POTOMAC ELECTRIC POWER CO, 10-Q, 1999-11-12

POTOMAC ELECTRIC POWER CO
10-Q, 1999-11-12
ELECTRIC SERVICES

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SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549


		FORM 10-Q


Quarterly Report Under Section 13 or 15(d) of the Securities Exchange Act of 1934


For Quarter Ended							September 30, 1999

Commission File Number						1-1072


Potomac Electric Power Company (Exact name of registrant as specified in its charter)


District of Columbia and Virginia (State or other jurisdiction of incorporation or organization)							53-0127880 (I.R.S. Employer Identification No.)


1900 Pennsylvania Avenue, N.W., Washington, D.C. (Address of principal executive office)							20068 (Zip Code)


202-872-2000 (Registrant's telephone number, including area code)


Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days.
	Yes		[ X ]	No	[ ]

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.

Class				Outstanding at September 30, 1999
Common Stock, $1 par value				118,530,802

TABLE OF CONTENTS

PART I - Financial Information	Page
Item 1. - Consolidated Financial Statements
Consolidated Statements of Earnings and Retained Income	2
Consolidated Balance Sheets	3
Consolidated Statements of Cash Flows	4
Notes to Consolidated Financial Statements	5
(1) Comprehensive Income	6
(2) Income Taxes	7
(3) Capitalization and Fair Value of Financial Instruments	10
(4) Commitments and Contingencies	14
(5) Segment Information	17
(6) Energy Trading and Risk Management Activities	19
Report of Independent Accountants on Review of Interim Financial Information	21
Item 2. - Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition
General	22
Safe Harbor Statements	22
Utility
Results of Operations	24
Year 2000 Readiness Disclosure	26
Capital Resources and Liquidity	28
Nonutility Subsidiary
General	29
Results of Operations	29
Year 2000 Readiness Disclosure	34
Capital Resources and Liquidity	34
Item 3. - Quantitative and Qualitative Disclosures About Market Risk	35
PART II - Other Information
Item 1. - Legal Proceedings	36
Item 5. - Other Information	36
Other Financing Arrangements	36
Base Rate Proceedings	36
Restructuring of the Bulk Power Market	38
Competition	38
Peak Load, Sales, Conservation, and Construction and Generating Capacity	38
Selected Nonutility Subsidiary Financial Information	40
Statistical Data	42
Item 6. - Exhibits and Reports on Form 8-K	43
Signatures	44
Computation of Ratios - Parent Company Only	45
Computation of Ratios - Consolidated	46
Independent Accountants Awareness Letter	47

Part I FINANCIAL INFORMATION
Item 1 CONSOLIDATED FINANCIAL STATEMENTS

POTOMAC ELECTRIC POWER COMPANY
Consolidated Statements of Earnings and Retained Income
(Unaudited)

	Three Months Ended		Nine Months Ended		Twelve Months Ended
	September 30,		September 30,		September 30,
	1999	1998	1999	1998	1999	1998
	(In millions, except per share data)
Revenue
Sales of electricity	$671.8	$665.2	$1,542.8	$1,508.4	$1,907.1	$1,885.0
Other electric revenue	4.4	5.0	12.3	11.0	14.6	13.0
Total Operating Revenue	676.2	670.2	1,555.1	1,519.4	1,921.7	1,898.0
Interchange deliveries	120.7	80.6	215.4	140.3	253.0	152.1
Total Revenue	796.9	750.8	1,770.5	1,659.7	2,174.7	2,050.1
Operating Expenses
Fuel	146.8	127.5	320.2	302.2	398.2	372.2
Purchased energy	103.3	99.0	247.0	213.0	303.8	259.3
Capacity purchase payments	51.3	37.6	160.5	116.2	200.0	159.0
Other operation	64.7	61.3	173.9	174.8	236.8	234.7
Maintenance	22.1	23.0	66.6	67.2	90.9	94.7
Total Operation and Maintenance	388.2	348.4	968.2	873.4	1,229.7	1,119.9
Depreciation and amortization	64.2	62.3	186.3	180.0	246.1	238.0
Income taxes	94.7	91.9	133.4	129.2	134.7	131.6
Other taxes	60.5	62.2	155.3	159.5	200.2	206.9
Total Operating Expenses	607.6	564.8	1,443.2	1,342.1	1,810.7	1,696.4
Operating Income	189.3	186.0	327.3	317.6	364.0	353.7
Other Income (Loss)
Nonutility Subsidiary
Income	60.5	29.9	168.6	103.2	208.9	127.0
Expenses, including interest and income taxes	(60.2)	(26.1)	(144.8)	(87.0)	(186.2)	(109.5)
Net earnings from nonutility subsidiary	0.3	3.8	23.8	16.2	22.7	17.5
Allowance for other funds used during
construction and capital cost recovery factor	0.4	0.4	1.1	0.9	1.6	2.6
Contract termination fee	-	-	23.2	-	23.2	-
Write-off of merger costs	-	-	-	-	-	(52.5)
Other, net	1.3	0.7	(6.3)	2.8	(5.9)	23.0
Total Other Income (Loss)	2.0	4.9	41.8	19.9	41.6	(9.4)
Income Before Utility Interest Charges	191.3	190.9	369.1	337.5	405.6	344.3
Utility Interest Charges
Long-term debt	34.6	34.2	104.4	102.8	138.6	137.3
Distributions on preferred securities of
subsidiary company	2.3	2.3	6.9	3.4	9.2	3.4
Other	1.3	2.2	5.1	7.9	6.3	9.5
Allowance for borrowed funds used during
construction and capital cost recovery factor	(0.9)	(0.9)	(2.6)	(3.2)	(3.5)	(5.2)
Net Utility Interest Charges	37.3	37.8	113.8	110.9	150.6	145.0
Net Income	154.0	153.1	255.3	226.6	255.0	199.3
Dividends on preferred stock	2.1	2.0	6.0	9.5	7.9	13.6
Redemption premium on preferred stock	-	-	-	6.6	-	6.6
Earnings for Common Stock	151.9	151.1	249.3	210.5	247.1	179.1

Retained Income at Beginning of Period	744.4	696.6	747.3	734.3	798.7	815.4
Dividends on Common Stock	(49.1)	(49.2)	(147.5)	(147.5)	(196.7)	(196.6)
Subsidiary Marketable Securities Net
Unrealized (Loss) Gain, Net of Tax	(4.9)	0.2	(6.8)	1.4	(6.8)	0.8
Retained Income at End of Period	$842.3	$798.7	$842.3	$798.7	$842.3	$798.7
Basic Average Common Shares
Outstanding	118.5	118.5	118.5	118.5	118.5	118.5
Basic Earnings Per Common Share	$1.28	$1.27	$2.10	$1.78	$2.08	$1.51
Diluted Average Common Shares
Outstanding	121.9	124.2	122.9	124.2	123.2	124.3
Diluted Earnings Per Common Share	$1.25	$1.23	$2.06	$1.73	$2.05	$1.49
Cash Dividends Per Common Share	$0.415	$0.415	$1.245	$1.245	$1.66	$1.66
Book Value Per Share					$16.64	$16.27
Dividend Payout Ratio					79.8%	109.9%
Effective Federal Income Tax Rate					27.0%	30.5%

POTOMAC ELECTRIC POWER COMPANY
Consolidated Balance Sheets
(Unaudited at September 30, 1999 and 1998)

	September 30,	December 31,	September 30,
ASSETS	1999	1998	1998
	(Millions of Dollars)
Property and Plant - at original cost
Electric plant in service	$ 6,620.8	$ 6,539.9	$ 6,492.3
Construction work in progress	99.4	73.2	72.6
Electric plant held for future use	2.2	4.3	4.3
Nonoperating property	22.5	40.4	40.7
	6,744.9	6,657.8	6,609.9
Accumulated depreciation	(2,241.2)	(2,136.6)	(2,104.7)
Net Property and Plant	4,503.7	4,521.2	4,505.2
Current Assets
Cash and cash equivalents	31.2	6.4	12.8
Customer accounts receivable, less allowance for uncollectible
accounts of $2.8, $2.4 and $2.3	156.8	114.9	185.4
Other accounts receivable, less allowance for uncollectible
accounts of $.3	47.9	44.8	39.9
Accrued unbilled revenue	116.8	65.6	117.4
Prepaid taxes	27.6	34.7	33.6
Other prepaid expenses	3.7	3.3	2.3
Material and supplies - at average cost
Fuel	48.0	53.3	44.7
Emission allowances	50.6	-	-
Construction and maintenance	68.1	68.7	70.0
Total Current Assets	550.7	391.7	506.1
Deferred Charges
Income taxes recoverable through future rates, net	227.9	232.5	234.8
Conservation costs, net	166.2	197.5	205.4
Unamortized debt reacquisition costs	50.2	49.9	50.6
Other	200.3	175.6	155.2
Total Deferred Charges	644.6	655.5	646.0
Nonutility Subsidiary Assets
Cash and cash equivalents	7.6	79.6	16.0
Marketable securities	230.4	231.1	240.7
Investment in finance leases	571.5	399.2	442.2
Operating lease equipment, net of accumulated depreciation
of $137.2, $120.1 and $114.4	108.9	122.6	128.3
Receivables, less allowance for uncollectible accounts
of $4.6, $5.0 and $5.0	74.2	55.6	42.8
Other investments	164.3	120.6	122.3
Other assets	26.5	23.1	18.7
Deferred income taxes	4.4	25.6	74.1
Total Nonutility Subsidiary Assets	1,187.8	1,057.4	1,085.1
Total Assets	$ 6,886.8	$ 6,625.8	$ 6,742.4
CAPITALIZATION AND LIABILITIES
Capitalization
Common stock	$ 118.5	$ 118.5	$ 118.5
Other common equity	1,853.8	1,758.9	1,810.3
Serial preferred stock	100.0	100.0	100.0
Redeemable serial preferred stock	50.0	50.0	50.0
Company obligated mandatorily redeemable preferred
securities of subsidiary trust which holds solely parent
junior subordinated debentures	125.0	125.0	125.0
Long-term debt	1,967.4	1,859.0	1,858.6
Total Capitalization	4,214.7	4,011.4	4,062.4
Other Non-Current Liabilities
Capital lease obligations	155.3	157.6	158.3
Current Liabilities
Long-term debt and preferred stock redemption	-	45.2	45.0
Short-term debt	148.6	191.7	119.1
Accounts payable and accrued expenses	178.9	193.2	293.7
Capital lease obligations due within one year	20.8	20.8	20.8
Other	95.8	95.8	91.0
Total Current Liabilities	444.1	546.7	569.6
Deferred Credits
Income taxes	1,059.4	1,049.2	1,051.7
Investment tax credits	50.9	53.7	54.6
Other	32.6	24.6	23.2
Total Deferred Credits	1,142.9	1,127.5	1,129.5
Nonutility Subsidiary Liabilities
Long-term debt	640.7	716.9	558.1
Short-term notes payable	158.9	-	183.0
Other	130.2	65.7	81.5
Total Nonutility Subsidiary Liabilities	929.8	782.6	822.6
Total Capitalization and Liabilities	$ 6,886.8	$ 6,625.8	$ 6,742.4

POTOMAC ELECTRIC POWER COMPANY
Consolidated Statements of Cash Flows
(Unaudited)

	Nine Months Ended		Twelve Months Ended
	September 30,		September 30,
	1999	1998	1999	1998
	(Millions of Dollars)
Operating Activities
Income from utility operations	$ 231.5	$ 210.4	$ 232.3	$ 181.8
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization	186.3	180.0	246.1	238.0
Deferred income taxes and investment tax credits	5.6	19.0	9.7	38.4
Deferred conservation costs	(8.1)	(20.8)	(11.6)	(29.1)
Allowance for funds used during construction
and capital cost recovery factor	(3.7)	(4.1)	(5.1)	(7.8)
Changes in materials and supplies	(44.7)	12.8	(51.9)	14.9
Changes in accounts receivable and accrued unbilled revenue	(96.1)	(124.6)	21.2	(42.9)
Changes in contract termination fee receivable	(24.1)	-	(24.1)	-
Changes in accounts payable	(0.7)	(6.4)	(7.0)	17.1
Changes in other current assets and liabilities	(1.1)	122.4	(97.6)	44.7
Changes in deferred merger costs	-	-	-	47.8
Net other operating activities	21.1	(7.6)	(0.1)	(23.5)
Nonutility subsidiary:
Net earnings	23.8	16.2	22.7	17.5
Deferred income taxes	24.8	(75.0)	73.3	(92.2)
Changes in other assets and net other operating activities	39.8	23.2	18.2	57.7
Net Cash From Operating Activities	354.4	345.5	426.1	462.4

