -----------     -----------
     Total Deferred Credits and Other Liabilities          4,981,511       4,932,235
                                                         -----------     -----------

Commitments and Contingencies (Notes 3 and 4)

Total Capitalization and Liabilities                     $15,260,619     $15,308,505
                                                         ===========     ===========
</TABLE>

See Notes to Consolidated Financial Statements.

<PAGE>
24

Consolidated Statements of Cash Flows

<TABLE>
<CAPTION>
For the Years Ended December 31,                                1996             1995             1994
                                                                                  Thousands of Dollars
<S>                                                      <C>              <C>              <C>
Cash Flows from Operating Activities
Net Income                                               $   517,205      $   609,732      $   426,713
Adjustments to reconcile Net Income to Net Cash
          provided by Operating Activities:
     Depreciation and Amortization                           566,412          531,299          517,681
     Deferred Income Taxes                                   166,771          183,514          (23,306)
     Gain on Sale of Subsidiary                                   --          (58,745)              --
     Early Retirement and Separation Programs                     --               --          254,106
     Deferred Energy Costs                                   (66,151)         (71,104)         (33,205)
     Amortization of Leased Property                          31,400           42,900           61,900
     Changes in Working Capital:
          Accounts Receivable                                 53,681           (8,198)          23,508
          Inventories                                         (2,729)         (10,872)          18,210
          Accounts Payable                                   (86,765)          (4,686)           5,342
          Other Current Assets and Liabilities               (25,040)           9,641           52,940
     Other Items affecting Operations                         17,461           16,855           (9,175)
                                                         -----------      -----------      -----------
Net Cash Flows from Operating Activities                   1,172,245        1,240,336        1,294,714
                                                         -----------      -----------      -----------

Cash Flows from Investing Activities
Investment in Plant                                         (548,854)        (532,614)        (570,903)
Proceeds from Sale of Subsidiary                                  --          150,000               --
Increase in Other Investments                               (114,126)         (82,041)         (17,951)
                                                         -----------      -----------      -----------
Net Cash Flows from Investing Activities                    (662,980)        (464,655)        (588,854)
                                                         -----------      -----------      -----------

Cash Flows from Financing Activities
Change in Short-Term Debt                                    287,500          (11,499)        (107,851)
Issuance of Common Stock                                      11,301           15,585            2,308
Retirement of Preferred Stock                                     --          (78,105)        (238,800)
Issuance of Company Obligated Mandatorily Redeemable
     Preferred Securities of a Partnership                        --           81,032          221,250
Issuance of Long-Term Debt                                    43,700          182,540          245,100
Retirement of Long-Term Debt                                (427,463)        (575,713)        (397,763)
Loss on Reacquired Debt                                       24,724           12,302           22,125
Dividends on Preferred and Common Stock                     (411,569)        (390,340)        (377,883)
Change in Dividends Payable                                    1,685            5,626           (3,249)
Expenses of Issuing Long-Term Debt and Capital Stock             890             (577)          (9,150)
Capital Lease Payments                                       (31,400)         (42,900)         (61,900)
                                                         -----------      -----------      -----------
Net Cash Flows from Financing Activities                    (500,632)        (802,049)        (705,813)
                                                         -----------      -----------      -----------

Increase/(Decrease) in Cash and Cash Equivalents               8,633          (26,368)              47
Cash and Cash Equivalents at beginning of period              20,602           46,970           46,923
                                                         -----------      -----------      -----------
Cash and Cash Equivalents at end of period               $    29,235      $    20,602      $    46,970
                                                         ===========      ===========      ===========
</TABLE>

See Notes to Consolidated Financial Statements.
<PAGE>
                                                                              25

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      Shares         Amount

<S>                                         <C>           <C>             <C>             <C>               <C>      <C>
Balance at January 1, 1994                     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

Net Income                                                                                     517,205
Cash Dividends Declared
     Preferred Stock
       (at specified annual rates)                                                             (21,042)
     Common Stock ($1.755 per share)                                                          (390,527)
Expenses of Capital Stock Activity                                                                (275)
Capital Stock Activity
     Long-Term Incentive Plan Issuances            370          11,301                          (2,028)
                                               -------     -----------     -----------     -----------       -----    -----------
Balance at December 31, 1996                   222,542     $ 3,517,614     $     1,326     $ 1,127,041       2,921    $   292,067
                                               =======     ===========     ===========     ===========       =====    ===========
</TABLE>

See Notes to Consolidated Financial Statements.

<PAGE>
26

Notes to Consolidated Financial Statements

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 non-utility subsidiaries which are not material. The
unconsolidated subsidiaries are accounted for under the equity method.

Use of Estimates
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.

     Estimates are used in the Company's accounting for unbilled revenue, the
allowance for uncollectible accounts, fuel adjustment clauses, depreciation and
amortization, taxes, reserves for contingencies, employee benefits, certain fair
value and recoverability determinations, and nuclear outage costs, among others.

Accounting for the Effects of Regulation
The Company follows the provisions of Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation," requiring the Company to record the financial statement effects of
the rate regulation to which the Company is currently subject. If a separable
portion of the Company's business no longer meets the provisions of SFAS No. 71,
the Company would be required to eliminate the financial statement effects of
regulation for that portion (see note 3).

Revenues
Electric and gas revenues are recorded as service is rendered or energy is
delivered to customers. At the end of each month, the Company accrues an
estimate for the unbilled amount of energy delivered or services provided to
customers (see note 7).

Fuel and Energy Cost Adjustment Clauses
The Company's classes of service historically have been subject to fuel
adjustment clauses designed to recover or refund the differences between the
actual cost of fuel, energy interchange, 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 were deferred and recovered
or refunded in future periods by means of prospective adjustments to rates.
Generally, such rates were adjusted every twelve months.

     In response to a Company proposal requesting the elimination of the Energy
Cost Adjustment (ECA), the PUC approved the roll-in of energy costs into the
base rates charged to the Company's electric customers. Effective December 31,
1996, the Company's classes of electric service are no longer subject to the
ECA.

