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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934 (FEE REQUIRED)
For the fiscal year ended December 31, 1993 Commission file number 1-1072
----------------- ------
Potomac Electric Power Company
- ------------------------------------------------------------------------------
(Exact name of registrant as specified in its charter)
District of Columbia and Virginia 53-0127880
- --------------------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1900 Pennsylvania Avenue, N. W.
Washington, D. C. 20068
- --------------------------------------------- -------------------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (202) 872-2456
-------------------
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
------------------- -----------------------------
First Mortgage Bonds, ) New York Stock Exchange, Inc.
9-3/4% Series due 2019 - )
due May 1, 2019 )
7% Convertible Debentures due 2018 - )
due January 15, 2018 )
5% Convertible Debentures due 2002 - )
due September 1, 2002 )
Continued
Name of each exchange on
Title of each class which registered
------------------- -----------------------------
Serial Preferred Stock, ) New York Stock Exchange, Inc.
$50 par value (entitled to )
cumulative dividends) )
$3.37 Series of 1987 )
$3.89 Series of 1991 )
$2.44 Convertible )
Series of 1966 )
Common Stock, $1 par value )
(The registrant's Common Stock is )
also listed on the Tokyo Stock )
Exchange) )
Securities registered pursuant to Section 12(g) of the Act:
None.
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 by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. .
---
As of March 8, 1994, Potomac Electric Power Company had 117,915,691
shares of its $1 par value Common Stock outstanding, and the aggregate market
value of these common shares (based upon the closing price of these shares on
the New York Stock Exchange on that date) held by nonaffiliates was
approximately $2.7 billion.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Company's 1993 Annual Report to shareholders are
incorporated by reference into Parts II and IV of this Form 10-K.
Portions of the Notice of Annual Meeting of Shareholders and Proxy
Statement, dated March 18, 1994, are incorporated by reference into Part III
of this Form 10-K.
2
POTOMAC ELECTRIC POWER COMPANY
Form 10-K - 1993
TABLE OF CONTENTS
PART I Page
Item 1 - Business ----
General ............................................................ 5
Sales .............................................................. 6
Capacity Planning .................................................. 7
Construction Program ............................................... 9
Fuel ............................................................... 11
Regulation ......................................................... 14
Rates .............................................................. 15
Environmental Matters .............................................. 19
Labor .............................................................. 23
Nonutility Subsidiary .............................................. 23
Item 2 - Properties .................................................. 25
Item 3 - Legal Proceedings ........................................... 26
Item 4 - Submission of Matters to a Vote of Security Holders ......... 27
PART II
Item 5 - Market for the Registrant's Common Equity and Related
Stockholder Matters ....................................... 27
Item 6 - Selected Financial Data ..................................... 28
Item 7 - Management's Discussion and Analysis of Financial Condition
and Results of Operations ................................. 28
Item 8 - Financial Statements and Supplementary Data ................. 28
Item 9 - Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure .................................. 28
PART III
Item 10 - Directors and Executive Officers of the Registrant ......... 29
Item 11 - Executive Compensation ..................................... 31
Item 12 - Security Ownership of Certain Beneficial Owners and
Management................................................ 32
Item 13 - Certain Relationships and Related Transactions ............. 32
PART IV
Item 14 - Exhibits, Financial Statement Schedules and Reports on
Form 8-K ................................................. 32
Exhibit 11 - Computation of Earnings Per Common Share ........... 39
Exhibit 12 - Computation of Ratios .............................. 40
Exhibit 22 - Subsidiaries of the Registrant ..................... 42
Exhibit 24 - Consent of Independent Accountants ................. 43
Report of Independent Accountants on Consolidated Financial
Statement Schedules .............................................. 44
Schedule V - Property, Plant and Equipment ...................... 45
Schedule VI - Accumulated Depreciation, Depletion and Amortization
of Property, Plant and Equipment ................. 48
Schedule VIII - Valuation and Qualifying Accounts .................. 51
Schedule IX - Short-Term Borrowings .............................. 52
Signatures ........................................................... 53
PAGE LEFT BLANK
INTENTIONALLY
4
Part I
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Item 1 BUSINESS
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GENERAL
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Potomac Electric Power Company (Company), which was incorporated in the
District of Columbia in 1896 and in the Commonwealth of Virginia in 1949, 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 the District of Columbia and major portions of
Montgomery and Prince George's counties in suburban Maryland. The area served
at retail covers approximately 640 square miles and had a population of
approximately 1.9 million at the end of 1993 and 1992. The Company also sells
electricity, at wholesale, to Southern Maryland Electric Cooperative Inc.
(SMECO), which distributes electricity in Calvert, Charles, Prince George's
and St. Mary's counties in southern Maryland. During 1993, approximately 59%
of the Company's revenues were derived from Maryland sales (including
wholesale) and 41% from sales in the District of Columbia. About 30% of the
Company's revenues were derived from residential customers, 64% from sales to
commercial and government customers and 6% from sales at wholesale.
Approximately 14% and 3% of 1993 revenues were derived from sales to the U.S.
and D.C. governments, respectively.
The Company holds valid franchises, permits and other rights adequate
for its business in the territory it serves, and such franchises, permits and
other rights contain no unduly burdensome restrictions.
The Company is a member of the Pennsylvania-New Jersey-Maryland
Interconnection (PJM) pursuant to an agreement under which its generating and
transmission facilities are operated on an integrated basis with those of the
other PJM member utilities in Pennsylvania, New Jersey, Maryland, Delaware and
a small portion of Virginia. The purpose of PJM is to improve the operating
economy and reliability of the systems in the group and to provide capital
economies by permitting lower reserve requirements than would be required on a
system basis. The Company also has direct high voltage connections with the
Potomac Edison Company and Virginia Electric and Power Company, neither of
which is a member of PJM.
5
SALES
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The following data presents the Company's sales and revenue by class of
service and by customer type, including data as to sales to the United States
and District of Columbia governments.
1993 1992 1991
---------- ---------- ----------
Electric Energy Sales (Thousands of Kilowatt-hours)
---------------------
Kilowatt-hours Sold - Total 25,693,999 24,484,444 24,796,279
========== ========== ==========
By Class of Service -
Residential service 6,739,987 6,155,793 6,503,105
General service 10,860,437 10,491,222 10,418,003
Large power service 5,232,380 5,183,560 5,261,308
Street lighting 163,827 163,739 161,577
Rapid transit 370,428 360,432 343,470
Wholesale 2,326,940 2,129,698 2,108,816
By Type of Customer -
Residential 6,726,520 6,142,414 6,488,294
Commercial 11,750,542 11,391,337 11,321,344
U.S. Government 3,986,149 3,947,611 4,016,129
D.C. Government 903,848 873,384 861,696
Wholesale 2,326,940 2,129,698 2,108,816
Electric Revenue (Thousands of Dollars)
----------------
Sales of Electricity - Total* $1,696,435 $1,556,098 $1,542,571
========== ========== ==========
By Class of Service -
Residential service $ 506,096 $ 433,648 $ 451,048
General service 747,237 705,178 681,182
Large power service 297,228 286,645 280,307
Street lighting 13,605 12,363 12,424
Rapid transit 24,107 22,914 20,913
Wholesale 108,162 95,350 96,697
By Type of Customer -
Residential $ 505,173 $ 432,797 $ 450,103
Commercial 791,357 748,550 724,039
U.S. Government 238,192 229,586 223,723
D.C. Government 53,551 49,815 48,009
Wholesale 108,162 95,350 96,697
* Exclusive of Other Electric Revenues of $6,007 in 1993, $6,069 in 1992 and
$9,495 in 1991.
6
The Company's sales of electric energy are seasonal, and, accordingly,
rates have been designed to closely reflect the daily and seasonal variations
in the cost of producing electricity, in part by raising summer rates and
lowering winter rates. Mild weather during the summer billing months of June
through October, when base rates are high to encourage customer conservation
and peak load shifting, has an adverse effect on revenues and, conversely, hot
weather during these months has a favorable effect.
Effective January 1, 1992, the Company changed its method of revenue
recognition to provide for the accrual of revenue for service rendered but
unbilled as of the end of the month. This change in accounting method has no
significant effect on revenue over a 12-month period. It affects the timing
of revenue recognition within the year, principally increasing revenues in the
second quarter and decreasing revenues in the fourth quarter.
The Company includes in revenues the amounts received for sales to other
utilities related to pooling and interconnection agreements. Amounts received
for such interchange deliveries are a component of the Company's fuel rates.
CAPACITY PLANNING
- -----------------
General
- -------
During the period 1994 through 2003 the Company estimates that its peak
demand will grow at a compound annual rate of approximately 1%. Based upon
average weather conditions, the Company expects its compound annual growth in
kilowatt-hour sales to range between 1% and 2% over the next decade. The
Company's ongoing strategies to meet the increasing energy needs of its
customers include conservation and energy use management programs which are
designed to curb growth in peak demand. The need for new capacity has been
further reduced by programs to maintain older generating units to ensure their
continued efficiency over an extended life and the cost-effective purchase of
capacity and energy.
Conservation and Energy Use Management Programs
- -----------------------------------------------
Cost-effective conservation programs have been a major component of the
Company's success in limiting the need for new construction during the past
decade.
The Company's conservation and energy use management 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. The Company offers an extensive array of
comprehensive conservation programs for its customers in the District of
Columbia and Maryland.
7
The Company's programs for residential customers include various types
of incentives to encourage the design of energy-efficient homes and the
purchase and installation of energy-efficiency measures. These incentives
include customer rebates for energy efficient appliances, bonuses to
contractors who build homes that meet high energy-efficiency standards,
coupons which offer significant discounts to customers who purchase energy-
efficient lights and water heater conservation measures and, commencing in
1993, a program to directly install, at no cost to the customer, lighting and
water heater tank wraps in single-family, apartment and condominium
residences. During 1993, the Company also initiated an appliance recycling
program for customers, by offering payments for inefficient, but still
functioning, refrigerators, air conditioners and freezers.
The Company's programs for commercial customers offer a variety of
approaches to encourage conservation, including design consultation and
technical assistance at no fee, equipment rebates to developers and designers,
cash incentives to customers who install energy-efficiency measures ranging
from lighting to efficient motors and equipment, and, for small commercial
customers, direct installation of efficient lighting and other measures at no-
cost to the customer. During 1993, as part of the Custom Rebate program, the
Company encouraged customers with older chillers to replace them with new high
efficiency chillers. Also, the Company began offering loans on a pilot basis
to commercial customers for efficiency improvements.
The Company continues to aggressively identify, design, and test
additional energy efficient conservation measures and technologies.
