<PAGE>

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

General
The Electricity Generation Customer Choice and Competition Act (Competition
Act), enacted in December 1996, provided for the restructuring of the
electric utility industry in Pennsylvania, including the institution of
retail competition for generation supply beginning in 1999. Pursuant to the
Competition Act, in April 1997, the Company filed with the Pennsylvania
Public Utility Commission (PUC) a restructuring plan in which it identified
$7.5 billion of retail electric generation-related stranded costs.

     At December 31, 1997, the Company determined that its electric generation
business no longer met the criteria of Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation." In connection with the discontinuance of SFAS No. 71, the Company
performed a market value analysis of its generation assets and wrote-off $1.8
billion (net of income taxes) of unrecoverable electric plant costs and
regulatory assets. See Note 4 of Notes to Consolidated Financial Statements.

     In May 1998, the PUC entered an Opinion and Order (Final Restructuring
Order) approving a joint petition and settlement of the Company's restructuring
case. Under the Final Restructuring Order, the Company has received approval to
recover stranded costs of $5.26 billion over 12 years beginning January 1, 1999
with a return of 10.75%. The Final Restructuring Order provides for the phase-in
of customer choice of electric generation suppliers (EGS) for all customers:
One-third of the peak load of each customer class on January 1, 1999; one-third
on January 2, 1999; and the remainder on January 2, 2000. The Final
Restructuring Order calls for an across the board retail electric rate reduction
of 8% in 1999. This rate reduction will decrease to 6% in 2000. See Note 3 of
Notes to Consolidated Financial Statements.

     Based on the estimated annual sales of the Company in the Final
Restructuring Order, the rate reductions are expected to reduce the Company's
revenues from retail electric sales by $270 million in 1999 and $200 million in
2000. The Company believes that its revenues from retail electric sales will be
further reduced by competition for electric generation services within its
traditional service territory. The Company is actively participating in the
competitive electric generation supply market throughout Pennsylvania. In
addition, the Company anticipates lower depreciation and amortization expense in
1999 as a result of the amortization schedule for the Company's stranded cost
recovery.

     In light of the expected impact on future revenues of the Final
Restructuring Order and competition for electric generation services, the
Company is continuing its cost management efforts through a Cost Competitiveness
Review (CCR). The goal of CCR is to achieve significant cost savings while
maintaining high levels of service quality, reliability, safety and overall
performance. The cost-control targets of CCR include reducing annual operating
and maintenance expense by at least $150 million by 2001. The expense reductions
will be realized, in part, through the elimination of approximately 1,200
employee positions. As part of the CCR, in April 1998, the Board of Directors
authorized the implementation of a retirement incentive program and an enhanced
severance benefit program to accompany targeted workforce reductions. In the
fourth quarter of 1998, the Company incurred an after-tax charge to earnings of
$74 million to recognize costs related to the CCR workforce reduction.
<PAGE>

Discussion of Operating Results
Earnings
The Company recorded basic earnings per average common share of $2.24 in
1998 as compared with a loss of $6.80 per share in 1997 and earnings per
share of $2.24 in 1996. Earnings per share in 1998 reflect higher revenues
net of fuel of $0.14 per share primarily attributable to sales to other
utilities and interchange sales; lower operating and maintenance expenses
of $0.10 per share and lower fuel expenses of $0.22 per share as a result
of the full return to service of Salem Nuclear Generating Station (Salem);
and lower operating and maintenance expenses of $0.21 per share. In
addition, earnings include the effects of a lower effective income tax rate
of $0.34 per share. These increases were partially offset by higher
depreciation and amortization expense of $0.17 per share; a charge of $0.33
per share related to the CCR workforce reduction program initiated in 1998;
and an extraordinary charge of $0.09 per share for premiums paid in
connection with the redemption of higher cost long-term debt.

     The loss in 1997 of $6.80 per common share was primarily due to an
extraordinary charge of $8.24 per share reflecting the effects of the PUC
Restructuring Order and deregulation of the Company's electric generation
operations. 1997 earnings were also reduced by several one-time charges totaling
$0.56 per share for changes in employee benefits, write-offs of information
systems development charges reflecting clarification of accounting guidelines
and additional reserves, including those for environmental site remediation; by
$0.30 per share for higher depreciation expense resulting from a full year's
increase in depreciation and amortization of assets associated with Limerick
Generating Station (Limerick) and other assets; by $0.12 per share for income
tax adjustments; by $0.09 per share for losses from new non-utility ventures;
and by $0.05 per share for increased depreciation expense due to plant
additions. These decreases were partially offset by a one-time $0.18 per share
credit relating to the settlement of litigation arising from the outage of
Salem; $0.08 per share for operational efficiencies; and higher revenues net of
fuel of $0.06 per share primarily due to increased sales to other utilities.

<PAGE>

Significant Operating Items
<TABLE>
<CAPTION>

Revenue and Expense Items as a Percentage of Total Operating Revenues                    Percentage Dollar Changes
------------------------------------------------------------------------------------------------------------------------        
     1998        1997        1996                                                  1998-1997                   1997-1996
------------------------------------------------------------------------------------------------------------------------
<S>               <C>         <C>         <C>                                      <C>                          <C>
      92%         90%         90%     Electric                                        15%                          8%
       8%         10%         10%     Gas                                            (11%)                         5%
   ------       -----       -----                                                  -------                     ------
     100%        100%        100%     Total Operating Revenues                        13%                          8%
   ======       =====       =====                                                  =======                     ======
      34%         28%         23%     Fuel and Energy Interchange                     36%                         33%
      24%         31%         30%     Operating and Maintenance (a)                  (12%)                        12%
      12%         12%         11%     Depreciation and Amortization                   11%                         19%
       5%          7%          7%     Taxes Other Than Income                        (10%)                         4%
   ------       -----       -----                                                  -------                     ------
      75%         78%         71%     Total Operating Expenses                         9%                         19%
   ======       =====       =====                                                  =======                     ======
      25%         22%         29%     Operating Income                                28%                        (19%)
   ======       =====       =====                                                  =======                     ======
      (7%)        (9%)       (10%)    Interest Expense                               (10%)                        (2%)
   ------       -----       -----                                                  -------                     ------
      (9%)        (8%)        (9%)    Total Other Income and Deductions              (15%)                         4%
   ------       -----       -----                                                  -------                     ------
      16%         14%         20%     Income Before Taxes and Extraordinary Item      35%                        (27%)
   ------       -----       -----                                                  -------                     ------
       6%          6%          8%     Income Taxes                                     9%                        (14%)
   ------       -----       -----                                                  -------                     ------
      10%          8%         12%     Income Before Extraordinary Item                58%                        (35%)
   ======       =====       =====                                                  =======                     ======
</TABLE>

(a) Includes Early Retirement and Separation Programs Expense in 1998.



Operating Revenues
Total operating revenues increased in 1998 by $593 million to $5,210
million.  This represented a $644 million increase in electric revenues and
a $51 million decrease in gas revenues compared to 1997. Electric revenues
increased as a result of additional sales to other utilities and
interchange sales, in addition to higher wholesale prices. The decrease in
gas revenues was primarily attributable to lower sales to house heating,
small commercial and residential customers as a result of milder weather
conditions in 1998, partially offset by higher purchased gas clause
revenues charged in 1998 compared to 1997.

     Total operating revenues increased in 1997 by $334 million to $4,618
million. This represented a $312 million increase in electric revenues and a $22
million increase in gas revenues over 1996. The increase in electric revenues
was primarily due to increased sales to other utilities. The increase in gas
revenues was primarily due to higher revenues from sales to commercial, house
heating and residential customers resulting from higher purchased gas clause
revenues charged in 1997 compared to 1996, partially offset by lower sales
resulting from milder weather conditions in 1997. This increase was partially
offset by reduced sales to interruptible customers switching to transportation
service.

Increases/(decreases) in electric sales and revenues by class of customer
for 1998 compared to 1997 and 1997 compared to 1996 are set forth as
follows:
<TABLE>
<CAPTION>
                                             1998 - 1997                        1997 - 1996
                               -----------------------------------------------------------------------
                                    Electric           Electric          Electric          Electric
                                     Sales             Revenues           Sales            Revenues
                               -----------------------------------------------------------------------
                               (Millions of kWh)   (Millions of $)  (Millions of kWh)   (Millions of $)
                               -----------------   ---------------  -----------------   ---------------
<S>                                    <C>           <C>                   <C>           <C>     
Residential                            356           $    30               (48)          $    (1)
House Heating                         (140)              (10)             (217)              (12)
Small Commercial
        and Industrial                 203                 5               194                30
Large Commercial
        and Industrial                 644               (11)             (174)              (21)
Other                                  (38)                2               (61)                8
Unbilled                                61               (18)              397                45
                               -----------------   ---------------  -----------------   ---------------
        Service Territory            1,086                (2)               91                49
Interchange Sales                    1,556               152               992                33
Sales to Other Utilities             8,365               494             8,650               230
                               -----------------   ---------------  -----------------   ---------------
Total                               11,007           $   644             9,733           $   312
                               =================   ===============  =================   ===============
</TABLE>

Fuel and Energy Interchange Expense
Fuel and energy interchange expense increased in 1998 by $462 million to
$1,752 million. The increase was primarily due to increased energy
purchases associated with increased sales to other utilities and
interchange sales partially offset by reduced replacement power expense
related to Salem. Increases in purchases of non-utility generation also
contributed to increased fuel expense in 1998. Fuel and energy interchange
expense as a percentage of operating revenues, increased from 28% to 34%
principally as a result of energy purchases associated with increased sales
to other utilities and interchange sales.

     Fuel and energy interchange expense increased in 1997 by $318 million to
$1,290 million. The increase was primarily due to purchases associated with
increased sales to other utilities and a one-time billing credit in 1996 from a
non-utility generator. Fuel and energy interchange expense as a percentage of
operating revenues increased from 23% to 28% principally due to purchases
associated with increased sales to other utilities.
<PAGE>

Operating and Maintenance Expense
Operating and maintenance expense, inclusive of expenses associated with
early retirement and separation programs, decreased in 1998 by $178 million
to $1,253 million. The decrease in 1998 was primarily attributable to the
full return to service of Salem which resulted in lower restart expenses, a
credit to pension and benefits expense related to the performance of
pension plan investments and lower property insurance and workers
compensation insurance. These decreases were partially offset by the charge
associated with the CCR workforce reduction program and increased power
marketing expenses.

     Operating and maintenance expense increased in 1997 by $157 million to
$1,431 million primarily due to several one-time charges totaling $187 million,
including charges for changes in employee benefits, write-offs of information
systems development charges reflecting clarification of accounting guidelines
and additional reserves, including reserves for environmental site remediation.
These increases were partially offset by lower operating costs at
Company-operated nuclear generating stations and lower administrative and
general expenses resulting from the Company's ongoing cost-control efforts.

Depreciation and Amortization Expense
Depreciation and amortization expense increased in 1998 by $62 million to
$643 million. The increase was primarily due to the amortization of
Deferred Generation Costs Recoverable in Current Rates during 1998,
preceding the Company's transition to market-based pricing of electric
generation in 1999. Included in this amortization were charges that were
included in operating and maintenance expense and interest expense in 1997.

     Depreciation and amortization expense increased in 1997 by $92 million to
$581 million. The increase was primarily due to increased depreciation of assets
associated with Limerick which became effective October 1, 1996. Depreciation
and amortization expense also increased due to additions to plant in service.

Interest Charges
Interest charges consist of interest expense, distributions on Company
Obligated Mandatorily Redeemable Preferred Securities of a Partnership
(COMRPS) and Allowance for Funds Used During Construction (AFUDC). Interest
charges decreased in 1998 by $22 million to $358 million. The decrease was
primarily due to the Company's program to reduce and/or refinance higher
cost, long-term debt, lower variable interest rates and the discontinuance
of amortization of the loss on reacquired debt related to electric
generation operations as of December 31, 1997. These decreases were
partially offset by lower AFUDC and capitalized interest resulting from
fewer projects in the construction base in 1998 and the replacement of $62
million of preferred stock with COMRPS in the third quarter of 1997.
<PAGE>

     Interest charges decreased in 1997 by $9 million to $380 million. The
decrease was primarily due to the Company's program to reduce and/or refinance
higher-cost, long-term debt. This decrease was partially offset by the
replacement of $62 million of preferred stock with COMRPS in the third quarter
of 1997.

Other Income and Deductions
Excluding Interest Charges
Other income and deductions excluding interest charges decreased in 1998 by
$77 million to a deduction of $73 million. The decrease was primarily due
to the settlement of litigation arising from the shutdown of Salem
recognized in 1997 and losses from the Company's non-utility ventures,
which are accounted for under the equity method, partially offset by
interest income on a gross receipts tax refund.

     Other income and deductions excluding interest charges increased in 1997 by
$6 million to $4 million. The increase was primarily due to the settlement of
litigation arising from the shutdown of Salem, partially offset by losses from
the Company's non-utility ventures. Also offsetting the increase was the
write-off of one of the Company's telecommunications investments as a result of
the auctioning of personal communications systems "C-block" licenses by the
Federal Communication Commission.

Income Taxes
Income taxes increased in 1998 by $27 million to $320 million. The
Company's effective income tax rate decreased, however, from 46.5% to 37.5%
in 1998 primarily as a result of full normalization of deferred taxes
associated with deregulated generation plant.

     Income taxes decreased in 1997 by $47 million to $293 million. The
Company's effective income tax rate increased, however, from 39.7% to 46.5% in
1997 primarily attributable to reduced tax depreciation benefits from plant and
regulatory assets which were not fully normalized for ratemaking purposes.

Preferred Stock Dividends
Preferred stock dividends decreased in 1998 by $4 million to $13 million
and decreased in 1997 by $1 million to $17 million. The decreases were
primarily a result of the replacement of $62 million of preferred stock
with COMRPS in the third
quarter of 1997.

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 used to fund the Company's
capital requirements, including investments in new and existing ventures,
to repay maturing debt and to make preferred and common stock dividend
payments.

     Cash flows from operations were $1,433 million in 1998 as compared to
$1,038 million in 1997 and $1,172 million in 1996. The increase in 1998 was
principally attributable to improved operating results and changes in working
capital.
<PAGE>

     Cash flows used in investing activities were $462 million in 1998 as
compared to $573 million in 1997 and $663 million in 1996. Expenditures under
the Company's construction program decreased to $415 million in 1998. Net funds
invested in diversified activities in 1998 were $47 million, consisting of $17
million for telecommunications ventures, $21 million for nuclear plant
decommissioning trust funds and $9 million for other deposits and ventures. In
1997 and 1996, funds used in similar activities were $83 million and $114
million, respectively.

     Cash flows used in financing activities were $956 million in 1998 as
compared to $461 million in 1997 and $501 million in 1996. The increase in 1998
was primarily attributable to increased retirement of long-term debt partially
offset by lower dividends on common stock. During 1998, in anticipation of
competition, which is expected to reduce cash flows, the Company reduced its
dividend payment requirements by reducing its common stock dividend to $1 per
share. The decrease in 1997 was primarily due to fewer retirements of
higher-cost debt.

     The Company's capital expenditures are currently estimated to be $440
million in 1999. Certain facilities under construction and to be constructed may
require permits and licenses which the Company has no assurance will be granted.
Capital expenditures do not include investments in joint ventures including
investments related to the Company's strategy to expand its generation
portfolio. See"Outlook-Expansion of Generation Portfolio." The Company may use
internally generated funds or external financing or a combination of both to
finance any acquisition.

     The Company meets its short-term liquidity requirements primarily through
the issuance of commercial paper and borrowings under bank credit facilities.
The Company has a $900 million unsecured revolving credit facility with a group
of banks which consists of a $450 million 364-day credit agreement and a $450
million three-year credit agreement. The Company uses the credit facility
principally to support its $600 million commercial paper program. There was no
debt outstanding under this credit facility at December 31, 1998. The Company
had $525 million of short-term debt, consisting of $125 million of commercial
paper, and a $400 million term loan, outstanding at December 31, 1998.

     At December 31, 1998, the Company's embedded cost of debt was 6.65% with
29% of the Company's long-term debt having floating rates.

     At December 31, 1998, the Company's capital structure consisted of 44.2%
common equity; 8.4% preferred stock and COMRPS (which comprised 5.1% of the
Company's total capitalization structure); and 47.4% long-term debt.

     In the Final Restructuring Order, the PUC authorized the Company to
securitize up to $4 billion of its allowed $5.26 billion stranded cost recovery
through the issuance of transition bonds (Transition Bonds). The proceeds of any
securitization are required to be used by the Company principally to reduce its
stranded costs and related capitalization. The Company currently proposes to
securitize its allowed stranded asset recovery, up to the maximum amount
authorized by the PUC, through the issuance of Transition Bonds by a special
purpose subsidiary (SPS). The Transition Bonds will be obligations of the SPS
secured by intangible transition property (ITP). ITP represents the irrevocable
right of the Company or its assignee, to collect non-bypassable charges from
customers to recover stranded costs. The Transition Bonds will be included in
the consolidated capitalization of the Company. Because the Transition Bonds
will be obligations of the SPS, payable from the ITP owned by the SPS, the
Company does not expect the issuance of Transition Bonds to adversely affect the
ratings on the Company's securities which remain outstanding after issuance of
Transition Bonds.
<PAGE>

     In anticipation of the issuance of Transition Bonds, the Company's Board of
Directors authorized the repurchase of up to 25 million shares of the Company's
common stock from time to time through open market, privately negotiated and/or
other types of transactions. The Company has entered into forward purchase
agreements to be settled from time to time, at the Company's election on either
a physical, net share or net cash basis. The amount at which these agreements
can be settled is dependent principally upon the market price of the Company's
common stock as compared to the forward purchase price per share and the number
of shares to be settled. If these agreements had been settled on a net share
basis at December 31, 1998, based on the closing price of the Company's common
stock on that date, the Company would have received approximately 4.6 million
shares of the Company's common stock.

