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, 1997
------------------
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
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(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, 1997
- -------------------------- ---------------------------------
Common Stock, $1 par value 118,500,723
TABLE OF CONTENTS
PART I - Financial Information Page
Item 1 - Consolidated Financial Statements
Consolidated Statements of Earnings and Retained Income.. 2
Consolidated Balance Sheets.............................. 3
Consolidated Statements of Cash Flows.................... 4
Notes to Consolidated Financial Statements
(1) Summary of Significant Accounting Policies......... 5
(2) Income Taxes....................................... 10
(3) Capitalization..................................... 13
(4) Fair Value of Financial Instruments................ 15
(5) Marketable Securities.............................. 17
(6) Commitments and Contingencies...................... 18
Report of Independent Accountants on Review of Interim
Financial Information.................................. 26
Item 2 - Management's Discussion and Analysis of Consolidated
Results of Operations and Financial Condition
Utility
Proposed Merger Update................................. 27
Results of Operations.................................. 29
Capital Resources and Liquidity........................ 32
New Accounting Standards............................... 33
Nonutility Subsidiary
Results of Operations.................................. 33
Capital Resources and Liquidity........................ 36
PART II - Other Information
Item 1 - Legal Proceedings................................. 37
Item 4 - Submission of Matters to a Vote of
Security Holders................................ 37
Item 5 - Other Information
Executive Officers of the Registrant..................... 38
Other Financing Arrangements............................. 38
Base Rate Proceedings.................................... 38
Restructuring of the Bulk Power Market................... 43
Competition.............................................. 44
Peak Load, Sales, Conservation, and Construction and
Generating Capacity.................................... 46
Selected Nonutility Subsidiary Financial Information..... 49
Statistical Data......................................... 51
Unaudited Pro Forma Combined Condensed Financial
Information............................................ 52
Item 6 - Exhibits and Reports on Form 8-K.................. 60
Signatures................................................. 61
Computations of Earnings Per Common Share.................. 62
Computation of Ratios - Parent Company Only................ 63
Computation of Ratios - Fully Consolidated................. 64
Independent Accountants Awareness Letter................... 65
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,
-------------------- ---------- -- -------- ----------------------
1997 1996 1997 1996 1997 1996
--------- --------- ---------- ---------- ---------- ----------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Revenue
Sales of electricity $ 615,621 $ 612,240 $1,423,198 $1,455,818 $1,792,121 $1,829,342
Other electric revenue 2,597 2,117 9,061 6,516 12,661 9,025
--------- --------- ---------- ---------- ---------- ----------
Total Operating Revenue 618,218 614,357 1,432,259 1,462,334 1,804,782 1,838,367
Interchange deliveries 14,824 43,868 40,814 134,264 82,004 160,481
--------- --------- ---------- ---------- ---------- ----------
Total Revenue 633,042 658,225 1,473,073 1,596,598 1,886,786 1,998,848
--------- --------- ---------- ---------- ---------- ----------
Operating Expenses
Fuel 92,953 93,191 249,655 260,709 316,739 351,149
Purchased energy 58,864 91,467 154,314 251,964 238,327 301,850
Capacity purchase payments 35,440 30,731 108,165 95,592 138,359 126,529
Other operation 55,187 55,055 160,319 167,037 216,608 226,343
Maintenance 22,717 23,276 67,797 65,970 93,351 93,025
--------- --------- ---------- ---------- ---------- ----------
Total Operation and Maintenance 265,161 293,720 740,250 841,272 1,003,384 1,098,896
Depreciation and amortization 59,581 56,972 173,982 167,048 229,949 220,938
Income taxes 82,222 81,588 115,280 127,567 121,798 130,708
Other taxes 59,578 59,683 154,219 155,079 199,506 200,227
--------- --------- ---------- ---------- ---------- ----------
Total Operating Expenses 466,542 491,963 1,183,731 1,290,966 1,554,637 1,650,769
--------- --------- ---------- ---------- ---------- ----------
Operating Income 166,500 166,262 289,342 305,632 332,149 348,079
--------- --------- ---------- ---------- ---------- ----------
Other Income
Nonutility Subsidiary
Income 32,898 36,406 101,370 85,502 130,834 118,697
Loss on assets held for disposal (2,022) - (2,022) (12,320) (2,446) (12,320)
Expenses, including interest
and income taxes (30,001) (31,520) (83,567) (56,781) (112,114) (90,420)
--------- --------- ---------- ---------- ---------- ----------
Net earnings from nonutility
subsidiary 875 4,886 15,781 16,401 16,274 15,957
Allowance for other funds used during
construction and capital cost recovery factor 1,608 1,567 4,949 4,964 6,557 6,658
Other, net 1,429 857 3,753 4,225 3,986 3,669
--------- --------- ---------- ---------- ---------- ----------
Total Other Income 3,912 7,310 24,483 25,590 26,817 26,284
--------- --------- ---------- ---------- ---------- ----------
Income Before Utility Interest Charges 170,412 173,572 313,825 331,222 358,966 374,363
--------- --------- ---------- ---------- ---------- ----------
Utility Interest Charges
Long-term debt 32,188 33,042 101,036 99,767 134,375 133,889
Other 4,053 3,606 9,557 11,495 11,894 13,898
Allowance for borrowed funds used during
construction and capital cost recovery factor (1,814) (1,763) (5,859) (5,714) (7,680) (8,352)
--------- --------- ---------- ---------- ---------- ----------
Net Utility Interest Charges 34,427 34,885 104,734 105,548 138,589 139,435
--------- --------- ---------- ---------- ---------- ----------
Net Income 135,985 138,687 209,091 225,674 220,377 234,928
Dividends on Preferred Stock 4,157 4,151 12,439 12,448 16,595 16,624
--------- --------- ---------- ---------- ---------- ----------
Earnings for Common Stock 131,828 134,536 196,652 213,226 203,782 218,304
Retained Income at Beginning of Period 728,241 711,726 760,285 742,296 796,946 784,026
Dividends on Common Stock (49,155) (49,153) (147,459) (147,458) (196,613) (196,611)
Subsidiary Marketable Securities Net
Unrealized Gain (Loss), Net of Tax 4,534 (163) 5,970 (11,118) 11,333 (8,773)
--------- --------- ---------- ---------- ---------- ----------
Retained Income at End of Period $ 815,448 $ 796,946 $ 815,448 $ 796,946 $ 815,448 $ 796,946
========= ========= ========== ========== ========== ==========
Average Common Shares
Outstanding (000's) 118,501 118,497 118,500 118,496 118,500 118,495
Earnings Per Common Share $1.11 $1.14 $1.66 $1.80 $1.72 $1.84
Cash Dividends Per Common Share $0.415 $0.415 $1.245 $1.245 $1.66 $1.66
Book Value Per Share $16.41 $16.25
Dividend Payout Ratio 96.5% 90.2%
Effective Federal Income Tax Rate 25.8% 21.1%
2
</TABLE>
<TABLE>
POTOMAC ELECTRIC POWER COMPANY
Consolidated Balance Sheets
(Unaudited at September 30, 1997 and 1996)
------------------------------------------
<CAPTION>
September 30, December 31, September 30,
ASSETS 1997 1996 1996
------ ------------- ------------- -------------
(Thousands of Dollars)
<S> <C> <C> <C>
Property and Plant - at original cost
Electric plant in service $ 6,335,130 $ 6,232,049 $ 6,168,497
Construction work in progress 84,901 62,469 72,624
Electric plant held for future use 4,210 4,152 4,133
Nonoperating property 22,750 22,921 22,699
------------- ------------- -------------
6,446,991 6,321,591 6,267,953
Accumulated depreciation (2,000,376) (1,898,342) (1,857,633)
------------- ------------- -------------
Net Property and Plant 4,446,615 4,423,249 4,410,320
------------- ------------- -------------
Current Assets
Cash and cash equivalents 2,916 2,174 7,689
Customer accounts receivable, less allowance
for uncollectible accounts of $558, $1,298
and $894 186,623 128,600 186,638
Other accounts receivable, less allowance for
uncollectible accounts of $300 25,117 38,490 36,253
Accrued unbilled revenue 88,071 70,214 110,201
Prepaid taxes 41,554 34,202 49,539
Other prepaid expenses 3,917 4,613 4,512
Material and supplies - at average cost
Fuel 60,432 68,232 67,091
Construction and maintenance 69,195 69,541 70,492
------------- ------------- -------------
Total Current Assets 477,825 416,066 532,415
------------- ------------- -------------
Deferred Charges
Income taxes recoverable through future rates, net 238,711 238,467 239,011
Conservation costs, net 224,464 233,793 234,832
Unamortized debt reacquisition costs 53,447 55,552 56,259
Other 196,614 159,139 132,293
------------- ------------- -------------
Total Deferred Charges 713,236 686,951 662,395
------------- ------------- -------------
Nonutility Subsidiary Assets
Cash and cash equivalents 10,087 804 199
Marketable securities 303,905 377,237 394,945
Investment in finance leases 460,021 484,972 480,415
Operating lease equipment, net of accumulated
depreciation of $146,083, $117,705 and $107,555 170,747 199,124 209,275
Assets held for disposal - 10,300 12,600
Receivables, less allowance for uncollectible
accounts of $6,000 34,997 87,745 89,717
Other investments 182,581 193,002 205,479
Other assets 14,146 12,436 16,777
------------- ------------- -------------
Total Nonutility Subsidiary Assets 1,176,484 1,365,620 1,409,407
------------- ------------- -------------
Total Assets $ 6,814,160 $ 6,891,886 $ 7,014,537
============= ============= =============
CAPITALIZATION AND LIABILITIES
- ------------------------------
Capitalization
Common stock $ 118,501 $ 118,500 $ 118,498
Other common equity 1,825,700 1,770,692 1,807,347
Serial preferred stock 125,291 125,298 125,299
Redeemable serial preferred stock 141,000 142,500 142,500
Long-term debt 1,727,707 1,767,598 1,668,973
------------- ------------- -------------
Total Capitalization 3,938,199 3,924,588 3,862,617
------------- ------------- -------------
Other Non-Current Liabilities
Capital lease obligations 161,057 162,936 163,528
------------- ------------- -------------
Total Other Non-Current Liabilities 161,057 162,936 163,528
------------- ------------- -------------
Current Liabilities
Long-term debt and preferred stock
redemption due within one year 50,985 152,445 150,985
Short-term debt 277,075 131,390 254,455
Accounts payable and accrued expenses 247,359 179,289 221,865
Capital lease obligations due within one year 20,772 20,772 20,772
Other 83,774 83,135 83,840
------------- ------------- -------------
Total Current Liabilities 679,965 567,031 731,917
------------- ------------- -------------
Deferred Credits
Income taxes 1,014,472 973,642 920,659
Investment tax credits 58,221 60,958 61,870
Other 30,842 35,658 33,971
------------- ------------- -------------
Total Deferred Credits 1,103,535 1,070,258 1,016,500
------------- ------------- -------------
Nonutility Subsidiary Liabilities
Long-term debt 863,167 996,232 940,318
Short-term notes payable 9,200 51,650 181,305
Deferred taxes and other 59,037 119,191 118,352
------------- ------------- -------------
Total Nonutility Subsidiary Liabilities 931,404 1,167,073 1,239,975
------------- ------------- -------------
Total Capitalization and Liabilities $ 6,814,160 $ 6,891,886 $ 7,014,537
============= ============= =============
3
</TABLE>
<TABLE>
POTOMAC ELECTRIC POWER COMPANY
Consolidated Statements of Cash Flows
(Unaudited)
-------------------------------------
<CAPTION>
Nine Months Ended Twelve Months Ended
September 30, September 30,
----------------------- -----------------------
1997 1996 1997 1996
--------- --------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Operating Activities
Income from utility operations $ 193,310 $ 209,273 $ 204,103 $ 218,971
Adjustments to reconcile income to net
cash from operating activities:
Depreciation and amortization 173,982 167,048 229,949 220,938
Deferred income taxes and investment tax credits 41,110 24,067 98,539 41,483
Deferred conservation costs (26,243) (39,351) (36,296) (58,999)
Allowance for funds used during construction
and capital cost recovery factor (10,808) (10,678) (14,237) (15,010)
Changes in materials and supplies 8,146 (3,883) 7,956 373
Changes in accounts receivable and accrued unbilled revenue (62,507) (85,249) 33,281 3,872
Changes in accounts payable (17,061) 4,039 (7,476) (36,720)
Changes in other current assets and liabilities 75,275 48,718 32,416 (4,190)
Net other operating activities (57,674) (21,440) (86,261) (54,430)
Nonutility subsidiary:
Net earnings 15,781 16,401 16,274 15,957
Deferred income taxes (46,624) (26,999) (56,023) (27,779)
Loss on assets held for disposal 2,022 12,320 2,446 12,320
Changes in other assets and net other operating activities 29,221 17,460 48,019 54,669
--------- --------- --------- ---------
Net Cash From Operating Activities 317,930 311,726 472,690 371,455
--------- --------- --------- ---------
Investing Activities
Total investment in property and plant (150,987) (139,531) (205,492) (191,578)
Allowance for funds used during construction
and capital cost recovery factor 10,808 10,678 14,237 15,010
--------- --------- --------- ---------
Net investment in property and plant (140,179) (128,853) (191,255) (176,568)
Nonutility subsidiary:
Purchase of marketable securities (35,103) (19,680) (35,103) (33,568)
Proceeds from sale or redemption of marketable securities 124,517 140,406 151,639 148,977
Investment in leased equipment (7,480) (3,056) (7,480) (54,841)
Proceeds from sale or disposition of leased equipment 28,484 3,658 28,484 3,658
Proceeds from assets held for disposal 4,600 34,154 4,600 34,154
Proceeds from sale of assets 2,700 285 2,415 6,251
Purchase of other investments (20,451) (4,500) (38,949) (5,164)
Proceeds from sale or distribution of other investments 6,107 14,193 25,781 13,196
Investment in promissory notes (12) (20,414) 16,157 (23,068)
Proceeds from promissory notes 63,807 14,083 66,399 16,416
--------- --------- --------- ---------
Net Cash From (Used by) Investing Activities 26,990 30,276 22,688 (70,557)
--------- --------- --------- ---------
Financing Activities
Dividends on common stock (147,459) (147,458) (196,613) (196,611)
Dividends on preferred stock (12,439) (12,448) (16,595) (16,624)
Redemption of preferred stock (1,500) - (1,500) -
Issuance of long-term debt 8,090 - 107,590 -
Reacquisition and retirement of long-term debt (151,460) (26,320) (151,460) (126,162)
Short-term debt, net 145,685 (4,010) 22,620 185,705
Other financing activities (297) (3,903) (398) (9,823)
Nonutility subsidiary:
Issuance of long-term debt 40,000 128,000 95,000 160,000
Repayment of long-term debt (173,065) (233,368) (176,799) (273,144)
Short-term debt, net (42,450) (42,045) (172,108) (39,895)
--------- --------- --------- ---------
Net Cash Used By Financing Activities (334,895) (341,552) (490,263) (316,554)
--------- --------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents 10,025 450 5,115 (15,656)
Cash and Cash Equivalents at Beginning of Period 2,978 7,438 7,888 23,544
--------- --------- --------- ---------
Cash and Cash Equivalents at End of Period $ 13,003 $ 7,888 $ 13,003 $ 7,888
========= ========= ========= =========
Cash paid for interest (net of capitalized interest) and income taxes:
Interest (including nonutility subsidiary
interest of $67,104, $77,664, $72,829 and $87,541) $ 176,836 $ 188,772 $ 205,031 $ 221,208
Income taxes $ 12,475 $ 3,398 $ 37,631 $ 31,289
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 vehicle
to conduct the Company's ongoing nonutility businesses.
Effective April 30, 1996, the Company reorganized its nonutility
subsidiaries whereby PEPCO Enterprises, Inc. (PEI) became a
subsidiary of PCI. 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,
through its subsidiaries, which provide 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.
5
Certain 1996 amounts have been reclassified to conform to
the current year presentation.
A description of significant accounting policies follows.
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,
6
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.
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 1997, 1996 and 1995.
7
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, 1997,
unamortized conservation costs totaled $85.1 million in Maryland
and $139.4 million in the District of Columbia.
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
jurisdictional AFUDC capitalization rates are determined as
prescribed by the FERC. The effective capitalization rates were
approximately 7.6%, compounded semiannually, for the nine months
ended September 30, 1997, and approximately 7.4% in 1996 and 7.9%
in 1995, compounded semiannually.
In Maryland, the Company accrues a CCRF on the retail
jurisdictional portion of certain pollution control expenditures
related to compliance with the Clean Air Act (CAA). The base for
calculating this return is the amount by which the Maryland
jurisdictional CAA expenditure balance exceeds the CAA balance
being recovered in base rates. The CCRF rate for Maryland is
9.46%. In the District of Columbia, the carrying costs of CAA
expenditures not in rate base are recovered through a base rate
surcharge.
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.
8
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 original maturities of three months or
less.
New Accounting Standards
- ------------------------
In June 1997, the Financial Accounting Standards Board
(FASB) issued Statement of Financial Accounting Standards (SFAS)
No. 130 entitled "Reporting Comprehensive Income" which will
become effective January 1, 1998. SFAS No. 130 establishes
standards for reporting and display of comprehensive income and
its components. All items that are required to be recognized
under accounting standards as components of comprehensive income
must be reported in a financial statement that is displayed with
the same prominence as other financial statements. The Company's
principal components of comprehensive income are net income and
unrealized gains and losses on marketable securities.
In June 1997, the FASB also issued SFAS No. 131 entitled
"Disclosures about Segments of an Enterprise and Related
Information" which will become effective for the Company's 1998
calendar year financial statements and will impact quarterly
reporting beginning in the first quarter of 1999. The Company is
evaluating SFAS No. 131 to determine the impact, if any, on its
reporting and disclosure requirements.
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.
