-----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, UTBvngRmlsxu+8tPbNIpBPBqYdB4XirmqooZpnNRomt+nJ66+QIR+SV8iDNx/YhB uS39841NUMo8ZxF6fjCbxw== 0000079732-96-000067.txt : 19960430 0000079732-96-000067.hdr.sgml : 19960430 ACCESSION NUMBER: 0000079732-96-000067 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19960331 FILED AS OF DATE: 19960429 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: 1934 Act SEC FILE NUMBER: 001-01072 FILM NUMBER: 96552151 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 FIRST QUARTER REPORT ON FORM 10-Q UNITED STATES 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 March 31, 1996 -------------- 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 March 31, 1996 ---------------------------- ----------------------------- Common Stock, $1 par value 118,495,333 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) Summary of Significant Accounting Policies......... 5 (2) Income Taxes....................................... 10 (3) Capitalization..................................... 13 (4) Fair Value of Financial Instruments................ 15 (5) Marketable Securities.............................. 17 (6) Commitments and Contingencies...................... 19 Report of Independent Accountants on Review of Interim Financial Information.................................. 24 Item 2 - Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition Utility Proposed Merger Update................................. 25 Results of Operations.................................. 26 Capital Resources and Liquidity........................ 28 New Accounting Standards............................... 29 Nonutility Subsidiary Results of Operations.................................. 30 Capital Resources and Liquidity........................ 33 PART II - Other Information Item 1 - Legal Proceedings................................. 34 Item 4 - Submission of Matters to a Vote of Security Holders......................................... 34 Item 5 - Other Information Other Financing Arrangements............................. 35 Base Rate Proceedings.................................... 35 Restructuring of the Bulk Power Market................... 38 Peak Load, Sales, Conservation and Construction and Generating Capacity.................................... 39 Selected Nonutility Subsidiary Financial Information..... 41 Statistical Data......................................... 43 Item 6 - Exhibits and Reports on Form 8-K.................. 44 Signatures................................................. 45 Computation of Earnings Per Common Share................... 46 Computation of Ratios - Parent Company Only................ 47 Computation of Ratios - Fully Consolidated................. 48 Independent Accountants Awareness Letter................... 49 1 Part I FINANCIAL INFORMATION - ------ --------------------- Item 1 CONSOLIDATED FINANCIAL STATEMENTS - ------ --------------------------------- POTOMAC ELECTRIC POWER COMPANY Consolidated Statements of Earnings and Retained Income (Unaudited) -------------------------------------------------------
Three Months Ended Twelve Months Ended March 31, March 31, -------------------- ---------------------- 1996 1995 1996 1995 --------- --------- ---------- ----------- (Thousands of Dollars) Revenue Sales of electricity $ 382,576 $ 361,171 $1,835,195 $1,771,640 Other electric revenue 2,696 2,262 9,076 7,483 --------- --------- ---------- ---------- Total Operating Revenue 385,272 363,433 1,844,271 1,779,123 Interchange deliveries 51,321 1,476 103,514 15,816 --------- --------- ---------- ---------- Total Revenue 436,593 364,909 1,947,785 1,794,939 --------- --------- ---------- ---------- Operating Expenses Fuel 92,713 83,541 364,626 363,139 Purchased energy 81,302 42,639 232,254 176,691 Capacity purchase payments 32,278 32,461 125,586 127,724 Other operation 55,719 58,236 221,513 212,063 Maintenance 21,427 22,827 91,459 91,221 --------- --------- ---------- ---------- Total Operation and Maintenance 283,439 239,704 1,035,438 970,838 Depreciation and amortization 55,401 47,660 213,232 184,949 Income taxes 8,171 (421) 137,051 115,465 Other taxes 45,555 47,148 201,114 205,713 --------- --------- ---------- ---------- Total Operating Expenses 392,566 334,091 1,586,835 1,476,965 --------- --------- ---------- ---------- Operating Income 44,027 30,818 360,950 317,974 --------- --------- ---------- ---------- Other Income (Loss) Nonutility Subsidiary Income 17,313 33,885 117,919 147,882 Loss on assets held for disposal - - (182,398) - Expenses, including interest and income taxes (14,845) (38,259) (53,076) (135,373) --------- --------- ---------- ---------- Net earnings (loss) from nonutility subsidiary 2,468 (4,374) (117,555) 12,509 Allowance for other funds used during construction and capital cost recovery factor 1,737 1,407 6,484 9,694 Other, net 1,755 1,094 1,344 (1,758) --------- --------- ---------- ---------- Total Other Income (Loss) 5,960 (1,873) (109,727) 20,445 --------- --------- ---------- ---------- Income Before Utility Interest Charges 49,987 28,945 251,223 338,419 --------- --------- ---------- ---------- Utility Interest Charges Long-term debt 33,434 32,306 132,748 128,221 Other 3,787 3,299 15,426 12,840 Allowance for borrowed funds used during construction and capital cost recovery factor (1,968) (2,688) (10,048) (11,418) --------- --------- ---------- ---------- Net Utility Interest Charges 35,253 32,917 138,126 129,643 --------- --------- ---------- ---------- Net Income (Loss) 14,734 (3,972) 113,097 208,776 Dividends on Preferred Stock 4,160 4,241 16,769 16,532 --------- --------- ---------- ---------- Earnings (Loss) for Common Stock 10,574 (8,213) 96,328 192,244 Retained Income at Beginning of Period 742,296 830,524 785,792 797,728 Dividends on Common Stock (49,152) (49,046) (196,576) (195,905) Subsidiary Marketable Securities Net Unrealized (Loss) Gain, Net of Tax (8,197) 12,527 9,977 (8,275) --------- --------- ---------- ---------- Retained Income at End of Period $ 695,521 $ 785,792 $ 695,521 $ 785,792 ========= ========= ========== ========== Average Common Shares Outstanding (000's) 118,495 118,249 118,473 118,098 Earnings (Loss) Per Common Share $0.09 ($0.07) $0.81 $1.63 Cash Dividends Per Common Share $0.415 $0.415 $1.66 $1.66 Book Value Per Share $15.40 $16.16 2
POTOMAC ELECTRIC POWER COMPANY Consolidated Balance Sheets (Unaudited at March 31, 1996 and 1995) --------------------------------------
March 31, December 31, March 31, ASSETS 1996 1995 1995 ------ ------------- ------------- ------------- (Thousands of Dollars) Property and Plant - at original cost Electric plant in service $ 6,069,071 $ 6,041,203 $ 5,832,996 Construction work in progress 103,015 93,047 176,103 Electric plant held for future use 4,096 4,082 18,288 Nonoperating property 22,771 22,771 7,555 ------------- ------------- ------------- 6,198,953 6,161,103 6,034,942 Accumulated depreciation (1,800,460) (1,760,792) (1,674,666) ------------- ------------- ------------- Net Property and Plant 4,398,493 4,400,311 4,360,276 ------------- ------------- ------------- Current Assets Cash and cash equivalents 11,400 5,844 1,984 Customer accounts receivable, less allowance for uncollectible accounts of $1,482, $1,669 and $2,221 133,053 137,456 109,059 Other accounts receivable, less allowance for uncollectible accounts of $300 37,810 36,765 30,290 Accrued unbilled revenue 63,015 73,622 55,992 Prepaid taxes 27,489 36,255 37,722 Other prepaid expenses 4,200 7,562 4,442 Material and supplies - at average cost Fuel and emission allowances 66,222 63,203 60,341 Construction and maintenance 70,513 70,497 72,619 ------------- ------------- ------------- Total Current Assets 413,702 431,204 372,449 ------------- ------------- ------------- Deferred Charges Income taxes recoverable through future rates, net 240,320 244,181 240,569 Conservation costs, net 234,460 230,412 180,871 Unamortized debt reacquisition costs 57,658 58,360 56,096 Other 149,024 138,619 111,086 ------------- ------------- ------------- Total Deferred Charges 681,462 671,572 588,622 ------------- ------------- ------------- Nonutility Subsidiary Assets Cash and cash equivalents 3,545 1,594 256 Marketable securities 417,377 530,323 490,211 Investment in finance leases 476,879 438,795 339,559 Operating lease equipment, net of accumulated depreciation of $89,629, $79,275 and $124,975 262,025 272,947 542,775 Assets held for disposal 28,300 104,370 - Receivables, less allowance for uncollectible accounts of $6,000, $6,000 and $5,000 63,004 74,957 77,426 Other investments 156,481 176,418 191,018 Other assets 15,416 15,659 22,221 ------------- ------------- ------------- Total Nonutility Subsidiary Assets 1,423,027 1,615,063 1,663,466 ------------- ------------- ------------- Total Assets $ 6,916,684 $ 7,118,150 $ 6,984,813 ============= ============= ============= CAPITALIZATION AND LIABILITIES - ------------------------------ Capitalization Common stock $ 118,495 $ 118,495 $ 118,349 Other common equity 1,706,011 1,752,817 1,793,972 Serial preferred stock 125,319 125,325 125,405 Redeemable serial preferred stock 143,485 143,485 143,562 Long-term debt 1,817,727 1,817,077 1,727,848 ------------- ------------- ------------- Total Capitalization 3,911,037 3,957,199 3,909,136 ------------- ------------- ------------- Other Non-Current Liabilities Capital lease obligations 164,677 165,235 166,817 ------------- ------------- ------------- Total Other Non-Current Liabilities 164,677 165,235 166,817 ------------- ------------- ------------- Current Liabilities Long-term debt due within one year 25,000 26,280 40,000 Short-term debt 286,940 258,465 237,525 Accounts payable and accrued expenses 163,481 162,039 164,560 Capital lease obligations due within one year 20,772 20,772 20,772 Other 77,527 86,034 106,984 ------------- ------------- ------------- Total Current Liabilities 573,720 553,590 569,841 ------------- ------------- ------------- Deferred Credits Income taxes 896,258 892,544 850,752 Investment tax credits 63,695 64,607 67,344 Other 36,193 35,089 26,796 ------------- ------------- ------------- Total Deferred Credits 996,146 992,240 944,892 ------------- ------------- ------------- Nonutility Subsidiary Liabilities Long-term debt 1,066,688 1,047,484 1,153,753 Short-term notes payable 73,230 223,350 27,400 Deferred taxes and other 131,186 179,052 212,974 ------------- ------------- ------------- Total Nonutility Subsidiary Liabilities 1,271,104 1,449,886 1,394,127 ------------- ------------- ------------- Total Capitalization and Liabilities $ 6,916,684 $ 7,118,150 $ 6,984,813 ============= ============= ============= 3
POTOMAC ELECTRIC POWER COMPANY Consolidated Statements of Cash Flows (Unaudited) -------------------------------------
Three Months Ended Twelve Months Ended March 31, March 31, ----------------------- ----------------------- 1996 1995 1996 1995 --------- --------- --------- --------- (Thousands of Dollars) Operating Activities Income from utility operations $ 12,266 $ 402 $ 230,652 $ 196,267 Adjustments to reconcile income to net cash from operating activities: Depreciation and amortization 55,401 47,660 213,232 184,949 Deferred income taxes and investment tax credits (5) 12,140 39,629 42,874 Allowance for funds used during construction and capital cost recovery factor (3,705) (4,095) (16,532) (21,112) Changes in materials and supplies (3,035) 13,158 (3,775) (369) Changes in accounts receivable and accrued unbilled revenue 13,965 36,681 (38,537) 6,184 Changes in accounts payable 9,850 (14,716) 10,146 (4,750) Changes in other current assets and liabilities 1,526 981 (940) 6,032 Changes in deferred conservation costs (15,829) (25,510) (95,115) (100,238) Net other operating activities (7,705) (16,085) (37,718) (1,054) Nonutility subsidiary: Net earnings (loss) 2,468 (4,374) (117,555) 12,509 Deferred income taxes (34,724) (2,531) (81,890) (150) Loss on assets held for disposal - - 182,398 - Changes in other assets and net other operating activities 46,098 14,584 98,944 53,073 --------- --------- --------- --------- Net Cash From Operating Activities 76,571 58,295 382,939 374,215 --------- --------- --------- --------- Investing Activities Total investment in property and plant (41,538) (63,977) (207,802) (297,478) Allowance for funds used during construction and capital cost recovery factor 3,705 4,095 16,532 21,112 --------- --------- --------- --------- Net investment in property and plant (37,833) (59,882) (191,270) (276,366) Nonutility subsidiary: Purchase of marketable securities (11,252) (2,069) (44,404) (57,348) Proceeds from sale or redemption of marketable securities 113,177 6,322 134,701 44,597 Investment in leased equipment - (6,618) (148,148) (75,100) Proceeds from sale or disposition of leased equipment 24,500 - 24,500 1,150 Proceeds from sale of assets 285 - 6,251 - Purchase of other investments (932) (624) (4,153) (3,461) Proceeds from sale or distribution of other investments 1,385 14,807 5,978 33,315 Investment in promissory notes (2,593) - (10,548) (542) Proceeds from promissory notes 1,980 1,669 8,288 5,460 --------- --------- --------- --------- Net Cash From (Used by) Investing Activities 88,717 (46,395) (218,805) (328,295) --------- --------- --------- --------- Financing Activities Dividends on common stock (49,152) (49,046) (196,576) (195,905) Dividends on preferred stock (4,160) (4,241) (16,769) (16,532) Issuance of common stock - 1,894 2,685 7,512 Redemption of preferred stock - - (78) (1,590) Issuance of long-term debt - 15,840 172,754 140,427 Reacquisition and retirement of long-term debt (1,300) (17,483) (101,282) (77,538) Proceeds from sale and leaseback of control center system - - - 152,000 Short-term debt, net 28,475 47,925 49,415 (45,425) Other financing activities (728) (3,995) (20,343) (16,522) Nonutility subsidiary: Issuance of long-term debt 78,000 75,000 185,000 246,750 Repayment of long-term debt (58,796) (61,752) (272,065) (173,092) Short-term debt, net (150,120) (21,000) 45,830 (77,450) --------- --------- --------- --------- Net Cash Used By Financing Activities (157,781) (16,858) (151,429) (57,365) --------- --------- --------- --------- Net Increase (Decrease) in Cash and Cash Equivalents 7,507 (4,958) 12,705 (11,445) Cash and Cash Equivalents at Beginning of Period 7,438 7,198 2,240 13,685 --------- --------- --------- --------- Cash and Cash Equivalents at End of Period $ 14,945 $ 2,240 $ 14,945 $ 2,240 ========= ========= ========= ========= Cash paid for interest (net of capitalized interest) and income taxes: Interest (including nonutility subsidiary interest of $34,800, $37,709, $86,803 and $86,669) $ 78,791 $ 71,683 $ 218,675 $ 211,731 Income taxes $ 2,559 $ 2,646 $ 44,638 $ 49,284 4