     The Company has entered into treasury forwards and forward starting
interest rate swaps to manage interest rate exposure associated with the
anticipated issuance of Transition Bonds. The fair value of ($4.7 million) was
based on the present value difference between the contracted rate (i.e., hedged
rate) and the market rates at December 31, 1998. 

     The aggregate change in fair value of the Transition Bond derivative
instruments that would have resulted from a hypothetical 50 basis point decrease
in the spot yield at December 31, 1998 is estimated to be $128 million. If the
derivative instruments had been terminated at December 31, 1998, this estimated
fair value represents the amount to be paid by the Company to the
counterparties.

     The aggregate change in fair value of the Transition Bond derivative
instruments that would have resulted from a hypothetical 50 basis point increase
in the spot yield at December 31, 1998 is estimated to be $113 million. If the
derivativeinstruments had been terminated at December 31,1998, this estimated
fair value represents the amount to be paid by the counterparties to the
Company.

Outlook
The Company is entering a period of financial uncertainty as a result of the
deregulation of its electric generation operations. Under the terms of the Final
Restructuring Order, revenues from regulated rates will decrease. In addition,
the Company will sell an increasing portion of its energy at market-based rates.
The Company believes that the deregulation of its electric generation operations
and other regulatory initiatives designed to encourage competition will increase
the Company's risk profile by changing and increasing the number of factors upon
which the Company's financial results are dependent. This may result in more
volatility in the Company's future results of operations. The Company believes
that it has significant advantages that will strengthen its position in the
increasingly competitive electric generation environment. These advantages
include the ability to produce electricity at a low variable-cost and the
demonstrated ability to market power in the competitive wholesale markets.
<PAGE>

     The Company's future financial condition and results of operations are
substantially dependent upon the effects of the Final Restructuring Order and
retail and wholesale competition for generation services. Additional factors
that affect the Company's financial condition and results of operations include
operation of nuclear generating facilities, Year 2000 issues, new accounting
pronouncements, inflation, weather, compliance with environmental regulations
and the profitability of the Company's investments in new ventures.

Final Restructuring Order
The Final Restructuring Order contains a number of provisions which the
Company expects will significantly impact its future results of operations
and financial condition, including mandated rate reductions, extended rate
caps, provisions designed to enhance competition for generation services,
the amortization of the Company's stranded cost recovery and the
securitization of stranded cost recovery.

     The Final Restructuring Order mandates retail electric rate reductions of
8% in 1999 and 6% in 2000 from rates in existence on December 31, 1996. Based on
the estimated annual sales of the Company in the Final Restructuring Order,
these rate reductions will reduce the Company's revenue from retail electric
sales by $270 million and $200 million in 1999 and 2000, respectively. The
Company's revenue from retail electric sales will be further reduced to the
extent that customers purchase generation service from alternate EGS.

     The Final Restructuring Order caps the Company's retail transmission and
distribution rates at their current levels through June 30, 2005. The Final
Restructuring Order also established rate caps for generation services,
consisting of the charge for stranded cost recovery and a charge for energy and
capacity, through 2010. The rate caps will limit the Company's ability to pass
cost increases through to customers.

     The Final Restructuring Order contains a number of provisions which are
designed to encourage competition for generation services. The Final
Restructuring Order establishes an above-market shopping credit for generation
services, equivalent to the Company's energy and capacity charge, in order to
provide an economic incentive for customers to choose an alternate EGS. If
market prices of retail generation services remain below the shopping credits
for generation established by the Final Restructuring Order, this economic
incentive to choose an alternate EGS will continue. If, on the other hand,
market prices of retail generation services exceed the shopping credits for
generation, customers will have an economic incentive to purchase generation
services from the Company as the provider of last resort (PLR) at below market
rates. Additionally, if on January 1, 2001 and January 1, 2003, less than 35%
and 50%, respectively, of the Company's residential and commercial customers are
obtaining generation service from alternate EGS, the non-shopping customers will
be randomly assigned to EGS, including those affiliated with the Company, to
meet these thresholds. Further, on January 1, 2001, 20% of all the Company's
residential customers, whether or not such customers are obtaining generation
service from an alternate EGS, will be assigned to a PLR other than the Company.
Such alternate supplier will be selected by a PUC-approved bidding process. The
right to provide this competitive default service will be rebid annually, and if
the number of residential customers served by this service falls below 17%,
further random selection of customers will be assigned to achieve the 20% level.
<PAGE>

     The Company's recovery of stranded costs is based on the level of
transition charges established in the Final Restructuring Order and the
projected annual retail sales in the Company's service territory. Recovery of
transition charges for stranded costs will be included in operating revenue and
are expected to be $552 million in 1999, increasing to $932 million by 2010, the
final year of stranded cost recovery. Amortization of the Company's stranded
cost recovery, which is a regulatory asset, will be included in depreciation and
amortization, beginning in 1999 at a level of ($14) million and increasing by
2010 to $879 million. The Company is allowed a 10.75% return on the unamortized
balance. As a result of this amortization schedule, the Company expects its
earnings to be disproportionately benefited by the recovery of stranded assets
in the early years of the transition period declining over the life of the
recovery as the balance of the unamortized regulatory asset is reduced. 

     Under the Final Restructuring Order, the Company may securitize up to $4
billion of its $5.26 billion of stranded cost recovery through the issuance of
Transition Bonds. The rate reductions and rate caps of the Final Restructuring
Order anticipate the benefits of securitization and no adjustment in the
Company's base rates will be made upon the issuance of Transition Bonds. As a
result of the 10.75% allowed return on the unamortized balance of stranded cost
recovery and expected costs of securitization substantially below this allowed
return, the Company anticipates that successful securitization, resulting in a
reduction of its common equity, will improve the Company's future financial
results.

Competition
The Company competes in both the retail electric generation market in
Pennsylvania and the wholesale electric generation market nationally.
Competition for electric generation services is expected to create new
uncertainties in the utility industry. These uncertainties include future
prices of generation services in both the wholesale and retail markets;
potential changes in the Company's customer profiles, both at the retail
level where change is expected to be ongoing as a result of customer
choice, and between the retail and wholesale markets; and supply and demand
volatility.

     Retail competition for generation supply commenced in January 1999, with
two-thirds of Pennsylvania electric utility consumers having the right to choose
their suppliers of generation service. The Company is actively competing for a
share of the generation supply market in its traditional service territory
through PECO Energy Distribution as the PLR for customers who do not or cannot
choose an alternate EGS and throughout Pennsylvania through Exelon Energy, the
Company's new competitive supplier. Generation services provided by PECO Energy
Distribution are at the energy and capacity charge mandated by the Final
Restructuring Order. Generation services offered by Exelon Energy are at
competitive market prices. Customers who continue to take generation service
from PECO Energy Distribution may choose an alternate generation supplier at any
time. As of January 12, 1999, approximately 12% of the Company's residential and
small commercial customers and approximately 50% of its large commercial and
industrial customers had selected an alternate EGS. As of that date, Exelon
Energy is providing generation service to approximately 135,000 business and
residential customers throughout Pennsylvania. Because the energy and capacity
charge (shopping credit) established by the PUC in the Restructuring Order
remains above current retail market prices for generation services, including
those offered by Exelon Energy, the Company's retail revenues will be reduced to
the extent customers choose an alternate EGS, including Exelon Energy. To the
extent that the Company cannot replace lost retail sales through PECO Energy
Distribution with retail sales by Exelon Energy, the Company will be required to
sell a larger portion of its energy and capacity in the wholesale market. Since
prices in the wholesale market are currently lower on average than those charged
in the competitive retail market, this will adversely affect the Company's
revenues and profit margins.
<PAGE>

     The Company is a low variable-cost electricity producer, which puts it in a
favorable position to take advantage of opportunities in the electric retail and
wholesale generation markets. The Company's competitive position and its future
financial condition and results of operations are dependent on the Company's
ability to successfully operate its low variable-cost power plants and market
its power effectively in competitive wholesale markets.

     The Company competes in the wholesale market by selling the energy and
capacity from the Company's installed capacity not utilized in the retail market
and buying and selling energy from third parties. The Company enters into both
long-term and short-term commitments to buy and sell power. Currently, the
Company's long-term commitments, together with the energy the Company expects to
market from the Company's installed capacity, make the Company a net power
seller. This long position, however, exposes the Company to the risk of
declining revenues in periods of low wholesale demand for generation services.
See Note 5 of Notes to Consolidated Financial Statements.

     There is an initiative in the Pennsylvania legislature to deregulate the
gas industry, which has the support of the governor. The Company cannot predict
whether the Pennsylvania legislature will enact legislation that deregulates the
gas industry or whether the governor will ultimately sign into law any such
legislation. The Company cannot predict the ultimate effect of gas industry
deregulation on its future financial condition or results of operations.

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 44% of
its installed generating capacity. Because of the Company's 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.
<PAGE>

     During 1998, Company-operated nuclear plants operated at an 86%
weighted-average capacity factor and Company-owned nuclear plants operated at an
83% weighted-average capacity factor. Company-owned nuclear plants produced 39%
of the Company's electricity. Nuclear generation is currently the most
cost-effective way for the Company to meet customer needs and commitments for
sales to other utilities. See "Expansion of Generation Portfolio".

New Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities," to
establish accounting and reporting standards for derivatives. The new
standard requires recognizing all derivatives as either assets or
liabilities on the balance sheet at their fair value and specifies the
accounting for changes in fair value depending upon the intended use of the
derivative. The new standard is effective for fiscal years beginning after
June 15, 1999. The Company expects to adopt SFAS No. 133 in the first
quarter of2000. The Company is in the process of evaluating the impact of
SFAS No. 133 on its financial statements.

     In November 1998, the FASB's Emerging Issues Task Force issued EITF 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities." EITF 98-10 outlines attributes that may be indicative of an energy
trading operation and gives further guidance on the accounting for contracts
entered into by an energy trading operation. This accounting guidance requires
mark-to-market accounting for contracts considered to be a trading activity.
EITF 98-10 is applicable for fiscal years beginning after December 15, 1998 with
any impact recorded as a cumulative effect adjustment through retained earnings
at the date of adoption. At December 31, 1998, the Company has evaluated its
wholesale marketing operation and related contracts under the guidance provided
in EITF 98-10. For those contracts entered into in the over-the-counter market
and considered to be a trading activity, the Company believes the impact to be
immaterial. However, with respect to the long-term commitments considered to be
trading activities, the Company is continuing to evaluate these commitments and
the impact of adopting EITF 98-10.

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
variations during winter months.

     Inflation affects the Company through increased operating costs and
increased capital costs for utility plant. As a result of the rate caps imposed
under the Final Restructuring Order and expected price pressures due to
competition, the Company may have a 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 28 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. The Pennsylvania Department of Environmental Protection has
approved the Company's clean-up of three sites. Eight other sites are currently
under some degree of active study and/or remediation.
<PAGE>

     As of December 31, 1998 and 1997, the Company had accrued $60 and $63
million, respectively, for environmental investigation and remediation costs,
including $33 and $35 million, respectively, for MGP investigation and
remediation that currently can be reasonably estimated. The Company expects to
expend $3 million for environmental remediation activities in 1999. The Company
cannot 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 such
costs will be recoverable from third parties.

     For a discussion of other contingencies, see Note 5 of Notes to
Consolidated Financial Statements.

Year 2000 Readiness Disclosure
Due to the severity of the potential impact of the Year 2000 Issue (Y2K
Issue) on the electric utility industry, the Company has adopted a
comprehensive schedule to achieve Y2K readiness by the time specified by
the NRC. The Company has dedicated extensive resources to its Y2K Project
(Project) and believes the project is progressing on schedule.

     The Project is addressing the issue resulting from computer programs using
two digits rather than four to define the applicable year and other programming
techniques that constrain date calculations or assign special meanings to
certain dates. Any of the Company's computer systems that have date-sensitive
software or microprocessors may recognize a date using "00" as the year 1900
rather than the year 2000. This could result in a system failure or
miscalculations causing disruptions of operations, including, a temporary
inability to process transactions, send bills, operate generating stations, or
engage in similar normal business activities.

     The Company has determined that it will be required to modify, convert or
replace significant portions of its software and a subset of its system hardware
and embedded technology so that its computer systems will properly utilize dates
beyond December 31, 1999. The Company presently believes that with these
modifications, conversions and replacements the effect of the Y2K Issue on the
Company can be mitigated. If such modifications, conversions and replacements
are not made, or are not completed in a timely manner, the Y2K Issue could have
a material impact on the operations and financial condition of the Company. The
costs associated with this potential impact are not presently quantifiable.
<PAGE>

     The Company is utilizing both internal and external resources to reprogram,
or replace and test software and computer systems for the Project. The Project
is scheduled for completion by July 1, 1999, except for a small number of
modifications, conversions or replacements that are impacted by vendor dates
and/or are being incorporated into scheduled plant outages between July and
October 1999.

     The Project is divided into four major sections - Information Technology
Systems (IT Systems), Embedded Technology (devices used to control, monitor or
assist the operation of equipment, machinery or plant), Supply Chain
(third-party suppliers and customers), and Contingency Planning. The general
phases common to all sections are: (1) inventorying Y2K items; (2) assigning
priorities to identified items; (3) assessing the Y2K readiness of items
determined to be material to the Company; (4) converting material items that are
determined not to be Y2K ready; (5) testing material items; and (6) designing
and implementing contingency plans for each critical Company process. Material
items are those believed by the Company to have a risk involving the safety of
individuals, may cause damage to property or the environment, or affect
revenues.

     The IT Systems section includes both the conversion of applications
software that is not Y2K ready and the replacement of software when available
from the supplier. The Company estimates that the software conversion phase was
approximately 66% complete at January 27, 1999, and the remaining conversions
are expected to be completed by the scheduled end date. The Company has been
experiencing slippage in delivery dates of vendor supplied products which may
have a minor impact on the July 1, 1999 target completion date. Contingency
planning for IT Systems is scheduled to be completed by July 1, 1999 with an
interim date of March 31, 1999 that addresses PUC contingency planning
requirements. The Project has identified 380 critical systems of which 238 are
IT Systems. The current readiness status of IT Systems is set forth below:

    Number of Systems              Progress Status
    -----------------------------------------------------------
     79 Systems                    Y2K Ready
     65 Systems                    In Testing
     87 Systems                    In Active Code Modification,    
                                      Or Package Upgrading
      7 Systems                    Not Started

     The Embedded Technology section consists of hardware and systems software
other than IT Systems. The Company estimates that the Embedded Technology
section was approximately 75% complete at January 27, 1999. The remaining
conversions are on schedule to be tested and ready by July 1, 1999, except for a
small number of systems which will be extended into the fall of 1999 because
their final tests will occur during a planned generating plant outage.
Contingency planning for Embedded Technology is scheduled to be completed by
July 1, 1999 with an interim date of March 31, 1999 that addresses PUC
contingency planning requirements. The Project has identified 142 critical
Embedded Technology systems. The current readiness status of those systems is
set forth below:
<PAGE>

    Number of Systems              Progress Status
    -----------------------------------------------------------
        31 Systems                 Y2K Ready
        29 Systems                 In Final Quality Review
        76 Systems                 In Progress
        6  Systems                 Not Started

     The Supply Chain section includes the process of identifying and
prioritizing critical suppliers and communicating with them about their plans
and progress in addressing the Y2K Issue. The Company initiated formal
communications with all of its critical suppliers to determine the extent to
which the Company may be vulnerable to their Y2K issues. The process of
evaluating these critical suppliers has commenced and is scheduled to be
completed by March 31, 1999.

     The Company, like other companies, is interconnected with many businesses,
including electric utilities, natural gas pipelines and municipalities. The
Company is working with businesses where interconnections exist to determine and
monitor their Y2K readiness efforts. In addition, the Company is currently
developing contingency plans to address how to respond to events which may
disrupt normal operations. These plans address Y2K risk scenarios that cross
departmental, business unit and industry lines as well as specific risks from
various internal and external sources, including supplier readiness. Emergency
plans already exist that cover various aspects of the Company's business. These
plans are being reviewed and updated, as needed, to address the Y2K Issue. The
Company is also participating in industry contingency planning efforts.

     The estimated total cost of the Project is $75 million, the majority of
which will be incurred during testing. This estimate includes the Company's
share of Y2K costs for jointly owned facilities. The total amount expended on
the Project through December 31, 1998 was $21 million. The Company expects to
fund the Project from operating cash flows.