9
<TABLE>
(2) INCOME TAXES
- ----------------
Provision for Income Taxes
- --------------------------
<CAPTION>
Three Months Ended Nine Months Ended Twelve Months Ended
September 30, September 30, September 30,
----------------------- ----------------------- -----------------------
1997 1996 1997 1996 1997 1996
---------- ---------- ---------- --------- ---------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Utility current tax expense
Federal $ 58,762 $ 60,965 $ 65,445 $ 92,718 $ 19,962 $ 81,792
State and local 7,756 8,049 8,708 12,395 2,594 10,910
---------- ---------- ---------- ---------- ---------- ----------
Total utility current tax expense 66,518 69,014 74,153 105,113 22,556 92,702
---------- ---------- ---------- ---------- ---------- ----------
Utility deferred tax expense
Federal 14,572 11,763 38,097 23,250 89,609 39,295
State and local 2,100 1,724 5,750 3,554 12,579 5,837
Investment tax credits (912) (912) (2,737) (2,737) (3,649) (3,649)
---------- ---------- ---------- ---------- ---------- ----------
Total utility deferred tax expense 15,760 12,575 41,110 24,067 98,539 41,483
---------- ---------- ---------- ---------- ---------- ----------
Total utility income tax expense 82,278 81,589 115,263 129,180 121,095 134,185
---------- ---------- ---------- ---------- ---------- ----------
Nonutility subsidiary current tax expense
Federal 17,642 (13,783) 20,793 (22,822) 25,363 (26,962)
---------- ---------- ---------- ---------- ---------- ----------
Nonutility subsidiary deferred tax expense
Federal (21,016) 9,314 (45,084) (26,975) (54,482) (27,650)
---------- ---------- ---------- ---------- ---------- ----------
Total nonutility subsidiary income tax credit (3,374) (4,469) (24,291) (49,797) (29,119) (54,612)
---------- ---------- ---------- ---------- ---------- ----------
Total consolidated income tax expense 78,904 77,120 90,972 79,383 91,976 79,573
Income taxes included in other income (3,318) (4,468) (24,308) (48,184) (29,822) (51,135)
---------- ---------- ---------- ---------- ---------- ----------
Income taxes included in utility operating
expenses $ 82,222 $ 81,588 $ 115,280 $ 127,567 $ 121,798 $ 130,708
========== ========== ========== ========== ========== ==========
10
</TABLE>
<TABLE>
Reconciliation of Consolidated Income Tax Expense
- -------------------------------------------------
<CAPTION>
Three Months Ended Nine Months Ended Twelve Months Ended
September 30, September 30, September 30,
----------------------- ----------------------- -----------------------
1997 1996 1997 1996 1997 1996
---------- ---------- ---------- ---------- ---------- ----------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Income before income taxes $ 214,889 $ 215,807 $ 300,063 $ 305,057 $ 312,353 $ 314,501
========== ========== ========== ========== ========== ==========
Utility income tax at federal
statutory rate $ 76,086 $ 75,387 $ 108,001 $ 118,459 $ 113,819 $ 123,605
Increases (decreases) resulting from
Depreciation 2,522 2,542 7,566 7,627 9,806 10,055
Removal costs (841) (1,000) (4,027) (2,478) (5,123) (5,364)
Allowance for funds used during
construction 238 208 603 488 806 595
Other (1,222) (988) (3,541) (2,463) (4,195) (1,470)
State income taxes, net of federal effect 6,407 6,352 9,398 10,284 9,863 10,803
Tax credits (912) (912) (2,737) (2,737) (3,881) (4,039)
---------- ---------- ---------- ---------- ---------- ----------
Total utility income tax expense 82,278 81,589 115,263 129,180 121,095 134,185
---------- ---------- ---------- ---------- ---------- ----------
Nonutility subsidiary income tax at federal
statutory rate (874) 146 (2,978) (11,689) (4,495) (13,530)
(Decreases) increases resulting from
Dividends received deduction (1,269) (2,636) (3,987) (8,680) (6,523) (10,722)
Reversal of previously accrued deferred
taxes - (2,105) (10,125) (30,804) (10,125) (30,804)
Other (1,231) 126 (7,201) 1,376 (7,976) 444
---------- ---------- ---------- ---------- ---------- ----------
Total nonutility subsidiary income tax credit (3,374) (4,469) (24,291) (49,797) (29,119) (54,612)
---------- ---------- ---------- ---------- ---------- ----------
Total consolidated income tax expense 78,904 77,120 90,972 79,383 91,976 79,573
Income taxes included in other income (3,318) (4,468) (24,308) (48,184) (29,822) (51,135)
---------- ---------- ---------- ---------- ---------- ----------
Income taxes included in utility operating
expenses $ 82,222 $ 81,588 $ 115,280 127,567 $ 121,798 130,708
========== ========== ========== ========== ========== ==========
11
</TABLE>
<TABLE>
Components of Consolidated Deferred Tax Liabilities (Assets)
- ------------------------------------------------------------
<CAPTION>
Sept. 30, Dec. 31, Sept. 30,
1997 1996 1996
---------- ---------- ----------
(Thousands of Dollars)
<S> <C> <C> <C>
Utility deferred tax liabilities (assets)
Depreciation and other book to tax
basis differences $ 855,970 $ 821,656 $ 808,405
Rapid amortization of certified pollution
control facilities 23,646 24,816 25,473
Deferred taxes on amounts to be collected
through future rates 90,376 90,284 90,490
Property taxes 13,310 12,664 12,456
Deferred fuel (12,099) (14,663) (14,227)
Prepayment premium on debt retirement 20,228 21,025 21,279
Deferred investment tax credit (22,042) (23,079) (23,424)
Contributions in aid of construction (29,530) (28,719) (27,737)
Contributions to pension plan 16,170 16,170 12,276
Conservation costs (demand side management) 48,093 41,106 -
Other 22,882 21,653 20,125
---------- ---------- ----------
Total utility deferred tax liabilities (net) 1,027,004 982,913 925,116
Current portion of utility deferred tax
liabilities (included in Other Current
Liabilities) 12,532 9,271 4,457
---------- ---------- ----------
Total utility deferred tax liabilities (net) -
non-current $1,014,472 $ 973,642 $ 920,659
========== ========== ==========
Nonutility subsidiary deferred tax liabilities
(assets)
Finance leases $ 118,305 $ 144,667 $ 138,135
Operating leases 41,660 49,551 59,396
Alternative minimum tax (97,109) (97,109) (84,540)
Other (45,197) (36,041) (45,411)
---------- ---------- ----------
Total nonutility subsidiary deferred tax
liabilities (net), (included in Deferred
taxes and other) $ 17,659 $ 61,068 $ 67,580
========== ========== ==========
12
</TABLE>
(3) CAPITALIZATION
--------------
Common Equity
- -------------
At September 30, 1997, 118,500,723 shares of the Company's
$1 par value Common Stock were outstanding. A total of 200
million shares is authorized. As of September 30, 1997,
2,324,721 shares were reserved for issuance under the Shareholder
Dividend Reinvestment Plan; 1,221,624 shares were reserved for
issuance under the Employee Savings Plans; and 2,769,412 and
3,392,500 shares were reserved for conversion of the 7% and 5%
Convertible Debentures, respectively. 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, 1997, the Company had outstanding 5,345,528
shares of its $50 par value Serial Preferred Stock, including the
Redeemable Serial Preferred Stock. A total of 11,125,649 shares
is authorized. At September 30, 1997, the aggregate annual
dividend requirements on the Serial Preferred Stock and the
Redeemable Serial Preferred Stock were approximately $6.4 million
and $10.1 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
(5,832 shares outstanding at September 30, 1997) is convertible
into Common Stock at $8.51 per share.
At September 30, 1997, the Company had outstanding one
million shares of its Serial Preferred Stock, Auction Series A.
The annual dividend rate is 4.205% ($2.1025) for the period
September 1, 1997, through November 30, 1997. For the period
June 1, 1997, through August 31, 1997, the annual dividend rate
was 4.5% ($2.25). The average rate at which dividends were paid
during the twelve months ended September 30, 1997, was 4.2%
($2.10).
At September 30, 1997, the Company had outstanding three
series of $50 par value Redeemable Serial Preferred Stock. There
are one million shares of the $3.89 (7.78%) Series of 1991 on
which the sinking fund requirement commences June 1, 2001; one
million shares of the $3.40 (6.80%) Series of 1992 on which the
sinking fund requirement commences September 1, 2002; and 839,696
13
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 2001 with respect to the three series
of Redeemable Serial Preferred Stock are $1 million in 1998, $1.5
million in 1999 through 2000 and $9.8 million in 2001.
The Company's Long-Term Debt at September 30, 1997, is
summarized below:
(Thousands of Dollars)
First Mortgage Bonds $1,341,800
Convertible Debentures 178,907
Notes Payable 283,090
Net Unamortized Discount (26,090)
Current Portion (50,000)
----------
Net Utility Long-Term Debt $1,727,707
==========
Nonutility Subsidiary Long-Term Debt $ 863,167
==========
At September 30, 1997, the aggregate annual interest
requirement on the Company's long-term debt, including debt due
within one year, was $122 million; and the aggregate amounts of
long-term debt maturities are $50 million in 1998, $45 million in
1999, $100 million in 2000 and $165 million in 2001. At
September 30, 1997, long-term debt due within one year consisted
of $50 million of 4-3/8% First Mortgage Bonds.
On July 10 and August 1, 1997, the Company redeemed, at
maturity, $50 million of 9.08% Medium-Term Notes. On October 9,
1997, the Company issued $175 million of 6-1/4%, 10 PUT 7-Year
First Mortgage Bonds maturing October 15, 2007. Each new bond
will be repayable on October 15, 2004, at the option of the
holder, at 100% of its principal amount, together with accrued
and unpaid interest. The bonds were offered to investors at a
price of 99.85% to yield 6.276% to the put date of October 15,
2004.
Nonutility Subsidiary Long-Term Debt
- ------------------------------------
Long-term debt at September 30, 1997, consisted primarily of
unsecured borrowings from institutional lenders maturing at
various dates between 1997 and 2003. The interest rates of such
borrowings ranged from 5% to 10.1%. The weighted average
effective interest rate was 7.48% at September 30, 1997, 7.44% at
December 31, 1996, and 7.16% at September 30, 1996. Annual
aggregate principal repayments on these borrowings are $26.3
million in 1997, $300.7 million in 1998, $170 million in 1999,
$122.5 million in 2000, $71.5 million in 2001 and $113.5 million
14
thereafter. Also included in long-term debt is $58.7 million of
non-recourse debt which is due in monthly installments with final
maturities in 1999, 2001, 2002 and 2011.
(4) FAIR VALUE OF FINANCIAL INSTRUMENTS
-----------------------------------
The following methods and assumptions were used to estimate,
at September 30, 1997, December 31, 1996, and September 30, 1996,
the fair value of each class of financial instruments shown below
for which it is practicable to estimate that value.
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 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 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
<TABLE>
The estimated fair values of the Company's financial instruments at
September 30, 1997, December 31, 1996, and September 30, 1996, are shown below.
<CAPTION>
September 30, December 31, September 30,
1997 1996 1996
-------------------------- ------------------------- -------------------------
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 $ 125,291 125,424 125,298 113,285 125,299 112,210
========== ========= ========= ========= ========= =========
Redeemable serial
preferred stock $ 141,000 144,010 142,500 146,491 142,500 143,465
========== ========= ========= ========= ========= =========
Long-term debt
First mortgage bonds $1,278,011 1,305,912 1,327,389 1,319,976 1,327,182 1,295,756
Medium-term notes $ 281,103 283,583 272,788 274,242 173,218 169,791
Convertible debentures $ 168,593 173,844 167,421 171,880 168,573 169,725
---------- --------- --------- --------- --------- ---------
Total long-term debt $1,727,707 1,763,339 1,767,598 1,766,098 1,668,973 1,635,272
========== ========= ========= ========= ========= =========
Nonutility Subsidiary
Assets
Marketable securities $ 303,905 303,905 377,237 377,237 394,945 394,945
========== ========= ========= ========= ========= =========
Notes receivable $ 23,438 19,707 72,251 71,593 74,842 72,279
========== ========= ========= ========= ========= =========
Liabilities
Long-term debt $ 863,167 871,071 996,232 1,011,814 940,318 954,605
========== ========= ========= ========= ========= =========
16
</TABLE>
(5) MARKETABLE SECURITIES
---------------------
PCI's marketable securities, primarily investment grade
preferred stocks with mandatory redemption features, are
classified as available-for-sale for financial reporting
purposes. Net unrealized gains or losses on such securities are
reflected, net of tax, in stockholders' equity. The net
unrealized gains (losses) on marketable securities, which relate
primarily to mandatory redeemable preferred stock, are shown
below:
September 30, December 31, September 30,
1997 1996 1996
------------- ------------ -------------
(Thousands of Dollars)
Market value $ 303,905 $ 377,237 $ 394,945
Cost 293,081 375,598 401,555
--------- --------- ---------
Net unrealized gain
(loss) $ 10,824 $ 1,639 $ (6,610)
========= ========= =========
Included in net unrealized gains and losses are gross
unrealized gains of $13.2 million and gross unrealized losses of
$2.4 million at September 30, 1997; gross unrealized gains of
$9.9 million and gross unrealized losses of $8.3 million at
December 31, 1996; and gross unrealized gains of $6.4 million and
gross unrealized losses of $13 million at September 30, 1996.
In determining gross realized gains and losses on sales or
calls of securities, specific identification is used. A summary
of realized gains and losses is shown below.
Three Months Nine Months Twelve Months
Ended Ended Ended
September 30, September 30, September 30,
-------------- -------------- --------------
1997 1996 1997 1996 1997 1996
------ ------ ------ ------ ------ ------
(Thousands of Dollars)
Gross realized
gains $ 715 $ 832 $7,527 $3,337 $8,856 $3,669
Gross realized
losses (4) (94) (627) (886) (792) (1,037)
------ ------ ------ ------ ------ ------
Net gain $ 711 $ 738 $6,900 $2,451 $8,064 $2,632
====== ====== ====== ====== ====== ======
17
At September 30, 1997, the contractual maturities for
mandatory redeemable preferred stock are $5 million within one
year, $108.8 million from one to five years, $91 million from
five to 10 years and $88.3 million for over 10 years.
(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 557,000
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, which are 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 Constellation Energy 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 included: 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
18
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. If the
Merger is not completed, a substantial portion of Merger related
costs would be written off as a charge against the Company's
results of operations. At September 30, 1997, the Company had
deferred $47.8 million in costs related to the Merger.
Shareholders of the Company and BGE, at separate special
meetings during March 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
with the Maryland and District of Columbia Public Service
Commissions on April 8, 1996.
On April 16, 1997, FERC announced its finding that the
proposed Merger would be in the public interest and approved the
transaction without conditions. FERC held that the Merger would
not adversely affect competition in the long- or short-term
wholesale capacity markets. In addition, FERC indicated that
evaluation of the effect of the Merger on retail markets would be
left to the Maryland and District of Columbia Public Service
Commissions.
Also on April 16, 1997, the Maryland Public Service
Commission unanimously approved the proposed Merger and ordered
Constellation Energy to reduce rates by $56 million ($44 million
for BGE and $12 million for PEPCO), beginning on the effective
date of the Merger, with base rates to be frozen for three years
thereafter. The reductions are premised on an 11.4% return on
equity (ROE). In addition, the Commission ordered that 50% of
earnings above an 11.4% ROE be used to further reduce customer
rates. In addition to ordering the rate decrease, the Order also
denies the two companies the opportunity to recover the full
costs for purchased power contracts previously approved by the
Commission. The Maryland Order would put in place a plan that
would eliminate any reasonable opportunity for shareholders to
share in the benefits. The Company and BGE believe that the
Maryland Order contains elements that must be revised for the
Merger to take place.
On May 2, 1997, the companies filed a request for
reconsideration of the Maryland Order. In the request, the
companies detailed areas of the Order that need to be revised for
the Merger to proceed and proposed a modified plan to address
these concerns. Highlights of this modified plan include: 1) a
$26 million rate reduction for Constellation Energy's Maryland
customers upon completion of the Merger, followed by a four-year
base-rate freeze; 2) a comprehensive surcharge that permits full
cost recovery of power purchase contracts the Commission had
previously approved; 3) a synergy sharing mechanism premised on
19
an 11.9% ROE that splits Merger benefits on a 50/50 basis between
customers and investors, allowing further customer rate
reductions if the new company's operations result in additional
savings; and 4) an opportunity for recovery of Merger costs over
the four-year, base-rate freeze period via the synergy sharing
mechanism. Under this proposal, Constellation Energy would write
off Merger costs in the year the Merger is consummated. There
can be no assurance that the Commission will grant the request
for reconsideration or that the Commission's Order will be
changed.
On May 1, 1997, the International Brotherhood of Electrical
Workers (IBEW) Local 1900 filed an appeal of the Maryland
Commission's decision with the Circuit Court of Baltimore County.
In view of the Commission's conclusion that, under Maryland law,
the IBEW's appeal divested it of authority to consider the
Application for Rehearing, the joint applicants filed a motion
requesting the Circuit Court to remand the case to the
Commission. On July 8, 1997, the Circuit Court of Baltimore
County decided to hold its ruling on the motion for remand until
July 28, 1997 while the Maryland Commission corrected a
computational error contained in its April 16, 1997 Order. On
July 14, 1997, the Company's and BGE's Chief Executive Officers
filed sworn affidavits in the Court stating that the Merger
cannot proceed unless other aspects of the Commission's Order
were modified. The affidavits stated that even if adjusted for
the computational error, the original order does not provide an
adequate financial basis upon which the companies could proceed
to consummate the Merger. On July 28, 1997, the Circuit Court
denied the motion for rehearing, accepted the Commission's
correction of the rate reduction to $47.5 million and established
a procedural schedule for consideration of the IBEW's appeal. By
order dated October 27, 1997, the Court affirmed the Commission's
order approving the Merger. On November 4, 1997, the Maryland
Commission reclaimed jurisdiction over the Merger case and will
consider the requests for reconsideration of its April 16, 1997
order. The Commission established December 3, 1997 as the date
for any party to the case to file responses regarding these
matters. Replies to these responses must be filed by December
13, 1997.
