UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
Form 8-K
CURRENT REPORT
PURSUANT TO SECTION 13 or 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Date of Report (Date of earliest event reported) January 29, 1999
POTOMAC ELECTRIC POWER COMPANY
(Exact name of registrant as specified in its charter)
District of Columbia and Virginia 1-1072 53-0127880
(State or other jurisdiction of (Commission (I.R.S. Employer
incorporation) File Number) Identification No.)
1900 Pennsylvania Avenue, N. W., Washington, D. C. 20068
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (202) 872-2000
(Former Name or Former Address, if Changed Since Last Report)
Pepco
Form 8-K
Item 7. Financial Statements, Pro-Forma Financial Information and
Exhibits.
Exhibits
Exhibit No. Description of Exhibit Reference
12 Computation of ratios...............Filed herewith.
23 Consent of Independent
Accountants.........................Filed herewith.
27 Financial Data Schedule.............Filed herewith.
99 The 1998 consolidated financial
statements of the Company and
Subsidiary, together with the
report thereon of
PricewaterhouseCoopers
dated January 25, 1999; and
Management's Discussion and
Analysis of Consolidated Results
of Operations and Financial
Condition as well as selected
financial data......................Filed herewith.
<PAGE>
Pepco
Form 8-K
Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by
the undersigned hereunto duly authorized.
Potomac Electric Power Company
(Registrant)
By ___________________________
Dennis R. Wraase
Senior Vice President and
Chief Financial Offier
January 29, 1999
DATE
Item 7
Exhibit 99
Financial Information
- ---------------------
Potomac Electric Power Company and Subsidiaries
Contents
- --------
Management's Discussion and Analysis of
Consolidated Results of Operations and
Financial Condition...................................... 2
Report of Independent Accountants.......................... 38
Consolidated Statements of Earnings........................ 39
Consolidated Balance Sheets................................ 40
Consolidated Statements of Cash Flows...................... 42
Consolidated Statements of Comprehensive Income............ 43
Notes to Consolidated Financial Statements................. 44
Selected Consolidated Financial Data....................... 90
1
Management's Discussion and Analysis of Consolidated
Results of Operations and Financial Condition
- ----------------------------------------------------
GENERAL
- -------
As an investor-owned electric utility, the Company is capital
intensive, with a gross investment in property and plant of
approximately $3 for each $1 of annual total revenue. The costs
associated with property and plant investment amounted to 46% of
the Company's total revenue in 1998. Fuel and purchased energy,
capacity purchase payments and other operating expenses were 54%
of total revenue.
Potomac Capital Investment Corporation (PCI), a wholly owned
subsidiary of the Company, conducts nonutility investment
programs and businesses with the objective of supplementing
current utility earnings and building long-term shareholder
value. Potomac Electric Power Company Trust I (Trust), the
Company's wholly owned business trust and subsidiary, was
established in April 1998 for the purposes of issuing Trust
Securities representing undivided beneficial interests in the
assets of the Trust, and investing the gross proceeds from the
sale of the Trust Securities in Junior Subordinated Debentures of
the Company.
The Company has two segments, consisting of its utility and
nonutility operations. The utility segment derives its revenue
from the generation, transmission, distribution and sale of
electric energy, while the nonutility segment, which primarily
consists of the operations of PCI, derives its revenue from
investment programs, energy-related businesses, and
telecommunication services. See the discussion included in Notes
(1) and (15) of the Notes to Consolidated Financial Statements,
Organization and Summary of Significant Accounting Policies - New
Accounting Standards and Segment Information, respectively, for
additional information.
The information set forth below discusses the results of
operations, capital resources and liquidity during the period
1996 through 1998 for the Company and its subsidiaries.
2
The Company's earnings for common stock during 1998 totaled
$208.3 million, as compared to $165.3 million in 1997. As set
forth below, utility basic earnings per common share from
operations increased from $1.53 in 1997 to $1.63 in 1998,
excluding the December 1997 write-off of 28 cents per share
related to the cancellation of the proposed merger with Baltimore
Gas and Electric Company (BG&E). Consolidated basic earnings per
common share increased from $1.39 in 1997 to $1.76 in 1998.
- -----------------------------------------------------------------
1998 1997 1996
- -----------------------------------------------------------------
Utility Operations $1.63 $1.53 $1.72
Merger Costs - (.28) -
Nonutility Subsidiary .13 .14 .14
----- ----- -----
Consolidated $1.76 $1.39 $1.86
===== ===== =====
- -----------------------------------------------------------------
The average number of common shares outstanding at December 31,
1998, was relatively unchanged from December 31, 1997.
FORWARD LOOKING STATEMENTS
- --------------------------
This Management's Discussion and Analysis of Consolidated Results
of Operations and Financial Condition contains forward looking
statements, as defined by the Private Securities Litigation Act
of 1995, with regard to matters that could have an impact on the
future operations, financial results or financial condition of
the Company. These statements are based on the current
expectations, estimates or projections of management and are not
guarantees of future performance. Actual results may differ
materially from those anticipated by the forward looking
statements, depending on the occurrence or nonoccurrence of
future events or conditions that are difficult to predict and
generally are beyond the control of the Company. All such
forward looking statements relating to the following matters are
qualified by the cautionary statements below and contained
elsewhere herein.
Growth in Demand, Sales and Capacity to Fulfill Demand
------------------------------------------------------
The actual growth in demand for and sales of electricity
within the Company's service territory may vary from the
statements made concerning the anticipated growth in demand
and sales, depending upon a number of factors, including
weather conditions, the competitive environment, general
economic conditions and the demographics of the Company's
service territory. Future construction expenditures
3
(including the need to construct additional generation
capacity) may vary from the projections, depending on the
accuracy of management's expectations regarding growth in
demand for and sales of electricity, regulatory developments
including potential changes in environmental regulations,
and the evolution of the competitive marketplace for
electricity.
Competition
-----------
Increased competition will have an impact on future results
of operations, which may be adverse, and will depend, among
other factors, upon governmental policies and regulatory
actions, including those of the Federal Energy Regulatory
Commission (FERC) and the Maryland and District of Columbia
public service commissions, future economic conditions and
the influence exerted by emerging market forces over the
structure of the electric industry.
Year 2000 Readiness Disclosure
------------------------------
The Company has implemented a 4-pronged approach to address
compliance with the Year 2000 processing requirements of its
computer systems. The phases being addressed are:
Corporate Applications Readiness, which includes all large
core business systems; Embedded Systems, which include all
operating and control systems; End-User Computing Systems,
which are all systems which are not considered core business
systems but contain date calculations; and Business
Partners' Systems and Vendor Supply-Chain Verification,
which is intended to monitor suppliers' compliance with Year
2000 processing. A database has been developed to identify
and track the progress of work on each phase. The
preliminary target date for completion of these phases is
mid-1999. The cost or consequences of a material incomplete
or untimely resolution of the Year 2000 problem could
adversely affect future operations, financial results or
financial condition of the Company.
4
UTILITY
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RESULTS OF OPERATIONS
- ---------------------
Total Revenue
- -------------
The changes in total revenue are shown in the following table.
- -----------------------------------------------------------------
Increase (Decrease)
from Prior Year
1998 1997 1996
- -----------------------------------------------------------------
(Millions of Dollars)
Change in kilowatt-hour sales $ 51.8 $ (8.6) $(11.5)
Change in base rate revenue 24.0 (7.2) 27.0
Change in fuel adjustment clause
billings to cover cost of
fuel and interchange and
capacity purchase payments (2.9) (9.2) (4.5)
Change in other revenue 2.4 1.0 1.4
------- ------- ------
Change in operating revenue 75.3 (24.0) 12.4
------- ------- ------
Change in interchange deliveries 125.1 (122.8) 121.8
------- ------- ------
Change in total revenue $ 200.4 $(146.8) $134.2
======= ======= ======
- -----------------------------------------------------------------
The increase in 1998 base rate revenue compared to 1997
primarily reflects the effects of increases in Maryland base
rates of $24 million and $19 million (effective November 1997 and
December 1998, respectively) and an increase in the District of
Columbia Demand Side Management (DSM) surcharge tariff of $9
million (effective September 1998); partially offset by
reductions of $3.2 million and $17 million in the Maryland DSM
surcharge tariff (effective September 1998 and June 1997,
respectively) and a $2.5 million reduction (effective January
1998) in rates for wholesale service to the Southern Maryland
Electric Cooperative (SMECO).
The decrease in 1997 base rate revenue compared to 1996
primarily reflects the June 1997 decrease in the Maryland DSM
surcharge (which includes a $7.3 million reduction in the
conservation incentive provision of the tariff). The increase in
base rate revenue in 1996 as compared to 1995 reflects the
effects of a District of Columbia base rate increase of $27.9
5
million (effective July 1995) and an increase of $17.7 million
(effective August 1996) associated with the Company's Maryland
DSM surcharge.
Fluctuations in interchange delivery transactions throughout
1998 resulted in three revisions to the Company's Maryland fuel
rate. The Company increased its Maryland fuel rate by 10.5%
effective March 1, 1998. Subsequently, on August 14, 1998, the
Company filed for a 5.3% decrease in the Maryland fuel rate,
which became effective beginning the billing month of September
1998. Also, on October 19, 1998, the Company filed for an
additional 6.3% decrease in the Maryland fuel rate, which became
effective beginning the billing month of November 1998. In
September 1997, the Company had reduced its Maryland fuel rate by
9.5%; included in this reduction was an adjustment for a deferred
fuel amortization credit to refund over a twelve month period
approximately $20.7 million of previously overrecovered fuel
costs incurred through June 30, 1997.
The increase in 1998 in revenue from interchange deliveries
reflects changes in prices and levels of energy delivered to the
Pennsylvania-New Jersey-Maryland Interconnection LLC (PJM) and
changes in prices and levels of bilateral energy sales under the
Company's wholesale power sales tariff. Interchange transactions
are subject to cost-based ratemaking regulations based on
formulas prescribed by the FERC.
The decrease in 1997 in revenue from interchange deliveries
reflects the termination of purchase-for-resale agreements under
the Company's wholesale power sales tariff, whereby the Company
purchased energy from one party (recording a corresponding
expense within Purchased energy) for the purpose of selling that
energy to a third party (and recording corresponding revenue
within Interchange deliveries). In early 1997, pursuant to
FERC's Order No. 888, the Company implemented an open access
transmission tariff (OATT) for wheeling transactions and
terminated purchase-for-resale agreements. In April 1997, PJM
implemented an OATT on behalf of its transmission owners,
replacing the Company's OATT.
The increase in 1996 in revenue from interchange deliveries
reflects the growth in the number of companies involved in power
sales tariff interchange transactions, and changes in levels and
prices of energy delivered to PJM.
Interchange deliveries also include revenue from sales of
short-term generating capacity. Revenues from capacity
transactions totaled approximately $4.4 million, $2.9 million and
$.6 million in 1998, 1997 and 1996, respectively. Presently, the
Company has agreements for installed capacity sales through May
31, 1999 totaling 232 megawatts. The benefits derived from
interchange deliveries, the allocated amounts of capacity sales
6
in the District of Columbia (approximately 40%) and revenue under
the OATT are passed through to the Company's customers through
fuel adjustment clauses.
Kilowatt-hour Sales
- -------------------
- -----------------------------------------------------------------
1998 1997
vs. vs.
1998 1997 1996 1997 1996
- -----------------------------------------------------------------
(Millions of Kilowatt-hours)
By Customer Type
Residential 6,745 6,552 6,869 2.9% (4.6)%
Commercial 12,049 11,811 11,712 2.0 .8
U.S. Government 3,968 3,934 3,902 .9 .8
D.C. Government 858 850 847 .9 .4
Wholesale (primarily
SMECO) 2,678 2,561 2,570 4.6 (.4)
------ ------ ------
Total energy sales 26,298 25,708 25,900 2.3 (.7)
====== ====== ======
Interchange
Energy deliveries 2,246 822 7,063 100.0+ (88.4)
====== ====== ======
By Geographic Area
Maryland, including
wholesale 16,017 15,601 15,763 2.7 (1.0)
District of Columbia 10,281 10,107 10,137 1.7 (.3)
------ ------ ------
Total energy sales 26,298 25,708 25,900 2.3 (.7)
====== ====== ======
- -----------------------------------------------------------------
Kilowatt-hour sales increased in 1998 resulting from an
increase in cooling degree hours of 15% from 1997. Cooling
degree hours however were 7.5% less than the 20-year average. In
addition, a .8% increase in customers produced a favorable impact
on kilowatt-hour sales. Kilowatt-hour sales decreased .7% in
1997 resulting from decreases in cooling degree hours of 5% and
21% from the 1996 and 20-year average, respectively, partially
offset by a .8% increase in customers. Assuming future weather
conditions approximate historical averages, the Company expects
its compound annual growth in retail kilowatt-hour sales to be
approximately 2% over the next decade.
On June 26, 1998, the Company established an all-time summer
peak demand of 5,807 megawatts. This compares with the 1997
summer peak demand of 5,689 megawatts, and the prior all-time
summer peak demand of 5,769 megawatts, which occurred in July
7
1991. The Company's present generation capability, excluding
short-term capacity transactions, is 6,806 megawatts. At the
time of the 1998 summer peak demand, the Company's energy use
management (EUM) programs had the capability of reducing system
demand by an additional 242 megawatts. Based on average weather
conditions, the Company estimates that its retail peak demand
will grow at a compound annual rate of approximately 2%,
reflecting anticipated service area growth trends. The 1997-1998
winter season peak demand of 4,076 megawatts was 18.6% below the
all-time winter peak demand of 5,010 megawatts which was
established in January 1994.
Operating Expenses
- ------------------
Fuel, Purchased Energy and Capacity Purchase Payments
- -----------------------------------------------------
- -----------------------------------------------------------------
1998 1997 1996
- -----------------------------------------------------------------
(Millions of Dollars)
Fuel expense $380.2 $319.6 $327.8
------ ------ ------
Purchased energy
PJM 146.3 86.6 114.6
Other 123.5 114.0 221.4
------ ------ ------
Total purchased energy 269.8 200.6 336.0
------ ------ ------
Fuel and purchased energy $650.0 $520.2 $663.8
====== ====== ======
Capacity purchase payments $155.7 $150.9 $125.8
====== ====== ======
- -----------------------------------------------------------------
Net System Generation and Purchased Energy were as follows.
- -----------------------------------------------------------------
1998 1997 1996
- -----------------------------------------------------------------
(Millions of Kilowatt-hours)
Net system generation 21,715 18,322 18,041
====== ====== ======
Purchased energy 8,204 9,371 16,157
====== ====== ======
- -----------------------------------------------------------------
The 1998 increase in fuel expense compared to 1997 reflects
an increase of 18.5% in net generation, partially offset by a
decrease in the system average unit fuel cost. Although net
8
generation increased 1.6% in 1997 compared to 1996, fuel expense
decreased due to the timing of fuel billed to customers through
the Company's fuel rates.
The Company's unit costs of fuel burned and the percentages
of system fuel requirements obtained from coal, oil and natural
gas are shown in the following table.
- -----------------------------------------------------------------
Percent of Unit Cost
Fuel Burned of Fuel Burned
------------------- --------------------------------
System
Coal Oil Gas Coal Oil Gas Average
- -----------------------------------------------------------------
(Per Million Btu)
1998 84.5 12.7 2.8 $1.55 $2.71 $2.63 $1.72
1997 89.1 6.4 4.5 1.65 3.80 2.87 1.84
1996 89.7 6.9 3.4 1.62 3.55 2.92 1.80
- -----------------------------------------------------------------
The 1998 system average unit fuel cost decreased by 6.5% due
to decreases in the costs of coal, residual oil and gas. The
increase of approximately 2% in the 1997 system average unit fuel
cost compared with the 1996 system average resulted primarily
from an increased unit cost of coal. The increase in the percent
of oil burned in 1998 reflects a decline in the price of oil.
The decrease in the percent of oil burned in 1997 reflects the
increase in the price of oil and the increased usage of lower-
cost gas. The Company's major cycling and certain peaking units
can burn either natural gas or oil, which provides protection
against possible supply disruptions, and adds flexibility in
selecting the most cost-effective fuel mix. The use of coal, oil
and natural gas also depends upon the availability of generating
units, energy and demand requirements of interconnected
utilities, regulatory requirements, weather conditions, and fuel
supply constraints, if any. The Company seeks to maintain a
minimum unit cost of energy through the economic dispatch of its
generating facilities, active participation in the bulk power
market and purchases of generating capacity.
The Company's generating and transmission facilities are
interconnected with those of other transmission owners in the PJM
power pool and other utilities, providing economic energy and
reliability benefits by facilitating the Company's participation
in the federally-regulated wholesale energy market. This market
has enabled the Company to purchase energy at costs lower than
those required to self-generate, and to sell energy at favorable
prices to other market participants.