     The Company's failure to become Y2K ready could result in an interruption
in or a failure of certain normal business activities or operations. In
addition, there can be no assurance that the systems of other companies on which
the Company's systems rely or with which they communicate will be converted in a
timely manner, or that a failure to convert by another company, or a conversion
that is incompatible with the Company's systems, will not have a material
adverse effect on the Company. Such failures could materially and adversely
affect the Company's results of operations, liquidity and financial condition.
The Company is currently developing contingency plans to address how to respond
to events that may disrupt normal operations, including activities with PJM
Interconnection, LLC.

     The costs of the Project and the date on which the Company plans to
complete the Y2K modifications are based on estimates, that were derived
utilizing numerous assumptions of future events, including the continued
availability of certain resources, third-party modification plans and other
factors, such as regulatory requirements that impact key systems. There can be
no assurance that these estimates will be achieved. Actual results could differ
materially from the projections. Specific factors that might cause a material
change include, but are not limited to, the availability and cost of trained
personnel, the ability to locate and correct all relevant computer programs and
microprocessors.
<PAGE>

     The Project is expected to significantly reduce the Company's level of
uncertainty about the Y2K Issue. The Company believes that the completion of the
Project, as scheduled, minimizes the possibility of significant interruptions of
normal operations.

Expansion of Generation Portfolio
The Company established specific goals to increase its generation capacity
from 9 gigawatts to 25 gigawatts by 2003. The Company is targeting a
balanced portfolio of nuclear, hydro and clean burning fossil capacity
through the acquisition of plants and long-term supply agreements. In order
to meet this strategic objective the Company may require significant
capital resources.

     In October 1998, the Company through AmerGen Energy Company, LLC, a 50%
owned joint venture with British Energy, Inc., entered into a definitive asset
purchase agreement with GPU, Inc. (GPU) to acquire GPU's 786 megawatt Three Mile
Island Unit No. 1 Nuclear Generating Facility for approximately $23 million in
cash, $77 million for nuclear fuel payable over five years and certain
contingent payments based upon future wholesale market prices. The Company
currently expects the acquisition, which is subject to various regulatory
approvals, to close by mid-year 1999.

Corporate Restructuring
In 1999, the Company's common shareholders will vote on a management
proposal for the formation of a holding company. The holding company will
be formed through the exchange of PECO Energy common stock for common stock
of the holding company. As a result, the Company will become a wholly owned
subsidiary of the holding company. The formation of the holding company
will not affect the Company's other securities. Management has proposed the
formation of the holding company to facilitate the disaggregation of the
Company's transmission and distribution, generation and unregulated
businesses and corporate central services in order to create increased
financial, management and organizational flexibility.

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 Note 5 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.
<PAGE>


Report of Independent Accountants



To the Shareholders and Board of Directors
of PECO Energy Company:


In our opinion, the accompanying consolidated balance sheets and the
related consolidated statements of income, cash flows and changes in common
shareholders' equity and preferred stock present fairly, in all material
respects, the financial position of PECO Energy Company and Subsidiary
Companies at December 31, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1998, in conformity with generally accepted accounting
principles. These financial statements are the responsibility of the
Company's management; our responsibility is to express an opinion on these
financial statements based on our audits. We conducted our audits of these
statements in accordance with generally accepted auditing standards which
require that we plan and perform the audit to obtain reasonable assurance
about whether the financial statements are free of material misstatement.
An audit includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management and
evaluating the overall financial statement presentation. We believe that
our audits provide a reasonable basis for the opinion expressed above.






PricewaterhouseCoopers LLP

Philadelphia, Pennsylvania
February 5, 1999
<PAGE>
24                                PECO Energy Company and Subsidiary Companies

Consolidated Statements of Income
<TABLE>
<CAPTION>
For the Years Ended December 31,                                        1998                   1997                1996
----------------------------------------------------------------------------------------------------------------------------
                                                                                                       Thousands of Dollars
                                                                   ---------------------------------------------------------
<S>                                                                 <C>                   <C>                   <C>       
Operating Revenues 
Electric                                                            $ 4,810,840           $ 4,166,669           $ 3,854,836
Gas                                                                     399,642               451,232               428,814
                                                                    -----------           -----------           -----------
        Total Operating Revenues                                      5,210,482             4,617,901             4,283,650
                                                                    -----------           -----------           -----------
Operating Expenses
Fuel and Energy Interchange                                           1,751,819             1,290,164               972,380
Operating and Maintenance                                             1,128,792             1,431,420             1,274,222
Early Retirement and Separation Programs                                124,200                    --                    --
Depreciation and Amortization                                           642,842               580,595               489,001
Taxes Other Than Income                                                 279,515               310,091               299,546
                                                                    -----------           -----------           -----------
        Total Operating Expenses                                      3,927,168             3,612,270             3,035,149
                                                                    -----------           -----------           -----------
Operating Income                                                      1,283,314             1,005,631             1,248,501
                                                                    -----------           -----------           -----------
Other Income and Deductions
Interest Expense                                                       (330,842)             (372,857)             (382,443)
Company Obligated Mandatorily Redeemable
        Preferred Securities of a Partnership, which
        holds Solely Subordinated Debentures of
        the Company                                                     (30,694)              (28,990)              (26,723)
Allowance for Funds Used During Construction                              3,522                21,771                19,947
Settlement of Salem Litigation                                               --                69,800                    --
Other, net                                                              (73,268)              (66,028)               (1,976)
                                                                    -----------           -----------           -----------
        Total Other Income and Deductions                              (431,282)             (376,304)             (391,195)
                                                                    -----------           -----------           -----------
Income Before Income Taxes and Extraordinary Item                       852,032               629,327               857,306
Income Taxes                                                            319,654               292,769               340,101
                                                                    -----------           -----------           -----------
Income Before Extraordinary Item                                        532,378               336,558               517,205
Extraordinary Item (net of income taxes of
        $13,757 and $1,290,961 for 1998 and 1997, respectively)         (19,654)           (1,833,664)                   --
                                                                    -----------           -----------           -----------
Net Income (Loss)                                                       512,724            (1,497,106)              517,205
Preferred Stock Dividends                                                13,109                16,804                18,036
                                                                    -----------           -----------           -----------
Earnings (Loss) Applicable to Common Stock                          $   499,615           $(1,513,910)          $   499,169
                                                                    ===========           ===========           ===========
Average Shares of Common Stock
        Outstanding (Thousands)                                         223,219               222,543               222,490
                                                                    ===========           ===========           ===========
Basic Earnings per Average Common Share
        Before Extraordinary Item (Dollars)                         $      2.33           $      1.44           $      2.24
Extraordinary Item (Dollars)                                        $     (0.09)          $     (8.24)          $        --
                                                                    -----------           -----------           -----------
Basic Earnings per Average Common Share (Dollars)                   $      2.24           $     (6.80)          $      2.24
                                                                    ===========           ===========           ===========
Diluted Earnings per Average Common Share
        Before Extraordinary Item (Dollars)                         $      2.32           $      1.44           $      2.24
Extraordinary Item (Dollars)                                        $     (0.09)          $     (8.24)          $        --
                                                                    -----------           -----------           -----------
Diluted Earnings per Average Common Share (Dollars)                 $      2.23           $     (6.80)          $      2.24
                                                                    ===========           ===========           ===========

Dividends per Common Share (Dollars)                                $      1.00           $      1.80           $     1.755
                                                                    ===========           ===========           ===========
</TABLE>

See Notes to Consolidated Financial Statements.

<PAGE>

PECO Energy Company and Subsidiary Companies                             25

Consolidated Statements of Cash Flows

<TABLE>
<CAPTION>
For the Years Ended December 31,                                    1998                  1997                  1996
-----------------------------------------------------------------------------------------------------------------------
                                                                                                   Thousands of Dollars
                                                                -------------------------------------------------------
<S>                                                             <C>                   <C>                   <C>
Cash Flows from Operating Activities
Net Income (Loss)                                               $   512,724           $(1,497,106)          $   517,205
Extraordinary Item (net of income taxes)                            (19,654)           (1,833,664)                   --
                                                                -----------           -----------           -----------
Income Before Extraordinary Item                                    532,378               336,558               517,205

Adjustments to reconcile Net Income to Net Cash
   provided by Operating Activities:
        Depreciation and Amortization                               704,718               664,294               566,412
        Deferred Income Taxes                                      (115,640)              (17,228)              166,770
        Amortization of Investment Tax Credits                      (18,066)              (18,201)              (15,979)
        Early Retirement and Separation Charge                      125,000                    --                    --
        Salem Litigation Settlement                                      --                69,800                    --
        Deferred Energy Costs                                         5,818                (5,652)              (66,151)
        Amortization of Leased Property                              59,923                39,100                31,400
Changes in Working Capital:
        Accounts Receivable                                          15,590              (289,610)               53,681
        Inventories                                                  14,192                28,628                (2,729)
        Accounts Payable                                              8,971                93,881               (86,765)
Other Current Assets and Liabilities                                 54,263                58,539               (25,040)
Other Deferred Credits - Other                                       49,948                78,846                (4,609)
Other Items affecting Operations                                     (4,190)                 (804)               38,050
                                                                -----------           -----------           -----------
Net Cash Flows from Operating Activities                          1,432,905             1,038,151             1,172,245
                                                                -----------           -----------           -----------
Cash Flows from Investing Activities
Investment in Plant                                                (415,331)             (490,200)             (548,854)
Increase in Other Investments                                       (46,742)              (83,261)             (114,126)
                                                                -----------           -----------           -----------
Net Cash Flows from Investing Activities                           (462,073)             (573,461)             (662,980)
                                                                -----------           -----------           -----------
Cash Flows from Financing Activities
Change in Short-Term Debt                                           123,500               114,000               287,500
Proceeds from Exercise of Stock Options                              50,700                   117                11,301
Retirement of Company Obligated Mandatorily Redeemable
        Preferred Securities of a Partnership                       (80,794)              (61,895)                   --
Issuance of Company Obligated Mandatorily Redeemable
        Preferred Securities of a Partnership                        78,105                50,000                    --
Issuance of Long-Term Debt                                           13,486               161,813                43,700
Retirement of Long-Term Debt                                       (841,755)             (283,303)             (427,463)
Loss on Reacquired Debt                                               6,753                22,752                24,724
Dividends on Preferred and Common Stock                            (236,307)             (417,383)             (411,569)
Capital Lease Payments                                              (59,923)              (39,100)              (31,400)
Other Items Affecting Financing                                      (9,918)               (7,522)                2,575
                                                                -----------           -----------           -----------
Net Cash Flows from Financing Activities                           (956,153)             (460,521)             (500,632)
                                                                -----------           -----------           -----------

Increase in Cash and Cash Equivalents                                14,679                 4,169                 8,633
Cash and Cash Equivalents at beginning of period                     33,404                29,235                20,602
                                                                -----------           -----------           -----------
Cash and Cash Equivalents at end of period                      $    48,083           $    33,404           $    29,235
                                                                ===========           ===========           ===========
</TABLE>

See Notes to Consolidated Financial Statements.
<PAGE>

26                                 PECO Energy Company and Subsidiary Companies

Consolidated Balance Sheets
<TABLE>
<CAPTION>

At December 31,                                                     1998                  1997
-------------------------------------------------------------------------------------------------
                                                                             Thousands of Dollars
                                                                ---------------------------------
<S>                                                             <C>                  <C>   
Assets

Utility Plant
Electric-Transmission & Distribution                            $ 3,833,780          $ 3,617,666
Electric-Generation                                               1,713,430            1,434,895
Gas                                                               1,131,999            1,071,819
Common                                                              407,320              302,672
                                                                -----------          -----------
                                                                  7,086,529            6,427,052
        Less Accumulated Provision for Depreciation               2,891,321            2,690,824
                                                                -----------          -----------
                                                                  4,195,208            3,736,228
Nuclear Fuel, net                                                   141,907              147,359
Construction Work in Progress                                       272,590              611,204
Leased Property, net                                                154,308              175,933
                                                                -----------          -----------
        Net Utility Plant                                         4,764,013            4,670,724
                                                                -----------          -----------

Current Assets
Cash and Temporary Cash Investments                                  48,083               33,404
Accounts Receivable, net
        Customers                                                    97,527              173,350
        Other                                                       213,229              139,996
Inventories, at average cost
        Fossil Fuel                                                  79,488               84,858
        Materials and Supplies                                       82,068               90,890
Deferred Energy Costs-Gas                                            29,847               35,665
Deferred Generation Costs Recoverable in Current Rates                   --              424,497
Other                                                                19,013               20,115
                                                                -----------          -----------
        Total Current Assets                                        569,255            1,002,775
                                                                -----------          -----------
Deferred Debits and Other Assets
Competitive Transition Charge                                     5,274,624            5,274,624
Recoverable Deferred Income Taxes                                   614,445              590,267
Deferred Non-Pension Postretirement Benefits Costs                   90,915               97,409
Investments                                                         550,904              515,835
Loss on Reacquired Debt                                              77,165               83,918
Other                                                               107,042              121,016
                                                                -----------          -----------
        Total Deferred Debits and Other Assets                    6,715,095            6,683,069
                                                                -----------          -----------

Total Assets                                                    $12,048,363          $12,356,568
                                                                ===========          ===========
</TABLE>

See Notes to Consolidated Financial Statements.
<PAGE>

PECO Energy Company and Subsdiary Companies                                27

Consolidated Balance Sheets (Continued)

<TABLE>
<CAPTION>


At December 31,                                                       1998                  1997
----------------------------------------------------------------------------------------------------
                                                                                Thousands of Dollars
                                                                 -----------------------------------
<S>                                                              <C>                    <C>         
Capitalization and Liabilities

Capitalization
Common Shareholders' Equity
        Common Stock                                             $  3,589,031           $  3,517,731
        Other Paid-In Capital                                           1,236                  1,239
        Retained Earnings (Accumulated Deficit)                      (532,925)              (792,239)
                                                                 ------------           ------------
                                                                    3,057,342              2,726,731
Preferred and Preference Stock
        Without Mandatory Redemption                                  137,472                137,472
        With Mandatory Redemption                                      92,700                 92,700
Company Obligated Mandatorily Redeemable Preferred
        Securities of a Partnership, which holds Solely
        Subordinated Debentures of the Company                        349,355                352,085
Long-Term Debt                                                      2,919,592              3,853,141
                                                                 ------------           ------------
        Total Capitalization                                        6,556,461              7,162,129
                                                                 ------------           ------------
Current Liabilities
Notes Payable                                                         525,000                401,500
Long-Term Debt Due Within One Year                                    361,523                247,087
Capital Lease Obligations Due Within One Year                          69,011                 55,808
Accounts Payable                                                      316,292                323,816
Taxes Accrued                                                         170,495                 66,397
Interest Accrued                                                       61,515                 77,911
Deferred Income Taxes                                                  14,168                185,696
Other                                                                 217,416                260,457
                                                                 ------------           ------------
        Total Current Liabilities                                   1,735,420              1,618,672
                                                                 ------------           ------------

Deferred Credits and Other Liabilities
Capital Lease Obligations                                              85,297                120,125
Deferred Income Taxes                                               2,376,792              2,297,042
Unamortized Investment Tax Credits                                    299,999                318,065
Pension Obligation                                                    219,274                211,596
Non-Pension Postretirement Benefits Obligation                        421,083                324,850
Other                                                                 354,037                304,089
                                                                 ------------           ------------
        Total Deferred Credits and Other Liabilities                3,756,482              3,575,767
                                                                 ------------           ------------
Commitments and Contingencies (Note 5)

Total Capitalization and Liabilities                             $ 12,048,363           $ 12,356,568
                                                                 ============           ============
</TABLE>

See Notes to Consolidated Financial Statements.
<PAGE>
28

                                   PECO Energy Company and Subsidiary Companies


Consolidated Statements of Changes in Common Shareholders' Equity and
Preferred Stock
<TABLE>
<CAPTION>
                                                                                         Retained    
                                                                             Other      Earnings
                                                 Common Stock               Paid-In    (Accumulated       Preferred Stock
All Amounts in Thousands                     Shares        Amount           Capital      Deficit)        Shares      Amount
-----------------------------------------------------------------------------------------------------------------------------

<S>                <C>                       <C>        <C>                <C>         <C>                <C>      <C>       
Balance at January 1, 1996                   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

Net Loss                                                                                (1,497,106)
Cash Dividends Declared
        Preferred Stock
         (at specified annual rates)                                                       (16,804)
        Common Stock ($1.80 per share)                                                    (400,578)
Expenses of Capital Activity                                                                    97
Stock Repurchase Forward Contract                                                           (4,889)
Capital Stock Activity
        Long-Term Incentive Plan Issuances         5             117

        Preferred Stock Redemptions                                             (87)                       (619)      (61,895)
                                           ---------    ------------      ---------   ------------     --------    ----------
Balance at December 31, 1997                 222,547    $  3,517,731       $  1,239    $  (792,239)       2,302    $  230,172

Net Income                                                                                 512,724
Cash Dividends Declared
        Preferred Stock
         (at specified annual rates)                                                       (13,109)
        Common Stock ($1.00 per share)                                                    (223,198)
Expenses of Capital Stock Activity                                                           2,731
Stock Repurchase Forward Contract                                                           (7,677)
Capital Stock Activity
        Long-Term Incentive Plan Issuances     2,137          71,300             (3)       (12,157)
                                           ---------    ------------      ---------   ------------     --------    ----------
Balance at December 31, 1998                 224,684    $  3,589,031       $  1,236    $  (532,925)       2,302    $  230,172
                                           =========    ============      =========   =============    ========    ==========
</TABLE>

See Notes to Consolidated Financial Statements.

