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, 1994 Commission file number 1-1072
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Potomac Electric Power Company
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(Exact name of registrant as specified in its charter)
District of Columbia and Virginia 53-0127880
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1900 Pennsylvania Avenue, N.W.
Washington, D. C. 20068
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (202) 872-2456
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Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
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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 .
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Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. X .
---
As of March 7, 1995, Potomac Electric Power Company had 118,248,594
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 $2.2 billion.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Company's 1994 Annual Report to shareholders are
incorporated by reference into Parts II and IV of this Form 10-K.
Portions of the Notice of Annual Meeting of Shareholders and Proxy
Statement, dated March 17, 1995, are incorporated by reference into Part III
of this Form 10-K.
2
POTOMAC ELECTRIC POWER COMPANY
Form 10-K - 1994
TABLE OF CONTENTS
PART I Page
Item 1 - Business ----
General ............................................................ 5
Sales .............................................................. 6
Capacity Planning .................................................. 7
Construction Program ............................................... 9
Fuel ............................................................... 10
Regulation ......................................................... 14
Rates .............................................................. 14
Competition ........................................................ 18
Environmental Matters .............................................. 20
Labor .............................................................. 24
Nonutility Subsidiary .............................................. 24
Item 2 - Properties .................................................. 26
Item 3 - Legal Proceedings ........................................... 27
Item 4 - Submission of Matters to a Vote of Security Holders ......... 28
PART II
Item 5 - Market for the Registrant's Common Equity and Related
Stockholder Matters ....................................... 28
Item 6 - Selected Financial Data ..................................... 28
Item 7 - Management's Discussion and Analysis of Financial Condition
and Results of Operations ................................. 29
Item 8 - Financial Statements and Supplementary Data ................. 29
Item 9 - Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure .................................. 29
PART III
Item 10 - Directors and Executive Officers of the Registrant ......... 30
Item 11 - Executive Compensation ..................................... 32
Item 12 - Security Ownership of Certain Beneficial Owners and
Management................................................ 32
Item 13 - Certain Relationships and Related Transactions ............. 32
PART IV
Item 14 - Exhibits, Financial Statement Schedule and Reports on
Form 8-K ................................................. 33
Schedule VIII - Valuation and Qualifying Accounts .................. 40
Signatures ........................................................... 41
Exhibit 11 - Computation of Earnings Per Common Share ........... 43
Exhibit 12 - Computation of Ratios .............................. 44
Exhibit 21 - Subsidiaries of the Registrant ..................... 46
Exhibit 23 - Consent of Independent Accountants ................. 47
Report of Independent Accountants on Consolidated Financial
Statement Schedule ............................................... 48
3
PAGE LEFT BLANK
INTENTIONALLY
4
Part I
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Item 1 BUSINESS
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GENERAL
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Potomac Electric Power Company (Company), which was incorporated in the
District of Columbia in 1896 and in the Commonwealth of Virginia in 1949, is
engaged in the generation, transmission, distribution and sale of electric
energy in the Washington, D.C. metropolitan area. The Company's retail
service territory includes the District of Columbia and major portions of
Montgomery and Prince George's counties in suburban Maryland. The area served
at retail covers approximately 640 square miles and had a population of
approximately 1.9 million at the end of 1994 and 1993. 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 1994, approximately 59%
of the Company's revenue were derived from Maryland sales (including
wholesale) and 41% from sales in the District of Columbia. About 30% of the
Company's revenue were derived from residential customers, 64% from sales to
commercial and government customers and 6% from sales at wholesale.
Approximately 14% and 3% of 1994 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 and Virginia Power, neither of
which is a member of PJM.
5
SALES
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The following data presents the Company's sales and revenue by class of
service and by customer type, including data as to sales to the United States
and District of Columbia governments.
1994 1993 1992
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Electric Energy Sales (Thousands of Kilowatt-hours)
---------------------
Kilowatt-hours Sold - Total 25,546,210 25,693,999 24,484,444
========== ========== ==========
By Class of Service -
Residential service 6,586,970 6,739,987 6,155,793
General service 15,345,484 15,388,525 14,969,669
Large power service (a) 683,762 704,292 705,113
Street lighting 162,439 163,827 163,739
Rapid transit 404,634 370,428 360,432
Wholesale 2,362,921 2,326,940 2,129,698
By Type of Customer -
Residential 6,574,199 6,726,520 6,142,414
Commercial 11,685,351 11,750,542 11,391,337
U.S. Government 4,009,810 3,986,149 3,947,611
D.C. Government 913,929 903,848 873,384
Wholesale 2,362,921 2,326,940 2,129,698
Electric Revenue (Thousands of Dollars)
----------------
Sales of Electricity - Total (b) $1,783,064 $1,696,435 $1,556,098
========== ========== ==========
By Class of Service -
Residential service $ 525,660 $ 506,096 $ 433,648
General service 1,066,710 1,010,552 958,369
Large power service (a) 35,701 33,913 33,454
Street lighting 13,783 13,605 12,363
Rapid transit 27,892 24,107 22,914
Wholesale 113,318 108,162 95,350
By Type of Customer -
Residential $ 524,738 $ 505,173 $ 432,797
Commercial 834,323 791,357 748,550
U.S. Government 254,030 238,192 229,586
D.C. Government 56,655 53,551 49,815
Wholesale 113,318 108,162 95,350
(a) Large power service customers are served at high voltage of 66KV or
higher.
(b) Exclusive of Other Electric Revenue (000s omitted) of $7,536 in 1994,
$6,007 in 1993 and $6,069 in 1992.
6
The Company's sales of electric energy are seasonal, and, accordingly,
rates have been designed to closely reflect the daily and seasonal variations
in the cost of producing electricity, in part by raising summer rates and
lowering winter rates. Mild weather during the summer billing months of June
through October, when base rates are high to encourage customer conservation
and peak load shifting, has an adverse effect on 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
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General
-------
During the period 1995 through 2004 the Company estimates that its peak
demand will grow at a compound annual rate of approximately 1%. Based upon
average weather conditions, the Company expects its compound annual growth in
kilowatt-hour sales to range between 1% and 2% over the next decade. The
Company's ongoing strategies to meet the increasing energy needs of its
customers include conservation and energy use management programs which are
designed to curb growth in peak demand. The need for new capacity has been
further reduced by programs to maintain older generating units to ensure their
continued efficiency over an extended life and the cost-effective purchase of
capacity and energy.
Conservation
------------
Cost-effective conservation programs have been a major component of the
Company's success in limiting the need for new construction during the past
decade.
The Company's conservation and energy use management programs are
designed to curb growth in demand in order to defer the need for construction
of additional generating capacity and to cost-effectively increase the
efficiency of energy use. During 1994, the Company reevaluated its
conservation programs, including additional review and consideration of the
current and prospective effect of these programs on customer rates and bills.
As a result of this reevaluation, the Company phased out several conservation
programs and reduced rebate levels for others. In addition, in November 1994
the Company temporarily suspended approval of additional applications for its
Custom Rebate Program. By narrowing its conservation offerings, the Company
expects to be able to continue to encourage its customers to use energy
efficiently without significantly increasing electricity prices. The Company
expects approximately 80% of the previously estimated benefits from
conservation for approximately 45% of estimated cost.
7
For residential customers the Company continues to offer rebates for
high efficiency heating and air conditioning equipment. These rebates are
paid directly to customers when customers buy equipment which significantly
exceeds the efficiency of average available equipment.
In 1995, the Company expects to resume operation of its highly
successful Custom Rebate Program for commercial customers. This program pays
rebates to customers who install energy efficient lighting, motors, heating
and cooling systems and other measures. The Company also continues to operate
the New Building Design Program, which offers cash incentives as well as
technical assistance to developers and designers who incorporate energy
efficient designs and equipment in new commercial construction.
During 1994, the Company invested approximately $90 million in energy
conservation programs. The Company recovers the costs of its conservation
programs in its Maryland jurisdiction through a rate surcharge which amortizes
costs over a five year period and permits the Company to earn a return on its
conservation investment while receiving compensation for lost revenue. In
addition, when the Company's performance exceeds its annual goals, the Company
earns a performance bonus. The Company was awarded a bonus of approximately
$5 million in 1994 based on its 1993 performance. At the end of 1994 the
conservation surcharge in Maryland was $.00338 per kilowatt-hour. In the
District of Columbia, conservation costs are amortized over 10 years with an
accrued return on unamortized costs. To date, costs have been considered in
base rate cases.
In 1994, approximately 151,000 customers participated in continuing
energy use management 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 based on time-of-use
rates.
It is estimated that peak load reductions of approximately 525 megawatts
have been achieved to date from conservation and energy use management
programs and that additional peak load reductions of approximately 380
megawatts will be achieved in the next five years. The Company also estimates
that in 1994 energy savings of more than 760 million kilowatt-hours have been
realized through operation of its conservation and energy use management
programs. During the next five years, the Company plans to expend an
estimated $370 million ($86 million in 1995) to encourage the efficient use of
electric energy and to reduce the need to build new generating facilities.
