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, 1998 
                               ------------------


Commission file number               1-1072
                                     ------


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



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



     1900 Pennsylvania Avenue, N.W., Washington, D.C.   20068
----------------------------------------------------------------  
     (Address of principal executive office)         (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, 1998 
--------------------------     ---------------------------------  
Common Stock, $1 par value                118,527,287
                        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
      (1) Comprehensive Income...............................  5
      (2) Income Taxes.......................................  6
      (3) Capitalization and Fair Value of Financial
            Instruments......................................  9
      (4) Commitments and Contingencies...................... 15
    Report of Independent Accountants on Review of Interim
      Financial Information.................................. 17
  
  Item 2 - Management's Discussion and Analysis of Consolidated
             Results of Operations and Financial Condition
    Forward Looking Statements............................... 18
    Utility
      Results of Operations.................................. 19 
        Year 2000 Compliance................................. 22
      Capital Resources and Liquidity........................ 27 
    Nonutility Subsidiary
      Results of Operations.................................. 29 
        Year 2000 Compliance................................. 30
      Capital Resources and Liquidity........................ 31 

PART II - Other Information
  Item 1 - Legal Proceedings................................. 33
  Item 5 - Other Information
    Other Financing Arrangements............................. 33 
    Base Rate Proceedings.................................... 33 
    Restructuring of the Bulk Power Market................... 36
    Competition.............................................. 36
    Peak Load, Sales, Conservation, and Construction and
      Generating Capacity.................................... 38
    Selected Nonutility Subsidiary Financial Information..... 41
    Statistical Data......................................... 43
  Item 6 - Exhibits and Reports on Form 8-K.................. 44
  Signatures................................................. 45
  Computations of Earnings Per Common Share.................. 46
  Computation of Ratios - Parent Company Only................ 47
  Computation of Ratios - Fully Consolidated................. 48
  Independent Accountants Awareness Letter................... 49



                              1


<TABLE>
Part I  FINANCIAL INFORMATION
------  ---------------------
Item 1  CONSOLIDATED FINANCIAL STATEMENTS
------  ---------------------------------

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

<CAPTION>

                                                      Three Months Ended        Nine Months Ended          Twelve Months Ended
                                                         September 30,            September 30,               September 30,
                                                     --------------------     ----------------------     ----------------------
                                                        1998       1997           1998        1997           1998        1997
                                                     ---------  ---------     ----------  ----------     ----------  ----------
                                                                        (In thousands, except per share data)
<S>                                                  <C>        <C>           <C>         <C>            <C>         <C>
Revenue
  Sales of electricity                               $ 665,241  $ 615,621     $1,508,426  $1,423,198     $1,885,028  $1,792,121
  Other electric revenue                                 4,956      2,597         10,982       9,061         12,950      12,661
                                                     ---------  ---------     ----------  ----------     ----------  ----------
    Total Operating Revenue                            670,197    618,218      1,519,408   1,432,259      1,897,978   1,804,782
  Interchange deliveries                                80,579     14,824        140,276      40,814        152,143      82,004
                                                     ---------  ---------     ----------  ----------     ----------  ----------
    Total Revenue                                      750,776    633,042      1,659,684   1,473,073      2,050,121   1,886,786
                                                     ---------  ---------     ----------  ----------     ----------  ----------
Operating Expenses
  Fuel                                                 127,466     92,953        302,208     249,655        372,171     316,739
  Purchased energy                                      99,027     58,864        213,011     154,314        259,261     238,327
  Capacity purchase payments                            37,639     35,440        116,216     108,165        158,962     138,359
  Other operation                                       61,349     55,187        174,754     160,319        234,725     216,608
  Maintenance                                           22,971     22,717         67,250      67,797         94,705      93,351
                                                     ---------  ---------     ----------  ----------     ----------  ----------
    Total Operation and Maintenance                    348,452    265,161        873,439     740,250      1,119,824   1,003,384
  Depreciation and amortization                         62,314     59,581        179,990     173,982        238,050     229,949
  Income taxes                                          91,851     82,222        129,150     115,280        131,600     121,798
  Other taxes                                           62,159     59,578        159,492     154,219        206,993     199,506
                                                     ---------  ---------     ----------  ----------     ----------  ----------
    Total Operating Expenses                           564,776    466,542      1,342,071   1,183,731      1,696,467   1,554,637
                                                     ---------  ---------     ----------  ----------     ----------  ----------
Operating Income                                       186,000    166,500        317,613     289,342        353,654     332,149
                                                     ---------  ---------     ----------  ----------     ----------  ----------
Other Income (Loss)
  Nonutility Subsidiary
    Income                                              29,889     32,898        103,212     101,370        126,982     130,834
    Expenses, including interest
      and income taxes                                 (26,112)   (32,023)       (86,973)    (85,589)      (109,443)   (114,560)
                                                     ---------  ---------     ----------  ----------     ----------  ----------
      Net earnings from nonutility
        subsidiary                                       3,777        875         16,239      15,781         17,539      16,274
  Allowance for other funds used during
    construction and capital cost recovery factor          375      1,608            855       4,949          2,614       6,557
  Write-off of merger costs                                  -          -              -           -        (52,533)          -
  Other, net                                               748      1,429          2,785       3,753         23,053       3,986
                                                     ---------  ---------     ----------  ----------     ----------  ----------
    Total Other Income (Loss)                            4,900      3,912         19,879      24,483         (9,327)     26,817
                                                     ---------  ---------     ----------  ----------     ----------  ----------
Income Before Utility Interest Charges                 190,900    170,412        337,492     313,825        344,327     358,966
                                                     ---------  ---------     ----------  ----------     ----------  ----------
Utility Interest Charges
  Long-term debt                                        34,191     32,188        102,797     101,036        137,328     134,375
  Distributions on preferred securities
    of subsidiary company                                2,304          -          3,380           -          3,380           -
  Other                                                  2,178      4,053          7,908       9,557          9,486      11,894
  Allowance for borrowed funds used during
    construction and capital cost recovery factor         (873)    (1,814)        (3,194)     (5,859)        (5,207)     (7,680)
                                                     ---------  ---------     ----------  ----------     ----------  ----------
      Net Utility Interest Charges                      37,800     34,427        110,891     104,734        144,987     138,589
                                                     ---------  ---------     ----------  ----------     ----------  ----------
Net Income                                             153,100    135,985        226,601     209,091        199,340     220,377
Dividends on preferred stock                             1,955      4,157          9,490      12,439         13,630      16,595
Redemption premium on preferred stock                       53          -          6,632           -          6,632           -
                                                     ---------  ---------     ----------  ----------     ----------  ----------
Earnings for Common Stock                              151,092    131,828        210,479     196,652        179,078     203,782

Retained Income at Beginning of Period                 696,571    728,241        734,318     760,285        815,448     796,946
Dividends on Common Stock                              (49,162)   (49,155)      (147,484)   (147,459)      (196,639)   (196,613)
Subsidiary Marketable Securities Net
  Unrealized Gain, Net of Tax                              212      4,534          1,400       5,970            826      11,333
                                                     ---------  ---------     ----------  ----------     ----------  ----------
Retained Income at End of Period                     $ 798,713  $ 815,448     $  798,713  $  815,448     $  798,713  $  815,448
                                                     =========  =========     ==========  ==========     ==========  ==========
Basic Average Common Shares
  Outstanding (000's)                                  118,527    118,501        118,522     118,500        118,517     118,500
Basic Earnings Per Common Share                          $1.27      $1.11          $1.78       $1.66          $1.51       $1.72
Diluted Average Common Shares
  Outstanding (000's)                                  124,245    124,292        124,244     124,292        124,256     124,305
Diluted Earnings Per Common Share                        $1.23      $1.07          $1.73       $1.62          $1.49       $1.69
Cash Dividends Per Common Share                         $0.415     $0.415         $1.245      $1.245          $1.66       $1.66
Book Value Per Share                                                                                         $16.27      $16.41
Dividend Payout Ratio                                                                                         109.9%       96.5%
Effective Federal Income Tax Rate                                                                              30.5%       25.8%


                                                               2
</TABLE>

<TABLE>
                                         POTOMAC ELECTRIC POWER COMPANY
                                           Consolidated Balance Sheets
                                   (Unaudited at September 30, 1998 and 1997)
                                   ------------------------------------------

<CAPTION>

                                                                September 30,     December 31,     September 30,
                  ASSETS                                            1998              1997             1997
                  ------                                        -------------    -------------     -------------
                                                                             (Thousands of Dollars)
<S>                                                             <C>              <C>               <C>
Property and Plant - at original cost
  Electric plant in service                                     $   6,492,267    $   6,392,750     $   6,335,130
  Construction work in progress                                        72,614           94,309            84,901
  Electric plant held for future use                                    4,295            4,231             4,210
  Nonoperating property                                                40,685           22,824            22,750
                                                                -------------    -------------     -------------
                                                                    6,609,861        6,514,114         6,446,991
  Accumulated depreciation                                         (2,104,680)      (2,027,780)       (2,000,376)
                                                                -------------    -------------     -------------
      Net Property and Plant                                        4,505,181        4,486,334         4,446,615
                                                                -------------    -------------     -------------
Current Assets
  Cash and cash equivalents                                            12,788            5,630             2,916
  Customer accounts receivable, less allowance
    for uncollectible accounts of $2,286, $2,102
    and $558                                                          185,397          116,554           186,623
  Other accounts receivable, less allowance for
    uncollectible accounts of $300                                     39,864           32,256            25,117
  Accrued unbilled revenue                                            117,438           69,259            88,071
  Prepaid taxes                                                        33,574           33,740            41,554
  Other prepaid expenses                                                2,366            7,599             3,917
  Material and supplies - at average cost
    Fuel                                                               44,749           59,434            60,432
    Construction and maintenance                                       69,984           68,128            69,195
                                                                -------------    -------------     -------------
      Total Current Assets                                            506,160          392,600           477,825
                                                                -------------    -------------     -------------
Deferred Charges
  Income taxes recoverable through future rates, net                  234,779          238,125           238,711
  Conservation costs, net                                             205,436          221,528           224,464
  Unamortized debt reacquisition costs                                 50,640           52,745            53,447
  Other                                                               155,125          148,900           196,614
                                                                -------------    -------------     -------------
      Total Deferred Charges                                          645,980          661,298           713,236
                                                                -------------    -------------     -------------
Nonutility Subsidiary Assets
  Cash and cash equivalents                                            16,019              422            10,087
  Marketable securities                                               240,680          302,522           303,905
  Investment in finance leases                                        442,224          463,592           460,021
  Operating lease equipment, net of accumulated
    depreciation of $114,392, $153,541 and $146,083                   128,344          163,289           170,747
  Receivables, less allowance for uncollectible
    accounts of $5,000, $6,000 and $6,000                              42,849           64,243            34,997
  Other investments                                                   122,320          162,865           182,581
  Other assets                                                         18,634           10,392            14,146
  Deferred income taxes                                                74,052                -                 -
                                                                -------------    -------------     -------------
      Total Nonutility Subsidiary Assets                            1,085,122        1,167,325         1,176,484
                                                                -------------    -------------     -------------
      Total Assets                                              $   6,742,443    $   6,707,557     $   6,814,160
                                                                =============    =============     =============

