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 June 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 June 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...................... 14
Report of Independent Accountants on Review of Interim
Financial Information.................................. 16
Item 2 - Management's Discussion and Analysis of Consolidated
Results of Operations and Financial Condition
Forward Looking Statements............................... 17
Utility
Results of Operations.................................. 18
Capital Resources and Liquidity........................ 23
Nonutility Subsidiary
Results of Operations.................................. 24
Capital Resources and Liquidity........................ 26
New Accounting Standards................................. 27
PART II - Other Information
Item 1 - Legal Proceedings................................. 27
Item 5 - Other Information
Other Financing Arrangements............................. 28
Base Rate Proceedings.................................... 28
Restructuring of the Bulk Power Market................... 30
Competition.............................................. 30
Peak Load, Sales, Conservation, and Construction and
Generating Capacity.................................... 33
Selected Nonutility Subsidiary Financial Information..... 36
Statistical Data......................................... 38
Item 6 - Exhibits and Reports on Form 8-K.................. 39
Signatures................................................. 40
Computations of Earnings Per Common Share.................. 41
Computation of Ratios - Parent Company Only................ 42
Computation of Ratios - Fully Consolidated................. 43
Independent Accountants Awareness Letter................... 44
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
Six Months Ended Twelve Months Ended
June 30,
June 30, June 30,
--------------------
- --------------------- ----------------------
1998 1997
1998 1997 1998 1997
--------- ---------
- --------- ---------- ---------- ----------
(Thousands of
Dollars except Per Share Data)
<S> <C> <C> <C>
<C> <C> <C>
Revenue
Sales of electricity $ 476,879 $ 437,924 $
843,185 $ 807,577 $1,835,408 $1,788,739
Other electric revenue 2,489 1,631
6,026 6,464 10,591 12,182
--------- ---------
- --------- ---------- ---------- ----------
Total Operating Revenue 479,368 439,555
849,211 814,041 1,845,999 1,800,921
Interchange deliveries 49,151 11,416
59,697 25,990 86,388 111,048
--------- ---------
- --------- ---------- ---------- ----------
Total Revenue 528,519 450,971
908,908 840,031 1,932,387 1,911,969
--------- ---------
- --------- ---------- ---------- ----------
Operating Expenses
Fuel 92,727 78,195
174,742 156,702 337,659 316,976
Purchased energy 73,556 44,376
113,984 95,450 219,096 270,932
Capacity purchase payments 38,615 36,781
78,577 72,725 156,765 133,649
Other operation 57,443 53,296
113,405 105,132 228,562 216,476
Maintenance 24,267 23,907
44,279 45,080 94,451 93,910
--------- ---------
- --------- ---------- ---------- ----------
Total Operation and Maintenance 286,608 236,555
524,987 475,089 1,036,533 1,031,943
Depreciation and amortization 58,854 56,801
117,676 114,401 235,317 227,340
Income taxes 35,811 27,763
37,299 33,058 121,972 121,164
Other taxes 51,504 49,232
97,333 94,641 204,411 199,611
--------- ---------
- --------- ---------- ---------- ----------
Total Operating Expenses 432,777 370,351
777,295 717,189 1,598,233 1,580,058
--------- ---------
- --------- ---------- ---------- ----------
Operating Income 95,742 80,620
131,613 122,842 334,154 331,911
--------- ---------
- --------- ---------- ---------- ----------
Other Income (Loss)
Nonutility Subsidiary
Income 37,260 28,665
73,323 68,472 129,991 134,342
Expenses, including interest
and income taxes (31,116) (27,209)
(60,861) (53,566) (115,354) (114,057)
--------- ---------
- --------- ---------- ---------- ----------
Net earnings from nonutility
subsidiary 6,144 1,456
12,462 14,906 14,637 20,285
Allowance for other funds used during
construction and capital cost recovery factor 230 1,681
480 3,341 3,847 6,516
Write-off of merger costs - -
- - (52,533) -
Other, net 1,219 1,638
2,037 2,324 23,734 3,414
--------- ---------
- --------- ---------- ---------- ----------
Total Other Income (Loss) 7,593 4,775
14,979 20,571 (10,315) 30,215
--------- ---------
- --------- ---------- ---------- ----------
Income Before Utility Interest Charges 103,335 85,395
146,592 143,413 323,839 362,126
--------- ---------
- --------- ---------- ---------- ----------
Utility Interest Charges
Long-term debt 34,179 34,104
68,606 68,847 135,325 135,228
Distributions on preferred securities
of subsidiary company 1,076 -
1,076 - 1,076 -
Other 3,230 3,406
5,730 5,505 11,362 11,448
Allowance for borrowed funds used during
construction and capital cost recovery factor (1,119) (2,239)
(2,321) (4,045) (6,148) (7,630)
--------- ---------
- --------- ---------- ---------- ----------
Net Utility Interest Charges 37,366 35,271
73,091 70,307 141,615 139,046
--------- ---------
- --------- ---------- ---------- ----------
Net Income 65,969 50,124
73,501 73,106 182,224 223,080
Dividends on preferred stock 3,395 4,137
7,535 8,282 15,831 16,590
Redemption premium on preferred stock 6,579 -
6,579 - 6,579 -
--------- ---------
- --------- ---------- ---------- ----------
Earnings for Common Stock 55,995 45,987
59,387 64,824 159,814 206,490
Retained Income at Beginning of Period 690,175 730,197
734,318 760,285 728,241 711,726
Dividends on Common Stock (49,164) (49,156)
(98,322) (98,304) (196,632) (196,610)
Subsidiary Marketable Securities, Net
Unrealized (Loss) Gain, Net of Tax (435) 1,213
1,188 1,436 5,148 6,635
--------- ---------
- --------- ---------- ---------- ----------
Retained Income at End of Period $ 696,571 $ 728,241 $
696,571 $ 728,241 $ 696,571 $ 728,241
========= =========
========= ========== ========== ==========
Basic Average Common Shares
Outstanding (000's) 118,527 118,500
118,519 118,500 118,510 118,499
Basic Earnings Per Common Share $0.47 $0.39
$0.50 $0.55 $1.35 $1.74
Diluted Average Common Shares
Outstanding (000's) 124,245 124,292
118,527 121,927 124,268 124,319
Diluted Earnings Per Common Share $0.46 $0.38
$0.50 $0.55 $1.34 $1.71
Cash Dividends Per Common Share $0.415 $0.415
$0.83 $0.83 $1.66 $1.66
Book Value Per Share
$15.41 $15.67
Dividend Payout Ratio
123.0% 95.4%
Effective Federal Income Tax Rate
30.0% 25.2%
2
</TABLE>
<TABLE>
POTOMAC ELECTRIC POWER COMPANY
Consolidated Balance Sheets
(Unaudited at June 30, 1998 and 1997)
-------------------------------------
<CAPTION>
June 30,
December 31, June 30,
ASSETS 1998
1997 1997
------ -------------
------------- -------------
(Thousands of Dollars)
<S> <C>
<C> <C>
Property and Plant - at original cost
Electric plant in service $ 6,471,501
$ 6,392,750 $ 6,299,044
Construction work in progress 65,020
94,309 78,450
Electric plant held for future use 4,274
4,231 4,190
Nonoperating property 40,685
22,824 22,976
-------------
------------- -------------
6,581,480
6,514,114 6,404,660
Accumulated depreciation (2,073,537)
(2,027,780) (1,961,519)
-------------
------------- -------------
Net Property and Plant 4,507,943
4,486,334 4,443,141
-------------
------------- -------------
Current Assets
Cash and cash equivalents 13,185
5,630 7,640
Customer accounts receivable, less allowance
for uncollectible accounts of $2,280, $2,102
and $661 149,684
116,554 164,006
Other accounts receivable, less allowance for
uncollectible accounts of $300 41,029
32,256 29,633