9
Energy transactions within the PJM power pool are priced at
rates which are approved by the FERC and are based on each power
pool participant's marginal cost. In April 1997, PJM implemented
a competitive "bid-based" energy marketplace, where companies
offered energy at prices not exceeding their cost of producing
the energy, and transactions occurred at the market's marginal
clearing price. In November 1997, the FERC conditionally
approved a PJM restructuring plan which, among other things,
established an independent system operator (ISO) having
responsibility for system operations and regional transmission
planning. The Commission authorized the independent body that
operates the ISO to also operate the PJM power exchange. On
April 1, 1998, the unconstrained market clearing pricing system
for purchased energy was replaced by a "locational marginal
pricing" system designed to economically control transmission
system congestion. Because of the Company's generation
availability and peak load characteristics, the Company generally
is able to sell into the PJM market during high price peak load
periods and buy from the market during low price periods. (Also
see the Restructuring of the Bulk Power Market discussion below).
In addition to interchange within PJM, the Company is
actively participating in the bilateral energy sales marketplace.
The Company's FERC-approved wholesale power sales tariff allows
both sales from Company-owned generation and sales of energy
purchased by the Company from other market participants.
Numerous utilities and marketers have executed service agreements
allowing them to arrange purchases under this tariff and the
Company has executed service agreements allowing it to purchase
energy under other market participants' power sales tariffs.
The Company continues to purchase energy from FirstEnergy
Corp. (FirstEnergy, formerly Ohio Edison) under the Company's
1987 long-term capacity purchase agreement with FirstEnergy and
Allegheny Energy, Inc. (AEI). Pursuant to this agreement, the
Company is purchasing 450 megawatts of capacity and associated
energy through the year 2005. The Company purchases energy from
the Panda-Brandywine, L.P. (Panda) facility pursuant to a 25-year
power purchase agreement for 230 megawatts of capacity supplied
by a gas-fueled combined-cycle cogenerator; capacity payments
under this agreement commenced in January 1997. The Company is
also purchasing 50 megawatts of capacity and related energy from
the Northeast Maryland Waste Disposal Authority under a short
term avoided cost-based purchase agreement. The capacity expense
under these agreements, including an allocation of a portion of
FirstEnergy's fixed operating and maintenance costs, was $149.8
million for 1998, $145.2 million for 1997 and $120 million for
1996. Commitments under these agreements are estimated at $203
million for 1999, $204 million for 2000, $209 million for 2001,
and $210 million for 2002 and 2003.
10
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 capacity payment to SMECO is approximately $5.5 million per
year.
The Company's customers are charged separate rates designed
to recover the actual cost of fuel used to generate electricity,
including the net cost of purchased energy less interchange
deliveries. Differences between actual costs of fuel and energy,
and fuel revenues collected are deferred on the Consolidated
Balance Sheets. The Company earns no return on costs eligible
for recovery within these fuel rates. The District of Columbia
fuel rate includes a provision for the current recovery of
purchased capacity costs as well as a provision for the credit
for capacity sales. In Maryland, purchased capacity costs are
recovered in base rates.
As electricity becomes more actively traded as a commodity,
the bulk power market is developing methods for traders to hedge
against price volatility. Both the New York Mercantile Exchange
(NYMEX) and the Chicago Board of Trade (CBOT) have introduced
futures contracts for electricity for various delivery points
across the country. NYMEX's recently introduced "Into Cinergy"
contract has outpaced the others in liquidity. NYMEX is planning
to refile its PJM futures contract with the Commodity Futures
Trading Commission to reflect a Western Hub delivery point and
the CBOT has announced its intention to introduce a PJM contract.
In addition, some market participants are using customized
instruments to hedge prices for both capacity and energy. Such
instruments include forward contracts to fix prices, options to
set ceilings or floors on prices and swaps to exchange variable
prices for a fixed price. The mid-Atlantic energy market is
expected to feature a secondary market in transmission congestion
hedging. The Company's current activity in these markets is
insignificant, and all activity is passed on to customers through
the Company's fuel adjustment clause mechanism. However, in the
future, the Company expects to increase its participation in the
hedging markets as part of its strategy to control costs and
avoid unreasonable risks. In some instances, as part of its
overall bulk power marketing activity, the Company may offer to
sell hedging instruments.
11
Other Operation and Maintenance Expenses
- ----------------------------------------
Other operation and maintenance expenses totaled $329.2 million
for 1998. These expenses increased by $13.6 million (4.3%) in
1998, principally due to non-recurring charges of $8.2 million
for operating costs associated with the Company's Targeted
Severance Plan (the Plan). The Plan offers severance pay and
subsidized health and dental benefits, at amounts dependent upon
years of service, to employees who lose employment due to
corporate restructuring and/or job consolidations. Under the
Plan, no changes were made to eligible pensions or benefits under
the retirement program. During 1998, 177 employees participated
in the Plan. Increases in other operation and maintenance
expenses in 1998 were also due to $5.7 million in expenditures
associated with the Company's efforts to accommodate the Year
2000. The Company's approach to testing and remediating Year
2000-related issues, and developing business continuation and
contingency plans is discussed in detail below. Other operation
and maintenance expenses increased by $.8 million (.2%) in 1997,
principally due to increases in electric plant maintenance
expense, partially offset by reduced labor and benefits costs.
The Company's budget and cost control disciplines have resulted
in a 17% decline in the number of Company employees since 1995.
Year 2000 Readiness Disclosure
------------------------------
The Company has implemented a 4-pronged approach to accommodate
the Year 2000. All phases are coordinated through a Corporate
Year 2000 Task Force comprised of representatives from each
Business Unit. The phases being addressed are as follows:
1. Corporate Applications (Information Technology)
Readiness: Corporate Applications are large core
systems such as Customer Information, Human Resources
and General Ledger, for which the Company's Computer
Services Group (CSG) has responsibility. Year 2000
modifications to these systems are being
programmed and tested by CSG.
2. Embedded Systems (Non-Information Technology
Processes): These systems include items such as
meters, power plant operating and control systems,
telecommunications systems and facilities-based
equipment (e.g. elevators). These products are being
evaluated and modified as required by the appropriate
internal end-user, in coordination with the systems'
vendors.
12
3. End-User Computing Systems (Non-Core [Departmental]
Business Systems): Corporate areas other than CSG
have developed systems, databases, spreadsheets, etc.
that contain date calculations. These products are
being evaluated and modified as required by the
appropriate end-user.
4. Business Partners' Systems and Vendor Supply-Chain
Verification: The Company is seeking to obtain Year
2000 assurances from numerous vendors who provide
products and services to the Company. This effort is
being jointly undertaken by the Company's Materials
Group and appropriate end-users.
The Task Force meets regularly to monitor the status of the
efforts of the Company's assigned staff, contractors, and vendors
in testing and remediating Year 2000 related issues. Task Force
Subcommittees are addressing additional Year 2000 related issues
including, but not limited to, customer communications, testing
procedures and business continuation and other contingency
planning.
As of December 31, 1998, approximately 99% of the changes
required to the 110 corporate IT systems have been made and
regression tested. The Company's mainframe computer system has
been partitioned so that a portion is isolated from the
production environment and used for Year 2000 full-cycle, or
"time machine," testing. This testing encompasses not only the
date change from 12/31/1999 to 1/1/2000, but also many of the
other potentially troublesome dates, including 2/29/2000. A total
of 80% of corporate IT systems have been tested in the time
machine. Among the major applications successfully tested are
the Customer Information, Accounts Payable, Materials Management,
and Construction Management systems. End-user computing testing
in the time machine will begin in January 1999. A parallel LAN
(local area network) Year 2000 testing facility has been
established. All standard LAN office automation and operating
systems applications supported by Computer Services have been
tested successfully. The first series of LAN business
applications supported by Computer Services is currently in
testing. The LAN test lab will be available for business units
to test their applications beginning in January 1999.
Assessments of critical operational systems containing
embedded systems were completed in October 1998 by teams of
vendors, contractors and Company personnel. Year 2000 upgrades
to the distributed control systems of Potomac River Units 1, 2,
3, 4 and 5 and Chalk Point Units 2 and 4 have been completed and
tested. Remediation efforts are in process at other plants and
areas of the electric system. A total of 95% of mission-critical
substation, system protection and distribution controls are
13
expected to be Year 2000 ready by January, 1999. The Energy
Management System (EMS) is critical to the operation of the
electric system. Factory acceptance testing for the Year 2000
mitigation software has successfully been completed and the new
software will be installed, tested, and operational by June 1,
1999. In total, 65% of EMS/Substation Control and Data
Acquisition facilities will be Year 2000 ready by January 1999.
In addition to including Year 2000 remediation and testing as
part of regularly scheduled plant outages, special Year 2000
outages have been scheduled in the winter of 1998-99 and spring
of 1999. Test scheduling is more complex for embedded systems
because of the difficulty inherent in scheduling power plant
outages to accommodate the testing. In addition, some vendors
are requesting that their customers refrain from testing certain
components because of the potential difficulties in recovering
from such tests. These vendors have either advised that their
product is Year 2000 ready or have invited Company
representatives to participate in testing at their facilities.
As of December 31, 1998 all affected plant units have outages
planned for Year 2000 testing. This differs from the original
plan to test one typical unit of each type. To accommodate this
change of scope, the completion date for all Year 2000 testing of
critical and high priority components has been revised from March
31, 1999 to June 30, 1999. This target date may be impacted by
the integration testing plans and scheduled generation/electric
systems outage decisions inherent in embedded systems processing.
As of December 31, 1998, based upon the Company's evaluation to
date, it appears that all identified Year 2000 impacted
processing components can be upgraded, modified or otherwise made
Year 2000 ready within acceptable time frames.
End-user computing systems comprise a relatively small
percentage of the required modifications both in terms of number
and criticality. All activities remain on schedule to be
completed by mid-1999.
The Company is participating in an Electric Power Research
Institute sponsored consortium of approximately 100 organizations
and investor-owned utilities to coordinate vendor contacts and
product evaluation. Since many embedded systems are similar
across utilities, this cooperative effort should help to reduce
total time expended in this area and help ensure that the
Company's efforts are consistent with the efforts and practices
of other investor-owned utilities.
The United States Department of Energy requested that the
North American Electric Reliability Council (NERC) prepare a
comprehensive report outlining the efforts of electric power
supply and delivery systems to prepare for Year 2000. NERC
collected data from utilities on a voluntary basis and issued
reports in September 1998 and January 1999. In the last update
14
provided to NERC, the Company reported 100% completion for both
the inventory and assessment phases of Year 2000, and 60%
completion in the remediation phase.
Major challenges remain in several areas: maintaining
sufficient human resources to complete Year 2000 tasks;
evaluating integrated testing requirements for many embedded
systems, taking into account planned outages and operational
needs; and completing contingency planning for the variety of
scenarios which might occur. There are two potential areas of
resource constraints. First, as the Company continues to
reorganize to prepare for industry deregulation, there is a risk
of losing technically and functionally knowledgeable people to
remediate and test systems. However, operating areas have been
instructed to give increased attention to Year 2000 staffing
needs when making reorganization decisions. Second, the
availability of vendor resources to complete embedded system
assessments and produce in volume any required component upgrades
will be a concern.
Integration testing also presents a challenge because of
scheduling constraints and admonitions from some vendors
regarding the risks of testing. A careful evaluation of testing
options and vendor testing documentation must be made on a
component-by-component basis in order to determine the most
appropriate method for obtaining Year 2000 readiness.
Business continuation and contingency planning efforts are
in progress. Business Units responsible for critical components
and systems are preparing plans in case of potential failures of
individual components or systems. These plans are referenced in
the Year 2000 tracking database and will be incorporated into the
Company's Year 2000 Business Continuity Plan.
In order to ensure adequate staffing for contingencies that
may arise, Company employees have been informed that vacation,
floating holidays, and other discretionary leave may not be
scheduled between December 26, 1999 and January 8, 2000.
Recognizing that all contingency plans should support
business continuity, the Company has formed a Business Continuity
Plan Team to integrate contingency plans. The Company's business
continuity planning will go beyond contingency planning to
document actions to be taken, resources required, and procedures
to be followed to ensure the continued availability of essential
services, programs, and operations in the event of unexpected
interruptions.
15
The following steps will be used for business continuity
planning:
1. Identification of Year 2000 Operating Risks - Identify
sources of risk, both internal and external, which may
impact the Company's ability to sustain reliable
operations into the Year 2000 and beyond.
2. Review of Existing Operating Plans - Review existing
procedures to determine if a Year 2000-specific plan
should be incorporated.
3. Develop Risk Management Strategies - Perform an analysis
of, and make recommendations for, alternative methods of
continuing critical business functions.
4. Develop Year 2000 Emergency Plan and Enhance Existing
Plans - A separate Year 2000 plan will be developed
that will interface with the Company's Corporate
Emergency Response Plan (ERP). Modification and
enhancements to existing plans will include the
following: (a) Procedures to be followed before,
during, and after a disaster; (b) Inventories of
information needs in a disaster, such as emergency
personnel lists, supplier lists, etc.; (c) Vital records
risk level; (d) Analysis of means to mitigate risk; and
(e) Integration of Year 2000 into the ERP.
5. Validation Process - Tests will be conducted by the
Business Continuity Planning Team to include tabletop
exercises and drills on likely Year 2000 scenarios.
The Company's planning process includes a review of
emergency coordination interfaces with the community. For
example, a key facet of business continuity is the Company's
interface with various emergency management agencies. The
Company is participating with the Metropolitan Washington Council
of Governments, which is looking at public safety issues on a
regional basis using existing regional public safety and
emergency management organizations. The Company presented a
planning status report to the Council of Governments in November
1998 and is also actively participating with emergency management
agencies in Year 2000 planning and drills. In December 1998, the
Company participated with the Montgomery County Office of
Emergency Preparedness in a countywide drill, as well as in a PJM
Interconnection drill. In January 1999, the Company participated
in a Maryland Emergency Management Agency drill. The Company
will participate in the next PJM drill in March 1999.
To assist in review and testing of business continuity
planning, the Company has contracted with Binominal
International. Binominal International, known for its
contingency planning and disaster recovery expertise, is
16
assisting in the review and testing of business continuity
planning, which will incorporate Year 2000 components.
The first draft of the Company's Business Continuity Plan
was completed in December 1998.
The Company is working through the PJM Interconnection to
address risks related to the regional electric transmission
system. Such interconnected systems are critical to the
reliability of each interconnected electric service provider, as
the failure of one such interconnected provider to achieve Year
2000 readiness could disrupt others from providing electric
service. Should the regional electric transmission grid become
unstable, power outages could occur. The Company's existing
emergency system restoration plan is being reviewed for use in
the event of such Year 2000 system disruptions.
NERC has responsibility for overseeing the efforts of the
industry in the United States and is coordinating Year 2000
efforts and contingency planning within and between the ten
electric reliability councils throughout the United States.
Coordination in the Company's region is through PJM. The Company
provides reports of its Year 2000 activities to NERC on a monthly
basis. Results show that the Company is on schedule to meet the
NERC target dates for Year 2000 readiness. The Company will
participate in NERC's planned drills in April and September 1999.
The availability of telecommunications services is a major
concern to the Company. Telecommunications are integral to
maintaining electric system operations internally, within PJM,
and throughout the Northern American grid. Contingency planning
for various loss of telecommunications scenarios is underway.
The Company agrees with NERC's September 1998 report to the
United States Department of Energy regarding the various Year
2000 scenarios that could occur. NERC has divided these into
"more probable scenario types," such as loss or unavailability of
a portion of generation, loss of a portion of system monitoring
and control functions, loss of voice communications, loss of a
portion of load, or uncharacteristic load; and "credible worst-
case scenarios," such as loss of a portion of transmission
facilities, underfrequency load shedding, and loss of intra- or
interregional communications. The Company's Business Continuity
Planning Team will be evaluating scenarios such as these and
developing appropriate response plans.
The Company has established a range of communications to
keep customers and suppliers informed of Year 2000 efforts.
During September 1998, Year 2000 briefing seminars were held for
many large customers. Individual meetings with several large
customers have also been held. A bill insert has been used to
advise customers of Year 2000 activities; future bill inserts
will be used as needed. A brochure for customers inquiring about
17
the Company's Year 2000 efforts is available and being
distributed. The brochure will be posted on the Company's web
page on the Internet, and the web page will be updated
periodically with the latest Year 2000 status information. An
updated telephone script has been developed for customer service
representatives answering Year 2000 related telephone inquiries
from customers.
The Company has contacted over 6,000 suppliers and vendors
to seek assurance that they will continue to provide goods and
services after December 1999. Follow-up contacts continue.
Identified essential suppliers will be defined as critical
dependencies in the draft Business Continuity Plan.
The cost or consequences of a material incomplete or
untimely resolution of the Year 2000 problem could adversely
affect future operations, financial results or financial
condition of the Company.
The cost of expected modifications will be approximately $14
million, and will be charged to expense as incurred. This
estimate may change as additional evaluations are completed and
remediation and testing progresses. Through December 31, 1998,
$7 million has been charged to expense; the remaining costs will
be expensed in 1999. Approximately $5.7 million, or 40% of the
total cost, was expensed in the twelve months ended December 31,
1998.