CAPITALIZATION AND LIABILITIES
------------------------------
Capitalization
  Common stock                                                  $     118,527    $     118,501     $     118,501
  Other common equity                                               1,810,317        1,744,527         1,825,700
  Serial preferred stock                                              100,000          125,290           125,291
  Redeemable serial preferred stock                                    50,000          141,000           141,000
  Company obligated mandatorily redeemable preferred
    securities of subsidiary trust which holds solely
    parent junior subordinated debentures                             125,000                -                 -
  Long-term debt                                                    1,858,590        1,901,486         1,727,707
                                                                -------------    -------------     -------------
      Total Capitalization                                          4,062,434        4,030,804         3,938,199
                                                                -------------    -------------     -------------
Other Non-Current Liabilities
Capital lease obligations                                             158,336          160,406           161,057
                                                                -------------    -------------     -------------
Current Liabilities
  Long-term debt and preferred stock
    redemption                                                         45,000           52,054            50,985
  Short-term debt                                                     119,125          131,375           277,075
  Accounts payable and accrued expenses                               293,659          185,893           247,359
  Capital lease obligations due within one year                        20,772           20,772            20,772
  Other                                                                91,073           92,293            83,774
                                                                -------------    -------------     -------------
      Total Current Liabilities                                       569,629          482,387           679,965
                                                                -------------    -------------     -------------
Deferred Credits
  Income taxes                                                      1,051,660        1,029,318         1,014,472
  Investment tax credits                                               54,571           57,308            58,221
  Other                                                                23,252           19,034            30,842
                                                                -------------    -------------     -------------
      Total Deferred Credits                                        1,129,483        1,105,660         1,103,535
                                                                -------------    -------------     -------------
Nonutility Subsidiary Liabilities
  Long-term debt                                                      558,142          830,458           863,167
  Short-term notes payable                                            182,975            7,685             9,200
  Deferred taxes and other                                             81,444           90,157            59,037
                                                                -------------    -------------     -------------
      Total Nonutility Subsidiary Liabilities                         822,561          928,300           931,404
                                                                -------------    -------------     -------------
      Total Capitalization and Liabilities                      $   6,742,443    $   6,707,557     $   6,814,160
                                                                =============    =============     =============

                                                       3
</TABLE>

<TABLE>
                                            POTOMAC ELECTRIC POWER COMPANY
                                        Consolidated Statements of Cash Flows
                                                     (Unaudited)
                                        -------------------------------------

<CAPTION>

                                                                        Nine Months Ended        Twelve Months Ended
                                                                          September 30,             September 30,
                                                                     -----------------------   -----------------------
                                                                       1998          1997        1998          1997
                                                                     ---------     ---------   ---------     ---------
                                                                                   (Thousands of Dollars)
<S>                                                                  <C>           <C>         <C>           <C>
Operating Activities
  Income from utility operations                                     $ 210,362     $ 193,310   $ 181,801     $ 204,103
  Adjustments to reconcile income to net
    cash from operating activities:
    Depreciation and amortization                                      179,990       173,982     238,050       229,949
    Deferred income taxes and investment tax credits                    18,975        41,110      38,408        98,539
    Deferred conservation costs                                        (20,771)      (26,243)    (29,071)      (36,296)
    Allowance for funds used during construction
      and capital cost recovery factor                                  (4,049)      (10,808)     (7,821)      (14,237)
    Changes in materials and supplies                                   12,829         8,146      14,894         7,956
    Changes in accounts receivable and accrued unbilled revenue       (124,630)      (62,507)    (42,888)       33,281
    Changes in accounts payable                                         (6,362)      (17,061)     17,087        (7,476)
    Changes in other current assets and liabilities                    122,374        75,275      44,640        32,416
    Changes in deferred merger costs                                         -       (18,758)     47,767       (37,278)
    Net other operating activities                                      (7,636)      (38,916)    (23,556)      (48,983)
  Nonutility subsidiary:
    Net earnings                                                        16,239        15,781      17,539        16,274
    Deferred income taxes                                              (75,023)      (46,624)    (92,158)      (56,023)
    Changes in other assets and net other operating activities          23,197        31,243      57,692        50,465
                                                                     ---------     ---------   ---------     ---------
Net Cash From Operating Activities                                     345,495       317,930     462,384       472,690
                                                                     ---------     ---------   ---------     ---------

Investing Activities
  Total investment in property and plant                              (150,019)     (150,987)   (230,775)     (205,492)
  Allowance for funds used during construction
    and capital cost recovery factor                                     4,049        10,808       7,821        14,237
                                                                     ---------     ---------   ---------     ---------
    Net investment in property and plant                              (145,970)     (140,179)   (222,954)     (191,255)
  Nonutility subsidiary:
    Purchase of marketable securities                                   (1,000)      (35,103)     (1,000)      (35,103)
    Proceeds from sale or redemption of marketable securities           66,897       124,517      67,380       151,639
    Investment in leased equipment                                           -        (7,480)          -        (7,480)
    Proceeds from sale or disposition of leased equipment               61,289        28,484      61,289        28,484
    Proceeds from sale of assets                                             -         7,300           -         7,015
    Purchase of other investments                                      (17,542)      (20,451)    (17,694)      (38,949)
    Proceeds from sale or distribution of other investments             32,669         6,107      45,292        25,781
    Proceeds from promissory notes, net                                      -        63,795         313        82,556
                                                                     ---------     ---------   ---------     ---------
Net Cash (Used by) From Investing Activities                            (3,657)       26,990     (67,374)       22,688
                                                                     ---------     ---------   ---------     ---------

Financing Activities
  Dividends on common stock                                           (147,484)     (147,459)   (196,639)     (196,613)
  Dividends on preferred stock                                          (9,490)      (12,439)    (13,630)      (16,595)
  Redemption of preferred stock                                       (123,680)       (1,500)   (123,680)       (1,500)
  Issuance of mandatorily redeemable preferred securities              125,000             -     125,000             -
  Issuance of long-term debt                                                 -         8,090     174,177       107,590
  Reacquisition and retirement of long-term debt                       (51,069)     (151,460)    (51,071)     (151,460)
  Short-term debt, net                                                 (12,250)      145,685    (157,950)       22,620
  Other financing activities                                            (3,085)         (297)     (4,164)         (398)
  Nonutility subsidiary:
    Issuance of long-term debt                                          52,103        40,000      52,103        95,000
    Repayment of long-term debt                                       (324,418)     (173,065)   (357,127)     (176,799)
    Short-term debt, net                                               175,290       (42,450)    173,775      (172,108)
                                                                     ---------     ---------   ---------     ---------
Net Cash Used By Financing Activities                                 (319,083)     (334,895)   (379,206)     (490,263)
                                                                     ---------     ---------   ---------     ---------
Net Increase in Cash and Cash Equivalents                               22,755        10,025      15,804         5,115
Cash and Cash Equivalents at Beginning of Period                         6,052         2,978      13,003         7,888
                                                                     ---------     ---------   ---------     ---------
Cash and Cash Equivalents at End of Period                           $  28,807     $  13,003   $  28,807     $  13,003
                                                                     =========     =========   =========     =========

Cash paid for interest (net of capitalized interest of
  $486, $350, $628 and $505) and income taxes:
    Interest (including nonutility subsidiary
      interest of $54,881, $67,104, $59,269 and $72,829)             $ 165,670     $ 176,836   $ 191,589     $ 205,031
    Income taxes (including nonutility subsidiary)                   $  27,180     $  12,475   $  33,565     $  37,631



                                                          4

</TABLE>

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------

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 to 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 1997
Annual Report to the Securities and Exchange Commission on Form
10-K.

     Certain 1997 amounts have been reclassified to conform to
the current year presentation.

(1)  COMPREHENSIVE INCOME 
     --------------------

     The Company's components of comprehensive income are net
income, and unrealized gains and losses on marketable securities. 
Comprehensive income totaled $153.3 million, $228 million and
$200.2 million for the three, nine and twelve months ended
September 30, 1998, compared to $140.5 million, $215.1 million
and $231.7 million in the corresponding periods ended September
30, 1997.


                              5

<TABLE>
(2) INCOME TAXES
----------------
Provision for Income Taxes
--------------------------


<CAPTION>

                                                   Three Months Ended           Nine Months Ended        Twelve Months Ended
                                                      September 30,               September 30,             September 30,
                                                 -----------------------    -----------------------    -----------------------
                                                    1998         1997          1998         1997          1998         1997
                                                 ----------   ----------    ----------    ---------    ----------    ---------
                                                                                  (Thousands of Dollars)
<S>                                              <C>          <C>           <C>          <C>           <C>          <C>
Utility current tax expense
  Federal                                        $   70,303   $   58,762    $   98,011   $   65,445    $   64,819   $   19,962
  State and local                                    10,006        7,756        12,535        8,708         8,518        2,594
                                                 ----------   ----------    ----------   ----------    ----------   ----------
Total utility current tax expense                    80,309       66,518       110,546       74,153        73,337       22,556
                                                 ----------   ----------    ----------   ----------    ----------   ----------
Utility deferred tax expense
  Federal                                            11,519       14,572        18,129       38,097        36,310       89,609
  State and local                                       980        2,100         3,583        5,750         5,748       12,579
  Investment tax credits                               (912)        (912)       (2,737)      (2,737)       (3,650)      (3,649)
                                                 ----------   ----------    ----------   ----------    ----------   ----------
Total utility deferred tax expense                   11,587       15,760        18,975       41,110        38,408       98,539
                                                 ----------   ----------    ----------   ----------    ----------   ----------

Total utility income tax expense                     91,896       82,278       129,521      115,263       111,745      121,095
                                                 ----------   ----------    ----------   ----------    ----------   ----------

Nonutility subsidiary current tax expense
  Federal                                             5,862       17,642        33,971       20,793        43,599       25,363
                                                 ----------   ----------    ----------   ----------    ----------   ----------

Nonutility subsidiary deferred tax credit
  Federal                                            (8,357)     (21,016)      (36,362)     (45,084)      (53,549)     (54,482)
                                                 ----------   ----------    ----------   ----------    ----------   ----------

Total nonutility subsidiary income tax credit        (2,495)      (3,374)       (2,391)     (24,291)       (9,950)     (29,119)
                                                 ----------   ----------    ----------   ----------    ----------   ----------

Total consolidated income tax expense                89,401       78,904       127,130       90,972       101,795       91,976
Income taxes included in other income                (2,450)      (3,318)       (2,020)     (24,308)      (29,805)     (29,822)
                                                 ----------   ----------    ----------   ----------    ----------   ----------
Income taxes included in utility operating
  expenses                                       $   91,851   $   82,222    $  129,150   $  115,280    $  131,600   $  121,798
                                                 ==========   ==========    ==========   ==========    ==========   ==========




                                                                                   6
</TABLE>




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


<CAPTION>

                                                   Three Months Ended          Nine Months Ended         Twelve Months Ended
                                                     September 30,               September 30,              September 30,
                                                 -----------------------    -----------------------    -----------------------
                                                    1998         1997          1998         1997          1998         1997
                                                 ----------   ----------    ----------   ----------    ----------   ----------
                                                                                  (Thousands of Dollars)
<S>                                              <C>          <C>           <C>          <C>           <C>          <C>
Income before income taxes                       $  242,501   $  214,889    $  353,731   $  300,063    $  301,135   $  312,353
                                                 ==========   ==========    ==========   ==========    ==========   ==========

Utility income tax at federal
  statutory rate                                 $   84,427   $   76,086    $  118,959   $  108,001    $  102,741   $  113,819
    Increases (decreases) resulting from
      Depreciation                                    2,765        2,522         8,294        7,566        11,581        9,806
      Removal costs                                  (1,296)        (841)       (4,585)      (4,027)       (6,460)      (5,123)
      Allowance for funds used during
        construction                                    240          238           674          603           930          806
      Other                                            (469)      (1,222)       (1,561)      (3,541)       (2,452)      (4,195)
      State income taxes, net of federal effect       7,141        6,407        10,477        9,398         9,273        9,863
      Tax credits                                      (912)        (912)       (2,737)      (2,737)       (3,868)      (3,881)
                                                 ----------   ----------    ----------   ----------    ----------   ----------
Total utility income tax expense                     91,896       82,278       129,521      115,263       111,745      121,095
                                                 ----------   ----------    ----------   ----------    ----------   ----------

Nonutility subsidiary income tax at federal
  statutory rate                                        448         (874)        4,847       (2,978)        2,656       (4,495)
    Decreases resulting from
      Dividends received deduction                   (1,027)      (1,269)       (3,385)      (3,987)       (4,817)      (6,523)
      Reversal of previously accrued deferred
        taxes                                             -            -             -      (10,125)            -      (10,125)
      Other                                          (1,916)      (1,231)       (3,853)      (7,201)       (7,789)      (7,976)
                                                 ----------   ----------    ----------   ----------    ----------   ----------
Total nonutility subsidiary income tax credit        (2,495)      (3,374)       (2,391)     (24,291)       (9,950)     (29,119)
                                                 ----------   ----------    ----------   ----------    ----------   ----------

