Item 7 Exhibit 99
2000 Highlights	2
Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition	3
Report of Independent Accountants	34
Consolidated Statements of Earnings	35
Consolidated Balance Sheets	36
Consolidated Statements of Shareholders' Equity and Comprehensive Income	38
Consolidated Statements of Cash Flows	39
Notes to Consolidated Financial Statements	40
Quarterly Financial Summary (Unaudited)	75
Stock Market Information	76

2000 Highlights
Consolidated Financial Information (Millions of      Dollars, except Per Share Data)		2000		1999		Change	% Change
Total Operating Revenue	$	3,047.7		2,476.0		571.7	23.1
Total Operating Expenses	$	2,328.2		2,095.6		232.6	11.1
Loss from Equity Investments, Principally      Telecommunication Entities	$	(17.1)		(9.6)		(7.5)	(78.1)
Operating Income	$	702.4		370.8		331.6	89.4
Net Income	$	352.0		247.1		104.9	42.5
Earnings Available for Common Stock	$	346.5		238.2		108.3	45.5
Basic Earnings (Loss) Per Share of Common Stock
Utility:
Continuing Operations	$	1.61		1.85		0.24	(13.0)
Divestiture Gain		1.58		-		1.58	-
Impairment Loss		(.20)		-		(0.20)	-
Total Utility		2.99		1.85		1.14	61.6
PCI		0.12		0.22		(.11)	(45.5)
Pepco Energy Services		(0.08)		(0.06)		(.02)	33.3
PepMarket		(0.01)		-		(.01)	-
Pepco Consolidated	$	3.02		2.01		1.01	50.2
Cash Dividends Per Common Share	$	1.66		1.66		-	-
Utility - Operating
Energy Sales (000s Megawatt-hours)		27,442		26,970		472	1.8
Total Investment in Property and Plant (In Millions)	$	4,284.7		6,784.3		(2,499.6)	(36.8)
Number of Electric Service Customers at Year-End		719,687		700,611		19,076	2.7
Average Price Per Kilowatt-hour		6.96	Cents	7.11	Cents	(0.15)	(2.1)
Potomac Capital Investment Corporation (PCI)      Asset Mix
Energy Leveraged Leases	$	469.3		433.3		36.0	8.3
Marketable Securities	$	231.4		203.2		28.2	13.9
Aircraft Leases	$	118.5		251.3		(132.8)	(52.8)
Telecommunications	$	118.2		39.6		78.6	100.0
Real Estate	$	102.8		78.8		24.0	30.5
Other (primarily investments and receivables)	$	368.0		277.2		90.8	32.8
PCI - Telecommunications
Cumulative Authorized Cable Households		900,000		550,000		350,000	63.6
Cumulative Constructed Households		175,000		70,000		105,000	100.0
Customer Services
On-network		35,000		15,000		20,000	100.0
Off-network		240,000		265,000		(25,000)	(9.4)
Total Customer Services		275,000		280,000		(5,000)	(1.8)
Pepco Energy Services, Inc.
Electrical Sales (000s Megawatt-hours)		640		118		522	100.0
Gas Sales (in millions of decatherms)		54,400		46,300		8,100	17.5
Number of Gas and Electric Service Customers at     Year-End (000s)		32,100		6,900		25,200	100.0
Service Revenues	$	32,500		27,700		4,800	17.3
Gas and Electric Revenues	$	202,500		105,500		97,000	100.0

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

COMPANY OVERVIEW

        Potomac Electric Power Company (Pepco or the Company) is engaged in three principal
lines of business. These business lines consist of (1) the provision of regulated electric utility
transmission and distribution services in the Washington, D.C. (D.C.), metropolitan area, (2) the
supply of telecommunications services including local and long distance telephone, high-speed
Internet and cable television, and (3) the supply of energy products and services in competitive
retail markets. The Company's regulated electric utility activities are referred to herein as the
"Utility" or "Utility Operations," and its telecommunications services and competitive energy
activities are referred to herein as its "Competitive Operations." Additionally, the Company has
a wholly owned Delaware statutory business trust, Potomac Electric Power Company Trust I,
which is referred to herein as the "Trust" and a wholly owned Delaware Investment Holding
Company, Edison Capital Reserves Corporation, which is referred to herein as "Edison."

        In 2000, the generating segment of the electric utility industry continued to transition from a
regulatory to a competitive environment, and in response to this transition, the Utility executed
its business plan to exit the electricity generating business by completing the divestiture of
substantially all of its generation assets in December 2000. Additionally, the Company's
comprehensive plans to implement customer choice were completed as Maryland and D.C.
customers began to have their choice of electricity suppliers on July 1, 2000, and January 1,
2001, respectively. An overview of the Company's business activities is provided below.

UTILITY OPERATIONS

        On June 7, 2000, the Company entered into an agreement (the Agreement) with Mirant
Corp., formerly Southern Energy Inc. (Southern Energy) to sell total capacity of 5,154
megawatts in four generating stations located in Maryland and Virginia, and six purchased
capacity contracts totaling 735 megawatts (the Generation Assets). Southern Energy paid a total
of $2.75 billion (including other related generation assets sold to Southern Energy). The
Agreement was reached after Southern Energy was selected by the Company as the winning
bidder in its auction process that was held to select the buyer of its Generation Assets. The
divestiture closed on December 19, 2000, and resulted in the Company's recognition of a pre-tax
gain of $423.8 million ($182 million net of income tax or $1.58 per share). Additionally, in
December 2000, the Company transferred its Benning Road and Buzzard Point generating plants,
which were not included in the Generation Assets divested to Southern Energy, to a subsidiary of
Pepco Energy Services, Inc. (Pepco Energy Services). These power plants are located in D.C.
and have a total installed capacity of 806 megawatts. These stations will function as exempt
wholesale generators and be operated and maintained by Southern Energy pursuant to an initial
three-year contract with Pepco Energy Services. As discussed in the "Impairment Loss" section
herein, these stations were determined to be impaired and were written down to their fair value
by recognizing a pre-tax impairment loss of $40.3 million in the fourth quarter of 2000 ($24.1
million net of income tax or 20 cents per share).

        In a separate transaction, on May 19, 2000, the Company reached an agreement with PPL
Global, Inc., and Allegheny Energy Supply Company, LLC, to sell its 9.72 percent interest in the
Conemaugh Generating Station (Conemaugh) for approximately $156 million. Conemaugh is
located near Johnstown, Pennsylvania, and consists of two baseload units totaling approximately
1,700 megawatts of capacity. The Conemaugh sale closed on January 8, 2001, and resulted in
the recognition of a pre-tax gain of approximately $39 million, which will be recorded in the first
quarter of 2001.

        In accordance with the terms of agreements approved by the Maryland Public Service
Commission (Maryland Commission) in 1999, retail access to a competitive market for
generation services was made available to all Maryland customers on July 1, 2000. Also under
these agreements, Maryland customers who are unable to receive generation services from
another supplier, or who do not select another supplier, are entitled to receive services (default
services) from the Company until July 1, 2004, at a rate for the applicable customer class that is
no higher than the bundled rate in effect on June 30, 2000, but subject to adjustment for tax law
changes enacted by the Maryland General Assembly relating to its authorization of electric
industry restructuring. Thereafter, the Company will provide default services using power
obtained through a competitive bidding process at regulated tariff rates determined on a pass-
through basis and including an allowance for the costs incurred by the Company in providing the
services. In D.C., customers began to have their choice of electricity suppliers on January 1,
2001. The Company has a full requirements contract with Southern Energy to fulfill these
obligations.

        A summary of the Utility's Results of Operations for the years ended December 31, 2000,
1999, and 1998 follows. Refer to the Consolidated Results of Operations section for a discussion
of the impact of the Utility's operations on the Company's consolidated operations.

Utility Operations	2000	1999	1998
	(Millions of Dollars)
Revenues Gain on Divestiture of Generation Assets Impairment Loss	$2,237.5 423.8 (40.3)	$ 2,219.3              -              -	$ 2,068.9                -                -
Expenses	(2,272.1)	(1,991.3)	(1,857.7)
Net Income	$  348.9	$   228.0	$   211.2

COMPETITIVE OPERATIONS

        Over the past few years, with the passage of the Telecommunications Act of 1996, and the
deregulation of the natural gas and electric industries also under way, the focus of Pepco's
Competitive Operations has been expanded to include new telecommunications and energy
businesses. To facilitate this expansion, in May 1999, Pepco created a new unregulated
company, Pepco Holdings, Inc. (PHI), as the parent company of two wholly owned subsidiaries,
Potomac Capital Investment Corporation (PCI) and Pepco Energy Services. The Company's
telecommunications services are provided by PCI and its competitive energy products and
services are provided by Pepco Energy Services. Additionally, in September 2000,
PepMarket.com, LLC, (PepMarket) was organized as a third direct, wholly owned subsidiary of
PHI to offer internet-based procurement services to businesses and institutional customers.
Additional information about the Company's competitive telecommunications services and
financial investments, its competitive energy products and services, and its business-to-business
procurement operations is provided below.

Competitive Telecommunications Services and Financial Investments

         Pepco supplies bundled residential telecommunications products and services through
PCI's operations in the D.C. and Northern Virginia metropolitan areas. PCI also manages a
financial investments portfolio intended to provide additional earnings and cash flow.

        PCI's telecommunications products and services are provided through Starpower
Communications (Starpower), which was formed in 1997 by wholly owned subsidiaries of PCI
and RCN Corporation (RCN). Starpower is currently the only regional company providing cable
television, local and long distance telephone, dial-up and high-speed Internet services in a
competitively priced, bundled package for residential consumers, over an advanced fiber-optic
network. During 2000, Starpower built sufficient advanced fiber-optic network to cumulatively
reach approximately 175,000 households as compared to approximately 70,000 households at
December 31, 1999. The customer subscriber services base is composed of customers served by
Starpower's advanced fiber-optic network (On-network) and off of other networks ahead of
Starpower's build-out (Off-network). The On-network customer subscriber services include
cable television, local and long distance telephone and high-speed Internet and totaled
approximately 35,000 as of December 31, 2000, compared to approximately 15,000 at December
31, 1999. The Off-network customer subscriber services include dial-up Internet and resale local
and long distance telephone and totaled approximately 240,000 as of December 31, 2000,
compared to approximately 265,000 at December 31, 1999. Total customer subscriber services
including cable television, local and long distance telephone, and Internet customers were
approximately 275,000 as of December 31, 2000, compared to approximately 280,000 customers
as of December 31, 1999. The decline in total customer subscriber services during 2000 is
principally due to the loss of dial-up Internet customers due to competition from free dial-up
Internet service providers.

        During 2000, Starpower received approval from the Prince George's County Council to
provide competitive cable television, phone, and high-speed Internet services to the more than
240,000 households in Prince George's County, Maryland. This coupled with the earlier
approval in August 2000 from the Arlington County Board of Supervisors to provide similar
services to the more than 90,000 households of Arlington County, Virginia means that Starpower
now has the authority to offer its advanced network services to approximately 900,000
households in the D.C. metropolitan area, which includes D.C.; Montgomery County, Maryland;
Gaithersburg, Maryland; Prince George's County, Maryland; Arlington County, Virginia; and
Falls Church, Virginia. The approximately 900,000 households at December 31, 2000 represents
a significant increase from approximately 550,000 authorized cable households at December 31,
1999.

        The success of Starpower will depend upon its ability to achieve its commercial objectives
and is subject to a number of uncertainties and risks, including the pace of entry into new
markets; the time and expense required for building out the planned network; success in
marketing services; the intensity of competition; the effect of regulatory developments; and the
possible development of alternative technologies. Statements concerning the activities of
Starpower that constitute forward-looking statements are subject to the foregoing risks and
uncertainties.

        Beginning in the mid-1990s, PCI began redirecting its business operations by reducing its
involvement in investments that are not related to the energy or telecommunications industries.
Significant progress has been made in reducing PCI's previous concentration of investments in
the aircraft industry and recent investments have expanded PCI's portfolio of electric generating
and natural gas transmission and distribution equipment leases. The following table summarizes
PCI's asset mix, in millions of dollars, as of December 31, for each year presented.

PCI Asset Mix
	2000		1999
Energy leveraged leases	$  469.3	33%	$  433.3	34%
Marketable securities	231.4	17	203.2	16
Aircraft leases	118.5	8	251.3	20
Telecommunications	118.2	8	39.6	3
Real estate	102.8	7	78.8	6
Other investments (primarily investments        and receivables)	368.0	27	277.2	21
Total Assets	$1,408.2	100%	$1,283.4	100%

        The long-standing objective of PCI's financial investment portfolio is to provide a
significant contribution to current earnings and to add to the long-term value of the Company.
Consistent with this strategy, PCI entered into the following significant transactions during 2000:

        PCI's utility industry products and services are provided through various operating interests.
Its underground cable services company, W. A. Chester, provides construction, installation and
maintenance services to utilities and to other customers throughout the United States. During
2000, PCI acquired Severn Cable, a growing telecommunications contractor in the Washington,
D.C. metropolitan area that specializes in the installation of strand, fiber-optic and coaxial cable.
Additionally, in 1999, PCI launched Pepco Technologies, Inc., a new business strategy that is
focused on bringing new technologies to the electric utility industry as it deregulates.

        A summary of PCI's Results of Operations for the years ended December 31, 2000, 1999,
and 1998 follows. Refer to the Consolidated Results of Operations section for a discussion of
the impact of PCI's operations on the Company's consolidated operations.

PCI Operations	2000	1999	1998
	(Millions of Dollars)
Revenues	$149.9	$123.4	$123.9
Loss from Equity Investments,          Principally Telecommunication Entities	(20.2)	(10.4)	(8.5)
Expenses	(116.4)	(86.3)	(99.1)
Net Income	$  13.3	$ 26.7	$ 16.3

Competitive Energy Products and Services

        In 2000, Pepco Energy Services' marketing, operating, and support staffs were increased
and business systems and infrastructure were selected to support its operations, including the
sourcing and procurement of natural gas and electricity to serve customers in competitive retail
markets. Pepco Energy Services currently provides nonregulated energy and energy-related
products and services in the mid-Atlantic region. Its products include electricity, natural gas,
energy-efficiency contracting, equipment operation and maintenance, fuel management, and
appliance warranties. These products and services are sold either in bundles or individually to
commercial, industrial, and residential customers. In addition, with the transfer of the Benning
Road and Buzzard Point generating plants from the Utility to Pepco Energy Services in
December 2000, its operations now also include the generation and sale of electricity in the
wholesale market. Pepco Energy Services' revenue grew by over $100 million from $133.3
million in 1999 to $236.4 million in 2000, principally from increased sales of electricity and
natural gas in competitive retail markets and from energy services contracting.

        Pepco Energy Services business operations included the following significant transactions
during 2000:

        A summary of Pepco Energy Services' Results of Operations for the years ended December
31, 2000, 1999, and 1998 follows. Refer to the Consolidated Results of Operations section for a
discussion of the impact of Pepco Energy Services' operations on the Company's consolidated
operations.

Pepco Energy Services' Operations	2000	1999	1998
	(Millions of Dollars)
Revenues	$236.4	$133.3	$ 28.0
Income from Equity Investment	3.1	.8	-
Expenses	(248.3)	(141.7)	(29.2)
Net Loss	$   (8.8)	$   (7.6)	$  (1.2)

Business-to-Business Procurement

        On December 1, 2000, PepMarket began its business operations. PepMarket is positioned
as an on-line business-to-business procurement marketplace for the D.C./Baltimore metropolitan
region, offering the procurement of goods and services through an exchange platform using
Commerce One software. PepMarket's initial focus will be on businesses with 1,000 to 10,000
employees with special emphasis on minority and protected class businesses. PepMarket will
earn revenue through high-volume transaction fees with additional revenue streams resulting
from value added services such as on-line auctions, financial settlements, logistics, and
procurement management.

        As of December 31, 2000, Pepco invested $11 million of its $16 million commitment to
PepMarket. Investment expenditures will continue over the next few years. PepMarket's
management anticipates its business will become profitable in 2003. Client corporations have
plans for spending of $350 million annually through PepMarket's internet-based exchange with
operating revenue generation anticipated to begin in the first quarter of 2001. The business
should continue to build as global, national and regional suppliers provide more catalog content
to the PepMarket trade environment. From inception through December 31, 2000, PepMarket
produced revenues of $.1 million and incurred expenses of $1.5 million, which resulted in a net
loss of $1.4 million. The future success of PepMarket will depend upon its ability to achieve its
commercial objectives and is subject to a number of uncertainties and risks, including, but not
limited to, the overall success of marketing services; the growth of suppliers; the intensity of
competition; the effect of government planning and regulation; and the possible development of
alternative technologies. Statements concerning the activities of PepMarket that constitute
forward-looking statements are subject to the foregoing risks and uncertainties.

SAFE HARBOR STATEMENT

        In accordance with the safe harbor provisions of the Private Securities Litigation Reform
Act of 1995 (Reform Act), the Company hereby makes the following cautionary statements
identifying important factors that could cause its actual results to differ materially from those
projected in forward-looking statements (as such term is defined in the Reform Act) made by the
Company in this Annual Report to Shareholders. Any statements that express, or involve
discussions as to expectations, beliefs, plans, objectives, assumptions or future events or
performance are not statements of historical facts and may be forward-looking.

        Forward-looking statements involve estimates, assumptions and uncertainties and are
qualified in their entirety by reference to, and are accompanied by, the following important
factors, which are difficult to predict, contain uncertainties, are beyond the control of the
Company and may cause actual results to differ materially from those contained in forward-
looking statements:

        Any forward-looking statements speak only as of January 19, 2001, and the Company
undertakes no obligation to update any forward-looking statement to reflect events or
circumstances after the date on which such statement is made or to reflect the occurrence of
unanticipated events. New factors emerge from time to time and it is not possible for
management to predict all of such factors, nor can it assess the impact of any such factor on the
business or the extent to which any factor, or combination of factors, may cause results to differ
materially from those contained in any forward-looking statement.