Accrued unbilled revenue 122,165
69,259 94,973
Prepaid taxes 1,347
33,740 105
Other prepaid expenses 7,652
7,599 6,892
Material and supplies - at average cost
Fuel 46,820
59,434 63,834
Construction and maintenance 68,860
68,128 67,931
-------------
------------- -------------
Total Current Assets 450,742
392,600 435,014
-------------
------------- -------------
Deferred Charges
Income taxes recoverable through future rates, net 236,409
238,125 239,435
Conservation costs, net 212,259
221,528 229,010
Unamortized debt reacquisition costs 51,341
52,745 54,149
Other 160,716
148,900 171,758
-------------
------------- -------------
Total Deferred Charges 660,725
661,298 694,352
-------------
------------- -------------
Nonutility Subsidiary Assets
Cash and cash equivalents 3,193
422 19,111
Marketable securities 240,811
302,522 289,293
Investment in finance leases 442,908
463,592 486,049
Operating lease equipment, net of accumulated
depreciation of $108,919, $153,541 and $137,492 114,026
163,289 179,337
Receivables, less allowance for uncollectible
accounts of $6,000 39,590
64,243 47,981
Other investments 169,897
162,865 186,906
Other assets 13,420
10,392 17,980
Deferred income taxes 64,538
- -
-------------
------------- -------------
Total Nonutility Subsidiary Assets 1,088,383
1,167,325 1,226,657
-------------
------------- -------------
Total Assets $ 6,707,793
$ 6,707,557 $ 6,799,164
=============
============= =============
CAPITALIZATION AND LIABILITIES
- ------------------------------
Capitalization
Common stock $ 118,527
$ 118,501 $ 118,501
Other common equity 1,708,196
1,744,527 1,738,619
Serial preferred stock 100,000
125,290 125,293
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 1,857,893
1,901,486 1,727,065
-------------
------------- -------------
Total Capitalization 3,959,616
4,030,804 3,850,478
-------------
------------- -------------
Other Non-Current Liabilities
Capital lease obligations 159,046
160,406 161,702
-------------
------------- -------------
Total Other Non-Current Liabilities 159,046
160,406 161,702
-------------
------------- -------------
Current Liabilities
Long-term debt and preferred stock
redemption due within one year 45,000
52,054 100,985
Short-term debt 245,400
131,375 311,600
Accounts payable and accrued expenses 221,340
185,893 158,846
Capital lease obligations due within one year 20,772
20,772 20,772
Other 90,654
92,293 81,710
-------------
------------- -------------
Total Current Liabilities 623,166
482,387 673,913
-------------
------------- -------------
Deferred Credits
Income taxes 1,037,543
1,029,318 1,001,460
Investment tax credits 55,484
57,308 59,133
Other 22,495
19,034 40,561
-------------
------------- -------------
Total Deferred Credits 1,115,522
1,105,660 1,101,154
-------------
------------- -------------
Nonutility Subsidiary Liabilities
Long-term debt 574,095
830,458 912,709
Short-term notes payable 186,780
7,685 -
Deferred taxes and other 89,568
90,157 99,208
-------------
------------- -------------
Total Nonutility Subsidiary Liabilities 850,443
928,300 1,011,917
-------------
------------- -------------
Total Capitalization and Liabilities $ 6,707,793
$ 6,707,557 $ 6,799,164
=============
============= =============
3
</TABLE>
<TABLE>
POTOMAC ELECTRIC POWER COMPANY
Consolidated Statements of Cash Flows
(Unaudited)
-------------------------------------
<CAPTION>
Six
Months Ended Twelve Months Ended
June 30, June 30,
- ----------------------- -----------------------
1998
1997 1998 1997
---------
--------- --------- ---------
(Thousands of Dollars)
<S> <C>
<C> <C> <C>
Operating Activities
Income from utility operations $ 61,039
$ 58,200 $ 167,587 $ 202,795
Adjustments to reconcile income to net
cash from operating activities:
Depreciation and amortization 117,676
114,401 235,317 227,340
Deferred income taxes and investment tax credits 7,390
25,350 42,583 95,354
Deferred conservation costs
(13,503) (17,752) (30,294) (40,191)
Allowance for funds used during construction
and capital cost recovery factor
(2,801) (7,386) (9,995) (14,146)
Changes in materials and supplies 11,882
6,008 16,085 18,341
Changes in accounts receivable and accrued unbilled revenue
(94,809) (51,308) (24,266) 34,242
Changes in accounts payable
(18,141) (20,405) 9,998 (22,456)
Changes in other current assets and liabilities 85,226
29,630 51,791 (5,734)
Changes in deferred merger costs -
(8,064) 37,073 (28,116)
Net other operating activities
(14,604) (9,796) (51,501) (31,562)
Nonutility subsidiary:
Net earnings 12,462
14,906 14,637 20,285
Deferred income taxes
(65,394) (25,612) (103,541) (25,723)
Changes in other assets and net other operating activities 34,207
33,866 66,079 36,065
---------
--------- --------- ---------
Net Cash From Operating Activities 120,630
142,038 421,553 466,494
---------
--------- --------- ---------
Investing Activities
Total investment in property and plant
(104,834) (99,554) (237,025) (201,658)
Allowance for funds used during construction
and capital cost recovery factor 2,801
7,386 9,995 14,146
---------
--------- --------- ---------
Net investment in property and plant
(102,033) (92,168) (227,030) (187,512)
Nonutility subsidiary:
Purchase of marketable securities
(500) (23,133) (12,470) (31,561)
Proceeds from sale or redemption of marketable securities 65,947
119,472 71,475 169,758
Investment in leased equipment -
(7,480) - (7,480)
Proceeds from sale or disposition of leased equipment 61,289
- 89,773 -
Proceeds from sale of assets -
4,900 2,400 9,415
Purchase of other investments
(16,310) (19,293) (17,620) (40,295)
Proceeds from sale or distribution of other investments 3,074
5,559 16,245 37,822
Proceeds from promissory notes, net -
52,980 11,128 62,155
---------
--------- --------- ---------
Net Cash From (Used By) Investing Activities 11,467
40,837 (66,099) 12,302
---------
--------- --------- ---------
Financing Activities
Dividends on common stock
(98,322) (98,304) (196,632) (196,610)
Dividends on preferred stock
(7,535) (8,282) (15,831) (16,590)
Redemption of preferred stock
(123,628) (1,500) (123,628) (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) (101,460) (101,071) (101,480)
Short-term debt, net 114,025
180,210 (66,200) (15,915)
Other financing activities
(2,974) (2,683) (9,808) (5,467)
Nonutility subsidiary:
Issuance of long-term debt 23,031
- 63,031 105,000
Repayment of long-term debt
(279,394) (83,523) (401,645) (174,052)
Short-term debt, net 179,095
(51,650) 186,780 (159,333)
---------
--------- --------- ---------
Net Cash Used By Financing Activities
(121,771) (159,102) (365,827) (458,357)
---------
--------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents 10,326
23,773 (10,373) 20,439
Cash and Cash Equivalents at Beginning of Period 6,052
2,978 26,751 6,312
---------
--------- --------- ---------
Cash and Cash Equivalents at End of Period $ 16,378
$ 26,751 $ 16,378 $ 26,751
=========
========= ========= =========
Cash paid for interest (net of capitalized interest) and income taxes:
Interest (including nonutility subsidiary
interest of $33,470, $37,275, $67,687 and $76,982) $ 101,563
$ 103,712 $ 200,605 $ 208,791
Income taxes (including nonutility subsidiary) $
(6,866) $ 1,826 $ 9,860 $ 27,750
4
</TABLE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- ------------------------------------------
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 $65.5 million, $74.7 million and
$187.4 million for the three, six and twelve months ended June
30, 1998, compared to $51.3 million, $74.5 million and $229.7
million in the corresponding periods ended June 30, 1997.