Depreciation and Amortization Expense, Income Taxes and
Other Taxes
- -------------------------------------------------------
Depreciation and amortization expense increased by $7.8 million
(3.4%) in 1998, and by $9 million (4%) in 1997, due to additional
investment in property and plant. Changes in income taxes in
1998 and 1997 reflect changes in the levels of taxable operating
income. Other taxes increased by $2.7 million (1.3%) in 1998,
reflecting increases in the levels of plant investment and
operating revenue, upon which taxes are based. Other taxes
increased by $1.3 million (.6%) in 1997, reflecting increases and
partially offsetting decreases in the levels of plant investment
and operating revenue, respectively.
Other Income, including Allowance for Funds Used During
Construction and Capital Cost Recovery Factor
- -------------------------------------------------------
Other income reflects net earnings from PCI of $15.1 million in
1998, $17.1 million in 1997 and $16.9 million in 1996. See the
Nonutility Subsidiary discussion below and the discussion
included in Note (14) of the Notes to Consolidated Financial
Statements, Selected Nonutility Subsidiary Financial Information.
Other income also reflects decreases in accruals for the equity
18
component of the Allowance for Funds Used During Construction
(AFUDC) resulting from declining amounts of Construction Work In
Progress expenditures not in rate base; and decreases in the
equity component of the Capital Cost Recovery Factor (CCRF)
accrued on declining amounts of pollution control expenditures
related to Clean Air Act (CAA) compliance. AFUDC equity totaled
$.9 million in 1998, $1 million in 1997 and $1.4 million in 1996;
CCRF equity totaled $.4 million in 1998, $5.7 million in 1997 and
$5.2 million in 1996. Other income for 1997 reflects a reduction
of $52.5 million resulting from the write-off of costs related to
cancellation of the proposed merger with BG&E; credits of $19.9
million for income taxes associated with this write-off are
reflected in Other, net. CCRF accruals on unamortized District
of Columbia DSM costs not in rate base, totaling $3.7 million in
1998, $5.4 million in 1997 and $4.1 million in 1996, are also
reflected in Other, net.
Utility Interest Charges
- ------------------------
Utility interest charges were relatively stable during the
three-year period 1996 through 1998, notwithstanding changes in
the levels of borrowing. Short-term borrowing costs have
remained relatively low. The average cost of outstanding long-
term utility debt declined from 7.51% at the beginning of 1996 to
7.37% at the end of 1998. Distributions on preferred securities
of the Trust totaled $5.7 million in 1998. Utility interest
charges are offset by both the debt component of AFUDC which
totaled $3.9 million in 1998, $3.8 million in 1997 and $3.9
million in 1996; and by the debt component of Clean Air Act CCRF
which totaled $.3 million in 1998, $4 million in 1997 and $3.6
million in 1996.
CAPITAL RESOURCES AND LIQUIDITY
- -------------------------------
The Company's total investment in property and plant, at original
cost, was $6.7 billion at year-end 1998. Investment in property
and plant construction, net of AFUDC and CCRF, was $603.3 million
for the period 1996 through 1998.
Internally generated cash from utility operations, after
dividends, totaled $646.7 million for the period 1996 through
1998. Sales of first mortgage bonds, medium-term notes and trust
originated preferred securities (TOPrS) during the period 1996
through 1998 provided a total of $406.8 million. During the
years 1996 through 1998, the Company retired $354.1 million in
outstanding long-term securities, including refinancings,
scheduled debt maturities, preferred stock redemptions and
sinking fund retirements. Interim financing was provided
principally through the issuance of short-term commercial
promissory notes. During the three-year period 1999 through
2001, capital resources of $314 million ($45.2 million in 1999)
19
will be required to meet scheduled debt maturities and sinking
fund requirements, and additional amounts will be required for
working capital and other needs. Approximately $759 million is
expected to be available from depreciation and amortization
charges and income tax deferrals over the three-year period of
which approximately $265 million is the 1999 portion.
Dividends on common stock were $196.6 million in 1998,
$196.7 million in 1997 and $196.6 million in 1996. The Company's
current annual dividend on common stock is $1.66 per share. The
dividend rate is determined by the Company's Board of Directors
and takes into consideration, among other factors, current and
possible future developments which may affect the Company's
income and cash flow levels. The Company has no current plans to
change the dividend; however, there can be no assurance that the
$1.66 dividend rate will be in effect in the future.
Dividends on preferred stock were $11.4 million in 1998,
$16.5 million in 1997 and $16.6 million in 1996. The embedded
cost of preferred stock was 5.74% at December 31, 1998, 6.44% at
December 31, 1997 and 6.41% at December 31, 1996.
In June 1998, the Company redeemed 60,000 shares of Serial
Preferred Stock, $3.37 series of 1987, at $50 per share for
sinking fund purposes. The Company also redeemed in accordance
with their terms, all of the 779,696 shares remaining after the
sinking fund redemption of Serial Preferred Stock, $3.37 series
of 1987, at $51.13 per share; all of the 500,000 shares of Serial
Preferred Stock, $3.82 series of 1969, at $51 per share; and all
of the 1,000,000 shares of Serial Preferred Stock, $3.89 series
of 1991, at $53.89 per share. The redemption totaled $123.7
million and includes $6.6 million in premiums.
In May 1998, the Company's wholly owned Trust issued $125
million of 7-3/8% TOPrS. The proceeds from the sale of the TOPrS
and from the common securities of the Trust to the Company were
used by the Trust to purchase from the Company $128.9 million of
7- 3/8% Junior Subordinated Deferrable Interest Debentures, due
June 1, 2038. The sole assets of the Trust are the Subordinated
Debentures. The Trust will use interest payments received from
the Company on the Subordinated Debentures to make quarterly cash
distributions on the TOPrS. Proceeds from the sale of the
Subordinated Debentures to the Trust were used by the Company to
redeem the three series of serial preferred stock in June 1998.
The Company's obligation under the declaration, including its
obligation to pay costs, expenses, debt and liabilities of the
Trust, provides a full and unconditional guarantee on a
subordinated basis of amounts payable on the TOPrS. See the
discussion included in Note (9) of the Notes to Consolidated
Financial Statements, Redeemable Serial Preferred Stock and
Company Obligated Mandatorily Redeemable Preferred Securities of
Subsidiary Trust, for additional information.
20
Total annualized interest cost for all utility outstanding
long-term debt and preferred securities of the Trust at December
31, 1998, was $139 million, compared with $132.6 million and $133
million at December 31, 1997 and 1996, respectively.
Year-end 1998 outstanding utility short-term indebtedness
totaled $191.7 million compared with $131.4 million at the end of
1997 and 1996.
The Company's capitalization ratios (excluding nonutility
subsidiary debt), at December 31, 1998, are presented below.
- -----------------------------------------------------------------
Excluding Including
Amounts Due Amounts Due
In One Year In One Year
- -----------------------------------------------------------------
Long-term debt 46.4% 43.8%
Redeemable serial preferred stock 1.2 1.2
Serial preferred stock 2.5 2.3
Company obligated mandatorily
redeemable preferred securities
of subsidiary trust which holds
solely parent junior subordinated
debentures 3.1 2.9
Common equity 46.8 44.2
Short-term debt and amounts due in
one year - 5.6
----- -----
Total capitalization 100.0% 100.0%
===== =====
- -----------------------------------------------------------------
The Company maintains 100% line of credit back-up in the
amount of $200 million, for its outstanding commercial promissory
notes, which was unused during 1998, 1997 and 1996.
Conservation
- ------------
The Company's DSM and EUM programs have increased the efficiency
of energy usage while successfully deferring the need for the
acquisition of additional generating capacity. To reduce the
near-term upward pressure on customer rates and bills, the
Company is continuing to reduce its conservation offerings and
limit conservation spending. This strategy recognizes the
transformation of the market to generally higher levels of energy
efficiency for residential and non-residential equipment.
Effective March 25, 1998, the Maryland Public Service Commission
approved a proposal supported by the Company to discontinue
operation of all but one DSM program in Maryland. The Company
received permission to substantially reduce rebates paid to
program participants for the single remaining program. A
21
proposal by the Company to eliminate DSM programs operated within
the District of Columbia was filed with the District of Columbia
Public Service Commission in March 1998, and is pending. The
effects of retail competition and updated research information on
the programs' net benefits support the discontinuance of these
programs.
The Company recovers the costs of Maryland DSM programs
through a base rate surcharge that includes a provision for the
recovery of program cost amortization and permits the Company to
earn a return on its DSM investment while receiving compensation
for lost revenue. In addition, when energy savings have exceeded
annual goals, the Company has earned a bonus. The Company was
awarded a bonus of $1.3 million in 1998, based on 1997
performance, which followed bonuses of $1.6 million in 1997,
based on 1996 performance, and $8.9 million in 1996, based on
1995 performance. Maryland DSM program goals have been
successively reduced to reflect declining DSM expenditures. On
September 16, 1998, the Company received permission from the
Maryland Commission to decrease the DSM surcharge tariff
effective with bills rendered on and after September 21, 1998,
which will reduce annual revenue by approximately $3 million.
The reduction in the surcharge rate reflects the decline in the
costs and scale of Maryland DSM programs. Beginning with the
September 1998 surcharge update, the program cost amortization
period of five years will be successively reduced to reflect the
following: 1998 program costs will be amortized over four years;
1999 program costs will be amortized over three years; 2000
program costs will be amortized over two years; and 2001 and
subsequent program costs will be amortized over one year. In
addition, the performance bonus provision of the surcharge
relative to future energy saving goals will no longer apply.
Investment in Maryland DSM programs totaled $15.4 million in
1998, $24 million in 1997 and $27.4 million in 1996.
In June 1995, the District of Columbia Commission adopted a
base rate surcharge mechanism that amortizes over a 10-year
period actual DSM costs prudently incurred since June 30, 1993;
prior to this decision, DSM costs had been considered in base
rate cases. The Environmental Cost Recovery Rider (ECRR)
includes both a DSM expenditure component and a component for
recovering certain expenditures associated with complying with
the CAA Amendments of 1990. Also within its June 1995 order, the
Commission adopted a DSM spending cap for the four-year period
1995 through 1998. The Company has successfully managed its
portfolio of DSM programs to ensure that the costs of these
programs are within the spending limit. In June 1997, the
Company filed an Application for Authority with the Commission to
update the ECRR surcharge tariff to recover actual DSM
expenditures incurred during the period January 1995 through
December 1996. In a June 1998 filing, the Company requested that
recovery of year 1997 DSM expenditures also be reflected within
the ECRR. On September 3, 1998, the Commission approved the
22
Company's June 1997 request for recovery of the January 1995
through December 1996 DSM expenditures, increasing annual revenue
by approximately $9 million. On October 30, 1998, the Company
updated its June 1998 request for 1997 DSM expenditures to
incorporate provisions of the Commission's September 3, 1998
decision, which would increase annual revenue by approximately $3
million. Investment in District of Columbia programs totaled
$5.2 million in 1998, $5.1 million in 1997 and $17.9 million in
1996.
In 1998, approximately 160,000 customers participated in
continuing EUM programs that cycle air conditioners and water
heaters during peak periods. In addition, the Company operates a
commercial load curtailment program that provides incentives to
customers for reducing energy usage during peak periods. Time-
of-use rates have been in effect since the early 1980s and
currently approximately 60% of the Company's revenue is derived
from time-of-use rates.
It is estimated that peak load reductions of approximately
730 megawatts have been achieved to date from DSM and EUM
programs and that additional peak load reductions of
approximately 50 megawatts will be achieved over the next five
years. The Company also estimates that, in 1998, energy
reductions of approximately 1.7 billion kilowatt-hours have been
realized through operation of its DSM and EUM programs. During
the next five years, the Company's projected costs for
conservation programs total $19 million ($16 million in 1999).
Construction and Generating Capacity
- ------------------------------------
Construction expenditures, excluding AFUDC and CCRF, totaled $206
million in 1998 ($66 million related to Generation) and are
projected to total $865 million ($389 million related to
Generation) for the five-year period 1999 through 2003, which
includes approximately $132 million of CAA expenditures. In
1999, construction expenditures are projected to total $185
million ($79 million related to Generation), which includes $22
million of estimated CAA expenditures. The Company plans to
finance its construction program primarily through funds provided
by operations.
The Company's present generation resource mix consists of
4,815 megawatts of steam generating capacity and 1,227 megawatts
from 31 combustion turbine units owned by the Company, including
166 megawatts of capacity from the Company's 9.72% undivided
interest in the Conemaugh Generating Station located in western
Pennsylvania. In addition, the Company has a purchase agreement
with SMECO, through 2015, for 84 megawatts of generating capacity
supplied by a combustion turbine installed and owned by SMECO at
the Company's Chalk Point Generating Station. A network of
23
transmission and distribution facilities delivers power from
these generation resources to customers and provides for system
reliability. On December 31, 1998, the Company and SMECO entered
into a new full-requirements agreement that supersedes the
existing rolling-10-year full service power supply requirements
contract. The agreement will be effective as of January 1, 1999,
if accepted by FERC without change or modification. As a result
of the agreement, approximately 600 megawatts of additional
capacity will become available by December 31, 2001 or, at
SMECO's option, December 31, 2000. See the discussion included
in Note (13) of the Notes to Consolidated Financial Statements,
Commitments and Contingencies, for additional information. The
Company projects that existing contracts for nonutility
generation and the emerging wholesale market for generation
resources will provide adequate reserve margins to meet
customers' needs beyond the year 2000.
The Company continues to purchase 450 megawatts of
generating capacity and associated energy from FirstEnergy under
a 1987 long-term capacity purchase agreement with FirstEnergy and
AEI. The Company also has a 25-year capacity purchase agreement
with Panda for 230 megawatts of capacity from a gas-fueled
combined-cycle cogenerator in Prince George's County, Maryland.
Pursuant to the terms of an October 1997 amendment to this
agreement, Panda is permitted to broker sales of certain amounts
of the Company's system capacity from January 1998 through May
2000, and to broker or sell energy from the Panda facility.
Panda will pay the Company for the right to broker capacity
sales, as well as a fee based on actual energy sales.
CLEAN AIR ACT
- -------------
The Company has complied with Phase I of the Acid Rain portion of
the CAA. Phase II of the CAA, effective January 1, 2000,
requires further reductions in nitrogen oxides (NOx) emissions
and sulfur dioxide (SO2) emissions (or the acquisition of
additional SO2 allowances) from the Company's generating units.
NOx emissions reductions are being achieved by installing new
boiler burner controls and equipment at the Company's Dickerson
Generating Station. Obligations for SO2 emissions reductions
will be met by continued use of lower sulfur coal, supplemented
by SO2 allowance purchases as necessary. Anticipated capital
expenditures for complying with the second phase of the CAA total
approximately $34 million. In addition to the Acid Rain portion
of the CAA, the State of Maryland and District of Columbia are
required, by Title I of the CAA, to achieve compliance with
ambient air quality standards for ground-level ozone.
On May 22, 1998 the State of Maryland issued final
regulations entitled "Post RACT Requirements for Nitrogen Oxides
(NOx) Sources (NOx Budget Proposal)," requiring a 65% reduction
in NOx emissions at the Company's Maryland generating units by
24
May 1, 1999. The regulations allow the purchase or trade of NOx
emission allowances to fulfill this obligation. The Company
appealed this regulation to the Circuit Court for Charles County,
Maryland on June 19, 1998, on the basis that the regulation does
not provide adequate time for the installation of NOx emission
reduction technology and that there is no functioning NOx
allowance market. On July 17, 1998, the case was moved to the
Circuit Court for Baltimore City and consolidated with a similar
appeal filed by BG&E. The Company believes it is unlikely that a
market in NOx allowances sufficient to ensure compliance will be
functioning by May 1999; presently, eight states have enacted the
rules necessary to create such a market. A preliminary plan for
installing the best available removal technology on the Company's
largest coal-fired units would require capital expenditures of
approximately $170 million and would yield NOx reductions of
nearly 85% beginning in year 2004. The Company cannot predict
the outcome of this litigation and is evaluating its options in
the event of an adverse decision. Also, on September 24, 1998,
the EPA issued rules for reducing interstate transport of ozone.
The Company's preliminary plan for NOx reductions of 85% by 2004
appears to be consistent with the EPA rules.
The Company owns a 9.72% undivided interest in the Conemaugh
Generating Station located in western Pennsylvania. NOx
emissions reduction equipment and flue gas desulfurization
equipment were installed at the station in 1994 for compliance
with Phases I and II of the CAA. The Company's share of
construction costs for this equipment was $36.2 million. As a
result of installing the flue gas desulfurization equipment, the
station has received additional SO2 emission allowances. The
Company's share of these bonus allowances is being used to reduce
the need for lower-sulfur fuel at its other plants.