Total consolidated income tax expense                89,401       78,904       127,130       90,972       101,795       91,976
Income taxes included in other income                (2,450)      (3,318)       (2,020)     (24,308)      (29,805)     (29,822)
                                                 ----------   ----------    ----------   ----------    ----------   ----------
Income taxes included in utility operating
  expenses                                       $   91,851   $   82,222    $  129,150   $  115,280    $  131,600   $  121,798
                                                 ==========   ==========    ==========   ==========    ==========   ==========



                                                                                   7

</TABLE>




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


<CAPTION>


                                                        Sept. 30,    Dec. 31,      Sept. 30,
                                                          1998         1997          1997
                                                       ----------   ----------    ----------
                                                               (Thousands of Dollars)
<S>                                                    <C>          <C>           <C>
Utility deferred tax liabilities (assets)
  Depreciation and other book to tax
    basis differences                                  $  893,906   $  869,343    $  855,970
  Rapid amortization of certified pollution
    control facilities                                     24,615       25,445        23,646
  Deferred taxes on amounts to be collected
    through future rates                                   88,887       90,154        90,376
  Property taxes                                           13,671       13,525        13,310
  Deferred fuel                                           (11,278)      (7,369)      (12,099)
  Prepayment premium on debt retirement                    19,165       19,962        20,228
  Deferred investment tax credit                          (20,661)     (21,697)      (22,042)
  Contributions in aid of construction                    (30,971)     (30,054)      (29,530)
  Contributions to pension plan                            18,157       18,157        16,170
  Conservation costs (demand side management)              48,947       48,041        48,093
  Other                                                    20,692       21,683        22,882
                                                       ----------   ----------    ----------
Total utility deferred tax liabilities, net             1,065,130    1,047,190     1,027,004
Current portion of utility deferred tax
  liabilities (included in Other Current
  Liabilities)                                             13,470       17,872        12,532
                                                       ----------   ----------    ----------
Total utility deferred tax liabilities, net -
  non-current                                          $1,051,660   $1,029,318    $1,014,472
                                                       ==========   ==========    ==========

Nonutility subsidiary deferred tax liabilities
  (assets)
  Finance leases                                       $  123,989   $  119,448    $  118,305
  Operating leases                                          8,854       28,823        41,660
  Alternative minimum tax                                 (97,109)     (97,109)      (97,109)
  Assets with a tax basis greater than book basis         (43,847)           -             -
  Other                                                   (65,939)     (50,947)      (45,197)
                                                       ----------   ----------    ----------
Total nonutility subsidiary deferred tax
  (assets) liabilities, net                            $  (74,052)  $      215    $   17,659
                                                       ==========   ==========    ==========



                                                        8
</TABLE>


(3)  CAPITALIZATION AND FAIR VALUE OF FINANCIAL INSTRUMENTS
     ------------------------------------------------------

Common Equity
-------------

     At September 30, 1998, 118,527,287 shares of the Company's
$1 par value Common Stock were outstanding.  A total of 200
million shares is authorized.  As of September 30, 1998,
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 2,769,412 and
3,392,500 shares were reserved for conversion of the 7% and 5%
Convertible Debentures, respectively.  

Serial Preferred, Redeemable Serial Preferred and Preference 
------------------------------------------------------------
   Stock, Company Obligated Mandatorily Redeemable Preferred
   ---------------------------------------------------------
   Securities and Long-Term Debt
   -----------------------------
 
     On June 1, 1998, the Company redeemed 60,000 shares of
Serial Preferred Stock, $3.37 series of 1987, at $50 per share
for sinking fund purposes.  The Company also redeemed in
accordance with their terms, all of the 779,696 shares remaining
after the sinking fund redemption of Serial Preferred Stock,
$3.37 series of 1987, at $51.13 per share; all of the 500,000
shares of Serial Preferred Stock, $3.82 series of 1969, at $51.00
per share; and all of the 1,000,000 shares of Serial Preferred
Stock, $3.89 series of 1991, at $53.89 per share.  The redemption
totaled $123.7 million and includes $6.6 million in premiums.

     At September 30, 1998, 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 11,095,501 shares
is authorized.  At September 30, 1998, the aggregate annual
dividend requirements on the Serial Preferred Stock and the
Redeemable Serial Preferred Stock were approximately $4.4 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, 1998, the Company had outstanding one
million shares of its Serial Preferred Stock, Auction Series A. 
The annual dividend rate is 4.04% ($2.02) for the period
September 1, 1998, through November 30, 1998.  For the period
June 1, 1998, through August 31, 1998, the annual dividend rate
was 4.1% ($2.05).  The average rate at which dividends were paid
during the twelve months ended September 30, 1998, was 4.18%
($2.09).


                              9


     At September 30, 1998, the Company had outstanding one
million 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 with respect to this series is $2.5 million. 

     In May 1998, Potomac Electric Power Company Trust I (Trust),
of which the Company owns all of the common securities, issued
$125 million of 7-3/8% Trust Originated Preferred Securities
(TOPrS).  The proceeds from the sale of the TOPrS and from the
common securities of the Trust to the Company were used by the
Trust to purchase from the Company $128.9 million of 7-3/8%
Junior Subordinated Deferrable Interest Debentures, due June 1,
2038.  The sole assets of the Trust are the Subordinated
Debentures.  The Trust will use interest payments received on the
Subordinated Debentures to make quarterly cash distributions on
the TOPrS.  Proceeds from the sale of the Subordinated Debentures
to the Trust were used by the Company to redeem three series of
serial preferred stock on June 1, 1998.  

     At September 30, 1998, the aggregate annual interest
requirement on the Company's long-term debt and Company obligated
mandatorily redeemable preferred securities of subsidiary trust,
including debt due within one year, was $139.6 million; and the
aggregate amounts of long-term debt maturities are $45 million in
1999, $100 million in 2000, $165 million in 2001 and $190 million
in 2002.  At September 30, 1998, long-term debt due within one
year consisted of $45 million of 4-1/2% First Mortgage Bonds.


                              10


     The estimated fair values of the Company's financial
instruments at September 30, 1998, net of amounts due within one
year, are summarized below:

                                           Carrying      Fair
                                            Amount       Value
                                          ----------   ----------
                                          (Thousands of Dollars)  
Utility
  Capitalization and Liabilities    
    Serial preferred stock                $  100,000   $   94,275 
                                           ==========  ==========

    Redeemable serial preferred stock     $   50,000   $   53,610
                                          ==========   ==========
    Company obligated mandatorily 
      redeemable preferred securities
      of subsidiary trust which holds
      solely parent junior subordinated
      debentures                          $  125,000   $ 130,000 
                                          ==========   ==========

    Long-term debt
      First mortgage bonds (net of
        unamortized premium and     
        discount of $13,659)              $1,408,141   $1,512,473 
      Medium-term notes (net of 
        unamortized discount of $1,782)      281,308      307,526 
      Convertible debentures (net of
        unamortized discount of $8,695)      169,141      174,493
                                          ----------   ----------
        Total long-term debt              $1,858,590   $1,994,492
                                          ==========   ==========

Nonutility Subsidiary 
  Assets
    Marketable securities (primarily      
      mandatorily redeemable preferred    
      stock)                              $  240,680   $  240,680
                                          ==========   ==========

    Notes receivable                      $   25,808   $   22,606
                                          ==========   ==========
  Liabilities 
    Long-term debt                        $  558,142   $  570,268 
                                          ==========   ==========

     The following methods and assumptions were used to estimate,
at September 30, 1998, the fair value of each class of financial
instrument shown above for which it is practicable to estimate
that value.


                              11


     The fair values of the Company's Serial preferred stock,
Redeemable serial preferred stock and TOPrS 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, excluding amounts due within one year, were based on
current market price, or for issues with no market price
available, were based on discounted cash flows using current
rates for similar issues with similar terms and remaining
maturities.

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

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

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

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




                              12



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

     Long-term debt at September 30, 1998, consisted primarily of
unsecured borrowings from institutional lenders.  The interest
rates of such borrowings ranged from 5% to 10.1%.  The weighted
average effective interest rate was 7.61% at September 30, 1998,
7.48% at December 31, 1997, and 7.48% at September 30, 1997. 
Annual aggregate principal repayments on these borrowings are
$8.3 million remaining in 1998, $170 million in 1999, $122.5
million in 2000, $71.5 million in 2001, $93 million in 2002 and
$72.6 million thereafter.  Also included in long-term debt is
$20.2 million of non-recourse debt which is due in monthly
installments with final maturities in 2002 and 2011. 

Nonutility Subsidiary Contractual Maturities
--------------------------------------------

     At September 30, 1998, the contractual maturities for
mandatorily redeemable preferred stock are $5 million within one
year, $95.9 million from one to five years, $86.5 million from
five to 10 years and $40.2 million for over 10 years. 



                              13   

<TABLE>
Calculations of Earnings Per Share
----------------------------------

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


                                             Three Months Ended         Nine Months Ended        Twelve Months Ended
                                                September 30,             September 30,             September 30,
                                              1998         1997         1998         1997         1998         1997
                                            --------     --------     --------     --------     --------     --------
<S>                                         <C>          <C>          <C>          <C>          <C>          <C>
                                                                (Thousands except Per Share Data)
Income (Numerator):

Earnings applicable to common stock         $151,092     $131,828     $210,479     $196,652     $179,078     $203,782

Add:  Dividends paid or accrued on
        Convertible Preferred Stock                -            4            2           11            6           14
      Interest paid or accrued on
        Convertible Debentures,
        net of related taxes                   1,577        1,588        4,732        4,767        6,320        6,372
                                            --------     --------     --------     --------     --------     --------
Earnings applicable to common stock,
  assuming conversion of convertible
  securities                                $152,669     $133,420     $215,213     $201,430     $185,404     $210,168
                                            ========     ========     ========     ========     ========     ========
Shares (Denominator):

Average shares outstanding for
  computation of basic earnings
  per common share                           118,527      118,501      118,522      118,500      118,517      118,500
                                            ========     ========     ========     ========     ========     ========
Average shares outstanding for
  diluted computation:

  Average shares outstanding                 118,527      118,501      118,522      118,500      118,517      118,500

  Additional shares resulting from:
    Conversion of Serial Preferred
      Stock, $2.44 Convertible Series
      of 1966 (the "Convertible
      Preferred Stock")                            -           34            4           35           12           34
    Conversion of 7% Convertible
      Debentures                               2,325        2,364        2,325        2,364        2,334        2,378
    Conversion of 5% Convertible
      Debentures                               3,393        3,393        3,393        3,393        3,393        3,393
                                            --------     --------     --------     --------     --------     --------
Average shares outstanding for
  computation of diluted
  earnings per common share                  124,245      124,292      124,244      124,292      124,256      124,305
                                            ========     ========     ========     ========     ========     ========

Basic earnings per common share                $1.27        $1.11        $1.78        $1.66        $1.51        $1.72

Diluted earnings per common share              $1.23        $1.07        $1.73        $1.62        $1.49        $1.69



                                                                  14

</TABLE>



(4)  COMMITMENTS AND CONTINGENCIES
     -----------------------------

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

     As discussed in the June 30, 1998 Form 10-Q, in December
1987, the Company was notified by the Environmental Protection
Agency (EPA) that it, along with several other utilities and
nonutilities, is a Potentially Responsible Party (PRP) under the
Comprehensive Environmental Response, Compensation and Liability
Act of 1980, as amended (CERCLA or Superfund), in connection with
the polychlorinated biphenyl compounds (PCBs) contamination of a
Philadelphia, Pennsylvania site owned by a nonaffiliated company. 
In the early 1970's, the Company sold scrap transformers, some of
which may have contained some level of PCBs, to a metal reclaimer
operating at the site.  In October 1994, a Remedial
Investigation/Feasibility Study including a number of possible
remedies was submitted to the EPA.  In December 1997, the EPA
signed a Record of Decision (ROD) that set forth a selected
remedial action plan with estimated implementation costs of
approximately $17 million.  On June 26, 1998, the EPA issued a
unilateral Administrative Order to the Company and twelve other
PRPs to conduct the design and actions called for in the ROD.  To
date, the Company has accrued $1.7 million for its share of this
contingency.