5
<TABLE>
(2) INCOME TAXES
- ----------------
Provision for Income Taxes
- --------------------------
<CAPTION>
Three Months Ended
Six Months Ended Twelve Months Ended
June 30,
June 30, June 30,
-----------------------
---------- ----------- ---------------------
1998 1997
1998 1997 1998 1997
---------- ----------
--------- --------- --------- ---------
(Thousands of Dollars)
<S> <C> <C>
<C> <C> <C> <C>
Utility current tax expense
Federal $ 31,207 $ 13,125
$ 27,707 $ 6,683 $ 53,277 $ 22,166
State and local 3,594 1,802
2,528 952 6,267 2,886
---------- ----------
---------- --------- ---------- ---------
Total utility current tax expense 34,801 14,927
30,235 7,635 59,544 25,052
---------- ----------
---------- --------- ---------- ---------
Utility deferred tax expense
Federal 1,062 12,123
6,610 23,525 39,363 86,799
State and local 1,024 1,866
2,604 3,650 6,869 12,204
Investment tax credits (912) (912)
(1,824) (1,825) (3,649) (3,649)
---------- ----------
---------- --------- ---------- ---------
Total utility deferred tax expense 1,174 13,077
7,390 25,350 42,583 95,354
---------- ----------
---------- --------- ---------- ---------
Total utility income tax expense 35,975 28,004
37,625 32,985 102,127 120,406
---------- ----------
---------- --------- ---------- ---------
Nonutility subsidiary current tax expense
Federal 13,867 (4,055)
28,108 3,151 55,378 (6,062)
Nonutility subsidiary deferred tax expense
Federal (13,299) (3,880)
(28,004) (24,068) (66,207) (24,152)
---------- ----------
---------- --------- ---------- ---------
Total nonutility subsidiary income tax expense 568 (7,935)
104 (20,917) (10,829) (30,214)
---------- ----------
---------- --------- ---------- ---------
Total consolidated income tax expense 36,543 20,069
37,729 12,068 91,298 90,192
Income taxes included in other income 732 (7,694)
430 (20,990) (30,674) (30,972)
---------- ----------
---------- --------- --------- ---------
Income taxes included in utility operating expenses $ 35,811 $ 27,763
$ 37,299 $ 33,058 $ 121,972 $ 121,164
========== ==========
========== ========= ========= =========
6
</TABLE>
<TABLE>
Reconciliation of Consolidated Income Tax Expense
- -------------------------------------------------
<CAPTION>
Three Months Ended
Six Months Ended Twelve Months Ended
June 30,
June 30, June 30,
-----------------------
---------- ----------- ---------------------
1998 1997
1998 1997 1998 1997
---------- ----------
--------- --------- --------- ---------
(Thousands of Dollars)
<S> <C> <C>
<C> <C> <C> <C>
Income before income taxes $ 102,512 $ 70,193
$ 111,230 $ 85,174 $ 273,522 $ 313,272
========== ==========
========== ========= ========== =========
Utility income tax at federal
statutory rate $ 33,529 $ 26,836
$ 34,532 $ 31,915 $ 94,400 $ 113,120
Increases (decreases) resulting from
Depreciation 2,764 2,522
5,529 5,044 11,338 9,826
Removal costs (2,030) (1,794)
(3,289) (3,186) (6,005) (5,282)
Allowance for funds used during
construction 221 160
434 365 928 776
Other (599) (1,192)
(1,093) (2,319) (3,205) (3,961)
State income taxes, net of federal effect 3,002 2,384
3,336 2,991 8,539 9,808
Tax credits (912) (912)
(1,824) (1,825) (3,868) (3,881)
---------- ----------
---------- --------- ---------- ---------
Total utility income tax expense 35,975 28,004
37,625 32,985 102,127 120,406
---------- ----------
---------- --------- ---------- ---------
Nonutility subsidiary income tax at federal
statutory rate 2,349 (2,268)
4,398 (2,104) 1,333 (3,475)
Decreases resulting from
Dividends received deduction (1,123) (1,196)
(2,358) (2,718) (5,059) (3,788)
Reversal of previously accrued deferred taxes - -
- (10,125) - (12,230)
Other (658) (4,471)
(1,936) (5,970) (7,103) (10,721)
---------- ----------
---------- --------- ---------- ---------
Total nonutility subsidiary income tax expense 568 (7,935)
104 (20,917) (10,829) (30,214)
---------- ----------
---------- --------- ---------- ---------
Total consolidated income tax expense 36,543 20,069
37,729 12,068 91,298 90,192
Income taxes included in other income 732 (7,694)
430 (20,990) (30,674) (30,972)
---------- ----------
---------- --------- ---------- ---------
Income taxes included in utility operating expenses $ 35,811 $ 27,763
$ 37,299 $ 33,058 $ 121,972 $ 121,164
========== ==========
========== ========= ========== =========
7
</TABLE>
<TABLE>
Components of Consolidated Deferred Tax Liabilities (Assets)
- ------------------------------------------------------------
<CAPTION>
June 30, Dec. 31,
June 30,
1998 1997
1997
---------- ----------
---------
(Thousands of
Dollars)
<S> <C> <C>
<C>
Utility deferred tax liabilities (assets)
Depreciation and other book to tax
basis differences $ 886,589 $ 869,343
$ 845,159
Rapid amortization of certified pollution
control facilities 25,005 25,445
24,036
Deferred taxes on amounts to be collected
through future rates 89,505 90,154
90,650
Property taxes 13,623 13,525
13,094
Deferred fuel (8,098) (7,369)
(14,964)
Prepayment premium on debt retirement 19,431 19,962
20,493
Deferred investment tax credit (21,006) (21,697)
(22,388)
Contributions in aid of construction (30,367) (30,054)
(29,176)
Contributions to pension plan 18,157 18,157
16,170
Conservation costs (demand side management) 46,169 48,041
45,764
Other 15,254 21,683
22,218
---------- ----------
----------
Total utility deferred tax liabilities, net 1,054,262 1,047,190
1,011,056
Current portion of utility deferred tax liabilities
(included in Other Current Liabilities) 16,719 17,872
9,596
---------- ----------
----------
Total utility deferred tax liabilities, net -
non-current $1,037,543 $1,029,318
$1,001,460
========== ==========
==========
Nonutility subsidiary deferred tax liabilities
(assets)
Finance leases $ 115,181 $ 119,448
$ 140,216
Operating leases 10,312 28,823
39,861
Alternative minimum tax (97,109) (97,109)
(97,109)
Assets with a tax basis greater than book basis (39,103) -
-
Other (53,819) (50,947)
(46,739)
---------- ----------
----------
Total nonutility subsidiary deferred tax liabilities
(assets), net $ (64,538) $ 215
$ 36,229
========== ==========
==========
8
</TABLE>
(3) CAPITALIZATION AND FAIR VALUE OF FINANCIAL INSTRUMENTS
------------------------------------------------------
Common Equity
- -------------
At June 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 June 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 $123.6 million and includes $6.6 million in premiums.
At June 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 June 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 June 30, 1998, the Company had outstanding one million
shares of its Serial Preferred Stock, Auction Series A. The
annual dividend rate is 4.1% ($2.05) for the period June 1, 1998,
through August 31, 1998. For the period March 1, 1998, through
May 31, 1998, the annual dividend rate was 4.087% ($2.0435). The
average rate at which dividends were paid during the twelve
months ended June 30, 1998, was 4.26% ($2.13).
9
At June 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.
On May 19, 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 the three series
of preferred stock on June 1, 1998. The Company's obligation
under the declaration, including its obligation to pay costs,
expenses, debt and liabilities of the Trust, provides a full and
unconditional guarantee on a subordinated basis of amounts
payable on the TOPrS. The Trust is a subsidiary of the Company,
and accordingly is consolidated in the Company's financial
statements.
10
The estimated fair values of the Company's financial
instruments at June 30, 1998, are summarized below:
Carrying Fair
Amount Value
---------- ----------
(Thousands of Dollars)
Utility
Capitalization and Liabilities
Serial preferred stock $ 100,000 $ 94,523
========== ==========
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 $ 126,250
========== ==========
Long-term debt
First mortgage bonds (net of
unamortized premium and
discount of $13,900) $1,407,900 $1,462,589
Medium-term notes (net of
unamortized discount of $1,833) 281,257 290,075
Convertible debentures (net of
unamortized discount of $9,100) 168,736 176,061
---------- ----------
Total long-term debt $1,857,893 $1,928,725
========== ==========
Nonutility Subsidiary
Assets
Marketable securities (primarily
mandatorily redeemable preferred
stock) $ 240,811 $ 240,811
========== ==========
Notes receivable $ 26,120 $ 22,809
========== ==========
Liabilities
Long-term debt $ 574,095 $ 578,909
========== ==========
At June 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.
11
Nonutility Subsidiary Long-Term Debt
- ------------------------------------
Long-term debt at June 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 7.69% at June 30, 1998, 7.48%
at December 31, 1997, and 7.44% at June 30, 1997. Annual
aggregate principal repayments on these borrowings are $37.3
million in 1998, $170 million in 1999, $122.5 million in 2000,
$71.5 million in 2001, $93 million in 2002 and $43.5 million
thereafter. Also included in long-term debt is $36.3 million of
non-recourse debt which is due in monthly installments with final
maturities in 2001, 2002 and 2011.
Nonutility Subsidiary Contractual Maturities
- --------------------------------------------
At June 30, 1998, the contractual maturities for mandatorily
redeemable preferred stock are $3.1 million within one year,
$94.7 million from one to five years, $83.7 million from five to
10 years and $47 million for over 10 years.