In December 1997, U.S. representatives at the climate change
negotiations in Kyoto, Japan, agreed to the reduction of
greenhouse gas emissions in certain portions of the developed
world. The Kyoto protocol is subject to conditions which may not
occur, and is also subject to ratification by the United States
Senate, which has indicated that it will not ratify an agreement
unless certain conditions, not currently provided for in the
Kyoto protocol, are met. At present, it is not possible to
predict whether the Kyoto protocol will attain the force of law
in the United States or what its impact would be on the Company.
Further developments in connection with the Kyoto process could
adversely affect future operations, financial results or
financial condition of the Company.
BASE RATE PROCEEDINGS
- ---------------------
The Company is subject to utility rate regulation based upon the
historical costs of plant investment, using recent test years to
measure the cost of providing service. The rate-making process
25
does not give recognition to the current cost of replacing plant
and the impact of inflation. Changes in industry structure and
regulation may affect the extent to which future rates are based
upon current costs of providing service. The regulatory
commissions have authorized fuel rates which provide for billing
customers on a timely basis for the actual cost of fuel and
interchange and for emission allowance costs and, in the District
of Columbia, for purchased capacity.
Annual base rate increases (decreases) which became
effective during the period 1996 through 1998 are shown below.
- -----------------------------------------------------------------
District
of
Year Total Maryland Columbia Wholesale
- -----------------------------------------------------------------
(Millions of Dollars)
1998 $16.5 $19.0 $ - $(2.5)
1997 24.0 24.0 - -
1996 (2.0) - - (2.0)
----- ----- ----- -----
$38.5 $43.0 $ - $(4.5)
===== ===== ===== =====
- -----------------------------------------------------------------
Maryland
- --------
On November 28, 1998, pursuant to a settlement agreement, the
Maryland Public Service Commission authorized a $19 million, or
2% increase in base rate revenue effective with service rendered
on and after December 1, 1998. In June 1998, the Company had
filed a request to increase its base rates to recover contractual
escalations in existing Commission-approved purchased capacity
contracts, costs related to the 1998 Targeted Severance Plan,
Year 2000 compliance costs, tax normalization of pre-1981 plant
removal costs, and certain other costs associated with prior
ratemaking determinations. The settlement's rate increase was
distributed among rate classes in a manner that will continue
movement toward equalized rates of return among rate classes, and
provided for a lessening of the Company's summer-winter rate
differential. The settlement was comprehensive and does not
include specific determinations regarding an authorized rate of
return; however, a rate of return of 8.80% will be used by the
Company, beginning in December 1998, for purposes of calculating
AFUDC and CCRF. Previously, pursuant to a November 1997
settlement agreement, the Commission authorized a $24 million, or
2.6%, increase in base rate revenue effective with bills rendered
on and after November 30, 1997.
26
District of Columbia
- --------------------
In July 1995, the District of Columbia Public Service Commission
authorized rates that are based on a 9.09% rate of return on
average rate base, including an 11.1% return on common stock
equity and a capital structure which excludes short-term debt.
Wholesale
- ---------
The Company has a full service power supply requirements contract
with SMECO, the Company's principal wholesale customer with a
peak load of approximately 600 megawatts, which represents
approximately 10% of the Company's total kilowatt-hour sales.
See the discussion included in Note (13) of the Notes to
Consolidated Financial Statements, Commitments and Contingencies,
for additional information.
COMPETITION
- -----------
Since the early 1980s, the Company has pursued strategies which
achieve financial flexibility through conservation and EUM
programs, extension of the useful life of generating equipment,
cost-effective purchases of capacity and energy, and preservation
of scheduling flexibility to add new generating capacity in
relatively small increments. The Company serves a unique and
stable service territory and is a low-cost energy producer with
customer prices that compare favorably with regional and national
averages.
In response to the electric utility industry's transition
from regulation to a more competitive market, the Company during
1997 began to make fundamental changes in the shape and direction
of its organizational units. Utility operations were
reconfigured into three primary business units: generation,
distribution and transmission. The structures of these
organizational units continued to unfold in 1998 and are expected
to offer the focus and flexibility necessary to maneuver in
whatever competitive form the industry finally takes. Such
reorganization allows the Company to make the best use of its
assets while concentrating the efforts of employees on making
each business unit profitable.
27
In reconfiguring utility operations into generation,
distribution and transmission business units, the Company has
decided not to seek to become a larger generation company. The
net book value of the Company's generating assets at December 31,
1998 is $1.8 billion. The Company's generating assets are
relatively small in comparison to other major utilities and it is
expected that through future consolidations, there will remain
only a few large generating companies in the country. The
Company's immediate focus will be on increasing the performance
and profitability of its existing generation in the deregulated
wholesale market. The Company intends to explore whether it
should establish joint partnerships with other utilities'
generating business units, create strategic alliances, divest its
generating assets or continue its present course. In the area of
transmission, which remains under federal regulation, the Company
believes it has certain strengths and skills. The Company
intends to continue to evaluate the cost effectiveness of its
transmission system with a view to expanding profit potential,
including the possibility of adding to the Company's transmission
assets. In the area of distribution, which continues to be
regulated at the local level, the Company believes it has
valuable assets and skills and intends to continue to enhance its
profitability locally and leverage its skills elsewhere.
The Company is currently engaged in regulatory proceedings
in Maryland where the Public Service Commission has outlined
steps and established dates for the phase-in implementation of
competition. In the District of Columbia, the Public Service
Commission is considering various issues regarding electric
industry structure and competition. The Company reaffirms its
full support for customer choice for its electric customers, and
has provided key principles to be used as guidelines for its
introduction. These principles include the concept that present
suppliers should not be put at a competitive disadvantage by
customer choice, that competition should not be regulated, and
that the benefits of customer choice should not be oversold.
Increased competition will have an impact on future results of
operations, which may potentially be adverse. The nature of this
competition will depend upon the actions of governmental and
regulatory agencies, future regional economic conditions and
influences exerted by emerging market forces over the structure
of the electric industry. See the discussion included in Note
(13) of the Notes to Consolidated Financial Statements,
Commitments and Contingencies, for additional information.
28
RESTRUCTURING OF THE BULK POWER MARKET
- --------------------------------------
The FERC issued its Final Rulemaking Orders No. 888 and No. 889
in April 1996 to further its goal of achieving greater
competition in the wholesale energy market. Order No. 888
required utilities to file open access transmission tariffs and
separately price generation, transmission and ancillary services.
Order No. 889 directed utilities to establish or participate in
an Open Access Same-time Information System (OASIS) where
transmission owners post certain transmission availability,
pricing and service information on an open-access communications
medium such as the Internet. Order No. 889 also required the
separation of utilities' transmission system operations and
wholesale marketing functions.
In November 1997, FERC issued an Order approving the
establishment of PJM as an ISO to administer transmission service
under a poolwide transmission tariff and provide open access
transmission service on a poolwide basis. The ISO, which began
operation on January 1, 1998, is now responsible for system
operations and regional transmission planning. In addition, the
Commission decided that the independent body that operates the
ISO may also operate the PJM power exchange. The Commission
approved the power pool's use of single, non-pancaked
transmission rates to access the eight transmission systems which
make up PJM. Each transmission owner within PJM has its own
transmission rate, whereby the transmission customer will pay a
single rate based on the cost of the transmission system where
the generating capacity is delivered. This PJM rate design has
been in effect since April 1997. The Commission also approved,
effective April 1, 1998, locational marginal pricing for
allocating scarce transmission capability. This method is based
on price differences in energy at the various locations on the
transmission system.
PJM has many years of experience in providing economically
efficient transmission and generation services throughout the
mid-Atlantic region, and has achieved for its members, including
the Company, significant cost savings through shared generating
reserves and integrated operations. The PJM members have
transformed the previous coordinated cost-based pool dispatch
into a bid-based regional energy market operating under a
standard of transmission service comparability. Benefits and/or
costs derived from the PJM market are passed through to the
Company's customers through fuel adjustment clauses and,
accordingly, will not have a material effect on the operating
results of the Company.
29
NEW ACCOUNTING STANDARDS
- ------------------------
See the discussion included in Note (1) of the Notes to
Consolidated Financial Statements, Organization and Summary of
Significant Accounting Policies.
ENVIRONMENTAL MATTERS
- ---------------------
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. As a result, the Company is subject to environmental
contingencies, principally related to possible obligations to
remove or mitigate the effects on the environment of the
disposal, effected in accordance with applicable laws at the
time, of certain substances at various sites. During 1998, the
Company participated in environmental assessments and cleanups
under these laws at four federal Superfund sites and a private
party site as a result of litigation. While the total cost of
remediation at these sites may be substantial, the Company shares
liability with other potentially responsible parties. Based on
the information known to the Company at this time, management is
of the opinion that resolution of these matters will not have a
material effect on the results of operations or financial
position of the Company. See the discussion included in Note
(13) of the Notes to Consolidated Financial Statements,
Commitments and Contingencies, for additional information.
30
NONUTILITY SUBSIDIARY
- ---------------------
RESULTS OF OPERATIONS
- ---------------------
Over the past several years, the focus of PCI and its
subsidiaries has shifted from financial investments in aircraft,
leases and securities to that of a provider of energy,
telecommunications and related products and services in the
Northern Virginia/Washington, D.C./Baltimore metropolitan area.
PCI is seeking to shift this focus by installing and employing
leading-edge technologies; by attempting to realize significant
economies of scale from multi-product marketing and the use of
common facilities and support services, wherever appropriate; and
by endeavoring to deliver high-quality, convenient and reliable
services at competitive prices.
PCI's businesses consist of four separate components: Mass
Market, Commercial Market, Utility Related Market, and Financial
Investments.
During 1998, PCI expanded its customer service and product
offerings through strategic partnerships and with acquisitions of
energy and telecommunications businesses.
Mass Market
-----------
In December 1997, wholly owned affiliates of PCI and RCN
Corporation entered into a 50/50 joint venture to create
Starpower Communications (Starpower). In 1998, Starpower became
the first company to begin offering a complete single-source
package of local and long-distance telephone and Internet
services to customers throughout the Washington, D.C.
metropolitan area. With planned initial investments of $150
million from each partner over a three year period (1998-2000),
Starpower has begun building a 6,000 mile fiber optic network to
ultimately serve homes and businesses in a geographic area that
extends from Northern Virginia to Baltimore. High population
density areas have been targeted for the initial build-out of the
fiber optics system, and Starpower will begin supplying cable
television to residential customers in portions of the District
of Columbia and Maryland during 1999. As of December 31, 1998,
PCI has invested $20 million of its total $150 million commitment
to Starpower.
PCI's portion of Starpower's pre-tax loss for 1998 is $10.6
million. PCI expects that the joint venture will continue to
incur losses in 1999 and 2000 as it develops and expands its
network and customer base. During the first quarter of 1998, RCN
31
acquired Erols Internet. The majority of Erols customers
(approximately 197,000 out of a total 316,000 in February 1998)
are located in Starpower's target market. These customer
accounts, as well as certain associated network assets and
related liabilities, have been contributed by RCN to Starpower.
Starpower has agreed to pay $51.9 million ($78.6 million in
assets, primarily goodwill, net of $26.7 million of unearned
revenue) through a ratable reduction to RCN's committed future
capital contributions. As a result of this transaction,
Starpower is amortizing the acquisition premium over a three to
five year period commencing February 1998.
Starpower has recently signed agreements with the City of
Gaithersburg and the District of Columbia to provide video
programming, to local residents as well as, local phone, long-
distance and high-speed Internet access. A 147-channel cable
television service through an advanced fiber-optic network is
being rolled out to these jurisdictions during 1999. The
commercial success of Starpower will depend upon the ability of
Starpower to achieve its commercial objectives subject to a
number of uncertainties and risks, including: the pace of entry
into new markets; the time and expense required for building out
the planned network; success in marketing services; the intensity
of competition; the affect of regulatory developments; and the
possible development of alternative technologies. Statements
concerning the activities of Starpower that constitute forward
looking statements are subject to the foregoing risks and
uncertainties.
Commercial Market
-----------------
In September 1998, a wholly owned subsidiary of PCI purchased the
net assets and operations of Gaslantic Corporation (Gaslantic), a
Maryland-based natural gas retail marketing and advisory services
company doing business principally in the mid-Atlantic region.
Gaslantic focuses on providing advisory services to commercial,
industrial and institutional end-users regarding the management
of the risks and costs of natural gas procurement, and making
retail sales of natural gas to such customers. It recommends
purchasing strategies, negotiates supply and pipeline
transportation agreements and, if requested, purchases natural
gas on behalf of its clients. Gaslantic is a fee-based adviser
and retail marketer rather than a gas trader. Typical of gas
marketing operations, Gaslantic's purchase of energy to fulfill
client contract requirements is a high volume and relatively low
margin business. Through December 31, 1998, revenues recorded
related to this business since its acquisition on September 10,
1998 totaled $13.3 million. With the acquisition of Gaslantic,
PCI added fuel supply management and retail sales of natural gas
to its inventory of integrated energy products and services,
which also includes energy use assessments, facilities operation
32
and management, performance-based energy efficiency contracting,
and the sale of electricity in markets open to retail
competition.
A wholly owned PCI subsidiary became licensed as a retail
power marketer during 1998 and began selling electricity to
commercial and residential customers in Pennsylvania in the
fourth quarter of 1998. Through December 31, 1998, the
subsidiary has signed agreements to supply a total of 10 MW of
electric load to various residential and business customers in
Pennsylvania, with the first deliveries of electricity scheduled
to begin in February 1999. As retail competition in the sale of
energy in the Washington, D.C. metropolitan region is phased in
by regulators over the next several years, PCI will use the
experience gained in Pennsylvania and other mid-Atlantic markets
to compete in these newly opening markets.
On January 25, 1999, a wholly owned unregulated subsidiary
of PCI signed a contract with SMECO to supply SMECO's full
requirements for power (approximately 600 MW of peak load) during
the four year period starting January 1, 2001. See the
discussion included in Note (13) of the Notes to Consolidated
Financial Statements, Commitments and Contingencies, for
additional information.
In late 1998, a wholly owned subsidiary of PCI acquired the
net assets and operations of MET Electrical Testing, Inc. (MET
Testing). MET Testing is an electrical testing and engineering
company based in Columbia, Maryland, with specialized experience
in testing, inspecting, repairing, upgrading and maintaining
industrial and commercial-type electrical installations and
equipment. MET Testing's business is primarily in the mid-
Atlantic states with clients that include major corporations,
healthcare facilities, property managers and government agencies.
MET Testing's annual revenues for 1998 were approximately $4.6
million. PCI expects to use MET Testing as a platform to build
additional commercial services such as the operation and
maintenance of commercial energy equipment.
The commercial success of PCI in these markets is subject to
a number of risks, including, regulatory developments and the
pace of deregulation; success in marketing services; the
intensity of competition; and the ability to secure electric
supply to fulfill sales commitments at favorable prices.
Statements concerning the activities of PCI in these markets that
constitute forward looking statements are subject to the
foregoing risks and uncertainties.
33
Utility Related Market
----------------------
A wholly owned subsidiary of PCI continues to own and
operate W. A. Chester, a utility contractor specializing in
underground transmission and cable distribution systems, and, in
partnership with Columbia Energy Group, a natural gas pipeline,
liquefied natural gas (LNG) storage and terminal facility, both
of which are providing services to the utility industry and other
customers.
Financial Investments
---------------------
PCI manages a portfolio of financial investments, including
securities, aircraft and electric power plant leases, real estate
and structured finance transactions. Its remaining aircraft
portfolio is being managed with the objective of identifying
future opportunities for its sale or other disposition on
economic terms. PCI will continue to make new financial
investments that contribute to current and future earnings.
Consolidated Results
--------------------
PCI's consolidated net earnings in 1998 were $15.1 million ($.13
per share), compared with consolidated net earnings of $17.1
million ($.14 per share) and $16.9 million ($.14 per share), in
1997 and 1996, respectively. During 1998, PCI recorded pre-tax
gains of $12.2 million ($7.9 million after-tax) from the sale of
real estate and pre-tax gains of $7.8 million ($4.6 million
after-tax) from the sale of aircraft and related equipment.
PCI's earnings in 1998 also include capital gains totaling $1.4
million, net of tax, related primarily to tender offers accepted
by PCI which reduced dividend income and the cost basis of PCI's
preferred stock portfolio by $74.4 million since year end 1997.
Proceeds from asset sales were used to pay down debt, which
resulted in a decrease in interest expense from 1997. PCI's 1998
consolidated net earnings included after-tax losses of $8.4
million and $1.2 million, related to its telecommunications and
energy services businesses, respectively. In January 1999, PCI
received cash of $6.2 million and other assets with a value of
$3.3 million in an early liquidation of a partnership interest
and will record $7 million in after-tax earnings in 1999.
In 1998, PCI generated income primarily from its leasing
activities and operating businesses. Income from leasing
activities, which includes rental income, gains on asset sales,
interest income and fees totaled $73.3 million in 1998, compared
to $75.6 million in 1997 and $91.7 million in 1996. The decrease
in income from leasing activities during 1998 was primarily due
to less rental income earned in 1998 as a result of asset sales
34
earlier in the year offset by the pre-tax gains on sales of
aircraft equipment. The decrease in income from leasing
activities in 1997 compared to 1996 was primarily due to asset
sales, resulting in lower rental income.