     The Company's PUC-established Purchased Gas Cost Adjustment (PGC) which
allows for the recovery of the difference between actual purchased gas costs and
the amounts of such costs included in the base rates charged to the Company's
natural gas customers will continue to be in effect subsequent to January 1,
1997.

Nuclear Fuel
The cost of 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 percentage of average depreciable
utility plant in service, were approximately 2.90% in 1996, 2.80% in 1995 and
2.77% in 1994. See note 3 for information concerning the change in 1996 to
depreciation and amortization.

     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 realized 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 credits are deferred and amortized to income over the
estimated useful life of the related utility plant (see note 13).

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 9.38% in 1996, 9.88% in 1995 and 7.74% in 1994, are computed under a
method prescribed by regulatory authorities. AFUDC is not included in regular

<PAGE>
                                                                              27

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, 1996
and 1995, capitalized software costs totaled $78 million and $65 million (net of
$29 million and $19 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 period approved for rate-making purposes.

Impairment of Long-Lived Assets
Effective January 1, 1996, under SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," long-lived
assets are subject to periodic analysis for impairment. No loss from impairment
has been recorded in 1996.

Reclassifications
Certain prior-year amounts have been reclassified for comparative purposes.
These reclassifications had no effect on net income or common shareholders'
equity.

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 3.6 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,                     1996            1995           1994
                                                                    Thousands of Dollars
<S>                                           <C>             <C>            <C>
Electric Operations
Operating revenues:
Residential                                   $ 1,370,158     $ 1,379,046    $ 1,371,237
Small commercial and industrial                   748,561         730,220        710,028
Large commercial and industrial                 1,098,307       1,135,550      1,149,193
Other                                             140,133         136,988        136,002
(Decrease)/increase in unbilled                   (25,950)         42,580        (11,130)
                                              -----------     -----------    -----------
     Service territory                          3,331,209       3,424,384      3,355,330
Interchange sales                                  25,991          17,488         23,017
Sales to other utilities                          497,636         333,454        246,450
                                              -----------     -----------    -----------
     Total operating revenues                   3,854,836       3,775,326      3,624,797
                                              -----------     -----------    -----------
Operating expenses, excluding depreciation      2,560,669       2,405,876      2,429,452
Depreciation                                      462,315         430,993        415,854
                                              -----------     -----------    -----------
     Operating income                         $   831,852     $   938,457    $   779,491
                                              ===========     ===========    ===========
Utility plant additions                       $   447,105     $   435,400    $   457,728
                                              ===========     ===========    ===========
</TABLE>
<PAGE>
28

<TABLE>
<CAPTION>
For the Years Ended December 31,                                1996             1995            1994
                                                                                 Thousands of Dollars
<S>                                                     <C>              <C>             <C>
Gas Operations
Operating revenues:
Residential                                             $     15,716     $     15,482    $     16,048
House heating                                                249,507          235,456         237,397
Commercial and industrial                                    132,822          125,631         128,077
Other                                                         11,462            5,382          20,168
(Decrease)/increase in unbilled                               (4,250)           6,540          (3,140)
                                                        ------------     ------------    ------------
     Subtotal                                                405,257          388,491         398,550
                                                        ------------     ------------    ------------
Other revenues (including transported for customers)          23,557           22,339          17,285
                                                        ------------     ------------    ------------
     Total operating revenues                                428,814          410,830         415,835
                                                        ------------     ------------    ------------
Operating expenses, excluding depreciation                   328,585          319,127         339,529
Depreciation                                                  26,686           26,261          26,247
                                                        ------------     ------------    ------------
     Operating income                                   $     73,543     $     65,442    $     50,059
                                                        ============     ============    ============
Utility plant additions                                 $     68,394     $     63,192    $     67,090
                                                        ============     ============    ============

Identifiable Assets* at December 31,
Electric                                                $ 10,287,444     $ 10,408,105    $ 10,410,461
Gas                                                          858,471          785,881         768,279
Nonallocable assets                                        4,114,704        4,114,519       4,243,410
                                                        ------------     ------------    ------------
     Total assets                                       $ 15,260,619     $ 15,308,505    $ 15,422,150
                                                        ============     ============    ============

<FN>
*    Includes utility plant less accumulated depreciation, inventories and
     allocated common utility property.
</FN>
</TABLE>


3. Rate Matters

Competition Act
The recently enacted electricity generation customer choice and competition Act
(Competition Act) provides for the restructuring of the electric industry in
Pennsylvania, including retail competition for generation beginning in 1999. At
that date, the Company expects it will no longer meet the criteria of SFAS No.
71 for the retail generation portion of its operations. The Competition Act
requires the unbundling of electric services into separate generation,
transmission and distribution services with open retail competition for
generation. Electric distribution and transmission services will remain
regulated by the PUC. The Competition Act requires utilities to submit to the
PUC restructuring plans, including their stranded costs which will result from
competition. Stranded costs include regulatory assets (see note 22), nuclear
decommissioning costs and long-term purchased power commitments, for which full
recovery is allowed, and other costs including investment in generating plants,
spent fuel disposal, retirement costs and reorganization costs, for which an
opportunity for recovery is allowed in an amount determined by the PUC as just
and reasonable. These costs, after mitigation by the utility, are to be
recovered and collected from distribution customers for up to nine years (or for
an alternative period determined by the PUC for good cause shown). During that
period, the utility is subject to a rate cap providing that total charges to
customers cannot exceed rates in place as of December 31, 1996, subject to
certain exceptions.

     The Company estimates that its stranded costs resulting from retail
generation competition at December 31, 1998 will be $7.1 billion. This estimate
includes $3.9 billion of generating assets, $560 million of unfunded and as yet
unrecorded decommissioning expenses and $2.6 billion of regulatory assets. On
January 22, 1997, the Company filed an Application with the PUC seeking to
recover $3.6 billion of its stranded costs and to securitize that recovery
through the issuance by a third party assignee of $3.9 billion of Transition
Bonds. The Company intends to seek recovery of the remaining $3.5 billion of its
stranded costs in the Company's restructuring filing mandated by the Competition
Act. To the extent the Company is not ultimately permitted by the PUC to recover
its retail electric stranded costs, this amount could result in a charge against
earnings. However, as of December 31, 1996, there is no impairment of its
generation assets under SFAS No. 121, and given the stranded cost recovery
provisions of the Competition Act, the Company believes that it will be given
the opportunity for full recovery of its regulatory assets.