12
<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 Six
Months Ended Twelve Months Ended
June 30, June
30, June 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 $55,995 $45,987 $59,387
$64,824 $159,814 $206,490
Add: Dividends paid or accrued on
Convertible Preferred Stock - 4 2
7 9 15
Interest paid or accrued on
Convertible Debentures,
net of related taxes 1,576 1,588 -
<F1> 1,786 6,332 6,388
------- ------- --------
-------- -------- --------
Earnings applicable to common stock,
assuming conversion of convertible
securities $57,571 $47,579 $59,389
$66,617 $166,155 $212,893
======= ======= ========
======== ======== ========
Shares (Denominator):
Average shares outstanding for
computation of basic earnings
per common share 118,527 118,500 118,519
118,500 118,510 118,499
======= ======= ========
======== ======== ========
Average shares outstanding for
diluted computation:
Average shares outstanding 118,527 118,500 118,519
118,500 118,510 118,499
Additional shares resulting from:
Conversion of Serial Preferred
Stock, $2.44 Convertible Series
of 1966 (the "Convertible
Preferred Stock") - 34 8
34 20 35
Conversion of 7% Convertible
Debentures 2,325 2,365 -
<F1> - <F1> 2,345 2,392
Conversion of 5% Convertible
Debentures 3,393 3,393 -
<F1> 3,393 3,393 3,393
------- ------- --------
-------- -------- --------
Average shares outstanding for
computation of diluted
earnings per common share 124,245 124,292 118,527
121,927 124,268 124,319
======= ======= ========
======== ======== ========
Basic earnings per common share $0.47 $0.39 $0.50
$0.55 $1.35 $1.74
Diluted earnings per common share $0.46 $0.38 $0.50
$0.55 $1.34 $1.71
<FN>
<F1>These amounts are not reflected in the computation of diluted EPS
because the effects are antidilutive and would increase diluted EPS.
</FN>
13
</TABLE>
(4) COMMITMENTS AND CONTINGENCIES
-----------------------------
Environmental Contingencies
- ---------------------------
As discussed in the 1997 Form 10-K, 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.
On May 22, 1998 the State of Maryland issued final
regulations entitled "Post RACT Requirements for Nitrogen Oxides
(NOx) Sources (NOx Budget Proposal)" requiring a 65% reduction in
NOx emissions at the Company's Maryland generating units by May
1, 1999. The regulations allow the purchase or trade of NOx
emission allowances to fulfill this obligation. The Company
appealed this regulation to the Circuit Court for Charles County,
Maryland 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. It is unlikely that a market containing NOx
allowances sufficient to ensure compliance will be functioning by
May 1999; presently, only three 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 year 2004. The Company cannot predict the
outcome of this litigation and is evaluating its options in the
event of an adverse decision. The EPA also has issued proposed
rules for reducing interstate transport of ozone. These
provisions also may result in further nitrogen oxides emissions
reductions from the Company's boilers; however, the extent of
reductions and associated costs cannot be predicted at this time.
14
Targeted Severance Plan
- -----------------------
As discussed in the March 31, 1998 Form 10-Q, the Company
has offered a targeted severance plan to 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 at amounts
dependent upon years of service. As of June 30, 1998, 74
employees in the Company's Generation Group participated in the
plan on a voluntary basis, and $3.7 million in severance costs
have been accrued. In the future, the plan will be made
available to employees within the Company's remaining business
units, and additional costs will be accrued as appropriate.
* * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * *
This Quarterly Report on Form 10-Q, including the report of
PricewaterhouseCoopers LLP (on page 16) will automatically be
incorporated by reference in the Prospectuses constituting parts
of the Company's Registration Statements on Forms S-3 (Numbers
33-58810, 33-61379 and 333-33495) and Forms S-8 (Numbers
33-36798, 33-53685, 33-54197, 333-56683 and 333-57221), filed
under the Securities Act of 1933. Such 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.
15
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 June 30, 1998 and 1997, and the related consolidated
statements of earnings and retained income for the three, six and
twelve month periods then ended and the consolidated statements
of cash flows for the six 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.
August 11, 1998
16
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 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.
17
YEAR 2000 COMPLIANCE
The Company has implemented a 4-phase approach to
accommodate the Year 2000. The phases being addressed are:
Corporate Application Compliance, which includes all large core
business systems; Business Partners' Systems and Vendor System
Verification, which is intended to monitor suppliers' compliance
with Year 2000 processing; End-user Computing Systems, which are
all systems which are not considered core business systems but
contain date calculations; and Non-Information Technology
Processes, which include all operating and control systems. A
database has been developed to identify and track the progress of
work on each phase. The preliminary target date for overall
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, six and twelve months
ended June 30, 1998, as compared to the corresponding periods in
1997. The increases in revenue from sales of electricity for the
periods ending June 30, 1998, resulted primarily from increases
in kilowatt-hour sales of 5.7%, 1.7% and 2.3% over the
corresponding periods in 1997. As measured in cooling degree
hours, the weather in the second quarter of 1998 was 26% hotter
than the second quarter of 1997 and 5% cooler than the 20-year
average. Sales in the twelve months ended June 30, 1997, reflect
milder than average weather in each calendar quarter. The
increases in revenues also reflect a 2.6% increase in Maryland
base rates pursuant to a November 1997 settlement agreement,
partially offset by a reduction in the Maryland Demand Side
Management (DSM) surcharge tariff effective June 1997. In the
second quarter of 1997, the Company recorded a $1.6 million bonus
for achieving 1996 energy saving goals under the conservation
incentive provision of the DSM tariff; in the third quarter of
1996, the Company recorded an $8.9 million bonus for achieving
1995 energy saving goals.
Interchange deliveries increased for the three and six
months ended June 30, 1998, as compared to the corresponding
periods in 1997. The increases for the three and six month
periods ended June 30, 1998, reflect changes in levels and prices
of energy delivered to the Pennsylvania-New Jersey-Maryland
Interconnection LLC (PJM) and increases in the levels of
18
bilateral energy transactions under the Company's wholesale power
sales tariff. The decrease for the twelve month period ended
June 30, 1998, reflects the termination in January 1997, pursuant
to FERC Order 888, of purchase-for-resale agreements, where the
Company purchased energy from one party for the purpose of
selling that energy to a third party.
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 has received
point-to-point transmission service revenue, classified as "Other
electric revenue," which totaled $.6 million, $.8 million and
$1.6 million for the three, six and twelve months ended June 30,
1998, and zero, $1.4 million and $1.4 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 a fuel
adjustment clause.
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.
OPERATING EXPENSES
Fuel and purchased energy increased for the three and six
months ended June 30, 1998, as compared to the corresponding
periods ended June 30, 1997. Fuel expense increased for the
three, six and twelve months ended June 30, 1998, as compared to
the corresponding periods in 1997, primarily due to increases of
24.5%, 16.3% and 15.8%, respectively, in net generation. The
increases in purchased energy for the three and six months ended
June 30, 1998, reflect changes in levels and prices of energy
purchased from PJM and other utilities and power marketers. The
decrease in purchased energy for the twelve months ended June 30,
1998, reflects the termination in January 1997, of purchase-for-
resale agreements.
19
The unit fuel costs for the comparative periods ended
June 30, were as follows:
Three Six Twelve
Months Ended Months Ended Months Ended
June 30, June 30, June 30,
------------ ------------ ------------
1998 1997 1998 1997 1998 1997
----- ----- ----- ----- ----- -----
System Average
Fuel Cost per MBTU $1.75 $1.89 $1.77 $1.86 $1.80 $1.82
System average unit fuel cost decreased for the three, six
and twelve months ended June 30, 1998, as compared to the
corresponding periods in 1997, primarily due to decreases in the
cost of coal and residual oil and an increase in the percent of
residual oil's contribution to the fuel mix.
For the twelve month periods ended June 30, 1998 and 1997,
the Company obtained 88% 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, six and
twelve months ended June 30, 1998, as compared to the
corresponding periods in 1997. These increases reflect capacity
payments made under the Panda contract, which commenced January
1, 1997.
Operating expenses other than fuel, purchased energy and
capacity purchase payments increased for the three, six and
twelve months ended June 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 increases in depreciation
and amortization expense associated with additional investment in
property and plant. Increases in these expenses in the three and
six month periods were also due to increases in income taxes
resulting from increased taxable income.
The Company has implemented a 4-phase approach to
accommodate the Year 2000. All of these activities 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 those large core
systems such as Customer Information, Human Resources
20
and General Ledger, for which the Company's Computer
Services Group (CSG) has responsibility. Year 2000
modifications to these systems are being analyzed,
programmed and tested by CSG.
2. Embedded Systems (Non-Information Technology
Processes): This category includes such items as
meters, power plant operating and control systems,
telecommunications and facilities-based equipment
(e.g. elevators). These products are being evaluated
and modified as required by the appropriate end-user
areas. This activity is being conducted in coordination
with the vendors of these products.
3. End-User Computing Systems (Non-Core Business Systems):
Many areas outside of CSG have developed systems, data
bases, spreadsheets, etc. that contain date
calculations. These products are being evaluated and
modified as required by appropriate end-user areas.
