Exhibit 13




Financial Information
---------------------
Potomac Electric Power Company and Subsidiary 

Contents 
--------

Management's Discussion and Analysis of
  Consolidated Results of Operations and
  Financial Condition......................................   2
Report of Independent Accountants..........................  28 
Consolidated Statements of Earnings........................  29 
Consolidated Balance Sheets................................  30 
Consolidated Statements of Cash Flows......................  32 
Notes to Consolidated Financial Statements.................  33 
Selected Consolidated Financial Data.......................  72 
Explanation of Graphic Material..................... Appendix A




                                1




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

PROPOSED MERGER UPDATE
----------------------

Shareholders of Potomac Electric Power Company (the Company,
PEPCO) and Baltimore Gas and Electric Company (BGE), at separate
special meetings during March 1996, approved a proposed merger
(the Merger) to form Constellation Energy Corporation
(Constellation Energy).  The Company and BGE filed a joint
Application for Authorization and Approval of the Merger with the
Federal Energy Regulatory Commission (FERC) on January 11, 1996,
and with the Maryland and District of Columbia Public Service
Commissions on April 8, 1996.  On July 31, 1996, FERC set the
application for hearing on the issue of whether the Merger would
impact competition.  Hearings began on October 21, 1996, and the
Administrative Law Judge certified the record to the Commission
on October 25, 1996.  The case was placed before FERC for
decision in December 1996.  The Maryland Commission conducted
hearings during June, September and December 1996.  The case was
placed before the Maryland Commission for decision in January
1997.  A prehearing conference was conducted by the District of
Columbia Commission in May 1996 and a procedural schedule was
published in July 1996.  The hearings, which were originally
scheduled to take place in December 1996, have been rescheduled
for February 1997.  The case is expected to be before the
District of Columbia Commission for decision in March 1997.  The
Nuclear Regulatory Commission has approved the transfer of BGE's
ownership interest in the operating licenses for the two
generating units at the Calvert Cliffs Nuclear Power Plant to
Constellation Energy at the effective time of the Merger.  In
addition, the State Corporation Commission of Virginia has
approved the Merger.  The Merger also requires approval from the
Pennsylvania Public Utility Commission.  Completion of the
approval process is expected to take until the end of the first
quarter of 1997.

     The combination of the Company and BGE will create a larger,
stronger company better able to maintain the low costs which will
be essential to compete effectively in the future, and better
able to contribute to economic and job development in the area. 
The Merger will result in lower operating costs than either
company could produce alone.  Over the first 10 years following
the Merger, Constellation Energy expects to achieve net merger-
related savings of $1.3 billion.  The allocation of the net
savings between customers and shareholders of Constellation
Energy will be determined in regulatory proceedings.  The
applications set forth the proposed plans for Constellation
Energy to share the benefits of the Merger with customers in the
District of Columbia and Maryland.  The proposal includes:  1) a
freeze on base electric rates until at least January 1, 2000, 2)


                                2


a unique bill credit for all customers if Constellation Energy
achieves certain financial targets, 3) an array of economic
development incentives and 4) programs to address the energy
needs of low-income customers.  At December 31, 1996, the Company
has deferred $29 million in costs related to the Merger.

See the Notes to Consolidated Financial Statements, (13)
Commitments and Contingencies, for additional information.

GENERAL
-------

As an investor-owned electric utility, the Company is capital
intensive, with a gross investment in property and plant of
approximately $3 for each $1 of annual total revenue.  The costs
associated with property and plant investment amounted to 47% of
the Company's total revenue in 1996.  Fuel and purchased energy,
capacity purchase payments and other operating expenses were 53%
of total revenue.  The Company's wholly owned subsidiary, Potomac
Capital Investment Corporation (PCI), conducts nonutility
investment programs with the objective of supplementing current
utility earnings and building long-term shareholder value.

     The information set forth below discusses the results of
operations, capital resources and liquidity during the period
1994 through 1996 for the Company and PCI.

     The Company's earnings for common stock during 1996 totaled
$220.4 million, as compared to $77.5 million in 1995.  As set
forth below, utility earnings per share increased from $1.70 in
1995 to $1.72 in 1996 and consolidated earnings increased from
$.65 to $1.86 in 1996.  The 1995 nonutility subsidiary results
reflect noncash, nonrecurring charges of $1.04 related to PCI's
May 1995 plan with respect to the aircraft leasing business. 

-----------------------------------------------------------------
                              1996        1995         1994
-----------------------------------------------------------------

Utility Operations           $1.72       $1.70        $1.63
Nonutility Subsidiary          .14       (1.05)         .16
                             -----       -----        -----      
Consolidated                 $1.86       $ .65        $1.79
                             =====       =====        =====
-----------------------------------------------------------------
 
The average number of common shares outstanding at December 31,
1996, was relatively unchanged from December 31, 1995.


                                3
UTILITY
-------

RESULTS OF OPERATIONS
---------------------

Total Revenue
-------------

The changes in total revenue are shown in the following table.

-----------------------------------------------------------------
                                         Increase (Decrease)
                                           from Prior Year
                                       1996      1995      1994
-----------------------------------------------------------------
                                        (Millions of Dollars)

Change in kilowatt-hour sales        $(11.5)   $ 27.2    $(18.7)
Change in base rate revenue            27.0      42.8      32.2
Change in fuel adjustment clause
   billings to cover cost of
   fuel and interchange and
   capacity purchase payments          (4.5)    (39.3)     73.2
Change in other revenue                 1.4       1.1       1.5
                                     ------    ------    ------  
   Change in Operating Revenue         12.4      31.8      88.2
                                     ------    ------    ------
Change in interchange deliveries      121.8      21.2       9.7
                                     ------    ------    ------
   Change in Total Revenue           $134.2    $ 53.0    $ 97.9
                                     ======    ======    ======
-----------------------------------------------------------------

     The $27 million change in 1996 base rate revenue compared to
1995 reflects the continued effects of a 1995 $27.9 million rate
increase in the District of Columbia (effective in July 1995) and
an increase of $17.7 million associated with the Company's Demand
Side Management (DSM) surcharge in Maryland, which includes a $.2
million increase in the conservation incentive provision of the
tariff for achieving specified 1995 Maryland energy goals.
 
     The increase in base rate revenue in 1995 as compared to
1994 reflects the effects of a District of Columbia rate increase
of $27.9 million and the continued effect of a 1994 rate increase
in the District of Columbia.  In addition, 1995 base rate revenue
reflects an increase of $28 million associated with the Company's
DSM surcharge in Maryland, which includes a $3.7 million increase
in the conservation incentive provision of the tariff for
achieving specified 1994 Maryland energy goals.



                                4


     The increase in base rate revenue in 1994 as compared to
1993 reflects the effect of a District of Columbia rate increase
of $26.7 million (effective primarily in March 1994) and the
continued effect of 1993 rate increases in Maryland.  In
addition, 1994 base rate revenue reflects $5 million associated
with the conservation incentive provision of the DSM surcharge
tariff for achieving specified 1993 Maryland energy goals.

     Increases in 1996 and 1995 revenue from interchange
deliveries reflect the growth in the number of companies involved
in power sales tariff interchange transactions, predominantly
where the Company buys energy from one party for the purpose of
selling that energy to a third party.  Interchange deliveries in
1996, 1995 and 1994 also reflect changes in levels and pricing of
energy delivered to the Pennsylvania-New Jersey-Maryland
Interconnection Association (PJM).  The benefits derived from
interchange deliveries are passed through to the Company's
customers through a fuel adjustment clause. 



                                5


Kilowatt-hour Sales
-------------------
-----------------------------------------------------------------
                                                   1996    1995
                                                    vs.     vs. 
                          1996     1995     1994   1995    1994
-----------------------------------------------------------------
                      (Millions of Kilowatt-hours)

By Customer Type
  Residential            6,869    6,707    6,574    2.4%    2.0%
  Commercial            11,712   11,861   11,685   (1.3)    1.5
  U.S. Government        3,902    3,998    4,010   (2.4)    (.3)
  D.C. Government          847      879      914   (3.6)   (3.8)
  Wholesale              2,570    2,465    2,363    4.3     4.3
                        ------   ------   ------   
    Total energy sales  25,900   25,910   25,546      -     1.4
                        ======   ======   ======

Interchange
  Energy deliveries      7,063    1,784      800      -       -
                        ======   ======   ====== 

By Geographic Area
  Maryland, including
    wholesale           15,763   15,594   15,251    1.1     2.2
  District of Columbia  10,137   10,316   10,295   (1.7)     .2
                        ------   ------   ------
    Total energy sales  25,900   25,910   25,546      -     1.4
                        ======   ======   ======
-----------------------------------------------------------------

     Kilowatt-hour sales in 1996 remained relatively unchanged
from 1995.  Kilowatt-hour sales were affected by a .6% increase
in the average number of customers and increased usage of
electricity during the blizzard-like conditions in the first
quarter of 1996, which brought a record amount of snowfall to the
Washington, D.C. area, and were partially offset by decreased
usage of electricity during the summer months due to the cooler
than average summer weather of 1996.  Cooling degree hours were
19% and 17% below the 1995 and 20-year average, respectively. 
Kilowatt-hour sales increased 1.4% in 1995 resulting in part from
a 1% increase in customers.  Cooling degree hours in 1995
remained relatively stable as compared to 1994.  Assuming future
weather conditions approximate historical averages, the Company
expects its compound annual growth in kilowatt-hour sales to
range between 1% and 2% over the next decade.



                                6


     The 1996 summer peak demand of 5,288 megawatts occurred on
June 17, 1996.  This compares with the 1995 summer peak demand of
5,732 megawatts, and the all-time summer peak demand of 5,769
megawatts which occurred in July 1991.  The Company's present
generation capability, including capacity purchase contracts, is
6,716 megawatts.  In addition, the Company had approximately 265
megawatts available from its dispatchable energy use management
programs to meet the 1996 summer peak demand.  Based on average
weather conditions, the Company estimates that its peak demand
will grow at a compound annual rate of approximately 1.5%.  The
1995-1996 winter season peak demand of 4,831 megawatts was 3.6%
below the all-time winter peak demand of 5,010 megawatts which
was established in January 1994.

Operating Expenses
------------------

Fuel, Purchased Energy and Capacity Purchase Payments

-----------------------------------------------------------------
                                1996         1995         1994
-----------------------------------------------------------------
                                   (Millions of Dollars)

Fuel expense                  $327.8       $355.4       $392.7
                              ------       ------       ------
Purchased energy
  PJM receipts                 114.6         79.4        108.8
  Other purchases              221.4        114.2         64.6
                              ------       ------       ------
    Total purchased energy     336.0        193.6        173.4
                              ------       ------       ------
  Fuel and purchased energy   $663.8       $549.0       $566.1
                              ======       ======       ======
Capacity purchase payments    $125.8       $125.8       $127.8
                              ======       ======       ======
-----------------------------------------------------------------

Net System Generation and Purchased Energy were as follows.
 
-----------------------------------------------------------------
                                1996         1995         1994
-----------------------------------------------------------------
                                (Millions of Kilowatt-hours)

Net system generation         18,041       19,234       19,320
                              ======       ======       ======

Purchased energy              16,157        9,755        8,356
                              ======       ======       ======
-----------------------------------------------------------------


                                7


     The 1996 decrease in fuel expense reflects a decrease of
6.2% in net generation, partially offset by an increase in the
system average fuel cost summarized below.  The 1995 decrease in
fuel expense reflects the decrease in the system average fuel
cost summarized below and a .4% decrease in net generation.  The
relatively high 1994 fuel expense reflects increased generation
and use of major cycling and peaking generation units which burn
higher cost fuels, especially during January 1994 when severe
cold weather sent demand for electricity to a new winter peak.

     The Company's unit costs of fuel burned and the percentages
of system fuel requirements obtained from coal, oil and natural
gas were as shown in the following table.

-----------------------------------------------------------------
              Percent of                    Unit Cost
             Fuel Burned                 of Fuel Burned         
         -------------------     --------------------------------
                                                          System
         Coal     Oil    Gas     Coal     Oil     Gas     Average
-----------------------------------------------------------------
                                        (Per Million Btu)
1996     89.7     6.9    3.4    $1.62    $3.55    $2.92    $1.80
1995     85.4     6.1    8.5     1.60     3.22     2.10     1.74
1994     76.1    18.4    5.5     1.73     2.70     2.49     1.95
-----------------------------------------------------------------

     The 1996 system average unit fuel cost increased by
approximately 3% which was primarily the result of the increase
in the cost of residual oil and an increase in the percent of
residual oil contribution to the fuel mix.  The decrease of
approximately 11% in the 1995 system average unit fuel cost
compared with the 1994 system average resulted from increased use
of lower-cost coal and gas and decreased net generation.  The
Company's major cycling and certain peaking units can burn either
natural gas or oil, adding flexibility in selecting the most
cost-effective fuel mix.  The decrease in the percent of gas
burned in 1996 reflects the increased price of gas and the
increased usage of lower-cost coal.  The increase in the percent
of gas burned in 1995 reflects the decreased price of gas and the
increased price of oil.  

     The Company's generating and transmission facilities are
interconnected with those of other members of the PJM power pool
and other utilities.  The pricing of PJM-dispatched internal
economy energy transactions is currently based upon "split
savings" whereby such energy is priced halfway between the cost
that the purchaser would incur if the energy were supplied by its
own sources and the cost of production to the company actually
supplying the energy (See Restructuring of the Bulk Power Market
discussion below).


                                8


     In addition to interchange with PJM, the Company is actively
participating in the emerging bilateral energy sales marketplace. 
The Company's wholesale power sales tariff allows both sales from
Company-owned generation and sales of energy purchased by the
Company from other market participants.  Over 40 utilities and
marketers have executed service agreements allowing them to
arrange purchases under this tariff.  The Company has also
executed service agreements allowing it to purchase energy under
other market participants' power sales tariffs.  These agreements
greatly expand the opportunities for economic transactions. 
During 1996, the Company entered into purchases, sales and
purchase-for-resale agreements producing approximately $11
million in savings that are passed along to customers.

     Throughout 1996, the Company purchased energy from Ohio
Edison under the Company's 1987 long-term capacity purchase
agreements with Ohio Edison and Allegheny Power System (APS), and
from the Northeast Maryland Waste Disposal Authority under an
avoided cost-based purchase agreement for a 32-megawatt
Montgomery County Resource Recovery Facility.  Pursuant to the
Company's long-term capacity purchase agreements with Ohio Edison
and APS, the Company is purchasing 450 megawatts of capacity and
associated energy through the year 2005.  Capacity payments for
the Montgomery County Resource Recovery facility are not expected
to commence until after the year 2000.  In August 1996, the
Company began purchasing energy from the Panda Brandywine L.P.
(Panda) facility, pursuant to a 25-year power purchase agreement
for 230 megawatts of capacity supplied by a gas-fueled combined-
cycle cogenerator.  The Panda facility achieved full commercial
operation in October 1996.  Capacity payments under this
agreement commence in January 1997.  The capacity expense under
these agreements, including an allocation of a portion of Ohio
Edison's fixed operating and maintenance costs, totaled $120
million in 1996.  Commitments under these agreements are
estimated at $141 million in 1997, $139 million in 1998, $200
million in 1999 and 2000 and $211 million in 2001.

     The Company has a purchase agreement with Southern Maryland
Electric Cooperative, Inc. (SMECO), through 2015, for 84
megawatts of capacity supplied by a combustion turbine installed
and owned by SMECO at the Company's Chalk Point Generating
Station.  The Company is responsible for all costs associated
with operating and maintaining the facility.  The capacity
payment to SMECO is approximately $5.5 million per year.  


                                9


     In January 1996, the Company filed an open access
transmission tariff with the FERC, which was amended in July
1996, in compliance with FERC's Order No. 888.  The service
agreement under this tariff has been signed by a number of
utilities and power marketers throughout the country, and these
entities are now eligible to purchase transmission service from
the Company.  This tariff would be suspended by the proposed PJM
poolwide transmission tariff.

     The Company began selling capacity to GPU, Inc. in October
1996 in the amount of 100 megawatts during both October and
November 1996 and 90 megawatts for December 1996.  Capacity sales
are expected to continue during 1997.

     As electricity becomes more actively traded as a commodity,
the bulk power market is developing methods for traders to hedge
against price volatility.  New York Mercantile Exchange (NYMEX)
futures contracts for electricity began trading in 1996 for
delivery at the California-Oregon border and at Palo Verde
Substation in Arizona.  The NYMEX predicts that an east coast
contract will be introduced in 1997 which will have greater
relevance to transactions in the mid-Atlantic marketplace.  In
addition, some market participants are using customized
instruments to hedge prices for both capacity and energy.  Such
instruments include forward contracts to fix prices, options to
set ceilings or floors on prices and contracts-for-differences to
exchange variable prices for a fixed price.  The proposed mid-
Atlantic energy market is expected to feature a secondary market
in transmission congestion hedging.  In the future, the Company
expects to participate in the hedging markets as part of its
strategy to control costs and avoid unreasonable risks.  In some
instances, as part of its overall bulk power marketing activity,
the Company may offer to sell hedging instruments.  
     
Other Operation and Maintenance Expenses
----------------------------------------

Other operation and maintenance expenses totaled $314.9 million
for 1996.  These expenses decreased by $2 million (.6%) in 1996,
including the $1.8 million and $.9 million paid on January 5,
1996, and June 7, 1996, respectively, to union members as part of
the 1995 Labor Agreement between the Company and Local 1900 of
the International Brotherhood of Electrical Workers.  These
expenses increased by $18.2 million (6.1%) in 1995, including
$15.2 million related to the December 1994 sale and leaseback of
the Company's control center system, and decreased by $2.8
million (.9%) in 1994.  The Company's budget and cost control
disciplines have resulted in a 13% decline in the number of
Company employees since 1993.  In addition, utility operating
results were affected by a nonrecurring charge of $7.4 million in
January 1995 for one-time operating costs associated with the  


                                10       


Company's successful Voluntary Severance Program, which has
provided annual savings in operating and construction costs of
approximately $15 million.  Bad debt expense, as a percent of
revenue was .4% in 1996, 1995 and 1994.  At December 31, 1996,
accounts receivable included $12.4 million, or 5.2% of
outstanding receivables, due from agencies of the District of
Columbia for electric service and maintenance, of which $7
million, or 2.9% of outstanding receivables, was in arrears.  As
of January 29, 1997, the District of Columbia accounts receivable
balance had been reduced to $8.2 million due to receipt of
additional payments.  The Company believes that amounts owed by
the District of Columbia will be paid and, accordingly, has not
established a bad debt reserve for this receivable balance.