Investing Activities
Total investment in property and plant	(138.7)	(150.0)	(200.4)	(230.8)
Allowance for funds used during construction
and capital cost recovery factor	3.7	4.1	5.1	7.8
Net investment in property and plant	(135.0)	(145.9)	(195.3)	(223.0)
Nonutility subsidiary:
Purchase of marketable securities	(25.1)	(1.0)	(25.1)	(1.0)
Proceeds from sale or redemption of marketable securities	15.6	66.9	25.2	67.4
Proceeds from sale or disposition of leased equipment	-	61.3	44.6	61.3
Purchase of other investments	(180.2)	(17.6)	(187.7)	(17.7)
Proceeds from sale or distribution of other investments	3.5	32.7	5.3	45.3
Proceeds from promissory notes	-	-	-	0.3
Proceeds from liquidation of partnership	8.4	-	8.4	-
Gain upon liquidation of partnership	(9.5)	-	(9.5)	-
Net Cash Used by Investing Activities	(322.3)	(3.6)	(334.1)	(67.4)

Financing Activities
Dividends on common stock	(147.5)	(147.5)	(196.7)	(196.6)
Dividends on preferred stock	(6.0)	(9.5)	(7.9)	(13.6)
Redemption of preferred stock	-	(123.7)	-	(123.7)
Issuance of mandatorily redeemable preferred securities	-	125.0	-	125.0
Issuance of long-term debt	266.6	-	266.6	174.2
Reacquisition and retirement of long-term debt	(207.7)	(51.1)	(207.7)	(51.1)
Short-term debt, net	(43.1)	(12.2)	29.5	(158.0)
Other financing activities	(2.4)	(3.1)	(2.4)	(4.2)
Nonutility subsidiary:
Issuance of long-term debt	36.2	52.1	204.3	52.1
Repayment of long-term debt	(134.3)	(324.4)	(143.6)	(357.1)
Short-term debt, net	158.9	175.3	(24.1)	173.8
Net Cash Used by Financing Activities	(79.3)	(319.1)	(82.0)	(379.2)
Net (Decrease) Increase in Cash and Cash Equivalents	(47.2)	22.8	10.0	15.8
Cash and Cash Equivalents at Beginning of Period	86.0	6.0	28.8	13.0
Cash and Cash Equivalents at End of Period	$ 38.8	$ 28.8	$ 38.8	$ 28.8

Cash paid for interest (net of capitalized interest of $1.1, $.5,
$1.3 and $.6) and income taxes:
Interest (including nonutility subsidiary interest of
$45.0, $54.9, $48.6 and $59.3)	$ 162.9	$ 165.7	$ 195.8	$ 191.6
Net income tax (refund) payment - including nonutility subsidiary	$ (21.4)	$ 27.2	$ 20.3	$ 33.6

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Organization

          Potomac Electric Power Company (the Company, or the Utility) is engaged in the
generation, transmission, distribution and sale of electric energy in the Washington, D.C.
metropolitan area. The Company's retail service territory includes all of the District of
Columbia and major portions of Montgomery and Prince George's counties in suburban
Maryland. In addition, the Company supplies electricity, at wholesale, under a
full-requirements agreement with Southern Maryland Electric Cooperative, Inc. (SMECO).
The Company also delivers economy energy to the Pennsylvania-New Jersey-Maryland
Interconnection LLC (PJM) of which the Company is a member. PJM is composed of more
than 100 electric utilities, independent power producers, power marketers, cooperatives and
municipals that operate on a fully integrated basis.

          On May 21, 1999, the Company 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, Pepco Holdings, Inc. (PHI, or the Nonutility
Subsidiary), was created as the parent company of Potomac Capital Investment Corp. (PCI)
and Pepco Energy Services, Inc. (PES). PCI will continue to manage its diversified portfolio
of financial investments and grow its new operating businesses that provide
telecommunications and utility related services. PES is focused on providing nonregulated
energy products (electricity and natural gas) and energy services (including energy efficiency
contracting, consulting services, construction, management and facilities operation and
maintenance) in competitive markets.

          Potomac Electric Power Company Trust I (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.

Basis of Presentation

          The information furnished in the accompanying consolidated statements of earnings
and retained income, consolidated balance sheets and consolidated statements of cash flows
reflects all adjustments (which consist only of normal recurring accruals) which are, in the
opinion of management, necessary for a fair presentation of the results of operations for the
interim periods. The accompanying consolidated financial statements and notes thereto
should be read in conjunction with the consolidated financial statements and notes included
in the Company's 1998 Annual Report to the Securities and Exchange Commission on
Form 10-K.

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

(1) Comprehensive Income

          The components of comprehensive income are net income and unrealized gains and
losses on marketable securities. The Company's comprehensive income was $149.1 million,
$248.5 million, and $248.2 million for the three, nine and twelve months ended
September 30, 1999, compared to $153.3 million, $228 million, and $200.1 million for the
corresponding periods ended September 30, 1998.

(2) INCOME TAXES
Provision for Income Taxes


	Three		Nine		Twelve
	Months Ended		Months Ended		Months Ended
	September 30,		September 30,		September 30,
	1999	1998	1999	1998	1999	1998
	(Millions of Dollars)

Utility current tax expense
Federal	$ 84.5	$ 70.3	$ 121.7	$ 98.0	$ 119.5	$ 64.8
State and local	11.3	10.0	16.1	12.5	15.7	8.5
Total utility current tax expense	95.8	80.3	137.8	110.5	135.2	73.3

Utility deferred tax (benefit) expense
Federal	0.4	11.5	6.6	18.1	10.9	36.3
State and local	0.1	1.0	1.7	3.6	2.5	5.8
Investment tax credits	(0.9)	(0.9)	(2.7)	(2.7)	(3.7)	(3.7)
Total utility deferred tax (benefit) expense	(0.4)	11.6	5.6	19.0	9.7	38.4

Total utility income tax expense	95.4	91.9	143.4	129.5	144.9	111.7

Nonutility subsidiary current tax (benefit) expense
Federal (1)	(61.2)	5.9	(57.2)	34.0	(75.8)	43.6

Nonutility subsidiary deferred tax expense (benefit)
Federal (1)	57.8	(8.4)	31.0	(36.4)	43.3	(53.5)

Total nonutility subsidiary income tax benefit	(3.4)	(2.5)	(26.2)	(2.4)	(32.5)	(9.9)

Total consolidated income tax expense	92.0	89.4	117.2	127.1	112.4	101.8
Income taxes included in other income	(2.7)	(2.5)	(16.2)	(2.1)	(22.3)	(29.8)
Income taxes included in utility
operating expenses	$ 94.7	$ 91.9	$ 133.4	$ 129.2	$ 134.7	$ 131.6

(1) Represents the utilization of alternatiave minimum tax credit carryforwards from prior years that will be offset against the regular tax liability.

Reconciliation of Consolidated Income Tax Expense


	Three		Nine		Twelve
	Months Ended		Months Ended		Months Ended
	September 30,		September 30,		September 30,
	1999	1998	1999	1998	1999	1998
	(Millions of Dollars)

Income before income taxes	$ 246.0	$ 242.5	$ 372.5	$ 353.7	$ 367.4	$ 301.1

Utility income tax at federal
statutory rate	$ 87.2	$ 84.4	$ 131.2	$ 119.0	$ 132.0	$ 102.7
Increases (decreases) resulting from
Depreciation	2.8	2.8	8.3	8.3	10.9	11.6
Removal costs	(0.8)	(1.3)	(4.3)	(4.6)	(5.7)	(6.5)
Allowance for funds used during
construction	0.1	0.2	0.5	0.6	0.4	0.9
Other	(0.4)	(0.4)	(1.2)	(1.6)	(0.5)	(2.4)
State income taxes, net of federal effect	7.4	7.1	11.6	10.5	11.8	9.3
Tax credits	(0.9)	(0.9)	(2.7)	(2.7)	(4.0)	(3.9)
Total utility income tax expense	95.4	91.9	143.4	129.5	144.9	111.7

Nonutility subsidiary income tax at federal
statutory rate	(1.1)	0.4	(0.8)	4.8	(3.4)	2.7
Decreases resulting from
Dividends received deduction	(1.1)	(1.0)	(3.1)	(3.4)	(4.1)	(4.8)
Reversal of previously accrued
deferred taxes	-	-	-	-	(1.0)	-
Partnership restructuring	-	-	(18.7)	-	(18.7)	-
Other	(1.2)	(1.9)	(3.6)	(3.8)	(5.3)	(7.8)

Total nonutility subsidiary income tax benefit	(3.4)	(2.5)	(26.2)	(2.4)	(32.5)	(9.9)

Total consolidated income tax expense	92.0	89.4	117.2	127.1	112.4	101.8
Income taxes included in other income	(2.7)	(2.5)	(16.2)	(2.1)	(22.3)	(29.8)
Income taxes included in utility
operating expenses	$ 94.7	$ 91.9	$ 133.4	$ 129.2	$ 134.7	$ 131.6

Components of Consolidated Deferred Tax Liabilities (Assets)



	September 30,	December 31,	September 30,
	1999	1998	1998
	(Millions of Dollars)

Utility deferred tax liabilities (assets)
Depreciation and other book to tax
basis differences	$ 909.8	$ 891.6	$ 893.9
Rapid amortization of certified pollution
control facilities	26.0	27.2	24.6
Deferred taxes on amounts to be collected
through future rates	86.3	88.0	88.9
Property taxes	13.0	12.9	13.7
Deferred fuel	(15.6)	(9.7)	(11.3)
Prepayment premium on debt retirement	18.1	18.9	19.2
Deferred investment tax credit	(19.3)	(20.3)	(20.7)
Contributions in aid of construction	(33.3)	(32.0)	(31.0)
Contributions to pension plan	22.1	22.1	18.2
Conservation costs (demand side management)	47.4	49.4	48.9
Other	17.1	19.7	20.7
Total utility deferred tax liabilities, net	1,071.6	1,067.8	1,065.1
Current portion of utility deferred tax liabilities
(included in Other Current Liabilities)	12.2	18.6	13.4
Total utility deferred tax liabilities, net - non-current	$ 1,059.4	$ 1,049.2	$ 1,051.7

Nonutility subsidiary deferred tax liabilities (assets)
Finance leases	$ 142.6	$ 134.3	$ 124.0
Operating leases	(16.5)	5.0	8.8
Alternative minimum tax	(2.6)	(43.6)	(97.1)
Assets with a tax basis greater than book basis	(42.0)	(46.0)	(43.8)
Other	(85.9)	(75.3)	(66.0)
Total nonutility subsidiary deferred tax assets, net	$ (4.4)	$ (25.6)	$ (74.1)

(3) Capitalization and Fair Value of Financial Instruments

Common Equity

          At September 30, 1999, 118,530,802 shares of the Company's $1 par value Common
Stock were outstanding. A total of 200 million shares is authorized. As of September 30,
1999, 2,324,721 shares were reserved for issuance under the Shareholder Dividend
Reinvestment Plan; 1,221,624 shares were reserved for issuance under the Employee Savings
Plans; and 3,392,500 shares were reserved for conversion of the 5% Convertible Debentures.