4. Business Partners' Systems and Vendor Supply-Chain
Verification: The Company contracts with many vendors
who provide products and services to the Company. The
Company is seeking to obtain Year 2000 assurances from
suppliers. This effort is being jointly undertaken by
the Company's Materials Group and appropriate end-user
areas.
The Corporate Year 2000 Task Force continues to meet
regularly to monitor the status of the efforts of the Company's
assigned staff and contractors in identifying, testing and
remediating Year 2000 related issues. The Task Force is
addressing additional Year 2000 related issues including, but not
limited to, testing procedures and business continuation and
other contingency planning.
As of August 11, 1998, approximately 80% of the 110
corporate Information Technology systems (7,891 programs) have
been re-programmed, and 50% have been regression tested and
placed into production. "Time Machine" testing using a portion
of the mainframe computer system partitioned for Year 2000 full-
cycle testing has commenced. A parallel LAN (local area network)
Year 2000 testing facility has been established.
In conjunction with equipment vendors, evaluation of
available alternatives for many embedded systems has been
undertaken. Many of these evaluations have been completed. The
remainder of the major appraisals are scheduled to be completed
by the end of the third quarter 1998. Remediation activities are
underway for many embedded systems and associated components.
Test scheduling is more complex for embedded systems because of
the difficulty inherent in scheduling power plant outages to
21
accommodate the testing. Much of the testing will be
accomplished in the spring of 1999 during regularly scheduled
outage periods. At that time, at least one typical unit of each
type will be tested, and the requirement for further testing will
be determined. Presently, no Year 2000-impacted processing
components have been identified that cannot be upgraded or
modified within acceptable time frames. The Company is
participating in an Electric Power Research Institute sponsored
consortium of approximately 85 investor-owned utilities to
coordinate vendor contacts and product evaluation. Because many
embedded systems are similar across utilities, this type of
concentrated effort should help to reduce total time expended in
this area and help to ensure that the Company's efforts are
consistent with the efforts and practices of other investor-owned
utilities.
End-user systems comprise a relatively small percentage of
the required modification both in terms of number and
criticality. All of these activities remain on schedule to be
completed in mid-1999.
The Company has sent letters and accompanying Year 2000
surveys to over 1,800 vendors and suppliers. Over 800 responses
have been received as of August 11, 1998. These responses
outline to varying degrees the approaches vendors are undertaking
to resolve Year 2000 issues within their own systems. Follow-up
letters will be sent to those vendors who have not responded or
whose response was inadequate.
The target date for completion of all Year 2000 related
activities remains at mid-1999. This target date may be impacted
by the integration testing plans and scheduled
generation/electric system outage decisions inherent in embedded
system processing.
Major challenges remain in three primary areas:(1)
maintaining sufficient human resources to complete Year 2000
tasks; (2) scheduling integrated testing for many embedded
systems, taking into account planned outages and operational
needs; and (3) completing contingency planning for the variety of
scenarios which might occur. There are two potential areas of
resource constraints. First, as other companies and government
agencies gear up their Year 2000 programs, the competition for
trained personnel (e.g. programmers) is becoming stronger. This
affects both in-house staff as well as contract personnel. As of
August 11, 1998, the Company has been able to continue to operate
effectively in the employment and contracting marketplace, and is
thus far maintaining the required level of resources. Second,
the availability of vendor resources to both complete embedded
system assessments and produce in volume any required component
upgrades may become problematic.
22
Contingency and business continuation planning are in
various stages of development for critical and high-priority
systems. The Company's existing storm response plan and computer
contingency plan are being modified for use in the event of any
Year 2000-related electric service disruption. 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 costs of expected modifications will be approximately
$14 million, and will be charged to expense as incurred; through
June 30, 1998, $3.5 million has been charged to expense.
Approximately $1.3 million and $2.2 million have been expensed in
the three and six months ended June 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
June 30, 1998, an increase of $67.4 million from the investment
at December 31, 1997, and an increase of $176.8 million from the
investment at June 30, 1997. Cash invested in property and plant
construction, excluding AFUDC and CCRF, amounted to $102 million
for the six months ended June 30, 1998, and $227 million for the
twelve months then ended.
At June 30, 1998, the Company's capital structure, excluding
short-term debt, long-term debt due within one year and
nonutility subsidiary debt, consisted of 46.9% long-term debt,
2.5% serial preferred stock, 1.3% redeemable serial preferred
stock, 3.2% Company obligated redeemable preferred securities of
subsidiary trust and 46.1% common equity.
Cash from utility operations, after dividends, was $33.5
million for the six months ended June 30, 1998, and $231.9
million for the twelve months then ended as compared with $12.3
million and $222.7 million, respectively, for the corresponding
periods ended June 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.
23
On May 19, 1998, Potomac Electric Power Company Trust I, of
which the Company owns all of the common securities, issued $125
million of 7-3/8% mandatorily redeemable preferred securities.
See the discussion included in Note (3) of the Notes to
Consolidated Financial Statements, Capitalization and Fair Value
of Financial Instruments, for additional information.
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 $3.89 series of
1991, at $53.89 per share. The redemption totaled $123.6 million
and includes $6.6 million in premiums.
Outstanding utility short-term debt totaled $245.4 million
at June 30, 1998, an increase of $114 million from the $131.4
million outstanding at December 31, 1997, and a decrease of $66.2
million from the $311.6 million outstanding at June 30, 1997.
See the discussion included in Note (3) of the Notes to
Consolidated Financial Statements, Capitalization and Fair Value
of Financial Instruments, for additional information.
The Company increased its Maryland fuel rate by 10.5%
effective March 1, 1998. The Maryland Commission order approving
the increase became final on July 25, 1998.
NONUTILITY SUBSIDIARY
- ---------------------
RESULTS OF OPERATIONS
- ---------------------
PCI's earnings for the three, six and twelve months ended
June 30, 1998, were $6.1 million ($.05 per share), $12.5 million
($.11 per share) and $14.6 million ($.12 per share),
respectively, compared with $1.5 million ($.01 per share), $14.9
million ($.13 per share) and $20.3 million ($.17 per share) for
the same periods ended June 30, 1997. Net earnings for the three
months ended June 30, 1998, increased over the corresponding
period in 1997 primarily as a result of pre-tax gains of $6.3
million ($4.1 million after-tax) realized on sales of aircraft.
The reductions in net earnings for the six and twelve months
ended June 30, 1998, as compared to the same periods in 1997,
were due primarily to 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
after the provision for transaction costs. Reductions in net
earnings for the six and twelve months ended June 30, 1998, from
24
the corresponding periods in 1997 were also due to decreases in
capital gains and dividend income as a result of 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 $22.1 million, $43.8 million
and $83.7 million for the three, six and twelve months ended June
30, 1998, respectively, compared to $14.6 million, $35.8 million
and $80.4 million for the corresponding periods in 1997. The
increases for all three periods ending June 30, 1998, compared to
the corresponding periods in 1997 were primarily due to gains on
sales of a B-747 aircraft and aircraft engines in the first
quarter resulting in pre-tax gains of $2.9 million, and the sale
of a B-747 and MD-82 in the second quarter resulting in pre-tax
gains of $6.3 million. The increases in income from leasing
activities were partially offset by a decrease in rental income
as a result of asset sales and by a decrease in interest income
related to the sale of aircraft notes during 1997. PCI's
marketable securities portfolio contributed pre-tax income of
$6.4 million, $11 million and $21.8 million for the three, six
and twelve months ended June 30, 1998, respectively, compared to
$6.1 million, $17.9 million and $34 million for the corresponding
periods in 1997. These results include net realized gains of $2
million, $2 million and $2.7 million for the three, six and
twelve months ended June 30, 1998, respectively, compared to $.9
million, $6.2 million and $8.1 million for the corresponding
periods in 1997. Securities income also decreased for the six
and twelve months ended June 30, 1998, due to decreases in
dividend income as a result of the reduction in the preferred
stock portfolio.
Other income totaled $8.7 million, $18.5 million and $24.5
million for the three, six and twelve months ended June 30, 1998,
respectively, compared to $7.9 million, $14.8 million and $19.9
million for the corresponding periods in 1997. The increases for
the six and twelve months ended June 30, 1998, over the same
periods in 1997, were primarily a result of a $3.1 million 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 $30.5 million, $60.8 million and $126.2 million
for the three, six and twelve months ended June 30, 1998,
respectively, compared to $35.1 million, $74.5 million and $144.3
million for the corresponding periods in 1997. The decreases
during the three, six and twelve months ended June 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
25
before income taxes for the three, six and twelve months ended
June 30, 1998, also decreased due to reductions in depreciation
and operation expenses resulting from the sale of aircraft.