Depreciation and Amortization Expense, Income Taxes and
Other Taxes
-------------------------------------------------------

Depreciation and amortization expense increased by $17.5 million
(8.5%), $25.5 million (14.2%) and $16.4 million (10%) in 1996,
1995 and 1994, respectively, due to additional investment in
property and plant and amortization of increased amounts of
conservation costs associated with the Company's DSM program. 
The increase in income taxes in 1996, 1995 and 1994, reflects
higher taxable operating income.  Other taxes decreased by $2.3
million (1.2%) and $3.4 million (1.6%) in 1996 and 1995,
respectively, and increased by $4.8 million (2.4%) in 1994.  The
decreases in 1996 and 1995 reflect the reduction in county fuel-
energy tax rates.  The increase in 1994 reflects changes in the
levels of operating revenue and plant investment upon which taxes
are based.

Other Income, Allowance for Funds Used During Construction and
Capital Cost Recovery Factor, and Utility Interest Charges
--------------------------------------------------------------

Other income reflects net earnings (loss) from PCI of $16.9
million in 1996, $(124.4) million in 1995 and $19.1 million in
1994.  See the Nonutility Subsidiary discussion below and the
discussion included in Note (15) of the Notes to Consolidated
Financial Statements, Selected Nonutility Subsidiary Financial
Information.  Other income also reflects credits for the equity
components of the Allowance for Funds Used During Construction
(AFUDC) accrued on the Company's Construction Work In Progress
expenditures not in rate base and the Capital Cost Recovery
Factor (CCRF) accrued on certain pollution control expenditures
related to Clean Air Act compliance.  AFUDC equity totaled $1.4
million in 1996, $1.5 million in 1995 and $9.1 million in 1994;
CCRF equity credits totaled $5.2 million in 1996, $4.7 million in
1995 and $3.5 million in 1994.  In addition, other income
includes, in "Other, net", CCRF accruals on unamortized District
of Columbia DSM costs not in rate base, totaling $8.8 million in 


                                11    


1996, $4.8 million in 1995 and $4.1 million in 1994.  "Other,
net" in 1994 also reflects a total after-tax reduction of
approximately $4.1 million associated with District of Columbia
Public Service Commission decisions.  These include disallowance
of rate case test period DSM program expenditures, adoption of an
unbilled revenue adjustment applicable to the District of
Columbia portion of the 1992 accounting change related to
unbilled revenue and adoption of a three-year phase-in period to
reflect increased postretirement benefit costs.

     Utility interest charges were relatively stable during the
three-year period 1994 through 1996, notwithstanding changes in
the levels of borrowing.  Short-term borrowing costs have
remained relatively low and, with the refinancing of higher cost
issues, the average cost of outstanding long-term utility debt
declined from 7.68% at the beginning of 1994 to 7.48% at the end
of 1996.  Utility interest charges were offset by both the debt
component of AFUDC which totaled $3.9 million in 1996, $7.5
million in 1995 and $9.6 million in 1994; and by the debt
component of Clean Air Act CCRF which totaled $3.6 million in
1996, $3.3 million in 1995 and $2.5 million in 1994.  Total AFUDC
decreased by $9.7 million in 1995, primarily due to the control
center system which came on-line in December 1994.

CAPITAL RESOURCES AND LIQUIDITY
-------------------------------

The Company's total investment in property and plant, at original
cost, was $6.3 billion at year-end 1996.  Investment in property
and plant construction, net of AFUDC and CCRF, was $685.9 million
for the period 1994 through 1996.  

     Internally generated cash from utility operations, after
dividends, totaled $386.4 million for the period 1994 through
1996.  Sales of First Mortgage Bonds, Medium-Term Notes and
Common Stock during the period 1994 through 1996 provided a total
of $605 million.  During the years 1994 through 1996, the Company
retired $292.3 million in outstanding long-term securities,
including refinancings, scheduled debt maturities and sinking
fund retirements.  Interim financing was provided principally
through the issuance of short-term commercial promissory notes. 
During the three-year period 1997 through 1999, capital resources
of $250.4 million ($152.4 million in 1997) will be required to
meet scheduled debt maturities and sinking fund requirements, and
additional amounts will be required for working capital and other
needs.  Approximately $825 million is expected to be available
from depreciation and amortization charges and income tax
deferrals over the three-year period of which approximately $275
million is the 1997 portion.



                                12


     In December 1996, the Company sold $100 million principal
amount of Medium-Term Notes.  Proceeds were applied to reduce
short-term debt and to fund ongoing construction and operating
activities.  See the discussion included in Notes (7) and (10) of
the Notes to Consolidated Financial Statements, Common Equity and
Long-Term Debt, respectively, for additional information. 

     Total annualized interest costs for all utility long-term
debt outstanding at December 31, 1996, was $133 million, compared
with $127.9 million and $123.7 million at December 31, 1995 and
1994, respectively.  

     The Company entered into a sale (at cost) and leaseback
agreement for its new control center system (system) in December
1994.  The system is an integrated energy management system used
by the Company's power dispatchers to centrally control the
operation of the Company's electric system, which consists of all
of its generating units, the transmission system and the
distribution system.  The Company has accounted for the lease of
the system as a capital lease, recorded at the present value of
future lease payments which totaled $152 million.  This lease has
been treated as an operating lease for ratemaking purposes.  

     Dividends on preferred stock were $16.6 million in 1996,
$16.9 million in 1995 and $16.4 million in 1994.  The embedded
cost of preferred stock was 6.41% at December 31, 1996, 6.43% at
December 31, 1995, and 6.53% at December 31, 1994.

     The Company's capitalization ratios (excluding nonutility    
subsidiary debt), at December 31, 1996, are presented below.

-----------------------------------------------------------------
                                    Excluding      Including
                                   Amounts Due    Amounts Due
                                   In One Year    In One Year
-----------------------------------------------------------------
Long-term debt                        45.1%          42.0%
Redeemable serial preferred stock      3.6            3.4
Serial preferred stock                 3.2            3.0
Common equity                         48.1           44.9
Short-term debt and amounts due in 
  one year                               -            6.7 
                                     -----          -----
  Total capitalization               100.0%         100.0%
                                     =====          =====
-----------------------------------------------------------------


                                13



     Year-end 1996 outstanding utility short-term indebtedness
totaled $131.4 million compared with $258.5 million and $189.6
million at the end of 1995 and 1994, respectively.  

     The Company maintains 100% line of credit back-up for its
outstanding commercial promissory notes, which was unused during
1996, 1995 and 1994. 

Conservation
------------

The Company's demand side management (DSM) and energy use
management (EUM) programs are designed to curb growth in demand
in order to defer the need for construction of additional
generating capacity and to cost-effectively increase the
efficiency of energy use.  To reduce the near-term upward
pressure on customer rates and bills, the Company has, since
1994, phased out several conservation programs and reduced rebate
levels for others.  By narrowing its conservation offerings and
limiting conservation spending, the Company expects to continue
to encourage its customers to use energy efficiently without
significantly increasing electricity prices.  In a June 1995
order, the Public Service Commission of the District of Columbia
adopted a DSM spending cap for the four-year period 1995 through
1998.  The Company continues to manage its existing portfolio of
DSM programs to ensure that the costs of these programs do not
exceed the spending limit.  In December 1996, the Company
announced the suspension of the New Building Design Program in
the District of Columbia because current commitments for rebates
are projected to reach the spending limit for commercial
programs.  In addition, the Company has not accepted new
applications in the Custom Rebate Program since its suspension in
November 1994.  Remaining allowable expenditures under the DSM
spending cap totaled $15 million at December 31, 1996.  The
Company expects to realize approximately 80% of the previously
estimated benefits from its demand side management programs for
approximately 45% of the previously estimated costs.

     During 1996, the Company invested approximately $27 million
in Maryland DSM programs.  The Company recovers the costs of
Maryland DSM programs through a base rate surcharge which
amortizes costs over a five-year period and permits the Company
to earn a return on its DSM investment while receiving
compensation for lost revenue.  In addition, when energy savings
exceed annual goals, the Company earns a bonus.  The Company was
awarded a bonus of $8.9 million in 1996, based on 1995
performance, which followed bonuses of $8.7 million in 1995,
based on 1994 performance and $5 million in 1994, based on 1993
performance.  Maryland DSM program goals for 1996 have been
reduced to reflect lower DSM expenditures.  Consequently, the
performance bonus in 1997 is expected to be significantly lower
than amounts awarded for performance in prior years.


                                14


     Investment in District of Columbia DSM programs totaled
approximately $18 million in 1996.  These DSM costs are amortized
over 10 years with an accrued return on unamortized costs.  In
June 1995, the Commission adopted a base rate surcharge for the
recovery of actual DSM costs prudently incurred since June 30,
1993; prior to this decision, DSM costs had been considered in
base rate cases.  This surcharge includes both a conservation
expenditure component and a component for recovering certain
expenditures associated with complying with the Clean Air Act
Amendments of 1990.  The conservation component is updated
annually in the spring of each year, while the Clean Air Act
component is updated quarterly.  On June 3, 1996, the Company
filed an application with the District of Columbia Public Service
Commission requesting approval for an updated conservation
component to reflect the recoverable DSM costs expended during
1995.  The proposed rate is expected to increase annual revenue
by approximately $8 million.  No action has been taken by the
District of Columbia Public Service Commission on the proposed
surcharge rate.  

     In 1996, approximately 160,000 customers participated in
continuing EUM programs which cycle air conditioners and water
heaters during peak periods.  In addition, the Company operates a
commercial load program which provides incentives to customers
for reducing energy use during peak periods.  Time-of-use rates
have been in effect since the early 1980s and currently
approximately 60% of the Company's revenue is derived from time-
of-use rates.

     It is estimated that peak load reductions of nearly 700
megawatts have been achieved to date from DSM and EUM programs
and that additional peak load reductions of approximately 400
megawatts will be achieved in the next five years.  The Company
also estimates that, in 1996, energy savings of more than 1.6
billion kilowatt-hours have been realized through operation of
its DSM and EUM programs.  During the next five years, the
Company's projected costs for conservation programs that
encourage the efficient use of electric energy and reduce the
need to build new generating facilities total $330 million ($55
million in 1997).

Construction and Generating Capacity 
------------------------------------

Construction expenditures, excluding AFUDC and CCRF, are
projected to total $1.2 billion for the five-year period 1997
through 2001, which includes $18 million of estimated Clean Air
Act expenditures.  In 1997, construction expenditures are
projected to total $215 million, which includes $4 million of
estimated Clean Air Act expenditures.  The Company plans to
finance its construction program primarily through funds provided
by operations.  Actual construction expenditures during the  


                                15


period 1997 through 2001 may vary from projections once the
Merger with BGE becomes effective.

     A 32-megawatt municipally financed resource recovery
facility in Montgomery County, Maryland, began commercial
operation in August 1995.  The Company has been purchasing energy
under the agreement covering this project without capacity
payment obligations, which are not expected to commence until
after the year 2000.  In addition, the Company has a 25-year
agreement with Panda for a 230-megawatt gas-fueled combined-cycle
cogeneration project in Prince George's County, Maryland.  The
project has been completed and the Panda facility achieved full
commercial operation in October 1996.  The Company projects that
existing contracts for nonutility generation and the Company's
commitment to conservation will provide adequate reserve margins
to meet customers' needs well beyond the year 2000.  In 1995, the
Maryland Public Service Commission issued an order that requires
electric utilities to competitively procure future capacity
resources.  The Company believes that completion of the first
combined-cycle unit at its Station H facility in Dickerson,
Maryland, currently scheduled for 2004, is likely to be the most
cost-effective alternative for the next increment of capacity. 
This will add a steam cycle to the two existing combustion
turbine units.

CLEAN AIR ACT
-------------

The Company has implemented cost-effective plans for complying
with Phase I of the Acid Rain portion of the Clean Air Act (CAA)
which requires the reduction of sulfur dioxide and nitrogen
oxides emissions to achieve prescribed standards.  Boiler burner
equipment for nitrogen oxides emissions control has been
installed and the use of lower-sulfur coal has been instituted at
the Company's Phase I affected stations, Chalk Point and
Morgantown.  Anticipated capital expenditures for complying with
the second phase of the CAA total $18 million over the next five
years.   Plans for complying with the second phase of the CAA are
being reviewed in anticipation of the pending Merger with BGE. 
If economical, continued use of lower-sulfur coal, cofiring with
natural gas and the purchase of sulfur dioxide (SO2) emission
allowances is expected.  Nitrogen oxides emissions reductions
will be achieved by installing control equipment in the most
cost-effective manner after considering the characteristics of
each of the merged company's boilers.  In addition to the Acid
Rain portion of the CAA, the State of Maryland and District of
Columbia are required, by Title I of the CAA, to achieve
compliance with ambient air quality standards for ground-level
ozone.  This provision is likely to result in further nitrogen
oxides emissions reductions from the Company's boilers; however,
the extent of reductions and associated cost cannot be estimated
at this time.


                                16


     The Company owns a 9.72% undivided interest in the Conemaugh
Generating Station located in western Pennsylvania.  Nitrogen
oxides emissions reduction equipment and flue gas desulfurization
equipment have been installed at the station for compliance with
Phase I of the CAA.  The Company's share of construction costs
for this equipment was $36.2 million.  As a result of installing
the flue gas desulfurization equipment, the station has received
additional SO2 emission allowances.  The Company's share of these
bonus allowances will be used to reduce the need for lower-sulfur
fuel at its other plants.

BASE RATE PROCEEDINGS
---------------------

The Company is subject to utility rate regulation based upon the
historical costs of plant investment, using recent test years to
measure the cost of providing service.  The rate-making process
does not give recognition to the current cost of replacing plant
and the impact of inflation.  Changes in industry structure and
regulation may affect the extent to which future rates are based
upon current costs of providing service.  The regulatory
commissions have authorized fuel rates which provide for billing
customers on a timely basis for the actual cost of fuel and
interchange and for emission allowance costs and, in the District
of Columbia, for purchased capacity.  As of December 31, 1996,
there are no base rate proceedings filed nor pending approval by
any of the Company's retail or wholesale regulatory commissions.

     Annual base rate increases (decreases) which became
effective during the period 1994 through 1996 are shown below.

----------------------------------------------------------------- 
                                         District
                                            of
Year              Total     Maryland     Columbia    Wholesale   
----------------------------------------------------------------- 
                            (Millions of Dollars)

1996             $(2.0)       $   -       $   -        $(2.0)
1995              30.2            -        27.9          2.3
1994              29.3            -        26.7          2.6   
                 -----        -----       -----        ----- 
                 $57.5        $   -       $54.6        $ 2.9 
                 =====        =====       =====        =====
-----------------------------------------------------------------

Maryland
--------

Pursuant to a settlement agreement, base rate revenue was
increased by $27 million, or 3%, effective November 1, 1993.  In
connection with the settlement agreement, no determination was
made with respect to rate of return.  The rate of return on 


                                17


common stock equity most recently determined for the Company in a
fully litigated rate case was 12.75% established by the
Commission in a June 1991 rate increase order.

     Effective August 27, 1996, the Maryland DSM surcharge tariff
was increased, providing approximately $18 million annually in
increased revenue.  The surcharge includes provisions for the
recovery of lost revenue, amortization of pre-1996 actual program
expenditures plus the initial amortization of 1996 projected
program costs, a capital cost recovery factor of 9.46% on
unamortized balances and an incentive of $8.9 million awarded for
exceeding 1995 energy saving goals.  Previously, incentives of
$8.7 million and $5 million were awarded for exceeding 1994 and
1993 energy saving goals, respectively.  Maryland DSM program
goals for 1996 have been reduced to reflect lower DSM
expenditures.  Consequently, the performance bonus in 1997 is
expected to be significantly lower than amounts awarded for
performance in prior years.

     On November 8, 1996, the Company filed a request with the
Maryland Public Service Commission for approval of a purchased
capacity surcharge, which is designed to recover changes in the
level of purchased capacity costs from levels included in base
rates.  The filing was made to recover capacity payments under
the Panda contract, which commenced January 1, 1997.  The
estimated 1997 Maryland portion of these payments is $10.5
million.  On January 8, 1997, the Maryland Public Service
Commission suspended the Company's request for a period of 90
days from January 8, 1997, or until the date of a Commission
Order in the Joint Application for Authorization and Approval of
the Merger with BGE, whichever comes first.  The District of
Columbia portion of the Panda capacity costs will be recovered
through the existing fuel adjustment clause.

District of Columbia
--------------------

In Formal Case No. 939, the Commission, in June 1995, authorized
a $27.9 million, or 3.8%, increase in base rate revenue effective
July 1995.  The authorized rates are based on a 9.09% rate of
return on average rate base, including an 11.1% return on common
stock equity and a capital structure which excludes short-term
debt.  In addition, the Commission approved the Company's Least-
Cost Plan filed in June 1994.  A four-year DSM spending cap for
the period 1995-1998 was approved, consistent with the Company's
proposal to narrow the scope of DSM activities by discontinuing
operation of certain DSM programs and by reducing expenditures on
the remaining programs.  This will enable the Company to
implement cost-effective DSM programs while limiting the impact
of such programs on the price of electricity.  An Environmental
Cost Recovery Rider (ECRR) was approved to provide for full cost
recovery of actual DSM program expenditures, through a billing
surcharge.  Costs will be amortized over 10 years, with a return  


                                18


on unamortized amounts by means of a capital cost recovery factor
computed at the authorized rate of return.  The initial rate,
which reflects actual costs expended from July 1993 through
December 1994, resulted in additional annual revenue of
approximately $15 million.  Although the Commission denied the
Company's request to recover "lost revenue" due to DSM programs,
through the surcharge, a process has been established whereby the
Company can seek recovery of lost revenue in a separate
proceeding.  The Commission also increased the time period for
filing Least-Cost Planning cases from two to three years.  On
June 3, 1996, the Company filed an Application for Authority with
the Commission to revise its ECRR.  The proposed rate, which
reflects actual costs expended during 1995, is expected to
increase annual revenue by approximately $8 million.  No action
has been taken by the District of Columbia Public Service
Commission on the revised ECRR.  Subsequent rate updates are
scheduled to be filed annually on June 1 to reflect the prior
year's actual costs, subject to the annual surcharge recovery
limit within the four-year spending cap for the period 1995-1998
(amounts spent in excess of the annual surcharge recovery limit,
but within the four-year spending cap, are deferred for future
recovery).  Remaining allowable expenditures under the spending
cap totaled $15 million at December 31, 1996.  Pre-July 1993 DSM
costs receive base rate treatment.  