CONSOLIDATED RESULTS OF OPERATIONS

OPERATING REVENUE

        The Company classifies its operating revenue as Utility and Competitive Operations.
Utility revenue is derived from the Utility's operations, the Trust, and Edison, while Competitive
Operations revenue is derived from the operations of its competitive subsidiaries. Additionally,
the gain that was realized from the divestiture of the Company's Generation Assets is classified
as "Gain on Divestiture of Generation Assets" in the consolidated statements of earnings.

Utility Revenue

        The components of Utility revenue are as follows.

Utility Revenue	2000	1999	1998
	(Millions of Dollars)
Base rate revenue	$1,359.1	$1,397.8	$1,354.6
Fuel rate revenue to cover cost of fuel and      interchange and capacity purchase payments	550.8	518.9	518.1
Interchange deliveries	291.6	258.7	177.8
Other utility revenue, including SMECO contract      termination fee recorded in 1999	36.0	43.9	18.4
Total Utility Revenue	$2,237.5	$2,219.3	$2,068.9

Base Rate Revenue

        The decrease in 2000 base rate revenue reflects the impact of base rate reductions in
January 2000 of 2% and 3.5% for D.C. residential and commercial customers, respectively,
associated with the termination of the conservation portion of the Environmental Cost Recovery
Rider. (A portion of the proceeds from the divestiture of the Generation Assets will be
designated for the recovery of unamortized conservation expenditures.) The decrease in 2000
base rate revenues also reflects additional base reductions in July 2000 of 1.5% for D.C.
customers and approximately 3% for Maryland customers.

        The increase in 1999 base rate revenue reflects a $19 million increase in Maryland base
rates (pursuant to a December 1998 settlement agreement) and a $9 million increase in the
District of Columbia Demand Side Management (DSM) surcharge tariff (effective September
1998).

        The following is a summary of Pepco's delivered kilowatt-hour sales.

				2000	1999
				vs.	vs.
Utility KWH Sales	2000	1999	1998	1999	1998
(Millions of KWHs)
By Customer Type
Residential	6,991	7,014	6,757	(.3)%	3.8%
General Service	16,227	15,890	15,591	2.1	1.9
Large Power Service (a)	712	701	686	1.6	2.2
Street Lighting	173	167	164	3.6	1.8
Wholesale (SMECO)	2,881	2,760	2,678	4.4	3.1
Metro	458	438	422	4.6	3.8
Total Energy Sales	27,442	26,970	26,298	1.8	2.6
Interchange
Energy deliveries	2,483	2,276	2,246	9.1	1.3
By Geographic Area
Maryland, including wholesale	16,826	16,552	16,017	1.7	3.3
District of Columbia	10,616	10,418	10,281	1.9	1.3
Total Energy Sales (a) Served at 66Kv or higher	27,442	26,970	26,298	1.8	2.6

        Kilowatt-hour sales increased in 2000 due to a 2.2% increase in delivery customers, and
winter temperatures that were 10% colder, as measured in heating degree days, than 1999.
Summer temperatures, as measured in cooling degree hours, were 31% milder than 1999 and
22% milder than the 20-year average, which had an unfavorable effect on kilowatt-hour sales.

        Kilowatt-hour sales increased in 1999 as the result of increases in cooling degree hours and
heating degree days of 6% and 11%, respectively, from 1998. Summer temperatures were 16%
hotter, as measured in cooling degree hours, than the 20-year average. In addition, a .9%
increase in utility customers produced a favorable impact on kilowatt-hour sales.

Fuel Rate Revenue

        Effective July 1, 2000, in Maryland (the date of commencement of customer choice) the
fuel clause was terminated. Effective February 9, 2001 (one month after the completion of the
sale of the Company's interest in Conemaugh), the fuel clause in D.C. will be terminated. Now
that generation services have been deregulated in both Maryland and D.C., and the Utility has
exited the generation business, the Utility will no longer incur fuel costs or engage in interchange
transactions. Standard Offer Services will be provided through energy purchased from Southern
Energy.

         As part of the agreement with Southern Energy to divest its Generation Assets, the
Company also signed a Transition Power Agreement (TPA) with Southern Energy. This TPA
was necessary because the Company will continue to be obligated, as the incumbent electric
utility, to supply the electric power needs of all of its current Maryland and D.C. customers that
cannot or do not choose an alternate electric power service provider during a four-year transition
period to retail access. This service, called Standard Offer Service, is required by settlement
agreements approved by both the Maryland and D.C. Public Service Commissions as part of the
deregulation of electric power generation and the initiation of customer choice.

        Under the TPA, the Company has the option of acquiring all of the energy and capacity that
is needed for Standard Offer Service from Southern Energy at prices that are below the
Company's current cost-based billing rates for Standard Offer Service, thereby providing the
Company with a built-in profit margin on all Standard Offer Service sales that the Company
acquires from Southern Energy. Under the settlement agreements mentioned above, the
Company will share such profit amounts with customers on an annual cycle basis, beginning
with the period July 1, 2000, to June 30, 2001, in Maryland and from February 9, 2001, to
February 8, 2002, in D.C. (the Generation Procurement Credit or "GPC").

        In both jurisdictions, amounts shared with customers each year are determined only after the
Company recovers certain guaranteed annual reductions to customer rates. In addition, because
the annual cycle for the GPC in Maryland began on July 1, 2000, the Company supplied
Standard Offer Service from its traditional sources until the Generation Assets were sold and,
thus, recorded losses on Standard Offer Services sales during this period, mostly because of
higher summer generating costs. Therefore, profit from Standard Offer Service sales in
Maryland between January 8, 2001 and June 30, 2001 will be recorded as income to the
Company until both the guaranteed rate reduction amount and the Standard Offer Service losses
incurred in 2000 are recovered. Once such amounts are recovered, profit is shared with
customers in Maryland generally on a 50/50 basis.

        Fluctuations in fuel and purchased power costs throughout 1999 and 1998 resulted in four
revisions to the Company's Maryland fuel rate. The Company increased its Maryland fuel rate
by 10.5% effective March 1, 1998. Subsequently, on August 14, 1998, the Company filed for a
5.3% reduction in the Maryland fuel rate, which became effective beginning the billing month of
September 1998. Also, on October 19, 1998, the Company filed for an additional 6.3%
reduction in the Maryland fuel rate, which became effective beginning the billing month of
November 1998, and on November 22, 1999, the Company filed for a 5.5% reduction in the
Maryland fuel rate, which became effective beginning the billing month of December 1999.

Interchange Deliveries

         The increases in interchange deliveries in 2000 and 1999 reflect changes in prices and
levels of energy delivered to PJM and changes in prices and levels of bilateral energy sales under
the Company's wholesale power sales tariff. Interchange transactions were subject to cost-based
ratemaking regulations based on formulas prescribed by the FERC, but during 2000, the
Company made a significant effort to move the sales of energy and capacity under its FERC
approved Market based pricing tariff. Interchange deliveries also include revenue from sales of
short-term generating capacity. Revenues from capacity transactions totaled $1.2 million, $6
million, and $4.4 million in 2000, 1999, and 1998, respectively. The benefits derived from
interchange deliveries, the allocated amounts of capacity sales in D.C. (approximately 40%), and
revenue under the Open Access Transmission Tariff (OATT) have historically been passed
through to the Company's customers through fuel adjustment clauses. However, as discussed in
Note (2) of the Notes to Consolidated Financial Statements, Summary of Significant
Accounting Policies, effective July 1, 2000 in Maryland (the date of commencement of customer
choice) the fuel clause was terminated. Effective February 9, 2001 (one month after the
completion of the sale of the Company's interest in Conemaugh), the fuel clause in D.C. will be
terminated.

Other Utility Revenue

        The decrease in other Utility revenue in 2000 results from the effect in 1999 of $23.2
million in income associated with the payment (to be received in January 2001) related to the
revision of SMECO's full-requirements power supply contract. This transaction is discussed in
detail in Note (12) of the Notes to Consolidated Financial Statements, SMECO Agreement.

        The increase in other utility revenue in 1999 is also related to the revision of SMECO's full-
requirements contract.

Competitive Operations Revenue

        A summary of the components of Competitive Operations revenue is as follows.

Competitive Operations Revenue	2000	1999	1998
	(Millions of Dollars)
Financial Investments         Leased assets         Marketable securities         Real estate         Other financial investments	$   59.7   17.2   8.2       16.7	$  62.5 15.8 3.3     23.4	$  73.3 19.3 15.1       4.4
Total Financial Investments	101.8	105.0	112.1
Energy Services
Energy-efficiency services	22.3	21.5	14.7
Electricity sales	47.3	4.3	-
Natural gas sales	155.2	101.2	13.3
Building services and Other	11.6	6.3	-
Total Energy Services	236.4	133.3	28.0
Utility Industry Services	48.2	18.4	11.8
Total Competitive Operations Revenue	$386.4	$256.7	$151.9

Financial Investments

        Revenue from financial investments was $101.8 million in 2000, $105 million in 1999 and
$112.1 million in 1998. Financial investments revenue primarily consists of income derived
from leased assets (electric power plants, gas transmission and distribution networks, aircraft,
and other assets) and marketable securities (primarily fixed-rate, utility preferred stocks).
Additionally, transactions involving real estate holdings and other financial investments are
classified as financial investments revenue. The basis for the overall decrease in financial
investments revenue for 2000 compared to 1999 is described below.

        Leased assets revenue decreased in 2000 primarily as the result of aircraft sales in 1999 and
in 2000 that resulted in less rental income earned in 2000 and due to pretax losses of $8.2 million
($5.4 million after-tax) related to the sale of aircraft that were recorded in 2000. This decrease
was partially offset by a full year of revenue generated from two similar leveraged lease
transactions with eight Dutch Municipal owned entities that were entered into in 1999. Leased
assets revenue decreased in 1999 primarily as the result of aircraft sales throughout 1998 that
resulted in less rental income earned in 1999 and due to a pre-tax loss of $3 million ($1.9 million
after-tax) that was recorded in 1999 related to the sale of two aircraft. This decrease was offset
by revenue generated from two similar leveraged lease transactions with eight Dutch Municipal
owned entities that were entered into during 1999. Additional information regarding these leases
is disclosed in Note (3) of the Notes to Consolidated Financial Statements, Leasing Activities.

        Marketable securities revenue increased in 2000 primarily due to reduced losses on the
sale of securities during the year compared to the prior year. Marketable securities revenue
decreased in 1999 primarily due to a reduction in dividend income as a result of the downsizing
of the preferred stock portfolio from 1997 through 1999. Marketable securities revenue included
a net realized loss of $.3 million in 2000, a net realized loss of $1.6 million in 1999, and a net
realized gain of $2.2 million in 1998.

        The increase in real estate revenue in 2000 primarily results from pre-tax gains of
$2.2 million ($1.4 million after-tax) on the sale of properties within PCI's real estate portfolio.
The decrease in real estate revenue in 1999, results from 1998 real estate sales that resulted in
pre-tax gains of $12.2 million ($7.9 million after-tax).

        Revenue from other financial investments decreased in 2000 as a result of one-time gains
recorded in 1999 related to the liquidation of a partnership, which resulted in a pre-tax gain of
approximately $9.5 million ($5.9 million after-tax), and from the sale of an investment that
resulted in a pre-tax gain of approximately $9.9 million ($6.4 million after-tax). The decrease
was partially offset by increased revenues received from existing investments. Revenue from
other financial investments increased in 1999 over 1998 due to the one-time gain transactions
noted above.

Energy Services

        Revenue from energy and energy services was $236.4 million in 2000, $133.3 million in
1999, and $28 million in 1998. Energy services revenue primarily consists of energy-efficiency
services and natural gas and electricity sales in competitive retail markets. During 2000, Pepco
Energy Services had electricity sales of 640,131 megawatt-hours compared with 118,253
megawatt-hours in 1999. Pepco Energy Services had natural gas sales of approximately 54.4
million decatherms in 2000, compared with approximately 46.3 million decatherms in 1999.
This component of revenue is primarily transaction driven.

        Pepco Energy Services revenue increased in 2000 primarily due to continued growth of its
natural gas business and a full year of retail electric revenues. Also, Pepco Energy Services
started its wholesale electric business during 2000. Pepco Energy Services revenue increased in
1999 due to the recognition of a full year of operations in 1999 from acquisitions that were made
in 1998.

        In the fourth quarter of 1999, Pepco Energy Services began to market energy products and
services to residential customers in Maryland and Pennsylvania. As of December 31, 2000 and
1999, Pepco Energy Services had approximately 38,500 and 5,400 customers, respectively.

Utility Industry Services

        The increase in utility industry services revenue during 2000 primarily results from the
pretax gain of approximately $19.7 million ($11.8 million after-tax) recorded by PCI for the sale
of its 50% interest in the Cove Point liquefied natural gas storage facility. The increase was also
partially related to the growth of this portion of PCI's business and additional revenues from
Severn Cable, acquired by PCI during 2000. The increase in utility industry services revenue
during 1999 results from the growth of this portion of PCI's business.

Gain on Divestiture of Generation Assets

        On December 19, 2000, the Company completed the sale of its Generation Assets to
Southern Energy (including other related generation assets) for $2.75 billion. This resulted in a
pre-tax gain of $423.8 million ($182 million net of income tax or $1.58 per share) that was
recorded in the fourth quarter of 2000. The amount of the pre-tax gain reflects a net book value
of electric power plants and other generating assets transferred to Southern Energy of
approximately $1.8 billion. Additionally, under the provisions of settlement agreements
approved by both the Maryland and D.C. Public Service Commissions, approximately $32.6
million and $46 million of transition and transaction costs, respectively, were reflected as
reductions in the calculation of the gain. Commitments for customer gain sharing of $243.8
million, as well as stranded regulatory assets such as conservation costs and unamortized debt
reacquisition costs were reflected as reductions in the calculation of the gain.

OPERATING EXPENSES

Total Fuel and Purchased Energy

        A summary of the Company's fuel and purchased energy is as follows.

	2000	1999	1998
	(Millions of Dollars)
Utility         Fuel expense         Capacity purchase payments         Purchased energy              PJM              Other                     Total purchased energy         Utility Fuel and Purchased Energy	$  357.7     205.7 254.8     196.5       451.3   1,014.7	$  396.4     213.9 181.1     130.3     311.4     921.7	$ 380.2   155.7 146.3   123.5   269.8   805.7
Pepco Energy Services
Electricity and natural gas	191.5	104.1	13.1
Consolidated Fuel and Purchased Energy	$1,206.2	$1,025.8	$818.8

Utility Fuel and Purchased Energy

        The Company divested its Generation Assets on December 19, 2000, and its interest in
Conemaugh on January 8, 2001. For additional information about the divestitures and their
impact on the TPA and GPC, refer to Note (1) Organization, Divestiture, and Segment
Information and the "Fuel Rate Revenue" section herein, respectively. The Utility's net system
generation and purchased energy in kilowatt-hours were as follows.

	2000	1999	1998
	(Millions of Kilowatt-hours)
Net system generation	18,834	22,807	21,715
Purchased energy	12,359	7,772	8,204

        The 2000 decrease in fuel expense compared to 1999 reflects a decrease of 17.4% in net
system generation, partially offset by an increase in the system average unit fuel cost. The
increase in 1999 fuel expense compared to 1998 reflects an increase of 5% in net system
generation, partially offset by a decrease in the system average unit fuel cost.

        The unit costs of fuel burned and the percentages of system fuel requirements obtained from
coal, oil and natural gas are shown in the following table.

Percent of Fuel Burned				Unit Cost of Fuel Burned
	Coal	Oil	Gas	Coal	Oil	Gas	System Average
				(Per Million Btu)
2000	83.7	5.8	10.5	$1.41	$3.93	$4.62	$1.90
1999	81.4	13.4	5.2	1.46	2.56	2.83	1.68
1998	84.5	12.7	2.8	1.55	2.71	2.63	1.72

        The 2000 system average unit fuel cost increased by 13% compared to 1999, principally
due to increases in the cost of natural gas. The 1999 system average unit fuel cost decreased by
2.3% compared to 1998, principally due to decreases in the costs of coal and oil. Prior to the
divestitures, the Company's major cycling and certain peaking units burned either natural gas or
oil, which provided protection against possible supply disruptions, and added flexibility in
selecting the most cost-effective fuel mix. The use of coal, oil and natural gas depended upon
the availability of generating units, energy and demand requirements of interconnected utilities,
regulatory requirements, weather conditions, and fuel supply constraints, if any.

        Effective July 1, 2000, in Maryland (the date of the commencement of customer choice) the
fuel clause was terminated, and therefore, fuel costs began to be expensed as incurred and fuel
rate revenue billed in any given period is no longer deferred for recovery from or repayment to
customers. Effective February 9, 2001 (one month after the completion of the sale of the
Company's interest in Conemaugh), the fuel clause in D.C. will be terminated. For the year
ended December 31, 2000, the discontinuance of the fuel clause had an unfavorable impact on
the Company's earnings as fuel costs exceeded fuel revenues by approximately $24 million (pre-
tax). Now that the Company has divested its Generation Assets, it will no longer incur losses
through provision of Standard Offer Services (refer to the Fuel Rate Revenue Section, herein).

        The Utility's transmission facilities are interconnected with those of other transmission
owners in the PJM power pool and other utilities, providing economic energy and reliability
benefits by facilitating the Company's participation in the federally regulated wholesale energy
market. This market has enabled the Company to purchase energy at costs lower than those
required to self-generate, and to sell energy at favorable prices to other market participants.

        Presently, all transmission service within the PJM power pool is administered by the PJM
Office of the Interconnection. Since April 1998, PJM has operated a "locational marginal
pricing" system designed to economically control transmission system congestion. Because of
the Company's pre-divestiture generation availability and peak load characteristics, the Company
generally was able to sell into the PJM market during high price peak load periods and buy from
the market during low price periods. (Also see the Restructuring of the Bulk Power Market
discussion below).

        In addition to interchange within PJM, prior to the divestiture of the Generation Assets in
December 2000, the Company actively participated in the bilateral energy sales marketplace.
The Company's FERC-approved wholesale power sales tariff allowed both sales from Company-
owned generation and sales of energy purchased by the Company from other market participants.
Numerous utilities and marketers executed service agreements allowing them to arrange
purchases under this tariff, and the Company executed service agreements allowing it to
purchase energy under other market participants' power sales tariffs.