The Company receives rate recognition for the cost of its conservation
programs in its Maryland jurisdiction through a rate surcharge which permits
the Company to earn a return on its conservation investment while receiving
compensation for lost revenues. The cost recovery mechanism also allows the
Company to earn a performance bonus for exceeding established goals. The
surcharge is adjusted periodically to reflect the Company's growing
conservation commitment. The District of Columbia Public Service Commission
has established a framework which provides for a return on approved
conservation investments and incentives for achieving demand side management
goals within base rate cases.
During 1993, the Company also continued to operate and expand its energy
use management programs. In 1993, approximately 134,000 customers
participated in programs which cycle air conditioners and water heaters during
peak periods. In addition, the Company operates a commercial load program
which provides incentives to customers for reducing energy use during peak
periods. Time-of-use rates have been in effect since the early 1980s and
currently approximately 60% of the Company's revenues are based on time-of-use
rates.
8
It is estimated that peak load reductions of approximately 390 megawatts
have been achieved to date from conservation and energy use management
programs and that additional peak load reductions of over 500 megawatts will
be achieved in the next five years. The Company also estimates that energy
savings of more than 450 million kilowatt-hours have been realized through
operation of its conservation and energy use management programs through 1993.
During the next five years, the Company plans to expend an estimated $525
million to encourage the efficient use of electric energy and to reduce the
need to build new generating facilities.
Although the Company is expanding its conservation and energy use
management efforts, new sources of supply will be needed to assure the future
reliability of electric service to the Washington area. These new sources of
supply will be provided through the Company's plans for purchases of capacity
and energy and through its ongoing construction program.
Purchase of Capacity and Energy
- -------------------------------
Pursuant to the Company's 1987 long-term capacity purchase agreements
with Ohio Edison and Allegheny Power System, the Company is purchasing 450
megawatts of capacity and associated energy through the year 2005. In
addition, the Company has a 25-year agreement with SMECO, which began in 1990,
to purchase 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 Company has been exploring other cost-effective sources of energy
and has entered into contracts for two nonutility generation projects which
total 270 megawatts of capacity. In 1991, the Company signed an agreement
with Panda Energy Corporation for a 230-megawatt gas-fueled combined-cycle
cogeneration project in Prince George's County, Maryland, which is scheduled
for service in 1996. The project is currently before the Maryland Public
Service Commission for issuance of a certificate of convenience and necessity.
In addition, the Company has signed a contract for a 40-megawatt resource
recovery facility which is now under construction in Montgomery County,
Maryland. In November 1993, after failing to obtain final building permits
from the District of Columbia, Dominion Energy terminated its contract to
build a 56-megawatt combined-cycle cogeneration facility at Georgetown
University.
CONSTRUCTION PROGRAM
- --------------------
The Company carries on a continuous construction program, the nature and
extent of which is determined by the Company's strategic planning process
which integrates supply-side and demand-side resource options.
9
From January 1, 1991 to December 31, 1993, the Company made property
additions, net of an Allowance for Funds Used During Construction (AFUDC), of
$1 billion (of which $300 million were made in 1993) and had property
retirements of $122 million (of which $40 million were made in 1993).
The Company's current construction program calls for estimated
expenditures, excluding AFUDC, of $290 million in 1994, $280 million in 1995,
$240 million in 1996, $210 million in 1997 and $245 million in 1998, an
aggregate of $1.3 billion for the five-year period. AFUDC is estimated to be
$24 million in 1994, $11 million in 1995, $14 million in 1996, $19 million in
1997 and $23 million in 1998. The 1994-1998 construction program includes
approximately $618 million for generating facilities (including $203 million
for Clean Air Act compliance), $66 million for transmission facilities, $558
million for distribution, service and other facilities, and $23 million
associated with the Company's energy use management programs. Making use of
the flexibilities in its long-term construction plan, the Company reduced
projected expenditures for the five years 1994 through 1998 by a total of $315
million from amounts previously planned. The construction reductions and
deferrals were associated with lower rates of projected growth in usage of
electricity resulting in large part from implementing economical conservation
programs. The Company plans to finance its construction program through funds
provided by operations and external financing.
The construction program includes amounts for the construction of
facilities that will not be completed until after 1998. Although the program
includes provision for escalation of construction costs, generally at an
annual rate of 4%, the aggregate budget for long lead time projects will
increase or decrease depending upon the actual rates of inflation in
construction costs. The program is reviewed continuously and revised as
appropriate to reflect changes in projections of demand, consumption patterns
and economic trends.
On June 1, 1993, the Company placed in service the second element of a
combined-cycle unit, consisting of a 139-megawatt combustion turbine
generating unit, at the Dickerson Generating Station located in Montgomery
County, Maryland. The first 139-megawatt combustion turbine generating unit
was placed in service on June 1, 1992. The total cost of the two combustion
turbine units currently in service was $162 million. These generating units
are primarily fueled by natural gas but can also burn No. 2 fuel oil. The
Dickerson project plan provides for two combined-cycle units with the
capability of adding a coal gasification facility, should future unit price
differentials among coal, oil and gas make gasification economically
attractive. The Company's construction schedule is flexible in order to
accommodate changes in future growth and the addition of nonutility
generation. Currently, no additional units are scheduled for the Dickerson
combined-cycle project until after the year 2003.
The Clean Air Act Amendments of 1990 (CAA) requires utilities to reduce
emissions of sulfur dioxide and nitrogen oxides in two phases, January 1995
(Phase I) and January 2000 (Phase II). The Company has developed plans for
complying with the CAA to achieve prescribed standards in Phases I and II.
10
The Company anticipates capital expenditures totaling $203 million over the
next five years pursuant to these plans. The plans call for replacement of
boiler burner equipment for nitrogen oxides emissions control, the use of
lower-sulfur fuel and cofiring with natural gas at selected baseload plants.
The CAA allows companies to achieve required emission levels by using a
market-based emission allowance trading system. If economical, emission
allowances may be purchased in lieu of burning lower-sulfur fuel.
The Company owns a 9.72% undivided interest in the Conemaugh Generating
Station located in western Pennsylvania. As a result of installing flue gas
scrubbing equipment to meet Phase I requirements of the CAA, this station will
receive additional allowances. The Company's share of these "bonus"
allowances may be used to reduce the need for lower-sulfur fuel at its other
plants. The Company's share of the construction cost for the flue gas
scrubbing equipment is approximately $38 million.
Installation of scrubbers is not contemplated for the Company's wholly
owned plants. Both the District of Columbia and Maryland commissions have
approved the Company's plans for meeting Phase I requirements including cost
recovery of investment and inclusion of emission allowance expenses in the
Company's fuel adjustment clause.
The Company is participating in the construction of the final segments
of a 500,000 volt transmission line providing further links in the
transmission systems of the Company, Baltimore Gas and Electric Company and
Virginia Electric and Power Company (Virginia Power). The Company's
construction schedule contemplates completion of the final segments in 1994.
FUEL
- ----
For customer billing purposes, all of the Company's kilowatt-hour sales
are covered by separately stated fuel rates (see Item 8 - Note 2 of "Notes to
Consolidated Financial Statements").
11
The Company's generating units burn only fossil fuels. The principal
fuel is coal. The Company owns no nuclear generation facilities and none are
planned. The following table sets forth the quantities of each type of fuel
used by the Company in the years 1993, 1992 and 1991 and the contribution, on
the basis of Btus, of each fuel to energy generated.
1993 1992 1991
-------------- -------------- --------------
% of % of % of
Quantity Btu Quantity Btu Quantity Btu
-------- ----- -------- ----- -------- -----
Coal
(000s net tons) 6,010 79.4 5,926 82.9 6,471 81.7
Residual oil
(000s barrels) 4,835 15.9 3,294 11.4 3,895 12.2
Natural gas
(000s dekatherms) 6,090 3.2 8,200 4.5 9,933 4.9
No. 2 fuel oil
(000s barrels) 480 1.5 376 1.2 407 1.2
The following table sets forth the average cost of each type of fuel
burned, for the years shown.
1993 1992 1991
------ ------ ------
Coal: per ton $43.69 $43.66 $45.37
per million Btu 1.72 1.72 1.78
Residual oil: per barrel 15.09 14.35 15.99
per million Btu 2.39 2.28 2.54
Natural gas: per dekatherm 2.88 2.32 2.18
per million Btu 2.88 2.32 2.18
No. 2 fuel oil: per barrel 24.98 26.70 29.07
per million Btu 4.30 4.60 5.01
The average cost of fuel burned per million Btu was $1.90 in 1993,
compared with $1.85 in 1992 and $1.93 in 1991. The increase of approximately
3% in the 1993 system average unit fuel cost compared with the 1992 system
average resulted from increased use of major cycling and peaking generation
units which burn higher cost fuels. The Company's major cycling and certain
peaking units can burn natural gas or oil, adding flexibility in selecting the
most cost-effective fuel mix.
Ten of the Company's sixteen steam-electric generating units can burn
only coal; two can burn only residual oil; two can burn either coal or
residual oil or a combination of both and two units can burn either residual
oil or natural gas. Those units capable of burning either coal or residual
oil normally burn coal as their primary fuel. The Company also has combustion
12
turbines, some of which can burn only No. 2 fuel oil, and others which can
burn natural gas or No. 2 fuel oil. During 1993, the new Dickerson combustion
turbine units resulted in the displacement of generation from older, less
cost-effective units. The following table provides details of the Company's
generating capability from the standpoint of plant configuration as well as
actual energy generation (see "Item 2 -Properties" for additional information
on type of fuel used in generating facilities).
Net Generating Net
Capability and Energy
Purchased Capacity Generated
------------------ ------------------
1993 1992 1991 1993 1992 1991
---- ---- ---- ---- ---- ----
Steam Generation
Dual fuel units, capable
of burning coal, residual
oil or a combination of
coal and residual oil.... 18% 18% 19% 29% 27% 29%
Units capable of burning
coal only................ 28% 29% 30% 45% 50% 47%
Units capable of burning
residual oil only........ 8% 9% 9% 1% - 1%
Units capable of burning
residual oil or natural
gas...................... 19% 19% 19% 10% 9% 10%
Combustion Turbines
Units capable of burning
No. 2 fuel oil only...... 9% 9% 9% )
Units capable of burning ) 2% 1% 1%
No. 2 fuel oil or natural )
gas...................... 11% 9% 7% )
Purchased capacity........... 7% 7% 7% 13%(a) 13%(a) 12%(a)
(a) Includes purchases under cogeneration agreements.
The Company's fuel mix objective is to obtain a minimum unit cost of
energy through the use of its generating facilities. The actual use of coal,
oil and natural gas is influenced by the availability of the generating units,
the relative cost of the fuels, energy and demand requirements of other
utilities with which the Company has interconnection arrangements, regulatory
requirements (for future units), weather conditions and fuel supply
constraints, if any.