PCI's marketable securities portfolio contributed pre-tax
income of $19.3 million in 1998, $28.6 million in 1997 and $33.7
million in 1996. The decreases in income from marketable
securities were primarily due to decreases in dividend income as
a result of reductions in the preferred stock portfolio since
1996. Income from marketable securities included net realized
gains of $2.2 million in 1998, $6.9 million in 1997 and $3.6
million in 1996.
Income from energy and utility industry services increased
over the prior years primarily due to 1998 acquisitions and
growth in contract revenue.
Other income totaled $8.4 million in 1998, compared with a
loss of $1.6 million in 1997 and a loss of $11.5 million in 1996.
The increase in other income for 1998 was primarily the result of
$12.2 million in pre-tax gains from the sales of real estate and
the 1997 pre-tax writedown of $10 million related to a real
estate property. The increase in other income during 1998 was
partially offset by pre-tax equity losses of $11.4 million
related to PCI's 50% equity investment in Starpower and the
writeoff of $3.2 million pre-tax ($2.1 million after-tax) of
PCI's remaining investment in oil and natural gas. Other income
increased in 1997 over 1996 as a result of pre-tax writedowns of
$29 million ($18.8 million after-tax) recorded in 1996 related to
PCI's investments in solar energy projects, real estate and oil
and natural gas, compared to a pre-tax writedown of $10 million
($6.5 million after-tax) recorded in 1997 related to a real
estate property.
Expenses before income taxes, which include interest,
depreciation, operating and other expenses totaled $137.1
million, $139.8 million and $159.3 million for the years ended
1998, 1997 and 1996, respectively. The decreases in expenses
before income taxes in 1998 compared to 1997 and 1996 were
primarily due to decreased interest expense over the three-year
period as a result of reduced debt outstanding, as proceeds from
sales of aircraft, marketable securities and other investments
were used to pay down debt. The decreases in expenses before
income taxes over the last two years were also due to reductions
in depreciation resulting from the sales of aircraft.
PCI had income tax credits of $8.7 million in 1998, $31.8
million in 1997 and $54.6 million in 1996. As a result of joint
venture operations and other activity, including the finalization
in 1998 of the Internal Revenue Services' examinations through
the 1995 tax year, PCI's obligation for previously accrued
35
deferred taxes was reduced resulting in a net reduction in income
tax expense during the years ended December 31, 1998, December
31, 1997 and December 31, 1996 of $1.5 million, $13.3 million and
$34.9 million, respectively.
Year 2000 Readiness Disclosure
------------------------------
In connection with Year 2000 compliance efforts, a PCI
representative is a member of the Corporate Year 2000 Task Force.
PCI is following the utility's approach, as discussed previously,
for monitoring its in-house systems and PCI's systems have been
included in the overall Year 2000 Corporate Data Base. All PCI
in-house business systems remain on schedule to become Year 2000
compliant by June 30, 1999. Costs for these remediation efforts
are currently estimated at less than $50,000. In addition, PCI
is addressing potential Year 2000 issues with the operations of
businesses in which PCI has investment or operating interests.
The Corporate Year 2000 Task Force will be assisting PCI with its
examination and monitoring of Year 2000 issues involving these
strategic business interests. Issues include ascertaining
responsibility for and monitoring progress of any Year 2000
remediation efforts required for investment-based business and
embedded systems. Plans and progress reports have been received
for most such systems. Due to the significant nature of PCI's
planned investment in Starpower, PCI has instituted a Starpower-
specific Year 2000 Program. Starpower receives significant
support services from RCN, which completed development of its
formal Year 2000 Plan in November 1998. PCI is working with
Starpower and RCN toward readiness of RCN-supplied support
systems, and other Starpower systems and operations with Year
2000 requirements. A contingency plan is being developed in the
event that remediation efforts are not successfully completed in
a timely fashion. The cost or consequences of a material
incomplete or untimely resolution of the Year 2000 problem could
adversely affect PCI's future operations, financial results or
financial condition.
CAPITAL RESOURCES AND LIQUIDITY
- -------------------------------
PCI has the capital resources necessary to carry out its business
plans. PCI will supply or arrange for the capital resources
needed to support the business activities of its growing
operating business units. PCI issues short-term and medium-term
notes under its own, separately rated commercial paper and
Medium-Term Note programs. PCI's $231.1 million securities
portfolio, consisting primarily of fixed-rate electric utility
preferred stocks provides additional liquidity and investment
flexibility. During 1998, PCI reduced the cost basis of its
marketable securities portfolio by $73.4 million primarily as the
result of calls and acceptance of tender offers of approximately
36
$74.4 million offset by purchases of $1 million. The reduced
size of the preferred stock portfolio lessens the impact of
future fluctuations in interest rates. Proceeds from securities
activity and sales of assets during 1998 were used to pay down
debt.
PCI had no short-term debt outstanding at December 31, 1998,
compared to $7.7 million at December 31, 1997. During 1998, PCI
issued $220.2 million in long-term debt, including non-recourse
debt, and debt payments totaled $333.7 million. PCI had cash and
cash equivalents of $79.6 million available at December 31, 1998
in order to satisfy debt service requirements in early 1999. At
December 31, 1998, PCI had $503 million available under its
Medium-Term Note Program and $400 million of unused bank credit
lines.
37
Report of Independent Accountants
To the Shareholders and
Board of Directors of
Potomac Electric Power Company
In our opinion, the accompanying consolidated balance sheets and
the related consolidated statements of earnings and comprehensive
income, and of cash flows present fairly, in all material
respects, the financial position of Potomac Electric Power
Company and its subsidiaries at December 31, 1998 and 1997, and
the results of their operations and their cash flows for each of
the three years in the period ended December 31, 1998, in
conformity with generally accepted accounting principles. These
financial statements are the responsibility of the Company's
management; our responsibility is to express an opinion on these
financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted
auditing standards which require that we plan and perform the
audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting
principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for the
opinion expressed above.
/s/ PricewaterhouseCoopers LLP
Washington, D.C.
January 25, 1999
38
<TABLE>
Consolidated Statements of Earnings
Potomac Electric Power Company and Subsidiaries
<CAPTION>
- --------------------------------------------------------------------------------------------------
For the year ended December 31,
1998 1997 1996
- --------------------------------------------------------------------------------------------------
(Millions of Dollars,
<S> <C> <C> <C>
except Per Share Data)
Revenue (Note 2)
Operating revenue $ 1,886.1 $ 1,810.8 $ 1,834.8
Interchange deliveries 177.8 52.7 175.5
--------- --------- ---------
Total Revenue 2,063.9 1,863.5 2,010.3
--------- --------- ---------
Operating Expenses
Fuel 380.2 319.6 327.8
Purchased energy 269.8 200.6 336.0
Capacity purchase payments (Note 13) 155.7 150.9 125.8
Other operation 237.7 220.3 223.3
Maintenance 91.5 95.3 91.5
--------- --------- ---------
Total Operation and Maintenance 1,134.9 986.7 1,104.4
Depreciation and amortization 239.8 232.0 223.0
Income taxes (Note 4) 130.5 117.7 134.1
Other taxes (Note 5) 204.4 201.7 200.4
--------- --------- ---------
Total Operating Expenses 1,709.6 1,538.1 1,661.9
--------- --------- ---------
Operating Income 354.3 325.4 348.4
--------- --------- ---------
Other Income (Loss)
Nonutility subsidiary (Note 14)
Income 143.5 125.1 121.6
Expenses, including interest and income taxes (128.4) (108.0) (104.7)
--------- --------- ---------
Net earnings from nonutility subsidiary 15.1 17.1 16.9
Allowance for other funds used during construction
and capital cost recovery factor 1.3 6.7 6.6
Write-off of merger costs (Note 13) - (52.5) -
Other, net 3.2 24.0 4.5
--------- --------- ---------
Total Other Income (Loss) 19.6 (4.7) 28.0
--------- --------- ---------
Income Before Utility Interest Charges 373.9 320.7 376.4
--------- --------- ---------
Utility Interest Charges
Interest on debt 146.1 146.7 146.9
Distributions on preferred securities of
subsidiary company (Note 9) 5.7 - -
Allowance for borrowed funds used during construction
and capital cost recovery factor (4.2) (7.8) (7.5)
--------- --------- ---------
Net Utility Interest Charges 147.6 138.9 139.4
--------- --------- ---------
Net Income 226.3 181.8 237.0
Dividends on Preferred Stock (Notes 8 and 9) 11.4 16.5 16.6
Redemption Premium on Preferred Stock 6.6 - -
--------- --------- ---------
Earnings for Common Stock $ 208.3 $ 165.3 $ 220.4
========= ========= =========
Basic Earnings Per Common Share (Note 7<F1> $1.76 $1.39 $1.86
Diluted Earnings Per Common Share (Note 7) $1.73 $1.38 $1.82
Cash Dividends Per Common Share $1.66 $1.66 $1.66
</TABLE>
39
<TABLE>
Consolidated Balance Sheets
Potomac Electric Power Company and Subsidiaries
<CAPTION>
- ----------------------------------------------------------------------------------------
December 31,
Assets 1998 1997
- ----------------------------------------------------------------------------------------
(Millions of Dollars)
<S> <C> <C>
Property and Plant - at original cost (Notes 6 and 10)
Electric plant in service $ 6,539.9 $ 6,392.8
Construction work in progress 73.2 94.3
Electric plant held for future use 4.3 4.2
Nonoperating property 40.4 22.8
--------- ---------
6,657.8 6,514.1
Accumulated depreciation (2,136.6) (2,027.8)
--------- ---------
Net Property and Plant 4,521.2 4,486.3
--------- ---------
Current Assets
Cash and cash equivalents 6.4 5.6
Customer accounts receivable, less allowance for uncollectible
accounts of $2.4 and $2.1 114.9 116.6
Other accounts receivable, less allowance for uncollectible
accounts of $.3 44.8 32.3
Accrued unbilled revenue 65.6 69.3
Prepaid taxes 34.7 33.7
Other prepaid expenses 3.3 7.6
Material and supplies - at average cost
Fuel 53.3 59.4
Construction and maintenance 68.7 68.1
--------- ---------
Total Current Assets 391.7 392.6
--------- ---------
Deferred Charges
Income taxes recoverable through future rates, net (Note 4) 232.5 238.1
Conservation costs, net 197.5 221.5
Unamortized debt reacquisition costs 49.9 52.7
Other 175.6 149.0
--------- ---------
Total Deferred Charges 655.5 661.3
--------- ---------
Nonutility Subsidiary Assets (Note 14)
Cash and cash equivalents 79.6 0.4
Marketable securities (Note 11) 231.1 302.5
Investment in finance leases (Note 14) 399.2 463.6
Operating lease equipment, net of accumulated depreciation
of $120.1 and $153.5 (Note 14) 122.6 163.3
Receivables, less allowance for uncollectible
accounts of $5.0 and $6.0 48.4 64.2
Other investments 120.6 162.9
Other assets 23.1 10.5
Deferred income taxes 61.8 -
--------- ---------
Total Nonutility Subsidiary Assets 1,086.4 1,167.4
--------- ---------
Total Assets $ 6,654.8 $ 6,707.6
========= =========
40
</TABLE>
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------
December 31,
Capitalization and Liabilities 1998 1997
- ----------------------------------------------------------------------------------------
(Millions of Dollars)
<S> <C> <C>
Capitalization
Common equity (Note 7)
Common stock, $1 par value - authorized 200,000,000 shares,
issued 118,527,287 and 118,500,891 shares $ 118.5 $ 118.5
Premium on stock and other capital contributions 1,025.3 1,025.2
Capital stock expense (13.7) (15.0)
Accumulated other comprehensive income 7.8 6.5
Retained income 739.5 727.8
--------- ---------
Total Common Equity 1,877.4 1,863.0
Preference stock, cumulative, $25 par value -
authorized 8,800,000 shares, no shares issued or outstanding - -
Serial preferred stock (Notes 8 and 11) 100.0 125.3
Redeemable serial preferred stock (Notes 9 and 11) 50.0 141.0
Company obligated mandatorily redeemable preferred securities
of subsidiary trust which holds solely parent junior
subordinated debentures (Notes 9 and 11) 125.0 -
Long-term debt (Notes 10 and 11) 1,859.0 1,901.5
--------- ---------
Total Capitalization 4,011.4 4,030.8
--------- ---------
Other Non-Current Liabilities
Capital lease obligations (Note 13) 157.6 160.4
--------- ---------
Current Liabilities
Long-term debt and preferred stock redemption 45.2 52.1
Short-term debt (Note 12) 191.7 131.4
Accounts payable and accrued payroll 104.5 118.4
Capital lease obligations due within one year 20.8 20.8
Taxes accrued 50.7 29.2
Interest accrued 38.0 38.3
Customer deposits 26.9 24.8
Other 68.9 67.4
--------- ---------
Total Current Liabilities 546.7 482.4
--------- ---------
Deferred Credits
Income taxes (Note 4) 1,049.2 1,029.3
Investment tax credits (Note 4) 53.7 57.3
Other 24.6 19.1
--------- ---------
Total Deferred Credits 1,127.5 1,105.7
--------- ---------
Nonutility Subsidiary Liabilities
Long-term debt (Notes 10 and 11) 716.9 830.5
Short-term notes payable (Note 12) - 7.7
Deferred taxes and other (Note 4) 94.7 90.1
--------- ---------
Total Nonutility Subsidiary Liabilities 811.6 928.3
--------- ---------
Commitments and Contingencies (Note 13)
Total Capitalization and Liabilities $ 6,654.8 $ 6,707.6
========= =========
41
</TABLE>
<TABLE>
Consolidated Statements of Cash Flows
Potomac Electric Power Company and Subsidiaries
<CAPTION>
- ----------------------------------------------------------------------------------------------------
For the year ended December 31,
1998 1997 1996
- ----------------------------------------------------------------------------------------------------
(Millions of Dollars)
<S> <C> <C> <C>
Operating Activities
Income from utility operations $ 211.2 $ 164.7 $ 220.1
Adjustments to reconcile income to net cash
from operating activities:
Depreciation and amortization 239.8 232.0 223.0
Deferred income taxes and investment tax credits 23.1 60.5 81.5
Deferred conservation costs (24.3) (34.5) (49.4)
Allowance for funds used during construction
and capital cost recovery factor (5.5) (14.5) (14.1)
Changes in materials and supplies 5.6 10.2 (4.1)
Changes in accounts receivable and accrued unbilled revenue (7.3) 19.2 10.5
Changes in accounts payable (12.6) 6.4 13.6
Changes in other current assets and liabilities 25.8 (2.5) 5.9
Changes in deferred merger costs - 29.0 (24.2)
Net other operating activities (28.9) (54.7) (24.4)
Nonutility subsidiary:
Net earnings 15.1 17.1 16.9
Deferred income taxes (62.7) (63.8) (36.4)
Changes in other assets and net other operating activities 37.9 65.7 49.0
--------- --------- ---------
Net Cash From Operating Activities 417.2 434.8 467.9
--------- --------- ---------
Investing Activities
Total investment in property and plant (211.7) (231.7) (194.0)
Allowance for funds used during construction
and capital cost recovery factor 5.5 14.5 14.1
--------- --------- ---------
Net investment in property and plant (206.2) (217.2) (179.9)
Nonutility subsidiary:
Purchase of marketable securities (1.0) (35.1) (19.7)
Proceeds from sale or redemption of marketable securities 76.6 125.0 167.5
Investment in leased equipment - (7.5) (3.1)
Proceeds from sale or disposition of leased equipment 105.9 28.5 3.7
Proceeds from sale of assets - 7.3 34.2
Purchase of other investments (25.0) (20.6) (23.0)
Proceeds from sale or distribution of other investments 34.3 18.7 33.9
Proceeds from promissory notes, net - 64.1 12.4
--------- --------- ---------
Net Cash (Used by) From Investing Activities (15.4) (36.8) 26.0
--------- --------- ---------
Financing Activities
Dividends on common stock (196.6) (196.7) (196.6)
Dividends on preferred stock (11.4) (16.5) (16.6)
Redemption of preferred stock (123.7) (1.5) -
Issuance of manditorily redeemable preferred securities 125.0 - -
Issuance of long-term debt - 182.3 99.5
Reacquisition and retirement of long-term debt (51.1) (151.5) (26.3)
Short-term debt, net 60.3 - (127.1)
Other financing activities (3.1) (1.3) (5.4)
Nonutility subsidiary:
Issuance of long-term debt 220.2 40.0 183.0
Repayment of long-term debt (333.7) (205.8) (237.1)
Short-term debt, net (7.7) (44.0) (171.7)
--------- --------- ---------
Net Cash Used by Financing Activities (321.8) (395.0) (498.3)
--------- --------- ---------
Net Increase (Decrease) In Cash and Cash Equivalents 80.0 3.0 (4.4)
Cash and Cash Equivalents at Beginning of Year 6.0 3.0 7.4
--------- --------- ---------
Cash and Cash Equivalents at End of Year $ 86.0 $ 6.0 $ 3.0
========= ========= =========
Cash paid for interest (net of capitalized interest of
$.7, $.5 and $.6) and income taxes:
Interest (including nonutility subsidiary interest
of $58.4, $71.5 and $83.4) $ 198.6 $ 202.8 $ 217.0
Income taxes (including nonutility subsidiary) $ 68.9 $ 53.1 $ 28.6
42
</TABLE>
<TABLE>
Consolidated Statements of Comprehensive Income
Potomac Electric Power Company and Subsidiaries
<CAPTION>
<S> <C> <C> <C>
- --------------------------------------------------------------------------------------------------
For the year ended December 31,
1998 1997 1996
- --------------------------------------------------------------------------------------------------
(Millions of Dollars)
Net Income $ 226.3 $ 181.8 $ 237.0
Other Comprehensive Income (Loss):
Unrealized gain (loss) on marketable securities 5.4 18.9 (3.3)
Less: Reclassification adjustment for gain included in
net income 3.4 10.6 5.6
--------- --------- ---------
Other Comprehensive Income (Loss), Before Tax 2.0 8.3 (8.9)
Income Tax Expense (Benefit) 0.7 2.9 (3.1)
--------- --------- ---------
Total Other Comprehensive Income (Loss), Net of Tax 1.3 5.4 (5.8)
--------- --------- ---------
Total Comprehensive Income $ 227.6 $ 187.2 $ 231.2
========= ========= =========
43
</TABLE>
Notes to Consolidated Financial Statements
- ------------------------------------------
(1) Organization and Summary of Significant Accounting Policies
-----------------------------------------------------------
Potomac Electric Power Company (the Company, PEPCO) is engaged in
the generation, transmission, distribution and sale of electric
energy in the Washington, D.C. metropolitan area. The Company's
retail service territory includes all of the District of Columbia
and major portions of Montgomery and Prince George's counties in
suburban Maryland. In addition, the Company supplies
electricity, at wholesale, under a full-requirements agreement
with Southern Maryland Electric Cooperative, Inc. (SMECO). See
Note (13) Commitments and Contingencies for a further discussion.