Although the Company is continuing its conservation and energy use
management efforts, new sources of supply will be needed to assure the future
reliability of electric service to the Washington area. These new sources of
supply will be provided through the Company's plans for purchases of capacity
and energy and through its ongoing construction program.
8
Purchase of Capacity and Energy
-------------------------------
Pursuant to the Company's 1987 long-term capacity purchase agreements
with Ohio Edison and Allegheny Power System, the Company is purchasing 450
megawatts of capacity and associated energy through the year 2005. In
addition, effective June 1, 1994 through May 31, 1995, the Company is
purchasing 147 megawatts of capacity from Pennsylvania Power and Light
Company. The Company also has a purchase agreement with SMECO, through 2015,
for 84 megawatts of capacity supplied by a combustion turbine installed and
owned by SMECO at the Company's Chalk Point Generating Station. The Company
is responsible for all costs associated with operating and maintaining the
facility.
The Company has been exploring other cost-effective sources of energy
and has entered into contracts for two nonutility generation projects which
total 270 megawatts of capacity. A 40-megawatt resource recovery facility
with which the Company has a contract is now under construction in Montgomery
County, Maryland. In addition, the Company has an agreement with Panda Energy
Corporation for a 230-megawatt gas-fueled combined-cycle cogeneration project
in Prince George's County, Maryland. This project has received a certificate
of convenience and necessity from the Maryland Public Service Commission.
These nonutility generation projects are expected to begin operating in 1995
and 1996, respectively.
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, 1992 to December 31, 1994, the Company made property
additions, net of an Allowance for Funds Used During Construction (AFUDC), of
$926 million (of which $298 million were made in 1994) and had property
retirements of $122 million (of which $44 million were made in 1994).
The Company's current construction program calls for estimated
expenditures, excluding AFUDC, of $215 million in 1995, $170 million in 1996,
$210 million in 1997, $240 million in 1998 and $250 million in 1999, an
aggregate of $1.1 billion for the five-year period. AFUDC is estimated to be
$7 million in 1995, $7 million in 1996, $7 million in 1997, $9 million in 1998
and $10 million in 1999. The 1995-1999 construction program includes
approximately $544 million for generating facilities (including $165 million
for Clean Air Act compliance), $35 million for transmission facilities, $497
million for distribution, service and other facilities, and $9 million
associated with the Company's energy use management programs. Making use of
the flexibilities in its long-term construction plan, the Company in 1994
reduced projected expenditures for the five years 1995 through 1999 by $190
million from amounts previously planned. This reduction followed a $365
million reduction in 1993. The construction reductions and deferrals are
9
associated with lower rates of projected growth in usage of electricity
resulting in large part from implementing economical conservation programs.
The Company plans to finance its construction program primarily through funds
provided by operations.
The construction program includes amounts for the construction of
facilities that will not be completed until after 1999. Although the program
includes provision for escalation of construction costs, generally at an
annual rate of 4%, the aggregate budget for long lead time projects will
increase or decrease depending upon the actual rates of inflation in
construction costs. The program is reviewed continuously and revised as
appropriate to reflect changes in projections of demand, consumption patterns
and economic trends.
The Clean Air Act Amendments of 1990 (CAA) requires utilities to reduce
emissions of sulfur dioxide and nitrogen oxides in two phases, January 1995
(Phase I) and January 2000 (Phase II). The Company has developed plans for
complying with the CAA to achieve prescribed standards in Phases I and II.
The Company anticipates capital expenditures totaling $165 million over the
next five years pursuant to these plans. The plans call for replacement of
boiler burner equipment for nitrogen oxides emissions control, the use of
lower-sulfur fuel and cofiring with natural gas at selected baseload plants.
The CAA allows companies to achieve required emission levels by using a
market-based emission allowance trading system. If economical, emission
allowances may be purchased in lieu of burning lower-sulfur fuel.
Installation of scrubbers is not contemplated for the Company's wholly
owned plants. Both the District of Columbia and Maryland commissions have
approved the Company's plans for meeting Phase I requirements including cost
recovery of investment and inclusion of emission allowance expenses in the
Company's fuel adjustment clause.
The Company owns a 9.72% undivided interest in the Conemaugh Generating
Station located in western Pennsylvania. As a result of installing flue gas
scrubbing equipment to meet Phase I requirements of the CAA, this station will
receive additional allowances. The Company's share of these "bonus"
allowances may be used to reduce the need for lower-sulfur fuel at its other
plants. The Company's share of the construction costs is approximately $38
million.
In addition, the final segment of a 500,000 volt transmission line which
provides links in the transmission systems of the Company, Baltimore Gas and
Electric Company and Virginia Power was placed in service prior to June 1,
1994.
FUEL
----
For customer billing purposes, all of the Company's kilowatt-hour sales
are covered by separately stated fuel rates (see Item 8 - Note 2 of "Notes to
Consolidated Financial Statements").
10
The Company's generating units burn only fossil fuels. The principal
fuel is coal. The Company owns no nuclear generation facilities and none are
planned. The following table sets forth the quantities of each type of fuel
used by the Company in the years 1994, 1993 and 1992 and the contribution, on
the basis of Btus, of each fuel to energy generated.
1994 1993 1992
-------------- -------------- --------------
% of % of % of
Quantity Btu Quantity Btu Quantity Btu
-------- ----- -------- ----- -------- -----
Coal
(000s net tons) 5,788 76.1 6,010 79.4 5,926 82.9
Residual oil
(000s barrels) 4,868 15.7 4,835 15.9 3,294 11.4
Natural gas
(000s dekatherms) 10,780 5.5 6,090 3.2 8,200 4.5
No. 2 fuel oil
(000s barrels) 919 2.7 480 1.5 376 1.2
The following table sets forth the average cost of each type of fuel
burned, for the years shown.
1994 1993 1992
------ ------ ------
Coal: per ton $44.39 $43.69 $43.66
per million Btu 1.73 1.72 1.72
Residual oil: per barrel 15.31 15.09 14.35
per million Btu 2.44 2.39 2.28
Natural gas: per dekatherm 2.49 2.88 2.32
per million Btu 2.49 2.88 2.32
No. 2 fuel oil: per barrel 24.34 24.98 26.70
per million Btu 4.17 4.30 4.60
The average cost of fuel burned per million Btu was $1.95 in 1994,
compared with $1.90 in 1993 and $1.85 in 1992. The increase of approximately
3% in each of the past two years in the system average unit fuel cost resulted
from increased use of major cycling and peaking generation units which burn
higher cost fuels. The Company's major cycling and certain peaking units can
burn natural gas or oil, adding flexibility in selecting the most cost-
effective fuel mix. The increase in the actual percent of gas contribution in
1994 to the fuel mix reflects the decreased price of gas and the increased
price of oil. The decrease in the actual percent of coal contribution to the
fuel mix in 1994 primarily reflects major outages for construction related to
Clean Air Act additions on baseload coal-fired generation units.
11
Ten of the Company's sixteen steam-electric generating units can burn
only coal; two can burn only residual oil; two can burn either coal or
residual oil or a combination of both and two units can burn either residual
oil or natural gas. Those units capable of burning either coal or residual
oil normally burn coal as their primary fuel. The Company also has combustion
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
------------------ ------------------
1994 1993 1992 1994 1993 1992
---- ---- ---- ---- ---- ----
Steam Generation
Dual fuel units, capable
of burning coal, residual
oil or a combination of
coal and residual oil.... 17% 18% 18% 28% 29% 27%
Units capable of burning
coal only................ 28% 28% 29% 43% 45% 50%
Units capable of burning
residual oil only........ 8% 8% 9% 1% 1% -
Units capable of burning
residual oil or natural
gas...................... 18% 19% 19% 12% 10% 9%
Combustion Turbines
Units capable of burning
No. 2 fuel oil only...... 9% 9% 9% )
Units capable of burning ) 3% 2% 1%
No. 2 fuel oil or natural )
gas...................... 11% 11% 9% )
Purchased capacity........... 9% 7% 7% 13%(a) 13%(a) 13%(a)
(a) Includes purchases under cogeneration agreements.
12
The Company's fuel mix objective is to obtain a minimum unit cost of
energy through the use of its generating facilities. The actual use of coal,
oil and natural gas is influenced by the availability of the generating units,
the relative cost of the fuels, energy and demand requirements of other
utilities with which the Company has interconnection arrangements, regulatory
requirements (for future units), weather conditions and fuel supply
constraints, if any.
The Company has numerous coal contracts with various expiration dates
through 2003 for aggregate annual deliveries of approximately 3.5 million
tons. Deliveries under these contracts are expected to provide approximately
58% of the estimated system coal requirements in 1995. Approximately 42% of
the estimated system coal requirements in 1995 will be purchased under shorter
term agreements and on a spot basis from a variety of suppliers. Prices under
the Company's coal contracts are generally determined by reference to base
amounts adjusted to reflect provisions for changes in suppliers' costs, which
in turn are determined by reference to published indices and are limited by
current market spot prices.