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------ (1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES ------------------------------------------ The Company is engaged in the generation, transmission, distribution and sale of electric energy in the Washington, D.C. metropolitan area. The Company's retail service territory includes all of the District of Columbia and major portions of Montgomery and Prince George's counties in suburban Maryland. Potomac Capital Investment Corporation (PCI), a wholly owned subsidiary of the Company, was formed in 1983 to provide a permanent vehicle for the conduct of the Company's ongoing nonutility investment programs. PCI's principal investments have been in aircraft and power generation equipment, equipment leasing and marketable securities, primarily preferred stock with mandatory redemption features. PCI also has investments in real estate properties in the Washington, D.C. metropolitan area. The Company's utility operations are regulated by the Maryland and District of Columbia public service commissions and its wholesale business by the Federal Energy Regulatory Commission (FERC). The Company complies with the Uniform System of Accounts prescribed by the FERC and adopted by the Maryland and District of Columbia regulatory commissions. Based upon the regulatory framework in which it operates, the Company currently applies the provisions of Statement of Financial Accounting Standards (SFAS) No. 71 entitled "Accounting for the Effects of Certain Types of Regulation" in accounting for certain deferred charges and credits to be recognized in future customer billings pursuant to regulatory authorization, principally deferred income taxes, unamortized conservation costs and unamortized debt reacquisition costs. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates and assumptions. Certain 1995 amounts have been reclassified to conform to the current year presentation. A description of significant accounting policies follows. 5 Principles of Consolidation - --------------------------- The consolidated financial statements combine the financial results of the Company and all majority-owned subsidiaries. The Company's principal subsidiary is PCI. All material intercompany balances and transactions have been eliminated. Total Revenue - ------------- Revenue is accrued for service rendered but unbilled as of the end of each month. The Company includes in revenue the amounts received for sales to other utilities related to pooling and interconnection agreements. Amounts received for such interchange deliveries are a component of the Company's fuel rates. In each jurisdiction, the Company's rate schedules include fuel rates. The fuel rate provisions are designed to provide for separately stated fuel billings which cover applicable net fuel and interchange costs, purchased capacity in the District of Columbia, and emission allowance costs in the Company's retail jurisdictions, or changes in the applicable costs from levels incorporated in base rates. Differences between applicable net costs incurred and fuel rate revenue billed in any given period are accounted for as other current assets or other current liabilities in those cases where specific provision has been made by the appropriate regulatory commission for the resolution of such differences within one year. Where no such provision has been made, the differences are accounted for as other deferred charges or other deferred credits pending regulatory determination. In the District of Columbia, pre-July 1993 conservation costs receive rate base treatment. Conservation expenditures for the period July 1993 to December 1994 are recovered through a surcharge mechanism which initially became effective July 11, 1995, and which will be updated annually on June 1 to recover 1995 and subsequent conservation expenditures, including a capital cost recovery factor (CCRF), which is a mechanism that enables the Company to earn a return on certain costs, principally unamortized demand side management (DSM) costs not in rate base. A procedure has been established to consider lost revenue without the need for base rate proceedings. In Maryland, conservation costs are recovered through a surcharge rate which reflects amortization of program costs, including costs in the year during which the surcharge commences, a CCRF, incentives, applicable taxes and estimated lost revenue. The surcharge is established annually in a collaborative process with the recovery of lost revenue subject to an earnings test performed on a quarterly basis. 6 Leasing Transactions - -------------------- Income from PCI investments in direct finance and leveraged lease transactions, in which PCI is an equity participant, is reported using the financing method. In accordance with the financing method, investments in leased property are recorded as a receivable from the lessee to be recovered through the collection of future rentals. For direct finance leases, unearned income is amortized to income over the lease term at a constant rate of return on the net investment. Income, including investment tax credits on leveraged equipment leases, is recognized over the life of the lease at a level rate of return on the positive net investment. PCI investments in equipment under operating leases are stated at cost less accumulated depreciation, except that assets held for disposal are carried at estimated fair value less estimated costs to sell. Depreciation is recorded on a straight line basis over the equipment's estimated useful life. No depreciation is taken on assets held for disposal. Property and Plant - ------------------ The cost of additions to, and replacements or betterments of, retirement units of property and plant is capitalized. Such cost includes material, labor, the capitalization of an Allowance for Funds Used During Construction (AFUDC) and applicable indirect costs, including engineering, supervision, payroll taxes and employee benefits. The original cost of depreciable units of plant retired, together with the cost of removal, net of salvage, is charged to accumulated depreciation. Routine repairs and maintenance are charged to operating expenses as incurred. The Company uses separate depreciation rates for each electric plant account. The rates, which vary from jurisdiction to jurisdiction, were equivalent to a system-wide composite depreciation rate of approximately 3.1% for 1996, 1995 and 1994. Conservation - ------------ In general, the Company accounts for conservation expenditures in connection with its DSM program as a deferred charge, and amortizes the costs over five years in Maryland and 10 years in the District of Columbia. At March 31, 1996, unamortized conservation costs totaled $103.4 million in Maryland and $131.1 million in the District of Columbia. 7 Allowance for Funds Used During Construction and Capital Cost - ------------------------------------------------------------- Recovery Factor --------------- In general, the Company capitalizes AFUDC with respect to investments in Construction Work in Progress with the exception of expenditures required to comply with federal, state or local environmental regulations (pollution control projects), which are included in rate base without capitalization of AFUDC. The Company accrues a CCRF on the retail jurisdictional portion of certain pollution control projects related to compliance with the Clean Air Act (CAA). The base for calculating this return is the amount by which the retail jurisdictional CAA expenditure balance exceeds the CAA balance included in rate base in the Company's most recently completed base rate proceeding. The CCRF rates for Maryland and the District of Columbia are 9.46% and 9.09%, respectively. The jurisdictional AFUDC capitalization rates are determined as prescribed by the FERC. The effective capitalization rates were approximately 7.3%, compounded semi-annually, for the three months ended March 31, 1996, and approximately 7.9% in 1995 and 7.6% in 1994, compounded semi-annually. Amortization of Debt Issuance and Reacquisition Costs - ----------------------------------------------------- The Company defers and amortizes expenses incurred in connection with the issuance of long-term debt, including premiums and discounts associated with such debt, over the lives of the respective issues. Costs associated with the reacquisition of debt are also deferred and amortized over the lives of the new issues. Cash and Cash Equivalents - ------------------------- For purposes of the consolidated financial statements, cash and cash equivalents include cash on hand, money market funds and commercial paper with maturities of three months or less. 8 Nonutility Subsidiary Receivables - --------------------------------- PCI, the Company's nonutility subsidiary, continuously monitors its receivables and establishes an allowance for doubtful accounts against its notes receivable, when deemed appropriate, on a specific identification basis. The direct write-off method is used when trade receivables are deemed uncollectible. New Accounting Standards - ------------------------ Effective January 1, 1996, the Company adopted SFAS No. 121 entitled "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." This statement requires the Company to review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recovered. In addition, regulated companies are required to write-off regulatory assets whenever those assets no longer are probable of recovery from customers through future rates. Adoption of this pronouncement did not have a material impact on the Company's consolidated financial statements. SFAS No. 123 entitled "Accounting for Stock-Based Compensation" also became effective as of January 1, 1996. This pronouncement encourages companies to recognize compensation expense for the fair value of stock-based compensation but permits accounting under Accounting Principles Board Opinion No. 25 entitled "Accounting for Stock Issued to Employees" as long as the proforma effects, as if the new standard had been applied, are disclosed in the notes to financial statements. The Company's use of stock-based compensation is limited and adoption of this pronouncement did not have a material impact on the consolidated financial statements. 9 (2) INCOME TAXES - ---------------- Provisions for Income Taxes - ---------------------------
Three Months Ended Twelve Months Ended March 31, March 31, -------------------- ----------------------- 1996 1995 1996 1995 -------- -------- ----------- --------- (Thousands of Dollars) Utility current tax expense Federal $ 8,519 $(11,397) $ 88,408 $ 60,983 State and local 777 (1,452) 11,402 8,372 -------- -------- ---------- -------- Total utility current tax expense 9,296 (12,849) 99,810 69,355 -------- -------- ---------- -------- Utility deferred tax expense Federal 279 11,469 37,149 40,670 State and local 628 1,583 6,129 5,853 Investment tax credits (912) (912) (3,649) (3,649) -------- -------- ---------- -------- Total utility deferred tax expense (5) 12,140 39,629 42,874 -------- -------- ---------- -------- Total utility income tax expense 9,291 (709) 139,439 112,229 -------- -------- ---------- -------- Nonutility subsidiary current tax expense Federal (4,034) (3,234) (36,392) (25,486) -------- -------- ---------- -------- Nonutility subsidiary deferred tax expense Federal (34,728) (3,055) (81,789) (590) State and local - - - 150 -------- -------- ---------- -------- Total nonutility subsidiary deferred tax expense (34,728) (3,055) (81,789) (440) -------- -------- ---------- -------- Total nonutility subsidiary income tax credit (38,762) (6,289) (118,181) (25,926) -------- -------- ---------- -------- Total consolidated income tax expense (29,471) (6,998) 21,258 86,303 Income taxes included in other income (37,642) (6,577) (115,793) (29,162) -------- -------- ---------- -------- Income taxes included in utility operating expenses $ 8,171 $ (421) $ 137,051 $115,465 ======== ======== ========== ======== 10
Reconciliation of Consolidated Income Tax Expense - -------------------------------------------------
Three Months Ended Twelve Months Ended March 31, March 31, -------------------- ----------------------- 1996 1995 1996 1995 -------- -------- ----------- --------- (Thousands of Dollars) (Loss) Income before income taxes $(14,737) $(10,970) $ 134,355 $295,079 ======== ======== ========== ======== Utility income tax at federal statutory rate $ 7,545 (107) $ 129,532 $107,974 Increases (decreases) resulting from Depreciation 2,542 2,248 9,467 8,430 Removal costs (308) (1,231) (6,281) (4,209) Allowance for funds used during construction 134 165 564 (1,300) Other (541) (1,038) (1,117) (3,957) State income taxes, net of federal effect 831 166 11,313 9,328 Tax credits (912) (912) (4,039) (4,037) -------- -------- ---------- -------- Total utility income tax expense 9,291 (709) 139,439 112,229 -------- -------- ---------- -------- Nonutility subsidiary income tax at federal statutory rate (12,703) (3,732) (82,508) (4,695) Increases (decreases) resulting from Dividends received deduction (1,636) (2,201) (7,959) (8,645) Reversal of previously accrued deferred taxes (23,506) - (23,506) (8,206) Other (917) (356) (4,208) (4,530) State income taxes, net of federal effect - - - 150 -------- -------- ---------- -------- Total nonutility subsidiary income tax credit (38,762) (6,289) (118,181) (25,926) -------- -------- ---------- -------- Total consolidated income tax expense (29,471) (6,998) 21,258 86,303 Income taxes included in other income (37,642) (6,577) (115,793) (29,162) -------- -------- ---------- -------- Income taxes included in utility operating expenses $ 8,171 $ (421) $ 137,051 $115,465 ======== ======== ========== ======== 11
