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, 1996 Commission file number 1-1072
----------------- ------
Potomac Electric Power Company
- ------------------------------------------------------------------------------
(Exact name of registrant as specified in its charter)
District of Columbia and Virginia 53-0127880
- --------------------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1900 Pennsylvania Avenue, N.W.
Washington, D. C. 20068
- --------------------------------------------- -------------------
(Address of principal executive 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 )
$2.44 Convertible )
Series of 1966 )
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. .
---
As of January 31, 1997, Potomac Electric Power Company had
118,496,828 shares of its $1 par value Common Stock outstanding, and the
aggregate market value of these common shares (based upon the closing price of
these shares on the New York Stock Exchange on that date) held by
nonaffiliates was approximately $2.9 billion.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Company's 1996 Annual Report to shareholders are
incorporated by reference into Parts II and IV of this Form 10-K.
2
POTOMAC ELECTRIC POWER COMPANY
Form 10-K - 1996
TABLE OF CONTENTS
PART I Page
Item 1 - Business ----
Proposed Merger .................................................... 5
General ............................................................ 6
Sales .............................................................. 8
Capacity Planning .................................................. 9
Construction Program ............................................... 11
Fuel ............................................................... 13
Regulation ......................................................... 17
Rates .............................................................. 17
Competition ........................................................ 21
Environmental Matters .............................................. 22
Labor .............................................................. 27
Nonutility Subsidiary .............................................. 27
Item 2 - Properties .................................................. 30
Item 3 - Legal Proceedings ........................................... 31
Item 4 - Submission of Matters to a Vote of Security Holders ......... 31
PART II
Item 5 - Market for the Registrant's Common Equity and Related
Stockholder Matters ....................................... 32
Item 6 - Selected Financial Data ..................................... 33
Item 7 - Management's Discussion and Analysis of Financial Condition
and Results of Operations ................................. 33
Item 8 - Financial Statements and Supplementary Data ................. 33
Item 9 - Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure .................................. 33
PART III
Item 10 - Directors and Executive Officers of the Registrant ......... 34
Item 11 - Executive Compensation ..................................... 39
Item 12 - Security Ownership of Certain Beneficial Owners and
Management................................................ 48
Item 13 - Certain Relationships and Related Transactions ............. 49
PART IV
Item 14 - Exhibits, Financial Statement Schedule and Reports on
Form 8-K ................................................. 50
Schedule VIII - Valuation and Qualifying Accounts .................. 58
Signatures ........................................................... 59
Exhibit 11 - Computations of Earnings Per Common Share .......... 61
Exhibit 12 - Computation of Ratios .............................. 62
Exhibit 21 - Subsidiaries of the Registrant ..................... 64
Exhibit 23 - Consent of Independent Accountants ................. 65
Report of Independent Accountants on Consolidated Financial
Statement Schedule ............................................... 66
3
PAGE LEFT BLANK
INTENTIONALLY
4
Part I
- ------
Item 1 BUSINESS
- ------ --------
PROPOSED MERGER
- ---------------
Shareholders of Potomac Electric Power Company (the Company, PEPCO) and
Baltimore Gas and Electric Company (BGE), at separate special meetings during
March 1996, approved a proposed merger (the Merger) to form Constellation
Energy Corporation (Constellation Energy). The Company and BGE filed a joint
Application for Authorization and Approval of the Merger with the Federal
Energy Regulatory Commission (FERC) on January 11, 1996, and with the Maryland
and District of Columbia Public Service Commissions on April 8, 1996. On July
31, 1996, FERC set the application for hearing on the issue of whether the
Merger would impact competition. Hearings began on October 21, 1996, and the
Administrative Law Judge certified the record to the Commission on October 25,
1996. The case was placed before FERC for decision in December 1996. The
Maryland Commission conducted hearings during June, September and December
1996. The case was placed before the Maryland Commission for decision in
January 1997. A prehearing conference was conducted by the District of
Columbia Commission in May 1996 and a procedural schedule was published in
July 1996. The hearings, which were originally scheduled to take place in
December 1996, have been rescheduled for February 1997. The case is expected
to be before the District of Columbia Commission for decision in March 1997.
On January 29, 1997, the waiting period under the Hart-Scott-Rodino Antitrust
Improvements Act was terminated and the parties may close the Merger after
regulatory approvals from other federal and state agencies are received. The
Nuclear Regulatory Commission has approved the transfer of BGE's ownership
interest in the operating licenses for the two generating units at the Calvert
Cliffs Nuclear Power Plant to Constellation Energy at the effective time of
the Merger. In addition, the State Corporation Commission of Virginia has
approved the Merger. The Merger also requires approval from the Pennsylvania
Public Utility Commission. Completion of the approval process is expected to
take until the end of the first quarter of 1997.
The combination of the Company and BGE will create a larger, stronger
company better able to maintain the low costs which will be essential to
compete effectively in the future, and better able to contribute to economic
and job development in the area. The Merger will result in lower operating
costs than either company could produce alone. Over the first 10 years
following the Merger, Constellation Energy expects to achieve net merger-
related savings of $1.3 billion. Additional information regarding the Merger
is presented in Note 13 of "Notes to Consolidated Financial Statements"
incorporated by reference in Item 8.
5
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. 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 1996 and 1995. 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 1996, approximately 59% of the Company's revenue
was derived from Maryland sales (including wholesale) and 41% from sales in
the District of Columbia. About 30% of the Company's revenue was derived from
residential customers, 63% from sales to commercial and government customers
and 7% from sales at wholesale. Approximately 14% and 3% of 1996 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.
The Company is a member of the Pennsylvania-New Jersey-Maryland
Interconnection Association (PJM) pursuant to an agreement under which its
generating and transmission facilities are operated on an integrated basis
with those of the other PJM member utilities in Pennsylvania, New Jersey,
Maryland, Delaware and a small portion of Virginia. The purpose of PJM is to
improve the operating economy and reliability of the systems in the group and
to provide capital economies by permitting lower reserve requirements than
would be required on a system basis. The Company also has direct high voltage
connections with the Potomac Edison Company, a subsidiary of Allegheny Power
System, Inc. (APS), and Virginia Power, neither of which is a member of PJM.
On July 24, 1996, nine of 10 PJM member companies, excluding PECO Energy
Company (PECO), filed, with the FERC, a comprehensive proposal to establish an
Independent System Operator (ISO) which would administer transmission service
under a PJM control area transmission tariff and operate the energy market in
a manner that assures comparable treatment for all participants. In early
August 1996, PECO filed a competing plan, opposing certain key features of the
previous proposal. On November 13, 1996, the FERC found that it could not
accept either proposal and ordered the PJM members to amend its proposals to
comport with Order No. 888 regarding open access tariffs and to attempt to
reach a consensus with other stakeholders. On December 31, 1996, the PJM
member companies filed a joint response to the FERC's order, which would, if
accepted, establish a single poolwide transmission tariff and modify the
membership and governance provisions of the PJM agreement. This compliance
filing is intended as an interim solution until a more comprehensive proposal
can be developed. These changes are not expected to have a material effect on
the operating results of the Company.
6
Additional information concerning the restructuring of the bulk power
market is presented in Management's Discussion and Analysis incorporated by
reference in Item 7.
7
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.
1996 1995 1994
---------- ---------- ----------
Electric Energy Sales (Thousands of Kilowatt-hours)
---------------------
Kilowatt-hours Sold - Total 25,899,889 25,910,047 25,546,210
========== ========== ==========
By Class of Service -
Residential service 6,882,313 6,720,267 6,586,970
General service 15,185,506 15,448,416 15,345,484
Large power service (a) 686,713 703,416 683,762
Street lighting 163,536 162,897 162,439
Rapid transit 411,577 409,837 404,634
Wholesale 2,570,244 2,465,214 2,362,921
By Type of Customer -
Residential 6,868,516 6,706,775 6,574,199
Commercial 11,711,865 11,861,248 11,685,351
U.S. Government 3,902,378 3,998,052 4,009,810
D.C. Government 846,886 878,758 913,929
Wholesale 2,570,244 2,465,214 2,362,921
Electric Revenue (Thousands of Dollars)
----------------
Sales of Electricity - Total (b) $1,824,741 $1,813,790 $1,783,064
========== ========== ==========
By Class of Service -
Residential service $ 549,147 $ 544,517 $ 525,660
General service 1,076,602 1,075,142 1,066,710
Large power service (a) 35,667 36,183 35,701
Street lighting 12,469 12,555 13,783
Rapid transit 28,707 28,276 27,892
Wholesale 122,149 117,117 113,318
By Type of Customer -
Residential $ 548,108 $ 543,532 $ 524,738
Commercial 852,497 848,892 834,323
U.S. Government 250,422 252,144 254,030
D.C. Government 51,565 52,105 56,655
Wholesale 122,149 117,117 113,318
(a) Large power service customers are served at a voltage of 66KV or
higher.
(b) Exclusive of Other Electric Revenue (000s omitted) of $10,116 in 1996,
$8,642 in 1995 and $7,536 in 1994.
8
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 1997 through 2006 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.
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.
The Company's DSM and EUM programs are designed to curb growth in demand
in order to defer the need for construction of additional generating capacity
and to cost-effectively increase the efficiency of energy use. To reduce the
near-term upward pressure on customer rates and bills, the Company has, since
1994, phased out several conservation programs and reduced rebate levels for
others. By narrowing its conservation offerings and limiting conservation
spending, the Company expects to continue to encourage its customers to use
energy efficiently without significantly increasing electricity prices. In a
June 1995 order, the Public Service Commission of the District of Columbia
adopted a DSM spending cap for the four-year period 1995 through 1998. The
Company continues to manage its existing portfolio of DSM programs to ensure
that the costs of these programs do not exceed the spending limit. In
December 1996, the Company announced the suspension of the New Building Design
Program in the District of Columbia because current commitments for rebates
are projected to reach the spending limit for commercial programs. In
addition, the Company has not accepted new applications in the Custom Rebate
Program since its suspension in November 1994. Remaining allowable
expenditures under the DSM spending cap totaled $15 million at December 31,
9
1996. The Company expects to realize approximately 80% of the previously
estimated benefits from its demand side management programs for approximately
45% of the previously estimated costs.
During 1996, the Company invested approximately $27 million in Maryland
DSM programs. The Company recovers the costs of Maryland DSM programs through
a base rate surcharge which amortizes costs over a five-year period and
permits the Company to earn a return on its DSM investment while receiving
compensation for lost revenue. In addition, when energy savings exceed annual
goals, the Company earns a bonus. The Company was awarded a bonus of $8.9
million in 1996, based on 1995 performance, which followed bonuses of $8.7
million in 1995, based on 1994 performance and $5 million in 1994, based on
1993 performance. Maryland DSM program goals for 1996 have been reduced to
reflect lower DSM expenditures. Consequently, the performance bonus in 1997
is expected to be significantly lower than amounts awarded for performance in
prior years.