     As discussed in the June 30, 1998 Form 10-Q, in May 1998,
the State of Maryland issued final regulations entitled "Post
RACT Requirements for Nitrogen Oxides (NOx) Sources (NOx Budget
Proposal)", requiring a 65% reduction in NOx emissions at the
Company's Maryland generating units by May 1, 1999.  The
regulations allow the purchase or trade of NOx emission
allowances to fulfill this obligation.  The Company appealed this
regulation to the Circuit Court for Charles County, Maryland on
June 19, 1998, on the basis that the regulation does not provide
adequate time for the installation of NOx emission reduction
technology and that there is no functioning NOx allowance market. 
On July 17, 1998, the case was moved to the Circuit Court for
Baltimore City and consolidated with a similar appeal filed by
Baltimore Gas and Electric Company.  The Company predicts it is
unlikely that a market containing NOx allowances sufficient to
ensure compliance will be functioning by May 1999; presently,
only seven states have enacted the rules necessary to create such
a market.  A preliminary plan for installing the best available
removal technology on the Company's largest coal-fired units
would require capital expenditures of approximately $173 million
and would yield NOx reductions of nearly 85% beginning in year
2004.  The Company cannot predict the outcome of this litigation
and is evaluating its options in the event of an adverse
decision.  Also, on September 24, 1998, the EPA issued rules for 


                              15    


reducing interstate transport of ozone.  The Company's
preliminary plan for NOx reductions of 85% by 2004 appears to be
consistent with the EPA rules.

     The Company's generating stations operate under National
Pollutant Discharge Eliminating System (NPDES) permits.  A NPDES
renewal application submitted in July 1993 for the Benning
station is pending.  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.  An NPDES renewal application
was submitted for the Potomac River station in August 1998.  

Targeted Severance Plan
-----------------------

     As discussed in the June 30, 1998 Form 10-Q, the Company has
offered a targeted severance plan to exempt, non-bargaining and
bargaining unit employees who lose employment due to corporate
restructuring and/or job consolidations.  Participants in the
plan will receive severance pay and subsidized health and dental
benefits.  Through September 30, 1998, 155 employees have
participated in the plan on a voluntary basis.  During the second
and third quarters of 1998, $3.7 million and $3.2 million,
respectively, in severance costs were expensed.  In the future,
additional costs will be accrued as appropriate.

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

     This Quarterly Report on Form 10-Q, including the report of
PricewaterhouseCoopers LLP (on page 17) 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, 333-33495 and 333-66127) and Forms S-8
(Numbers 33-36798, 33-53685, 33-54197, 333-56683 and 333-57221),
filed under the Securities Act of 1933.  Such 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.



                              16


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 consolidated subsidiaries (the
Company) at September 30, 1998 and 1997, 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 generally accepted
auditing standards, the consolidated balance sheet as of December
31, 1997, and the related consolidated statement of earnings and
consolidated statement of cash flows for the year then ended (not
presented herein); and in our report dated January 16, 1998, 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, 1997, is fairly stated, in all material respects, in
relation to the consolidated balance sheet from which it has been
derived.




/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Washington, D.C.
November 12, 1998 



                              17


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

FORWARD LOOKING STATEMENTS
--------------------------

     This Management's Discussion and Analysis of Consolidated
Results of Operations and Financial Condition contains forward
looking statements, as defined by the Private Securities
Litigation Act of 1995, with regard to matters that could have an
impact on the future operations, financial results or financial
condition of the Company.  These statements are based on the
current expectations, estimates or projections of management and
are not guarantees of future performance.  Actual results may
differ materially from those anticipated by the forward looking
statements, depending on the occurrence or nonoccurrence of
future events or conditions that are difficult to predict and
generally are beyond the control of the Company.  All such
forward looking statements relating to the following matters are
qualified by the cautionary statements below and contained
elsewhere herein.

GROWTH IN DEMAND, SALES AND CAPACITY TO FULFILL DEMAND

     The actual growth in demand for and sales of electricity
within the Company's service territory may vary from the
statements made concerning the anticipated growth in demand and
sales, depending upon a number of factors, including weather
conditions, the competitive environment, general economic
conditions and the demographics of the Company's service
territory.  Future construction expenditures (including the need
to construct additional generation capacity) may vary from the
projections, depending on the accuracy of management's
expectations regarding growth in demand for and sales of
electricity, regulatory developments including potential changes
in environmental regulations, and the evolution of the
competitive marketplace for electricity.

COMPETITION

     Increased competition will have an impact on future results
of operations, which may be adverse, and will depend, among other
factors, upon governmental policies and regulatory actions,
including those of the Federal Energy Regulatory Commission
(FERC) and the Maryland and District of Columbia public service
commissions, future economic conditions and the influence exerted
by emerging market forces over the structure of the electric
industry.


                              18 


YEAR 2000 COMPLIANCE

     The Company has implemented a 4-pronged approach to
accommodate the Year 2000.  The phases being addressed are: 
Corporate Applications Readiness, which includes all large core
business systems; Embedded Systems, which include all operating
and control systems; End-User Computing Systems, which are all
systems which are not considered core business systems but
contain date calculations; and Business Partners' Systems and
Vendor Supply-Chain Verification, which is intended to monitor
suppliers' compliance with Year 2000 processing.  A database has
been developed to identify and track the progress of work on each
phase.  The preliminary target date for completion of these
phases is mid-1999.  The cost or consequences of a material
incomplete or untimely resolution of the Year 2000 problem could
adversely affect future operations, financial results or
financial condition of the Company.
     
UTILITY
-------

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

TOTAL REVENUE

     Total revenue increased for the three, nine and twelve
months ended September 30, 1998, as compared to the corresponding
periods in 1997.  The increases in revenue from sales of
electricity for the periods ending September 30, 1998, resulted
primarily from increases in kilowatt-hour sales of 7.1%, 3.7% and
3.4% over the corresponding periods in 1997.  Although weather,
as measured in cooling degree hours, in the second and third
quarters of 1998 was 18% hotter than in 1997, it was,
nevertheless, 7% cooler than the 20-year average.  Weather in the
first quarter of 1998 was 4% milder than the first quarter of
1997 and 17% milder than the 20-year average.  The increases in
revenue also reflect a 2.6% increase in Maryland base rates
pursuant to a November 1997 settlement agreement; partially
offset by rate reductions of $2.5 million (effective January 1,
1998) for wholesale service to the Southern Maryland Electric
Cooperative, Inc. (SMECO) and $17 million (effective June 1997)
in the Maryland Demand Side Management (DSM) surcharge tariff.  

     Effective September 21, 1998, the Maryland DSM surcharge
tariff was lowered, which will reduce annual revenues by
approximately $3 million, reflecting the Company's efforts to
reduce conservation program offerings and limit conservation
spending.  In the third quarter of 1998, the Company recorded a
$1.3 million bonus, which was awarded for achieving 1997 energy
goals under the conservation incentive provision of the tariff;
in the second quarter of 1997, the Company recorded a $1.6
million bonus for achieving 1996 energy saving goals.  


                              19


     Interchange deliveries increased for the three, nine and
twelve months ended September 30, 1998, as compared to the
corresponding periods in 1997.  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.

     In January 1997, the Company implemented an open access
transmission tariff (OATT) and in April 1997, PJM implemented an
OATT on behalf of its transmission owners, replacing the
Company's tariff.  Under these tariffs, the Company receives
point-to-point transmission service revenue, classified as "Other
electric revenue," which totaled $2.7 million, $3.5 million and
$3.6 million for the three, nine and twelve months ended
September 30, 1998, and $.6 million, $2 million and $2 million
for the corresponding periods in 1997.  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:

                            Rate  
                         (Decrease)
                          Increase       %          Effective
Regulatory Jurisdiction    ($000)      Change          Date
-----------------------  ----------    -------    ---------------
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 Item 5 "Other Information," the Company is
negotiating with SMECO to establish rates for the future which
could result in a new full-requirements agreement.

OPERATING EXPENSES

     Fuel expense increased for the three, nine and twelve months
ended September 30, 1998, as compared to the corresponding
periods in 1997, primarily due to increases of 24.2%, 19.4% and
19.3%, respectively, in net generation; partially offset 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, 1998, reflect changes in levels
and prices of energy purchased from PJM and other utilities and
power marketers.


                              20


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

                          Three          Nine          Twelve
                       Months Ended   Months Ended   Months Ended
                       September 30,  September 30,  September 30 
                       -------------  -------------  ------------
                       1998    1997   1998    1997   1998   1997
                       -----   -----  -----   -----  -----  -----
System Average 
  Fuel Cost per MBTU   $1.72   $1.81  $1.75   $1.84  $1.77  $1.82


     System average unit fuel cost decreased for the three, nine
and twelve months ended September 30, 1998, as compared to the
corresponding periods in 1997, primarily due to decreases in the
costs of coal and residual oil.

     For the twelve month periods ended September 30, 1998 and
1997, the Company obtained 84% and 90%, 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, 1998, as compared to the
corresponding periods in 1997.  These increases reflect
contractual escalations under existing purchase capacity
contracts with Ohio Edison and Panda-Brandywine (Panda).

     Operating expenses other than fuel, purchased energy and
capacity purchase payments increased for the three, nine and
twelve months ended September 30, 1998, as compared to the
corresponding periods in 1997, primarily due to increases in
other operation and maintenance expenses associated with the
Company's targeted severance plan and Year 2000 remediation
costs, increases in depreciation and amortization expense
associated with additional investment in property and plant, and
increases in income taxes resulting from increased taxable
income.


                              21



                      Year 2000 Compliance
                      --------------------

     The Company has implemented a 4-pronged approach to
accommodate the Year 2000.  All phases are coordinated through a
Corporate Year 2000 Task Force comprised of representatives from
each Business Unit.  The phases being addressed are as follows:

     1.  Corporate Applications (Information Technology)
         Readiness:  Corporate Applications are large core
         systems such as Customer Information, Human Resources 
         and General Ledger, for which the Company's Computer
         Services Group (CSG) has responsibility.  Year 2000
         modifications to these systems are being
         programmed and tested by CSG.

     2.  Embedded Systems (Non-Information Technology
         Processes):  These systems include items such as
         meters, power plant operating and control systems,
         telecommunications systems and facilities-based
         equipment (e.g. elevators).  These products are being
         evaluated and modified as required by the appropriate
         internal end-user, in coordination with the systems'
         vendors. 

     3.  End-User Computing Systems (Non-Core [Departmental]
         Business Systems):  Corporate areas other than CSG
         have developed systems, databases, spreadsheets, etc.
         that contain date calculations.  These products are
         being evaluated and modified as required by the
         appropriate end-user. 

     4.  Business Partners' Systems and Vendor Supply-Chain
         Verification:  The Company is seeking to obtain Year
         2000 assurances from numerous vendors who provide
         products and services to the Company.  This effort is
         being jointly undertaken by the Company's Materials
         Group and appropriate end-users. 
         

     The Task Force meets regularly to monitor the status of the
efforts of the Company's assigned staff, contractors, and vendors
in testing and remediating Year 2000 related issues.  Task Force
Subcommittees are addressing additional Year 2000 related issues
including, but not limited to, customer communications, testing
procedures and business continuation and other contingency
planning.

     As of September 30, 1998, approximately 95% of the 110
corporate Information Technology systems (7,891 programs) have
been upgraded and/or re-programmed.  "Time Machine" testing using
a portion of the mainframe computer system partitioned for Year
2000 full-cycle testing is now in its second series of processing 


                             22


applications; 65% of corporate Information Technology systems
have been tested in the time machine.  A parallel LAN (local area
network) Year 2000 testing facility has been established, and
testing of LAN-based applications has commenced.

     Assessments of critical operational systems containing
embedded systems were completed in October 1998 by teams of
vendors, contractors and Company personnel.  Year 2000 upgrades
to the distributed control systems of Potomac River Units 1, 2, 4
and 5 have been completed and will be tested in November 1998. 
The distributed control systems of Chalk Point Units 2 & 4 will
be remediated and tested in November and December 1998. 
Remediation efforts are in process at other plants and areas of
the electric system.  In addition to including Year 2000
remediation and testing as part of regularly scheduled plant
outages, special Year 2000 outages have been scheduled in the
fall of 1998 and winter and spring of 1999.  Test scheduling is
more complex for embedded systems because of the difficulty
inherent in scheduling power plant outages to accommodate the
testing.  In addition, some vendors are requesting that their
customers refrain from testing certain components because of the
potential difficulties in recovering from such tests.  These
vendors have either advised that their product is Year 2000 ready
or have invited the Company to participate in testing at their
facilities.  At this time, all affected plant units have outages
planned for Year 2000 testing.  This differs from the original
plan to test one typical unit of each type.  To accommodate this
change of scope, the completion date for all Year 2000 testing of
critical and high priority components has been revised to June
30, 1999.  This target date may be impacted by the integration
testing plans and scheduled generation/ electric systems outage
decisions inherent in embedded systems processing.  As of
November 12, 1998, it appears that all identified Year 2000
impacted processing components can be upgraded, modified or
otherwise made Year 2000 ready within acceptable time frames.  

