Annual Report — [x] Reg. S-K Item 405 — Form 10-K
Filing Table of Contents
Document/Exhibit Description Pages Size
1: 10-K405 Annual Report -- [x] Reg. S-K Item 405 44± 193K
3: EX-3 Articles of Incorporation 51± 195K
4: EX-3 By-Laws 13 58K
5: EX-4 Supplemental Indenture 34 124K
6: EX-10 Amendment to Employment Agreement 1 8K
7: EX-10 Union Contract Extension 1 8K
2: EX-13 Annual or Quarterly Report to Security Holders 68± 291K
8: EX-27 Financial Data Schedule 2± 10K
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, 1997 Commission file number 1-1072
----------------- ------
Potomac Electric Power Company
------------------------------------------------------------------------------
(Exact name of registrant as specified in its charter)
District of Columbia and Virginia 53-0127880
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1900 Pennsylvania Avenue, N.W.
Washington, D. C. 20068
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (202) 872-2000
-------------------
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
------------------- -----------------------------
7% Convertible Debentures due 2018 - ) New York Stock Exchange, Inc.
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 )
Common Stock, $1 par value )
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. X .
---
As of March 3, 1998, Potomac Electric Power Company had 118,527,028
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 $3 billion.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Company's 1997 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 4, 1998, are incorporated by reference into Part III of
this Form 10-K.
2
POTOMAC ELECTRIC POWER COMPANY
Form 10-K - 1997
TABLE OF CONTENTS
PART I Page
Item 1 - Business ----
Termination of Proposed Merger...................................... 5
General ............................................................ 5
Sales .............................................................. 7
Capacity Planning .................................................. 8
Construction Program ............................................... 9
Fuel ............................................................... 11
Regulation ......................................................... 15
Rates .............................................................. 15
Competition ........................................................ 18
Environmental Matters .............................................. 19
Labor .............................................................. 24
Nonutility Subsidiary .............................................. 24
Item 2 - Properties .................................................. 26
Item 3 - Legal Proceedings ........................................... 27
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 ....................................... 28
Item 6 - Selected Financial Data ..................................... 28
Item 7 - Management's Discussion and Analysis of Financial Condition
and Results of Operations ................................. 29
Item 8 - Financial Statements and Supplementary Data ................. 29
Item 9 - Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure .................................. 29
PART III
Item 10 - Directors and Executive Officers of the Registrant ......... 30
Item 11 - Executive Compensation ..................................... 32
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 Schedule and Reports on
Form 8-K ................................................. 33
Schedule II - Valuation and Qualifying Accounts .................... 42
Signatures ........................................................... 43
Exhibit 11 - Computations of Earnings Per Common Share .......... 45
Exhibit 12 - Computation of Ratios .............................. 46
Exhibit 21 - Subsidiaries of the Registrant ..................... 48
Exhibit 23 - Consent of Independent Accountants ................. 48
Report of Independent Accountants on Consolidated Financial
Statement Schedule ............................................... 49
3
PAGE LEFT BLANK
INTENTIONALLY
4
Part I
------
Item 1 BUSINESS
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TERMINATION OF PROPOSED MERGER
------------------------------
On December 22, 1997, Potomac Electric Power Company (the Company,
PEPCO) and Baltimore Gas and Electric Company announced the cancellation of
their proposed merger (the Merger) to create Constellation Energy Corporation.
As a result, the Company recorded a $52.5 million non-operating charge ($32.6
million net of income tax or 28 cents per share) to write off its cumulative
deferred Merger-related costs.
While all necessary regulatory approvals had been received, the orders
of both the Maryland and the District of Columbia public service commissions
contained financial conditions that made it impossible for the two companies'
investors to share in the benefits of the proposed Merger. The regulatory plan
proposed by the companies had called for an equal sharing of the savings
between customers and shareholders. Both commission orders returned more than
the estimated total Merger savings to the customers. The companies tried
unsuccessfully to obtain timely reconsideration of these conditions but
concluded that a favorable outcome could not be expected within a reasonable
period, if at all.
GENERAL
-------
The 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, and in other businesses through a nonutility subsidiary.
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 1997 and 1996.
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
1997, approximately 59% of the Company's revenue was derived from Maryland
sales (including wholesale) and 41% from sales in the District of Columbia.
About 29% of the Company's revenue was derived from residential customers, 64%
from sales to commercial and government customers and 7% from sales at
wholesale. Approximately 14% and 3% of 1997 revenue 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.
5
The Company is a transmission-owning member of the Pennsylvania-New
Jersey-Maryland Interconnection LLC (PJM) pursuant to an agreement under which
its generating and transmission facilities are operated on an integrated basis
with those of the other PJM members in Pennsylvania, New Jersey, Maryland,
Delaware and a small portion of Virginia. The purpose of PJM is to operate a
wholesale energy market, improve the operating economy and reliability of the
systems in the group, and provide capital economies by permitting lower
reserve requirements than would be required on an individual basis. The
Company also has direct high voltage connections with the Potomac Edison
Company, a subsidiary of Allegheny Energy, Inc. (AEI, formerly Allegheny Power
System, Inc.), and Virginia Power, neither of which is a transmission owner in
PJM.
On November 25, 1997, the Federal Energy Regulatory Commission (FERC)
conditionally approved a PJM restructuring plan which, among other things,
reconstitutes the PJM staff as an independent system operator (ISO) and
provides for open access transmission service on a pool-wide basis. The ISO
began operation on January 1, 1998. The PJM pool-wide transmission tariff was
implemented on April 1, 1997; a revised version incorporating locational
pricing will become effective April 1, 1998. Benefits and/or costs derived
from the PJM market are passed through to the Company's customers through fuel
adjustment clauses and, accordingly, will not have a material effect on the
operating results of the Company.
Additional information concerning the restructuring of the bulk power
market is presented in Management's Discussion and Analysis incorporated by
reference in Item 7.
The Company has implemented, through an internal Task Force, a 4-phase
approach to accommodate the year 2000. The phases being addressed are:
Corporate Application Compliance which includes all large core business
systems; Business Partners' Systems and Vendor System Verification which is
intended to ensure all suppliers are in compliance with year 2000 processing;
End-user Computing Systems which are all systems which are not considered core
business systems but contain date calculations; and Non-Information Technology
Processes that include all operating and control systems. The Task Force has
developed a database to identify and track the progress of work on each phase.
The preliminary target date for overall completion of these phases is mid-
1999. The Company is required to charge to expense, as incurred, internal and
external costs specifically associated with modifying internal-use computer
software for the year 2000, in accordance with a July 1996 pronouncement of
the Emerging Issues Task Force of the Financial Accounting Standards Board.
The costs of expected modifications to be made, principally in the next two
years, will be approximately $10 million. The cost or consequences of a
material incomplete or untimely resolution of the year 2000 problem could
adversely affect future operations, financial results or financial condition
of the Company.
6
SALES
-----
The following data present 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.
1997 1996 1995
---------- ---------- ----------
Electric Energy Sales (Thousands of Kilowatt-hours)
---------------------
Kilowatt-hours Sold - Total 25,708,085 25,899,889 25,910,047
========== ========== ==========
By Class of Service -
Residential service 6,564,396 6,882,313 6,720,267
General service 15,307,001 15,185,506 15,448,416
Large power service (a) 698,185 686,713 703,416
Street lighting 166,251 163,536 162,897
Rapid transit 411,634 411,577 409,837
Wholesale 2,560,618 2,570,244 2,465,214
By Type of Customer -
Residential 6,551,773 6,868,516 6,706,775
Commercial 11,811,045 11,711,865 11,861,248
U.S. Government 3,934,440 3,902,378 3,998,052
D.C. Government 850,209 846,886 878,758
Wholesale 2,560,618 2,570,244 2,465,214
Electric Revenue (Thousands of Dollars)
----------------
Sales of Electricity - Total (b) $1,799,800 $1,824,741 $1,813,790
========== ========== ==========
By Class of Service -
Residential service $ 525,652 $ 549,147 $ 544,517
General service 1,073,585 1,076,602 1,075,142
Large power service (a) 35,476 35,667 36,183
Street lighting 12,925 12,469 12,555
Rapid transit 28,862 28,707 28,276
Wholesale 123,300 122,149 117,117
By Type of Customer -
Residential $ 524,695 $ 548,108 $ 543,532
Commercial 851,375 852,497 848,892
U.S. Government 249,341 250,422 252,144
D.C. Government 51,089 51,565 52,105
Wholesale 123,300 122,149 117,117
(a) Large power service customers are served at a voltage of 66KV or
higher.