Investment in District of Columbia DSM programs totaled approximately
$18 million in 1996. These DSM costs are amortized over 10 years with an
accrued return on unamortized costs. In June 1995, the Commission adopted a
base rate surcharge for the recovery of actual DSM costs prudently incurred
since June 30, 1993; prior to this decision, DSM costs had been considered in
base rate cases. Subsequent rate updates are scheduled to be filed annually
on June 1 to reflect the prior year's actual costs, subject to the annual
surcharge recovery limit within the four-year spending cap for the period
1995-1998 (amounts spent in excess of the annual surcharge recovery limit, but
within the four-year spending cap, are deferred for future recovery).
Remaining allowable expenditures under the spending cap totaled $15 million at
December 31, 1996. Pre-July 1993 DSM costs receive base rate treatment. This
surcharge includes both a conservation expenditure component and a component
for recovering certain expenditures associated with complying with the Clean
Air Act Amendments of 1990. The conservation component is updated annually in
the spring of each year, while the Clean Air Act component is updated
quarterly. On June 3, 1996, the Company filed an application with the
District of Columbia Public Service Commission requesting approval for an
updated conservation component to reflect the recoverable DSM costs expended
during 1995. The proposed rate is expected to increase annual revenue by
approximately $8 million. No action has been taken by the District of
Columbia Public Service Commission on the proposed surcharge rate.
In 1996, approximately 160,000 customers participated in continuing EUM
programs which cycle air conditioners and water heaters during peak periods.
In addition, the Company operates a commercial load program which provides
incentives to customers for reducing energy use during peak periods. Time-of-
use rates have been in effect since the early 1980s and currently
approximately 60% of the Company's revenue is derived from time-of-use rates.
It is estimated that peak load reductions of nearly 700 megawatts have
been achieved to date from DSM and EUM programs and that additional peak load
reductions of approximately 400 megawatts will be achieved in the next five
years. The Company also estimates that, in 1996, energy savings of more than
1.6 billion kilowatt-hours have been realized through operation of its DSM and
10
EUM programs. During the next five years, the Company's projected costs for
conservation programs that encourage the efficient use of electric energy and
reduce the need to build new generating facilities total $330 million ($55
million in 1997).
Although the Company is continuing its DSM and EUM efforts, new sources
of supply will be needed to assure the future reliability of electric service
to the Washington area beyond the year 2000. These new sources of supply will
be provided through the Company's plans for purchases of capacity and energy
and through its ongoing construction program.
Purchase of Capacity and Energy
- -------------------------------
Throughout 1996, the Company purchased energy from Ohio Edison under the
Company's 1987 long-term capacity purchase agreements with Ohio Edison and
APS, and from the Northeast Maryland Waste Disposal Authority under an avoided
cost-based purchase agreement for a 32-megawatt Montgomery County Resource
Recovery Facility. Pursuant to the Company's long-term capacity purchase
agreements with Ohio Edison and APS, the Company is purchasing 450 megawatts
of capacity and associated energy through the year 2005. Capacity payments
for the Montgomery County Resource Recovery facility are not expected to
commence until after the year 2000. In August 1996, the Company began
purchasing energy from the Panda 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. The Panda facility achieved full
commercial operation in October 1996. Capacity payments under this agreement
commence in January 1997.
The Company has a purchase agreement with Southern Maryland Electric
Cooperative, Inc. (SMECO), through 2015, for 84 megawatts of capacity supplied
by a combustion turbine installed and owned by SMECO at the Company's Chalk
Point Generating Station. The Company is responsible for all costs associated
with operating and maintaining the facility.
In October 1996, the Company began selling capacity to GPU, Inc. in the
amount of 100 megawatts during both October and November 1996 and 90 megawatts
for December 1996. Capacity sales are expected to continue during 1997.
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, 1994, to December 31, 1996, the Company made property
additions, net of an Allowance for Funds Used During Construction (AFUDC) and
Capital Cost Recovery Factor (CCRF), of $686 million (of which $180 million
were made in 1996) and had property retirements of $117 million (of which $31
million were made in 1996).
11
The Company's current construction program calls for estimated
expenditures, excluding AFUDC and CCRF, of $215 million in 1997, $230 million
in 1998, $235 million in 1999, $245 million in 2000 and $280 million in 2001,
an aggregate of $1.2 billion for the five-year period. AFUDC and CCRF are
estimated to be $16 million in 1997, $17 million in 1998, $18 million in 1999,
$21 million in 2000 and $27 million in 2001. The 1997-2001 construction
program includes approximately $590 million for generating facilities
(including $18 million for Clean Air Act compliance), $60 million for
transmission facilities, $551 million for distribution, service and other
facilities, and $4 million associated with the Company's energy use management
programs. The Company plans to finance its construction program primarily
through funds provided by operations. Actual construction expenditures and
activity during the period 1997 through 2001 may vary from projections once
the Merger with BGE becomes effective.
The construction program includes amounts for the construction of
facilities that will not be completed until after 2001. Although the program
includes provision for escalation of construction costs, generally at an
annual rate of 3.5%, 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 $18 million over the next five years. Plans for
complying with the second phase of the CAA are being reviewed in anticipation
of the pending Merger with BGE. If economical, continued use of lower-sulfur
coal, cofiring with natural gas and the purchase of sulfur dioxide (SO2)
emission allowances is expected. Nitrogen oxides emissions reductions will be
achieved by installing control equipment in the most cost-effective manner
after considering the characteristics of each of the merged company's boilers.
In addition to the Acid Rain portion of the CAA, the State of Maryland and
District of Columbia are required, by Title I of the CAA, to achieve
compliance with ambient air quality standards for ground-level ozone. This
provision is likely to result in further nitrogen oxides emissions reductions
from the Company's boilers; however, the extent of reductions and associated
cost cannot be estimated at this time.
Installation of scrubbers is not contemplated for the Company's wholly
owned plants. Both the District of Columbia and Maryland commissions have
approved the Company's plans for meeting Phase I requirements including cost
recovery of investment and inclusion of emission allowance expenses in the
Company's fuel adjustment clause.
12
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 Phase I of the CAA. The Company's share of the
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 will be used to reduce the need for lower-sulfur fuel at its other
plants.
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 24-28 Cycling
Buzzard Point 16 28 Peaking
Potomac River 2/3 39-47 Cycling/Base
Dickerson 3/3 3-37 Base/Peaking
Chalk Point 2/2/7(b) 5-32 Base/Cycling/Peaking
Morgantown 2/6 23-26 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.
13
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 1996, 1995 and 1994 and the contribution, on the basis of
Btus, of each fuel to energy generated.
1996 1995 1994
-------------- -------------- --------------
% of % of % of
Quantity Btu Quantity Btu Quantity Btu
-------- ----- -------- ----- -------- -----
Coal
(000s net tons) 6,224 89.7 6,312 85.4 5,788 76.1
Residual oil
(000s barrels) 1,365 4.8 1,348 4.4 4,868 15.7
Natural gas
(000s dekatherms) 6,111 3.4 16,387 8.5 10,780 5.5
No. 2 fuel oil
(000s barrels) 657 2.1 580 1.7 919 2.7
The following table sets forth the average cost of each type of fuel
burned, for the years shown.
1996 1995 1994
------ ------ ------
Coal: per ton $42.17 $41.84 $44.39
per million Btu 1.62 1.60 1.73
Residual oil: per barrel 20.04 18.01 15.31
per million Btu 3.19 2.88 2.44
Natural gas: per dekatherm 2.92 2.10 2.49
per million Btu 2.92 2.10 2.49
No. 2 fuel oil: per barrel 25.34 23.71 24.34
per million Btu 4.34 4.06 4.17
The average cost of fuel burned per million Btu was $1.80 in 1996,
compared with $1.74 in 1995 and $1.95 in 1994. The 1996 system average unit
fuel cost increased by approximately 3% which 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 decrease of approximately 11%
in the 1995 system average unit fuel cost compared with the 1994 system
average resulted from increased use of lower-cost coal and gas and decreased
net generation. 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 decrease in the percent of gas burned in 1996
reflects the increased price of gas and the increased usage of lower-cost
coal. The increase in the percent of gas burned in 1995 reflects the
decreased price of gas and the increased price of oil.
14
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 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
------------------ ------------------
1996 1995 1994 1996 1995 1994
---- ---- ---- ---- ---- ----
Steam Generation
Dual fuel units, capable
of burning coal, residual
oil or a combination of
coal and residual oil.... 17% 18% 17% 33% 29% 28%
Units capable of burning
coal only................ 28% 28% 28% 45% 46% 43%
Units capable of burning
residual oil only........ 8% 8% 8% 1% 1% 1%
Units capable of burning
residual oil or natural
gas...................... 18% 19% 18% 4% 6% 12%
Combustion Turbines
Units capable of burning
No. 2 fuel oil only...... 8% 9% 9% )
Units capable of burning ) 1% 3% 3%
No. 2 fuel oil or natural )
gas...................... 11% 11% 11% )
Purchased capacity........... 10% 7% 9% 16%(a) 15%(a) 13%(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
15
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 with various expiration dates
through 2003 for aggregate annual deliveries of approximately 3.2 million
tons. Deliveries under these contracts are expected to provide approximately
54% of the estimated system coal requirements in 1997. Approximately 46% of
the estimated system coal requirements in 1997 will be purchased under shorter
term agreements and on a spot basis from a variety of suppliers. Each of the
Company's longer term 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.
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. In addition, the Company actively
pursues spot market natural gas purchases when there is economic benefit. The
Company has a one-year contract with Eastern Energy Marketing for the
Dickerson combustion turbine units through March 31, 1997. Both contracts are
for an interruptible supply of natural gas with provisions for price review
and adjustment each month. The actual use of natural gas for these units will
be dependent upon operational requirements, the relative costs of natural gas
and oil, and the availability of natural gas.
16
REGULATION
- ----------
The Company's utility operations are regulated by the Maryland and
District of Columbia Public Service Commissions and, as to its wholesale
business, the Federal Energy Regulatory Commission (FERC). In addition, in
certain limited respects relating to its participation in the Conemaugh
Generating Station and related transmission lines, the Company is subject to
regulation by the Pennsylvania Public Utility Commission.
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 investments 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 7.4% in 1996, 7.9% in 1995 and 7.6% in 1994, 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 rate base in the Company's
most recently completed base rate proceeding. The CCRF rate for Maryland is
9.46%. In the District of Columbia, the carrying costs of CAA expenditures
not in rate base are recovered through a base rate surcharge.
17
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, 1996, there were no base rate proceedings filed nor pending
approval by any of the Company's retail or wholesale regulatory commissions.