        The Company purchases energy from FirstEnergy Corp. (FirstEnergy, formerly Ohio
Edison) under a long-term capacity purchase agreement with FirstEnergy and Allegheny Energy,
Inc. (AEI). Pursuant to this agreement, the Company is required to purchase 450 megawatts of
capacity and associated energy through the year 2005. As of December 19, 2000, the Company
resells the energy and capacity to Southern Company Energy Marketing L.P. (SCEM), an
affiliate of Southern Energy. The Company also resells to SCEM the energy and capacity it
purchases under the short-term, cost-based purchase agreement for 50 megawatts of capacity and
related energy from the Northeast Maryland Waste Disposal Authority.

        The Company will continue to purchase 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; capacity payments under this agreement
commenced in January 1997. As of December 19, 2000, the Company resells this capacity and
energy to SCEM. Capacity expenses under this agreement were $41.3 million for 2000,
$43.7 million for 1999, and $27.6 million for 1998. The increases since 1997 reflect contractual
escalations under existing purchase capacity contracts. These costs are reflected in rates in D.C.
through a fuel adjustment clause on a dollar-for-dollar basis and in Maryland through base rate
proceedings. Under the terms of the Company's asset sale agreement with Southern Energy,
resales of energy and capacity purchased by the Company under the foregoing power purchase
agreements are at prices equal to the Company's payment obligations under such agreements.
The Company continues to be liable for the obligation to Panda but is reimbursed by Southern
Energy for the amount it pays.

        The Company's facility and capacity agreement with SMECO, through 2015, with respect
to the 84 megawatt combustion turbine installed and owned by SMECO at the Chalk Point
Generating Station has been assigned to Southern Energy Peaker LLP (SEP), an affiliate of
Southern Energy. The Company remains liable to SMECO for the performance of the contract
and is indemnified by Southern Energy for any such liability. The capacity payment to SMECO
was approximately $5.5 million per year.

        All of SCEM's and SEP's obligations to the Company have been guaranteed by Southern
Energy.

Pepco Energy Services' Fuel and Purchased Energy

        Pepco Energy Services enters into agreements for the future delivery of natural gas and
electricity to its customers and generally operates to secure firm, fixed price supply commitments
to meet its fixed-price sales obligations. Earnings are dependent upon the origination and
execution of transactions which may be affected by market, credit, weather, regulatory, and other
conditions. Natural gas and electricity expense for Pepco Energy Services increased in 2000
over 1999 due to increased volumes of retail sales of natural gas and electricity and as a result of
rising fuel prices. Natural gas and electricity expense increased in 1999 over 1998 due to the
recognition of a full year of operations of Pepco Gas Services along with the initiation of
electricity sales in 1999.

        In January 1999, Pepco Energy Services signed a contract with SMECO to supply
SMECO's full-requirements for power (approximately 600 MW of peak load) during the four-
year period starting January 1, 2001. A firm commitment has been secured from a third party for
the delivery of power sufficient to serve SMECO's full requirements. Both the sales
commitment to SMECO and the third-party purchase agreement are at fixed prices that do not
vary with future changes in market conditions.

Other Operation and Maintenance

        The increase in other operation and maintenance expense in both 2000 and 1999 primarily
resulted from the growth of Pepco Energy Services' business operations during the year. The
1999 increase was partially offset by reductions in labor and benefits costs associated with the
success of Pepco's Targeted Severance Plan (the Plan). The Plan offered severance pay and
subsidized health and dental benefits, at amounts dependent upon years of service, to employees
who lost employment due to corporate restructuring and/or job consolidations. Under the Plan,
no changes were made to eligible pensions or benefits under the retirement program.

Depreciation and Amortization Expense

        Depreciation and amortization expense decreased in 2000 due to reductions in the
amortization of conservation expenditures concurrently with the termination of the Maryland and
D.C. conservation surcharges. These expenses increased in 1999 due to the Company's
additional investment in utility property and plant and increased amortization of conservation
expenditures.

Other Taxes

        Other taxes increased in 2000 as a result of the Right of Way Fee in D.C. and the Universal
Service Charge in Maryland, both of which commenced in 2000. Other taxes decreased in 1999
due to a decrease in the level of gross receipts taxes collected from customers in the District of
Columbia.

Interest Expense

        The components of interest expense were relatively stable during the three-year period 1998
through 2000. Short-term borrowing costs have remained relatively low. The average cost of
outstanding long-term Utility debt decreased from 7.33% at the beginning of 1998 to 7.1% at the
end of 2000. Distributions on preferred securities of the Trust established in April 1998 totaled
$9.2 million in 2000 and 1999. Interest expense is offset by the debt components of an
Allowance for Funds Used During Construction (AFUDC) and Clean Air Act Capital Cost
Recovery Factor, which totaled $5.4 million in 2000, $3.4 million in 1999 and $4.2 million in
1998.

Impairment Loss

        During the fourth quarter of 2000, the Company closed on the divestiture of its Generation
Assets and transferred its Benning Road and Buzzard Point generating stations, which were not
included in the divestiture, to a subsidiary of Pepco Energy Services. As a result of the
divestiture and the transfer of the stations, as well as the volatility of energy prices and the
availability of current financial information derived from the completion of the Company's 2001
budgeting cycle, the Company determined that it was necessary to reassess whether the carrying
amounts of these generating stations were recoverable. Based on this assessment, the stations
were determined to be impaired and were written down to their fair value by recognizing a pre-
tax impairment loss of $40.3 in the fourth quarter of 2000 ($24.1 million net of income tax or
20 cents per share). The fair value of approximately $33 million was determined using the
present value of their estimated expected future cash flows.

         Additionally, this line item on the Company's consolidated statements of earnings for the
year ended December 31, 2000, includes PCI's impairment loss of $5.4 million ($3.5 million net
of income tax or 3 cents per share) related to its aircraft portfolio.

LOSS FROM EQUITY INVESTMENTS, PRINCIPALLY TELECOMMUNICATION
ENTITIES

        This amount represents the Company's share of pre-tax loss from the entities in which it has
a 20% to 50% equity investment. The Company's most significant equity investment is PCI's
joint venture in Starpower. The increases in the loss from 2000 over 1999 and from 1999 over
1998 primarily result from costs incurred from expanding the Starpower fiber-optic network.
For additional information about the Company's equity investments, see Note (5) of the Notes to
Consolidated Financial Statements, Loss from Equity Investments, Principally
Telecommunication Entities.

INCOME TAX EXPENSE

        The increase in income tax expense in 2000 is primarily due to increases in federal and state
income taxes associated with the gain on the divestiture of the Generation Assets. The decrease
in income tax expense in 1999 is primarily the result of PHI's recognition of $18.7 million in tax
benefits during 1999 associated with the completion of a restructuring transaction related to a
partnership. Additionally, the fluctuations in income tax expense reflect changes in the levels of
the Company's taxable income.

CAPITAL RESOURCES AND LIQUIDITY

USE OF PROCEEDS FROM THE DIVESTITURE

        The Company received cash proceeds of $2.75 billion from the sale of its electric plants and
other generating assets to Southern Energy. A portion of the proceeds has been used to retire
$525 million of the Company's long-term debt. Additionally, approximately $200 million was
used to repay loans entered into in connection with the Company's treasury stock reacquisition
completed in October 2000; approximately $800 million will be used to pay income taxes due on
the sale; and $150 million was used to fund a capital contribution to PHI for use in its
telecommunication business. Additionally, approximately $244 million will be paid to meet the
Company's commitment for customer gain sharing. The Company intends to use the remaining
proceeds to further its business strategies and/or to fund additional capital structure reductions,
including additional repurchases by the Company of its common stock which could be
accompanied by a change in the dividend.

        For the year ended December 31, 2000, the Company recorded approximately $2.6 million
in net interest income related to proceeds from the divestiture that were invested by Edison,
which represented 13 days of interest.

ADDITIONAL SOURCES OF LIQUIDITY

        The Utility also obtains its capital resources from internally generated cash from its
operations and the sale of First Mortgage Bonds, Medium-Term Notes, and Trust Originated
Preferred Securities (TOPrS). Interim financing is provided principally through the issuance of
Short-Term Commercial Promissory Notes. Pepco maintains 100% line of credit back-up in the
amount of $350 million, for its outstanding Commercial Promissory Notes, which was unused
during 2000, 1999, and 1998.

        PCI obtains its capital resources from the issuance of Short-Term and Medium-Term Notes
under its own, separately rated Commercial Paper and Medium-Term Note programs. On July 7,
2000, PCI completed a new series Medium-Term Note facility providing up to $900 million of
future debt issuances. The notes will bear interest at fixed or floating rates and will have
maturity dates varying from nine months and one day from the date of issue through November
30, 2009. As of December 31, 2000, PCI had approximately $900 million available under its
Medium-Term Note credit facility.

        Additionally, PCI's $231.4 million securities portfolio, which consists primarily of Fixed-
Rate Electric Utility Preferred Stocks, provides additional liquidity and investment flexibility.

        On September 21, 2000, Moody's Investor Services announced that it upgraded PCI's senior
unsecured debt rating from Baa1 to A3. This senior unsecured debt is currently rated BBB+ by
Standard & Poors and the Fitch Rating Agency.
        Pepco Energy Services obtains its capital resources primarily through equity contributions
from PHI and third-party financing.

        The Company's capitalization ratios at December 31, 2000, are presented below.

	Excluding    Amounts Due     In One Year	Including    Amounts Due     In One Year
Short-term debt	-%	22.8%
Long-term debt and capital lease obligations	47.2	36.4
Trust originated preferred securities	3.2	2.5
Serial preferred stock	1.0	.8
Redeemable serial preferred stock	1.3	1.0
Shareholders' equity	47.3	36.5
Total Capitalization	100.0%	100.0%

DIVIDENDS ON COMMON AND PREFERRED STOCK

        Dividends on common stock were $190.4 million in 2000, and $196.6 million in 1999 and
1998. The Company's annual dividend rate on its common stock is determined by the
Company's Board of Directors on a quarterly basis. In view of the divestiture of the Company's
Generation Assets and the competitive environment in which the Company's future operations
will take place, the Board of Directors believes that the high payout ratio represented by the
current annual dividend rate of $1.66 per share will not be consistent with the Company's future
utility and telecommunications operations. Accordingly, the Board is continuing to evaluate the
current rate with a view to changing the rate in the future.

        Dividends on preferred stock were $5.5 million in 2000, $7.9 million in 1999, and $11.4
million in 1998. The embedded cost of preferred stock was 6.67% at December 31, 2000, 6.62%
at December 31, 1999, and 5.74% at December 31, 1998.

        Total annualized interest cost for all outstanding long-term debt and preferred securities of
the Trust was $190.8 million at December 31, 2000, $205.4 million at December 31, 1999, and
$191.7 million at December 31, 1998, respectively.

CONSERVATION

        Historically, the Company has recovered the costs of its Maryland and D.C. conservation
programs through base rate surcharges. In general, these surcharges have allowed the Company
to recover the unamortized costs of DSM and energy use management programs that have
successfully increased the efficiency of energy usage throughout the Company's service territory.

        Under provisions of the D.C. and Maryland agreements approving the divestiture of the
Generation Assets, the conservation related portion of the D.C. Environmental Cost Recovery
Rider was terminated, effective January 1, 2000, and the Maryland DSM surcharge was
discontinued effective July 1, 2000. In addition, the Company was allowed to offset unrecovered
DSM and conservation costs, including an estimate of additional DSM expenditures to be
incurred during a three-year transition period, against the proceeds from the sale of Generation
Assets. A total of $138.1 million was offset against the proceeds.

CONSTRUCTION AND CAPACITY

       The Company completed the divestiture of its Generation Assets to Southern Energy on
December 19, 2000. Utility construction expenditures, excluding AFUDC and Capital Cost
Recovery Factor (CCRF), totaled $225.5 million in 2000, which included $75.2 million related
to its divested Generation Assets. For the five-year period 2001 through 2005, expenditures for
transmission and distribution related Utility plant are projected to total $770.5 million. The
Company plans to finance its Utility construction program primarily through funds provided
from operations.

        The Company had a facility and capacity agreement with SMECO, which expires in 2015,
for 84 megawatts of generating capacity supplied by a combustion turbine installed and owned
by SMECO at the Chalk Point Generating Station. This agreement has been assumed and
assigned to SEP, an affiliate of Southern Energy. Additionally, the Company purchases 450
megawatts of generating capacity and associated energy from FirstEnergy under a long-term
capacity purchase agreement with FirstEnergy and AEI. The Company also resells to SCEM the
energy and capacity it purchases under the short-term, cost-based purchase agreement for 50
megawatts of capacity and related energy from the Northeast Maryland Waste Disposal
Authority.

        The Company will continue to purchase energy from Panda pursuant to a 25-year capacity
purchase agreement for 230 megawatts of capacity from a gas-fueled combined-cycle
cogenerator in Prince George's County, Maryland. As of December 19, 2000, the Company
resells this capacity and energy to SCEM. Under the terms of the Company's asset sale
agreement with Southern Energy, resales of energy and capacity purchased by the Company
under the foregoing power purchase agreements are at prices equal to the Company's payment
obligations under such agreements. The Company continues to be liable for the obligation to
Panda but is reimbursed by Southern Energy for the amount it pays.

BASE RATE PROCEEDINGS

        The Utility is subject to 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. Historically, the Company's 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. The Maryland fuel clause terminated effective July 1, 2000, and will be
terminated on February 9, 2001 in D.C.

        Annual base rate increases (decreases) that became effective during the periods 1998
through 2000 are shown below.

Year	Total	Maryland	District of    Columbia	Wholesale
	(Millions of Dollars)
2000	$(24.3)	$(13.0)	$(11.3)	$    -
1999	-	-	-	-
1998	16.5	19.0	-	(2.5)
	$ (7.8)	$   6.0	$(11.3)	$(2.5)

MARYLAND

        On September 23, 1999, the Company filed an amendment to its divestiture filing in
Maryland (the Maryland Amendment), which was approved by the Maryland Commission on
December 22, 1999. The Maryland Amendment provides residential customers with a 3% base
rate reduction, or approximately $10 million in revenue per year, which the Company may
recover through future potential generation procurement savings, effective December 19, 2000,
(the Company's closing of the divestiture of the Generation Assets). As discussed in the "Fuel
Rate Revenue" section herein, the Company has a four-year TPA with Southern Energy
containing fixed costs that on average are lower than its capped production rate, which may give
rise to generation procurement savings during the rate-capped period.

        Also on September 23, 1999, the Company filed an Agreement of Stipulation and
Settlement Regarding Unbundled Rate Issues (the Maryland Phase II Settlement Agreement),
which was approved by the Maryland Commission on December 22, 1999. This agreement was
the result of negotiations conducted among representatives of the parties to the Company's
original divestiture filing as well as other parties. The Maryland Phase II Settlement Agreement
creates reductions in rates for all customers. Although the amount of the reduction will vary
somewhat by class of customer, the estimated overall net effect will be reductions for all
customers equivalent to approximately 4% of base rates, or approximately $29 million in
revenue per year. This decrease is being achieved through the elimination of the DSM surcharge
rate, effective July 1, 2000, made possible because DSM costs were substantially recovered as of
July 1, 2000. Unamortized DSM costs totaling $16.4 million were offset against the proceeds
from the divestiture of the Generation Assets. An Electric Universal Service Program surcharge
has been implemented to assist low-income customers in paying energy bills, and allows the
Company to recover approximately $7 million in annual charges for Universal Service that have
been imposed by the Maryland legislature. The Maryland Phase II Settlement Agreement also
extends the term of the Company's transitional Standard Offer Service rate cap by one year. The
Company will not file for a base rate increase prior to December 2003.

        In November 1998, pursuant to a settlement agreement, the Maryland Commission
authorized a $19 million, or 2%, increase in base rate revenue effective with service rendered on
and after December 1, 1998. In June 1998, the Company had filed a request to increase its base
rates to recover contractual escalations in existing Commission-approved purchased capacity
contracts, costs related to the 1998 Targeted Severance Plan, Year 2000 compliance costs, tax
normalization of pre-1981 plant removal costs, and certain other costs associated with prior rate-
making determinations. The settlement's rate increase was distributed among rate classes in a
manner that will continue movement toward equalized rates of return among rate classes, and
provided for a lessening of the Company's summer-winter rate differential. The settlement was
comprehensive and did not include specific determinations regarding an authorized rate of
return; however, a rate of return of 8.8% has been used by the Company for purposes of
calculating AFUDC and CCRF. Previously, pursuant to a November 1997 settlement agreement,
the Commission authorized a $24 million, or 2.6%, increase in base rate revenue effective with
bills rendered on and after November 30, 1997.

DISTRICT OF COLUMBIA

        On November 8, 1999, the Company filed a Non-Unanimous Agreement of Stipulation and
Full Settlement (the D.C. Agreement), which was approved by the D.C. Commission on
December 22, 1999. Under the terms of the D.C. Agreement, the rates for service to residential
customers in D.C. would be reduced by a total of 7% as follows: 2% effective January 1, 2000,
an additional 1-1/2% effective July 1, 2000, and an additional 3-1/2% effective one month after
the closing on the sale of the generation assets. The corresponding rate reductions for
commercial customers in D.C. total 6-1/2% as follows: 3-1/2% on January 1, 2000, 1-1/2% on
July 1, 2000, and 1-1/2% one month after the closing of the sale of the generation assets. The
January 1, 2000 rate reductions approximate $25 million annually and reflect the termination of
the DSM surcharge. Unamortized DSM costs totaling $121.7 million were offset against the
proceeds from the divestiture of the Generation Assets. The July 1, 2000 rate reductions
approximate $12 million annually, and reflect reductions in the Company's cost of service since
its last D.C. base rate case, which was decided on June 30, 1995. The post-closing rate
reductions of approximately $15 million annually represent the guaranteed reductions through
the operation of the Generation Procurement Credit and are guaranteed, but may be recouped by
the Company if it is able to purchase electricity at a lower cost than its frozen production rate
during the period the Company's rates are capped. As mentioned, the Company has a four-year
transition Power Agreement with Southern Energy. The rates will be capped at the levels in
effect one month after the closing of the sale of the assets for a period of six years for Residential
Aid Discount low-income customers and four years for other customers. The period during
which the caps will be in effect will begin one month following the date of the closing on the
sale of the assets. The capped rates will include rates in effect one month after the closing of the
asset sale, the average level of fuel costs for the 12 months prior to the date of the closing, plus
the CAA portion of the Environmental Cost Recovery Rider in effect one month after the
closing.