(b) Exclusive of Other Electric Revenue (000s omitted) of $11,029 in
1997, $10,116 in 1996 and $8,642 in 1995.
7
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 revenue and, conversely, hot
weather during these months has a favorable effect.
The Company includes in revenue the amounts received for sales to other
utilities related to pooling and interconnection agreements. Amounts received
for such interchange deliveries are a component of the Company's fuel rates.
CAPACITY PLANNING
-----------------
General
-------
During the period 1998 through 2007 the Company estimates that its peak
demand will grow at a compound annual rate of approximately 1.5%. 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 demand side management (DSM) and energy use management (EUM)
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. Plans to construct or purchase
additional future capacity may be affected by the ongoing efforts to introduce
competition for the supply of electricity in the jurisdictions being served by
the Company.
Conservation
------------
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. See the information concerning these programs presented in
Management's Discussion and Analysis incorporated by reference in Item 7.
Purchase of Capacity and Energy
-------------------------------
The Company continues to purchase energy from Ohio Edison under the
Company's 1987 long-term capacity purchase agreements with Ohio Edison and
AEI. Pursuant to this agreement, the Company is purchasing 450 megawatts of
capacity and associated energy through the year 2005. In August 1996, the
Company began purchasing energy from the Panda Brandywine L.P. (Panda)
facility, pursuant to a 25-year power purchase agreement for 230 megawatts of
capacity supplied by a gas-fueled combined-cycle cogenerator. Capacity
payments under this agreement commenced in January 1997. In October 1997, the
Company restructured its agreement with Panda to resolve certain disputes
regarding capacity and energy payment rates for the facility. In exchange for
8
an adjustment in capacity payment rates and a reduction in the present value
of capacity payments over the term of the agreement, the Company accrued a
one-time payment to Panda of approximately $3.9 million at December 31, 1997.
Other features of the settlement allow Panda to broker sales of certain
amounts of the Company's system capacity from January 1998 through May 2000,
and to broker or sell energy from the Panda facility. Panda will pay the
Company for the right to broker capacity sales, as well as a fee based on
actual energy sales.
The Company also purchases energy from the Northeast Maryland Waste
Disposal Authority under an avoided cost-based purchase agreement for a 32-
megawatt Montgomery County Resource Recovery Facility. In November 1997, the
Company agreed to purchase the 32-megawatt rated capacity of this facility for
the period November 1, 1997 to December 31, 1998. This purchase facilitated
the sale of 35 megawatts of capacity to Northeast Utilities Service Company
(NUSCO).
The Company has a purchase agreement with SMECO, through 2015, for 84
megawatts of capacity supplied by a combustion turbine installed and owned by
SMECO at the Company's Chalk Point Generating Station. The Company is
responsible for all costs associated with operating and maintaining the
facility.
The Company sold capacity to PECO Energy Company in the amount of 150
megawatts during January 1997 and 100 megawatts for the period February
through May 1997; and to GPU, Inc. in the amount of 130 megawatts for the
period August 1, 1997, through December 31, 1997. In addition, the Company is
currently selling capacity to Delmarva Power & Light Company in the amount of
100 megawatts for the period June 1, 1997, through May 31, 1998. As noted
above, the Company is also selling 35 megawatts of capacity to NUSCO during
the period November 1, 1997 through December 31, 1998.
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.
From January 1, 1995, to December 31, 1997, the Company made property
additions, net of an Allowance for Funds Used During Construction (AFUDC) and
Capital Cost Recovery Factor (CCRF), of $611 million (of which $217 million
were made in 1997) and had property retirements of $110 million (of which $37
million were made in 1997).
In 1997, the Company reduced its projected 1997-2001 construction
program by $313 million, a 26% decrease. The Company's current construction
program calls for estimated expenditures, excluding AFUDC and CCRF, of $175
million in 1998, $180 million in 1999, $160 million in 2000 and 2001, and $170
million in 2002, an aggregate of $845 million for the five-year period. AFUDC
and CCRF are estimated to be $7 million in 1998, $6 million in 1999 and 2000,
$8 million in 2001 and $11 million in 2002. The 1998-2002 construction
program includes approximately $265 million for generating facilities
9
(including approximately $75 million for Clean Air Act compliance), $2 million
for transmission facilities, $575 million for distribution, service and other
facilities, and $3 million associated with the Company's EUM programs. The
Company plans to finance its construction program primarily through funds
provided by operations.
The construction program includes amounts for the construction of
facilities that will not be completed until after 2002. Although the program
includes provision for escalation of construction costs, generally at an
annual rate of 3%, 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 continually and is revised as
appropriate to reflect changes in projections of demand, consumption patterns
and economic trends.
The Clean Air Act Amendments of 1990 (CAA) require 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 implemented cost-
effective plans for complying with Phase I of the Acid Rain portion of the CAA
which requires the reduction of sulfur dioxide and nitrogen oxides emissions
to achieve prescribed standards. Boiler burner equipment for nitrogen oxides
emissions control has been installed and the use of lower-sulfur coal has been
instituted at the Company's Phase I affected stations, Chalk Point and
Morgantown. Anticipated capital expenditures for complying with the second
phase of the CAA total approximately $75 million over the next five years. If
economical, continued use of lower-sulfur coal, cofiring with natural gas and
the purchase of sulfur dioxide (SO2) emission allowances is expected.
Nitrogen oxides emissions reductions will be achieved by installing new boiler
burner controls and equipment at the Company's Dickerson Generating Station.
In addition to the Acid Rain portion of the CAA, the State of Maryland and
District of Columbia are required, by Title I of the CAA, to achieve
compliance with ambient air quality standards for ground-level ozone.
Further, the U.S. Environmental Protection Agency (EPA) has issued proposed
rules for reducing interstate transport of ozone. These provisions are likely
to result in further nitrogen oxides emissions reductions from the Company's
boilers; however, the extent of reductions and associated costs cannot be
predicted at this time.
The Company owns a 9.72% undivided interest in the Conemaugh Generating
Station located in western Pennsylvania. Nitrogen oxides emissions reduction
equipment and flue gas desulfurization equipment have been installed at the
station for compliance with Phases I and II of the CAA. The Company's share
of construction costs for this equipment was $36.2 million. As a result of
installing the flue gas desulfurization equipment, the station has received
additional SO2 emission allowances. The Company's share of these bonus
allowances is being used to reduce CAA compliance costs at its other plants.
10
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").
The ages of the Company's generating units, all of which are in
operation, are presented in the table below.
Generating Number Age
Station of Units (a) (Years) Service Type
-------------- ------------ ------- --------------------
Benning 2 25-29 Cycling
Buzzard Point 16 29 Peaking
Potomac River 2/3 40-48 Cycling/Base
Dickerson 3/3 4-38 Base/Peaking
Chalk Point 2/2/7(b) 6-33 Base/Cycling/Peaking
Morgantown 2/6 24-27 Base/Peaking
(a) By service type.
(b) Includes a combustion turbine unit owned by SMECO and operated by
the Company.
Since the 1970s, the Company has conducted continuing programs to extend the
useful lives of generating units and to ensure their continued availability
and efficiency.
The Company's generating units burn only fossil fuels. The principal
fuel is coal. The Company owns no nuclear generation facilities. The
following table sets forth the quantities of each type of fuel used by the
Company in the years 1997, 1996 and 1995 and the contribution, on the basis of
Btus, of each fuel to energy generated.
1997 1996 1995
-------------- -------------- --------------
% of % of % of
Quantity Btu Quantity Btu Quantity Btu
-------- ----- -------- ----- -------- -----
Coal
(000s net tons) 6,318 89.1 6,224 89.7 6,312 85.4
Residual oil
(000s barrels) 1,350 4.6 1,365 4.8 1,348 4.4
Natural gas
(000s dekatherms) 8,318 4.5 6,111 3.4 16,387 8.5
No. 2 fuel oil
(000s barrels) 564 1.8 657 2.1 580 1.7
11
The following table sets forth the average cost of each type of fuel
burned, for the years shown.