Serial Preferred, Redeemable Serial Preferred, Company Obligated Mandatorily Redeemable
Preferred Securities and Long-Term Debt

          At September 30, 1999, the Company had outstanding 3,000,000 shares of its $50 par
value Serial Preferred Stock, including the Redeemable Serial Preferred Stock. A total of
8,750,000 shares is authorized. At September 30, 1999, the aggregate annual dividend
requirements on the Serial Preferred Stock and the Redeemable Serial Preferred Stock were
approximately $4.9 million and $3.4 million, respectively. Also, the Company has a total of
8,800,000 shares of cumulative, $25 par value, Preference Stock authorized and unissued.

          At September 30, 1999, the Company had outstanding 1,000,000 shares of its Serial
Preferred Stock, Auction Series A. The annual dividend rate is 5% ($2.50) for the period
September 1, 1999 through November 30, 1999. For the period June 1, 1999 through
August 31, 1999, the annual dividend rate was 4.27% ($2.10). The average rate at which
dividends were paid during the twelve months ended September 30, 1999, was 4.35%
($2.17). As discussed in Note (4) of the Notes to Consolidated Financial Statements,
Commitments and Contingencies, on October 28, 1999, the Company announced the
redemption, on December 1, 1999, of all one million outstanding shares of this series.

          At September 30, 1999, the Company had outstanding 1,000,000 shares of
Redeemable Serial Preferred Stock, $3.40 (6.80%) Series of 1992, on which the sinking fund
requirement commences September 1, 2002. The sinking fund requirement in 2002 and 2003
with respect to this series is $2.5 million.

          At September 30, 1999, the aggregate annual interest requirement on the Company's
long-term debt and Company obligated mandatorily redeemable preferred securities of
subsidiary trust was $139.7 million; and the aggregate amounts of long-term debt maturities
are zero in 2000; $165 million in 2001, $190 million in 2002, and $90 million in 2003.

          The estimated fair values of the Company's financial instruments at September 30, 1999, are summarized below:

	Carrying Amount	Fair Value
	(Millions of Dollars)
Utility
Capitalization and Liabilities
Serial preferred stock	$ 100.0	$ 87.4
Redeemable serial preferred stock	$ 50.0	$ 53.0
Company obligated mandatorily redeemable preferred securities of subsidiary trust which holds solely parent junior subordinated debentures	$ 125.0	$ 112.5
Long-term debt
First mortgage bonds (net of unamortized premium and discount of $15.6)	$1,576.2	$1,542.4
Medium-term notes (net of unamortized discount of $1.6)	281.5	279.3
Convertible debentures (net of unamortized discount of $5.3)	109.7	109.3
Total long-term debt	$1,967.4	$1,931.0

Nonutility Subsidiary
Assets
Marketable securities (primarily mandatorily redeemable preferred stock)	$ 230.4	$ 230.4
Notes receivable	$ 24.6	$ 24.9
Liabilities
Long-term debt	$ 640.7	$ 645.6

          The following methods and assumptions were used to estimate, at September 30, 1999,
the fair value of each class of financial instrument for which it is practicable to estimate that
value.

          The fair values of the Company's Serial preferred stock, Redeemable serial preferred
stock and Trust Originated Preferred Securities were based on quoted market prices or
discounted cash flows using current rates of preferred stock with similar terms.

          The fair values of the Company's Long-term debt, which includes First mortgage
bonds, Medium-term notes, and Convertible debentures, were based on current market price,
or for issues with no market price available, fair values were based on discounted cash flows
using current rates for similar issues with similar terms and remaining maturities.

          The fair value of PHI's Marketable securities was based on quoted market prices.

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

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

          The fair value of PHI's interest rate swap agreements is discussed in Note (6) of the
accompanying Notes to Consolidated Financial Statements, Energy Trading and Risk
Management Activities.

          The carrying amounts of all other financial instruments approximate their fair values.

Calculations of Earnings Per Share

Reconciliations of the numerator and denominator for basic and diluted earnings per common share are shown below.

Three Months Ended Nine Months Ended Twelve Months Ended

September 30, September 30, September 30,

1999 1998 1999 1998 1999 1998

(Millions except Per Share Data)

Income (Numerator):

Earnings applicable to common stock $151.9 $151.1 $249.3 $210.5 $247.1 $179.1

Add: Interest paid or accrued on

           Convertible Debentures,

            net of related taxes      0.9      1.6      3.5      4.7      5.0      6.3

Earnings applicable to common stock,

   assuming conversion of convertible
  securities $152.8 $152.7 $252.8 $215.2 $252.1 $185.4

Shares (Denominator):

Average shares outstanding for

   computation of basic earnings

   per common share 118.5 118.5 118.5 118.5 118.5 118.5

Average shares outstanding for

   diluted computation:

   Average shares outstanding 118.5 118.5 118.5 118.5 118.5 118.5

   Additional shares resulting from:

     Conversion of 7% Convertible

       Debentures - 2.3 1.0 2.3 1.3 2.4

     Conversion of 5% Convertible

       Debentures      3.4      3.4      3.4      3.4      3.4      3.4

Average shares outstanding for

   computation of diluted

   earnings per common share 121.9 124.2 122.9 124.2 123.2 124.3

Basic earnings per common share $1.28 $1.27 $2.10 $1.78 $2.08 $1.51

Diluted earnings per common share $1.25 $1.23 $2.06 $1.73 $2.05 $1.49

Nonutility Subsidiary Long-Term Debt

          Long-term debt at September 30, 1999, consisted primarily of unsecured borrowings
from institutional lenders. The interest rates of such borrowings ranged from 5% to 9.7%.
The weighted average effective interest rate was 7.21% at September 30, 1999, 7.35% at
December 31, 1998, and 7.61% at September 30, 1998. Annual aggregate principal
repayments on these borrowings are $39.0 million in 1999, $147.5 million in 2000,
$88.5 million in 2001, $93 million in 2002, $134.5 million in 2003, and $100.4 million
thereafter. Also included in long-term debt is $37.8 million of non-recourse debt which is
due in monthly installments with final maturities in 2002, 2011 and 2018.

Nonutility Subsidiary Contractual Maturities

          At September 30, 1999, the contractual maturities for mandatorily redeemable
preferred stock are $55.5 million within one year, $43 million from one to five years,
$97.7 million from five to 10 years, and $31.6 million for over 10 years.

(4) Commitments and Contingencies

Competition

          For additional information refer to Note (4) of the Notes to Consolidated Financial
Statements, Commitments and Contingencies and Item 5. Other Information of the
Company's June 30, 1999 Form 10-Q. Also see Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations of the Company's 1998
Form 10-K.

Proposed Sale of Generating Assets

          On September 23, 1999, the Company filed an Amendment to Agreement of
Stipulation and Settlement (the Amendment) with the Maryland Public Service Commission
(Maryland Commission) related to the Company's February 3, 1999 Agreement of
Stipulation and Settlement (the Agreement). The purpose of the Amendment is to allow, but
not require, the Company to exclude its Benning Road and Buzzard Point generating stations,
located in Washington, D.C., from the proposed sale. The net book value of these stations at
September 30, 1999 is approximately $75 million. The Amendment also stipulates that if
those stations are excluded from the sale, the Company will not seek to recover any stranded
costs associated with them from Maryland customers. In addition, those stations will not be
included in the cost of service for purposes of calculating the Company's Maryland
jurisdictional revenue requirement in any rate case filed after June 30, 2000. The Agreement
by its terms will terminate if all required regulatory approvals are not obtained by January 1,
2000.

          On March 16, 1999, the Company filed an application with the D.C. Public Service
Commission (D.C. Commission), which must approve the Company's sale of the
generation assets. The D.C. Commission held hearings during the week of September 27,
1999 and a decision is expected by December 31, 1999.

          In connection with the Company's divestiture application, on November 8, 1999, the
Company filed a non-unanimous agreement of stipulation and full settlement (the D.C. Agreement)
with the D.C. Commission. The D.C. Agreement is opposed by the Office of the People's Counsel,
the District of Columbia Government, and the District of Columbia Consumer Utility Board. Under the
D.C. Agreement, if approved by the D.C. Commission, with the possible exception of stranded costs
related to the Benning Road and Buzzard Point generating stations, if not sold, the Company would recover all
of its stranded costs if any, regulatory assets (including DSM costs not otherwise recovered
from the proceeds of the auction of the generation assets), above market purchased power
costs and transition costs. Consistent with the Amendment discussed above, if the Benning
Road and Buzzard Point generating stations are not sold in the auction of the generation
assets, the Company will not seek to recover any stranded costs associated with them from
District of Columbia customers. In addition, those stations will not be included in the cost of
service for purposes of calculating the Company's District of Columbia jurisdictional revenue
requirement in any future rate case. If these stations are not sold, they will become deregulated and
subject to the effects of the competitive marketplace. The Company continues to evaluate its
alternatives and to assess changing market conditions in order to determine if these stations, with a
net book value of approximately $75 million as of September 30, 1999, are impaired.

          Under the D.C. Agreement, the rates for service to residential customers in the District
of Columbia would be reduced by 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
the District of Columbia are 3-1/2% on January 1, 2000 and 1-1/2% on both July 1, 2000 and
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 (all unamortized DSM costs, equal to $129.3 million at September 30, 1999, will be
deducted from the proceeds of the auction of the generation assets before the sharing, if any,
of any amounts received from the auction between utility customers and shareholders). The
July 1, 2000 rate reductions approximate $12 million annually, and reflect reductions in the
Company's cost of service since its last District of Columbia base rate case, which was
decided on June 30, 1995. The rate reductions following the closing of approximately
$15 million annually 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, which is the four-year period commencing one month following
the date of the closing. Conversely, the Company's future earnings would be reduced if
it is required to purchase power at prices in excess of those included in base rates.
Residential rates for qualified low income customers would be capped for six years commencing
one month after the date of the closing.

          If and when the D.C. Commission approves the sale of the Company's generation assets
and the Maryland Commission approves the Agreement, the Company's generation assets allocated
to Maryland will become deregulated and application of Statement of Financial Accounting
Standards No. 71 (SFAS 71) "Accounting for the Effects of Certain Types of Regulation"
will no longer apply to this generation segment of the Company's business. Under the terms
of the Agreement, all stranded costs allocated to Maryland and the Maryland related
expenses incurred by the Company in preparation for the implementation of retail
competition will be recovered from customers. Accordingly, there will be no impact on the
Company's results of operations from the discontinuance of the provisions of SFAS 71.

          The Company will continue to apply the provisions of SFAS 71 to the portion of its
generation assets allocated to the District of Columbia until the D.C. Council enacts enabling
legislation and the D.C. Commission addresses restructuring issues. As noted above the D.C.
Agreement provides that all stranded costs, if any, allocated to the District of Columbia will be
recovered from customers, with the possible exception of stranded costs related to the Benning
Road and Buzzard Point generating stations, if not sold. Accordingly, if the D.C. Commission
approves the D.C. Agreement and the sale of the stations there should be no impact on the
Company's results of operations from the discontinuance of the provisions of SFAS 71. If these
stations are not sold, the Company will evaluate its alternatives and assess changing market
conditions to determine if these stations are impaired.

Environmental Contingencies

          In addition to the updated information disclosed below, refer to Note (4) of the Notes
to Consolidated Financial Statements, Commitments and Contingencies and Item 5. Other
Information of the Company's June 30, 1999 Form 10-Q. Also see Item 8. Financial
Statements and Supplementary Data of the Company's 1998 Form 10-K.

          The Company's generating stations operate under National Pollutant Discharge
Eliminating System (NPDES) permits. NPDES permits were issued for the Potomac River
station in February 1994, the Morgantown station in February 1995, the Dickerson station in
August 1996, and the Chalk Point station in September 1996. NPDES renewal applications
were submitted in July 1993 for the Benning station and in August 1998 for the Potomac
River station. At September 30, 1999, resolution of these applications is pending.

Redemption of Serial Preferred Stock, Auction Series A

          On October 28, 1999, the Company announced the redemption, on December 1, 1999,
of all one million outstanding shares of its Serial Preferred Stock, Auction Series A, at a price
of $50 per share plus an amount equal to accrued and unpaid dividends to the date of
redemption.

