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
<TABLE>
Part I FINANCIAL INFORMATION
- ------ ---------------------
Item 1 CONSOLIDATED FINANCIAL STATEMENTS
- ------ ---------------------------------
POTOMAC ELECTRIC POWER COMPANY
Consolidated Statements of Earnings and Retained Income
(Unaudited)
-------------------------------------------------------
<CAPTION>
Three Months Ended Twelve Months Ended
March 31, March 31,
-------------------- ----------------------
1996 1995 1996 1995
--------- --------- ---------- -----------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
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
</TABLE>
<TABLE>
POTOMAC ELECTRIC POWER COMPANY
Consolidated Balance Sheets
(Unaudited at March 31, 1996 and 1995)
--------------------------------------
<CAPTION>
March 31, December 31, March 31,
ASSETS 1996 1995 1995
------ ------------- ------------- -------------
(Thousands of Dollars)
<S> <C> <C> <C>
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
</TABLE>
<TABLE>
POTOMAC ELECTRIC POWER COMPANY
Consolidated Statements of Cash Flows
(Unaudited)
-------------------------------------
<CAPTION>
Three Months Ended Twelve Months Ended
March 31, March 31,
----------------------- -----------------------
1996 1995 1996 1995
--------- --------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
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
</TABLE>
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
<TABLE>
(2) INCOME TAXES
- ----------------
Provisions for Income Taxes
- ---------------------------
<CAPTION>
Three Months Ended Twelve Months Ended
March 31, March 31,
-------------------- -----------------------
1996 1995 1996 1995
-------- -------- ----------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
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
</TABLE>
<TABLE>
Reconciliation of Consolidated Income Tax Expense
- -------------------------------------------------
<CAPTION>
Three Months Ended Twelve Months Ended
March 31, March 31,
-------------------- -----------------------
1996 1995 1996 1995
-------- -------- ----------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
(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
</TABLE>
<TABLE>
Components of Consolidated Deferred Tax Liabilities (Assets)
- ------------------------------------------------------------
<CAPTION>
Mar. 31, Dec. 31, Mar. 31,
1996 1995 1995
--------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C>
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
</TABLE>
(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
<TABLE>
(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.
<CAPTION>
March 31, December 31, March 31,
1996 1995 1995
-------------------------- ------------------------- -------------------------
Carrying Fair Carrying Fair Carrying Fair
Amount Value Amount Value Amount Value
----------- ---------- ---------- ---------- ---------- ----------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
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
</TABLE>
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
<TABLE>
Consolidated Statements of Earnings:
- -----------------------------------
<CAPTION>
Three Twelve
Months Ended Months Ended
March 31, March 31,
---------------------- -----------------------
1996 1995 1996 1995
--------- -------- --------- --------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
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)<F1> $ 12,509
========= ======== ========= ========
Per share contribution
(reduction) to earnings of
the Company $0.02 $(.04) $(.99)<F1> $.11
===== ===== ===== ====
<FN>
<F1>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.
</FN>
42
</TABLE>
<TABLE>
STATISTICAL DATA
- ----------------
<CAPTION>
Three Months Ended Twelve Months Ended
March 31, March 31,
--------------------------------- -------------------------------------
1996 1995 % Change 1996 1995 % Change
-------- -------- -------- ---------- ---------- --------
<S> <C> <C> <C> <C> <C> <C>
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 <F1> 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 <F1> 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).
<FN>
<F1> Large Power Service customers are served at a voltage of 66KV or higher.
</FN>
43
</TABLE>
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
<TABLE>
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:
<CAPTION>
March 31, December 31, December 31,
1996 1995 1994
------------- ------------ ------------
<S> <C> <C> <C>
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
<FN>
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%.
</FN>
46
</TABLE>
<TABLE>
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.
<CAPTION>
Twelve
Months For The Year Ended December 31,
Ended ---------------------------------------------------------
March 31,
1996 1995 1994 1993 1992 1991
--------- --------- --------- --------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
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
</TABLE>
<TABLE>
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.