1997 1996 1995
------ ------ ------
Coal: per ton $42.82 $42.17 $41.84
per million Btu 1.65 1.62 1.60
Residual oil: per barrel 20.95 20.04 18.01
per million Btu 3.49 3.19 2.88
Natural gas: per dekatherm 2.87 2.92 2.10
per million Btu 2.87 2.92 2.10
No. 2 fuel oil: per barrel 26.96 25.34 23.71
per million Btu 4.63 4.34 4.06
The system average cost of fuel burned per million Btu was $1.84 in 1997
compared with $1.80 in 1996 and $1.74 in 1995. The increase of approximately
2% in the 1997 system average unit fuel cost compared with the 1996 system
average is attributed primarily to the increased unit cost of coal resulting
principally from an increased cost of railroad transportation. The increase
of approximately 3% in the 1996 system average unit fuel cost compared with
the 1995 system average was primarily the result of the increase in the cost
of residual oil and an increase in the percent of residual oil contribution to
the fuel mix. The Company's major cycling and certain peaking units can burn
either natural gas or oil, adding flexibility in selecting the most cost-
effective fuel mix. The increase in the percent of gas burned in 1997
reflects the decreased price of gas and the decreased usage of higher-cost
oil. The decrease in the percent of gas burned in 1996 reflects the increased
price of gas and the increased usage of lower-cost coal.
12
Ten of the Company's 16 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 turbines, some of
which can burn only No. 2 fuel oil, and others which can burn either natural
gas or No. 2 fuel oil. 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
------------------ ------------------
1997 1996 1995 1997 1996 1995
---- ---- ---- ---- ---- ----
Steam generation
Dual fuel units, capable
of burning coal, residual
oil or a combination of
coal and residual oil.... 17% 17% 18% 31% 33% 29%
Units capable of burning
coal only................ 28% 28% 28% 45% 45% 46%
Units capable of burning
residual oil only........ 8% 8% 8% -% 1% 1%
Units capable of burning
residual oil or natural
gas...................... 18% 18% 19% 4% 4% 6%
Combustion turbines
Units capable of burning
No. 2 fuel oil only...... 8% 8% 9% )
Units capable of burning ) 2% 1% 3%
No. 2 fuel oil or natural )
gas...................... 11% 11% 11% )
Purchased capacity........... 10% 10% 7% 18%(a) 16%(a) 15%(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
13
utilities with which the Company has interconnection arrangements, regulatory
requirements (for future units), environmental constraints, weather conditions
and fuel supply constraints, if any.
The Company has numerous coal contracts, primarily expiring in the
period ranging from late-1998 to mid-1999, for aggregate annual deliveries of
approximately 3.2 million tons. Deliveries under these contracts are expected
to provide approximately 48% of the estimated system coal requirements in
1998. The balance of the Company's coal requirements will be purchased under
shorter-term agreements and on a spot basis from a variety of suppliers. Each
of the Company's coal contracts, which are not fixed price contracts, contains
price escalation/de-escalation provisions whereby the adjusted base price to-
be-paid to the supplier for coal received by the Company is adjusted on a
quarterly basis. Contract price adjustments are calculated according to
changes in the contract-specified published indices and are limited by current
spot market prices. The Company plans to replace the contracts when they
expire with either short-term or spot agreements at favorable prices.
Most of the coal currently used by the Company is deep 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 purchased under one two-year and two one-year contracts.
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 three one-year contracts.
Certain units at the Company's Chalk Point and Dickerson Generating
Stations are capable of burning natural gas as well as oil. The Company has a
contract with Washington Gas Light Company to purchase natural gas for Chalk
Point, extending through December 1998. This is for an interruptible supply
of natural gas with provisions for price review and monthly adjustment. No
term agreement exists to purchase natural gas for the Dickerson Generating
Station. The Company actively pursues spot market purchases of natural gas on
a monthly basis for its Chalk Point and Dickerson stations. 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.
14
REGULATION
----------
The Company's utility operations are regulated by the Maryland and
District of Columbia public service commissions and its wholesale business by
the Federal Energy Regulatory Commission (FERC). 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.
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 270 megawatts.
RATES
-----
General
-------
The Company's retail rates for electric service in Maryland and the
District of Columbia are based on allowed rates of return on 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 investment in Electric Plant in Service (net
of depreciation, certain pre-1981 investment tax credits and plant related
deferred income taxes) 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. The jurisdictional
AFUDC capitalization rates are determined on a gross basis pursuant to
formulas prescribed by the FERC. The effective capitalization rates were
approximately 7.6% in 1997, 7.4% in 1996 and 7.9% in 1995, compounded
semiannually. In Maryland, the Company accrues a capital cost recovery factor
(CCRF) on the retail jurisdictional portion of certain pollution control
expenditures related to compliance with the CAA. The base for calculating
this return is the amount by which the Maryland jurisdictional CAA expenditure
balance exceeds the CAA balance being recovered in base rates. The CCRF rate
for Maryland is 9%. In the District of Columbia, the carrying costs of CAA
expenditures not in rate base are recovered through a base rate surcharge.
15
Rate orders received by the Company during the past three years provided
for changes in annual base rate revenue as shown in the table below. At
December 31, 1997, there were no base rate proceedings filed nor pending
approval before the Company's retail or wholesale regulatory commissions.
Rate
Increase
(Decrease) % Effective
Regulatory Jurisdiction ($000) Change Date
----------------------- ---------- --------- ---------------
Federal-Wholesale $(2,500) (1.8) January 1998
Maryland 24,000 2.6 November 1997
Federal-Wholesale (2,000) (1.7) January 1996
District of Columbia 27,900 3.8 July 1995
Federal-Wholesale 2,300 1.8 January 1995
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.
The District of Columbia fuel rate includes a provision for the current
recovery of purchased capacity costs as well as a provision for the credit for
capacity sales. In Maryland, purchased capacity costs are recovered in base
rates. Accordingly, the Company will seek recovery of future changes in the
levels of these costs through base rate applications to the Maryland
Commission.
The Company reduced its Maryland fuel rate by 9.5% effective August 28,
1997. Included in the reduction was an adjustment for a deferred fuel
amortization credit to refund over a 12-month period approximately $20.7
million of previously overrecovered fuel costs incurred through June 30, 1997.
The Maryland Commission order approving the reduction became final on December
13, 1997. On February 19, 1998, the Company applied for a 10.5% increase in
the Maryland fuel rate, which became effective March 1, 1998 subject to
refund.
See Item 8 - Note 2 of "Notes to Consolidated Financial Statements" for
additional information.
Maryland
--------
On November 25, 1997, pursuant to a settlement agreement, the Commission
authorized a $24 million, or 2.6%, increase in base rate revenues effective
with bills rendered on and after November 30, 1997. Of the $24 million
increase in base rates, approximately $12 million will replace CCRF accrued on
CAA expenditures and, therefore, will have no effect on future net income
16
levels. The increased rates afford the Company the opportunity to recover
capacity costs associated with the Panda agreement previously approved by the
Maryland Commission. Capacity payments to Panda commenced in January 1997 and
totaled $25.3 million in 1997, of which the Maryland portion was approximately
$13 million. In connection with the settlement agreement, no determination
was made with respect to rate of return for purposes of setting rates;
however, a rate of return of 9% will be used by the Company, beginning in
December 1997, for purposes of computing AFUDC and CCRF.
Effective June 6, 1997, the Maryland DSM surcharge tariff was lowered,
which will reduce annual revenues by approximately $17 million, reflecting the
Company's efforts to narrow conservation program offerings and limit
conservation spending. The surcharge includes provisions for the recovery of
lost revenue, amortization of pre-1997 actual program expenditures plus the
initial amortization of 1997 projected program costs, a CCRF on unamortized
program balances and an incentive of $1.6 million awarded for achieving
specified 1996 energy goals. Previously, incentives of $8.9 million and $8.7
million were awarded for achieving 1995 and 1994 energy goals, respectively.
Maryland energy goals for 1996 had been reduced to reflect lower DSM
expenditures; consequently, the performance bonus awarded in 1997 was lower
than those awarded in prior years.