Nonutility Subsidiary - Debt Guarantee

          On September 30, 1999 PCI and PES jointly and severally guaranteed the repayment
of debt for the benefit of PES and its partner in connection with the financing of their
contract with the Military District of Washington (MDW). This contingent obligation is
$3.3 million as of September 30, 1999 and will increase to a maximum of $33.9 million in
January 2002 as the partnership receives draws from the financing. Thereafter, the
contingent obligation will decline as principal is paid down through proceeds of the MDW
contract. For a discussion of this contract refer to Item 2. Management's Discussion and
Analysis of Consolidated Results of Operations and Financial Condition, herein.

(5)  Segment Information

          The Company has identified its operations (Utility Segment) and its Nonutility
Subsidiary's operations (Nonutility Segment) as its two reportable segments. The factors
used to identify these segments are that the Company organizes its business around
differences in products, services, and regulatory environments and that the operating results
for each segment are regularly reviewed by the Company's chief operating decision-maker in
order to make decisions about Company and Nonutility Subsidiary resources and
performance.

          Revenues for the Utility Segment are principally derived from the generation,
transmission, distribution and sale of electric energy. The operations of the Trust are also
included in the Utility Segment. The Nonutility Segment derives its revenue from financial
investments, energy services, utility industry services, and telecommunications services.

          The following table presents information about the Company's reportable segments for
the three, nine and twelve months ended September 30, 1999 and 1998, respectively. There
are no differences in the basis of segmentation or in the basis of measurement of segment
profit or loss as outlined in Item 8. Financial Statements and Supplementary Data of the
Company's 1998 Form 10-K.

	Segment
	Utility	Nonutility	Total
Three Months Ended:	(Millions of Dollars)
September 30, 1999
Revenues	$ 796.9	$ 60.5	$ 857.4
Income	153.7	.3	154.0
Income (Loss) Before Income Taxes	249.1	(3.1)	246.0
Income Tax Expense (Benefit)	95.4	(3.4)	92.0
September 30, 1998
Revenues	$ 750.8	$ 29.9	$ 780.7
Income	149.3	3.8	153.1
Income Before Income Taxes	241.2	1.3	242.5
Income Tax Expense (Benefit)	91.9	(2.5)	89.4

Nine Months Ended:
September 30, 1999
Revenues	$1,770.5	$ 168.6	$1,939.1
Income	231.5	23.8	255.3
Income (Loss) Before Income Taxes	374.9	(2.4)	372.5
Income Tax Expense (Benefit)	143.4	(26.2)	117.2
September 30, 1998
Revenues	$1,659.7	$ 103.2	$1,762.9
Income	210.4	16.2	226.6
Income Before Income Taxes	339.9	13.8	353.7
Income Tax Expense (Benefit)	129.5	(2.4)	127.1

Twelve Months Ended:
September 30, 1999
Revenues	$2,174.7	$ 208.9	$2,383.6
Income	232.3	22.7	255.0
Income (Loss) Before Income Taxes	377.2	(9.8)	367.4
Income Tax Expense (Benefit)	144.9	(32.5)	112.4
September 30, 1998
Revenues	$2,050.1	$ 127.0	$2,177.1
Income	181.8	17.5	199.3
Income Before Income Taxes	293.5	7.6	301.1
Income Tax Expense (Benefit)	111.7	(9.9)	101.8

          Revenues are earned primarily within the United States and there were no material
transactions between the segments.
(6) Energy Trading and Risk Management Activities

The Company

          The Company 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 PES

          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 $39 million at
September 30, 1999. 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 September 30, 1999, the interest rate swap agreements have an average life
of 3.69 years with a fixed rate of 6.69% and variable rate of 6.27%. The fair value of these
interest rate swap agreements, based on quoted market prices, was approximately $.8 million
as of September 30, 1999.

          PES enters into agreements to sell electricity and natural gas to customers and matches
these sales with offsetting forward agreements to purchase electricity and natural gas. PES
limits exposure to changes in market prices by counterbalancing fixed price sales agreements
with fixed price supply agreements and floating price sales agreements with floating price
supply agreements.

Accounting Treatment

          The Company's, PCI's, and PES' agreements are not used for trading purposes and are
accounted for under Statement of Financial Accounting Standards No. 80 (SFAS 80),
"Accounting for Futures Contracts." In accordance with SFAS 80, the financial agreements
that represent hedges are not included on the consolidated balance sheets and gains and
losses are recognized in the consolidated statement of earnings and retained income at the
time of the transaction. There were no deferred gains or losses at September 30, 1999.

          The accounting treatment outlined in Emerging Issues Task Force Issue 98-10
(EITF 98-10) "Accounting for Energy Trading and Risk Management Activities," does not
apply to the Company's, PCI's, and PES' agreements since the agreements are not entered
into for trading purposes as defined by EITF 98-10. Additionally, the Company, PCI, and
PES are in the process of determining the impact, if any, that Statement of Financial
Accounting Standards No. 133 (SFAS 133) "Accounting for Derivative Instruments and
Hedging Activities," will have on its financial statements and disclosures. The effective date
of SFAS 133 has been delayed and will become effective for the Company's 2001 calendar
year financial statements.

* * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * *

          This Quarterly Report on Form 10-Q, including the review report of
PricewaterhouseCoopers LLP will automatically be incorporated by reference in the
Prospectuses constituting parts of the Company's Registration Statements on Forms S-3
(Numbers 33-58810, 33-61379 and 333-33495) and Forms S-8 (Numbers 33-36798,
33-53685, 33-54197, 333-56683 and 333-57221), filed under the Securities Act of 1933.
Such review report of PricewaterhouseCoopers LLP, however, is not a "report" or "part of
the Registration Statement" within the meaning of Sections 7 and 11 of the Securities Act of
1933 and the liability provisions of Section 11(a) of such Act do not apply.

REPORT OF INDEPENDENT ACCOUNTANTS

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

We have reviewed the accompanying consolidated balance sheets of Potomac Electric Power
Company and its consolidated subsidiaries (the Company) at September 30, 1999 and 1998,
and the related consolidated statements of earnings and retained income for the three, nine
and twelve month periods then ended and the consolidated statements of cash flows for the
nine and twelve month periods then ended. These financial statements are the responsibility
of the Company's management.

We conducted our review in accordance with standards established by the American Institute
of Certified Public Accountants. A review of interim financial information consists
principally of applying analytical procedures to financial data and making inquiries of
persons responsible for financial and accounting matters. It is substantially less in scope than
an audit conducted in accordance with generally accepted auditing standards, the objective of
which is the expression of an opinion regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to
the accompanying financial information for it to be in conformity with generally accepted
accounting principles.

We have previously audited, in accordance with auditing standards generally accepted in the
United States, the consolidated balance sheet as of December 31, 1998, and the related
consolidated statements of earnings and consolidated statement of cash flows for the year
then ended (not presented herein); and in our report dated January 25, 1999, we expressed an
unqualified opinion on those consolidated financial statements. In our opinion, the
information set forth in the accompanying consolidated balance sheet information as of
December 31, 1998, is fairly stated, in all material respects, in relation to the consolidated
balance sheet from which it has been derived.

PricewaterhouseCoopers LLP
Washington, D.C.
November 12, 1999

Part I     FINANCIAL INFORMATION
Item 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED
                 RESULTS OF OPERATIONS AND FINANCIAL CONDITION

GENERAL

          As an investor-owned electric utility, Potomac Electric Power Company (the
Company, or the Utility) is capital intensive, with a gross investment in property and plant of
approximately $3 for each $1 of annual total revenue. The costs associated with property and
plant investment amounted to 46% of the Company's total revenue for the twelve months
ended September 30, 1999 and December 31, 1998, respectively. Additionally, fuel and
purchased energy, capacity purchase payments and other operating expenses were 54% of
total revenue for the twelve months ended September 30, 1999 and December 31, 1998,
respectively.

          On May 21, 1999, the Company 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, Pepco Holdings, Inc. (PHI, or the Nonutility
Subsidiary), was created as the parent company of Potomac Capital Investment Corp. (PCI)
and Pepco Energy Services, Inc. (PES). PCI will continue to manage its diversified portfolio
of financial investments and grow its new operating businesses that provide
telecommunications and utility related services. PES is focused on providing nonregulated
energy products (electricity and natural gas) and energy services (including energy efficiency
contracting, consulting services, construction, management and facilities operation and
maintenance) in competitive markets.

          Potomac Electric Power Company Trust I (Trust), a Delaware statutory business trust
and a wholly owned subsidiary of the Company, was established in April 1998 for the
purposes of issuing Trust Securities representing undivided beneficial interests in the assets
of the Trust, and investing the gross proceeds from the sale of the Trust Securities in Junior
Subordinated Debentures of the Company.

          The Company has identified its operations (Utility Segment) and its Nonutility
Subsidiary's operations (Nonutility Segment) as its two reportable segments. The Utility
Segment principally derives its revenue from the generation, distribution and sale of electric
energy. The operations of the Trust are also included in the Utility Segment. The Nonutility
Segment derives its revenue from financial investments, energy services, utility industry
services, and telecommunications services. See Note (5) of the Notes to Consolidated
Financial Statements, Segment Information, herein, for the Company's segment disclosure.

Safe Harbor Statements

          In connection with the safe harbor provisions of the Private Securities Litigation
Reform Act of 1995 (Reform Act), the Company and its Nonutility Subsidiary are hereby
filing cautionary statements identifying important factors that could cause actual results to
differ materially from those projected in forward-looking statements (as such term is defined
in the Reform Act) made in this Quarterly Report on Form 10-Q. 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 its Nonutility Subsidiary and may cause actual results to differ materially from
those contained in forward-looking statements:

-	prevailing governmental policies and regulatory actions, including those of the Federal Energy Regulatory Commission (FERC), with respect to allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power, and present or prospective wholesale and retail competition (including but not limited to retail wheeling and transmission costs);
-	economic and geographic factors including political and economic risks;
-	changes in and compliance with environmental and safety laws and policies;
-	weather conditions;
-	population growth rates and demographic patterns;
-	competition for retail and wholesale customers;
-	Year 2000 issues; delays or changes in costs of Year 2000 compliance; failure of major suppliers, customers, or others to resolve their own Year 2000 issues on a timely basis;
-	growth in demand, sales, and capacity to fulfill demand;
-	changes in tax rates or policies or in rates of inflation;
-	changes in projects costs;
-	unanticipated changes in operating expenses and capital expenditures;
-	capital market conditions;
-	competition for new energy development opportunities and other opportunities;
-	legal and administrative proceedings (whether civil or criminal) and settlements that influence business and profitability;
-	pace of entry into new markets;
-	time and expense required for building out the planned Starpower network;
-	success in marketing services;
-	possible development of alternative technologies; and
-	the ability to secure electric and gas supply to fulfill sales commitments at favorable prices.

          Any forward-looking statements speak only as of November 12, 1999, and the Company
and its Nonutility Subsidiary undertake 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.

UTILITY

RESULTS OF OPERATIONS

Total Revenue

          Total revenue increased for the three, nine and twelve months ended September 30,
1999, as compared to the corresponding periods in 1998. The increases in revenue from
sales of electricity for the periods ending September 30, 1999 resulted primarily from
increases in kilowatt-hour sales of 2.8%, 2.7%, and 1.5% over the corresponding periods in
1998. The increases in sales reflect 1999 summer temperatures that were 7 percent hotter, as
measured in cooling degree hours, than the corresponding period in 1998. Temperatures in
the first quarter, as measured in heating degree days, were 15 % colder than the
corresponding period in 1998.

          The increases in base rate revenue in the three, nine and twelve months ended
September 30, 1999, compared to the corresponding periods in 1998, reflect the effects of 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.

          Interchange deliveries increased for the three, nine and twelve months ended
September 30, 1999, as compared to the corresponding periods in 1998. The increases for
the periods reflect changes in levels and prices of energy delivered to the Pennsylvania-
New Jersey-Maryland Interconnection LLC (PJM) and increases in the levels of bilateral
energy transactions under the Company's wholesale power sales tariff.

