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 September 30, 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 September 30, 1996
- -------------------------- ---------------------------------
Common Stock, $1 par value 118,497,681
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....................................... 9
(3) Capitalization..................................... 12
(4) Fair Value of Financial Instruments................ 14
(5) Marketable Securities.............................. 16
(6) Commitments and Contingencies...................... 18
Report of Independent Accountants on Review of Interim
Financial Information.................................. 23
Item 2 - Management's Discussion and Analysis of Consolidated
Results of Operations and Financial Condition
Utility
Proposed Merger Update................................. 24
Results of Operations.................................. 25
Capital Resources and Liquidity........................ 28
Nonutility Subsidiary
Results of Operations.................................. 28
Capital Resources and Liquidity........................ 31
PART II - Other Information
Item 1 - Legal Proceedings................................. 32
Item 5 - Other Information
Other Financing Arrangements............................. 32
Base Rate Proceedings.................................... 32
Restructuring of the Bulk Power Market................... 35
Peak Load, Sales, Conservation, and Construction and
Generating Capacity.................................... 36
Selected Nonutility Subsidiary Financial Information..... 39
Statistical Data......................................... 41
Item 6 - Exhibits and Reports on Form 8-K.................. 42
Signatures................................................. 43
Computations of Earnings Per Common Share.................. 44
Computation of Ratios - Parent Company Only................ 45
Computation of Ratios - Fully Consolidated................. 46
Independent Accountants Awareness Letter................... 47
1
<TABLE>
Part I FINANCIAL INFORMATION
- ------ ---------------------
Item 1 CONSOLIDATED FINANCIAL STATEMENTS
- ------ ---------------------------------
POTOMAC ELECTRIC POWER COMPANY
Consolidated Statements of Earnings and Retained Income
(Unaudited)
-------------------------------------------------------
<CAPTION>
Three Months Ended Nine Months Ended Twelve Months Ended
September 30, September 30, September 30,
-------------------- ---------- -- -------- ----------------------
1996 1995 1996 1995 1996 1995
--------- --------- ---------- ---------- ---------- ----------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Revenue
Sales of electricity $ 612,240 $ 640,253 $1,455,818 $1,440,266 $1,829,342 $1,790,729
Other electric revenue 2,117 2,258 6,516 6,133 9,025 7,906
--------- --------- ---------- ---------- ---------- ----------
Total Operating Revenue 614,357 642,511 1,462,334 1,446,399 1,838,367 1,798,635
Interchange deliveries 43,868 21,073 134,264 27,453 160,481 30,319
--------- --------- ---------- ---------- ---------- ----------
Total Revenue 658,225 663,584 1,596,598 1,473,852 1,998,848 1,828,954
--------- --------- ---------- ---------- ---------- ----------
Operating Expenses
Fuel 93,191 111,842 260,709 265,013 351,149 349,836
Purchased energy 91,467 55,677 251,964 143,706 301,850 181,371
Capacity purchase payments 30,731 30,286 95,592 94,832 126,529 125,231
Other operation 55,055 53,291 167,037 164,725 226,343 220,257
Maintenance 23,276 21,930 65,970 65,803 93,025 91,813
--------- --------- ---------- ---------- ---------- ----------
Total Operation and Maintenance 293,720 273,026 841,272 734,079 1,098,896 968,508
Depreciation and amortization 56,972 55,507 167,048 151,600 220,938 198,521
Income taxes 81,588 90,926 127,567 125,320 130,708 123,378
Other taxes 59,683 60,889 155,079 157,560 200,227 203,565
--------- --------- ---------- ---------- ---------- ----------
Total Operating Expenses 491,963 480,348 1,290,966 1,168,559 1,650,769 1,493,972
--------- --------- ---------- ---------- ---------- ----------
Operating Income 166,262 183,236 305,632 305,293 348,079 334,982
--------- --------- ---------- ---------- ---------- ----------
Other Income (Loss)
Nonutility Subsidiary
Income 36,406 34,747 85,502 101,298 118,697 145,701
Loss on assets held for disposal - - - (170,078) - (170,078)
Expenses, including interest
and income taxes (31,520) (38,827) (69,101) (55,173) (102,740) (87,429)
--------- --------- ---------- ---------- ---------- ----------
Net earnings (loss) from nonutility
subsidiary 4,886 (4,080) 16,401 (123,953) 15,957 (111,806)
Allowance for other funds used during
construction and capital cost recovery factor 1,567 1,566 4,964 4,461 6,658 7,190
Other, net 857 (477) 4,225 1,239 3,669 3,085
--------- --------- ---------- ---------- ---------- ----------
Total Other Income (Loss) 7,310 (2,991) 25,590 (118,253) 26,284 (101,531)
--------- --------- ---------- ---------- ---------- ----------
Income Before Utility Interest Charges 173,572 180,245 331,222 187,040 374,363 233,451
--------- --------- ---------- ---------- ---------- ----------
Utility Interest Charges
Long-term debt 33,042 32,839 99,767 97,498 133,889 129,792
Other 3,606 4,091 11,495 12,536 13,898 15,707
Allowance for borrowed funds used during
construction and capital cost recovery factor (1,763) (2,632) (5,714) (8,131) (8,352) (10,939)
--------- --------- ---------- ---------- ---------- ----------
Net Utility Interest Charges 34,885 34,298 105,548 101,903 139,435 134,560
--------- --------- ---------- ---------- ---------- ----------
Net Income 138,687 145,947 225,674 85,137 234,928 98,891
Dividends on Preferred Stock 4,151 4,200 12,448 12,675 16,624 16,772
--------- --------- ---------- ---------- ---------- ----------
Earnings for Common Stock 134,536 141,747 213,226 72,462 218,304 82,119
Retained Income at Beginning of Period 711,726 689,475 742,296 830,524 784,026 877,755
Dividends on Common Stock (49,153) (49,152) (147,458) (147,316) (196,611) (196,313)
Subsidiary Marketable Securities Net
Unrealized (Loss) Gain, Net of Tax (163) 1,956 (11,118) 28,356 (8,773) 20,465
--------- --------- ---------- ---------- ---------- ----------
Retained Income at End of Period $ 796,946 $ 784,026 $ 796,946 $ 784,026 $ 796,946 $ 784,026
========= ========= ========== ========== ========== ==========
Average Common Shares
Outstanding (000's) 118,497 118,488 118,496 118,385 118,495 118,326
Earnings Per Common Share $1.14 $1.20 $1.80 $0.61 $1.84 $0.69
Cash Dividends Per Common Share $0.415 $0.415 $1.245 $1.245 $1.66 $1.66
Book Value Per Share $16.25 $16.15
2
</TABLE>
<TABLE>
POTOMAC ELECTRIC POWER COMPANY
Consolidated Balance Sheets
(Unaudited at September 30, 1996 and 1995)
------------------------------------------
<CAPTION>
September 30, December 31, September 30,
ASSETS 1996 1995 1995
------ ------------- ------------- -------------
(Thousands of Dollars)
<S> <C> <C> <C>
Property and Plant - at original cost
Electric plant in service $ 6,168,497 $ 6,041,203 $ 5,957,833
Construction work in progress 72,624 93,047 134,167
Electric plant held for future use 4,133 4,082 4,061
Nonoperating property 22,699 22,771 22,770
------------- ------------- -------------
6,267,953 6,161,103 6,118,831
Accumulated depreciation (1,857,633) (1,760,792) (1,724,899)
------------- ------------- -------------
Net Property and Plant 4,410,320 4,400,311 4,393,932
------------- ------------- -------------
Current Assets
Cash and cash equivalents 7,689 5,844 21,866
Customer accounts receivable, less allowance
for uncollectible accounts of $894, $1,669
and $1,656 186,638 137,456 190,932
Other accounts receivable, less allowance for
uncollectible accounts of $300 36,253 36,765 34,712
Accrued unbilled revenue 110,201 73,622 111,320
Prepaid taxes 49,539 36,255 29,426
Other prepaid expenses 4,512 7,562 7,301
Material and supplies - at average cost
Fuel 67,091 63,203 64,336
Construction and maintenance 70,492 70,497 73,620
------------- ------------- -------------
Total Current Assets 532,415 431,204 533,513