13
The Company has several intermediate and long-term coal contracts with
various expiration dates through 2003 for aggregate annual deliveries of
approximately 4.3 million tons. Deliveries under these contracts are expected
to provide approximately 75% of the estimated system coal requirements in
1994. Approximately 25% of the estimated system coal requirements in 1994
will be purchased under shorter term agreements and on a spot basis from a
variety of suppliers. Prices under the Company's intermediate and long-term
coal contracts are generally determined by reference to base amounts adjusted
to reflect provisions for changes in suppliers' costs, which in turn are
determined by reference to published indices and limited by current market
prices.
Most of the coal currently used by the Company is surface mined in
Pennsylvania, West Virginia and Maryland. The Company believes that it will
be able to continue to obtain the quantities of coal needed to operate at its
current fuel mix objective. The costs of coal to the Company may be affected
by increases in the costs of production, including the costs of complying with
federal legislation (such as amendments to the CAA, discussed above, the costs
of surface mining reclamation and black lung benefits), the imposition of (or
changes in) state severance taxes and by modification of contracts with
Conrail, CSX Transportation and Norfolk Southern which cover all of the coal
movements to the Company's generating stations.
The Company purchases both domestically refined and imported residual
oil. Residual oil is being obtained under one two-year and one one-year
contract. Prices under the contracts are determined by reference to base
contract prices, as adjusted to reflect current market prices. Prior to
expiration of the contracts, the Company expects to solicit bids for new
contracts to supply its residual oil requirements. The Company also purchases
No. 2 fuel oil under two one-year contracts.
Certain units at the Company's Chalk Point Generating Station and the
new Dickerson combustion turbine units are capable of burning natural gas as
well as oil. The Company has a contract with Washington Gas Light Company for
Chalk Point extending through April, 1995. The Company has a one-year
contract with Consolidated Natural Gas for the Dickerson combustion turbine
units through March 31, 1994. Competitive proposals are currently under
review for a one year term contract to commence April 1, 1994. Both contracts
are for an interruptible supply of natural gas with provisions for price
review and adjustment each month. The actual use of natural gas for these
units will be dependent upon operational requirements, the relative costs of
natural gas and oil, and the availability of natural gas.
REGULATION
- ----------
The Company's utility operations are regulated by the Maryland and
District of Columbia public service commissions and, as to its wholesale
business, the Federal Energy Regulatory Commission (FERC). In addition, in
certain limited respects relating to its participation in the Conemaugh
Generating Station and related transmission lines, the Company is subject to
regulation by the Pennsylvania Public Utility Commission.
14
The Company's operations are subject to certain portions of the National
Energy Act designed to promote the conservation of energy and the development
and use of more plentiful domestic fuels through various regulatory and tax
provisions. The legislation, among other things, requires states to develop
residential energy conservation plans and requires utilities to enter into
cogeneration purchases with operators of qualified facilities. To date, this
legislation has fostered nonutility generation (cogeneration and solid waste
fired generation) supplying the Company with approximately 8 megawatts. As
noted above under "Purchase of capacity and energy," the Company is planning
additional cost-effective nonutility generation projects.
RATES
- -----
General
- -------
The Company's retail rates for electric service in Maryland and the
District of Columbia are based on allowed rates of return to the Company's
jurisdictional original cost rate base investments as determined in base rate
proceedings before the regulatory commissions by reference to the test periods
used in setting rates. Rate base in each of these jurisdictions generally has
included (1) the Company's full investments in Electric Plant in Service (net
of depreciation, certain pre-1981 investment tax credits and plant related
deferred income taxes), Electric Plant Held for Future Use and the pollution
control portion of Construction Work in Progress (CWIP), (2) inventories of
fuels and other materials and supplies and (3) an allowance for cash working
capital. The Company has employed, since 1978, Allowance for Funds Used
During Construction (AFUDC) accounting. In general, the Company capitalizes
AFUDC with respect to investments in CWIP 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. In 1992, pursuant to orders from both the Maryland
and District of Columbia commissions, the Company commenced the accrual of a
capital cost recovery factor on the retail jurisdictional portion of certain
pollution control projects related to compliance with the CAA. The base for
calculating this return is the amount by which the retail jurisdictional CAA
expenditure balance exceeds the CAA balance included in rate base in the
Company's most recently completed base rate proceeding. The jurisdictional
AFUDC capitalization rates are determined on a gross basis pursuant to
formulas prescribed by the FERC. The effective capitalization rates were
approximately 8.7% in 1993 and 9.1% in 1992 and 1991, compounded semiannually.
15
Rate orders received by the Company during the past three years provided
for increases (decreases) in annual base rate revenues as shown in the table
below.
Rate
Increase
(Decrease) % Effective
Regulatory Jurisdiction ($000) Change Date
-------------------------- ---------- ---------- ---------------
District of Columbia $25,400 3.8% March/June 1994
Federal-Wholesale 2,600 2.3 January 1994
Maryland 27,000 3.0 November 1993
Federal-Wholesale 3,801 3.1 January 1993
Maryland 25,300 3.0 1992/1993 (a)
District of Columbia 30,380 4.6 July 1992
Federal-Wholesale 2,814 2.6 January 1992
District of Columbia 19,740 3.3 October 1991
Maryland 19,724 2.6 June 1991
Federal-Wholesale (502) (.5) January 1991
(a) See Maryland discussion below.
Fuel Rates
- ----------
The Company has separately stated fuel rates in each jurisdiction. Such
rates include the delivered cost of fuel and the applicable costs and/or
credits from the interchange of energy with other electric utilities, to the
extent not provided for in base rates (see Item 8 - Note 2 of "Notes to
Consolidated Financial Statements").
Maryland
- --------
In October 1993, pursuant to a settlement agreement, the Commission
authorized a $27 million, or 3%, increase in base rate revenues effective
November 1, 1993. The settlement included a new system composite depreciation
rate of approximately 3.1%, up from the 3% rate previously in effect. Prior
to the settlement, the Company had filed updated cost of service data which
demonstrated a need for a $49.9 million increase in Maryland base rate
revenue, based upon the requested return of 9.89% on average rate base
including a 12.75% return on common stock equity, 1993 federal tax legislation
and the completed separate depreciation case. In connection with the
settlement agreement, no determination was made with respect to rate of
return. The rate of return on common stock equity most recently determined
for the Company in a fully litigated rate case was 12.75% established by the
Commission in a June 1991 rate increase order.
In October 1992, pursuant to a settlement agreement, the Commission
authorized an increase in base rate revenues of approximately 3% with $18
million effective December 1, 1992, and $7.3 million effective June 1, 1993.
No determination with respect to rate of return was specified.
16
District of Columbia
- --------------------
On March 4, 1994, the Commission authorized a $25.4 million, or 3.8%,
increase in base rate revenues. Of the total increase, $23.2 million became
effective March 16, 1994. The remaining $2.2 million is scheduled to become
effective on June 5, 1994, contingent on the June 1, 1994 in-service date of
the final segment of a 500-kilovolt transmission line between the Company and
Baltimore Gas & Electric Company. The authorized rates are based on a 9.05%
rate of return on average rate base, including an 11% return on common stock
equity. The Commission approved the Company's proposal for including future
changes in purchased capacity costs in fuel adjustment clause billings. In
addition, the Commission reversed its longstanding practice of including
Electric Plant Held for Future Use in rate base and ordered the Company to
accrue AFUDC on plant held for future use. The order increased test period
revenues by $3 million, which reduced the Company's revenue requirement, to
reflect 20% of the cumulative effect of a 1992 accounting change related to
unbilled revenues applicable to the District of Columbia. The Commission
rejected the Company's proposed Demand Side Management (DSM) surcharge.
Consistent with prior decisions, the order included $5.3 million in base rates
to recognize DSM program costs without provision for lost revenues between
rate cases. In addition, the Commission found that the Company had not
adequately supported $5.5 million, or 25% of conservation expenditures during
the test year. Subsequent to the test period in the case, the Company has
expended approximately $20 million on conservation in the District of
Columbia. The Company is considering available alternatives, including
reconsideration of the decision. A Commission decision on reconsideration
would be expected by early May 1994.
The Company had been seeking a $55.4 million, or 8.2%, increase in base
rate revenue, based upon a return of 9.46% on average rate base including an
11.8% return on common stock equity. On June 4, 1993, the Company had filed a
base rate application requesting a $72.6 million increase in base rate revenue
based upon a requested return of 9.84% on average rate base including a 12.35%
return on common stock equity. The Company updated its initial June 1993 cost
of service data filing to reflect subsequent events such as final federal tax
legislation changes, the effects of a new three year labor agreement with its
union employees, the settlement of the United Mine Workers strike as it
related to the Company's coal inventory, cost of service revisions and an
updated cost of capital study. The requested increase in annual base rate
revenues was predicated on adoption by the Commission of the Company's
ratemaking proposal with respect to the demand side management program costs,
including treatment of lost revenues.
In June 1992, the Commission authorized a $30.4 million, or 4.6%,
increase in base rate revenues effective July 7, 1992. The authorized rates
are based on a 9.96% rate of return on average rate base, including a 12.35%
return on common stock equity. The Commission also approved a procedure for
deferring purchased capacity cost increases between rate cases, accruing a
return on the deferred amounts, and including such deferred amounts in
determining revenue requirements in future rate proceedings. In February
17
1993, the Commission adopted a surcharge mechanism, to become effective
following the Company's next base rate case discussed above, for recovery of
the capital cost carrying charges on CAA compliance costs between rate
proceedings. The Company is authorized to accrue a capital cost recovery
factor on applicable CAA costs while the surcharge rate is effective.
Wholesale
- ---------
The Company has a 10-year full service power supply contract with SMECO,
a wholesale customer. The contract period is to be extended for an additional
year on January 1 of each year, unless notice is given by either party of
termination of the contract at the end of the 10-year period. The full
service obligation can be reduced by SMECO by up to 20% of its annual
requirements with a five-year advance notice for each such reduction.
SMECO rates were increased by $3.8 million and $2.8 million effective
January 1, 1993 and 1992, respectively.
In November 1993, the Company amended its contract with SMECO to provide
for rate increases of $2.6 million, $2.3 million and $4.2 million effective
January 1, 1994, 1995 and 1996, respectively.
Interchange of Power
- --------------------
The Company's generating and transmission facilities are interconnected
with the other members of PJM and other utilities. The pricing of most PJM
internal economy energy transactions is based upon "split savings" so that the
price of such energy is halfway between the cost that the purchaser would
incur if the energy were supplied by its own sources and the cost of
production to the company actually supplying the energy.
The Company has interconnection agreements with Allegheny Power System
(APS) and Virginia Power. These agreements provide a mechanism and the
flexibility to purchase power from these parties or from others with whom they
are interconnected on an as-needed basis in amounts mutually agreed to from
time-to-time pursuant to negotiated rates, terms and conditions.