<PAGE>
Notes to Consolidated Financial Statements                                 29

Notes to Consolidated Financial Statements

1. Significant Accounting Policies
General
The consolidated financial statements of PECO Energy Company (the Company)
include the accounts of its utility subsidiary companies, all of which are
wholly owned. Accounting policies for all of the Company's operations are
in accordance with generally accepted accounting principles (GAAP).
Accounting policies for regulated operations are also 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 GAAP 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 by the Company in accounting for unbilled revenue, the
allowance for uncollectible accounts, purchased gas adjustment clause,
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 accounts for all of its electric transmission and distribution
and gas operations in accordance with 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 such operations are currently
subject. If a separable portion of the Company's business no longer meets
the provisions of SFAS No. 71, the Company is required to eliminate the
financial statement effects of regulation for that portion. Effective
December 31, 1997, the Company determined that the electric generation
portion of its business no longer met the criteria of SFAS No. 71 and,
accordingly, implemented SFAS No. 101, "Regulated Enterprises - Accounting
for the Discontinuation of FASB Statement No. 71," for that portion of its
business.

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.

Purchased Gas and Energy Cost Adjustment Clauses
The Company's gas rates are subject to a fuel adjustment clause designed to
recover or refund the difference between the actual cost of purchased gas
and the amount included in base rates. Differences between the amounts
billed to customers and the actual costs recoverable are deferred and
recovered or refunded in future periods by means of prospective quarterly
adjustments to rates.

<PAGE>

     Prior to December 31, 1996, the Company's retail electric rates were
subject to an Energy Cost Adjustment (ECA) clause designed to recover or refund
the difference between the actual cost of fuel, energy interchange or purchased
power and the amount of such costs included in base rates. Effective December
31, 1996, the PUC approved the roll-in of electric energy costs into the base
rates charged to the Company's retail electric customers and such rates are no
longer subject to the ECA.

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
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.

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.

Depreciation, Amortization and Decommissioning
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 2.8% in 1998, 3.3% in 1997 and
2.9% in 1996. See note 3 for information concerning the change in 1996 to
depreciation and amortization.

     The Company's current estimate of the costs for decommissioning its
ownership share of its nuclear generating stations is currently included in
regulated rates and is 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. The
Company believes that the amounts being recovered from customers through
electric rates will be sufficient to fully fund the unrecorded portion of its
decommissioning obligation.

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 for regulated operations. AFUDC
is recorded as a charge to Construction Work in Progress and as a credit to
AFUDC included in Other Income and Deductions. The rates used for
capitalizing AFUDC, which averaged 8.63% in 1998, 8.88% in 1997 and 9.38%
in 1996, are computed under a method prescribed by regulatory authorities.
AFUDC is not included in regular taxable income and the depreciation of
capitalized AFUDC is not tax deductible.

<PAGE>
30                                 PECO Energy Company and Subsidiary Companies

     Effective January 1, 1998, the Company ceased accruing AFUDC for electric
generation-related construction projects and began using SFAS No. 34,
"Capitalizing Interest Costs," to calculate the costs during construction of
debt funds used to finance its electric generation-related construction
projects. The Company recorded capitalized interest of $7 million in 1998.

Gains and Losses on Reacquired Debt
Prior to December 31, 1997, gains and losses on reacquired debt were
deferred and amortized to interest expense over the period approved for
ratemaking purposes. Effective January 1, 1998, gains and losses on
reacquired debt associated with the electric generation portion of the
Company's operations are expensed as incurred. Gains and losses on
reacquired debt associated with the Company's regulated operations continue
to be deferred and amortized to interest expense over the period approved
for ratemaking purposes based on management's assessment of the likelihood
of recovery.

Income Taxes
Deferred Federal and state income taxes are provided on all significant
timing differences between book bases and tax bases of assets and
liabilities, transactions that reflect taxable income in a year different
than book income and tax carry forwards. Investment tax credits previously
used for income tax purposes have been deferred on the Consolidated Balance
Sheet and are recognized in book income over the life of the related
property. The Company and its subsidiaries file a Consolidated Federal
income tax return. Income taxes are allocated to each of the Company's
subsidiaries within the consolidated group based on the separate return
method.

Derivative Financial Instruments
Hedge accounting is applied only if the derivative reduces the risk of the
underlying hedged item and is designated at inception as a hedge, with
respect to the hedged item. If a derivative instrument ceased to meet the
criteria for deferral, any gains or losses would be currently recognized in
income. The Company does not hold or issue derivative financial instruments
for trading purposes.

Utility Plant
Effective December 31, 1997, electric generation plant is valued at the
lower of original cost or market pursuant to SFAS No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to Be
Disposed Of"(SFAS No. 121). All other utility plant continues to be valued
at original cost.

Capitalized Software Costs
Software projects which exceed $5 million are capitalized. At December 31,
1998 and 1997, capitalized software costs totaled $84 and $86 million (net
of $37 and $29 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.
<PAGE>

New Accounting Pronouncements
In 1998, the Company adopted SFAS No. 131, "Disclosures about Segments of
an Enterprise and Related Information" (SFAS No. 131). SFAS No. 131
supersedes SFAS No. 14, "Financial Reporting for Segments of a Business
Enterprise," replacing the "industry segment" approach with the
"management" approach. The management approach designates the internal
organization that is used by management for making operating decisions and
assessing performance as the source of the Company's reportable segments.
SFAS No. 131 also requires disclosures about products and services,
geographic areas and major customers. The adoption of SFAS No. 131 did not
affect the Company's financial condition or results of operations (see note 2).

     In 1998, the Company adopted SFAS No. 132, "Employers' Disclosures about
Pensions and Other Postretirement Benefits," (SFAS No. 132) which revises and
standardizes employers' disclosures about pension and other postretirement
benefit plans but does not change the measurement or recognition of those plans.
The adoption of SFAS No. 132 did not affect the Company's financial condition or
results of operations (see note 6).

     In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities," (SFAS
No. 133) to establish accounting and reporting standards for derivatives. The
new standard requires recognizing all derivatives as either assets or
liabilities on the balance sheet at their fair value and specifies the
accounting for changes in fair value depending upon the intended use of the
derivative. The new standard will be effective for fiscal years beginning after
June 15, 1999. The Company expects to adopt SFAS No. 133 in the first quarter of
2000. The Company is in the process of evaluating the impact of SFAS No. 133 on
its financial statements.

     In November 1998, the FASB's Emerging Issues Task Force issued EITF 98-10.
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities." EITF 98-10 outlines attributes that may be indicative of an energy
trading operation and gives further guidance on the accounting for contracts
entered into by an energy trading operation. This accounting guidance requires
mark-to-market accounting for contracts considered to be a trading activity.
EITF 98-10 is applicable for fiscal years beginning after December 15, 1998 with
any impact recorded as a cumulative effect adjustment through retained earnings
at the date of adoption. At December 31, 1998, the Company has evaluated its
wholesale marketing operation and related contracts under the guidance provided
in EITF 98-10. For those contracts entered into in the over-the-counter market
and considered to be a trading activity, the Company believes the impact to be
immaterial. However, due to the duration, complexity, and uncertainties
surrounding the long-term commitments considered to be trading activities, the
Company is continuing to evaluate these commitments and the impact of adopting
EITF 98-10.

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

2. Nature of Operations and Information about Products and Services
The Company is primarily a vertically integrated public utility that
provides retail electric and natural gas service to the public in its
traditional service territory and retail electric generation service
throughout Pennsylvania in conjunction with Pennsylvania's Customer Choice
Program. The Company also engages in the wholesale marketing of electricity
on a national basis. The Company participates in joint ventures which
provide services such as telecommunications in the Philadelphia
metropolitan area. Revenues and expenses associated with these activities,
the Customer Choice Program, joint ventures and other projects are
reflected in Other Income and Deductions in the Company's Consolidated
Statements of Income.
<TABLE>
<CAPTION>

For the Years Ended December 31,                                      1998                 1997                   1996
-------------------------------------------------------------------------------------------------------------------------
                                                                                                    Thousands of Dollars
                                                                  -------------------------------------------------------
<S>                                                              <C>                  <C>                     <C>
Operating Revenues from Electric Operations
Residential                                                       $ 1,377,237           $ 1,357,449           $ 1,370,158
Small commercial and industrial                                       783,682               778,743               748,561
Large commercial and industrial                                     1,066,868             1,077,374             1,098,307
Other                                                                 149,424               147,523               140,133
Unbilled                                                                1,409                19,130               (25,950)
                                                                  -----------           -----------           -----------
        Service territory                                           3,378,620             3,380,219             3,331,209
Interchange sales                                                     210,965                58,614                25,991
Sales to other utilities                                            1,221,255               727,836               497,636
                                                                  -----------           -----------           -----------
        Total operating revenues                                  $ 4,810,840           $ 4,166,669           $ 3,854,836
                                                                  ===========           ===========           ===========
Operating Revenues from Gas Operations
Residential                                                       $    15,968           $    16,852           $    15,716
House heating                                                         236,430               265,299               249,507
Commercial and industrial                                             124,548               144,801               132,822
Other                                                                   2,037                 3,228                11,462
Unbilled                                                               (2,960)                 (969)               (4,250)
                                                                  -----------           -----------           -----------
        Subtotal                                                      376,023               429,211               405,257
Other revenues (including gas transported for customers)               23,619                22,021                23,557
                                                                  -----------           -----------           -----------
        Total operating revenues                                  $   399,642           $   451,232           $   428,814
                                                                  ===========           ===========           ===========
</TABLE>

3. Rate Matters
Final Restructuring Order
On May 14, 1998, the PUC issued a final order (Final Restructuring Order)
approving a Joint Petition for Settlement (Global Settlement) filed by the
Company and numerous parties to the Company's restructuring proceeding
mandated by the Electricity Generation Competition and Customer Choice Act
(Competition Act). The Competition Act provides for the restructuring of
the electric utility industry in Pennsylvania, including the deregulation
of generation operations and the institution of retail competition for
generation supply beginning in 1999. The Final Restructuring Order provided
for the recovery of $5.26 billion of stranded costs through transition
charges to distribution customers over a 12 year period beginning in 1999
with a 10.75% return on the balance and supercedes all prior orders
regarding recovery of generation-related regulatory assets and liabilities.
During the 12 year stranded cost recovery period, the Company will amortize
the recoverable stranded costs in accordance with the rate schedules
determined in the Final Restructuring Order.
<PAGE>
                                                                              31

     The Final Restructuring Order provided for the phase-in of customer choice
of electric generation supplier (EGS) for all customers: one-third of the peak
load of each customer class on January 1, 1999; one-third on January 2, 1999;
and the remainder on January 2, 2000. The Final Restructuring Order also
established market share thresholds to ensure that a minimum number of
residential and commercial customers choose an EGS. If less than 35% and 50% of
residential and commercial customers have chosen an EGS by January 1, 2001 and
January 1, 2003, respectively, the number of customers sufficient to meet the
necessary threshold levels shall be randomly selected and assigned to an EGS
through a PUC-determined process. 

     Beginning January 1, 1999, electric rates will be unbundled into
transmission and distribution components, a Competitive Transition Charge (CTC)
for recovery of stranded costs and an energy and capacity charge. Eligible
customers who choose an alternative EGS will not be charged the energy and
capacity charge or the transmission charge and instead will purchase their
electric energy supply and transmission at market-based rates from their EGS.
The Company will in turn be reimbursed by the EGS, via the PJM Interconnection,
LLC, for the cost of the transmission service at a rate approximately equivalent
to the unbundled transmission rate. Also, beginning January 1, 1999, the Company
will unbundle its retail electric rates for metering, meter reading and billing
and collection services to provide credits to those customers who elect to have
an alternative supplier perform these services.

     In accordance with the Competition Act and the Final Restructuring Order,
the Company's retail electric rates are capped at the year-end 1996 levels
(system-wide average of 9.96 cents/kilowatt hour (kWh)) through June 2005. The
Final Restructuring Order requires the Company to reduce its retail electric
rates by 8% from the 1996 system-wide average rate on January 1, 1999. The rate
decrease will become 6% from January 1, 2000 until January 1, 2001, when the
system-wide average rate cap will revert to 9.96 cents/kWh. The transmission and
distribution rate component will remain capped at a system-wide average rate of
2.98 cents/kWh through June 30, 2005. Additionally, generation rate caps,
defined as the sum of the applicable transition charge and energy and capacity
charge, will remain in effect through 2010.
<PAGE>

32                                 PECO Energy Company and Subsidiary Companies

     The Final Restructuring Order requires that on January 1, 2001, 20% of all
of the Company's residential customers, determined by random selection and
without regard to whether such customers are obtaining generation service from
an alternate EGS, shall be assigned to a provider of last resort default
supplier other than the Company through a PUC-approved bidding process.

     The Final Restructuring Order authorizes the issuance of up to $4 billion
of transition bonds (Transition Bonds). In preparation for the issuance of
Transition Bonds, the Company formed a special purpose subsidiary (SPS). The
proceeds of the Transition Bonds are required to be used principally to reduce
recoverable stranded costs and related capitalization. The Transition Bonds will
be obligations of the SPS, secured by intangible transition property (ITP). ITP
represents the irrevocable right of the Company or its assignee, to collect
non-bypassable charges from customers to recover stranded costs.

     The Company filed complaints in federal and state courts relating to the
restructuring orders issued by the PUC in December 1997, January 1998 and
February 1998. In addition, numerous other parties filed appeals and cross
appeals of these orders. In accordance with the terms of the Final Restructuring
Order, all appeals and cross-appeals filed by the signatories to the Global
Settlement have been placed in a pending but inactive status. Such appeals and
cross appeals will be permanently withdrawn at such time that the Final
Restructuring Order is no longer subject to administrative or judicial
challenge.

     In an appeal of a PUC order issued in May 1997, an intervenor brought an
action asserting that the stranded cost recovery provisions of the Competition
Act violated the Commerce Clause of the United States Constitution. On May 7,
1998, the Commonwealth Court of Pennsylvania unanimously rejected the claim. The
intervenor petitioned the Supreme Court of Pennsylvania for allowance of appeal.
On September 29, 1998, the Pennsylvania Supreme Court denied the petition. On
December 28, 1998, the intervenor filed a petition for certiorari with the
United States Supreme Court.

Limerick
Through 1997, the Company was recovering certain deferred Limerick costs.
At December 31, 1997, the unamortized portion of these regulatory assets of
$321 million was included as part of electric generation-related regulatory
assets.

     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 and to
share in the benefits which resulted from the operation of both Limerick Units
No. 1 and No. 2. The Company's ECA was discontinued at December 31, 1996. During
1996, the Company recorded as revenue net of fuel costs $82 million, 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.
<PAGE>

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. At December 31,
1997, $90 million of depreciation and amortization that would have been
recognized in 1998 was deferred as a regulatory asset since the Company's
rates continued to be cost-based until January 1, 1999. During 1998 these
amounts were amortized and recovered.

Energy Cost Adjustment (ECA)
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 year
ended December 31, 1996 the Company recorded a bonus of $22 million.

4. Accounting Changes
The Company accounts for its electric transmission and distribution and gas
operations in accordance with SFAS No. 71 which requires the Company to
record the financial statement effects of the rate regulation to which the
Company is subject. Use of SFAS No. 71 is applicable to the utility
operations 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.
The Company believes that it is probable that regulatory assets associated
with these operations will be recovered.

     Effective December 31, 1997, the Company discontinued the application of
SFAS No. 71 for its retail electric generation operations and adopted the
provisions of SFAS No. 101 "Regulated Enterprises - Accounting for the
Discontinuation of Application of FASB Statement No. 71."

     As required by SFAS No. 101, at December 31, 1997, the Company performed an
impairment test of its electric generation assets pursuant to SFAS No. 121, on a
plant specific basis and determined that $6.1 billion of its $7.1 billion of
electric generation assets would be impaired as of December 31, 1998. The
Company estimated the fair value for each of its electric generating units by
determining its estimated future operating cash inflows and outflows. The net
future cash flows for each electric generating plant were then compared to its
net book value. For any electric generating plant with future undiscounted cash
flows less than its book value, net cash flows were discounted using a discount
rate commensurate with the risk of each electric generating plant. Since the
Company's retail electric rates continued to be cost-based through January 1,
1999, $333 million representing depreciation expense on electric
generation-related assets in 1998 and $91 million representing amortization of
other regulatory assets in 1998 were reclassified to a regulatory asset and were
amortized and recovered in 1998.
<PAGE>

Notes to Consolidated Financial Statements                                   33

     At December 31, 1997, the Company had total electric generation-related
stranded costs of $8.4 billion, representing $5.8 billion of net stranded
electric generation plant and $2.6 billion of electric generation-related
regulatory assets. The original PUC restructuring order allowed the Company to
recover $5.3 billion of its generation-related stranded costs from customers.
This resulted in a net unrecoverable amount of $3.1 billion. Accordingly, the
Company recorded an extraordinary charge at December 31, 1997 of $3.1 billion
($1.8 billion net of taxes) of electric generation-related stranded costs that
will not be recovered from customers. The Final Restructuring Order did not
change the amount of allowable stranded costs.