The Company also delivers economy energy to the Pennsylvania-New
Jersey-Maryland Interconnection LLC (PJM) of which the Company is
a member. PJM is composed of more than 100 electric utilities,
independent power producers, power marketers, cooperatives and
municipals which operate on a fully integrated basis.
Potomac Capital Investment Corporation (PCI), a wholly owned
subsidiary of the Company, was formed in 1983 to provide a
vehicle to conduct the Company's ongoing nonutility investment
programs and operating businesses. During 1998, PCI's principal
new business activity has been the development and expansion of
operating businesses in the competitive markets for energy and
telecommunications products and services. PCI's principal
financial investments are in aircraft and power generation
equipment, equipment leasing and marketable securities, primarily
preferred stock with mandatory redemption features. In addition,
PCI has investments in real estate properties in the Washington,
D.C. metropolitan area.
Potomac Electric Power Company Trust I (Trust), a Delaware
statutory business trust and a wholly owned subsidiary of the
Company, was established in April 1998. The Trust exists for the
exclusive purposes of (i) issuing Trust securities representing
undivided beneficial interests in the assets of the Trust, (ii)
investing the gross proceeds from the sale of the Trust
Securities in Junior Subordinated Deferrable Interest Debentures
issued by the Company, and (iii) engaging only in other
activities as necessary or incidental to the foregoing. See Note
(9) Redeemable Serial Preferred Stock and Company Obligated
Mandatorily Redeemable Preferred Securities of Subsidiary Trust
for a further discussion.
The Company's utility operations are regulated by the
Maryland and District of Columbia public service commissions and
its wholesale business by the Federal Energy Regulatory
Commission (FERC). The Company complies with the Uniform System
of Accounts prescribed by the FERC and adopted by the Maryland
and District of Columbia regulatory commissions.
44
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the
reported amounts of revenue and expenses during the reporting
period. Actual results could differ from those estimates and
assumptions.
Certain prior year amounts have been reclassified to conform
to the current year presentation.
A summary of the Company's significant accounting policies
is as follows.
Principles of Consolidation
- ---------------------------
The consolidated financial statements include the financial
results of the Company and its wholly owned subsidiaries. All
material intercompany balances and transactions have been
eliminated.
Total Revenue
- -------------
Revenue is accrued for service rendered but unbilled as of the
end of each month. The Company includes in revenue the amounts
received for sales of energy, and resales of purchased energy, to
other utilities and to power marketers. Amounts received for
such interchange deliveries are a component of the Company's fuel
rates.
In each jurisdiction, the Company's rate schedules include
fuel rates. The fuel rate provisions are designed to provide for
separately stated fuel billings which cover applicable net fuel
and interchange costs, purchased capacity in the District of
Columbia, and emission allowance costs in the Company's retail
jurisdictions, or changes in the applicable costs from levels
incorporated in base rates. Differences between applicable net
costs incurred and fuel rate revenue billed in any given period
are accounted for as other current assets or other current
liabilities in those cases where specific provision has been made
by the appropriate regulatory commission for the resolution of
such differences within one year. Where no such provision has
been made, the differences are accounted for as other deferred
charges or other deferred credits pending regulatory
determination.
45
Leasing Transactions
- --------------------
Income from PCI investments in direct finance and leveraged lease
transactions, in which PCI is an equity participant, is reported
using the financing method. In accordance with the financing
method, investments in leased property are recorded as a
receivable from the lessee to be recovered through the collection
of future rentals. For direct finance leases, unearned income is
amortized to income over the lease term at a constant rate of
return on the net investment. Income, including investment tax
credits on leveraged equipment leases, is recognized over the
life of the lease at a level rate of return on the positive net
investment.
PCI investments in equipment under operating leases are
stated at cost less accumulated depreciation. Depreciation is
recorded on a straight line basis over the equipment's estimated
useful life.
Property and Plant
- ------------------
The cost of additions to, and replacements or betterments of,
retirement units of property and plant is capitalized. Such cost
includes material, labor, the capitalization of an Allowance for
Funds Used During Construction (AFUDC) and applicable indirect
costs, including engineering, supervision, payroll taxes and
employee benefits. The original cost of depreciable units of
plant retired, together with the cost of removal, net of salvage,
is charged to accumulated depreciation. Routine repairs and
maintenance are charged to operating expenses as incurred.
The Company uses separate depreciation rates for each
electric plant account. The rates, which vary from jurisdiction
to jurisdiction, were equivalent to a system-wide composite
depreciation rate of approximately 3.1% for 1998, 1997 and 1996.
Conservation
- ------------
In general, the Company accounts for conservation expenditures in
connection with its DSM program as a deferred charge. These
program costs are amortized as they are included in rates charged
to customers.
In the District of Columbia, these costs are amortized over
10 years with an accrued return on unamortized costs. In
Maryland program costs have been amortized over a five year
period. Future DSM expenditures in Maryland will be recovered
over progressively shorter periods so that all expenditures will
be fully recovered by December 31, 2002. Unamortized
46
conservation costs totaled $59.8 million in Maryland and $137.7
million in the District of Columbia at December 31, 1998, and
$81.9 million in Maryland and $139.6 million in the District of
Columbia at December 31, 1997.
Allowance for Funds Used During Construction and Capital
Cost Recovery Factor
- --------------------------------------------------------
In general, the Company capitalizes AFUDC with respect to
investments in Construction Work in Progress with the exception
of expenditures required to comply with federal, state or local
environmental regulations (pollution control projects), which are
included in rate base without capitalization of AFUDC. The
jurisdictional AFUDC capitalization rates are determined as
prescribed by the FERC. The effective capitalization rates were
approximately 7.5% in 1998, 7.6% in 1997 and 7.4% in 1996,
compounded semiannually.
In Maryland, the Company accrues a CCRF on the retail
jurisdictional portion of certain pollution control expenditures
related to compliance with the CAA. The base for calculating
this return is the amount by which the Maryland jurisdictional
CAA expenditure balance exceeds the CAA balance being recovered
in base rates. The CCRF rate for Maryland is 9%. In the
District of Columbia, the carrying costs of CAA expenditures not
in rate base are recovered through a base rate surcharge.
Amortization of Debt Issuance and Reacquisition Costs
- -----------------------------------------------------
The Company defers and amortizes expenses incurred in connection
with the issuance of long-term debt, including premiums and
discounts associated with such debt, over the lives of the
respective issues. Costs associated with the reacquisition of
debt are also deferred and amortized over the lives of the new
issues.
Nonutility Subsidiary Receivables
- ---------------------------------
PCI continuously monitors its receivables and establishes an
allowance for doubtful accounts against its notes receivable,
when deemed appropriate, on a specific identification basis. The
direct write-off method is used when trade receivables are deemed
uncollectible.
47
Cash and Cash Equivalents
- -------------------------
For purposes of the consolidated financial statements, cash and
cash equivalents include cash on hand, money market funds and
commercial paper with original maturities of three months or
less.
New Accounting Standards
- ------------------------
In 1998, the Company implemented SFAS No. 130 entitled "Reporting
Comprehensive Income, SFAS No. 131 entitled "Disclosures about
Segments of an Enterprise and Related Information," and SFAS No.
132 entitled "Employers Disclosures about Pensions and Other
Postretirement Benefits."
In June 1998, the FASB issued SFAS No. 133 entitled,
"Accounting for Derivative Instruments and Hedging Activities,"
which is effective for all fiscal quarters of fiscal years
beginning after June 15, 1999. The statement establishes
accounting and reporting standards for derivative instruments and
for hedging activities. Additionally, the Emerging Issues Task
Force has issued Issue 98-10 "Accounting for Energy Trading and
Risk Management Activities." Presently, the Company's use of
derivatives and hedging activities is not significant. The
Company believes that the adoption of SFAS No. 133 will not have
a material impact on the Company's financial position or results
of operations.
In March 1998, the Accounting Standards Executive Committee
of the American Institute of Certified Public Accountants issued
Statement of Position (SOP) 98-1 entitled "Accounting for the
Costs of Computer Software Developed or Obtained for Internal
Use." This pronouncement will become effective January 1, 1999.
The Company does not believe that the SOP will have a material
impact on the Company's financial position or results of
operations.
48
(2) Total Revenue
-------------
Total revenue for each year ended December 31, was comprised as
shown below.
- -----------------------------------------------------------------
1998 1997 1996
--------------------------------------------------
Amount % Amount % Amount %
- -----------------------------------------------------------------
(Millions of Dollars)
Sales of
Electricity
Residential $ 566.8 30.3 $ 524.7 29.2 $ 548.1 30.1
Commercial 876.7 46.8 851.4 47.3 852.5 46.7
U.S.
Government 253.5 13.5 249.3 13.9 250.4 13.7
D.C.
Government 51.5 2.8 51.1 2.8 51.6 2.8
Wholesale
(primarily
SMECO) 124.2 6.6 123.3 6.8 122.2 6.7
-------- ----- -------- ----- -------- -----
Total 1,872.7 100.0 1,799.8 100.0 1,824.8 100.0
===== ===== =====
Other electric
revenue 13.4 11.0 10.0
--------- -------- --------
Operating
revenue 1,886.1 1,810.8 1,834.8
Interchange
deliveries 177.8 52.7 175.5
--------- -------- --------
Total Revenue $2,063.9 $1,863.5 $2,010.3
========= ======== ========
- -----------------------------------------------------------------
Sales of electricity include base rate revenue and fuel rate
revenue. Fuel rate revenue was $518.1 million in 1998, $509.1
million in 1997 and $521.9 million in 1996.
The Company's Maryland fuel rate is based on historical net
fuel, interchange and emission allowance costs and does not
include capacity costs associated with power purchases. The
zero-based rate may not be changed without prior approval of the
Maryland Public Service Commission. Application to the
Commission for an increase in the rate may only be made when the
currently calculated fuel rate, based on the most recent actual
49
net fuel, interchange and emission allowance costs, exceeds the
currently effective fuel rate by more than 5%. If the currently
calculated fuel rate is more than 5% below the currently
effective fuel rate, the Company must apply to the Commission for
a fuel rate reduction.
The District of Columbia fuel rate is based upon an average
of historical and projected net fuel, net interchange, emission
allowance costs and purchased capacity net of capacity sales, and
is adjusted monthly to reflect changes in such costs.
Interchange deliveries include transactions in the bilateral
energy sales marketplace, where the Company's wholesale power
sales tariff allows both sales from Company-owned generation and
sales of energy purchased by the Company from other market
participants. The benefits derived from interchange deliveries
are passed back to customers as a component of the Company's fuel
rates.
(3) Pensions and Other Postretirement and Postemployment
Benefits
----------------------------------------------------
The Company's General Retirement Program (Program), a
noncontributory defined benefit program, covers substantially all
full-time employees of the Company and PCI. The Program provides
for benefits to be paid to eligible employees at retirement based
primarily upon years of service with the Company and their
compensation rates for the three years preceding retirement.
Annual provisions for accrued pension cost are based upon
independent actuarial valuations. The Company's policy is to
fund accrued pension costs.
In addition to providing pension benefits, the Company
provides certain health care and life insurance benefits for
retired employees and inactive employees covered by disability
plans. Health maintenance organization arrangements are
available, or a health care plan pays stated percentages of most
necessary medical expenses incurred by these employees, after
subtracting payments by Medicare or other providers and after a
stated deductible has been met. The life insurance plan pays
benefits based on base salary at the time of retirement and age
at the date of death. Participants become eligible for the
benefits of these plans if they retire under the provisions of
the Company's Program with 10 years of service or become inactive
employees under the Company's disability plans. The Company is
amortizing the unrecognized transition obligation measured at
January 1, 1993, over a 20-year period.
50
Pension expense included in net income was $9.3 million in
1998, $11.6 million in 1997 and $14.2 million in 1996.
Postretirement benefit expense included in net income was $12.6
million, $11.1 million and $10.9 million in 1998, 1997 and 1996,
respectively. The components of net periodic benefit cost were
computed as follows.
- -----------------------------------------------------------------
Pension Benefits
1998 1997 1996
- -----------------------------------------------------------------
(Millions of Dollars)
Components of net periodic
benefit cost
Service cost $13.0 $ 11.4 $ 11.4
Interest cost 33.9 32.4 30.6
Expected return on plan assets (41.2) (35.8) (31.7)
Amortization of prior service
cost 1.4 1.4 1.4
Recognized actuarial loss 2.2 2.2 2.5
------ ------ ------
Net period benefit cost $ 9.3 $ 11.6 $ 14.2
====== ====== ======
- -----------------------------------------------------------------
Other Benefits
1998 1997 1996
- -----------------------------------------------------------------
(Millions of Dollars)
Components of net periodic
benefit cost
Service cost $ 4.0 $ 3.6 $ 2.8
Interest cost 5.8 5.3 5.3
Expected return on plan assets (1.5) (1.4) (1.0)
Recognized actuarial loss 4.3 3.6 3.8
------ ------ ------
Net period benefit cost $ 12.6 $ 11.1 $ 10.9
====== ====== ======
51
Assumed health care cost trend rates have a significant
effect on the amounts reported for the health care plans. The
assumed health care cost trend rate used to measure the expected
cost benefits covered by the plan is 6.5%. This rate is expected
to decline to 5.5% over the next two-year period. A one-
percentage point change in the assumed health care cost trend
rates would have the following effects for fiscal year 1998:
- -----------------------------------------------------------------
1-Percentage- 1-Percentage-
Point Increase Point Decrease
-------------- --------------
(Millions of Dollars)
Effect on total of service
and interest cost components $ .8 $ (.7)
Effect on postretirement
benefit obligation $5.0 $(4.4)
- -----------------------------------------------------------------
52
Pension program assets are stated at fair value and were
comprised of approximately 43% and 47% of cash equivalents and
fixed income investments and the balance in equity investments at
December 31, 1998 and 1997, respectively.
The following table sets forth the Program's funded status
and amounts included in Deferred Charges - Other on the
Consolidated Balance Sheets.
- -----------------------------------------------------------------
Pension Benefits
1998 1997
- -----------------------------------------------------------------
(Millions of Dollars)
Funded status $(31.4) $(26.8)
Unrecognized actuarial loss 95.1 77.7
Unrecognized prior service cost 12.1 13.5
------ ------
Prepaid benefit cost $ 75.8 $ 64.4
====== ======
Weighted average assumptions as
of December 31
Discount rate 6.5% 7.0%
Expected return on plan assets 9.0% 9.0%
Rate of compensation increase 3.75% 4.0%
- -----------------------------------------------------------------
Other Benefits
1998 1997
- -----------------------------------------------------------------
(Millions of Dollars)
Funded status $(77.8) $(68.4)
Unrecognized actuarial loss 44.2 36.7
Unrecognized prior service cost 29.5 31.6
------ ------
Prepaid (Accrued) benefit cost $ (4.1) $ (.1)
====== ======
Weighted average assumptions as
of December 31
Discount rate 6.5% 7.0%
Expected return on plan assets 9.0% 9.0%
Rate of compensation increase 3.75% 4.0%
- -----------------------------------------------------------------
53
The changes in benefit obligation and fair value of plan
assets are presented in the following table.