Components of Consolidated Deferred Tax Liabilities (Assets) - ------------------------------------------------------------
Mar. 31, Dec. 31, Mar. 31, 1996 1995 1995 --------- --------- --------- (Thousands of Dollars) Utility deferred tax liabilities (assets) Depreciation and other book to tax basis differences $787,327 $773,323 $731,754 Rapid amortization of certified pollution control facilities 26,147 26,640 28,640 Deferred taxes on amounts to be collected through future rates 90,985 92,472 91,104 Property taxes 11,969 11,808 11,294 Deferred fuel (12,621) (7,154) (1,703) Prepayment premium on debt retirement 21,809 22,080 21,475 Deferred investment tax credit (24,115) (24,464) (25,501) Contributions in aid of construction (27,325) (27,206) (25,007) Contributions to pension plans 11,329 10,859 - Other 15,023 25,124 25,443 -------- -------- -------- Total utility deferred tax liabilities (net) 900,528 903,482 857,499 Current portion of utility deferred tax liabilities (included in Other Current Liabilities) 4,270 10,938 6,747 -------- -------- -------- Total utility deferred tax liabilities (net) - non-current $896,258 $892,544 $850,752 ======== ======== ======== Nonutility subsidiary deferred tax liabilities (assets) Finance leases $152,412 $149,103 $132,604 Operating leases 32,822 66,802 112,413 Reversal of previously accrued taxes related to partnerships (10,592) (11,593) (17,088) Alternative minimum tax (80,933) (84,512) (77,167) Other (29,887) (16,840) (10,422) -------- -------- -------- Total nonutility subsidiary deferred tax liabilities (net), (included in Deferred taxes and other) $ 63,822 $102,960 $140,340 ======== ======== ======== 12
(3) CAPITALIZATION -------------- Common Equity - ------------- At March 31, 1996, 118,495,333 shares of the Company's $1 par value Common Stock were outstanding. A total of 200 million shares is authorized. As of March 31, 1996, 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 2,771,633 and 3,392,500 shares were reserved for conversion of the 7% and 5% Convertible Debentures, respectively. Under the Stock Option Agreement with Baltimore Gas and Electric Company, 23,579,900 shares could become issuable, contingent upon specific events associated with termination of the Merger Agreement. (See Note 6 - Commitments and Contingencies for additional information.) Serial Preferred, Redeemable Serial Preferred and Preference - ------------------------------------------------------------ Stock and Long-Term Debt ------------------------ At March 31, 1996, the Company had outstanding 5,376,072 shares of its $50 par value Serial Preferred Stock, including the Redeemable Serial Preferred Stock. A total of 11,126,222 shares is authorized. At March 31, 1996, the aggregate annual dividend requirements on the Serial Preferred Stock and the Redeemable Serial Preferred Stock were approximately $6.3 million and $10.2 million, respectively. Also, the Company has a total of 8,800,000 shares of cumulative, $25 par value, Preference Stock authorized and unissued. The Company's $2.44 Convertible Preferred Stock, 1966 Series (6,376 shares outstanding at March 31, 1996) is convertible into Common Stock at $8.51 per share. At March 31, 1996, the Company had outstanding one million shares of its Serial Preferred Stock, Auction Series A. The annual dividend rate is 3.99% ($1.995) for the period March 1, 1996, through May 31, 1996. For the period December 1, 1995, through February 29, 1996, the annual dividend rate was 4.335% ($2.1675). The average rate at which dividends were paid during the 12 months ended March 31, 1996, was 4.48% ($2.24). 13 At March 31, 1996, the Company had outstanding three series of $50 par value Redeemable Serial Preferred Stock. There are one million shares of the $3.89 (7.78%) Series of 1991 on which the sinking fund requirement commences June 1, 2001; one million shares of the $3.40 (6.80%) Series of 1992 on which the sinking fund requirement commences September 1, 2002; and 869,696 shares of the $3.37 (6.74%) Series of 1987 on which the sinking fund requires redemption, beginning June 1993, at par, of not less than 30,000 nor more than 60,000 shares annually. Sinking fund requirements through 2000 with respect to the three series of Redeemable Serial Preferred Stock are $1 million in 1997 and $1.5 million annually thereafter. The Company's Long-Term Debt at March 31, 1996, is summarized below: (Thousands of Dollars) First Mortgage Bonds $1,341,800 Convertible Debentures 180,447 Notes Payable 350,000 Net Unamortized Discount (29,520) Current Portion (25,000) ---------- Net Utility Long-Term Debt $1,817,727 ========== Nonutility Subsidiary Long-Term Debt $1,066,688 ========== At March 31, 1996, the aggregate annual interest requirement on the Company's long-term debt, including debt due within one year, was $127.8 million; and the aggregate amounts of long-term debt maturities are $25 million in 1996, $150 million in 1997, $50 million in 1998, $45 million in 1999 and $100 million in 2000. At March 31, 1996, long-term debt due within one year consisted of $25 million of 6-1/4% Medium-Term Notes. Nonutility Subsidiary Long-Term Debt - ------------------------------------ Long-term debt at March 31, 1996, consisted primarily of unsecured borrowings from institutional lenders maturing at various dates between 1996 and 2003. The interest rates of such borrowings ranged from 5% to 10.1%. The weighted average effective interest rate was 7.51% at March 31, 1996, 7.66% at December 31, 1995, and 7.46% at March 31, 1995. Annual aggregate principal repayments on these borrowings are $173.4 million in 1996, $194.5 million in 1997, $301.3 million in 1998, $140.5 million in 1999, $95 million in 2000 and $97.5 million thereafter. Also included in long-term debt is $64.5 million of non-recourse debt which is due in monthly installments with final maturities in 2001, 2002 and 2011. 14 (4) FAIR VALUE OF FINANCIAL INSTRUMENTS - --------------------------------------- The estimated fair values of the Company's financial instruments at March 31, 1996, December 31, 1995, and March 31, 1995, are shown below.
March 31, December 31, March 31, 1996 1995 1995 -------------------------- ------------------------- ------------------------- Carrying Fair Carrying Fair Carrying Fair Amount Value Amount Value Amount Value ----------- ---------- ---------- ---------- ---------- ---------- (Thousands of Dollars) Utility Capitalization and Liabilities Serial preferred stock $ 125,319 110,261 125,325 114,590 125,405 105,386 ========== ========= ========= ========= ========= ========= Redeemable serial preferred stock $ 143,485 148,612 143,485 145,046 143,562 134,008 ========== ========= ========= ========= ========= ========= Long-term debt First Mortgage Bonds $1,326,767 1,305,270 1,326,560 1,385,609 1,212,111 1,144,575 Medium-Term Notes $ 323,081 324,542 323,007 336,351 347,786 336,285 Convertible Debentures $ 167,879 171,906 167,510 174,054 167,951 157,359 ---------- --------- --------- --------- --------- --------- Total long-term debt $1,817,727 1,801,718 1,817,077 1,896,014 1,727,848 1,638,219 ========== ========= ========= ========= ========= ========= Nonutility Subsidiary Assets Marketable securities $ 417,377 417,377 530,323 530,323 490,211 490,211 ========== ========= ========= ========= ========= ========= Notes receivable $ 63,515 60,575 62,175 63,184 59,609 58,856 ========== ========= ========= ========= ========= ========= Liabilities Long-term debt $1,066,688 1,089,373 1,047,484 1,071,354 1,153,753 1,156,223 ========== ========= ========= ========= ========= ========= 15
The methods and assumptions below were used to estimate, at March 31, 1996, December 31, 1995, and March 31, 1995, the fair value of each class of financial instruments shown above for which it is practicable to estimate that value. The fair value of the Company's long-term debt, which includes First Mortgage Bonds, Medium-Term Notes and Convertible Debentures, excluding amounts due within one year, was based on the current market price, or for issues with no market price available, was based on discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The fair value of the Company's Serial Preferred Stock, including Redeemable Serial Preferred Stock, was based on quoted market prices or discounted cash flows using current rates of preferred stock with similar terms. The fair value of PCI's Marketable Securities was based on quoted market prices. The fair value of PCI's Notes Receivable was based on discounted future cash flows using current rates and similar terms. The fair value of PCI's long-term debt, including non- recourse debt, was based on current rates offered to similar companies for debt with similar remaining maturities. The carrying amounts of all other financial instruments approximate fair value. 16 (5) MARKETABLE SECURITIES --------------------- PCI's marketable securities are classified as available-for- sale for financial reporting purposes. Investment grade preferred stocks with mandatory redemption features made up 95% of the portfolio at March 31, 1996. Net unrealized gains and losses are reflected, net of tax, in stockholder's equity. The net unrealized (losses) gains are shown below: As of March 31, 1996 --------------------------------------- Net Market Unrealized Cost Value Losses ---------- ---------- -------------- (Thousands of Dollars) Mandatory redeemable preferred stock $ 419,153 $ 417,112 $ (2,041) Equity securities 341 265 (76) ---------- ---------- ------------ Total $ 419,494 $ 417,377 $ (2,117) ========== ========== ============ As of December 31, 1995 --------------------------------------- Net Market Unrealized Cost Value Gain/(Loss) ---------- ---------- -------------- (Thousands of Dollars) Mandatory redeemable preferred stock $ 519,488 $ 530,115 $ 10,627 Equity securities 341 208 (133) ---------- ---------- ------------ Total $ 519,829 $ 530,323 $ 10,494 ========== ========== ============ 17 As of March 31, 1995 --------------------------------------- Net Market Unrealized Cost Value Losses ---------- ---------- -------------- (Thousands of Dollars) Mandatory redeemable preferred stock $ 507,674 $ 490,211 $ (17,463) Equity securities 3 - (3) ---------- ---------- ------------ Total $ 507,677 $ 490,211 $ (17,466) ========== ========== ============ Included in net unrealized gains and losses are gross unrealized losses of $10.2 million and gross unrealized gains of $8.1 million at March 31, 1996; gross unrealized gains of $17.1 million and gross unrealized losses of $6.6 million at December 31, 1995; and gross unrealized losses of $22.8 million and gross unrealized gains of $5.3 million at March 31, 1995. At March 31, 1996, the contractual maturities for mandatory redeemable preferred stock are $5.8 million within one year, $64.8 million from one to five years, $121.9 million from five to 10 years and $226.7 million for over 10 years. In determining gross realized gains and losses on sales or maturities of securities, specific identification is used. A summary of realized gains and losses is shown below. Three Months Three Months Ended Ended March 31, 1996 March 31, 1995 -------------- -------------- (Thousands of Dollars) Gross realized gains $ 2,261 $ 147 Gross realized losses (671) (10) --------- --------- Net gain $ 1,590 $ 137 ========= ========= 18 (6) COMMITMENTS AND CONTINGENCIES ----------------------------- Proposed Merger - --------------- The Company entered into an Agreement and Plan of Merger with Baltimore Gas and Electric Company (BGE) in September 1995. This Agreement provides for a strategic business combination in which each company will merge into Constellation Energy Corporation (Constellation Energy), a newly formed company to create an integrated, non-holding company structure (the Merger). Each outstanding share of the Company's common stock will be converted into the right to receive .997 of a share of common stock of Constellation Energy and each outstanding share of BGE common stock will be converted into the right to receive one share of Constellation Energy's common stock. This transaction is expected to qualify as a tax-free exchange of shares for the holders of each company's common stock and as a pooling of interests for accounting purposes. Constellation Energy will serve a population of approximately 4.5 million with approximately 1.8 million electric customers and over 530,000 natural gas customers. It is estimated that savings from the combined utility systems will approximate $1.3 billion over 10 years, net of costs to achieve. The allocation of the net savings between customers and shareholders of the Company will be determined in regulatory proceedings. On March 29, 1996, shareholders of the Company and BGE, in separate special meetings, approved the Merger Agreement. The Company and BGE filed a joint Application for Authorization and Approval of the Merger with the FERC on January 11, 1996, and on April 8, 1996, with the Maryland and District of Columbia Public Service Commissions. Additional approvals are required from the Nuclear Regulatory Commission, the Virginia State Corporation Commission and the Pennsylvania Public Utility Commission. Completion of the approval process is expected to take until the end of the first quarter of 1997. If the Merger Agreement is terminated by either the Company or BGE due to a material breach by the other party, the breaching party must pay the non-breaching party, as liquidated damages, $10 million in cash in respect of out-of-pocket expenses. The Merger Agreement also requires payment of a termination fee of $75 million in cash, plus $10 million in cash in respect of out- of-pocket expenses, by one party to the other if the Merger Agreement is terminated under certain circumstances including, if either the Company or BGE terminates the Merger Agreement after the Board of Directors of the other party