          The Company receives point-to-point transmission service revenue, pursuant to the
PJM open access transmission tariff. Such revenues are classified as "Other electric
revenue," and totaled $2 million, $4.6 million and $5 million for the three, nine and twelve
months ended September 30, 1999, and $2.7 million, $3.5 million and $3.6 million for the
corresponding periods in 1998. The benefits derived from interchange deliveries, capacity
sales in the District of Columbia and revenue under the open access transmission tariff are
passed through to the Company's customers through fuel adjustment clauses.

          Recent rate orders received by the Company provided for changes in annual base rate
revenue as shown in the table below:

Regulatory Jurisdiction	Rate Increase (Decrease) ($000)	% Change	Effective Date
Maryland	$19,000	2.0%	December 1998
Federal - Wholesale	(2,500)	(1.8)	January 1998
Maryland	24,000	2.6	November 1997

See Part II, Item 5, Base Rate Proceedings, for additional information.

          As discussed in Part I, Item 2., Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition of the Company's June 30, 1999
Form 10-Q, the Company has a new full-requirements agreement with the Southern
Maryland Electric Cooperative, Inc. (SMECO), effective January 1, 1999.

Operating Expense

          Fuel expense increased for the three, nine and twelve months ended September 30,
1999, as compared to the corresponding periods in 1998, primarily due to increases of 9.7%,
7.3% and 9.1% in net generation; partially offset in the nine and twelve month periods by
decreases in the system average unit cost of fuel discussed below. The increases in purchased
energy for the three, nine and twelve months ended September 30, 1999, reflect changes in
levels and prices of energy purchased from PJM and other utilities and power marketers.

          The unit fuel costs for the comparative periods ended September 30 were as follows:

	Three Months Ended September 30,		Nine Months Ended September 30,		Twelve Months Ended September 30,
	1999	1998	1999	1998	1999	1998
System Average Fuel Cost per Mbtu	$1.76	$1.72	$1.72	$1.75	$1.70	$1.77

          System average unit fuel cost decreased for the nine and twelve months ended
September 30, 1999, as compared to the corresponding periods in 1998, primarily due to
decreases in the costs of coal and residual oil. The increase for the three months ended
September 30, 1999 was primarily attributable to increases in the cost of residual oil and
natural gas and an increase in the percent of natural gas contribution to the fuel mix.

          For the twelve month periods ended September 30, 1999 and 1998, the Company
obtained 81% and 84%, respectively, of its system generation from coal based upon
percentage of Btus. The Company's major cycling and certain peaking units can burn either
natural gas or oil, adding flexibility in selecting the most cost-effective fuel mix.

          Capacity purchase payments increased for the three, nine and twelve months ended
September 30, 1999, as compared to the corresponding periods in 1998. These increases
reflect contractual escalations under existing purchase capacity contracts with FirstEnergy
and Panda-Brandywine (Panda). The increases are reflected in rates in the District of
Columbia through a fuel adjustment clause on a dollar-for-dollar basis and in Maryland
through a rate settlement in December 1998. The Maryland rates, however, are seasonal,
which results in lower recovery in the winter and higher recovery in the summer.

          Operating expenses other than fuel, purchased energy and capacity purchase payments
increased for the three, nine and twelve months ended September 30, 1999, as compared to
the corresponding periods in 1998. Increases in these expenses in the three month period
were due to increases in operation and maintenance expenses related to summer storm
damage, and increases in depreciation and amortization expense associated with additional
investment in property and plant. Increases in these expenses in the nine and twelve month
periods were due to increases in depreciation and amortization expense association with
additional investment in property and plant; partially offset by decreases in operation and
maintenance expenses association with reduced labor and benefits costs, and a reduction in
gross receipts taxes collected from customers in the District of Columbia.

Year 2000 Readiness Disclosure

          For a discussion of the Company's Year 2000 Readiness Disclosure at December 31,
1998, refer to Part II., Item 7., Management's Discussion and Analysis of Financial Condition
and Results of Operations of the Company's 1998 Form 10-K. The status of the Company's
Year 2000 efforts at September 30, 1999 is as follows.

          Based on the Company's successful remediation of systems in the 50 separate
categories that the North American Electric Reliability Council (NERC) defines as
mission-critical facilities and information technology (IT) business systems, NERC stated in
its August 3, 1999 report to the U.S. Department of Energy (DOE) that the Company is Year
2000 ready with no exceptions. NERC also stated in this report that the Company has
completed all contingency plans in accordance with NERC guidelines.

          Systems that have an impact solely on departmental or work group operations have
been defined with medium and low criticality. None of these systems has an impact on
electric service to customers.

          All critical suppliers, including generation fuel and transportation, have responded
positively to the correspondence sent by the Company requesting Year 2000 readiness status.
The Company continues to follow-up via phone calls to monitor Year 2000 progress with
these suppliers. When warranted, the Company has developed and documented contingency
supply alternatives. The Company continues to attempt to contact non-critical
vendors/suppliers, and maintains documentation of all such communication efforts.

          Year 2000 business continuity and contingency plans have been completed in
accordance with NERC guidelines. Sixty teams from all business units participated in
designing plans to deal with approximately 175 scenarios which could potentially disrupt
operations. The Company has designed 519 plans to deal with these incidents. Tabletop
testing and refinement of the plans have also been completed. The Company has recently
reaffirmed the policy of no vacation time or discretionary leave for any employee during the
critical millennium rollover, from December 26, 1999 through January 8, 2000. Contingency
staffing plans for this period have been completed. Information from the staffing and
business continuity plan databases were used to develop business unit Year 2000 Rollover
Plans.

          The Company continues to participate in community and industry coordination and
drills. The Company participated in the NERC-sponsored "dress rehearsal" drill held on
September 8 and 9, 1999, which simulated the rollover from December 31, 1999 to
January 1, 2000. This drill reconfirmed the capabilities of the Company's contingency
communications plans including the use of satellite phones to link with the PJM control
center. The Company went well beyond the NERC-defined drill parameters by activating its
Emergency Command Center (ECC) and interacting with field personnel tasked with
checking the status of various systems and facilities. The ECC operated from 8 PM on
September 8, 1999 through 2 AM on September 9, 1999 under the direction of the
Company's Chief Executive Officer (CEO) and other senior executives. Representatives
from the local media were in attendance, and the CEO and other Company personnel
conducted several press briefings. The District of Columbia Emergency Management
Agency participated jointly with the Company during this exercise by opening its command
center and testing communication links. Several tabletop exercises were conducted at the
Company's ECC. The rollover to September 9, 1999 was monitored as part of the drill, and
proved to be uneventful. All aspects of the drill were carried out successfully.

          The Company was an active participant in the September 1, 1999 drill sponsored by
the Washington Metropolitan Council of Governments with the Company's employees
stationed at several locations throughout the District and metropolitan area.

          In September 1999, the Company was selected at random by NERC and DOE to
undergo a Year 2000 audit. This independent review, conducted in October 1999,
emphasized energy management (EMS) and supervisory control and data acquisition
(SCADA) systems, but also involved an examination of the Company's Business Continuity
Plans (BCPs) and the Corporate Year 2000 Database. The audit required the Company to
rerun an EMS test, setting the date forward to January 1, 2000. This was done successfully.
The DOE assessors awarded the Company the highest rating available.

          In September 1999, the DC PSC initiated an independent verification and validation of
the Company's Year 2000 efforts using an outside consultant. This audit involves a review
of (1) the Company's Corporate Year 2000 Database with supporting test plans and results;
(2) the BCPs; (3) vendor and supply chain efforts and documentation; and (4) other pertinent
Year 2000 documentation. This process is on-going.

          The Company has established a range of communications to keep customers and the
public informed of Year 2000 efforts. Bill inserts have been used to advise customers of
Year 2000 activities. Future bill inserts will be used as needed. A Year 2000 disclosure
brochure is being distributed to customers who inquire about the Company's Year 2000
efforts. This brochure was updated in August 1999. The information included in the
brochure has been posted on the Company's web site on the Internet. The web site has been
updated and will continue to be updated periodically with the latest Year 2000 status
information.

          The cost or consequences of a material incomplete or untimely resolution of the Year
2000 problem could adversely affect the future operations, financial results or financial
condition of the Company.

          The cost of expected modifications will be approximately $12 million, and will be
charged to expense as incurred. Through September 30, 1999, $10 million has been charged
to expense; the remaining costs will be expensed in the fourth quarter of 1999.
Approximately $.7 million, $3 million, and $5.3 million of the total expected cost, were
expensed in the three, nine and twelve months ended September 30, 1999, respectively.

CAPITAL RESOURCES AND LIQUIDITY

          The Company's investment in property and plant, at original cost before accumulated
depreciation, was $6.7 billion at September 30, 1999, an increase of $87.1 million from the
investment at December 31, 1998, and an increase of $135 million from the investment at
September 30, 1998. Cash invested in property and plant construction, excluding Allowance
for Funds Used During Construction and Capital Cost Recovery Factor, amounted to
$135 million and $195.3 million for the nine and twelve months ended September 30, 1999,
and $145.9 million and $223 million for the corresponding periods in 1998.

          At September 30, 1999, the Company's capital structure, excluding short-term debt and
nonutility subsidiary debt, consisted of 46.6% long-term debt, 2.4% serial preferred stock,
1.2% redeemable serial preferred stock, 3% Company obligated redeemable preferred
securities of subsidiary trust and 46.8% common equity.

          Cash from utility operations, after dividends, was $112.5 million and $107.3 million
for the nine and twelve months ended September 30, 1999, and $224.1 million and
$269.2 million for the corresponding periods in 1998.

          The Company's current annual dividend on common stock is $1.66 per share. The
dividend rate is determined by the Company's Board of Directors and takes into
consideration, among other factors, current and possible future developments which may
affect the Company's income and cash flow levels. The Company has no current plans to
change the dividend; however, there can be no assurance that the $1.66 dividend rate will be
in effect in the future.

          Outstanding utility short-term debt totaled $148.6 million at September 30, 1999,
compared to $191.7 million and $119.1 million outstanding at December 31, 1998 and
September 30, 1998, respectively.

          As discussed in Note (4) of the Notes to Consolidated Financial Statements,
Commitments and Contingencies, herein, on October 28, 1999, the Company announced the
redemption on December 1, 1999, of all one million outstanding shares of its Serial Preferred
Stock, Auction Series A.

NONUTILITY SUBSIDIARY

GENERAL

          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 underway, the focus of the
Company's nonutility subsidiaries has been significantly expanded to include new
competitive telecommunications and energy businesses. To facilitate this expansion, on
May 21, 1999, the Company reorganized its nonregulated subsidiaries into two major
operating groups to compete for new market share in deregulated markets. As part of the
reorganization, a new unregulated company, PHI, was created as the parent company of PCI
and PES.

          PCI continues to manage its diversified portfolio of financial investments and grow its
new operating businesses that provide telecommunications and utility-related services. PCI's
telecommunication products and services are primarily provided through its 50% equity
interest in a joint venture known as Starpower Communications, LLC (Starpower). Both
partners in the joint venture have committed to initially contribute up to $150 million of
equity to the joint venture over a three-year period (1998 - 2000) to build an advanced,
high-bandwidth fiber-optic network for consumers in the Washington, Baltimore, and
Northern Virginia metropolitan region. Over this "Last Mile" fiber-optic link, Starpower
provides a consumer package of telecommunication services including cable television, local
and long distance telephone, dial up and high-speed Internet services. As of September 30,
1999, PCI has invested $46.7 million of its total $150 million commitment.

          PES provides nonregulated energy and energy-related services in competitive retail
markets in the mid-Atlantic region from Pennsylvania to Georgia. In addition to its principal
office in Washington, D.C., PES has offices in Pittsburgh, Pennsylvania; Philadelphia,
Pennsylvania; Columbia, Maryland; Virginia Beach, Virginia; and Savannah, Georgia. Its
products include electricity, natural gas, energy efficiency contracting, equipment operation
and maintenance, fuel management, and appliance warranties. These products and services
are sold in bundles or individually to commercial, industrial and residential customers.