Pursuant to the Company's long-term capacity purchase agreements with
Ohio Edison and APS, the Company is purchasing 450 megawatts of capacity and
associated energy through the year 2005. The cost of capacity under these
agreements increased from $12,380 per megawatt, per month, in 1993 to $18,060
per megawatt, per month, effective January 1, 1994, plus an allocation of
fixed operating and maintenance expenses, with provision for escalation in
1999.
The Company began a 25-year purchase agreement in 1990 with SMECO 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 $462,000 per month.
18
ENVIRONMENTAL MATTERS
- ---------------------
General
- -------
The Company is subject to federal, state and local legislation and
regulation with respect to environmental matters, including air and water
quality and the handling of solid and hazardous waste. Air quality
requirements relate to both ambient air quality and emissions from facilities,
including particulate matter, sulfur dioxide, nitrogen oxides, carbon
monoxide, volatile organic compounds and visible emissions. Water quality
requirements relate to intake and discharge of water from facilities,
including water used for cooling purposes in electric generating facilities.
Waste requirements relate to the generation, treatment, storage,
transportation and disposal of specified wastes. Compliance with such
requirements may limit or prevent certain operations or substantially increase
the cost of construction and operation of the Company's existing and future
generating installations. The Company has expended approximately $462 million
through December 31, 1993, for the construction of pollution control
facilities. The $618 million 1994-1998 construction program for generating
facilities includes estimated provision for pollution control facilities,
including expenditures for CAA compliance, of $78 million for 1994, $67
million for 1995, $44 million for 1996, $45 million for 1997 and $56 million
for 1998. The Company is unable to predict the future course of environmental
regulations generally, the manner in which compliance with such regulations
will be required, the availability of technology to meet such regulations and
any budget amendments which may be required to recognize the costs which may
ultimately be associated with such compliance.
Air Quality
- -----------
Under authority of the Clean Air Act of 1970, as amended, the U.S.
Environmental Protection Agency (EPA) has issued national primary and
secondary standards for the following air pollutants: sulfur dioxide,
nitrogen dioxide, particulate matter, carbon monoxide, ozone and lead. EPA
has also enacted regulations designed to prevent significant deterioration of
air quality in areas where air quality levels are better than the secondary
ambient air quality standards. The appropriate agencies in Maryland, the
District of Columbia and Virginia have issued regulations designed to
implement EPA's standards and regulations.
In 1990, Congress enacted amendments to the CAA that require the
reduction of sulfur dioxide and nitrogen oxides emissions from electric
generating units. The Company cannot fully predict the financial and
operating effects of this new legislation until all of the related
implementing regulations are adopted by EPA and by appropriate agencies in
each of the jurisdictions where the Company's generating facilities are
located. However, the Company has developed cost-effective plans for
complying with the CAA to achieve prescribed standards in two phases.
19
The Company anticipates capital expenditures totaling $203 million over the
next five years. The plans call for replacement of boiler burner equipment
for nitrogen oxides emissions control, the use of lower-sulfur fuel and
cofiring with natural gas at selected baseload plants. The CAA allows
companies to achieve sulfur dioxide emission reduction requirements by using a
market-based emission allowance trading system. If economical, emission
allowances may be purchased in lieu of burning lower-sulfur fuel.
Maryland, the District of Columbia and Northern Virginia are members of
the Ozone Transport Commission, established by the CAA for the purpose of
developing a regional solution to attainment of the ambient ozone standard in
the northeastern United States. Those states are currently preparing rules
under Title I of the CAA which will require the retrofit of existing
generating units with Reasonably Available Control Technology (RACT) for
nitrogen oxides control by mid-1995. The Company has developed a plan whereby
the nitrogen oxides reductions already planned to be achieved by PEPCO under
Title IV of the CAA will also satisfy the states' requirements for RACT. This
plan will be undergoing regulatory review during 1994.
The Company is unaware in any respect in which its generating stations
are not presently in compliance with federal and state air quality
regulations, with the exception of visible emissions from the Dickerson
Station and Chalk Point Units 1, 2 and 4. The State of Maryland has adopted a
regulation which allows a case-by-case exception to visible emissions limits.
Recognizing that the specified units cannot continuously satisfy a standard
requiring no visible emissions, the Company is working with Maryland
regulators to establish revised visible emissions standards for the subject
units.
Water Quality
- -------------
The Company's generating stations operate under National Pollutant
Discharge Elimination System (NPDES) permits. NPDES renewal applications
submitted in March 1991 for the Morgantown station, December 1991 for the
Dickerson station, March 1992 for the Chalk Point station, April 1993 for the
Buzzard Point station, and July 1993 for the Benning station, are all pending.
An NPDES permit for the Potomac River Station was issued and effective as of
February 24, 1994.
The Maryland Department of the Environment promulgated regulations
effective April 16, 1990 that, among other things, set numeric criteria for
toxic substances in surface waters. These regulations are applicable to the
Company's Chalk Point, Morgantown and Dickerson generating stations. None of
the numeric criteria have been incorporated into the NPDES permits for these
stations at this time. While it is not known whether the criteria will be
included in the Company's permits in the future, or, if included, what the
economic impact will be, it has been preliminarily estimated that if the
regulations are interpreted in the manner most detrimental, the Company could
incur capital costs of as much as $810 million and annual operating and
20
maintenance expenses of $224 million in order to comply with these
regulations. The Company, in conjunction with other utilities, industrial
companies, and the Maryland Chamber of Commerce, filed a suit in May 1990 that
challenges the validity of the regulations. The suit is pending in the
Circuit Court for Baltimore City. The parties have reached settlement of the
suit contingent upon the outcome of subsequent rulemaking proceedings.
Revised regulations were adopted on May 6, 1993 in accordance with the
settlement agreement. EPA approval of the revised regulations is pending.
On March 18, 1993, the Company brought to the attention of state and
federal authorities information discovered in an internal Company
investigation to the effect that one of the Company's NPDES permits may have
been violated by the pumping of water from a settlement pond at a Company-
owned flyash storage facility. Further investigation both internally and by
the governmental authorities has continued, including issuance of, and
response by the Company to, a federal grand jury subpoena for documents
germane to the investigation and testimony of two Company employees before the
grand jury.
Toxic Substances
- ----------------
The Company was notified by the EPA on December 18, 1987, that it, along
with five other utilities and eight non-utilities, is a potentially
responsible party (PRP) under the Comprehensive Environmental Response,
Compensation and Liability Act of 1980, as amended (CERCLA or Superfund), in
connection with the polychlorinated biphenyl compounds (PCBs) contamination of
soil, ground water and surface water occurring at a Philadelphia, Pennsylvania
site owned by an unaffiliated company. Additional PRPs have since been
identified and the number is continuously subject to change. In the early
1970s, the Company sold scrap transformers, some of which may have contained
some level of PCBs, to a metal reclaimer operating at the site. The Company
and nine other PRPs executed an Administrative Order by Consent (ACO) with the
EPA and the performance of a Remedial Investigation/ Feasibility Study (RI/FS)
is in progress. Pursuant to an agreement among the participating PRPs, the
Company is responsible for 12% of the costs of the RI/FS. It is currently
estimated that the PRPs' cost of compliance with the ACO, including the RI/FS
and legal fees, will be approximately $6.5 million. The Company has paid
$548,000 to date. The Company cannot estimate the extent of the EPA's
administrative and oversight costs or the expense associated with a site
remedy ultimately acceptable to the EPA.
On September 19, 1989, an unaffiliated company, the Richmond,
Fredericksburg and Potomac Railroad (RF&P), requested the Company to
participate in the investigation and remediation of a 3-acre site in
Arlington, Virginia owned by RF&P at which it is alleged that soil and
groundwater have been contaminated by PCB compounds. Subsequently, the
Virginia Department of Waste Management requested information from the Company
related to transformers which may have been sold or sent to the site operator.
21
On December 7, 1990, a Summons and Complaint filed by RF&P in the United
States District Court for the Eastern District of Virginia against the Company
and seven other defendants was received. The Complaint alleges that the
defendant site operator released PCBs and other hazardous substances at the
site during the course of its operation, and that the sole source of PCBs and
other hazardous substances is from the defendant operator's operations and
from transformers and capacitors supplied by other defendants. Subsequently,
additional defendants were added to the Complaint. The Complaint seeks
contribution and other equitable remedies for remediation of the site. In
October 1993, the parties reached a settlement which was approved by the Court
on October 25, 1993 subject to confirmation by additional site testing that
remediation can be accomplished at or below, and that no regulatory authority
will require a remediation which exceeds, approximately $4 million.
During 1993, the Company participated with two other PRPs in a removal
action at a site in Harmony, West Virginia pursuant to an Administrative Order
(AO) issued by the EPA. Approximately $3 million (of which the Company has
paid one-third, subject to possible reallocation) was expended on the removal
action, which the EPA has stated is in compliance with the AO. Approximately
$1.9 million of this cost has now been recovered from third parties. EPA
oversight costs, which are not expected to be material, have not yet been
assessed. While compliance with the AO has been completed, the Company cannot
determine whether it will be subject to any future liability with respect to
the site.
In August 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 Cases." The Company (and other defendants) were
brought into these cases on a theory of premises liability under which
plaintiffs argue that the Company was negligent in not providing a safe work
environment for employees of its contractors who allegedly were exposed to
asbestos while working on the Company's property. Initially, a total of
approximately four hundred and forty-eight (448) individual plaintiffs added
the Company to their Complaints. While the pleadings are not entirely clear,
it appears that each plaintiff seeks $2 million in compensatory damages and $4
million in punitive damages from each defendant. In a related proceeding in
the Baltimore City case, the Company was served, in September 1993, with a
third party complaint by Owens Corning Fiberglass, Inc. (Owens Corning)
alleging that Owens Corning was in the process of settling approximately 700
individual asbestos-related cases and seeking a judgment for contribution
against the Company on the same theory of alleged negligence set forth above
in the plaintiffs' case. Subsequently, Pittsburgh Corning Corp. (Pittsburgh
Corning) filed a third party complaint against the Company, seeking
contribution for the same plaintiffs involved in the Owens Corning third party
complaint. Since the filings, a number of the individual suits have been
disposed of without any payment by the Company. On March 14, 1994, the
Company and Pittsburgh Corning filed a Joint Stipulation of Dismissal of the
Pittsburgh Corning third party complaint, which dismissal would require no
payment by the Company. While the aggregate amount specified in the remaining
suits would exceed $1 billion, the Company believes the amounts are greatly
22
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.
Solid and Hazardous Waste
- -------------------------
The Resource Conservation and Recovery Act of 1976 (RCRA) provides
federal mandates and authority for dealing with the generation, treatment,
storage, transportation and disposal of solid or hazardous waste. The
principal utility wastes of fly ash, bottom ash and scrubber sludge are exempt
from EPA regulation as hazardous waste. The Company sends its wastes
designated as hazardous to appropriately licensed facilities for hazardous
waste treatment, storage and disposal. The current impact of regulations
under RCRA is not substantial. The only permit which will be required at this
time is for the Morgantown Generating Station, where the Company burns certain
amounts of PCB-contaminated mineral oil. Maryland regulations provide for a
special "limited facility permit" for this activity and the Company's
application for such permit is pending.