WHOLESALE

        The Utility's full-service power supply requirements contract with SMECO, the Utility's
principal wholesale customer with a peak load of approximately 600 megawatts, which
represents approximately 10% of the Company's total kilowatt-hour sales, expired on December
31, 2000, and was replaced by a full-requirements supply contract with Pepco Energy Services.
The four-year agreement between SMECO and Pepco Energy Services was awarded pursuant to
competitive bidding and commenced January 1, 2001. See Note (12) of the Notes to
Consolidated Financial Statements, SMECO Agreement, for additional information.

COMPETITION

       During 1999 and 2000, the generating segment of the electric utility industry continued to
transition from a regulatory to a competitive environment. The Company exited the electricity
generating business by divesting substantially all of its generation assets on December 19, 2000.
The Utility's operations now consist of its transmission and distribution service. On July 1, 2000
in Maryland and January 1, 2001 in D.C., Pepco's customers began to have their choice of
electricity suppliers.

        In the area of transmission, which remains under federal regulation, the Company believes
it has certain strengths and skills. The Company intends to continue to evaluate the cost-
effectiveness of its transmission system with a view to expanding profit potential. In the area of
distribution, which continues to be regulated at the local level, the Company believes it has
valuable assets and skills and intends to continue to enhance its profitability.

        The Company is pursuing operating strategies through PHI that provide for earnings
contributions to the Company and build shareholder value through the launching of new
businesses, particularly those in the competitive markets for deregulated electricity, natural gas,
and telecommunications products and services throughout the mid-Atlantic region. In the future,
increased competition, regulatory actions, and changing economic conditions may impact PHI's
operations.

RESTRUCTURING OF THE BULK POWER MARKET

        FERC issued an Order in 1997 approving the establishment of PJM as an Independent
System Operator (ISO) to administer transmission service under a poolwide transmission tariff
and provide open access transmission service on a poolwide basis. The ISO began operation in
January 1998 and is responsible for system operations and regional transmission planning. In
addition, the Commission decided that the independent body that operates the ISO may also
operate the PJM power exchange. The Commission approved the power pool's use of single,
non-pancaked transmission rates to access the eight transmission systems that make up PJM.
Pursuant to a rate design in effect since April 1997, each transmission owner within PJM has its
own transmission rate, whereby the transmission customer will pay a single rate based on the
cost of the transmission system where the generating capacity is delivered. The Commission
also approved, effective April 1998, locational marginal pricing for managing scarce
transmission capability. This method is based on price differences in energy at the various
locations on the transmission system. In March 1999, the FERC approved market-based rates for
pricing sales through the PJM energy market and a market monitoring plan.

        In December 1999 and February 2000, the FERC issued its landmark Orders No. 2000 and
2000-A. Order 2000 requires all public utilities to join or form a regional transmission
organization (RTO) in furtherance of the FERC's goal to increase competition in the wholesale
generation market. The qualifications to become certified as an RTO expand on the
independence, scope, transmission service, ratemaking, and expansion planning elements needed
to achieve approval as an ISO. Since PJM is already a FERC-approved ISO and because it
exceeds all the requirements of an RTO, the Company does not anticipate any difficulties in PJM
achieving this certification.

        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. The PJM members have transformed the previous coordinated cost-based
pool dispatch into a bid-based regional energy market operating under a standard of transmission
service comparability. Irrespective of the Company's divestiture of its Generation Assets and the
availability of customer choice, the Company continues to be a transmission-owning member of
PJM.

ENVIRONMENTAL MATTERS

OIL SPILL AT THE CHALK POINT GENERATING STATION

          As discussed in Note (13) of the Notes to Consolidated Financial Statements,
Commitments and Contingencies, on April 7, 2000, approximately 139,000 gallons of oil leaked
from a pipeline at a generation station which was owned by the Company at Chalk Point in
Aquasco, Maryland. As of December 31, 2000, approximately $66 million in clean-up costs had
been incurred in connection with the oil spill; and it is currently anticipated that total costs
(excluding liability claims against the Company and fines or other monetary penalties, if any)
may be in the range of $70 million to $75 million. These costs, which have continued to be
incurred beyond December 31, 2000, consist principally of the costs to clean up the oil spill such
as labor, supplies, repair work on damaged properties, and the rental of equipment.

          In addition, as a result of the oil spill, nine class action lawsuits and one lawsuit on behalf
of two individuals have been filed against the Company. At this early stage, no determination
has been made as to the merits of the claims. The Company has indicated its willingness to settle
appropriate claims arising from the oil spill. Otherwise, the Company intends to vigorously
contest the lawsuits. Fines or penalties, if any, assessed by government authorities are not
expected to be recoverable from the Company's insurance carrier. The Company does not
believe that fines or penalties assessed, if any, will have a material adverse effect on its financial
position; however, such fines or penalties, if any, could have a material adverse effect on the
Company's results of operations in the fiscal quarter in which they are assessed. On December
20, 2000, the Office of Pipeline Safety of the Department of Transportation (DOT) issued a
Notice of Probable Violation and proposed a civil penalty in the amount of approximately
$674,000. The Company plans to contest certain facts and findings by the DOT.

          For the year ended December 31, 2000, the Company recorded the net amount of $1
million in operating expense as a result of the oil spill. This amount represents an accrual of $75
million in total oil spill related clean-up costs, net of $5 million in insurance proceeds received
through June 30, 2000 (the date the amount was recorded by the Company) and an additional
$69 million in probable recoveries from its insurance carriers. Through December 31, 2000,
$35.8 million has been received from the carriers. However, no assurances can be given that the
remaining amount due from the carriers will actually be received. The aggregate insurance
coverage available under the Company's general liability insurance policy with respect to this
event is $100 million. The Company will continue to assess the status of the oil spill clean-up
efforts, as necessary, for any significant changes in the estimated costs of completing the
remediation.

OTHER ENVIRONMENTAL MATTERS

         The Company is subject to federal, state and local legislation and regulation with respect
to environmental matters, including 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 2000, the Company participated in environmental assessments and clean-ups under these
laws at four 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 partially 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 Company's financial position or results of operations.

        Environmental liabilities in connection with violations of or noncompliance with
environmental laws and related to any asset sold to Southern Energy, arising prior to, on or after
the sale's December 19, 2000 closing date, have been assumed by Southern Energy, except for
any monetary fines or penalties imposed by a Governmental Authority to the extent arising out
of or relating to acts or omissions of the Company in respect to any asset sold to Southern
Energy. Liabilities arising in connection with the release, threatened release or cleanup of
hazardous substances, arising prior to, on or after the sale's closing date, have also been assumed
by Southern Energy, except for any environmental liability of the Company arising out of or in
connection with the disposal by, or on behalf of, the Company and release or threatened release,
prior to the sale's closing date of hazardous substances at any off-site location. Any
environmental liability arising out of, related to, or otherwise associated with the release of fuel
oil from the Ryceville-Piney Point Pipeline, as discussed in Note (13) of the Notes to
Consolidated Financial Statements, Commitments and Contingencies, will be retained and
discharged by the Company.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

MARKET RISK

        Market risk represents the potential loss arising from adverse changes in market rates and
prices. Certain of the Company's financial instruments are exposed to market risk in the form of
interest rate risk, equity price risk, and credit and nonperformance risk. The Company manages
its market risk in accordance with its established policies.

INTEREST RATE RISK

        The carrying value of the Company's long-term debt, which consists of first mortgage
bonds, medium-term notes, convertible debentures, recourse debt from institutional lenders, and
certain non-recourse debt was $1,736.3 million at December 31, 2000. The fair value of this
long-term debt, based mainly on current market prices or discounted cash flows using current
rates for similar issues with similar terms and remaining maturities, was $1,730.9 million at
December 31, 2000. The interest rate risk related to this debt was estimated as the potential
$100.1 million increase in fair value at December 31, 2000, that resulted from a hypothetical
10% decrease in the prevailing interest rates.

        PCI uses interest rate swap agreements to minimize its interest rate risk. The fair value of
these agreements at December 31, 2000, was approximately $29 million. The potential loss in
fair value from these agreements resulting from a hypothetical 10% adverse movement in base
interest rates was estimated at $.6 million at December 31, 2000.

EQUITY PRICE RISK

        The carrying value of the Company's marketable securities, which consist primarily of
preferred stocks with mandatory redemption features, was $231.4 million (including net
unrealized losses of $11.5 million) at December 31, 2000. This includes preferred stock issued
by two California utilities with a carrying value of $20.3 million (including net unrealized losses
of $8 million) at December 31, 2000. Subsequently, the market value of such preferred stock has
continued to decline. The fair value of marketable securities, based on quoted market prices, is
equivalent to its carrying value at December 31, 2000. The equity price risk related to these
securities was estimated as the potential $23.1 million decrease in fair value at December 31,
2000, that resulted from a hypothetical 10% decrease in the quoted market prices.

CREDIT AND NONPERFORMANCE RISK

        The Company's forward agreements may be subject to credit losses and nonperformance by
the counterparties to the agreements. However, the Company anticipates that the counterparties
will be able to fully satisfy their obligations under the agreements. The Company does not
obtain collateral or other securities to support financial instruments subject to credit risk, but
monitors the credit standing of the counterparties.

NEW ACCOUNTING STANDARDS

        Refer to Note (2) of the Notes to Consolidated Financial Statements, Summary of
Significant Accounting Policies.


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 shareholders' equity and comprehensive income, and of cash flows
present fairly, in all material respects, the financial position of Potomac Electric Power Company
and its subsidiaries at December 31, 2000 and 1999, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 2000, in conformity with
accounting principles generally accepted in the United States of America. 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 auditing standards generally accepted in the United States of
America, which require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit includes examining,
on a test basis, evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our audits provide a
reasonable basis for the opinion expressed above.




PricewaterhouseCoopers LLP
Washington, D.C.
January 19, 2001

CONSOLIDATED STATEMENTS OF EARNINGS
POTOMAC ELECTRIC POWER COMPANY AND SUBSIDIARIES
For the Year Ended December 31,	2000	1999	1998
(Millions of Dollars, except per share data)
Operating Revenue
Utility	$2,237.5	$2,219.3	$2,068.9
Competitive operations	386.4	256.7	151.9
Gain on divestiture of generation assets	423.8	-	-
Total Operating Revenue	3,047.7	2,476.0	2,220.8
Operating Expenses
Fuel and purchased energy	1,206.2	1,025.8	818.8
Other operation and maintenance	409.8	400.6	372.8
Depreciation and amortization	247.6	272.8	263.9
Other taxes	207.4	201.1	204.4
Interest	211.5	195.3	198.1
Impairment loss	45.7	-	-
Total Operating Expenses	2,328.2	2,095.6	1,858.0
Loss from Equity Investments, Principally Telecommunication Entities	(17.1)	(9.6)	(8.5)
Operating Income	702.4	370.8	354.3
Distributions on Preferred Securities of Subsidiary Trust	9.2	9.2	5.7
Income Tax Expense	341.2	114.5	122.3
Net Income	352.0	247.1	226.3
Dividends on Preferred Stock	5.5	7.9	11.4
Redemption Premium/Expenses on Preferred Stock	-	1.0	6.6
Earnings Available for Common Stock	$346.5	$238.2	$208.3
Earnings Per Share of Common Stock
Basic	$3.02	$2.01	$1.76
Diluted	$2.96	$1.98	$1.73
Cash Dividends Per Share of Common Stock	$1.66	$1.66	$1.66
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements

CONSOLIDATED BALANCE SHEETS
POTOMAC ELECTRIC POWER COMPANY AND SUBSIDIARIES
Assets	December 31, 2000             1999
(Millions of Dollars)
CURRENT ASSETS
Cash and cash equivalents	$1,864.6	$98.7
Marketable securities	231.4	203.2
Accounts receivable, less allowance for uncollectible          accounts of $9.1 and $8.0	478.4	295.0
Fuel, materials and supplies - at average cost	36.4	192.0
Prepaid expenses	413.6	35.9
Total Current Assets	3,024.4	824.8
INVESTMENTS AND OTHER ASSETS
Investment in financing leases	589.5	664.3
Operating lease equipment - net of accumulated           depreciation of $135.4 and $113.9	54.6	77.9
Regulatory assets, net	-	411.7
Other	637.0	407.5
Total Investments and Other Assets	1,281.1	1,561.4
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment	4,284.7	6,784.3
Accumulated depreciation	(1,562.9)	(2,259.9)
Net Property, Plant and Equipment	2,721.8	4,524.4
Total Assets	$7,027.3	$6,910.6
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements

CONSOLIDATED BALANCE SHEETS
POTOMAC ELECTRIC POWER COMPANY AND SUBSIDIARIES
Liabilities and Shareholders' Equity	December 31,             2000             1999
(Millions of Dollars)
CURRENT LIABILITIES
Short-term debt	$1,150.1	$347.0
Accounts payable and accrued payroll	273.8	239.0
Capital lease obligations due within one year	15.2	20.8
Interest and taxes accrued	814.4	85.1
Other	181.9	91.6
Total Current Liabilities	2,435.4	783.5
DEFERRED CREDITS
Regulatory liabilities, net	186.1	-
Income taxes	418.7	1,052.8
Investment tax credits	28.3	50.0
Other	21.4	22.0
Total Deferred Credits	654.5	1,124.8
LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS	1,859.6	2,867.0
COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES      OF SUBSIDIARY TRUST WHICH HOLDS SOLELY PARENT JUNIOR      SUBORDINATED DEBENTURES	125.0	125.0
PREFERRED STOCK
Serial preferred stock	40.8	50.0
Redeemable serial preferred stock	49.5	50.0
Total Preferred Stock	90.3	100.0
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS' EQUITY
Common stock, $1 par value - authorized 200,000,000 shares,          issued 118,544,736 and 118,530,802 shares, respectively	118.5	118.5
Premium on stock and other capital contributions	1,027.3	1,025.4
Capital stock expense	(13.0)	(12.9)
Accumulated other comprehensive loss	(7.5)	(1.8)
Retained income	937.2	781.1
	2,062.5	1,910.3
Less cost of shares of common stock in treasury
(7,792,907 and zero shares, respectively)	(200.0)	-
Total Shareholders' Equity	1,862.5	1,910.3
Total Liabilities and Shareholders' Equity	$7,027.3	$6,910.6
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME
POTOMAC ELECTRIC POWER COMPANY AND SUBSIDIARIES
	Common Stock Shares       Par Value		Premium on Stock	Comprehensive     Income	Accumulated     Other Comprehensive  Income (Loss)	Cost of Treasury  Shares	Retained  Income
(Dollar Amounts in Millions)
BALANCE, DECEMBER 31, 1997	118,500,891	$118.5	$1,025.2		$6.5		$727.8
Net Income	-	-	-	$226.3	-	-	226.3
Other comprehensive income:
Add: Unrealized gain on marketable securities	-	-	-	4.2	4.2	-	-
Less: Gain included in net income	-	-	-	2.2	2.2	-	-
Income tax expense	-	-	-	0.7	0.7	-	-
Total comprehensive income	-	-	-	$227.6		-	-
Dividends:
Preferred stock	-	-	-		-	-	(11.4)
Common stock	-	-	-		-	-	(196.6)
Conversion of preferred stock	26,396	-	0.1		-	-	-
Redemption premium on preferred stock	-	-	-		-	-	(6.6)
BALANCE, DECEMBER 31, 1998	118,527,287	$118.5	$1,025.3		$7.8	$   -	$739.5
Net Income	-	-	-	$247.1	-	-	$247.1
Other comprehensive income:
Add: Loss included in net income	-	-	-	1.6	1.6	-	-
Income tax benefit	-	-	-	5.1	5.1	-
Less: Unrealized loss on marketable securities	-	-	-	16.3	16.3	-	-
Total comprehensive income	-	-	-	$237.5	-	-	-
Dividends:
Preferred stock	-	-	-		-	-	(7.9)
Common stock	-	-	-		-	-	(196.6)
Conversion of debentures	3,515	-	0.1		-	-	-
Redemption expense on preferred stock	-	-	-		-	-	(1.0)
BALANCE, DECEMBER 31, 1999	118,530,802	$118.5	$1,025.4		($1.8)	$   -	$781.1
Net Income	-	-	-	$352.0	-	-	$352.0
Other comprehensive income:
Add: Loss included in net income	-	-	-	0.3	0.3	-	-
Income tax benefit	-	-	-	3.1	3.1	-	-
Less: Unrealized loss on marketable securities	-	-	-	9.1	9.1	-	-
Total comprehensive income	-	-	-	$346.3		-	-
Dividends:
Preferred stock	-	-	-		-	-	(5.5)
Common stock	-	-	-		-	-	(190.4)
Cost of treasury shares	(7,792,907)	-	1.6			(200.0)
Conversion of stock options	13,934	-	0.3		-	-	-
Redemption expense on preferred stock	-	-	-		-	-	-
BALANCE, DECEMBER 31, 2000	110,751,829	$118.5	$1,027.3		($7.5)	($200.0)	$937.2
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements

CONSOLIDATED STATEMENTS OF CASH FLOWS
POTOMAC ELECTRIC POWER COMPANY AND SUBSIDIARIES
For the Year Ended December 31,	2000	1999	1998
(Millions of Dollars)
OPERATING ACTIVITIES
Net income	$352.0	$247.1	$226.3
Adjustments to reconcile net income to net cash      (used by) from operating activities:
Gain on divestiture of generation assets	(423.8)	-	-
Impairment loss	45.7	-	-
Depreciation and amortization	247.6	272.8	263.9
Changes in:
Accounts receivable and unbilled revenue	(184.5)	(46.1)	5.7
Fuel, materials and supplies	155.6	(70.0)	5.5
Regulatory liabilities/assets	(227.0)	(6.8)	(13.1)
Contract termination fee	(1.5)	(24.5)	-
Accounts payable	34.8	43.6	(20.9)
Net other operating activities	(20.3)	23.9	(50.2)
Net Cash (Used by) From Operating Activities	(21.4)	440.0	417.2
INVESTING ACTIVITIES
Net investment in property, plant and equipment	(225.5)	(200.3)	(206.2)
Proceeds from:
Divestiture of generation assets	2,741.0	-	-
Sale of aircraft	87.1	-	-
Sale or redemption of marketable securities, net of purchases	(38.2)	11.6	75.6
Sale of leased equipment, net of additions	-	19.4	105.9
Sale or distribution of other investments, net of purchases	(78.5)	(59.6)	9.3
Purchase of leveraged leases	-	(205.9)	-
Gain from liquidation of partnership, net of proceeds	-	(1.1)	-
Net other investing activities	(90.5)	-	-
Net Cash From (Used by) Investing Activities	2,395.4	(435.9)	(15.4)
FINANCING ACTIVITIES
Dividends on preferred and common stock	(195.9)	(204.5)	(208.0)
Redemption of preferred stock	(9.7)	(51.0)	(123.7)
Issuance of mandatorily redeemable preferred securities	-	-	125.0
Reacquisition of long-term debt, net of issuances	(1,007.4)	257.1	(158.7)
Repurchase of common stock	(200.0)	-	-
Issuance of short-term debt, net of repayments	803.1	7.8	46.7
Other financing activities	1.8	(0.8)	(3.1)
Net Cash (Used by) From Financing Activities	(608.1)	8.6	(321.8)
Net Increase In Cash and Cash Equivalents	1,765.9	12.7	80.0
Cash and Cash Equivalents at Beginning of Year	98.7	86.0	6.0
CASH AND CASH EQUIVALENTS AT END OF YEAR	$1,864.6	$98.7	$86.0
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest (net of capitalized interest of $3.4,       $1.8, and $.7) and income taxes:
Interest	$108.4	$194.0	$198.6
Income taxes	$45.8	$(20.7)	$68.9
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITY
Transfer of Benning and Buzzard Point stations to Pepco Energy Services	$53.6	$-	$-
_________________________________________________________________________________________________________ The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)    ORGANIZATION, DIVESTITURE, AND SEGMENT INFORMATION

ORGANIZATION

        Potomac Electric Power Company (Pepco or the Company) is engaged in the transmission
and distribution of electric energy in the Washington, D.C. (D.C.), metropolitan area (the Utility
or Utility Operations). The Company is also engaged in the sale of electricity, natural gas, and
telecommunications in markets throughout the mid-Atlantic region through its wholly owned
nonregulated subsidiary, Pepco Holdings, Inc. (PHI). Potomac Electric Power Company Trust I
(the Trust) and Edison Capital Reserves Corporation (Edison), are also wholly owned
subsidiaries of the Company.

        In May 1999, Pepco reorganized its nonregulated subsidiaries into two major operating
groups to compete for market share in deregulated markets. As part of the reorganization, a new
unregulated company, PHI, was created in 1999 as the parent company of its two wholly owned
subsidiaries, Potomac Capital Investment Corporation (PCI) and Pepco Energy Services, Inc.
(Pepco Energy Services). Additionally, in September 2000, PepMarket.com, LLC, (PepMarket)
was organized as a third direct, wholly owned subsidiary of PHI.

        PCI will continue to manage its diversified portfolio of financial investments and grow its
new operating businesses that provide telecommunication services and utility industry-related
services. As discussed in Note (5) of the Notes to Consolidated Financial Statements, Loss from
Equity Investments, Principally Telecommunication Entities, PCI's telecommunication products
and services are provided through its wholly owned subsidiary's 50% equity interest in a joint
venture, formed in December 1997, known as Starpower Communications, LLC (Starpower).

        Pepco Energy Services provides nonregulated energy and energy related services in the
mid-Atlantic region. Its products include electricity, natural gas, energy efficiency contracting
equipment retrofits, fuel management, equipment operation and maintenance and appliance
warranties. These products are sold in bundles or individually to large commercial and industrial
customers and to residential customers.

         PepMarket, which began operations on December 1, 2000, will earn fee income by offering
Internet-based procurement services to businesses and institutional clients in the D.C./Baltimore
metropolitan region. As of December 31, 2000, Pepco has invested $11 million of its planned
commitment of $16 million to PepMarket.

        The Trust, a Delaware statutory business trust and a wholly owned subsidiary of the
Company, was established in April 1998. The Trust exists for the exclusive purposes of (i)
issuing Trust securities representing undivided beneficial interests in the assets of the Trust, (ii)
investing the gross proceeds from the sale of the Trust Securities in Junior Subordinated
Deferrable Interest Debentures issued by the Company, and (iii) engaging only in other activities
as necessary or incidental to the foregoing. See Note (10) of the Notes to Consolidated Financial
Statements, Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary
Trust, for additional information.

        Edison, a Delaware Investment Holding Company and wholly owned subsidiary of the
Company, was established in November 2000. Edison exists for the purpose of managing and
investing a significant portion of the proceeds received from the divestiture.

DIVESTITURE

        On June 7, 2000, the Company entered into an agreement (the Agreement) with Mirant
Corp., formerly Southern Energy Inc. (Southern Energy) to sell total capacity of 5,154
megawatts in four generating stations located in Maryland and Virginia, and six purchased
capacity contracts totaling 735 megawatts (the Generation Assets) for $2.75 billion (including
other related generation assets). The Agreement was reached after Southern Energy was selected
by the Company as the winning bidder in its auction process that was held to select the buyer of
its Generation Assets. The divestiture closed on December 19, 2000 and resulted in the
Company's recognition of a pre-tax gain of approximately $423.8 million ($182 million net of
income tax or $1.58 per share). Concurrently, the Company transferred its Benning Road and
Buzzard Point generating plants, which were not included in the Generation Assets divested to
Southern Energy, to Pepco Energy Services. These power plants are located in D.C. and have a
total installed capacity of 806 megawatts. These stations will function as exempt wholesale
generators and be operated and maintained by Southern Energy pursuant to an initial three-year
contract with Pepco Energy Services.

        As a result of the divestiture and the transfer of its Benning Road and Buzzard Point
stations, as well as the volatility of energy prices and the availability of current financial
information derived from the completion of the Company's 2001 budgeting cycle, the Company
determined that it was necessary to assess whether the carrying amounts of these generating
stations were recoverable. Based on this assessment, the stations were determined to be impaired
and were written down to their fair value by recognizing a pre-tax impairment loss of $40.3
million in the fourth quarter of 2000 ($24.1 million net of income tax or 20 cents per share). The
fair value of approximately $33 million was determined using the present value of their
estimated expected future cash flows.

        In a separate transaction, on May 19, 2000, the Company reached an agreement with PPL
Global, Inc., and Allegheny Energy Supply Company, LLC, to sell its 9.72 percent interest in the
Conemaugh Generating Station (Conemaugh) for approximately $156 million. Conemaugh is
located near Johnstown, Pennsylvania, and consists of two baseload units totaling approximately
1,700 megawatts of capacity. The Conemaugh sale closed on January 8, 2001, and resulted in
the recognition of a pre-tax gain of approximately $39 million, which will be recorded in the first
quarter of 2001. Additionally, as the utility industry continued its transition to a competitive
environment, retail access for generation services was made available to all Maryland customers
on July 1, 2000, and to D.C. customers on January 1, 2001.
 
        As part of the agreement with Southern Energy to divest its generation assets, the Company
also signed a Transition Power Agreement (TPA) with Southern Energy. This TPA was
necessary because the Company will continue to be obligated, as the incumbent electric utility, to
supply the electric power needs of all of its current Maryland and D.C. customers that cannot or
do not choose an alternate electric power service provider during a four-year transition period to
retail access. This service, called Standard Offer Service, is required by settlement agreements
approved by both the Maryland and D.C. Public Service Commissions as part of the deregulation
of electric power generation and the initiation of customer choice.

        Under the TPA, the Company has the option of acquiring all of the energy and capacity that
is needed for Standard Offer Service from Southern Energy at prices that are below the
Company's current cost-based billing rates for Standard Offer Service, thereby providing the
Company with a built-in profit margin on all Standard Offer Service sales that the Company
acquires from Southern Energy. Under the settlement agreements mentioned above, the
Company will share such profit amounts with customers on an annual cycle basis, beginning
with the period July 1, 2000 to June 30, 2001 in Maryland and from February 9, 2001 to
February 8, 2002 in D.C. (the Generation Procurement Credit or "GPC").

        In both jurisdictions, amounts shared with customers each year are determined only after the
Company recovers certain guaranteed annual reductions to customer rates. In addition, because
the annual cycle for the GPC in Maryland began on July 1, 2000, the Company supplied
Standard Offer Service from its traditional sources until the Generation Assets were sold and,
thus, recorded losses on Standard Offer Services sales during this period, mostly because of
higher summer generating costs. Therefore, profit from Standard Offer Service sales in
Maryland between January 8, 2001 and June 30, 2001 will be recorded as income to the
Company until both the guaranteed rate reduction amount and the Standard Offer Service losses
incurred in 2000 are recovered. Once such amounts are recovered, profit is shared with
customers in Maryland generally on a 50/50 basis.

SEGMENT INFORMATION

        The Company has identified the Utility's operations, the Trust, and Edison (Utility
Segment) and PHI's operations (Competitive Segment) as its two reportable segments. The
following table presents information about the Company's reportable segments (in millions of
dollars, except per share amounts).

For the year ended December 31,
2000
				Competitive Segment
		Utility Segment		PCI		Pepco Energy    Services		PepMarket		Total  PHI		Consolidated
Revenue:
Utility	$	2,237.5	$	-	$	-	$	-	$	-	$	2,237.5
Gain on divestiture of generation assets		423.8		-		-		-		-		423.8
Financial investments		-		101.8		-		-		101.8		101.8
Energy services		-		-		236.4		-		236.4		236.4
Utility industry services		-		48.1		-		-		48.1		48.1
Other		-		-		-		0.1		0.1		0.1
Total Revenue		2,661.3		149.9		236.4		0.1		386.4		3,047.7
Expenses:
Fuel and purchased energy		1,014.7		-		191.5		-		191.5		1,206.2
Operating expenses and other		515.9		41.3		57.8		2.2		101.3		617.2
Depreciation and amortization		223.9		21.5		2.1		0.1		23.7		247.6
Interest		155.5		54.4		1.6		-		56.0		211.5
Income tax expense (benefit)		352.9		(6.2)		(4.7)		(0.8)		(11.7)		341.2
Distributions on preferred securities of subsidiary Trust		9.2		-		-		-		-		9.2
Impairment loss		40.3		5.4		-		-		5.4		45.7
Total Expenses		2,312.4		116.4		248.3		1.5		366.2		2,678.6
(Loss) Income from Equity Investments,     Principally Telecommunication Entities		-		(20.2)		3.1		-		(17.1)		(17.1)
Net Income (Loss)	$	348.9	$	13.3	$	(8.8)	$	(1.4)	$	3.1	$	352.0
Earnings (Loss) Per Share	$	2.99	$	0.12	$	(0.08)	$	(0.01)	$	0.03	$	3.02
Total Assets	$	6,163.4	$	1,232.7	$	163.1	$	13.0	$	1,408.8	$	7,572.2
Expenditures for Assets	$	225.5	$	1.8	$	14.8	$	8.9	$	25.5	$	251.0
1999
				Competitive Segment
		Utility Segment		PCI		Pepco Energy    Services		PepMarket		Total PHI		Consolidated
Revenue:
Utility	$	2,219.3	$	-	$	-			$	-	$	2,219.3
Financial investments		-		105.0		-		-		105.0		105.0
Energy services		-		-		133.3		-		133.3		133.3
Utility industry services		-		18.4		-		-		18.4		18.4
Total Revenue		2,219.3		123.4		133.3		-		256.7		2,476.0
Expenses:
Fuel and purchased energy		921.7		-		104.1		-		104.1		1,025.8
Operating expenses and other		526.9		36.1		38.7		-		74.8		601.7
Depreciation and amortization		247.5		24.0		1.3		-		25.3		272.8
Interest		143.4		50.3		1.6		-		51.9		195.3
Income tax expense (benefit)		142.6		(24.1)		(4.0)		-		(28.1)		114.5
Distributions on preferred securities of subsidiary Trust		9.2		-		-		-		-		9.2
Total Expenses		1,991.3		86.3		141.7		-		228.0		2,219.3
(Loss) Income from Equity Investments, Principally Telecommunication Entities		-		(10.4)		.8		-		(9.6)		(9.6)
Net Income (Loss)	$	228.0	$	26.7	$	(7.6)		-	$	19.1	$	247.1
Earnings (Loss) Per Share	$	1.85	$	.22	$	(.06)	$	-	$	.16	$	2.01
Total Assets	$	5,902.8	$	1,238.8	$	44.6	$	-	$	1,283.4	$	7,186.2
Expenditures for Assets	$	200.3	$	0.4	$	2.4	$	-	$	2.8	$	203.1
1998
				Competitive Segment
		Utility Segment		PCI		Pepco Energy    Services		PepMarket		Total  PHI		Consolidated
Revenue:
Utility	$	2,068.9	$	-	$	-		-	$	-	$	2,068.9
Financial investments		-		112.1		-		-		112.1		112.1
Energy services		-		-		28.0		-		28.0		28.0
Utility industry services		-		11.8		-		-		11.8		11.8
Total Revenue		2,068.9		123.9		28.0		-		151.9		2,220.8
Expenses:
Fuel and purchased energy		805.7		-		13.1		-		13.1		818.8
Operating expenses and other		533.6		27.2		16.4		-		43.6		577.2
Depreciation and amortization		239.8		24.1		-		-		24.1		263.9
Interest		141.9		55.9		0.3		-		56.2		198.1
Income tax expense (benefit)		131.0		(8.1)		(0.6)				(8.7)		122.3
Distributions on preferred securities of subsidiary Trust		5.7		-		-		-		-		5.7
Total Expenses		1,857.7		99.1		29.2		-		128.3		1,986.0
Loss from Equity Investments, Principally Telecommunication Entities		-		(8.5)		-		-		(8.5)		(8.5)
Net Income (Loss)	$	211.2	$	16.3	$	(1.2)		-	$	15.1	$	226.3
Earnings (Loss) Per Share	$	1.63	$	.14	$	(.01)	$	-	$	.13	$	1.76
Total Assets	$	5,817.1	$	1,000.8	$	31.0	$	-	$	1,031.8	$	6,848.9
Expenditures for Assets	$	206.2	$	0.3	$	2.5	$	-	$	2.8	$	209.0
The Company's revenues from external customers are earned primarily within the United States and principally all of the Company's long-lived assets are held in the United States. In addition, there were no material transactions between segments.
Total segment assets of $7,572.2 million, $7,186.2 million, and $6,848.9 million, as of December 31, 2000, 1999, and 1998, respectively, include $510.1 million, $252.9 million, and $243.4 million, representing the utility segment's investment in PHI and $34.8 million, $22.7 million, and $31.4 million, of intersegment net receivables. As of December 31, 2000, 1999, and 1998, respectively, these amounts are eliminated in consolidation and therefore they are not reflected in the Company's total assets as recorded on the accompanying Consolidated Balance Sheets.

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

GENERAL

        The Utility's transmission and distribution operations are regulated by the Maryland Public
Service Commission (Maryland Commission) and the D.C. Public Service Commission (D.C.
Commission) and its wholesale business is regulated by the Federal Energy Regulatory
Commission (FERC). The Company complies with the Uniform System of Accounts prescribed
by FERC and adopted by the Maryland and D.C. Commissions.

        The preparation of these consolidated 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, the 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. Certain prior year amounts have been reclassified in order to conform to the
current year presentation.

PRINCIPLES OF CONSOLIDATION

        The accompanying consolidated financial statements present the financial results of the
Company and its wholly owned subsidiaries. All intercompany balances and transactions have
been eliminated.

        Investments in entities in which the Company has a 20% to 50% interest are accounted for
using the equity method. Under the equity method, investments are carried at cost and adjusted
for the Company's proportionate share of the investments' undistributed earnings or losses. Refer
to Note (5) of the Notes to Consolidated Financial Statements, Loss from Equity Investments,
Principally Telecommunication Entities for additional information.

REVENUE

        The Company classifies its revenue as Utility and Competitive Operations. Utility revenue
consists of the Utility's operations, the Trust, and Edison, and Competitive Operations revenue
consists of PHI's operations.

        The Utility's revenue for services rendered but unbilled as of the end of each month is
accrued. At December 31, 2000 and 1999, $85.6 million and $77.2 million in accrued unbilled
revenue, respectively, was recorded. These amounts are included in the accounts receivable
balance on the accompanying consolidated balance sheets. The amounts received for the sale of
energy and resales of purchased energy to other utilities and to power marketers is included in
Utility revenue. Amounts received, through July 1, 2000 in Maryland and December 31, 2000 in
D.C., for such interchange deliveries were components of the Company's fuel rates.

        Interchange deliveries include transactions in the bilateral energy sales marketplace, where
wholesale power sales tariffs allow both sales from Company-owned generation and sales of
energy purchased from other market participants. As discussed in Note (1) Organization,
Divestiture, and Segment Information, on December 19, 2000, the Company divested its
Generation Assets.

        Revenue from Pepco Energy Services' energy services contracts and from PCI's utility
industry services contracts is recognized using the percentage-of-completion method of revenue
recognition, which recognizes revenue as work progresses on the contract. Revenue from Pepco
Energy Services' electric and gas marketing businesses and from PepMarket's business is
recognized as services are rendered.

ENVIRONMENTAL REMEDIATION COSTS

          The Company accrues environmental remediation costs at the time that management
determines that it is probable that an asset has been impaired or that a liability has been incurred
and the amount of the loss can be reasonably estimated. Environmental remediation costs are
charged as an operating expense unless the costs extend the life of an asset or prevent
environmental contamination that has yet to occur, in which case the costs are capitalized.
Amounts that the Company has determined are probable of recovery from third parties, such as
insurance carriers, are netted against the operating expense line item. The amount that is
probable of recovery from third parties and the anticipated liability for environmental
remediation costs are separately recorded. Amounts accrued for probable environmental
remediation costs that may be incurred in the future are not measured on a discounted basis.