PCI had income tax expense of $.6 million, $.1 million and
an income tax credit of $10.8 million for the three, six and
twelve months ended June 30, 1998, respectively, compared to
income tax credits of $7.9 million, $20.9 million and $30.2
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 first quarter 1997 joint
venture operations that reduced previously accrued deferred taxes
by $10.1 million.
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 above, 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
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. 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 $240.8 million securities portfolio, consisting
primarily of fixed-rate electric utility preferred stocks.
During the first six months of 1998, PCI had a net reduction in
the cost basis of its marketable securities portfolio of $65.4
million, primarily as the result of calls and acceptance of
tender offers of approximately $65.9 million offset by purchases
of $.5 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.
26
PCI had short-term debt outstanding of $186.8 million at
June 30, 1998, compared to $7.7 million at December 31, 1997 and
no short-term debt outstanding at June 30, 1997. During the
three, six and twelve months ended June 30, 1998, PCI issued
$12.4 million, $23 million and $63 million in long-term debt,
including non-recourse debt, and debt repayments totaled $140.6
million, $279.4 million and $401.6 million, respectively. At
June 30, 1998, PCI had $700 million available under its Medium-
Term Note Program and $400 million of unused bank credit lines.
As of June 30, 1998, PCI has invested $12.5 million of its
total $150 million commitment to Starpower Communications, LLC, a
joint venture with RCN Telecom Services, Inc. of Princeton, N.J.
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.
NEW ACCOUNTING STANDARDS
- ------------------------
In June 1998, the Financial Accounting Standards Board
issued Statement of Financial Accounting Standards (SFAS) No. 133
entitled "Accounting for Derivative Instruments and Hedging
Activities," which is effective for all fiscal quarters of fiscal
years beginning after June 15, 1999. The statement establishes
accounting and reporting standards for derivative instruments and
for hedging activities. An entity is required to recognize, at
fair value, all derivatives as either assets or liabilities on
the statement of financial position, and to recognize changes in
fair value of derivatives on the statement of financial
performance. Presently, the Company's use of derivatives and
hedging activities is insignificant. Accordingly, adoption of
SFAS No. 133 is not expected to have a material impact on the
consolidated financial statements.
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.
27
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 $270 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
- --------
On June 5, 1998, the Company filed a rate increase request
with the Maryland Public Service Commission (PSC) seeking to
increase 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-
Brandywine. These increases result from contractual escalations
and not from increased levels of capacity. Additional items that
make up the 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 PSC
has set a hearing schedule and is expected to issue a decision in
December 1998. Previously, pursuant to a November 1997
settlement agreement, the PSC authorized a $24 million, or 2.6%,
increase in base rate revenue effective with bills rendered on
and after November 30, 1997.
District of Columbia
- --------------------
As discussed in the March 31, 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.
Federal - Wholesale
- -------------------
As discussed in the March 31, 1998 Form 10-Q, the Company
has a 10-year full service power supply contract with Southern
Maryland Electric Cooperative, Inc. (SMECO), a wholesale
28
customer. The contract period is to be extended for an
additional year on January 1 of each year, unless notice is given
by either party of termination of the contract at the end of the
10-year period. The full service obligation can be reduced by
SMECO by up to 20% of its annual requirements with a five-year
advance notice for each such reduction. SMECO has agreed not to
give the Company a notice of reduction or termination of service
prior to December 15, 1998.
On April 7, 1998, SMECO issued a request for proposals for
power supply resources to replace existing requirements purchases
in the event it exercises its rights to reduce purchases from the
Company, pursuant to terms of the existing contract or earlier,
either through negotiated reductions in the required notice
periods or through other means. Under the notice of reduction
provision, SMECO may reduce its obligation to purchase capacity
and energy from the Company by an amount not exceeding 20% per
year of its anticipated total system requirements. Based on its
projected load requirements and with the appropriate five
calendar year notice, SMECO estimates that it could purchase
approximately 150 MW of capacity and associated energy from
market suppliers beginning January 1, 2004. On June 29, 1998,
Pepco Services, Inc., a wholly owned subsidiary of PCI submitted
a proposal to supply firm capacity and associated energy and
ancillary service to SMECO.
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. In January 1997, pursuant
to FERC Order 888, the Company terminated purchase-for-resale
agreements, where the Company purchased energy from one party
(recording a corresponding expense within Purchased energy) for
the purpose of selling that energy to a third party (and
recording corresponding revenue within Interchange deliveries).
Since April 1, 1997, all transmission service in PJM has been
administered by the PJM Office of the Interconnection. In
addition to interchange with PJM, the Company is actively
participating in the emerging bilateral energy sales marketplace.
The Company's wholesale power sales tariff allows both sales from
Company-owned generation and sales of energy purchased by the
Company from other market participants. Numerous utilities and
marketers have executed service agreements allowing them to
arrange purchases under this 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 238
megawatts. Revenues from capacity and bilateral energy
transactions totaled approximately $15.5 million, $19.1 million
29
and $23.6 million for the three, six and twelve months ended June
30, 1998, respectively, and $.9 million, $6.7 million and $7.3
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.
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
- -----------
As discussed in the March 31, 1998 Form 10-Q, the Company is
currently engaged in regulatory proceedings in Maryland where the
PSC has outlined steps and established dates for the phase-in
implementation of competition.
On July 1, 1998, the Company filed with the PSC (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 (CTC);
(3) proposed unbundled rates for retail service; and (4) a
proposal to freeze retail rates from the time competition begins
until January 2004 (collectively, the Filing). The Filing was
made in compliance with Orders issued by the PSC in December 1997
which establish a process for implementing retail competition and
provide 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 rate case before the PSC, the future price
of electricity, including fuel charges, future revenues, the
costs of transmission and distribution, and service territory
demographics, some or all of which may prove not to have been
accurate. The Filing, in accordance with the terms of the PSC's
Orders, will be the subject of an adjudicatory proceeding which
is expected to conclude in October 1999.
30
In connection with the Filing, the Company reiterated its
position that absent appropriate enabling legislation by the
Maryland General Assembly (which has yet to be enacted and the
General Assembly is not scheduled to reconvene until January
1999), the PSC lacks the legal authority to implement the plan
filed by the Company, or any other restructuring plan providing
for retail competition.
The PSC'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 PSC with respect to the Filing.
Accordingly, the Filing does not constitute the Company's final
restructuring plan.
The PSC's December 3, 1997 Order provided that Maryland
utilities will be given a fair opportunity to recover verifiable
and prudently incurred stranded costs that cannot be mitigated
and stated that the Commission will consider proposals to
establish a CTC to address stranded costs. According to the
Commission, the recovery of "stranded costs" is meant to address
the economic impact to Maryland utilities of deregulation.
The Company's "unbundled rates" proposal breaks down its
electricity prices into separate rates for generation supply
(i.e., the cost of producing power or buying it from third
parties) and for electricity delivery (i.e., the cost of
transmission and distribution of electricity to consumers). In
the Filing, the Company's anticipated 1999 average price of 7.78
cents per kilowatt-hour breaks down into a supply charge of 4.60
cents and a delivery charge of 3.18 cents. The Company currently
has a rate case pending in Maryland to recover, among other
things, scheduled 1999 cost increases under long-term power
purchase contracts with third parties, the costs to modify the
Company's systems and operations to handle Year 2000 computer
issues and the costs associated with the Company's 1998 employee
voluntary severance program. These average supply and delivery
charges include the "make whole" portion of the requested rate
increase -- $41.6 million -- which, if approved by the PSC, would
go into effect on January 1, 1999.
As part of the Filing, the Company proposes that effective
with the beginning of competition, which is currently scheduled
to commence on July 1, 2000, both the supply and delivery
components of the Company's retail prices will be frozen at
then-existing levels until January 1, 2004. The Company also
proposes to eliminate its fuel rate on July 1, 2000, and take the
risk of fuel cost increases after implementation of the
restructuring plan until January 1, 2004, when the Company no
longer has the obligation to supply electricity at the frozen
31
rate. The only exceptions to the rate freeze would be for
unexpected increases in taxes or new environmental requirements.
After January 1, 2004, supply prices would be set by the
competitive marketplace and delivery prices would be determined
by regulators.