Rate
(Decrease)
Increase % Effective
Regulatory Jurisdiction ($000) Change Date
----------------------- ---------- --------- ---------------
Federal-Wholesale $(2,000) (1.7) January 1996
District of Columbia 27,900 3.8 July 1995
Federal-Wholesale 2,300 1.8 January 1995
District of Columbia 26,700 3.9 March/June 1994
Federal-Wholesale 2,600 2.3 January 1994
Maryland 27,000 3.0 November 1993
Fuel Rates
- ----------
The Company has separately stated fuel rates in each jurisdiction. Such
rates include the delivered cost of fuel and the applicable costs and/or
credits from the interchange of energy with other electric utilities, to the
extent not provided for in base rates. (See Item 8 - Note 2 of "Notes to
Consolidated Financial Statements" for additional information).
Maryland
- --------
Pursuant to a settlement agreement, base rate revenue was increased by
$27 million, or 3%, effective November 1, 1993. In connection with the
settlement agreement, no determination was made with respect to rate of
return. The rate of return on common stock equity most recently determined
for the Company in a fully litigated rate case was 12.75% established by the
Commission in a June 1991 rate increase order.
Effective August 27, 1996, the Maryland DSM surcharge tariff was
increased, providing approximately $18 million annually in increased revenue.
The surcharge includes provisions for the recovery of lost revenue,
amortization of pre-1996 actual program expenditures plus the initial
amortization of 1996 projected program costs, a capital cost recovery factor
of 9.46% on unamortized balances and an incentive of $8.9 million awarded for
exceeding 1995 energy saving goals. Previously, incentives of $8.7 million
and $5 million were awarded for exceeding 1994 and 1993 energy saving goals,
respectively. Maryland DSM program goals for 1996 have been reduced to
reflect lower DSM expenditures. Consequently, the performance bonus in 1997
is expected to be significantly lower than amounts awarded for performance in
prior years.
18
On November 8, 1996, the Company filed a request with the Maryland
Public Service Commission for approval of a purchased capacity surcharge,
which is designed to recover changes in the level of purchased capacity costs
from levels included in base rates. The filing was made to recover capacity
payments under the Panda contract, which commenced January 1, 1997. The
estimated 1997 Maryland portion of these payments is $10.5 million. On
January 8, 1997, the Maryland Public Service Commission suspended the
Company's request for a period of 90 days from January 8, 1997, or until the
date of a Commission Order in the Joint Application for Authorization and
Approval of the Merger with BGE, whichever comes first. The District of
Columbia portion of the Panda capacity costs will be recovered through the
existing fuel adjustment clause.
District of Columbia
- --------------------
In Formal Case No. 939, the Commission, in June 1995, authorized a $27.9
million, or 3.8%, increase in base rate revenue effective July 11, 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
capital cost recovery factor 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. On June 3, 1996, the
Company filed an Application for Authority with the Commission to revise its
ECRR. The proposed rate, which reflects actual costs expended during 1995, is
expected to increase annual revenue by approximately $8 million. No action
has been taken by the District of Columbia Public Service Commission on the
revised ECRR. Subsequent rate updates are scheduled to be filed annually on
June 1 to reflect the prior year's actual costs, subject to the annual
surcharge recovery limit within the four-year spending cap for the period
1995-1998 (amounts spent in excess of the annual surcharge recovery limit, but
within the four-year spending cap, are deferred for future recovery). Pre-
July 1993 conservation costs receive base rate treatment. The Commission
previously authorized an increase in base rate revenue of $23.2 million
effective March 16, 1994, and $2.2 million effective June 5, 1994. A further
base rate increase of $1.3 million was authorized pursuant to a May 1994 order
on reconsideration of the Commission's March 1994 rate order.
19
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 and $2.6 million effective January 1,
1995 and 1994, respectively. Pursuant to a new agreement with SMECO for the
years 1996 through 1998, a rate reduction of $2 million from the 1995 rate
level became effective January 1, 1996, with an additional $2.5 million rate
reduction scheduled to become effective January 1, 1998. SMECO has agreed not
to give the Company a notice of reduction or termination of service prior to
December 15, 1998.
Interchange of Power
- --------------------
The Company's generating and transmission facilities are interconnected
with those of other members of the PJM power pool and other utilities. The
pricing of most PJM-dispatched internal economy energy transactions is based
upon "split savings" whereby such energy is priced halfway between the cost
that the purchaser would incur if the energy were supplied by its own sources
and the cost of production to the company actually supplying the energy.
On July 24, 1996, nine of the 10 PJM member companies (the Supporting
Companies), excluding PECO, filed, with the FERC, a comprehensive proposal
including the contracts and tariff that would establish an Independent System
Operator (ISO) to administer transmission service under a PJM control area
transmission tariff and operate the energy market in a manner that assures
comparable treatment for all participants. Under the Supporting Companies'
proposal, reliability of the pool will be maintained under an installed
capacity obligation. The ISO will administer a bid-priced energy spot market
that will also accommodate bilateral transactions, and the ISO will provide
transmission service on a poolwide basis. In early August 1996, PECO filed a
competing plan opposing certain key features of the Supporting Companies'
proposal.
On November 13, 1996, the FERC found that it could not accept either the
Supporting Companies' proposal or PECO's opposing proposal. Consequently,
FERC ordered the PJM members to amend its proposals to comport with Order No.
888 on ISOs and to attempt to reach a consensus with other stakeholders. If
PJM members could not comply with this order by December 31, 1996, FERC
required, at a minimum, that PJM file a poolwide pro forma open access
transmission tariff by December 31, 1996, and amend existing PJM pooling
agreements for compatibility with the Order. On December 31, 1996, the PJM
member companies filed a joint response to FERC's Order. This compliance
filing, if accepted, establishes a single poolwide transmission tariff and
modifies the membership and governance provisions of the PJM agreement. The
PJM members noted areas of disagreement in the filing and indicated that the
20
compliance filing was an interim solution until a more comprehensive proposal
could be developed. These changes are not expected to have a material effect
on the operating results of the Company.
In addition to interchange with PJM, the Company is actively
participating in the emerging bilateral energy sales marketplace. The
Company's wholesale power sales tariff allows both sales from Company-owned
generation and sales of energy purchased by the Company from other market
participants. Over 40 utilities and marketers have executed service
agreements allowing them to arrange purchases under this tariff. The Company
has also executed service agreements allowing it to purchase energy under
other market participants' power sales tariffs. These agreements greatly
expand the opportunities for economic transactions. During 1996, the Company
entered into purchases, sales, and purchase-for-resale agreements producing
approximately $11 million in savings that are passed along to customers.
Throughout 1996, the Company purchased energy from Ohio Edison under the
Company's 1987 long-term capacity purchase agreements with Ohio Edison and
APS, and from the Northeast Maryland Waste Disposal Authority under an avoided
cost-based purchase agreement for a 32-megawatt Montgomery County Resource
Recovery Facility. Pursuant to the Company's long-term capacity purchase
agreements with Ohio Edison and APS, the Company is purchasing 450 megawatts
of capacity and associated energy through the year 2005. Capacity payments
for the Montgomery County Resource Recovery facility are not expected to
commence until after the year 2000. In August 1996, the Company began
purchasing energy from the Panda 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. The Panda facility achieved full
commercial operation in October 1996. Capacity payments under this agreement
commence in January 1997. The capacity expense under these agreements,
including an allocation of a portion of Ohio Edison's fixed operating and
maintenance costs, totaled $120 million in 1996. Commitments under these
agreements are estimated at $141 million in 1997, $139 million in 1998, $200
million in 1999 and 2000 and $211 million in 2001.
The Company has a purchase agreement with Southern Maryland Electric
Cooperative, Inc. (SMECO), through 2015, for 84 megawatts of capacity supplied
by a combustion turbine installed and owned by SMECO at the Company's Chalk
Point Generating Station. The Company is responsible for all costs associated
with operating and maintaining the facility. The capacity payment to SMECO is
approximately $5.5 million per year.
COMPETITION
- -----------
The electric utility industry is subject to increasing competitive
pressures, stemming from a combination of increasing independent power
production and regulatory and legislative initiatives intended to increase
bulk power competition, including the Energy Policy Act of 1992. Since the
early 1980s, the Company has pursued strategies which achieve financial
flexibility through conservation and energy use management programs, extension
of the useful life of generating equipment, cost-effective purchases of
21
capacity and energy and preservation of scheduling flexibility to add new
generating capacity in relatively small increments. The Company serves a
unique and stable service territory and is a low-cost energy producer with
customer prices which compare favorably with regional and national averages.
Pursuant to an August 1995 order in a generic proceeding dealing with
electric industry structure and the advent of competition, the Maryland Public
Service Commission found that competition at the wholesale level holds the
greatest potential for producing significant benefits, while competition at
the retail level would carry many potential problems and difficult-to-find
solutions. The Commission stated that it was intrigued by a restructuring
concept suggested by the Company, which calls for functionally dividing the
utility into generation and transmission/distribution segments. The
Commission encouraged the Company to develop the concept further and suggested
that other electric utilities in the state develop similar proposals specific
to their competitive positions. In October 1996, the Maryland Commission
reopened a generic proceeding to review regulatory and competitive issues
affecting the electricity industry. The Commission cited the evolving nature
of the electric industry as the basis for continuing its investigation. As
part of this investigation, the Commission directed its Staff to submit a
report on or before May 31, 1997, containing, among other things,
recommendations regarding regulatory and competitive issues facing the
electric industry in Maryland. The Commission also directed the four major
electric utilities in Maryland to prepare unbundled cost studies and model
unbundled retail service tariffs prior to August 1, 1997. The District of
Columbia Public Service Commission initiated a proceeding to investigate
issues regarding electricity industry structure and competition in late 1995.
In September 1996, the Commission issued an order designating the issues to be
examined in the proceeding. Initial comments regarding the designated issues
were filed with the Commission in January 1997, with reply comments due in
March 1997.
Additional information concerning competition is presented in
Management's Discussion and Analysis incorporated by reference in Item 7.
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
22
generating installations. The Company has expended approximately $621 million
through December 31, 1996, for the construction of pollution control
facilities. The $590 million 1997-2001 construction program for generating
facilities includes estimated provisions for pollution control facilities,
including expenditures for CAA compliance, of $21 million for 1997, $36
million for 1998, $35 million for 1999, $20 million for 2000 and $29 million
for 2001. The Company is unable to predict the future course of environmental
regulations generally, the manner in which compliance with such regulations
will be required, the availability of technology to meet such regulations and
any budget amendments which may be required to recognize the costs which may
ultimately be associated with such compliance.
Air Quality
- -----------
Under authority of the Clean Air Act of 1970, as amended, the U.S.
Environmental Protection Agency (EPA) has issued national primary and
secondary standards for the following air pollutants: sulfur dioxide,
nitrogen dioxide, particulate matter, carbon monoxide, ozone and lead. 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 new legislation until all of the related
implementing regulations are adopted by EPA and by appropriate agencies in
each of the jurisdictions where the Company's generating facilities are
located. However, the Company has 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 $18 million over the next five years. Plans for
complying with the second phase of the CAA are being reviewed in anticipation
of the pending Merger with BGE. If economical, continued use of lower-sulfur
coal, cofiring with natural gas and the purchase of sulfur dioxide (SO2)
emission allowances is expected. Nitrogen oxides emissions reductions will be
achieved by installing control equipment in the most cost-effective manner
after considering the characteristics of each of the merged company's boilers.