CASH AND CASH EQUIVALENTS

        Cash and cash equivalents include cash on hand, money market funds and commercial
paper with original maturities of three months or less. The cash and cash equivalents balance at
December 31, 2000 includes approximately $1.8 billion in proceeds from the divestiture of the
Generation Assets that have been invested by Edison.

MARKETABLE SECURITIES

        Marketable securities consist primarily of preferred stocks with mandatory redemption
features, which are classified as "available for sale" for financial reporting purposes. Net
unrealized gains or losses on such securities are reflected, net of tax, in shareholders' equity.

        Included in net unrealized gains and losses are gross unrealized gains of $.3 million and
gross unrealized losses of $11.8 million at December 31, 2000 and gross unrealized gains of $2
million and gross unrealized losses of $4.7 million at December 31, 1999.

        In determining gross realized gains and losses on sales or maturities of securities, specific
identification is used. Gross realized gains were $1.1 million, $.6 million, and $4.7 million in
2000, 1999, and 1998, respectively. Gross realized losses were $1.4 million, $2.2 million, and
$2.5 million in 2000, 1999, and 1998, respectively.

At December 31, 2000, the contractual maturities for mandatorily redeemable preferred stock are
$99.6 million within one year, $37.1 million from one to five years, $89.7 million from five to 10
years and $15.8 million for over 10 years.

LEASING ACTIVITIES

        Income from investments in direct financing leases and leveraged lease transactions, in
which the Company is an equity participant, is accounted for 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
financing 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 constant rate of return on the
positive net investment.

        Investments in equipment under operating leases are stated at cost, less accumulated
depreciation. Depreciation is recorded on a straight-line basis over the equipment's estimated
useful life.

OTHER ASSETS

        The other assets balance principally consists of real estate under development, equity and
other investments, prepaid benefit costs, and the SMECO contract termination fee which is
discussed in Note (12) of the Notes to Consolidated Financial Statements, SMECO Agreement.

SHORT-TERM DEBT

        Short-term financing requirements have been principally satisfied through the sale of
commercial promissory notes. Interest rates for short-term financing during 2000 ranged from
5.77% to 6.63%. Additionally, a minimum 100% line of credit back-up for outstanding
commercial promissory notes is maintained. This line of credit was unused during 2000, 1999,
and 1998.

AMORTIZATION OF DEBT ISSUANCE AND REACQUISITION COSTS

        Expenses incurred in connection with the issuance of long-term debt, including premiums
and discounts associated with such debt, are deferred and amortized 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.

FUEL COSTS

        Effective July 1, 2000, in Maryland (the date of commencement of customer choice) the
fuel clause was terminated. Effective February 9, 2001 (one month after the completion of the
sale of the Company's interest in Conemaugh), the fuel clause in D.C. will be terminated. For a
discussion of the Company's TPA and GPC refer to Note (1) Organization, Divestiture, and
Segment Information.

TREASURY STOCK

          The Company uses the cost method of accounting for treasury stock. Under the cost
method, the Company records the total cost of the treasury stock as a reduction to its
shareholders' equity on the face of its consolidated balance sheets. Additionally, stock held in
treasury is not considered outstanding for the purposes of computing the Company's earnings per
share.

NEW ACCOUNTING STANDARDS

        In June 1998, the Financial Accounting Standards Board issued Statement of Financial
Accounting Standards No. 133 (SFAS 133) entitled, "Accounting for Derivative Instruments and
Hedging Activities." SFAS 133 establishes accounting and reporting standards for derivative
instruments and hedging activities. The effective date of SFAS No. 133 has been delayed and
will become effective for the Company's 2001 calendar year financial statements. Accordingly,
we will adopt SFAS 133 on January 1, 2001. At that date, the cumulative effect of the
implementation of SFAS 133 did not have a material impact on the Company's consolidated
results of operations, financial position, or cash flows.

(3)    LEASING ACTIVITIES

        The investment in financing leases was comprised of the following at December 31:

	2000	1999
	(Millions of Dollars)
Energy leveraged leases	$469.3	$433.3
Aircraft leases	63.9	173.4
Other	56.3	57.6
Total	$589.5	$664.3

        The components of the net investment in finance leases at December 31, 2000, and 1999 are
summarized below:

At December 31, 2000:	Leveraged     Leases	Direct  Finance  Leases	Total       Finance        Leases
	(Millions of Dollars)
Rents receivable	$  345.1	$  95.8	$  440.9
Debt service payable from proceeds      of residual value, net	(1,503.7)	-	(1,503.7)
Estimated residual value	2,145.8	30.6	2,176.4
Less:   Unearned and deferred income	(485.7)	(38.4)	(524.1)
Investment in finance leases	501.5	88.0	589.5
Less:   Deferred taxes	(191.3)	(43.9)	(235.2)
Net Investment in Finance Leases	$  310.2	$  44.1	$  354.3
At December 31, 1999:
Rents receivable	$   354.7	$ 206.2	$  560.9
Debt service payable from proceeds of     residual value, net	(1,503.7)	-	(1,503.7)
Estimated residual value	2,149.3	60.9	2,210.2
Less:   Unearned and deferred income	(525.1)	(78.0)	(603.1)
Investment in finance leases	475.2	189.1	664.3
Less:   Deferred taxes	(150.9)	(35.8)	(186.7)
Net Investment in Finance Leases	$   324.3	$ 153.3	$  477.6

        Income recognized from leveraged leases was comprised of the following:

For the Year Ended December 31,	2000	1999	1998
	(Millions of Dollars)
Pre-tax earnings from leveraged leases	$37.5	$20.5	$13.4
Investment tax credit recognized	.8	.9	.8
Income from leveraged leases, including      investment tax credit	38.3	21.4	14.2
Income tax expense (credit)	7.5	2.3	(.5)
Net Income from Leveraged Leases	$30.8	$19.1	$14.7

        Rents receivable from leveraged leases are net of non-recourse debt. Minimum lease
payments receivable from finance leases, for each of the years 2001 through 2005 and thereafter,
are $20.8 million, $19.1 million, $11.3 million, $9.2 million, $8.4 million, and $520.7 million,
respectively.

        In July and November 1999, PCI entered into two similar leveraged lease transactions with
eight Dutch Municipal owned entities, for a total of $1.3 billion. These transactions involved the
purchase and leaseback of 38 gas transmission and distribution networks, located throughout the
Netherlands, over base lease terms approximating 25 years. These transactions were financed
with approximately $1.1 billion of third-party, non-recourse debt at commercial rates for a period
of approximately 25 years. PCI's net investment in these finance leases was approximately $193
million and was funded primarily through the Medium-Term Note program.

(4)    PROPERTY, PLANT AND EQUIPMENT

        As discussed in Note (1) of the Notes to Consolidated Financial Statements, Organization,
Divestiture, and Segment Information, the Company divested its Generation Assets in December
2000 and divested its interest in Conemaugh in January 2001.

        Property, plant and equipment is comprised of the following.

At December 31, 2000	Original      Cost	Accumulated  Depreciation	Net        Book Value
	(Millions of Dollars)
Generation	$ 92.0	$   19.0	$ 73.0
Distribution	3,046.1	1,142.1	1,904.0
Transmission	698.2	226.3	471.9
General	304.3	174.9	129.4
Construction work in progress	57.7	-	57.7
Nonoperating property	86.4	.6	85.8
Total	$4,284.7	$1,562.9	$2,721.8
At December 31, 1999
Generation	$2,650.0	$  805.6	$1,844.4
Distribution	2,943.1	1,059.6	1,883.5
Transmission	719.4	225.2	494.2
General	360.4	169.0	191.4
Construction work in progress	86.7	-	86.7
Nonoperating property	24.7	.5	24.2
Total	$6,784.3	$2,259.9	$4,524.4

        The nonoperating property amounts include balances for electric plant held for future use.

        Property, plant and equipment includes regulatory assets of $41 million and $44 million at
December 31, 2000 and 1999, respectively, which are accounted for pursuant to Statement of
Financial Accounting Standards No. 71 (SFAS 71) "Accounting for the Effects of Certain Types
of Regulation."

        The cost of additions to, and replacements or betterments of, retirement units of property
and plant is capitalized. Such costs include 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 3.5% for the Company's transmission and distribution system
property in 2000, 1999 and 1998.

(5)     LOSS FROM EQUITY INVESTMENTS, PRINCIPALLY
         TELECOMMUNICATION ENTITIES

        PCI and Pepco Energy Services have investments ranging from 20% to 50% in certain
businesses, which are accounted for using the equity method. The most significant equity
investment is PCI's joint venture in Starpower which is discussed in detail below. Investments
that are accounted for using the equity method are as follows.

Entity	Ownership    Interest	Share of (Loss)Income			Net Investment
		2000	1999	1998		2000	1999
Starpower	50%	$(20.2)	$(12.2)	$(10.4)		$118.2	$39.6
Metricom D.C., LLC      (Metricom)	20%	-	(.8)	(.8)		-	-
Cove Point LNG, LP      (Cove Point)	50%	-	2.6	2.7		-	10.4
Viron/Pepco Services, Inc.	50%	3.1	.8	-		1.8	.8
Total		$ (17.1)	$  (9.6)	$ (8.5)		$120.0	$50.8

        The total (loss)/income shown above is presented prior to the recognition of PHI's tax
expense/benefit.

        In October 1999, a subsidiary of PHI sold its 20% equity interest in Metricom. The sale
resulted in the recognition of an after-tax gain of approximately $1.7 million. On January 11,
2000, PCI sold its 50% interest in Cove Point to Columbia Energy Group for total proceeds of
$40.7 million. This transaction resulted in an after-tax gain of $11.8 million, which was
recorded during the first quarter of 2000. The 50% investment in Viron/Pepco Services, Inc. was
created in 1999 to provide energy-savings performance contracting services to the Military
District of Washington.

STARPOWER

        PCI's telecommunication products and services are provided through Starpower, which was
formed in 1997 by wholly-owned subsidiaries of PCI and RCN Corporation. Each Starpower
partner initially committed to contribute a total of $150 million of equity to the joint venture over
a three-year period (1998-2000). This initial commitment was fulfilled by each partner during
the fourth quarter of 2000. Additionally, during the fourth quarter of 2000, each partner agreed
to contribute an additional $18 million to fund capital requirements until the capital requirements
budget for 2001 is finalized. As of December 31, 2000, PCI has invested a total of $162 million
of its $168 million commitment to Starpower.

        During the first quarter of 1998, RCN acquired Erols Internet (Erols). The majority of Erols
customers (approximately 197,000 out of a total of 316,000 in February 1998) were located in
Starpower's target market. These customer accounts, as well as certain associated network assets
and related liabilities, have been contributed by RCN to Starpower. Starpower has agreed to pay
$51.9 million ($78.6 million in assets, primarily goodwill, net of $26.7 million of unearned
revenue) through a ratable reduction of RCN's committed future capital contributions. As a
result of this transaction, Starpower is amortizing the acquisition premium principally over a
three-to-five year period, which commenced in February 1998.

A summary of Starpower's financial information is as follows.

			As of December 31,
Balance Sheets			2000	1999
			(Millions of Dollars)
Assets
Current assets			$ 98.1	$  32.6
Intangible assets, net of accumulated amortization of      $47.9 and $31.7			20.4	35.5
Property, plant and equipment, net of      accumulated depreciation of $28.2 and $16.3			229.7	112.3
Total Assets			$348.2	$180.4
Liabilities and Partners' Equity
Current liabilities			$108.0	$  61.5
Noncurrent liabilities			1.9	4.5
Accumulated deficit			(45.3)	(45.3)
Partners' equity			283.6	159.7
Total Liabilities and Partners' Equity			$348.2	$180.4
	For the Year Ended December 31,
Income Statements		2000	1999	1998
		(Millions of Dollars)
Total revenue		$73.5	$60.3	$34.2
Cost of sales		22.2	16.0	10.1
Gross margin		51.3	44.3	24.1
Operating expense		64.5	45.4	21.2
(Loss) Earnings before interest, depreciation      and amortization		(13.2)	(1.)	2.9
Depreciation and amortization		28.2	23.7	24.3
Interest income		1.0	.4	.7
Loss		$40.4	$24.4	$20.7
PCI's Portion of Loss		$20.2	$12.2	$10.4

(6)    PENSIONS AND OTHER POSTRETIREMENT AND POSTEMPLOYMENT
        BENEFITS

        As discussed in Note (1) Organization, Divestiture, and Segment Information, on December
19, 2000, the Company divested its Generation Assets, including other related assets, to Southern
Energy. In accordance with the terms of the divestiture, with respect to generation employees
transferred between the Company and Southern Energy, the Company will only be responsible
for the portion of transferred employees' pensions that relate to service with the Company.

        As a result of the divestiture, in December 2000 the Company recognized a curtailment
charge of approximately $8.7 million. Since this charge is the direct result of the divestiture, it
was considered to be a transaction cost and was netted against the gain on divestiture of
Generation Assets on the Company's accompanying statements of earnings.
        The Company's General Retirement Program (Program), a noncontributory defined benefit
program, covers substantially all full-time employees of the Company. 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.

        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.
Health maintenance organization arrangements are available, or a 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 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.

        Pension expense included in net income was $3 million in 2000, $8.7 million in 1999 and
$9.3 million in 1998. Postretirement benefit expense included in net income was $18 million,
$15.8 million and $12.6 million in 2000, 1999, and 1998, respectively. The components of net
periodic benefit cost were computed as follows.

	Pension Benefits
	2000	1999	1998
	(Millions of Dollars)
Components of Net Periodic Benefit Cost Service cost Interest cost Expected return on plan assets Amortization of prior service cost Recognized actuarial loss Net Period Benefit Cost	$12.8 37.2 (48.7) 1.4      .3 $ 3.0	$ 13.2 34.9 (44.7) 1.4     3.9 $  8.7	$  13.0 33.9 (41.2) 1.4       2.2 $   9.3

	Other Benefits
		2000	1999	1998
		(Millions of Dollars)
Components of Net Periodic Benefit Cost Service cost Interest cost Expected return on plan assets Recognized actuarial loss Net Period Benefit Cost		$ 5.8 8.2 (1.9)     5.9 $18.0	$  5.4 6.6 (1.6)     5.4 $15.8	$  4.0 5.8 (1.5)      4.3 $12.6

        Assumed health care cost trend rates have a significant effect on the amounts reported for
the health care plans. The assumed health care cost trend rate used to measure the expected cost
benefits covered by the plan is 7.5%. This rate is expected to decline to 5.5% over the next four-
year period. A one percentage point change in the assumed health care cost trend rate would
have the following effects for fiscal year 2000.

	1-Percentage-Point	1-Percentage-Point
	Increase	Decrease
	(Millions of Dollars)
Effect on total of service and      interest cost components	$1.3	$(1.1)
Effect on postretirement benefit      obligation	$7.8	$(6.7)

        Pension program assets are stated at fair value and are composed of approximately 41% and
35% of cash equivalents and fixed income investments with the balance in equity investments
at December 31, 2000 and 1999, respectively.

        The following table sets forth the Program's funded status and amounts included in
Investments and Other Assets - Other on the Consolidated Balance Sheets.

	Pension Benefits
	2000	1999
	(Millions of Dollars)
Funded status	$  44.6	$21.5
Unrecognized actuarial loss	71.8	45.6
Unrecognized prior service cost Prepaid Benefit Cost	7.1  $123.5	10.8 $77.9
Weighted average assumptions as of      December 31
Discount rate	7.0%	7.0%
Expected return on plan assets	9.0%	9.0%
Rate of compensation increase	4.0%	4.0%
	Other Benefits
	2000	1999
	(Millions of Dollars)
Funded status	$(92.4)	$(87.0)
Unrecognized actuarial loss	49.6	49.3
Unrecognized initial net obligation	18.9	27.4
Accrued Benefit Cost	$(23.9)	$(10.3)
Weighted average assumptions as of      December 31
Discount rate	7.0%	7.0%
Expected return on plan assets	9.0%	9.0%
Rate of compensation increase	4.0%	4.0%

        The changes in benefit obligation and fair value of plan assets are presented in the following
table.

	Pension Benefits
	2000	1999
	(Millions of Dollars)
Change in Benefit Obligation
Benefit obligation at beginning of year	$533.2	$541.6
Service cost	12.8	13.3
Interest cost	37.2	34.9
Actuarial gain	(18.8)	(27.0)
Benefits paid	(32.1)	(29.6)
Benefit Obligation at End of Year	$532.3	$533.2
Accumulated Benefit Obligation at December 31	$471.9	$453.9
Change in Fair Value of Plan Assets
Fair value of plan assets at beginning of year	$554.7	$510.2
Actual return on plan assets	3.4	64.7
Company contributions	50.0	10.0
Benefits paid	(31.2)	(30.2)
Fair Value of Plan Assets at End of Year	$576.9	$554.7

	Other Benefits
	2000	1999
	(Millions of Dollars)
Change in Benefit Obligation
Benefit obligation at beginning of year	$ 105.6	$  93.4
Service cost	5.8	5.4
Interest cost	8.2	6.7
Actuarial loss	2.8	7.7
Benefits paid	(9.0)	(7.6)
Benefit Obligation at End of Year	$113.4	$105.6
Change in Fair Value of Plan Assets
Fair value of plan assets at beginning of year	$18.6	$15.6
Actual return on plan assets	.6	2.8
Company contributions	7.0	5.8
Benefits paid	(5.2)	(5.6)
Fair Value of Plan Assets at End of Year	$21.0	$18.6

        The Company also sponsors defined contribution savings plans covering all eligible
employees. Under these plans, the Company makes contributions on behalf of participants.
Company contributions to the plans totaled $5 million in 2000, $5.6 million in 1999, and $5.8
million in 1998.

        In February 2000 and 1999, the Company funded the 2000 and 1999 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 February 2001, the 2001 portion of the
Company's estimated liability will be funded. Assets are composed of cash equivalents, fixed
income investments and equity investments.