Wholesale
---------

The Company has a 10-year full service power supply contract with
the Southern Maryland Electric Cooperative, Inc. (SMECO), a
wholesale customer.  The contract period is to be extended for an
additional year on January 1 of each year, unless notice is given 
by either party of termination of the contract at the end of the
10-year period.  The full service obligation can be reduced by
SMECO by up to 20% of its annual requirements with a five-year
advance notice for each such reduction.  SMECO rates were
increased by $2.3 million effective January 1, 1995.  Pursuant to
a new agreement with SMECO for the years 1996 through 1998, a
rate reduction of $2 million from the 1995 rate level became
effective January 1, 1996, with an additional $2.5 million rate
reduction scheduled to become effective January 1, 1998.  SMECO
has agreed not to give the Company a notice of reduction or
termination of service prior to December 15, 1998.

COMPETITION
-----------
The electric utility industry is subject to increasing
competitive pressures, stemming from a combination of increasing
independent power production and regulatory and legislative
initiatives intended to increase bulk power competition,
including the Energy Policy Act of 1992.  Since the early 1980s,
the Company has pursued strategies which achieve financial


                                19   


flexibility through conservation and energy use management
programs, extension of the useful life of generating equipment,
cost-effective purchases of capacity and energy and preservation
of scheduling flexibility to add new generating capacity in
relatively small increments.  The Company serves a unique and
stable service territory and is a low-cost energy producer with
customer prices which compare favorably with regional and
national averages.

     Pursuant to an August 1995 order in a generic proceeding
dealing with electric industry structure and the advent of
competition, the Maryland Public Service Commission found that
competition at the wholesale level holds the greatest potential
for producing significant benefits, while competition at the
retail level would carry many potential problems and difficult-
to-find solutions.  The Commission stated that it was intrigued
by a restructuring concept suggested by the Company, which calls
for functionally dividing the utility into generation and
transmission/distribution segments.  The Commission encouraged
the Company to develop the concept further and suggested that
other electric utilities in the state develop similar proposals
specific to their competitive positions.  In October 1996, the
Maryland Commission reopened a generic proceeding to review
regulatory and competitive issues affecting the electricity
industry.  The Commission cited the evolving nature of the
electric industry as the basis for continuing its investigation. 
As part of this investigation, the Commission directed its Staff
to submit a report on or before May 31, 1997, containing, among
other things, recommendations regarding regulatory and
competitive issues facing the electric industry in Maryland.  The
Commission also directed the four major electric utilities in
Maryland to prepare unbundled cost studies and model unbundled
retail service tariffs prior to August 1, 1997.  The District of
Columbia Public Service Commission initiated a proceeding to
investigate issues regarding electricity industry structure and
competition in late 1995.  In September 1996, the Commission
issued an order designating the issues to be examined in the
proceeding.  Initial comments regarding the designated issues
were filed with the Commission in January 1997, with reply
comments due in February 1997.  

     Based on the regulatory framework in which it operates, the
Company currently applies the provisions of Statement of
Financial Accounting Standards (SFAS) No. 71, "Accounting for the
Effects of Certain Types of Regulation" in accounting for its
utility operations.  SFAS No. 71 allows regulated entities, in
appropriate circumstances, to establish regulatory assets and to
defer the income statement impact of certain costs that are
expected to be recovered in future rates. Deregulation of
portions of the Company's business could, in the future, result
in not meeting the rate recovery criteria for application of SFAS
No. 71 for part or all of the business.  


                                20     


While the Company does not foresee such a situation at this time,
if this were to occur in the transition to a more competitive
business, accounting standards of enterprises in general would
apply which would entail the write off of any previously deferred
costs to results of operations.  Regulatory assets include
deferred income taxes, unamortized conservation costs and
unamortized debt reacquisition costs recoverable through future
rates.

RESTRUCTURING OF THE BULK POWER MARKET
--------------------------------------

In April 1996, the FERC issued its Final Rulemaking Orders No.
888 and No. 889.  Both rulemakings address achieving greater
competition in the wholesale energy market.  Order No. 888
required utilities to file open access transmission tariffs by
July 9, 1996.  Such filing was made by the Company and was
accepted by the FERC.  Order No. 889 requires utilities to
establish or participate in an Open Access Same-Time Information
System (OASIS) which requires transmission owners to post certain
transmission availability, pricing and service information on an
open-access communications medium such as the Internet.  On
January 3, 1997, the Company's OASIS became operational and is
accessible through the PJM OASIS on the Internet.  Order No. 889
also required the Company to establish a code of conduct that
complies with FERC's prescribed standards in order to separate
utilities' transmission system operations and wholesale marketing
functions.  The Company's filed code of conduct became effective
on January 3, 1997.

     PJM has many years of experience in providing economically
efficient transmission and generation services throughout the
mid-Atlantic region, and has achieved for its members, including
the Company, significant cost savings through shared generating
reserves and integrated operations.  In order to meet the FERC's
goals, the PJM member companies plan to implement significant
market-oriented changes in 1997, which will support broader
market participation and achieve even greater efficiencies.  The
PJM members are working to transform today's coordinated cost-
based pool dispatch into a vigorous price-based regional energy
market operating under a standard of transmission service
comparability.  On July 24, 1996, nine of the 10 PJM member
companies (the Supporting Companies), excluding PECO Energy
Company (PECO), filed, with the FERC, a comprehensive proposal
including the contracts and tariff that would establish an
Independent System Operator (ISO) to administer transmission
service under a PJM control area transmission tariff and operate
the energy market in a manner that assures comparable treatment
for all participants.  Under the Supporting Companies' proposal,
reliability of the pool will be maintained under an installed
capacity obligation.  The ISO will administer a bid-priced energy
spot market that will also accommodate bilateral transactions,
and the ISO will provide transmission service on a poolwide 


                                21


basis.  In early August 1996, PECO filed a competing plan
opposing certain key features of the Supporting Companies'
proposal.

     On November 13, 1996, the FERC found that it could not
accept either the Supporting Companies' proposal or PECO's
opposing proposal.  Consequently, FERC ordered the PJM members to
amend its proposals to comport with Order No. 888 on ISOs and to
attempt to reach a consensus with other stakeholders.  If PJM
members could not comply with this order by December 31, 1996,
FERC required, at a minimum, that PJM file a poolwide pro forma
open access transmission tariff by December 31, 1996, and amend
existing PJM pooling agreements for compatibility with the Order. 
On December 31, 1996, the PJM member companies filed a joint
response to FERC's Order.  This compliance filing, if accepted,
establishes a single poolwide transmission tariff and modifies
the membership and governance provisions of the PJM agreement. 
The PJM members noted areas of disagreement in the filing and
indicated that the compliance filing was an interim solution
until a more comprehensive proposal could be developed.  These
changes are not expected to have a material effect on the
operating results of the Company.

NEW ACCOUNTING STANDARDS
------------------------

Effective January 1, 1996, the Company adopted SFAS No. 121
entitled "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of."  This statement
requires the Company to review long-lived assets for impairment
whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recovered.  In addition,
regulated companies are required to write off regulatory assets
whenever those assets no longer are probable of recovery from
customers through future rates.  Adoption of this pronouncement
did not have a material impact on the Company's consolidated
financial statements.

     SFAS No. 123 entitled "Accounting for Stock-Based
Compensation" also became effective as of January 1, 1996.  This
pronouncement encourages companies to recognize compensation
expense for the fair value of stock-based compensation but
permits accounting under Accounting Principles Board Opinion No.
25 entitled "Accounting for Stock Issued to Employees" so long as
the pro forma effects, as if the new standard had been applied,
are disclosed in the notes to financial statements.  The
Company's use of stock-based compensation is limited and adoption
of this pronouncement did not have a material impact on the
consolidated financial statements.




                               22


ENVIRONMENTAL MATTERS
---------------------

The Company is subject to federal, state and local legislation
and regulation with respect to environmental matters, including
air and water quality and the handling of solid and hazardous
waste.  As a result, the Company is subject to environmental
contingencies, principally related to possible obligations to
remove or mitigate the effects on the environment of the
disposal, effected in accordance with applicable laws at the
time, of certain substances at various sites.  During 1996, the
Company was participating in environmental assessments and
cleanups under these laws at three federal Superfund sites and a
private party site as a result of litigation.  While the total
cost of remediation at these sites may be substantial, the
Company shares liability with other potentially responsible
parties.  Based on the information known to the Company at this
time, management is of the opinion that resolution of these
matters will not have a material effect on the results of
operations or financial position of the Company.

     See the discussion included in Note (13) of the Notes to
Consolidated Financial Statements, Commitments and Contingencies,
for additional information.

NONUTILITY SUBSIDIARY
---------------------

RESULTS OF OPERATIONS 
---------------------

PCI's earnings for 1996 were $16.9 million ($.14 per share),
compared with a net loss of $124.4 million ($1.05 per share) in
1995 and net earnings of $19.1 million ($.16 per share) in 1994.  
During 1996, PCI continued the execution of the plan adopted in
May 1995 with respect to the aircraft equipment leasing business. 
PCI's losses in 1995 reflect the implementation of the plan which
resulted in noncash, after-tax charges of $122.2 million ($1.04
per share) during 1995.  Under the plan, PCI is not making new
investments to increase the size of the aircraft portfolio and 13
aircraft were designated for sale over 18 to 24 months from the
date the plan was announced.  The book values of these aircraft
were reduced to their estimated net realizable values of
approximately $104 million and no depreciation or routine accrual
for repair and maintenance expenditures for these aircraft have
been recorded since the plan was adopted.  During 1996, eight of
these aircraft were sold and one was placed on a long-term lease. 
Additional losses on assets held for disposal, recorded primarily
in the first quarter of 1996, totaled $12.7 million ($8.3 million
after-tax).  The remaining portfolio of assets held for disposal
was $10.3 million as of December 31, 1996.  


                                23


     During the fourth quarter of 1995, PCI formed a joint
venture with an affiliate of a major institutional investor to
assist with the disposition and management of 19 portfolio
aircraft.  PCI contributed 11 aircraft from its portfolio of
aircraft held for disposal, eight additional aircraft under long-
term leases and a portfolio of preferred stocks to the joint
venture.  All of the assets of the venture are fully consolidated
in PCI's financial statements with the outside investor's portion
reflected as a minority interest.  During 1996, two aircraft were
sold from the joint venture during the first quarter, four
aircraft were sold during the second quarter and one aircraft was
sold during the third quarter.  As a result of joint venture
operations in 1996, PCI's obligation for previously accrued
deferred income taxes was reduced, resulting in after-tax
earnings of $27.7 million, after provision for transaction costs. 
The excess deferred income taxes were recognized as a reduction
of income tax expense.  Future operations of the joint venture
may result in additional reversal of deferred income taxes.

     PCI continues to hold and closely monitor its aircraft
leasing portfolio, with the objective of identifying future
opportunities for disposition of these investments on favorable
terms.  Equipment values and sales opportunities may be affected
by future market conditions and events, including the
creditworthiness of PCI's lessees.

     On December 1, 1996, Canadian Airlines (Canadian)
unilaterally announced a three-month suspension of lease payments
to its operating lessors.  PCI has two aircraft on operating
lease to Canadian with a book value of $44 million at December
31, 1996.  Canadian cites an anticipated temporary cash
deficiency in early 1997 as the reason for the suspension of
payments.  Canadian intends to resume payment of rent beginning
in March 1997 and has requested no changes in the terms of its
leases with PCI.  Canadian has proposed to repay PCI the total
deferred rent amount of $1.3 million in 10 equal quarterly
installments beginning October 1, 1998, with interest accrued at
a market rate.  PCI expects to negotiate repayment terms with
Canadian.

     As a result of the first quarter 1996 implementation of SFAS
No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of", a pre-tax charge of
$9.6 million ($6.2 million after-tax) was recorded in the first
quarter of 1996 related to PCI's investment in solar electric
generating systems (SEGS) projects, reflecting revised first
quarter assumptions relating to the recoverability of the
investment.  In addition, PCI recorded a pre-tax charge of $9
million ($5.9 million after-tax) in the first quarter of 1996 and
$1.9 million ($1.2 million after-tax) in the fourth quarter of
1996, reflecting current assessments of the net realizable values
of real estate and oil and natural gas investments.


                                24


     PCI has limited partnership interests in five 30-megawatt
SEGS projects in the Mojave Desert in California.  The Company
owns 22%, 10%, 19%, 31%, and 25% of SEGS projects III through
VII, respectively.  The five SEGS power generation projects sell
electricity to Southern California Edison Company (Edison) under
30-year Interim Standard Offer No. 4 power purchase agreements
which fix the capacity charge for the term of the agreements and
fix the energy rate paid by Edison for the first 10 years of the
agreements.  For the remaining term of the agreements, energy
rates are variable, based on Edison's avoided cost of generation. 
The SEGS projects are scheduled to begin supplying electricity at
avoided cost energy rates at various times beginning in early
1997 through the end of 1998.  In conjunction with other project
investors, PCI is investigating and pursuing alternatives for
these projects, including but not limited to, renegotiating the
power purchase agreements and, with respect to SEGS III and IV,
restructuring the associated non-recourse debt.

     The lenders to SEGS III and IV filed suit against the SEGS
III and IV partnerships to restrain them from making
distributions of 1996 partnership profits.  The trial in this
case was concluded in November 1996 and the parties are waiting
for a decision by the Court.  The outcome is uncertain, and PCI
now expects that the losing party will appeal the court's
decision.  An appeal is expected to take more than a year to be
concluded.  Discussions with the SEGS III and IV lenders during
December 1996 have not resulted in any progress toward settlement
of the lawsuit or restructuring of the project loans.  In light
of the continuing uncertainty associated with the SEGS III and IV
litigation and the recent lack of success in reaching a
negotiated settlement with the project lenders, PCI recorded an
additional $8.5 million pre-tax ($5.5 million after-tax) charge
in the fourth quarter, representing a write-off of its remaining
investment in SEGS III and IV.  PCI's current projections of
future distributions from SEGS V, VI and VII indicate a recovery
of its remaining December 31, 1996, investment balance of $26.8
million.

     PCI generates income primarily from its leasing activities
and securities investments.  Income from leasing activity, which
includes rental income, gains on asset sales, interest income and
fees totaled $91.7 million in 1996, compared to $100.6 million in
1995 and $111.3 million in 1994.  The decrease in 1996 income
from leasing activities over 1995 was primarily due to
nonrecurring fee income earned during 1995.  PCI's marketable
securities portfolio contributed pre-tax income of $33.7 million
in 1996, compared with $36.1 million in 1995 and $35.1 million in
1994.  The reductions since 1994 are primarily the result of the
decreasing size of the portfolio.  Income from securities
included net realized gains from the sale or call of securities
of $3.6 million in 1996, $.4 million in 1995 and $.8 million in
1994. 


                                25


     Other income decreased in 1996 as compared to 1995 by $8.1
million primarily due to the previously discussed 1996 writedowns
of PCI's investments in SEGS, real estate and oil and natural
gas.  On December 31, 1996, PCI sold its $2.8 million (20%
interest) in Advanced Separation Technologies, Inc. for an after-
tax gain of $6.7 million.  Also included in other income during
1996 is $1.1 million in net income from PCI's investment in PEPCO
Enterprises, Inc. (PEI), a wholly owned subsidiary, which was
contributed to PCI by PEPCO during 1996.  PEI has business
interests which include telecommunications, liquefied natural gas
storage facilities, underground cable construction and
maintenance services and an energy management services company.

     Expenses, before income taxes, which include interest,
depreciation and operating, and administrative and general
expenses totaled $152.7 million in 1996, compared to $344.6
million in 1995 and $150.6 million in 1994.  The decrease is
primarily the result of the second quarter 1995 pre-tax writedown
of $170.1 million related to the May 1995 plan with respect to
the aircraft equipment leasing business.  In addition, expenses
before income taxes decreased during 1996, due to lower interest
expense resulting from less debt outstanding.  Also, during the
second quarter of 1996, responsibility for certain repair and
maintenance expenses was assumed by a lessee.  Accordingly, PCI
reversed $6.5 million of expenses accrued in prior periods.  

     PCI had income tax credits of $54.6 million in 1996,
compared to $85.7 million in 1995 and $22.7 million in 1994.  The
decrease in income tax credits in 1996 from 1995 was due to lower
pre-tax income in 1995, primarily the result of the pre-tax
charge to earnings in May 1995.

CAPITAL RESOURCES AND LIQUIDITY
-------------------------------

     The $377.2 million securities portfolio, consisting
primarily of investment grade preferred stocks, provides PCI with
liquidity and investment flexibility.  During 1996, PCI has
reduced its marketable securities portfolio by $153.1 million
primarily as the result of calls (approximately $82 million) and
sales of fixed rate preferred stocks, generating net pre-tax
gains of $3.6 million.  PCI's fixed rate portfolio is sensitive
to fluctuations in interest rates.  The decision to reduce the
size of the preferred stock portfolio was made to lessen the
impact of future fluctuations in interest rates, while still
maintaining a substantial portfolio for liquidity purposes.  The
proceeds from the securities activity during 1996 were used to
pay down short-term debt.  In addition, proceeds from aircraft
sales were also used to pay down short-term debt.