     Effective December 31, 1997, the Company discontinued the application of
SFAS No. 71 for its wholesale energy sales operations. Based on projections of
the Company's retail load growth, the Company concluded all of its owned
generation capacity would be necessary to meet its electric retail load. As a
result, the discontinuance of SFAS No. 71 for its wholesale energy sales
operations did not result in a charge against income.

5. Commitments and Contingencies
Capital Commitments
The Company estimates $440 million of capital expenditures in 1999. Certain
facilities under construction and to be constructed may require permits and
licenses which the Company has no assurance will be granted. Capital
expenditures do not include investments in joint ventures including
investments related to the Company's strategy to expand its generation
portfolio.

Nuclear Insurance
As of December 31, 1998, the Price-Anderson Act limited the liability of
nuclear reactor owners to $9.8 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 $9.6 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 $88 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, the U.S. 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 $30 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. Such losses could have a material
adverse effect on the Company's financial condition and results of operations.
<PAGE>

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 $10 million per year.

Nuclear Decommissioning and Spent Fuel Storage
The Company's current estimate of its nuclear facilities' decommissioning
cost is $1.5 billion in 1997 dollars. Through 1998, this amount was being
collected through electric rates over the life of each generating unit.
Beginning in 1999, decommissioning costs will be recoverable through
regulated rates. Under rates in effect through December 31, 1998, the
Company collected and expensed approximately $20 million annually from
customers which was accounted for as a component of depreciation expense
and accumulated depreciation. At December 31,1998 and 1997, $336 and $294
million, respectively, were included in accumulated depreciation. In order
to fund future decommissioning costs, at December 31, 1998 and 1997, the
Company held $378 and $320 million, respectively, in trust accounts which
are included as Investments in the Company's Consolidated Balance Sheets
and include both net unrealized and realized gains. Net unrealized gains of
$60 and $43 million were recognized as a Deferred Credit in the Company's
Consolidated Balance Sheet at December 31, 1998 and 1997, respectively. The
Company recognized net realized gains of $12, $11 and $10 million as Other
Income in the Company's Consolidated Statement of Income for the years
ended December 31, 1998, 1997 and 1996, respectively. The Company believes
that the amounts being recovered from customers through regulated rates
will be sufficient to fully fund the unrecorded portion of its
decommissioning obligation.

     In an Exposure Draft issued in 1996, the 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 has expanded the scope of the Exposure Draft to
include closure or removal liabilities that are incurred at any time during the
operating life of the related long-lived asset. The FASB has decided that it
should proceed toward either a final Statement or a revised Exposure Draft. The
timing of this project is still to be determined. 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 a related regulatory 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
U.S. 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
long-term storage and disposal. This fee may be adjusted prospectively in order
to ensure full cost recovery. Because of inaction by the DOE following the D.C.
Court of Appeals finding of the DOE's obligation to begin receiving spent fuel
in 1998, a group of forty-two utility companies, including the Company, and
forty-six state agencies, filed suit against the DOE 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

<PAGE>

34                                 PECO Energy Company and Subsidiary Companies

action to meet its 1998 obligations. In November 1997, the D.C. Court of Appeals
issued a decision in which it held that the DOE had not abided by its prior
determination that the DOE has an unconditional obligation to begin disposal of
spent nuclear fuel by January 31, 1998. The D.C. Court of Appeals also precluded
the DOE from asserting that it was not required to begin receiving spent nuclear
fuel because it had not yet prepared a permanent repository or an interim
storage facility. The DOE and one of the utility companies filed Petitions for
Reconsideration of the decision which were denied, as were petitions seeking
U.S. Supreme Court review of the decision. In addition, the DOE is exploring
other options to address delays in the waste acceptance schedule.

     Peach Bottom has on-site facilities with capacity to store spent nuclear
fuel discharged from the units through 2000 for Unit No. 2 and 2001 for Unit No.
3. Life-of-plant storage capacity will be provided by on-site dry cask storage
facilities, the construction of which began in 1998. Limerick has on-site
facilities with capacity to store spent nuclear fuel to 2007. Salem has on-site
facilities with spent fuel storage capacity through 2008 for Unit No. 1 and 2012
for Unit No. 2.

Energy Commitments
The Company's electric utility operations include the wholesale marketing
of electricity. The Company utilized certain types of fixed-price contracts
and other risk management instruments in connection with its wholesale
marketing operations. These contracts include long-term contracts which
commit the Company to purchase or sell energy at fixed prices in the future
(i.e. fixed-price forward purchase and sales contracts), and short-term
bilateral swaps and options contracted for in the over-the-counter market.
Under some of these contracts, the Company may purchase at its option
additional power as needed. The use of the foregoing types of contracts is
so that the Company may manage and hedge its retail and wholesale
commitments in coordination with the economic dispatch of the Company's
installed capacity.
<PAGE>

     At December 31,1998, the Company had long-term commitments relating to the
purchase from unaffiliated utilities and others of energy associated with 632 MW
of capacity in 1999, with 2,054 MW of capacity during the period 2000 through
2002 and with 2,431 MW of capacity thereafter. During 1998, purchases under
long-term commitments resulted in expenditures of $170 million. As of December
31, 1998, these purchase commitments result in obligations of approximately $121
million for 1999, $526 million for 2000 through 2002 and $805 million
thereafter. These purchases will be utilized through a combination of retail
sales to customers, long-term sales to other utilities and open market sales.

     At December 31, 1998, the Company had entered into long-term agreements
with unaffiliated utilities to sell energy associated with 5,094 MW of capacity,
of which 1,030 MW of these agreements are for 1999, 2,202 MW are for 2000
through 2002 and the remaining 1,862 MW extend through 2009. 

     At December 31, 1998, the Company had entered into long-term agreements
with unaffiliated utilities to purchase transmission rights. These purchase
commitments result in obligations of approximately $21 million in 1999, $19
million in 2000 and $9 million per year in 2001 through 2003.

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 28 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. The Pennsylvania Department of Environmental Protection has
approved the Company's clean up of three sites. Eight other sites are currently
under some degree of active study and/or remediation.

     As of December 31, 1998 and 1997, the Company had accrued $60 and $63
million, respectively, for environmental investigation and remediation costs,
including $33 and $35 million, respectively, for MGP investigation and
remediation, that currently can be reasonably estimated. The Company cannot
reasonably estimate whether it will incur other significant liabilities for
additional investigation and remediation costs at these or additional sites
identified by the Company, environmental agencies or others, or whether such
costs will be recoverable from third parties.
<PAGE>

Notes to Consolidated Financial Statements                                  35

Litigation
Grays Ferry Cogeneration Partnership
On April 9, 1998, Grays Ferry Cogeneration Partnership (Grays Ferry), two of
three partners of Grays Ferry and Trigen-Philadelphia Energy Corporation, filed
a complaint in Philadelphia County of Common Pleas against the Company for
specific performance, breach of contract, fraud and breach of implied covenant
of good faith and fair dealing, conversion, unjust enrichment, breach of
fiduciary duties and tortious interference with respect to two power purchase
agreements (PPAs) that the Company had entered into with Grays Ferry. The
plaintiff seeks specific performance, damages in excess of $200 million and
punitive damages. A preliminary injunction was entered against the Company on
May 5, 1998, enjoining the Company from terminating the PPAs. On May29, 1998,
Westinghouse Power Generation filed a complaint in the Philadelphia Court of
Common Pleas against the Company for tortious interference with two alleged
contracts that Westinghouse has with Grays Ferry. On September 4, 1998, The
Chase Manhattan Bank, as agent for a syndicate of banks that are lenders to
Grays Ferry, filed a complaint against the Company alleging tortious
interference by the Company in the credit agreements between Grays Ferry and the
banks and breach of contract of a letter agreement between the Company and the
banks. The Company cannot predict the outcome of these matters.

Cajun Electric Power Cooperative, Inc.
On May 27, 1998, the United States Department of Justice, on behalf of the
Rural Utilities Service and the Chapter 11 Trustee for the Cajun Electric
Power Cooperative, Inc. (Cajun), filed an action claiming breach of
contract against the Company in the United States District Court for the
Middle District of Louisiana arising out of the Company's termination of
the contract to purchase Cajun's interest in the River Bend nuclear power
plant. This action seeks $67 million in damages. The Company cannot predict
the outcome of this matter.

The Company is involved in various other 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.

6. Retirement Benefits
The Company and its subsidiaries have a defined benefit pension plan and
postretirement benefit plans applicable to essentially all employees. The
following provides a reconciliation of benefit obligations, plan assets and
funded status of the plans.

<PAGE>

<TABLE>
<CAPTION>

                                                                                                        Other Postretirement
Thousands of Dollars                                                    Pension Benefits                       Benefits
--------------------------------------------------------------------------------------------------------------------------------
                                                                       1998           1997              1998            1997
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                               <C>             <C>             <C>               <C>        
Change in Benefit Obligation
Net benefit obligation at beginning of year                       $ 2,141,040     $ 1,982,915     $     779,231     $   662,701
Service cost                                                           30,167          25,368            18,375          14,401
Interest cost                                                         153,644         150,057            53,924          54,149
Plan participants' contributions                                           --              --               397              --
Plan amendments                                                            --          (3,052)               --              --
Actuarial (gain)/loss                                                 143,274         129,148            (8,260)         85,452
Curtailments                                                          (73,330)             --            10,403              --
Settlements                                                           (46,541)             --                --              --
Special termination benefits                                          114,182              --            29,712              --
Gross benefits paid                                                  (152,850)       (143,396)          (36,011)        (37,472)
                                                                  -----------     -----------     -------------     -----------

Net benefit obligation at end of year                             $ 2,309,586     $ 2,141,040     $     847,771     $   779,231
                                                                  ===========     ===========     =============     ===========
Change in Plan Assets
Fair value of plan assets at beginning of year                    $ 2,538,039     $ 2,302,935     $     178,045     $   126,661
Actual return on plan assets                                          343,754         377,803            23,535          22,691
Employer contributions                                                 16,404             697            57,319          66,165
Plan participants' contributions                                           --              --               397              --
Gross benefits paid                                                  (152,850)       (143,396)          (36,011)        (37,472)
                                                                  -----------     -----------     -------------     -----------

Fair value of plan assets at end of year                          $ 2,745,347     $ 2,538,039     $     223,285     $   178,045
                                                                  ===========     ===========     =============     ===========

Funded status at end of year                                      $   435,761     $   396,999     $    (624,486)    $  (601,186)
Unrecognized net actuarial (gain)/loss                               (659,480)       (649,903)           37,617          53,110
Unrecognized prior service cost                                        65,419          83,188                --              --
Unrecognized net transition obligation(asset)                         (30,512)        (35,713)          165,786         223,226
                                                                  -----------     -----------     -------------     -----------

Net amount recognized at end of year                              $  (188,812)    $  (205,429)    $    (421,083)    $  (324,850)
                                                                  ===========     ===========     =============     ===========
Amounts recognized in the consolidated balance sheet consist of:
        Prepaid benefit cost                                      $    30,462     $     6,167     $         N/A     $       N/A
        Accrued benefit cost                                         (219,274)       (211,596)         (421,083)       (324,850)
                                                                  -----------     -----------     -------------     -----------

Net amount recognized at end of year                              $  (188,812)    $  (205,429)    $    (421,083)    $  (324,850)
                                                                  ===========     ===========     =============     ===========
</TABLE>

<PAGE>

36
<TABLE>
<CAPTION>
                                                                             PECO Energy Company and Subsidiary Companies

                                                  Pension Benefits                      Other Postretirement Benefits
--------------------------------------------------------------------------------------------------------------------------
                                        1998            1997         1996            1998            1997            1996
                                    --------------------------------------------------------------------------------------
<S>                                     <C>             <C>          <C>             <C>             <C>             <C>  
Weighted-average assumptions
        as of December 31
Discount rate                           7.00%           7.25%        7.75%           7.00%           7.25%           7.75%
Expected return on plan assets          9.50%           9.50%        9.50%           8.00%           8.00%           8.00%
Rate of compensation increase           5.00%           5.00%        5.00%           5.00%           5.00%           5.00%
Health care cost trend on
        covered charges                  N/A             N/A          N/A             6.5%            7.0%            8.0%
                                                                            decreasing to   decreasing to   decreasing to
                                                                           ultimate trend  ultimate trend  ultimate trend
                                                                          of 5.0% in 2002 of 5.0% in 2002    5.0% in 2002

Components of net periodic benefit cost
Service cost                       $  30,167        $ 25,368     $ 27,627        $ 18,375         $14,401         $11,855
Interest cost                        153,644         150,057      145,570          53,924          54,149          48,524
Expected return on assets           (209,976)       (182,866)    (171,207)        (13,243)         (9,984)         (3,937)
Amortization of:
 Transition obligation (asset)        (4,538)         (4,538)      (4,538)         14,882          14,882          14,882
 Prior service cost                    6,441           6,441        5,114              --              --              --
 Actuarial (gain)loss                 (7,028)         (3,898)         248              --              --              --
Curtailment charge (credit)          (62,002)             --           --          52,961              --              --
Settlement charge (credit)           (13,439)             --           --              --              --              --
                                   ---------        --------     --------        --------         -------         -------
Net periodic benefit cost          $(106,731)       $ (9,436)    $  2,814        $126,899         $73,448         $71,324
                                   =========        ========     ========        ========         =======         =======
Special termination benefit
        charge(credit)             $ 114,182        $     --     $     --        $ 29,712         $    --         $    --
                                   =========        ========     ========        ========         =======         =======
</TABLE>
Sensitivity of retiree welfare results
<TABLE>
<CAPTION>
<S>                                                                           <C>        
Effect of a one percentage point increase in assumed health care cost trend   
        on total service and interest cost components                         $       10,432
        on postretirement benefit obligation                                  $       90,490

Effect of a one percentage point decrease in assumed health care cost trend
        on total service and interest cost components                         $       (8,460)
        on postretirement benefit obligation                                  $      (75,599)
</TABLE>

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

     During 1998, costs were recognized for special termination benefits in
connection with the retirement incentives and enhanced severance benefits
provided under the Company's Workforce Reduction Program.

     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 Company sponsors a qualifying savings plan covering all employees.
Contributions made by participating employees are matched based on a specified
percentage of employee contribution up to 4% of the employees' pay base. The
cost of the Company's matching contribution to the savings plan totaled $7
million, $7 million and $3 million in 1998, 1997 and 1996, respectively.
<PAGE>

Notes to Consolidated Financial Statements                                 37

7. Accounts Receivable
Accounts receivable at December 31, 1998 and 1997 included unbilled
operating revenues of $142 and $135 million, respectively. The allowance
for uncollectible accounts at December 31, 1998 and 1997 was $20 and $32
million, respectively.

     The Company is party to an agreement with a financial institution under
which it can sell or finance with limited recourse an undivided interest,
adjusted daily, in up to $425 million of designated accounts receivable until
November 2000. At December 31, 1998, the Company had sold a $425 million
interest in accounts receivable, consisting of a $358 million interest in
accounts receivable which the Company accounts for as a sale and a $67 million
interest in special agreement accounts receivable which were accounted for as a
long-term note payable (see note 12). The Company retains the servicing
responsibility for these receivables. The agreement requires the Company to
maintain the $425 million interest, which, if not met, requires the Company to
deposit cash in order to satisfy such requirements. At December 31, 1998, the
Company did not meet this requirement and was required to make a deposit of $7
million.

8. Common Stock
At December 31, 1998 and 1997, common stock without par value consisted of
500,000,000 shares authorized and 224,684,306 and 222,546,562 shares
outstanding, respectively. At December 31, 1998, there were 5,800,841
shares reserved for issuance under the Company's Dividend Reinvestment and
Stock Purchase Plan.

Stock Repurchase
During 1997, the Company's Board of Directors authorized the repurchase of
up to 25 million shares of its common stock from time to time through
open-market, privately negotiated and/or other types of transactions in
conformity with the rulesof the Securities and Exchange Commission.

     Pursuant to these authorizations, the Company has entered into forward
purchase agreements to be settled from time to time, at the Company's election,
on either a physical, net share or net cash basis. The amount at which these
agreements can be settled is dependent principally upon the market price of the
Company's common stock as compared to the forward purchase price per share and
the number of shares to be settled. If these agreements had been settled
<PAGE>

on a net share basis at December 31, 1998, based on the closing price of
the Company's common stock on that date, the Company would have received
approximately 4.6 million shares of Company common stock.