------------- ------------- -------------
Deferred Charges
Income taxes recoverable through future rates, net 239,011 244,181 241,795
Conservation costs, net 234,832 230,412 221,552
Unamortized debt reacquisition costs 56,259 58,360 54,773
Other 132,293 138,619 122,664
------------- ------------- -------------
Total Deferred Charges 662,395 671,572 640,784
------------- ------------- -------------
Nonutility Subsidiary Assets
Cash and cash equivalents 199 1,594 1,678
Marketable securities 394,945 530,323 521,555
Investment in finance leases 480,415 438,795 432,466
Operating lease equipment, net of accumulated
depreciation of $107,555, $79,275 and $69,432 209,275 272,947 234,654
Assets held for disposal 12,600 104,370 104,370
Receivables, less allowance for uncollectible
accounts of $6,000, $6,000 and $5,000 89,717 74,957 78,854
Other investments 205,479 176,418 189,732
Other assets 16,777 15,659 14,137
------------- ------------- -------------
Total Nonutility Subsidiary Assets 1,409,407 1,615,063 1,577,446
------------- ------------- -------------
Total Assets $ 7,014,537 $ 7,118,150 $ 7,145,675
============= ============= =============
CAPITALIZATION AND LIABILITIES
- ------------------------------
Capitalization
Common stock $ 118,498 $ 118,495 $ 118,493
Other common equity 1,807,347 1,752,817 1,794,582
Serial preferred stock 125,299 125,325 125,341
Redeemable serial preferred stock 142,500 143,485 143,485
Long-term debt 1,668,973 1,817,077 1,816,847
------------- ------------- -------------
Total Capitalization 3,862,617 3,957,199 3,998,748
------------- ------------- -------------
Other Non-Current Liabilities
Capital lease obligations 163,528 165,235 165,771
------------- ------------- -------------
Total Other Non-Current Liabilities 163,528 165,235 165,771
------------- ------------- -------------
Current Liabilities
Long-term debt and preferred stock
redemption due within one year 150,985 26,280 124,800
Short-term debt 254,455 258,465 68,750
Accounts payable and accrued expenses 221,865 162,039 242,238
Capital lease obligations due within one year 20,772 20,772 20,772
Other 83,840 86,034 111,911
------------- ------------- -------------
Total Current Liabilities 731,917 553,590 568,471
------------- ------------- -------------
Deferred Credits
Income taxes 920,659 892,544 880,093
Investment tax credits 61,870 64,607 65,519
Other 33,971 35,089 30,228
------------- ------------- -------------
Total Deferred Credits 1,016,500 992,240 975,840
------------- ------------- -------------
Nonutility Subsidiary Liabilities
Long-term debt 940,318 1,047,484 1,055,260
Short-term notes payable 181,305 223,350 221,200
Deferred taxes and other 118,352 179,052 160,385
------------- ------------- -------------
Total Nonutility Subsidiary Liabilities 1,239,975 1,449,886 1,436,845
------------- ------------- -------------
Total Capitalization and Liabilities $ 7,014,537 $ 7,118,150 $ 7,145,675
============= ============= =============
3
</TABLE>
<TABLE>
POTOMAC ELECTRIC POWER COMPANY
Consolidated Statements of Cash Flows
(Unaudited)
-------------------------------------
<CAPTION>
Nine Months Ended Twelve Months Ended
September 30, September 30,
----------------------- -----------------------
1996 1995 1996 1995
--------- --------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Operating Activities
Income from utility operations $ 209,273 $ 209,090 $ 218,971 $ 210,697
Adjustments to reconcile income to net
cash from operating activities:
Depreciation and amortization 167,048 151,600 220,938 198,521
Deferred income taxes and investment tax credits 24,067 34,358 41,483 45,209
Allowance for funds used during construction
and capital cost recovery factor (10,678) (12,592) (15,010) (18,129)
Changes in materials and supplies (3,883) 8,162 373 6,158
Changes in accounts receivable and accrued unbilled revenue (85,249) (104,942) 3,872 (44,294)
Changes in accounts payable 4,039 26,339 (36,720) 26,323
Changes in other current assets and liabilities 48,718 51,423 (4,190) 10,359
Changes in deferred conservation costs (39,351) (85,149) (58,999) (108,486)
Net other operating activities (21,440) (12,672) (54,430) 4,656
Nonutility subsidiary:
Net earnings (loss) 16,401 (123,953) 15,957 (111,806)
Deferred income taxes (26,999) (48,917) (27,779) (43,897)
Loss on assets held for disposal - 170,078 - 170,078
Changes in other assets and net other operating activities 29,780 46,300 66,989 50,756
--------- --------- --------- ---------
Net Cash From Operating Activities 311,726 309,125 371,455 396,145
--------- --------- --------- ---------
Investing Activities
Total investment in property and plant (139,531) (178,628) (191,578) (260,687)
Allowance for funds used during construction
and capital cost recovery factor 10,678 12,592 15,010 18,129
--------- --------- --------- ---------
Net investment in property and plant (128,853) (166,036) (176,568) (242,558)
Nonutility subsidiary:
Purchase of marketable securities (19,680) (21,333) (33,568) (29,591)
Proceeds from sale or redemption of marketable securities 140,406 19,275 148,977 21,456
Investment in leased equipment (3,056) (102,981) (54,841) (110,933)
Proceeds from sale or disposition of leased equipment 3,658 - 3,658 -
Proceeds from assets held for disposal 34,154 - 34,154 -
Proceeds from sale of assets 285 - 6,251 1,500
Purchase of other investments (4,500) (3,154) (5,164) (3,560)
Proceeds from sale or distribution of other investments 14,193 16,611 13,196 18,115
Investment in promissory notes (20,414) (5,301) (23,068) (1,376)
Proceeds from promissory notes 14,083 5,644 16,416 6,986
--------- --------- --------- ---------
Net Cash From (Used by) Investing Activities 30,276 (257,275) (70,557) (339,961)
--------- --------- --------- ---------
Financing Activities
Dividends on common stock (147,458) (147,316) (196,611) (196,313)
Dividends on preferred stock (12,448) (12,675) (16,624) (16,772)
Issuance of common stock - 4,580 - 6,418
Redemption of preferred stock - (78) - (1,578)
Issuance of long-term debt - 188,594 - 188,594
Reacquisition and retirement of long-term debt (26,320) (17,623) (126,162) (34,653)
Proceeds from sale and leaseback of control center system - - - 152,000
Short-term debt, net (4,010) (120,850) 185,705 (163,925)
Other financing activities (3,903) (17,691) (9,823) (26,945)
Nonutility subsidiary:
Issuance of long-term debt 128,000 150,000 160,000 197,000
Repayment of long-term debt (233,368) (235,245) (273,144) (273,909)
Short-term debt, net (42,045) 172,800 (39,895) 126,610
--------- --------- --------- ---------
Net Cash Used By Financing Activities (341,552) (35,504) (316,554) (43,473)
--------- --------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents 450 16,346 (15,656) 12,711
Cash and Cash Equivalents at Beginning of Period 7,438 7,198 23,544 10,833
--------- --------- --------- ---------
Cash and Cash Equivalents at End of Period $ 7,888 $ 23,544 $ 7,888 $ 23,544
========= ========= ========= =========
Cash paid for interest (net of capitalized interest) and income taxes:
Interest (including nonutility subsidiary
interest of $77,664, $83,795, $87,541 and $92,400) $ 188,772 $ 190,481 $ 221,208 $ 223,907
Income taxes $ 3,398 $ 16,834 $ 31,289 $ 52,925
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), the Company's
wholly owned subsidiary, 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 is also involved with
activities which provide utility related, telecommunication and
energy services. In addition, PCI 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 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 of energy, and resales of purchased
energy, to other utilities and to power marketers. 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 is scheduled to 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 September 30, 1996,
unamortized conservation costs totaled $98.8 million in Maryland
and $136 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 7.4%, compounded semi-annually, for the nine
months ended September 30, 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.