LABOR
- -----
A new three-year Agreement between the Company and Local 1900 of the
International Brotherhood of Electrical Workers (IBEW) was ratified on July
20, 1993 by Union members. The total package, including wage and benefit
changes, will increase costs by 6.1% over the three-year period. The
Agreement includes several changes that will reduce the Company's cost of its
post-retirement benefit obligations. At December 31, 1993, 2,940 of the
Company's 4,893 employees were represented by the IBEW.
NONUTILITY SUBSIDIARY
- ---------------------
Potomac Capital Investment Corporation (PCI), the Company's principal
wholly-owned subsidiary, was formed in late 1983 to provide a vehicle for
ongoing nonutility investment business. PCI's objective is to provide an
annual supplement to utility earnings and to build long-term shareholder
value.
At December 31, 1993, PCI's assets totaled $1.7 billion, including $924
million in finance and operating equipment leases and $466.2 million in
marketable securities, principally investment grade sinking fund preferred
stock. The Company's equity investment in PCI was $290.9 million, including
$145.2 million of subsidiary retained earnings. Additional financial
information concerning assets, income, expenses and net earnings is presented
in the consolidated financial statements incorporated by reference in Item 8.
23
PCI's equipment-leasing portfolio consists primarily of wide-body
commercial aircraft and satellite communications equipment. Income from
leasing activities includes rental and interest income, gains on asset sales
and service fees. Additional information concerning leasing activities is
presented in Management's Discussion and Analysis incorporated by reference in
Item 7.
PCI's real estate activity consists of real estate projects and holdings
in the Washington metropolitan area. PCI also owns leasehold interests in oil
and natural gas producing properties in Texas.
24
Part I
- ------
Item 2 PROPERTIES
- ------ ----------
Megawatts of Net Capability
Steam --------------------------- Net Megawatt-
Generation Steam
Combustion Hours Generated Generating Station Location
Primary Fuel Generation Turbine in 1993 ----------
- -------- --------------------------------------- -------------- ------------
- ------------ ---------------
(Thousands)
Benning Benning Road and
Anacostia River, N.E. No. 4 Oil 550 -
185 Washington, D.C.
Buzzard Point 1st and V Streets, S.W. -
- 256 4 Washington, D.C.
Potomac River Bashford Lane and Potomac River Coal
482 - 2,090 Alexandria,
Virginia
Dickerson Potomac River, South of Little Monocacy Coal
546 291 3,516 River, Dickerson,
Maryland
Chalk Point Patuxent River at Swanson Creek Coal/
1,907 516 5,851 Aquasco, Maryland
Residual Oil/
Natural Gas
Morgantown Potomac River, South of Route 301 Coal/
1,164 248 6,443 Newburg, Maryland
Residual Oil
----------- ----------- -----------
Total - Wholly owned Units
4,649 1,311 18,089
Conemaugh Indiana County, Pennsylvania Coal
165 1 1,056
----------- ----------- ----------
- - Total - All Stations Operated
4,814 1,312 19,145
=========== Purchased Capacity
450 - 2,926
----------- -----------
=========== Total System
5,264 1,312
=========== ===========
All of the above properties are held in fee, but as to Conemaugh, the
Company holds a 9.72% undivided interest as a tenant in common.
Combustion turbines burn No. 2 fuel oil and certain units can also
burn natural gas.
Generating capacity under long-term agreement with the Ohio Edison System.
Includes 84 megawatts supplied by a combustion turbine owned by SMECO
and operated by the Company.
25
The five steam-electric generating stations, together with
combustion turbines, had an aggregate net capability at December 31, 1993, of
5,960 megawatts (including the 84 megawatt combustion turbine owned by SMECO
at the Company's Chalk Point Generating Station), assuming all units are
available for service at the time and for the usual duration of the system
peak (which occurs in the summer). The Company also has 166 megawatts of net
capability available from its 9.72% undivided interest in a mine-mouth, steam-
electric generating station known as the Conemaugh Generating Station, located
in Indiana County, Pennsylvania, which it owns with eight other utilities as
tenants in common. The Company also receives generating capacity and
associated energy from Ohio Edison under its 1987 long-term agreements with
Ohio Edison and APS. The agreements, which provide for 450 megawatts of
capacity and associated energy, are expected to continue at that level through
the year 2005. The net 60-minute peak load in 1993 was 5,754 megawatts, which
occurred on July 9, 1993, and was .3% below the all-time summer peak demand of
5,769 megawatts. To meet the 1993 summer peak demand, the Company also had
201 megawatts available from its dispatchable energy use management programs.
For additional information regarding the Company's net generating capability,
see "Construction Program" and "Fuel" under Item 1 "Business."
The Company owns the transmission and distribution facilities serving
its customers. As stated above, the Company's interest in the Conemaugh
Generating Station and its associated transmission lines is that of a tenant
in common with eight other owners. Substantially all of such Conemaugh
transmission lines, substantially all of the Company's transmission and
distribution lines of less than 230,000 volts, small portions of its 230,000
volt transmission lines and certain of its substations are located on land
owned by others or in public streets and highways. Substantially all of the
Company's property and plant is subject to the mortgage which secures its
bonded indebtedness.
Item 3 LEGAL PROCEEDINGS
- ------ -----------------
For information regarding pending environmental legal proceedings, see
"Environmental Matters" under Item 1 "Business."
The Company was a defendant in employment discrimination litigation
which was pending in the United States District Court for the District of
Columbia. In February 1993, the parties to the case reached tentative
settlement of the claims and, in April 1993, the Company paid $38.26 million
into a trust fund pursuant to the terms of the agreement. The funds will be
disbursed from the trust fund to certain covered classes of current and former
employees and applicants for employment and to cover the plaintiffs' legal and
expert fees and costs. The Court approved the settlement agreement effective
July 1993. The Company received insurance payments of $13.5 million in
October 1993 and $24 million in January 1994, bringing the total recovered
from insurance companies to $37.5 million. At December 31, 1993,
approximately $.8 million was charged to non-operating expense.
26
Item 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
- ------ ---------------------------------------------------
None.
Part II
- -------
Item 5 MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
- ------ -----------------------------------------------------------------
MATTERS
-------
The following table presents the dividends per share of Common Stock and
the high and low of the daily Common Stock transaction prices as reported in
The Wall Street Journal during each period. The New York Stock Exchange is
the principal market on which the Company's Common Stock is traded. The
Company's Common Stock is also traded on the Tokyo Stock Exchange.
Dividends Price Range
Period Per Share High Low
--------------------- --------------- -------- ---------
1993:
First Quarter...... $.41 $26-1/2 $23-7/8
Second Quarter..... .41 27-3/8 25-5/8
Third Quarter...... .41 28-7/8 27-1/8
Fourth Quarter..... .41 $1.64 28-3/4 24-5/8
1992:
First Quarter...... $.40 $25-1/8 $22-3/4
Second Quarter..... .40 26 23
Third Quarter...... .40 27-1/2 25-1/8
Fourth Quarter..... .40 $1.60 26-3/4 22-5/8
The number of holders of Common Stock was 98,312 at March 8, 1994 and
98,892 at December 31, 1993.
There were 117,915,691 and 117,797,652 shares of the Company's $1 par
value Common Stock outstanding at March 8, 1994, and December 31, 1993,
respectively. A total of 200 million shares is authorized.
At its January 1994 meeting, the Company's Board of Directors declared a
quarterly dividend on Common Stock of 41 1/2 cents per share, an increase of
1/2 cent per share over the quarterly dividend of 41 cents paid during 1993.
The increased dividend is payable March 31, 1994, to shareholders of record on
February 25, 1994.
27
Item 6 SELECTED FINANCIAL DATA
- ------ -----------------------
The information required by Item 6 is incorporated herein by reference
to "Selected Consolidated Financial Data" in the Financial Information of the
Company's 1993 Annual Report to shareholders.
Item 7 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
- ------ ---------------------------------------------------------------
RESULTS OF OPERATIONS
---------------------
The information required by Item 7 is incorporated herein by reference
to the "Management's Discussion and Analysis of Consolidated Results of
Operations and Financial Condition" in the Financial Information section of
the Company's 1993 Annual Report to shareholders.
See "Rates" under Item 1 "Business" for an update to the discussion of
the Company's base rate proceeding in the District of Columbia.
Item 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
- ------ -------------------------------------------
The consolidated financial statements, together with the report thereon
of Price Waterhouse dated January 21, 1994, and supplementary data from the
Company's 1993 Annual Report to shareholders are incorporated herein by
reference. With the exception of the aforementioned information and the
information incorporated in Items 5, 6, 7, 8 and 9, the 1993 Annual Report to
Shareholders is not deemed filed as part of this Form 10-K Annual Report.
Item 9 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
- ------ ---------------------------------------------------------------
FINANCIAL DISCLOSURE
--------------------
None.
28
Part III
- --------
Item 10 DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
- ------- --------------------------------------------------
The information required by Item 10 with regard to Directors of the
registrant is incorporated herein by reference to the Company's Notice of
Annual Meeting of Shareholders and Proxy Statement dated March 18, 1994.
Information with regard to the executive officers of the registrant as
of March 8, 1994, is as follows:
Served in
such position
Name Position Age since
- -------------------- -------------------------------- --- -------------
Edward F. Mitchell Chairman of the Board and Chief
Executive Officer 62 1992 (1)
John M. Derrick Jr. President and Chief Operating
Officer 53 1992 (2)
H. Lowell Davis Vice Chairman and Chief Financial
Officer and Director 61 1983
Paul Dragoumis Executive Vice President 59 1989 (3)
Dennis R. Wraase Senior Vice President -
Finance and Accounting 49 1992 (4)
Iraline G. Barnes Vice President - Corporate 46 1990 (5)
Relations
Earl K. Chism Vice President and Treasurer 58 1989 (6)
Susann D. Felton Vice President - Materials 45 1992 (7)
William R. Gee Jr. Vice President - System
Engineering 53 1991 (8)
Robert C. Grantley Vice President - Customer
Services 45 1989 (9)
Anthony S. Macerollo Vice President - Human
Resources 52 1989 (10)
Eddie R. Mayberry Vice President - Market
Planning and Policy 46 1993 (11)
John D. McCallum Vice President - Corporate Tax 44 1992 (12)
29
Served in
such position
Name Position Age since
- -------------------- -------------------------------- --- -------------
James S. Potts Vice President - Environment 48 1993 (13)
William J. Sim Vice President - Operations
and Construction 49 1991 (14)
William T. Torgerson Vice President and General
Counsel 49 1989 (15)
Andrew W. Williams Vice President - Energy Policy
and Development 44 1989 (16)
None of the above persons has a "family relationship" with any other officer
listed or with any director or nominee for director.