In addition to the Acid Rain portion of the CAA, the State of Maryland
and District of Columbia are required, by Title I of the CAA, to achieve
compliance with ambient air quality standards for ground-level ozone. This
provision is likely to result in further nitrogen oxides emissions reductions
from the Company's boilers; however, the extent of reductions and associated
cost cannot be estimated at this time.
23
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.
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
24
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, 1996. The report included
a number of possible remedies, the estimated costs of which range from $2
million to $90 million. In July 1995, the EPA announced its proposed remedial
action plan for the site and indicated it will accept comments on the plan
from any interested parties. The EPA's estimate of the costs associated with
implementation of the plan is approximately $17 million. The Company cannot
predict whether the EPA will include the plan in its ROD as proposed or make
changes as a result of comments received. In addition, the Company cannot
estimate the total extent of the EPA's administrative and oversight costs. To
date, the Company has accrued $1.7 million for its share of this contingency.
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 alleges that the
defendant site operator released PCBs and other hazardous substances at the
site during the course of its operation, and that the sole source of PCBs and
other hazardous substances is from the defendant operator's operations and
from transformers and capacitors supplied by other defendants. Subsequently,
additional defendants were added to the Complaint. The Complaint seeks
contribution and other equitable remedies for remediation of the site. In
October 1993, the parties reached, and the Court approved, a settlement
subject to confirmation by additional site testing that remediation can be
accomplished at or below, and that no regulatory authority will require a
remediation which exceeds, approximately $4 million.
During 1993, the Company 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 has paid
one-third, subject to possible reallocation) was expended on the removal
action, which the EPA has stated is in compliance with the AO. 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
25
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 are not entirely clear, it appears that each plaintiff
seeks $2 million in compensatory damages and $4 million in punitive damages
from each defendant. In a related proceeding in the Baltimore City case, the
Company was served, in September 1993, with a third party complaint by Owens
Corning Fiberglass, Inc. (Owens Corning) alleging that Owens Corning was in
the process of settling approximately 700 individual asbestos-related cases
and seeking a judgment for contribution against the Company on the same theory
of alleged negligence set forth above in the plaintiffs' case. Subsequently,
Pittsburgh Corning Corp. (Pittsburgh Corning) filed a third-party complaint
against the Company, seeking contribution for the same plaintiffs involved in
the Owens Corning third-party complaint. Since 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. In 1995 and 1996, 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 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.
26
Solid and Hazardous Waste
- -------------------------
The Resource Conservation and Recovery Act of 1976 (RCRA) provides
federal mandates and authority for dealing with the generation, treatment,
storage, transportation and disposal of solid or hazardous waste. The
principal utility wastes of fly ash, bottom ash and scrubber sludge are exempt
from EPA regulation as hazardous waste. The Company sends its wastes
designated as hazardous to appropriately licensed facilities for hazardous
waste treatment, storage and disposal. The current impact of regulations
under RCRA is not substantial. The only permit which will be required at this
time is for the Morgantown Generating Station, where the Company burns certain
amounts of PCB-contaminated mineral oil. Maryland regulations provide for a
special "limited facility permit" for this activity and the Company's
application for such permit is pending.
LABOR
- -----
The Company has approved, in conjunction with the Merger with BGE, a
severance plan for all exempt and non-bargaining unit employees who are not
offered a position in Constellation Energy. Such employees will receive two
weeks of pay per year of service, with a minimum payment of eight weeks of
pay. In addition, employees will receive company-sponsored health and dental
insurance for two weeks per year of service, with a minimum of eight weeks of
insurance coverage; employees will also not be obligated to reimburse the
Company for tuition payments made by the Company on their behalf within two
years of termination.
An extension of the current 1993 Labor Agreement between the Company and
Local 1900 of the International Brotherhood of Electrical Workers was ratified
by the Union members in December 1995. The 1995 Agreement extends the 1993
Agreement, which was due to expire on June 1, 1996, for two years or until the
effective date of the Merger with BGE, whichever occurs first. This Agreement
provides severance benefits, previously approved by the Company for exempt and
non-bargaining unit employees, for all union members and provided for a lump-
sum payment of 2% of base pay on January 5, 1996, a lump-sum payment of 1% of
base pay on June 7, 1996, and a lump-sum payment of 3% of base pay to be paid
on June 6, 1997, or the effective date of the Merger, whichever occurs first.
NONUTILITY SUBSIDIARY
- ---------------------
Potomac Capital Investment Corporation (PCI), the Company's wholly owned
subsidiary, was organized in late 1983 with the objective of supplementing
utility earnings and building long-term shareholder value. In April 1996, the
Company contributed its investment in PEPCO Enterprises, Inc. (PEI), an energy
services and telecommunications products and services company, to PCI.
Investments made by PEI contributed $1.1 million in after-tax earnings to PCI
during 1996.
27
PCI's assets totaled $1.4 billion at December 31, 1996, including
equipment leases of aircraft and power plants totaling $684.1 million at
December 31, 1996, marketable securities, primarily fixed rate preferred
stocks totaling $377.2 million at December 31, 1996 and to a lesser extent,
real estate and other investments. The Company's equity investment in PCI was
$196.3 million at December 31, 1996, including $32.8 million in subsidiary
retained earnings. Since its inception in 1983, PCI has paid the parent
Company $100 million in dividends.
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 1996 were $16.9 million compared to a net loss of
$124.4 million in 1995 and net earnings of $19.1 million in 1994. During
1996, PCI continued the execution of the plan adopted in May 1995 with respect
to the aircraft equipment leasing business. PCI's losses in 1995 reflect the
implementation of the plan which resulted in noncash, after-tax charges of
$122.2 million during 1995. Under the plan, PCI is not making new investments
to increase the size of the aircraft portfolio and 13 aircraft were designated
for sale over 18 to 24 months from the date the plan was announced. The book
values of these aircraft were reduced to their estimated net realizable values
of approximately $104 million and no depreciation or routine accrual for
repair and maintenance expenditures for these aircraft has been recorded since
the plan was adopted. During 1996, eight of these aircraft were sold and one
was placed on a long-term lease. Additional losses on assets held for
disposal, recorded primarily in the first quarter of 1996, totaled $12.7
million ($8.3 million after-tax). PCI reduced its portfolio of assets held
for disposal from $104 million (13 aircraft) at December 31, 1995, to $10.3
million (four aircraft). PCI also sold an aircraft engine leasing subsidiary
during 1996 for its approximate book value which reduced the investment in
operating lease equipment by $32.7 million. In addition, PCI wrote down
certain energy-related investments and real estate totaling $29.1 million
($18.8 million after-tax). PCI sold its $2.8 million (20% interest) in a
Florida-based technology company in the fourth quarter of 1996 and recorded an
after-tax gain of $6.7 million. As a result of joint venture operations in
1996, PCI was able to reduce previously accrued deferred income taxes and
record after-tax earnings of $27.7 million after provision for transaction
costs.
The $377.2 million securities portfolio, consisting primarily of
investment grade preferred stocks, provides PCI with liquidity and investment
flexibility. During 1996, PCI has reduced its marketable securities portfolio
by $153.1 million primarily as the result of calls (approximately $82 million)
and sales of fixed rate preferred stocks, generating net pretax gains of $3.6
million. PCI's fixed rate portfolio is sensitive to fluctuations in interest
rates. The decision to reduce the size of the preferred stock portfolio was
made to lessen the impact of future fluctuations in interest rates, while
still maintaining a substantial portfolio for liquidity purposes.
28
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 $54.4 million
at December 31, 1996.
Additional information concerning PCI's investment activities is
presented in Management's Discussion and Analysis incorporated by reference in
Item 7.
29
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 1996
- ------------------ --------------------------------------- --------------
- ------------ ------------ ---------------
(Thousands)
Benning Benning Road and Anacostia River, N.E. No. 4 Oil
550 - 102
Washington, D.C.
Buzzard Point 1st and V Streets, S.W. -
- 256 7
Washington, D.C.
Potomac River Bashford Lane and Potomac River Coal
482 - 1,665
Alexandria, Virginia
Dickerson Potomac River, South of Little Monocacy Coal
546 291 3,360
River, Dickerson, Maryland
Chalk Point Patuxent River at Swanson Creek Coal/
1,907 516 <F2> 4,584
Aquasco, Maryland Residual Oil/
Natural Gas
Morgantown Potomac River, South of Route 301 Coal/
1,164 248 7,216
Newburg, Maryland Residual Oil
- ----------- ----------- -----------
Total - Wholly owned Units
4,649 1,311 16,934
Conemaugh Indiana County, Pennsylvania Coal
165 1 1,107
- ----------- ----------- -----------
Total - All Stations Operated
4,814 1,312 18,041
- ------------ ===========
Cogeneration
- - 252
===========
Purchased Capacity
Ohio Edison <F3>
450 - 3,086
Panda Brandywine <F4>
230 - 165
- ------------ -----------
680 - 3,251
- ------------ ===========
Capacity Sale
GPU, Inc. <F5>
(90) -
- ------------ ------------
Total System
5,404 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 Allegheny
Power System, Inc.
<F4>Generating capacity under long-term agreement with Panda Brandywine L.P.
<F5>Generating capacity under short-term agreement with GPU, Inc.
</FN> 30
The five steam-electric generating stations, together with combustion
turbines, had an aggregate net capability at December 31, 1996, 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 APS. 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 project has been completed and the Panda facility
achieved full commercial operation in October 1996. The net 60-minute peak
load in 1996 was 5,288 megawatts, which occurred on June 17, 1996, and was
8.3% below the all-time summer peak demand of 5,769 megawatts. To meet the
1996 summer peak demand, the Company also had approximately 265 megawatts
available from its dispatchable energy use management programs. For
additional information regarding the Company's net generating capability, see
"Construction Program" and "Fuel" under Item 1 - Business.
The Company owns the transmission and distribution facilities serving
its customers. As stated above, the Company's interest in the Conemaugh
Generating Station and its associated transmission lines is that of a tenant
in common with eight other owners. Substantially all of such Conemaugh
transmission lines, substantially all of the Company's transmission and
distribution lines of less than 230,000 volts, small portions of its 230,000
volt transmission lines and certain of its substations are located on land
owned by others or in public streets and highways. Substantially all of the
Company's property and plant is subject to the mortgage which secures its
bonded indebtedness.
Item 3 LEGAL PROCEEDINGS
- ------ -----------------
For information regarding pending environmental legal proceedings, see
"Environmental Matters" under Item 1 - Business.
Item 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
- ------ ---------------------------------------------------
None.
31
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
--------------------- --------------- -------- ---------
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
1995:
First Quarter...... $.415 $20-1/8 $18-3/8
Second Quarter..... .415 22-1/2 18-1/2
Third Quarter...... .415 24-5/8 20-1/2
Fourth Quarter..... .415 $1.66 26-1/4 24
The number of holders of Common Stock was 88,783 at January 31, 1997,
and 89,620 at December 31, 1996.