RESULTS OF OPERATIONS

          Refer to Part II., Item 5. - Other Information - Selected Nonutility Subsidiary Financial
Information, herein, for PHI's Consolidated Statements of Earnings for the three, nine and
twelve months ended September 30, 1999 and 1998.

Income

Financial Investments

          Financial investments income consists primarily 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 transactions contribute to
financial investments income. In general, the timing of the recognition of financial
investments income is transaction driven.

          The leased assets component of financial investments income, which primarily
includes rental and interest income, increased for the three months ended September 30,
1999, compared to the corresponding period in 1998, primarily as a result of income received
from the leveraged leases with four Dutch Municipal owned entities that were entered into
during the third quarter of 1999. This component of financial investment income decreased
for the nine and twelve months ended September 30, 1999, compared to the corresponding
periods in 1998, primarily as a result of a reduction in the size of PCI's aircraft portfolio due
to the disposition of aircraft. PCI's remaining aircraft portfolio, with a net book value of
$283.6 million and $313.7 million at September 30, 1999 and December 31, 1998,
respectively, is being managed with the objective of identifying further opportunities for its
sale or disposition on economic terms. Leased assets contributed income of $17.2 million,
$48.1 million and $62.1 million for the three, nine and twelve months ended September 30,
1999, respectively, compared to $15.5 million, $59.3 million and $77.9 million for the
corresponding periods in 1998.

          The marketable securities component of financial investments income increased for the
three months ended September 30, 1999, compared to the corresponding period in 1998, due
to the recognition of income from sales. This component of financial investment income
decreased for the nine and twelve months ended September 30, 1999, compared to the
corresponding periods in 1998, due to decreases in dividend income which resulted from
reductions in the size of the stock portfolio during 1998. The marketable securities portfolio
contributed income, including net realized gains, of $5.5 million, $13.5 million and
$17.9 million for the three, nine and twelve months ended September 30, 1999, respectively,
compared to $3.9 million, $14.9 million and $19.9 million for the corresponding periods in
1998.

          The remaining component of financial investments income represents revenue related
to the sale of real estate and other financial transactions. This component of financial
investment income decreased for the three and nine months ended September 30, 1999,
compared to the corresponding periods in 1998, primarily due to gains on the sales of real
estate that were recorded during the first and third quarters of 1998. This component of
financial investment income increased for the twelve months ended September 30, 1999,
compared to the corresponding period in 1998, as a result of a $10 million writedown of real
estate that was recorded during the fourth quarter of 1997. Income for the three, nine and
twelve months ended September 30, 1999 was $1.3 million, $16.6 million and $19.1 million,
respectively, compared to $9.0 million, $17.3 million and $11.6 million for the
corresponding periods in 1998.

          PCI is in the process of building, owning and financing a new ten-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 September 30, 1999, PCI has invested $25.7 million related to the
acquisition of land and development of the new building.

          In July 1999, PCI entered into a $724 million leveraged lease transaction with four
Dutch Municipal owned entities. This transaction involved the purchase and leaseback of 21
gas transmission and distribution networks, located throughout The Netherlands, over base
lease terms approximating 25 years. The transaction was financed with approximately
$607 million of third-party, non-recourse debt through two banks at commercial rates for a
period of 25 years. PCI's initial net investment in these finance leases was approximately
$134 million and was funded primarily through its Medium-Term Note program. This
transaction added $1.1 million of net income during the third quarter of 1999.

          On October 29, 1999, a subsidiary of PHI sold its minority equity interest in Metricom,
D.C., LLC, a wireless internet joint venture with Metricom, Inc. The sale resulted in an
after-tax gain of approximately $1.7 million, which will be recorded in the fourth quarter of
1999.

Energy Services

          Energy services income represents income generated from the operations of PES. The
increase in energy services income for all periods in 1999, compared to the corresponding
periods in 1998, results principally from a significant increase in the volume of energy
efficiency business and from the acquisition of Gaslantic Corporation (Gaslantic) in
September 1998. Typical of gas marketing operations, Gaslantic's purchase of energy to
fulfill client contract requirements is a high-volume and relatively low-margin business.

          In June 1999, the Department of Defense awarded the federal government's largest
energy-saving performance contract ever to a 50/50 partnership between a wholly owned
subsidiary of PES and another contractor. Under the $214 million contract, executed on
June 29, 1999, the partnership will implement energy-savings measures for five military
bases in the Military District of Washington (MDW). The partnership will invest $67 million
over the next 30 months in infrastructure improvements. Thereafter, the partnership will
maintain, operate and monitor the equipment for 15 years. There are no front-payments by
the government, and PES and its partner will provide energy engineering, equipment
installation, construction supervision, maintenance, operations and monitoring over the term
of the contract to provide energy savings that will pay for these improvements. The
energy-savings measures will cover a wide range of technologies, including lighting,
building envelope, building automation systems, chillers, controls, HVAC, boilers and water
conservation. Financing for this project has been obtained and construction has begun. As
discussed in Note (4) of the Notes to Consolidated Financial Statements, Commitments and
Contingencies, PCI and PES have jointly and severally guaranteed the repayment of debt for
the benefit of the partnership in connection with the partnership's financing of its contract
with MDW.

          A wholly owned subsidiary of PES signed a four-year agreement commencing in
January 2001, to provide full requirements energy to SMECO (approximately 600 MW of
peak load). The PES subsidiary has secured a firm commitment from a third party 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. The revenues from this contract are expected to be approximately
$100 million per year. Including this contract and energy supply contracts with commercial
and residential customers in Pennsylvania, PES has supply contracts for approximately
650 MW of load.

          PES has significantly increased its commercial energy services in 1999. PES
recognized revenue of $85.4 million and $9.4 million for the nine months ended
September 30, 1999, and 1998, respectively.

          In total, during the first nine months of 1999, PES signed contracts for the future
delivery of energy and energy services which will provide future revenues of approximately
$500 million. Commodity revenues are recognized upon delivery to the customer while
construction energy contract revenues are recognized using the percentage of completion
method.

Utility Industry Services

          The decrease in utility industry services income for the three months ended
September 30, 1999, compared to the corresponding period in 1998 is attributable to timing
differences related to the recognition of contract revenue. The increase in utility industry
services income for nine and twelve months ended September 30, 1999, compared to the
corresponding periods in 1998, results from the growth of this portion of the business.
During the past six years, PCI has acquired ownership and operating interests in a natural gas
pipeline, liquefied natural gas storage facilities, and an underground cable services company,
all of which profitably provide products and services to utilities and to other customers.
Additionally, in 1999, PCI launched a new business strategy that is targeted at bringing new
electric technologies to the utility industry as it deregulates.

Telecommunications Services

          Telecommunications services losses represent PCI's share of losses from its equity
investments, principally Starpower. PCI expects that its investment in Starpower will
continue to incur losses for the remainder of 1999 and 2000 as it develops and expands its
network and customer base. However, Starpower had earnings from its operations before
interest, taxes, depreciation and amortization in 1998, two years ahead of schedule, and as of
September 30, 1999 has had similar results, principally from its Internet operations.

          Starpower is currently the only regional company to provide cable television, local and
long distance telephone, dial-up and high speed Internet services on an a-la-carte basis, or
combined into one bundled, competitively priced package, over an advance fiber-optic
network. During 1999, Starpower expects to build sufficient advanced fiber-optic network to
add in excess of 50,000 on-network households and as of September 30, 1999, has added in
excess of 25,000 on-network households. Of these on-network households, in excess of
10,000 on-network customer service connections have been sold with the average customer
household purchasing in excess of 2 services. Customer take rates have substantially
exceeded plan. Starpower's total customer service connections including cable, phone and
Internet customers now exceed 270,000 as of September 30, 1999, from a level of 237,000 as
of year-end 1998.

          During the third quarter, Starpower added to its number of approved cable households
by winning approvals from Montgomery County, Maryland and the City of Falls Church,
Virginia to build an advance fiber-optic network and offer competitive cable television
services to households in these jurisdictions. The Montgomery County Council awarded a
15-year franchise to Starpower to compete for customers against the county's existing cable
provider. The franchise will enable Starpower to potentially serve more than 80 percent of
the 308,000 households in the county, which is the nation's eighth wealthiest county and the
largest county in Maryland with a population of 850,000. The long-term agreement with the
City of Falls Church allows Starpower to enter the Virginia suburbs for the first time.
Starpower intends to start construction of the network in Falls Church and expects to begin to
offer its bundle of advanced communication services, including digital cable television, local
and long distance telephone service, and high-speed Internet service, in Northern Virginia
during 2000. These agreements increased the number of authorized cable households for
Starpower in the Washington metropolitan area to in excess of 500,000 at September 30,
1999, approximately 25% ahead of plan. Starpower is currently seeking additional cable
regulatory authority approvals in the Washington, D.C. Metropolitan Area, which if realized
will potentially double the authorized cable households.

          In July 1999, Starpower announced a strategic portal alliance with Lycos, one of the
leading Internet portal companies in the United States. This agreement provides the Lycos'
portal to Starpower's current dial-up Internet customer base and includes a strategic alliance
to build a high-speed Lycos portal known as "Lycos Lightening" for Starpower's customers
served from its high-speed advanced fiber-optic network.

          The success of Starpower will depend upon the ability of Starpower 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.

Expenses

Operating and Administrative & General

          The increase in operating and administrative and general expenses for all periods in
1999, compared to the corresponding periods in 1998, mainly results from the increase in
PES' business activities. Purchases of gas and electricity to fulfill sales commitments
aggregated $29.6 million, $49.4 million, and $79.7 million for the three, nine and twelve
months ended September 30, 1999. There were no gas and electricity purchases for the
corresponding periods in 1998.

Interest and Depreciation

          The decrease in interest expense for all periods in 1999, compared to the corresponding
periods in 1998, results from reduced borrowings during 1999 and lower effective interest
rates. The increase in depreciation expense for the three months ended September 30, 1999,
compared to the corresponding period in 1998, was primarily due to an adjustment of
depreciation estimates. Additionally, the decrease in depreciation expense for the nine and
twelve months ended September 30, 1999, compared to the corresponding periods in 1998,
results from the disposition of aircraft.

Income Tax Benefit

          The increase in PHI's income tax benefit for the nine and twelve months ended
September 30, 1999, compared to the corresponding periods in 1998, primarily reflects the
recognition of $18.7 million in tax benefits in June 1999 associated with the completion of a
partnership restructuring transaction. This restructuring allowed PCI to consolidate the
majority of its aircraft assets under one umbrella company, and by doing so, facilitates the
management and disposition of its aircraft portfolio.

Year 2000 Readiness Disclosure

          For a discussion of PHI's Year 2000 Readiness Disclosure at December 31, 1998, refer
to Item 7. Management's Discussion and Analysis of Financial Condition and Results of
Operations of the Company's 1998 Form 10-K. The status of PHI's Year 2000 efforts at
September 30, 1999 is as follows.

          PHI is continuing to work closely with the Corporate Year 2000 Task Force in
connection with its Year 2000 remediation efforts. PHI has nearly completed the first three
phases of its Year 2000 remediation plan by identifying items requiring remediation,
correcting any problems that have been identified, and completing the compliance testing for
all critical systems. In addition, PHI is nearing completion of the final element of its Year
2000 remediation plan which is the preparation of a contingency plan in the event that
remediation efforts are not successfully completed in a timely fashion.

          The cost or consequences of a material incomplete or untimely resolution of the Year
2000 problem could adversely affect the future operations, financial results or financial
condition of PHI.

CAPITAL RESOURCES AND LIQUIDITY

          At September 30, 1999, PCI had a $230.4 million marketable securities portfolio,
consisting primarily of fixed-rate, utility preferred stocks. During the first nine months of
1999, the cost basis of PCI's marketable securities portfolio increased by $9.6 million,
primarily as a result of calls and acceptance of tender offers of approximately $15.6 million,
offset by security purchases of $25.2 million.

