-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, AB/3Ffo31kWEIhLPNQbEai5NjtJvxC4yHfcLo5ALCpw8/nnGYvQz0h1pbO43Gp3O Mwhnz8XWCrr9P+os6Wj6qg== 0000079732-98-000086.txt : 19980812 0000079732-98-000086.hdr.sgml : 19980812 ACCESSION NUMBER: 0000079732-98-000086 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19980630 FILED AS OF DATE: 19980811 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: POTOMAC ELECTRIC POWER CO CENTRAL INDEX KEY: 0000079732 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 530127880 STATE OF INCORPORATION: VA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-01072 FILM NUMBER: 98682537 BUSINESS ADDRESS: STREET 1: 1900 PENNSYLVANIA AVE NW STREET 2: C/O M T HOWARD RM 841 CITY: WASHINGTON STATE: DC ZIP: 20068 BUSINESS PHONE: 2028722456 FILER: COMPANY DATA: COMPANY CONFORMED NAME: POTOMAC ELECTRIC POWER CO TRUST I CENTRAL INDEX KEY: 0001062043 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 522098938 STATE OF INCORPORATION: VA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-01072-01 FILM NUMBER: 98682538 BUSINESS ADDRESS: STREET 1: 1900 PENNSYLVANIA AVE NW STREET 2: C/O M T HOWARD RM 841 CITY: WASHINGTON STATE: DC ZIP: 20068 BUSINESS PHONE: 2028722456 10-Q 1 SECOND QUARTER REPORT ON FORM 10-Q 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 Part I FINANCIAL INFORMATION - ------ --------------------- Item 1 CONSOLIDATED FINANCIAL STATEMENTS - ------ --------------------------------- POTOMAC ELECTRIC POWER COMPANY Consolidated Statements of Earnings and Retained Income (Unaudited) - -------------------------------------------------------
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) 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
POTOMAC ELECTRIC POWER COMPANY Consolidated Balance Sheets (Unaudited at June 30, 1998 and 1997) -------------------------------------
June 30, December 31, June 30, ASSETS 1998 1997 1997 ------ ------------- ------------- ------------- (Thousands of Dollars) 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
POTOMAC ELECTRIC POWER COMPANY Consolidated Statements of Cash Flows (Unaudited) -------------------------------------
Six Months Ended Twelve Months Ended June 30, June 30, - ----------------------- ----------------------- 1998 1997 1998 1997 --------- --------- --------- --------- (Thousands of Dollars) 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
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 (2) INCOME TAXES - ---------------- Provision for Income Taxes - --------------------------
Three Months Ended Six Months Ended Twelve Months Ended June 30, June 30, June 30, ----------------------- ---------- ----------- --------------------- 1998 1997 1998 1997 1998 1997 ---------- ---------- --------- --------- --------- --------- (Thousands of Dollars) 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
Reconciliation of Consolidated Income Tax Expense - -------------------------------------------------
Three Months Ended Six Months Ended Twelve Months Ended June 30, June 30, June 30, ----------------------- ---------- ----------- --------------------- 1998 1997 1998 1997 1998 1997 ---------- ---------- --------- --------- --------- --------- (Thousands of Dollars) 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
Components of Consolidated Deferred Tax Liabilities (Assets) - ------------------------------------------------------------
June 30, Dec. 31, June 30, 1998 1997 1997 ---------- ---------- --------- (Thousands of Dollars) 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
(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 Calculations of Earnings Per Share - ---------------------------------- Reconciliations of the numerator and denominator for basic and diluted earnings per common share are shown below.
Three Months Ended Six Months Ended Twelve Months Ended June 30, June 30, June 30, 1998 1997 1998 1997 1998 1997 ------- ------- -------- -------- -------- -------- (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 - 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 - - 2,345 2,392 Conversion of 5% Convertible Debentures 3,393 3,393 - 3,393 3,393 3,393 ------- ------- -------- -------- -------- -------- Average shares outstanding for computation of diluted earnings per common share 124,245 124,292 118,527 121,927 124,268 124,319 ======= ======= ======== ======== ======== ======== 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 These amounts are not reflected in the computation of diluted EPS because the effects are antidilutive and would increase diluted EPS. 13
(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 Potomac Capital Investment Corporation Consolidated Statements of Earnings: - --------------------------------------
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) 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
STATISTICAL DATA - ----------------
Three Months Ended Twelve Months Ended June 30, June 30, --------------------------------- - ------------------------------------ 1998 1997 % Change 1998 1997 % Change -------- -------- -------- - ---------- ---------- -------- 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 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 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 ------------------ (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). Large Power Service customers are served at a voltage of 66KV or higher. At June 30, 1998, the net generation capability, excluding short-term capacity transactions, was 6,806 MW. 38
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 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.
Twelve Months For The Year Ended December 31, Ended - --------------------------------------------------------- June 30, 1998 1997 1996 1995 1994 1993 --------- --------- - --------- --------- --------- --------- (Thousands of Dollars) 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
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.
Twelve Months For The Year Ended December 31, Ended - --------------------------------------------------------- June 30, 1998 1997 1996 1995 1994 1993 --------- --------- - --------- --------- --------- --------- (Thousands of Dollars) 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
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 EX-27 2 FINANCIAL DATA SCHEDULE WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
UT 2 POTOMAC CAPITAL INVESTMENT CORPORATION POTOMAC ELECTRIC POWER COMPANY TRUST I 1,000 6-MOS DEC-31-1998 JUN-30-1998 PER-BOOK 4,468,069 0 450,742 660,725 1,128,257 6,707,793 118,527 1,011,625 696,571 1,826,723 50,000 100,000 1,857,893 0 0 245,400 45,000 0 159,046 20,772 2,402,959 6,707,793 908,908 37,299 739,996 777,295 131,613 14,979 146,592 73,091 73,501 14,114 59,387 98,322 139,600 120,630 $0.50 $0.50 Included on the Balance Sheet in the caption "Short-term debt." Includes redeemable preferred securities of subsidiary trust. Includes preferred stock redemption premium of $6,579. Total annualized interest costs for all utility long-term debt and manditorily redeemable preferred securities of subsidiary trust outstanding at June 30, 1998. Both basic and diluted earnings per share for the six months ended June 30, 1998 were $.50.
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