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.
8
<TABLE>
(2) INCOME TAXES
- ----------------
Provision for Income Taxes
- --------------------------
<CAPTION>
Three Months Ended Nine Months Ended Twelve Months Ended
September 30, September 30, September 30,
-------------------- ---------------------- ---------------------
1996 1995 1996 1995 1996 1995
--------- --------- --------- ---------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Utility current tax expense
Federal $ 60,965 $ 66,468 $ 92,718 $ 79,418 $ 81,792 $ 68,692
State and local 8,049 9,229 12,395 10,658 10,910 9,021
-------- -------- -------- -------- -------- --------
Total utility current tax expense 69,014 75,697 105,113 90,076 92,702 77,713
-------- -------- -------- -------- -------- --------
Utility deferred tax expense
Federal 11,763 13,859 23,250 32,294 39,295 42,760
State and local 1,724 1,654 3,554 4,801 5,837 6,099
Investment tax credits (912) (913) (2,737) (2,737) (3,649) (3,650)
-------- -------- -------- -------- -------- --------
Total utility deferred tax expense 12,575 14,600 24,067 34,358 41,483 45,209
-------- -------- -------- -------- -------- --------
Total utility income tax expense 81,589 90,297 129,180 124,434 134,185 122,922
-------- -------- -------- -------- -------- --------
Nonutility subsidiary current tax expense
Federal (13,783) (23,512) (22,822) (31,452) (26,962) (38,351)
-------- -------- -------- -------- -------- --------
Nonutility subsidiary deferred tax expense
Federal 9,314 17,220 (26,975) (49,441) (27,650) (45,139)
State and local - - - - - 953
-------- -------- -------- -------- -------- --------
Total nonutility subsidiary deferred tax expense 9,314 17,220 (26,975) (49,441) (27,650) (44,186)
-------- -------- -------- -------- -------- --------
Total nonutility subsidiary income tax expense (4,469) (6,292) (49,797) (80,893) (54,612) (82,537)
-------- -------- -------- -------- -------- --------
Total consolidated income tax expense 77,120 84,005 79,383 43,541 79,573 40,385
Income taxes included in other income (4,468) (6,921) (48,184) (81,779) (51,135) (82,993)
-------- -------- -------- -------- -------- --------
Income taxes included in utility operating expenses $ 81,588 $ 90,926 $127,567 $125,320 $130,708 $123,378
======== ======== ======== ======== ======== ========
9
</TABLE>
<TABLE>
Reconciliation of Consolidated Income Tax Expense
- -------------------------------------------------
<CAPTION>
Three Months Ended Nine Months Ended Twelve Months Ended
September 30, September 30, September 30,
-------------------- ---------------------- ---------------------
1996 1995 1996 1995 1996 1995
--------- -------- --------- ---------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Income before income taxes $215,807 $229,952 $305,057 $128,678 $314,501 $139,276
======== ======== ======== ======== ======== ========
Utility income tax at federal
statutory rate $ 75,387 $ 84,113 $118,459 $116,733 $123,605 $116,767
Increases (decreases) resulting from
Depreciation 2,542 2,248 7,627 6,745 10,055 9,077
Removal costs (1,000) (1,419) (2,478) (4,318) (5,364) (5,108)
Allowance for funds used during
construction 208 161 488 488 595 79
Other (988) (966) (2,463) (2,606) (1,470) (3,763)
State income taxes, net of federal effect 6,352 7,073 10,284 10,129 10,803 9,908
Tax credits (912) (913) (2,737) (2,737) (4,039) (4,038)
-------- -------- -------- -------- -------- --------
Total utility income tax expense 81,589 90,297 129,180 124,434 134,185 122,922
-------- -------- -------- -------- -------- --------
Nonutility subsidiary income tax at federal
statutory rate 146 (3,630) (11,689) (71,696) (13,530) (68,020)
Increases (decreases) resulting from
Dividends received deduction (2,636) (2,169) (8,680) (6,482) (10,722) (8,700)
Reversal of previously accrued deferred taxes (2,105) - (30,804) - (30,804) (1,659)
Other 126 (493) 1,376 (2,715) 444 (5,111)
State income taxes, net of federal effect - - - - - 953
-------- -------- -------- -------- -------- --------
Total nonutility subsidiary income tax expense (4,469) (6,292) (49,797) (80,893) (54,612) (82,537)
-------- -------- -------- -------- -------- --------
Total consolidated income tax expense 77,120 84,005 79,383 43,541 79,573 40,385
Income taxes included in other income (4,468) (6,921) (48,184) (81,779) (51,135) (82,993)
-------- -------- -------- -------- -------- --------
Income taxes included in utility operating expenses $ 81,588 $ 90,926 $127,567 $125,320 $130,708 $123,378
======== ======== ======== ======== ======== ========
10
</TABLE>
<TABLE>
Components of Consolidated Deferred Tax Liabilities (Assets)
- ------------------------------------------------------------
<CAPTION>
Sept. 30, Dec. 31, Sept. 30,
1996 1995 1995
--------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C>
Utility deferred tax liabilities (assets)
Depreciation and other book to tax
basis differences $808,405 $773,323 $758,523
Rapid amortization of certified pollution
control facilities 25,473 26,640 27,864
Deferred taxes on amounts to be collected
through future rates 90,490 92,472 91,568
Property taxes 12,456 11,808 11,682
Deferred fuel (14,227) (7,154) (5,151)
Prepayment premium on debt retirement 21,279 22,080 20,722
Deferred investment tax credit (23,424) (24,464) (24,810)
Contributions in aid of construction (27,737) (27,206) (25,627)
Contributions to pension plan 12,276 10,859 -
Other 20,125 25,124 27,997
-------- -------- --------
Total utility deferred tax liabilities (net) 925,116 903,482 882,768
Current portion of utility deferred tax liabilities
(included in Other Current Liabilities) 4,457 10,938 2,675
-------- -------- --------
Total utility deferred tax liabilities (net) - noncurrent $920,659 $892,544 $880,093
======== ======== ========
Nonutility subsidiary deferred tax liabilities (assets)
Finance leases $170,656 $149,103 $136,553
Operating leases 26,909 66,802 126,687
Reversal of previously accrued taxes related
to partnerships (8,525) (11,593) (15,223)
Alternative minimum tax (84,540) (84,512) (61,899)
Other (36,920) (16,840) (83,640)
-------- -------- --------
Total nonutility subsidiary deferred tax liabilities
(net), (included in Deferred taxes and other) $ 67,580 $102,960 $102,478
======== ======== ========
11
</TABLE>
(3) CAPITALIZATION
--------------
Common Equity
- -------------
At September 30, 1996, 118,497,681 shares of the Company's
$1 par value Common Stock were outstanding. A total of 200
million shares is authorized. As of September 30, 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 September 30, 1996, the Company had outstanding 5,375,670
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 September 30, 1996, the aggregate annual
dividend requirements on the Serial Preferred Stock and the
Redeemable Serial Preferred Stock were approximately $6.4 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
(5,974 shares outstanding at September 30, 1996) is convertible
into Common Stock at $8.51 per share.
At September 30, 1996, the Company had outstanding one
million shares of its Serial Preferred Stock, Auction Series A.
The annual dividend rate is 4.19% ($2.095) for the period
September 1, 1996, through November 30, 1996. For the period
June 1, 1996, through August 31, 1996, the annual dividend rate
was 4.14% ($2.07). The average rate at which dividends were paid
during the 12 months ended September 30, 1996, was 4.19% ($2.10).