     Under the Competition Act, the Company is required to use the proceeds it
receives from any securitization of the recovery of stranded assets principally
to reduce qualified stranded costs and related capitalization. In the
Application, the Company proposes using the proceeds it receives resulting from
the issuance of the Transition Bonds to pay estimated transaction and use of
proceeds costs of $277 million, to settle deferred fuel balances of $240 million
and to reduce capitalization by approximately $3.4 billion. The capitalization
reduction is expected to be proportionate to the Company's current
capitalization.

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 a nine year period beginning October 1, 1996. 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, 1996, the
unrecovered portion of these balances


<PAGE>
                                                                              29

were $228 and $46 million, respectively.

     Under its electric tariffs and ECA, the Company was 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 1996, 1995 and 1994, the Company recorded as revenue net of fuel costs
$82, $79 and $68 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 issued in 1990, 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, 1996 and 1995, such costs included in
Deferred Limerick Costs totaled $88 and $91 million, respectively. These costs
are included in base rates and are being recovered over a nine year period
beginning October 1, 1996.

Declaratory Accounting Order
Pursuant to a PUC Declaratory Order, effective October 1, 1996, the Company
increased depreciation and amortization on assets associated with Limerick by
$100 million per year and decreased depreciation and amortization on other
Company assets by $10 million per year, for a net increase in depreciation and
amortization of $90 million per year.

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 SFAS No.
106, "Employers' Accounting for Postretirement Benefits Other Than Pensions,"
(see note 6). 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
1996 and 1995, the Company deposited $46.5 and $59.6 million, respectively, 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 a December 1994 PUC approved accounting order, the
Company is recognizing $2.8 million in non-pension postretirement benefits costs
annually associated with gas utility operations. During 1996 and 1995, the
Company deposited $2.9 and $3.8 million, respectively, in trust accounts to fund
its gas non-pension postretirement benefits costs.

Energy Cost Adjustment
Through December 31, 1996, the Company was subject to a PUC-established electric
ECA which, in addition to reconciling fuel costs and revenues, incorporated a
nuclear performance standard which allowed for financial bonuses or penalties
depending on whether the Company's system nuclear capacity factor exceeded or
fell below a specified range. For the years ended December 31, 1996, 1995 and
1994, the Company recorded bonuses of $22, $13 and $14 million, respectively.

4. Commitments and Contingencies

Capital Commitments
Total construction program expenditures primarily for utility plant are
estimated to be $560 million for 1997 and $1,225 million for the period 1998 to
2000. Construction expenditure estimates are reviewed and revised periodically
to reflect changes in economic conditions 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. Additionally, for
the period 1997 through 2000, the Company plans to invest approximately
$200-$300 million in other new ventures which includes telecommunications
activities.

     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 currently limits the liability of nuclear reactor owners
to $8.9 billion for claims that could arise from a single incident. The limit is
subject to change to account for the effects of inflation and changes in the
number of licensed reactors. The Company carries the maximum available
commercial insurance of $200 million and the remaining $8.7 billion is provided
through 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.

     The Company carries property damage, decontamination and premature
decommissioning insurance in the amount of its $2.75 billion proportionate share
for each station loss resulting from damage to its nuclear plants. 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 Nuclear Regulatory Commission (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 $31 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 $13 million per year.

Nuclear Decommissioning and Spent Fuel Storage
The Company's 1990 estimate of its nuclear facilities' decommissioning cost of
$643 million is being collected through electric base rates over the life of
each generating unit. Under

<PAGE>
30

current rates, the Company collects and expenses approximately $20 million
annually from customers. The expense is accounted for as a component of
depreciation expense and accumulated depreciation. At December 31, 1996 and
1995, $256 and $216 million, respectively, was included in accumulated
depreciation. In order to fund future decommissioning costs, at December 31,
1996 and 1995, the Company held $266 and $223 million, respectively, in trust
accounts which are included as an Investment in the Company's Consolidated
Balance Sheet and include both net unrealized and realized gains. Net unrealized
gains of $26 and $19 million were recognized as a Deferred Credit in the
Company's Consolidated Balance Sheet at December 31, 1996 and 1995,
respectively. The Company recognized net realized gains of $10, $9 and $7
million as Other Income in the Company's Consolidated Statement of Income for
the years ended December 31, 1996, 1995 and 1994 respectively. The most recent
estimate of the Company's share of the cost to decommission its nuclear units is
$1.4 billion in 1995 dollars. The Company has included the unfunded and as yet
unrecorded portion of the decommissioning trust fund estimate in its January 22,
1997 application with the PUC.

     In an exposure draft issued in 1996, the Financial Accounting Standards
Board (FASB) proposed changes in the accounting for closure and removal costs of
production facilities, including the recognition, measurement and classification
of decommissioning costs for nuclear generating stations. The FASB is currently
considering expanding the scope of the Exposure Draft to include closure or
removal liabilities that are incurred at any time in the operating life of the
long-lived asset. The FASB plans to issue either a final Statement or a revised
Exposure Draft in the second quarter of 1997. 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. Based on recent public pronouncements, it is not likely that a permanent
disposal site will be available for the industry before 2015, at the earliest.
In reaction to statements from the DOE that it was not legally obligated to
begin to accept spent fuel in 1998, a group of utilities and state government
agencies filed a lawsuit against the DOE which resulted in a decision by the
United States Court of Appeals for the District of Columbia (D.C. Court of
Appeals) in July 1996 that the DOE had an unequivocal obligation to begin to
accept spent fuel in 1998. In accordance with the NWPA, the Company pays the DOE
one mill ($.001) per kilowatthour of net nuclear generation for the cost of
nuclear fuel disposal. This fee may be adjusted prospectively in order to ensure
full cost recovery. Because of inaction by the DOE in response to the D.C. Court
of Appeals finding of the DOE's obligation to begin receiving spent fuel in
1998, a group of thirty-six utility companies, including the Company, and
forty-six state agencies, filed suit against the DOE on January 31, 1997 seeking
authorization to suspend further payments to the U.S. government under the NWPA
and to deposit such payments into an escrow account until such time as the DOE
takes effective action to meet its 1998 obligations. Legislation introduced in
Congress in January 1997 would authorize construction of a temporary storage
facility which could accept spent nuclear fuel from utilities soon after 1998.
In addition, the DOE is exploring other options to address delays in the waste
acceptance schedule.