The term of office for each of the above persons is from April 28, 1993
to April 27, 1994.
(1) Mr. Mitchell was elected to the position of Chairman of the Board on
December 21, 1992. He was elected Chief Executive Officer effective
September 1, 1989. Prior to that time he held the position of
President and Chief Operating Officer, since 1983.
(2) Mr. Derrick was elected to the position of President on December 21,
1992. He was elected Executive Vice President and Chief Operating
Officer on July 27, 1989. Prior to that time he held the position of
Vice President - Customer Services, since 1981.
(3) Mr. Dragoumis was elected to his present position on July 27, 1989.
Prior to that time he held the position of Senior Vice President.
(4) Mr. Wraase was elected to his present position on April 22, 1992. He
was elected Senior Vice President and Comptroller on July 27, 1989.
Prior to that time he held the position of Vice President and
Comptroller, since 1985.
(5) Mrs. Barnes was elected to her present position effective April 1,
1990. Prior to that time she served as Associate Judge of the Superior
Court of the District of Columbia for ten years.
(6) Mr. Chism was elected to his present position on July 27, 1989. Prior
to that time he held the positions of Treasurer from 1988 to 1989, and
of Assistant Treasurer from 1987 to 1988.
(7) Ms. Felton was elected to her present position on April 22, 1992.
Prior to that time she held the position of Manager, Materials.
30
(8) Mr. Gee was elected to his present position on April 24, 1991. Prior to
that time he held the position of Vice President - Generating
Engineering and Construction, since 1989. Prior to 1989, he held the
position of Manager, Generating Engineering.
(9) Mr. Grantley was elected to his present position on July 27, 1989.
Prior to that time he held the position of Manager, Customer Services,
since 1987.
(10) Mr. Macerollo was elected to his present position on July 27, 1989.
Prior to that time he held the position of Manager, Human Resources,
since 1986.
(11) Dr. Mayberry was elected to his present position on April 28, 1993.
Prior to that time he held the position of Manager, Market Planning and
Policy, since 1989. Prior to 1989 he held the position of Manager,
Rate and Economic Analysis.
(12) Mr. McCallum was elected to his present position on April 22, 1992.
Prior to that time he held the position of Assistant Comptroller, since
1987.
(13) Mr. Potts was elected to his present position on April 28, 1993. Prior
to that time he held the position of Manager, Generating Strategic
Support since 1991. Prior to 1991 he held the position of Manager,
Production Performance.
(14) Mr. Sim was elected to his present position on April 24, 1991. Prior to
that time he was President of the American Energy division of the
Company's nonutility subsidiary, Potomac Capital Investment Corporation,
since 1988. Prior to 1988, he held the position of Manager, Generating
Construction.
(15) Mr. Torgerson was elected to his present position effective January 1,
1989. Prior to that time he held the position of Vice President and
Deputy General Counsel, since 1986.
(16) Mr. Williams was elected to his present position on July 27, 1989.
Prior to that time he held the position of Manager, Financial Planning
and Analysis, since 1985.
Item 11 EXECUTIVE COMPENSATION
- ------- ----------------------
The information required by Item 11 is incorporated herein by reference
to the Company's Notice of Annual Meeting of Shareholders and Proxy Statement
dated March 18, 1994.
31
Item 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
- ------- --------------------------------------------------------------
The information required by Item 12 is incorporated herein by reference
to the Company's Notice of Annual Meeting of Shareholders and Proxy Statement
dated March 18, 1994.
Item 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
- ------- ----------------------------------------------
None.
Part IV
- -------
Item 14 EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
- ------- ---------------------------------------------------------------
(a) Documents List
--------------
1. Financial Statements
The following documents are filed as part of this report as incorporated
herein by reference from the indicated pages of the Company's 1993 Annual
Report.
Reference (Page)
----------------
Form 10-K
Annual Report Annual Report
to Shareholders Exhibit 13
--------------- -------------
Consolidated Statements of Earnings -
for the years ended December 31, 1993,
1992 and 1991 15 24
Consolidated Balance Sheets -
December 31, 1993 and 1992 16-17 25-26
Consolidated Statements of Cash Flows -
for the years ended December 31, 1993,
1992 and 1991 18 27
Notes to Consolidated Financial
Statements 19-31 28-60
Report of Independent Accountants 14 23
32
2. Financial Statement Schedules
Unaudited supplementary data entitled "Quarterly Financial Summary
(Unaudited)" is incorporated herein by reference in Item 8 (included in "Notes
to Consolidated Financial Statements" as Note 15).
The following financial statement schedules are submitted under Item 14
(d):
Report of Independent Accountants on
Consolidated Financial Statement Schedules
Schedule V - Property, Plant and Equipment
Schedule VI - Accumulated Depreciation,
Depletion and Amortization of Property,
Plant and Equipment
Schedule VIII - Valuation and Qualifying Accounts
Schedule IX - Short-Term Borrowings
All other schedules are omitted because they are not applicable, or the
required information is presented in the financial statements.
3. Exhibits required by Securities and Exchange Commission Regulation
S-K (summarized below).
Exhibit
No. Description of Exhibit Reference*
- ------- ---------------------- ----------
3-A Charter of the Company.............. Filed herewith.
3-B By-Laws of the Company.............. Exh. 3-B to Form 10-K,
3/26/93.
4 Mortgage and Deed of Trust dated
July 1, 1936, of the Company to The
Riggs National Bank of Washington,
D.C., as Trustee, securing First
Mortgage Bonds of the Company, and
Supplemental Indenture dated
July 1, 1936........................ Exh. B-4 to First Amendment,
6/19/36, to Registration
Statement No. 2-2232.
33
Exhibit
No. Description of Exhibit Reference*
- ------- ---------------------- ----------
4 Supplemental Indentures, to the
(cont.) aforesaid Mortgage and Deed of
Trust, dated -
December 1, 1939 and December
10, 1939.......................... Exhs. A & B to Form 8-K,
1/3/40.
August 1, 1940...................... Exh. A to Form 8-K, 9/25/40.
July 15, 1942 and August 10,
1942................................ Exh. B-1 to Amendment No. 2,
8/24/42, and B-3 to Post-
Effective Amendment,
8/31/42, to Registration
Statement No. 2-5032.
August 1, 1942...................... Exh. B-4 to Form 8-A,
10/8/42.
October 15, 1942.................... Exh. A to Form 8-K, 12/7/42.
October 15, 1947.................... Exh. A to Form 8-K, 12/8/47.
January 1, 1948..................... Exh.7-B to Post-Effective
Amendment No. 2, 1/28/48,
to Registration Statement
No. 2-7349.
December 31, 1948................... Exh. A-2 to Form 10-K,
4/13/49.
May 1, 1949......................... Exh. 7-B to Post-Effective
Amendment No. 1,
5/10/49, to Registration
Statement No. 2-7948.
December 31, 1949................... Exh. (a)-1 to Form 8-K,
2/8/50.
May 1, 1950......................... Exh. 7-B to Amendment No. 2,
5/8/50, to Registration
Statement No. 2-8430.
February 15, 1951................... Exh. (a) to Form 8-K, 3/9/51.
March 1, 1952....................... Exh. 4-C to Post-Effective
Amendment No. 1, 3/12/52,
to Registration Statement
No. 2-9435.
February 16, 1953................... Exh. (a)-1 to Form 8-K,
3/5/53.
May 15, 1953........................ Exh. 4-C to Post-Effective
Amendment No. 1, 5/26/53,
to Registration Statement
No. 2-10246.
34
Exhibit
No. Description of Exhibit Reference*
- ------- ---------------------- ----------
4 March 15, 1954 and March 15,
(cont.) 1955................................ Exh. 4-B to Registration
Statement No. 2-11627,
5/2/55.
May 16, 1955........................ Exh. A to Form 8-K, 7/6/55.
March 15, 1956...................... Exh. C to Form 10-K, 4/4/56.
June 1, 1956........................ Exh. A to Form 8-K, 7/2/56.
April 1, 1957....................... Exh. 4-B to Registration
Statement No. 2-13884,
2/5/58.
May 1, 1958......................... Exh. 2-B to Registration
Statement No. 2-14518,
11/10/58.
December 1, 1958.................... Exh. A to Form 8-K, 1/2/59.
May 1, 1959......................... Exh. 4-B to Amendment No. 1,
5/13/59, to Registration
Statement No. 2-15027.
November 16, 1959................... Exh. A to Form 8-K, 1/4/60.
May 2, 1960......................... Exh. 2-B to Registration
Statement No. 2-17286,
11/9/60.
December 1, 1960 and April 3,
1961................................ Exh. A-1 to Form 10-K,
4/24/61.
May 1, 1962......................... Exh. 2-B to Registration
Statement No. 2-21037,
1/25/63.
February 15, 1963................... Exh. A to Form 8-K, 3/4/63.
May 1, 1963......................... Exh. 4-B to Registration
Statement No. 2-21961,
12/19/63.
April 23, 1964...................... Exh. 2-B to Registration
Statement No. 2-22344,
4/24/64.
May 15, 1964........................ Exh. A to Form 8-K, 6/2/64.
May 3, 1965......................... Exh. 2-B to Registration
Statement No. 2-24655,
3/16/66.
April 1, 1966....................... Exh. A to Form 10-K, 4/21/66.
June 1, 1966........................ Exh. 1 to Form 10-K, 4/11/67.
April 28, 1967...................... Exh. 2-B to Post-Effective
Amendment No. 1 to
Registration Statement No.
2-26356, 5/3/67.
May 1, 1967......................... Exh. A to Form 8-K, 6/1/67.
35
Exhibit
No. Description of Exhibit Reference*
- ------ ---------------------- ----------
4 July 3, 1967........................ Exh. 2-B to Registration
(cont.) Statement No. 2-28080,
1/25/68.
February 15, 1968................... Exh. II-I to Form 8-K, 3/7/68.
May 1, 1968......................... Exh. 2-B to Registration
Statement No. 2-31896,
2/28/69.
March 15, 1969...................... Exh. A-2 to Form 8-K, 4/8/69.
June 16, 1969....................... Exh. 2-B to Registration
Statement No. 2-36094,
1/27/70.
February 15, 1970................... Exh. A-2 to Form 8-K, 3/9/70.
May 15, 1970........................ Exh. 2-B to Registration
Statement No. 2-38038,
7/27/70.
August 15, 1970..................... Exh. 2-D to Registration
Statement No. 2-38038,
7/27/70.
September 1, 1971................... Exh. 2-C to Registration
Statement No. 2-45591, 9/1/72.
September 15, 1972.................. Exh. 2-E to Registration
Statement No. 2-45591, 9/1/72.