Most of the coal currently used by the Company is surface mined in
Pennsylvania, West Virginia and Maryland. The Company believes that it will
be able to continue to obtain the quantities of coal needed to operate at its
current fuel mix objective. The costs of coal to the Company may be affected
by increases in the costs of production, including the costs of complying with
federal legislation (such as amendments to the CAA, discussed above, the costs
of surface mining reclamation and black lung benefits), the imposition of (or
changes in) state severance taxes and by modification of contracts with
Conrail, CSX Transportation and Norfolk Southern which cover all of the coal
movements to the Company's generating stations.
The Company purchases both domestically refined and imported residual
oil. Residual oil is being obtained under one two-year and 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 two one-year contracts.
Certain units at the Company's Chalk Point Generating Station and the
new Dickerson combustion turbine units are capable of burning natural gas as
well as oil. The Company has a contract with Washington Gas Light Company for
Chalk Point extending through December 1998. The Company has a one-year
contract with Consolidated Natural Gas for the Dickerson combustion turbine
units through March 31, 1995. 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.
13
REGULATION
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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 8 megawatts. As
noted above under "Purchase of Capacity and Energy," the Company is planning
additional cost-effective nonutility generation projects.
RATES
-----
General
-------
The Company's retail rates for electric service in Maryland and the
District of Columbia are based on allowed rates of return to the Company's
jurisdictional original cost rate base investments as determined in base rate
proceedings before the regulatory commissions by reference to the test periods
used in setting rates. Rate base in each of these jurisdictions generally has
included (1) the Company's full investments in Electric Plant in Service (net
of depreciation, certain pre-1981 investment tax credits and plant related
deferred income taxes) and the pollution control portion of Construction Work
in Progress (CWIP), (2) inventories of fuels and other materials and supplies
and (3) an allowance for cash working capital. The Company has employed,
since 1978, Allowance for Funds Used During Construction (AFUDC) accounting.
In general, the Company capitalizes AFUDC with respect to investments in CWIP
with the exception of expenditures required to comply with federal, state or
local environmental regulations (pollution control projects), which are
included in rate base without capitalization of AFUDC. In 1992, pursuant to
orders from both the Maryland and District of Columbia commissions, the
Company commenced the accrual of a capital cost recovery factor on the retail
jurisdictional portion of certain pollution control projects related to
compliance with the CAA. The base for calculating this return is the amount
by which the retail jurisdictional CAA expenditure balance exceeds the CAA
balance included in rate base in the Company's most recently completed base
rate proceeding. The jurisdictional AFUDC capitalization rates are determined
on a gross basis pursuant to formulas prescribed by the FERC. The effective
capitalization rates were approximately 7.6% in 1994, 8.7% in 1993 and 9.1% in
1992, compounded semiannually.
14
Rate orders received by the Company during the past three years provided
for increases in annual base rate revenue as shown in the table below.
Rate
Increase
(Decrease) % Effective
Regulatory Jurisdiction ($000) Change Date
-------------------------- ---------- ---------- ---------------
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
Federal-Wholesale 3,801 3.1 January 1993
Maryland 25,300 3.0 1992/1993 (a)
District of Columbia 30,380 4.6 July 1992
Federal-Wholesale 2,814 2.6 January 1992
(a) See Maryland discussion below.
Fuel Rates
----------
The Company has separately stated fuel rates in each jurisdiction. Such
rates include the delivered cost of fuel and the applicable costs and/or
credits from the interchange of energy with other electric utilities, to the
extent not provided for in base rates.
In January 1995, the Company filed for a 5.3% decrease in the Maryland
fuel rate which became effective, subject to refund, on February 1, 1995.
Previously, the Company filed for a 5.3% increase in the fuel rate which
became effective, subject to refund, on November 1, 1994. Both cases are
currently pending and a final order in each case is expected during the second
quarter of 1995 (see Item 8 - Note 2 of "Notes to Consolidated Financial
Statements").
Maryland
--------
In October 1993, pursuant to a settlement agreement, the Commission
authorized a $27 million, or 3%, increase in base rate revenue effective
November 1, 1993. The settlement included a new system composite depreciation
rate of approximately 3.1%, up from the 3% rate previously in effect. In
connection with the settlement agreement, no determination was made with
respect to rate of return. The rate of return on common stock equity most
recently determined for the Company in a fully litigated rate case was 12.75%
established by the Commission in a June 1991 rate increase order.
In October 1992, pursuant to a settlement agreement, the Commission
authorized an increase in base rate revenue of approximately 3% with $18
million effective December 1, 1992, and $7.3 million effective June 1, 1993.
No determination with respect to rate of return was specified.
15
District of Columbia
--------------------
In its pending base rate proceeding, the Company further updated its
cost of service data filing, on February 21, 1995, to reduce the base rate
revenue increase request to $56.6 million, or 7.6%, based upon a 1994 calendar
year test period and a return of 9.89% on average rate base, including a
12.75% return on common stock equity. The update was filed principally to
reflect the effect of the Company's Voluntary Severance Program. This case
was originally filed on September 30, 1994, requesting a $67 million, or 9%,
increase in base rate revenue. The Company had previously updated its initial
cost of service data filing to reduce the request to $60.6 million to reflect
subsequent events which included the sale and leaseback of the Control Center
Replacement project, a reduction in the 1995 District of Columbia income tax
rate, an approved traffic signal maintenance deregulation agreement with the
District of Columbia and an increase in the FICA tax wage base. In accordance
with Commission directives, the Company has included conservation program
expenditures subsequent to June 1993 in the proposed Environmental Cost
Recovery Rider in its pending Least-Cost Planning proceeding filed in June
1994. It is expected that both proceedings will be concluded by mid-1995. On
January 17, 1995, the Commission Staff filed testimony recommending a $37.1
million rate increase.
In May 1994, the Commission ruled on the application for reconsideration
of its March 1994 rate order. The Commission's original order authorized the
Company to increase its base rates by a total of $25.4 million in two steps:
an increase of $23.2 million effective March 16, 1994 and an increase of $2.2
million effective June 5, 1994. The order on reconsideration authorized an
additional "step 2" base rate increase of $1.3 million resulting in a total
base rate increase of $26.7 million. Of the "step 2" increase, $3 million was
contingent on the June 1, 1994 in-service date of the final segment of a 500
kilovolt transmission line which provides links in the transmission systems of
the Company, Baltimore Gas and Electric Company and Virginia Power. This
transmission line segment was placed in service prior to June 1, 1994. The
authorized rates are based on a 9.05% rate of return on average rate base,
including an 11% return on common stock equity. Prior to the order, the
Company had filed updated cost of service data which demonstrated a need for
$55.4 million increase in District of Columbia base rate revenue, based upon
the requested return of 9.46% on average rate base including an 11.8% return
on common stock equity.
The Commission's rate increase order approved the Company's proposal for
including future changes in purchased capacity costs in fuel adjustment
billings. In addition, the Commission reversed in longstanding practice of
including Electric Plant Held for Future Use in rate base. The Commission
also authorized an accounting change for postretirement benefit costs
consistent with SFAS No. 106 entitled "Employers' Accounting for
Postretirement Benefits Other Than Pensions" and adopted a three-year phase-in
approach for inclusion of these increased costs in the Company's rates. In
June 1994, the Company established a regulatory asset for the increase in
postretirement benefit costs of $.6 million on an after tax basis which will
be amortized over a three year period.
16
The initial order also reduced the Company's revenue requirement to
reflect 20% of the cumulative effect of a 1992 accounting change related to
unbilled revenue applicable to the District of Columbia. The Commission's
initial decision to adopt an unbilled revenue adjustment, supplemented by its
subsequent decisions in response to the Company's application for
reconsideration and motion for clarification, has required the Company to
establish in June 1994 a regulatory liability of $2.5 million on an after tax
basis which will be amortized in 1995 and 1996.
The Commission's initial decision rejected the Company's proposal to
provide rate recognition of DSM costs through a billing surcharge and
consistent with prior decisions, included $5.3 million in base rates to
recognize DSM program costs without provision for lost revenue between rate
cases. In addition, the initial decision and subsequent decisions in response
to the Company's application for reconsideration and motion for clarification,
disallowed the recovery of 25% of test period DSM program expenditures which
required the Company to write off $2.2 million on an after tax basis in June
1994. In its order on reconsideration, the Commission stated that in the
future the appropriate forum for consideration for DSM cost recovery would be
the Company's least-cost resource planning cases, which the Company files on
a two-year cycle. Under this new process, DSM approval and cost recovery will
be linked together in the same proceeding. Subsequent to June 1993, the
Company has expended through December 31, 1994, approximately $56 million on
conservation in the District of Columbia. The Company requested a surcharge
mechanism for billing unamortized DSM costs in its June 1994 Least-Cost
Planning Case filing.