For retail customers who do not wish to buy the supply
portion of their electric service from a source other than the
Company once they are free to do so, the Company proposes to
provide both supply and delivery service at the frozen rates
until January 1, 2004. For customers who enter the competitive
supply market, the Company proposes to provide them with a
"shopping credit" equal to the estimated market price for
electricity (currently expected to start at 3.61 cents per
kilowatt-hour in 2000 and increase to 3.98 cents per kilowatt-
hour in 2003, reflecting forecasted increases in market price).
The shopping credit would terminate on January 1, 2004.
Under the Company's proposal, the transition to customer
choice, including recovery of stranded costs, would be made
without any increase in prices to customers. Initially, prices
would be held at the levels in effect when competition begins for
customers who choose to buy both supply and delivery from the
Company. During the freeze, a non-bypassable CTC will be
included in the frozen rate. After the end of the freeze in
January 2004, all customers would pay, as part of their delivery
charge, an explicit CTC which would initially be .97 cents per
kilowatt-hour, but would decrease to .51 cents per kilowatt-hour
in 2006, decrease again to .13 cents per kilowatt-hour in 2011
and decrease again to .12 cents per kilowatt-hour in 2016. The
CTC will end in 2021 when the last of the Company's
pre-competition power purchase contracts ends. The proposed CTC
will allow the Company the opportunity for full recovery of its
prudent, non-mitigated stranded costs, as contemplated by the PSC
in its December 3, 1997 Order, without causing an increase in
rates.
In the Filing, the Company identifies 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, which it
proposes be securitized and recovered over the period from 2000
through 2010. The $600.4 million is composed of $319.8 million
relating to generation assets, $242.6 million relating to power
purchase contracts, and $38 million in other stranded costs. The
present value of the pre-tax CTC revenues necessary to recover
these amounts over the ten-year period is $944.1 million. The
Company proposes to recover additional stranded costs associated
with its long-term Panda and SMECO power purchase contracts,
having a present value of $42 million, over the period 2011 to
2021, which it does not propose be securitized. All stranded
cost recovery would be accomplished through the non-bypassable
CTC discussed above. The Company has also proposed a "true up"
32
mechanism which would update prospectively in July 2004 its
stranded cost estimates taking into account changes in market
price or other factors.
The stranded costs in the Company's case relate to costs
(with the exception of costs which are the subject of the
currently pending rate case) which are already included in the
Company's rates. They have been approved by regulators as being
appropriate to recover because they were found to have been
prudently incurred to meet the Company's regulatory-era
obligation to provide reliable service to everyone who wants it.
It is anticipated that under the Company's plan these costs would
be amortized to match the revenues collected by the CTC. As part
of its plan, the Company proposes to securitize a portion of its
stranded cost recovery and thereby achieve savings through a
reduction in capital costs.
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 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 its stranded costs fully 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.
Although not currently required to do so, the Company
intends to file a restructuring plan for consideration by the
District of Columbia Public Service Commission by the end of
1998, relating to its D.C. service territory.
PEAK LOAD, SALES, CONSERVATION, AND CONSTRUCTION
- ------------------------------------------------
AND GENERATING CAPACITY
-----------------------
Peak Load and Sales Data
- ------------------------
Kilowatt-hour sales increased 5.7%, 1.7% and 2.3% for the
three, six and twelve months ended June 30, 1998, compared to
sales in the corresponding periods of 1997. As measured in
cooling degree hours, the weather in the second quarter of 1998
was 26% hotter than the second quarter of 1997 and 5% cooler than
the 20-year average. Sales in the twelve months ended June 30,
1997 reflect milder than average weather in each calendar
quarter. Assuming future weather conditions approximate
33
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.
Conservation
- ------------
As discussed in the March 31, 1998 Form 10-Q, the Maryland
Public Service Commission has approved the Company's proposal to
substantially reduce the scale of DSM programs in Maryland. The
Company invested approximately $4.9 million, $9.9 million and
$21.2 million in Maryland DSM programs for the three, six and
twelve months ended June 30, 1998, respectively, and $5.5
million, $12.8 million and $28.7 million for corresponding
periods in 1997. The Company recovers the costs of these
programs through a base rate surcharge and expects to be provided
an opportunity for full recovery of its investment in Maryland
conservation programs through the continued operation of this
surcharge mechanism. Consequently, these expenditures have not
been characterized as stranded costs within the Maryland
regulatory proceedings related to industry restructuring.
Investment in District of Columbia DSM programs totaled
approximately $.5 million, $1.3 million and $4.3 million for the
three, six and twelve months ended June 30, 1998, respectively,
and $.8 million, $2.1 million and $9.6 million for the
corresponding periods in 1997. These DSM costs are amortized
over ten years with an accrued return on unamortized costs. On
June 1, 1998, the Company filed an Application for Authority with
the Commission to revise its Environmental Cost Recovery Rider.
In the Application, which superseded Applications filed in June
1996 and 1997, the proposed rate seeks recovery of conservation
expenditures during the period 1995 through 1997, and is expected
to increase annual revenue by approximately $12 million. The
Public Service Commission is not required to act, nor has it
acted, on two prior such requests. A proposal by the Company to
34
eliminate DSM programs operated within the District of Columbia
was filed with the Commission in March 1998, and, as of August
11, 1998, 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 Clean Air Act (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. On January
21, 1998, the Company filed a complaint at the Federal Energy
Regulatory Commission challenging the rate for transmission
service being charged by AEI to deliver the Ohio Edison purchase.
The complaint argues that the rate being charged by AEI is
approximately double the open-access rate AEI proposed in
connection with its merger with Duquesne Light Company. If
successful, this action by the Company would reduce the annual
cost of delivering the Ohio Edison power. 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. This purchase has facilitated the sale of 35 megawatts
of capacity to Northeast Utilities Service Company. The capacity
expense under these agreements, including an allocation of a
portion of Ohio Edison's fixed operating and maintenance costs,
was $75.8 million for the six months ended June 30, 1998, and is
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.
The Company projects that existing contracts for nonutility
generation and the emerging wholesale market for generation
resources is expected to provide adequate reserve margins to meet
present customers' needs well beyond the year 2000.
35
SELECTED NONUTILITY SUBSIDIARY FINANCIAL INFORMATION
- ----------------------------------------------------
The Company's wholly owned subsidiary, Potomac Capital
Investment Corporation (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 $240.8
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 equity investment in PCI was $240.6
million, $227 million and $215.2 million, at June 30, 1998,
December 31, 1997, and June 30, 1997, respectively.
36
<TABLE>
Potomac Capital Investment Corporation
Consolidated Statements of Earnings:
- --------------------------------------
<CAPTION>
Three Six
Twelve
Months Ended Months
Ended Months Ended
June 30, June
30, June 30,
----------------------
- ----------------------- -----------------------
1998 1997 1998
1997 1998 1997
-------- --------- ---------
- --------- --------- ---------
(Thousands of Dollars except
Per Share Amounts)
<S> <C> <C> <C>
<C> <C> <C>
Income
Leasing activities $ 22,125 $ 14,646 $ 43,836
$ 35,761 $ 83,659 $ 80,367
Marketable securities 6,413 6,132 11,026
17,874 21,793 34,040
Other 8,722 7,887 18,461
14,837 24,539 19,935
-------- -------- ---------
- --------- --------- ---------
37,260 28,665 73,323
68,472 129,991 134,342
-------- -------- ---------
- --------- --------- ---------
Expenses
Interest 13,824 17,523 29,220
36,549 61,630 77,018
Administrative and general 4,854 2,356 8,152
8,710 12,931 15,199
Depreciation and operating 11,870 15,265 23,385
29,224 51,622 52,054
Income tax credit 568 (7,935) 104
(20,917) (10,829) (30,214)
-------- -------- ---------
- --------- --------- ---------
31,116 27,209 60,861
53,566 115,354 114,057
-------- -------- ---------
- --------- --------- ---------
Net earnings from
nonutility subsidiary $ 6,144 $ 1,456 $ 12,462
$ 14,906 $ 14,637 $ 20,285
======== ======== =========
========= ========= =========
Per share contribution to
earnings of the Company $ .05 $ .01 $ .11
$ .13 $ .12 $ .17
===== ===== =====
===== ===== =====
37
</TABLE>
<TABLE>
STATISTICAL DATA
- ----------------
<CAPTION>
Three Months Ended
Twelve Months Ended
June 30,
June 30,
---------------------------------
- ------------------------------------
1998 1997 % Change
1998 1997 % Change
-------- -------- --------
- ---------- ---------- --------
<S> <C> <C> <C> <C>
<C> <C>
Revenue from Sales
------------------
of Electricity
--------------
(Thousands of Dollars)
Residential $136,084 $119,812 13.6 $
542,083 $ 524,896 3.3
General Service 291,782 270,804 7.7
1,091,811 1,068,188 2.2
Large Power Service <F1> 9,277 8,990 3.2
35,408 35,414 -
Street Lighting 2,843 2,910 (2.3)
13,198 12,643 4.4
Rapid Transit 7,417 7,038 5.4
29,549 28,690 3.0
Wholesale 29,476 28,370 3.9
123,359 118,908 3.7
-------- --------
- ---------- ----------
System $476,879 $437,924 8.9
$1,835,408 $1,788,739 2.6
======== ========
========== ==========
Energy Sales
------------
(Millions of KWH)
Residential 1,492 1,390 7.3
6,644 6,493 2.3
General Service 3,862 3,688 4.7
15,377 15,100 1.8
Large Power Service <F1> 172 160 7.5
701 675 3.9
Street Lighting 33 34 (2.9)
165 164 0.6
Rapid Transit 104 99 5.1
418 408 2.5
Wholesale 602 558 7.9
2,614 2,504 4.4
-------- --------
- ---------- ----------
System 6,265 5,929 5.7
25,919 25,344 2.3
======== ========
========== ==========
Average System Revenue
----------------------
per KWH (cents per KWH) 7.61 7.39 3.0
7.08 7.06 0.3
-----------------------
System Peak Demand <F2>
------------------
(Thousands of KW)
Summer - -
5,807 5,689
Winter - -
4,076 4,632
Net Generation
--------------
(Millions of KWH) 5,034 4,042
19,689 17,005
Fuel Mix (% of Btu)
-------------------
Coal (%) 84 86
88 90
Oil (%) 13 5
9 5
Gas (%) 3 9
3 5
Fuel Cost per MBtu
------------------
System Average $1.75 $1.89
$1.80 $1.82
Weather Data
------------
Heating Degree Days 290 462
3,681 3,871
20 Year Average 337
4,006
Cooling Degree Hours 2,500 1,988
9,395 7,789
20 Year Average 2,635
11,096
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 June 30, 1998, the net generation capability, excluding
short-term capacity transactions, was 6,806 MW.