<CAPTION>
Twelve
Months For The Year Ended December 31,
Ended ---------------------------------------------------------
March 31,
1996 1995 1994 1993 1992 1991
--------- --------- --------- --------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
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
</TABLE>
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
<TABLE> <S> <C>
<ARTICLE> UT
<SUBSIDIARY>
<NUMBER> 1
<NAME> POTOMAC CAPITAL INVESTMENT CORPORATION
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> MAR-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,376,480
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 413,702
<TOTAL-DEFERRED-CHARGES> 681,462
<OTHER-ASSETS> 1,445,040
<TOTAL-ASSETS> 6,916,684
<COMMON> 118,495
<CAPITAL-SURPLUS-PAID-IN> 1,010,490
<RETAINED-EARNINGS> 695,521
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,824,506
143,485
125,319
<LONG-TERM-DEBT-NET> 1,817,727
<SHORT-TERM-NOTES> 3,540<F1>
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 283,400<F1>
<LONG-TERM-DEBT-CURRENT-PORT> 25,000
0
<CAPITAL-LEASE-OBLIGATIONS> 164,677
<LEASES-CURRENT> 20,772
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,508,258
<TOT-CAPITALIZATION-AND-LIAB> 6,916,684
<GROSS-OPERATING-REVENUE> 436,593
<INCOME-TAX-EXPENSE> 8,171
<OTHER-OPERATING-EXPENSES> 384,395
<TOTAL-OPERATING-EXPENSES> 392,566
<OPERATING-INCOME-LOSS> 44,027
<OTHER-INCOME-NET> 5,960
<INCOME-BEFORE-INTEREST-EXPEN> 49,987
<TOTAL-INTEREST-EXPENSE> 35,253
<NET-INCOME> 14,734
4,160
<EARNINGS-AVAILABLE-FOR-COMM> 10,574
<COMMON-STOCK-DIVIDENDS> 49,152
<TOTAL-INTEREST-ON-BONDS> 127,800<F2>
<CASH-FLOW-OPERATIONS> 76,571
<EPS-PRIMARY> $.09
<EPS-DILUTED> 0<F3>
<FN>
<F1>Included on the Balance Sheet in the caption "Short-term debt."
<F2>Total annualized interest costs for all utility long-term debt outstanding
at March 31, 1996.
<F3>If all the convertible preferred stock and debentures were converted into
common stock, the result would be anti-dilutive.
</FN>
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<RESTATED>
<SUBSIDIARY>
<NUMBER> 1
<NAME> POTOMAC CAPITAL INVESTMENT CORPORATION
<MULTIPLIER> 1,000
<S> <C> <C> <C>
<PERIOD-TYPE> 12-MOS 9-MOS 6-MOS
<FISCAL-YEAR-END> DEC-31-1995 DEC-31-1995 DEC-31-1995
<PERIOD-START> JAN-01-1995 JAN-01-1995 JAN-01-1995
<PERIOD-END> DEC-31-1995 SEP-30-1995 JUN-30-1995
<BOOK-VALUE> PER-BOOK PER-BOOK PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,378,269 4,371,863 4,357,551
<OTHER-PROPERTY-AND-INVEST> 0 0 0
<TOTAL-CURRENT-ASSETS> 431,204 533,513 454,664
<TOTAL-DEFERRED-CHARGES> 671,572 640,784 628,161
<OTHER-ASSETS> 1,637,105 1,599,515 1,515,821
<TOTAL-ASSETS> 7,118,150 7,145,675 6,956,197
<COMMON> 118,495 118,493 118,486
<CAPITAL-SURPLUS-PAID-IN> 1,010,521 1,010,556 1,010,593
<RETAINED-EARNINGS> 742,296 784,026 689,475
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,871,312 1,913,075 1,818,554
143,485 143,485 143,485
125,325 125,341 125,401
<LONG-TERM-DEBT-NET> 1,817,077 1,816,847 1,703,370
<SHORT-TERM-NOTES> 3,540<F1> 0 0
<LONG-TERM-NOTES-PAYABLE> 0 0 0
<COMMERCIAL-PAPER-OBLIGATIONS> 254,925<F1> 68,750<F1> 354,000<F1>
<LONG-TERM-DEBT-CURRENT-PORT> 26,280 124,800 65,000
0 0 0
<CAPITAL-LEASE-OBLIGATIONS> 165,235 165,771 166,304
<LEASES-CURRENT> 20,772 20,772 20,772
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,690,199 2,766,834 2,559,311
<TOT-CAPITALIZATION-AND-LIAB> 7,118,150 7,145,675 6,956,197
<GROSS-OPERATING-REVENUE> 1,876,102 1,473,852 810,268
<INCOME-TAX-EXPENSE> 128,460 125,320 34,394
<OTHER-OPERATING-EXPENSES> 1,399,901 1,043,239 653,817
<TOTAL-OPERATING-EXPENSES> 1,528,361 1,168,559 688,211
<OPERATING-INCOME-LOSS> 347,741 305,293 122,057
<OTHER-INCOME-NET> (117,560) (118,252) (115,262)
<INCOME-BEFORE-INTEREST-EXPEN> 230,181 187,041 6,795
<TOTAL-INTEREST-EXPENSE> 135,790 101,904 67,605
<NET-INCOME> 94,391 85,137 (60,810)
16,851 12,675 8,475
<EARNINGS-AVAILABLE-FOR-COMM> 77,540 72,462 (69,285)
<COMMON-STOCK-DIVIDENDS> 196,469 147,316 98,164
<TOTAL-INTEREST-ON-BONDS> 127,900<F2> 128,500<F2> 123,600<F2>
<CASH-FLOW-OPERATIONS> 376,722 310,504 96,381
<EPS-PRIMARY> $.65 $.61 ($.59)
<EPS-DILUTED> 0<F3> 0<F3> 0<F3>
<FN>
<F1>Included on the Balance Sheet in the caption "Short-term debt."