In July 1994, the Company filed a Petition for Review with the District
of Columbia Court of Appeals related to the Commission's decisions to disallow
the recovery of 25% of test period DSM program expenditures and to reject an
adjustment to reflect increases in employee benefit costs. The Company
expects to receive an order on appeal in the second quarter of 1995.
Wholesale
---------
The Company has a 10-year full service power supply contract with SMECO,
a wholesale customer. The contract period is to be extended for an additional
year on January 1 of each year, unless notice is given by either party of
termination of the contract at the end of the 10-year period. The full
service obligation can be reduced by SMECO by up to 20% of its annual
requirements with a five-year advance notice for each such reduction.
SMECO rates were increased by $2.3 million effective January 1, 1995.
The rates were increased by $2.6 million and $3.8 million effective January 1,
1994 and 1993, respectively. A rate increase of $4.2 million is scheduled to
become effective January 1, 1996.
17
Interchange of Power
--------------------
The Company's generating and transmission facilities are interconnected
with the other members of PJM and other utilities. The pricing of most PJM
internal economy energy transactions is based upon "split savings" so that the
price of such energy is halfway between the cost that the purchaser would
incur if the energy were supplied by its own sources and the cost of
production to the company actually supplying the energy.
The Company has interconnection agreements with Allegheny Power System
(APS) and Virginia Power. These agreements provide a mechanism and the
flexibility to purchase power from these parties or from others with whom they
are interconnected on an as-needed basis in amounts mutually agreed to from
time-to-time pursuant to negotiated rates, terms and conditions.
Pursuant to the Company's long-term capacity purchase agreements with
Ohio Edison and APS, the Company is purchasing 450 megawatts of capacity and
associated energy through the year 2005. The monthly capacity commitment
under these agreements, excluding an allocation of fixed operating and
maintenance cost, increased from $12,380 per megawatt through 1993 to $18,060
per megawatt, effective January 1, 1994 with provision for escalation in 1999.
In addition, effective June 1, 1994 through May 31, 1995, the Company is
purchasing 147 megawatts of capacity from Pennsylvania Power and Light Company
at a total cost of $3 million.
The Company has a purchase agreement with SMECO, through 2015, for 84
megawatts of capacity supplied by a combustion turbine installed and owned by
SMECO at the Company's Chalk Point Generating Station. The Company is
responsible for all costs associated with operating and maintaining the
facility. The capacity payment to SMECO is $462,000 per month.
COMPETITION
-----------
The traditional concept of a vertically integrated electric utility
industry, with exclusive franchises serving defined areas, is changing.
Market forces, federal regulatory policies and customer demands are creating a
more competitive landscape. Although much of the future outlook for the
utility industry remains undefined, it is clear that the power generation
sector is rapidly moving toward a competitive, commodity-based business, with
broader access to utility-owned transmission facilities. The Company believes
that it has prepared for these changes.
The Company has achieved a highly competitive position by developing and
emphasizing the strong fundamentals of its core business. A premium has been
placed on financial, operating and construction flexibility, which has
prepared the Company to operate in the new and changing business environment.
In 1994, the Company's average price was 6.98 cents per kilowatt-hour,
compared with 6.60 cents in 1993 and 6.65 cents in 1985 - a modest 5% increase
over the past 10 years. Electricity price comparisons in 1993 of East Coast
18
cities range from a high of 13.3 cents per kilowatt-hour in New York to a low
of 6.5 cents in Richmond and 6.3 cents in Raleigh. Based on this comparison,
the the Company's rates compare favorably with those of electric utilities
serving other East Coast cities.
The Company's cost of generation is among the lowest on the Eastern
Seaboard. The Company's plants are maintained at a high level of availability
and their operating efficiency continues to be among the best in the nation.
Based on 1993 data, the Company's net investment in generating capacity was
only $232 per kilowatt, compared with $380 industrywide. Due to this low
generating investment and because of the Company's extensive investment in the
underground distribution and transmission network serving the nation's
capital, generating assets account for only 38% of total plant investment.
This low ratio compares favorably with an industry median of about 50%. In
addition, the Company's contracts for purchased power are competitive and no
additional generating capacity is foreseen until well into the next decade.
The Company's investment in transmission plant amounts to approximately
10% of total assets, about the median for the industry. In 1994, the last
sections of a 243-mile, 500-kilovolt transmission ring surrounding Washington,
D.C. was completed. This loop provides greater reliability for the Company's
system and increases access to other utilities and power pools.
Substantial concern has been expressed over the potential burdens and
risks of "stranded investment" as the utility industry makes the transition to
a less regulated business. Much of this concern focuses on certain high-cost
nuclear and other generating investments that may not be competitive with
alternative sources of power. The Company is in a favorable position with its
low plant investment per kilowatt. Significantly, approximately 50% of the
Company's net plant investment is in distribution system assets, which are not
likely to be "stranded" by market developments and which provide a stable
revenue base in an evolving business environment.
In addition, the Company's costs deferred under traditional rate-making
conventions - known as "regulatory assets" - are relatively limited. They
consist mostly of deferred taxes and other routine deferrals such as those
associated with conservation programs and changes in fuel costs.
Consequently, the Company does not expect significant "regulatory asset"
burdens.
With a significant federal presence, a well-educated and affluent
population, and a total absence of heavy industry, the Washington metropolitan
area is unique among America's major markets. The Company's nonresidential
load consists principally of commercial office buildings. The Company does
not have large customers with energy-intensive operations, which would be
vulnerable in a more open marketplace.
Additional information concerning competition is presented in
Management's Discussion and Analysis incorporated by reference in Item 7.
19
ENVIRONMENTAL MATTERS
---------------------
General
-------
The Company is subject to federal, state and local legislation and
regulation with respect to environmental matters, including air and water
quality and the handling of solid and hazardous waste. Air quality
requirements relate to both ambient air quality and emissions from facilities,
including particulate matter, sulfur dioxide, nitrogen oxides, carbon
monoxide, volatile organic compounds and visible emissions. Water quality
requirements relate to intake and discharge of water from facilities,
including water used for cooling purposes in electric generating facilities.
Waste requirements relate to the generation, treatment, storage,
transportation and disposal of specified wastes. Compliance with such
requirements may limit or prevent certain operations or substantially increase
the cost of construction and operation of the Company's existing and future
generating installations. The Company has expended approximately $546 million
through December 31, 1994, for the construction of pollution control
facilities. The $544 million 1995-1999 construction program for generating
facilities includes estimated provision for pollution control facilities,
including expenditures for CAA compliance, of $47 million for 1995, $17
million for 1996, $43 million for 1997, $58 million for 1998 and $59 million
for 1999. 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 developed cost-effective plans for
complying with the CAA to achieve prescribed standards in two phases. The
Company anticipates CAA related capital expenditures totaling $165 million
20
over the next five years. The plans call for replacement of boiler burner
equipment for nitrogen oxides emissions control, the use of lower-sulfur fuel
and cofiring with natural gas at selected baseload plants. The CAA allows
companies to achieve required emission levels by using a market-based emission
allowance trading system. If economical, emission allowances may be purchased
in lieu of burning lower-sulfur fuel.
Maryland, the District of Columbia and Northern Virginia are members of
the Ozone Transport Commission, established by the CAA for the purpose of
developing a regional solution to attainment of the ambient ozone standard in
the northeastern United States. Those states are currently preparing rules
under Title I of the CAA which will require the retrofit of existing
generating units with Reasonably Available Control Technology (RACT) for
nitrogen oxides control by mid-1995. The Company has developed a plan whereby
the nitrogen oxides reductions already planned to be achieved by PEPCO under
Title IV of the CAA will also satisfy the states' requirements for RACT. This
plan will be undergoing regulatory review and implementation during 1995.
The Company is unaware in any respect in which its generating stations
are not presently in compliance with federal and state air quality
regulations, with the exception of visible emissions from the Dickerson
Station and Chalk Point Units 3 and 4. Recognizing that the specified units
cannot continuously satisfy their applicable standards, the Company is working
with Maryland regulators to establish revised visible emissions standards for
the Dickerson units and a plan of compliance for the Chalk Point units.
Water Quality
-------------
The Company's generating stations operate under National Pollutant
Discharge Elimination System (NPDES) permits. NPDES renewal applications
submitted in December 1991 for the Dickerson station, March 1992 for the Chalk
Point station, April 1993 for the Buzzard Point station and July 1993 for the
Benning station are pending. NPDES permits were issued for the Potomac River
station in February 1994 and for the Morgantown station in February 1995.
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 filed in the Circuit
Court for Baltimore City was subsequently dismissed on July 25, 1994. It is
currently not anticipated that these regulations will result in any
significant adverse economic impact on the Company.