     End-user computing systems comprise a relatively small
percentage of the required modification both in terms of number
and criticality.  All activities remain on schedule to be
completed by mid-1999.

     The Company is participating in an Electric Power Research
Institute sponsored consortium of approximately 100 organizations
and investor-owned utilities to coordinate vendor contacts and
product evaluation.  Since many embedded systems are similar
across utilities, this cooperative effort should help to reduce
total time expended in this area and help ensure that the
Company's efforts are consistent with the efforts and practices
of other investor-owned utilities.  



                              23


     The United States Department of Energy requested that the
North American Electric Reliability Council (NERC) prepare a
comprehensive report outlining the efforts of electric power
supply and delivery systems to prepare for Year 2000.  NERC
collected data from utilities on a voluntary basis, and issued a
report on September 17, 1998.  The Company was among the first
30% of utilities to respond to NERC with the requested data.  

     Major challenges remain in several areas:  maintaining
sufficient human resources to complete Year 2000 tasks;
evaluating integrated testing requirements for many embedded
systems, taking into account planned outages and operational
needs; and completing contingency planning for the variety of
scenarios which might occur.  There are three potential areas of
resource constraints.  First, as other companies and government
agencies gear up their Year 2000 remediation activities, the
competition for trained personnel (e.g. programmers) is becoming
stronger.  The Company continues to operate effectively in the
employment and contracting marketplace, and is maintaining the
required level of resources.  Second, as the Company continues to
reorganize to prepare for industry deregulation, there is a risk
of losing technically and functionally knowledgeable people to
remediate and test systems.  However, operating areas have been
instructed to give increased attention to Year 2000 staffing
needs when making reorganization decisions.  Third, the
availability of vendor resources to complete embedded system
assessments and produce in volume any required component upgrades
will be a concern. 

     Integration testing also presents a challenge because of
scheduling constraints and admonitions from some vendors
regarding the risks of testing.  A careful evaluation of testing
options and vendor testing documentation must be made on a
component-by-component basis in order to determine the most
appropriate method for obtaining Year 2000 readiness.  

     Business continuation and contingency planning efforts are
in progress at several levels.  Business Units responsible for
critical components and systems are preparing plans in case of
potential failures of individual components or systems.  These
plans are referenced in the Year 2000 tracking database and will
be incorporated into the Company's Year 2000 Business Continuity
Plan.

     In order to ensure adequate staffing for contingencies that
may arise, Company employees have been informed that vacation,
floating holidays, and other discretionary leave may not be
scheduled between December 26, 1999 and January 8, 2000.

     The Company has embarked on a program to identify and
remediate problems that could affect service to customers.  The
objective is to identify and minimize risk to critical business
functions and associated computer processes before the problems 


                              24


impact Company operations.  Recognizing that all contingency
plans should support business continuity, the Company has formed
a Business Continuity Plan Team to integrate contingency plans. 
The Company's business continuity planning will go beyond
contingency planning to document actions to be taken, resources
required, and procedures to be followed to ensure the continued
availability of essential services, programs, and operations in
the event of unexpected interruptions.

     The following steps will be used for business continuity
planning:

     1.  Identification of Year 2000 Operating Risks - Identify
         sources of risk, both internal and external, which may
         impact the Company's ability to sustain reliable
         operations into the Year 2000 and beyond.

     2.  Review of Existing Operating Plans - Review existing
         procedures to determine if a Year 2000-specific plan
         should be incorporated.

     3.  Develop Risk Management Strategies - Perform an analysis
         of, and make recommendations for, alternative methods of
         continuing critical business functions.

     4.  Develop Year 2000 Emergency Plan and Enhance Existing
         Plans -  A separate Year 2000 plan will be developed
         that will interface with the Company's Corporate
         Emergency Response Plan (ERP).  Modification and
         enhancements to existing plans will include the
         following:  (a) Procedures to be followed before,
         during, and after a disaster; (b) Inventories of
         information needs in a disaster, such as emergency
         personnel lists, supplier lists, etc.; (c) Vital records
         risk level; (d) Analysis of means to mitigate risk; and
         (e) Integration of Year 2000 into the ERP.
 
     5.  Validation Process - Tests will be conducted by the
         Business Continuity Planning Team to include tabletop
         exercises and drills on likely Year 2000 scenarios.

     The Company's planning process includes a review of
emergency coordination interfaces with the community.  For
example, a key facet of business continuity is the Company's
interface with various emergency management agencies.  The
Company is participating with the Metropolitan Washington Council
of Governments, which is looking at public safety issues on a
regional basis using existing regional public safety and
emergency management organizations.  The Company presented a
planning status report to the Council of Governments on November
5, 1998 and is also actively participating with county emergency
management agencies in Year 2000 planning and drills.


                              25


     To assist in review and testing of business continuity
planning, the Company contracted with Binominal International and
LGS Group Inc. (LGS).  Binominal International is known for its
contingency planning and disaster recovery expertise.  Binominal
International will assist in the review and testing of business
continuity planning.  LGS will provide the resources to assist
the Company in identifying and incorporating Year 2000 components
into the plan as they relate to critical applications.  This will
consist of reviewing the ERP procedure and commenting on it with
respect to Year 2000.  LGS is a leading international information
technology and management consulting firm.

     The first draft of the Company's Business Continuity Plan is
scheduled to be completed by December 15, 1998.

     The Company is working through the PJM Interconnection to
address risks related to the regional electric transmission
system.  Such interconnected systems are critical to the
reliability of each interconnected electric service provider, as
the failure of one such interconnected provider to achieve Year
2000 readiness could disrupt others from providing electric
service.  Should the regional electric transmission grid become
unstable, power outages could occur.  The Company's existing
emergency system restoration plan is being reviewed for use in
the event of such Year 2000 system disruptions.

     NERC has responsibility for overseeing the efforts of the
industry in the United States and is coordinating Year 2000
efforts and contingency planning within and between the ten
electric reliability councils throughout the United States. 
Coordination in the Company's region is through PJM.  PJM, along
with NERC, has set a deadline of December 31, 1998 for the
development of draft contingency plans.  The Company provides
reports of its Year 2000 activities to NERC on a monthly basis. 
Results show that the Company is on schedule to meet the NERC
target dates for Year 2000 readiness.  The Company will
participate in NERC's planned 1999 drills.

     The availability of telecommunications services is a major
concern to the Company.  Telecommunications are integral to
maintaining electric system operations internally, within PJM,
and throughout the Northern American grid.  Contingency planning
for various loss of telecommunications scenarios is underway.

     The Company agrees with NERC's September 17, 1998 report to
the United States Department of Energy regarding the various Year
2000 scenarios that could occur.  NERC has divided these into
"more probable scenario types," such as loss or unavailability of
a portion of generation, loss of a portion of system monitoring
and control functions, loss of voice communications, loss of a
portion of load, or uncharacteristic load; and "credible worst-
case scenarios," such as loss of a portion of transmission 


                              26


facilities, underfrequency load shedding, and loss of intra- or
interregional communications.  The Company's Business Continuity
Planning Team will be evaluating scenarios such as these and
developing appropriate response plans.

     The Company has established a range of communications to
keep customers and suppliers informed of Year 2000 efforts. 
During September 1998, Year 2000 briefing seminars were held for
many large customers.  Individual meetings with several large
customers have also been held.  A bill insert has been used to
advise customers of Year 2000 activities; future bill inserts
will be used as needed.  A brochure for customers inquiring about
the Company's Year 2000 efforts is being finalized and will be
ready for distribution within one month.  The brochure will be
posted on the Company's web page on the Internet, and the web
page will be updated periodically with the latest Year 2000
status information.  An updated telephone script has been
developed for customer service representatives answering Year
2000 related telephone inquiries from customers.

     The Company has contacted over 6,000 suppliers and vendors
to seek assurance that they will continue to provide goods and
services after December 1999.  Follow-up contacts continue. 
Identified essential suppliers will be defined as critical
dependencies in the draft Business Continuity Plan.

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

     The cost of expected modifications will be approximately $14
million, and will be charged to expense as incurred; through
September 30, 1998, $4.7 million has been charged to expense. 
Approximately $1.2 million and $3.4 million have been expensed in
the three and nine months ended September 30, 1998, respectively. 
Approximately 70% of the total cost will be spent in 1998, and
the remainder in 1999.  These estimates may change as additional
evaluations are completed and remediation and testing progresses.

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

     The Company's investment in property and plant, at original
cost before accumulated depreciation, was $6.6 billion at 
September 30, 1998, an increase of $95.7 million from the
investment at December 31, 1997, and an increase of $162.9
million from the investment at September 30, 1997.  Cash invested
in property and plant construction, excluding Allowance for Funds
Used During Construction and Capital Cost Recovery Factor,
amounted to $146 million for the nine months ended September 30,
1998, and $223 million for the twelve months then ended. 


                              27


     At September 30, 1998, the Company's capital structure,
excluding short-term debt, long-term debt due within one year and
nonutility subsidiary debt, consisted of 45.7% long-term debt,
2.5% serial preferred stock, 1.2% redeemable serial preferred
stock, 3.1% Company obligated redeemable preferred securities of
subsidiary trust and 47.5% common equity.

     Cash from utility operations, after dividends, was $224.1
million for the nine months ended September 30, 1998, and $269
million for the twelve months then ended as compared with $157.6
million and $248.8 million, respectively, for the corresponding
periods ended September 30, 1997.

     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.

     In May 1998, Potomac Electric Power Company Trust I, of
which the Company owns all of the common securities, issued $125
million of 7-3/8% Trust Originated Preferred Securities.  

     In June 1998, the Company redeemed three series of serial
preferred stock.  The redemption totaled $123.7 million and
includes $6.6 million in premiums.

     Outstanding utility short-term debt totaled $119.1 million
at September 30, 1998, a decrease of $12.3 million from the
$131.4 million outstanding at December 31, 1997, and a decrease
of $158 million from the $277.1 million outstanding at September
30, 1997.  

     On August 14, 1998, the Company filed for a 5.3% decrease in
the Maryland fuel rate, which became effective beginning the
billing month of September 1998, subject to refund.  Also, on
October 19, 1998, the Company filed for an additional 6.3%
decrease in the Maryland fuel rate, which became effective
beginning the billing month of November 1998, subject to refund.
 
     Also see the discussion included in Note (3) of the Notes to
Consolidated Financial Statements, Capitalization and Fair Value
of Financial Instruments, for additional information.


                              28


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

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

     Earnings for Potomac Capital Investment Corporation (PCI)
for the three, nine and twelve months ended September 30, 1998,
were $3.8 million ($.03 per share), $16.2 million ($.14 per
share) and $17.5 million ($.15 per share), respectively, compared
with $.9 million ($.01 per share), $15.8 million ($.13 per share)
and $16.3 million ($.14 per share) for the periods ended
September 30, 1997.  Net earnings for the three, nine and twelve
months ended September 30, 1998, were greater than the
corresponding periods in 1997 primarily due to the sale of real
estate in the third quarter of 1998 which generated a pre-tax
gain of $9.1 million ($5.9 million after-tax); and to reduced
interest expense associated with a decrease in outstanding debt. 
The increases for the nine and twelve months ended September 30,
1998, were partially offset by first quarter 1997 joint venture
operations that reduced PCI's obligation for previously accrued
deferred income taxes resulting in after-tax earnings of $7.4
million, and decreases in capital gains and dividend income
associated with the reduction in the preferred stock portfolio.