At September 30, 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
12
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 September 30, 1996, is
summarized below:
(Thousands of Dollars)
First Mortgage Bonds $1,341,800
Convertible Debentures 180,427
Notes Payable 325,000
Net Unamortized Discount (28,254)
Current Portion (150,000)
----------
Net Utility Long-Term Debt $1,668,973
==========
Nonutility Subsidiary Long-Term Debt $ 940,318
==========
At September 30, 1996, the aggregate annual interest
requirement on the Company's long-term debt, including debt due
within one year, was $126.2 million; and the aggregate amounts of
long-term debt maturities are $150 million in 1997, $50 million
in 1998, $45 million in 1999 and $100 million in 2000. At
September 30, 1996, long-term debt due within one year consisted
of $100 million of 6.66% - 6.73% Medium-Term Notes and $50
million of 9.08% Medium-Term Notes.
Nonutility Subsidiary Long-Term Debt
- ------------------------------------
Long-term debt at September 30, 1996, consisted primarily of
unsecured borrowings from institutional lenders maturing at
various dates between late 1996 and 2003. The interest rates of
such borrowings ranged from 5% to 10.1%. The weighted average
effective interest rate was 7.16% at September 30, 1996, 7.66% at
December 31, 1995, and 7.65% at September 30, 1995. Annual
aggregate principal repayments on these borrowings are $2 million
in 1996, $194 million in 1997, $300.8 million in 1998, $170
million in 1999, $115 million in 2000 and $97.5 million
thereafter. Also included in long-term debt is $61.1 million of
non-recourse debt which is due in monthly installments with final
maturities in 2001, 2002 and 2011.
13
<TABLE>
(4) Fair Value of Financial Instruments
- ---------------------------------------
The estimated fair values of the Company's financial instruments at
September 30, 1996, December 31, 1995, and September 30, 1995, are shown below.
<CAPTION>
September 30, December 31, September 30,
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 $ 125,299 112,210 125,325 114,590 125,341 112,287
========== ========= ========= ========= ========= =========
Redeemable serial
preferred stock $ 142,500 143,465 143,485 145,046 143,485 145,525
========== ========= ========= ========= ========= =========
Long-term debt
First mortgage bonds $1,327,182 1,295,756 1,326,560 1,385,609 1,325,427 1,314,415
Medium-term notes $ 168,573 169,791 323,007 336,351 322,933 323,249
Convertible debentures $ 173,218 169,725 167,510 174,054 168,487 171,634
---------- --------- --------- --------- --------- ---------
Total long-term debt $1,668,973 1,635,272 1,817,077 1,896,014 1,816,847 1,809,298
========== ========= ========= ========= ========= =========
Nonutility Subsidiary
Assets
Marketable securities $ 394,945 394,945 530,323 530,323 521,555 521,555
========== ========= ========= ========= ========= =========
Notes receivable $ 74,842 72,279 62,175 63,184 62,256 61,355
========== ========= ========= ========= ========= =========
Liabilities
Long-term debt $ 940,318 954,605 1,047,484 1,071,354 1,055,260 1,058,417
========== ========= ========= ========= ========= =========
14
</TABLE>
The methods and assumptions below were used to estimate, at
September 30, 1996, December 31, 1995, and September 30, 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, excluding amounts
due within one year, 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.
15
(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 September 30, 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 September 30, 1996
---------------------------------------
Net
Market Unrealized
Cost Value Losses
---------- ---------- --------------
(Thousands of Dollars)
Mandatory redeemable
preferred stock $ 401,552 $ 394,945 $ (6,607)
Equity securities 3 - (3)
---------- ---------- ------------
Total $ 401,555 $ 394,945 $ (6,610)
========== ========== ============
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
========== ========== ============
16
As of September 30, 1995
---------------------------------------
Net
Market Unrealized
Cost Value Gain/(Loss)
---------- ---------- --------------
(Thousands of Dollars)
Mandatory redeemable
preferred stock $ 514,328 $ 521,285 $ 6,957
Equity securities 341 270 (71)
---------- ---------- ------------
Total $ 514,669 $ 521,555 $ 6,886
========== ========== ============
Included in net unrealized gains and losses are gross
unrealized losses of $13 million and gross unrealized gains of
$6.4 million at September 30, 1996; gross unrealized losses of
$6.6 million and gross unrealized gains of $17.1 million at
December 31, 1995; and gross unrealized losses of $8.2 million
and gross unrealized gains of $15.1 million at September 30,
1995.
At September 30, 1996, the contractual maturities for
mandatory redeemable preferred stock are $7.4 million within one
year, $74 million from one to five years, $110.5 million from
five to 10 years and $209.7 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 Ended Nine Months Ended
September 30, September 30,
------------------ ------------------
1996 1995 1996 1995
-------- -------- -------- --------
(Thousands of Dollars)
Gross realized
gains $ 832 $ 73 $ 3,337 $ 435
Gross realized
losses (94) (12) (886) (220)
-------- -------- -------- --------
Net gain $ 738 $ 61 $ 2,451 $ 215
======== ======== ======== ========
17
(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. Preliminary estimates indicate that
savings from the combined utility systems will approximate $1.3
billion over 10 years following the Merger. These savings are
net of costs to achieve presently estimated to be approximately
$150 million. Approximately two-thirds of the projected savings
are expected to result from reduced labor costs, with the
remaining savings split between nonfuel purchasing and corporate
and administrative programs. The allocation of the net savings
between customers and shareholders of the Company will be
determined in regulatory proceedings. The applications for
approval of the Merger, filed with the various regulatory
commissions, 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 development of estimated
savings resulting from the Merger was based upon assumptions
which involve judgments with respect to, among other things,
future national and regional economic and competitive conditions,
inflation rates, regulatory treatment, weather conditions,
financial market conditions, interest rates, future business
decisions and other uncertainties, all of which are difficult to
predict and many of which are beyond the control of the Company
and BGE. Accordingly, while the Company believes that such
assumptions are reasonable for purposes of the development of
estimates of potential savings, there can be no assurance that
such assumptions will approximate actual experience or that all
such savings will be realized.
18
Shareholders of the Company and BGE, at separate special
meetings on March 29, 1996, 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. On July 31, 1996, FERC set the application
for hearing on the issue of whether the merger would impact
competition. Hearings began on October 21, 1996 and the
Administrative Law Judge has been directed to certify the record
to the Commission by November 1, 1996. The case is expected to
be before FERC for decision in December 1996. The Maryland
Commission conducted hearings during June and September 1996 and
further hearings are scheduled for December 1996. The case is
scheduled to be before the Maryland Commission for decision in
January 1997. A prehearing conference was conducted by the
District of Columbia Commission in May 1996 and a procedural
schedule was published on July 19, 1996. Hearings are scheduled
to take place in December 1996 and the case is expected to be
before the District of Columbia Commission for decision in
January 1997. 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
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.
19
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, which was paid 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 and the June 30, 1996
Form 10-Q, 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 and the June 30, 1996
Form 10-Q, 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 liability at this site is .0042%.
The EPA has also indicated that 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 and the June 30,
1996 Form 10-Q, 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
20
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 $.9 million as of September 30,
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 and the June 30,
1996 Form 10-Q, 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.
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
21
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.
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.
* * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * *
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 23) 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.
22
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors
and Shareholders of
Potomac Electric Power Company
We have reviewed the accompanying consolidated balance sheets of
Potomac Electric Power Company and consolidated subsidiaries (the
Company) at September 30, 1996 and 1995, and the related
consolidated statements of earnings and retained income for the
three, nine and twelve month periods then ended and the
consolidated statements of cash flows for the nine and twelve
month periods then ended. These financial statements are the
responsibility of the Company's management.
We conducted our review in accordance with standards established
by the American Institute of Certified Public Accountants. A
review of interim financial information consists principally of
applying analytical procedures to financial data and making
inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit
conducted in accordance with generally accepted auditing
standards, the objective of which is the expression of an opinion
regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material
modifications that should be made to the accompanying financial
information for it to be in conformity with generally accepted
accounting principles.