                                26 



     During the third quarter of 1996, PCI sold its investment in
an aircraft engine leasing subsidiary for its approximate book
value.  As a result of the sale, PCI's investment in operating
lease equipment decreased by $32.7 million.

     PCI's outstanding short-term debt totaled $51.7 million at
December 31, 1996, a decrease of $171.7 million from the $223.4
million outstanding at December 31, 1995, and an increase of $3.3
million from the $48.4 million outstanding at December 31, 1994. 
During 1996, PCI issued $183 million in long-term debt, including
non-recourse debt, and debt repayments totaled $237.1 million. 
At December 31, 1996, PCI had $236.3 million available under its
Medium-Term Note Program and $400 million available under its
committed bank credit facility.  


                                27 


Report of Independent Accountants

                                
To the Shareholders and
Board of Directors of
Potomac Electric Power Company


In our opinion, the accompanying consolidated balance sheets and
the related consolidated statements of earnings and of cash flows
present fairly, in all material respects, the financial position
of Potomac Electric Power Company and its subsidiaries at
December 31, 1996 and 1995, and the results of their operations
and their cash flows for each of the three years in the period
ended December 31, 1996, in conformity with generally accepted
accounting principles.  These financial statements are the
responsibility of the Company's management; our responsibility is
to express an opinion on these financial statements based on our
audits.  We conducted our audits of these statements in
accordance with generally accepted auditing standards which
require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of
material misstatement.  An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the
financial statements, assessing the accounting principles used
and significant estimates made by management, and evaluating the
overall financial statement presentation.  We believe that our
audits provide a reasonable basis for the opinion expressed
above.




/s/ Price Waterhouse LLP
Washington, D.C.
January 17, 1997



                                28


<TABLE>
Consolidated Statements of Earnings
Potomac Electric Power Company and Subsidiary
<CAPTION>

------------------------------------------------------------------------------
---------------------------
                                                                         For the
year ended December 31,
                                                                        1996   
      1995          1994
------------------------------------------------------------------------------
---------------------------
                                                                        
(Thousands of Dollars)
<S>                                                              <C>          
<C>           <C>
Revenue (Note 2)
  Operating revenue                                              $ 1,834,857  
$ 1,822,432   $ 1,790,600
  Interchange deliveries                                             175,454   
    53,670        32,474
                                                                 -----------  
-----------   -----------
    Total Revenue                                                  2,010,311   
 1,876,102     1,823,074
                                                                 -----------  
-----------   -----------

Operating Expenses
  Fuel                                                               327,792   
   355,453       392,730
  Purchased energy                                                   335,978   
   193,592       173,384
                                                                 -----------  
-----------   -----------
    Fuel and purchased energy                                        663,770   
   549,045       566,114
  Capacity purchase payments (Note 13)                               125,786   
   125,769       127,822
  Other operation                                                    223,326   
   224,030       206,106
  Maintenance                                                         91,524   
    92,859        92,614
  Depreciation and amortization                                      223,016   
   205,490       179,986
  Income taxes (Note 4)                                              134,085   
   128,460       119,859
  Other taxes (Note 5)                                               200,365   
   202,708       206,080
                                                                 -----------  
-----------   -----------
    Total Operating Expenses                                       1,661,872   
 1,528,361     1,498,581
                                                                 -----------  
-----------   -----------
Operating Income                                                     348,439   
   347,741       324,493
                                                                 -----------  
-----------   -----------

Other Income (Loss)
  Nonutility subsidiary (Note 15)
    Income                                                           114,966   
   134,493       147,006
    Loss on assets held for disposal                                 (12,744)  
  (170,078)            -
    Expenses, including interest and income taxes                    (85,328)  
   (88,812)     (127,918)
                                                                 -----------  
-----------   -----------
      Net earnings (loss) from nonutility subsidiary                  16,894   
  (124,397)       19,088
  Allowance for other funds used during construction
    and capital cost recovery factor                                   6,572   
     6,155        12,610
  Other, net                                                           4,458   
       682        (1,902)
                                                                 -----------  
-----------   -----------
    Total Other Income (Loss)                                         27,924   
  (117,560)       29,796
                                                                 -----------  
-----------   -----------
Income Before Utility Interest Charges                               376,363   
   230,181       354,289
                                                                 -----------  
-----------   -----------

Utility Interest Charges
  Interest on debt                                                   146,939   
   146,558       139,210
  Allowance for borrowed funds used during construction
    and capital cost recovery factor                                  (7,536)  
   (10,768)      (12,083)
                                                                 -----------  
-----------   -----------
    Net Utility Interest Charges                                     139,403   
   135,790       127,127
                                                                 -----------  
-----------   -----------

Net Income                                                           236,960   
    94,391       227,162
Dividends on Preferred Stock                                          16,604   
    16,851        16,437
                                                                 -----------  
-----------   -----------
Earnings for Common Stock                                        $   220,356  
$    77,540   $   210,725
                                                                 ===========  
===========   ===========

Average Common Shares Outstanding (000s)                             118,497   
   118,412       118,006

Earnings Per Common Share <F1>                                         $1.86   
      $.65         $1.79

Cash Dividends Per Common Share                                        $1.66   
     $1.66         $1.66

<FN>
<F1>No material dilution would occur if all of the convertible preferred stock
    and debentures were  converted into common stock.
</FN>

                                                      29
</TABLE>


<TABLE>
Consolidated Balance Sheets
Potomac Electric Power Company and Subsidiary
<CAPTION>


------------------------------------------------------------------------------
---------------
                                                                            
December 31,
Assets                                                                    1996 
        1995
------------------------------------------------------------------------------
---------------
                                                                     (Thousands
of Dollars)
<S>                                                                <C>         
 <C>
Property and Plant - at original cost (Notes 6 and 10)
  Electric plant in service                                        $ 6,232,049 
 $ 6,041,203
  Construction work in progress                                         62,469 
      93,047
  Electric plant held for future use                                     4,152 
       4,082
  Nonoperating property                                                 22,921 
      22,771
                                                                   ----------- 
 -----------
                                                                     6,321,591 
   6,161,103
  Accumulated depreciation                                          (1,898,342) 
 (1,760,792)
                                                                   ----------- 
 -----------
      Net Property and Plant                                         4,423,249 
   4,400,311
                                                                   ----------- 
 -----------



Current Assets
  Cash and cash equivalents                                              2,174 
       5,844
  Customer accounts receivable, less allowance for uncollectible
    accounts of $1,298 and $1,669                                      128,600 
     137,456
  Other accounts receivable, less allowance for uncollectible
    accounts of $300                                                    38,490 
      36,765
  Accrued unbilled revenue (Note 1)                                     70,214 
      73,622
  Prepaid taxes                                                         34,202 
      36,255
  Other prepaid expenses                                                 4,613 
       7,562
  Material and supplies - at average cost
    Fuel                                                                68,232 
      63,203
    Construction and maintenance                                        69,541 
      70,497
                                                                   ----------- 
 -----------
      Total Current Assets                                             416,066 
     431,204
                                                                   ----------- 
 -----------



Deferred Charges
  Income taxes recoverable through future rates, net (Note 4)          238,467 
     244,181
  Conservation costs, net                                              233,793 
     230,412
  Unamortized debt reacquisition costs                                  55,552 
      58,360
  Other                                                                159,139 
     138,619
                                                                   ----------- 
 -----------
      Total Deferred Charges                                           686,951 
     671,572
                                                                   ----------- 
 -----------


Nonutility Subsidiary Assets
  Cash and cash equivalents                                                804 
       1,594
  Marketable securities (Notes 11 and 15)                              377,237 
     530,323
  Investment in finance leases (Note 15)                               484,972 
     438,795
  Operating lease equipment, net of accumulated depreciation
    of $117,705 and $79,275 (Note 15)                                  199,124 
     272,947
  Assets held for disposal                                              10,300 
     104,370
  Receivables, less allowance for uncollectible
    accounts of $6,000                                                  87,745 
      74,957
  Other investments                                                    193,002 
     176,418
  Other assets                                                          12,436 
      15,659
                                                                   ----------- 
 -----------
      Total Nonutility Subsidiary Assets                             1,365,620 
   1,615,063
                                                                   ----------- 
 -----------
      Total Assets                                                 $ 6,891,886 
 $ 7,118,150
                                                                   =========== 
 ===========

                                               30
</TABLE>



<TABLE>
<CAPTION>

------------------------------------------------------------------------------
---------------
                                                                            
December 31,
Capitalization and Liabilities                                            1996 
        1995
------------------------------------------------------------------------------
---------------
                                                                     (Thousands
of Dollars)
<S>                                                                <C>         
 <C>
Capitalization
  Common equity (Note 7)
    Common stock, $1 par value - authorized 200,000,000 shares,
      issued 118,500,037 and 118,494,577 shares                    $   118,500 
 $   118,495
    Premium on stock and other capital contributions                 1,025,187 
   1,025,088
    Capital stock expense                                              (14,780) 
    (14,567)
    Retained income                                                    760,285 
     742,296
                                                                   ----------- 
 -----------
      Total Common Equity                                            1,889,192 
   1,871,312

  Preference stock, cumulative, $25 par value -
    authorized 8,800,000 shares, no shares issued or outstanding             - 
           -
  Serial preferred stock (Notes 8 and 11)                              125,298 
     125,325
  Redeemable serial preferred stock (Notes 9 and 11)                   142,500 
     143,485
  Long-term debt (Notes 10 and 11)                                   1,767,598 
   1,817,077
                                                                   ----------- 
 -----------
      Total Capitalization                                           3,924,588 
   3,957,199
                                                                   ----------- 
 -----------

Other Non-Current Liabilities
  Capital lease obligations (Note 13)                                  162,936 
     165,235
                                                                   ----------- 
 -----------
      Total Other Non-Current Liabilities                              162,936 
     165,235
                                                                   ----------- 
 -----------

Current Liabilities
  Long-term debt and preferred stock redemption
    due within one year                                                152,445 
      26,280
  Short-term debt (Note 12)                                            131,390 
     258,465
  Accounts payable and accrued payroll                                 117,810 
     104,396
  Capital lease obligations due within one year                         20,772 
      20,772
  Taxes accrued                                                         23,362 
      19,111
  Interest accrued                                                      38,117 
      38,532
  Customer deposits                                                     24,119 
      23,372
  Other                                                                 59,016 
      62,662
                                                                   ----------- 
 -----------
      Total Current Liabilities                                        567,031 
     553,590
                                                                   ----------- 
 -----------

Deferred Credits
  Income taxes (Note 4)                                                973,642 
     892,544
  Investment tax credits (Note 4)                                       60,958 
      64,607
  Other                                                                 35,658 
      35,089
                                                                   ----------- 
 -----------
      Total Deferred Credits                                         1,070,258 
     992,240
                                                                   ----------- 
 -----------

Nonutility Subsidiary Liabilities
  Long-term debt (Notes 10 and 11)                                     996,232 
   1,047,484
  Short-term notes payable (Note 12)                                    51,650 
     223,350
  Deferred taxes and other (Note 4)                                    119,191 
     179,052
                                                                   ----------- 
 -----------
      Total Nonutility Subsidiary Liabilities                        1,167,073 
   1,449,886
                                                                   ----------- 
 -----------
Commitments and Contingencies (Note 13)

      Total Capitalization and Liabilities                         $ 6,891,886 
 $ 7,118,150
                                                                   =========== 
 ===========

                                               31
</TABLE>

<TABLE>
Consolidated Statements of Cash Flows
Potomac Electric Power Company and Subsidiary
<CAPTION>

------------------------------------------------------------------------------
-----------------------------
                                                                           For
the year ended December 31,
                                                                          1996 
        1995          1994
------------------------------------------------------------------------------
-----------------------------
                                                                          
(Thousands of Dollars)
<S>                                                                <C>         
 <C>           <C>
Operating Activities
  Income from utility operations                                   $   220,066 
 $   218,788   $   208,074
  Adjustments to reconcile income to net cash
    from operating activities:
    Depreciation and amortization                                      223,016 
     205,490       179,986
    Deferred income taxes and investment tax credits                    81,496 
      51,774        44,641
    Allowance for funds used during construction
      and capital cost recovery factor                                 (14,108) 
    (16,923)      (24,693)
    Changes in materials and supplies                                   (4,073) 
     12,418       (13,883)
    Changes in accounts receivable and accrued unbilled revenue         10,539 
     (15,822)       (6,098)
    Changes in accounts payable                                         13,624 
     (14,419)        8,257
    Changes in other current assets and liabilities                      5,859 
      (1,484)       (6,760)
    Changes in deferred conservation costs                             (49,404) 
   (104,796)      (92,504)
    Net other operating activities                                     (48,674) 
    (45,664)          360
  Nonutility subsidiary:
    Net earnings (loss)                                                 16,894 
    (124,397)       19,088
    Deferred income taxes                                              (36,398) 
    (49,697)        6,386
    Loss on assets held for disposal                                    12,744 
     170,078             -
    Changes in other assets and net other operating activities          36,258 
      83,509        47,648
                                                                   ----------- 
 -----------   -----------
Net Cash From Operating Activities                                     467,839 
     368,855       370,502
                                                                   ----------- 
 -----------   -----------

Investing Activities
  Total investment in property and plant                              (194,036) 
   (230,675)     (316,890)
  Allowance for funds used during construction
    and capital cost recovery factor                                    14,108 
      16,923        24,693
                                                                   ----------- 
 -----------   -----------
    Net investment in property and plant                              (179,928) 
   (213,752)     (292,197)
  Nonutility subsidiary:
    Purchase of marketable securities                                  (19,680) 
    (35,221)     (127,335)
    Proceeds from sale or redemption of marketable securities          167,528 
      27,846        82,444
    Investment in leased equipment                                      (3,056) 
   (154,766)      (72,134)
    Proceeds from sale or disposition of leased equipment                3,658 
           -         1,150
    Proceeds from sale of assets                                        34,154 
       5,966             -
    Purchase of other investments                                      (22,998) 
     (3,818)       (7,191)
    Proceeds from sale or distribution of other investments             33,867 
      15,614        18,429
    Investment in promissory notes                                      (4,245) 
     (7,955)         (542)
    Proceeds from promissory notes                                      16,675 
       7,977         4,902
                                                                   ----------- 
 -----------   -----------
Net Cash From (Used by) Investing Activities                            25,975 
    (358,109)     (392,474)
                                                                   ----------- 
 -----------   -----------

Financing Activities
  Dividends on common stock                                           (196,612) 
   (196,469)     (195,755)
  Dividends on preferred stock                                         (16,604) 
    (16,851)      (16,437)
  Issuance of common stock                                                   - 
       4,580         9,285
  Redemption of preferred stock                                              - 
         (78)       (4,047)
  Issuance of long-term debt                                            99,500 
     188,594       302,999
  Reacquisition and retirement of long-term debt                       (26,320) 
   (117,465)     (144,422)
  Proceeds from sale and leaseback of control center system                  - 
           -       152,000
  Short-term debt, net                                                (127,075) 
     68,865      (105,015)
  Other financing activities                                            (5,358) 
    (23,611)      (14,452)
  Nonutility subsidiary:
    Issuance of long-term debt                                         183,000 
     182,000       286,750
    Repayment of long-term debt                                       (237,102) 
   (275,021)     (173,950)
    Short-term debt, net                                              (171,703) 
    174,950       (77,850)
                                                                   ----------- 
 -----------   -----------
Net Cash (Used by) From Financing Activities                          (498,274) 
    (10,506)       19,106
                                                                   ----------- 
 -----------   -----------
Net (Decrease) Increase In Cash and Cash Equivalents                    (4,460) 
        240        (2,866)
Cash and Cash Equivalents at Beginning of Year                           7,438 
       7,198        10,064
                                                                   ----------- 
 -----------   -----------
Cash and Cash Equivalents at End of Year (Note 14)                 $     2,978 
 $     7,438   $     7,198
                                                                   =========== 
 ===========   ===========


                                                      32
</TABLE>



Notes to Consolidated Financial Statements
------------------------------------------

(1)  Summary of Significant Accounting Policies
     ------------------------------------------

The Company is engaged in the generation, transmission,
distribution and sale of electric energy in the Washington, D.C.
metropolitan area.  The Company's retail service territory
includes all of the District of Columbia and major portions of
Montgomery and Prince George's counties in suburban Maryland.

     Potomac Capital Investment Corporation (PCI), the Company's
wholly owned subsidiary, was formed in 1983 to provide a
permanent vehicle for the conduct of the Company's ongoing
nonutility investment programs.  Effective April 30, 1996, the
Company reorganized its nonutility subsidiaries whereby PEPCO
Enterprises, Inc. (PEI) became a subsidiary of PCI.  PCI's
principal investments have been in aircraft and power generation
equipment, equipment leasing and marketable securities, primarily
preferred stock with mandatory redemption features.  PCI is also
involved with activities, through PEI, which provide utility-
related telecommunication and energy services.  In addition, PCI
has investments in real estate properties in the Washington, D.C.
metropolitan area.

     The Company's utility operations are regulated by the
Maryland and District of Columbia Public Service Commissions and
its wholesale business by the Federal Energy Regulatory
Commission (FERC).  The Company complies with the Uniform System
of Accounts prescribed by the FERC and adopted by the Maryland
and District of Columbia regulatory commissions.  Based upon the
regulatory framework in which it operates, the Company currently
applies the provisions of the Statement of Financial Accounting
Standards (SFAS) No. 71 entitled "Accounting for the Effects of
Certain Types of Regulation" in accounting for certain deferred
charges and credits to be recognized in future customer billings
pursuant to regulatory authorization, principally deferred income
taxes, unamortized conservation costs and unamortized debt
reacquisition costs.  
 
     The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the
reported amounts of revenue and expenses during the reporting
period.  Actual results could differ from those estimates and
assumptions.



                                33


     Certain prior year amounts have been reclassified to conform
to the current year presentation.

     A description of significant accounting policies follows.

Principles of Consolidation
---------------------------

The consolidated financial statements combine the financial
results of the Company and PCI.  All material intercompany
balances and transactions have been eliminated.