21
On March 18, 1993, the Company brought to the attention of state and
federal authorities information discovered in an internal Company
investigation to the effect that one of the Company's NPDES permits may have
been violated by the pumping of water from a settlement pond at a Company-
owned flyash storage facility. Further investigation both internally and by
the governmental authorities has continued, including issuance of, and
response by the Company to, a federal grand jury subpoena for documents
germane to the investigation and testimony of two Company employees before the
grand jury.
Toxic Substances
----------------
The Company was notified by the EPA on December 18, 1987, that it, along
with five other utilities and eight non-utilities, is a potentially
responsible party (PRP) under the Comprehensive Environmental Response,
Compensation and Liability Act of 1980, as amended (CERCLA or Superfund), in
connection with the polychlorinated biphenyl compounds (PCBs) contamination of
soil, ground water and surface water occurring at a Philadelphia, Pennsylvania
site owned by an unaffiliated company. Additional PRPs have since been
identified and the number is continuously subject to change. In the early
1970s, the Company sold scrap transformers, some of which may have contained
some level of PCBs, to a metal reclaimer operating at the site. In October
1994, a Remedial Investigation/Feasibility Study (RI/FS) was submitted to the
EPA. Pursuant to an agreement among the participating PRPs, the Company is
responsible for 12% of the costs of the RI/FS. Total costs of the RI/FS,
including legal fees, are currently estimated to be $5.6 million. The Company
has paid $836,000 to date. The report includes a number of possible remedies,
the estimated costs of which range from $2 million to $90 million. In
addition, the Company cannot estimate the total extent of the EPA's
administrative and oversight costs. While a remedy near the lower end of the
range is possible, the Company cannot predict what remedy may be acceptable to
the EPA. To date, the Company has accrued approximately $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
22
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 Cases." The Company (and other defendants) were
brought into these cases on a theory of premises liability under which
plaintiffs argue that the Company was negligent in not providing a safe work
environment for employees of its contractors who allegedly were exposed to
asbestos while working on the Company's property. Initially, a total of
approximately four hundred and forty-eight (448) individual plaintiffs added
the Company to their Complaints. While the pleadings are not entirely clear,
it appears that each plaintiff seeks $2 million in compensatory damages and $4
million in punitive damages from each defendant. In a related proceeding in
the Baltimore City case, the Company was served, in September 1993, with a
third party complaint by Owens Corning Fiberglass, Inc. (Owens Corning)
alleging that Owens Corning was in the process of settling approximately 700
individual asbestos-related cases and seeking a judgment for contribution
against the Company on the same theory of alleged negligence set forth above
in the plaintiffs' case. Subsequently, Pittsburgh Corning Corp. (Pittsburgh
Corning) filed a third party complaint against the Company, seeking
contribution for the same plaintiffs involved in the Owens Corning third party
complaint. Since the filings, a number of the individual suits have been
disposed of without any payment by the Company. 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. While the
aggregate amount specified in the remaining suits would exceed $1 billion, 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.
23
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 a labor contract expiring May 31, 1996, with Local 1900
of the International Brotherhood of Electrical Workers which represents 2,912
of the Company's 4,863 employees.
In September 1994, the Company announced a Voluntary Severance Program
(VSP), which offered incentive payments to full-time employees based upon
years of service, to voluntarily sever employment no later than the first
quarter of 1995. Approximately 340 employees will participate in the VSP.
During January 1995, $7.4 million in severance costs was expensed. The VSP
will result in annual savings of more than $15 million. Including this
reduction, the Company's workforce has declined by more than 700 employees, or
14%, since 1989.
NONUTILITY SUBSIDIARY
---------------------
Potomac Capital Investment Corporation (PCI), the Company's principal
wholly owned subsidiary, was formed in late 1983 to provide a vehicle for
ongoing nonutility investment business. PCI's objective is to provide an
annual supplement to utility earnings and to build long-term shareholder
value.
At December 31, 1994, PCI's assets totaled $1.7 billion, including
$954.4 million in finance and operating equipment leases and $473.6 million in
marketable securities, principally investment grade sinking fund preferred
stock. The Company's equity investment in PCI was $271.1 million, including
$149.3 million of subsidiary retained earnings. Additional financial
information concerning assets, income, expenses and net earnings is presented
in the consolidated financial statements incorporated by reference in Item 8.
PCI's equipment-leasing portfolio consists primarily of wide-body
commercial aircraft. Income from leasing activities includes rental and
interest income, gains on asset sales and service fees. At December 31, 1994,
24
a portion ($263 million carrying value) of PCI's aircraft leasing portfolio
consisted of equipment not on lease (four L-1011 aircraft returned by TWA when
leases expired in November 1994) and equipment on short-term, and in some
cases, usage-based operating leases with monthly rentals and maintenance
payments dependent upon hours used. Under these leases, PCI is responsible
for future operating and maintenance expenses exceeding amounts provided
therefor by lessees. Most of the usage-based and short-term leases include
provisions for early termination by PCI if more favorable transactions become
available. In January 1995, because of the lessee's inability to make timely
rental payments and to satisfy other lease obligations, Fortunair Canada
returned one B747 aircraft previously under short-term lease. PCI is
continuing to seek new leases with more favorable terms or to sell the
equipment on satisfactory terms. In January 1995, Continental Airlines
(Continental) announced its intention to seek the early termination of its A-
300 aircraft leases and the reduction of rental payments due under certain
leases of other widebody aircraft. Pending discussions with lessors,
Continental has indicated that it will not be making full payments to such
lessors as required by the terms of its contracts. Beginning in February
1995, Continental unilaterally reduced, by approximately 50%, the amounts of
rent paid to PCI for the lease of one A-300 aircraft and six DC-10-30 aircraft
(two of which are owned jointly with another investor). Continental also has
informed PCI that, during 1995, it intends to take out of service and further
reduce the rent payments for the lease of the A-300 aircraft. Continental is
seeking temporary rent deferrals for the contractual rents due on the DC-10-30
aircraft. PCI has declared Continental to be in default of its obligations
under the A-300 and DC-10-30 leases and has reserved the right to exercise the
default remedies available under the leases, including repossession of the
aircraft and acceleration and recovery of the present value of the full rents
due during the remainder of the lease terms. PCI has informed Continental
that it expects all lease obligations to be satisfied in full, and currently
is discussing with Continental the payment terms and schedule for the unpaid
balance of rents due from Continental under the leases of the DC-10-30
aircraft and compensation to be paid for the return of the A-300 aircraft
prior to the scheduled end of its lease term. Additional information
concerning leasing activities is presented in Management's Discussion and
Analysis incorporated by reference in Item 7.
PCI's aircraft leasing business has been affected adversely by a lengthy
economic downturn in the airline industry. There can be no assurance that a
recovery will occur or as to the nature, extent or timing of any such
recovery. Accordingly, management is evaluating business strategies to
improve the overall performance of PCI's aircraft equipment operating lease
portfolio, including actions which could have a non-recurring material
adverse impact on the Company's earnings for 1995.
PCI's real estate activity consists of real estate projects and holdings
in the Washington metropolitan area. PCI also owns leasehold interests in oil
and natural gas producing properties in Texas.
25
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 1994
------------------ --------------------------------------- -------------- ------------ ------------ ---------------
(Thousands)
Benning Benning Road and Anacostia River, N.E. No. 4 Oil 550 - 255
Washington, D.C.
Buzzard Point 1st and V Streets, S.W. - - 256 19
Washington, D.C.
Potomac River Bashford Lane and Potomac River Coal 482 - 2,109
Alexandria, Virginia
Dickerson Potomac River, South of Little Monocacy Coal 546 291 3,311
River, Dickerson, Maryland
Chalk Point Patuxent River at Swanson Creek Coal/ 1,907 516 <F2> 6,235
Aquasco, Maryland Residual Oil/
Natural Gas
Morgantown Potomac River, South of Route 301 Coal/ 1,164 248 6,327
Newburg, Maryland Residual Oil
----------- ----------- -----------
Total - Wholly owned Units 4,649 1,311 18,256
Conemaugh Indiana County, Pennsylvania Coal 165 1 1,064
----------- ----------- -----------
Total - All Stations Operated 4,814 1,312 19,320
===========
Purchased Capacity
Ohio Edision <F3> 450 - 2,957
===========
Other <F4> 147 -
----------- -----------
Total System 5,411 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.
<F4>A one-year agreement with Pennsylvania Power and Light Company which
became effective June 1, 1994.
</FN> 26
The five steam-electric generating stations, together with combustion
turbines, had an aggregate net capability at December 31, 1994, of 5,960
megawatts (including the 84 megawatt combustion turbine owned by SMECO at the
Company's Chalk Point Generating Station), assuming all units are available
for service at the time and for the usual duration of the system peak (which
occurs in the summer). The Company also has 166 megawatts of net capability
available from its 9.72% undivided interest in a mine-mouth, steam-electric
generating station known as the Conemaugh Generating Station, located in
Indiana County, Pennsylvania, which it owns with eight other utilities as
tenants in common. The Company also receives generating capacity and
associated energy from Ohio Edison under its 1987 long-term agreements with
Ohio Edison and APS. The agreements, which provide for 450 megawatts of
capacity and associated energy, are expected to continue at that level through
the year 2005. The net 60-minute peak load in 1994 was 5,660 megawatts, which
occurred on July 6, 1994, and was 1.9% below the all-time summer peak demand
of 5,769 megawatts. To meet the 1994 summer peak demand, the Company also had
256 megawatts available from its dispatchable energy use management programs.