On October 20, 1997, the District of Columbia Public Service
Commission approved the proposed Merger, subject to several
conditions. These conditions include an allocation of the first
four years of the Commission's computation of the District's
proportionate share of estimated net cost savings from the Merger
of 75% to ratepayers and 25% to shareholders. The Commission
increased the Company's and BGE's estimated net cost savings of
the Merger from $1.3 billion over ten years to $1.8 billion. The
75% of the District's portion of estimated savings allocated to
ratepayers, which totals $99.5 million, would be given in the
form of a surcredit on customer bills of $94.5 million over the
first four years following the Merger ($15.2 million in year one,
20
$24 million in year two, $26.5 million in year three and $28.8
million in year four) and $5 million, funded in the first year,
devoted to economic development in the District of Columbia.
These conditions represent significant differences from the
proposals presented by the companies. Therefore, the Company and
BGE will ask the Commission to reconsider its decision and
allocate the appropriate net savings equally between customers
and shareholders.
The Company is unable to predict when a final decision will
be reached by the Maryland or D.C. Public Service Commissions.
The results of the final D.C. decision in combination with the
final results of the Maryland proceeding will require further
study in order to determine whether the Merger will still be
beneficial to customers and shareholders. The Merger will not
proceed unless the regulatory approvals conform to the
fundamental requirement that shareholders have a reasonable
opportunity to share in the expected benefits of the Merger.
The waiting period under the Hart-Scott-Rodino Antitrust
Improvements Act was terminated on January 29, 1997. If the
Merger is not completed by January 28, 1998, a new Hart-Scott-
Rodino filing would be required. The Nuclear Regulatory
Commission has approved the transfer of BGE's ownership interest
in the operating licenses for the two generating units at the
Calvert Cliffs Nuclear Power Plant to Constellation Energy at the
effective time of the Merger. In addition, the Merger has been
approved by the State Corporation Commission of Virginia and the
Pennsylvania Public Utility Commission.
If the Merger Agreement is terminated by either the Company
or BGE prior to March 31, 1998, 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 prior to
March 31, 1998, 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 are not offered a position in Constellation Energy.
Such employees will receive two weeks of pay per year of service,
21
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; employees will also not be
obligated to reimburse the Company for tuition payments made by
the Company on their behalf within two years of termination.
An extension of the current 1993 Labor Agreement between the
Company and Local 1900 of the IBEW was ratified by the Union
members in December 1995. The 1995 Agreement extends the 1993
Agreement, which was due to expire on June 1, 1996, through May
31, 1998 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 provided for
a lump-sum payment of 2% of base pay on January 5, 1996, a lump-
sum payment of 1% of base pay on June 7, 1996, and a lump-sum
payment of 3% of base pay on June 6, 1997.
On March 31, 1997, the Company signed a contract to purchase
land in downtown Washington, D.C. and is planning to build a $90
million regional headquarters for Constellation Energy, if the
Merger is completed.
Environmental Contingencies
- ---------------------------
On October 6, 1997, the Company received notice from the
U.S. Environmental Protection Agency (EPA) that it, along with 68
other parties, may be a Potentially Responsible Party (PRP) under
the Comprehensive Environmental Response Compensation and
Liability Act (CERCLA or Superfund) at the Butler Mine Tunnel
Superfund site in Pittstown Township, Luzerne County,
Pennsylvania. The site is a mine drainage tunnel with an outfall
on the Susquehana River where oil waste was disposed via a
borehole in the tunnel. The letter notifying the Company of its
potential liability also contained a request for a reimbursement
of approximately $.8 million for response costs incurred by EPA
at the site. The letter requested that the Company submit a good
faith proposal to conduct or finance the remedial action
contained in a July 1996 Record of Decision (ROD). The EPA
estimates the present cost of the remedial action to be $3.7
million. 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 June 30, 1997 Form 10-Q, the Company
received notice in December 1995 from the EPA that it is a PRP
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 an
22
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 June 30, 1997 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 June 30, 1997 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 the costs of the RI/FS. Total
costs of the RI/FS and associated activities prior to the
issuance of a 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, 1997. 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 June 30, 1997 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.
23
Initially, a total of approximately 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 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. Through September 30, 1997,
approximately 400 of the individual plaintiffs have dismissed
their claims against the Company. No payments were made by the
Company in connection with the dismissals. While the aggregate
amount specified in the remaining suits would exceed $400
million, the Company believes the amounts are greatly exaggerated
as were the claims already disposed of. The amount of total
liability, if any, and any related insurance recovery cannot be
precisely determined at this time; however, based on information
and relevant circumstances known at this time, the Company does
not believe these suits will have a material adverse effect on
its financial position. However, an unfavorable decision
rendered against the Company could have a material adverse effect
on results of operations in the 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.
24
Other
- -----
The Company is currently evaluating its computer software
and databases to determine the extent of modifications necessary
to accommodate the year 2000. The Company's computer systems are
generally based on two digits and will require additional
programming to recognize the start of the new century. In July,
1996, the Emerging Issues Task Force of the Financial Accounting
Standards Board reached a consensus that internal and external
costs specifically associated with modifying internal-use
computer software for the year 2000 should be charged to expense
as incurred. The Company estimates the cost of future
modifications, which are expected to be made over the next three
years, to be in the range of $8 million to $20 million.
* * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * *
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 1996
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 26) will automatically be
incorporated by reference in the Prospectuses constituting parts
of the Company's Registration Statements on Forms S-3 (Numbers
33-58810, 33-61379 and 333-33495) and Forms S-8 (Numbers 33-
36798, 33-53685 and 33-54197), in the Joint Proxy Statement/
Prospectus constituting part of the Registration Statement on
Form S-4 (Number 33-64799) of Constellation Energy Corporation
and in the Prospectuses constituting parts of the Registration
Statements on Forms S-3 (Numbers 333-24705 and 333-24855) 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.
25
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, 1997 and 1996, 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, 1996, 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 17, 1997, 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, 1996, 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.
November 13, 1997
26
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.
On April 16, 1997, FERC announced its finding that the
proposed Merger would be in the public interest and approved the
transaction without conditions. FERC held that the Merger would
not adversely affect competition in the long- or short-term
wholesale capacity markets. In addition, FERC indicated that
evaluation of the effect of the Merger on retail markets would be
left to the Maryland and District of Columbia Public Service
Commissions.
Also on April 16, 1997, the Maryland Public Service
Commission unanimously approved the proposed Merger and ordered
Constellation Energy to reduce rates by $56 million ($44 million
for BGE and $12 million for PEPCO), beginning on the effective
date of the Merger, with base rates to be frozen for three years
thereafter. The reductions are premised on an 11.4% return on
equity (ROE). In addition, the Commission ordered that 50% of
earnings above an 11.4% ROE be used to further reduce customer
rates. In addition to ordering the rate decrease, the Order also
denies the two companies the opportunity to recover the full
costs for purchased power contracts previously approved by the
Commission. The Maryland Order would put in place a plan that
would eliminate any reasonable opportunity for shareholders to
share in the benefits. The Company and BGE believe that the
Maryland Order contains elements that must be revised for the
Merger to take place.
On May 2, 1997, the companies filed a request for
reconsideration of the Maryland Order. In the request, the
companies detailed areas of the Order that need to be revised for
the Merger to proceed and proposed a modified plan to address
these concerns. Highlights of this modified plan include: 1) a
$26 million rate reduction for Constellation Energy's Maryland
customers upon completion of the Merger, followed by a four-year
base-rate freeze; 2) a comprehensive surcharge that permits full
cost recovery of power purchase contracts the Commission had
previously approved; 3) a synergy sharing mechanism premised on
an 11.9% ROE that splits Merger benefits on a 50/50 basis between
27
customers and investors, allowing further customer rate
reductions if the new company's operations result in additional
savings; and 4) an opportunity for recovery of Merger costs over
the four-year, base-rate freeze period via the synergy sharing
mechanism. Under this proposal, Constellation Energy would write
off Merger costs in the year the Merger is consummated. There
can be no assurance that the Commission will grant the request
for reconsideration or that the Commission's Order will be
changed.
On May 1, 1997, IBEW Local 1900 filed an appeal of the
Maryland Commission's decision with the Circuit Court of
Baltimore County. In view of the Commission's conclusion that,
under Maryland law, the IBEW's appeal divested it of authority to
consider the Application for Rehearing, the joint applicants
filed a motion requesting the Circuit Court to remand the case to
the Commission. On July 8, 1997, the Circuit Court of Baltimore
County decided to hold its ruling on the motion for remand until
July 28, 1997 while the Maryland Commission corrected a
computational error contained in its April 16, 1997 Order. On
July 14, 1997, the Company's and BGE's Chief Executive Officers
filed sworn affidavits in the Court stating that the Merger
cannot proceed unless other aspects of the Commission's Order
were modified. The affidavits stated that even if adjusted for
the computational error, the original order does not provide an
adequate financial basis upon which the companies could proceed
to consummate the Merger. On July 28, 1997, the Circuit Court
denied the motion for rehearing, accepted the Commission's
correction of the rate reduction to $47.5 million and established
a procedural schedule for consideration of the IBEW's appeal. By
order dated October 27, 1997, the Court affirmed the Commission's
order approving the Merger. On November 4, 1997, the Maryland
Commission reclaimed jurisdiction over the Merger case and will
consider the requests for reconsideration of its April 16, 1997
order. The Commission established December 3, 1997 as the date
for any party to the case to file responses regarding these
matters. Replies to these responses must be filed by December
13, 1997.
On October 20, 1997, the District of Columbia Public Service
Commission approved the proposed Merger, subject to several
conditions. These conditions include an allocation of the first
four years of the Commission's computation of the District's
proportionate share of estimated net cost savings from the Merger
of 75% to ratepayers and 25% to shareholders. The Commission
increased the Company's and BGE's estimated net cost savings of
the Merger from $1.3 billion over ten years to $1.8 billion. The
75% of the District's portion of estimated savings allocated to
ratepayers, which totals $99.5 million, would be given in the
form of a surcredit on customer bills of $94.5 million over the
first four years following the Merger ($15.2 million in year one,
$24 million in year two, $26.5 million in year three and $28.8
28
million in year four) and $5 million, funded in the first year,
devoted to economic development in the District of Columbia.
These conditions represent significant differences from the
proposals presented by the companies. Therefore, the Company and
BGE will ask the Commission to reconsider its decision and
allocate the appropriate net savings equally between customers
and shareholders.
The Company is unable to predict when a final decision will
be reached by the Maryland or D.C. Public Service Commissions.
The results of the final D.C. decision in combination with the
final results of the Maryland proceeding will require further
study in order to determine whether the Merger will still be
beneficial to customers and shareholders. The Merger will not
proceed unless the regulatory approvals conform to the
fundamental requirement that shareholders have a reasonable
opportunity to share in the expected benefits of the Merger.
The waiting period under the Hart-Scott-Rodino Antitrust
Improvements Act was terminated on January 29, 1997. If the
Merger is not completed by January 28, 1998, a new Hart-Scott-
Rodino filing would be required. The Nuclear Regulatory
Commission has approved the transfer of BGE's ownership interest
in the operating licenses for the two generating units at the
Calvert Cliffs Nuclear Power Plant to Constellation Energy at the
effective time of the Merger. In addition, the Merger has been
approved by the State Corporation Commission of Virginia and the
Pennsylvania Public Utility Commission. If the Merger is not
completed, a substantial portion of Merger related costs would be
written off as a charge against the Company's results of
operations. At September 30, 1997, the Company has deferred
$47.8 million in costs related to the Merger.
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, nine and twelve
months ended September 30, 1997, as compared to the corresponding
periods in 1996. Revenue from the sale of electricity in the
three months ended September 30, 1997, compared to the
corresponding period in 1996, was relatively unchanged, although
sales increased 3.3%. As measured in cooling degree hours,
although weather in the third quarter of 1997 was 13% hotter than
in 1996, it was, nevertheless, 22% cooler than the 20-year
average. The decreases in revenue from the sale of electricity
for the nine and twelve months ended September 30, 1997, were
29
primarily due to decreases in kilowatt-hour sales of 1.6% and
1.9% from the corresponding periods ended September 30, 1996.
The declines in sales reflect mild weather in the fourth quarter
of 1996 as well as throughout the first half of 1997. The
weather in the fourth quarter of 1995 as well as the first and
second quarters of 1996 was more severe than average.
Revenue from the sale of electricity also reflects the
effects of the Maryland Demand Side Management (DSM) surcharge
tariff. Effective June 6, 1997, the surcharge tariff rate was
lowered, which will reduce annual revenue by approximately $17
million, reflecting the Company's efforts to narrow conservation
program offerings and limit conservation spending. In the second
quarter of 1997, the Company recorded a $1.6 million bonus, which
was awarded for exceeding 1996 energy saving goals under the
conservation incentive provision of the tariff. In the third
quarter of 1996, the Company recorded an $8.9 million bonus,
which was awarded for exceeding 1995 energy saving goals.
Interchange deliveries decreased for the three, nine and
twelve months ended September 30, 1997. These decreases
principally reflect changes in the levels of activity in
purchase-for-resale agreements under the Company's wholesale
power sales tariff. Beginning in January 1997 through March
1997, and pursuant to FERC's Order No. 888, the Company
implemented an open access transmission tariff (OATT) and
terminated the purchase-for-resale agreements. On April 1, 1997,
the Pennsylvania-New Jersey-Maryland Interconnection Association
(PJM) implemented an OATT on behalf of its transmission owners,
replacing the Company's OATT. Under these tariffs, the Company
has received revenue from service agreements, classified as
"Other electric revenue", totaling $.6 million in the three
months ended and $2 million in the nine and twelve months ended
September 30, 1997, respectively. In addition, interchange
deliveries include revenue from bilateral energy transactions and
the sale of short-term generating capacity, which totaled
approximately $1.6 million, $8.3 million and $8.9 million for the
three, nine and twelve months ended September 30, 1997,
respectively. The benefits derived from interchange deliveries,
capacity sales in the District of Columbia and revenue under the
open access transmission tariff are passed through to the
Company's customers through a fuel adjustment clause.
30
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
See Part II, Item 5, Base Rate Proceedings, for additional
information.
OPERATING EXPENSES
Fuel and purchased energy decreased for the three, nine and
twelve months ended September 30, 1997, as compared to the
corresponding periods ended September 30, 1996. Fuel expense for
the three month period ended September 30, 1997, remained
relatively unchanged as compared to the corresponding period in
1996. Fuel expense decreased for the nine and twelve months
ended September 30, 1997, as compared to the corresponding
periods in 1996, primarily due to decreases of 3% and 8.2%,
respectively, in net generation; partially offset by increases in
the system average fuel cost. The decrease in purchased energy
for the three, nine and twelve months ended September 30, 1997,
reflects changes in levels and prices of energy purchased from
PJM and other utilities and power marketers, 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
September 30, September 30, September 30,
------------- ------------- -------------
1997 1996 1997 1996 1997 1996
----- ----- ----- ----- ----- -----
System Average
Fuel Cost per MBTU $1.81 $1.82 $1.84 $1.81 $1.82 $1.79
System average unit fuel cost remained relatively unchanged
for the three months ended September 30, 1997 as compared to the
corresponding period in 1996. System average unit fuel cost
increased for the nine and twelve months ended September 30,
1997, as compared to the corresponding periods in 1996, due to an
increase in the cost of coal, partially offset by a decrease in
the usage of higher-cost residual oil.
31
For the twelve month periods ended September 30, 1997 and
1996, the Company obtained 90% and 89%, respectively, of its
system generation from coal based upon percentage of Btus. The
Company's major cycling and certain peaking units can burn either
natural gas or oil, adding flexibility in selecting the most
cost-effective fuel mix.
Capacity purchase payments increased for the three, nine and
twelve months ended September 30, 1997, as compared to the
corresponding periods in 1996. These increases reflect capacity
payments made under the Panda contract, which commenced January
1, 1997; partially offset by a slight decrease in fixed operating
and maintenance expense associated with the capacity agreements
with Ohio Edison and Allegheny Power System (APS).
Operating expenses other than fuel, purchased energy and
capacity purchase payments increased for the three months ended
September 30, 1997, as compared to the corresponding period in
1996, primarily due to increases in depreciation and amortization
expense associated with additional investment in property and
plant. Operating expenses other than fuel, purchased energy and
capacity purchase payments decreased for the nine and twelve
months ended September 30, 1997, as compared to the corresponding
periods in 1996, due to a decline in other operation expenses
resulting from lower labor and benefits costs, and decreased
income taxes due to lower taxable income; partially offset by
increased depreciation and amortization expense primarily due to
additional investment in property and plant.
The Company is currently evaluating its computer software
and databases to determine the extent of modifications necessary
to accommodate the year 2000. The Company's computer systems are
generally based on two digits and will require additional
programming to recognize the start of the new century. In July,
1996, the Emerging Issues Task Force of the Financial Accounting
Standards Board reached a consensus that internal and external
costs specifically associated with modifying internal-use
computer software for the year 2000 should be charged to expense
as incurred. The Company estimates the cost of future
modifications, which are expected to be made over the next three
years, to be in the range of $8 million to $20 million.
CAPITAL RESOURCES AND LIQUIDITY
- -------------------------------
The Company's investment in property and plant, at original
cost before accumulated depreciation, was $6.4 billion at
September 30, 1997, an increase of $125.4 million from the
investment at December 31, 1996, and an increase of $179 million
from the investment at September 30, 1996. Cash invested in
property and plant construction, excluding AFUDC and CCRF,
amounted to $140.2 million for the nine months ended September
30, 1997, and $191.3 million for the twelve months then ended.
32
At September 30, 1997, 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 43.9% long-term debt, 3.2% serial preferred
stock, 3.5% redeemable serial preferred stock and 49.4% common
equity.
Cash from utility operations, after dividends, was $157.6
million for the nine months ended September 30, 1997, and $248.8
million for the twelve months then ended as compared with $132.6
million and $103.1 million, respectively, for the corresponding
periods ended September 30, 1996.
In August 1997, the Company filed for a 9.5% decrease in the
Maryland fuel rate. The proposed Fuel Billing Rate also includes
an adjustment for a deferred fuel amortization credit which is
designed to refund, over a twelve month period, approximately
$20.7 million of over recovered fuel costs.
Outstanding utility short-term debt totaled $277.1 million
at September 30, 1997, an increase of $145.7 million from the
$131.4 million outstanding at December 31, 1996, and an increase
of $22.6 million from the $254.5 million outstanding at September
30, 1996. See the discussion included in Note (3) of the Notes
to Consolidated Financial Statements, Capitalization, for
additional information.