withdraws or adversely modifies its recommendation of the transaction. The termination fees payable by the Company under these provisions and the aggregate amount which could be payable by the Company upon a required repurchase of an option (or shares of common stock 19 issued pursuant to the exercise of the option) granted by the Company to BGE in connection with entry into the Merger Agreement may not exceed $125 million in the aggregate. The Company has approved, in conjunction with the Merger with BGE, a severance plan for all exempt and non-bargaining unit employees who lose employment due to the Merger. Employees who lose employment as a result of the Merger will receive two weeks of pay per year of service, with a minimum payment of eight weeks of pay. In addition, employees will receive company-sponsored health and dental insurance for two weeks per year of service, with a minimum of eight weeks of insurance coverage. In December 1995, an extension of the current 1993 Labor Agreement between the Company and Local 1900 of the International Brotherhood of Electrical Workers was ratified by the Union members. The 1995 Agreement extends the 1993 Agreement, which was due to expire on June 1, 1996, for two years or until the effective date of the Merger with BGE, whichever occurs first. This Agreement provides severance benefits, previously approved by the Company for exempt and non-bargaining unit employees, for all union members and provides for a lump-sum payment of 2% of base pay, which was paid on January 5, 1996, a lump-sum payment of 1% of base pay on June 7, 1996, and a lump-sum payment of 3% of base pay on June 6, 1997, or the effective date of the Merger, whichever occurs first. Environmental Contingencies - --------------------------- As discussed in the 1995 Form 10-K, the Company received notice in December 1995 from the U.S. Environmental Protection Agency (EPA) that it is a Potentially Responsible Party (PRP) under the Comprehensive Environmental Response Compensation and Liability Act (CERCLA or Superfund) with respect to the release or threatened release of radioactive and mixed radioactive and hazardous wastes at a site in Denver, Colorado, operated by RAMP Industries, Inc. Evidence indicates that the Company's connection to the site arises from agreement with a vendor to package, transport and dispose of two laboratory instruments containing small amounts of radioactive material at a Nevada facility. While the Company cannot predict its liability at this site, the Company believes that it will not have a material adverse effect on its financial position or results of operations. As discussed in the 1995 Form 10-K, the Company received notice from the EPA in October 1995 that it, along with several hundred other companies, may be a PRP in connection with the Spectron Superfund Site located in Elkton, Maryland. The site was operated as a hazardous waste disposal, recycling, and processing facility from 1961 to 1988. A group of PRPs allege, based on records they have collected, that the Company's share of 20 liability at this site is .0042%. The EPA has also indicated at a de minimis settlement is likely to be appropriate for this site. While the outcome of negotiations and the ultimate liability with respect to this site cannot be predicted, the Company believes that its liability at this site will not have a material adverse effect on its financial position or results of operations. As also discussed in the 1995 Form 10-K, a Remedial Investigation/Feasibility Study (RI/FS) report was submitted to the EPA in October 1994, with respect to a site in Philadelphia, Pennsylvania. Pursuant to an agreement among the PRPs, the Company is responsible for 12% of the costs of the RI/FS. Total costs of the RI/FS and associated activities prior to the issuance of a Record of Decision (ROD) by the EPA, including legal fees, are currently estimated to be $7.5 million. The Company has paid $.8 million as of March 31, 1996. The report included a number of possible remedies, the estimated costs of which range from $2 million to $90 million. In July 1995, the EPA announced its proposed remedial action plan for the site and indicated it will accept comments on the plan from any interested parties. The EPA's estimate of the costs associated with implementation of the plan is approximately $17 million. The Company cannot predict whether the EPA will include the plan in its ROD as proposed or make changes as a result of comments received. In addition, the Company cannot estimate the total extent of the EPA's administrative and oversight costs. To date, the Company has accrued $1.7 million for its share of this contingency. As also discussed in the 1995 Form 10-K, during 1993 the Company was served with Amended Complaints filed in three jurisdictions (Prince George's County, Baltimore City, and Baltimore County), in separate ongoing, consolidated proceedings each denominated "In re: Personal Injury Asbestos Case." The Company (and other defendants) were brought into these cases on a theory of premises liability under which plaintiffs argue that the Company was negligent in not providing a safe work environment for employees of its contractors who allegedly were exposed to asbestos while working on the Company's property. Initially, a total of approximately four hundred and forty-eight (448) individual plaintiffs added the Company to their Complaints. While the pleadings are not entirely clear, it appears that each plaintiff seeks $2 million in compensatory damages and $4 million in punitive damages from each defendant. In a related proceeding in the Baltimore City case, the Company was served, in September 1993, with a third party complaint by Owens Corning Fiberglass, Inc. (Owens Corning) alleging that Owens Corning was in the process of settling approximately 700 individual asbestos-related cases and seeking a judgment for contribution against the Company on the same theory of alleged negligence set forth above in the plaintiffs' case. 21 Subsequently, Pittsburgh Corning Corp. (Pittsburgh Corning) filed a third-party complaint against the Company, seeking contribution for the same plaintiffs involved in the Owens Corning third-party complaint. Since the initial filings in 1993, approximately fifty (50) individual suits have been filed against the Company. The third party complaints involving Pittsburgh Corning and Owens Corning were dismissed by the Baltimore City Court during 1994 without any payment by the Company. In 1995 and 1996, approximately four hundred (400) of the individual plaintiffs have dismissed their claims against the Company. No payments were made by the Company in connection with the dismissals. While the aggregate amount specified in the remaining suits would exceed $400 million, the Company believes the amounts are greatly exaggerated as were the claims already disposed of. The amount of total liability, if any, and any related insurance recovery cannot be precisely determined at this time; however, based on information and relevant circumstances known at this time, the Company does not believe these suits will have a material adverse effect on its financial position. However, an unfavorable decision rendered against the Company could have a material adverse effect on results of operations in the fiscal year in which a decision is rendered. The Company is involved in other legal and administrative (including environmental) proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Management is of the opinion that the final disposition of these proceedings will not have a material adverse effect on the Company's financial position or results of operations. Other - ----- In May 1995, a subsidiary of the Company, PepData, Inc. and Metricom, Inc., entered into a joint venture agreement to own and operate a wireless data communication network which will offer economical data communication services to approximately four million people in the Washington, D.C. metropolitan area. The agreement calls for the Company to invest $7 million and to own 20 percent of the joint venture company. As of March 31, 1996, the Company has invested $.1 million in the joint venture. Nonutility Subsidiary - --------------------- See the discussion on PCI in Part I, Item 2, Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition. * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * 22 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 1995 Annual Report to the Securities and Exchange Commission on Form 10-K. * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * This Quarterly Report on Form 10-Q, including the report of Price Waterhouse LLP (on page 24) will automatically be incorporated by reference in the Prospectuses constituting part of the Company's Registration Statements on Forms S-3 (Registration Nos. 33-58810 and 33-61379) and Forms S-8 (Registration Nos. 33-36798, 33-53685 and 33-54197) and in the Joint Proxy Statement/Prospectus constituting part of the Registration Statement on Form S-4 (Number 33-64799) of Constellation Energy Corporation filed under the Securities Act of 1933. Such report of Price Waterhouse 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. 23 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 March 31, 1996 and 1995, and the related consolidated statements of earnings and retained income for the three and twelve month periods then ended and the consolidated statements of cash flows for the three 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, 1995, 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 19, 1996, 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, 1995, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived. /s/ Price Waterhouse LLP Price Waterhouse LLP Washington, D.C. April 29, 1996 24 Part I FINANCIAL INFORMATION - ------ --------------------- Item 2 MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED - ------ ---------------------------------------------------- RESULTS OF OPERATIONS AND FINANCIAL CONDITION --------------------------------------------- UTILITY - ------- PROPOSED MERGER UPDATE - ---------------------- On March 29, 1996, shareholders of the Company and BGE, in separate special meetings, approved the Merger to form Constellation Energy Corporation (Constellation Energy). The Company and BGE filed a joint Application for Authorization and Approval of the Merger with the FERC on January 11, 1996, and on April 8, 1996, with the Maryland and District of Columbia Public Service Commissions. The combination of the Company and BGE will create a larger, stronger company better able to maintain the low costs which will be essential to compete effectively, and better able to contribute to economic and job development in the area. The Merger will result in lower operating costs than either company could produce alone. Over the first 10 years following the Merger, Constellation Energy expects to achieve net merger- related savings of $1.3 billion. Due to these savings, customers in the District of Columbia and Maryland will benefit from lower rates over time than they otherwise would have experienced. The applications set forth the proposed plans for Constellation Energy to share the benefits of the Merger with customers in the District of Columbia and Maryland. The proposal includes: (1) a freeze on base electric rates until at least January 1, 2000, (2) a unique bill credit for all customers if Constellation Energy achieves certain financial targets, (3) an array of economic development incentives, and (4) programs to address the energy needs of low-income customers. The Merger also requires approval from the Nuclear Regulatory Commission, the Virginia State Corporation Commission and the Pennsylvania Public Utility Commission. Completion of the approval process is expected to take until the end of the first quarter of 1997. See Part I, Item 1, Notes to Consolidated Financial Statements, (6) Commitments and Contingencies, for additional information. 25 RESULTS OF OPERATIONS - --------------------- TOTAL REVENUE Total revenue increased for the three and twelve months ended March 31, 1996, as compared to the corresponding periods in 1995. The increases in revenue from sales of electricity for the three and twelve month periods were primarily due to increases in kilowatt-hour sales of 7.2% and 4.8% for the three and twelve months ended March 31, 1996, respectively, over the corresponding periods in 1995, the effect of the 1995 base rate increase in the District of Columbia and the effect of the increase in the Demand Side Management (DSM) surcharge tariff rate in Maryland; partially offset by a decrease in fuel rate revenue. The increase in revenue for the twelve months ended March 31, 1996, also includes the recognition of $8.7 million in revenue in June 1995 compared to $5 million in June 1994 for achieving specified 1994 Maryland energy goals associated with the conservation incentive provision of the DSM surcharge tariff. The increase in kilowatt-hour sales for the three and twelve months ended March 31, 1996, was primarily attributable to the impact of blizzard- like conditions during the first quarter of 1996 which brought a record amount of snowfall to the Washington, D.C. area, as compared to the mild winter weather during the first quarter of 1995. Heating degree days for the three and twelve months were 16% and 27%, respectively, above the corresponding periods in 1995, and 11% and 14%, respectively, above the 20-year averages. In addition, the substantial increases in interchange deliveries for both the three and twelve month periods ended in 1996 reflect increases in the power sales tariff interchange transactions. 