District of Columbia
--------------------
The District of Columbia Public Service Commission authorized a $27.9
million, or 3.8%, increase in base rate revenue effective in July 1995. The
authorized rates are based on a 9.09% rate of return on average rate base,
including an 11.1% return on common stock equity and a capital structure which
excludes short-term debt. In addition, the Commission approved the Company's
Least-Cost Plan filed in June 1994. A four-year DSM spending cap for the
period 1995-1998 was approved, consistent with the Company's proposal to
narrow the scope of DSM activities by discontinuing operation of certain DSM
programs and by reducing expenditures on the remaining programs. This will
enable the Company to implement cost-effective DSM programs while limiting the
impact of such programs on the price of electricity. An Environmental Cost
Recovery Rider (ECRR) was approved to provide for full cost recovery of actual
DSM program expenditures, through a billing surcharge. Costs will be
amortized over 10 years, with a return on unamortized amounts by means of a
CCRF computed at the authorized rate of return. The initial rate, which
reflects actual costs expended from July 1993 through December 1994, resulted
in additional annual revenue of approximately $15 million. Although the
Commission denied the Company's request to recover "lost revenue" due to DSM
programs, through the surcharge, a process has been established whereby the
Company can seek recovery of lost revenue in a separate proceeding. The
Commission also increased the time period for filing Least-Cost Planning cases
from two to three years. In June 1997, the Company filed an Application for
Authority with the Commission to revise its ECRR. In the Application, which
superseded an Application filed in June 1996, the proposed rate seeks recovery
of actual costs expended during 1995 and 1996, and is expected to increase
annual revenue by approximately $9 million. No action has been taken by the
Commission on the revised ECRR, and the Company is unable to predict when the
Commission will act upon the proposed rate. Subsequent rate updates are
17
scheduled to be filed annually on June 1 to reflect the prior year's actual
costs, subject to the annual surcharge recovery limit within the four-year
spending cap for the period 1995-1998 (amounts spent in excess of the annual
surcharge recovery limit, but within the four-year spending cap, are deferred
for future recovery). Remaining allowable expenditures under the spending cap
totaled $10 million at December 31, 1997. Pre-July 1993 DSM costs receive
base rate treatment.
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 $2.3 million effective January 1, 1995. Pursuant to a
new agreement with SMECO for the years 1996 through 1998, a rate reduction of
$2 million from the 1995 rate level became effective January 1, 1996, and an
additional $2.5 million rate reduction became effective January 1, 1998.
SMECO has agreed not to give the Company a notice of reduction or termination
of service prior to December 15, 1998.
Interchange of Power
--------------------
The Company's generating and transmission facilities are interconnected
with those of other transmission owners in the PJM power pool and other
utilities. Historically, the pricing of most PJM-dispatched internal economy
energy transactions was based upon "split savings" whereby such energy was
priced halfway between the cost that the purchaser would incur if the energy
were supplied by its own sources and the cost of production to the company
actually supplying the energy. In April 1997, PJM implemented a "bid-based"
energy market, where companies offer energy at prices based on cost, and
transactions occur at the market's marginal clearing price. The Company's
application for permission to bid using "market based" pricing has been filed
with FERC and is awaiting approval.
See the discussion above and the discussion concerning PJM, PJM
restructuring, bilateral energy sales and capacity purchase and sale
transactions presented in Management's Discussion and Analysis incorporated by
reference in Item 7.
COMPETITION
-----------
The Company is currently engaged in regulatory proceedings in Maryland
where the Public Service Commission has outlined steps and established dates
for the phased-in implementation of competition. In the District of Columbia,
the Public Service Commission is considering various issues regarding electric
18
industry structure and competition but has not rendered a decision. Detailed
information concerning competition is presented in Management's Discussion and
Analysis incorporated by reference in Item 7.
Additionally, in order to prepare for competition, the Company began to
make fundamental changes during 1997 in the shape and direction of its
organizational units and in the business culture of its work force. Utility
operations were reconfigured into three primary business units: generation,
distribution and transmission. These organizational units will offer the
focus and flexibility necessary to maneuver in whatever competitive form the
industry finally takes. Such reorganization allows the Company to make the
best use of its assets while concentrating the efforts of employees on making
each business unit profitable.
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 $663 million
through December 31, 1997, for the construction of pollution control
facilities. The $265 million 1998-2002 construction program for generating
facilities includes estimated provisions for pollution control facilities,
including expenditures for CAA compliance, of $18 million in 1998, $22 million
in 1999, $19 million in 2000, $26 million in 2001, and $17 million in 2002.
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
-----------
On December 11, 1997, U.S. representatives at the climate change
negotiations in Kyoto, Japan, agreed to the reduction of greenhouse gas
emissions in certain portions of the developed world. The Kyoto protocol is
subject to conditions which may not occur, and is also subject to ratification
by the United States Senate, which has indicated that it will not ratify an
agreement unless certain conditions, not currently provided for in the Kyoto
19
protocol, are met. At present, it is not possible to predict whether the
Kyoto protocol will attain the force of law in the United States or what its
impact would be on the Company. Further developments in connection with the
Kyoto process could adversely affect future operations, financial results or
financial condition of the Company.
Under authority of the Clean Air Act of 1970, as amended, the EPA has
issued national primary and secondary standards for the following air
pollutants: sulfur dioxide, nitrogen dioxide, particulate matter, carbon
monoxide, ozone and lead. The 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 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 implemented cost-effective plans for complying with Phase I of
the Acid Rain portion of the CAA which requires the reduction of sulfur
dioxide and nitrogen oxides emissions to achieve prescribed standards. Boiler
burner equipment for nitrogen oxides emissions control has been installed and
the use of lower-sulfur coal has been instituted at the Company's Phase I
affected stations, Chalk Point and Morgantown. Anticipated capital
expenditures for complying with the second phase of the CAA total
approximately $75 million over the next five years. If economical, continued
use of lower-sulfur coal, cofiring with natural gas and the purchase of sulfur
dioxide (SO2) emission allowances is expected. Nitrogen oxides emissions
reductions will be achieved by installing new boiler burner controls and
equipment at the Company's Dickerson Generating Station.
In addition to the Acid Rain portion of the CAA, the State of Maryland
and District of Columbia are required, by Title I of the CAA, to achieve
compliance with ambient air quality standards for ground-level ozone.
Further, the EPA has issued proposed rules for reducing interstate transport
of ozone. These provisions are likely to result in further nitrogen oxides
emissions reductions from the Company's boilers; however, the extent of
reductions and associated costs cannot be predicted at this time.
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. The Company has implemented a cost-effective
approach for complying with state rules under Title I of the CAA which
required the retrofit of existing generating units with Reasonably Available
Control Technology (RACT) for nitrogen oxides control. The Company cannot
predict the impact of future standards which may be required under Title I.
20
The Company is unaware of 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. Recognizing that the station cannot continuously satisfy its
applicable standards, the Company is working with Maryland regulators to
establish revised visible emissions standards.
Water Quality
-------------
The Company's generating stations operate under National Pollutant
Discharge Elimination System (NPDES) permits. A NPDES renewal application
submitted in July 1993 for the Benning station is pending. NPDES permits were
issued for the Potomac River station in February 1994, the Morgantown station
in February 1995, the Dickerson station in August 1996 and the Chalk Point
station in September 1996.
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 criteria, if incorporated into the
NPDES permits for the Company's Chalk Point, Morgantown and Dickerson
Generating Stations, had the potential to cause the Company to incur
significant costs to achieve compliance. The Company, in conjunction with
other utilities, industrial companies and the Maryland Chamber of Commerce,
filed a suit in May 1990 that challenged the validity of the regulations. The
parties entered into a settlement agreement and revised regulations were
adopted on May 6, 1993, in accordance with the settlement agreement. These
revised regulations received EPA approval and the suit was dismissed on July
25, 1994. It is currently not anticipated that these regulations will result
in any significant adverse economic impact on the Company.
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 continually 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. In October
1994, a Remedial Investigation/Feasibility Study (RI/FS) report was submitted
to the EPA. Pursuant to an agreement among the PRPs, the Company is
responsible for 12% of the costs of the RI/FS. Total costs of the RI/FS and
associated activities prior to the issuance of a Record of Decision (ROD) by
the EPA, including legal fees, are currently estimated to be $7.5 million.
The Company has paid $.9 million as of December 31, 1997. The report included
a number of possible remedies, the estimated costs of which range from $2
million to $90 million. On December 31, 1997 the Acting Regional
Administrator for EPA Region III signed an ROD that sets forth EPA's selected
21
remedial action plan. Although the plan selected in the ROD differs from
EPA's July, 1995 proposal, the EPA continues to estimate implementation costs
to be approximately $17 million. The Company cannot estimate the total extent
of the EPA's administrative and oversight costs. To date, the Company has
accrued $1.7 million for its share of this contingency.
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.
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 alleged 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 was 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 sought
contribution and other equitable remedies for remediation of the site. In
October 1993, the parties reached, and the Court approved, a settlement
subject to confirmation by additional site testing that remediation could be
accomplished at or below, and that no regulatory authority would require a
remediation which exceeded, approximately $4 million. The Virginia Department
of Environmental Quality has required additional sampling of the site as part
of its voluntary remediation program.