There were 118,496,828 and 118,500,037 shares of the Company's $1 par
value Common Stock outstanding at January 31, 1997, and December 31, 1996,
respectively. A total of 200 million shares is authorized.
In January 1997, a dividend of 41-1/2 cents per share was declared
payable March 31, 1997, to holders of record of the Company's common stock on
March 10, 1997.
In connection with the Merger of the Company and BGE into Constellation
Energy Corporation, BGE's dividend policy will be adopted and the annual
dividend at the expected 1997 closing date is expected to be $1.67 per share.
The Company currently pays $1.66 per share annually and BGE's annual dividend
rate is currently $1.60 per share. However, no assurance can be given that
the $1.67 dividend rate will be in effect and Constellation Energy Corporation
reserves the right to increase or decrease the dividend on Common Stock as may
be required by law or contract or as may be determined by its Board of
Directors, in its discretion, to be advisable.
32
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 1996 Annual Report to shareholders.
Item 7 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
- ------ ---------------------------------------------------------------
RESULTS OF OPERATIONS
---------------------
The information required by Item 7 is incorporated herein by reference
to the "Management's Discussion and Analysis of Consolidated Results of
Operations and Financial Condition" in the Financial Information section of
the Company's 1996 Annual Report to shareholders.
The lenders to SEGS III and IV filed suit against the SEGS III and IV
partnerships to restrain them from making distributions of 1996 partnership
profits. The trial in this case was concluded in November 1996 and a decision
was reached by the Court in late January 1997 in favor of the project owners.
Management believes that there is a substantial likelihood that the lenders
will appeal the court's decision. An appeal is expected to take more than a
year to be concluded.
Item 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
- ------ -------------------------------------------
The consolidated financial statements, together with the report thereon
of Price Waterhouse LLP dated January 17, 1997, and supplementary data from
the Company's 1996 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 1996 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.
33
Part III
- --------
Item 10 DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
- ------- --------------------------------------------------
Information with regard to the directors and executive officers of the
registrant as of January 31, 1997, is as follows:
Directors
- ---------
Principal Occupation and Business Director
Name and Age Experience for Past Five Years Since
- ------------ --------------------------------- --------
Roger R. Blunt, Sr. Chairman of the Board, President 1984
Age 66 (j)(k)(n) and Chief Executive Officer of
Blunt Enterprises, Inc. (general
contracting and construction
management), a Washington-based
holding company, that includes
Essex Construction Corporation and
Tyroc Construction Corporation,
both of which he is Chairman of
the Board and Chief Executive
Officer.
A. James Clark Chairman of the Board and President 1977
Age 69 (a)(l)(m)(o) of Clark Enterprises, Inc., a
holding company based in Bethesda,
Maryland that includes The Clark
Construction Group, Inc. (formerly
The George Hyman Construction
Company and OMNI Construction
Group, Inc.). He serves as
Chairman of the Executive Committee
for The Clark Construction Group.
H. Lowell Davis See Executive Officers Below. 1973
(b)(k)
John M. Derrick, Jr. See Executive Officers Below. 1994
(k)
Richard E. Marriott Chairman of the Board of Host 1993
Age 58 (c)(m)(n) Marriott Corporation, a company
based in Bethesda, Maryland, which
owns lodging properties throughout
the world. From 1986 to October
1993 he served as Vice Chairman
and Executive Vice President of
the Marriott Corporation, a hotel
and hospitality company.
34
Principal Occupation and Business Director
Name and Age Experience for Past Five Years Since
- ------------ --------------------------------- --------
David O. Maxwell Retired Chairman of the Board and 1993
Age 66 (d)(j)(m) Chief Executive Officer of the
Federal National Mortgage
Association, a position he held
from 1981 to 1991.
Floretta D. McKenzie President of The McKenzie Group, 1988
Age 61 (e)(j)(k) Inc., an educational consulting
firm which she founded in 1987.
Ann D. McLaughlin Chairman of The Aspen Institute. 1991
Age 55 (f)(m)(n) She served as Vice Chairman of
The Aspen Institute from 1993 to
1996 and was President of the
Federal City Council from 1990
until 1995. Ms. McLaughlin was
President and Chief Executive
Officer of the New American
Schools Development Corporation
from July 1992 to 1993. She is
a member of the Board of Trustees
of The Urban Institute, Washington,
D.C.
Edward F. Mitchell See Executive Officers Below. 1980
(k)(o)
Peter F. O'Malley Of Counsel to O'Malley, Miles, 1982
Age 57 (g)(l)(m)(o) Nylen & Gilmore, P.A., a law firm
in Calverton, Maryland. He has
served as Of Counsel since 1989.
Louis A. Simpson President and Chief Executive 1990
Age 60 (h)(j)(l)(o) Officer of Capital Operations
(investments), GEICO Corporation,
Washington, D.C. since May 1993.
From 1985 to May 1993, he served
as Vice Chairman of GEICO
Corporation.
A. Thomas Young Retired Executive Vice President of 1995
Age 58 (i)(j)(l)(o) Lockheed Martin Corporation. From
1990 to 1995, he was President and
Chief Operating Officer of Martin
Marietta Corporation.
35
(a) Mr. Clark is also a director of CarrAmerica Realty Corporation.
(b) Mr. Davis is also a director of AVEMCO Corporation.
(c) Mr. Marriott is also a director of Marriott International, Inc. and
Host Marriott Services Corporation.
(d) Mr. Maxwell is also a director of Financial Security Assurance Holdings
Ltd., Salomon Inc, and SunAmerica Inc.
(e) Dr. McKenzie is also a director of Marriott International, Inc.
(f) Ms. McLaughlin, a former U.S. Secretary of Labor, is also a director of
AMR Corporation/American Airlines, Inc., Donna Karan International,
Inc., General Motors Corporation, Harman International Industries, Inc.,
Host Marriott Corporation, Kellogg Company, Nordstrom, Inc., Sedgwick
Group plc, Union Camp Corporation and Vulcan Materials Company.
(g) Mr. O'Malley is also a director of Giant Food Inc. and Legg Mason, Inc.
(h) Mr. Simpson is also a director of Cohr, Inc., Pacific American Income
Shares, Inc., Salomon Inc. and Thompson PBE, Inc.
(i) Mr. Young is also a director of The B.F. Goodrich Company, Cooper
Industries, Inc., The Dial Corp., Memotec Communications, Inc. and
Science Applications International Corporation.
(j) Mr. Blunt is Chairman of the Audit Committee. Messrs. Maxwell, Simpson
and Young and Dr. McKenzie are members of the Committee.
(k) Mr. Mitchell is Chairman of the Executive Committee. Messrs. Blunt,
Davis and Derrick and Dr. McKenzie are members of the Committee.
(l) Mr. O'Malley is Chairman of the Finance Committee. Messrs. Clark,
Simpson and Young are members of the Committee.
(m) Mr. Clark is Chairman of the Human Resources Committee.
Messrs. Marriott, Maxwell and O'Malley and Ms. McLaughlin are members of
the Committee.
(n) Ms. McLaughlin is Chairman of the Nominating Committee. Messrs. Blunt
and Marriott are members of the Committee.
(o) Mr. Mitchell is Chairman of the Chairman's Advisory Committee.
Messrs. Clark, O'Malley, Simpson and Young are members of the Committee.
36
Executive Officers
- ------------------
Served in
such position
Name Position Age since
- -------------------- -------------------------------- --- -------------
Edward F. Mitchell Chairman of the Board and Chief
Executive Officer 65 1992 (1)
John M. Derrick, Jr. President and Chief Operating
Officer and Director 56 1992 (2)
H. Lowell Davis Vice Chairman and Director 64 1983
Dennis R. Wraase Senior Vice President and
Chief Financial Officer 52 1992 (3)
William T. Torgerson Senior Vice President and
General Counsel 52 1994 (4)
Iraline G. Barnes Vice President - Corporate 49 1990
Relations
Earl K. Chism Vice President and Comptroller 61 1994 (5)
Kirk J. Emge Vice President - Regulatory
Law 47 1994 (6)
Susann D. Felton Vice President - Materials 48 1992 (7)
William R. Gee, Jr. Vice President - Energy Planning
and Economy 56 1991
Robert C. Grantley Vice President - Customers
and Community Relations 48 1989
Anthony J. Kamerick Vice President and Treasurer 49 1994 (8)
Anthony S. Macerollo Vice President - Corporate
Administration and Services 55 1989
James S. Potts Vice President - Environment 51 1993 (9)
William J. Sim Vice President - Power Supply
and Delivery 52 1991
Andrew W. Williams Vice President - Energy and
Market Policy and Development 47 1989
None of the above persons has a "family relationship" with any other officer
listed or with any director.
37
The term of office for each of the above persons is from April 24, 1996,
until the next succeeding Annual Meeting and until their successors have been
elected and qualified.
(1) Mr. Mitchell was elected to the position of Chairman of the Board on
December 21, 1992. He was elected Chief Executive Officer effective
September 1, 1989.
(2) Mr. Derrick was elected to the position of President on December 21,
1992. He was elected Executive Vice President and Chief Operating
Officer on July 27, 1989.
(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. He was elected Senior Vice President and
Comptroller on July 27, 1989.
(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) Ms. Felton was elected to her present position on April 22, 1992. Prior
to that time she held the position of Manager, Materials.
(8) 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. Prior to 1992 he held the position of Assistant Comptroller.
(9) 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.
Section 16(a) Beneficial Ownership Reporting Compliance
- -------------------------------------------------------
Anthony S. Macerollo, Vice President, Corporate Administration and
Services, purchased 152 shares of Common Stock of the Company in March 1996
and inadvertently failed to file a Form 4 by the April 10, 1996, deadline. He
filed the Form 4 on May 9, 1996.
38
Item 11 EXECUTIVE COMPENSATION
- ------- ----------------------
Each of the Company's directors, except directors who are employees of
the Company, is paid an annual retainer of $26,000, plus a fee of $1,000 for
each Board and committee meeting attended. The Company has a Retirement Plan
for Directors under which directors retiring at or after age 65 will receive,
for life, or for lesser periods depending on the length of the director's
non-employee board service, annual benefits equal to the retainer fee for
directors in effect at the time of retirement, with limited death benefits to
a surviving spouse; provided, however, in the event of a change in control of
the Company, if a director's service is terminated after completing 10 years
of Board service, the director would receive a lump sum payment of the
actuarial present value of a life annuity commencing at age 65, in an amount
equal to the retainer in effect at the time of change in control. The
actuarial present value of a reduced annuity benefit would be paid in a lump
sum in the case of a director whose service is terminated in the event of a
change in control, but prior to completing 10 years of Board service. The
Company also has a Stock Compensation Plan for the Board of Directors under
which directors of the Company may elect to receive up to 100% of their
retainers in shares of the Company's Common Stock and deferred compensation
plans which permit directors to defer annual retainer and meeting fee
payments.