     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 on-site facilities with spent fuel
storage capacity through 2008 for Unit No. 1 and 2012 for Unit No. 2. Public
Service Electric and Gas Company (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, although such recovery is not assured.

Energy Purchases
In the ordinary course of business, the Company enters into commitments to buy
and sell power. As of December 31,1996, the Company had long-term aggreements to
purchase from unaffiliated utilities, primarily in 1997, energy associated with
2,200 MW of capacity. During 1996, purchases under long-term agreements resulted
in expenditures of $44 million. At December 31, 1996, these purchases result in
commitments of approximately $259 million for 1997, $48 million for 1998, $51
million for 1999, $52 million for 2000 and $50 million for 2001. These purchases
will be utilized through a combination of sales to jurisdictional customers
primarily to compensate for the Salem shutdown, long-term sales to other
utilities and open market 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 27 sites where former manufactured gas plant
(MGP) activities have or may 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. Eight of the sites are under some degree of active study or
remediation.

     As of December 31, 1996 and 1995, the Company had accrued $28 and $27
million, respectively, for environmental investigation and remediation costs,
including $16 and $13 million, respectively, for MGP investigation and
remediation, that currently can be reasonably estimated. The Company cannot
predict whether it will incur other significant liabilities for addi-


<PAGE>
                                                                              31

tional 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 from third parties.

Shutdown of Salem Generating Station
PSE&G removed Salem Units No. 1 and No. 2 from service in the second quarter of
1995 and 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 estimates the projected restart of Unit No. 2 to occur in the
second quarter of 1997 and of Unit No. 1 to occur in the summer of 1997. It is
the Company's belief that the earliest that Unit No. 1 will return to service is
late in the third quarter of 1997. For the years ended December 31, 1996 and
1995, the Company had incurred and expensed approximately $149 million and $50
million of replacement power and maintenance costs, respectively.

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

5. 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
80%, 74% and 85% of pension costs were charged to operations in 1996, 1995 and
1994, respectively, and the remainder, associated with construction labor, to
the cost of new utility plant.

Pension costs for 1996, 1995 and 1994 included the following components:

<TABLE>
<CAPTION>
                                                       1996          1995          1994
<S>                                               <C>           <C>           <C>
                                                                   Thousands of Dollars
Service cost benefits earned during the period    $  27,627     $  19,710     $  33,403
Interest cost on projected benefit obligation       145,570       147,261       136,690
Actual return on plan assets                       (320,247)     (456,057)       12,946
Amortization of transition asset                     (4,538)       (4,538)       (4,538)
Amortization and deferral                           154,402       300,214      (161,955)
                                                  ---------     ---------     ---------
     Net pension cost                             $   2,814     $   6,590     $  16,546
                                                  =========     =========     =========
</TABLE>


The changes in net periodic pension costs in 1996, 1995 and 1994 were as
follows:

<TABLE>
<CAPTION>
                                                          1996         1995         1994
<S>                                                   <C>          <C>          <C>
                                                                     Thousands of Dollars
Change in number, characteristics and salary
     levels of participants and net actuarial gain    $(12,893)    $  1,486     $ (6,004)
Change in plan provisions                                   --       (8,305)      (1,777)
Change in actuarial assumptions                          9,117       (3,136)        (959)
                                                      --------     --------     --------
     Net change                                       $ (3,776)    $ (9,955)    $ (8,740)
                                                      ========     ========     ========
</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 1996, 1995 and 1994.

     The weighted-average discount rate used in determining the actuarial
present value of the projected benefit obligation was 7.75% at December 31,
1996, 7.25% at December 31, 1995 and 8.25% at December 31, 1994. The average
rate of increase in future compensation levels ranged from 4% to 6% at December
31, 1996 and 1995, and from 4.25% to 6.25% at December 31, 1994.

     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.
<PAGE>
32

The funded status of the plan at December 31, 1996 and 1995 is summarized as
follows:

<TABLE>
<CAPTION>
                                                                           1996            1995
                                                                           Thousands of Dollars
<S>                                                                 <C>             <C>
Actuarial present value of accumulated plan benefit obligations:
Vested benefit obligation                                           $(1,657,098)    $(1,746,685)
Accumulated benefit obligation                                       (1,742,116)     (1,838,661)

Projected benefit obligation for services rendered to date          $(1,982,915)    $(2,097,300)
Plan assets at fair value                                             2,302,935       2,088,950
                                                                    -----------     -----------
     Funded status                                                      320,020          (8,350)
Unrecognized transition asset                                           (40,251)        (44,789)
Unrecognized prior service costs                                         92,682          68,223
Unrecognized net gain                                                  (588,013)       (265,472)
                                                                    -----------     -----------
     Pension liability recognized on the balance sheet              $  (215,562)    $  (250,388)
                                                                    ===========     ===========
</TABLE>

6. 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, which represents the previously unrecognized
accumulated non-pension postretirement benefit obligation, is being amortized on
a straight-line basis over an allowed 20-year period. As a result of voluntary
retirement and separation programs in 1994, the Company accelerated recognition
of $177 million of its non-pension postretirement benefits obligation (see note
21).

     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 8% in 1997 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 $68 million
and the annual service and interest costs by $8 million.

     Total costs for all plans amounted to $71 million in 1996 and 1995 and $81
million in 1994.