During 1993, the Company and two other PRPs completed 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 paid one-
third, subject to possible reallocation) was expended on the removal action,
which the EPA has stated is in compliance with the AO. The Company and two
other PRPs have entered into settlements with third parties to recover
approximately $2.4 million of this cost. 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.
During 1993, the Company was served with Amended Complaints filed in
three jurisdictions (Prince George's County, Baltimore City, and Baltimore
County), in separate ongoing, consolidated proceedings each denominated "In
re: Personal Injury Asbestos Case." The Company (and other defendants) were
brought into these cases on a theory of premises liability under which
plaintiffs argue that the Company was negligent in not providing a safe work
environment for employees of its contractors who allegedly were exposed to
asbestos while working on the Company's property. Initially, a total of
approximately 448 individual plaintiffs added the Company to their Complaints.
While the pleadings were not entirely clear, it appeared that each plaintiff
sought $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
22
Corning Fiberglass, Inc. (Owens Corning) alleging that Owens Corning was in
the process of settling approximately 700 individual asbestos-related cases
and seeking a judgment for contribution against the Company on the same theory
of alleged negligence set forth above in the plaintiffs' case. Subsequently,
Pittsburgh Corning Corp. (Pittsburgh Corning) filed a third party complaint
against the Company, seeking contribution for the same plaintiffs involved in
the Owens Corning third party complaint. Since the initial filings in 1993,
approximately 50 individual suits have been filed against the Company. The
third party complaints involving Pittsburgh Corning and Owens Corning were
dismissed by the Baltimore City Court during 1994 without any payment by the
Company. Through December 31, 1997, approximately 400 of the individual
plaintiffs have dismissed their claims against the Company. No payments were
made by the Company in connection with the dismissals. While the aggregate
amount specified in the remaining suits would exceed $400 million, the Company
believes the amounts are greatly exaggerated as were the claims already
disposed of. The amount of total liability, if any, and any related insurance
recovery cannot be precisely determined at this time; however, based on
information and relevant circumstances known at this time, the Company does
not believe these suits will have a material adverse effect on its financial
position. However, an unfavorable decision rendered against the Company could
have a material adverse effect on results of operations in the fiscal year in
which a decision is rendered.
In October 1995, the Company received notice from the EPA that it, along
with several hundred other companies, may be a PRP in connection with the
Spectron Superfund Site located in Elkton, Maryland. The site was operated as
a hazardous waste disposal, recycling, and processing facility from 1961 to
1988. A group of PRPs allege, based on records they have collected, that the
Company's share of liability at this site is .0042%. The EPA has also
indicated that a de minimis settlement is likely to be appropriate for this
site. While the outcome of negotiations and the ultimate liability with
respect to this site cannot be predicted, the Company believes that its
liability at this site will not have a material adverse effect on its
financial position or results of operations.
In December 1995, the Company received notice from the EPA that it is a
PRP under the CERCLA with respect to the release or threatened release of
radioactive and mixed radioactive and hazardous wastes at a site in Denver,
Colorado, operated by RAMP Industries, Inc. Evidence indicates that the
Company's connection to the site arises from an agreement with a vendor to
package, transport and dispose of two laboratory instruments containing small
amounts of radioactive material at a Nevada facility. While the Company
cannot predict its liability at this site, the Company believes that it will
not have a material adverse effect on its financial position or results of
operations.
On October 6, 1997, the Company received notice from the EPA that it,
along with 68 other parties, may be a PRP under the CERCLA at the Butler Mine
Tunnel Superfund site in Pittstown Township, Luzerne County, Pennsylvania.
The site is a mine drainage tunnel with an outfall on the Susquehanna River
where oil waste was disposed via a borehole in the tunnel. The letter
notifying the Company of its potential liability also contained a request for
a reimbursement of approximately $.8 million for response costs incurred by
23
EPA at the site. The letter requested that the Company submit a good faith
proposal to conduct or finance the remedial action contained in a July 1996
ROD. The EPA estimates the present cost of the remedial action to be $3.7
million. While the Company cannot predict its liability at this site, the
Company believes that it will not have a material adverse effect on its
financial position or results of operations.
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 that 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
-----
In January 1998, the Company's current 1993 Labor Agreement with Local
1900 of the International Brotherhood of Electrical Workers (IBEW) was
extended until June 1, 1999. The extension agreement was ratified by the
union membership in January 1998 and all members of Local 1900 received a 2.5%
lump-sum payment in February 1998. The lump-sum payment to the IBEW
membership totaled $2.9 million. All other provisions of the 1993 agreement
remain the same. The IBEW represents 2,534 of the Company's 4,067 employees.
NONUTILITY SUBSIDIARY
---------------------
Potomac Capital Investment Corporation (PCI), the Company's wholly owned
subsidiary, was formed in 1983 with the objective of supplementing utility
earnings and building long-term shareholder value. In April 1996, the Company
reorganized its nonutility subsidiaries whereby PEPCO Enterprises, Inc. (PEI),
an energy services and telecommunications products and services company,
became a subsidiary of PCI. Investments made by PEI contributed $1.7 million
in after-tax earnings to PCI during 1997.
PCI's assets totaled $1.2 billion at December 31, 1997, including
equipment leases of aircraft and power plants totaling $626.9 million,
marketable securities, primarily fixed rate preferred stocks totaling $302.5
million, and to a lesser extent, real estate and other investments. The
Company's equity investment in PCI was $227 million at December 31, 1997,
including $49.9 million in subsidiary retained earnings. Since its inception
in 1983, PCI has paid the parent Company $100 million in dividends.
24
PCI's leasing activities include operating and finance lease
investments, asset management and marketing of aircraft and aircraft engines,
and investments in power generation equipment and real estate.
PCI's earnings for 1997 were $17.1 million compared with net earnings of
$16.9 million in 1996 and a net loss of $124.4 million in 1995. During 1997,
PCI sold its remaining aircraft held for disposal, resulting in a $2 million
pre-tax ($1.3 million after-tax) charge to earnings. As a result of joint
venture operations during 1997, PCI's obligation for previously accrued
deferred income taxes was reduced, resulting in after-tax earnings of $7.4
million after provision for transaction costs. PCI's earnings for 1997 also
include capital gains totaling $4.5 million, net of tax, related primarily to
tender offers accepted by PCI which reduced the cost basis of its preferred
stock portfolio by $83 million since year end 1996. Proceeds were used to pay
down debt, resulting in a decrease in interest expense from 1996.
On December 18, 1997, PCI and RCN Telecom Services, Inc. (RCN) of
Princeton, New Jersey, signed the definitive agreements forming a joint
venture known as Starpower Communications, L.L.C. to provide a package of
local and long distance telephone, cable television, high speed Internet and
other telecommunications services to residents and businesses in the
Washington, D.C./Baltimore/Northern Virginia metropolitan region. The joint
venture is equally owned and managed by PCI and RCN. PCI and RCN each will
invest up to $150 million over a three-year period to build out, market and
provide these services over an advanced fiber optic network. PCI's investment
in the joint venture will be funded through cash from operations and
borrowings under its Medium-Term Note facility. PCI expects that the joint
venture will incur operating losses initially, as it develops and expands its
network and customer base. Start-up costs incurred by PCI relating to the
telecommunications business have been expensed.
The $302.5 million securities portfolio, consisting primarily of fixed-
rate electric utility preferred stocks, provides PCI with liquidity and
investment flexibility. During 1997, PCI reduced the cost basis of its
marketable securities portfolio by $83 million primarily as the result of
calls and acceptance of tender offers (approximately $118.1 million) offset by
purchases of $35.1 million. The reduced size of the preferred stock portfolio
lessens the impact of future fluctuations in interest rates.
PCI's investments in real estate include commercial buildings built for
and leased principally to the tenant, an apartment project, residential land
under development and commercial, industrial and residential land held for
long-term development. PCI's net investment in real estate was $45.3 million
at December 31, 1997.
Additional information concerning PCI's investment activities is
presented in Management's Discussion and Analysis incorporated by reference in
Item 7.
25
[Enlarge/Download Table]
Part I
------
Item 2 PROPERTIES
------ ----------
Megawatts of Net Capability
Steam --------------------------- Net Megawatt-
Generation Steam Combustion Hours Generated
Generating Station Location Primary Fuel Generation Turbine <F1> in 1997
------------------ --------------------------------------- -------------- ------------ ------------ ---------------
(Thousands)
Benning Benning Road and Anacostia River, N.E. No. 4 Oil 550 - 53
Washington, D.C.