Total Revenue
-------------

Revenue is accrued for service rendered but unbilled as of the
end of each month.  The Company includes in revenue the amounts
received for sales of energy, and resales of purchased energy, to
other utilities and to power marketers.  Amounts received for
such interchange deliveries are a component of the Company's fuel
rates.

     In each jurisdiction, the Company's rate schedules include
fuel rates.  The fuel rate provisions are designed to provide for
separately stated fuel billings which cover applicable net fuel
and interchange costs, purchased capacity in the District of
Columbia, and emission allowance costs in the Company's retail
jurisdictions, or changes in the applicable costs from levels
incorporated in base rates.  Differences between applicable net
costs incurred and fuel rate revenue billed in any given period
are accounted for as other current assets or other current
liabilities in those cases where specific provision has been made
by the appropriate regulatory commission for the resolution of
such differences within one year.  Where no such provision has
been made, the differences are accounted for as other deferred
charges or other deferred credits pending regulatory
determination.

     In the District of Columbia, pre-July 1993 conservation
costs receive rate base treatment.  Conservation expenditures for
the period July 1993 to December 1994 are recovered through a
surcharge mechanism which initially became effective July 11,
1995, and which is scheduled to be updated annually on June 1 to
recover 1995 and subsequent conservation expenditures, including
a capital cost recovery factor (CCRF), which is a mechanism that
enables the Company to earn a return on certain costs,
principally unamortized Demand Side Management (DSM) costs not in
rate base.  A procedure has been established to consider lost
revenue without the need for base rate proceedings.  In Maryland,
conservation costs are recovered through a surcharge rate which
reflects amortization of program costs including costs in the
year during which the surcharge commences, a CCRF, incentives, 


                                34


applicable taxes and estimated lost revenue.  The surcharge is
established annually in a collaborative process with the recovery
of lost revenue subject to an earnings test performed on a
quarterly basis.

Leasing Transactions
--------------------

Income from PCI investments in direct finance and leveraged lease
transactions, in which PCI is an equity participant, is reported
using the financing method.  In accordance with the financing
method, investments in leased property are recorded as a
receivable from the lessee to be recovered through the collection
of future rentals.  For direct finance leases, unearned income is
amortized to income over the lease term at a constant rate of
return on the net investment.  Income, including investment tax
credits on leveraged equipment leases, is recognized over the
life of the lease at a level rate of return on the positive net
investment.

     PCI investments in equipment under operating leases are
stated at cost less accumulated depreciation, except that assets
held for disposal are carried at estimated fair value less
estimated costs to sell.  Depreciation is recorded on a straight
line basis over the equipment's estimated useful life.  No
depreciation is taken on assets held for disposal.

Property and Plant
------------------

The cost of additions to, and replacements or betterments of,
retirement units of property and plant is capitalized.  Such cost
includes material, labor, the capitalization of an Allowance for
Funds Used During Construction (AFUDC) and applicable indirect
costs, including engineering, supervision, payroll taxes and
employee benefits.  The original cost of depreciable units of
plant retired, together with the cost of removal, net of salvage,
is charged to accumulated depreciation.  Routine repairs and
maintenance are charged to operating expenses as incurred.

     The Company uses separate depreciation rates for each
electric plant account.  The rates, which vary from jurisdiction
to jurisdiction, were equivalent to a system-wide composite
depreciation rate of approximately 3.1% for 1996, 1995 and 1994.

Conservation 
------------

In general, the Company accounts for conservation expenditures in
connection with its DSM program as a deferred charge, and
amortizes the costs over five years in Maryland and 10 years in


                                35


the District of Columbia.  At December 31, 1996, unamortized
conservation costs totaled $96 million in Maryland and $138
million in the District of Columbia.  

Allowance for Funds Used During Construction and Capital 
  Cost Recovery Factor 
--------------------------------------------------------

In general, the Company capitalizes AFUDC with respect to
investments in Construction Work in Progress with the exception
of expenditures required to comply with federal, state or local
environmental regulations (pollution control projects), which are
included in rate base without capitalization of AFUDC.  The
jurisdictional AFUDC capitalization rates are determined as
prescribed by the FERC.  The effective capitalization rates were
approximately 7.4% in 1996, 7.9% in 1995 and 7.6% in 1994,
compounded semiannually.

     In Maryland, the Company accrues a CCRF on the retail
jurisdictional portion of certain pollution expenditures related
to compliance with the Clean Air Act (CAA).  The base for
calculating this return is the amount by which the Maryland
jurisdictional CAA expenditure balance exceeds the CAA balance
being recovered in base rates.  The CCRF rate for Maryland is
9.46%.  In the District of Columbia, the carrying costs of CAA
expenditures not in rate base are recovered through a base rate
surcharge.

Amortization of Debt Issuance and Reacquisition Costs
-----------------------------------------------------

The Company defers and amortizes expenses incurred in connection
with the issuance of long-term debt, including premiums and
discounts associated with such debt, over the lives of the
respective issues.  Costs associated with the reacquisition of
debt are also deferred and amortized over the lives of the new
issues.

New Accounting Standards
------------------------

Effective January 1, 1996, the Company adopted SFAS No. 121
entitled "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of."  This statement
requires the Company to review long-lived assets for impairment
whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recovered.  In addition,
regulated companies are required to write off regulatory assets
whenever those assets no longer are probable of recovery from
customers through future rates.  Adoption of this pronouncement
did not have a material impact on the Company's consolidated
financial statements.


                                36   


     SFAS No. 123 entitled "Accounting for Stock-Based
Compensation" also became effective as of January 1, 1996.  This
pronouncement encourages companies to recognize compensation
expense for the fair value of stock-based compensation but
permits accounting under Accounting Principles Board Opinion No.
25 entitled "Accounting for Stock Issued to Employees" as long as
the pro forma effects, as if the new standard had been applied,
are disclosed in the notes to financial statements.  The
Company's use of stock-based compensation is limited and adoption
of this pronouncement did not have a material impact on the
consolidated financial statements.

Nonutility Subsidiary Receivables
---------------------------------

PCI, the Company's nonutility subsidiary, continuously monitors
its receivables and establishes an allowance for doubtful
accounts against its notes receivable, when deemed appropriate,
on a specific identification basis.  The direct write-off method
is used when trade receivables are deemed uncollectible. 

(2)  Total Revenue
     -------------

The Company's retail service area includes all of the District of
Columbia and major portions of Montgomery and Prince George's
counties in suburban Maryland.  The Company supplies electricity,
at wholesale, under a contract with Southern Maryland Electric
Cooperative, Inc. (SMECO), and also delivers economy energy to
the Pennsylvania-New Jersey-Maryland Interconnection Association
(PJM) of which the Company is a member.  PJM is composed of 11
electric utilities which operate on a fully integrated basis.


                                37    


     Total revenue for each year was comprised as shown below.

-----------------------------------------------------------------
                      1996            1995             1994     
               -------------------------------------------------- 
                 Amount    %     Amount     %     Amount     %
-----------------------------------------------------------------
                             (Thousands of Dollars)
Sales of
  Electricity

  Residential  $  548,108  30.1 $  543,532  30.0 $  524,738  29.5
  Commercial      852,497  46.7    848,892  46.8    834,323  46.8
  U.S.
    Government    250,422  13.7    252,144  13.9    254,030  14.2
  D.C.
    Government     51,565   2.8     52,105   2.9     56,655   3.2
  Wholesale       122,149   6.7    117,117   6.4    113,318   6.3
               ---------- -----  --------- ----- ---------- -----
    Total       1,824,741 100.0  1,813,790 100.0  1,783,064 100.0
                          =====            =====            =====
Other electric
  revenue          10,116            8,642            7,536
               ----------       ----------       ----------      

  Operating     
    revenue     1,834,857        1,822,432        1,790,600

Interchange
  deliveries      175,454           53,670           32,474
               ----------       ----------       ----------
 Total Revenue $2,010,311       $1,876,102       $1,823,074
               ==========       ==========       ========== 
-----------------------------------------------------------------

     Sales of electricity include base rate revenue and fuel rate
revenue.  Fuel rate revenue was $521.9 million in 1996, $526.6
million in 1995 and $557.4 million in 1994.

     The Company's Maryland fuel rate is based on historical net
fuel, interchange and emission allowance costs.  The zero-based
rate may not be changed without prior approval of the Maryland
Public Service Commission.  Application to the Commission for an
increase in the rate may only be made when the currently
calculated fuel rate, based on the most recent actual net fuel,
interchange and emission allowance costs, exceeds the currently
effective fuel rate by more than 5%.  If the currently calculated
fuel rate is more than 5% below the currently effective fuel
rate, the Company must apply to the Commission for a fuel rate
reduction.


                                38


     The District of Columbia fuel rate is based upon an average
of historical and projected net fuel, interchange and emission
allowance costs and purchased capacity, and is adjusted monthly
to reflect changes in such costs.

     Rates for service, at wholesale, to SMECO include a fuel
adjustment charge based upon estimated applicable fuel and
interchange costs for each billing month.  The difference between
the estimated costs and the actual applicable fuel and
interchange costs incurred each month is reflected as an
adjustment to the fuel rate in the succeeding month.

     Interchange deliveries include power sales tariff
transactions, predominantly those where the Company buys energy
from one party for the purpose of selling that energy to a third
party.  The benefits derived from interchange deliveries are a
component of the Company's fuel rates.

(3)  Pensions and Other Postretirement and Postemployment
       Benefits
     ----------------------------------------------------

The Company's General Retirement Program (Program), a
noncontributory defined benefit program, covers substantially all
full-time employees of the Company and its subsidiary.  The
Program provides for benefits to be paid to eligible employees at
retirement based primarily upon years of service with the Company
and their compensation rates for the three years preceding
retirement.  Annual provisions for accrued pension cost are based
upon independent actuarial valuations.  The Company's policy is
to fund accrued pension costs.

     Pension expense included in net income was $14.2 million in
1996, $13.9 million in 1995 and $14.3 million in 1994.  The net
periodic pension cost was computed as follows.

-----------------------------------------------------------------
                                        1996      1995      1994
----------------------------------------------------------------- 
                                       (Thousands of Dollars)

Service cost-benefits earned         $11,400   $ 9,900   $10,800
Interest cost on projected
  benefit obligation                  30,600    28,400    26,800
Actual return on Program assets      (38,200)  (51,900)   (4,600)
Differences between actual
  and expected return on
  Program assets and net
  amortization                        10,400    27,500   (18,700)
                                     -------   -------   -------
  Pension cost                       $14,200   $13,900   $14,300
                                     =======   =======   =======
----------------------------------------------------------------

                                39


     Program assets are stated at fair value and were comprised
of approximately 53% and 60% of cash equivalents and fixed income
investments and the balance in equity investments at December 31,
1996 and 1995, respectively.  The following table sets forth the
Program's funded status and amounts recognized on the
Consolidated Balance Sheets.

-----------------------------------------------------------------
                                                1996        1995
-----------------------------------------------------------------
                                           (Thousands of Dollars)

Actuarial present value of benefit obligations:
  Program benefits:
    Vested benefits                        $(322,000)  $(295,700)
    Nonvested benefits                       (49,400)    (44,000)
                                           ---------   ---------
Accumulated benefit obligation             $(371,400)  $(339,700)
                                           =========   =========
Actuarial present value of projected
  benefit obligation                       $(438,100)  $(399,400)
Program assets at fair value                 402,500     360,500
                                           ---------   ---------
Projected benefit obligation in excess of
  Program assets                             (35,600)    (38,900)
Unrecognized actuarial loss                   68,700      55,600
Unrecognized prior service cost               14,900      16,300
Unrecognized net obligation at
  January 1, 1987, being recognized
  over 18 years                                  300         300
                                           ---------   ---------
Prepaid pension expense                    $  48,300   $  33,300
                                           =========   =========
----------------------------------------------------------------- 

     The assumed weighted average discount rate and weighted
average rate of increase in future compensation levels used in
determining the actuarial present value of the projected benefit
obligation were 7.5% and 4% in 1996 and 1995.  The assumed long-
term rate of return on Program assets was 9% in 1996 and 1995. 

     In addition to providing pension benefits, the Company
provides certain health care and life insurance benefits for
retired employees and inactive employees covered by disability
plans.  The health care plan pays stated percentages of most
necessary medical expenses incurred by these employees, after
subtracting payments by Medicare or other providers and after a
stated deductible has been met.  The life insurance plan pays
benefits based on base salary at the time of retirement and age
at the date of death.  Participants become eligible for the 



                                40


benefits of these plans if they retire under the provisions of
the Company's Program with 10 years of service or become inactive
employees under the Company's disability plans.  The Company is
amortizing the unrecognized transition obligation measured at
January 1, 1993, over a 20-year period.

     Postretirement benefit expense included in net income was
$10.9 million, $9 million and $8.7 million in 1996, 1995 and
1994, respectively.  The following table sets forth the
components of the postretirement expense.

-----------------------------------------------------------------
                                          1996     1995     1994
-----------------------------------------------------------------
                                         (Thousands of Dollars)
 
Service cost-benefits attributable        
  to service during the year           $ 2,800  $ 2,300  $ 2,600
Interest cost on accumulated                             
  postretirement benefit obligation      5,300    4,500    4,200
Actual loss (return) on plan assets     (1,300)  (1,900)     200
Amortization of transition                             
  obligation                             2,100    2,100    2,500
Difference between actual and 
  expected return on plan assets
  and net amortization                   2,000    2,000     (800)
                                       -------  -------  -------
Net postretirement benefit cost        $10,900  $ 9,000  $ 8,700
                                       =======  =======  =======
-----------------------------------------------------------------



                                41



     The following table sets forth the accumulated post-
retirement benefit obligation reconciled to the amounts
recognized on the Consolidated Balance Sheets.

-----------------------------------------------------------------
                                              1996        1995
-----------------------------------------------------------------
                                          (Thousands of Dollars)

Accumulated postretirement 
  benefit obligation to                         
    Retirees and dependents               $(50,600)   $(40,100)
    Active employees fully eligible         (5,600)     (9,300)
    Active employees not fully
      eligible                             (19,500)    (15,200)
                                          --------    --------
Total accumulated postretirement
  benefit obligation                       (75,700)    (64,600)
Plan assets at fair value                    9,800       7,800
                                          --------    --------
Accumulated postretirement benefit 
  obligation in excess of plan assets      (65,900)    (56,800)
Unrecognized transition obligation          33,700      35,800
Unrecognized actuarial loss                 33,400      23,100
                                          --------    --------
Prepaid postretirement benefit 
  cost                                    $  1,200    $  2,100
                                          ========    ========
-----------------------------------------------------------------

     The Company's obligation at December 31, 1996 and 1995, was
based on a discount rate of 7.5%, and a weighted average rate of
increase in future compensation levels of 4%.  The assumed
health-care cost trend rate is 7.5% which declines to 5.5% after
a four-year period.  A one percentage point increase in the
health-care cost trend rate would increase the Accumulated
Postretirement Benefit Obligation by $4 million to approximately
$79.7 million and the sum of the service cost and interest cost
for 1996 by approximately $.6 million.

     In January 1996 and 1995, the Company funded the 1996 and
1995 portions of its estimated liability for postretirement
medical and life insurance costs through the use of an Internal
Revenue Code (IRC) 401 (h) account, within the Company's pension
plan, and an IRC 501 (c)(9) Voluntary Employee Beneficiary
Association (VEBA).  The Company plans to fund the 401(h) account
and the VEBA annually.  In January 1997, the 1997 portion of the
Company's estimated liability will be funded.  Assets were
comprised of cash equivalents, fixed income investments and
equity investments and the assumed return on plan assets was 9%
in 1996 and 1995. 


                                42  


<TABLE>
(4) Income Taxes
    ------------

The provision for income taxes, reconciliation of consolidated income tax expense
and components of consolidated deferred tax liabilities (assets) are set forth
below.