Stock Option Plans
The Company maintains a Long-Term Incentive Plan (LTIP) for certain
full-time salaried employees of the Company. The types of long-term
incentive awards which have been granted under the LTIP are non-qualified
options to purchase shares of the Company's common stock and shares of
restricted common stock. In 1998, the Company initiated a Broad-based
Incentive Program and awarded non-qualified options to all employees except
those in electric transmission and distribution system and gas operations.
The Company uses the disclosure-only provisions of SFAS No. 123,
"Accounting for Stock-Based Compensation." If the Company 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 follows:
<TABLE>
<CAPTION>
                                                                                    1998            1997
------------------------------------------------------------------------------------------------------------
                                                                                        Thousands of Dollars
                                                       -----------------------------------------------------
<S>                                                    <C>                     <C>            <C>       
Earnings (Loss) applicable to common stock             As reported             $    499,615   $   (1,513,910)
                                                       Pro forma               $    493,696   $   (1,515,895)

Earnings (Loss) per average common share (Dollars)     As reported             $      2.24    $        (6.80)                 
                                                       Pro forma               $      2.20    $        (6.81)
</TABLE>

Options granted under the LTIP and the Broad-based Incentive Program become
exercisable upon attainment of a target share value and/or time. All
options expire 10 years from the date of grant. Information with respect to
the LTIP and the Broad-based Incentive Program at December 31, 1998 and
changes for the three years then ended, is as follows:

<PAGE>

38
<TABLE>
<CAPTION>
                                                                                     PECO Energy Company and Subsidiary

                                                         Weighted                        Weighted                        Weighted
                                                          Average                         Average                         Average
                                                         Exercise                         Exercise                        Exercise
                                                           Price                           Price                            Price
                                          Shares        (per share)       Shares         (per share)         Shares     (per share)
                                           1998            1998            1997             1997              1996          1996
----------------------------------------------------------------------------------------------------------------------------------
<S>                <C>                  <C>             <C>              <C>             <C>               <C>           <C>      
Balance at January 1                    3,816,794       $   26.14        2,961,194       $   26.68         2,591,765     $   26.16
Options granted                         2,933,540           27.74        1,139,000           22.49           786,500         28.12
Options exercised                      (2,130,744)          23.86               --              --          (369,871)        25.07
Options cancelled                         (91,000)          24.82        (283,400)           24.96           (47,200)        29.36
                                       ----------                        ---------                         ---------
Balance at December 31                  4,528,590           27.71        3,816,794           26.14         2,961,194         26.68
                                       ==========                        =========                         =========
Exercisable at December 31              3,462,550           23.91        2,800,794           26.65         2,192,694         26.17
                                       ==========                        =========                         =========
Weighted average fair value of
        options granted during year                     $    3.43                        $    2.97                       $    2.78
                                                        =========                        =========                       =========
</TABLE>

The fair value of each option is estimated on the date of grant using the
Black-Scholes option-pricing model with the following weighted average
assumptions used for grants in 1998, 1997 and 1996, respectively:

                                1998            1997            1996
--------------------------------------------------------------------------------
Dividend yield                   6.8%            6.2%            6.2%
Expected volatility             21.4%           19.5%           16.6%
Risk-free interest rate          5.5%            6.4%            5.5%
Expected life (years)            9.5               5               5

At December 31, 1998, the option groups outstanding, based on ranges of
exercise prices, were 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
------------------------------------------------------------------------------------------------------------
<S>      <C>                              <C>             <C>     <C>              <C>           <C>      
$15.75 - $20.00                           899,700         8.71    $   19.60        899,700       $   19.60
$20.01 - $25.00                         1,019,750         8.41        22.15      1,004,750           22.18
$25.01 - $30.00                         1,510,600         5.76        27.38      1,510,600           27.38
$30.01 - $35.00                            78,500         9.43        32.97         47,500           31.98
$35.01 - $50.00                         1,020,040         9.87        40.48             --              --
                                        ---------                                ---------
        Total                           4,528,590                                3,462,550
                                        =========                                =========
</TABLE>
The Company issued 7,000 and 4,475 shares of restricted common stock during 1998
and 1997, respectively. Vesting in the restricted common stock awards is ove r a
period not to exceed 10 years from the grant date. The compensation cost
associated with these awards is amortized to expense over the vesting period.
Compensation cost associated with these awards is immaterial.

9. Earnings Per Share
Diluted earnings per average common share is calculated by dividing
earnings applicable to common stock by the weighted average shares of
common stock outstanding including stock options outstanding under the
Company's stock option plans considered to be common stock equivalents. The
following table shows the effect of these stock options on the weighted
average number of shares outstanding used in calculating diluted earnings
per average common share:
<TABLE>
<CAPTION>
                                                                    1998               1997                1996
--------------------------------------------------------------------------------------------------------------------
<S>                                                             <C>                 <C>                 <C>        
Average Common Shares Outstanding                               223,219,000         222,543,000         222,490,000
Assumed Conversion of Stock Options                                 685,000                  --                  --
                                                                -----------         -----------         -----------   
Potential Average Dilutive Common Shares Outstanding            223,904,000         222,543,000         222,490,000
                                                                ===========         ===========         =========== 
</TABLE>
<PAGE>

Notes to Consolidated Financial Statements                                  39

10. Preferred and Preference Stock
At December 31, 1998 and 1997, Series Preference Stock consisted of
100,000,000 shares authorized, of which no shares were outstanding. At
December 31, 1998 and 1997, cumulative Preferred Stock, no par value,
consisted of 15,000,000 shares authorized.
<TABLE>
<CAPTION>
                                       Current                  Shares                        Amount
                                      Redemption              Outstanding             Thousands of Dollars
Series of Preferred Stock              Price(a)          1998           1997           1998            1997
-------------------------------------------------------------------------------------------------------------
Series (without mandatory redemption)
<S>                                     <C>             <C>            <C>        <C>             <C>        
$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                                   112.00          150,000        150,000         15,000          15,000
$3.80                                   106.00          300,000        300,000         30,000          30,000
$7.48                                   (b)             500,000        500,000         50,000          50,000
                                                      ---------      ---------    -----------     -----------
                                                      1,374,720      1,374,720        137,472         137,472
Series (with mandatory redemption)
$6.12                                   (c)             927,000        927,000         92,700          92,700
                                                      ---------      ---------    -----------     -----------
        Total preferred stock                         2,301,720      2,301,720    $   230,172     $   230,172
                                                      =========      =========    ===========     ===========
</TABLE>

(a)  Redeemable, at the option of the Company, at the indicated dollar amounts
     per share, plus accrued dividends.
(b)  None of the shares of this series are subject to redemption prior to April
     1, 2003.
(c)  Annual sinking fund requirements in 1999 - 2003 are $18,540,000. None of
     the shares of this series are subject to redemption prior to August 1,
     1999.

11. Company Obligated Mandatorily Redeemable Preferred Securities of a
Partnership (COMRPS)
At December 31, 1998 and 1997, 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 A, C and D series of
COMRPS with liquidation values of $25 (A and C) and $1,000 (D) 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 related series of
COMRPS. The interest expense on the debentures is included in Other Income
and Deductions in the Consolidated Statements of Income and is deductible
for tax purposes.
<TABLE>
<CAPTION>
                     Mandatory                                                                      Amount
                     Redemption      Distribution        Trust Receipts Outstanding          Thousands of Dollars
At December 31,         Date            Rate               1998             1997            1998             1997
----------------------------------------------------------------------------------------------------------------------
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                 --           80,835
C (b)                   2037            8.00%           2,000,000        2,000,000             50,000           50,000
D (c)                   2028            7.38%              78,105               --             78,105               --
                                                       ----------       ----------      -------------    -------------
    Total                                              10,928,105       13,974,183      $     349,355    $     352,085
                                                       ==========       ==========      =============    =============
</TABLE>

(a) On May 15, 1998, PECO Energy Capital Trust I redeemed all outstanding Trust
    Receipts, each representing an 8.72% Cumulative Monthly Income Preferred
    Security, Series B of PECO Energy Capital, L.P.

(b) Ownership of this series is evidenced by Trust Receipts, each representing
    an 8.00% COMRPS, Series C, representing limited partnership interests. The
    Trust Receipts were issued by PECO Energy Capital Trust II, the sole assets
    of which are 8.00% COMRPS, Series C. Each holder of Trust Receipts is
    entitled to withdraw the corresponding number of 8.00% COMRPS, Series C from
    the Trust in exchange for the Trust Receipts so held.

(c) Ownership of this series is evidenced by Trust Receipts, each representing
    an 7.38% COMRPS, Series D, representing limited partnership interests. The
    Trust Receipts were issued by PECO Energy Capital Trust III, the sole assets
    of which are 7.38% COMRPS, Series D. Each holder of Trust Receipts is
    entitled to withdraw the corresponding number of 7.38% COMRPS, Series D from
    the Trust in exchange for the Trust Receipts so held. This Series was issued
    on April 6, 1998.
<PAGE>
40

12. Long-Term Debt
<TABLE>
<CAPTION>

At December 31,                                      Series          Due          1998             1997
----------------------------------------------------------------------------------------------------------
                                                                                    Thousands of Dollars
                                             -------------------------------------------------------------
<S>                                            <C>                <C>         <C>             <C>
First and refunding mortgage bonds (a)                5 3/8%          1998     $       --      $  225,000
                                               7 1/2%-9 1/4%          1999        325,000         325,000
                                               5 5/8%-7 3/8%          2001        330,000         330,000
                                                   7 1/8%-8%          2002        500,000         500,000
                                               6 1/2%-6 5/8%          2003        450,000         450,000
                                              6 3/8%-10 1/4%     2004-2008        111,562         115,625
                                                          (b)    2009-2013        154,200         154,200
                                               6 5/8%-8 3/4%     2019-2024      1,082,130       1,607,130
                                                                               ----------      ----------
Total first and refunding mortgage bonds                                        2,952,892       3,706,955
Notes payable                                                                      15,930          15,574
Pollution control notes                                   (c)                     212,705         212,705
Medium-term notes                                         (d)                      50,000          62,400
Note Payable - accounts receivable agreement              (e)                      66,837         128,999
Unamortized debt discount and premium, net                                        (17,249)        (26,405)
                                                                               ----------      ----------
Total long-term debt                                                            3,281,115       4,100,228
Due within one year                                       (f)                     361,523         247,087
                                                                               ----------      ----------
        Long-term debt included in capitalization         (g)                  $2,919,592      $3,853,141
                                                                               ==========      ==========
</TABLE>

(a) Utility plant is subject to the lien of the Company's mortgage.
(b) Floating rates, which were an average annual interest rate of 3.13% at
    December 31, 1998.
(c) Floating rates, which were an average annual interest rate of 3.32% at
    December 31, 1998.
(d) Medium-term notes collateralized by mortgage bonds. The average annual
    interest rate was 9.09% at December 31, 1998.
(e) See note 7.
(f) Long-term debt maturities, including mandatory sinking fund requirements, in
    the period 1999-2003 are as follows: 1999 - $361,523,000; 2000 -
    $74,255,500; 2001 - $337,431,500; 2002 - $507,436,500; 2003 - $406,534,500.
(g) The annualized interest on long-term debt at December 31, 1998, was $222
    million, of which $210 million was associated with mortgage bonds and $12
    million was associated with other long-term debt.

In the fourth quarter of 1998, the Company redeemed $525 million of its
First Mortgage Bonds consisting of: $150 million of its 8 3/4% series due
2022, $125 million of its 8 5/8% series due 2022 and $250 million of its 8
1/4% series due 2022 at redemption prices of 105.75, 105.20 and 104.85 plus
interest, respectively. As a result, the Company recognized an
extraordinary charge of $34 million ($20 million net of income taxes). The
extraordinary charge consisted primarily of premiums and the write-off of
deferred charges.

13. Short-Term Debt
<TABLE>
<CAPTION>
                                                      1998            1997            1996
---------------------------------------------------------------------------------------------
                                                                         Thousands of Dollars
                                                 --------------------------------------------
<S>                                              <C>              <C>            <C>         
Average borrowings                               $   209,261      $   248,111    $    198,090
Average interest rates, computed on daily basis         5.83%            5.83%           5.64%
Maximum borrowings outstanding                   $   525,000      $   464,500    $    369,500
Average interest rates, at December 31                  6.17%            6.74%           6.90%
</TABLE>

The Company has a $400 million one-year term loan agreement with a group of
banks, which expires on November 30, 1999. At December 31, 1998, $400
million of short-term debt was outstanding under this term loan agreement.

     The Company has a $900 million unsecured revolving credit facility with a
group of banks. The credit facility consists of a $450 million 364-day credit
agreement and a $450 million three-year credit agreement. The Company uses the
credit facility principally to support its $600 million commercial paper
program. There was no debt outstanding under this credit facility at December
31, 1998. At December 31, 1998, $125 million of commercial paper was
outstanding. At December 31, 1998, the Company had available formal and informal
lines of credit with banks aggregating $100 million.
<PAGE>

Notes to Consolidated Financial Statements                                  41

14. Income Taxes
Income tax expense (benefit) is comprised of the following components:
<TABLE>
<CAPTION>


For the Years Ended December 31,                 1998                 1997                 1996
---------------------------------------------------------------------------------------------------
                                                                               Thousands of Dollars
                                            -------------------------------------------------------
<S>                                         <C>                   <C>                   <C>        
Included in operations:
Federal
        Current                             $   358,051           $   251,509           $   126,471
        Deferred                               (109,211)              (11,378)              154,564
        Investment tax credit, net              (18,066)              (18,201)              (15,979)
State
        Current                                  95,309                76,689                62,839
        Deferred                                 (6,429)               (5,850)               12,206
                                            -----------           -----------           -----------
                                                319,654               292,769               340,101
                                            ===========           ===========           ===========
Included in extraordinary item:
Federal
        Current                                 (10,583)                 (123)                   --
        Deferred                                     --              (987,234)                   --
State
        Current                                  (3,174)                  (29)                   --
        Deferred                                     --              (303,575)                   --
                                            -----------           -----------           -----------
                                                (13,757)           (1,290,961)                   --
                                            -----------           -----------           -----------
        Total                               $   305,897           $  (998,192)          $   340,101
                                            ===========           ===========           ===========
</TABLE>

The total income tax provisions, excluding the extraordinary item, differed
from amounts computed by applying the federal statutory tax rate to pre-tax
income as follows:
<TABLE>
<CAPTION>
                                                 1998                1997                 1996
---------------------------------------------------------------------------------------------------
                                                                               Thousands of Dollars
                                             ------------------------------------------------------
<S>                                         <C>                  <C>                  <C>      
Net Income                                    $ 532,378             $ 336,558             $ 517,205
Total income tax provisions                     319,654               292,769               340,101
                                              ---------             ---------             ---------
        Income before income taxes            $ 852,032             $ 629,327             $ 857,306
                                              =========             =========             =========

Income taxes on above at federal statutory 
 rate of 35%                                  $ 298,211             $ 220,264             $ 300,057
Increase (decrease) due to:
        Property basis differences              (10,262)               40,828                 9,903
        State income taxes, net of federal 
         income tax benefit                      57,582                46,046                48,779
        Amortization of investment tax 
         credit                                 (18,066)              (18,201)              (15,979)
        Prior period income taxes               (12,951)               (2,985)               (1,707)
        Other, net                                5,140                 6,817                  (952)
                                              ---------             ---------             ---------
        Total income tax provisions           $ 319,654             $ 292,769             $ 340,101
                                              =========             =========             =========
Effective income tax rate                          37.5%                 46.5%                 39.7%
                                              =========             =========             =========
</TABLE>
<PAGE>

42                                PECO Energy Company and Subsidiary Companies

Provisions for deferred income taxes consist of the tax effects of the
following temporary differences:
<TABLE>
<CAPTION>
                                                             1998                 1997                  1996
---------------------------------------------------------------------------------------------------------------
                                                                                           Thousands of Dollars
                                                        -------------------------------------------------------
<S>                                                     <C>                   <C>                   <C>        
Deferred generation charges recoverable                 $  (174,787)          $        --           $        --
Depreciation and amortization                               140,448                57,530                42,385
Deferred energy costs                                        (2,491)                2,256                27,374
Retirement and separation programs                          (51,146)              (12,734)               19,746
Incremental nuclear outage costs                             (7,434)                 (981)                2,440
Uncollectible accounts                                        4,764                (1,710)               (2,805)
Reacquired debt                                              (5,026)               (8,607)               (9,578)
Unbilled revenue                                              3,579                (5,110)                3,910
Environmental clean-up costs                                 (3,574)              (15,121)                 (714)
Obsolete inventory                                            4,206                (7,074)                5,829
Limerick plant disallowances and phase-in plan                   --                  (747)                 (747)
AMT credits                                                 (42,067)                   --                83,010
Other nuclear operating costs                                 9,926                (9,892)                   --
Other                                                         7,962               (15,038)               (4,080)
                                                        -----------           -----------           -----------
        Subtotal                                           (115,640)              (17,228)              166,770
Extraordinary item                                               --            (1,290,809)                   --
                                                        -----------           -----------           -----------
        Total                                           $  (115,640)          $(1,308,037)          $   166,770
                                                        ===========           ===========           ===========
</TABLE>

The tax effect of temporary differences giving rise to the Company's net
deferred tax liability as of December 31, 1998 and 1997 is as follows:
<TABLE>
<CAPTION>
                                                                       Liability or (Asset)
                                                                     1998              1997
------------------------------------------------------------------------------------------------
                                                                           Thousands of Dollars
------------------------------------------------------------------------------------------------
<S>                                                             <C>                 <C>        
Nature of temporary difference:
Plant basis difference                                          $   2,653,760       $ 2,620,254
Deferred investment tax credit                                        299,999           318,065
Deferred debt refinancing costs                                        37,575           111,651
Other, net                                                           (300,375)         (249,167)
        Deferred income taxes (net) on the balance sheet        $   2,690,959       $ 2,800,803
</TABLE>

The net deferred tax liability shown above as of December 31, 1998 and 1997
was comprised of $3,123 and $3,153 million of deferred tax liabilities, and
$432 and $352 million of deferred tax assets, respectively.