39
SUMMARY COMPENSATION TABLE
Annual Compensation
------------------------------------
Long-term
Other Annual Incentive
Plan All Other
Name and Principal Position Year Salary Bonus Compensation
Payouts Compensation
- --------------------------- ----- --------- --------- ------------
- -------------- ------------
<F1> <F2>
<F3,4>
Edward F. Mitchell 1996 $600,000 $263,340 $115,861
$79,670 $55,513
Chairman of the Board and 1995 560,000 206,599 96,100
136,201 56,479
Chief Executive Officer 1994 553,333 0 79,716
95,568 58,800
H. Lowell Davis 1996 $418,667 $183,752 $72,718
$59,015 $38,702
Vice Chairman 1995 412,000 151,998 62,248
103,650 40,388
1994 408,000 0 56,192
72,710 44,354
John M. Derrick, Jr. 1996 $373,333 $152,152 $11,672
$44,261 $36,867
President 1995 350,000 190,612 10,423
59,236 37,111
1994 333,333 0 9,970
41,546 37,674
Dennis R. Wraase 1996 $222,667 $84,350 $3,054
$21,953 $24,568
Senior Vice President and 1995 203,000 130,642 2,972
38,627 24,455
Chief Financial Officer 1994 190,667 26,693 3,004
27,085 24,609
William T. Torgerson 1996 $210,667 $74,300 $2,565
$0 $23,030
Senior Vice President and 1995 197,667 123,263 2,572
0 22,703
General Counsel 1994 187,000 23,375 2,536
0 22,464
40
<FN>
<F1> Other Annual Compensation
Amounts in this column represent above-market earnings on deferred
compensation funded by Company-owned life insurance policies held in trust,
assuming the expected retirement at age 65. The amounts are reduced if the
executive terminates employment prior to age 62 for any reason other than
death, total or permanent disability or a change in control of the Company.
In the event of a change in control and termination of the participant's
employment, a lump sum payment will be made equal to the net present value of
the expected payments at age 65 discounted using the Pension Guaranty
Corporation immediate payment interest rate plus one-half of one percent. The
Company has purchased such policies on participating individuals under a
program designed so that if assumptions as to mortality experience, policy
return and other factors are realized, the compensation deferred and the death
benefits payable to the Company under such insurance policies will cover all
premium payments and benefit payments projected under this program, plus a
factor for the use of Company funds.
<F2> Long-Term Incentive Plan Payouts
Amounts in this column represent the value of the vested long-term
restricted stock granted under the terms of the Company's Executive Restricted
Stock Performance Award Program for the three-year performance cycle ended
December 31, 1995. Under the terms of the plan, restricted stock awards made
in 1996 for the performance cycle ended December 31, 1995, vested in two equal
installments, January 1, 1996, and January 1, 1997. Amounts shown above
reflect the value of the shares which vested January 1, 1997, based on the
average of the high and low stock price on the New York Stock Exchange on
December 31, 1996.
<F3> Restricted Stock
The number and market value of the non-vested restricted shareholdings
at December 31, 1996, for the five executives presented above are: 3,131
shares or $79,645 for Mr. Mitchell, 2,319 shares or $58,990 for Mr. Davis,
1,739 shares or $44,236 for Mr. Derrick, and 863 shares or $21,953 for Mr.
Wraase. In the event of change of control and subsequent termination
diminution of duties, the balance of the restricted shareholdings becomes
vested immediately.
<F4> All Other Compensation
Amounts in this column consist of (i) Company contributions to the
Savings Plan for Exempt Employees of $7,000 for Messrs. Mitchell, Derrick,
Wraase and Torgerson, respectively, and $7,225 for Mr. Davis for 1996, (ii)
Company contributions to the Executive Deferred Compensation Plan due to
Internal Revenue Service limitations on maximum contributions to the Savings
Plan for Exempt Employees of $16,200, $5,496, $7,386, $2,769 and $2,730 for
Messrs. Mitchell, Davis, Derrick, Wraase and Torgerson, respectively, for
1996, (iii) the term life insurance portion of life insurance written on a
split-dollar basis of $8,394, $4,979, $1,731, $947 and $963 for Messrs.
Mitchell, Davis, Derrick, Wraase and Torgerson, respectively, for 1996, and
41
(iv) the interest on employer paid premiums for split-dollar life insurance of
$23,919, $21,002, $20,750, $13,852 and $12,337 for Messrs. Mitchell, Davis,
Derrick, Wraase and Torgerson, respectively, for 1996. The split-dollar life
insurance contract provides death benefits to the executive's beneficiaries of
approximately three times the executive's annual salary. The split-dollar
program is designed so that, if the assumptions made as to mortality
experience, policy return and other factors are realized, the Company will
recover all plan costs, including a factor for the use of Company funds. The
split-dollar policy provides a cash surrender value to each participant in
excess of any premiums paid.
</FN>
42
LONG-TERM INCENTIVE PLAN -- AWARDS IN LAST FISCAL YEAR
Performance or
Other Period Minimum Threshold Maximum
Until Maturation Number Number Number
Name or Payout of Shares of Shares of Shares
- -------------------- ------------------ ----------- ----------- -----------
Edward F. Mitchell January 1, 2000 0 1,072 8,042
January 1, 2001 0 1,072 8,041
H. Lowell Davis January 1, 2000 0 786 5,900
January 1, 2001 0 786 5,900
John M. Derrick, Jr. January 1, 2000 0 668 5,012
January 1, 2001 0 668 5,012
Dennis R. Wraase January 1, 2000 0 428 3,208
January 1, 2001 0 427 3,207
William T. Torgerson January 1, 2000 0 386 2,893
January 1, 2001 0 386 2,892
43
The above table reflects the share awards available under the Company's
Executive Restricted Stock Performance Award Program for the three-year
performance cycle beginning January 1, 1996. The Plan provides for the award
of restricted stock based on comparisons of Company performance to the Salomon
Brothers Electric Utilities index. The awards are based on total return to
shareholders over the three-year performance cycle and market-to-book ratios
for the same periods. Each of these two performance measures is given equal
weight. For a participant to receive the maximum award, the Company must have
the highest total return to shareholders and market-to-book ratio as compared
to the companies contained in the Salomon Brothers Electric Utilities index.
Generally, the Company results must be above the median of the companies
contained in the index for a participant to receive any award. Actual grants,
if any, will not be determined until the end of the performance cycle and the
shares earned based on performance will vest in two equal installments on
January 1 of each of the two years commencing one year after the end of the
performance cycle. No dividends are paid on awards until actual grants are
made. Total shares granted will reflect reinvested dividends during the
performance cycle.
44
PENSION PLAN TABLE
Annual Retirement Benefits
Average Annual
- ---------------------------------------------------------------------
Salary in Final Years in Plan
Three Years
- ---------------------------------------------------------------------
of Employment 15 20 25 30 35
40
- --------------- --------- --------- --------- --------- ---------
- ---------
$150,000 $39,000 $53,000 $66,000 $79,000 $92,000
$105,000
$250,000 $66,000 $88,000 $109,000 $131,000 $153,000
$175,000
$350,000 $92,000 $123,000 $153,000 $184,000 $214,000
$245,000
$450,000 $118,000 $158,000 $197,000 $236,000 $276,000
$315,000
$550,000 $144,000 $193,000 $241,000 $289,000 $337,000
$385,000
$650,000 $171,000 $228,000 $284,000 $341,000 $398,000
$455,000
$750,000 $197,000 $263,000 $328,000 $394,000 $459,000
$525,000
45
The Company's General Retirement Plan provides participants benefits
after five years of service based on the average salary (the term salary being
equal to the amounts contained in the Salary column of the Summary
Compensation Table) for the final three years of employment and years in the
Plan at time of retirement. Normal retirement under the Plan is at age 65.
Plan benefits are subject to an offset for any Social Security benefits.
Benefits under the Plan may be reduced under certain provisions of the
Internal Revenue Code, as amended, and by salary deferrals under the Company's
deferred compensation plans (other than CODA contributions made under the
Savings Plan). Where any such limitations occur, the Company will pay (as an
operating expense) a retirement supplement to eligible executives designed to
maintain total retirement benefits at a formula level of the Plan. In order
to attract and retain executives, the Company provides supplemental retirement
benefits for executives who retire under the terms of the General Retirement
Plan and are at least 59 years of age, which increases the average salary by
the average of the highest three annual incentive awards out of the last five
consecutive years. The annual incentive amounts are equal to the amounts
shown in the Bonus column of the Summary Compensation Table. The current
age, years of credited service and compensation used to determine retirement
benefits for the above-named officers are as follows: Mr. Mitchell, 65 and 40
years of credit, $600,657; Mr. Davis, 64 and 39 years of credit, $439,250; Mr.
Derrick, 56 and 35 years of credit, $382,532; Mr. Wraase, 52 and 27 years of
credit, $312,949; and Mr. Torgerson, 52 and 27 years of credit, $200,710.
Annual benefits at age 65 (including the effect of the Social Security offset)
are illustrated in the table above.
Employment Agreements
- ---------------------
An employment agreement dated April 26, 1995 and amended September 22,
1995, between the Company and Mr. Mitchell provides for his continued
employment as Chief Executive Officer of the Company until the later of
January 1, 1997, or the effective date of the proposed merger with Baltimore
Gas and Electric Company at an annual salary determined by the Board of
Directors. The agreement provides for a supplemental retirement benefit
payable to Mr. Mitchell (or his surviving spouse) for a period of not less
than ten years in an amount equal to the excess of 65% of his final average
annual compensation (based upon salary paid or deferred during his final 12
months of employment and the target annual award during his last year of
employment) over the benefits to which he is entitled under the Company's
General Retirement Plan. The employment agreement also provides for certain
additional spouse benefits, and for the provision by the Company of
supplemental life insurance for Mr. Mitchell following his retirement. If the
proposed merger with Baltimore Gas and Electric Company is completed, Mr.
Mitchell's employment agreement will be superseded by an employment agreement
that he has entered into with Constellation Energy Corporation.
Effective August 1, 1995, the Company entered into an agreement with Mr.
Davis pursuant to which he will continue to be employed as Vice Chairman of
the Company through March 31, 1997. During the term of the agreement, Mr.
Davis will be paid at an annual rate which will be no less than his base
salary in effect on August 1, 1995. Upon termination for any reason, either
46
on or before April 1, 1997, Mr. Davis will be entitled to amounts due him
under the Company's General Retirement Plan, the Supplemental Benefit Plan,
the Executive Performance Supplemental Retirement Plan, and the Supplemental
Executive Retirement Plan.
Effective August 1, 1995, the Company entered into employment agreements
with Messrs. Derrick, Torgerson and Wraase which provide for each executive's
employment through August 1, 2000, and automatically extend for successive
periods of five years thereafter unless the Company or the executive has given
one year's prior notice that it shall not be so extended. Each of the
employment agreements provides that the executive (i) will receive an annual
base salary in an amount not less than his salary in effect as of August 1,
1995, and incentive compensation as determined by the Company's Board and (ii)
will be entitled to participate in retirement and other benefit plans, and
receive fringe benefits, on the same basis as other senior executives of the
Company.