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 $(2,000) (1.7)% January 1996 District of Columbia 27,900 3.8 July 1995 Federal - Wholesale 2,300 1.8 January 1995 District of Columbia 26,700 3.9 March/June 1994 Federal - Wholesale 2,600 2.3 January 1994 OPERATING EXPENSES Fuel and purchased energy increased for the three and twelve months ended March 31, 1996, as compared to the corresponding periods ended March 31, 1995. Fuel expense increased reflecting higher customer usage of electricity and the increased volume of 26 interchange deliveries in the first quarter of 1996. Fuel expense increased slightly for the twelve months ended March 31, 1996, primarily as the result of an increase of 11.1% in net generation; partially offset by a decrease in the system average fuel cost. The increases in purchased energy for the three and twelve months ended March 31, 1996, reflect increases in energy purchased from PJM and other utilities. The unit fuel costs for the comparative periods ended March 31, were as follows: Three Twelve Months Ended Months Ended ------------ ------------- 1996 1995 1996 1995 ---- ---- ---- ---- System Average Fuel Cost per MBTU $1.82 $1.82 $1.74 $1.86 System average unit fuel cost remained stable for the three months ended and decreased for the twelve months ended March 31, 1996, as compared to the corresponding periods in 1995. The decrease in the system average unit fuel cost for the twelve months ended March 31, 1996, was primarily attributable to decreased use of cycling and peaking units which burn oil and natural gas resulting in an increase in the percent of coal contribution to the fuel mix; partially offset by an increase in net generation resulting from increased customer usage of electricity during the first quarter of 1996. The Company's major cycling and certain peaking units can burn natural gas or oil, adding flexibility in selecting the most cost-effective fuel mix. For the twelve month periods ended March 31, 1996 and 1995, the Company obtained 86% and 83%, respectively, of its system generation from coal based upon percentage of Btus. Capacity purchase payments decreased slightly for the three and twelve months ended March 31, 1996, as compared to the corresponding periods in 1995. The decreases reflect a decrease of 147 megawatts of capacity that was purchased from Pennsylvania Power and Light Company for a one year period from June 1994 through May 1995 and decreases in fixed operating and maintenance expense associated with the capacity agreements with Ohio Edison and Allegheny Power System (APS). Operating expenses other than fuel, purchased energy and capacity purchase payments increased for the three and twelve months ended March 31, 1996, as compared to the corresponding periods in 1995. The increases were principally due to increased income taxes due to higher taxable income, increased depreciation 27 and amortization expense due to additional investment in property and plant and amortization of increased amounts of conservation costs associated with the Company's DSM program and the $1.8 million paid on January 5, 1996, to all union members as part of the 1995 Labor Agreement between the Company and Local 1900 of the International Brotherhood of Electrical Workers; partially offset by a nonrecurring charge of $7.4 million taken in January 1995 for operating costs associated with the Company's Voluntary Severance Program. The increase in operating expenses other than fuel, purchased energy and capacity purchase payments for the twelve months ended March 31, 1996, also includes increased rent expense associated with the December 1994 sale and leaseback of the Company's control center system. Bad debt expense, as a percent of revenue, was .5% and .4% for the three and twelve months ended March 31, 1996, respectively, as compared to .6% and .4%, respectively, for the corresponding periods in 1995. At March 31, 1996, accounts receivable included $15.2 million, or 6.5% of outstanding receivables, due from the agencies of the District of Columbia for electric service and maintenance, of which $9.6 million was in arrears. As of April 24, 1996, the District of Columbia accounts receivable balance had been reduced to $11.7 million due to receipt of additional payments. The Company believes that amounts owed by the District of Columbia will be paid and, accordingly, has not established a bad debt reserve for this receivable balance. CAPITAL RESOURCES AND LIQUIDITY - ------------------------------- The Company's investment in property and plant, at original cost before accumulated depreciation, was $6.2 billion at March 31, 1996, an increase of $37.9 million from the investment at December 31, 1995, and an increase of $164 million from the investment at March 31, 1995. Cash invested in property and plant construction, excluding AFUDC and CCRF, amounted to $37.8 million for the three months ended March 31, 1996, and $191.3 million for the twelve months then ended. At March 31, 1996, the Company's capital structure, excluding short-term debt, long-term debt due within one year, and nonutility subsidiary debt, consisted of 46.4% long-term debt, 3.2% serial preferred stock, 3.7% redeemable serial preferred stock and 46.7% common equity. Cash from utility operations, after dividends, was $9.4 million for the three months ended March 31, 1996, and $87.7 million for the twelve months then ended as compared with $2.7 million and $96.3 million, respectively, for the same periods ended March 31, 1995. 28 Outstanding utility short-term debt totaled $286.9 million at March 31, 1996, an increase of $28.5 million from the $258.5 million outstanding at December 31, 1995, and an increase of $49.4 million from the $237.5 million outstanding at March 31, 1995. See the discussion included in Note (3) of the Notes to Consolidated Financial Statements, Capitalization, for additional information. NEW ACCOUNTING STANDARDS - ------------------------ Statements of Financial Accounting Standards (SFAS) No. 121 entitled "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" and No. 123 entitled "Accounting for Stock-Based Compensation" became effective for the Company's 1996 consolidated financial statements. See the discussion included in Note (1) of the Notes to Consolidated Financial Statements, Summary of Significant Accounting Policies, for additional information. 29 NONUTILITY SUBSIDIARY - --------------------- RESULTS OF OPERATIONS - --------------------- Reflecting transactions discussed below, PCI's earnings for the three months ended March 31, 1996, were $2.5 million ($.02 per share) compared to a loss of $4.4 million ($.04 per share) for the same period in 1995. PCI incurred a net loss of $117.6 million ($.99 per share) for the twelve months ended March 31, 1996, compared to earnings of $12.5 million ($.11 per share) for the twelve months ended March 31, 1995. PCI's loss for the twelve months ended March 31, 1996, as compared to earnings for the twelve months ended March 31, 1995, reflect the implementation of PCI's May 1995 plan to exit the aircraft equipment leasing business, resulting in noncash, after-tax charges of $121 million ($1.03 per share) in the twelve months ended March 31, 1996. Under the plan, PCI will make no new investments to increase the size of the aircraft portfolio and 13 aircraft were designated for sale over 18 to 24 months from the date the plan was announced. The book values of these aircraft were reduced to their estimated net realizable values of approximately $104 million and no depreciation or routine accrual for repair and maintenance expenditures for these aircraft has been recorded since the plan was adopted. In accordance with the plan, PCI continues to hold and closely monitor the remainder of its aircraft leasing portfolio, with the objective of identifying future opportunities for disposition of these investments on favorable terms. Depreciation of 10 aircraft has been increased to achieve book values at lease expiration that will correspond to their respective anticipated residual values. The net effect of the revised depreciation, coupled with the elimination of further depreciation on the aircraft designated for sale, will result in higher depreciation charges through 1997, and lower depreciation charges thereafter, as compared to the depreciation charges PCI would have incurred absent the plan. No adjustments were made to the remainder of PCI's aircraft leasing portfolio, which consisted of 12 aircraft under leveraged or direct finance leases. Satisfactory execution of the entire plan may be affected by future market conditions and events, which may have an impact on equipment values and sales opportunities and, in the case of the portion of the portfolio on long-term lease, the creditworthiness of PCI's lessees. During the fourth quarter of 1995, as a part of its plan to exit the aircraft equipment leasing business, PCI formed a joint venture with an affiliate of a major institutional investor to assist with the disposition and management of 19 portfolio aircraft. PCI contributed 11 aircraft from its portfolio of aircraft held for disposal, eight additional aircraft under long- 30 term leases, and a portfolio of preferred stocks to the joint venture. All of the assets of the venture are fully consolidated on PCI's financial statements with the outside investor's portion reflected as a minority interest. During January 1996, this joint venture sold two B747 aircraft. As a result of joint venture operations for the three months ended March 31, 1996, PCI's obligation for previously accrued deferred taxes was reduced, resulting in after-tax earnings of $21.6 million, after provision for transaction costs. The excess deferred taxes were recognized as a reduction of income tax expense for the current period. Future operations of the joint venture may result in additional reversal of deferred taxes. During March 1996, PCI and Atlas Air, Inc. (Atlas) settled their litigation regarding the B747-200F aircraft designated for sale by PCI. Atlas agreed to a long-term lease of the aircraft with more favorable terms for PCI. Under the revised agreement, PCI receives increased monthly rental payments and is no longer obligated for any future operating and maintenance costs associated with the aircraft. The new lease results in a reclassification of this aircraft from Assets Held for Disposal to Investment in Finance Leases. As the result of recent activity in PCI's aircraft portfolio, including the B747 aircraft sales and the current negotiation of terms for the disposition of other aircraft, PCI re-evaluated the carrying value of its portfolio of aircraft held for disposal and recorded a pre-tax charge of $12.3 million ($8 million after-tax) related to this portfolio during the first quarter of 1996. During the first quarter of 1996, PCI implemented SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of". This resulted in a pre-tax charge of $9.6 million ($6.2 million after-tax) related to PCI's investment in solar electric generating systems (SEGS) projects, reflecting revised first quarter assumptions relating to the recoverability of the investment. No additional adjustments were required as the result of the implementation of this accounting standard. In addition, PCI recorded a pre-tax charge of $9 million ($5.9 million after-tax), reflecting current assessments of the net realizable values of real estate and oil and natural gas investments. PCI has five 30-megawatt SEGS projects in the Mojave Desert in California. The Company owns 22%, 10%, 19%, 31%, and 25% of SEGS projects III through VII, respectively. The five SEGS power generation projects sell electricity to Southern California Edison Company (Edison) under 30-year Interim Standard Offer No. 4 power purchase agreements which fix the capacity charge for the term of the agreements and fix the energy rate paid by Edison for the first 10 years of the agreements. For the remaining term of the agreements, energy rates are variable, based on Edison's 31 avoided cost of generation. The SEGS projects are scheduled to begin supplying electricity at avoided cost rates at various times beginning in early 1997 through the end of 1998. In conjunction with other project investors, PCI is investigating and pursuing alternatives for these projects, including but not limited to, renegotiating the power purchase agreements and restructuring the associated non-recourse debt. If current avoided cost levels were to continue or the investors are not successful in their pursuit of other alternatives, PCI could experience reduced earnings or incur additional losses associated with these projects. PCI's investment in SEGS at March 31, 1996, was $41 million, reflecting the previously discussed writedown. PCI generates income primarily from its leasing activities and securities investments. Income from leasing activity, which includes rental income, gains on asset sales, interest income and fees totaled $23.9 million and $104 million for the three and twelve months ended March 31, 1996, respectively, compared to $23.8 million and $110.5 million for the corresponding periods in 1995. The decrease for the twelve month period was primarily due to decreased rental income from operating leases and reduced fee income. PCI's marketable securities portfolio contributed pre- tax income of $10.1 million and $37 million for the three and twelve months ended March 31, 1996, respectively, compared to $9.1 million and $35.9 million for the same periods in 1995, which results included net realized gains of $1.6 million and $1.9 million for the three and twelve months ended March 31, 1996, compared to $.1 million and $.9 million for the three and twelve months ended March 31, 1995, respectively. Other income decreased $17.6 millon and $24.5 million for the three and twelve months ended March 31, 1996, respectively, compared to the same periods in 1995. The decrease is primarily the result of the previously discussed first quarter 1996 writedowns of PCI's investments in SEGS, real estate and oil and natural gas. Expenses, before income taxes, which include interest, depreciation and operating, and administrative and general expenses totaled $53.6 million and $353.7 million for the three and twelve months ended March 31, 1996, respectively, compared to $44.5 million and $161.3 million for the same periods in 1995. The increase during the three month period comparing 1996 to 1995 was primarily due to the $12.3 million pre-tax writedown of assets held for disposal in March 1996, offset by lower repair and maintenance expenses in 1996 resulting from the implementation of the May 1995 plan to exit the aircraft equipment leasing business. The increase in expenses before income taxes for the twelve month period ended March 31, 1996, over the same period in 1995 was primarily due to charges related to the May 1995 plan and an increase in interest expense resulting from higher weighted average interest rates. 