We have previously audited, in accordance with generally accepted
auditing standards, the consolidated balance sheet as of December
31, 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.
October 28, 1996
23
Part I FINANCIAL INFORMATION
- ------ ---------------------
Item 2 MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED
- ------ ----------------------------------------------------
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
---------------------------------------------
UTILITY
- -------
PROPOSED MERGER UPDATE
- ----------------------
Shareholders of the Company and BGE, at separate special
meetings during March 1996, 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. On July 31, 1996, FERC set the application
for hearing on the issue of whether the merger would impact
competition. Hearings began on October 21, 1996 and the
Administrative Law Judge has been directed to certify the record
to the Commission by November 1, 1996. The case is expected to
be before FERC for decision in December 1996. The Maryland
Commission conducted hearings during June and September 1996 and
further hearings are scheduled for December 1996. The case is
scheduled to be before the Maryland Commission for decision in
January 1997. A prehearing conference was conducted by the
District of Columbia Commission in May 1996 and a procedural
schedule was published on July 19, 1996. Hearings are scheduled
to take place in December 1996 and the case is expected to be
before the District of Columbia Commission for decision in
January 1997.
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. The allocation of the net
savings between customers and shareholders of the Company will be
determined in regulatory proceedings. 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.
24
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.
RESULTS OF OPERATIONS
- ---------------------
TOTAL REVENUE
Total revenue decreased for the three months ended and
increased for the nine and twelve months ended September 30,
1996, as compared to the corresponding periods in 1995. The
decrease in revenue from sales of electricity for the three
months ended September 30, 1996, was primarily due to a 7.3%
decrease in kilowatt-hour sales from the corresponding period in
1995, partially offset by the effect of the August 1996 increase
in the Demand Side Management (DSM) surcharge tariff rate in
Maryland. Pursuant to this tariff, an incentive provision of
$8.9 million was recorded in August 1996 for achieving specific
1995 energy conservation goals. An incentive provision of $8.7
million was recorded in June 1995 for achieving specific 1994
goals. The decrease in kilowatt-hour sales for the three months
ended September 30, 1996, was attributable to cooler than average
summer weather as compared to hotter than average summer weather
during the corresponding period in 1995. Cooling degree hours
for the three months ended September 30, 1996 were 38% below the
corresponding period in 1995 and were 31% below the 20-year
average for this period. The increase in revenue from sales of
electricity for the nine and twelve months ended September 30,
1996, was primarily due to the effect of the July 1995 base rate
increase in the District of Columbia, increases in kilowatt-hour
sales of .8% and 2.5%, respectively, over the corresponding
periods in 1995, and the August 1996 increase in the DSM
surcharge tariff rate in Maryland. The increase in kilowatt-hour
sales for the nine and twelve months ended September 30, 1996,
was favorably impacted by the effects of colder than average
winter weather during the first quarter of 1996 offset by the
effects of cooler than average summer weather during 1996.
The increase in interchange deliveries for the three, nine
and twelve months ended September 30, 1996, reflects the growth
in the number of companies involved in power sales tariff
interchange transactions where the Company buys energy from one
party for the purpose of selling that energy to a third party.
The benefits derived from interchange deliveries are passed
through to the Company's customers through a fuel clause.
25
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, nine and
twelve months ended September 30, 1996, as compared to the
corresponding periods ended September 30, 1995. Fuel expense
decreased for the three and nine months ended and increased for
the twelve months ended September 30, 1996, as compared to the
corresponding periods in 1995. The decrease in the three and
nine months ended September 30, 1996, was primarily the result of
decreases of 19.5% and .3%, respectively, in net generation. The
increase for the twelve months ended September 30, 1996, was
primarily the result of an increase of 4.8% in net generation due
to higher customer usage of electricity. The increase in
purchased energy for the three, nine and twelve months ended
September 30, 1996, reflects changes in levels and prices of
energy purchased from PJM and other utilities, primarily the
purchases related to the power sales tariff interchange
transactions.
The unit fuel costs for the comparative periods ended
September 30, were as follows:
Three Nine Twelve
Months Ended Months Ended Months Ended
------------ ------------ ------------
1996 1995 1996 1995 1996 1995
---- ---- ---- ---- ---- ----
System Average
Fuel Cost per MBTU $1.82 $1.74 $1.81 $1.74 $1.79 $1.75
System average unit fuel cost increased for the three, nine
and twelve months ended September 30, 1996, as compared to the
corresponding periods in 1995. The increases were primarily
attributable to an increase in the cost of residual oil and an
increase in the percent of residual oil contribution to the fuel
mix. 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.
26
For the twelve month periods ended September 30, 1996 and
1995, the Company obtained 89% and 84%, respectively, of its
system generation from coal based upon percentage of Btus.
Capacity purchase payments increased slightly for the three,
nine and twelve months ended September 30, 1996, as compared to
the corresponding periods in 1995. The increases were primarily
attributable to increases in fixed operating and maintenance
expense associated with the capacity agreements with Ohio Edison
and Allegheny Power System (APS). In addition, the increase for
the nine and twelve months ended September 30, 1996, was
partially offset by the expiration of a purchase agreement for
147 megawatts of capacity from Pennsylvania Power and Light
Company for the one year period June 1994 through May 1995.
Operating expenses other than fuel, purchased energy and
capacity purchase payments decreased for the three months and
increased for the nine and twelve months ended September 30,
1996, as compared to the corresponding periods in 1995. The
decrease for the three months ended September 30, 1996, was
principally due to decreased income taxes due to lower taxable
income. The increases for the nine and twelve months ended
September 30, 1996 were principally due to increased depreciation
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, increased income
taxes due to higher taxable income and the $1.8 million and $.9
million paid on January 5, 1996 and June 7, 1996, respectively,
to union members as part of the 1995 Labor Agreement between the
Company and Local 1900 of the International Brotherhood of
Electrical Workers. The increase for the nine and twelve months
ended September 30, 1996, was 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. In
addition, the increase in operating expenses other than fuel,
purchased energy and capacity purchase payments for the twelve
months ended September 30, 1996, includes 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 .3%, .3% and .4% for the three, nine and twelve
months ended September 30, 1996, respectively, as compared to
.2%, .3% and .4% for the three, nine and twelve months ended
September 30, 1995. At September 30, 1996, accounts receivable
included $17.5 million, or 5.3% 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 October 23, 1996, the District of Columbia accounts
receivable balance had been reduced to $12.2 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.
27
CAPITAL RESOURCES AND LIQUIDITY
- -------------------------------
The Company's investment in property and plant, at original
cost before accumulated depreciation, was $6.3 billion at
September 30, 1996, an increase of $106.9 million from the
investment at December 31, 1995, and an increase of $149.1
million from the investment at September 30, 1995. Cash invested
in property and plant construction, excluding AFUDC and CCRF,
amounted to $128.9 million and $176.6 million, respectively, for
the nine and twelve months ended September 30, 1996.
At September 30, 1996, the Company's capital structure,
excluding short-term debt, long-term debt and serial preferred
stock redemption due within one year, and nonutility subsidiary
debt, consisted of 43.2% long-term debt, 3.2% serial preferred
stock, 3.7% redeemable serial preferred stock and 49.9% common
equity.
Cash from utility operations, after dividends, was $132.6
million and $103.1 million, respectively, for the nine and twelve
months ended September 30, 1996, compared with $105.6 million and
$117.9 million, respectively, for the same periods ended
September 30, 1995.
Outstanding utility short-term debt totaled $254.5 million
at September 30, 1996, a decrease of $4 million from the $258.5
million outstanding at December 31, 1995, and an increase of
$185.7 million from the $68.8 million outstanding at September
30, 1995. See the discussion included in Note (3) of the Notes
to Consolidated Financial Statements, Capitalization, for
additional information.