April 1, 1973....................... Exh. A to Form 8-K, 5/9/73.
January 2, 1974..................... Exh. 2-D to Registration
Statement No. 2-49803,
12/5/73.
August 15, 1974..................... Exhs. 2-G and 2-H to
Amendment No. 1 to
Registration Statement
No. 2-51698, 8/14/74.
June 15, 1977....................... Exh. 4-A to Form 10-K,
3/19/81.
July 1, 1979........................ Exh. 4-B to Form 10-K,
3/19/81.
June 16, 1981....................... Exh. 4-A to Form 10-K,
3/19/82.
June 17, 1981....................... Exh. 2 to Amendment No. 1,
6/18/81, to Form 8-A.
December 1, 1981.................... Exh. 4-C to Form 10-K,
3/19/82.
August 1, 1982...................... Exh. 4-C to Amendment No. 1
to Registration Statement
No. 2-78731, 8/17/82.
October 1, 1982..................... Exh. 4 to Form 8-K, 11/8/82.
April 15, 1983...................... Exh. 4 to Form 10-K, 3/23/84.
November 1, 1985.................... Exh. 2-B to Form 8-A, 11/1/85.
36
Exhibit
No. Description of Exhibit Reference*
- ------ ---------------------- ----------
4 March 1, 1986....................... Exh. 4 to Form 10-K, 3/28/86.
(cont.) November 1, 1986.................... Exh. 2-B to Form 8-A, 11/5/86.
March 1, 1987....................... Exh. 2-B to Form 8-A, 3/2/87.
September 16, 1987.................. Exh. 4-B to Registration
Statement No. 33-18229,
10/30/87.
May 1, 1989......................... Exh. 4-C to Registration
Statement No. 33-29382,
6/16/89.
August 1, 1989...................... Exh. 4 to Form 10-K, 3/23/90.
April 5, 1990....................... Exh. 4 to Form 10-K, 3/29/91.
May 21, 1991........................ Exh. 4 to Form 10-K, 3/27/92.
May 7, 1992......................... Exh. 4 to Form 10-K, 3/26/93.
September 1, 1992................... Exh. 4 to Form 10-K, 3/26/93.
November 1, 1992.................... Exh. 4 to Form 10-K, 3/26/93.
March 1, 1993....................... Exh. 4 to Form 10-K, 3/26/93.
March 2, 1993....................... Exh. 4 to Form 10-K, 3/26/93.
July 1, 1993........................ Exh. 4.4 to Registration
Statement No. 33-49973,
8/11/93.
August 20, 1993..................... Exh. 4.4 to Registration
Statement No. 33-50377,
9/23/93.
September 29, 1993.................. Filed herewith.
September 30, 1993.................. Filed herewith.
October 1, 1993..................... Filed herewith.
February 10, 1994................... Filed herewith.
February 11, 1994................... Filed herewith.
4-A Indenture, dated as of January 15,
1988, between the Company and
Centerre Trust Company of St. Louis
(now known as Boatmen's Trust
Company), Trustee for the Company's
$75,000,000 issue of 7% Convertible
Debentures due 2018 ................ Exh. 4-A to Form 10-K,
3/25/88.
4-B Indenture, dated as of July 28,
1989, between the Company and
The Bank of New York, Trustee,
with respect to the Company's
Medium-Term Note Program............ Exh. 4 to Form 8-K, 6/21/90.
37
Exhibit
No. Description of Exhibit Reference*
- ------ ---------------------- ----------
4C Indenture, dated as of August 15,
1992, between the Company and the
Bank of New York, Trustee, for the
Company's $115,000,000 issue of 5%
Convertible Debentures due 2002..... Exh. 4-C to Form 10-K,
3/26/93.
10 Agreement, effective July 23, 1993,
between the Company and the
International Brotherhood of
Electrical Workers (Local Union
#1900).............................. Exh. 10 to Form 10-Q, 7/30/93.
**11 Computation of Earnings Per
Common Share...................... Filed herewith.
**12 Computation of Ratios............... Filed herewith.
13 Financial Information Section of
Annual Report .................... Filed herewith.
**22 Subsidiaries of the Registrant...... Filed herewith.
**24 Consent of Independent Accountants.. Filed herewith.
* The exhibits referred to in this column by specific designations and
date have heretofore been filed with the Securities and Exchange
Commission under such designations and are hereby incorporated herein
by reference. The Forms 8-A, 8-K and 10-K referred to were filed by
the Company under the Commission's File No. 1-1072 and the
Registration Statements referred to are registration statements of
the Company.
** These exhibits are submitted under Item 14(c).
(b) Reports on Form 8-K
-------------------
None.
38
POTOMAC ELECTRIC POWER COMPANY
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
YEAR ENDED DECEMBER 31, 1993
Col. A Col. B Col. C Col. D
Col. E Col. F
------ ------ ------ ------
------ ------
Other Balance
Balance at
changes at end
beginning Additions
add of
Description of period at cost
Retirements (deduct) period
- --------------------------------------- ---------- --------- ---------
- -- --------- ----------
(Thousands of
Dollars)
Electric Utility Plant:
Production plant (steam generation) $1,638,725 $ 61,645 $
19,828 $ - $1,680,542
Production plant (other generation) 371,671 54,814
131 - 426,354
Transmission plant 515,097 9,535
1,613 - 523,019
Distribution plant 2,171,213 129,785
12,999 - 2,287,999
General plant and other 317,575 8,110
5,618 14,755 334,822
Construction work in progress 314,855 58,810
- - - 373,665
Electric plant held for future use 34,766 (1,122)
- - - 33,644
---------- --------- ---------
- -- --------- ----------
Total Electric Utility Plant 5,363,902 321,577
40,189 14,755 5,660,045
Nonoperating Property 3,722 1,374
- - - 5,096
---------- --------- ---------
- -- --------- ----------
Total Property and Plant $5,367,624 $ 322,951 $
40,189 $ 14,755 $5,665,141
========== =========
=========== ========= ==========
Nonutility Property
Operating lease equipment,
principally aircraft $ 620,982 $ 6,695 $
- - $ 23,068 $ 650,745
========== =========
=========== ========= ==========
Reclassification of computer software costs from Deferred charges.
Purchase of remaining interest and subsequent consolidation of
airplane engine leasing subsidiary.
Additions to Electric Utility Plant include an Allowance for
Funds Used During Construction (AFUDC).
39
POTOMAC ELECTRIC POWER COMPANY
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
YEAR ENDED DECEMBER 31, 1992
Col. A Col. B Col. C Col. D
Col. E Col. F
------ ------ ------ ------
------ ------
Other Balance
Balance at
changes at end
beginning Additions
add of
Description of period at cost
Retirements (deduct) period
- --------------------------------------- ---------- --------- ---------
- -- --------- ----------
(Thousands of
Dollars)
Electric Utility Plant:
Production plant (steam generation) $1,596,114 $ 59,745 $
17,134 $ - $1,638,725
Production plant (other generation) 229,825 142,068
222 - 371,671
Transmission plant 470,462 47,607
2,972 - 515,097
Distribution plant 2,067,047 116,215
12,049 - 2,171,213
General plant and other 310,658 12,769
5,852 - 317,575
Construction work in progress 349,239 (34,384)
- - - 314,855
Electric plant held for future use 21,995 12,771
- - - 34,766
---------- --------- ---------
- -- --------- ----------
Total Electric Utility Plant 5,045,340 356,791
38,229 - 5,363,902
Nonoperating Property 2,781 941
- - - 3,722
---------- --------- ---------
- -- --------- ----------
Total Property and Plant 5,048,121 $ 357,732 $
38,229 $ - $5,367,624
========== =========
=========== ========= ==========
Nonutility Property
Operating lease equipment,
principally aircraft $ 743,014 $ 29,911 $
- - $(151,943)$ 620,982
========== =========
=========== ========= ==========
Sale of aircraft lease equipment and aircraft ($105,000,000)
transferred to finance leases.
Additions to Electric Utility Plant include an Allowance for
Funds Used During Construction (AFUDC).
40
POTOMAC ELECTRIC POWER COMPANY
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
YEAR ENDED DECEMBER 31, 1991
Col. A Col. B Col. C Col. D
Col. E Col. F
------ ------ ------ ------
------ ------
Other Balance
Balance at
changes at end
beginning Additions
add of
Description of period at cost
Retirements (deduct) period
- --------------------------------------- ---------- --------- ---------
- -- --------- ----------
(Thousands of
Dollars)
Electric Utility Plant:
Production plant (steam generation) $1,558,842 $ 62,024 $
24,752 $ - $1,596,114
Production plant (other generation) 70,791 161,636
2,602 - 229,825
Transmission plant 445,663 25,519
720 - 470,462
Distribution plant 1,916,028 162,433
11,414 - 2,067,047
General plant and other 275,749 38,723
3,814 - 310,658
Construction work in progress 374,437 (25,198)
- - - 349,239
Electric plant held for future use 14,381 7,614
- - - 21,995
---------- --------- ---------
- -- --------- ----------
Total Electric Utility Plant 4,655,891 432,751
43,302 - 5,045,340
Nonoperating Property 3,389 (608)
- - - 2,781
---------- --------- ---------
- -- --------- ----------
Total Property and Plant $4,659,280 $ 432,143 $
43,302 $ - $5,048,121
========== =========
=========== ========= ==========
Nonutility Property
Operating lease equipment,
principally aircraft $ 438,177 $ 393,395 $
- - $ (88,558)$ 743,014
========== =========
=========== ========= ==========
Sale of aircraft lease equipment and aircraft ($84,356,000)
transferred to partnership.
Additions to Electric Utility Plant include an Allowance for
Funds Used During Construction (AFUDC).
41
POTOMAC ELECTRIC POWER COMPANY
SCHEDULE VI - ACCUMULATED DEPRECIATION,
DEPLETION AND
AMORTIZATION OF PROPERTY, PLANT AND
EQUIPMENT
YEAR ENDED DECEMBER 31, 1993
Col. A Col. B Col. C Col.