<CAPTION>
Provisions for Income Taxes
---------------------------

------------------------------------------------------------------------------
---------------------
                                                                      1996     
  1995        1994
------------------------------------------------------------------------------
---------------------
                                                                        
(Thousands of Dollars)

<S>                                                              <C>         <C> 
       <C>
Utility current tax expense
  Federal                                                        $  47,235   $ 
68,492   $  63,395
  State and local                                                    6,281     
 9,173       8,612
                                                                 ---------  
---------   ---------
Total utility current tax expense                                   53,516     
77,665      72,007
                                                                 ---------  
---------   ---------
Utility deferred tax expense
  Federal                                                           74,762     
48,339      42,070
  State and local                                                   10,383     
 7,084       6,221
  Investment tax credits                                            (3,649)    
(3,649)     (3,650)
                                                                 ---------  
---------   ---------
Total utility deferred tax expense                                  81,496     
51,774      44,641
                                                                 ---------  
---------   ---------

Total utility income tax expense                                   135,012    
129,439     116,648
                                                                 ---------  
---------   ---------

Nonutility subsidiary current tax expense
  Federal                                                          (18,252)   
(35,592)    (29,315)
                                                                 ---------  
---------   ---------

Nonutility subsidiary deferred tax expense
  Federal                                                          (36,373)   
(50,116)      6,758
  State and local                                                        -     
     -        (138)
                                                                 ---------  
---------   ---------
Total nonutility subsidiary deferred tax expense                   (36,373)   
(50,116)      6,620
                                                                 ---------  
---------   ---------

Total nonutility subsidiary income tax expense                     (54,625)   
(85,708)    (22,695)
                                                                 ---------  
---------   ---------

Total consolidated income tax expense                               80,387     
43,731      93,953
Income taxes included in other income                              (53,698)   
(84,729)    (25,906)
                                                                 ---------  
---------   ---------
Income taxes included in utility operating expenses              $ 134,085   $
128,460   $ 119,859
                                                                 =========  
=========   =========



                                                  43
</TABLE>


<TABLE>
<CAPTION>
Reconciliation of Consolidated Income Tax Expense
-------------------------------------------------


------------------------------------------------------------------------------
---------------------
                                                                      1996     
  1995        1994
------------------------------------------------------------------------------
---------------------
                                                                        
(Thousands of Dollars)

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

Income before income taxes                                       $ 317,347   $
138,122   $ 321,115
                                                                 =========  
=========   =========

Utility income tax at federal statutory rate                     $ 124,277   $
121,879   $ 113,653
  Increases (decreases) resulting from
    Depreciation                                                     9,867     
 9,173       8,022
    Removal costs                                                   (3,574)    
(7,204)     (4,086)
    Allowance for funds used during construction                       691     
   595      (2,411)
    Other                                                           (3,117)    
(1,613)     (4,175)
    State income taxes, net of federal effect                       10,749     
10,648       9,683
    Tax credits                                                     (3,881)    
(4,039)     (4,038)
                                                                 ---------  
---------   ---------
Total utility income tax expense                                   135,012    
129,439     116,648
                                                                 ---------  
---------   ---------

Nonutility subsidiary income tax at federal statutory rate         (13,206)   
(73,537)     (1,262)
  Increases (decreases) resulting from
    Dividends received deduction                                    (7,114)    
(8,524)     (8,487)
    Reversal of previously accrued deferred taxes                  (30,804)    
     -      (8,206)
    Other                                                           (3,501)    
(3,647)     (4,602)
    State income taxes, net of federal effect                            -     
     -        (138)
                                                                 ---------  
---------   ---------
Total nonutility subsidiary income tax expense                     (54,625)   
(85,708)    (22,695)
                                                                 ---------  
---------   ---------

Total consolidated income tax expense                               80,387     
43,731      93,953
Income taxes included in other income                              (53,698)   
(84,729)    (25,906)
                                                                 ---------  
---------   ---------
Income taxes included in utility operating expenses              $ 134,085   $
128,460   $ 119,859
                                                                 =========  
=========   =========

</TABLE>

<TABLE>
<CAPTION>
Components of Consolidated Deferred Tax Liabilities (Assets)
------------------------------------------------------------

                                                                     At December
31,
                                                                
----------------------
                                                                      1996     
  1995
                                                                
----------------------
                                                                 (Thousands of
Dollars)

<S>                                                              <C>         <C>
Utility deferred tax liabilities (assets)
  Depreciation and other book to tax basis differences           $ 821,656   $
773,323
  Rapid amortization of certified pollution control
    facilities                                                      24,816     
26,640
  Deferred taxes on amounts to be collected through
    future rates                                                    90,284     
92,472
  Property taxes                                                    12,664     
11,808
  Deferred fuel                                                    (14,663)    
(7,154)
  Prepayment premium on debt retirement                             21,025     
22,080
  Deferred investment tax credit                                   (23,079)   
(24,464)
  Contributions in aid of construction                             (28,719)   
(27,206)
  Contributions to pension plan                                     16,170     
10,859
  Conservation costs (demand side management)                       41,106     
     -
  Other                                                             21,653     
25,124
                                                                 ---------  
---------
Total utility deferred tax liabilities (net)                       982,913    
903,482
Current portion of utility deferred tax liabilities
  (included in Other Current Liabilities)                            9,271     
10,938
                                                                 ---------  
---------
Total utility deferred tax liabilities (net) - noncurrent        $ 973,642   $
892,544
                                                                 =========  
=========

Nonutility subsidiary deferred tax liabilities (assets)
  Finance leases                                                 $ 144,290   $
149,103
  Operating leases                                                  57,383     
66,802
  Reversal of previously accrued taxes related
    to partnerships                                                 (7,455)   
(11,593)
  Alternative minimum tax                                          (97,109)   
(84,512)
  Other                                                            (36,041)   
(16,840)
                                                                 ---------  
---------
Total nonutility subsidiary deferred tax liabilities (net),
  (included in Deferred taxes and other)                         $  61,068   $
102,960
                                                                 =========  
=========


                                                  44

</TABLE>



     The utility net deferred tax liability represents the tax
effect, at presently enacted tax rates, of temporary differences
between the financial statement and tax bases of assets and
liabilities.  The portion of the utility net deferred tax
liability applicable to utility operations, which has not been
reflected in current service rates, represents income taxes
recoverable through future rates, net and is recorded as a
Deferred Charge on the balance sheet.  No valuation allowance for
deferred tax assets was required or recorded at December 31, 1996
and 1995.

     The Tax Reform Act of 1986 repealed the Investment Tax
Credit (ITC) for property placed in service after December 31,
1985, except for certain transition property.  ITC previously
earned on utility property continues to be normalized over the
remaining service lives of the related assets.  

     The Company and its subsidiary file a consolidated federal
income tax return.  The Company's federal income tax liabilities
for all years through 1992 have been finally determined.  The
Company is of the opinion that the final settlement of its
federal income tax liabilities for subsequent years will not have
a material adverse effect on its financial position.



                               45


(5)  Other Taxes
     -----------

Taxes, other than income taxes, charged to utility operating
expenses for each period are shown below.

-----------------------------------------------------------------
                                 1996          1995          1994
-----------------------------------------------------------------
                                    (Thousands of Dollars)

Gross receipts               $ 96,147      $ 95,158      $ 93,549

Property                       69,234        64,991        60,443

Payroll                        10,673        11,269        11,063

County fuel-energy             15,448        21,887        30,842

Environmental, use and
  other                         8,863         9,403        10,183
                             --------      --------      --------
                             $200,365      $202,708      $206,080
                             ========      ========      ========
----------------------------------------------------------------- 
                          

                                46


(6)  Jointly Owned Generating Facilities
     -----------------------------------

The Company owns a 9.72% undivided interest in the Conemaugh
Generating Station located near Johnstown, Pennsylvania,
consisting of two baseload units totaling 1,700 megawatts.  The
Company and other utilities own the station as tenants in common
and share costs and output in proportion to their ownership
shares.  Each owner has arranged its own financing relating to
its share of the facility.  In 1996, the owners collectively
arranged for interim tax-exempt financing, pending completion of
long-term tax-exempt financing arrangements, pursuant to approval
by the Indiana County Industrial Development Authority relating
to certain pollution control facilities constructed at the
Conemaugh Station.  Each owner separately entered into a loan
agreement for its share of the financing.  The Company's share of
the operating expenses of the station is included in the
Consolidated Statements of Earnings.  The Company's investment in
the Conemaugh facility of $88.7 million at December 31, 1996, and
$85.7 million at December 31, 1995, includes $.7 million and $1.3
million of Construction Work in Progress, respectively.



                                47


<TABLE>
(7) Common Equity

Changes in common stock, premium on stock and retained income are summarized
below.
<CAPTION>

------------------------------------------------------------------------------
---------
                                              Common Stock        Premium      
Retained
                                          Shares    Par Value     on Stock     
 Income
------------------------------------------------------------------------------
---------
                                                          (Thousands of Dollars)

<S>                                  <C>           <C>          <C>           <C>
Balance, December 31, 1993           117,797,652   $  117,798   $ 1,011,778   $ 
839,433

  Net income before net earnings
    from nonutility subsidiary                 -            -            -     
 208,074
  Nonutility subsidiary:
    Net earnings                               -            -            -     
  19,088
    Marketable securities net
      unrealized loss, net of tax              -            -            -     
 (23,879)
  Dividends:
    Preferred stock                            -            -            -     
 (16,437)
    Common stock                               -            -            -     
(195,755)
  Conversion of preferred stock            3,845            4            29    
       -
  Gain on acquisition of preferred
    stock                                      -            -           109    
       -
  Other capital reductions                     -            -           (66)   
       -
  Sale of common stock through
    Shareholder Dividend
    Reinvestment Plan                    355,198          355         6,603    
       -
  Issuance of common stock to
    Employee Savings Plans                91,408           91         2,236    
       -
                                     -----------   ----------   ----------   
----------
Balance, December 31, 1994           118,248,103      118,248     1,020,689    
 830,524

  Net income before net loss
    from nonutility subsidiary                 -            -            -     
 218,788
  Nonutility subsidiary:
    Net loss                                   -            -            -     
(124,397)
    Marketable securities net
      unrealized gain, net of tax              -            -            -     
  30,701
  Dividends:
    Preferred stock                            -            -            -     
 (16,851)
    Common stock                               -            -            -     
(196,469)
  Conversion of preferred stock            9,730           10            74    
       -
  Gain on acquisition of preferred
    stock                                      -            -             5    
       -
  Other capital reductions                     -            -           (23)   
       -
  Sale of common stock through
    Shareholder Dividend
    Reinvestment Plan                    158,501          159         2,881    
       -
  Issuance of common stock to
    Employee Savings Plans                78,243           78         1,462    
       -
                                     -----------   ----------   ----------   
----------
Balance, December 31, 1995           118,494,577      118,495     1,025,088    
 742,296

  Net income before net earnings
    from nonutility subsidiary                 -            -            -     
 220,066
  Nonutility subsidiary:
    Net earnings                               -            -            -     
  16,894
    Marketable securities net
      unrealized loss, net of tax              -            -            -     
  (5,755)
  Dividends:
    Preferred stock                            -            -            -     
 (16,604)
    Common stock                               -            -            -     
(196,612)
  Conversion of preferred stock            3,239            3            25    
       -
  Conversion of debentures                 2,221            2            58    
       -
  Other capital contributions                  -            -            16    
       -
                                     -----------   ----------   -----------  
----------
Balance, December 31, 1996           118,500,037   $  118,500   $ 1,025,187   $ 
760,285
                                     ===========   ==========   ===========  
==========



                                              48
</TABLE>


     The Company's Shareholder Dividend Reinvestment Plan (DRP)
provides that shares of common stock purchased through the plan
may be original issue shares or, at the option of the Company,
shares purchased in the open market.  The DRP permits additional
cash investments by plan participants limited to one investment
per month of not less than $25 and not more than $5,000.

     As of December 31, 1996, 35,900 shares of common stock were
reserved for issuance upon the conversion of convertible
preferred stock, 2,769,412 and 3,392,500 shares were reserved for
conversion of the 7% and 5% convertible debentures, respectively,
2,324,721 shares were reserved for issuance under the DRP and
1,221,624 shares were reserved for issuance under the Employee
Savings Plans.  Under the Stock Option Agreement with Baltimore
Gas and Electric Company, 23,579,900 shares could become
issuable, contingent upon specific events associated with
termination of the Merger Agreement.  See Note (13) Commitments
and Contingencies for additional information.

     Certain provisions of the Company's corporate charter,
relating to preferred and preference stock, would impose
restrictions on the payment of dividends under certain
circumstances.  No portion of retained income was so restricted
at December 31, 1996.


                                49


(8)  Serial Preferred Stock
     ----------------------

The Company has authorized 11,125,649 shares of cumulative $50
par value Serial Preferred Stock.  At December 31, 1996 and 1995,
there were outstanding 5,375,646 shares and 5,376,202 shares,
respectively.  The various series of Serial Preferred Stock
outstanding [excluding 2,869,696 shares of Redeemable Serial
Preferred Stock - See Note (9)] and the per share redemption
price at which each series may be called by the Company are as
follows.

-----------------------------------------------------------------
                                    Redemption      December 31,
                                       Price       1996      1995
-----------------------------------------------------------------
                                                  (Thousands of
                                                     Dollars)

$2.44 Series of 1957, 300,000 shares  $51.00   $ 15,000  $ 15,000
$2.46 Series of 1958, 300,000 shares  $51.00     15,000    15,000
$2.28 Series of 1965, 400,000 shares  $51.00     20,000    20,000
$3.82 Series of 1969, 500,000 shares  $51.00     25,000    25,000
$2.44 Convertible Series of 1966,
  5,950 and 6,506 shares,
  respectively                        $50.00        298       325
Auction Series A, 1,000,000 shares    $50.00     50,000    50,000
                                               --------  --------
                                               $125,298  $125,325
                                               ========  ========
-----------------------------------------------------------------

     The $2.44 Convertible Series of 1966 is convertible into
common stock of the Company at a price based upon a formula that
is subject to adjustment in certain events.  At December 31,
1996, 5.88 shares of common stock could be obtained upon the
conversion of each share of convertible preferred stock at the
then effective conversion price of $8.51 per share of common
stock.  The number of shares of this series converted into common
stock was 556 shares in 1996, 1,676 shares in 1995 and 656 shares
in 1994. 

     Dividends on the Serial Preferred Stock, Auction Series A,
are based on the rate determined by auction procedures prior to
each dividend period.  The maximum rate can range from 110% to
200% of the applicable "AA" Composite Commercial Paper Rate.  The
annual dividend rate is 4.2% ($2.10) for the period December 1,
1996 through February 28, 1997.  The average annual dividend
rates were 4.153% ($2.0765) in 1996 and 4.638% ($2.319) in 1995. 



                                50



(9)  Redeemable Serial Preferred Stock
     ---------------------------------

The outstanding series of $50 par value Redeemable Serial
Preferred Stock are shown below.

----------------------------------------------------------------- 
                                                 December 31,
                                                1996       1995   
----------------------------------------------------------------- 
                                           (Thousands of Dollars)

$3.37  Series of 1987, 869,696 shares       $ 43,485   $ 43,485
$3.89  Series of 1991, 1,000,000 shares       50,000     50,000
$3.40  Series of 1992, 1,000,000 shares       50,000     50,000
                                            --------   --------
                                             143,485    143,485
Redemption Requirement due within one
  year                                          (985)         -
                                            --------   --------
                                            $142,500   $143,485
                                            ========   ========
----------------------------------------------------------------

     The shares of the $3.37 (6.74%) Series are subject to
mandatory redemption, at par, through the operation of a sinking
fund.  Beginning June 1993, not less than 30,000 nor more than
60,000 shares will be redeemed annually.  The option to redeem in
excess of 30,000 shares annually is not cumulative; however,
shares which are acquired or redeemed by the Company other than
through the operation of the sinking fund may, at the option of
the Company, be applied toward the satisfaction of sinking fund
requirements.  Presently, the shares are callable for redemption
at a per share price of $52.25, which is reduced in succeeding
years, equaling par value beginning June 1, 2002.

     The shares of the $3.89 (7.78%) Series are subject to
mandatory redemption, at par, through the operation of a sinking
fund which will redeem not less than 165,000 nor more than
330,000 shares annually, beginning June 1, 2001, and 175,000
shares on June 1, 2006.  The option to redeem in excess of
165,000 shares annually is not cumulative.  The shares may be
called for redemption at any time at a per share price of $53.89,
which is reduced in succeeding years, equaling $50.98 beginning
June 1, 2003.


                                51



     The shares of the $3.40 (6.80%) Series are subject to
mandatory redemption, at par, through the operation of a sinking
fund which will redeem 50,000 shares annually, beginning
September 1, 2002, with the remaining shares redeemed on
September 1, 2007.  The shares are not redeemable prior to
September 1, 2002; thereafter, the shares are redeemable at par.

     In the event of default with respect to dividends, or
sinking fund or other redemption requirements relating to the
serial preferred stock, no dividends may be paid, nor any other
distribution made, on common stock.  Payments of dividends on all
series of serial preferred or preference stock, including series
which are redeemable, must be made concurrently.

     The sinking fund requirements through 2001 with respect to
the Redeemable Serial Preferred Stock are $1 million in 1997,
$1.5 million annually in 1998 through 2000, and $9.8 million in
2001. 


                                52


<TABLE>
(10) Long-Term Debt

<CAPTION>

Details of long-term debt are shown below.
------------------------------------------------------------------------------
------------------------
Interest                                                                       
      December 31,
 Rate                                   Maturity                               
   1996          1995
------------------------------------------------------------------------------
------------------------
                                                                              
(Thousands of Dollars)
<S>                                 <C>                                      <C> 
         <C>
First Mortgage Bonds
Fixed Rate Series:
4-3/8%                              February 15, 1998                        $ 
 50,000    $   50,000
4-1/2%                              May 15, 1999                               
 45,000        45,000
9%                                  April 15, 2000                             
100,000       100,000
5-1/8%                              April 1, 2001                              
 15,000        15,000
5-7/8%                              May 1, 2002                                
 35,000        35,000
6-5/8%                              February 15, 2003                          
 40,000        40,000
5-5/8%                              October 15, 2003                           
 50,000        50,000
6-1/2%                              September 15, 2005                         
100,000       100,000
6-1/2%                              March 15, 2008                             
 78,000        78,000
5-7/8%                              October 15, 2008                           
 50,000        50,000
5-3/4%                              March 15, 2010                             
 16,000        16,000
9%                                  June 1, 2021                               
100,000       100,000
6%                                  September 1, 2022                          
 30,000        30,000
6-3/8%                              January 15, 2023                           
 37,000        37,000
7-1/4%                              July 1, 2023                               
100,000       100,000
6-7/8%                              September 1, 2023                          
100,000       100,000
5-3/8%                              February 15, 2024                          
 42,500        42,500
5-3/8%                              February 15, 2024                          
 38,300        38,300
6-7/8%                              October 15, 2024                           
 75,000        75,000
7-3/8%                              September 15, 2025                         
 75,000        75,000
8-1/2%                              May 15, 2027                               
 75,000        75,000
7-1/2%                              March 15, 2028                             
 40,000        40,000
Variable Rate Series:
Adjustable rate                     December 1, 2001                           
 50,000        50,000
                                                                            
----------    ----------
  Total First Mortgage Bonds                                                 
1,341,800     1,341,800

Convertible Debentures
5%                                  September 1, 2002                          
115,000       115,000
7%                                  January 15, 2018                           
 65,367        66,747

Medium-Term Notes
6.25%                               May 28, 1996                               
      -        25,000
6.66% to 6.73%                      May 1997                                   
100,000       100,000
9.08%                               July and August 1997                       
 50,000        50,000
6.53%                               December 17, 2001                          
100,000             -
7.46% to 7.60%                      January 2002                               
 40,000        40,000
7.64%                               January 17, 2007                           
 35,000        35,000
6.25%                               January 20, 2009                           
 50,000        50,000
7%                                  January 15, 2024                           
 50,000        50,000
                                                                            
----------    ----------
  Total Utility Long-Term Debt                                               
1,947,167     1,873,547
Net unamortized discount                                                       
(28,109)      (30,190)
Current portion                                                               
(151,460)      (26,280)
                                                                            
----------    ----------
  Net Utility Long-Term Debt                                                
$1,767,598    $1,817,077
                                                                            
==========    ==========

Nonutility Subsidiary Long-Term Debt
Varying rates through 2011                                                   $ 
996,232    $1,047,484
                                                                            
==========    ==========


                                                   53

</TABLE>



Utility Long-Term Debt
----------------------

The outstanding First Mortgage Bonds (bonds) are secured by a
lien on substantially all of the Company's property and plant. 
Additional bonds may be issued under the mortgage as amended and
supplemented in compliance with the provisions of the indenture. 