     Currently, PCI generates income primarily from its leasing
activities and operating businesses.  Income from leasing
activities, which includes rental income, gains on asset sales,
interest income and fees, totaled $15.5 million, $59.3 million
and $77.9 million for the three, nine and twelve months ended
September 30, 1998, respectively, compared to $21.3 million,
$57.1 million and $78.4 million for the corresponding periods in
1997.  The decrease for the three months ended September 30,
1998, compared to the corresponding period in 1997, was primarily
the result of a decrease in rental income as a result of asset
sales and a decrease in interest income related to the sale of
aircraft notes during 1997.  The increase for the nine months
ended September 30, 1998, compared to the corresponding period in
1997, was primarily due to the pre-tax gains on sales of aircraft 
equipment of $2.9 million in the first quarter and $6.3 million
in the second quarter, offset by a decrease in rental income. 
The decrease for the twelve months ended September 30, 1998,
compared to the corresponding period in 1997, was primarily due
to decreases in rental income and interest income, partially
offset by gains from sales of assets during the first and second
quarters of 1998.  PCI's marketable securities portfolio
contributed pre-tax income of $3.9 million, $14.9 million and
$19.9 million for the three, nine and twelve months ended
September 30, 1998, respectively, compared to $5.8 million, $23.6
million and $31.8 million for the corresponding periods in 1997. 
These results include net realized gains of zero, $2 million and
$1.9 million for the three, nine and twelve months ended 


                              29


September 30, 1998, respectively, compared to $.7 million, $6.9
million and $8.1 million for the corresponding periods in 1997. 
Securities income decreased for the three, nine and twelve months
ended September 30, 1998, due to decreases in dividend income as
a result of the reduction in the preferred stock portfolio.

     Other income totaled $10.5 million, $28.9 million and $29.2
million for the three, nine and twelve months ended September 30,
1998, respectively, compared to $5.8 million, $20.7 million and
$20.6 million for the corresponding periods in 1997.  The
increases for the three, nine and twelve months ended September
30, 1998, over the corresponding periods in 1997, were primarily
the result of a $9.1 million pre-tax gain on the sale of real
estate in the third quarter of 1998 and a $3.1 million pre-tax
gain on the sale of real estate during the first quarter of 1998. 

     Expenses before income taxes, which include interest,
depreciation and operating, and administrative and general
expenses totaled $28.6 million, $89.4 million and $119.4 million
for the three, nine and twelve months ended September 30, 1998,
respectively, compared to $35.4 million, $109.9 million and
$143.7 million for the corresponding periods in 1997.  The
decreases during the three, nine and twelve months ended
September 30, 1998, were primarily due to decreased interest
expense as a result of reduced debt outstanding, as proceeds from
sales of aircraft and marketable securities were used to pay down
debt.  Expenses before income taxes for the three, nine and
twelve months ended September 30, 1998, also decreased due to
reductions in depreciation and operating expenses resulting from
the sale of aircraft.

     PCI had income tax credits of $2.5 million, $2.4 million and
$10 million for the three, nine and twelve months ended September
30, 1998, respectively, compared to income tax credits of $3.4
million, $24.3 million and $29.1 million for the corresponding
periods in 1997.  The decreases in income tax credits for all
three periods were primarily the result of higher pre-tax income,
and for the nine and twelve month periods, the first quarter 1997
joint venture operations that reduced previously accrued deferred
taxes by $10.1 million.

                      Year 2000 Compliance
                      --------------------

     In connection with Year 2000 compliance efforts, a PCI
representative sits on the Corporate Year 2000 Task Force.  PCI
is following the utility's approach, as discussed previously, for
monitoring its in-house systems and PCI's systems have been
included in the overall Year 2000 Corporate Data Base.  All PCI 
in-house business systems remain on schedule to become Year 2000
compliant by mid-1999.  Costs for these remediation efforts are
currently estimated at less than $50,000.  In addition, PCI is 


                              30


addressing potential Year 2000 issues with the operations of
businesses in which PCI has investment or operating interests. 
The Corporate Year 2000 Task Force will be assisting PCI with its
examination and monitoring of Year 2000 issues involving these
strategic business interests.  Issues include ascertaining
responsibility for and monitoring progress of any Year 2000
remediation efforts required for investment-based business and
embedded systems.  Plans and progress reports have been received
for most such systems.  Due to the significant nature of PCI's
planned investment in Starpower Communications, LLC (Starpower),
a joint venture with RCN Telecom Services, Inc. (RCN), PCI has
instituted a Starpower-specific Year 2000 Program.  Starpower
receives significant support services from RCN which plans to
complete its formal Year 2000 Plan by the end of November 1998,
somewhat later than the original target completion date.  PCI is
working with Starpower and RCN toward readiness of RCN-supplied
support systems, and other Starpower systems and operations with
Year 2000 requirements.  A contingency plan is being developed 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 PCI's future operations, financial results or
financial condition.

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

     PCI has a $240.7 million securities portfolio, consisting
primarily of fixed-rate electric utility preferred stocks. 
During the first nine months of 1998, PCI had a net reduction in
the cost basis of its marketable securities portfolio of $64
million, primarily as the result of calls and acceptance of
tender offers of approximately $65 million offset by purchases of
$1 million.  The reduced size of the preferred stock portfolio
lessens the impact of future fluctuations in interest rates.  The
proceeds from securities activity during 1998 were used to pay
down debt.  PCI also received $11 million in cash proceeds from
the sale of a B-747 aircraft during the first quarter of 1998. 
In April 1998, PCI sold two aircraft, a B-747 on operating lease
to United Airlines and an MD-82 on direct finance lease to
Continental Airlines, for $50.3 million and recorded an after-tax
gain of $4.1 million.  In September 1998, PCI sold real estate
and received $12.6 million in cash proceeds and recorded an
after-tax gain of $5.9 million.

     PCI had short-term debt outstanding of $183 million at
September 30, 1998, compared to $7.7 million at December 31,
1997, and $9.2 million at September 30, 1997.  During the three,
nine and twelve months ended September 30, 1998, PCI issued $29.1
million, $52.1 million and $52.1 million in long-term debt,
including non-recourse debt, and debt repayments totaled $45
million, $324.4 million and $357.1 million, respectively.  At 


                              31


September 30, 1998, PCI had $700 million available under its
Medium-Term Note Program and $400 million of unused bank credit
lines.  

     As of September 30, 1998, PCI has invested $12.5 million of
its total $150 million commitment to Starpower.  Starpower has
recently launched its local and long distance telephone and dial-
up Internet service in the Washington, D.C. area and will add
video and high-speed Internet as it builds out its fiber optic
network.  PCI expects that the joint venture will incur operating
losses initially, as it develops and expands its network and
customer base.

     During the first quarter of 1998, RCN acquired Erols
Internet in a stock-for-stock exchange.  The majority of Erols
customers (approximately 197,000 out of a total 316,000) are
located in Starpower's target market.  These customers' accounts,
as well as certain associated network assets and related
liabilities, have been committed by RCN to Starpower.  As a
result of this transaction, Starpower is amortizing the majority
of acquisition premium paid for its portion of the Erols business
over a five-year period commencing March 1998.  PCI's annual net
of tax share of the amortization is estimated to be $5.5 million
for 1999.  PCI's year-to-date share of the amortization, which
was recorded in the third quarter of 1998, had a negative after-
tax impact on earnings of $3.2 million.

     On September 23, 1998, Starpower and the City of
Gaithersburg signed the first Open Video System (OVS) agreement
in the state of Maryland.  This local approval allows Starpower
to offer Gaithersburg residents and businesses an alternate
choice in video programming and will pave the way for Starpower
to provide local phone, long-distance and high-speed Internet
access within the market.  A 94-channel basic cable service
through an advanced fiber-optic network will be offered in mid-
1999.  Also, on October 26, 1998, subject to Control Board
approval, Starpower and the District of Columbia signed an OVS
agreement to provide video programming, local phone, long-
distance and high-speed Internet access to District residents. 
This agreement will enable Starpower to begin delivering service
over its fiber optic network to 9,000 residences by the end of
1998.

     On September 9, 1998, Pepco Services, Inc., a wholly owned
subsidiary of PCI, purchased the assets and operations of
Gaslantic Corporation, a Maryland-based natural gas retail
marketing and advisory services company, for $4.2 million. 
Gaslantic, currently based in Forest Hill, Maryland, specializes
in strategic fuel management for large gas users in the eastern
United States, and assists commercial, industrial and
institutional customers in obtaining the best fuel source, 


                              32


transportation and price.  The acquisition will enable Pepco
Services, Inc., to provide its customers with a wider array of
energy solutions.

Part II   OTHER INFORMATION
-------   -----------------
Item 1    LEGAL PROCEEDINGS
------    -----------------

     See Part I, Item 1, Notes to Consolidated Financial
Statements, (4) Commitments and Contingencies.  Also, see the
discussion of Environmental Matters under Item 1 - Business of
the Company's 1997 Form 10-K.

Item 5   OTHER INFORMATION
------   -----------------

OTHER FINANCING ARRANGEMENTS - Credit Agreements
------------------------------------------------

     The Company and PCI satisfy their short-term financing
requirements through the sale of commercial promissory notes. 
The Company and PCI 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 1998 and 1997.

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

Maryland
--------

     In June 1998, the Company filed a rate increase request with
the Maryland Public Service Commission seeking to increase annual
revenue by $56.3 million, or 5.9%.  The request was filed to
recover $30.3 million of increased capacity costs, beginning
January 1, 1999, under existing Commission-approved purchased
capacity contracts with Ohio Edison and Panda.  These increases
result from contractual escalations and not from increased levels
of capacity.  Additional items that make up the requested
increase are:  amortization over five years of costs related to
the 1998 severance plan ($3.5 million); amortization over five
years of Year 2000 compliance costs ($1.2 million); an increase
in the authorized rate of return from 9% to 9.23% ($6.8 million);
other adjustments to conform to prior ratemaking determinations
($6.5 million); and a request to normalize tax effects of pre-
1981 plant removal costs ($8 million).  The request was based on
a partially projected test period and a requested return on
equity of 12%.  The request was updated on September 11, 1998,
using actual results to replace the partially projected data
included in the filing.  The updated data indicated a revenue
increase requirement of $50.4 million.  


                              33   


     On October 9, 1998, the Company along with the Maryland
People's Counsel, the Maryland Commission Staff, and all of the
other parties filed a joint motion with the Commission seeking
approval of a settlement agreement with respect to the Company's
application for a rate increase.  Under the terms of the
settlement, the Company would increase its base rates by an
average of 2%, or $19 million annually, effective with services
rendered on and after December 1, 1998.  The settlement is a
comprehensive settlement of all issues in the case and does not
include a specific rate of return determination.  On October 28,
1998, the settlement agreement was accepted by the Hearing
Examiner in the case, and is scheduled to become a final Order of
the Commission on November 28, 1998.  Previously, pursuant to a
November 1997 settlement agreement, the Commission authorized a
$24 million, or 2.6%, increase in base rate revenue effective
with bills rendered on and after November 30, 1997.

     Effective September 21, 1998, the Maryland DSM surcharge
tariff was lowered, which will reduce annual revenues by
approximately $3 million, reflecting the Company's efforts to
reduce conservation program offerings and limit conservation
spending.  The surcharge includes provisions for the recovery of
lost revenue, amortization of pre-1998 actual program
expenditures plus the initial amortization of 1998 projected
program costs, a return on unamortized program balances and an
incentive of $1.3 million awarded for achieving specified 1997
energy goals.  In the second quarter of 1997, an incentive of
$1.6 million was awarded for achieving 1996 energy goals. 
Maryland energy goals have been successively reduced to reflect
declining DSM expenditures.  

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

     As discussed in the June 30, 1998 Form 10-Q, the District of
Columbia Public Service Commission authorized a $27.9 million, or
3.8%, increase in base rate revenues, effective July 1995.