NEW ACCOUNTING STANDARDS
- ------------------------
See the discussion included in Note (1) of the Notes to
Consolidated Financial Statements, Summary of Significant
Accounting Policies.
NONUTILITY SUBSIDIARY
- ---------------------
RESULTS OF OPERATIONS
- ---------------------
PCI's earnings for the three, nine and twelve months ended
September 30, 1997 were $.9 million ($.01 per share), $15.8
million ($.13 per share) and $16.3 million ($.14 per share),
respectively, compared with $4.9 million ($.04 per share), $16.4
million ($.14 per share) and $16 million ($.13 per share) for the
same periods ended September 30, 1996. Net earnings for the
three months ended September 30, 1997 decreased from the
corresponding period in the prior year primarily due to a third
quarter 1996 reversal of previously accrued deferred income taxes
of $1.8 million related to joint venture activity and a third
quarter 1997 $2 million pretax charge ($1.3 million after tax)
resulting from the sale of the last L-1011 aircraft and spare
L-1011 engines. With this sale, PCI eliminated the balance in
33
assets held for disposal as of September 30, 1997. Rental income
from operating leases also decreased for the three months ended
September 30, 1997. As a result of joint venture operations for
the nine months ended September 30, 1997, PCI's obligation for
previously accrued deferred income taxes was reduced, resulting
in after-tax earnings of $7.4 million after the provision for
transaction costs. Results for the nine months ended September
30, 1997, also include capital gains totaling $4.5 million, net
of tax, related primarily to tender offers accepted by PCI which
reduced the cost basis of its preferred stock portfolio by $117.6
million. Proceeds were used to pay down debt which resulted in a
decrease in interest expense. Purchases of preferred stock
during the nine months ended September 30, 1997, totaled $35.1
million. The cost basis of the marketable securities portfolio
at September 30, 1997, was $293.1 million and market value was
$303.9 million.
On July 31, 1997, an aircraft owned by PCI and on long-term
leveraged lease to Federal Express Corporation crash-landed at
Newark International Airport. Based on information provided by
Federal Express, no loss of life or serious injury resulted from
the accident; however, the aircraft was a total loss. The
aircraft was insured and PCI fully recovered its $28.5 million
investment.
On August 6, 1997, PCI announced an agreement with RCN
Telecom Services, Inc. (RCN) of Princeton, New Jersey to form a
joint venture that will provide Washington, D.C. area residents
and businesses a package of local and long distance telephone,
cable television, Internet and other telecommunications services
from a single source. PCI and RCN each intend to invest up to
$150 million over a three-year period in order to serve customers
over an advanced fiber optic network. The joint venture will be
equally owned and managed by PCI and RCN. This agreement is
subject to the satisfaction of a number of conditions, including
the execution of mutually satisfactory definitive agreements. No
assurances can be given that the transaction will be consummated.
For the three, nine and twelve months ended September 30,
1997, PCI generated income primarily from its leasing activities
and securities investments. Income from leasing activities,
which includes rental income, gains on asset sales, interest
income and fees totaled $21.3 million, $57.1 million and $78.4
million for the three, nine and twelve months ended September 30,
1997, respectively, compared to $23.3 million, $70.3 million and
$99.8 million for the corresponding periods in 1996. The
decreases for all three periods ending September 30, 1997,
compared to the corresponding periods in 1996, were primarily due
to sales of aircraft equipment. PCI's marketable securities
portfolio contributed pretax income of $5.8 million, $23.6
million and $31.8 million for the three, nine and twelve months
ended September 30, 1997, respectively, compared to $8 million,
$25.5 million and $34.1 million for the corresponding periods in
34
1996. The decreases in income from marketable securities for all
three periods were primarily due to decreases in dividend income
as a result of a reduction in the preferred stock portfolio.
Income from marketable securities also included net realized
gains of $.7 million, $6.9 million and $8.1 million for the
three, nine and twelve months ended September 30, 1997, compared
to $.7 million, $2.5 million and $2.6 million for the three, nine
and twelve months ended September 30, 1996, respectively.
Other income increased by $.7 million, $31 million and $35.9
million for the three, nine and twelve months ended September 30,
1997, respectively, compared to the corresponding periods in
1996. The increase in other income for the nine and twelve
months ended September 30, 1997 over the corresponding periods
ended September 30, 1996, was primarily the result of revenue
earned from investments made by Pepco Enterprises, Inc. (PEI), a
wholly owned subsidiary, which the Company contributed to PCI in
the second quarter of 1996. PEI has business interests that
include telecommunications, liquefied natural gas storage
facilities, underground cable construction and maintenance
services and an energy management services company. Other income
for the three, nine and twelve months ended September 30, 1997,
includes $3.8 million, $13.1 million and $15.8 million,
respectively, in revenue from these new business activities. In
addition to the favorable impact from PEI revenue, the increase
in other income for the nine and twelve month periods in 1997
over the same periods in 1996 is primarily the result of the
first quarter 1996 writedowns of PCI's investments in solar
electric generating systems (SEGS), real estate and oil and
natural gas. Included in the twelve months ended September 30,
1997 results is a $8.8 million pretax gain ($6.7 million after-
tax) related to the sale of PCI's $2.8 million (20%) interest in
a Florida-based technology company during the fourth quarter of
1996.
Expenses before income taxes, which include interest,
depreciation and operating, and administrative and general
expenses totaled $35.4 million, $109.9 million and $143.7 million
for the three, nine and twelve months ended September 30, 1997,
respectively, compared to $36 million, $118.9 million and $157.4
million for the corresponding periods in 1996. The decrease in
expenses before income taxes for the three, nine and twelve
months ended September 30, 1997, compared to the corresponding
periods in 1996 was primarily due to the $12.3 million pretax
first quarter 1996 writedown of assets held for disposal and to
lower interest expense resulting from less debt outstanding as
proceeds from sales of marketable securities and aircraft have
been used to pay down debt. The decrease was partially offset by
operating expenses of PEI of $2.9 million, $8.6 million and $10
million for the three, nine and twelve months ended September 30,
1997, respectively.
35
PCI had income tax credits of $3.4 million, $24.3 million
and $29.1 million for the three, nine and twelve months ended
September 30, 1997, respectively, and $4.5 million, $49.8 million
and $54.6 million for the corresponding periods in 1996. The
decreases in income tax credits for the three, nine and twelve
months ended September 30, 1997, compared to the corresponding
periods in 1996, were primarily due to deferred tax reversals of
zero, $10.1 million and $10.1 million, respectively, during the
three, nine and twelve months ended September 30, 1997, compared
to $2.1 million, $30.8 million and $30.8 million, respectively,
during the corresponding periods in 1996.
CAPITAL RESOURCES AND LIQUIDITY
- -------------------------------
A $303.9 million securities portfolio at September 30, 1997,
consisting primarily of investment grade preferred stocks,
provides PCI with liquidity and investment flexibility. During
the nine months ended September 30, 1997, PCI reduced the cost
basis of its marketable securities portfolio by $82.5 million
primarily as the result of calls and acceptance of tender offers
(approximately $117.6 million) offset by purchases of $35.1
million. PCI's fixed rate portfolio is sensitive to fluctuations
in interest rates. The reduced size of the preferred stock
portfolio lessens the impact of future fluctuations in interest
rates, while still maintaining a substantial portfolio for
liquidity purposes. The proceeds from the securities activity
during the first nine months were used to pay down short-term
debt and acquire short-term investments. During the first
quarter of 1997, PCI received $25.8 million in cash proceeds from
the sale of notes receivable from World Airways and recorded an
after-tax charge to earnings of $.4 million. PCI also received
$15.7 million in cash proceeds during the second quarter of 1997
for the early redemption of a note receivable related to a 1996
sale of an aircraft engine leasing subsidiary. During the third
quarter of 1997 PCI received $12.9 million for the sale of notes
receivable from Continental Airlines and recorded an after-tax
gain of $.9 million. The sale and early redemption of the notes
further reduce PCI's exposure to the ongoing credit risk
associated with the airline industry as well as the inherent
uncertainty regarding the future value of the aircraft which
secured the repayment of the notes.
PCI had short-term debt outstanding of $9.2 million at
September 30, 1997, compared to the $51.7 million outstanding at
December 31, 1996, and the $181.3 million outstanding at
September 30, 1996. During the three, nine and twelve months
ended September 30, 1997, debt repayments totaled $89.5 million,
$173.1 million and $176.8 million, respectively. At September
30, 1997, PCI had $196.3 million available under its Medium-Term
Note Program and $400 million of unused bank credit lines.
36
Part II OTHER INFORMATION
- ------- -----------------
Item 1 LEGAL PROCEEDINGS
- ------ -----------------
See Part I, Item 1, Notes to Consolidated Financial
Statements, (6) Commitments and Contingencies, for information on
various legal proceedings.
Item 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
- ------ ---------------------------------------------------
(a) Annual meeting of shareholders held October 23, 1997.
(b) (1) Directors who were elected at the annual meeting:
For Term Expiring in 2000:
Richard E. Marriott Votes cast for: 100,412,575
Votes withheld: 3,272,650
David O. Maxwell Votes cast for: 100,639,616
Votes withheld: 3,045,609
Floretta D. McKenzie Votes cast for: 100,162,430
Votes withheld: 3,522,795
Edward F. Mitchell Votes cast for: 100,668,501
Votes withheld: 3,016,724
(2) Directors whose terms of office continued after the
annual meeting:
Roger R. Blunt, Sr. Ann D. McLaughlin
A. James Clark Peter F. O'Malley
H. Lowell Davis Louis A. Simpson
John M. Derrick, Jr. A. Thomas Young
(c) (1) The following shareholder proposal was introduced:
"RESOLVED: That the shareholders of PEPCO recommend
that the Board of Directors take the necessary steps to
reinstate the election of directors ANNUALLY, instead of the
staggered system which was recently adopted."
The following statement has been supplied by the
shareholder submitting this proposal:
"REASONS: Until recently, directors of PEPCO were
elected annually by all shareholders."
37
"The great majority of New York Stock Exchange
listed corporations elect all their directors each year."
"This insures that ALL directors will be more
accountable to ALL shareholders each year and to a certain
extent prevents the self-perpetuation of the Board."
"Last year the owners of 15,254,044 shares,
representing 21.3% of shares voting, voted FOR this
proposal."
The shareholder proposal was defeated. There were
55,285,808 votes cast against the proposal, 28,159,771 votes cast
in support of the proposal, 3,698,560 votes abstaining and
16,541,086 broker nonvotes.
Item 5 OTHER INFORMATION
- ------ -----------------
EXECUTIVE OFFICERS OF THE REGISTRANT
- ------------------------------------
At the Annual Meeting of Directors held on October 23, 1997,
the Board of Directors elected John M. Derrick, Jr., President
and Chief Executive Officer. Mr. Derrick succeeds Edward F.
Mitchell as Chief Executive Officer. Mr. Mitchell remains as
Chairman of the Board.
OTHER FINANCING ARRANGEMENTS - Credit Agreements
- ------------------------------------------------
The Company and PCI satisfy their short-term financing
requirements through the sale of commercial promissory notes.
The Company and PCI maintain minimum 100 percent lines of credit
back-up, in the amounts of $285 million and $400 million,
respectively, for their outstanding commercial promissory notes.
These lines of credit were unused during 1997 and 1996.
BASE RATE PROCEEDINGS
- ---------------------
Maryland
- --------
On August 20, 1997, the Company filed an application
requesting an increase of $64.5 million, or 6.9%, in annual base
rate revenues in Maryland based upon a twelve months ended June
30, 1997 test period, a return on rate base of 9.52% and a return
on common stock equity of 12.5%. In addition, the Company
requested that $31.3 million of the total annual increase be
added to current rates immediately through a temporary surcharge.
38
This would allow the Company to begin to recover costs being
incurred since January 1997, in connection with a 25-year, 230-
megawatt capacity purchase agreement with Panda-Brandywine, L.P.
(Panda) previously approved by the Commission. In September
1997, the Commission suspended the Company's request for the
temporary surcharge for a period of not more than 150 days.
Capacity payments to Panda are estimated to total approximately
$21 million in 1997, of which the Maryland portion is
approximately $11 million. The requested base rates are based
upon the current costs of providing service to Maryland customers
and include recovery of costs associated with capacity purchase
contracts, increases in taxes, and recovery of other cost of
service items previously approved by the Maryland Commission. On
November 7, 1997, the Company along with the Maryland People's
Counsel, the Maryland Commission Staff, and several intervenors
filed a joint motion with the Commission seeking approval of a
settlement with respect to the Company's application to increase
annual base rate revenues. The settlement agreement provides for
a $24 million permanent increase in base rate revenues, effective
no sooner than with bills rendered on and after November 30,
1997. Of the $24 million in increased base rates, approximately
$12 million will replace CCRF accrued on Clean Air Act
expenditures. The Company agreed to withdraw its request to
implement a purchased capacity adjustment charge but can renew
its request as part of a new application to increase base rates.
In connection with the settlement agreement, no determination was
made with respect to rate of return for purposes of setting
rates; however, a rate of return of 9% will be used by the
Company, beginning in December 1997, for purposes of computing
AFUDC and CCRF. The Company is unable to predict when or if the
settlement will be approved by the Commission.
Effective June 6, 1997, the Maryland Demand Side Management
surcharge tariff rate was reduced. The new surcharge tariff rate
will reduce annual revenue by approximately $17 million,
reflecting the Company's efforts to narrow conservation program
offerings and limit conservation spending. The surcharge
includes provisions for the recovery of lost revenue,
amortization of pre-1997 actual program expenditures plus the
initial amortization of 1997 projected program expenditures, a
CCRF of 9.46% on unamortized balances and an incentive bonus for
exceeding energy saving goals. In the second quarter of 1997,
the Company recorded a $1.6 million bonus, awarded for exceeding
1996 energy saving goals. In the third quarter of 1996, the
Company recorded an $8.9 million bonus for exceeding 1995 energy
saving goals.
See Part I, Item I, Notes to Consolidated Financial
Statements, (6) Commitments and Contingencies, for additional
information.
39
District of Columbia
- --------------------
In Formal Case No. 939, the District of Columbia Public
Service 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 DSM 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 DSM 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. Although
the Commission denied the Company's request to recover "lost
revenue" due to DSM programs, through a 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. In June 1996 and June 1997, the Company filed
Applications for Authority with the Commission to revise its
ECRR. The latest proposed rate seeks recovery of actual costs
expended during 1995 and 1996, and is expected to increase annual
revenue by approximately $9 million. No action has been taken by
the Commission on the revised ECRR. Subsequent rate updates are
scheduled to be filed annually on June 1 to reflect the prior
year's actual costs, subject to the annual surcharge recovery
limit within the four-year spending cap for the period 1995-1998
(amounts spent in excess of the annual surcharge recovery limit,
but within the four-year spending cap, are deferred for future
recovery). Remaining allowable expenditures under the spending
cap totaled $11.2 million at September 30, 1997. Pre-July 1993
DSM costs receive base rate treatment.
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
40
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.
Pursuant to an agreement for the years 1996 through 1998,
SMECO rates were reduced by $2 million 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 participates in wholesale capacity, energy and
transmission purchases and sales transactions, the savings from
which are passed along to customers. In compliance with FERC
Order No. 888, the Company provided transmission service with its
open access tariff from January 1, 1997 until April 1, 1997. On
February 28, 1997, the FERC ordered the PJM member companies to
implement a poolwide open access transmission tariff based on a
proposal made by PJM Supporting Companies in December 1996.
Since April 1, 1997, all transmission service in PJM has been
administered by the PJM Office of the Interconnection. Revenue
from Company transmission sales during January through March 1997
totaled approximately $1.4 million, and the Company's share of
PJM transmission sales since April 1997 totaled approximately $.6
million.
The Company's generating and transmission facilities are
interconnected with those of other transmission owners in the PJM
power pool and other utilities. Historically, the pricing of
most PJM-dispatched internal economy energy transactions was
based upon "split savings" whereby such energy was priced 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. On April 1, 1997, PJM
members implemented an interim restructuring plan which provides
for poolwide transmission service under a pool tariff and a bid-
price based energy market whereby all energy that clears through
the market is priced at the margin. In the initial phase of
this plan, bids are being based on cost. Bilateral transactions
are also permitted. The restructured PJM is now a Limited
Liability Corporation governed by an independent board of
directors with membership open to eligible entities.
In addition to interchange with PJM, the Company is actively
participating in the emerging bilateral energy sales marketplace.
The Company's wholesale power sales tariff allows both sales from
Company-owned generation and sales of energy purchased by the
Company from other market participants. Over 40 utilities and
marketers have executed service agreements allowing them to
arrange purchases under this tariff. The Company has also
41
executed service agreements allowing it to purchase energy under
other market participants' power sales tariffs. These agreements
greatly expand the opportunities for economic transactions. The
Company's Power Sales Tariff also allows for the sale of
generating capacity on a short-term basis. The Company sold
capacity to PECO Energy (PECO) in the amount of 150 megawatts
during January 1997 and 100 megawatts per month for the period of
February through May 1997. In addition, the Company has signed
agreements to sell capacity to Delmarva Power & Light Co. in the
amount of 100 megawatts per month for the period June 1, 1997,
through May 31, 1998; and to GPU Energy in the amount of 130
megawatts per month for the period August 1, 1997, through
December 31, 1997. The Company has also signed an agreement,
dated October 2, 1997, to sell 35 megawatts of capacity to
Northeast Utilities Service Company (NUSCO) during the period
November 1, 1997 through December 31, 1998. Revenue from
capacity and energy transactions totaled approximately $1.6
million, $8.3 million and $8.9 million for the three, nine and
twelve months ended September 30, 1997, respectively, and are
included as components of interchange deliveries.
The Company continues to purchase energy from Ohio Edison
under the Company's 1987 long-term capacity purchase agreements
with Ohio Edison and APS, and from the Northeast Maryland Waste
Disposal Authority under an avoided cost-based purchase agreement
for a 32-megawatt Montgomery County Resource Recovery Facility.
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.
Capacity payments for the Montgomery County Resource Recovery
facility are not expected to commence until after the year 2000.