- -----------------------------------------------------------------
Pension Benefits
1998 1997
- -----------------------------------------------------------------
(Millions of Dollars)
Change in benefit obligation
Benefit obligation at beginning
of year $ 495.6 $ 438.1
Service cost 13.0 11.4
Interest cost 33.9 32.4
Actuarial loss 25.1 39.1
Benefits paid (26.0) (25.4)
------- -------
Benefit obligation at end of year $ 541.6 $ 495.6
======= =======
Accumulated benefit obligation
at December 31, $ 467.4 $ 413.5
======= =======
Change in fair value of plan assets
Fair value of plan assets at
beginning of year $ 468.8 $ 402.5
Actual return on plan assets 49.1 64.2
Company contributions 20.0 27.5
Benefits paid (27.7) (25.4)
------- -------
Fair value of plan assets at end
of year $ 510.2 $ 468.8
======= =======
- -----------------------------------------------------------------
54
- -----------------------------------------------------------------
Other Benefits
1998 1997
- -----------------------------------------------------------------
(Millions of Dollars)
Change in benefit obligation
Benefit obligation at beginning
of year $ 82.0 $ 73.1
Service cost 4.0 3.6
Interest cost 5.8 5.3
Actuarial loss 7.9 5.4
Benefits paid (6.3) (5.4)
------ ------
Benefit obligation at end of year $ 93.4 $ 82.0
====== ======
Change in fair value of plan assets
Fair value of plan assets at
beginning of year $ 13.6 $ 9.8
Actual return on plan assets 1.7 2.7
Company contributions 4.7 3.6
Benefits paid (4.4) (2.5)
------ ------
Fair value of plan assets at end
of year $ 15.6 $ 13.6
====== ======
- -----------------------------------------------------------------
The Company also sponsors defined contribution savings plans
covering all eligible employees. Under these plans, the Company
makes contributions on behalf of participants. Company
contributions to the plans totaled $5.8 million in 1998, and $6
million in 1997 and 1996.
In January 1998 and 1997, the Company funded the 1998 and
1997 portions of its estimated liability for postretirement
medical and life insurance costs through the use of an Internal
Revenue Code (IRC) 401 (h) account, within the Company's pension
plan, and an IRC 501 (c)(9) Voluntary Employee Beneficiary
Association (VEBA). The Company plans to fund the 401(h) account
and the VEBA annually. In January 1999, the 1999 portion of the
Company's estimated liability will be funded. Assets were
comprised of cash equivalents, fixed income investments and
equity investments.
55
<TABLE>
(4) Income Taxes
------------
The provisions for income taxes, reconciliation of consolidated income tax expense
and components of consolidated deferred tax liabilities (assets) are set forth below.
<CAPTION>
Provisions for Income Taxes
- ---------------------------
- -----------------------------------------------------------------------------------------------
1998 1997 1996
- -----------------------------------------------------------------------------------------------
(Millions of Dollars)
<S> <C> <C> <C>
Utility current tax expense
Federal $ 95.8 $ 32.2 47.2
State and local 12.1 4.7 6.3
-------- -------- -------
Total utility current tax expense 107.9 36.9 53.5
-------- -------- -------
Utility deferred tax expense
Federal 22.4 56.3 74.7
State and local 4.3 7.9 10.4
Investment tax credits (3.6) (3.6) (3.6)
-------- -------- -------
Total utility deferred tax expense 23.1 60.6 81.5
-------- -------- -------
Total utility income tax expense 131.0 97.5 135.0
-------- -------- -------
Nonutility subsidiary current tax expense
Federal 15.4 30.4 (18.2)
Nonutility subsidiary deferred tax expense
Federal (24.1) (62.3) (36.4)
-------- -------- -------
Total nonutility subsidiary income tax expense (8.7) (31.9) (54.6)
-------- -------- -------
Total consolidated income tax expense 122.3 65.6 80.4
Income taxes included in other income (8.2) (52.1) (53.7)
-------- -------- -------
Income taxes included in utility operating expenses $ 130.5 $ 117.7 134.1
======== ======== =======
56
</TABLE>
<TABLE>
<CAPTION>
Reconciliation of Consolidated Income Tax Expense
- -------------------------------------------------
- -----------------------------------------------------------------------------------------------
1998 1997 1996
- -----------------------------------------------------------------------------------------------
(Millions of Dollars)
<S> <C> <C> <C>
Income before income taxes $ 348.6 $ 247.4 317.4
======== ======== =======
Utility income tax at federal statutory rate $ 119.8 $ 91.8 124.3
Increases (decreases) resulting from
Depreciation 10.9 10.9 9.9
Removal costs (6.0) (5.9) (3.6)
Allowance for funds used during construction 0.5 0.9 0.7
Other (0.9) (4.5) (3.1)
State income taxes, net of federal effect 10.7 8.2 10.7
Tax credits (4.0) (3.9) (3.9)
-------- -------- -------
Total utility income tax expense 131.0 97.5 135.0
-------- -------- -------
Nonutility subsidiary income tax at federal statutory rate 2.2 (5.2) (13.2)
Increases (decreases) resulting from
Dividends received deduction (4.4) (5.4) (7.1)
Reversal of previously accrued deferred taxes (1.0) (10.1) (30.8)
Other (5.5) (11.2) (3.5)
-------- -------- -------
Total nonutility subsidiary income tax expense (8.7) (31.9) (54.6)
-------- -------- -------
Total consolidated income tax expense 122.3 65.6 80.4
Income taxes included in other income (8.2) (52.1) (53.7)
-------- -------- -------
Income taxes included in utility operating expenses $ 130.5 $ 117.7 134.1
======== ======== =======
</TABLE>
<TABLE>
<CAPTION>
Components of Consolidated Deferred Tax Liabilities (Assets)
- ------------------------------------------------------------
At December 31,
--------------------
1998 1997
--------------------
(Millions of Dollars)
<S> <C> <C>
Utility deferred tax liabilities (assets)
Depreciation and other book to tax basis differences $ 891.6 $ 869.3
Rapid amortization of certified pollution control
facilities 27.2 25.4
Deferred taxes on amounts to be collected through
future rates 88.0 90.2
Property taxes 12.9 13.5
Deferred fuel (9.7) (7.4)
Prepayment premium on debt retirement 18.9 20.0
Deferred investment tax credit (20.3) (21.7)
Contributions in aid of construction (32.0) (30.1)
Contributions to pension plan 22.1 18.2
Conservation costs (demand side management) 49.4 48.0
Other 19.7 21.8
-------- --------
Total utility deferred tax liabilities, net 1,067.8 1,047.2
Current portion of utility deferred tax liabilities
(included in Other Current Liabilities) 18.6 17.9
-------- --------
Total utility deferred tax liabilities, net - non-current $1,049.2 $1,029.3
======== ========
Nonutility subsidiary deferred tax (assets) liabilities
Finance leases $ 134.3 $ 119.4
Operating leases 5.0 28.8
Alternative minimum tax (79.9) (97.1)
Assets with a tax basis greater than book basis (46.0) -
Other (75.2) (50.9)
-------- --------
Total nonutility subsidiary deferred tax (assets)
liabilities, net $ (61.8) $ 0.2
======== ========
57
</TABLE>
The utility net deferred tax liability represents the tax
effect, at presently enacted tax rates, of temporary differences
between the financial statement and tax bases of assets and
liabilities. The portion of the utility net deferred tax
liability applicable to utility operations, which has not been
reflected in current service rates, represents income taxes
recoverable through future rates, net and is recorded as a
Deferred Charge on the balance sheet. No valuation allowance for
deferred tax assets was required or recorded at December 31, 1998
and 1997.
The Tax Reform Act of 1986 repealed the Investment Tax
Credit (ITC) for property placed in service after December 31,
1985, except for certain transition property. ITC previously
earned on utility property continues to be normalized over the
remaining service lives of the related assets.
The Company and PCI file a consolidated federal income tax
return. The Company's federal income tax liabilities for all
years through 1995 have been finally determined. The Company is
of the opinion that the final settlement of its federal income
tax liabilities for subsequent years will not have a material
adverse effect on its financial position or results of operation.
(5) Other Taxes
-----------
Taxes, other than income taxes, charged to utility operating
expenses for each period are shown below.
- -----------------------------------------------------------------
1998 1997 1996
- -----------------------------------------------------------------
(Millions of Dollars)
Gross receipts $ 98.4 $ 95.8 $ 96.1
Property 71.0 71.4 69.2
Payroll 10.9 10.5 10.7
County fuel-energy 15.8 15.4 15.4
Environmental, use and
other 8.3 8.6 9.0
------ ------ ------
$204.4 $201.7 $200.4
====== ====== ======
- -----------------------------------------------------------------
58
(6) Jointly Owned Generating Facilities
-----------------------------------
The Company owns a 9.72% undivided interest in the Conemaugh
Generating Station located near Johnstown, Pennsylvania,
consisting of two baseload units totaling 1,700 megawatts. The
Company and other utilities own the station as tenants in common
and share costs and output in proportion to their ownership
shares. Each owner has arranged its own financing relating to
its share of the facility. In 1997, the owners collectively
arranged for long-term tax-exempt financing, pursuant to an
agreement with the Indiana County Industrial Development
Authority relating to certain pollution control facilities
constructed at the Conemaugh Station. The Company's share of
this financing totaled $8.1 million. The Company's share of the
operating expenses of the station is included in the Consolidated
Statements of Earnings. The Company's investment in the
Conemaugh facility of $90.6 million at December 31, 1998, and
$89.9 million at December 31, 1997, includes $.3 million of
Construction Work in Progress.
59
<TABLE>
(7) Common Equity
Changes in common stock, premium on stock, accumulated other comprehensive income and
retained income are summarized below.
- -----------------------------------------------------------------------------------------------------------
Accumulated
Other
Common Stock Premium Comprehensive Retained
Shares Par Value on Stock Income <F1> Income
<CAPTION>
- -----------------------------------------------------------------------------------------------------------
(Millions of Dollars)
<S> <C> <C> <C> <C> <C>
Balance, December 31, 1995 118,494,577 $ 118.5 $ 1,025.1 $ 6.9 $ 735.4
Net income before net earnings
from nonutility subsidiary - - - - 220.1
Nonutility subsidiary:
Net earnings - - - - 16.9
Other comprehensive loss - - - (5.8) -
Dividends:
Preferred stock - - - - (16.6)
Common stock - - - - (196.6)
Conversion of preferred stock 3,239 - - - -
Conversion of debentures 2,221 - 0.1 - -
----------- ---------- ---------- -------------- - ---------
Balance, December 31, 1996 118,500,037 118.5 1,025.2 1.1 759.2
Net income before net earnings
from nonutility subsidiary - - - - 164.7
Nonutility subsidiary:
Net earnings - - - - 17.1
Other comprehensive income - - - 5.4 -
Dividends:
Preferred stock - - - - (16.5)
Common stock - - - - (196.7)
Conversion of preferred stock 854 - - - -
----------- ---------- ---------- -------------- - ---------
Balance, December 31, 1997 118,500,891 118.5 1,025.2 6.5 727.8
Net income before net earnings
from nonutility subsidiary - - - - 211.2
Nonutility subsidiary:
Net earnings - - - - 15.1
Other comprehensive income - - - 1.3 -
Dividends:
Preferred stock - - - - (11.4)
Common stock - - - - (196.6)
Conversion of preferred stock 26,396 - 0.1 - -
Redemption premium on preferred stock - - - - (6.6)
----------- ---------- ---------- -------------- - ---------
Balance, December 31, 1998 118,527,287 $ 118.5 $ 1,025.3 $ 7.8 $ 739.5
=========== ========== ========== ============== = =========
<FN>Represents unrealized gains (losses) on marketable securities of nonutility subsidiary.
</FN>
60
</TABLE>
The Company's Shareholder Dividend Reinvestment Plan (DRP)
provides that shares of common stock purchased through the plan
may be original issue shares or, at the option of the Company,
shares purchased in the open market. The DRP permits additional
cash investments by plan participants limited to one investment
per month of not less than $25 and not more than $5,000.
As of December 31, 1998, 2,769,412 and 3,392,500 shares of
common stock were reserved for issuance upon the conversion of
the 7% and 5% convertible debentures, respectively, 2,324,721
shares were reserved for issuance under the DRP and 1,221,624
shares were reserved for issuance under the Employee Savings
Plans.
Certain provisions of the Company's corporate charter,
relating to preferred and preference stock, would impose
restrictions on the payment of dividends under certain
circumstances. No portion of retained income was so restricted
at December 31, 1998.
61
<TABLE>
Calculations of Earnings Per Common Share
- -----------------------------------------
Reconciliations of the numerator and denominator for basic and diluted earnings
per common share are shown below.
<CAPTION>
- ------------------------------------------------------------------------------------------------------------
For the year ended December 31,
1998 1997 1996
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
(Millions, except Per Share Data)
Income (Numerator):
Earnings applicable to common stock $ 208.3 $ 165.3 $ 220.4
Add: Dividends paid or accrued on Convertible Preferred Stock - - -
Interest paid or accrued on Convertible Debentures, net of
related taxes 6.3 6.3 6.4
---------- ---------- ----------
Earnings applicable to common stock, assuming conversion of
convertible securities $ 214.6 $ 171.6 $ 226.8
========== ========== ==========
Shares (Denominator):
Average shares outstanding for computation of basic earnings
per common share 118.5 118.5 118.5
========== ========== ==========
Average shares outstanding for diluted computation:
Average shares outstanding 118.5 118.5 118.5
Additional shares resulting from:
Conversion of Convertible Debentures 5.7 5.8 5.8
---------- ---------- ----------
Average shares outstanding for computation of diluted earnings
per common share 124.2 124.3 124.3
========== ========== ==========
Basic earnings per common share $1.76 $1.39 $1.86
Diluted earnings per common share $1.73 $1.38 $1.82
62
</TABLE>
(8) Serial Preferred Stock
----------------------
The Company has authorized 8,750,000 shares of cumulative $50 par
value Serial Preferred Stock. At December 31, 1998 and 1997,
there were outstanding 3,000,000 shares and 5,345,499 shares,
respectively. The various series of Serial Preferred Stock
outstanding [excluding 1,000,000 shares of Redeemable Serial
Preferred Stock - See Note (9)] and the per share redemption
price at which each series may be called by the Company are as
follows.
- -----------------------------------------------------------------
Redemption December 31,
Price 1998 1997
- -----------------------------------------------------------------
(Millions of
Dollars)
$2.44 Series of 1957, 300,000 shares $51.00 $ 15.0 $ 15.0
$2.46 Series of 1958, 300,000 shares $51.00 15.0 15.0
$2.28 Series of 1965, 400,000 shares $51.00 20.0 20.0
$3.82 Series of 1969, none and
500,000 shares, respectively $51.00 - 25.0
$2.44 Convertible Series of 1966,
none and 5,803 shares, respectively $50.00 - .3
Auction Series A, 1,000,000 shares $50.00 50.0 50.0
------ ------
$100.0 $125.3
====== ======
- -----------------------------------------------------------------
The Company on March 1, 1998, redeemed all remaining shares
of Serial Preferred Stock, $2.44 Convertible Series of 1966.
Prior to the redemption, the $2.44 Convertible Series was
convertible into common stock of the Company. The number of
shares of this series converted into common stock was 4,525
shares in 1998, 147 shares in 1997 and 556 shares in 1996. In
addition, on June 1, 1998, the Company redeemed all of the
500,000 shares of Serial Preferred Stock, $3.82 Series of 1969.
Dividends on the Serial Preferred Stock, Auction Series A,
are based on the rate determined by auction procedures prior to
each dividend period. The maximum rate can range from 110% to
200% of the applicable "AA" Composite Commercial Paper Rate. The
annual dividend rate is 4.2% ($2.10) for the period December 1,
1998 through February 28, 1999. The average annual dividend
rates were 4.136% ($2.068) in 1998 and 4.221% ($2.1105) in 1997.
63
(9) Redeemable Serial Preferred Stock and Company Obligated
Mandatorily Redeemable Preferred Securities of Subsidiary
Trust
---------------------------------------------------------
The outstanding series of $50 par value Redeemable Serial
Preferred Stock are shown below.