Buzzard Point 1st and V Streets, S.W. - - 256 17
Washington, D.C.
Potomac River Bashford Lane and Potomac River Coal 482 - 1,870
Alexandria, Virginia
Dickerson Potomac River, South of Little Monocacy Coal 546 291 3,434
River, Dickerson, Maryland
Chalk Point Patuxent River at Swanson Creek Coal/ 1,907 516 <F2> 4,815
Aquasco, Maryland Residual Oil/
Natural Gas
Morgantown Potomac River, South of Route 301 Coal/ 1,164 248 6,942
Newburg, Maryland Residual Oil
----------- ----------- -----------
Total - Wholly owned Units 4,649 1,311 17,131
Conemaugh Indiana County, Pennsylvania Coal 165 1 1,191
----------- ----------- -----------
Total - All Stations Operated 4,814 1,312 18,322
------------ ===========
Cogeneration - - 263
===========
Purchased Capacity
Ohio Edison <F3> 450 - 3,375
Panda-Brandywine <F4> 230 - 406
------------ -----------
680 - 3,781
------------ ===========
Total System, excluding Short-
term Capacity Transactions 5,494 1,312
------------ ------------
Short-term Capacity Transactions, net <F5> (233) -
------------ ------------
Total System 5,261 1,312
=========== ===========
<FN>
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.
<F1>Combustion turbines burn No. 2 fuel oil and certain units can also burn natural
gas.
<F2>Includes 84 megawatts supplied by a combustion turbine owned by SMECO and
operated by the Company.
<F3>Generating capacity under long-term agreements with Ohio Edison and AEI.
<F4>Generating capacity under long-term agreement with Panda-Brandywine L.P.
<F5>Generating capacity purchases of 32 megawatts from Northeast Maryland Waste Disposal Authority
and generating capacity sales of 100 megawatts to Delmarva Power & Light Company, 130 megawatts
to GPU, Inc. and 35 megawatts to Northeast Utilities Service Company.
</FN>
26
The five steam-electric generating stations, together with combustion
turbines, had an aggregate net capability at December 31, 1997, 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 long-term agreements with Ohio Edison
and AEI. The agreements, which provide for 450 megawatts of capacity and
associated energy, are expected to continue at that level through the year
2005. In addition, the Company has a 25-year agreement with Panda for a 230-
megawatt gas-fueled combined-cycle cogeneration project in Prince George's
County, Maryland. The Panda facility achieved full commercial operation in
October 1996. The net 60-minute peak load in 1997 was 5,689 megawatts, which
occurred on June 25, 1997, and was 1.4% below the all-time summer peak demand
of 5,769 megawatts. To meet the 1997 summer peak demand, the Company also had
approximately 265 megawatts available from its dispatchable EUM 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.
Item 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
------ ---------------------------------------------------
None.
27
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.
Dividends Price Range
Period Per Share High Low
--------------------- --------------- -------- ---------
1997:
First Quarter...... $.415 $26 $23-7/8
Second Quarter..... .415 24-7/8 21-1/8
Third Quarter...... .415 23-3/4 21
Fourth Quarter..... .415 $1.66 26 21
1996:
First Quarter...... $.415 $27-3/8 $24-1/2
Second Quarter..... .415 26-5/8 24-3/8
Third Quarter...... .415 26-3/4 24
Fourth Quarter..... .415 $1.66 27-3/8 23-5/8
The number of holders of Common Stock was 79,626 at March 3, 1998, and
81,229 at December 31, 1997.
There were 118,527,028 and 118,500,891 shares of the Company's $1 par
value Common Stock outstanding at March 3, 1998, and December 31, 1997,
respectively. A total of 200 million shares is authorized.
In January 1998, a dividend of 41-1/2 cents per share was declared
payable March 31, 1998, to holders of record of the Company's common stock on
March 10, 1998. The Company's current annual dividend on common stock is
$1.66 per share. The dividend rate is determined by the Company's Board of
Directors and takes into consideration, among other factors, current and
possible future developments which may affect the Company's income and cash
flow levels. The Company has no current plans to change the dividend;
however, there can be no assurance that the $1.66 dividend rate will be in
effect in the future.
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 1997 Annual Report to shareholders.
28
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 1997 Annual Report to shareholders.
Item 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
------ -------------------------------------------
The consolidated financial statements, together with the report thereon
of Price Waterhouse LLP dated January 16, 1998, and supplementary data from
the Company's 1997 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 and 8, the 1997 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.
29
Part III
--------
Item 10 DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
------- --------------------------------------------------
The information required by Item 10 consisting of information required
by Item 401 of Regulation S-K with regard to Directors of the registrant and
the information required by Item 405 of Regulation S-K is incorporated herein
by reference to the Company's Notice of Annual Meeting of Shareholders and
Proxy Statement dated March 4, 1998.
Information with regard to the executive officers of the registrant as
of March 3, 1998, is as follows:
Executive Officers
------------------
Served in
such position
Name Position Age since
-------------------- -------------------------------- --- -------------
Edward F. Mitchell Chairman of the Board 66 1992 (1)
John M. Derrick, Jr. President and Chief Executive
Officer and Director 57 1997 (2)
Dennis R. Wraase Senior Vice President and
Chief Financial Officer 53 1997 (3)
William T. Torgerson Senior Vice President External
Affairs and General Counsel 53 1994 (4)
Earl K. Chism Vice President and Comptroller 62 1994 (5)
Kirk J. Emge Vice President - Regulatory
Law 48 1994 (6)
Susann D. Felton Vice President - Generation
Fuels and Business Planning 49 1992
William R. Gee, Jr. Vice President - Resource
Planning 57 1991
Robert C. Grantley Vice President - Customer
Service and Power Distribution 49 1989
Anthony J. Kamerick Vice President and Treasurer 50 1994 (7)
Anthony S. Macerollo Vice President - Corporate
Services 56 1989
30
Executive Officers (cont.)
--------------------------
Served in
such position
Name Position Age since
-------------------- -------------------------------- --- -------------
James S. Potts Vice President - Environment 52 1993 (8)
William J. Sim Vice President - Generation 53 1991
Andrew W. Williams Vice President - Transmission
and Marketing 48 1989
None of the above persons has a "family relationship" with any other officer
listed or with any director.
The term of office for each of the above persons is from October 23,
1997, until the next succeeding Annual Meeting and until their successors have
been elected and qualified.
(1) Mr. Mitchell was also Chief Executive Officer, prior to October 23,
1997.
(2) Mr. Derrick was elected to the position of Chief Executive Officer on
October 23, 1997 and President on December 21, 1992.
(3) Mr. Wraase was elected to his present position on April 24, 1996. Prior
to that time, from April 22, 1992, he served as Senior Vice President,
Finance and Accounting.
(4) Mr. Torgerson was elected Senior Vice President and General Counsel on
April 27, 1994. He served as Secretary from August 22, 1994 to April
24, 1996. Prior to 1994 he held the position of Vice President and
General Counsel.
(5) Mr. Chism was elected to his present position on April 27, 1994.
Prior to that time he held the position of Vice President and Treasurer
since July 1989.
(6) Mr. Emge was elected to his present position on April 27, 1994. Prior
to that time he held the position of Deputy General Counsel.
(7) Mr. Kamerick was elected to his present position on April 27, 1994.
Prior to that time he held the position of Comptroller from 1992 to
1994.
(8) 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.
31
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 4, 1998.
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 4, 1998. There is no shareholder that is known to the Company to
be the beneficial owner of more than five percent of any class of the
Company's voting securities.
Item 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
------- ----------------------------------------------
None.
32
Part IV
-------
Item 14 EXHIBITS, FINANCIAL STATEMENT SCHEDULE 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 1997 Annual
Report.
Reference (Page)
----------------
Form 10-K
Annual Report Annual Report
to Shareholders Exhibit 13
--------------- -------------
Consolidated Balance Sheets -
December 31, 1997 and 1996 16-17 30-31
Consolidated Statements of
Earnings - for the years
ended December 31, 1997,
1996 and 1995 18 32
Consolidated Statements of
Cash Flows - for the years
ended December 31, 1997,
1996 and 1995 19 33
Notes to Consolidated Financial
Statements 20-31 34-70
Report of Independent Accountants 32 29
2. Financial Statement Schedule
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 16).
Schedule II (Valuation and Qualifying Accounts) and the Report of
Independent Accountants on Consolidated Financial Statement Schedule is
submitted pursuant to Item 14(d).
All other schedules are omitted because they are not applicable, or the
required information is presented in the financial statements.