     In June 1997, the Company requested that the Commission
update the Environmental Cost Recovery Rider (ECRR) surcharge
tariff to include recovery of actual DSM expenditures incurred
during the period January 1995 through December 1996, increasing
annual revenue by approximately $9 million.  This surcharge
includes both a conservation expenditure component and a
component for recovering certain costs associated with complying
with the Clean Air Act (CAA) amendments of 1990.  The
conservation component is scheduled to be updated annually on
June 1 of each year, while the CAA component is updated
quarterly.  In a June 1998 filing, the Company requested that
recovery of year 1997 DSM expenditures also be reflected within
the ECRR.  On September 3, 1998, the Commission approved the
Company's June 1997 request for recovery of the January 1995 


                              34


through December 1996 DSM expenditures, increasing annual revenue
by approximately $9 million.  On October 30, 1998, the Company
updated its June 1998 request for 1997 DSM expenditures to
incorporate provisions of the Commission's September 3, 1998,
decision, which would increase annual revenue by approximately $3
million.

Federal - Wholesale
-------------------

     As discussed in the June 30, 1998 Form 10-Q, the Company has
a rolling-10-year power supply contract with SMECO, a wholesale
customer with a peak load of about 600 megawatts, to supply
SMECO's entire electricity requirements.  SMECO issued a request
for proposals early in 1998.  The Company is currently
negotiating with SMECO to establish rates for the future which
could result in a new full-requirements agreement.

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.  Presently, the Company has
agreements for installed capacity sales through December 31,
1998, totaling 271 megawatts.  Revenues from capacity and
bilateral energy transactions totaled approximately $35.2
million, $54.3 million and $57.1 million for the three, nine and
twelve months ended September 30, 1998, respectively, and $1.6
million, $8.3 million and $8.9 million for the corresponding
periods in 1997, and are included as components of interchange
deliveries. 

     The Company continues to purchase energy from Ohio Edison
under the Company's 1987 long-term capacity purchase agreement
with Ohio Edison and Allegheny Energy, Inc. (AEI).  The Company
is purchasing energy from the Panda facility, pursuant to a
25-year power purchase agreement for 230 megawatts of capacity 
supplied by a gas-fueled combined-cycle cogenerator.  The Company
also purchases energy from the Northeast Maryland Waste Disposal
Authority under an avoided cost-based purchase agreement.  


                              35


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

     See the discussion of the Restructuring of the Bulk Power
Market under Item 1 - Business of the Company's 1997 Form 10-K.

COMPETITION
-----------

Maryland
--------

     The Company is currently engaged in regulatory proceedings
in Maryland where the Public Service Commission has outlined
steps and established dates for the phase-in implementation of
competition.  

     As discussed in the June 30, 1998 Form 10-Q, on July 1,
1998, the Company filed with the Commission (1) a quantification
of its Maryland jurisdictional generating, purchased power and
other costs that the Company projects would be stranded in a
competitive market for generating services; (2) a proposed method
for recovering such stranded costs through a non-bypassable
Competitive Transition Charge; (3) proposed unbundled rates for
retail service; and (4) a proposal to freeze retail rates from
the time competition begins until January 2004.  This filing was
made in compliance with Orders issued by the Commission in
December 1997 that established a process for implementing retail
competition and provided for the phase-in of customer choice for
generation supply service beginning in July 2000 and ending with
all customers having choice in July 2002.  The Company made
numerous assumptions in the filing, including assumptions as to
the outcome of its pending base rate case before the Commission,
the future price of electricity including fuel charges, future
revenues, the cost of transmission and distribution, and service
territory demographics, some or all of which may prove not to
have been accurate.  This filing will be the subject of an
adjudicatory proceeding which is expected to conclude in
October 1999.  In connection with the filing, the Company
reiterated its position that absent appropriate enabling
legislation by the Maryland General Assembly, the Commission
lacks the legal authority to implement the plan filed by the
Company, or any other restructuring plan providing for retail
competition.

     The Commission's implementation process provides for a
15-month period to study the filing.  After that period, the
Company will be required to file a restructuring plan in November
1999 which would take into account any restructuring legislation
enacted by the General Assembly, as well as the outcome of the
adjudicatory proceeding initiated by the Commission with respect
to the filing.  Accordingly, the filing does not constitute the
Company's final restructuring plan.


                              36


     If a competitive market for generation supply is implemented
in Maryland, the Company assumes that the Commission will follow
through on its commitment to provide a fair opportunity for the
Company to recover its prudently incurred stranded costs (the
total economic value of previously expected regulatory earnings
that will not be recovered in a deregulated energy market, having
a net after-tax present value of $600.4 million) and that the
stranded costs identified by the Company in the filing will be
determined to have been prudently incurred.  The inability of the
Company to recover fully its stranded costs could have a material
adverse impact on the future earnings and cash flows of the
Company, and may result in consequences including, but not
limited to, increases in the cost of capital, increases in rates
for transmission and distribution services, exposure to
downgrades in credit ratings and involuntary layoffs of
employees.

     On October 9, 1998, the Company and four other electric
utilities operating in Maryland - Allegheny Power, Choptank
Electric Cooperative, Inc., Conectiv and SMECO - filed separate
appeals in Baltimore City Circuit Court seeking a judicial review
of recent decisions by the Maryland Commission in which the
Commission asserted its authority to restructure the electric
utility industry without authorization from the state
legislature.  The Company believes that the proper way to ensure
progress is for the legislature, in its 1999 session, to grant
the Commission authority to proceed.  Accordingly, the utilities
have asked the court to defer action on the appeal until after
completion of the 1999 legislative session, which begins in
January 1999.  The appeal complies with current state law that
allows a party to a Commission order only 30 days to appeal;
otherwise, the decision is final and not subject to court review.

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

     In September 1996, the District of Columbia Public Service
Commission issued an order designating the issues to be examined
regarding electric industry structure and competition.  The
Company filed comments on the designated issues in early 1997,
and on August 31, 1998, the Commission Staff issued its proposal
for bringing choice of electric suppliers to District of Columbia
customers.  The Staff's proposal is currently under the review of
the full Commission, which may ultimately reach different
conclusions.  Pursuant to the Staff's recommendation, competition
would be phased in over a two-year period beginning January 1,
2001.  Customers representing one-fifth of the electric load in a
particular customer class would be able to choose their electric
generation supplier at that time.  On January 1, 2002, the
eligible group increases to one-half of any one customer class,
and all customers will then become eligible one year later.  The
Staff proposed the establishment of working groups to address
issues such as conservation, environmental compliance, consumer 


                             37


protection, provision of universal service, supplier
certification, and the need for legislation to pave the way for
choice.  More difficult issues such as the design of unbundled
rates and stranded cost estimation and recovery would be
addressed in future adjudicatory proceedings.  The Company
expects that the full Commission will issue an order in the near
future in response to the Staff report.  Although not currently
required to do so, the Company intends to file a restructuring
plan related to its District of Columbia service territory by the
end of 1998. 

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

Peak Load and Sales Data
------------------------
     
     Kilowatt-hour sales increased 7.1%, 3.7% and 3.4% for the
three, nine and twelve months ended September 30, 1998, compared
to sales in the corresponding periods of 1997.  Although weather,
as measured in cooling degree hours, in the second and third
quarters of 1998 was 18% hotter than in 1997, it was
nevertheless, 7% cooler than the 20-year average.  Weather in the
first quarter of 1998 was 4% milder than the first quarter of
1997 and 17% milder than the 20-year average.  Assuming future
weather conditions approximate historical averages, the Company
expects its compound annual growth in kilowatt-hour sales to be
approximately 2% over the next decade.

     On June 26, 1998, the Company established an all-time summer
peak demand of 5,807 megawatts.  This compares with the 1997
summer peak demand of 5,689 megawatts, and the prior all-time
summer peak demand of 5,769 megawatts, which occurred in July
1991.  The Company's present generation capability, excluding
short-term capacity transactions, is 6,806 megawatts.  At the
time of the 1998 summer peak demand, the Company's energy use
management programs had the capability of reducing system demand
by an additional 242 megawatts.  Based on average weather
conditions, the Company estimates that its peak demand will grow
at a compound annual rate of approximately 2%, reflecting
anticipated service area growth trends. The 1997-1998 winter
season peak demand of 4,076 megawatts was 18.6% below the
all-time winter peak demand of 5,010 megawatts which was
established in January 1994.


                              38


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

     On September 16, 1998, the Company received permission from
the Maryland Public Service Commission to decrease the DSM
surcharge effective with bills rendered on and after September
21, 1998, which will reduce annual revenue by approximately $3
million.  The reduction in the surcharge rate reflects a decline
in the costs and scale of Maryland DSM programs.  The Company
invested approximately $3.1 million, $13 million and $18.9
million in Maryland DSM programs for the three, nine and twelve
months ended September 30, 1998, respectively, and $5.4 million,
$18.2 million and $24.1 million for corresponding periods in
1997.  The surcharge mechanism includes a provision for the
recovery of program cost amortization and permits the Company to
earn a return on its conservation investment while receiving
compensation for lost revenue.  In addition, when energy savings
exceed annual goals, the Company earns a performance bonus.  The
Company was awarded a bonus of $1.3 million in 1998, based on
1997 performance, which followed a bonus of $1.6 million in 1997,
based on 1996 performance.  The surcharge tariff is revised each
year.  Beginning with the 1998 surcharge update, the program cost
amortization period will be successively reduced to reflect the
following:  1998 program costs will be amortized over four years;
1999 program costs will be amortized over three years; 2000
program costs will be amortized over two years; and 2001 and
subsequent program costs will be amortized over one year.  In
addition, the performance bonus provision of the surcharge
relative to future energy saving goals will no longer apply.

     Investment in District of Columbia DSM programs totaled
approximately $3.2 million, $4.5 million and $5.9 million for the
three, nine and twelve months ended September 30, 1998,
respectively, and $1.6 million, $3.7 million and $6.8 million for
the corresponding periods in 1997.  These DSM costs are amortized
over ten years with an accrued return on unamortized costs.  In
June 1997, the Company filed an Application for Authority with
the District of Columbia Commission to update the ECRR surcharge
tariff to recover actual DSM expenditures incurred during the
period January 1995 through December 1996.  The ECRR surcharge
includes both a conservation expenditure component and a
component for recovering certain costs associated with complying
with the CAA amendments of 1990.  The conservation component is
scheduled to be updated annually on June 1 of each year, while
the CAA component is updated quarterly.  In a June 1998 filing,
the Company requested that recovery of year 1997 DSM expenditures
also be reflected within the ECRR.  On September 3, 1998, the
Commission approved the Company's June 1997 request for recovery
of the January 1995 through December 1996 DSM expenditures,
increasing annual revenue by approximately $9 million.  On
October 30, 1998, the Company updated its June 1998 request for
1997 DSM expenditures to incorporate provisions of the 


                              39


Commission's September 3, 1998, decision, which would increase
annual revenue by approximately $3 million.  A proposal by the
Company to eliminate DSM programs operated within the District of
Columbia was filed with the Commission in March 1998, and as of
November 11, 1998, a decision is pending.

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

     Construction expenditures, excluding AFUDC and CCRF, are
projected to total $845 million for the five-year period 1998
through 2002, which includes approximately $75 million of
estimated CAA expenditures.  In 1998, construction expenditures
are projected to total $175 million, which includes $10 million
of estimated CAA expenditures.  The Company plans to finance its
construction program primarily through funds provided by
operations.  

     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 Ohio Edison under a 1987 long-term
capacity purchase agreement with Ohio Edison and AEI.  In January
1998, the Company filed a complaint at the FERC challenging the
rate for transmission service being charged by AEI to deliver the
Ohio Edison energy.  The complaint argued that the rate being
charged exceeds the rate that AEI now charges under its Order 888
OATT.  In an order issued October 30, 1998, the FERC declined to
lower AEI's rate for transmission service.  The Company also has
a 25-year agreement with Panda for a 230-megawatt gas-fueled
combined-cycle cogeneration project in Prince George's County,
Maryland.  In addition, the Company continues to purchase
capacity and associated energy from a 32-megawatt municipally
financed resource recovery facility in Montgomery County,
Maryland.  The capacity expense under these agreements, including
an allocation of a portion of Ohio Edison's fixed operating and
maintenance costs, was $36.2 million, $112 million and $153.3
million for the three, nine and twelve months ended September 30,
1998, respectively, compared to $34 million, $103.9 million and
$132.7 million for the three, nine and twelve months ended
September 30, 1997, respectively.  Purchased capacity expenses
are estimated at $144 million for 1998.  Commitments under these
agreements are estimated at $202 million for 1999, $203 million
for 2000, $211 million for 2001, $209 million for 2002 and $210
million for 2003.