32 PCI had income tax credits of $38.8 million and $118.2 million for the three and twelve months ended March 31, 1996, respectively, and $6.3 million and $25.9 million for the corresponding periods in 1995. The increase in income tax credits for the three month period 1996 over 1995 was the result of the previously discussed deferred tax liability reduction during the first quarter of 1996. The increase in tax credits for the twelve month periods was primarily the result of the pre- tax charge to earnings as a result of the Company's decision to exit the aircraft equipment leasing business. CAPITAL RESOURCES AND LIQUIDITY - ------------------------------- The $417.4 million securities portfolio, consisting primarily of investment grade preferred stocks, provides PCI with liquidity and investment flexibility. During the first quarter of 1996, PCI reduced its marketable securities portfolio by $112.9 million as the result of calls (approximately $67.2 million) and sales of fixed rate preferred stocks, generating net pre-tax gains of $1.6 million. PCI's fixed rate portfolio is highly sensitive to fluctuations in interest rates. The decision to reduce the size of the preferred stock portfolio was made to lessen the impact of future fluctuations in interest rates, while still maintaining a substantial portfolio for liquidity purposes. The proceeds from the securities activity during the first quarter were used to pay down short-term debt. In addition, proceeds from aircraft sales also were used to pay down short- term debt. PCI's outstanding short-term debt totaled $73.2 million at March 31, 1996, a decrease of $150.1 million from the $223.4 million outstanding at December 31, 1995, and an increase of $45.8 million from the $27.4 million outstanding at March 31, 1995. During the three and twelve months ended March 31, 1996, PCI issued $78 million and $185 million in long-term debt, and debt repayments, including non-recourse debt, totaled $58.8 million and $272.1 million, respectively, for those same periods. At March 31, 1996, PCI had $316.3 million available under its Medium-Term Note Program and $400 million available under its committed bank credit facility. 33 Part II OTHER INFORMATION - ------- ----------------- Item 1 LEGAL PROCEEDINGS - ------ ----------------- See Part I, Item 1, Notes to Consolidated Financial Statements, (6) Commitments and Contingencies, for information on various legal proceedings. Item 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS - ------ --------------------------------------------------- (a) Special meeting of shareholders to approve the Merger with BGE was held on March 29, 1996. For voting results, see Form 8-K filed by the Company on April 3, 1996, incorporated herein by reference. Annual meeting of shareholders held April 24, 1996. (b) (1) Directors who were elected at the annual meeting: For Term Expiring in 1999: Roger R. Blunt, Sr. Votes cast for: 90,799,278 Votes withheld: 2,971,628 A. James Clark Votes cast for: 91,570,136 Votes withheld: 2,200,770 Ann D. McLaughlin Votes cast for: 89,128,131 Votes withheld: 4,642,775 A. Thomas Young Votes cast for: 91,650,838 Votes withheld: 2,120,068 (2) Directors whose terms of office continued after the annual meeting: H. Lowell Davis Floretta D. McKenzie John M. Derrick, Jr. Edward F. Mitchell Richard E. Marriott Peter F. O'Malley David O. Maxwell Louis A. Simpson (c) (1) The following shareholder proposal was introduced: "RESOLVED: That the shareholders of PEPCO recommend that the Board of Directors take the necessary steps to reinstate the election of directors ANNUALLY, instead of the staggered system which was recently adopted." 34 The following statement has been supplied by the shareholder submitting this proposal: "REASONS: Until recently, directors of PEPCO were elected annually by all shareholders." "The great majority of New York Stock Exchange listed corporations elect all their directors each year. "This insures that ALL directors will be more accountable to ALL shareholders each year and to a certain extent prevents the self-perpetuation of the Board." "Last year the owners of 20,209,474 shares, representing 25% of shares voting, voted FOR this proposal." The shareholder proposal was defeated. There were 56,467,610 votes cast against the proposal, 15,254,044 votes cast in support of the proposal, 3,672,877 votes abstaining and 18,376,375 broker nonvotes. 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 for their outstanding commercial promissory notes. These lines of credit were unused during 1996 and 1995. BASE RATE PROCEEDINGS - --------------------- Maryland - -------- Pursuant to a settlement agreement, base rate revenue was increased by $27 million, or 3%, effective November 1, 1993. In connection with the settlement agreement, no determination was made with respect to rate of return. The rate of return on common stock equity most recently determined for the Company in a fully litigated rate case was 12.75%, established by the Commission in a June 1991 rate increase order. The Company's Maryland DSM Surcharge, which provides for the recovery of conservation program costs over a five-year period and includes provisions for the recovery of lost revenue, a CCRF, calculated at 9.46%, on unrecovered program balances and an incentive amount based on achieving prior-year goals, was 35 increased effective July 1, 1995. The new rate will result in an increase in the annual surcharge recovery of approximately $29 million, including the initial amortization of 1995 projected program costs and the incentives of $8.7 million and $5 million for exceeding 1994 and 1993 program goals, respectively. District of Columbia - -------------------- In Formal Case No. 939, the Commission, in June 1995, authorized a $27.9 million, or 3.8%, increase in base rate revenue effective July 1995. The authorized rates are based on a 9.09% rate of return on average rate base, including an 11.1% return on common stock equity and a capital structure which excludes short-term debt. In addition, the Commission approved the Company's Least-Cost Plan filed in June 1994. A four-year DSM spending cap for the period 1995-1998 was approved, consistent with the Company's proposal to narrow the scope of DSM activities by discontinuing operation of certain DSM programs and by reducing expenditures on the remaining programs. This will enable the Company to implement cost-effective conservation programs while limiting the impact of such programs on the price of electricity. An Environmental Cost Recovery Rider (ECRR) was approved to provide for full cost recovery of actual conservation program expenditures, through a billing surcharge. Costs will be amortized over 10 years, with a return on unamortized amounts by means of a CCRF computed at the authorized rate of return. The initial rate, which reflects all actual costs expended from July 1993 through December 1994, will result in $15 million of additional revenue annually. Subsequent rate updates will be filed annually on June 1 to reflect the prior year's actual costs, subject to the annual surcharge recovery limit within the four-year spending cap for the period 1995-1998 (amounts spent in excess of the annual surcharge recovery limit, but within the four-year spending cap, are deferred for future recovery). Pre- July 1993 conservation costs receive base rate treatment. Although the Commission denied the Company's request to recover "lost revenue" due to DSM programs, through the surcharge, a process has been established whereby the Company can seek recovery of lost revenue in a separate proceeding. The Commission also increased the time period for filing Least-Cost Planning cases from two to three years. Federal - Wholesale - ------------------- The Company has a 10-year full service power supply contract with Southern Maryland Electric Cooperative, Inc. (SMECO), a wholesale 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 36 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 rates were increased by $2.3 million effective January 1, 1995. Pursuant to a new agreement with SMECO for the years 1996 through 1998, a rate reduction of $2 million from the 1995 rate level became effective January 1, 1996, with an additional $2.5 million rate reduction scheduled to become effective January 1, 1998. SMECO has agreed not to give the Company a notice of reduction or termination of service prior to December 15, 1998. Federal - Interchange and Purchased Energy - ------------------------------------------ The Company's generating and transmission facilities are interconnected with the other members of the Pennsylvania-New Jersey-Maryland Interconnection Association (PJM) and other utilities. The pricing of most PJM internal economy energy transactions is based upon "split savings" so that the price of such energy is halfway between the cost that the purchaser would incur if the energy were supplied by its own sources and the cost of production to the company actually supplying the energy. In November 1995, the PJM members filed with the FERC a detailed proposal that offers to all generators and wholesale buyers of electricity a regional energy market and open access to PJM high-voltage transmission lines. Under the proposal, PJM will be transformed into an Independent System Operator (ISO), which will administer a bid-priced energy spot market that will also accommodate bilateral transactions between participants. The ISO will operate the regional energy market and administer transmission service. PJM expects to implement the new structure by year-end 1996. In addition to PJM interchange activity, the Company has interconnection agreements with APS and Virginia Power. These agreements provide a mechanism and the flexibility to purchase power from these parties or from others with whom they are interconnected on an as-needed basis in amounts mutually agreed to from time-to-time pursuant to negotiated rates, terms and conditions. In addition, during 1995 the Company entered into an agreement with PECO Energy Company (PECO) to purchase up to 300, but not less than 200, megawatt-hours of energy each hour beginning in June 1995. The purchase of energy by the Company under this agreement was terminated on January 31, 1996. Pursuant to the Company's long-term capacity purchase agreements with Ohio Edison and APS, the Company is purchasing 450 megawatts of capacity and associated energy through the year 2005. The monthly capacity commitment under these agreements, excluding an allocation of fixed operating and maintenance cost, is $18,060 per megawatt effective January 1994, with provision 37 for escalation in 1999. In addition, from June 1994 through May 1995, the Company purchased 147 megawatts of capacity from Pennsylvania Power and Light Company. RESTRUCTURING OF THE BULK POWER MARKET - -------------------------------------- In March 1995, the FERC issued a Notice of Proposed Rulemaking (NOPR) on competition in the wholesale energy market. The FERC's goal is to achieve greater competition in the bulk power market through open access to utilities' high voltage transmission lines. The Company, through its membership in PJM, endorses the goals of the FERC. PJM has many years of experience in providing economically efficient transmission and generation services throughout the Mid-Atlantic region, and has achieved for its members, including the Company, significant cost savings through shared generating reserves and integrated operations. In order to meet the FERC's goals, the PJM members plan to implement significant market-oriented changes by year-end 1996, which will support broader market participation and achieve even greater efficiencies. The PJM members are working to transform today's coordinated cost-based pool dispatch into a vigorous price-based regional energy market operating under a standard of transmission service comparability. The Company, together with PJM, supports the evolution of new market-based structures to make competition truly effective. In early 1995, the FERC approved a power sales tariff, filed by the Company, which allows both sales from Company-owned generation and sales of energy purchased by the Company. This tariff expands the Company's opportunities to participate in direct energy sales with other utilities and power marketers. Through the use of similar tariffs, many other parties are now in a position to buy and sell energy. The Company is actively encouraging this market by buying energy for its own use and for contemporaneous resale, when economic transactions are available. Revenues associated with the power sales tariff were $43 million and $66 million, respectively, for the three and twelve months ended March 31, 1996. On January 25, 1996, the Company filed an open-access transmission tariff with the FERC, which provides for open access to the Company's transmission system at specified rates. The Company's filing was accepted by FERC, effective March 26, 1996. The proposed rates are subject to refund pending final approval. Non-rate terms and conditions are subject to the outcome of FERC's open access NOPR proceeding. 