33
3. Exhibits required by Securities and Exchange Commission Regulation
S-K (summarized below).
Exhibit
No. Description of Exhibit Reference*
------- ---------------------- ----------
3.1 Charter of the Company.............. Filed herewith.
3.2 By-Laws of the Company.............. Filed herewith.
4 Mortgage and Deed of Trust dated
July 1, 1936, of the Company to
The Bank of New York as Successor
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.
Supplemental Indentures, to the
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.
34
Exhibit
No. Description of Exhibit Reference*
------- ---------------------- ----------
4 May 1, 1949......................... Exh. 7-B to Post-Effective
(cont.) 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.
March 15, 1954 and March 15,
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.
35
Exhibit
No. Description of Exhibit Reference*
------- ---------------------- ----------
4 May 1, 1962......................... Exh. 2-B to Registration
(cont.) 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.
July 3, 1967........................ Exh. 2-B to Registration
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
36
Exhibit
No. Description of Exhibit Reference*
------- ---------------------- ----------
4 April 1, 1973....................... Exh. A to Form 8-K, 5/9/73.
(cont.) 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.
March 1, 1986....................... Exh. 4 to Form 10-K, 3/28/86.
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.
37
Exhibit
No. Description of Exhibit Reference*
------- ---------------------- ----------
4 March 2, 1993....................... Exh. 4 to Form 10-K, 3/26/93.
(cont.) 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.................. Exh. 4 to Form 10-K, 3/25/94.
September 30, 1993.................. Exh. 4 to Form 10-K, 3/25/94.
October 1, 1993..................... Exh. 4 to Form 10-K, 3/25/94.
February 10, 1994................... Exh. 4 to Form 10-K, 3/25/94.
February 11, 1994................... Exh. 4 to Form 10-K, 3/25/94.
March 10, 1995...................... Exh. 4.3 to Registration
Statement No. 61379, 7/28/95.
September 6, 1995................... Exh. 4 to Form 10-K, 4/1/96.
September 7, 1995................... Exh. 4 to Form 10-K, 4/1/96.
October 2, 1997..................... Filed herewith.
4-A Indenture, dated as of January 15,
1988, between the Company and
The Bank of New York, Successor
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.
4-C 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.
Employment Agreement**.............. Exh. 10.1 to Form 10-Q,
10/30/95.
Employment Agreement**.............. Exh. 10.2 to Form 10-Q,
10/30/95.
38
Exhibit
No. Description of Exhibit Reference*
------- ---------------------- ----------
10 Employment Agreement**.............. Exh. 10.3 to Form 10-Q,
(cont.) 10/30/95.
Employment Agreement**.............. Exh. 10.4 to Form 10-Q,
10/30/95.
Amendment to Employment Agreement**. Exh. 10.5 to Form 10-Q,
10/30/95.
Severance Agreement**............... Exh. 10.6 to Form 10-Q,
10/30/95.
Severance Agreement**............... Exh. 10.7 to Form 10-Q,
10/30/95.
Severance Agreement**............... Exh. 10.8 to Form 10-Q,
10/30/95.
Severance Agreement**............... Exh. 10.9 to Form 10-Q,
10/30/95.
Amendment to Employment Agreement**. Exh. 10.1 to Form 10-K,
4/1/96.
Amendment to Employment Agreement**. Exh. 10.2 to Form 10-K,
4/1/96.
Amendment to Employment Agreement**. Exh. 10.3 to Form 10-K,
4/1/96.
Severance Agreement**............... Exh. 10.4 to Form 10-K,
4/1/96.
Severance Agreement**............... Exh. 10.5 to Form 10-K,
4/1/96.
Severance Agreement**............... Exh. 10.6 to Form 10-K,
4/1/96.
Severance Agreement**............... Exh. 10.7 to Form 10-K,
4/1/96.
Severance Agreement**............... Exh. 10.8 to Form 10-K,
4/1/96.
Severance Agreement**............... Exh. 10.9 to Form 10-K,
4/1/96.
Severance Agreement**............... Exh. 10.10 to Form 10-K,
4/1/96.
Severance Agreement**............... Exh. 10.11 to Form 10-K,
4/1/96.
Severance Agreement**............... Exh. 10.12 to Form 10-K,
4/1/96.
Amendment to Agreement, dated
December 8, 1995 between the
Company and the International
Brotherhood of Electrical Workers
(Local Union #1900) and Contract
Ratification Notification dated
December 22, 1995**................. Exh. 10.13 to Form 10-K,
4/1/96.
39
Exhibit
No. Description of Exhibit Reference*
------- ---------------------- ----------
10.1 Amendment to Employment Agreement... Filed herewith.
10.2 1998 General Memorandum of Under-
standing, dated January 8, 1998
between the Company and the
International Brotherhood of
Electrical Workers (Local Union
#1900).............................. Filed herewith.
11 Computation of Earnings Per
Common Share...................... Filed herewith.
12 Computation of Ratios............... Filed herewith.
13 Financial Information Section of
Annual Report..................... Filed herewith.
21 Subsidiaries of the Registrant...... Filed herewith.
23 Consent of Independent Accountants.. Filed herewith.
27 Financial Data Schedule............. 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 pursuant to Item 14(c).
40
(b) Reports on Form 8-K
-------------------
A Current Report on Form 8-K was filed by the Company on October 30,
1997, providing details of the District of Columbia Public Service
Commission's approval of the proposed Merger with Baltimore Gas and
Electric Company (BGE) to create Constellation Energy Corporation.
The item reported on such Form 8-K was Item 5 (Other Events).
A Current Report on Form 8-K was filed by the Company on December 22,
1997, providing details of the termination of the proposed Merger with
BGE to create Constellation Energy Corporation. The item reported on
such Form 8-K was Item 5 (Other Events).
41
[Enlarge/Download Table]
Schedule II Valuation and Qualifying Accounts
----------- ---------------------------------
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 <F1> Deductions <F2> of Period
------------------------------------------- --------- ---------- ----------- ------------- ---------
(Thousands of Dollars)
Year Ended December 31, 1997
Allowance for uncollectible accounts -
customer and other accounts receivable
Utility operations $ 1,598 $ 9,804 $ 1,003 $ (10,003) $ 2,402
Nonutility subsidiary $ 6,000 $ - $ - $ - $ 6,000
Year Ended December 31, 1996
Allowance for uncollectible accounts -
customer and other accounts receivable
Utility operations $ 1,969 $ 8,517 $ 1,225 $ (10,113) $ 1,598
Nonutility subsidiary $ 6,000 $ - $ - $ - $ 6,000
Year Ended December 31, 1995
Allowance for uncollectible accounts -
customer and other accounts receivable
Utility operations $ 2,732 $ 7,171 $ 1,070 $ (9,004) $ 1,969
Nonutility subsidiary $ 5,000 $ 1,000 $ - $ - $ 6,000
<FN>
<F1> Collection of accounts previously written off.
<F2> Uncollectible accounts written off.
</FN>
42
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 26th day of March, 1998.
POTOMAC ELECTRIC POWER COMPANY
(Registrant)
/S/ JOHN M. DERRICK, JR.
By
--------------------------
(John M. Derrick, Jr.,
President, Chief Executive
Officer and Director)
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/ JOHN M. DERRICK, JR.
--------------------------- President, Chief Executive
(John M. Derrick, Jr.) Officer and Director
(ii), Principal Financial Officer
(iii) Principal Accounting Officer
/S/ D. R. WRAASE
--------------------------- Senior Vice President and
(Dennis R. Wraase) Chief Financial Officer
(iv) Directors:
/S/ EDWARD F. MITCHELL
--------------------------- Chairman of the Board
(Edward F. Mitchell)
/S/ ROGER R. BLUNT, SR.
--------------------------- Director
(Roger R. Blunt, Sr.)
March 26, 1998
43
Signature Title Date
--------- ----- ----
(iv) Directors (cont.):
/S/ A. JAMES CLARK
--------------------------- Director
(A. James Clark)
/S/ H. LOWELL DAVIS
--------------------------- Director
(H. Lowell Davis)
--------------------------- Director
(Richard E. Marriott)
/S/ DAVID O. MAXWELL
--------------------------- Director
(David O. Maxwell)
/S/ FLORETTA D. McKENZIE
--------------------------- Director
(Floretta D. McKenzie)
--------------------------- Director
(Ann D. McLaughlin)
/S/ PETER F. O'MALLEY
--------------------------- Director
(Peter F. O'Malley)
/S/ LOUIS A. SIMPSON
--------------------------- Director
(Louis A. Simpson)
/S/ A. THOMAS YOUNG
--------------------------- Director
(A. Thomas Young)
March 26, 1998
44
(c) Exhibit 11 Computations of Earnings Per Common Share
---------- ----------------------------------------
The information required by Exhibit 11 is incorporated herein by
reference to Note 7 of the "Notes to Consolidated Financial Statements" on
page 25 of the Company's Annual Report to shareholders.