NONUTILITY SUBSIDIARY
- ---------------------
RESULTS OF OPERATIONS
- ---------------------
PCI's earnings for the three, nine and twelve months ended
September 30, 1996 were $4.9 million ($.04 per share), $16.4
million ($.14 per share) and $16 million ($.13 per share)
compared to net losses of $4.1 million ($.03 per share), $124
million ($1.05 per share) and $111.8 million ($.95 per share) for
the same periods ending September 30, 1995. PCI's losses in 1995
reflect the implementation of the May 1995 announcement of a plan
to exit the aircraft equipment leasing business, resulting in
noncash, after-tax charges of $115.2 million ($.98 per share)
recorded in the second quarter of 1995. Under the plan, PCI is
not making 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
28
values of approximately $104 million and no depreciation or
routine accrual for repair and maintenance expenditures for these
aircraft have been recorded since the plan was adopted. As of
September 30, 1996, eight of these aircraft have been sold and
one has been placed on a long-term lease. This activity, in
addition to a first quarter 1996 writedown of $12.3 million ($8
million after-tax), reduced the portfolio of assets held for
disposal to $12.6 million as of September 30, 1996.
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.
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-
term leases, and a portfolio of preferred stocks to the joint
venture. All of the assets of the venture are fully consolidated
in PCI's financial statements with the outside investor's portion
reflected as a minority interest. Two aircraft were sold from
the joint venture during the first quarter of 1996, four aircraft
were sold during the second quarter of 1996 and one aircraft was
sold during the third quarter of 1996. As a result of joint
venture operations for the three and nine months ended September
30, 1996, PCI's obligation for previously accrued deferred income
taxes was reduced, resulting in after-tax earnings of $1.8
million and $27.7 million, respectively, after provision for
transaction costs. The excess deferred income taxes were
recognized as a reduction of income tax expense. Future
operations of the joint venture may result in additional reversal
of deferred income taxes.
As a result of the first quarter 1996 implementation of SFAS
No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of", a pre-tax charge of
$9.6 million ($6.2 million after-tax) was recorded 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) in the first
quarter, reflecting current assessments of the net realizable
values of real estate and oil and natural gas investments.
29
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
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. There is ongoing
litigation which may limit or eliminate future cash flow to the
project investors. If current avoided cost levels were to
continue or the investors are not successful in litigation or 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 September 30, 1996, was
$40.6 million.
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 $23.3 million, $70.3 million and $99.8 million for
the three, nine and twelve months ended September 30, 1996,
respectively, compared to $25.2 million, $71.1 million and $108.7
million for the corresponding periods in 1995. The decrease in
earnings during the three, nine and twelve month periods ended
September 30, 1996 over the same periods in 1995 was primarily
due to non-recurring fee income earned during the three months
ended September 30, 1995. PCI's marketable securities portfolio
contributed pre-tax income of $8 million, $25.5 million and $34.1
million for the three, nine and twelve months ended September 30,
1996 compared to $9 million, $27.5 million and $36.3 million,
respectively, for the same periods in 1995. The reductions were
primarily the result of the decreased size of the portfolio.
Income from securities during the three, nine and twelve months
ended September 30, 1996, included net realized gains from the
sale or call of securities of $.7 million, $2.5 million and $2.6
million, respectively, compared to $.06 million, $.2 million and
$.2 million, respectively, for the same periods ended September
30, 1995.
Other income increased by $4.6 million during the three
months ended September 30, 1996, compared to the three months
ended September 30, 1995 primarily due to fee income earned
related to a partnership transaction during July 1996. Other
income decreased by $13 million and $15.9 million for the nine
and twelve months ended September 30, 1996, respectively,
30
compared to the same periods in 1995. The decrease during the
nine and twelve month periods ended September 30, 1996, was
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 $36 million, $118.9 million and $157.4 million
for the three, nine and twelve months ended September 30, 1996,
compared to $45.1 million, $306.1 million and $340 million,
respectively for the same periods in 1995. The decreases are
primarily the result of the second quarter 1995 pre-tax writedown
of $170.1 million related to the May 1995 plan to exit the
aircraft equipment leasing business. In addition, expenses
before income taxes decreased during the three, nine and twelve
months ended September 30, 1996, due to lower interest expense
resulting from less debt outstanding. Also, during the second
quarter of 1996, responsibility for certain repair and
maintenance expenses was assumed by a lessee. Accordingly, PCI
reversed $6.5 million of expenses accrued in prior periods.
PCI had income tax credits of $4.5 million, $49.8 million
and $54.6 million for the three, nine and twelve months ended
September 30, 1996, respectively, compared to income tax credits
of $6.3 million, $80.9 million and $82.5 million for the
corresponding periods in 1995. The decreases in income tax
credits for the three, nine and twelve months ended September 30,
1996, from the same periods in 1995 were due to lower pre-tax
income in 1995, primarily the result of the pre-tax charge to
earnings as a result of PCI's decision to exit the aircraft
equipment leasing business in May 1995.
CAPITAL RESOURCES AND LIQUIDITY
- -------------------------------
The $394.9 million securities portfolio, consisting
primarily of investment grade preferred stocks, provides PCI with
liquidity and investment flexibility. During 1996, PCI has
reduced the cost basis of its marketable securities portfolio by
$118.3 million primarily as the result of calls (approximately
$77.7 million) and sales of fixed rate preferred stocks,
generating net pre-tax gains of $2.5 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 1996 were used to pay down short-term debt. In addition,
proceeds from aircraft sales also were used to pay down short-
term debt.
31
During the third quarter of 1996, PCI sold its investment in
an aircraft engine leasing subsidiary for $12.3 million, its
approximate book value. As a result of the sale, PCI's
investment in operating lease equipment decreased by $32.7
million.
PCI's outstanding short-term debt totaled $181.3 million at
September 30, 1996, a decrease of $42.1 million from the $223.4
million outstanding at December 31, 1995, and an decrease of
$39.9 million from the $221.2 million outstanding at September
30, 1995. During the three, nine and twelve months ended
September 30, 1996, PCI issued $50 million, $128 million and $160
million, respectively, in long-term debt, including non-recourse
debt. Debt repayments totaled $86.8 million, $233.4 million and
$273.1 million, respectively, for the same periods ended
September 30, 1996. At September 30, 1996, PCI had $266.3
million available under its Medium-Term Note Program and $400
million available under its committed bank credit facility.
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 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.
32
Effective August 27, 1996, the Maryland DSM surcharge tariff
was increased, which will provide approximately $18 million
annually in increased revenue. The surcharge includes a
provision for the recovery of lost revenue, amortization of pre-
1996 actual program expenditures plus the initial amortization of
1996 projected program costs, a capital cost recovery factor of
9.46% on unamortized balances, and an incentive of $8.9 million
awarded for exceeding 1995 energy savings goals. The $8.9
million conservation incentive was reflected in utility results
in August 1996. An incentive of $8.7 million was recorded in
June 1995 for exceeding 1994 energy savings goals.
During October 1996, the Company plans to file a request
with the Maryland Public Service Commission for approval of a
purchased capacity surcharge, which is designed to recover
changes in the level of purchased capacity costs from levels
included in base rates. The filing is being made to recover
capacity payments under the Panda-Brandywine, L.P. (Panda)
contract, which commence on January 1, 1997. The District of
Columbia portion of the Panda capacity costs will be recovered
through the existing fuel adjustment clause.
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 actual costs expended from July 1993
through December 1994, resulted in additional annual revenue of
approximately $15 million. On June 3, 1996, the Company filed an
Application for Authority with the Commission to revise its ECRR.
The proposed rate, which reflects actual costs expended from July
1993 through December 1995, is expected to increase annual
revenue by approximately $8 million. As of September 30, 1996,
no action has been taken by the District of Columbia Public
Service Commission on the proposed ECRR. Subsequent rate updates
are scheduled to be filed annually on June 1 to reflect the prior
33
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
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 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,
34
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
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.