     In accordance with SFAS No. 71, the Company recorded a recoverable deferred
income tax asset of $614 and $586 million at December 31,1998 and 1997,
respectively. These balances are applicable only to regulated assets, due to the
discontinuance of SFAS No. 71 for the Company's electric generation operations.
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 1990 which
resulted in a net increase of $11 million in credits available for carry
forward. The 1991 through 1993 federal income tax returns have been examined and
the Company and the IRS are in the process of settling the audit which will not
have an adverse impact on financial condition or results of operations of the
Company. The years 1994 through 1996 are currently being examined by the IRS.
<PAGE>

Notes to Consolidated Financial Statements                                 43

15. Taxes, Other Than Income - Operating
For the Years Ended December 31,         1998          1997           1996   
-----------------------------------------------------------------------------
                                                         Thousands of Dollars
                                    -----------------------------------------
Gross receipts                      $ 155,663     $   163,552     $   160,246
Capital stock                          43,754          48,085          41,972
Real estate                            51,313          69,597          69,185
Payroll                                30,068          25,976          27,585
Other                                  (1,283)          2,881             558
                                    ---------     -----------     -----------
        Total                       $ 279,515     $   310,091     $   299,546
                                    =========     ===========     ===========
16. Leases
Leased property included in utility plant was as follows:

<TABLE>
<CAPTION>
At December 31,                         1998            1997
-------------------------------------------------------------
                                         Thousands of Dollars
                                    -------------------------
<S>                                 <C>           <C>        
Nuclear fuel                        $ 523,325     $   521,921
Electric plant                          2,321           2,321
                                    ---------     -----------
Gross leased property                 525,646         524,242
                                    ---------     -----------
Accumulated amortization             (371,338)       (348,309)
        Net leased property         $ 154,308     $   175,933
                                    =========     ===========
</TABLE>

Nuclear fuel is amortized as the fuel is consumed. Amortization of leased
property totaled $60, $39 and $31 million for the years ended December 31,
1998, 1997 and 1996, respectively. Other operating expenses included
interest on capital lease obligations of $9 million in 1998, 1997 and 1996,
respectively.

Minimum future lease payments as of December 31, 1998 were:
<TABLE>
<CAPTION>

For the Years Ending December 31,                           Capital Leases        Operating Leases         Total
-----------------------------------------------------------------------------------------------------------------
                                                                                             Thousands of Dollars
                                                              ---------------------------------------------------
<S>                                                           <C>                   <C>                <C>       
1999                                                          $   69,026            $    48,806        $  117,832
2000                                                              65,714                 45,457           111,171
2001                                                              32,439                 42,850            75,289
2002                                                                  92                 42,056            42,148
2003                                                                  92                 49,386            49,478
Remaining years                                                      721                511,164           511,885
                                                              ----------            -----------        ----------
Total minimum future lease payments                           $  168,084            $   739,719        $  907,803
Imputed interest (rates ranging from 6.5% to 17.0%)              (13,776)           ===========        ==========
                                                              ----------
        Present value of net minimum future lease payments    $  154,308
                                                              ----------
</TABLE>

Rental expense under operating leases totaled $69 million in 1998 and $74
million in 1997 and 1996, respectively.

<PAGE>

44                                 PECO Energy Company and Subsidiary Companies

17. Jointly Owned Electric Utility Plant
The Company's ownership interests in jointly owned electric utility plant
at December 31, 1998, 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                              $  347,001   $   20,026   $   118,256   $   190,672       $   82,078
Accumulated depreciation                      183,383       12,929        73,644        91,052           32,638
Construction work in progress                  22,586        1,632         1,770         3,865            1,300
</TABLE>

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

18. Cash and Cash Equivalents
For purposes of the Statements of Cash Flows, the Company considers all
highly liquid debt instruments purchased with a maturity of three months or
less to be cash equivalents. The following disclosures supplement the
accompanying Statements of Cash Flows:
<TABLE>
<CAPTION>
                                                     1998           1997          1996
-----------------------------------------------------------------------------------------
                                                                     Thousands of Dollars
                                                 ----------------------------------------
<S>                                              <C>           <C>            <C>        
Cash paid during the year:
        Interest (net of amount capitalized)     $   384,932   $    405,838   $   415,063
        Income taxes (net of refunds)                346,539        345,232       251,554
Noncash investing and financing:
        Capital lease obligations incurred            38,307         32,909        33,063
</TABLE>

19. Investments
<TABLE>
<CAPTION>

At December 31,                                                1998             1997
---------------------------------------------------------------------------------------
                                                                   Thousands of Dollars
                                                           ----------------------------
<S>                                                        <C>              <C>        
Trust accounts for decommissioning nuclear plants          $    377,970     $   320,442
Telecommunications ventures                                      48,391          85,601
Energy services and other ventures                               39,359          65,578
Nonutility property                                              40,456          24,697
Other                                                            44,728          19,517
                                                           ------------     -----------
        Total                                              $    550,904     $   515,835
                                                           ============     ===========
</TABLE>

20. Financial Instruments

Fair values of financial instruments, including liabilities, are estimated
based on quoted market prices for the same or similar issues. The carrying
amounts and fair values of the Company's financial instruments as of
December 31, 1998 and 1997 were as follows:
<TABLE>
<CAPTION>
Thousands of Dollars                                                          1998                            1997
----------------------------------------------------------------------------------------------------------------------------
                                                                     Carrying        Fair          Carrying           Fair
                                                                      Amount         Value           Amount          Value
                                                                   ---------------------------------------------------------
<S>                                                                <C>             <C>           <C>            <C>         
Non-derivatives:
Assets
        Cash and temporary cash investments                        $     48,083    $   48,083    $    33,404    $     33,404
        Trust accounts for decommissioning nuclear plants               377,970       377,970        320,442         320,442
Liabilities
        Long-term debt (including amounts due within one year)        3,281,115     3,404,250      4,100,228       4,210,885
Derivatives:
        Treasure forwards                                                    --          (300)            --              --
        Forward interest rate swaps                                          --        (4,400)            --              --
</TABLE>
<PAGE>

Notes to Consolidated Financial Statements                                45

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.

     The fair value of derivatives generally reflects the estimated amounts that
the Company would receive or pay to terminate the contracts at the reporting
date, thereby taking into account the current unrealized gains or losses of open
contracts. Dealer quotes are available for all of the Company's derivatives.

     The anticipated issuance of Transition Bonds significantly exposes the
Company to market risks of changes in interest rates. Derivative financial
instruments are used by the Company to reduce these risks. 

     The Company has entered into treasury forwards in an aggregate notional
amount of $4 billion with an average interest rate of 4.71%. The Company has
entered into forward starting interest rate swaps in the aggregate notional
amount of $713 million with an average interest rate of 5.72%. The notional
amount of derivatives do not represent amounts that are exchanged by the parties
and, thus, are not a measure of the Company's exposure. The amounts exchanged
are calculated on the basis of the notional or contract amounts, as well as on
the other terms of the derivatives, which relate to interest rates and the
volatility of these rates.

     The Company would be exposed to credit-related losses in the event of
non-performance by the counterparties that issued the derivative instruments.
The Company does not expect that counterparties to the interest rate swaps and
treasury forwards will fail to meet these obligations, given their high credit
ratings. The credit exposure of derivatives contracts is represented by the fair
value of contracts at the reporting date. The Company's interest-rate swaps are
documented under master agreements. Among other things, these agreements provide
for a maximum credit exposure for both parties. Payments are required by the
appropriate party when the maximum limit is reached. The same maximum credit
exposure applies to the treasury forwards.

21. Early Retirement and Separation Program
In April 1998, the Board of Directors authorized the implementation of a
retirement incentive program and an enhanced severance benefit program. The
retirement incentive program allowed employees age 50 and older, who have
been designated as excess or who are in job classifications facing
reduction, to retire from the Company. The enhanced severance benefit
program provided non-retiring excess employees with fewer than ten years of
service benefits equal to two weeks pay per year of service. Non-retiring
excess employees with more than ten years of service receive benefits equal
to three weeks pay per year of service.

     Through its Cost Competitiveness Review (CCR), the Company identified 1,157
employees across the Company who were considered excess or were in job
classifications facing reduction. Of the 1,157 employees, 711 were eligible for
and agreed to take the retirement incentive program. The remaining employees are
eligible for the enhanced severance benefit program. The Company has eliminated
approximately 422 positions as of December 31, 1998 through both
attrition and the early retirement and severance program. The Company
expects an additional 735 positions to be eliminated during 1999 and 2000.

     The Company recorded an early retirement and separation program charge to
earnings of $125 million ($74 million, net of income taxes) in the fourth
quarter of 1998 to recognize costs related to the CCR workforce reduction
program. This charge consisted of the following: $121 million for the
actuarially determined pension and other postretirement benefits costs and $4
million for outplacement services costs and the continuation of benefits for one
year. Approximately $0.8 million of the $125 million charge was related to the
Company's non-utility operations and accordingly was recorded in Other Income
and Deductions. All cash payments related to the early retirement and severance
program are expected to be funded through the assets of the Company's Service
Annuity Plan.

22. Other Income and Deductions
Settlement of Salem Litigation
On December 31, 1997, the Company received $70 million pursuant to the May
1997 settlement agreement with Public Service Electric and Gas Company
resolving a suit filed by the Company concerning the shutdown of Salem.
During the second quarter of 1997, the Company recorded $70 million ($41
million net of income taxes) as Other Income.


Ventures
The Company periodically reviews its investments to determine that they are
properly valued in its financial statements.  Other Income and Deductions
reflects write-offs of these investments of $10 million and $20 million in
1998 and 1997, respectively.

<PAGE>
46

23. Regulatory Assets and Liabilities
At December 31, 1998 and 1997, the Company had deferred the following
regulatory assets on the Consolidated Balance Sheets:
<TABLE>
<CAPTION>
                                                              1998               1997
------------------------------------------------------------------------------------------
                                                                      Thousands of Dollars
                                                        ----------------------------------
<S>                                                     <C>                 <C>          
Competitive transition charge                           $   5,274,624       $   5,274,624
Recoverable deferred income taxes (see note 14)               614,445             585,661
Deferred generation costs recoverable in current rates             --             424,497
Loss on reacquired debt                                        77,165              83,918
Compensated absences                                            4,289               3,881
Deferred energy costs                                          29,847              35,665
Non-pension postretirement benefits                            90,915              97,409
                                                        -------------       -------------
        Total                                           $   6,091,285       $   6,505,655
                                                        =============       =============
</TABLE>

24. 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 (Loss)
                                             ----------------------------------------------------------------------------------
Millions of Dollars                              1998            1997            1998        1997            1998         1997
-------------------------------------------------------------------------------------------------------------------------------
<S>                                         <C>             <C>              <C>         <C>        <C>              <C>
Quarter ended
March 31                                     $    1,173      $    1,163      $    285     $    302   $        114     $    113
June 30                                           1,207           1,032           362          250            151          123
September 30                                      1,774           1,278           546          388            274          158
December 31                                       1,056           1,145            90           66            (26)      (1,891)

                                                  Earnings Applicable            Average Shares                   Earnings
                                                    to Common Stock                Outstanding               Per Average Share
                                             ----------------------------------------------------------------------------------
Millions of Dollars (except per share data)      1998             1997          1998         1997            1998         1997
-------------------------------------------------------------------------------------------------------------------------------
Quarter ended
March 31                                     $      110        $    109         222.5        222.5   $       0.50     $   0.49
June 30                                             148             118         222.7        222.5           0.66         0.53
September 30                                        270             154         223.1        222.5           1.21         0.69
December 31                                         (28)         (1,895)        224.5        222.5          (0.13)       (8.51)
</TABLE>

The increase in 1998 second quarter results was primarily due to increased
operating revenues net of related fuel costs.   Revenues from wholesale
sales increased significantly compared to 1997. Second quarter 1998
earnings also benefited from the full return to service of Salem which
decreased the cost of fuel purchases and outage-related costs compared to
1997, from decreased operating and maintenance expense and from reduced
uncollectible expenses.

     The increase in 1998 third quarter results was due primarily to increased
operating revenues net of related fuel costs. Revenues from wholesale sales
increased significantly compared to 1997. Third quarter earnings also benefited
from the full return to service of Salem, reduction of operating and maintenance
costs, reduction of uncollectible expenses and a one-time refund of gross
receipts tax.

     The increase in the fourth quarter results was primarily due to the
extraordinary charge of $8.24 per share recorded in 1997 resulting from
deregulation of the Company's electric generation operations; several one-time
adjustments for changes in employee benefits; write-offs of information systems
development charges reflecting clarification of accounting guidelines and
additional reserves to revise estimates for accruals; higher income tax
adjustments; and higher losses from the Company's non-utility ventures. This
increase was partially offset by an Early Retirement and Severance charge and an
extraordinary charge for the premiums paid in connection with the redemption of
higher-cost, long-term debt recorded in the fourth quarter of 1998.

<PAGE>

Notes to Consolidated Financial Statements                                  47

Financial Statistics



Summary of Earnings and Financial Condition
<TABLE>
<CAPTION>

For the Years Ended December 31,                1998            1997        1996            1995            1994            1993
--------------------------------------------------------------------------------------------------------------------------------
                                                                                      Millions of Dollars, except per share data
                                         ---------------------------------------------------------------------------------------
<S>                                      <C>            <C>             <C>            <C>           <C>              <C>         
Income Data
Operating Revenues                          $    5,210     $    4,618       $   4,284     $   4,186       $  4,041      $  3,988
Operating Income                                 1,283          1,006           1,249         1,401          1,064         1,390
Income before Extraordinary Item                   532            337             517           610            427           591
Extraordinary Item (net of income taxes)           (20)        (1,834)             --            --             --            --
Net Income (Loss)                                  513         (1,497)            517           610            427           591
Earnings Applicable to Common Stock                500         (1,514)            499           587            389           542

Earnings per Average Common Share
        Before Extraordinary Item                 2.33           1.44            2.24          2.64           1.76          2.45
Extraordinary Item                               (0.09)         (8.24)             --            --             --            --
Earnings per Average Common Share                 2.24          (6.80)           2.24          2.64           1.76          2.45

Dividends per Common Share                        1.00           1.80           1.755          1.65          1.545          1.43
Common Stock Equity                              13.61          12.25           20.88         20.40          19.41         19.25
Average Shares of Common Stock
        Outstanding (Millions)                   223.2          222.5           222.5         221.9          221.6         221.1

At December 31,
--------------------------------------------------------------------------------------------------------------------------------
Balance Sheet Data
Net Utility Plant                           $    4,610     $    4,495       $  10,760     $  10,758       $ 10,829      $ 10,763
Leased Property, net                               154            176             182           181            174           194
Total Current Assets                               569          1,003             420           426            427           515
Total Deferred Debits and
        Other Assets                             6,715          6,683           3,899         3,944          3,992         3,905
                                            ----------     ----------       ---------     ---------       --------      -------- 
        Total Assets                        $   12,048     $   12,357       $  15,261     $  15,309       $ 15,422      $ 15,377
                                            ==========     ==========       =========     =========       ========      ======== 
Common Shareholders' Equity                 $    3,057     $    2,727       $   4,646     $   4,531       $  4,303      $  4,263
Preferred and Preference Stock
        Without Mandatory Redemption               137            137             199           199            277           423
        With Mandatory Redemption                   93             93              93            93             93           187
Company Obligated Mandatorily
        Redeemable Preferred
        Securities of a Partnership                349            352             302           302            221            --
Long-Term Debt                                   2,920          3,853           3,936         4,199          4,786         4,884
                                            ----------     ----------       ---------     ---------       --------      -------- 
        Total Capitalization                     6,556          7,162           9,176         9,324          9,680         9,757
Total Current Liabilities                        1,735          1,619           1,103         1,052            850           954
Total Deferred Credits and
        Other Liabilities                        3,757          3,576           4,982         4,933          4,892         4,666
                                            ----------     ----------       ---------     ---------       --------      -------- 
        Total Capitalization and
        Liabilities                         $   12,048     $   12,357       $  15,261     $  15,309  $      15,422  $     15,377
                                            ==========     ==========       =========     =========       ========      ======== 
</TABLE>