</FN>
38
</TABLE>
Item 6 EXHIBITS AND REPORTS ON FORM 8-K
- ------ --------------------------------
(a) Exhibits
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
None.
39
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
August 11, 1998
- ---------------
DATE
40
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.
41
<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 June 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
- ---------------------------------------------------------
June 30,
1998 1997 1996
1995 1994 1993
--------- ---------
- --------- --------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C>
<C> <C> <C>
Net income $167,587 $164,749
$220,066 $218,788 $208,074 $216,478
Taxes based on income 102,127 97,487
135,011 129,439 116,648 107,223
--------- ---------
- --------- --------- --------- ---------
Income before taxes 269,714 262,236
355,077 348,227 324,722 323,701
--------- ---------
- --------- --------- --------- ---------
Fixed charges:
Interest charges 147,763 146,703
146,939 146,558 139,210 141,393
Interest factor in rentals 23,614 23,616
23,560 23,431 6,300 5,859
--------- ---------
- --------- --------- --------- ---------
Total fixed charges 171,377 170,319
170,499 169,989 145,510 147,252
--------- ---------
- --------- --------- --------- ---------
Income before income taxes and fixed charges $441,091 $432,555
$525,576 $518,216 $470,232 $470,953
========= =========
========= ========= ========= =========
Coverage of fixed charges 2.57 2.54
3.08 3.05 3.23 3.20
==== ====
==== ==== ==== ====
Preferred dividend requirements $22,410 $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 $36,080 $26,361
$26,732 $26,793 $25,642 $24,383
--------- ---------
- --------- --------- --------- ---------
Total fixed charges and preferred dividends $207,457 $196,680
$197,231 $196,782 $171,152 $171,635
========= =========
========= ========= ========= =========
Coverage of combined fixed charges
and preferred dividends 2.13 2.20
2.66 2.63 2.75 2.74
==== ====
==== ==== ==== ====
42
</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 June 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
- ---------------------------------------------------------
June 30,
1998 1997 1996
1995 1994 1993
--------- ---------
- --------- --------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C>
<C> <C> <C>
Net income $182,224 $181,830
$236,960 $94,391 $227,162 $241,579
Taxes based on income 91,298 65,669
80,386 43,731 93,953 62,145
--------- ---------
- --------- --------- --------- ---------
Income before taxes 273,522 247,499
317,346 138,122 321,115 303,724
--------- ---------
- --------- --------- --------- ---------
Fixed charges:
Interest charges 209,986 216,156
231,029 238,724 224,514 221,312
Interest factor in rentals 23,746 23,687
23,943 26,685 9,938 9,257
--------- ---------
- --------- --------- --------- ---------
Total fixed charges 233,732 239,843
254,972 265,409 234,452 230,569
--------- ---------
- --------- --------- --------- ---------
Nonutility subsidiary capitalized interest (583) (493)
(649) (529) (521) (2,059)
--------- ---------
- --------- --------- --------- ---------
Income before income taxes and fixed charges $506,671 $486,849
$571,669 $403,002 $555,046 $532,234
========= =========
========= ========= ========= =========
Coverage of fixed charges 2.17 2.03
2.24 1.52 2.37 2.31
==== ====
==== ==== ==== ====
Preferred dividend requirements $22,410 $16,579
$16,604 $16,851 $16,437 $16,255
--------- ---------
- --------- --------- --------- ---------
Ratio of pre-tax income to net income 1.50 1.36
1.34 1.46 1.41 1.26
--------- ---------
- --------- --------- --------- ---------
Preferred dividend factor $33,615 $22,547
$22,249 $24,602 $23,176 $20,481
--------- ---------
- --------- --------- --------- ---------
Total fixed charges and preferred dividends $267,347 $262,390
$277,221 $290,011 $257,628 $251,050
========= =========
========= ========= ========= =========
Coverage of combined fixed charges
and preferred dividends 1.90 1.86
2.06 1.39 2.15 2.12
==== ====
==== ==== ==== ====
43
</TABLE>
Exhibit 15
August 11, 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 August 11, 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 and
333-33495) filed on February 26, 1993, July 28, 1995 and August
13, 1997, respectively. We are also aware of our
responsibilities under the Securities Act of 1933.
Very truly yours,
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Washington, D.C.
44
WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
<TABLE> <S> <C>
<ARTICLE> UT
<SUBSIDIARY>
<NUMBER> 2
<NAME> POTOMAC CAPITAL INVESTMENT CORPORATION
POTOMAC ELECTRIC POWER COMPANY TRUST I
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> JUN-30-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,468,069
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 450,742
<TOTAL-DEFERRED-CHARGES> 660,725
<OTHER-ASSETS> 1,128,257
<TOTAL-ASSETS> 6,707,793
<COMMON> 118,527
<CAPITAL-SURPLUS-PAID-IN> 1,011,625
<RETAINED-EARNINGS> 696,571
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,826,723
50,000
100,000
<LONG-TERM-DEBT-NET> 1,857,893
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 245,400<F1>
<LONG-TERM-DEBT-CURRENT-PORT> 45,000
0
<CAPITAL-LEASE-OBLIGATIONS> 159,046
<LEASES-CURRENT> 20,772
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,402,959<F2>
<TOT-CAPITALIZATION-AND-LIAB> 6,707,793
<GROSS-OPERATING-REVENUE> 908,908
<INCOME-TAX-EXPENSE> 37,299
<OTHER-OPERATING-EXPENSES> 739,996
<TOTAL-OPERATING-EXPENSES> 777,295
<OPERATING-INCOME-LOSS> 131,613
<OTHER-INCOME-NET> 14,979
<INCOME-BEFORE-INTEREST-EXPEN> 146,592
<TOTAL-INTEREST-EXPENSE> 73,091
<NET-INCOME> 73,501
14,114<F3>
<EARNINGS-AVAILABLE-FOR-COMM> 59,387
<COMMON-STOCK-DIVIDENDS> 98,322
<TOTAL-INTEREST-ON-BONDS> 139,600<F4>
<CASH-FLOW-OPERATIONS> 120,630
<EPS-PRIMARY> $0.50<F5>
<EPS-DILUTED> $0.50
<FN>
<F1>Included on the Balance Sheet in the caption "Short-term debt."
<F2>Includes redeemable preferred securities of subsidiary trust.
<F3>Includes preferred stock redemption premium of $6,579.
<F4>Total annualized interest costs for all utility long-term debt and
manditorily redeemable preferred securities of subsidiary trust outstanding
at June 30, 1998.
<F5>Both basic and diluted earnings per share for the six months ended June
30, 1998 were $.50.
</FN>
</TABLE>