     In December 1996, the Company issued $100 million of 6.53%
Medium-Term Notes.  The proceeds were used to reduce short-term
debt and to fund ongoing construction and operating activities.  

     The interest rate on the $50 million Adjustable Rate series
First Mortgage Bonds is adjusted annually on December 1, based
upon 116% of the 10-year "constant maturity" United States
Treasury bond rate for the preceding three-month period ended
October 31.  Effective December 1, 1996, the applicable interest
rate is 7.867%.  The applicable interest rate was 7.443% at
December 1, 1995, and 8.68% at December 1, 1994.

     The 7% Convertible Debentures are convertible into shares of
common stock at a conversion price of $27 per share.

     The 5% Convertible Debentures are convertible into shares of
common stock at a conversion rate of 29-1/2 shares for each
$1,000 principal amount.

     The aggregate amounts of maturities for the Company's long-
term debt outstanding at December 31, 1996, are $151.5 million in
1997, $50 million in 1998, $45 million in 1999, $100 million in
2000 and $165 million in 2001.

Nonutility Subsidiary Long-Term Debt
------------------------------------

Long-term debt at December 31, 1996, consisted of $932.2 million
of recourse debt from institutional lenders maturing at various
dates between 1997 and 2003.  The interest rates of such
borrowings ranged from 5% to 10.1%.  The weighted average
interest rate was 7.44% at December 31, 1996, 7.66% at December
31, 1995, and 7.47% at December 31, 1994.  Annual aggregate
principal repayments are $194 million in 1997, $300.7 million in
1998, $170 million in 1999, $115 million in 2000, $54 million in
2001 and $98.5 million thereafter.



                                54


     Long-term debt also includes $64 million of non-recourse
debt, $36.1 million of which was secured by aircraft currently
under operating lease.  The debt is payable in monthly
installments at rates of LIBOR (London Interbank Offered Rate)
plus 1.25% and LIBOR plus 1.375% with final maturity on March 15,
2002.  Non-recourse debt of $27.9 million is related to PCI's
majority-owned real estate partnerships of which $15.2 million is
due in consecutive monthly installments with maturity on May 11,
2001, based on a 30-year amortization period at a fixed rate of
interest of 9.05%.  An additional $4.7 million is payable in
quarterly installments, at a fixed interest rate of 7%, with
final maturity on December 31, 1999.  The remaining non-recourse
real estate debt consists of $8 million payable in monthly
installments at a fixed rate of interest of 9.66% with final
maturity on October 1, 2011. 


                                55


<TABLE>
(11) Fair Value of Financial Instruments
----------------------------------------

The estimated fair values of the Company's financial instruments at December 31,
1996,
and 1995 are shown below.
<CAPTION>


------------------------------------------------------------------------------
------------------
                                                           December 31,
                                               1996                            
1995
------------------------------------------------------------------------------
------------------
                                      Carrying         Fair            Carrying 
       Fair
                                       Amount          Value            Amount 
        Value
                                    -----------     -----------      ----------- 
   -----------
                                                       (Thousands of Dollars)
<S>                                 <C>              <C>              <C>      
      <C>
Utility
  Capitalization and Liabilities
    Serial preferred stock          $  125,298         113,285          125,325 
       114,590
    Redeemable serial
      preferred stock               $  142,500         146,491          143,485 
       145,046
    Long-term debt
      First mortgage bonds          $1,327,389       1,319,976        1,326,560 
     1,385,609
      Medium-term notes             $  272,788         274,242          323,007 
       336,351
      Convertible debentures        $  167,421         171,880          167,510 
       174,054

Nonutility Subsidiary
  Assets
    Marketable securities           $  377,237         377,237          530,323 
       530,323
    Notes receivable                $   72,251          71,593           62,175 
        63,184
  Liabilities
    Long-term debt                  $  996,232       1,011,814        1,047,484 
     1,071,354
------------------------------------------------------------------------------
------------------


                                                     56

</TABLE>



     The methods and assumptions below were used to estimate, at
December 31, 1996 and 1995, the fair value of each class of
financial instruments shown above for which it is practicable to
estimate that value.

     The fair value of the Company's long-term debt, which
includes First Mortgage Bonds, Medium-Term Notes and Convertible
Debentures, excluding amounts due within one year, was based on
the current market price, or for issues with no market price
available, was based on discounted cash flows using current rates
for similar issues with similar terms and remaining maturities.

     The fair value of the Company's Serial Preferred Stock,
including Redeemable Serial Preferred Stock, excluding amounts
due within one year, was based on quoted market prices or
discounted cash flows using current rates of preferred stock with
similar terms.

     The fair value of PCI's Marketable Securities was based on
quoted market prices.

     The fair value of PCI's Notes Receivable was based on
discounted future cash flows using current rates and similar
terms.

     The fair value of PCI's long-term debt, including non-
recourse debt, was based on current rates offered to similar
companies for debt with similar remaining maturities.

     The carrying amounts of all other financial instruments
approximate fair value.

(12)  Short-Term Debt
      ---------------

The Company's short-term financing requirements have been
satisfied principally through the sale of commercial promissory
notes.  Interest rates for the Company's short-term financing
during the year ranged from 5.3% to 6.0%.

     The Company maintains a minimum 100% line of credit back-up
for its outstanding commercial promissory notes, which was unused
during 1996, 1995 and 1994.


                                57


Nonutility Subsidiary Short-Term Notes Payable
----------------------------------------------

The nonutility subsidiary's short-term financing requirements
have been satisfied principally through the sale of commercial
promissory notes.

     The nonutility subsidiary maintains a minimum 100% line of
credit back-up for its outstanding commercial promissory notes,
which was unused during 1996, 1995 and 1994. 

(13)  Commitments and Contingencies
      -----------------------------

Proposed Merger
---------------

The Company entered into an Agreement and Plan of Merger with
Baltimore Gas and Electric Company (BGE) in September 1995.  This
Agreement provides for a strategic business combination in which
each company will merge into Constellation Energy Corporation
(Constellation Energy), a newly formed company to create an
integrated, non-holding company structure (the Merger).  Each
outstanding share of the Company's common stock will be converted
into the right to receive .997 of a share of common stock of
Constellation Energy and each outstanding share of BGE common
stock will be converted into the right to receive one share of
Constellation Energy's common stock.  This transaction is
expected to qualify as a tax-free exchange of shares for the
holders of each company's common stock and as a pooling of
interests for accounting purposes.  Constellation Energy will
serve a population of approximately 4.5 million with
approximately 1.8 million electric customers and over 530,000
natural gas customers.  Preliminary estimates indicate that
savings from the combined utility systems will approximate $1.3
billion over 10 years following the Merger.  These savings are
net of costs to achieve presently estimated to be approximately
$150 million.  Approximately two-thirds of the projected savings
are expected to result from reduced labor costs, with the
remaining savings split between nonfuel purchasing and corporate
and administrative programs.  The allocation of the net savings
between customers and shareholders of Constellation Energy will
be determined in regulatory proceedings.  The applications for
approval of the Merger, filed with the various regulatory
commissions, set forth the proposed plans for Constellation
Energy to share the benefits of the Merger with customers in the
District of Columbia and Maryland.  The proposal includes:  1) a
freeze on base electric rates until at least January 1, 2000, 2)
a unique bill credit for all customers if Constellation Energy
achieves certain financial targets, 3) an array of economic
development incentives, and 4) programs to address the energy
needs of low-income customers.  The development of estimated
savings resulting from the Merger was based upon assumptions 


                                58


which involve judgments with respect to, among other things,
future national and regional economic and competitive conditions,
inflation rates, regulatory treatment, weather conditions,
financial market conditions, interest rates, future business
decisions and other uncertainties, all of which are difficult to
predict and many of which are beyond the control of the Company
and BGE.  Accordingly, while the Company believes that such
assumptions are reasonable for purposes of the development of
estimates of potential savings, there can be no assurance that
such assumptions will approximate actual experience or that all
such savings will be realized.  At December 31, 1996, the Company
has deferred $29 million in costs related to the Merger.

     Shareholders of the Company and BGE, at separate special
meetings on March 29, 1996, approved the Merger Agreement.  The
Company and BGE filed a joint Application for Authorization and
Approval of the Merger with the FERC on January 11, 1996, and on
April 8, 1996, with the Maryland and District of Columbia Public
Service Commissions.  On July 31, 1996, FERC set the application
for hearing on the issue of whether the Merger would impact
competition.  Hearings began on October 21, 1996, and the
Administrative Law Judge certified the record to the Commission
on October 25, 1996.  The case was placed before FERC for
decision in December 1996.  The Maryland Commission conducted
hearings during June, September and December 1996.  The case was
placed before the Maryland Commission for decision in January
1997.  A prehearing conference was conducted by the District of
Columbia Commission in May 1996 and a procedural schedule was
published on July 19, 1996.  The hearings, which were originally
scheduled to take place in December 1996, have been rescheduled
for February 1997.  The case is expected to be before the
District of Columbia Commission for decision in March 1997.  The
Nuclear Regulatory Commission has approved the transfer of BGE's
ownership interest in the operating licenses for the two
generating units at the Calvert Cliffs Nuclear Power Plant to
Constellation Energy at the effective time of the Merger.  In
addition, the State Corporation Commission of Virginia has
approved the Merger.  The Merger also requires approval from the
Pennsylvania Public Utility Commission.  Completion of the
approval process is expected to take until the end of the first
quarter of 1997.

     If the Merger Agreement is terminated by either the Company
or BGE due to a material breach by the other party, the breaching
party must pay the non-breaching party, as liquidated damages,
$10 million in cash in respect of out-of-pocket expenses.  The
Merger Agreement also requires payment of a termination fee of
$75 million in cash, plus $10 million in cash in respect of out-
of-pocket expenses, by one party to the other if the Merger
Agreement is terminated under certain circumstances, including if
either the Company or BGE terminates the Merger Agreement after
the Board of Directors of the other party withdraws or adversely
modifies its recommendation of the transaction.  The termination  


                                59     


fees payable by the Company under these provisions and the
aggregate amount which could be payable by the Company upon a
required repurchase of an option (or shares of common stock
issued pursuant to the exercise of the option) granted by the
Company to BGE in connection with entry into the Merger Agreement
may not exceed $125 million in the aggregate.
 
     The Company has approved, in conjunction with the Merger
with BGE, a severance plan for all exempt and non-bargaining unit
employees who lose employment due to the Merger.  Employees who
lose employment as a result of the Merger will receive two weeks
of pay per year of service, with a minimum payment of eight weeks
of pay.  In addition, employees will receive company-sponsored
health and dental insurance for two weeks for each year of
service, with a minimum of eight weeks of insurance coverage.  

     An extension of the current 1993 Labor Agreement between the
Company and Local 1900 of the International Brotherhood of
Electrical Workers was ratified by the Union members in December
1995.  The 1995 Agreement extends the 1993 Agreement, which was
due to expire on June 1, 1996, for two years or until the
effective date of the Merger with BGE, whichever occurs first. 
This Agreement provides severance benefits, previously approved
by the Company for exempt and non-bargaining unit employees, for
all union members and provided for a lump-sum payment of 2% of
base pay on January 5, 1996, a lump-sum payment of 1% of base pay
on June 7, 1996, and a lump-sum payment of 3% of base pay to be
paid on June 6, 1997, or the effective date of the Merger,
whichever occurs first.

Leases
------

The Company leases its general office building and certain data
processing and duplicating equipment, motor vehicles,
communication system and construction equipment under long-term
lease agreements.  The lease of the general office building
expires in 2002 and leases of equipment extend for periods of up
to six years.  Charges under such leases are accounted for as
operating expenses or construction expenditures, as appropriate.

     Rents, including property taxes and insurance, net of rental
income from subleases, aggregated approximately $16.2 million in
1996, $15.6 million in 1995 and $14.9 million in 1994.  The
approximate annual commitments under all operating leases,
reduced by rentals to be received under subleases are $14.6
million in 1997, $7.8 million in 1998, $6.6 million in 1999, $5.4
million in 2000, $4.3 million in 2001 and a total of $6.2 million
in the years thereafter.

     The Company entered into a sale (at cost) and leaseback
agreement, in December 1994, for its control center system
(system).  The system is an integrated energy management system 


                                60


used by the Company's power dispatchers to centrally control the
operation of the Company's electric system, which consists of all
of its generating units, the transmission system and the
distribution system.  The lease of the system is accounted for as
a capital lease, and was recorded at the present value of future
lease payments which totaled $152 million.  The lease requires
semi-annual payments of $7.6 million over a 25-year period and
provides for transfer of ownership of the system to the Company
for $1 at the end of the lease term.  Under SFAS No. 71, the
amortization of leased assets is modified so that the total of
interest on the obligation and amortization of the leased asset
is equal to the rental expense allowed for ratemaking purposes. 
This lease has been treated as an operating lease for ratemaking
purposes.

Fuel Contracts 
--------------

The Company has numerous coal contracts with various expiration
dates through 2003 for aggregate annual deliveries of
approximately 3.2 million tons.  Deliveries under these contracts
are expected to provide approximately 54% of the estimated system
coal requirements in 1997.  Approximately 46% of the estimated
system coal requirements in 1997 will be purchased under shorter
term agreements and on a spot basis from a variety of suppliers. 
Prices under the Company's coal contracts are generally
determined by reference to base amounts adjusted to reflect
provisions for changes in suppliers' costs, which in turn are
determined by reference to published indices and limited by
current market prices.

Capacity Purchase Agreements
----------------------------

The Company's long-term capacity purchase agreements with Ohio
Edison and APS commenced June 1, 1987, and are expected to
continue at the 450 megawatt level through 2005.  Under the terms
of the agreements with Ohio Edison and APS, the Company is
required to make capacity payments, subject to certain
contingencies, which include a share of Ohio Edison's fixed
operating and maintenance cost.  The Company also has a 25-year
agreement with Panda Brandywine L.P. (Panda) for 230 megawatts of
capacity supplied by a gas-fueled combined-cycle cogenerator,
which achieved full commercial operation in October 1996.  The
Company began purchasing energy from the Panda facility in August
1996 and capacity payments under this agreement commence in
January 1997.  The capacity commitment under these agreements,
including a share of Ohio Edison's fixed operating and
maintenance cost, are estimated at $141 million in 1997, $139
million in 1998, $200 million in 1999 and 2000, $211 million in
2001 and $1.7 billion in the years thereafter.



                                61    



     The Company began a 25-year purchase agreement in June 1990  
with SMECO for 84 megawatts of capacity supplied by a combustion
turbine installed and owned by SMECO at the Company's Chalk Point
Generating Station.  The Company is responsible for all costs
associated with operating and maintaining the facility.  The
Company is accounting for this agreement as a capital lease,
recorded at fair market value which totaled $37.1 million at the
date construction was complete.  The capacity payment to SMECO is
approximately $5.5 million per year.  Under SFAS No. 71,
amortization of leased assets is modified so that the total of
interest on the obligation and amortization of the leased asset
is equal to rental expense allowed for ratemaking purposes.  This
agreement has been treated as an operating lease for ratemaking
purposes.

     In November 1996, the Company filed a request with the
Maryland Public Service Commission for approval of a purchased
capacity surcharge designed to recover capacity payments under
the Panda contract, which commenced January 1, 1997, as well as
other changes in the level of purchased capacity costs from
levels included in base rates.  The estimated 1997 Maryland
portion of these payments is $10.5 million.  On January 8, 1997,
the Maryland Public Service Commission suspended the Company's
request for a period of 90 days from January 8, 1997, or until
the date of a Commission Order in the Joint Application for
Authorization and Approval for the Merger with BGE, whichever
comes first.  The District of Columbia portion of the Panda
capacity costs will be recovered through the existing fuel
adjustment clause.

Environmental Contingencies
---------------------------

The Company is subject to contingencies associated with
environmental matters, principally related to possible
obligations to remove or mitigate the effects on the environment
of the disposal of certain substances at the sites discussed
below.

     In October 1994, a Remedial Investigation/Feasibility Study
(RI/FS) report was submitted to the U.S. Environmental Protection
Agency (EPA) with respect to a site in Philadelphia,
Pennsylvania.  Pursuant to an agreement among the potentially
responsible parties (PRPs), the Company is responsible for 12% of
the costs of the RI/FS.  Total costs of the RI/FS and associated
activities prior to the issuance of a Record of Decision (ROD) by
the EPA, including legal fees, are currently estimated to be $7.5
million.  The Company has paid $.9 million as of December 31,
1996.  The report included a number of possible remedies, the
estimated costs of which range from $2 million to $90 million. 
In July 1995, the EPA announced its proposed remedial action plan
for the site and indicated it will accept comments on the plan
from any interested parties.  The EPA's estimate of the costs 


                                62


associated with implementation of the plan is approximately $17
million.  The Company cannot predict whether the EPA will include
the plan in its ROD as proposed or make changes as a result of
comments received.  In addition, the Company cannot estimate the
total extent of the EPA's administrative and oversight costs.  To
date, the Company has accrued $1.7 million for its share of this
contingency.

     In October 1995, the Company received notice from the EPA
that it, along with several hundred other companies, may be a PRP
in connection with the Spectron Superfund Site located in Elkton,
Maryland.  The site was operated as a hazardous waste disposal,
recycling, and processing facility from 1961 to 1988.  A group of
PRPs allege, based on records they have collected, that the
Company's share of liability at this site is .0042%.  The EPA has
also indicated that a de minimis settlement is likely to be
appropriate for this site.  While the outcome of negotiations and
the ultimate liability with respect to this site cannot be
predicted, the Company believes that its liability at this site
will not have a material adverse effect on its financial position
or results of operations.