Under each of the employment agreements with Messrs. Derrick, Torgerson
and Wraase, the executive is entitled to certain benefits if his employment is
terminated prior to the expiration of the initial term of the agreement (or as
extended) either (i) by the Company other than for cause, death or disability
or (ii) by the executive if his salary is reduced, he is not in good faith
considered for incentive awards, the Company fails to provide him with
retirement, other benefit plans and fringe benefits provided to other
similarly situated executives, he is required to relocate by more than 50
miles from Washington, D.C., or he is demoted from a senior management
position. These benefits include a lump sum payment in cash equal to the sum
of (i) the greater of (A) the present value of the executive's annual base
salary (the highest base salary in effect during the three-year period
preceding termination) and annual cash incentive awards (calculated based on
the highest annual incentive target award during the three-year period
preceding termination) through the remainder of the agreement (not to exceed
three years) and (B) two times the executive's annual salary and target annual
incentive award as in effect at the time of termination, (ii) the executive's
annual cash incentive award for the year preceding termination of employment,
if not yet paid, and (iii) a pro rata portion of the executive's annual cash
incentive award for the year in which the executive's employment terminates.
In addition, the executive will be entitled to receive certain supplemental
retirement benefits under existing plans of the Company, the same benefits
that a retiree who has attained age 55 and has completed 30 years of service
would be entitled, and a continuation of premium payment under the Company's
split dollar life insurance policy.
If the proposed merger with Baltimore Gas and Electric Company is
completed, Mr. Derrick's employment agreement will be superseded by an
employment agreement that he has entered into with Constellation Energy
Corporation, and Messrs. Torgerson and Wraase's employment agreements will be
assumed by Constellation.
47
Item 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
- ------- --------------------------------------------------------------
The following table sets forth the beneficial ownership of common stock
of the Company for each director, the five executive officers shown in the
Summary Compensation Table on page 40, and all directors and executive
officers as a group as of January 31, 1997. None of such persons beneficially
owns shares of any other class of equity securities of the Company.
Number of
Common Shares
Name of Beneficial Owner Owned (1)
------------------------ -------------
Roger R. Blunt, Sr. 336
A. James Clark 98,482 (2)
H. Lowell Davis 64,491 (3)
John M. Derrick, Jr. 21,592 (3)
Richard E. Marriott 100
David O. Maxwell 500
Floretta D. McKenzie 812
Ann D. McLaughlin 509
Edward F. Mitchell 59,068 (3)
Peter F. O'Malley 1,828
Louis A. Simpson 2,000
William T. Torgerson 7,954 (3)
Dennis R. Wraase 16,189 (3)
A. Thomas Young 1,000
-------
All Directors and Executive Officers
as a Group (25 Individuals) 383,460
=======
(1) Each of the individuals listed, as well as all directors and
executive officers as a group, beneficially owned less than 1%
of the Company's outstanding common stock. Participants'
shares in the Company's Dividend Reinvestment and Employee
Savings Plan are included.
(2) Mr. Clark owns 8,874 shares of the Common Stock of the Company.
Clark Enterprises, Inc., of which he is the major owner, owns
89,608 shares of the Common Stock of the Company. Mr. Clark
has sole voting and investment power with respect to the shares
held by that company.
(3) Includes shares awarded under the Company's Long-Term Incentive
Plan which have not yet vested.
48
On September 22, 1995, the Company and Baltimore Gas and Electric
Company (BGE) signed reciprocal stock option agreements in connection with the
proposed merger of PEPCO and BGE with and into Constellation Energy
Corporation. Pursuant to the stock option agreements, PEPCO granted BGE an
irrevocable option to purchase up to 23,579,900 shares of PEPCO common stock
under certain circumstances if the Agreement and Plan of Merger dated as of
September 22, 1995, becomes terminable.
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.
49
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 1996 Annual
Report.
Reference (Page)
----------------
Form 10-K
Annual Report Annual Report
to Shareholders Exhibit 13
--------------- -------------
Consolidated Statements of
Earnings - for the years
ended December 31, 1996,
1995 and 1994 15 29
Consolidated Balance Sheets -
December 31, 1996 and 1995 16-17 30-31
Consolidated Statements of
Cash Flows - for the years
ended December 31, 1996,
1995 and 1994 18 32
Notes to Consolidated Financial
Statements 19-31 33-72
Report of Independent Accountants 32 28
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 VIII (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.
50
3. Exhibits required by Securities and Exchange Commission Regulation
S-K (summarized below).
Exhibit
No. Description of Exhibit Reference*
- ------- ---------------------- ----------
2.1 Agreement and Plan of Merger
dated as of September 22,
1995................................ Exh. 2-1 to Form 8-K,
9/26/95.
2.2 PEPCO Stock Option Agreement
dated as of September 22,
1995................................ Exh. 2-2 to Form 8-K,
9/26/95.
2.3 BGE Stock Option Agreement
dated as of September 22,
1995................................ Exh. 2-3 to Form 8-K,
9/26/95.
3.1 Charter of the Company.............. Filed herewith.
3.2 By-Laws of the Company.............. Exh. 3.2 to Form 10-K,
4/1/96.
4 Mortgage and Deed of Trust dated
July 1, 1936, of the Company to The
Riggs National Bank of Washington,
D.C., as Trustee, securing First
Mortgage Bonds of the Company, and
Supplemental Indenture dated
July 1, 1936........................ Exh. B-4 to First Amendment,
6/19/36, to Registration
Statement No. 2-2232.
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.
51
Exhibit
No. Description of Exhibit Reference*
- ------- ---------------------- ----------
4 July 15, 1942 and August 10,
(cont.) 1942................................ Exh. B-1 to Amendment No. 2,
8/24/42, and B-3 to Post-
Effective Amendment,
8/31/42, to Registration
Statement No. 2-5032.
August 1, 1942...................... Exh. B-4 to Form 8-A,
10/8/42.
October 15, 1942.................... Exh. A to Form 8-K, 12/7/42.
October 15, 1947.................... Exh. A to Form 8-K, 12/8/47.
January 1, 1948..................... Exh.7-B to Post-Effective
Amendment No. 2, 1/28/48,
to Registration Statement
No. 2-7349.
December 31, 1948................... Exh. A-2 to Form 10-K,
4/13/49.
May 1, 1949......................... Exh. 7-B to Post-Effective
Amendment No. 1,
5/10/49, to Registration
Statement No. 2-7948.
December 31, 1949................... Exh. (a)-1 to Form 8-K,
2/8/50.
May 1, 1950......................... Exh. 7-B to Amendment No. 2,
5/8/50, to Registration
Statement No. 2-8430.
February 15, 1951................... Exh. (a) to Form 8-K, 3/9/51.
March 1, 1952....................... Exh. 4-C to Post-Effective
Amendment No. 1, 3/12/52,
to Registration Statement
No. 2-9435.
February 16, 1953................... Exh. (a)-1 to Form 8-K,
3/5/53.
May 15, 1953........................ Exh. 4-C to Post-Effective
Amendment No. 1, 5/26/53,
to Registration Statement
No. 2-10246.
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.
52
Exhibit
No. Description of Exhibit Reference*
- ------- ---------------------- ----------
4 April 1, 1957....................... Exh. 4-B to Registration
(cont.) Statement No. 2-13884,
2/5/58.
May 1, 1958......................... Exh. 2-B to Registration
Statement No. 2-14518,
11/10/58.
December 1, 1958.................... Exh. A to Form 8-K, 1/2/59.
May 1, 1959......................... Exh. 4-B to Amendment No. 1,
5/13/59, to Registration
Statement No. 2-15027.
November 16, 1959................... Exh. A to Form 8-K, 1/4/60.
May 2, 1960......................... Exh. 2-B to Registration
Statement No. 2-17286,
11/9/60.
December 1, 1960 and April 3,
1961................................ Exh. A-1 to Form 10-K,
4/24/61.
May 1, 1962......................... Exh. 2-B to Registration
Statement No. 2-21037,
1/25/63.
February 15, 1963................... Exh. A to Form 8-K, 3/4/63.
May 1, 1963......................... Exh. 4-B to Registration
Statement No. 2-21961,
12/19/63.
April 23, 1964...................... Exh. 2-B to Registration
Statement No. 2-22344,
4/24/64.
May 15, 1964........................ Exh. A to Form 8-K, 6/2/64.
May 3, 1965......................... Exh. 2-B to Registration
Statement No. 2-24655,
3/16/66.
April 1, 1966....................... Exh. A to Form 10-K, 4/21/66.
June 1, 1966........................ Exh. 1 to Form 10-K, 4/11/67.
April 28, 1967...................... Exh. 2-B to Post-Effective
Amendment No. 1 to
Registration Statement No.
2-26356, 5/3/67.
May 1, 1967......................... Exh. A to Form 8-K, 6/1/67.
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.
53
Exhibit
No. Description of Exhibit Reference*
- ------- ---------------------- ----------
4 June 16, 1969....................... Exh. 2-B to Registration
(cont.) Statement No. 2-36094,
1/27/70.
February 15, 1970................... Exh. A-2 to Form 8-K, 3/9/70.
May 15, 1970........................ Exh. 2-B to Registration
Statement No. 2-38038,
7/27/70.
August 15, 1970..................... Exh. 2-D to Registration
Statement No. 2-38038,
7/27/70.
September 1, 1971................... Exh. 2-C to Registration
Statement No. 2-45591, 9/1/72.
September 15, 1972.................. Exh. 2-E to Registration
Statement No. 2-45591, 9/1/72.
April 1, 1973....................... Exh. A to Form 8-K, 5/9/73.
January 2, 1974..................... Exh. 2-D to Registration
Statement No. 2-49803,
12/5/73.
August 15, 1974..................... Exhs. 2-G and 2-H to
Amendment No. 1 to
Registration Statement
No. 2-51698, 8/14/74.
June 15, 1977....................... Exh. 4-A to Form 10-K,
3/19/81.
July 1, 1979........................ Exh. 4-B to Form 10-K,
3/19/81.
June 16, 1981....................... Exh. 4-A to Form 10-K,
3/19/82.
June 17, 1981....................... Exh. 2 to Amendment No. 1,
6/18/81, to Form 8-A.
December 1, 1981.................... Exh. 4-C to Form 10-K,
3/19/82.
August 1, 1982...................... Exh. 4-C to Amendment No. 1
to Registration Statement
No. 2-78731, 8/17/82.
October 1, 1982..................... Exh. 4 to Form 8-K, 11/8/82.
April 15, 1983...................... Exh. 4 to Form 10-K, 3/23/84.
November 1, 1985.................... Exh. 2-B to Form 8-A, 11/1/85.
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.