45
[Enlarge/Download Table]
Exhibit 12 Computation of Ratios
---------- ---------------------
The computations of the coverage of fixed charges, before income taxes, and
the coverage of combined fixed charges and preferred dividends for each of the
years 1997 through 1993 on the basis of parent company operations only, are as
follows.
For The Year Ended December 31,
---------------------------------------------------------
1997 1996 1995 1994 1993
--------- --------- --------- --------- ---------
(Thousands of Dollars)
Net income $164,749 $220,066 $218,788 $208,074 $216,478
Taxes based on income 97,487 135,011 129,439 116,648 107,223
--------- --------- --------- --------- ---------
Income before taxes 262,236 355,077 348,227 324,722 323,701
--------- --------- --------- --------- ---------
Fixed charges:
Interest charges 146,703 146,939 146,558 139,210 141,393
Interest factor in rentals 23,616 23,560 23,431 6,300 5,859
--------- --------- --------- --------- ---------
Total fixed charges 170,319 170,499 169,989 145,510 147,252
--------- --------- --------- --------- ---------
Income before income taxes and fixed charges $432,555 $525,576 $518,216 $470,232 $470,953
========= ========= ========= ========= =========
Coverage of fixed charges 2.54 3.08 3.05 3.23 3.20
==== ==== ==== ==== ====
Preferred dividend requirements $16,579 $16,604 $16,851 $16,437 $16,255
--------- --------- --------- --------- ---------
Ratio of pre-tax income to net income 1.59 1.61 1.59 1.56 1.50
--------- --------- --------- --------- ---------
Preferred dividend factor $26,361 $26,732 $26,793 $25,642 $24,383
--------- --------- --------- --------- ---------
Total fixed charges and preferred dividends $196,680 $197,231 $196,782 $171,152 $171,635
========= ========= ========= ========= =========
Coverage of combined fixed charges
and preferred dividends 2.20 2.66 2.63 2.75 2.74
==== ==== ==== ==== ====
46
[Enlarge/Download Table]
Exhibit 12 Computation of Ratios
---------- ---------------------
The computations of the coverage of fixed charges, before income taxes, and
the coverage of combined fixed charges and preferred dividends for each of the
years 1997 through 1993 on a fully consolidated basis are as follows.
For The Year Ended December 31,
---------------------------------------------------------
1997 1996 1995 1994 1993
--------- --------- --------- --------- ---------
(Thousands of Dollars)
Net income $181,830 $236,960 $94,391 $227,162 $241,579
Taxes based on income 65,669 80,386 43,731 93,953 62,145
--------- --------- --------- --------- ---------
Income before taxes 247,499 317,346 138,122 321,115 303,724
--------- --------- --------- --------- ---------
Fixed charges:
Interest charges 216,156 231,029 238,724 224,514 221,312
Interest factor in rentals 23,687 23,943 26,685 9,938 9,257
--------- --------- --------- --------- ---------
Total fixed charges 239,843 254,972 265,409 234,452 230,569
--------- --------- --------- --------- ---------
Nonutility subsidiary capitalized interest (493) (649) (529) (521) (2,059)
--------- --------- --------- --------- ---------
Income before income taxes and fixed charges $486,849 $571,669 $403,002 $555,046 $532,234
========= ========= ========= ========= =========
Coverage of fixed charges 2.03 2.24 1.52 2.37 2.31
==== ==== ==== ==== ====
Preferred dividend requirements $16,579 $16,604 $16,851 $16,437 $16,255
--------- --------- --------- --------- ---------
Ratio of pre-tax income to net income 1.36 1.34 1.46 1.41 1.26
--------- --------- --------- --------- ---------
Preferred dividend factor $22,547 $22,249 $24,602 $23,176 $20,481
--------- --------- --------- --------- ---------
Total fixed charges and preferred dividends $262,390 $277,221 $290,011 $257,628 $251,050
========= ========= ========= ========= =========
Coverage of combined fixed charges
and preferred dividends 1.86 2.06 1.39 2.15 2.12
==== ==== ==== ==== ====
47
Exhibit 21 Subsidiaries of the Registrant
---------- ------------------------------
The Company has one wholly owned nonutility subsidiary company, Potomac
Capital Investment Corporation (PCI), which was incorporated in Delaware in
1983.
Exhibit 23 Consent of Independent Accountants
---------- ----------------------------------
We hereby consent to the incorporation by reference in the Registration
Statements on Forms S-8 (Numbers 33-36798, 33-53685 and 33-54197) and to the
incorporation by reference in the Prospectuses constituting part of the
Registration Statements on Forms S-3 (Numbers 33-58810, 33-61379 and 333-
33495) of Potomac Electric Power Company of our report dated January 16, 1998
appearing in the Annual Report to shareholders which is incorporated in this
Annual Report on Form 10-K. We also consent to the incorporation by reference
of our report on the Consolidated Financial Statement Schedule, which appears
under Item 14(a) of this Form 10-K.
/s/ Price Waterhouse LLP
Washington, D.C.
March 26, 1998
48
Report of Independent Accountants on Consolidated
-------------------------------------------------
Financial Statement Schedule
----------------------------
January 16, 1998
To the Board of Directors of
Potomac Electric Power Company
Our audits of the consolidated financial statements referred to in our report
dated January 16, 1998 appearing in the 1997 Annual Report to shareholders of
Potomac Electric Power Company (which report and consolidated financial
statements are incorporated by reference in this Annual Report on Form 10-K)
also included an audit of the consolidated financial statement schedule
listed in Item 14(a) of this Form 10-K. In our opinion, this consolidated
financial statement schedule presents fairly, in all material respects, the
information set forth therein when read in conjunction with the related
consolidated financial statements.
/s/ Price Waterhouse LLP
Washington, D.C.
49
Dates Referenced Herein and Documents Incorporated by Reference
| This ‘10-K405’ Filing | | Date | | Other Filings |
|---|
| |  |
| | 1/15/18 |
| | 9/1/02 |
| | 6/1/99 |
| | 12/31/98 | | 10-K405, 8-K |
| | 12/15/98 |
| | 5/31/98 |
| | 4/1/98 |
| | 3/31/98 | | 10-Q |
| Filed on: | | 3/27/98 |
| | 3/26/98 |
| | 3/10/98 |
| | 3/4/98 |
| | 3/3/98 |
| | 3/1/98 |
| | 2/19/98 |
| | 1/16/98 |
| | 1/8/98 |
| | 1/1/98 |
| | 12/31/97 |
| | 12/22/97 | | 8-K |
| | 12/18/97 |
| | 12/13/97 |
| | 12/11/97 | | 11-K |
| | 11/30/97 |
| | 11/25/97 |
| | 11/1/97 |
| | 10/30/97 | | 8-K |
| | 10/23/97 | | DEF 14A |
| | 10/6/97 |
| | 10/2/97 |
| | 8/28/97 |
| | 8/1/97 |
| | 6/30/97 | | 10-Q, 11-K |
| | 6/25/97 |
| | 6/6/97 |
| | 6/1/97 |
| | 4/1/97 |
| For Period End: | | 12/31/96 | | 10-K |
| | 4/24/96 | | DEF 14A |
| | 1/1/96 |
| | 12/31/95 | | 10-K405 |
| | 12/22/95 |
| | 12/8/95 |
| | 9/7/95 | | 424B5 |
| | 9/6/95 |
| | 3/10/95 |
| | 1/1/95 |
| | 8/22/94 |
| | 7/25/94 |
| | 4/27/94 | | DEF 14A |
| | 2/11/94 |
| | 2/10/94 |
| | 10/1/93 |
| | 9/30/93 |
| | 9/29/93 |
| | 8/20/93 |
| | 7/23/93 |
| | 7/1/93 |
| | 5/6/93 |
| | 4/28/93 |
| | 3/2/93 |
| | 3/1/93 |
| | 12/21/92 |
| | 11/1/92 |
| | 9/1/92 |
| | 8/15/92 |
| | 5/7/92 |
| | 4/22/92 |
| List all Filings |
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