38 PEAK LOAD, SALES, CONSERVATION, AND CONSTRUCTION - ------------------------------------------------ AND GENERATING CAPACITY ----------------------- Peak Load and Sales Data - ------------------------ Kilowatt-hour sales increased 7.2% and 4.8% for the three months and twelve months ended March 31, 1996, as compared to sales for the corresponding periods ended March 31, 1995. The increases in sales were primarily attributable to the impact of blizzard-like conditions during the first quarter of 1996 which brought a record amount of snowfall to the Washington, D.C. area, as compared to the mild winter weather during the first quarter of 1995. Heating degree days for the three and twelve months ended March 31, 1996, were 16% and 27%, respectively, above the corresponding periods in 1995, and 11% and 14% over the 20-year averages. Assuming future weather conditions approximate historical averages, the Company expects its compound annual growth in kilowatt-hour sales to range between 1% and 2% over the next decade. The 1995 summer peak demand of 5,732 megawatts occurred on August 4, 1995. This compares with the 1994 summer peak demand of 5,660 megawatts, and the all-time summer peak demand of 5,769 megawatts which occurred in July 1991. The Company's present generation capability, including capacity purchase contracts, is 6,576 megawatts. To meet the 1995 summer peak demand, the Company had approximately 270 megawatts available from its dispatchable energy use management programs. Based on average weather conditions, the Company estimates that its peak demand will grow at a compound annual rate of approximately 1%, reflecting continuing success with conservation and energy use management programs and anticipated service area growth trends. The 1995-1996 winter season peak demand of 4,831 megawatts was 3.6% below the all-time winter peak demand of 5,010 megawatts which was established in January 1994. Conservation - ------------ The Company's conservation and energy use management programs (EUM) are designed to curb growth in demand in order to defer the need for construction of additional generating capacity and to cost-effectively increase the efficiency of energy use. To reduce the near-term upward pressure on customer rates and bills, the Company has, since 1994, phased out several conservation programs and reduced rebate levels for others. By narrowing its conservation offerings and limiting conservation spending, the Company expects to continue to encourage its customers to use energy efficiently without significantly increasing electricity prices. 39 The Company invested approximately $15 million in energy conservation programs in the first quarter of 1996 and approximately $100 million during 1995. The Company recovers the costs of its conservation programs in its Maryland jurisdiction through a base rate surcharge which amortizes costs over a five- year period and permits the Company to earn a return on its conservation investment while receiving compensation for lost revenue. In addition, when the Company's performance exceeds its annual goals, the Company earns a performance bonus. The Company was awarded a bonus of $8.7 million in 1995, based on 1994 performance. In the District of Columbia, conservation costs are amortized over 10 years with an accrued return on unamortized costs. It is estimated that, in 1995, peak load reductions of over 600 megawatts were achieved from conservation and energy use management programs and that additional peak load reductions of approximately 430 megawatts will be achieved in the next five years. The Company also estimates that, in 1995, energy savings of more than 1.2 billion kilowatt-hours were realized through operation of its conservation and energy use management programs. See the discussions included in Summary of Significant Accounting Policies, Total Revenue, and Base Rate Proceedings, for additional information. Construction and Generating Capacity - ------------------------------------ Construction expenditures, excluding AFUDC, are projected to total $1.1 billion for the five-year period 1996 through 2000, which includes $112 million of estimated Clean Air Act expenditures. In 1996, construction expenditures are projected to total $170 million, which includes $6 million of estimated Clean Air Act expenditures. As a result of lower rates of projected load growth resulting in large part from implementing economical conservation programs, the Company previously reduced its projected construction expenditures by $155 million in 1994 and $425 million in 1993. The Company plans to finance its construction program primarily through funds provided by operations. The Company has implemented cost-effective plans for complying with Phase I of the Clean Air Act (CAA) which requires the reduction of sulfur dioxide and nitrogen oxides emissions to achieve prescribed standards. Boiler burner equipment for nitrogen oxides emissions control has been replaced and the use of lower-sulfur coal has been instituted at the Company's Phase I affected stations, Chalk Point and Morgantown. Anticipated capital expenditures for complying with the second phase of the CAA total $112 million over the next five years. The Company's plans call for continued replacement of boiler burner equipment for nitrogen oxides emissions control and further use of lower-sulfur fuel and cofiring with natural gas for sulfur 40 dioxide (SO2) emissions control. If economical, the Company will purchase SO2 emission allowances in lieu of burning lower-sulfur fuel. A 32-megawatt municipally financed resource recovery facility in Montgomery County, Maryland, began commercial operation in August 1995. Under the contract covering this project, the Company will initially purchase energy without capacity payment obligations. In addition, the Company has an agreement with Panda Brandywine L.P. (Panda) for a 230-megawatt gas-fueled combined-cycle cogeneration project in Prince George's County, Maryland, scheduled for operation in the fourth quarter of 1996. The 25-year agreement currently requires capacity purchase payments to Panda of approximately $1.6 million per month from January 1, 1997, through December 31, 1998. Capacity payments in 1999 and 2000 are approximately $3 million per month and generally increase thereafter, peaking at approximately $4.5 million per month. The project was financed in April 1995 and is approximately 65% complete at March 31, 1996. The Company projects that existing contracts for nonutility generation and the Company's commitment to conservation will provide adequate reserve margins to meet customers' needs well beyond the year 2000. In 1995, the Maryland Public Service Commission issued an order that requires electric utilities to competitively procure future capacity resources. The Company believes that completion of the first combined-cycle unit at its Station H facility in Dickerson, Maryland, currently scheduled for 2004, is likely to be the most cost-effective alternative for the next increment of capacity. This will add a steam cycle to the two existing combustion turbine units. SELECTED NONUTILITY SUBSIDIARY FINANCIAL INFORMATION - ---------------------------------------------------- The Company's wholly owned nonutility subsidiary, Potomac Capital Investment Corporation (PCI), was organized in late 1983 to provide a vehicle for ongoing nonutility investment business. The principal assets of PCI are portfolios of securities and equipment leases, and to a lesser extent real estate and other investments. The $417.4 million securities portfolio, consisting primarily of investment grade preferred stocks, provides PCI with significant liquidity and flexibility to participate in additional investment opportunities. The Company's equity investment in PCI was $162.7 million and $270 million at March 31, 1996 and 1995, respectively. 41 Consolidated Statements of Earnings: - -----------------------------------
Three Twelve Months Ended Months Ended March 31, March 31, ---------------------- ----------------------- 1996 1995 1996 1995 --------- -------- --------- -------- (Thousands of Dollars) Income Leasing activities $ 23,917 $ 23,826 $ 103,956 $110,548 Marketable securities 10,058 9,145 37,035 35,934 Other (16,662) 914 (23,072) 1,400 --------- -------- --------- -------- 17,313 33,885 117,919 147,882 --------- -------- --------- -------- Interest 22,129 22,313 91,454 86,596 Administrative and general 5,363 2,631 13,208 10,380 Depreciation and operating 26,115 19,604 248,993 64,323 Income tax credit (38,762) (6,289) (118,181) (25,926) --------- -------- --------- -------- 14,845 38,259 235,474 135,373 --------- -------- --------- -------- Net earnings (loss) from nonutility subsidiary $ 2,468 $ (4,374) $(117,555) $ 12,509 ========= ======== ========= ======== Per share contribution (reduction) to earnings of the Company $0.02 $(.04) $(.99) $.11 ===== ===== ===== ==== Reflects non-recurring, noncash, after-tax charges of $121 million or $1.03 per share related to the 1995 decision to exit the aircraft business. 42
STATISTICAL DATA - ----------------
Three Months Ended Twelve Months Ended March 31, March 31, --------------------------------- ------------------------------------- 1996 1995 % Change 1996 1995 % Change -------- -------- -------- ---------- ---------- -------- Revenue from Sales ------------------ of Electricity -------------- (Thousands of Dollars) Residential $126,567 $112,529 12.5 $ 558,555 $ 517,390 8.0 General Service 204,728 201,829 1.4 1,078,041 1,066,204 1.1 Large Power Service 7,194 7,289 (1.3) 36,088 36,006 0.2 Street Lighting 3,190 3,342 (4.5) 12,403 13,491 (8.1) Rapid Transit 6,691 6,384 4.8 28,583 27,950 2.3 Wholesale 34,206 29,798 14.8 121,525 110,599 9.9 -------- -------- ---------- ---------- System $382,576 $361,171 5.9 $1,835,195 $1,771,640 3.6 ======== ======== ========== ========== Energy Sales ------------ (Millions of KWH) Residential 1,987 1,713 16.0 6,994 6,364 9.9 General Service 3,657 3,584 2.0 15,522 15,235 1.9 Large Power Service 176 171 2.9 708 685 3.4 Street Lighting 45 44 2.3 164 161 1.9 Rapid Transit 103 98 5.1 415 401 3.5 Wholesale 738 646 14.2 2,557 2,317 10.4 -------- -------- ---------- ---------- System 6,706 6,256 7.2 26,360 25,163 4.8 ======== ======== ========== ========== Average System Revenue ---------------------- per KWH (cents per KWH) 5.70 5.77 (1.2) 6.96 7.04 (1.1) ----------------------- System Peak Demand ------------------ (Thousands of KW) Summer - - 5,732 5,660 Winter - - 4,831 4,685 Net Generation -------------- (Millions of KWH) 5,265 4,396 20,104 18,102 Fuel Mix (% of Btu) ------------------- Coal (%) 89 86 86 83 Oil (%) 11 9 7 10 Gas (%) - 5 7 7 Fuel Cost per MBtu ------------------ System Average $1.82 $1.82 $1.74 $1.86 Weather Data ------------ Heating Degree Days 2,466 2,120 4,525 3,569 20 Year Average 2,223 3,979 Cooling Degree Hours - - 11,459 11,454 20 Year Average 12 11,035 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. 43
Item 6 EXHIBITS AND REPORTS ON FORM 8-K - ------ -------------------------------- (a) Exhibits Exhibit 11 - Computation 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. Exhibit 27.1 - Restated financial data schedule - filed herewith. Exhibit 27.2 - Restated financial data schedule - filed herewith. (b) Reports on Form 8-K A Current Report on Form 8-K was filed by the Company on February 6, 1996, providing detailed information and audited consolidated financial statements. The item reported on such Form 8-K was Item 7 (Financial Statements, Pro-Forma Financial Information and Exhibits.) A Current Report on Form 8-K was filed by the Company on April 3, 1996, providing details on the voting results associated with the approval of the Merger Agreement by shareholders of the Company at a special meeting held on March 29, 1996. The item reported on such Form 8-K was Item 5 (Other Events). 44 SIGNATURES ---------- Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. Potomac Electric Power Company ------------------------------ Registrant By /s/ D. R. Wraase ------------------------------ (D. R. Wraase) Senior Vice President and Chief Financial Officer April 29, 1996 - -------------- DATE 45 Exhibit 11 Computations of Earnings Per Common Share - ---------- ----------------------------------------- The following is the basis for the computation of primary and fully diluted earnings per common share for the twelve months ended March 31, 1996, and the twelve months ended December 31, 1995 and 1994:
March 31, December 31, December 31, 1996 1995 1994 ------------- ------------ ------------ Average shares outstanding for computation of primary earnings per common share 118,473,152 118,412,478 118,005,847 ============ ============ ============ Average shares outstanding for fully diluted computation: Average shares outstanding 118,473,152 118,412,478 118,005,847 Additional shares resulting from: Conversion of Serial Preferred Stock, $2.44 Convertible Series of 1966 (the "Convertible Preferred Stock") 37,491 38,255 48,110 Conversion of 7% Convertible Debentures 2,421,539 2,469,639 2,531,244 Conversion of 5% Convertible Debentures 3,392,500 3,392,500 3,392,500 ------------ ------------ ------------ Average shares outstanding for computation of fully diluted earnings per common share 124,324,682 124,312,872 123,977,701 ============ ============ ============ Earnings applicable to common stock $96,328,000 $77,540,000 $210,725,000 Add: Dividends paid or accrued on Convertible Preferred Stock 15,000 16,000 20,000 Interest paid or accrued on Convertible Debentures, net of related taxes 6,419,000 6,475,000 6,537,000 ------------ ------------ ------------ Earnings applicable to common stock, assuming conversion of convertible securities $102,762,000 $84,031,000 $217,282,000 ============ ============ ============ Primary earnings per common share $0.81 $0.65 $1.79 Fully diluted earnings per common share $0.83 $0.68 $1.75 This calculation is submitted in accordance with Regulation S-K item 601 (b)(11) although it is contrary to paragraph 40 of APB No. 15 because it produces an antidilutive result for the twelve months ended March 31, 1996, and December 31, 1995. In addition, the valuation is not required by footnote 2 to paragraph 14 of APB No. 15 for 1994 because it results in dilution of less than 3%. 46
Exhibit 12 Computation of Ratios - ---------- --------------------- The computations of the coverage of fixed charges, excluding the cumulative effect of the 1992 accounting change, before income taxes, and the coverage of combined fixed charges and preferred dividends for the twelve months ended March 31, 1996, and for each of the preceeding five years on the basis of parent company operations only, are as follows.