The net periodic benefits costs for 1996 and 1995 included the following
components:

<TABLE>
<CAPTION>
                                                      1996         1995         1994
<S>                                               <C>          <C>          <C>
                                                                Thousands of Dollars
Service cost benefits earned during the period    $ 11,855     $  8,681     $ 17,056
Interest cost on projected benefit obligation       48,524       48,641       41,196
Amortization of transition asset                    14,882       14,882       22,659
Actual return on plan assets                       (13,257)      (2,075)          --
Deferred asset gain                                  9,320        1,359           --
                                                  --------     --------     --------
     Net postretirement benefits costs            $ 71,324     $ 71,488     $ 80,911
                                                  ========     ========     ========
</TABLE>

Plan assets consist principally of common stock, U.S. government obligations and
other fixed income instruments. In determining non-pension postretirement
benefits costs, the assumed long-term rate of return on assets was 8% for 1996,
1995 and 1994.

     The weighted-average discount rate used in determining the actuarial
present value of the projected benefit obligation was 7.50% as of January 1,
1996, 8.50% as of January 1, 1995 and 7.25% at January 1, 1994. The average rate
of increase in future compensation levels ranged from 4% to 6% at December 31,
1996 and 1995, and from 4.25% to 6.25% at December 31, 1994.

     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.

<PAGE>
                                                                              33

The funded status of the plan at December 31, 1996 and 1995 is summarized as
follows:

<TABLE>
<CAPTION>
                                                                                    1996          1995
<S>                                                                            <C>           <C>
                                                                                  Thousands of Dollars
Accumulated postretirement benefit obligation:
Retirees                                                                       $ 609,206     $ 628,804
Fully eligible active plan participants                                            4,509         4,199
Other active plan participants                                                    48,986        41,863
                                                                               ---------     ---------
     Total                                                                       662,701       674,866
Plan assets at fair value                                                       (126,661)      (66,735)
                                                                               ---------     ---------
     Accumulated postretirement benefit obligation in excess of plan assets      536,040       608,131
Unrecognized transition obligation                                              (238,108)     (252,990)
Unrecognized net gain                                                            (17,126)      (28,890)
                                                                               ---------     ---------
     Accrued postretirement benefits cost recognized on the balance sheet      $ 315,058     $ 326,251
                                                                               =========     =========
</TABLE>

Measurement of the accumulated postretirement benefits obligation was based on a
7.75% and 7.5% assumed discount rate as of December 31, 1996 and 1995,
respectively.

For the regulatory treatment of non-pension postretirement benefits costs, see
note 3.

7. Accounts Receivable

Accounts receivable at December 31, 1996 and 1995 included unbilled operating
revenues of $117 and $148 million, respectively. Accounts receivable at December
31, 1996 and 1995 were net of an allowance for uncollectible accounts of $24 and
$21 million, respectively.

     The Company is party to an agreement with a financial institution under
which it sold with limited recourse an undivided interest, adjusted daily, in up
to $425 million of designated accounts receivable until November 14, 2000. At
December 31, 1996 and 1995, the Company had sold a $425 million interest in
accounts receivable. 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, 1996, $23 million of deferred Limerick costs were included in the
pool of eligible receivables.

8. Common Stock

At December 31, 1996 and 1995, common stock without par value consisted of
500,000,000 shares authorized and 222,542,087 and 222,172,216 shares
outstanding, respectively. At December 31, 1996, there were 5,800,841 shares
reserved for issuance under the dividend reinvestment and stock purchase plan.

Long-Term Incentive Plan (LTIP)

The Company maintains an 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. The Company has
adopted the disclosure-only provisions of SFAS No. 123, "Accounting for
Stock-Based Compensation," but applies Accounting Principles Board (APB) Opinion
No. 25, "Accounting for Stock Issued to Employees" and related interpretations
in accounting for the LTIP. If the Company had elected to account for the LTIP
based on SFAS No. 123, earnings applicable to common stock and earnings per
average common share would have been changed to the pro forma amounts as
indicated below:

<TABLE>
<CAPTION>
                                                                            1996          1995
                                                                          Thousands of Dollars

<S>                                             <C>                     <C>           <C>
Earnings applicable to common stock             As reported             $499,169      $586,515
                                                Pro forma               $497,887      $585,063

Earnings per average common share (Dollars)     As reported             $   2.24      $   2.64
                                                Pro forma               $   2.24      $   2.64
</TABLE>
<PAGE>
34

Options granted under the LTIP become exercisable on the anniversary of the date
of grant and all options expire 10 years from the date of the grant. Information
with respect to the LTIP at December 31, 1996 and changes for the three years
then ended, is as follows:

<TABLE>
<CAPTION>
                                                    Weighted                    Weighted                     Weighted
                                                     Average                     Average                      Average
                                                    Exercise                    Exercise                     Exercise
                                                       Price                       Price                        Price
                                        Shares   (per share)        Shares   (per share)        Shares    (per share)
                                          1996          1996          1995          1995          1994          1994

<S>                                  <C>           <C>           <C>           <C>           <C>           <C>
Balance at  January 1                2,591,765     $   26.16     2,651,397     $   26.73     1,961,882     $   25.12
Options granted                        786,500         28.12       850,700         26.46       909,000         30.13
Options exercised                     (369,871)        25.07      (561,232)        23.91       (90,885)        22.91
Options cancelled                      (47,200)        29.36      (349,100)        35.57      (128,600)        28.87
                                     ---------                   ---------                   ---------
Balance at December 31               2,961,194         26.68     2,591,765         26.16     2,651,397         26.73
                                     =========                   =========                   =========
Exercisable at December 31           2,192,694         26.17     1,813,565         25.91     1,865,397         25.21
Weighted average fair value of
     options granted during year                   $    2.78                   $    2.91                   $      --
</TABLE>

The fair value of each option is estimated on the date of the grant using the
Black-Scholes option-pricing model.

     The following weighted average assumptions were used for grants in 1996:
dividend yield of 6.2%, expected volatility of 16.6%, risk-free interest rate of
5.5%, and an expected life of five years. The following weighted average
assumptions were used for grants in 1995: dividend yield of 6.2%, expected
volatility of 15.3%, risk-free interest rate of 6.9%, and an expected life of
five years.