54
Exhibit
No. Description of Exhibit Reference*
- ------- ---------------------- ----------
4 May 1, 1989......................... Exh. 4-C to Registration
(cont.) Statement No. 33-29382,
6/16/89.
August 1, 1989...................... Exh. 4 to Form 10-K, 3/23/90.
April 5, 1990....................... Exh. 4 to Form 10-K, 3/29/91.
May 21, 1991........................ Exh. 4 to Form 10-K, 3/27/92.
May 7, 1992......................... Exh. 4 to Form 10-K, 3/26/93.
September 1, 1992................... Exh. 4 to Form 10-K, 3/26/93.
November 1, 1992.................... Exh. 4 to Form 10-K, 3/26/93.
March 1, 1993....................... Exh. 4 to Form 10-K, 3/26/93.
March 2, 1993....................... Exh. 4 to Form 10-K, 3/26/93.
July 1, 1993........................ Exh. 4.4 to Registration
Statement No. 33-49973,
8/11/93.
August 20, 1993..................... Exh. 4.4 to Registration
Statement No. 33-50377,
9/23/93.
September 29, 1993.................. 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.
4-A Indenture, dated as of January 15,
1988, between the Company and
Centerre Trust Company of St. Louis
(now known as Boatmen's Trust
Company), Trustee for the Company's
$75,000,000 issue of 7% Convertible
Debentures due 2018 ................ Exh. 4-A to Form 10-K,
3/25/88.
4-B Indenture, dated as of July 28,
1989, between the Company and
The Bank of New York, Trustee,
with respect to the Company's
Medium-Term Note Program............ Exh. 4 to Form 8-K, 6/21/90.
55
Exhibit
No. Description of Exhibit Reference*
- ------- ---------------------- ----------
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.
Employment Agreement**.............. Exh. 10.3 to Form 10-Q,
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.
56
Exhibit
No. Description of Exhibit Reference*
- ------- ---------------------- ----------
10 Severance Agreement**............... Exh. 10.10 to Form 10-K,
(cont.) 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.
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.
24 Power of Attorney................... 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).
(b) Reports on Form 8-K
-------------------
None.
57
POTOMAC ELECTRIC POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
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, 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
Year Ended December 31, 1994
Allowance for uncollectible accounts -
customer and other accounts receivable
Utility operations $ 3,048 $ 6,967 $
893 $ (8,176) $ 2,732
Nonutility subsidiary $ - $ 5,000 $
- $ - $ 5,000
<FN>
<F1>Collection of accounts previously written off.
<F2>Uncollectible accounts written off.
</FN>
58
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 28th day of February, 1997.
POTOMAC ELECTRIC POWER COMPANY
(Registrant)
By /s/ E. F. Mitchell
--------------------------
(Edward F. Mitchell,
Chairman of the Board and
Chief Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated:
Signature Title Date
--------- ----- ----
(i) Principal Executive Officers
/s/ E. F. Mitchell
--------------------------- Chairman of the Board and
(Edward F. Mitchell) Chief Executive Officer
/s/ John M. Derrick Jr.
--------------------------- President and Director
(John M. Derrick Jr.)
(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/ Roger R. Blunt
------------------------- Director
(Roger R. Blunt Sr.)
February 28, 1997
59
Signature Title Date
--------- ----- ----
(iv) Directors (cont.):
A. J. Clark*
------------------------- Director
(A. James Clark)
/s/ H. L. Davis
------------------------- Director
(H. Lowell Davis)
R. E. Marriott*
------------------------- Director
(Richard E. Marriott)
/s/ David O. Maxwell
------------------------ Director
(David O. Maxwell)
/s/ Floretta D. McKenzie
------------------------- Director
(Floretta D. McKenzie)
Ann D. McLaughlin*
------------------------- Director
(Ann D. McLaughlin)
Peter F. O'Malley*
------------------------- Director
(Peter F. O'Malley)
Louis A. Simpson*
------------------------- Director
(Louis A. Simpson)
------------------------- Director
(A. Thomas Young)
* By: /s/ Ellen Sheriff Rogers
-----------------------
(Ellen Sheriff Rogers,
Attorney-in-Fact)
February 28, 1997
60
Exhibit 11 Computations of Earnings Per Common Share <F1>
- ---------- ------------------------------------------
The following is the basis for the computation of primary and fully
diluted earnings per common share for each of the years 1996, 1995 and 1994:
1996 1995
1994
------------ ------------
------------
Average shares outstanding for
computation of primary earnings
per common share 118,496,683 118,412,478
118,005,847
============ ============
============
Average shares outstanding for
fully diluted computation:
Average shares outstanding 118,496,683 118,412,478
118,005,847
Additional shares resulting from:
Conversion of Serial Preferred
Stock, $2.44 Convertible Series
of 1966 (the "Convertible
Preferred Stock") 34,986 38,255
48,110
Conversion of 7% Convertible
Debentures 2,418,579 2,469,639
2,531,244
Conversion of 5% Convertible
Debentures 3,392,500 3,392,500
3,392,500
------------ ------------
------------
Average shares outstanding for
computation of fully diluted
earnings per common share 124,342,748 124,312,872
123,977,701
============ ============
============
Earnings applicable to common stock $220,356,000 $77,540,000
$210,725,000
Add: Dividends paid or accrued on
Convertible Preferred Stock 15,000 16,000
20,000
Interest paid or accrued on
Convertible Debentures,
net of related taxes 6,416,000 6,475,000
6,537,000
------------ ------------
------------
Earnings applicable to common stock,
assuming conversion of convertible
securities $226,787,000 $84,031,000
$217,282,000
============ ============
============
Primary earnings per common share $1.86 $0.65
$1.79
Fully diluted earnings per common share $1.82 $0.68
$1.75
<FN>
<F1>This calculation is submitted in accordance with Regulation S-K, item 601 (b)
(11) although not required by footnote 2 to paragraph 14 of APB No. 15 for
1996
and 1994 because it results in dilution of less than 3%. In addition, the
valuation is contrary to paragraph 40 of APB No. 15 because it produces an
antidilutive result for 1995.
</FN>
61
Exhibit 12 Computation of Ratios
- ---------- ---------------------
The computations of the coverage of fixed charges, excluding the cumulative
effect of the 1992 accounting change, before income taxes, and the coverage of
combined fixed charges and preferred dividends for each of the years 1996
through 1992 on the basis of parent company operations only, are as follows.
For The Year Ended
December 31,
- ---------------------------------------------------------
1996 1995 1994
1993 1992
--------- --------- ---------
--------- ---------
(Thousands of
Dollars)
Net income before cumulative effect
of accounting change $220,066 $218,788 $208,074
$216,478 $172,599
Taxes based on income 135,011 129,439 116,648
107,223 76,965
--------- --------- ---------
--------- ---------
Income before taxes and cumulative effect
of accounting change 355,077 348,227 324,722
323,701 249,564
--------- --------- ---------
--------- ---------
Fixed charges:
Interest charges 146,939 146,558 139,210
141,393 138,097
Interest factor in rentals 23,560 23,431 6,300
5,859 6,140
--------- --------- ---------
--------- ---------
Total fixed charges 170,499 169,989 145,510
147,252 144,237
--------- --------- ---------
--------- ---------
Income before income taxes, cumulative
effect of accounting change and
fixed charges $525,576 $518,216 $470,232
$470,953 $393,801
========= ========= =========
========= =========
Coverage of fixed charges 3.08 3.05 3.23
3.20 2.73
==== ==== ====
==== ====
Preferred dividend requirements $16,604 $16,851 $16,437
$16,255 $14,392
--------- --------- ---------
--------- ---------
Ratio of pre-tax income to net income 1.61 1.59 1.56
1.50 1.45
--------- --------- ---------
--------- ---------
Preferred dividend factor $26,732 $26,793 $25,642
$24,383 $20,868
--------- --------- ---------
--------- ---------
Total fixed charges and preferred dividends $197,231 $196,782 $171,152
$171,635 $165,105
========= ========= =========
========= =========
Coverage of combined fixed charges
and preferred dividends 2.66 2.63 2.75
2.74 2.39
==== ==== ====
==== ====
62
Exhibit 12 Computation of Ratios
- ---------- ---------------------
The computations of the coverage of fixed charges, excluding the cumulative
effect of the 1992 accounting change, before income taxes, and the coverage of
combined fixed charges and preferred dividends for each of the years 1996
through 1992 on a fully consolidated basis are as follows.
For The Year Ended
December 31,
- ---------------------------------------------------------
1996 1995 1994
1993 1992
--------- --------- ---------
--------- ---------
(Thousands of
Dollars)
Net income before cumulative effect
of accounting change $236,960 $94,391 $227,162
$241,579 $200,760
Taxes based on income 80,386 43,731 93,953
62,145 79,481
--------- --------- ---------
--------- ---------
Income before taxes and cumulative effect
of accounting change 317,346 138,122 321,115
303,724 280,241
--------- --------- ---------
--------- ---------
Fixed charges:
Interest charges 231,029 238,724 224,514
221,312 226,453
Interest factor in rentals 23,943 26,685 9,938
9,257 6,599
--------- --------- ---------
--------- ---------
Total fixed charges 254,972 265,409 234,452
230,569 233,052
--------- --------- ---------
--------- ---------
Nonutility subsidiary capitalized interest (649) (529) (521)
(2,059) (2,200)
--------- --------- ---------
--------- ---------
Income before income taxes, cumulative
effect of accounting change and
fixed charges $571,669 $403,002 $555,046
$532,234 $511,093
======== ======== ========
======== ========
Coverage of fixed charges 2.24 1.52 2.37
2.31 2.19
==== ==== ====
==== ====
Preferred dividend requirements $16,604 $16,851 $16,437
$16,255 $14,392
--------- --------- ---------
--------- ---------
Ratio of pre-tax income to net income 1.34 1.46 1.41
1.26 1.40
--------- --------- ---------
--------- ---------
Preferred dividend factor $22,249 $24,602 $23,176
$20,481 $20,149
--------- --------- ---------
--------- ---------
Total fixed charges and preferred dividends $277,221 $290,011 $257,628
$251,050 $253,201
======== ======== ========
======== ========
Coverage of combined fixed charges
and preferred dividends 2.06 1.39 2.15
2.12 2.02
==== ==== ====
==== ====
63
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. Effective April 30, 1996, the Company reorganized its nonutility
subsidiaries and contributed its investment in PEPCO Enterprises, Inc. (PEI)
to PCI.
64
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 and 33-61379) of
Potomac Electric Power Company and to the incorporation by reference in the
Joint Proxy Statement/Prospectus constituting part of the Registration
Statement on Form S-4 (Number 33-64799) of Constellation Energy Corporation of
our report dated January 17, 1997 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.
February 28, 1997
65
Report of Independent Accountants on Consolidated
- -------------------------------------------------
Financial Statement Schedule
- ----------------------------
January 17, 1997
To the Board of Directors of
Potomac Electric Power Company
Our audits of the consolidated financial statements referred to in our report
dated January 17, 1997 appearing in the 1996 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.
66