In August 1996, the Company began purchasing energy from the
Panda facility, pursuant to a 25-year power purchase agreement
for 230 megawatts of capacity supplied by a gas-fueled combined-
cycle cogenerator. The Panda facility achieved full commercial
operation in October 1996. Capacity payments under this
agreement commenced in January 1997. The capacity expense under
these agreements, including an allocation of a portion of Ohio
Edison's fixed operating and maintenance costs, was $34 million
and $104 million for the three and nine months ended September
30, 1997, and is estimated at $141 million for 1997. Commitments
under these agreements are estimated at $143 million for 1998,
$204 million for 1999, $203 million for 2000, $212 million for
2001 and $214 million for 2002.
The Company has a purchase agreement with Southern Maryland
Electric Cooperative, Inc. (SMECO), through 2015, for 84
megawatts of capacity supplied by a combustion turbine installed
and owned by SMECO at the Company's Chalk Point Generating
Station. The Company is responsible for all costs associated
with operating and maintaining the facility. The capacity
payment to SMECO is approximately $5.5 million per year.
42
RESTRUCTURING OF THE BULK POWER MARKET
- --------------------------------------
In April 1996, the FERC issued its Final Rulemaking Orders
No. 888 and No. 889. Both rulemakings address achieving greater
competition in the wholesale energy market. Order No. 888
required utilities to file open access transmission tariffs by
July 9, 1996. Such filing was made by the Company and was
accepted by the FERC. Order No. 889 required utilities to
establish or participate in an Open Access Same-Time Information
System (OASIS) which requires transmission owners to post certain
transmission availability, pricing and service information on an
open-access communications medium such as the Internet. On
January 3, 1997, the Company's OASIS became operational.
Subsequently, on April 1, 1997, PJM implemented an OASIS on
behalf of the PJM transmission owners which replaced the
Company's OASIS. Order No. 889 also required the Company to
establish a code of conduct that complies with FERC's prescribed
standards in order to separate utilities' transmission system
operations and wholesale marketing functions. The Company's
filed code of conduct became effective on January 3, 1997.
On July 24, 1996, nine of the ten PJM member companies (the
Supporting Companies), excluding PECO, filed, with the FERC, a
comprehensive proposal including the contracts and tariff that
would establish an Independent System Operator (ISO) to
administer transmission service under a PJM control area
transmission tariff and operate the energy market in a manner
that assures comparable treatment for all participants. Under
the Supporting Companies' proposal, reliability of the pool will
be maintained under an installed capacity obligation. The ISO
will administer a bid-priced energy spot market that will also
accommodate bilateral transactions, and the ISO will provide
transmission service on a poolwide basis. In early August 1996,
PECO filed a competing plan opposing certain key features of the
Supporting Companies' proposal.
On November 13, 1996, the FERC found that it could not
accept either the Supporting Companies' proposal or PECO's
opposing proposal. Consequently, FERC ordered the PJM members to
amend their proposals to comport with Order No. 888 on ISOs and
to attempt to reach a consensus with other stakeholders. At a
minimum, FERC ordered that PJM file a poolwide pro forma open
access transmission tariff by December 31, 1996, and amend
existing PJM pooling agreements for compatibility with the Order.
On December 31, 1996, the PJM member companies filed a joint
response to FERC's Order. This compliance filing established a
single poolwide transmission tariff and modified the membership
and governance provisions of the PJM Agreement. The PJM members
noted areas of disagreement in the filing and indicated that the
compliance filing was an interim solution until a more
comprehensive proposal could be developed.
43
On February 28, 1997, the FERC ruled on areas of
disagreement between the PJM members and ordered that PJM
implement an open access transmission tariff and a bid-based
energy market. A new PJM Operating Agreement was filed on March
31, 1997, superseding the original PJM Agreement. This Agreement
opens PJM's membership to eligible entities. PJM formed a
Limited Liability Corporation on March 31, 1997, and the members
have elected an independent board of directors to govern the PJM
Interconnection Office. The PJM members subsequently moved the
implementation date to April 1, 1997. In early June 1997, the
Supporting Companies and PECO each filed with the FERC separate
proposals for the development of an Independent System Operator.
The FERC has yet to rule on the proposals.
PJM has many years of experience in providing economically
efficient transmission and generation services throughout the
mid-Atlantic region, and has achieved for its members, including
the Company, significant cost savings through shared generating
reserves and integrated operations. The PJM members are working
to transform today's coordinated cost-based pool dispatch into a
priced-based regional energy market operating under a standard of
transmission service comparability. Benefits and/or costs
derived from transactions for transmission service under the open
access transmission tariff are passed through to the Company's
customers through fuel adjustment clauses and as such, will not
have a material effect on the operating results of the Company.
COMPETITION
- -----------
The electric utility industry is subject to increasing
competitive pressures, stemming from a combination of increasing
independent power production and regulatory and legislative
initiatives intended to increase bulk power competition,
including the Energy Policy Act of 1992. Since the early 1980s,
the Company has pursued strategies which achieve financial
flexibility through conservation and energy use management
programs, extension of the useful life of generating equipment,
cost-effective purchases of capacity and energy and preservation
of scheduling flexibility to add new generating capacity in
relatively small increments. The Company serves a unique and
stable service territory and is a low-cost energy producer with
customer prices which compare favorably with regional and
national averages.
Pursuant to an August 1995 order in a generic proceeding
dealing with electric industry structure and the advent of
competition, the Maryland Public Service Commission found that
competition at the wholesale level holds the greatest potential
for producing significant benefits, while competition at the
retail level would carry many potential problems with difficult-
to-find solutions. The Commission stated that it was intrigued
by a restructuring concept suggested by the Company, which calls
44
for functionally dividing the utility into generation and
transmission/distribution segments. The Commission encouraged
the Company to develop the concept further and suggested that
other electric utilities in the state develop similar proposals
specific to their competitive positions. In October 1996, the
Maryland Commission reopened the generic proceeding to review
regulatory and competitive issues affecting the electricity
industry. The Commission cited the evolving nature of the
electric industry as the basis for continuing its investigation.
As part of this investigation, the Commission directed its Staff
to submit a report on or before May 31, 1997, containing, among
other things, recommendations regarding regulatory and
competitive issues facing the electric industry in Maryland. The
Commission also directed the four major electric utilities in
Maryland to prepare unbundled cost studies and model unbundled
retail service tariffs prior to August 1, 1997.
On May 30, 1997, the Commission Staff issued its report,
recommending that all Maryland customers be given a choice of
electricity suppliers beginning April, 2001. The Staff
recommends a three step process for implementing customer choice.
Starting in April 1998, all investor-owned utilities in Maryland
would begin sending customers bills that itemize the costs of
specific services such as generation, transmission and delivery
of electricity. Next, up to 20 percent of the utilities'
customers would be offered the option of enrolling in one of two
prototype customer choice programs starting at the end of 1998
and 1999, respectively. Lastly, all customers of Maryland
investor-owned utilities would have the option to choose their
supplier of electricity, with service beginning April 2, 2001.
Under the plan, one of the choices available to customers would
be a regulated power supplier. For now, existing utilities would
continue to provide customers with electricity delivery services
as well as distribution-related services such as billing and
metering, at prices regulated by the Maryland Commission.
Further unbundling would be considered later. The Staff also
recommended that utilities be permitted to recover prudently
incurred stranded costs. In comments provided to the Commission
on the Staff report, the Company reaffirmed its full support for
customer choice for Maryland electric customers and provided key
principles that should be used as guidelines for the effective
introduction of electric customer choice. The principles include
the concept that Maryland companies should not be put at a
competitive disadvantage by customer choice, that competition
should not be regulated, and that the benefits of customer choice
should not be oversold. At the conclusion of legislative
hearings underway, certain actions must be taken by the Maryland
legislature and the Public Service Commission before any changes
can take effect.
45
The District of Columbia Public Service Commission initiated
a proceeding to investigate issues regarding electricity industry
structure and competition in late 1995. In September 1996, the
Commission issued an order designating the issues to be examined
in the proceeding. Initial comments regarding the designated
issues were filed with the Commission in January 1997, and reply
comments were filed in March 1997.
PEAK LOAD, SALES, CONSERVATION, AND CONSTRUCTION
- ------------------------------------------------
AND GENERATING CAPACITY
-----------------------
Peak Load and Sales Data
- ------------------------
Kilowatt-hour sales increased 3.3% for the three months
ended September 30, 1997, and decreased 1.6% and 1.9%, for the
nine and twelve months ended September 30, 1997, respectively, as
compared to sales for the corresponding periods in 1996. As
measured in cooling degree hours, although weather in the third
quarter of 1997 was 13% hotter than in 1996, it was,
nevertheless, 22% cooler than the 20-year average. The declines
in sales for the nine and twelve month periods ended September
30, 1997, reflect mild weather in the fourth quarter of 1996 as
well as throughout the first half of 1997. The weather in the
fourth quarter of 1995 as well as the first and second quarters
of 1996 was more severe than average. 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 1997 summer peak demand was 5,689 megawatts. This
compares with the 1996 summer peak demand of 5,288 megawatts, and
the all-time summer peak demand of 5,769 megawatts which occurred
in July 1991. The Company's present generation capability,
including capacity purchase contracts, is 6,576 megawatts. To
meet the 1997 summer peak demand, the Company had approximately
265 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 1.5%, reflecting continuing success
with demand side management (DSM) and energy use management (EUM)
programs and anticipated service area growth trends. The 1996-
1997 winter season peak demand of 4,632 megawatts was 7.5% below
the all-time winter peak demand of 5,010 megawatts which was
established in January 1994.
46
Conservation
- ------------
The Company's DSM and EUM programs 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.
In Maryland, the Company invested approximately $5.4
million, $18.2 million and $24.1 million in DSM programs for the
three, nine and twelve months ended September 30, 1997,
respectively. The Company recovers the costs of Maryland DSM
programs 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 $1.6 million in 1997, based on 1996
performance, which followed a bonus of $8.9 million in 1996,
based on 1995 performance. As expected, the performance bonus in
1997 was significantly lower than amounts awarded in prior years,
reflecting reduced DSM program expenditures. Investment in
District of Columbia DSM programs totaled approximately $1.6
million, $3.7 million and $6.8 million for the three, nine and
twelve months ended September 30, 1997, respectively. These DSM
costs are amortized over ten years with an accrued return on
unamortized costs.
The Company estimates that peak load reductions of over 700
megawatts have been achieved to date from DSM and EUM programs
and that additional peak load reductions of approximately 400
megawatts will be achieved in the next five years. The Company
also estimates that, in 1996, energy savings of more than 1.6
billion kilowatt-hours were realized through operation of its DSM
and EUM programs. See the discussions included in Summary of
Significant Accounting Policies, Total Revenue, and Base Rate
Proceedings, for additional information.
Construction and Generating Capacity
- ------------------------------------
Construction expenditures, excluding AFUDC and CCRF, are
projected to total $1.2 billion for the five-year period 1997
through 2001, which includes $18 million of estimated Clean Air
Act (CAA) expenditures. In 1997, construction expenditures are
projected to total $215 million, which includes $4 million of
estimated CAA expenditures. The Company plans to finance its
47
construction program primarily through funds provided by
operations. Actual construction expenditures during the period
1997 through 2001 may vary from projections once the Merger with
BGE becomes effective.
The Company has implemented cost-effective plans for
complying with Phase I of the Acid Rain portion of the 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 $18 million over the next five years.
Plans for complying with the second phase of the CAA are being
reviewed in anticipation of the pending Merger with BGE. If
economical, continued use of lower-sulfur coal, cofiring with
natural gas and the purchase of sulfur dioxide (SO2) emission
allowances is expected. Nitrogen oxides emissions reductions
will be achieved by installing control equipment in the most
cost-effective manner after considering the characteristics of
each of the merged company's boilers. In addition to the Acid
Rain portion of the CAA, the State of Maryland and District of
Columbia are required, by Title I of the CAA, to achieve
compliance with ambient air quality standards for ground-level
ozone. This provision is likely to result in further nitrogen
oxides emissions reductions from the Company's boilers; however,
the extent of reductions and associated cost cannot be estimated
at this time.
The Company has been purchasing energy from a 32-megawatt
municipally financed resource recovery facility in Montgomery
County, Maryland, which began commercial operation in August
1995. Capacity payment obligations associated with this facility
are expected to commence after the year 2000. 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 Panda facility achieved full commercial
operation in October 1996. The Company projects that existing
contracts for nonutility generation and the Company's commitment
to conservation will provide adequate reserve margins to meet
customers' needs well beyond the year 2000. In 1995, the
Maryland Public Service Commission issued an order that requires
electric utilities to competitively procure future capacity
resources. The Company believes that completion of the first
combined-cycle unit at its Station H facility in Dickerson,
Maryland, currently scheduled for 2004, is likely to be the most
cost-effective alternative for the next increment of capacity.
This will add a steam cycle to the two existing combustion
turbine units.
48
SELECTED NONUTILITY SUBSIDIARY FINANCIAL INFORMATION
- ----------------------------------------------------
The Company's wholly owned nonutility subsidiary, Potomac
Capital Investment Corporation (PCI), was organized in late 1983
to provide a vehicle to conduct the Company's ongoing nonutility
businesses. The principal assets of PCI are portfolios of
securities and equipment leases, and to a lesser extent real
estate and other investments. The $303.9 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 $225.6 million, $196.3
million and $189.1 million, at September 30, 1997, December 31,
1996, and September 30, 1996, respectively.
On August 6, 1997, PCI announced an agreement with RCN
Telecom Services, Inc. (RCN) of Princeton, New Jersey to form a
joint venture to provide a package of local and long-distance
telephone, cable television, Internet and other
telecommunications services to Washington, D.C. area residents
and businesses. PCI and RCN each intend to invest up to $150
million over a three-year period to provide these services over
an advanced fiber optic network.
See Item 2, Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition, for
additional information.
49
<TABLE>
Consolidated Statements of Earnings:
- -----------------------------------
<CAPTION>
Three Nine Twelve
Months Ended Months Ended Months Ended
September 30, September 30, September 30,
--------------------- --------------------- ---------------------
1997 1996 1997 1996 1997 1996
-------- -------- -------- -------- -------- --------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Income
Leasing activities $ 21,305 $ 23,256 $ 57,066 $ 70,311 $ 78,416 $ 99,839
Marketable securities 5,751 7,991 23,625 25,515 31,800 34,096
Other 5,842 5,159 20,679 (10,324) 20,618 (15,238)
-------- -------- -------- -------- -------- --------
32,898 36,406 101,370 85,502 130,834 118,697
-------- -------- -------- -------- -------- --------
Expenses
Interest 16,482 20,608 53,031 63,581 72,892 87,510
Administrative and general 3,536 4,395 12,246 13,435 14,340 16,093
Depreciation and
operating 13,357 10,986 42,581 29,562 54,001 41,429
Loss on assets held for disposal 2,022 - 2,022 12,320 2,446 12,320
Income tax credit (3,374) (4,469) (24,291) (49,797) (29,119) (54,612)
-------- -------- -------- -------- -------- --------
32,023 31,520 85,589 69,101 114,560 102,740
-------- -------- -------- -------- -------- --------
Net earnings from
nonutility subsidiary $ 875 $ 4,886 $ 15,781 $ 16,401 $ 16,274 $ 15,957
======== ======== ======== ======== ======== ========
Per share contribution
to earnings of the
Company $ .01 $ .04 $ .13 $ .14 $ .14 $ .13
===== ===== ===== ===== ===== =====
50
</TABLE>
<TABLE>
STATISTICAL DATA
- ----------------
<CAPTION>
Three Months Ended Twelve Months Ended
September 30, September 30,
--------------------------------- -------------------------------------
1997 1996 % Change 1997 1996 % Change
-------- -------- -------- ---------- ---------- --------
<S> <C> <C> <C> <C> <C> <C>
Revenue from Sales
------------------
of Electricity
--------------
(Thousands of Dollars)
Residential $185,274 $182,285 1.6 $ 527,885 $ 549,110 (3.9)
General Service 370,409 373,327 (0.8) 1,065,271 1,080,575 (1.4)
Large Power Service <F1> 11,822 11,784 0.3 35,452 35,940 (1.4)
Street Lighting 3,055 2,998 1.9 12,700 12,402 2.4
Rapid Transit 8,444 8,605 (1.9) 28,529 28,939 (1.4)
Wholesale 36,617 33,241 10.2 122,284 122,376 (0.1)
-------- -------- ---------- ----------
System $615,621 $612,240 0.6 $1,792,121 $1,829,342 (2.0)
======== ======== ========== ==========
Energy Sales
------------
(Millions of KWH)
Residential 1,872 1,782 5.1 6,583 6,897 (4.6)
General Service 4,322 4,237 2.0 15,184 15,319 (0.9)
Large Power Service <F1> 198 176 12.5 697 696 0.1
Street Lighting 37 36 2.8 165 164 0.6
Rapid Transit 113 114 (0.9) 408 416 (1.9)
Wholesale 674 639 5.5 2,539 2,574 (1.4)
-------- -------- ---------- ----------
System 7,216 6,984 3.3 25,576 26,066 (1.9)
======== ======== ========== ==========
Average System Revenue
----------------------
per KWH (cents per KWH) 8.53 8.77 (2.7) 7.01 7.02 (0.1)
-----------------------
System Peak Demand <F2>
------------------
(Thousands of KW)
Summer - - 5,689 5,288
Winter - - 4,632 4,831
Net Generation
--------------
(Millions of KWH) 5,469 4,860 17,614 19,197
Fuel Mix (% of Btu)
-------------------
Coal (%) 88 86 90 89
Oil (%) 5 7 5 8
Gas (%) 7 7 5 3
Fuel Cost per MBtu
------------------
System Average $1.81 $1.82 $1.82 $1.79
Weather Data
------------
Heating Degree Days 14 9 3,876 4,570
20 Year Average 21 4,036
Cooling Degree Hours 6,526 5,773 8,542 9,509
20 Year Average 8,331 11,117
Heating Degree Days - The daily difference in degrees by which the mean temperature is
below 65 degrees Fahrenheit (dry bulb).
Cooling Degree Hours - The daily sum of the differences, by hours, by which the temperature
(effective temperature) for each hour exceeds 71 degrees Fahrenheit (effective temperature).
<FN>
<F1> Large Power Service customers are served at a voltage of 66KV or higher.