Twelve Months For The Year Ended December 31, Ended --------------------------------------------------------- March 31, 1996 1995 1994 1993 1992 1991 --------- --------- --------- --------- --------- --------- (Thousands of Dollars) Net income before cumulative effect of accounting change $230,652 $218,788 $208,074 $216,478 $172,599 $186,813 Taxes based on income 139,439 129,439 116,648 107,223 76,965 80,988 --------- --------- --------- --------- --------- --------- Income before taxes and cumulative effect of accounting change 370,091 348,227 324,722 323,701 249,564 267,801 --------- --------- --------- --------- --------- --------- Fixed charges: Interest charges 148,174 146,558 139,210 141,393 138,097 138,512 Interest factor in rentals 23,347 23,431 6,300 5,859 6,140 5,690 --------- --------- --------- --------- --------- --------- Total fixed charges 171,521 169,989 145,510 147,252 144,237 144,202 --------- --------- --------- --------- --------- --------- Income before income taxes, cumulative effect of accounting change and fixed charges $541,612 $518,216 $470,232 $470,953 $393,801 $412,003 ========= ========= ========= ========= ========= ========= Coverage of fixed charges 3.16 3.05 3.23 3.20 2.73 2.86 ==== ==== ==== ==== ==== ==== Preferred dividend requirements $16,769 $16,851 $16,437 $16,255 $14,392 $12,298 --------- --------- --------- --------- --------- --------- Ratio of pre-tax income to net income 1.60 1.59 1.56 1.50 1.45 1.43 --------- --------- --------- --------- --------- --------- Preferred dividend factor $26,830 $26,793 $25,642 $24,383 $20,868 $17,586 --------- --------- --------- --------- --------- --------- Total fixed charges and preferred dividends $198,351 $196,782 $171,152 $171,635 $165,105 $161,788 ========= ========= ========= ========= ========= ========= Coverage of combined fixed charges and preferred dividends 2.73 2.63 2.75 2.74 2.39 2.55 ==== ==== ==== ==== ==== ==== 47
Exhibit 12 Computation of Ratios - ---------- --------------------- The computations of the coverage of fixed charges, excluding the cumulative effect of the 1992 accounting change, before income taxes, and the coverage of combined fixed charges and preferred dividends for the twelve months ended March 31, 1996, 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 --------------------------------------------------------- March 31, 1996 1995 1994 1993 1992 1991 --------- --------- --------- --------- --------- --------- (Thousands of Dollars) Net income before cumulative effect of accounting change $113,097 $94,391 $227,162 $241,579 $200,760 $210,164 Taxes based on income 21,258 43,731 93,953 62,145 79,481 80,737 --------- --------- --------- --------- --------- --------- Income before taxes and cumulative effect of accounting change 134,355 138,122 321,115 303,724 280,241 290,901 --------- --------- --------- --------- --------- --------- Fixed charges: Interest charges 240,190 238,724 224,514 221,312 226,453 225,323 Interest factor in rentals 25,747 26,685 9,938 9,257 6,599 6,080 --------- --------- --------- --------- --------- --------- Total fixed charges 265,937 265,409 234,452 230,569 233,052 231,403 --------- --------- --------- --------- --------- --------- Nonutility subsidiary capitalized interest (562) (529) (521) (2,059) (2,200) (6,542) --------- --------- --------- --------- --------- --------- Income before income taxes, cumulative effect of accounting change and fixed charges $399,730 $403,002 $555,046 $532,234 $511,093 $515,762 ======== ======== ======== ======== ======== ======== Coverage of fixed charges 1.50 1.52 2.37 2.31 2.19 2.23 ==== ==== ==== ==== ==== ==== Preferred dividend requirements $16,769 $16,851 $16,437 $16,255 $14,392 $12,298 --------- --------- --------- --------- --------- --------- Ratio of pre-tax income to net income 1.19 1.46 1.41 1.26 1.40 1.38 --------- --------- --------- --------- --------- --------- Preferred dividend factor $19,955 $24,602 $23,176 $20,481 $20,149 $16,971 --------- --------- --------- --------- --------- --------- Total fixed charges and preferred dividends $285,892 $290,011 $257,628 $251,050 $253,201 $248,374 ======== ======== ======== ======== ======== ======== Coverage of combined fixed charges and preferred dividends 1.40 1.39 2.15 2.12 2.02 2.08 ==== ==== ==== ==== ==== ==== 48
Exhibit 15 April 29, 1996 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 April 29, 1996, (issued pursuant to the provisions of Statement on Auditing Standards No. 71) in the Prospectuses constituting parts of the Registration Statements (Numbers 33-36798, 33-53685 and 33-54197) on Forms S-8 filed on September 12, 1990, May 18, 1994 and June 17, 1994, respectively, and (Numbers 33-58810 and 33-61379) on Forms S-3 filed on February 26, 1993 and July 28, 1995, respectively, and in the Joint Proxy Statement/Prospectus constituting part of the Registration Statement (Number 33-64799) on Form S-4 of Constellation Energy Corporation filed on December 7, 1995. We are also aware of our responsibilities under the Securities Act of 1933. Very truly yours, /s/ Price Waterhouse LLP Price Waterhouse LLP Washington, D.C. 49 EX-27 2 FINANCIAL DATA SCHEDULE
UT 1 POTOMAC CAPITAL INVESTMENT CORPORATION 1,000 3-MOS DEC-31-1996 JAN-01-1996 MAR-31-1996 PER-BOOK 4,376,480 0 413,702 681,462 1,445,040 6,916,684 118,495 1,010,490 695,521 1,824,506 143,485 125,319 1,817,727 3,540 0 283,400 25,000 0 164,677 20,772 2,508,258 6,916,684 436,593 8,171 384,395 392,566 44,027 5,960 49,987 35,253 14,734 4,160 10,574 49,152 127,800 76,571 $.09 0 Included on the Balance Sheet in the caption "Short-term debt." Total annualized interest costs for all utility long-term debt outstanding at March 31, 1996. If all the convertible preferred stock and debentures were converted into common stock, the result would be anti-dilutive.
EX-27 3 FINANCIAL DATA SCHEDULE
UT 1 POTOMAC CAPITAL INVESTMENT CORPORATION 1,000 12-MOS 9-MOS 6-MOS DEC-31-1995 DEC-31-1995 DEC-31-1995 JAN-01-1995 JAN-01-1995 JAN-01-1995 DEC-31-1995 SEP-30-1995 JUN-30-1995 PER-BOOK PER-BOOK PER-BOOK 4,378,269 4,371,863 4,357,551 0 0 0 431,204 533,513 454,664 671,572 640,784 628,161 1,637,105 1,599,515 1,515,821 7,118,150 7,145,675 6,956,197 118,495 118,493 118,486 1,010,521 1,010,556 1,010,593 742,296 784,026 689,475 1,871,312 1,913,075 1,818,554 143,485 143,485 143,485 125,325 125,341 125,401 1,817,077 1,816,847 1,703,370 3,540 0 0 0 0 0 254,925 68,750 354,000 26,280 124,800 65,000 0 0 0 165,235 165,771 166,304 20,772 20,772 20,772 2,690,199 2,766,834 2,559,311 7,118,150 7,145,675 6,956,197 1,876,102 1,473,852 810,268 128,460 125,320 34,394 1,399,901 1,043,239 653,817 1,528,361 1,168,559 688,211 347,741 305,293 122,057 (117,560) (118,252) (115,262) 230,181 187,041 6,795 135,790 101,904 67,605 94,391 85,137 (60,810) 16,851 12,675 8,475 77,540 72,462 (69,285) 196,469 147,316 98,164 127,900 128,500 123,600 376,722 310,504 96,381 $.65 $.61 ($.59) 0 0 0 Included on the Balance Sheet in the caption "Short-term debt." Total annualized interest costs for all utility long-term debt outstanding. If all the convertible preferred stock and debentures were converted into common stock, the result would be anti-dilutive.
EX-27 4 FINANCIAL DATA SCHEDULE
UT 1 POTOMAC CAPITAL INVESTMENT CORPORATION 1,000 3-MOS 12-MOS 9-MOS DEC-31-1995 DEC-31-1994 DEC-31-1994 JAN-01-1995 JAN-01-1994 JAN-01-1994 MAR-31-1995 DEC-31-1994 SEP-30-1994 PER-BOOK PER-BOOK PER-BOOK 4,353,341 4,327,434 4,284,889 0 0 0 372,449 425,138 492,671 588,622 568,069 556,296 1,670,401 1,681,254 1,703,761 6,984,813 7,001,895 7,037,617 118,349 118,248 118,147 1,008,180 1,006,526 1,004,762 785,792 830,524 877,755 1,912,321 1,955,298 2,000,664 143,562 143,563 145,063 125,405 125,409 125,414 1,727,848 1,723,399 1,768,296 0 0 0 0 0 0 237,525 189,600 232,675 40,000 45,445 17,000 0 0 0 166,817 167,324 30,672 20,772 20,772 5,539 2,610,563 2,631,085 2,712,294 6,984,813 7,001,895 7,037,617 364,909 1,823,074 1,467,971 (421) 119,859 121,800 334,512 1,378,722 1,051,367 334,091 1,498,581 1,173,167 30,818 324,493 294,804 (1,873) 29,796 13,074 28,945 354,289 307,878 32,917 127,127 94,469 (3,972) 227,162 213,409 4,241 16,437 12,341 (8,213) 210,725 201,068 49,046 195,755 146,758 123,600 123,700 123,600 60,091 376,450 283,471 ($.07) $1.79 $1.70 0 0 0 Included on the Balance Sheet in the caption "Short-term debt." Total annualized interest costs for all utility long-term debt outstanding. No material dilution would occur if all the convertible preferred stock and debentures were converted into common stock.
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