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.
Revenue associated with the power sales tariff, which commenced
in September 1995, were $38 million, $118 million and $137
million, respectively, for the three, nine and twelve months
ended September 30, 1996. The benefits derived from interchange
deliveries are passed through to the Company's customers through
a fuel clause.
RESTRUCTURING OF THE BULK POWER MARKET
- --------------------------------------
On July 9, 1996, FERC's final orders became effective with
respect to its March 1995 Notice of Proposed Rulemaking (NOPR) on
open access transmission, stranded costs and same-time
information systems. In addition, FERC issued a NOPR on Capacity
Reservation Tariffs (CRT). Order No. 888 requires the filing of
an open access transmission tariff that complies with FERC's
terms and conditions. Such filing was made by the Company on
July 9, 1996. Order No. 889 requires the Company to establish or
participate in Open Access Same-Time Information Systems and to
comply with prescribed standards of conduct by January 3, 1997.
The CRT NOPR proposes a reservation-based transmission service
which would replace the proforma tariff set forth in Order No.
888 by December 31, 1997. Compliance with Order No. 888 and 889
is not expected to have a significant impact on the Company's
results of operations.
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
35
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. 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's control area transmission system. 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 filed its final plan
with FERC on July 24, 1996, with a phased-in implementation
planned to begin in January 1997 with transitional planning
beginning immediately upon filing.
PEAK LOAD, SALES, CONSERVATION, AND CONSTRUCTION
- ------------------------------------------------
AND GENERATING CAPACITY
-----------------------
Peak Load and Sales Data
- ------------------------
Kilowatt-hour sales decreased 7.3% for the three months
ended and increased .8% and 2.5% for the nine and twelve months
ended September 30, 1996, respectively, as compared to sales for
the corresponding periods in 1995. The decrease in sales for the
three months ended September 30, 1996, was primarily attributable
to the cooler than average summer weather during the third
quarter of 1996, as compared to the hotter than average summer
weather during the corresponding period in 1995. Cooling degree
hours for the three months ended September 30, 1996, were 38% and
31% below the corresponding period in 1995 and the 20-year
average, respectively. The increase in sales for the nine and
twelve months ended September 30, 1996, was primarily
attributable to the impact of the blizzard-like conditions during
the first quarter of 1996 which brought a record amount of
snowfall to the Washington, D.C. area, partially offset by the
cooler than average summer weather of 1996. 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 1996 summer peak demand was 5,288 megawatts. This
compares with the 1995 summer peak demand of 5,732 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
36
meet the 1996 summer peak demand, the Company had approximately
282 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.
The Company invested approximately $36 million in energy
conservation programs in the first nine months 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 $8.9 million in 1996, based on 1995
performance, as compared to an $8.7 million bonus awarded 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.
37
Construction and Generating Capacity
- ------------------------------------
Construction expenditures, excluding AFUDC and CCRF, 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 Acid Rain portion 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 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 a 25-
year agreement with Panda for a 230-megawatt gas-fueled combined-
cycle cogeneration project in Prince George's County, Maryland.
The project has been completed and the Panda facility is expected
to achieve actual commercial operation during November 1996. For
the years 1997 through 2000, the Company estimates that payments
for capacity and energy under this agreement will total $42.6
million in 1997, $41.1 million in 1998, $59.3 million in 1999 and
$61.6 million in 2000. 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
38
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 permanent 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 $394.9 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 $189.1 million, $168.4
million and $166.5 million at September 30, 1996, December 31,
1995 and September 30, 1995, respectively.
39
<TABLE>
Consolidated Statements of Earnings:
- -----------------------------------
<CAPTION>
Three Nine Twelve
Months Ended Months Ended Months Ended
September 30, September 30, September 30,
---------------------- ---------------------- ----------------------
1996 1995 1996 1995 1996 1995
-------- --------- -------- --------- -------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Income
Leasing activities $ 23,256 $ 25,181 $ 70,311 $ 71,112 $ 99,839 $ 108,749
Marketable securities 7,991 8,972 25,515 27,540 34,096 36,335
Other 5,159 594 (10,324) 2,646 (15,238) 617
-------- --------- -------- --------- -------- ---------
36,406 34,747 85,502 101,298 118,697 145,701
-------- --------- -------- --------- -------- ---------
Expenses
Interest 20,608 22,589 63,581 67,708 87,510 89,939
Administrative and general 4,395 2,393 13,435 7,821 16,093 10,524
Depreciation and
operating 10,986 20,137 41,882 230,615 53,749 239,581
Income tax credit (4,469) (6,292) (49,797) (80,893) (54,612) (82,537)
-------- --------- -------- --------- -------- ---------
31,520 38,827 69,101 225,251 102,740 257,507
-------- --------- -------- --------- -------- ---------
Net earnings (loss) from
nonutility subsidiary $ 4,886 $ (4,080)<F1>$ 16,401 $(123,953)<F1>$ 15,957 $(111,806)<F1>
======== ========= ======== ========= ======== =========
Per share contribution
(reduction) to earnings
$ .04 $(.03)<F1> $ .14 $(1.05)<F1> $ .13 $(.95)<F1>
===== ===== ===== ====== ===== =====
<FN>
<F1> Reflects non-recurring, noncash, after-tax charges of $5.2 million
($.04 per share) for the three months ended September 30, 1995, and
$122.2 million ($1.04 per share) for the nine and twelve months ended
September 30, 1995, related to the 1995 decision to exit the aircraft
equipment leasing business.
</FN>
40
</TABLE>
<TABLE>
STATISTICAL DATA
- ----------------
<CAPTION>
Three Months Ended Twelve Months Ended
September 30, September 30,
--------------------------------- -------------------------------------
1996 1995 % Change 1996 1995 % Change
-------- -------- -------- ---------- ---------- --------
<S> <C> <C> <C> <C> <C> <C>
Revenue from Sales
------------------
of Electricity
--------------
(Thousands of Dollars)
Residential $182,285 $200,045 (8.9) $ 549,110 $ 533,645 2.9
General Service 373,327 381,957 (2.3) 1,080,575 1,067,488 1.2
Large Power Service <F1> 11,784 12,275 (4.0) 35,940 36,187 (0.7)
Street Lighting 2,998 2,918 2.7 12,402 12,682 (2.2)
Rapid Transit 8,605 8,378 2.7 28,939 28,176 2.7
Wholesale 33,241 34,680 (4.1) 122,376 112,551 8.7
-------- -------- ---------- ----------
System $612,240 $640,253 (4.4) $1,829,342 $1,790,729 2.2
======== ======== ========== ==========
Energy Sales
------------
(Millions of KWH)
Residential 1,782 2,007 (11.2) 6,897 6,518 5.8
General Service 4,237 4,503 (5.9) 15,319 15,285 0.2
Large Power Service <F1> 176 196 (10.2) 696 695 0.1
Street Lighting 36 37 (2.7) 164 162 1.2
Rapid Transit 114 113 0.9 416 408 2.0
Wholesale 639 674 (5.2) 2,574 2,374 8.4
-------- -------- ---------- ----------
System 6,984 7,530 (7.3) 26,066 25,442 2.5
======== ======== ========== ==========
Average System Revenue
----------------------
per KWH (cents per KWH) 8.77 8.50 3.2 7.02 7.04 (0.3)
-----------------------
System Peak Demand
------------------
(Thousands of KW)
Summer - - 5,288 5,732
Winter - - 4,831 4,685
Net Generation
--------------
(Millions of KWH) 4,860 6,035 19,197 18,322
Fuel Mix (% of Btu)
-------------------
Coal (%) 86 76 89 84
Oil (%) 7 7 8 7
Gas (%) 7 17 3 9
Fuel Cost per MBtu
------------------
System Average $1.82 $1.74 $1.79 $1.75
Weather Data
------------
Heating Degree Days 9 30 4,570 3,660
20 Year Average 21 3,978
Cooling Degree Hours 5,773 9,336 9,509 11,198
20 Year Average 8,344 11,104
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>
41
</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.