<F2> At September 30, 1997, the generation capability, including capacity purchase contracts,
was 6,576 MW.
</FN>
51
</TABLE>
UNAUDITED PRO FORMA COMBINED CONDENSED FINANCIAL INFORMATION
- ------------------------------------------------------------
The following unaudited pro forma condensed information
combines the historical consolidated balance sheets and
statements of income of Potomac Electric Power Company and
Baltimore Gas and Electric Company, including their respective
subsidiaries, after giving effect to the proposed Merger of the
two companies into Constellation Energy Corporation. As
previously disclosed, the Merger is expected to close as soon as
all necessary regulatory approvals, on terms satisfactory to
PEPCO and BGE, are obtained. As of the date of this filing, the
Merger has not closed. The unaudited pro forma combined
condensed balance sheet at September 30, 1997, gives effect to
the Merger as if it had occurred at September 30, 1997. The
unaudited pro forma combined condensed statement of income for
the nine months ended September 30, 1997, gives effect to the
Merger as if it had occurred at January 1, 1997. These
statements are prepared on the basis of accounting for the Merger
as a pooling of interests and are based on the assumptions set
forth in the notes thereto. Constellation Energy Corporation was
formed September 22, 1995, and has no assets or operations.
Therefore, Constellation Energy Corporation has no financial
statements and, in turn, there has been no audit of such
statements.
The following pro forma financial information has been
prepared from, and should be read in conjunction with, the
historical consolidated financial statements and related notes
thereto of PEPCO and BGE, which are contained in their respective
1934 Act reports for prior periods. The following information is
not necessarily indicative of the financial position or operating
results that would have occurred if the Merger had been
consummated on the dates, or at the beginning of the periods, for
which the Merger is being given effect nor is it necessarily
indicative of future financial position or operating results.
The following unaudited pro forma combined condensed
financial information of Constellation Energy Corporation is set
forth below:
Balance Sheet as of September 30, 1997
Income Statement for the Nine Months Ended September 30,
1997
Notes to Unaudited Pro Forma Combined Condensed Financial
Statements
The following PEPCO financial information is also set forth
below:
Reclassifying Balance Sheet as of September 30, 1997
Reclassifying Income Statement for the Nine Months Ended
September 30, 1997
52
Other Information
- -----------------
Both PEPCO and BGE file annual and quarterly reports with
the Securities and Exchange Commission (SEC). These are
available at the SEC's public reference rooms in Washington, D.C.
and New York, New York (call 1-800-SEC-0330 for more
information); and at the SEC's web site at http://www.sec.gov.
53
<TABLE>
CONSTELLATION ENERGY CORPORATION
UNAUDITED PRO FORMA COMBINED CONDENSED BALANCE SHEET
SEPTEMBER 30, 1997
(IN THOUSANDS)
----------------------------------------------------
<CAPTION>
PEPCO
BGE (As Reclassified) Pro Forma Pro Forma
(As Reported) (See Note 1) Adjustments Combined
-------------- ----------------- ------------- -------------
<S> <C> <C> <C> <C>
ASSETS
Current Assets
Cash and Cash Equivalents $ 189,758 $ 13,003 $ - $ 202,761
Accounts Receivable - net 398,014 311,370 - 709,384
Materials and Supplies 166,516 129,627 - 296,143
Prepayments and Other 326,059 45,471 - 371,530
------------- ---------------- ------------ ------------
Total Current Assets 1,080,347 499,471 - 1,579,818
------------- ---------------- ------------ ------------
Investments and Other Assets
Notes Receivable - 23,438 - 23,438
Real Estate Projects 443,922 72,956 - 516,878
Power Generation Systems 421,762 979 - 422,741
Financial Instruments 130,235 - - 130,235
Marketable Securities 27,752 303,905 - 331,657
Investment in Finance Leases 28,870 460,021 - 488,891
Operating Lease Equipment - net - 170,747 - 170,747
Other Investments 433,309 108,646 - 541,955
------------- ---------------- ------------ ------------
Total Investments and Other Assets 1,485,850 1,140,692 - 2,626,542
------------- ---------------- ------------ ------------
Utility Plant
Plant in Service
Electric 6,698,259 6,335,130 - 13,033,389
Gas 832,002 - - 832,002
Common 546,101 - - 546,101
------------- ---------------- ------------ ------------
Total Plant in Service 8,076,362 6,335,130 - 14,411,492
Accumulated Depreciation (2,773,956) (1,999,638) - (4,773,594)
------------- ---------------- ------------ ------------
Net Plant in Service 5,302,406 4,335,492 - 9,637,898
Construction Work in Progress 165,845 84,901 - 250,746
Nuclear Fuel - net 140,261 - - 140,261
Other Plant - net 25,470 26,222 - 51,692
------------- ---------------- ------------ ------------
Net Utility Plant 5,633,982 4,446,615 - 10,080,597
------------- ---------------- ------------ ------------
Deferred Charges
Regulatory Assets 474,598 461,337 - 935,935
Other 106,823 207,824 - 314,647
------------- ---------------- ------------ ------------
Total Deferred Charges 581,421 669,161 - 1,250,582
------------- ---------------- ------------ ------------
Total Assets $ 8,781,600 $ 6,755,939 $ - $ 15,537,539
============= ================ ============ ============
LIABILITIES AND CAPITALIZATION
Current Liabilities
Short-term Borrowings $ 250,500 $ 286,275 $ - $ 536,775
Current Portion of Long-term Debt,
Preferred Stock and Preference Stock 203,574 369,735 - 573,309
Accounts Payable 144,690 275,956 - 420,646
Other 286,303 104,546 - 390,849
------------- ---------------- ------------ ------------
Total Current Liabilities 885,067 1,036,512 - 1,921,579
------------- ---------------- ------------ ------------
Deferred Credits and Other Liabilities
Deferred Income Taxes 1,298,068 1,032,131 - 2,330,199
Capital Lease Obligations - 161,057 - 161,057
Pension and Postemployment Benefits 188,535 - - 188,535
Other 97,862 43,623 - 141,485
------------- ---------------- ------------ ------------
Total Deferred Credits and Other
Liabilities 1,584,465 1,236,811 - 2,821,276
------------- ---------------- ------------ ------------
Capitalization
Long-term Debt 3,095,983 2,272,124 - 5,368,107
Preferred Stock - 266,291 - 266,291
Preference Stock 301,500 - - 301,500
Common Shareholders' Equity 2,914,585 1,944,201 - 4,858,786
------------- ---------------- ------------ ------------
Total Capitalization 6,312,068 4,482,616 - 10,794,684
------------- ---------------- ------------ ------------
Total Liabilities and Capitalization $ 8,781,600 $ 6,755,939 $ - $ 15,537,539
============= ================ ============ ============
<FN>
See accompanying Notes to Unaudited Pro Forma Combined
Condensed Financial Statements.
</FN>
54
</TABLE>
<TABLE>
CONSTELLATION ENERGY CORPORATION
UNAUDITED PRO FORMA COMBINED CONDENSED INCOME STATEMENT
NINE MONTHS ENDED SEPTEMBER 30, 1997
(In thousands, except per share amounts)
-------------------------------------------------------
<CAPTION>
PEPCO
BGE (As Reclassified) Pro Forma Pro Forma
(As Reported) (See Note 5) Adjustments Combined
------------- ----------------- ------------ -------------
<S> <C> <C> <C> <C>
Revenue
Electric $ 1,691,700 $ 1,473,073 $ - $ 3,164,773
Gas 366,948 - - 366,948
Diversified businesses 436,310 101,370 - 537,680
------------ ----------------- ----------- ------------
Total Revenue 2,494,958 1,574,443 - 4,069,401
------------ ----------------- ----------- ------------
Operating Expenses
Electric fuel and purchased energy 383,245 512,134 - 895,379
Gas purchased for resale 206,775 - - 206,775
Operations 389,163 160,319 - 549,482
Maintenance 139,040 67,797 - 206,837
Diversified business expenses 391,582 54,827 - 446,409
Loss on assets held for disposal - 2,022 - 2,022
Depreciation and amortization 256,136 173,982 - 430,118
Taxes other than income taxes 165,334 154,219 - 319,553
------------ ----------------- ----------- ------------
Total Operating Expenses 1,931,275 1,125,300 - 3,056,575
------------ ----------------- ----------- ------------
Income from Operations 563,683 449,143 - 1,012,826
Total Other Income 5,395 8,685 - 14,080
------------ ----------------- ----------- ------------
Income Before Interest and Income Taxes 569,078 457,828 - 1,026,906
Net Interest Expense 171,493 157,765 - 329,258
------------ ----------------- ----------- ------------
Income Before Income Taxes 397,585 300,063 - 697,648
Income Taxes 139,097 90,972 - 230,069
------------ ----------------- ----------- ------------
Net Income 258,488 209,091 - 467,579
Preferred and Preference Stock Dividends 22,752 12,439 - 35,191
------------ ----------------- ----------- ------------
Earnings Applicable to Common Stock $ 235,736 $ 196,652 $ - $ 432,388
============ ================= =========== ============
Average Shares of Common Stock Outstanding 147,667 118,500 265,812
Earnings Per Share of Common Stock $1.60 $1.66 $1.63
<FN>
See accompanying Notes to Unaudited Pro Forma Combined Condensed Financial
Statements.
</FN>
55
</TABLE>
Notes to Unaudited Pro Forma Combined Condensed Financial
- ---------------------------------------------------------
Statements
- ----------
1. The revenue, expenses, assets, and liabilities of PEPCO's
nonregulated subsidiaries have been reclassified to conform
with the presentation used by BGE. The effect of accounting
policy differences are immaterial and have not been adjusted
in the pro forma combined condensed financial statements.
2. Pro forma per common share amounts give effect to the
conversion of each share of PEPCO and BGE Common Stock into
.997 share and 1 share, respectively, of Constellation Energy
Corporation Common Stock. The pro forma combined condensed
financial statements are presented as if the companies were
combined during all periods included therein.
3. The allocation between PEPCO and BGE and their customers of
the estimated cost savings resulting from the Merger, net of
the costs incurred to achieve such savings, will be subject
to regulatory review and approval. None of these estimated
cost savings, the costs to achieve such savings, or
transaction costs have been reflected in the pro forma
combined condensed financial statements.
4. Intercompany transactions between PEPCO and BGE during the
periods presented were not material and, accordingly, no pro
forma adjustments were made to eliminate such transactions.
5. The PEPCO reclassifying information reflects the
reclassifying entries necessary to adjust PEPCO's
consolidated balance sheet and statement of income
presentation to be consistent with the presentation expected
to be used by Constellation Energy Corporation.
56
<TABLE>
POTOMAC ELECTRIC POWER COMPANY
RECLASSIFYING BALANCE SHEET
SEPTEMBER 30, 1997
(In Thousands)
------------------------------
<CAPTION>
PEPCO PEPCO PEPCO
(As Reported) (Reclasses) (As Reclassified)
-------------- -------------- -----------------
<S> <C> <C> <C>
ASSETS
Current Assets
Cash and Cash Equivalents $ 2,916 $ 10,087 $ 13,003
Accounts Receivable - net - 311,370 311,370
Customer Accounts Receivable - net 186,623 (186,623) -
Other Accounts Receivable - net 25,117 (25,117) -
Accrued Unbilled Revenue 88,071 (88,071) -
Materials and Supplies - 129,627 129,627
Fuel 60,432 (60,432) -
Construction and Maintenance 69,195 (69,195) -
Prepayments and Other - 45,471 45,471
Prepaid Taxes 41,554 (41,554) -
Other Prepaid Expenses 3,917 (3,917) -
------------- ------------- ----------------
Total Current Assets 477,825 21,646 499,471
------------- ------------- ----------------
Investments and Other Assets
Notes Receivable - 23,438 23,438
Real Estate Projects - 72,956 72,956
Power Generation Systems - 979 979
Marketable Securities - 303,905 303,905
Investment in Finance Leases - 460,021 460,021
Operating Lease Equipment - net - 170,747 170,747
Other Investments - 108,646 108,646
------------- ------------- ----------------
Total Investments and Other Assets - 1,140,692 1,140,692
------------- ------------- ----------------
Utility Plant
Plant in Service
Electric 6,335,130 - 6,335,130
Construction Work in Progress 84,901 (84,901) -
Electric Plant Held for Future Use 4,210 (4,210) -
Nonoperating Property 22,750 (22,750) -
------------- ------------- ----------------
Total Plant in Service 6,446,991 (111,861) 6,335,130
Accumulated Depreciation (2,000,376) 738 (1,999,638)
Construction Work in Progress - 84,901 84,901
Other Plant - net - 26,222 26,222
------------- ------------- ----------------
Net Utility Plant 4,446,615 - 4,446,615
------------- ------------- ----------------
Deferred Charges
Regulatory Assets - 461,337 461,337
Income Taxes Recoverable through Future Rates, net 238,711 (238,711) -
Conservation Costs, net 224,464 (224,464) -
Unamortized Debt Reacquisition Costs 53,447 (53,447) -
Other 196,614 11,210 207,824
------------- ------------- ----------------
Total Deferred Charges 713,236 (44,075) 669,161
------------- ------------- ----------------
Nonutility Subsidiary Assets
Cash and Cash Equivalents 10,087 (10,087) -
Marketable Securities 303,905 (303,905) -
Investment in Finance Leases 460,021 (460,021) -
Operating Lease Equipment - net 170,747 (170,747) -
Receivables - net 34,997 (34,997) -
Other Investments 182,581 (182,581) -
Other Assets 14,146 (14,146) -
------------- ------------- ----------------
Total Nonutility Subsidiary Assets 1,176,484 (1,176,484) -
------------- ------------- ----------------
Total Assets $ 6,814,160 $ (58,221) $ 6,755,939
============= ============= ================
57
</TABLE>
<TABLE>
POTOMAC ELECTRIC POWER COMPANY
RECLASSIFYING BALANCE SHEET
SEPTEMBER 30, 1997
(In Thousands)
------------------------------
<CAPTION>
PEPCO PEPCO PEPCO
(As Reported) (Reclasses) (As Reclassified)
-------------- ------------ -----------------
<S> <C> <C> <C>
LIABILITIES AND CAPITALIZATION
Current Liabilities
Short-term Borrowings $ 277,075 $ 9,200 $ 286,275
Current Portion of Long-term Debt and Preferred Stock 50,985 318,750 369,735
Accounts Payable and Accrued Expenses 247,359 28,597 275,956
Capital Lease Obligations Due within One Year 20,772 (20,772) -
Other 83,774 20,772 104,546
------------- ----------- ----------------
Total Current Liabilities 679,965 356,547 1,036,512
------------- ----------- ----------------
Deferred Credits and Other Liabilities
Deferred Income Taxes 1,014,472 17,659 1,032,131
Deferred Investment Tax Credits 58,221 (58,221) -
Capital Lease Obligations - 161,057 161,057
Other 30,842 12,781 43,623
------------- ----------- ----------------
Total Deferred Credits and Other Liabilities 1,103,535 133,276 1,236,811
------------- ----------- ----------------
Other Non-Current Liabilities
Capital Lease Obligations 161,057 (161,057) -
------------- ----------- ----------------
Total Other Non-Current Liabilities 161,057 (161,057) -
------------- ----------- ----------------
Capitalization
Long-term Debt 1,727,707 544,417 2,272,124
Preferred Stock - 266,291 266,291
Serial Preferred Stock 125,291 (125,291) -
Redeemable Serial Preferred Stock 141,000 (141,000) -
Common Shareholders' Equity - 1,944,201 1,944,201
Common Stock 118,501 (118,501) -
Other Common Equity 1,825,700 (1,825,700) -
------------- ----------- ----------------
Total Capitalization 3,938,199 544,417 4,482,616
------------- ----------- ----------------
Nonutility Subsidiary Liabilities
Long-term Debt 863,167 (863,167) -
Short-term Notes Payable 9,200 (9,200) -
Deferred Taxes and Other 59,037 (59,037) -
------------- ----------- ----------------
Total Nonutility Subsidiary Liabilities 931,404 (931,404) -
------------- ----------- ----------------
Total Liabilities and Capitalization $ 6,814,160 $ (58,221) $ 6,755,939
============= =========== ================
58
</TABLE>
<TABLE>
POTOMAC ELECTRIC POWER COMPANY
RECLASSIFYING STATEMENT OF INCOME
NINE MONTHS ENDED SEPTEMBER 30, 1997
(In thousands, except per share amounts)
----------------------------------------
<CAPTION> PEPCO PEPCO PEPCO
(As Reported) (Reclasses) (As Reclassified)
------------- ------------- -----------------
<S> <C> <C> <C>
Electric $ 1,473,073 $ - $ 1,473,073
Diversified businesses - 101,370 101,370
------------ ------------ ----------------
Total Revenue 1,473,073 101,370 1,574,443
------------ ------------ ----------------
Operating Expenses
Electric fuel and purchased energy - 512,134 512,134
Fuel 249,655 (249,655) -
Purchased energy 154,314 (154,314) -
Capacity purchase payments 108,165 (108,165) -
Operations 160,319 - 160,319
Maintenance 67,797 - 67,797
Diversified business expenses - 54,827 54,827
Loss on assets held for disposal - 2,022 2,022
Depreciation and amortization 173,982 - 173,982
Income taxes 115,280 (115,280) -
Taxes other than income taxes 154,219 - 154,219
------------ ------------ ----------------
Total Operating Expenses 1,183,731 (58,431) 1,125,300
------------ ------------ ----------------
Income from Operations 289,342 159,801 449,143
------------ ------------ ----------------
Other Income
Nonutility Subsidiary Income 101,370 (101,370) -
Loss on assets held for disposal (2,022) 2,022 -
Expenses, including interest and income taxes (83,567) 83,567 -
------------ ------------ ----------------
Net earnings from nonutility subsidiary 15,781 (15,781) -
Allowance for other funds used during construction
and capital cost recovery factor 4,949 - 4,949
Other, net 3,753 (17) 3,736
------------ ------------ ----------------
Total Other Income 24,483 (15,798) 8,685
------------ ------------ ----------------
Income Before Interest and Income Taxes 313,825 144,003 457,828
------------ ------------ ----------------
Interest Expense
Interest on debt 101,036 - 101,036
Other 9,557 - 9,557
Subsidiary interest expense - 53,031 53,031
Allowance for borrowed funds used during construction
and capital cost recovery factor (5,859) - (5,859)
------------ ------------ ----------------
Net Interest Expense 104,734 53,031 157,765
------------ ------------ ----------------
Income before income taxes 209,091 90,972 300,063
------------ ------------ ----------------
Income taxes - Utility - 115,280 115,280
Income taxes - Nonoperating - (17) (17)
Income taxes - Subsidiary - (24,291) (24,291)
------------ ------------ ----------------
Total Income Taxes - 90,972 90,972
------------ ------------ ----------------
Net Income 209,091 - 209,091
Preferred Dividends 12,439 - 12,439
------------ ------------ ----------------
Earnings Applicable to Common Stock $ 196,652 $ - $ 196,652
============ ============ ================
Average Shares of Common Stock Outstanding 118,500 118,500
Earnings Per Share of Common Stock $1.66 $1.66
59
</TABLE>
Item 6 EXHIBITS AND REPORTS ON FORM 8-K
- ------ --------------------------------
(a) Exhibits
Exhibit 3 - By-Laws of the Company - filed
herewith.