<PAGE>

Operating Statistics
<TABLE>
<CAPTION>

For the Years Ended December 31,                          1998         1997          1996         1995          1994         1993
----------------------------------------------------------------------------------------------------------------------------------
Electric Operations
Output (Millions of Kilowatthours)
<S>                                                      <C>           <C>          <C>          <C>           <C>          <C>   
Fossil                                                   10,262        9,659        10,856       10,792        11,239       10,352
Nuclear                                                  29,732       25,853        24,373       25,499        28,195       27,026
Hydro                                                     1,715        1,558         2,404        1,425         1,970        1,699
Pumped storage output                                     1,426        1,403         1,540        1,741         1,596        1,478
Pumped storage input                                     (1,853)      (1,924)       (2,230)      (2,507)       (2,256)      (2,192)
Purchase and interchange                                 34,075       29,615        19,539       13,945         6,164        6,447
Internal combustion                                         176          144           179          175           106           56
                                                     ----------   ----------   -----------  -----------   -----------   ----------
        Total electric output                            75,533       66,308        56,661       51,070        47,014       44,866
                                                     ==========   ==========   ===========  ===========   ===========   ==========
Sales (Millions of Kilowatthours)
Residential                                              10,623       10,407        10,671       10,636        10,859       10,609
Small commercial and industrial                           6,888        6,685         6,491        6,200         6,150        5,769
Large commercial and industrial                          15,678       15,034        15,208       15,763        15,968       15,956
Other                                                       803          841           902          860           791          771
Unbilled                                                    131           70          (327)         535          (205)          31
                                                     ----------   ----------   -----------  -----------   -----------   ----------
        Service territory                                34,123       33,037        32,945       33,994        33,563       33,136
Interchange sales                                         3,483        1,927           935          496           768          457
Sales to other utilities                                 37,258       28,893        20,243       14,041        10,039        8,670
                                                     ----------   ----------   -----------  -----------   -----------   ----------
        Total electric sales                             74,864       63,857        54,123       48,531        44,370       42,263
                                                     ==========   ==========   ===========  ===========   ===========   ==========
Number of Customers, December 31,
Residential                                           1,343,791    1,333,861     1,324,448    1,321,379     1,350,210    1,341,873
Small commercial and industrial                         145,055      144,142       142,431      141,653       143,605      142,363
Large commercial and industrial                           3,248        3,308         3,299        3,394         3,603        3,742
Other                                                     1,150        1,094         1,051          959           944          888
                                                     ----------   ----------   -----------  -----------   -----------   ----------
        Total electric customers                      1,493,244    1,482,405     1,471,229    1,467,385     1,498,362    1,488,866
                                                     ==========   ==========   ===========  ===========   ===========   ==========
Operating Revenues (Millions of Dollars)
Residential                                          $    1,377   $    1,357   $     1,370  $     1,379   $     1,371   $    1,351
Small commercial and industrial                             784          779           749          730           710          679
Large commercial and industrial                           1,067        1,077         1,098        1,135         1,149        1,168
Other                                                       150          148           140          137           136          161
Unbilled                                                      1           19           (26)          43           (11)          (1)
                                                     ----------   ----------   -----------  -----------   -----------   ----------
        Service territory                                 3,379        3,380         3,331        3,424         3,355        3,358
Interchange sales                                           211           59            26           17            23           14
Sales to other utilities                                  1,221          728           498          334           247          233
                                                     ----------   ----------   -----------  -----------   -----------   ----------
        Total electric revenues $                         4,811   $    4,167   $     3,855  $     3,775   $     3,625   $    3,605
                                                     ==========   ==========   ===========  ===========   ===========   ==========
Operating Expenses
Operating expenses, excluding
        depreciation and amortization                $    2,993   $    2,698   $     2,244  $     2,026   $     2,209   $    1,894
Depreciation and amortization                               611          553           462          431           416          401
                                                     ----------   ----------   -----------  -----------   -----------   ----------
        Total operating expenses                          3,604        3,251         2,706        2,457         2,625        2,295
                                                     ----------   ----------   -----------  -----------   -----------   ----------
Electric Operating Income                            $    1,207   $      916   $     1,149  $     1,318   $     1,000   $    1,310
                                                     ==========   ==========   ===========  ===========   ===========   ==========
Average Use per Residential Customer (Kilowatthours)
Without electric heating                                  6,948        6,695         6,771        6,908         6,736        6,727
With electric heating                                    15,398       16,400        17,946       17,189        17,527       17,096
All customers                                             7,935        7,830         8,074        8,130         8,041        7,970
Electric Peak Load, Demand
        (Thousands of Kilowatts)                          7,108        7,390         6,509        7,244         7,227        7,100
Net Electric Generating Capacity-
        Year-end Summer Rating
        (Thousands of Kilowatts)                          9,262        9,204         9,201        9,078         8,956        8,877
Cost of Fuel per Million BTU                         $     0.82   $     0.84   $      0.93  $      0.87   $      0.89   $     0.90
BTU per Net Kilowatthour Generated                       10,496       10,737        10,682       10,705        11,617       10,675
</TABLE>

<PAGE>

Notes to Consolidated Financial Statements
<TABLE>
<CAPTION>

Operating Statistics (continued)
For the Years Ended December 31,                1998            1997           1996           1995          1994          1993
--------------------------------------------------------------------------------------------------------------------------------
Gas Operations
Sales (Millions of Cubic Feet)
<S>                                              <C>            <C>            <C>            <C>           <C>            <C>  
Residential                                      1,496          1,614          1,681          1,516         1,636          1,637
House heating                                   28,402         32,666         35,471         30,698        32,246         30,242
Commercial and industrial                       16,757         19,830         20,999         18,464        19,762         18,635
Other                                              554            673          2,571          1,582         7,039          9,733
Unbilled                                          (440)           212         (1,306)         1,710          (474)           676
                                             ---------     ----------     ----------     ----------    ----------     ----------
        Total gas sales                         46,769         54,995         59,416         53,970        60,209         60,923
Gas transported for customers                   28,204         30,412         27,891         48,531        29,801         22,946
                                             ---------     ----------     ----------     ----------    ----------     ----------
        Total gas sales and
        gas transported                         74,973         85,407         87,307        102,501        90,010         83,869
                                             =========     ==========     ==========     ==========    ==========     ==========
Number of Customers
Residential                                     55,417         55,592         56,003         56,533        57,122         59,573
House heating                                  324,081        314,335        303,996        295,481       287,481        277,500
Commercial and industrial                       35,931         35,215         34,182         33,308        32,292         31,573
                                             ---------     ----------     ----------     ----------    ----------     ----------
        Total gas customers                    415,429        405,142        394,181        385,322       376,895        368,646
                                             =========     ==========     ==========     ==========    ==========     ==========
Operating Revenues (Millions of Dollars)
Residential                                  $      16      $      17      $      16      $      15     $      16      $      15
House heating                                      236            265            249            236           238            202
Commercial and industrial                          125            145            133            126           128            110
Other                                                2              3             11              5            20             28
Unbilled                                            (3)            (1)            (4)             7            (3)             5
                                             ---------     ----------     ----------     ----------    ----------     ----------
        Subtotal                                   376            429            405            389           399            360
Other revenues (including gas
        transported for customers)                  24             22             24             22            17             23
                                             ---------     ----------     ----------     ----------    ----------     ----------
        Total gas revenues                   $     400      $     451      $     429      $     411     $     416      $     383
                                             ---------     ----------     ----------     ----------    ----------     ----------
Operating Expenses
Operating expenses, excluding
        depreciation and amortization        $     291      $     333      $     302      $     302     $     326      $     279
Depreciation and amortization                       32             28             27             26            26             24
                                             ---------     ----------     ----------     ----------    ----------     ----------
        Total operating expenses                   323            361            329            328           352            303
                                             ---------     ----------     ----------     ----------    ----------     ----------
Gas Operating Income                         $      77      $      90      $     100      $      83     $      64      $      80
                                             =========     ==========     ==========     ==========    ==========     ==========
</TABLE>

Securities Statistics
Ratings on PECO Energy Company's securities
<TABLE>
<CAPTION>
                                                 Mortgage Bonds                      Preferred Stock
                                             --------------------------------------------------------------
                                                            Date                                   Date
Agency                                        Rating     Established              Rating        Established
------------------------------------------------------------------------------------------------------------
<S>                                            <C>        <C>                       <C>           <C>
Duff and Phelps, Inc.                           A-         10/98                    BBB           10/98
Fitch Investors Service, Inc.                   A-          9/92                    BBB+           9/92
Moody's Investors Service                       Baa1        4/92                    baa2           4/92
Standard & Poor's Corporation                   BBB+        4/92                    BBB-           2/99
</TABLE>

NYSE-Composite Common Stock Prices, Earnings and Dividends by Quarter (Per
Share)
<TABLE>
<CAPTION>
                                      1998                                     1997
                ------------------------------------------------------------------------------------------
                 Fourth     Third      Second       First      Fourth      Third      Second       First
                Quarter    Quarter     Quarter     Quarter     Quarter    Quarter     Quarter     Quarter
                ------------------------------------------------------------------------------------------
<S>             <C> <C>    <C> <C>    <C>  <C>    <C> <C>     <C>  <C>   <C>  <C>     <C> <C>    <C>   <C>
High price      $42-3/16   $36-3/4    $ 30-5/8    $24-11/16   $ 25-1/8   $ 24-5/16    $21-1/8    $  26-3/8
Low price       $ 36-1/2   $28-1/2    $21-3/16    $  18-7/8   $21-7/16   $  20-3/4    $18-3/4    $      20
Close           $ 41-3/4   $36-3/4    $29-3/16    $  22-1/8   $ 24-1/4   $ 23-7/16    $    21    $  20-3/8
Earnings        $  (0.13)  $  1.21    $   0.66    $    0.50   $  (8.51)  $    0.69    $  0.53    $    0.49
Dividends       $   0.25   $  0.25    $   0.25    $    0.25   $   0.45   $    0.45    $  0.45    $    0.45
</TABLE>

<PAGE>

50                                 PECO Energy Company and Subsidiary Companies

Board of Directors

Susan W. Catherwood (55)
Chairman, Trustee Board,
The University of Pennsylvania Medical Center and Health System

Daniel L. Cooper (63)
Former Vice President and General Manager, Nuclear Services Division
Gilbert/Commonwealth, Inc.

M. Walter D'Alessio (65)
President and Chief Executive Officer,
Legg Mason Real Estate Services 
(Commercial mortgage banking and pension
fund advisors)

G. Fred DiBona, Jr. (47)(1)
President and Chief Executive           
Officer,
Independence Blue Cross

R. Keith Elliott (56)
Chairman, Chief Executive Officer,
Hercules, Inc.

Richard H. Glanton (52)(1)
Partner of the law firm Reed Smith 
Shaw and McClay

Rosemarie B. Greco (52)(2)
Former President and
Chief Executive Officer,
Private Industry Council

Corbin A. McNeill, Jr. (59)(1)
Chairman of the Board
President and Chief Executive 
Officer of the Company

John M. Palms, PhD. (63)
President,
University of South Carolina

Joseph F. Paquette, Jr. (64)(1)
Former Chairman of the Board of 
Directors of the Company

Ronald Rubin (67)
Chief Executive Officer,
Pennsylvania Real Estate Investment Trust

Robert Subin (60)
Former Senior Vice President,
Campbell Soup Company
<PAGE>

Officers

Corbin A. McNeill, Jr. (59)
Chairman of the Board of Directors
President and Chief Executive Officer

Gerald R. Rainey (49)(9)
President and Chief Nuclear Officer,
PECO Nuclear

Nancy J. Bessey (45)(6)
President, Power Team

Gregory A. Cucchi (49)(10)
Senior Vice President,
Corporate and President,
PECO Energy Ventures

James W. Durham (61)
Senior Vice President
and General Counsel

Michael J. Egan (45)
Senior Vice President, Finance
and Chief Financial Officer

Kenneth G. Lawrence (51)(10)
Senior Vice President,
Corporate and President,
PECO Energy Distribution

William H. Smith, III (50)
Senior Vice President,
Business Services Group

David W. Woods (41)(14)
Senior Vice President,
Corporate and Public Affairs

John B. Cotton (53)(11)
Special Projects, PECO Nuclear

John Doering, Jr. (55)(4)
Vice President, Peach Bottom Atomic Power Station

Gregory P. Dudkin (41)(6)
Vice President, Operations,
PECO Energy Distribution

Drew B. Fetters (47)(10)
Vice President,
Nuclear Development,
PECO Nuclear

Jean H. Gibson (42)(8)
Vice President and Controller

Joseph J. Hagan (48)(16)
Senior Vice President,
Nuclear Operations,
PECO Nuclear

Paul E. Haviland (44)(5)
Vice President,
Corporate Development

Thomas P. Hill, Jr. (50)(7)
Vice President, Regulatory and
External Affairs, PECO Energy
Distribution

Christine A. Jacobs (46)(13)
Vice President, Support Services

Suzanne L. Keenan (34)(6)
Vice President, Customer & Marketing Services,
PECO Energy Distribution
<PAGE>

Cassandra A. Matthews (48)
Vice President, Information 
Technology and Chief Information Officer

John P. McElwain (48)(15)
Vice President,
Nuclear Projects, PECO Nuclear

J. Barry Mitchell (51)
Vice President, Treasury and
Evaluation, and Treasurer

James A. Muntz (41)(16)
Vice President, Fossil Operations

James D. von Suskil (52)(3)
Vice President,
Limerick Generating Station,
PECO Nuclear

Richard G. White (40)(12)
Vice President, Corporate Planning

Katherine K. Combs (48)
Corporate Secretary

Edward J. Cullen, Jr. (51)
Assistant Corporate Secretary

Todd D. Cutler (38)
Assistant Corporate Secretary

Diana Moy Kelly (44)
Assistant Treasurer

George R. Shicora (52)
Assistant Treasurer and
Cash Manager

(1)     Member of the Executive 
        Committee of the Board of 
        Directors
(2)     Elected February 23, 1998
(3)     Effective January 26, 1998
(4)     Effective March 2, 1998
(5)     Effective March 4, 1998
(6)     Effective April 8, 1998
(7)     Effective April 9, 1998
(8)     Effective May 31, 1998
(9)     Effective June 1, 1998
(10)    Effective June 22, 1998
(11)    Effective August 14, 1998
(12)    Effective September 28, 1998
(13)    Effective November 9, 1998
(14)    Effective December 1, 1998
(15)    Effective January 6, 1999, no
        longer an officer of  PECO Energy
(16)    Effective January 26, 1999

<PAGE>

Stock Exchange Listings
Most Company securities are listed on the New York Stock Exchange and the
Philadelphia Stock Exchange under PE.

Dividends
The Company has paid dividends on its common stock continually since 1902.
The Board of Directors normally considers common stock dividends for
payment in March, June, September and December. The Company expects that
the $1.00 per share dividend paid to common shareholders in 1998 is fully
taxable as dividend income for federal income tax purposes.

Shareholders may use their dividends to purchase additional shares of
common stock through the Company's Dividend Reinvestment and Stock Purchase
Plan (Plan). The Company pays all brokerage and service fees for Plan
purchases. All shareholders have the opportunity to invest additional funds
in common stock of the Company, whether or not they have their dividends
reinvested, with all purchasing fees paid by the Company.

In 1998, over 57 percent of the Company's common shareholders were
participants in the Plan. Information concerning the Plan may be obtained
from: EquiServe, PECO Energy Company Plan, P.O. Box 2598, Jersey City, NJ
07303-2598.

Comments Welcomed
The Company is always pleased to answer questions and provide information.
Please address your comments to Katherine K. Combs, Corporate Secretary,
PECO Energy Company, 2301 Market Street, P.O. Box 8699, Philadelphia, PA
19101-8699.

Inquiries relating to shareholder accounting records, stock transfer and
change of address should be directed to: EquiServe, P.O. Box 2500, Jersey
City, NJ 07303-2500.

Toll-Free Telephone Lines
Toll-free telephone lines are available to the Company's shareholders for
inquiries concerning their stock ownership. Calls should be directed to
1-800-626-8729.

For current Company news call 1-888-340-7326
<PAGE>

Shareholder Information

Annual Meeting
The Annual Meeting of the Shareholders of the Company will be held at the
Sunnybrook Ballroom and Conference Center in Pottstown, Pennsylvania on
April 27, 1999, at 9:30 AM. The record date for voting at the shareholders'
meeting is March 5, 1999. Prompt return of proxies will be appreciated.

To vote your proxy over the internet visit
http://www.vote-by-net.com

To receive future Annual Reports and proxy statements
electronically, sign-up at:
http://www.vote-by-net.com/signup/peco

Form 10-K
Form 10-K, the annual report filed with the Securities and Exchange
Commission, is available without charge to shareholders by calling
1-888-340-7326 or by obtaining a copy from our internet site
http://www/peco.com/investor.

Shareholders
The Company had 142,794 shareholders of record of
common stock as of December 31, 1998.

Transfer Agents and Registrars
Preferred and Common Stock Registrar and Transfer Agent: First Chicago
Trust, Division of EquiServe, (1-800-626-8729)
P.O. Box 2500, Jersey City, NJ 07303-2500

First and Refunding Mortgage Bond Trustee:
First Union National Bank, (1-800-665-9343)
Corporate Trust Operations Customer Information Center
Redemption Bldg 3C3
1525 West W.T. Harris Blvd.Charlotte, NC 28288-1153

Internet Site
Visit our internet site at http://www.peco.com

General Office
2301 Market Street
Philadelphia, Pennsylvania 19103
(215) 841-4000