For additional information regarding the Company's net generating capability,
see "Construction Program" and "Fuel" under Item 1 - Business.
The Company owns the transmission and distribution facilities serving
its customers. As stated above, the Company's interest in the Conemaugh
Generating Station and its associated transmission lines is that of a tenant
in common with eight other owners. Substantially all of such Conemaugh
transmission lines, substantially all of the Company's transmission and
distribution lines of less than 230,000 volts, small portions of its 230,000
volt transmission lines and certain of its substations are located on land
owned by others or in public streets and highways. Substantially all of the
Company's property and plant is subject to the mortgage which secures its
bonded indebtedness.
Item 3 LEGAL PROCEEDINGS
------ -----------------
For information regarding pending environmental legal proceedings, see
"Environmental Matters" under Item 1 - Business.
The Company was a defendant in employment discrimination litigation
which was pending in the United States District Court for the District of
Columbia. In February 1993, the parties to the case reached tentative
settlement of the claims and, in April 1993, the Company paid $38.26 million
into a trust fund pursuant to the terms of the Agreement. The funds will be
disbursed from the trust fund to certain covered classes of current and former
employees and applicants for employment and to cover the plaintiffs' legal and
expert fees and costs. The Court approved the settlement agreement, effective
in July 1993. The Company received insurance payments of $13.5 million in
October 1993 and $24 million in January 1994, bringing the total recovered
from insurance companies to $37.5 million. At December 31, 1993,
approximately $.8 million was charged to non-operating expense. Subsequently,
in November 1994, the Company received an additional insurance recovery of $.8
million which was treated as a credit to amounts previously charged to non-
operating expense.
27
Item 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
------ ---------------------------------------------------
None.
Part II
-------
Item 5 MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
------ -----------------------------------------------------------------
MATTERS
-------
The following table presents the dividends per share of Common Stock and
the high and low of the daily Common Stock transaction prices as reported in
The Wall Street Journal during each period. The New York Stock Exchange is
the principal market on which the Company's Common Stock is traded.
Dividends Price Range
Period Per Share High Low
--------------------- --------------- -------- ---------
1994:
First Quarter...... $.415 $26-5/8 $21-3/4
Second Quarter..... .415 23-1/2 18-1/2
Third Quarter...... .415 21-1/2 18-3/8
Fourth Quarter..... .415 $1.66 19-3/4 18-1/4
1993:
First Quarter...... $.41 $26-1/2 $23-7/8
Second Quarter..... .41 27-3/8 25-5/8
Third Quarter...... .41 28-7/8 27-1/8
Fourth Quarter..... .41 $1.64 28-3/4 24-5/8
The number of holders of Common Stock was 104,047 at March 7, 1995 and
96,638 at December 31, 1994.
There were 118,248,594 and 118,248,103 shares of the Company's $1 par
value Common Stock outstanding at March 7, 1995, and December 31, 1994,
respectively. A total of 200 million shares is authorized.
At its January 1995 meeting, the Company's Board of Directors declared a
quarterly dividend on Common Stock of 41-1/2 cents per share continuing the
$1.66 annual dividend rate set in January 1994. The dividend is payable March
31, 1995, to shareholders of record on February 27, 1995.
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 1994 Annual Report to shareholders.
28
Item 7 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
------ ---------------------------------------------------------------
RESULTS OF OPERATIONS
---------------------
The information required by Item 7 is incorporated herein by reference
to the "Management's Discussion and Analysis of Consolidated Results of
Operations and Financial Condition" in the Financial Information section of
the Company's 1994 Annual Report to shareholders.
See "Nonutility Subsidiary" under Item 1 - Business for an update to the
discussion of the Company's nonutility subsidiary, including developments
relating to the subsidiary's aircraft leasing portfolio.
See "Rates" under Item 1 - Business for an update to the discussion of
the Company's base rate proceeding in the District of Columbia.
Item 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
------ -------------------------------------------
The consolidated financial statements, together with the report thereon
of Price Waterhouse LLP dated January 26, 1995, and supplementary data from
the Company's 1994 Annual Report to shareholders are incorporated herein by
reference. With the exception of the aforementioned information and the
information incorporated in Items 5, 6, 7, 8 and 9, the 1994 Annual Report to
shareholders is not deemed filed as part of this Form 10-K Annual Report.
Item 9 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
------ ---------------------------------------------------------------
FINANCIAL DISCLOSURE
--------------------
None.
29
Part III
--------
Item 10 DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
------- --------------------------------------------------
The information required by Item 10 with regard to Directors of the
registrant is incorporated herein by reference to the Company's Notice of
Annual Meeting of Shareholders and Proxy Statement dated March 17, 1995.
Information with regard to the executive officers of the registrant as
of March 7, 1995, is as follows:
Served in
such position
Name Position Age since
-------------------- -------------------------------- --- -------------
Edward F. Mitchell Chairman of the Board and Chief
Executive Officer 63 1992 (1)
John M. Derrick Jr. President and Chief Operating
Officer and Director 54 1992 (2)
H. Lowell Davis Vice Chairman and Chief Financial
Officer and Director 62 1983
Paul Dragoumis Executive Vice President 60 1989
William T. Torgerson Senior Vice President, General
Counsel and Secretary 50 1994 (3)
Dennis R. Wraase Senior Vice President -
Finance and Accounting 50 1992 (4)
Iraline G. Barnes Vice President - Corporate 47 1990 (5)
Relations
Earl K. Chism Vice President and Comptroller 59 1994 (6)
Kirk J. Emge Vice President - Regulatory
Law 45 1994 (7)
Susann D. Felton Vice President - Materials 46 1992 (8)
William R. Gee Jr. Vice President - System
Engineering 54 1991 (9)
Robert C. Grantley Vice President - Customers
and Community Relations 46 1989
Anthony J. Kamerick Vice President and Treasurer 47 1994 (10)
30
Served in
such position
Name Position Age since
-------------------- -------------------------------- --- -------------
Anthony S. Macerollo Vice President - Corporate
Administration and Services 53 1989
Eddie R. Mayberry Vice President - Market
Planning and Policy 47 1993 (11)
John D. McCallum Vice President - Corporate Tax 45 1992 (12)
James S. Potts Vice President - Environment 49 1993 (13)
William J. Sim Vice President - Power Supply
and Delivery 50 1991 (14)
Andrew W. Williams Vice President - Energy and
Market Policy and Development 45 1989
None of the above persons has a "family relationship" with any other officer
listed or with any director or nominee for director.
The term of office for each of the above persons is from April 27, 1994
to April 26, 1995.
(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. Torgerson was elected Senior Vice Present and General Counsel on
April 27, 1994. He was elected Secretary effective August 22, 1994.
Prior to 1994 he held the position of Vice President and General
Counsel.
(4) Mr. Wraase was elected to his present position on April 22, 1992. He
was elected Senior Vice President and Comptroller on July 27, 1989.
(5) Mrs. Barnes was elected to her present position effective April 1, 1990.
Prior to that time she served as Associate Judge of the Superior Court
of the District of Columbia for ten years.
(6) Mr. Chism was elected to his present position on April 27, 1994.
Prior to that time he held the position of Vice President and Treasurer
since July 1989.
31
(7) Mr. Emge was elected to his present position on April 27, 1994. Prior
to that time he held the position of Deputy General Counsel.
(8) Ms. Felton was elected to her present position on April 22, 1992. Prior
to that time she held the position of Manager, Materials.
(9) Mr. Gee was elected to his present position on April 24, 1991. Prior to
that time he held the position of Vice President - Generating
Engineering and Construction, since 1989.
(10) 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.
(11) Dr. Mayberry was elected to his present position on April 28, 1993.
Prior to that time he held the position of Manager, Market Planning and
Policy, since 1989.
(12) Mr. McCallum was elected to his present position on April 22, 1992.
Prior to that time he held the position of Assistant Comptroller.
(13) Mr. Potts was elected to his present position on April 28, 1993. Prior
to that time he held the position of Manager, Generating Strategic
Support since 1991. Prior to 1991 he held the position of Manager,
Production Performance.
(14) Mr. Sim was elected to his present position on April 24, 1991. Prior to
that time he was President of the American Energy division of the
Company's nonutility subsidiary, Potomac Capital Investment Corporation,
since 1988.