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
A Current Report on Form 8-K was filed by the
Company on July 14, 1997, providing details of the
Potomac Electric Power Company and Baltimore Gas
and Electric Company (BGE) response to the
Baltimore County Circuit Court delay in the
decision to remand the Merger case to the Maryland
Public Service Commission for reconsideration.
The item reported on such Form 8-K was Item 5
(Other Events).
A Current Report on Form 8-K was filed by the
Company on August 6, 1997, providing details on the
joint venture formed by Potomac Capital Investment
Corporation (PCI) and RCN Corporation (RCN) to
provide bundled telecommunication services to the
Washington, D.C. metropolitan area. The item
reported on such Form 8-K was Item 5 (Other
Events).
60
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
November 13, 1997
- -----------------
DATE
61
<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, 1997,
and the twelve months ended December 31, 1996 and 1995:
<CAPTION>
September 30, December 31, December 31,
1997 1996 1995
------------- ------------ ------------
<S> <C> <C> <C>
Average shares outstanding for
computation of primary earnings
per common share 118,499,671 118,496,683 118,412,478
============ ============ ============
Average shares outstanding for
fully diluted computation:
Average shares outstanding 118,499,671 118,496,683 118,412,478
Additional shares resulting from:
Conversion of Serial Preferred
Stock, $2.44 Convertible Series
of 1966 (the "Convertible
Preferred Stock") 34,292 34,986 38,255
Conversion of 7% Convertible
Debentures 2,364,559 2,418,579 2,469,639
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 124,291,022 124,342,748 124,312,872
============ ============ ============
Earnings applicable to common stock $203,782,000 $220,356,000 $77,540,000
Add: Dividends paid or accrued on
Convertible Preferred Stock 14,000 15,000 16,000
Interest paid or accrued on
Convertible Debentures,
net of related taxes 6,353,000 6,416,000 6,475,000
------------ ------------ ------------
Earnings applicable to common stock,
assuming conversion of convertible
securities $210,149,000 $226,787,000 $84,031,000
============ ============ ============
Primary earnings per common share $1.72 $1.86 $0.65
<FN> $1.69 $1.82 $0.68
The valuation is not required by footnote 2 to paragraph 14 of APB No. 15 for the
the twelve months ended September 30, 1997 and December 31, 1996 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
No. 15 because it produces an antidilutive result for the twelve months ended December
31, 1995.
</FN>
62
</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, 1997, 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,
1997 1996 1995 1994 1993 1992
--------- --------- --------- --------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Net income before cumulative effect
of accounting change $204,103 $220,066 $218,788 $208,074 $216,478 $172,599
Taxes based on income 121,095 135,011 129,439 116,648 107,223 76,965
--------- --------- --------- --------- --------- ---------
Income before taxes and cumulative effect
of accounting change 325,198 355,077 348,227 324,722 323,701 249,564
--------- --------- --------- --------- --------- ---------
Fixed charges:
Interest charges 146,269 146,939 146,558 139,210 141,393 138,097
Interest factor in rentals 23,414 23,560 23,431 6,300 5,859 6,140
--------- --------- --------- --------- --------- ---------
Total fixed charges 169,683 170,499 169,989 145,510 147,252 144,237
--------- --------- --------- --------- --------- ---------
Income before income taxes, cumulative
effect of accounting change and
fixed charges $494,881 $525,576 $518,216 $470,232 $470,953 $393,801
========= ========= ========= ========= ========= =========
Coverage of fixed charges 2.92 3.08 3.05 3.23 3.20 2.73
==== ==== ==== ==== ==== ====
Preferred dividend requirements $16,595 $16,604 $16,851 $16,437 $16,255 $14,392
--------- --------- --------- --------- --------- ---------
Ratio of pre-tax income to net income 1.59 1.61 1.59 1.56 1.50 1.45
--------- --------- --------- --------- --------- ---------
Preferred dividend factor $26,386 $26,732 $26,793 $25,642 $24,383 $20,868
--------- --------- --------- --------- --------- ---------
Total fixed charges and preferred dividends $196,069 $197,231 $196,782 $171,152 $171,635 $165,105
========= ========= ========= ========= ========= =========
Coverage of combined fixed charges
and preferred dividends 2.52 2.66 2.63 2.75 2.74 2.39
==== ==== ==== ==== ==== ====
63
</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, 1997, 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,
1997 1996 1995 1994 1993 1992
--------- --------- --------- --------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Net income before cumulative effect
of accounting change $220,377 $236,960 $94,391 $227,162 $241,579 $200,760
Taxes based on income 91,976 80,386 43,731 93,953 62,145 79,481
--------- --------- --------- --------- --------- ---------
Income before taxes and cumulative effect
of accounting change 312,353 317,346 138,122 321,115 303,724 280,241
--------- --------- --------- --------- --------- ---------
Fixed charges:
Interest charges 219,664 231,029 238,724 224,514 221,312 226,453
Interest factor in rentals 23,427 23,943 26,685 9,938 9,257 6,599
--------- --------- --------- --------- --------- ---------
Total fixed charges 243,091 254,972 265,409 234,452 230,569 233,052
--------- --------- --------- --------- --------- ---------
Nonutility subsidiary capitalized interest (504) (649) (529) (521) (2,059) (2,200)
--------- --------- --------- --------- --------- ---------
Income before income taxes, cumulative
effect of accounting change and
fixed charges $554,940 $571,669 $403,002 $555,046 $532,234 $511,093
======== ======== ======== ======== ======== ========
Coverage of fixed charges 2.28 2.24 1.52 2.37 2.31 2.19
==== ==== ==== ==== ==== ====
Preferred dividend requirements $16,595 $16,604 $16,851 $16,437 $16,255 $14,392
--------- --------- --------- --------- --------- ---------
Ratio of pre-tax income to net income 1.42 1.34 1.46 1.41 1.26 1.40
--------- --------- --------- --------- --------- ---------
Preferred dividend factor $23,565 $22,249 $24,602 $23,176 $20,481 $20,149
--------- --------- --------- --------- --------- ---------
Total fixed charges and preferred dividends $266,656 $277,221 $290,011 $257,628 $251,050 $253,201
======== ======== ======== ======== ======== ========
Coverage of combined fixed charges
and preferred dividends 2.08 2.06 1.39 2.15 2.12 2.02
==== ==== ==== ==== ==== ====
64
</TABLE>
Exhibit 15
November 13, 1997
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 November 13, 1997, (issued pursuant
to the provisions of Statement on Auditing Standards No. 71) in
the Prospectuses constituting parts of the Registration
Statements on Forms S-8 (Numbers 33-36798, 33-53685 and 33-54197)
filed on September 12, 1990, May 18, 1994 and June 17, 1994,
respectively, and on Forms S-3 (Numbers 33-58810, 33-61379 and
333-33495) filed on February 26, 1993, July 28, 1995 and August
13, 1997, respectively, in the Joint Proxy Statement/Prospectus
constituting part of the Registration Statement on Form S-4
(Number 33-64799) of Constellation Energy Corporation filed on
December 7, 1995, and in the Prospectuses constituting parts of
the Registration Statements on Forms S-3 (Numbers 333-24705 and
333-24855) of Constellation Energy Corporation filed on April 7,
1997 and April 9, 1997, respectively. 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.
65
=================================================================
By-Laws
of
POTOMAC ELECTRIC POWER COMPANY
WASHINGTON, D. C.
As amended through
October 23, 1997
=================================================================
PAGE
<PAGE>
POTOMAC ELECTRIC POWER COMPANY
BY-LAWS
______
ARTICLE I
SECTION 1. The annual meeting of the stockholders of the
Company shall be held on such day, at such time and place within
or without the District of Columbia as the Board of Directors or
the Executive Committee shall designate for the purpose of
electing directors and of transacting such other business as may
properly be brought before the meeting.
At an annual meeting of the stockholders, only such business
shall be conducted as shall have been properly brought before the
meeting. To be properly brought before an annual meeting,
business must be specified in the notice of meeting (or any
supplement thereto) given by or at the direction of the Board,
otherwise properly brought before the meeting by or at the
direction of the Board, or otherwise properly brought before the
meeting by a stockholder. In addition to any other applicable
requirements, for business to be properly brought before an
annual meeting by a stockholder, the stockholder must have given
timely notice thereof in writing to the Secretary of Potomac
Electric Power Company. To be timely, a stockholder's notice
must be received at the principal executive offices of the
Company not less than 50 days nor more than 75 days prior to the
meeting; provided, however, that in the event that less than 65
days' notice or prior public disclosure of the date of the
meeting is given or made to stockholders, notice by the
stockholder to be timely must be so received not later than the
close of business on the fifteenth day following the day on which
such notice of the date of the annual meeting was mailed or such
public disclosure was made, whichever first occurs. A
stockholder's notice to the Secretary shall set forth (i) a brief
description of the business desired to be brought before the
annual meeting and the reasons for conducting such business at
the annual meeting, (ii) the name and record address of the
stockholder proposing such business, (iii) the class and number
of shares of the Company that are beneficially owned by the
stockholder, and (iv) any material interest of the stockholder in
such business.
Notwithstanding anything in the By-Laws to the contrary, no
business shall be conducted at the annual meeting except in
accordance with the procedures set forth in this Article I,
Section 1; provided, however, that nothing in this Article I,
Section 1 shall be deemed to preclude discussion by any
stockholder of any business properly brought before the annual
meeting in accordance with such procedures.
<PAGE>
2
The Chairman of an annual meeting shall, if the facts
warrant, determine that business was not properly brought before
the meeting in accordance with the provisions of this Article I,
Section 1, and if he should so determine, he shall so declare to
the meeting and any such business not properly brought before the
meeting shall not be transacted.
SECTION 2. Special meetings of the stockholders, when
called, shall be held at such time and place within or without
the District of Columbia and may be called by the Board of
Directors, or the Executive Committee, or the holders of record
of not less than one-fifth of all the outstanding shares entitled
to vote at the meeting, or, if the meeting is for the purpose of
enabling the holders of the Serial Preferred Stock of the Company
to elect directors upon the conditions set forth in the Articles
of Incorporation of the Company, such meeting shall be called as
therein provided.
SECTION 3. Written notice stating the place, day and hour
of each meeting of the stockholders and the purpose or purposes
for which the meeting is called shall be given not less than ten
days (or such longer period as may be prescribed by law) and not
more than fifty days before the date of the meeting to each
stockholder of record entitled to vote at the meeting, by
depositing such notice in the United States mail addressed to the
respective stockholders at their addresses as they appear on the
records of the Company, with postage thereon prepaid.
In connection with the first election of a portion of the
members of the Board of Directors by the holders of the Serial
Preferred Stock upon accrual of such right, as provided in the
Articles of Incorporation of the Company, the Company shall
prepare and mail to the holders of the Serial Preferred Stock
entitled to vote thereon such proxy forms, communications and
documents as may be deemed appropriate for the purpose of
soliciting proxies for the election of directors by the holders
of the Serial Preferred Stock.
The Secretary or an Assistant Secretary of the Company shall
cause to be made, at least ten days before each meeting of
stockholders, a complete list of the stockholders entitled to
vote at such meeting or any adjournment thereof, with the address
of and the number of shares held by each. Such list, for a
period of ten days prior to such meeting, shall be kept on file
at the principal place of business of the Company and shall be
subject to inspection for any proper purpose by any stockholder
at any time during usual business hours. Such list shall also be
produced and kept open at the time and place of the meeting and
shall be subject to the inspection for any proper purpose of any
stockholder during the whole time of the meeting.
SECTION 4. At each meeting of stockholders the holders
of record of a majority of the outstanding shares entitled
to vote at such meeting, represented in person or by proxy,
shall constitute a quorum, except as otherwise provided by
law or by the Articles of Incorporation of the Company.
The affirmative vote of the holders of a majority of the
<PAGE>
3
shares represented at a duly organized meeting at which a quorum
was present at the time of organization, and entitled to vote on
the subject matter, shall be the act of the stockholders, unless
the vote of the holders of a greater number, or voting by
classes, is required by law or by the Articles of Incorporation
of the Company and except that in elections of directors those
receiving the greatest numbers of votes shall be deemed elected
even though not receiving a majority. If a meeting cannot be
organized because a quorum has not attended, the holders of a
majority of the shares represented at the meeting may adjourn the
meeting from time to time, without notice other than announcement
at the meeting, until a quorum shall have been obtained, when any
business may be transacted which might have been transacted at
the meeting as first convened had there been a quorum.
SECTION 5. Meetings of the stockholders shall be presided
over by the Chairman of the Board or, if he is not present, by
the President or, if neither is present, by a Vice Chairman or,
if no such officer is present, by a chairman to be chosen at the
meeting. The Secretary of the Company or, if he is not present,
an Assistant Secretary of the Company or, if neither is present,
a secretary to be chosen at the meeting, shall act as Secretary
of the meeting.
SECTION 6. Each stockholder entitled to vote at any meeting
may so vote either in person or by proxy executed in writing by
the stockholder or by his duly authorized attorney-in-fact and
shall be entitled to one vote on each matter submitted to a vote
for each share of stock of the Company having voting power
thereon registered in his name at the date fixed for the
determination of the stockholders entitled to vote at the
meeting.
SECTION 7. At all elections of directors the voting shall
be by ballot. At all such elections, the Chairman of the meeting
shall appoint two inspectors of election, unless such appointment
shall be unanimously waived by the stockholders present in person
or represented by proxy at the meeting and entitled to vote for
the election of directors. No director or candidate for the
office of director shall be appointed as such inspector. The
inspectors, before entering upon the discharge of their duties,
shall take and subscribe an oath or affirmation faithfully to
execute the duties of inspector at such meeting with strict
impartiality and according to the best of their ability, and
shall take charge of the polls and after the balloting shall make
a certificate of the result of the vote taken.
SECTION 8. In order to determine who are stockholders of
the Company for any proper purpose, the Board of Directors either
may close the stock transfer books or, in lieu thereof, may fix
in advance a date as the record date for such determination, such
date in any case to be not more than fifty days (and, in the case
of a meeting of stockholders, not less than ten days or such
longer period as may be required by law) prior to the date on
which the particular action, requiring such determination, is to
be taken. When such a record date has been so fixed for the
determination of stockholders entitled to vote at a meeting, such
determination shall apply to any adjournment thereof.
<PAGE>
4
ARTICLE II
BOARD OF DIRECTORS
SECTION 1. The Board of Directors of the Company shall
consist of twelve persons, each of whom shall be a stockholder of
the Company. The directors shall be divided into three classes,
designated Class I, Class II, and Class III. Each of the classes
shall have four directors. At the 1987 annual meeting of
stockholders, Class I directors shall be elected for a one-year
term, Class II directors for a two-year term, and Class III
directors for a three-year term. At each succeeding annual
meeting of stockholders beginning in 1988, successors to the
class of directors whose term expires at that annual meeting
shall be elected for a three-year term. Except as otherwise
provided in the Articles of Incorporation of the Company and in
these By-Laws, the directors shall hold office until the annual
meeting of the stockholders for the year in which their
respective terms expire and until their respective successors
shall have been elected and qualified. No person shall be
eligible for election as a director after he shall have attained
his seventieth birthday, and no person shall be eligible to serve
as a director beyond the next annual meeting after he shall have
attained his seventieth birthday. No director who is a full time
employee of the Company shall be eligible to serve as a director
beyond the next annual meeting after termination of his
employment with the Company, provided, that (a) this provision
shall not apply to a director who is serving or has served as
Chief Executive Officer and (b) a director serving at the time of
termination of employment as Vice Chairman shall be permitted to
continue as director until the expiration of his three-year term.
Seven members of the Board shall constitute a quorum for the
transaction of business, but if any meeting of the Board cannot
be organized because a quorum has not attended, a majority of
those present may adjourn the meeting from time to time, without
notice other than announcement at the meeting, until a quorum
shall have been obtained, when any business may be transacted
which might have been transacted at the meeting as first convened
had there been a quorum. The acts of a majority of the directors
present at a meeting at which a quorum is present shall, except
as otherwise provided by law, by the Articles of Incorporation of
the Company, or by these By-Laws, be the acts of the Board of
Directors.
Only persons who are nominated in accordance with the
following procedures shall be eligible for election as Directors.
Nominations of persons for election to the Board of the Company
may be made at the annual meeting of stockholders by or at
the direction of the Board of Directors, by any nominating
committee or person appointed by the Board, or by any
stockholder of the Company entitled to vote for the election
of Directors at the meeting who complies with the notice
procedures set forth in this Article II, Section 1. Such
nominations, other than those made by or at the direction
of the Board, shall be made pursuant to timely notice in
writing to the Secretary of Potomac Electric Power Company.