     At December 31, 1996, the option groups outstanding based on ranges of
exercise prices is as follows:

<TABLE>
<CAPTION>
                                          Options Outstanding                     Options Exercisable
                                                  Weighted-
                                                    Average    Weighted-                      Weighted-
                                                  Remaining      Average                        Average
                                  Number   Contractual Life     Exercise          Number       Exercise
Range of Exercise Prices     Outstanding            (Years)        Price     Exercisable          Price

<C>                            <C>                   <C>       <C>             <C>           <C>
$15.75 - $20.00                  117,594               3.86      $ 18.43         117,594       $  18.43
$20.01 - $25.00                  155,500               4.75        22.70         125,500          22.37
$25.01 - $30.00                2,675,900               7.63        27.23       1,941,400          26.86
$30.01 - $50.00                   12,200               7.55        37.18           8,200          30.93
                               ---------                                       ---------
     Total                     2,961,194                                       2,192,694
                               ---------                                       ---------
</TABLE>

9. Preferred and Preference Stock

At December 31, 1996 and 1995, Series Preference Stock consisted of 100,000,000
shares authorized, of which no shares were outstanding. At December 31, 1996 and
1995, 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)             1996            1995           1996            1995
<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         618,954         61,895          61,895
$7.48                                       (d)          500,000         500,000         50,000          50,000
                                                       ---------       ---------     ----------     -----------
                                                       1,993,674       1,993,674        199,367         199,367
Series (with mandatory redemption)
$6.12                                       (e)          927,000         927,000         92,700          92,700
                                                       ---------       ---------     ----------     -----------
     Total preferred stock                             2,920,674       2,920,674     $  292,067     $   292,067
                                                       =========       =========     ==========     ===========
<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.
(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 1997-1998.
     Annual sinking fund requirements in 1999 are $18,540,000. None of the
     shares of this series are subject to redemption prior to August 1, 1999.
</FN>
</TABLE>


<PAGE>
                                                                              35
10.  Company Obligated Mandatorily Redeemable Preferred Securities of a
     Partnership (COMRPS)

At December 31, 1996 and 1995, 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>
                                                                                                 Amount
                                                             Shares Outstanding          Thousands of Dollars
At December 31,         Due     Distribution Rate            1996           1995           1996           1995
Series
<S>                    <C>                  <C>         <C>            <C>          <C>            <C>
A                      2043                 9.00%       8,850,000      8,850,000    $   221,250    $   221,250
B (a)                  2025                 8.72%       3,124,183      3,124,183         80,932         81,032
                                                       ----------     ----------    -----------    -----------
     Total                                             11,974,183     11,974,183    $   302,182    $   302,282
                                                       ==========     ==========    ===========    ===========
<FN>
(a)  Ownership of this series is evidenced by Trust Receipts, each representing
     a 8.72% COMRPS, Series B, representing limited partnership interests. 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>

11. Long-Term Debt
<TABLE>
<CAPTION>
At December 31,                                              Series           Due           1996            1995
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
                                                     5 5/8%-7 3/8 %          2001        330,000         330,000
                                                         6 3/8%-8 %     2002-2006      1,025,000       1,025,000
                                                           10 1/4 %     2007-2011         44,688          48,750
                                                                (b)     2012-2016        154,200         188,200
                                                    6 7/10%-7 3/5 %     2017-2021        277,590         277,590
                                                     6 5/8%-8 3/4 %     2022-2024      1,329,540       1,329,540
                                                                                     -----------     -----------
Total first and refunding mortgage bonds                                               3,786,018       3,824,080
Notes payable - banks                                                                         --         167,000
Term loan agreements                                            (c)          1997        175,000         350,000
Pollution control notes                                         (d)     1997-2034        212,705         169,005
Medium-term notes                                               (e)     1997-2005         74,400         121,800
Unamortized debt discount and premium, net                                               (29,306)        (32,599)
                                                                                     -----------     -----------
Total long-term debt                                                                   4,218,817       4,599,286
Due within one year (f)                                                                  283,303         401,003
                                                                                     -----------     -----------
     Long-term debt included in capitalization (g)                                   $ 3,935,514     $ 4,198,283
                                                                                     ===========     ===========
<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 3.532% at
     December 31, 1996.
(c)  The average annual rate in 1996 was 5.94%. The Company also has a $400
     million revolving credit and term loan agreement with a group of banks
     which terminates in 2001. There is an annual commitment fee of 0.125% on
     the unused amount. There was no debt outstanding under this agreement at
     December 31, 1996.
(d)  Floating rates, which were an average annual interest rate of 3.620% at
     December 31, 1996.
(e)  Medium-term notes collateralized by mortgage bonds. The average annual
     interest rate was 8.465% at December 31, 1996.
(f)  Long-term debt maturities, including mandatory sinking fund requirements,
     in the period 1997-2001 are as follows: 1997 - $283,303,000; 1998 -
     $241,463,000; 1999 - $359,063,000; 2000 - $4,063,000; 2001 - $334,063,000.
(g)  The annualized interest on long-term debt at December 31, 1996, was $292
     million, of which $274 million was associated with mortgage bonds and $18
     million was associated with other long-term debt.
</FN>
</TABLE>
<PAGE>
36

12. Short-Term Debt
<TABLE>
<CAPTION>
                                                          1996         1995            1994
                                                                       Thousands of Dollars
<S>                                                <C>             <C>          <C>
Average borrowings                                 $   198,090     $ 17,560     $   130,539
Average interest rates, computed on daily basis           5.64%        6.25%           4.03%
Maximum borrowings outstanding                     $   369,500     $182,000     $   418,600
Average interest rates, at December 31                    6.90%          --            6.73%
</TABLE>

The Company has a $300 million commercial paper program which is supported by
the $400 million revolving credit agreement (see note 11); at December 31, 1996,
$200 million was outstanding. In 1996, $87.5 million of a term loan agreement
with a group of banks was refinanced with a single bank as short-term debt under
a 364-day term loan facility; at December 31, 1996, $87.5 million was
outstanding. At December 31, 1996, the Company had formal and informal lines of
credit with banks aggregating $275 million. No short-term debt was outstanding
against these lines at that date.