(b) Reports on Form 8-K
None.
42
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
October 28, 1996
- ----------------
DATE
43
<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 September 30, 1996,
and the twelve months ended December 31, 1995 and 1994:
<CAPTION>
September 30, December 31, December 31,
1996 1995 1994
------------- ------------ ------------
<S> <C> <C> <C>
Average shares outstanding for
computation of primary earnings
per common share 118,495,471 118,412,478 118,005,847
============ ============ ============
Average shares outstanding for
fully diluted computation:
Average shares outstanding 118,495,471 118,412,478 118,005,847
Additional shares resulting from:
Conversion of Serial Preferred
Stock, $2.44 Convertible Series
of 1966 (the "Convertible
Preferred Stock") 35,127 38,255 48,110
Conversion of 7% Convertible
Debentures 2,420,799 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 124,343,897 124,312,872 123,977,701
============ ============ ============
Earnings applicable to common stock $218,304,000 $77,540,000 $210,725,000
Add: Dividends paid or accrued on
Convertible Preferred Stock 14,000 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 $224,737,000 $84,031,000 $217,282,000
============ ============ ============
Primary earnings per common share $1.84 $0.65 $1.79
Fully diluted earnings per common share $1.81 $0.68 $1.75
<FN>
The valuation is not required by footnote 2 to paragraph 14 of APB No. 15 for the
the twelve months ended September 30, 1996 and December 31, 1994 because it results
in dilution of less than 3%. In addition, 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 December 31, 1995.
</FN>
44
</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
September 30, 1996, and for each of the preceding five years on the basis of
parent company operations only, are as follows.
<CAPTION>
Twelve
Months For The Year Ended December 31,
Ended ---------------------------------------------------------
Sept. 30,
1996 1995 1994 1993 1992 1991
--------- --------- --------- --------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Net income before cumulative effect
of accounting change $218,971 $218,788 $208,074 $216,478 $172,599 $186,813
Taxes based on income 134,185 129,439 116,648 107,223 76,965 80,988
--------- --------- --------- --------- --------- ---------
Income before taxes and cumulative effect
of accounting change 353,156 348,227 324,722 323,701 249,564 267,801
--------- --------- --------- --------- --------- ---------
Fixed charges:
Interest charges 147,787 146,558 139,210 141,393 138,097 138,512
Interest factor in rentals 23,170 23,431 6,300 5,859 6,140 5,690
--------- --------- --------- --------- --------- ---------
Total fixed charges 170,957 169,989 145,510 147,252 144,237 144,202
--------- --------- --------- --------- --------- ---------
Income before income taxes, cumulative
effect of accounting change and
fixed charges $524,113 $518,216 $470,232 $470,953 $393,801 $412,003
========= ========= ========= ========= ========= =========
Coverage of fixed charges 3.07 3.05 3.23 3.20 2.73 2.86
==== ==== ==== ==== ==== ====
Preferred dividend requirements $16,624 $16,851 $16,437 $16,255 $14,392 $12,298
--------- --------- --------- --------- --------- ---------
Ratio of pre-tax income to net income 1.61 1.59 1.56 1.50 1.45 1.43
--------- --------- --------- --------- --------- ---------
Preferred dividend factor $26,765 $26,793 $25,642 $24,383 $20,868 $17,586
--------- --------- --------- --------- --------- ---------
Total fixed charges and preferred dividends $197,722 $196,782 $171,152 $171,635 $165,105 $161,788
========= ========= ========= ========= ========= =========
Coverage of combined fixed charges
and preferred dividends 2.65 2.63 2.75 2.74 2.39 2.55
==== ==== ==== ==== ==== ====
45
</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
September 30, 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 ---------------------------------------------------------
Sept. 30,
1996 1995 1994 1993 1992 1991
--------- --------- --------- --------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Net income before cumulative effect
of accounting change $234,928 $94,391 $227,162 $241,579 $200,760 $210,164
Taxes based on income 79,573 43,731 93,953 62,145 79,481 80,737
--------- --------- --------- --------- --------- ---------
Income before taxes and cumulative effect
of accounting change 314,501 138,122 321,115 303,724 280,241 290,901
--------- --------- --------- --------- --------- ---------
Fixed charges:
Interest charges 235,936 238,724 224,514 221,312 226,453 225,323
Interest factor in rentals 24,013 26,685 9,938 9,257 6,599 6,080
--------- --------- --------- --------- --------- ---------
Total fixed charges 259,949 265,409 234,452 230,569 233,052 231,403
--------- --------- --------- --------- --------- ---------
Nonutility subsidiary capitalized interest (639) (529) (521) (2,059) (2,200) (6,542)
--------- --------- --------- --------- --------- ---------
Income before income taxes, cumulative
effect of accounting change and
fixed charges $573,811 $403,002 $555,046 $532,234 $511,093 $515,762
======== ======== ======== ======== ======== ========
Coverage of fixed charges 2.21 1.52 2.37 2.31 2.19 2.23
==== ==== ==== ==== ==== ====
Preferred dividend requirements $16,624 $16,851 $16,437 $16,255 $14,392 $12,298
--------- --------- --------- --------- --------- ---------
Ratio of pre-tax income to net income 1.34 1.46 1.41 1.26 1.40 1.38
--------- --------- --------- --------- --------- ---------
Preferred dividend factor $22,276 $24,602 $23,176 $20,481 $20,149 $16,971
--------- --------- --------- --------- --------- ---------
Total fixed charges and preferred dividends $282,225 $290,011 $257,628 $251,050 $253,201 $248,374
======== ======== ======== ======== ======== ========
Coverage of combined fixed charges
and preferred dividends 2.03 1.39 2.15 2.12 2.02 2.08
==== ==== ==== ==== ==== ====
46
</TABLE>
Exhibit 15
October 28, 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 October 28, 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.
47
<TABLE> <S> <C>
<ARTICLE> UT
<SUBSIDIARY>
<NUMBER> 1
<NAME> POTOMAC CAPITAL INVESTMENT CORPORATION
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> SEP-30-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,388,435
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 532,415
<TOTAL-DEFERRED-CHARGES> 662,395
<OTHER-ASSETS> 1,431,292
<TOTAL-ASSETS> 7,014,537
<COMMON> 118,498
<CAPITAL-SURPLUS-PAID-IN> 1,010,401
<RETAINED-EARNINGS> 796,946
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,925,845
142,500
125,299
<LONG-TERM-DEBT-NET> 1,668,973
<SHORT-TERM-NOTES> 3,830<F1>
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 250,625<F1>
<LONG-TERM-DEBT-CURRENT-PORT> 150,000
985
<CAPITAL-LEASE-OBLIGATIONS> 163,528
<LEASES-CURRENT> 20,772
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,562,180
<TOT-CAPITALIZATION-AND-LIAB> 7,014,537
<GROSS-OPERATING-REVENUE> 1,596,598
<INCOME-TAX-EXPENSE> 127,567
<OTHER-OPERATING-EXPENSES> 1,163,399
<TOTAL-OPERATING-EXPENSES> 1,290,966
<OPERATING-INCOME-LOSS> 305,632
<OTHER-INCOME-NET> 25,590
<INCOME-BEFORE-INTEREST-EXPEN> 331,222
<TOTAL-INTEREST-EXPENSE> 105,548
<NET-INCOME> 225,674
12,448
<EARNINGS-AVAILABLE-FOR-COMM> 213,226
<COMMON-STOCK-DIVIDENDS> 147,458
<TOTAL-INTEREST-ON-BONDS> 126,200<F2>
<CASH-FLOW-OPERATIONS> 311,726
<EPS-PRIMARY> $1.80
<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 September 30, 1996.
<F3>No material dilution would occur if all the convertible preferred stock and
debentures were converted into common stock.
</FN>
</TABLE>