D Col. E Col. F
------ ------ ------ ----
- -- ------ ------
Additions
Balance charged
Other Balance
at to costs
changes at end
beginning and
add of
Description of period expenses
Retirements (deduct) period
- --------------------------------------- ----------- ---------
- -------------- ---------- ----------
(Thousands
of Dollars)
Accumulated Depreciation:
- -------------------------
Electric Utility Plant:
Production plant (steam generation) $ 579,826 $ 52,060 $
30,060 $ - $ 601,826
Production plant (other generation) 66,174 16,666
346 - 82,494
Transmission plant 152,032 10,961
(363) - 163,356
Distribution plant 560,143 58,573
23,135 - 595,581
General plant and other 72,375 15,223
4,473 - 83,125
----------- ---------
- -------------- ---------- ----------
1,430,550 153,483
57,651 - 1,526,382
Nonoperating Property 414 63
- - 477
----------- ---------
- -------------- ---------- ----------
Total Accumulated Depreciation 1,430,964 153,546
57,651 - 1,526,859
----------- ---------
- -------------- ---------- ----------
Accumulated Amortization:
- -------------------------
Electric Utility Plant:
Production plant (other generation) 116 53
- - 169
General plant and other 5,287 482
- 1,202 6,971
----------- ---------
- -------------- ---------- ----------
Total Accumulated Amortization 5,403 535
- 1,202 7,140
----------- ---------
- -------------- ---------- ----------
Total Accumulated Depreciation
and Amortization $ 1,436,367 $ 154,081 $
57,651 $ 1,202 $1,533,999
=========== =========
============== ========== ==========
Nonutility Accumulated Depreciation
- -----------------------------------
Operating lease equipment,
principally aircraft $ 55,981 $ 29,321 $
- $ - $ 85,302
=========== =========
============== ========== ==========
Includes depreciation of "Production plant (steam generation)"
($501,000) and "General plant" ($4,079,000) charged to clearing
accounts and subsequently redistributed to appropriate operating
and construction accounts.
Charged to Other Income.
After deduction of net salvage.
Reclassification of computer software costs from Deferred charges.
42
POTOMAC ELECTRIC POWER COMPANY
SCHEDULE VI - ACCUMULATED DEPRECIATION,
DEPLETION AND
AMORTIZATION OF PROPERTY, PLANT AND
EQUIPMENT
YEAR ENDED DECEMBER 31, 1992
Col. A Col. B Col. C Col.
D Col. E Col. F
------ ------ ------ ----
- -- ------ ------
Additions
Balance charged
Other Balance
at to costs
changes at end
beginning and
add of
Description of period expenses
Retirements (deduct) period
- --------------------------------------- ----------- ---------
- -------------- ---------- ----------
(Thousands
of Dollars)
Accumulated Depreciation:
- -------------------------
Electric Utility Plant:
Production plant (steam generation) $ 553,037 $ 53,230 $
26,441 $ - $ 579,826
Production plant (other generation) 52,261 13,141
(772) - 66,174
Transmission plant 144,876 10,580
3,424 - 152,032
Distribution plant 522,104 51,939
13,900 - 560,143
General plant and other 63,746 14,457
5,828 - 72,375
----------- ---------
- -------------- ---------- ----------
1,336,024 143,347
48,821 - 1,430,550
Nonoperating Property 351 63
- - 414
----------- ---------
- -------------- ---------- ----------
Total Accumulated Depreciation 1,336,375 143,410
48,821 - 1,430,964
----------- ---------
- -------------- ---------- ----------
Accumulated Amortization:
- -------------------------
Electric Utility Plant:
Production plant (other generation) 63 53
- - 116
General plant and other 4,817 470
- - 5,287
----------- ---------
- -------------- ---------- ----------
Total Accumulated Amortization 4,880 523
- - 5,403
----------- ---------
- -------------- ---------- ----------
Total Accumulated Depreciation
and Amortization $ 1,341,255 $ 143,933 $
48,821 $ - $1,436,367
=========== =========
============== ========== ==========
Nonutility Accumulated Depreciation
- -----------------------------------
Operating lease equipment,
principally aircraft $ 36,018 $ 29,322 $
- $ (9,359)$ 55,981
=========== =========
============== ========== ==========
Includes depreciation of "Production plant (steam generation)"
($527,000) and "General plant" ($4,253,000) charged to clearing
accounts and subsequently redistributed to appropriate operating
and construction accounts.
Charged to Other Income.
After deduction of net salvage.
Principally sale of aircraft lease equipment and
transfer of aircraft to finance leases.
43
POTOMAC ELECTRIC POWER COMPANY
SCHEDULE VI - ACCUMULATED DEPRECIATION,
DEPLETION AND
AMORTIZATION OF PROPERTY, PLANT AND
EQUIPMENT
YEAR ENDED DECEMBER 31, 1991
Col. A Col. B Col. C Col.
D Col. E Col. F
------ ------ ------ ----
- -- ------ ------
Additions
Balance charged
Other Balance
at to costs
changes at end
beginning and
add of
Description of period expenses
Retirements (deduct) period
- --------------------------------------- ----------- ---------
- -------------- ---------- ----------
(Thousands
of Dollars)
Accumulated Depreciation:
- -------------------------
Electric Utility Plant:
Production plant (steam generation) $ 533,535 $ 51,825 $
32,323 $ - $ 553,037
Production plant (other generation) 49,167 6,482
3,388 - 52,261
Transmission plant 135,977 9,827
928 - 144,876
Distribution plant 483,998 48,793
10,687 - 522,104
General plant and other 53,941 13,248
3,443 - 63,746
----------- ---------
- -------------- ---------- ----------
1,256,618 130,175
50,769 - 1,336,024
Nonoperating Property 291 60
- - 351
----------- ---------
- -------------- ---------- ----------
Total Accumulated Depreciation 1,256,909 130,235
50,769 - 1,336,375
----------- ---------
- -------------- ---------- ----------
Accumulated Amortization:
- -------------------------
Electric Utility Plant:
Production plant (other generation) 17 46
- - 63
General plant and other 4,362 455
- - 4,817
----------- ---------
- -------------- ---------- ----------
Total Accumulated Amortization 4,379 501
- - 4,880
----------- ---------
- -------------- ---------- ----------
Total Accumulated Depreciation
and Amortization $ 1,261,288 $ 130,736 $
50,769 $ - $1,341,255
=========== =========
============== ========== ==========
Nonutility Accumulated Depreciation
- -----------------------------------
Operating lease equipment,
principally aircraft $ 13,942 $ 23,647 $
- $ (1,571)$ 36,018
=========== =========
============== ========== ==========
Includes depreciation of "Production plant (steam generation)"
($525,000) and "General plant" ($4,504,000) charged to clearing
accounts and subsequently redistributed to appropriate operating
and construction accounts.
Charged to Other Income.
After deduction of net salvage.
Principally transfer of aircraft lease equipment to partnership.
44
POTOMAC ELECTRIC POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND
1991
Col. A Col. B Col. C
Col. D Col. E
------ ------ ------
------ ------
Additions
Balance
- ------------------------- Balance
at Charged to Charged
to at
Beginning Costs and
Other End
Description of Period Expenses
Accounts Deductions of Period
- ------------------------------------------- --------- ----------
- ----------- ------------- ---------
(Thousands of
Dollars)
Year Ended December 31, 1993
Allowance for uncollectible accounts -
customer and other accounts receivable $ 2,709 $ 6,451 $
658 $ (6,770) $ 3,048
Year Ended December 31, 1992
Allowance for uncollectible accounts -
customer and other accounts receivable $ 3,115 $ 5,753 $
836 $ (6,995) $ 2,709
Year Ended December 31, 1991
Allowance for uncollectible accounts -
customer and other accounts receivable $ 3,189 $ 4,861 $
663 $ (5,598) $ 3,115
Collection of accounts previously written off.
Uncollectible accounts written off.
45
POTOMAC ELECTRIC POWER COMPANY
SCHEDULE IX - SHORT-TERM BORROWINGS
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
Col. A Col. B Col. C Col. D
Col. E Col. F
------ ------ ------ ------ -
- ----- ------
Maximum
Average
Weighted Aggregate
Aggregate Weighted
Balance Average Face Amount
Face Amount Average
At End Effective Outstanding
Outstanding Effective
Category of Aggregate Of Interest During
During the Interest
Short-Term Borrowings Period Rate the Period
Period Rate
- ------------------------------ ---------- --------- ----------- ---
- -------- ---------
(000s) (000s)
(000s)
Year Ended December 31, 1993
Payable to Holders of
Commercial Paper $ 274,615 3.34 % $ 274,615 $
105,777 3.12 %
Payable to Banks $ 20,000 3.01 % $ 20,000 $
20,000 3.00 %
Year Ended December 31, 1992
Payable to Holders of
Commercial Paper $ 41,600 3.48 % $ 199,980 $
80,948 3.92 %
Payable to Banks $ 20,000 3.16 % $ 20,000 $
20,000 3.54 %
Year Ended December 31, 1991
Payable to Holders of
Commercial Paper $ 66,800 5.19 % $ 262,760 $
120,205 6.34 %
Payable to Banks $ 20,000 4.44 % $ 20,000 $
20,000 5.72 %
Non-Utility Subsidiary:
- -----------------------
Year Ended December 31, 1993
Payable to Holders of
Commercial Paper $ 126,250 3.53 % $ 339,900 $
156,400 3.26 %
Year Ended December 31, 1992
Payable to Holders of
Commercial Paper $ 263,515 3.62 % $ 342,000 $
255,000 3.76 %
Year Ended December 31, 1991
Payable to Holders of
Commercial Paper $ 270,905 5.20 % $ 349,300 $
303,381 5.96 %
Calculation of average amounts have been weighted by the
dollar amounts of the notes outstanding.
46
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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, in the City of
Washington, District of Columbia, on the 25th day of March, 1994.
POTOMAC ELECTRIC POWER COMPANY
(Registrant)
By /s/ E. F. Mitchell
--------------------------
(Edward F. Mitchell,
Chairman of the Board and
Chief Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated:
Signature Title Date
--------- ----- ----
(i) Principal Executive Officer
/s/ E. F. Mitchell
--------------------------- Chairman of the Board and
(Edward F. Mitchell) Chief Executive Officer
(ii) Principal Financial Officer
/s/ H. L. Davis
--------------------------- Vice Chairman and Chief
(H. Lowell Davis) Financial Officer and Director
(iii) Principal Accounting Officer
/s/ D. R. Wraase
--------------------------- Senior Vice President
(Dennis R. Wraase) Finance and Accounting
March 25, 1994
47
Signature Title Date
--------- ----- ----
(iv) Directors:
/s/ Roger R. Blunt
------------------------- Director
(Roger R. Blunt Sr.)
/s/ A. J. Clark
------------------------- Director
(A. James Clark)
/s/ Richard E. Marriott
------------------------- Director
(Richard E. Marriott)
/s/ David O. Maxwell
------------------------ Director
(David O. Maxwell)
/s/ Floretta D. McKenzie
------------------------- Director
(Floretta D. McKenzie)
/s/ Ann D. McLaughlin
------------------------- Director
(Ann D. McLaughlin)
/s/ Peter F. O'Malley
------------------------- Director
(Peter F. O'Malley)
/s/ Louis A. Simpson
------------------------- Director
(Louis A. Simpson)
/s/ W. Reid Thompson
------------------------- Director
(W. Reid Thompson)
48
Signature Title Date
--------- ----- ----
(iv) Directors:
/s/ Charls E. Walker
------------------------- Director
(Charls E. Walker)
March 25, 1994
49