13. Income Taxes

Income tax expense is comprised of the following components:

<TABLE>
<CAPTION>
For the Years Ended December 31,                 1996          1995          1994
                                                             Thousands of Dollars
<S>                                         <C>           <C>           <C>
Included in operating income:
Federal
     Current                                $ 126,702     $ 170,042     $ 164,472
     Deferred                                 156,129       159,970        (2,691)
     Investment tax credit, net               (15,979)      (21,679)       28,006
State
     Current                                   63,447        72,177        77,754
     Deferred                                  12,806        16,387       (33,508)
                                            ---------     ---------     ---------
                                              343,105       396,897       234,033
                                            =========     =========     =========
Included in other income and deductions:
Federal
     Current                                     (231)       20,754         1,989
     Deferred                                  (1,565)        7,556         9,722
State
     Current                                     (608)        6,909           409
     Deferred                                    (600)         (399)        3,171
                                            ---------     ---------     ---------
                                               (3,004)       34,820        15,291
                                            ---------     ---------     ---------
     Total                                  $ 340,101     $ 431,717     $ 249,324
                                            =========     =========     =========
</TABLE>

The total income tax provisions differed from amounts computed by applying the
federal statutory tax rate to income as shown below:
<TABLE>
<CAPTION>
                                                                 1996             1995             1994
                                                                                   Thousands of Dollars
<S>                                                       <C>              <C>              <C>
Net Income                                                $   517,205      $   609,732      $   426,713
Total income tax provisions                                   340,101          431,717          249,324
                                                          -----------      -----------      -----------
     Income before income taxes                           $   857,306      $ 1,041,449      $   676,037
                                                          ===========      ===========      ===========

Income taxes on above at federal statutory rate at 35%    $   300,057      $   364,507      $   236,613
Increase (decrease) due to:
Depreciation timing differences not normalized                  7,924           14,127           12,767
Limerick plant disallowances and phase-in plan                   (651)            (736)            (530)
AFUDC                                                          (6,981)          (9,467)          (7,759)
State income taxes, net of federal income tax benefit          48,779           61,799           31,086
Amortization of investment tax credit                         (15,979)         (13,604)         (14,570)
Prior period income taxes                                      (1,707)           1,791          (14,524)
Other, net                                                      8,659           13,300            6,241
                                                          -----------      -----------      -----------
     Total income tax provisions                          $   340,101      $   431,717      $   249,324
                                                          ===========      ===========      ===========
Effective Income Tax rate                                        39.7%            41.5%            36.9%
</TABLE>
<PAGE>
                                                                              37

Provisions for deferred income taxes consist of the tax effects of the following
temporary differences:
<TABLE>
<CAPTION>
                                                                   1996          1995          1994
                                                                               Thousands of Dollars
<S>                                                           <C>           <C>           <C>
Depreciation and amortization                                 $  42,385     $  32,287     $  85,772
Deferred energy costs                                            27,374        30,073        13,777
Retirement and separation programs                               19,746        15,733       (82,008)
Incremental nuclear maintenance and refueling outage costs        2,440         8,079        (2,751)
Uncollectible accounts                                           (2,805)       (1,991)      (23,096)
Reacquired debt                                                  (9,578)       (3,266)      (12,954)
Unrecovered revenue                                               3,910            (5)       (2,239)
Environmental clean-up costs                                       (714)        2,433        (3,949)
Obsolete inventory                                                5,829         6,362        (6,192)
Limerick plant disallowances and phase-in plan                     (747)        2,507        12,894
AMT credits                                                      83,010        91,399            --
Other                                                            (4,080)          (97)       (2,560)
                                                              ---------     ---------     ---------
     Total                                                    $ 166,770     $ 183,514     $ (23,306)
                                                              =========     =========     =========
</TABLE>
The tax effect of temporary differences which gives rise to the Company's net
deferred tax liability as of December 31, 1996 and 1995 are as follows:
<TABLE>
<CAPTION>
                                                       Liability or (Asset)
                                                            1996        1995
                                                         Millions of Dollars
<S>                                                      <C>         <C>
Nature of temporary difference
Plant basis difference                                   $ 3,796     $ 3,797
Deferred investment tax credit                               336         351
Deferred debt refinancing costs                              120         130
Other, net                                                  (168)       (249)
                                                         -------     -------
     Deferred income taxes (net) on the balance sheet    $ 4,084     $ 4,029
                                                         =======     =======
</TABLE>

The net deferred tax liability shown above as of December 31, 1996 and 1995 is
comprised of $4,347 and $4,401 million of deferred tax liabilities, and $263 and
$372 million of deferred tax assets, respectively.

     In accordance with SFAS No. 71, the Company has recorded a recoverable
deferred income tax asset of $2,322 million and $2,420 million at December 31,
1996 and 1995, respectively (see note 22). These recoverable deferred income
taxes include the deferred tax effects associated principally with liberalized
depreciation accounted for in accordance with the ratemaking policies of the
PUC, as well as the revenue impacts thereon, and assume recovery of these costs
in future rates.

     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. The years 1991 through 1993 are currently being examined by the IRS.

     Investment tax credits and other general business credits were fully
utilized for tax purposes at December 31, 1994 and reduced federal income taxes
currently payable by $43 million in 1994. The AMT credit was fully utilized for
tax purposes at December 31, 1996, and reduced federal income taxes currently
payable by $71 million in 1996.

14. Taxes, Other Than Income - Operating
<TABLE>
<CAPTION>
For the Years Ended December 31,        1996        1995        1994
                                                Thousands of Dollars
<S>                                 <C>         <C>         <C>
Gross receipts                      $160,246    $165,172    $160,704
Capital stock                         41,972      42,444      39,957
Real estate                           69,185      71,600      77,571
Payroll                               27,585      30,109      31,556
Other                                    558       4,746       1,901
                                    --------    --------    --------
     Total                          $299,546    $314,071    $311,689
                                    ========    ========    ========
</TABLE>
<PAGE>
38

15. Leases

Leased property included in utility plant at December 31, was as follows:

<TABLE>
<CAPTION>
                                 1996          1995
                               Thousands of Dollars
<S>                         <C>           <C>
Nuclear fuel                $ 527,116     $ 494,051
Electric plant                  2,069         2,076
                            ---------     ---------
Gross leased property         529,185       496,127
Accumulated amortization     (347,097)     (315,702)
                            ---------     ---------
     Net leased property    $ 182,088     $ 180,425
                            =========     =========
</TABLE>

The nuclear fuel obligation is amortized as the fuel is consumed. Amortization
of leased property totaled $31, $43 and $62 million for the years ended December
31, 1996, 1995 and 1994, respectively. Other operating expenses included
interest on capital lease obligations of $9, $10 and $7 million in 1996, 1995
and 1994, respectively.