To be timely, a stockholder's notice shall be received at
the principal executive offices of the Company not less than
50 days nor more than 75 days prior to the meeting; provided,
<PAGE>
5
however, that in the event that less than 65 days' notice or
prior public disclosure of the date of the meeting is given or
made to stockholders, notice by the stockholder to be timely must
be so received not later than the close of business on the
fifteenth day following the day on which such notice of the date
of the meeting was mailed or such public disclosure was made,
whichever first occurs. Such stockholder's notice to the
Secretary shall set forth (a) as to each person whom the
stockholder proposes to nominate for election or reelection as a
Director, (i) the name, age, business address and residence
address of the person, (ii) the principal occupation or
employment of the person, (iii) the class and number of shares of
capital stock of the Company that are beneficially owned by the
person and (iv) any other information relating to the person that
is required to be disclosed in solicitations for proxies for
election of Directors pursuant to Section 14(a) of the Securities
Exchange Act of 1934, as amended; and (b) as to the stockholder
giving the notice (i) the name and record address of the
stockholder and (ii) the class and number of shares of capital
stock of the Company that are beneficially owned by the
stockholder. The Company may require any proposed nominee to
furnish such other information as may reasonably be required by
the Company to determine the eligibility of such proposed nominee
to serve as Director of the Company. No person shall be eligible
for election as a Director of the Company unless nominated in
accordance with the procedures set forth herein.
The Chairman of the meeting shall, if the facts warrant,
determine that a nomination was not made in accordance with the
foregoing procedure, and if he should so determine, he shall so
declare to the meeting and the defective nomination shall be
disregarded.
The Board of Directors, as soon as is reasonably practicable
after the initial election of Directors by the stockholders in
each year, shall elect one of its number Chairman of the Board,
who may be, but is not required to be, an officer and employee of
the Company.
SECTION 2. Any vacancy, from any cause other than an
increase in the number of Directors, occurring among the
directors shall be filled without undue delay by a majority of
the remaining directors who were elected, or whose predecessors
in office were elected, by the same class of stockholders as that
which elected the last incumbent of the vacant directorship. The
term of any director elected by the remaining directors to fill a
vacancy (other than one caused by an increase in the number of
directors) shall expire at the next stockholders' meeting at
which directors are elected.
SECTION 3. Regular meetings of the Board of Directors
shall be held at the office of the Company in the District
of Columbia (unless otherwise fixed by resolution of the
Board) at such time as may from time to time be fixed by
resolution of the Board. Special meetings of the Board
may be held upon call of the Executive Committee, or the
Chairman of the Board, or the President, or a Vice Chairman,
by oral, telegraphic or written notice, setting forth the
time and place (either within or without the District of
Columbia) of the meeting, duly served on or sent or
mailed to each director not less than two days before the
<PAGE>
6
meeting. A meeting of the Board may be held without notice,
immediately after, and at the same place as, the annual meeting
of the stockholders. A waiver in writing of any notice, signed
by a director, whether before or after the time stated therein,
shall be deemed equivalent to the giving of such notice to such
director. Neither the business to be transacted at, nor the
purpose of, any regular or special meeting of the Board need be
specified in any notice, or waiver of notice, of such meeting.
SECTION 4. Meetings of the Board of Directors shall be
presided over by the Chairman of the Board or, if he is not
present, by the President or, if neither is present, by a Vice
Chairman or, if no such officer is present, by a chairman to be
chosen at the meeting. The Secretary of the Company or, if he is
not present, an Assistant Secretary of the Company or, if neither
is present, a secretary to be chosen at the meeting, shall act as
secretary of the meeting.
SECTION 5. The Board of Directors may, by resolution or
resolutions adopted by not less than the number of directors
necessary to constitute a quorum of the Board, designate an
Executive Committee consisting of not less than three nor more
than seven directors. Except as otherwise provided by law, the
Executive Committee shall have and may exercise, when the Board
is not in session, all of the powers of the Board in the
management of the property, business and affairs of the Company;
but the Executive Committee shall not have power to fill
vacancies in the Board, or to change the membership of, or to
fill vacancies in, the Executive Committee, or to adopt, alter,
amend, or repeal by-laws of the Company. The Board shall have
the power at any time to fill vacancies in, to change the
membership of, or to dissolve, the Executive Committee. The
Executive Committee may make rules for the conduct of its
business and fix the time and place of its meetings, and may
appoint such committees and assistants as it shall from time to
time deem necessary. A majority of the members of the Executive
Committee shall constitute a quorum, and the acts of a majority
of the members of the Committee present at a meeting at which a
quorum is present shall be the acts of said Committee. All
action taken by the Executive Committee shall be reported to the
Board at its regular meeting next succeeding the taking of such
action.
SECTION 6. The Board of Directors may also, by
resolution or resolutions adopted by not less than the number
of directors necessary to constitute a quorum of the Board,
designate one or more other committees, each such committee to
consist of such number of directors as the Board may from time
to time determine, which, to the extent provided in said
resolution or resolutions, shall have and may exercise such
limited authority as the Board may authorize. Such committee
or committees shall have such name or names as the Board may
from time to time determine. The Board shall have the power
at any time to fill vacancies in, to change the membership of,
or to dissolve, any such committee. A majority, or such other
number as the Board may designate, of the members of any such
committee shall constitute a quorum. Each such committee may
make rules for the conduct of its business and fix the time and
place of its meetings unless the Board shall otherwise provide.
<PAGE>
7
All action taken by any such committee shall be reported to the
Board at its regular meeting next succeeding the taking of such
action, unless otherwise directed.
SECTION 7. The Board of Directors shall fix the
compensation to be paid to each director who is not a salaried
employee of the Company for serving as a director and for
attendance at meetings of the Board and committees thereof, and
may authorize the payment to directors of expenses incurred in
attending any such meeting or otherwise incurred in connection
with the business of the Company. This By-Law shall not be
construed to preclude any Director from serving the Company in
any other capacity and receiving compensation therefor.
SECTION 8. At a special meeting called expressly for such
purpose (i) any director elected by the holders of the Serial
Preferred Stock, or elected by directors to fill a vacancy among
the directors elected by the holders of such stock, may be
removed, only for cause, by a vote of the holders of a majority
of the shares of Serial Preferred Stock, and the resulting
vacancy may be filled, for the unexpired term of the director so
removed, by a vote of the holders of such Stock; and (ii) any
director elected by the holders of the Common Stock, or elected
by directors to fill a vacancy among the directors elected by the
holders of such stock, may be removed, only for cause, by a vote
of the holders of a majority of the shares of Common Stock, and
the resulting vacancy may be filled, for the unexpired term of
the director so removed, by a vote of the holders of such Stock.
SECTION 9. With respect to a Company officer, director, or
employee, the Company shall indemnify, and with respect to any
other individual the Company may indemnify, any person who was or
is a party or is threatened to be made a party to any threatened,
pending or completed action, suit or proceeding (an "Action"),
whether civil, criminal, administrative, arbitrative or
investigative (including an Action by or in the right of the
Company) by reason of the fact that he is or was a director,
officer, employee or agent of the Company, or is or was serving
at the request of the Company as a director, officer, employee or
agent of another corporation, partnership, joint venture, trust
or other enterprise, against expenses (including attorneys'
fees), judgments, fines and amounts paid in settlement actually
and reasonably incurred by him in connection with such Action;
except in relation to matters as to which he shall be finally
adjudged in such Action to have knowingly violated the criminal
law or be liable for willful misconduct in the performance of his
duty to the Company. The termination of any Action by judgment,
order, settlement, conviction, or upon a plea of nolo contendere
or its equivalent, shall not of itself create a presumption that
the person was guilty of willful misconduct.
Any indemnification (unless ordered by a court) shall be
made by the Company only as authorized in the specific case
upon a determination that indemnification of the director,
officer, employee or agent is proper in the circumstances
because he has met the applicable standard of conduct set forth
above. In the case of any director, such determination shall be
<PAGE>
8
made: (1) by the Board of Directors by a majority vote of a
quorum consisting of directors who were not parties to such
Action; or (2) if such a quorum is not obtainable, by majority
vote of a committee duly designated by the Board of Directors (in
which designation directors who are parties may participate)
consisting solely of two or more directors not at the time
parties to the proceeding; or (3) by special legal counsel
selected by the Board of Directors or its committee in the manner
prescribed by clause (1) or (2) of this paragraph, or if such a
quorum is not obtainable and such a committee cannot be
designated, by majority vote of the Board of Directors, in which
selection directors who are parties may participate; or (4) by
vote of the shareholders, in which vote shares owned by or voted
under the control of directors, officers and employees who are at
the time parties to the Action may not be voted. In the case of
any officer, employee, or agent other than a director, such
determination may be made (i) by the Board of Directors or a
committee thereof; (ii) by the Chairman of the Board of the
Company or, if the Chairman is a party to such Action, the
President of the Company, or (iii) such other officer of the
Company, not a party to such Action, as such person specified in
clause (i) or (ii) of this paragraph may designate.
Authorization of indemnification and evaluation as to
reasonableness of expenses shall be made in the same manner as
the determination that indemnification is permissible, except
that if the determination is made by special legal counsel,
authorization of indemnification and evaluation as to
reasonableness of expenses shall be made by those entitled
hereunder to select such legal counsel.
Expenses incurred in defending an Action for which
indemnification may be available hereunder shall be paid by the
Company in advance of the final disposition of such Action as
authorized in the manner provided in the preceding paragraph,
subject to execution by the person being indemnified of a written
undertaking to repay such amount if and to the extent that it
shall ultimately be determined by a court that such
indemnification by the Company is not permitted under applicable
law.
It is the intention of the Company that the indemnification
set forth in this Section 9 of Article II, shall be applied to no
less extent than the maximum indemnification permitted by law.
In the event that any right to indemnification or other right
hereunder may be deemed to be unenforceable or invalid, in whole
or in part, such unenforceability or invalidity shall not affect
any other right hereunder, or any right to the extent that it is
not deemed to be unenforceable. The indemnification provided
herein shall be in addition to, and not exclusive of, any other
rights to which those indemnified may be entitled under any by-
law, agreement, vote of stockholders, or otherwise, and shall
continue as to a person who has ceased to be a director, officer,
employee, or agent and inure to the benefit of such person's
heirs, executors, and administrators.
SECTION 10. The Board of Directors may, in its
discretion, at any time elect one or more persons to the
position of Advisory Director, to serve as such during
the pleasure of the Board, but, except for a director
who has served as Chief Executive Officer, no person
<PAGE>
9
shall be eligible to serve as an Advisory Director beyond the
next annual meeting after he shall have attained his seventy-
second birthday. Advisory Directors so elected by the Board
shall be entitled to attend, and take part in discussions at,
meetings of the Board of Directors, but shall not be considered
members of the Board for quorum or voting purposes. Advisory
Directors shall receive the same compensation as members of the
Board.
SECTION 11. In any proceeding brought by a stockholder in
the right of the Company or brought by or on behalf of the
stockholders of the Company, no monetary damages shall be
assessed against an officer or director. The liability of an
officer or director shall not be limited as provided in this
section if the officer or director engaged in willful misconduct
or a knowing violation of the criminal law.
ARTICLE III
OFFICERS
SECTION 1. The Board of Directors, as soon as reasonably
practicable after the initial election of directors by
stockholders in each year, may elect a Chairman of the Board as
an officer of the Company, shall elect a President, may elect one
or more Vice Chairmen and shall elect one or more Vice Presidents
(who may be given such other descriptive titles as the Board may
specify), a Secretary, a Treasurer and a Comptroller, and from
time to time may elect such Assistant Secretaries, Assistant
Treasurers, Assistant Comptrollers and other officers, and
appoint such other agents, as it may deem desirable. Any two or
more offices may be held by the same person, except the offices
of President and Secretary. The Board of Directors shall elect
the Chairman of the Board or one of the above officers Chief
Executive Officer of the Company.
SECTION 2. The term of office of all officers shall be
until the next succeeding annual election of officers and until
their respective successors shall have been elected and
qualified; but any officer or agent elected or appointed by the
Board of Directors may be removed, with or without cause, by the
affirmative vote of a majority of the members of the Board
whenever in their judgment the best interests of the Company will
be served thereby. Such removal shall be without prejudice to
contract rights, if any, of the person so removed. Election or
appointment of an officer or agent shall not of itself create
contract rights. Unless specifically authorized by resolution of
the Board of Directors, no agreement for the employment of any
officer for a period longer than one year shall be made.
SECTION 3. Subject to such limitations as the Board of
Directors or the Executive Committee may from time to time
prescribe, the officers of the Company shall each have such
authority and perform such duties in the management of the
property, business and affairs of the Company as by custom
generally pertain to their respective offices, as well as
<PAGE>
10
such authority and duties as from time to time may be conferred
by the Board of Directors, the Executive Committee or the Chief
Executive Officer.
SECTION 4. The salaries of all officers, employees and
agents of the Company shall be determined and fixed by the Board
of Directors, or pursuant to such authority as the Board may from
time to time prescribe.
ARTICLE IV
CERTIFICATES OF STOCK
SECTION 1. The shares of the capital stock of the Company
shall be represented by certificates, provided that the Board of
Directors of the Company may provide by resolution that some or
all of the shares of any or all of its classes or series of
capital stock may be uncertificated shares. Except as otherwise
expressly provided by law, the rights and obligations of the
holders of uncertificated shares and the rights and obligations
of the holders of certificates representing shares of the same
class and series shall be identical. Shares of the capital stock
of the Company that are evidenced by certificates shall be in
such form as the Board of Directors may from time to time
prescribe. Such certificates shall be signed by the President or
a Vice President and by the Secretary or an Assistant Secretary,
shall be sealed with the seal of the Company, or a facsimile
thereof, shall be countersigned and registered in such manner, if
any, as the Board may by resolution prescribe. Where such a
certificate is countersigned by a transfer agent (other than the
Company or an employee of the Company), or by a transfer clerk
and registered by a registrar, the signatures thereon of the
President or Vice President and the Secretary or Assistant
Secretary may be facsimiles. In case any officer who has signed
or whose facsimile signature has been placed upon any such
certificate shall have ceased to be such officer before such
certificate is issued, it may be issued by the Company with the
same effect as if such officer had not ceased to hold such office
at the date of its issue.
SECTION 2. The shares of the capital stock of the Company
shall be transferable on the books of the Company by the holders
thereof in person or by duly authorized attorney, and, if
represented by certificates, upon surrender and cancellation of
the certificates evidencing such shares, with duly executed
assignment and power of transfer endorsed thereon or attached
thereto, and with such proof of the authenticity of the
signatures as the Company or its agents may reasonably require
and, if uncertificated, upon receipt of appropriate instructions.
SECTION 3. No certificate evidencing shares of the
capital stock of the Company shall be issued in place of
any certificate alleged to have been lost, stolen, or
destroyed, except upon production of such evidence of
the loss, theft or destruction, and upon such
<PAGE>
11
indemnification of the Company and its agents by such person or
persons and in such manner, as the Board of Directors may from
time to time prescribe.
ARTICLE V
CHECKS, NOTES, CONTRACTS, ETC.
All checks and drafts on the Company's bank accounts, bills
of exchange, promissory notes, acceptances, obligations, other
instruments for the payment of money, and endorsements other than
for deposit in a bank account of the Company shall be signed by
the Treasurer or an Assistant Treasurer and shall be
countersigned by the Chief Executive Officer, the President, a
Vice Chairman or a Vice President, unless otherwise authorized by
the Board of Directors; provided that checks drawn on the
Company's dividend and/or special accounts may bear the manual
signature, or the facsimile signature, affixed thereto by a
mechanical device, of such officer or agent as the Board of
Directors shall authorize.
All contracts, bonds and other agreements and undertakings
of the Company shall be executed by the Chief Executive Officer,
the President, a Vice Chairman or a Vice President and by such
other officer or officers, if any, as may be designated, from
time to time, by the Board of Directors and, in the case of any
such document required to be under seal, the corporate seal shall
be affixed thereto and attested by the Secretary or an Assistant
Secretary.
Whenever any instrument is required by this Article to be
signed by more than one officer of the Company, no person shall
so sign in more than one capacity.
ARTICLE VI
FISCAL YEAR
The fiscal year of the Company shall begin on the first day
of January in each year and shall end on the thirty-first day of
December following.
ARTICLE VII
OFFICES
The principal office of the Company shall be situated
in the District of Columbia. The registered office of
the Company in Virginia shall be situated in the County
of Fairfax. The Company may have such other offices
at such places, within the District of Columbia, the
<PAGE>
12
Commonwealth of Virginia, or elsewhere, as shall be determined
from time to time by the Board of Directors or by the Chief
Executive Officer.
ARTICLE VIII
AMENDMENTS
Except as otherwise provided by law, the Board of Directors
may alter, amend, or repeal the By-Laws of the Company, or adopt
new By-Laws, at any meeting of the Board, by the affirmative vote
of not less than the number of directors necessary to constitute
a quorum of the Board.
<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-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> SEP-30-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,424,603
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 477,825
<TOTAL-DEFERRED-CHARGES> 713,236
<OTHER-ASSETS> 1,198,496
<TOTAL-ASSETS> 6,814,160
<COMMON> 118,501
<CAPITAL-SURPLUS-PAID-IN> 1,010,252
<RETAINED-EARNINGS> 815,448
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,944,201
141,000
125,291
<LONG-TERM-DEBT-NET> 1,727,707
<SHORT-TERM-NOTES> 0<F1>
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 277,075<F1>
<LONG-TERM-DEBT-CURRENT-PORT> 50,000
985
<CAPITAL-LEASE-OBLIGATIONS> 161,057
<LEASES-CURRENT> 20,772
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,366,072
<TOT-CAPITALIZATION-AND-LIAB> 6,814,160
<GROSS-OPERATING-REVENUE> 1,473,073
<INCOME-TAX-EXPENSE> 115,280
<OTHER-OPERATING-EXPENSES> 1,068,451
<TOTAL-OPERATING-EXPENSES> 1,183,731
<OPERATING-INCOME-LOSS> 289,342
<OTHER-INCOME-NET> 24,483
<INCOME-BEFORE-INTEREST-EXPEN> 313,825
<TOTAL-INTEREST-EXPENSE> 104,734
<NET-INCOME> 209,091
12,439
<EARNINGS-AVAILABLE-FOR-COMM> 196,652
<COMMON-STOCK-DIVIDENDS> 147,459
<TOTAL-INTEREST-ON-BONDS> 122,000<F2>
<CASH-FLOW-OPERATIONS> 317,930
<EPS-PRIMARY> $1.66
<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, 1997.
<F3>No material dilution would occur if all the convertible preferred stock and
debentures were converted into common stock.
</FN>
</TABLE>