Item 11 EXECUTIVE COMPENSATION
------- ----------------------
The information required by Item 11 is incorporated herein by reference
to the Company's Notice of Annual Meeting of Shareholders and Proxy Statement
dated March 17, 1995.
Item 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
------- --------------------------------------------------------------
The information required by Item 12 is incorporated herein by reference
to the Company's Notice of Annual Meeting of Shareholders and Proxy Statement
dated March 17, 1995.
Item 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
------- ----------------------------------------------
None.
32
Part IV
-------
Item 14 EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON FORM 8-K
------- --------------------------------------------------------------
(a) Documents List
--------------
1. Financial Statements
The following documents are filed as part of this report as incorporated
herein by reference from the indicated pages of the Company's 1994 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, 1994,
1993 and 1992 15 28
Consolidated Balance Sheets -
December 31, 1994 and 1993 16-17 29-30
Consolidated Statements of
Cash Flows - for the years
ended December 31, 1994,
1993 and 1992 18 31
Notes to Consolidated Financial
Statements 19-30 32-69
Report of Independent Accountants 31 27
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).
33
All other schedules are omitted because they are not applicable, or the
required information is presented in the financial statements.
3. Exhibits required by Securities and Exchange Commission Regulation
S-K (summarized below).
Exhibit
No. Description of Exhibit Reference*
------- ---------------------- ----------
3-A Charter of the Company.............. Filed herewith.
3-B By-Laws of the Company.............. Filed herewith.
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.
July 15, 1942 and August 10,
1942................................ Exh. B-1 to Amendment No. 2,
8/24/42, and B-3 to Post-
Effective Amendment,
8/31/42, to Registration
Statement No. 2-5032.
August 1, 1942...................... Exh. B-4 to Form 8-A,
10/8/42.
October 15, 1942.................... Exh. A to Form 8-K, 12/7/42.
October 15, 1947.................... Exh. A to Form 8-K, 12/8/47.
January 1, 1948..................... Exh.7-B to Post-Effective
Amendment No. 2, 1/28/48,
to Registration Statement
No. 2-7349.
December 31, 1948................... Exh. A-2 to Form 10-K,
4/13/49.
34
Exhibit
No. Description of Exhibit Reference*
------- ---------------------- ----------
4 May 1, 1949......................... Exh. 7-B to Post-Effective
(cont.) Amendment No. 1,
5/10/49, to Registration
Statement No. 2-7948.
December 31, 1949................... Exh. (a)-1 to Form 8-K,
2/8/50.
May 1, 1950......................... Exh. 7-B to Amendment No. 2,
5/8/50, to Registration
Statement No. 2-8430.
February 15, 1951................... Exh. (a) to Form 8-K, 3/9/51.
March 1, 1952....................... Exh. 4-C to Post-Effective
Amendment No. 1, 3/12/52,
to Registration Statement
No. 2-9435.
February 16, 1953................... Exh. (a)-1 to Form 8-K,
3/5/53.
May 15, 1953........................ Exh. 4-C to Post-Effective
Amendment No. 1, 5/26/53,
to Registration Statement
No. 2-10246.
March 15, 1954 and March 15,
1955................................ Exh. 4-B to Registration
Statement No. 2-11627,
5/2/55.
May 16, 1955........................ Exh. A to Form 8-K, 7/6/55.
March 15, 1956...................... Exh. C to Form 10-K, 4/4/56.
June 1, 1956........................ Exh. A to Form 8-K, 7/2/56.
April 1, 1957....................... Exh. 4-B to Registration
Statement No. 2-13884,
2/5/58.
May 1, 1958......................... Exh. 2-B to Registration
Statement No. 2-14518,
11/10/58.
December 1, 1958.................... Exh. A to Form 8-K, 1/2/59.
May 1, 1959......................... Exh. 4-B to Amendment No. 1,
5/13/59, to Registration
Statement No. 2-15027.
November 16, 1959................... Exh. A to Form 8-K, 1/4/60.
May 2, 1960......................... Exh. 2-B to Registration
Statement No. 2-17286,
11/9/60.
December 1, 1960 and April 3,
1961................................ Exh. A-1 to Form 10-K,
4/24/61.
35
Exhibit
No. Description of Exhibit Reference*
------- ---------------------- ----------
4 May 1, 1962......................... Exh. 2-B to Registration
(cont.) Statement No. 2-21037,
1/25/63.
February 15, 1963................... Exh. A to Form 8-K, 3/4/63.
May 1, 1963......................... Exh. 4-B to Registration
Statement No. 2-21961,
12/19/63.
April 23, 1964...................... Exh. 2-B to Registration
Statement No. 2-22344,
4/24/64.
May 15, 1964........................ Exh. A to Form 8-K, 6/2/64.
May 3, 1965......................... Exh. 2-B to Registration
Statement No. 2-24655,
3/16/66.
April 1, 1966....................... Exh. A to Form 10-K, 4/21/66.
June 1, 1966........................ Exh. 1 to Form 10-K, 4/11/67.
April 28, 1967...................... Exh. 2-B to Post-Effective
Amendment No. 1 to
Registration Statement No.
2-26356, 5/3/67.
May 1, 1967......................... Exh. A to Form 8-K, 6/1/67.
July 3, 1967........................ Exh. 2-B to Registration
Statement No. 2-28080,
1/25/68.
February 15, 1968................... Exh. II-I to Form 8-K, 3/7/68.
May 1, 1968......................... Exh. 2-B to Registration
Statement No. 2-31896,
2/28/69.
March 15, 1969...................... Exh. A-2 to Form 8-K, 4/8/69.
June 16, 1969....................... Exh. 2-B to Registration
Statement No. 2-36094,
1/27/70.
February 15, 1970................... Exh. A-2 to Form 8-K, 3/9/70.
May 15, 1970........................ Exh. 2-B to Registration
Statement No. 2-38038,
7/27/70.
August 15, 1970..................... Exh. 2-D to Registration
Statement No. 2-38038,
7/27/70.
September 1, 1971................... Exh. 2-C to Registration
Statement No. 2-45591, 9/1/72.
September 15, 1972.................. Exh. 2-E to Registration
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.
36
Exhibit
No. Description of Exhibit Reference*
------- ---------------------- ----------
4 August 15, 1974..................... Exhs. 2-G and 2-H to
(cont.) Amendment No. 1 to
Registration Statement
No. 2-51698, 8/14/74.
June 15, 1977....................... Exh. 4-A to Form 10-K,
3/19/81.
July 1, 1979........................ Exh. 4-B to Form 10-K,
3/19/81.
June 16, 1981....................... Exh. 4-A to Form 10-K,
3/19/82.
June 17, 1981....................... Exh. 2 to Amendment No. 1,
6/18/81, to Form 8-A.
December 1, 1981.................... Exh. 4-C to Form 10-K,
3/19/82.
August 1, 1982...................... Exh. 4-C to Amendment No. 1
to Registration Statement
No. 2-78731, 8/17/82.
October 1, 1982..................... Exh. 4 to Form 8-K, 11/8/82.
April 15, 1983...................... Exh. 4 to Form 10-K, 3/23/84.
November 1, 1985.................... Exh. 2-B to Form 8-A, 11/1/85.
March 1, 1986....................... Exh. 4 to Form 10-K, 3/28/86.
November 1, 1986.................... Exh. 2-B to Form 8-A, 11/5/86.
March 1, 1987....................... Exh. 2-B to Form 8-A, 3/2/87.
September 16, 1987.................. Exh. 4-B to Registration
Statement No. 33-18229,
10/30/87.
May 1, 1989......................... Exh. 4-C to Registration
Statement No. 33-29382,
6/16/89.
August 1, 1989...................... Exh. 4 to Form 10-K, 3/23/90.
April 5, 1990....................... Exh. 4 to Form 10-K, 3/29/91.
May 21, 1991........................ Exh. 4 to Form 10-K, 3/27/92.
May 7, 1992......................... Exh. 4 to Form 10-K, 3/26/93.
September 1, 1992................... Exh. 4 to Form 10-K, 3/26/93.
November 1, 1992.................... Exh. 4 to Form 10-K, 3/26/93.
March 1, 1993....................... Exh. 4 to Form 10-K, 3/26/93.
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.
37
Exhibit
No. Description of Exhibit Reference*
------- ---------------------- ----------
4 August 20, 1993..................... Exh. 4.4 to Registration
(cont.) 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.
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.
4C Indenture, dated as of August 15,
1992, between the Company and the
Bank of New York, Trustee, for the
Company's $115,000,000 issue of 5%
Convertible Debentures due 2002..... Exh. 4-C to Form 10-K,
3/26/93.
10 Agreement, effective July 23, 1993,
between the Company and the
International Brotherhood of
Electrical Workers (Local Union
#1900).............................. Exh. 10 to Form 10-Q, 7/30/93.
38
Exhibit
No. Description of Exhibit Reference*
------- ---------------------- ----------
**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.
*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.