                              40  


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

SELECTED NONUTILITY SUBSIDIARY FINANCIAL INFORMATION
----------------------------------------------------

     The Company's wholly owned subsidiary, PCI, was organized in
late 1983 to provide a vehicle to conduct the Company's ongoing
nonutility investment programs and businesses.  The principal
assets of PCI are portfolios of securities and equipment leases,
and to a lesser extent real estate and other investments.  The
$240.7 million securities portfolio, consisting primarily of
fixed rate electric utility preferred stocks, provides PCI with
significant liquidity and flexibility to participate in
additional investment opportunities.  The Company's investment in
PCI was $244.6 million, $227 million and $225.6 million, at
September 30, 1998, December 31, 1997, and September 30, 1997,
respectively.


                              41


<TABLE>
Potomac Capital Investment Corporation
Consolidated Statements of Earnings:
--------------------------------------

<CAPTION>


                                         Three                     Nine                      Twelve
                                      Months Ended              Months Ended              Months Ended
                                      September 30,             September 30,             September 30,
                                 ---------------------     ---------------------     ---------------------
                                   1998         1997         1998         1997         1998         1997
                                 --------     --------     --------     --------     --------     --------

                                                    (In thousands, except per share data)
<S>                              <C>          <C>          <C>          <C>          <C>          <C>
Income
  Leasing activities             $ 15,512     $ 21,305     $ 59,348     $ 57,066     $ 77,866     $ 78,416
  Marketable securities             3,899        5,751       14,925       23,625       19,941       31,800
  Other                            10,478        5,842       28,939       20,679       29,175       20,618
                                 --------     --------     --------     --------     --------     --------
                                   29,889       32,898      103,212      101,370      126,982      130,834
                                 --------     --------     --------     --------     --------     --------

Expenses
  Interest                         13,718       16,482       42,938       53,031       58,866       72,892
  Administrative and general        3,533        3,536       11,685       12,246       12,928       14,340
  Depreciation and
    operating                      11,356       15,379       34,741       44,603       47,599       56,447
  Income tax credit                (2,495)      (3,374)      (2,391)     (24,291)      (9,950)     (29,119)
                                 --------     --------     --------     --------     --------     --------
                                   26,112       32,023       86,973       85,589      109,443      114,560
                                 --------     --------     --------     --------     --------     --------
Net earnings from
  nonutility subsidiary          $  3,777     $    875     $ 16,239     $ 15,781     $ 17,539     $ 16,274
                                 ========     ========     ========     ========     ========     ========

Per share contribution to
  earnings of the Company           $ .03        $ .01        $ .14        $ .13        $ .15        $ .14
                                    =====        =====        =====        =====        =====        =====



                                                            42


</TABLE>

<TABLE>

STATISTICAL DATA
----------------
<CAPTION>

                                             Three Months Ended                  Twelve Months Ended
                                                September 30,                       September 30,
                                      ---------------------------------    -------------------------------------
                                        1998       1997        % Change       1998         1997         % Change
                                      --------   --------      --------    ----------   ----------      --------
  <S>                                 <C>        <C>              <C>      <C>          <C>                <C>
  Revenue from Sales
  ------------------
    of Electricity
    --------------
  (Thousands of Dollars)

    Residential                       $208,073   $185,274         12.3     $  564,882   $  527,885          7.0
    General Service                    394,286    370,409          6.4      1,115,688    1,065,271          4.7
    Large Power Service <F1>            11,701     11,822         (1.0)        35,287       35,452         (0.5)
    Street Lighting                      3,143      3,055          2.9         13,286       12,700          4.6
    Rapid Transit                        8,668      8,444          2.7         29,773       28,529          4.4
    Wholesale                           39,370     36,617          7.5        126,112      122,284          3.1
                                      --------   --------                  ----------   ----------
      System                          $665,241   $615,621          8.1     $1,885,028   $1,792,121          5.2
                                      ========   ========                  ==========   ==========

  Energy Sales
  ------------
  (Millions of KWH)

    Residential                          2,020      1,872          7.9          6,792        6,583          3.2
    General Service                      4,618      4,322          6.8         15,673       15,184          3.2
    Large Power Service <F1>               182        198         (8.1)           685          697         (1.7)
    Street Lighting                         36         37         (2.7)           164          165         (0.6)
    Rapid Transit                          117        113          3.5            422          408          3.4
    Wholesale                              757        674         12.3          2,697        2,539          6.2
                                      --------   --------                  ----------   ----------
      System                             7,730      7,216          7.1         26,433       25,576          3.4
                                      ========   ========                  ==========   ==========

  Average System Revenue
  ----------------------
    per KWH (cents per KWH)               8.61       8.53          0.9           7.13         7.01          1.7
    -----------------------

  System Peak Demand <F2>
  ------------------
  (Thousands of KW)

    Summer                                   -          -                       5,807        5,689
    Winter                                   -          -                       4,076        4,632

  Net Generation
  --------------
  (Millions of KWH)                      6,792      5,469                      21,012       17,614

  Fuel Mix (% of Btu)
  -------------------
    Coal (%)                                74         88                          84           90
    Oil (%)                                 21          5                          13            5
    Gas (%)                                  5          7                           3            5

  Fuel Cost per MBtu
  ------------------
    System Average                       $1.72      $1.81                       $1.77        $1.82

  Weather Data
  ------------
    Heating Degree Days                      4         14                       3,671        3,876
    20 Year Average                         22                                  4,007
    Cooling Degree Hours                 7,573      6,526                      10,442        8,542
    20 Year Average                      8,201                                 10,966

     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).
<FN>

<F1> Large Power Service customers are served at a voltage of 66KV or higher.
<F2> At September 30, 1998, the net generation capability, excluding short-term capacity transactions,
     was 6,806 MW.
</FN>


                                                            43
</TABLE>



Item 6   EXHIBITS AND REPORTS ON FORM 8-K
------   --------------------------------

         (a)  Exhibits
    
              Exhibit 3    -   By-Laws.

              Exhibit 11   -   Computations of Earnings Per 
                               Common Share - 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
 
              A Current Report on Form 8-K was filed by the
              Company on July 1, 1998, summarizing the Company's
              filing of stranded costs and unbundled rates for
              retail competition, submitted in compliance with
              orders previously issued by the Maryland Public
              Service Commission.  The item reported on such Form
              8-K was Item 5 (Other Events). 



                              44     


                           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       /s/ D. R. Wraase      
                             ------------------------------
                                    (D. R. Wraase)
                                Senior Vice President and 
                                  Chief Financial Officer


November 12, 1998 
-----------------
      DATE




                              45                            


Exhibit 11     Computations of Earnings Per Common Share
----------     -----------------------------------------

     See the information included in Note (3) of the Notes to
Consolidated Financial Statements, Capitalization and Fair Value
of Financial Instruments.






                              46

<TABLE>
Exhibit 12    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, 1998, and for each of the preceding five years, on the basis of
parent company operations only, are as follows.




<CAPTION>
                                                  Twelve
                                                  Months                    For The Year Ended December 31,
                                                   Ended      ---------------------------------------------------------
                                               September 30,
                                                   1998          1997        1996        1995        1994        1993
                                               ------------   ---------   ---------   ---------   ---------   ---------
                                                                                (Thousands of Dollars)

<S>                                                <C>         <C>         <C>         <C>         <C>         <C>
Net income                                         $181,801    $164,749    $220,066    $218,788    $208,074    $216,478
Taxes based on income                               111,745      97,487     135,011     129,439     116,648     107,223
                                               ------------   ---------   ---------   ---------   ---------   ---------

Income before taxes                                 293,546     262,236     355,077     348,227     324,722     323,701
                                               ------------   ---------   ---------   ---------   ---------   ---------

Fixed charges:
  Interest charges                                  150,194     146,703     146,939     146,558     139,210     141,393
  Interest factor in rentals                         23,619      23,616      23,560      23,431       6,300       5,859
                                               ------------   ---------   ---------   ---------   ---------   ---------

Total fixed charges                                 173,813     170,319     170,499     169,989     145,510     147,252
                                               ------------   ---------   ---------   ---------   ---------   ---------

Income before income taxes and fixed charges       $467,359    $432,555    $525,576    $518,216    $470,232    $470,953
                                               ============   =========   =========   =========   =========   =========

Coverage of fixed charges                              2.69        2.54        3.08        3.05        3.23        3.20
                                                       ====        ====        ====        ====        ====        ====


Preferred dividend requirements                     $20,262     $16,579     $16,604     $16,851     $16,437     $16,255
                                               ------------   ---------   ---------   ---------   ---------   ---------


Ratio of pre-tax income to net income                  1.61        1.59        1.61        1.59        1.56        1.50
                                               ------------   ---------   ---------   ---------   ---------   ---------

Preferred dividend factor                           $32,622     $26,361     $26,732     $26,793     $25,642     $24,383
                                               ------------   ---------   ---------   ---------   ---------   ---------

Total fixed charges and preferred dividends        $206,435    $196,680    $197,231    $196,782    $171,152    $171,635
                                               ============   =========   =========   =========   =========   =========
Coverage of combined fixed charges
  and preferred dividends                              2.26        2.20        2.66        2.63        2.75        2.74
                                                       ====        ====        ====        ====        ====        ====




                                                                  47
</TABLE>


<TABLE>
Exhibit 12    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, 1998, and for each of the preceding five years, on a fully
consolidated basis, are as follows.



<CAPTION>

                                                  Twelve
                                                  Months                    For The Year Ended December 31,
                                                   Ended      ---------------------------------------------------------
                                               September 30,
                                                   1998          1997        1996        1995        1994        1993
                                               ------------   ---------   ---------   ---------   ---------   ---------
                                                                                (Thousands of Dollars)

<S>                                                <C>         <C>         <C>          <C>        <C>         <C>
Net income                                         $199,340    $181,830    $236,960     $94,391    $227,162    $241,579
Taxes based on income                               101,795      65,669      80,386      43,731      93,953      62,145
                                               ------------   ---------   ---------   ---------   ---------   ---------

Income before taxes                                 301,135     247,499     317,346     138,122     321,115     303,724
                                               ------------   ---------   ---------   ---------   ---------   ---------

Fixed charges:
  Interest charges                                  209,681     216,156     231,029     238,724     224,514     221,312
  Interest factor in rentals                         23,795      23,687      23,943      26,685       9,938       9,257
                                               ------------   ---------   ---------   ---------   ---------   ---------

Total fixed charges                                 233,476     239,843     254,972     265,409     234,452     230,569
                                               ------------   ---------   ---------   ---------   ---------   ---------

Nonutility subsidiary capitalized interest             (620)       (493)       (649)       (529)       (521)     (2,059)
                                               ------------   ---------   ---------   ---------   ---------   ---------

Income before income taxes and fixed charges       $533,991    $486,849    $571,669    $403,002    $555,046    $532,234
                                               ============   =========   =========   =========   =========   =========

Coverage of fixed charges                              2.29        2.03        2.24        1.52        2.37        2.31
                                                       ====        ====        ====        ====        ====        ====


Preferred dividend requirements                     $20,262     $16,579     $16,604     $16,851     $16,437     $16,255
                                               ------------   ---------   ---------   ---------   ---------   ---------


Ratio of pre-tax income to net income                  1.51        1.36        1.34        1.46        1.41        1.26
                                               ------------   ---------   ---------   ---------   ---------   ---------

Preferred dividend factor                           $30,596     $22,547     $22,249     $24,602     $23,176     $20,481
                                               ------------   ---------   ---------   ---------   ---------   ---------

Total fixed charges and preferred dividends        $264,072    $262,390    $277,221    $290,011    $257,628    $251,050
                                               ============   =========   =========   =========   =========   =========
Coverage of combined fixed charges
  and preferred dividends                              2.02        1.86        2.06        1.39        2.15        2.12
                                                       ====        ====        ====        ====        ====        ====





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</TABLE>




                                                    Exhibit 15




November 12, 1998






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, 1998, (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,
333-33495 and 333-66127) filed on February 26, 1993, July 28,
1995, August 13, 1997 and October 26, 1998, respectively.  We are
also aware of our responsibilities under the Securities Act of
1933.

Very truly yours,



/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Washington, D.C.





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