     In December 1995, the Company received notice from the EPA
that it is a PRP under the Comprehensive Environmental Response
Compensation and Liability Act (CERCLA or Superfund) with respect
to the release or threatened release of radioactive and mixed
radioactive and hazardous wastes at a site in Denver, Colorado
operated by RAMP Industries, Inc.  Evidence indicates that the
Company's connection to the site arises from an agreement with a
vendor to package, transport and dispose of two laboratory
instruments containing small amounts of radioactive material at a
Nevada facility.  While the Company cannot predict its liability
at this site, the Company believes that it will not have a
material adverse effect on its financial position or results of
operations.

Litigation
----------

During 1993, the Company was served with Amended Complaints filed
in three jurisdictions (Prince George's County, Baltimore City,
and Baltimore County), in separate ongoing, consolidated
proceedings each denominated "In re: Personal Injury Asbestos
Case."  The Company (and other defendants) were brought into
these cases on a theory of premises liability under which
plaintiffs argue that the Company was negligent in not providing
a safe work environment for employees of its contractors who
allegedly were exposed to asbestos while working on the Company's
property.  Initially, a total of approximately 448 individual
plaintiffs added the Company to their Complaints.  While the
pleadings are not entirely clear, it appears that each plaintiff
seeks $2 million in compensatory damages and $4 million in
punitive damages from each defendant.  


                                63


In a related proceeding in the Baltimore City case, the Company
was served, in September 1993, with a third party complaint by
Owens Corning Fiberglass, Inc. (Owens Corning) alleging that
Owens Corning was in the process of settling approximately 700
individual asbestos-related cases and seeking a judgment for
contribution against the Company on the same theory of alleged
negligence set forth above in the plaintiffs' case. 
Subsequently, Pittsburgh Corning Corp. (Pittsburgh Corning) filed
a third party complaint against the Company, seeking contribution
for the same plaintiffs involved in the Owens Corning third party
complaint.  Since the initial filings in 1993, approximately 50
individual suits have been filed against the Company.  The third
party complaints involving Pittsburgh Corning and Owens Corning
were dismissed by the Baltimore City Court during 1994 without
any payment by the Company.  In 1995 and 1996, approximately 400
of the individual plaintiffs have dismissed their claims against
the Company.  No payments were made by the Company in connection
with the dismissals.  While the aggregate amount specified in the
remaining suits would exceed $400 million, the Company believes
the amounts are greatly exaggerated as were the claims already
disposed of.  The amount of total liability, if any, and any
related insurance recovery cannot be precisely determined at this
time; however, based on information and relevant circumstances
known at this time, the Company does not believe these suits will
have a material adverse effect on its financial position. 
However, an unfavorable decision rendered against the Company
could have a material adverse effect on results of operations in
the fiscal year in which a decision is rendered.

     The Company is involved in other legal and administrative
(including environmental) proceedings before various courts and
agencies with respect to matters arising in the ordinary course
of business.  Management is of the opinion that the final
disposition of these proceedings will not have a material adverse
effect on the Company's financial position or results of
operations.


                                64   


(14)  Supplemental Disclosure of Cash Flow Information
      ------------------------------------------------

Listed below is supplemental disclosure of cash flow information.

-----------------------------------------------------------------
                                         1996      1995      1994 
-----------------------------------------------------------------
                                        (Thousands of Dollars)
                                         
Cash paid for:
  Interest, net of capitalized        
    interest (including nonutility 
    subsidiary interest of $83,389, 
    $93,672 and $83,724)             $216,967  $223,789  $203,013
 
  Income taxes                       $ 28,555  $ 44,725  $ 51,368
 
-----------------------------------------------------------------

     For purposes of the consolidated financial statements, cash
and cash equivalents include cash on hand, money market funds and
commercial paper with original maturities of three months or
less.


                                65 


(15)  Selected Nonutility Subsidiary Financial Information
      ----------------------------------------------------

Selected financial information of the Company's consolidated,
wholly owned nonutility investment subsidiary, Potomac Capital
Investment Corporation (PCI) and its subsidiaries, is presented
below.  Subsidiary equity at December 31, 1996, and December 31,
1995, was $196.3 million and $168.4 million, respectively.  These
amounts include $1.1 million and $6.8 million of unrealized
appreciation, at December 31, 1996 and 1995, respectively,
relating to the marketable securities portfolio on an after-tax
basis.  PCI paid a $9 million dividend to the parent Company in
1995. 

----------------------------------------------------------------- 
                                        For the year ended     
                                            December 31,
                                    1996        1995        1994
----------------------------------------------------------------
                                   (Thousands of Dollars)     
Income
  Leasing activities           $ 91,661    $ 100,640    $111,262
  Marketable securities          33,690       36,121      35,148
  Other                         (10,385)      (2,268)        596
                               --------    ---------    --------
                                114,966      134,493     147,006
                               --------    ---------    --------
Expenses
  Interest                       83,442       91,637      84,783
  Administrative and general     15,529       10,479      10,259
  Depreciation and operating     40,982       72,404      55,571
  Loss on assets held for 
    disposal                     12,744      170,078           -
  Income tax credit             (54,625)     (85,708)    (22,695)
                               --------    ---------    --------
                                 98,072      258,890     127,918
                               --------    ---------    --------
  Net earnings (loss) from
    nonutility subsidiary      $ 16,894    $(124,397)   $ 19,088 
                               =========   =========    ========




                                66               



Marketable Securities
---------------------

PCI's marketable securities are classified as available-for-sale
for financial reporting purposes.  Investment grade preferred
stocks with mandatory redemption features made up 95% of the
portfolio at December 31, 1996.  Net unrealized gains and losses
on such securities are reflected, net of tax, in stockholder's
equity.



                                67



<TABLE>
<CAPTION>

------------------------------------------------------------------------------
-------------
                                                           December 31,
                                            1996                               
      1995
                         
-----------------------------------------------------------------
                                                       Net
                                         Market    Unrealized                  
   Market
                             Cost        Value     Gain (Loss)         Cost    
   Value
------------------------------------------------------------------------------
-------------
                                                     (Thousands of Dollars)
<S>                      <C>          <C>          <C>             <C>         
<C>
Mandatory redeemable
  preferred stock        $  375,595   $  377,237   $     1,642     $  519,488  
$  530,115
Equity securities                 3            -            (3)           341  
       208
                         ----------   ----------   -----------     ----------  
----------
  Total                  $  375,598   $  377,237   $     1,639     $  519,829  
$  530,323
                         ==========   ==========   ===========     ==========  
==========
------------------------------------------------------------------------------
-------------



                                                 68
</TABLE>


     Included in net unrealized gains and losses are gross
unrealized gains of $9.9 million and gross unrealized losses of
$8.3 million at December 31, 1996, and gross unrealized gains of
$17.1 million and gross unrealized losses of $6.6 million at
December 31, 1995.

     In determining gross realized gains and losses on sales or
maturities of securities, specific identification is used.  Gross
realized gains were $4.7 million and $.8 million for 1996 and
1995, respectively.  Gross realized losses were $1.1 million and
$.4 million for 1996 and 1995, respectively. 

     At December 31, 1996, the contractual maturities for
mandatory redeemable preferred stock are $7.1 million within one
year, $72.8 million from one to five years, $100.2 million from
five to 10 years and $195.6 million for over 10 years. 



                                69


Leasing Activities 
------------------ 

PCI's net investment in finance leases is summarized below.

-----------------------------------------------------------------
                                                  December 31,
                                                1996        1995
-----------------------------------------------------------------
                                           (Thousands of Dollars)

Rents receivable                            $711,961    $680,135
Estimated residual values                    102,590     100,590
Less: Unearned and deferred income          (329,579)   (341,930)
                                            --------    --------
Investment in finance leases                 484,972     438,795
Less: Deferred taxes arising from 
  finance leases                            (144,667)   (115,582)
                                            --------    --------
  Net investment in finance leases          $340,305    $323,213
                                            ========    ========
-----------------------------------------------------------------

     Minimum lease payments receivable from finance leases,
primarily aircraft, for each of the years 1997 through 2001 are
$27.9 million, $33 million, $34.5 million, $37.3 million and
$36.7 million, respectively.  Net income from leveraged leases
was $22.5 million in 1996, $11 million in 1995 and $5.6 million
in 1994.

     Rent payments receivable from aircraft equipment operating
leases for each of the years 1997 through 2001 are $41 million in
1997, $33.6 million in 1998, $29.5 million in 1999, $26 million
in 2000 and $22 million in 2001.

     During 1995, PCI purchased from and leased back to an
Australian governmental entity two 350 megawatt (gross) coal-
fired electric generating units located in Queensland, Australia. 
PCI's original equity investment totaled $96 million and is being
accounted for as a leveraged lease.

     During 1994, PCI purchased from and leased back to a Dutch
electric utility company an approximate one-third undivided
interest in a recently constructed 650 megawatt (gross) baseload,
coal and gas-fired power plant located in The Netherlands.  PCI's
original equity investment totaled $60 million and is accounted
for as a leveraged lease.



                                70


<TABLE>
(16) Quarterly Financial Summary (Unaudited)
<CAPTION>
------------------------------------------------------------------------------
---------------------------------------
                                                          1st          2nd     
    3rd          4th
                                                        Quarter      Quarter   
  Quarter      Quarter       Total
------------------------------------------------------------------------------
---------------------------------------
                                                              (Thousands of
Dollars except Per Share Data)
<S>                                                  <C>              <C>      
   <C>          <C>        <C>
1996
Operating Revenue                                    $   385,272      462,705  
   614,357      372,523    1,834,857
Total Revenue                                        $   436,593      501,780  
   658,225      413,713    2,010,311
Operating Expenses                                   $   392,566      406,437  
   491,963      370,906    1,661,872
Operating Income                                     $    44,027       95,343  
   166,262       42,807      348,439
Net Income                                           $    14,734       72,253  
   138,687       11,286      236,960
Earnings for Common Stock                            $    10,574       68,116  
   134,536        7,130      220,356
Earnings Per Common Share                            $       .09          .57  
      1.14          .06         1.86
Dividends Per Share                                  $      .415         .415  
      .415         .415         1.66

1995
Operating Revenue                                    $   363,433      440,455  
   642,511      376,033    1,822,432
Total Revenue                                        $   364,909      445,359  
   663,584      402,250    1,876,102
Operating Expenses                                   $   334,091      354,120  
   480,348      359,802    1,528,361
Operating Income                                     $    30,818       91,239  
   183,236       42,448      347,741
Net (Loss) Income                                    $    (3,972)     (56,838) 
   145,947        9,254       94,391
(Loss) Earnings for Common Stock                     $    (8,213)     (61,072) 
   141,747        5,078       77,540
(Loss) Earnings Per Common Share                     $      (.07)        (.52) 
      1.20          .04          .65
Dividends Per Share                                  $      .415         .415  
      .415         .415         1.66

1994
Operating Revenue                                    $   374,910      458,431  
   605,023      352,236    1,790,600
Total Revenue                                        $   393,044      467,451  
   607,476      355,103    1,823,074
Operating Expenses                                   $   355,708      370,439  
   447,020      325,414    1,498,581
Operating Income                                     $    37,336       97,012  
   160,456       29,689      324,493
Net Income                                           $    14,414       64,293  
   134,702       13,753      227,162
Earnings for Common Stock                            $    10,268       60,224  
   130,576        9,657      210,725
Earnings Per Common Share                            $       .09          .51  
      1.11          .08         1.79
Dividends Per Share                                  $      .415         .415  
      .415         .415         1.66


The Company's sales of electric energy are seasonal and, accordingly,
comparisons by quarter within a year are not meaningful.
   The total of the four quarterly earnings per share may not equal
the earnings per share for the year due to changes in the number of
common shares outstanding during the year.



                                                          71
</TABLE>


<TABLE>
Stock Market Information
<CAPTION>
------------------------------------------------------------------------------
------------------------------------------------------
1996                                     High         Low          1995        
                           High         Low
------------------------------------------------------------------------------
------------------------------------------------------
<S>                                      <C>          <C>          <C>         
                           <C>          <C>
1st Quarter                              $27-3/8      $24-1/2      1st Quarter 
                           $20-1/8      $18-3/8
2nd Quarter                              $26-5/8      $24-3/8      2nd Quarter 
                           $22-1/2      $18-1/2
3rd Quarter                              $26-3/4      $24          3rd Quarter 
                           $24-5/8      $20-1/2
4th Quarter                              $27-3/8      $23-5/8      4th Quarter 
                           $26-1/4      $24
(Close $25-3/4)                                                    (Close
$26-1/4)
Shareholders at December 31, 1996: 89,620
------------------------------------------------------------------------------
------------------------------------------------------
</TABLE>
<TABLE>
Selected Consolidated Financial Data
<CAPTION>
------------------------------------------------------------------------------
------------------------------------------------------
                                              1996         1995         1994   
     1993         1992          1991         1986
------------------------------------------------------------------------------
------------------------------------------------------
                                                                   (Thousands
except Per Share Data)
<S>                                     <C>           <C>          <C>         
<C>          <C>           <C>          <C>
Operating Revenue                       $1,834,857    1,822,432    1,790,600   
1,702,442    1,562,167     1,552,066    1,370,542

Total Revenue                           $2,010,311    1,876,102    1,823,074   
1,725,205    1,601,558     1,619,315    1,398,902

Operating Expenses                      $1,661,872    1,528,361    1,498,581   
1,400,543    1,322,105     1,329,084    1,128,801

Net Earnings (Loss) from
  Nonutility Subsidiary                 $   16,894     (124,397)      19,088   
   25,101       28,161        23,351       26,729

Income Before Extraordinary Gain
  and Cumulative Effect of Accounting
  Change                                $  236,960       94,391      227,162   
  241,579      200,760       210,164      206,053

Extraordinary Gain, Net of Income
  Taxes                                 $        -            -            -   
        -            -             -       21,680

Cumulative Effect of Accounting
  Change, Net of Income Taxes           $        -            -            -   
        -       16,022             -            -

Net Income                              $  236,960       94,391      227,162   
  241,579      216,782       210,164      227,733

Earnings for Common Stock               $  220,356       77,540      210,725   
  225,324      202,390       197,866      215,900

Average Common Shares Outstanding          118,497      118,412      118,006   
  115,640      112,390       105,911       94,255

Earnings (Loss) Per Common Share
  Utility Operations                    $     1.72         1.70         1.63   
     1.73         1.55 <F1>     1.65         2.01 <F2>
  Nonutility Subsidiary                 $     0.14        (1.05)         .16   
      .22          .25           .22          .28
    Consolidated                        $     1.86          .65         1.79   
     1.95         1.80 <F1>     1.87         2.29 <F2>

Cash Dividends Per Common Share         $     1.66         1.66         1.66   
     1.64         1.60          1.56         1.18

Investment in Property and Plant        $6,321,591    6,161,103    5,974,170   
5,701,550    5,404,265     5,084,964    3,497,471

Net Investment in Property
  and Plant                             $4,423,249    4,400,311    4,334,399   
4,167,551    3,967,898     3,743,709    2,543,162

Utility Assets                          $5,526,266    5,503,087    5,327,606   
5,036,737    4,515,403     4,211,556    2,961,261

Nonutility Subsidiary Assets            $1,365,620    1,615,063    1,674,289   
1,665,132    1,663,508     1,679,079      460,189

Total Assets                            $6,891,886    7,118,150    7,001,895   
6,701,869    6,178,911     5,890,635    3,421,450

Long-Term Utility Obligations
  (including redeemable preferred
  stock)                                $1,910,098    1,960,562    1,866,962   
1,736,621    1,727,609     1,662,157    1,071,942

------------------------------------------------------------------------------
------------------------------------------------------
<FN>
<F1>Includes $.14 as the cumulative effect of an accounting change for unbilled
revenue.
<F2>Includes $.23 as the effect of an extraordinary gain on sale of Virginia
service territory.
</FN>


                                                                          72
</TABLE>


                                                       Appendix A




1.  The Use of Revenue pie chart presents the following
    information.


    (Thousands of Dollars)

    1996 Use of Revenue
    -------------------

    Fuel and Purchased Energy           $  663,770            33%
    Wages and Benefits                     174,210             9 
    Materials and Services                 111,253             5
    Capacity Purchase Payments             125,786             6
    Taxes                                  335,913            17*
    Depreciation and Amortization          223,016            11*
    Interest                               139,403             7*
    Common Stock Dividends                 196,612            10*
    Preferred Stock Dividends               16,604             1*
    Retained Income                         23,744             1*
                                        ----------           --- 
                 
                                        $2,010,311           100%
                                        ==========           ===




*Plant-Related Costs



                                                       Appendix A

 


2.  The Cooling Degree Hours bar chart presents the following
    information.


                                             % of
                                            20-Year
                    Year                    Average 
                    ----                    -------

                    1992                       61%

                    1993                      119%

                    1994                      103%

                    1995                      103%

                    1996                       83%




                                                       Appendix A




3.  The System Fuel Costs line chart presents the following
    information.


    Year         Coal          Oil          Gas           System
    ----         ----          ---          ---           ------
 
    1987        $1.64         $2.97        $2.69          $1.81

    1988         1.67          2.74         2.32           1.84

    1989         1.69          2.78         2.52           1.95

    1990         1.77          3.00         2.34           1.94

    1991         1.78          2.76         2.18           1.93

    1992         1.72          2.50         2.32           1.85

    1993         1.72          2.55         2.88           1.90

    1994         1.73          2.70         2.49           1.95

    1995         1.60          3.22         2.10           1.74

    1996         1.62          3.55         2.92           1.80



                                                       Appendix A




4.  The Construction Expenditures bar chart presents the
    following information.
     
 
                   Construction                        Total
                   Expenditures                    Construction
                    (excluding       Clean Air     Expenditures
                  AFUDC, CCRF &         Act         (excluding
           Year   Clean Air Act)    Expenditures   AFUDC & CCRF)
           ----   ---------------   ------------   -------------

Actual:    1992        $297              $30            $327
           1993         232               63             295
           1994         234               58             292
           1995         187               27             214
           1996         176                4             180

Forecast:  1997         211                4             215
           1998         223                7             230
           1999         235                -             235
           2000         243                2             245
           2001         275                5             280