39
POTOMAC ELECTRIC POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992
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, 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
Year Ended December 31, 1993
Allowance for uncollectible accounts -
customer and other accounts receivable
Utility operations $ 2,709 $ 6,451 $ 658 $ (6,770) $ 3,048
Nonutility subsidiary $ - $ - $ - $ - $ -
Year Ended December 31, 1992
Allowance for uncollectible accounts -
customer and other accounts receivable
Utility operations $ 3,115 $ 5,753 $ 836 $ (6,995) $ 2,709
Nonutility subsidiary $ - $ - $ - $ - $ -
<FN>
<F1>Collection of accounts previously written off.
<F2>Uncollectible accounts written off.
</FN>
40
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 24th day of March, 1995.
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
/s/ H. L. Davis
--------------------------- Vice Chairman and Chief
(H. Lowell Davis) Financial Officer and Director
(iii) Principal Accounting Officer
/s/ D. R. Wraase
--------------------------- Senior Vice President
(Dennis R. Wraase) Finance and Accounting
March 24, 1995
41
Signature Title Date
--------- ----- ----
(iv) Directors:
/s/ Roger R. Blunt
------------------------- Director
(Roger R. Blunt Sr.)
/s/ A. J. Clark
------------------------- Director
(A. James Clark)
/s/ Richard E. Marriott
------------------------- Director
(Richard E. Marriott)
/s/ David O. Maxwell
------------------------ Director
(David O. Maxwell)
/s/ Floretta D. McKenzie
------------------------- Director
(Floretta D. McKenzie)
/s/ Ann D. McLaughlin
------------------------- Director
(Ann D. McLaughlin)
/s/ Peter F. O'Malley
------------------------- Director
(Peter F. O'Malley)
/s/ Louis A. Simpson
------------------------- Director
(Louis A. Simpson)
/s/ W. Reid Thompson
------------------------- Director
(W. Reid Thompson)
March 24, 1995
42
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 1994, 1993 and 1992:
1994 1993 1992
------------ ------------ ------------
Average shares outstanding for
computation of primary earnings
per common share 118,005,847 115,639,668 112,389,698
============ ============ ============
Average shares outstanding for
fully diluted computation:
Average shares outstanding 118,005,847 115,639,668 112,389,698
Additional shares resulting from:
Conversion of Serial Preferred
Stock, $2.44 Convertible Series
of 1966 (the "Convertible
Preferred Stock") 48,110 51,967 57,542
Conversion of 7% Convertible
Debentures 2,531,244 2,546,858 2,603,912
Conversion of 5% Convertible
Debentures 3,392,500 3,392,500 1,130,833
------------ ------------ ------------
Average shares outstanding for
computation of fully diluted
earnings per common share 123,977,701 121,630,993 116,181,985
============ ============ ============
Earnings applicable to common
stock, before cumulative effect
of accounting change $210,725,000 $225,324,000 $186,368,000
Cumulative effect of accounting
change, net of income taxes - - 16,022,000
------------ ------------ ------------
Earnings applicable to common stock,
as reported 210,725,000 225,324,000 202,390,000
Add: Dividends paid or accrued on
Convertible Preferred Stock 20,000 22,000 24,000
Interest paid or accrued on
Convertible Debentures,
net of related taxes 6,537,000 6,548,000 4,303,000
------------ ------------ ------------
Earnings applicable to common stock,
including cumulative effect of
accounting change and assuming
conversion of convertible securities $217,282,000 $231,894,000 $206,717,000
============ ============ ============
Primary earnings per common share
Before cumulative effect $1.79 $1.95 $1.66
Cumulative effect - - 0.14
----- ----- -----
Total $1.79 $1.95 $1.80
===== ===== =====
Fully diluted earnings per common share
Before cumulative effect $1.75 $1.91 $1.64
Cumulative effect - - 0.14
----- ----- -----
Total $1.75 $1.91 $1.78
===== ===== =====
<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 because it results in dilution of less than 3%.
</FN>
43
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 1994 through 1990 on the basis of parent company operations only, are
as follows.
For The Year Ended December 31,
-----------------------------------------------------
1994 1993 1992 1991 1990
--------- --------- --------- --------- ---------
(Thousands of Dollars)
Net income before cumulative effect
of accounting change $208,074 $216,478 $172,599 $186,813 $165,199
Taxes based on income 116,648 107,223 76,965 80,988 70,962
-------- -------- -------- -------- --------
Income before taxes and cumulative effect
of accounting change 324,722 323,701 249,564 267,801 236,161
-------- -------- -------- -------- --------
Fixed charges:
Interest charges 139,210 141,393 138,097 138,512 127,386
Interest factor in rentals 6,300 5,859 6,140 5,690 4,237
-------- -------- -------- -------- --------
Total fixed charges 145,510 147,252 144,237 144,202 131,623
-------- -------- -------- -------- --------
Income before income taxes, cumulative
effect of accounting change and
fixed charges $470,232 $470,953 $393,801 $412,003 $367,784
======== ======== ======== ======== ========
Coverage of fixed charges 3.23 3.20 2.73 2.86 2.79
==== ==== ==== ==== ====
Preferred dividend requirements $16,437 $16,255 $14,392 $12,298 $10,598
-------- -------- -------- -------- --------
Ratio of pre-tax income to net income 1.56 1.50 1.45 1.43 1.43
---- ---- ---- ---- ----
Preferred dividend factor $25,642 $24,383 $20,868 $17,586 $15,155
-------- -------- -------- -------- --------
Total fixed charges and preferred dividends $171,152 $171,635 $165,105 $161,788 $146,778
======== ======== ======== ======== ========
Coverage of combined fixed charges
and preferred dividends 2.75 2.74 2.39 2.55 2.51
==== ==== ==== ==== ====
44
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 1994 through 1990 on a fully consolidated basis are as follows.
For The Year Ended December 31,
-----------------------------------------------------
1994 1993 1992 1991 1990
--------- --------- --------- --------- ---------
(Thousands of Dollars)
Net income before cumulative effect
of accounting change $227,162 $241,579 $200,760 $210,164 $170,234
Taxes based on income 93,953 62,145 79,481 80,737 63,360
-------- -------- -------- -------- --------
Income before taxes and cumulative effect
of accounting change 321,115 303,724 280,241 290,901 233,594
-------- -------- -------- -------- --------
Fixed charges:
Interest charges 224,514 221,312 226,453 225,323 199,469
Interest factor in rentals 9,938 9,257 6,599 6,080 4,559
-------- -------- -------- -------- --------
Total fixed charges 234,452 230,569 233,052 231,403 204,028
-------- -------- -------- -------- --------
Nonutility subsidiary capitalized interest (521) (2,059) (2,200) (6,542) -
-------- -------- -------- -------- --------
Income before income taxes, cumulative
effect of accounting change and
fixed charges $555,046 $532,234 $511,093 $515,762 $437,622
======== ======== ======== ======== ========
Coverage of fixed charges 2.37 2.31 2.19 2.23 2.14
==== ==== ==== ==== ====
Preferred dividend requirements $16,437 $16,255 $14,392 $12,298 $10,598
-------- -------- -------- -------- --------
Ratio of pre-tax income to net income 1.41 1.26 1.40 1.38 1.37
---- ---- ---- ---- ----
Preferred dividend factor $23,176 $20,481 $20,149 $16,971 $14,519
-------- -------- -------- -------- --------
Total fixed charges and preferred dividends $257,628 $251,050 $253,201 $248,374 $218,547
======== ======== ======== ======== ========
Coverage of combined fixed charges
and preferred dividends 2.15 2.12 2.02 2.08 2.00
==== ==== ==== ==== ====
45
Exhibit 21 Subsidiaries of the Registrant
---------- ------------------------------
The Company has two wholly owned nonutility investment subsidiary
companies, Potomac Capital Investment Corporation and PEPCO Enterprises, Inc.,
(PEI) both of which were incorporated in Delaware in 1983. Subsidiaries of
PEI and Columbia Gas System, Inc. have formed the Cove Point joint venture
partnership discussed in Part II, Item 7, "Management's Discussion and
Analysis of Financial Condition and Results of Operations."
46
Exhibit 23 Consent of Independent Accountants
---------- ----------------------------------
We hereby consent to the incorporation by reference in the Registration
Statements on Form 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 33-50377) of
Potomac Electric Power Company of our report dated January 26, 1995 appearing
in the Annual Report to shareholders which is also incorporated by reference
in this Annual Report on Form 10-K. We also consent to the incorporation by
reference of our report on the Consolidated Financial Statement Schedule,
which appears under Item 14(a) of this Form 10-K.
/s/ Price Waterhouse LLP
Washington, D.C.
March 24, 1995
47
Report of Independent Accountants on Consolidated
-------------------------------------------------
Financial Statement Schedule
----------------------------
January 26, 1995
To the Board of Directors of
Potomac Electric Power Company
Our audits of the consolidated financial statements referred to in our report
dated January 26, 1995 appearing in the 1994 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.
48