          PCI had short-term debt outstanding of $158.9 million as of September 30, 1999.
There was no short-term debt outstanding as of December 31, 1998. For the three, nine and
twelve months ended September 30, 1999, PCI issued (repaid) $12.2 million, $158.9 million
and $(24.1) million in short-term debt, respectively. During the three, nine and twelve
months ended September 30, 1999, PCI issued $0.1 million, $36.2 million and
$204.3 million in long-term debt, including non-recourse debt, and debt repayments totaled
$34.1 million, $134.3 million and $143.6 million, respectively. The weighted-average
effective interest rate of long-term debt was 7.21% at September 30, 1999, 7.35% at
December 31, 1998, and 7.61% at September 30, 1998. At September 30, 1999, PCI had
$101.5 million available under its Medium-Term Note Program and $400 million of unused
bank credit lines.

          PHI expects that based on its cash on hand, as well as credit facilities available, it has
sufficient available funds to meet normal working capital requirements, capital expenditures,
scheduled debt repayments and acquisitions, if necessary.

          In July 1999, PCI entered into a $724 million leveraged lease transaction with four
Dutch Municipal owned entities. This transaction involved the purchase and leaseback of 21
gas transmission and distribution networks, located throughout The Netherlands, over base
lease terms approximating 25 years. The transaction was financed with approximately
$607 million of third-party, non-recourse debt through two banks at commercial rates for a
period of 25 years. PCI's initial net investment in these finance leases was approximately
$134 million and was funded primarily through its Medium-Term Note program. This
transaction added $1.1 million of net income during the third quarter of 1999.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
                  RISK

          For information other than the updated disclosures contained below, refer to Item 7A.
Quantitative and Qualitative Disclosures About Market Risk of the Company's 1998
Form 10-K.

          As discussed in Note (6) of the Notes to Consolidated Financial Statements, Energy
Trading and Risk Management Activities, herein, PCI uses interest rate swap agreements to
minimize its interest rate risk. The fair value of these agreements at September 30, 1999 was
approximately $.8 million. The potential loss in fair value from these agreements resulting
from a hypothetical 10% adverse movement in base interest rates is estimated at
approximately $1 million at September 30, 1999.

          Additionally, as a result of the forward agreements discussed in Note (6) of the Notes
to Consolidated Financial Statements, Energy Trading and Risk Management Activities, herein, the
Company and PES may be subject to credit losses and nonperformance by the counter parties
to the agreements, but anticipate that the counter parties will be able to fully satisfy their
obligations under the agreements. The Company and PES do not obtain collateral or other
securities to support financial instruments subject to credit risk, but monitor the credit
standing of the counter parties.

PART II OTHER INFORMATION
Item 1.      LEGAL PROCEEDINGS

          Refer to Note (4) of the Notes to Consolidated Financial Statements, Commitments
and Contingencies, herein. Also, refer to the discussion of Environmental Matters under
Item 1. Business and Item 3. Legal Proceedings of the Company's 1998 Form 10-K.

Item 5.    OTHER INFORMATION

OTHER FINANCING ARRANGEMENTS

          The Company and PHI satisfy their short-term financing requirements through the sale
of commercial promissory notes. The Company and PHI maintain minimum 100 percent
lines of credit back-up, in the amounts of $165 million and $400 million, respectively, for
their outstanding commercial promissory notes. These lines of credit were unused during
1999 and 1998.

BASE RATE PROCEEDINGS

          In addition to the updated information disclosed below, refer to the discussion of
Maryland and the District of Columbia Base Rate Proceedings under Item 5. Other
Information - Base Rate Proceedings of the Company's June 30, 1999 Form 10-Q and Item 1.
Business of the Company's 1998 Form 10-K. Also refer to the discussion of the Agreement,
the Amendment, and the D.C. Agreement in Note (4) of the Notes to Consolidated Financial Statements,
Commitments and Contingencies, herein.

          On September 23, 1999, the Company filed an Agreement of Stipulation and
Settlement Regarding Unbundled Rate Issues (the Phase II Settlement Agreement) with the
Maryland Commission. The Phase II Settlement Agreement is the result of negotiations
conducted over a period of approximately five months among representatives of the parties to
the Agreement as well as other parties. The 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 a reduction in the Demand-Side
Management (DSM) surcharge rate, effective July 1, 2000, made possible through
acceleration of the recovery of DSM costs. This charge allows the Company to fully recover
approximately $7 million in charges for Universal Service that have been imposed by the
Maryland legislature. There is no earnings effect from this rate reduction. Additionally, the
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, available after the Company's generation assets are sold.
Conversely, the Company's future earnings would be reduced if it is required to purchase
power at prices in excess of those included in base rates. The 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. The Phase
II Settlement Agreement contains several other provisions that will provide important
protections and benefits to the Company's Maryland customers and promote a fair and
orderly implementation of the restructuring process. Additionally, the Amendment and the
Phase II Settlement Agreement provide that customer choice be available for all customers
on July 1, 2000.

          On March 1, 1999, the Company filed comments in response to the several additional
industry restructuring issues set forth by the D.C. Commission in its December 30, 1998
order. In this March 1, 1999 filing, the Company, among other things, supported the
introduction of retail competition for generation services on a phased-in basis scheduled to
begin on January 1, 2001 and to be completed by January 1, 2003. Legislation introduced in
the Council of the District of Columbia would, if enacted, permit customer choice beginning
January 1, 2002, on a phased-in basis. A working group consisting of members of the D.C.
Council and interested parties held a meeting on October 25, 1999. The timing and outcome
of the Council's deliberations on the legislation is uncertain.

          As discussed in Note (4) of the Notes to Consolidated Financial Statements,
Commitments and Contingencies, herein, on November 8, 1999, the Company filed the
D.C. Agreement with the D.C. Commission. The D.C. Agreement provides that, contingent upon
the enactment of the necessary tax and enabling legislation by the Council of the District
of Columbia by March 31, 2000, the Company will implement a retail competition pilot
program for D.C. residential customers no later than January 1, 2001. At least 10% of
D.C. residential customers will be eligible for the pilot program.

         Contingent upon the enactment of the legislation by March 31, 2000, the Company will
implement retail competition for all D.C. commercial customers on January 1, 2001. If the
legislation is enacted after March 31, 2000, the Company will implement, if consistent with
the legislation, a retail competition pilot program for residential customers and full retail
competition for commercial customers within nine months of the effective date of the
legislation.

Federal - Interchange and Purchased Energy

          The Company participates in wholesale capacity, energy and transmission purchases
and sales transactions, the savings from which are passed along to customers. Presently, all
transmission service in PJM is administered by the PJM Office of the Interconnection. In
addition to interchange with PJM, the Company is actively participating in the bilateral
energy sales marketplace; numerous utilities and marketers have executed service agreements
allowing them to arrange purchases under the Company's wholesale power sales tariff, and
the Company has executed service agreements allowing it to purchase energy under other
market participants' power sales tariffs. The Company's power sales tariff also allows for the
sale of generating capacity on a short-term basis. Revenues from capacity and bilateral
energy transactions totaled approximately $55.6 million, $79.3 million, and $85.3 million for
the three, nine and twelve months ended September 30, 1999, respectively, and
$35.2 million, $54.3 million, and $57.1 million for the corresponding periods in 1998, and
are included as components of interchange deliveries.

          Also see the discussion under Item 5. Other Information - Federal - Interchange and
Purchased Energy of the Company's June 30, 1999 Form 10-Q.

RESTRUCTURING OF THE BULK POWER MARKET

          In addition to the updated information discussed below, refer to the discussion of the
Restructuring of the Bulk Power Market under Item 1. Business of the Company's 1998
Form 10-K.

COMPETITION

          For a discussion of Competition refer to Item 5. Other Information - Competition of
the Company's June 30, 1999 Form 10-Q. Also refer to Item 3. Legal Proceedings and Item
7. Management's Discussion and Analysis of Financial Condition and Results of Operations -
Subsequent Events of the Company's 1998 Form 10-K.

PEAK LOAD, SALES, CONSERVATION, AND CONSTRUCTION AND
    GENERATING CAPACITY

Peak Load and Sales Data

          Kilowatt-hour sales increased 2.8%, 2.7%, and 1.5% for the three, nine and twelve
months ended September 30, 1999, compared to sales in the corresponding periods of 1998.
The increases in sales reflect 1999 summer temperatures that were 7 percent hotter, as
measured in cooling degree hours, than the corresponding period in 1998. Temperatures in
the first quarter, as measured in heating degree days, were 15 percent cooler than the
corresponding period in 1998. Assuming future weather conditions approximate historical
averages, the Company expects its compound annual growth in retail kilowatt-hour sales to
be approximately 2% over the next decade.

          On July  6, 1999, the Company established an all-time summer peak demand of 5,927
megawatts. This compares with the prior all-time summer peak of 5,807 megawatts which
occurred in June 1998. The 1998-1999 winter season peak demand of 4,631 megawatts was
7.6% below the all-time winter peak demand of 5,010 megawatts which was established in
January 1994.

Conservation

          For additional information refer to Item 5. Other Information - Conservation of the
Company's June 30, 1999 Form 10-Q.

          On April 7, 1999, the Maryland Public Service Commission approved the
discontinuation of the Company's High Efficiency Air Conditioner and Heat Pump Rebate
Program. Acceptance of applications for rebate payments under this program was suspended
on July 15, 1999. This action will further reduce the Company's Maryland annual
conservation expenditures. On April 7, 1999, the Maryland Commission approved a
program whereby the Company would reimburse the Maryland Weatherization Assistance
Program for installing conservation measures in the residences of low income customers in
the Company's Maryland service territory. Reimbursements, limited to $500,000 annually,
began in August 1999.

          In September 1998, the Company received permission from the Maryland Commission
to decrease the DSM surcharge; the reduction reflects a decline in the costs and scale of
Maryland DSM programs. The Company invested approximately $2.4 million, $4.9 million
and $7.2 million in Maryland DSM programs for the three, nine and twelve months ended
September 30, 1999, respectively, and $3.1 million, $13 million and $18.9 million for
corresponding periods in 1998. The Company has entered into a settlement agreement,
subject to Maryland Public Service Commission approval, as part of Case No. 8796, Phase II
concerning unbundled rate issues related to the transition to Maryland retail electricity
competition. Under the terms of this settlement agreement, the DSM Surcharge will continue
at its current level until June 30, 2000. The estimated balance of the remaining cost
components of the current DSM Surcharge as of June 30, 2000, together with the Company's
estimate of additional DSM expenditures to be incurred under existing programs during the
Maryland retail competition transition period, will be amortized over a period of three years
(July 2000 through June 2003). As of July 1, 2000, the lost revenues attributable to the
Company's DSM programs that are in excess of the level of such lost revenues currently
reflected in the Company's base rates will be incorporated into the Company's rates for
Delivery Services if, but only if, the Company's calculated rate of return for the twelve
months ended March 31, 2000, is no greater than the allowed rate of return.

          On June 1, 1999, the Company submitted an application to the District of Columbia
Public Service Commission to revise the conservation component of the Environmental Cost
Recovery Rider (ECRR) and requested that the Company's October 1998 application be
withdrawn. In the June 1, 1999 application, the Company proposed maintaining the
conservation component of the ECRR at its existing level until such time that all unrecovered
DSM expenditures are fully recovered. Freezing the current rates will permit the Company
to recover its DSM expenditures somewhat more quickly than if the rates were adjusted
annually. If the Commission approves the Company's June 1999 proposal, all residential
DSM expenditures are expected to be fully recovered by 2005 and all nonresidential
expenditures by 2008. A proposal by the Company to eliminate DSM programs operated
within the District of Columbia was filed with the Commission in March 1998, and a
decision is pending.

          Investment in District of Columbia DSM programs totaled approximately $1 million,
$1.8 million, and $2.5 million for the three, nine and twelve months ended September 30,
1999, respectively, and $3.2 million, $4.5 million, and $5.9 million for the corresponding
periods in 1998.