Minimum future lease payments as of December 31, 1996 were:
<TABLE>
<CAPTION>
For the Year Ending December 31,                         Capital Leases    Operating Leases           Total
                                                                                       Thousands of Dollars
<C>                                                          <C>                <C>             <C>
1997                                                         $   49,804         $    47,919     $    97,723
1998                                                             54,595              44,541          99,136
1999                                                             45,751              42,339          88,090
2000                                                             22,267              41,534          63,801
2001                                                             20,305              40,632          60,937
Remaining years                                                  18,598             554,412         573,010
                                                             ----------         -----------     -----------
Total minimum future lease payments                          $  211,320         $   771,377     $   982,697
                                                                                ===========     ===========
Imputed interest (rates ranging from 6.5% to 17.0%)             (29,232)
                                                             ----------
        Present value of net minimum future lease payments   $  182,088
                                                             ==========
</TABLE>

Rental expense under operating leases totaled $74, $115 and $101 million in
1996, 1995 and 1994, respectively.

16. Jointly Owned Electric Utility Plant

The Company's ownership interests in jointly owned electric utility plant at
December 31, 1996 were as follows:

<TABLE>
<CAPTION>
                                                                                                       Transmission
                                                               Production Plants                     and Other Plant
                                        Peach Bottom          Salem       Keystone     Conemaugh
                                                     Public Service            GPU           GPU
                                         PECO Energy   Electric and     Generating    Generating         Various
Operator                                     Company    Gas Company          Corp.         Corp.       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                             $  754,271     $1,234,771     $  108,144     $  165,713     $   87,623
Accumulated depreciation                     326,778        432,959         59,231         67,216         30,475
Construction work in progress                 49,441        164,122          8,956         22,529          1,164
</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.
<PAGE>
                                                                              39

17. 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>
                                                       1996        1995        1994
<S>                                                <C>         <C>         <C>
                                                               Thousands of Dollars
Cash paid during the year:
     Interest (net of amount capitalized)          $415,063    $449,664    $437,096
     Income taxes (net of refunds)                  251,554     257,677     205,316
Noncash investing and financing:
     Capital lease obligations incurred              33,063      48,760      41,763
</TABLE>


18. Investments

<TABLE>
<CAPTION>
At December 31,                                          1996        1995
Thousands of Dollars
<S>                                                  <C>         <C>
Trust accounts for decommissioning nuclear plants    $266,270    $222,655
Telecommunications ventures                            79,833      21,500
Energy services and other ventures                     44,023      40,779
Nonutility property                                    26,349      26,816
Other deposits                                         11,255         132
Emission allowances                                     2,480       6,347
Gas exploration and development joint ventures          2,364         219
                                                     --------    --------
     Total                                           $432,574    $318,448
                                                     ========    ========
</TABLE>

19. 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, 1996 and
1995 were as follows:

<TABLE>
<CAPTION>
Thousands of Dollars                                                   1996                            1995
                                                        Carrying Amount     Fair Value  Carrying Amount     Fair Value
<S>                                                         <C>             <C>             <C>             <C>
Cash and temporary cash investments                         $   29,235      $   29,235      $   20,602      $   20,602
Long-term debt (including amounts due within one year)       4,218,817       4,239,357       4,599,286       4,773,700
Trust accounts for decommissioning nuclear plants              266,270         266,270         222,655         222,655
</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.

20. Other Income

Nuclear Fuel Agreement with Long Island Power Authority (LIPA)
In 1994, the Company recognized $26 million as Other Income in accordance with a
1993 agreement with LIPA and other parties to accept slightly irradiated nuclear
fuel from Shoreham Nuclear Power Station.

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 of $59 million ($27 million net of taxes) on the
sale was recorded in the second quarter of 1995.

<PAGE>
40

21. Voluntary Retirement and Separation 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.

22. Regulatory Assets and Liabilities

At December 31, 1996 and 1995, the Company had deferred the following regulatory
assets on the Consolidated Balance Sheet:

<TABLE>
<CAPTION>
                                                        1996        1995
                                                     Millions of Dollars
<S>                                                   <C>         <C>
Recoverable deferred income taxes (see note 13)       $2,322      $2,420
Deferred Limerick costs (see note 3)                     362         390
Loss on reacquired debt                                  284         309
Compensated absences                                      38          33
Deferred energy costs (see note 3)                       122          56
Non-pension postretirement benefits (see note 3)         233         248
                                                      ------      ------
     Total                                            $3,361      $3,456
                                                      ======      ======
</TABLE>

23. 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        1996        1995        1996        1995        1996        1995
<S>                    <C>         <C>         <C>         <C>         <C>         <C>
Quarter ended
March 31                 $1,171      $1,059      $  253      $  257      $  150      $  152
June 30                     989         959         196         233          99         154
September 30              1,110       1,125         249         292         150         184
December 31               1,014       1,044         208         222         118         120
</TABLE>

<TABLE>
<CAPTION>
                       Earnings Applicable       Average Shares                  Earnings
                         to Common Stock           Outstanding               Per Average Share

Millions of Dollars      1996      1995          1996        1995          1996          1995
Quarter ended
<S>                      <C>       <C>          <C>         <C>      <C>           <C>
March 31                 $146      $146         222.4       221.7    $      0.65   $      0.66
June 30                    94       148         222.5       221.8           0.43          0.67
September 30              145       178         222.5       221.9           0.65          0.80
December 31               114       115         222.5       221.9           0.51          0.52
</TABLE>

The decrease in 1996 third quarter results was primarily due to the lower
electric revenues from less favorable weather conditions, higher customer
expenses and higher costs related to the Salem outage.

     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 20).