<F2>Total annualized interest costs for all utility long-term debt outstanding.
<F3>If all the convertible preferred stock and debentures were converted into
common stock, the result would be anti-dilutive.
</FN>
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<RESTATED>
<SUBSIDIARY>
<NUMBER> 1
<NAME> POTOMAC CAPITAL INVESTMENT CORPORATION
<MULTIPLIER> 1,000
<S> <C> <C> <C>
<PERIOD-TYPE> 3-MOS 12-MOS 9-MOS
<FISCAL-YEAR-END> DEC-31-1995 DEC-31-1994 DEC-31-1994
<PERIOD-START> JAN-01-1995 JAN-01-1994 JAN-01-1994
<PERIOD-END> MAR-31-1995 DEC-31-1994 SEP-30-1994
<BOOK-VALUE> PER-BOOK PER-BOOK PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,353,341 4,327,434 4,284,889
<OTHER-PROPERTY-AND-INVEST> 0 0 0
<TOTAL-CURRENT-ASSETS> 372,449 425,138 492,671
<TOTAL-DEFERRED-CHARGES> 588,622 568,069 556,296
<OTHER-ASSETS> 1,670,401 1,681,254 1,703,761
<TOTAL-ASSETS> 6,984,813 7,001,895 7,037,617
<COMMON> 118,349 118,248 118,147
<CAPITAL-SURPLUS-PAID-IN> 1,008,180 1,006,526 1,004,762
<RETAINED-EARNINGS> 785,792 830,524 877,755
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,912,321 1,955,298 2,000,664
143,562 143,563 145,063
125,405 125,409 125,414
<LONG-TERM-DEBT-NET> 1,727,848 1,723,399 1,768,296
<SHORT-TERM-NOTES> 0 0 0
<LONG-TERM-NOTES-PAYABLE> 0 0 0
<COMMERCIAL-PAPER-OBLIGATIONS> 237,525<F1> 189,600<F1> 232,675<F1>
<LONG-TERM-DEBT-CURRENT-PORT> 40,000 45,445 17,000
0 0 0
<CAPITAL-LEASE-OBLIGATIONS> 166,817 167,324 30,672
<LEASES-CURRENT> 20,772 20,772 5,539
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,610,563 2,631,085 2,712,294
<TOT-CAPITALIZATION-AND-LIAB> 6,984,813 7,001,895 7,037,617
<GROSS-OPERATING-REVENUE> 364,909 1,823,074 1,467,971
<INCOME-TAX-EXPENSE> (421) 119,859 121,800
<OTHER-OPERATING-EXPENSES> 334,512 1,378,722 1,051,367
<TOTAL-OPERATING-EXPENSES> 334,091 1,498,581 1,173,167
<OPERATING-INCOME-LOSS> 30,818 324,493 294,804
<OTHER-INCOME-NET> (1,873) 29,796 13,074
<INCOME-BEFORE-INTEREST-EXPEN> 28,945 354,289 307,878
<TOTAL-INTEREST-EXPENSE> 32,917 127,127 94,469
<NET-INCOME> (3,972) 227,162 213,409
4,241 16,437 12,341
<EARNINGS-AVAILABLE-FOR-COMM> (8,213) 210,725 201,068
<COMMON-STOCK-DIVIDENDS> 49,046 195,755 146,758
<TOTAL-INTEREST-ON-BONDS> 123,600<F2> 123,700<F2> 123,600<F2>
<CASH-FLOW-OPERATIONS> 60,091 376,450 283,471
<EPS-PRIMARY> ($.07) $1.79 $1.70
<EPS-DILUTED> 0<F3> 0<F3> 0<F3>
<FN>
<F1>Included on the Balance Sheet in the caption "Short-term debt."
<F2>Total annualized interest costs for all utility long-term debt outstanding.
<F3>No material dilution would occur if all the convertible preferred stock and
debentures were converted into common stock.
</FN>
</TABLE>