(7) Long-Term Debt and Capital Lease Obligations
The components of long-term debt and capital lease obligations are shown below.
			At December 31,
Interest Rate	Maturity		2000		1999
			(Millions of Dollars)
First Mortgage Bonds
Fixed Rate Series:
5-1/8%	April 1, 2001	$	15.0	$	15.0
5-7/8%	May 1, 2002		35.0		35.0
6-5/8%	February 15, 2003		40.0		40.0
5-5/8%	October 15, 2003		50.0		50.0
6-1/2%	September 15, 2005		100.0		100.0
6%	April 1, 2004		270.0		270.0
6-1/4%	October 15, 2007;
	PUT date
	October 15, 2004		175.0		175.0
6-1/2%	March 15, 2008		78.0		78.0
5-7/8%	October 15, 2008		50.0		50.0
5-3/4%	March 15, 2010		16.0		16.0
9%	June 1, 2021		100.0		100.0
6%	September 1, 2022		30.0		30.0
6-3/8%	January 15, 2023		37.0		37.0
7-1/4%	July 1, 2023		100.0		100.0
6-7/8%	September 1, 2023		100.0		100.0
5-3/8%	February 15, 2024		42.5		42.5
5-3/8%	February 15, 2024		38.3		38.3
6-7/8%	October 15, 2024		75.0		75.0
7-3/8%	September 15, 2025		75.0		75.0
8-1/2%	May 15, 2027		75.0		75.0
7-1/2%	March 15, 2028		40.0		40.0
Variable Rate Series:
Adjustable rate	December 1, 2001		50.0		50.0
Total First Mortgage Bonds			1,591.8		1,591.8
Convertible Debentures
5%	September 1, 2002		115.0		115.0
Medium-Term Notes
Fixed Rate Series:
6.53%	December 17, 2001		100.0		100.0
7.46% to 7.60%	January 2002		40.0		40.0
7.64%	January 17, 2007		35.0		35.0
6.25%	January 20, 2009		50.0		50.0
7%	January 15, 2024		50.0		50.0
Variable Rate Series: Adjustable rate	June 1, 2027		8.1		8.1
Recourse Debt
5.00% - 5.99%	2001-2003		1.0		1.0
6.00% - 6.99%	2001-2005		282.3		361.6
7.00% - 8.99%	2001-2004		377.5		414.4
9.00% - 9.70%	2001		6.0		62.0
Nonrecourse debt			31.0		52.8
Net unamortized discount			(12.9)		(21.7)
Current portion			(938.5)		(147.5)
Net Long-Term Debt			1,736.3		2,712.5
Capital Lease Obligations			123.3		154.5
Long -Term Debt and Capital Lease Obligations		$	1,859.6	$	2,867.0

        The outstanding First Mortgage Bonds are secured by a lien on substantially all of the
Company's property, plant and equipment. Additional bonds may be issued under the mortgage
as amended and supplemented in compliance with the provisions of the indenture. As discussed
in Note (1) of the Notes to Consolidated Financial Statements, Organization, Divestiture, and
Segment Information, on December 19, 2000 the Company divested its Generation Assets to
Southern Energy. As a result of the divestiture the following First Mortgage Bonds will be
redeemed during January 2001: $15 million 5-1/8% Series due 2001, $35 million 5-7/8% Series
due 2002, $40 million 6-5/8% Series due 2003, $270 million 6% Series due 2004, and $50
million Adjustable Rate Series due 2001. This debt is classified as short-term on the
accompanying consolidated balance sheets at December 31, 2000.

        The interest rate on the $50 million Adjustable Rate series First Mortgage Bonds (to be
redeemed in January 2001) is adjusted annually on December 1, based upon the 10-year
"constant maturity" United States Treasury bond rate for the preceding three-month period ended
October 31, plus a market-based adjustment factor. Effective December 1, 2000, the applicable
interest rate is 6.99%. The applicable interest rate was 7.19% at December 1, 1999 and 6.09% at
December 1, 1998.

        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. In December 2000, this
series was called for early redemption on February 1, 2001.

        The $666.8 million of recourse debt is primarily from institutional lenders maturing at
various dates between 2001 and 2005. The interest rates of such borrowings ranged from 5% to
9.7%. The weighted average interest rate was 7.30% at December 31, 2000 and December 31,
1999.

        Long-term debt also includes $31 million of non-recourse debt, $3.2 million of which is
secured by aircraft currently under operating leases. The debt is payable in monthly installments
at rates of LIBOR (London Interbank Offered Rate) plus 1.25% with final maturity on August
15, 2001. In addition, non-recourse debt includes $21 million associated with a direct finance
lease which is due to mature in 2018. The remaining non-recourse debt of $6.8 million is related
to majority-owned real estate partnerships and is payable in monthly installments at a fixed rate
of interest of 9.66%, with final maturity on October 1, 2011.

        The aggregate amounts of maturities for utility long-term debt outstanding at December 31,
2000, are $625 million in 2001, $40 million in 2002, $50 million in 2003, zero in 2004, $100
million in 2005, and $1,175 million thereafter.

        Refer to Note (13) of the Notes to Consolidated Financial Statements, Commitments and
Contingencies, for a discussion of the Company's capital lease obligations.

(8) Income Taxes
The provision for income taxes, reconciliation of consolidated income tax expense, and components of consolidated deferred tax liabilities (assets) are shown below.
Provision for Income Taxes
		For the Year Ended December 31,
		2000		1999		1998
		(Millions of Dollars)
Current Tax Expense
Federal	$	465.8	$	57.2	$	111.2
State and local		114.9		16.9		12.1
Total Current Tax Expense		580.7		74.1		123.3
Deferred Tax Expense
Federal		(247.2)		42.8		(1.7)
State and local		(19.6)		1.2		4.3
Investment tax credits		27.3		(3.6)		(3.6)
Total Deferred Tax Expense		(239.5)		40.4		(1.0)
Total Income Tax Expense	$	341.2	$	114.5	$	122.3
Reconciliation of Consolidated Income Tax Expense
		For the Year Ended December 31,
		2000		1999		1998
		(Millions of Dollars)
Income Before Income Taxes	$	693.2	$	361.6	$	348.6
Income tax at federal statutory rate	$	242.6	$	126.5	$	122.0
Increases (decreases) resulting from
Depreciation		11.7		11.5		10.9
Removal costs		(5.6)		(5.0)		(6.0)
Allowance for funds used during construction		0.9		0.3		0.5
State income taxes, net of federal effect		63.3		11.8		10.7
Tax credits		(4.8)		(4.7)		(4.0)
Dividends received deduction		(3.4)		(4.1)		(4.4)
Reversal of previously accrued deferred taxes		(2.1)		-		(1.0)
Taxes related to divestitures at non-statutory rates		48.3		-		-
Other		(9.7)		(21.8)		(6.4)
Total Income Tax Expense	$	341.2	$	114.5	$	122.3

Components of Consolidated Deferred Tax Liabilities (Assets)
		At December 31,
		2000		1999
		(Millions of Dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other book to tax basis differences	$	500.8	$	903.9
Rapid amortization of certified pollution control        facilities and prepayment premium on debt retirement		4.9		45.0
Deferred taxes on amounts to be collected through        future rates		17.5		85.5
Deferred investment tax credit		(17.5)		(18.9)
Contributions in aid of construction		(42.4)		(34.3)
Conservation costs (demand side management)		-		42.5
Finance and operating leases		122.2		96.4
Alternative minimum tax		-		(27.6)
Assets with a tax basis greater than book basis		(23.8)		(28.5)
Customer Sharing		(98.1)		-
Transition Costs		(13.1)		-
Property taxes, contributions to pension plan, and other		(8.9)		4.8
Total Deferred Tax Liabilities, Net		441.6		1,068.8
Current portion of deferred tax liabilities      (included in Other Current Liabilities)		22.9		16.0
Total Deferred Tax Liabilities, Net - Non-Current	$	418.7	$	1,052.8

        The 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 net deferred tax liability applicable to Pepco's operations, which has not been
reflected in current service rates, represents income taxes recoverable through future rates, net
and is recorded as a regulatory asset on the balance sheet. No valuation allowance for deferred
tax assets was required or recorded at December 31, 2000 and 1999.

        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 Pepco's property continues to be normalized over the remaining service lives of the related
assets.

        The Company files a consolidated federal income tax return. The Company's federal
income tax liabilities for all years through 1995 have been 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 or results of operations.

OTHER TAXES

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

	2000	1999	1998
	(Millions of Dollars)
Gross receipts	$  90.1	$  91.8	$  98.4
Property	67.7	72.7	71.0
Payroll	9.7	9.7	10.9
County fuel-energy	16.8	16.4	15.8
Environmental, use and other	23.1	10.5	8.3
	$207.4	$201.1	$204.4

(9)    SERIAL PREFERRED STOCK AND REDEEMABLE PREFERRED STOCK

        The Company has authorized 7,750,000 shares of cumulative $50 par value Serial Preferred
Stock. At December 31, 2000 and 1999, there were 1,806,543 shares and 2,000,000 shares
outstanding, respectively. The various series of Preferred Stock outstanding and the per share
redemption price at which each series may be called by the Company are as follows.

	Redemption       Price	December 31,    2000              1999
		(Millions of Dollars)
$2.44 Series of 1957, 275,041 and 300,000 shares	$51.00	$13.7	$15.0
$2.46 Series of 1958, 213,942 and 300,000 shares	$51.00	10.7	15.0
$2.28 Series of 1965, 327,560 and 400,000 shares	$51.00	16.4	20.0
		$40.8	$50.0
$3.40 Series of 1992, 990,000 and 1,000,000 shares		$49.5	$50.0

        During March 2000, the Company repurchased the following Preferred Stock: 1,570 shares
of $2.44 series of 1957 at $37.50 per share; 5,028 shares of $2.46 series of 1958 at $37.50 per
share; 33,118 shares of $2.28 series of 1965 at $38.625 per share; 23,389 shares of $2.44 series
of 1957 at $41.50 per share; and 46,030 shares of $2.46 series of 1958 at $41.72 per share. The
repurchase totaled approximately $4.4 million.

        In May 2000, the Company repurchased 10,000 shares of Redeemable Preferred Stock,
$3.40 Series of 1992, at $49.50 per share. The repurchase totaled approximately $.5 million.

        In December 2000, the Company repurchased 39,322 shares of Serial Preferred Stock,
$2.28 series of 1965, at $37.875 per share and 35,000 shares of $2.46 series of 1958, at $38.90
per share. The repurchases totaled $1.5 million and $1.4 million, respectively.

        The shares of the $3.40 (6.80%) Series are subject to mandatory redemption, at par, through
the operation of a sinking fund that 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. The sinking fund
requirements through 2004 with respect to the Redeemable Serial Preferred Stock are $2 million
in 2002, and $2.5 million in 2003 and 2004.

        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 that are redeemable, must be made concurrently.

(10)   COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED
          SECURITIES OF SUBSIDIARY TRUST

        In May 1998, the Trust issued $125 million of 7-3/8% Trust Originated Preferred Securities
(TOPrS). The proceeds from the sale of the TOPrS to the public and from the sale of the
common securities of the Trust to the Company were used by the Trust to purchase from the
Company $128.9 million of 7-3/8% Junior Subordinated Deferrable Interest Debentures, due
June 1, 2038 (Junior Subordinated Debentures). The sole assets of the Trust are the Junior
Subordinated Debentures. The Trust will use interest payments received on the Junior
Subordinated Debentures to make quarterly cash distributions on the TOPrS. Accrued and
unpaid distributions on the TOPrS, as well as payment of the redemption price upon the
redemption and of the liquidation amount upon the voluntary or involuntary dissolution, winding
up or termination of the Trust, to the extent such funds are held by the Trust, are guaranteed by
the Company (Guarantee). The Guarantee, when taken together with the Company's obligation
under the Junior Subordinated Debentures and the Indenture for the Junior Subordinated
Debentures, and the Company's obligations under the declaration of Trust for the TOPrS,
including its obligations to pay costs, expenses, debts and liabilities of the Trust, provides a full
and unconditional guarantee by the Company on a subordinated basis of the Trust obligations.
Proceeds from the sale of the Junior Subordinated Debentures to the Trust were used to redeem
three series of preferred stock in June 1998.

(11) TREASURY STOCK TRANSACTIONS AND CALCULATIONS OF EARNINGS
         PER SHARE OF COMMON STOCK

TREASURY STOCK TRANSACTIONS

        In April 2000, following the indicative bid stage of the auction process used to divest its
Generation Assets, Pepco announced its Board-approved plan to repurchase $200 million of its
common stock as a preliminary use of the proceeds to be received from the divestiture. As part of
this plan the Company acquired 7,792,907 shares of its common stock. The total cost of the
Company's treasury shares of approximately $200 million at December 31, 2000, is reflected as a
reduction to shareholders' equity on the accompanying consolidated balance sheets. These
treasury shares are no longer "outstanding" and therefore are not included in the Company's
calculation of average common shares outstanding for purposes of computing earnings per share
for the period the shares are held in treasury. Accordingly, the Company's average common
shares outstanding for the year ended December 31, 2000, decreased in comparison to the year
ended 1999. Approximately $181.5 million of the total cost of the treasury shares of $200
million was funded by short-term loans, which were paid off using proceeds from the divestiture.

Calculations of Earnings Per Share of Common Stock
Reconciliations of the numerator and denominator for basic and diluted earnings per common share are shown below.
		For the Year Ended December 31,
		2000		1999		1998
(Millions, except Per Share Data)
Income (Numerator):
Earnings applicable to common stock	$	346.5	$	238.2	$	208.3
Add:  Interest paid or accrued on Convertible Debentures,      net of related taxes		3.6		4.4		6.3
Earnings Applicable to Common Stock, Assuming      Conversion of Convertible Securities	$	350.1	$	242.6	$	214.6
Shares (Denominator):
Average shares outstanding for computation of basic      earnings per share of common stock		114.9		118.5		118.5
Average shares outstanding for diluted computation:
Average shares outstanding		114.9		118.5		118.5
Additional shares resulting from:      Conversion of Convertible Debentures		3.4		4.1		5.7
Average Shares Outstanding for Computation of Diluted      Earnings Per Share of Common Stock		118.3		122.6		124.2
Basic earnings per share of common stock		$3.02		$2.01		$1.76
Diluted earnings per share of common stock		$2.96		$1.98		$1.73

        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, 2000, 3,392,500 shares of common stock were reserved for issuance
upon the conversion of the 5% convertible debentures, 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.

        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 restricted at December 31, 2000.

(12)  SMECO AGREEMENT

        In February 1999, FERC accepted a new full-requirements agreement between SMECO and
the Utility that superseded their previous rolling 10-year power supply contract. The agreement,
which became effective as of January 1, 1999, continued the total rate for electricity, but with a
non-varying fuel component. The agreement expired on December 31, 2000, and SMECO made
a one-time termination payment to the Company of $26 million on January 16, 2001. This
payment compensates the Company for future earnings it would otherwise have received under
the 10-year contract. Accordingly, during the first quarter of 1999, the Company recorded pre-
tax income of $23.2 million. This amount is classified as "Accounts Receivable" as of
December 31, 2000 in the accompanying Consolidated Balance Sheets. In accordance with
Accounting Principles Board Opinion No. 21 "Interest on Receivables and Payables," the amount
owed by SMECO required the imputation of interest and therefore the Company amortized a
$2.8 million difference between the present value of the termination payment and its face amount
($26 million) through December 31, 2000 using the effective interest method at a 6% interest
rate. The 6% interest rate approximated the rate the Company could have earned on a two-year
treasury instrument.

        In January 1999, Pepco Energy Services signed a contract with SMECO to supply
SMECO's full-requirements for power (approximately 600 MW of peak load) during the four-
year period starting January 1, 2001. A firm commitment has been secured from a third party for
the delivery of power sufficient to serve SMECO's full requirements. Both the sales
commitment to SMECO and the third-party purchase agreement are at fixed prices that do not
vary with future changes in market conditions.

(13)  COMMITMENTS AND CONTINGENCIES

OIL SPILL AT THE CHALK POINT GENERATING STATION

        On April 7, 2000, approximately 139,000 gallons of oil leaked from a pipeline at a
generation station which was owned by the Company at Chalk Point in Aquasco, Maryland. The
pipeline is operated by Support Terminals Services Operating Partnership LP, an unaffiliated
pipeline management company. The oil spread from Swanson Creek to the Patuxent River and
several of its tributaries. The area affected covers portions of 17 miles of shoreline along the
Patuxent River and approximately 45 acres of marshland adjacent to the Chalk Point property.
Clean-up operations have been under way under the direction of the Environmental Protection
Agency since the leak was discovered. The Company has been joined in the clean-up effort by
officials from other federal, state, county and local government agencies. The 51-mile pipeline,
which transports oil to the plants at Chalk Point and Morgantown, has been shut down by the
Office of Pipeline Safety, a unit of the federal government's Department of Transportation
(DOT), until a plan of corrective measures to prevent a reoccurrence of the spill is approved.
However, the plants remain fully operational and are being operated using coal and natural gas.
The pipeline and the plants were sold to Southern Energy as part of the Generation Asset
divestiture. As of December 31, 2000, approximately $66 million in clean-up costs had been
incurred in connection with the oil spill; and it is currently anticipated that total costs (excluding
liability claims against the Company and fines or other monetary penalties, if any) may be in the
range of $70 million to $75 million. These costs, which have continued to be incurred beyond
December 31, 2000, consist principally of the costs to clean up the oil spill such as labor,
supplies, repair work on damaged properties, and the rental of equipment.

        In addition, as a result of the oil spill, nine class action lawsuits and two additional lawsuits
on behalf of a number of Southern Maryland residents have been filed against the Company. At
this early stage, no determination has been made as to the merits of the claims. The Company
has indicated its willingness to settle appropriate claims arising from the oil spill. Otherwise, the
Company intends to vigorously contest the lawsuits. Fines or penalties, if any, assessed by
government authorities are not expected to be recoverable from the Company's insurance carrier.
The Company does not believe that fines or penalties assessed, if any, will have a material
adverse effect on its financial position; however, such fines or penalties, if any, could have a
material adverse effect on the Company's results of operations in the fiscal quarter in which they
are assessed. On December 20, 2000, the Office of Pipeline Safety of the DOT issued a Notice
of Probable Violation and proposed a civil penalty in the amount of approximately $674,000.
The Company plans to contest certain facts and findings by the DOT.