Construction and Generating Capacity

          In 1999, construction expenditures are projected to total $185 million ($79 million
related to Generation) which includes $22 million of estimated Clean Air Act (CAA)
expenditures. The Company plans to finance its construction program primarily through
funds provided by operations. The Company incurred construction expenditures, excluding
AFUDC and CCRF, of $135 million for the nine months ended September 30, 1999
($52 million related to Generation). These expenditures are projected to total $865 million
($389 million related to Generation) for the five-year period 1999 through 2003, which
includes approximately $132 million of estimated CAA expenditures.

          The Company's present generating resource mix consists of 4,815 megawatts of steam
generating capacity and 1,227 megawatts from 31 combustion turbine units owned by the
Company, including 166 megawatts of capacity from the Company's 9.72% undivided
interest in the Conemaugh Generating Station located in western Pennsylvania.

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

          The Company continues to purchase 450 megawatts of capacity and associated energy
from FirstEnergy under a 1987 long-term capacity purchase agreement with FirstEnergy and
Allegheny Energy, Inc. (AEI). The Company also has a 25-year capacity purchase
agreement with Panda for 230 megawatts of capacity from a gas-fueled combined-cycle
cogenerator in Prince George's County, Maryland. In addition, the Company continues to
purchase capacity and associated energy from a 50-megawatt municipally financed resource
recovery facility in Montgomery County, Maryland. The capacity expense under these
agreements, including an allocation of a portion of FirstEnergy's fixed operating and
maintenance costs, was $49.7 million, $156 million, and $193.9 million for the three, nine
and twelve months ended September 30, 1999, respectively, compared to $36.2 million,
$112 million, and $153.3 million for the corresponding periods in 1998.

          The Company projects that existing contracts for nonutility generation and the
emerging wholesale market for generation resources will provide adequate reserve margins
to meet customers' needs beyond the year 2000.

SELECTED NONUTILITY SUBSIDIARY FINANCIAL INFORMATION

          In May 1999, the Company reorganized its nonregulated subsidiaries into two
operating groups. As part of the reorganization, a new unregulated company, PHI, was
created as the parent of PCI and PES.

          The principal assets of PHI are a portfolio of marketable securities and equipment
leases, and to a lesser extent real estate and other investments. The $230.4 million
marketable securities portfolio, which consists primarily of fixed rate utility preferred stocks,
provides PCI with significant liquidity and flexibility to participate in additional investment
opportunities. Nonutility subsidiary equity totaled $260.4 million at September 30, 1999;
$243.4 million at December 31, 1998; and $244.6 million at September 30, 1998, which
includes $88.8 million, $65 million, and $66.1 million of retained earnings, respectively.

Pepco Holdings, Inc. and Subsidiaries
Consolidated Statements of Earnings:


	Three		Nine		Twelve
	Months Ended		Months Ended		Months Ended
	September 30,		September 30,		September 30,
	1999	1998	1999	1998	1999	1998
	(Millions of Dollars except Per Share Amounts)

Income
Financial Investments	$ 24.0	$ 28.4	$ 78.2	$ 91.5	$ 99.1	$109.4
Energy Services	35.2		85.4	9.4	104.0	12.2
Utility Industry Services	4.0	4.7	13.7	10.6	17.7	13.7
Telecommunications Services	(2.7)	(6.0)	(8.7)	(8.3)	(11.9)	(8.3)

	60.5	29.9	168.6	103.2	208.9	127.0

Expenses
Operating	35.5	5.8	91.2	16.4	113.2	21.6
Interest	13.6	13.7	38.2	43.0	51.4	58.9
Administrative and General	8.7	3.5	24.6	11.7	31.2	12.9
Depreciation	5.8	5.6	17.0	18.3	22.9	26.0
Income Tax Benefit	(3.4)	(2.5)	(26.2)	(2.4)	(32.5)	(9.9)

	60.2	26.1	144.8	87.0	186.2	109.5

Net Earnings from
Nonutility Subsidiary	$ 0.3	$ 3.8	$ 23.8	$ 16.2	$ 22.7	$ 17.5


Per Share Contribution (Reduction) to
Earnings of the Company
PCI	$ .02	$ .03	$ .24	$ .14	$ .23	$ .16
PES	(.02)	-	(.04)	-	(.04)	(.01)
PHI Consolidated	$ -	$ .03	$ .20	$ .14	$ .19	$ .15

STATISTICAL DATA

	Three Months Ended			Twelve Months Ended
	September 30,			September 30,
	1999	1998	% Change	1999	1998	% Change

Revenue from Sales of Electricity
(Millions of Dollars)

Residential	$220.4	$208.1	5.9	$ 589.9	$ 564.9	4.4
General Service	388.0	394.3	(1.6)	1,110.7	1,115.7	(0.4)
Large Power Service *	12.8	11.7	9.4	36.0	35.3	2.0
Street Lighting	3.2	3.1	3.2	13.4	13.3	0.8
Rapid Transit	8.9	8.6	3.5	30.3	29.7	2.0
Wholesale	38.5	39.4	(2.3)	126.8	126.1	0.6
System	$671.8	$665.2	1.0	$1,907.1	$1,885.0	1.2

Energy Sales
(Millions of KWH)

Residential	2,166	2,020	7.2	7,023	6,792	3.4
General Service	4,641	4,618	0.5	15,774	15,673	0.6
Large Power Service *	204	182	12.1	698	685	1.9
Street Lighting	37	36	2.8	166	164	1.2
Rapid Transit	125	117	6.8	433	422	2.6
Wholesale	771	757	1.8	2,742	2,697	1.7
System	7,944	7,730	2.8	26,836	26,433	1.5

Average System Revenue per KWH
(cents per KWH)	8.46	8.61	(1.7)	7.11	7.13	(0.3)

System Peak Demand **
(Thousands of KW)

Summer	-	-		5,927	5,807
Winter	-	-		4,631	4,076

Net Generation
(Millions of KWH)	7,448	6,792		22,928	21,012

Fuel Mix (% of Btu)
Coal (%)	75	74		81	84
Oil (%)	16	21		14	13
Gas (%)	9	5		5	3

Fuel Cost per MBtu
System Average	$1.76	$1.72		$1.70	$1.77

Weather Data
Heating Degree Days	22	4		3,655	3,671
20 Year Average	22			3,978
Cooling Degree Hours	8,656	7,573		10,818	10,442
20 Year Average	7,080			9,497

Heating Degree Days - The daily difference in degrees by which the mean temperature is below
  65 degrees Fahrenheit (dry bulb).

Cooling Degree Hours - The daily sum of the differences, by hours, by which the temperature
  (effective temperature) for each hour exceeds 71 degrees Fahrenheit (effective temperature).

*  Large Power Service customers are served at high voltage of 66KV or higher.
** At September 30, 1999, the net generation capability, excluding short-term capacity transactions, was 6,806 MW.

Item 6. EXHIBITS AND REPORTS ON FORM 8-K

(a)	Exhibits
	Exhibit 10.1	-	Severance Agreement - filed herewith.
	Exhibit 10.2	-	Retention Agreement - filed herewith.
	Exhibit 10.3	-	Retention Agreement - filed herewith.
	Exhibit 12	-	Computation of ratios - filed herewith.
	Exhibit 15	-	Letter re unaudited interim financial information - filed herewith.
	Exhibit 27	-	Financial data schedule - filed herewith.
(b)	Reports on Form 8-K
	None.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has
duly caused this report to be signed on its behalf by the undersigned thereunto duly
authorized.

Potomac Electric Power Company
                     Registrant

By  ________________________
                   D. R. Wraase
       Executive Vice President and
            Chief Financial Officer

November 12, 1999
        Date

Exhibit 12   Statements Re. Computation of Ratios

    The computations of the coverage of fixed charges before income taxes, and the coverage of combined
fixed charges and preferred dividends for the twelve months ended September 30, 1999, and for each of the
preceding five years, on the basis of parent company operations only, are as follows:

	Twelve
	Months
	Ended	For the Year Ended December 31,
	September 30,
	1999	1998	1997	1996	1995	1994
	(Millions of Dollars)

Net income	$232.3	$211.2	$164.7	$220.1	$218.8	$208.1
Taxes based on income	144.9	131.0	97.5	135.0	129.4	116.6

Income before taxes	377.2	342.2	262.2	355.1	348.2	324.7

Fixed charges:
Interest charges	154.1	151.8	146.7	146.9	146.6	139.2
Interest factor in rentals	23.4	23.8	23.6	23.6	23.4	6.3

Total fixed charges	177.5	175.6	170.3	170.5	170.0	145.5

Income before income taxes and fixed charges	$554.7	$517.8	$432.5	$525.6	$518.2	$470.2

Coverage of fixed charges	3.12	2.95	2.54	3.08	3.05	3.23


Preferred dividend requirements	$7.9	$18.0	$16.5	$16.6	$16.9	$16.5


Ratio of pre-tax income to net income	1.62	1.62	1.59	1.61	1.59	1.56

Preferred dividend factor	$12.9	$29.2	$26.2	$26.7	$26.9	$25.7

Total fixed charges and preferred dividends	$190.4	$204.8	$196.5	$197.2	$196.9	$171.2

Coverage of combined fixed charges
and preferred dividends	2.91	2.53	2.20	2.66	2.63	2.75

Exhibit 12 Statements Re. Computation of Ratios

The computations of the coverage of fixed charges before income taxes, and the coverage of combined
fixed charges and preferred dividends for the twelve months ended September 30, 1999, and for each
of the preceding five years, on a consolidated basis, are as follows.

	Twelve
	Months
	Ended	For the Year Ended December 31,
	September 30,
	1999	1998	1997	1996	1995	1994
	(Millions of Dollars)

Net income	$255.0	$226.3	$181.8	$237.0	$94.4	$227.2
Taxes based on income	112.4	122.3	65.6	80.4	43.7	94.0

Income before taxes	367.4	348.6	247.4	317.4	138.1	321.2

Fixed charges:
Interest charges	206.8	208.6	216.1	231.1	238.7	224.5
Interest factor in rentals	23.6	24.0	23.7	23.9	26.7	9.9

Total fixed charges	230.4	232.6	239.8	255.0	265.4	234.4

Nonutility subsidiary capitalized interest	(1.3)	(0.6)	(0.5)	(0.7)	(0.5)	(0.5)

Income before income taxes and fixed charges	$596.5	$580.6	$486.7	$571.7	$403.0	$555.1

Coverage of fixed charges	2.59	2.50	2.03	2.24	1.52	2.37


Preferred dividend requirements	$7.9	$18.0	$16.5	$16.6	$16.9	$16.5


Ratio of pre-tax income to net income	1.44	1.54	1.36	1.34	1.46	1.41

Preferred dividend factor	$11.5	$27.7	$22.4	$22.2	$24.7	$23.3

Total fixed charges and preferred dividends	$241.9	$260.3	$262.2	$277.2	$290.1	$257.7

Coverage of combined fixed charges
and preferred dividends	2.47	2.23	1.86	2.06	1.39	2.15

Exhibit 15

November 12, 1999

Securities and Exchange Commission
450 Fifth Street, N.W.
Washington, D.C. 20549

Ladies and Gentlemen:

We are aware that Potomac Electric Power Company has incorporated by reference our
report dated November 12, 1999, (issued pursuant to the provisions of Statement on Auditing
Standards No. 71) in the Prospectuses constituting parts of the Registration Statements on
Forms S-8 (Numbers 33-36798, 33-53685, 33-54197, 333-56683 and 333-57221) filed on
September 12, 1990, May 18, 1994, June 17, 1994, June 12, 1998 and June 19, 1998,
respectively, and on Forms S-3 (Numbers 33-58810, 33-61379 and 333-33495) filed on
February 26, 1993, July 28, 1995 and August 13, 1997, respectively. We are also aware of
our responsibilities under the Securities Act of 1933.

Very truly yours,

PricewaterhouseCoopers LLP
Washington, D.C.