        For the year ended December 31, 2000, the Company recorded the net amount of $1 million
in operating expense as a result of the oil spill. This amount, which is included in the "Fuel and
Purchased Energy" line item on the Company's consolidated statements of earnings, represents
an accrual of $75 million in total oil spill related clean-up costs, net of $5 million in insurance
proceeds received through June 30, 2000 (the date the amount was recorded by the Company)
and an additional $69 million in probable recoveries from its insurance carriers. Through
December 31, 2000, $35.8 million has been received from the carriers. However, no assurances
can be given that the remaining amount due from the carriers will actually be received. The
aggregate insurance coverage available under the Company's general liability insurance policy
with respect to this event is $100 million. The Company will continue to assess the status of the
oil spill clean-up efforts, as necessary, for any significant changes in the estimated costs of
completing the remediation.

ACCOUNTING FOR CERTAIN TYPES OF REGULATION

        Based on the regulatory framework in which it has operated, the Company has historically
applied the provisions of SFAS 71, "Accounting for the Effects of Certain Types of Regulation."
SFAS 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.

        The components of the Company's regulatory (liability)/asset balances at December 31,
2000 and 1999 are as follows:

	2000	1999
	(Millions of Dollars)
Income taxes recoverable through future rates, net Customer sharing commitment	$   43.5   (243.8)	$226.0          -
Conservation costs, net	-	163.2
Unamortized debt reacquisition costs	26.7	49.4
Deferred fuel liability, net	(13.7)	(40.4)
Other	1.2	13.5
Net Regulatory (Liability)/Asset	$(186.1)	$411.7

        The Company's Generation Assets (divested to Southern Energy on December 19, 2000)
were deregulated as of December 31, 1999, and the application of SFAS 71 was discontinued for
this portion of the Company's business. Under the terms of the Maryland and D.C. Agreements,
all stranded costs, including future costs related to plant removal associated with divested
generation facilities, plus all above-market costs associated with purchased power obligations,
regulatory assets and obligations, and related expenses incurred by the Company in preparation
for the implementation of retail competition were offset against the proceeds from the sale of the
Generation Assets.

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.

        PCI is in the process of building, owning and financing a new 10-story, 360,000 square foot
commercial office building at an estimated cost of $92 million. The new building is expected to
be completed in mid-2001. The Utility will lease the majority of the office space from PCI. As
of December 31, 2000, PCI has invested $56.3 million related to the acquisition of land and
development of the new building.

        Rents, including property taxes and insurance, net of rental income from subleases,
aggregated approximately $18.6 million in 2000, $18.7 million in 1999, and $18.4 million in
1998. The approximate annual commitments under all operating leases, reduced by rentals to be
received under subleases, are $9.7 million for 2001, $4.9 million for 2002, $1.5 million for 2003,
$.7 million for 2004, $.4 million for 2005, and a total of $4.8 million for the years thereafter.

        The Utility leases its consolidated control center, an integrated energy management center
used by the Utility's power dispatchers to centrally control the operation of the Utility's
transmission and distribution systems. The lease 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 Utility for $1 at the end of the lease term. Under SFAS 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 rate-making purposes.
This lease has been treated as an operating lease for rate-making purposes. Accordingly, the
Company has recorded a regulatory asset of approximately $41 million and $35 million at
December 31, 2000 and 1999, respectively.

OTHER 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.

        On May 22, 1998, the State of Maryland issued final regulations entitled, "Post RACT
Requirements for Nitrogen Oxides (NOx) Sources (NOx Budget Proposal)," requiring a 65%
reduction in NOx emissions at the Company's Maryland generating units by May 1, 1999. The
regulations allow the purchase or trade of NOx emission allowances to fulfill this obligation.
The Company appealed this regulation to the Circuit Court for Charles County, Maryland, in
June 1998, on the basis that the regulation does not provide adequate time for the installation of
NOx emission reduction technology and that there is no functioning NOx allowance market. In
July 1998, the case was moved to the Circuit Court for Baltimore City and consolidated with a
similar appeal filed by Baltimore Gas and Electric Company. On February 23, 1999, the Circuit
Court for Baltimore City declared the Maryland NOx Budget Proposal to be invalid and
remanded it to the Department of Environment. On September 13, 1999, the Company reached
agreement with the Maryland Department of Environment to meet the 65% NOx emission
reduction requirement by May 1, 2001. With the sale of its Generation Assets on December 19,
2000, obligations associated with the NOx reduction agreement were transferred to Southern
Energy.

        In October 1997, the Company received notice from the EPA that it, along with 68 other
parties, may be a Potentially Responsible Party (PRP) under the Comprehensive Environmental
Response Compensation and Liability Act (CERCLA or Superfund) at the Butler Mine Tunnel
Superfund site in Pittstown Township, Luzerne County, Pennsylvania. The site is a mine
drainage tunnel with an outfall on the Susquehanna River where oil waste was disposed of via a
borehole in the tunnel. The letter notifying the Company of its potential liability also contained a
request for a reimbursement of approximately $.8 million for response costs incurred by EPA at
the site. The letter requested that the Company submit a good faith proposal to conduct or
finance the remedial action contained in a July 1996 Record of Decision (ROD). The EPA
estimated the cost of the remedial action to be $3.7 million. The Company reached a settlement
with a group of large PRPs wherein the Company paid a small share of the estimated remedial
action cost and received in return indemnification for past, present and future liability associated
with the conditions that gave rise to EPA's ROD. While the agreement does not resolve the
Company's liability with respect to claims brought by EPA or others not a party to the
agreement, the Company believes that it is sufficiently protected by the indemnity agreement that
any such liability 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 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.

        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 1987, the Company was notified by the EPA that it, along with several other
utilities and nonutilities, is a PRP in connection with the polychlorinated biphenyl compounds
(PCBs) contamination of a Philadelphia, Pennsylvania, site owned by a nonaffiliated company.
In the early 1970s, the Company sold scrap transformers, some of which may have contained
some level of PCBs, to a metal reclaimer operating at the site. In October 1994, a Remedial
Investigation/Feasibility Study (RI/FS) including a number of possible remedies was submitted
to the EPA. In December 1997, the EPA signed a ROD that set forth a selected remedial action
plan with estimated implementation costs of approximately $17 million. In June 1998, the EPA
issued a unilateral Administrative Order to the Company and 12 other PRPs to conduct the
design and actions called for in the ROD. To date, the Company has accrued $1.7 million for its
share of these costs.

         The Company's Benning Service Center facility operates under a National Pollutant
Discharge Elimination System (NPDES) permit. The EPA issued an NPDES permit for this
facility in November 2000. The Company has filed a petition with the EPA Environmental
Appeals Board seeking review and reconsideration of certain provisions of the EPA's permit
determination.

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 approximate 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. 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 90 additional 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. Through December 31, 2000, approximately 400 of the individual plaintiffs
have dismissed their claims against the Company. 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 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.

LABOR AGREEMENT

        A four-year Agreement (Labor Agreement) between the Company and Local 1900 of the
International Brotherhood of Electrical Workers (IBEW) was ratified on December 18, 1998, by
Union members. The Labor Agreement provides for a general wage increase of 3% each year in
1999, 2000 and 2001, beginning February 14, 1999, and 3% increase in wages in the fourth year
of the contract (2002) unless either party elects to reopen the Labor Agreement. The Company
also agreed to a 3% lump-sum payment for the period of January 3, 1999, to February 14, 1999.
In addition, the Labor Agreement resolves important issues that will arise based on the
Company's divestiture of its Generation Assets and establishes a framework for ongoing progress
towards improving management and union relations with joint committees. At December 31,
2000, 1,475 of the Company's 2,566 employees were represented by the IBEW.

(14) Fair Value of Financial Instruments
The estimated fair values of the Company's financial instruments at December 31, 2000 and 1999 are shown below.
At December 31,
		2000			1999
(Millions of Dollars)
	Carrying Amount		Fair Value	Carrying Amount		Fair Value
Assets
Marketable securities	$	231.4	231.4		203.2	203.2
Notes receivable	$	23.2	21.7		32.5	32.5
Liabilities and Capitalization
Long-Term Debt
First mortgage bonds	$	1,170.2	1,164.4		1,576.5	1,501.9
Medium-term notes	$	181.8	182.3		281.6	273.8
Convertible debentures	$	-	-		110.1	107.2
Recourse and non-recourse debt	$	384.3	384.2		744.3	707.5
Company Obligated Mandatorily Redeemable Preferred           Securities of Subsidiary Trust which holds Solely Parent           Junior Subordinated Debentures	$	125.0	123.7		125.0	106.9
Serial Preferred Stock	$	40.8	31.1		50.0	35.3
Redeemable Serial Preferred Stock	$	49.5	54.4		50.0	53.0

        The methods and assumptions below were used to estimate, at December 31, 2000 and
1999, 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 Marketable Securities was based on quoted market prices.

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

        The fair value of the 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 prices 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 recourse and the non-recourse debt held by PHI was based on current rates offered
to similar companies for debt with similar remaining maturities.

        The fair value of the Serial Preferred Stock, Redeemable Serial Preferred Stock and
Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust,
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 the interest rate swap agreements is discussed in Note (15) of the
accompanying Notes to Consolidated Financial Statements, Risk Management Activities.

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

(15)  RISK MANAGEMENT ACTIVITIES

UTILITY

        The Utility enters into forward and option agreements for the purchase and sale of power.
The intent of these agreements is to either secure power for retail customers at advantageous
prices or to obtain profitable prices for power generated by the Utility's facilities.

PCI AND PEPCO ENERGY SERVICES

        PCI has entered into interest rate swap agreements to fix certain variable rate debt under its
Medium-Term Note program in order to reduce its exposure to interest rate fluctuations. These
agreements have a notional amount of approximately $29 million at December 31, 2000. The
interest rate differential to be paid or received on the swap agreements is accrued as interest rates
change and is recognized as an adjustment to interest expense. As of December 31, 2000, the
interest rate swap agreements have an average life of approximately four years with a fixed rate
of 6.42% and variable rate of 6.46%. The fair value of these interest rate swap agreements,
based on quoted market prices, was approximately $.1 million as of December 31, 2000.

        Pepco Energy Services enters into agreements to sell electricity and natural gas to
customers and generally operates to secure firm, fixed-commitments to meet its fixed price sales
obligations and to match floating price sales agreements with floating price supply agreements.

ACCOUNTING TREATMENT

        Pepco Energy Services manages its portfolio of energy purchases and sales to customers
using a variety of instruments including forward contracts, swap agreements, option contracts
and futures contracts. Active portfolio management allows Pepco Energy Services to effectively
manage and hedge the risk of its firm, fixed price supply commitments to meet its fixed price
sales obligations. Pepco Energy Services' management takes an active role in the risk
management process and has developed policies and procedures that require specific
administrative and business functions to assist in the identification, assessment and control of
various risks. Management reviews any open positions in accordance with strict policies in order
to limit exposure to market risk. Pepco Energy Services accounts for certain commodity
transactions in accordance with guidance provided by Emerging Issues Task Force Issue 98-10.
Unrealized gains and losses on such transactions are recorded as assets and liabilities at each
reporting period. The market prices used to value these transactions reflect the best estimate of
market prices considering various factors including closing exchange and over-the-counter
quotations and price.

        Additionally, the effective date of Statement of Financial Accounting Standards No. 133
(SFAS 133), "Accounting for Derivative Instruments and Hedging Activities," was delayed and
will become effective for the Company's 2001 calendar year financial statements. Accordingly,
the Company will adopt SFAS 133 on January 1, 2001. At that date, the cumulative effect of the
implementation of SFAS 133 did not have a material impact on the Company's consolidated
results of operations, financial position, or cash flows.

(16) Quarterly Financial Summary (Unaudited)
		1st Quarter	2nd Quarter	3rd Quarter	4th Quarter	Total
(Millions of Dollars, except Per Share Data)
2000
Total Operating Revenue	$	529.2	653.1	835.7	1029.7	3,047.7
Total Operating Expenses	$	508.7	552.0	629.7	637.8	2,328.2
Loss from Equity Investments,
Principally Telecommunication Entities	$	(3.9)	(4.0)	(3.2)	(6.0)	(17.1)
Operating Income	$	16.6	97.1	202.8	385.9	702.4
Net Income	$	9.7	58.0	120.8	163.5	352.0
Earnings Available for Common Stock	$	8.3	56.6	119.5	162.1	346.5
Basic Earnings Per Share of Common Stock	$	.07	.48	1.07	1.46	3.02
Diluted Earnings Per Share of Common Stock	$	.07	.47	1.04	1.43	2.96
Cash Dividends Per Common Share	$	.415	.415	.415	.415	1.66
1999
Total Operating Revenue	$	512.0	600.0	861.7	502.3	2,476.0
Total Operating Expenses	$	467.6	508.6	610.8	507.8	2,095.6
Loss from Equity Investments,
Principally Telecommunication Entities	$	(3.1)	(1.7)	(2.6)	(2.8)	(9.6)
Operating Income (Loss)	$	41.3	89.7	248.3	(8.6)	370.8
Net Income (Loss)	$	26.0	75.3	154.0	(8.2)	247.1
Earnings (Loss) Available for Common Stock	$	24.0	73.3	151.9	(11.1)	238.2
Basic Earnings (Loss) Per Share of Common Stock	$	.20	.62	1.28	(.09)	2.01
Diluted Earnings (Loss) Per Share of Common Stock	$	.20	.61	1.25	(.09)	1.98
Cash Dividends Per Common Share	$	.415	.415	.415	.415	1.66
1998
Total Operating Revenue	$	417.4	569.0	786.8	447.7	2,220.8
Total Operating Expenses	$	409.0	463.8	537.0	448.2	1,858.0
Income (Loss) from Equity Investments,
Principally Telecommunication Entities	$	.1	(1.0)	(5.3)	(2.3)	(8.5)
Operating Income (Loss)	$	8.5	104.2	244.5	(2.8)	354.3
Net Income (Loss)	$	7.5	66.0	153.1	(.3)	226.3
Earnings (Loss) Available for Common Stock	$	3.4	56.0	151.1	(2.2)	208.3
Basic Earnings (Loss) Per Share of Common Stock	$	.03	.47	1.27	(.02)	1.76
Diluted Earnings (Loss) Per Share of Common Stock	$	.03	.46	1.23	(.02)	1.73
Cash Dividends Per Common 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 totals of the four quarterly basic earnings per common share and diluted earnings per common share may not equal the basic earnings per common share and diluted earnings per common share for the year due to changes in the number of common shares outstanding during the year and, with respect to the diluted earnings per common share, changes in the amount of dilutive securities.

Stock Market Information
2000		High	Low	1999					High	Low
1st Quarter		$27-11/16	$19-1/16	1st Quarter					$26-1/2	$23
2nd Quarter		$27-7/8	$20-15/16	2nd Quarter					$31-3/4	$23-1/8
3rd Quarter		$27-7/16	$23-5/8	3rd Quarter					$31-5/16	$25-1/16
4th Quarter		$25-9/16	$21-1/2	4th Quarter					$28-1/16	$21-1/4
(Close $24-11/16)				(Close $22-15/16)
Shareholders at December 31, 2000: 61,151
Selected Consolidated Financial Data
		2000	1999	1998		1997		1996	1995	1990
(In Millions, except Per Share Data)
Total Operating Revenue	$	3,047.7	2,476.0	2,220.8		1,997.1		2,141.2	2,019.2	1,624.3
Total Operating Expenses	$	2,328.2	2,095.6	1,858.0		1,751.7		1,826.5	1,880.3	1,382.9
Net Income	$	352.0	247.1	226.3		181.8		237.0	94.4	170.2
Earnings Available for Common Stock	$	346.5	238.2	208.3		165.3		220.4	77.5	159.6
Basic Common Shares Outstanding (Average)		114.9	118.5	118.5		118.5		118.5	118.4	98.6
Diluted Common Shares Outstanding (Average)		118.3	122.6	124.2		124.3		124.3	118.5	101.4
Basic Earnings (Loss) Per Share of Common Stock
Utility:
Continuing Operations	$	1.61	1.85	1.63		1.25	*	1.72	1.70	1.57
Divestiture Gain		1.58	-	-		-		-	-	-
Impairment Loss		(.20)	-	-		-		-	-	-
Total Utility		2.99	1.85	1.63		1.25	*	1.72	1.70	1.57
PCI		.12	.22	.14		.15		.14	(1.05)	.05
Pepco Energy Services		(.08)	(.06)	(.01)		(.01)		-	-	-
PepMarket		(.01)	-	-		-		-	-	-
Pepco Consolidated		3.02	2.01	1.76		1.39	*	1.86	.65	1.62
Diluted Earnings (Loss) Per Share of Common Stock
Utility:
Continuing Operations	$	1.59	1.82	1.61		1.24	*	1.69	1.70	1.56
Divestiture Gain		1.54	-	-	-	-	-	-	-	-
Impairment Loss		(.20)	-	-	-	-	-	-	-	-
Total Utility		2.93	1.82	1.61		1.24	*	1.69	1.70	1.56
PCI		.12	.22	.13		.15	.13	.13	(1.05)	.05
Pepco Energy Services		(.08)	(.06)	(.01)		(.01)		-	-	-
Pepmarket		(.01)	-	-		-		-	-	-
Pepco Consolidated		2.96	1.98	1.73		1.38	*	1.82	.65	1.61
Cash Dividends Per Share of Common Stock	$	1.66	1.66	1.66		1.66		1.66	1.66	1.52
Investment in Property, Plant and Equipment	$	4,284.7	6,784.3	6,657.8		6,514.1		6,321.6	6,161.1	4,659.3
Net Investment in Property, Plant and Equipment	$	2,721.8	4,524.4	4,521.2		4,486.3		4,423.2	4,400.3	3,398.0
Total Assets	$	7,027.3	6,910.6	6,574.1		6,683.2		6,852.4	7,082.3	5,239.7
Long-Term Obligations (including      redeemable preferred stock)	$	2,034.1	3,042.0	2,738.5		3,033.4		3,069.2	3,173.3	1,516.1
* Includes ($.28) as the net effect of the write-off of merger-related costs.