- -----------------------------------------------------------------
December 31,
1998 1997
- -----------------------------------------------------------------
(Millions of Dollars)
$3.37 Series of 1987, none and
839,696 shares, respectively $ - $ 42.0
$3.89 Series of 1991, none and
1,000,000 shares, respectively - 50.0
$3.40 Series of 1992, 1,000,000 shares 50.0 50.0
------ ------
50.0 142.0
Redemption Requirement due within one
year - (1.0)
------ ------
$ 50.0 $141.0
====== ======
- ----------------------------------------------------------------
On May 19, 1998, Potomac Electric Power Company Trust I (see
Note (1) Organization and Summary of Significant Accounting
Policies) issued $125 million of 7-3/8% Trust Originated
Preferred Securities (TOPrS). The proceeds from the sale of the
TOPrS to the public and from the sale of the common securities of
the Trust to the Company were used by the Trust to purchase from
the Company $128.9 million of 7-3/8% Junior Subordinated
Deferrable Interest Debentures, due June 1, 2038 (Junior
Subordinated Debentures). The sole assets of the Trust are the
Junior Subordinated Debentures. The Trust will use interest
payments received on the Junior Subordinated Debentures to make
quarterly cash distributions on the TOPrS. Accrued and unpaid
distributions on the TOPrS, as well as payment of the redemption
price upon the redemption and of the liquidation amount upon the
voluntary or involuntary dissolution, winding-up or termination
of the Trust, to the extent such funds are held by the Trust, are
guaranteed by the Company (Guarantee). The Guarantee, when taken
together with the Company's obligation under the Junior
Subordinated Debentures and the Indenture for the Junior
Subordinated Debentures, and the Company's obligations under the
declaration of Trust for the TOPrS, including its obligations to
pay costs, expenses, debts and liabilities of the Trust, provides
a full and unconditional guarantee by the Company on a
subordinated basis of the Trust obligations. Proceeds from the
64
sale of the Junior Subordinated Debentures to the Trust were used
by the Company to redeem the Serial Preferred Stock, $3.82 Series
of 1969, $3.37 Series of 1987 and $3.89 Series of 1991 on June 1,
1998.
The shares of the $3.40 (6.80%) Series are subject to
mandatory redemption, at par, through the operation of a sinking
fund which will redeem 50,000 shares annually, beginning
September 1, 2002, with the remaining shares redeemed on
September 1, 2007. The shares are not redeemable prior to
September 1, 2002; thereafter, the shares are redeemable at par.
In the event of default with respect to dividends, or
sinking fund or other redemption requirements relating to the
serial preferred stock, no dividends may be paid, nor any other
distribution made, on common stock. Payments of dividends on all
series of serial preferred or preference stock, including series
which are redeemable, must be made concurrently.
The sinking fund requirements through 2003 with respect to
the Redeemable Serial Preferred Stock are $2.5 million in 2002
and 2003.
65
<TABLE>
(10) Long-Term Debt
<CAPTION>
Details of long-term debt are shown below.
- ----------------------------------------------------------------------------------------------------
Interest December 31,
Rate Maturity 1998 1997
- ----------------------------------------------------------------------------------------------------
(Millions of Dollars)
<S> <C> <C> <C>
First Mortgage Bonds
Fixed Rate Series:
4-3/8% February 15, 1998 $ - $ 50.0
4-1/2% May 15, 1999 45.0 45.0
9% April 15, 2000 100.0 100.0
5-1/8% April 1, 2001 15.0 15.0
5-7/8% May 1, 2002 35.0 35.0
6-5/8% February 15, 2003 40.0 40.0
5-5/8% October 15, 2003 50.0 50.0
6-1/2% September 15, 2005 100.0 100.0
6-1/4% October 15, 2007;
PUT date
October 15, 2004 175.0 175.0
6-1/2% March 15, 2008 78.0 78.0
5-7/8% October 15, 2008 50.0 50.0
5-3/4% March 15, 2010 16.0 16.0
9% June 1, 2021 100.0 100.0
6% September 1, 2022 30.0 30.0
6-3/8% January 15, 2023 37.0 37.0
7-1/4% July 1, 2023 100.0 100.0
6-7/8% September 1, 2023 100.0 100.0
5-3/8% February 15, 2024 42.5 42.5
5-3/8% February 15, 2024 38.3 38.3
6-7/8% October 15, 2024 75.0 75.0
7-3/8% September 15, 2025 75.0 75.0
8-1/2% May 15, 2027 75.0 75.0
7-1/2% March 15, 2028 40.0 40.0
Variable Rate Series:
Adjustable rate December 1, 2001 50.0 50.0
--------- ---------
Total First Mortgage Bonds 1,466.8 1,516.8
Convertible Debentures
5% September 1, 2002 115.0 115.0
7% January 15, 2018 62.8 63.9
Medium-Term Notes
Fixed Rate Series:
6.53% December 17, 2001 100.0 100.0
7.46% to 7.60% January 2002 40.0 40.0
7.64% January 17, 2007 35.0 35.0
6.25% January 20, 2009 50.0 50.0
7% January 15, 2024 50.0 50.0
Variable Rate Series:
Adjustable rate June 1, 2027 8.1 8.1
--------- ---------
Total Utility Long-Term Debt 1,927.7 1,978.8
Net unamortized discount (23.5) (26.2)
Current portion (45.2) (51.1)
--------- ---------
Net Utility Long-Term Debt $ 1,859.0 $ 1,901.5
========= =========
Nonutility Subsidiary Long-Term Debt
Varying rates through 2018 $ 716.9 $ 830.5
========= =========
66
</TABLE>
Utility Long-Term Debt
- ----------------------
The outstanding First Mortgage Bonds are secured by a lien on
substantially all of the Company's property and plant.
Additional bonds may be issued under the mortgage as amended and
supplemented in compliance with the provisions of the indenture.
In February 1998, the Company redeemed, at maturity, $50
million of 4-3/8% First Mortgage Bonds.
The interest rate on the $50 million Adjustable Rate series
First Mortgage Bonds is adjusted annually on December 1, based
upon the 10-year "constant maturity" United States Treasury bond
rate for the preceding three-month period ended October 31, plus
a market based adjustment factor. Effective December 1, 1998,
the applicable interest rate is 6.093%. The applicable interest
rate was 7.38% at December 1, 1997, and 7.867% at December 1,
1996.
The 7% Convertible Debentures are convertible into shares of
common stock at a conversion price of $27 per share.
The 5% Convertible Debentures are convertible into shares of
common stock at a conversion rate of 29-1/2 shares for each
$1,000 principal amount.
The aggregate amounts of maturities for the Company's long-
term debt outstanding at December 31, 1998, are $45.2 million in
1999, $100 million in 2000, $165 million in 2001, $190 million in
2002 and $90 million in 2003.
Nonutility Subsidiary Long-Term Debt
- ------------------------------------
Long-term debt at December 31, 1998, consisted primarily of
$697.6 million of recourse debt from institutional lenders
maturing at various dates between 1999 and 2018. The interest
rates of such borrowings ranged from 5% to 10.1%. The weighted
average interest rate was 7.35% at December 31, 1998, 7.48% at
December 31, 1997, and 7.44% at December 31, 1996. Annual
aggregate principal repayments are $170 million in 1999, $147.5
million in 2000, $88.5 million in 2001, $93 million in 2002, and
$134.5 million in 2003.
67
Long-term debt also includes $19.2 million of non-recourse
debt, $11.7 million of which is secured by aircraft currently
under operating lease. The debt is payable in monthly
installments at rates of LIBOR (London Interbank Offered Rate)
plus 1.25% with final maturity on March 15, 2002. Non-recourse
debt of $7.5 million is related to PCI's majority-owned real
estate partnerships and is based on a 30-year amortization period
at a fixed rate of interest of 9.66%, with final maturity on
October 1, 2011.
68
<TABLE>
(11) Fair Value of Financial Instruments
- ----------------------------------------
The estimated fair values of the Company's financial instruments at December 31, 1998,
and 1997 are shown below.
<CAPTION>
- ------------------------------------------------------------------------------------------------------
December 31,
1998 1997
- ------------------------------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- -------- -------- --------
(Millions of Dollars)
<S> <C> <C> <C> <C>
Utility
Capitalization and Liabilities
Serial preferred stock $ 100.0 95.4 125.3 127.3
Redeemable serial preferred stock $ 50.0 53.6 141.0 142.6
Company obligated mandatorily redeemable
preferred securities of subsidiary trust
which holds solely parent junior
subordinated debentures $ 125.0 128.7 - -
Long-term debt
First mortgage bonds $1,408.4 1,489.5 1,452.4 1,507.5
Medium-term notes $ 281.3 304.5 281.2 289.9
Convertible debentures $ 169.3 175.2 167.9 172.4
Nonutility Subsidiary
Assets
Marketable securities $ 231.1 231.1 302.5 302.5
Notes receivable $ 25.5 22.4 23.1 19.5
Liabilities
Long-term debt $ 716.9 729.2 830.5 841.0
- ------------------------------------------------------------------------------------------------------
69
</TABLE>
The methods and assumptions below were used to estimate, at
December 31, 1998 and 1997, the fair value of each class of
financial instruments shown above for which it is practicable to
estimate that value.
The fair value of the Company's Serial Preferred Stock,
Redeemable Serial Preferred Stock and Company Obligated
Mandatorily Redeemable Preferred Securities of Subsidiary Trust,
excluding amounts due within one year, was based on quoted market
prices or discounted cash flows using current rates of preferred
stock with similar terms.
The fair value of the Company's Long-term Debt, which
includes First Mortgage Bonds, Medium-Term Notes and Convertible
Debentures, excluding amounts due within one year, was based on
the current market price, or for issues with no market price
available, was based on discounted cash flows using current rates
for similar issues with similar terms and remaining maturities.
The fair value of PCI's Marketable Securities was based on
quoted market prices.
The fair value of PCI's Notes Receivable was based on
discounted future cash flows using current rates and similar
terms.
The fair value of PCI's Long-term Debt, including non-
recourse debt, was based on current rates offered to similar
companies for debt with similar remaining maturities.
The carrying amounts of all other financial instruments
approximate fair value.
(12) Short-Term Debt
---------------
The Company's short-term financing requirements have been
satisfied principally through the sale of commercial promissory
notes. Interest rates for the Company's short-term financing
during the year ranged from 4.6% to 6.3%.
The Company maintains a minimum 100% line of credit back-up
for its outstanding commercial promissory notes, which was unused
during 1998, 1997 and 1996.
70
Nonutility Subsidiary Short-Term Notes Payable
- ----------------------------------------------
The nonutility subsidiary's short-term financing requirements
have been satisfied principally through the sale of commercial
promissory notes.
The nonutility subsidiary maintains a minimum 100% line of
credit back-up, in the amount of $400 million, for its
outstanding commercial promissory notes, which was unused during
1998, 1997 and 1996.
(13) Commitments and Contingencies
-----------------------------
Competition
- -----------
The electric utility industry continues to be subjected to
increasing competitive pressures, stemming from a combination of
increasing independent power production and regulatory and
legislative initiatives intended to increase bulk power
competition, including the Energy Policy Act of 1992.
Based on the regulatory framework in which it operates, the
Company continues to apply the provisions of Statement of
Financial Accounting Standards (SFAS) No. 71, "Accounting for the
Effects of Certain Types of Regulation" in accounting for its
retail utility operations. SFAS No. 71 allows regulated
entities, in appropriate circumstances, to establish regulatory
assets and to defer the income statement impact of certain costs
that are expected to be recovered in future rates. Deregulation
of portions of the Company's business could, in the future,
result in not meeting the rate recovery criteria for application
of SFAS No. 71 for part or all of the business. If this were to
occur in the transition to a more competitive industry,
accounting standards of enterprises in general would apply which
would entail the write-off of any previously deferred costs to
results of operations. Regulatory assets include deferred income
taxes, unamortized conservation costs and unamortized debt
reacquisition costs recoverable through future rates. In
addition, electric plant in service includes a regulatory asset
related to capital leases, which are treated as operating leases
for ratemaking purposes, of approximately $37 million and $29
million at December 31, 1998 and 1997, respectively.
Under traditional regulation, utilities are provided an
opportunity to earn a fair return on invested capital in exchange
for a commitment to serve all customers within a designated
service territory. To further the goal of providing universal
access to safe and reliable electric service within this
71
regulated environment, regulatory decisions led to costs and
commitments by utilities that may not be entirely recovered
through market-based revenues in a competitive environment.
Recovery and measurement of above-market, or "stranded" costs in
a future competitive environment, will be subject to regulatory
proceedings. Potential above-market costs include, but are not
limited to, costs associated with generation facilities that are
fixed and unavoidable, including future costs related to plant
removal; above-market costs associated with purchased power
obligations; and regulatory assets and obligations incurred in
accordance with SFAS No. 71. The inability of the Company to
recover its stranded costs fully could have a material adverse
impact on the future earnings and cash flows of the Company, and
may result in consequences including, but not limited to,
increases in the cost of capital, increases in rates for
transmission and distribution services, exposure to downgrades in
credit ratings and involuntary layoffs of employees. The Company
expects to be provided an opportunity to recover its stranded
costs.
Maryland
- --------
In December 1997, the Maryland Public Service Commission issued
orders that outlined steps toward a competitive electric
generation market and established dates for the phased-in
implementation of competition. Pursuant to the orders,
competition will be phased in over a two-year period beginning
July 1, 2000. Customers representing one-third of the electric
load in a particular customer class will be able to choose their
electric generation supplier at that time. On July 1, 2001, the
eligible group increases to two-thirds in any one customer class,
and all customers will then become eligible one year later. The
Commission affirmed that Maryland utilities will be given the
opportunity to recover verifiable and prudently incurred stranded
costs which cannot be mitigated or reduced; proposals to
establish a Competitive Transition Charge (CTC) for stranded cost
recovery will be addressed in future proceedings. The Commission
recommended that the Maryland legislature enact legislation to
allow securitization of stranded costs, where it can be shown
that this financing procedure will reduce costs for customers.
The Commission ordered no mandatory rate reductions during the
transition to competition, and applied the designation of default
provider to the consumer's current utility. In addition, the
Commission recognized the need for tax reform to "level the
playing field" for Maryland utilities, and requested the Maryland
legislature to enact the necessary legislation. Also, the
Commission stated that fuel adjustment clauses are incompatible
with the workings of a competitive generation market, and
requested that legislation be enacted to discontinue use of fuel
adjustment clauses in the future. Additionally, the Commission
requested that legislation be enacted to permit price cap
72
regulation and materially depart from cost of service regulation
with respect to the purchase and generation of electricity. The
Commission proposed the establishment of statewide roundtables to
address issues such as provision of metering and billing
services, consumer protection and DSM, but did not propose any
changes to the form of regulation currently applicable to the
recovery of costs associated with the distribution of
electricity. Moreover, the Commission did not order the
divestiture or corporate unbundling of generating assets but
indicated it will consider these options as part of its review of
future market power studies required to be filed by Maryland
electric utilities.
In compliance with Commission orders, the Company filed on
July 1, 1998, a quantification of its Maryland jurisdictional
generating, purchased power and other costs that the Company
projects would be stranded in a competitive market for generating
services; a proposed method for recovering such stranded costs
through a non-bypassable CTC; proposed unbundled rates for retail
service; and a proposal to freeze retail rates from the time
competition begins until January 2004 (collectively, the Filing).
The Company made numerous assumptions in the Filing, including
assumptions as to the outcome of the recently-concluded 1998 base
rate case, the future price of electricity including fuel
charges, future revenues, the costs of transmission and
distribution, and service territory demographics, some or all of
which may prove not to have been accurate. The Filing will be
the subject of an adjudicatory proceeding which, in accordance
with the terms of the Commission's orders, is expected to
conclude in October 1999. As is its normal practice and is
consistent with the Commission's procedural orders, the Company
is also pursuing discussions with the other parties to the
adjudicatory proceedings as to whether settlement of the issues
is possible. Any such settlement would require the Commission's
approval.
The Commission's implementation process provides for a
15-month period to study the Filing. After that period, the
Company will be required to file a restructuring plan in November
1999 which would take into account any restructuring legislation
enacted by the General Assembly, as well as the outcome of the
adjudicatory proceeding initiated by the Commission with respect
to the Filing. Accordingly, the Filing does not constitute the
Company's final restructuring plan. In connection with the
Filing, the Company reiterated its position that absent
appropriate enabling legislation by the Maryland General Assembly
(which has yet to be enacted), the Commission lacks the legal
authority to implement the plan filed by the Company, or any
other restructuring plan providing for retail competition.
73
The Company has proposed separate unbundled rates for
generation supply (i.e., the cost of producing power or buying it
from third parties) and for electricity delivery (i.e., the cost
of transmission and distribution of electricity to consumers).
In the Filing, the Company's anticipated 1999 average price of
7.78 cents per kilowatt-hour breaks down into a supply charge of
4.60 cents and a delivery charge of 3.18 cents, which exceed the
rates approved within the Company's recent Maryland base rate
settlement agreement.
As part of the Filing, the Company proposes that effective
with the initial phase of competition, which is currently
scheduled to commence July 1, 2000, both the supply and delivery
components of the Company's retail prices will be frozen at
then-existing levels until January 1, 2004. The Company also
proposes to eliminate its fuel rate on July 1, 2000, and assume
the risk of fuel cost increases after implementation of the
restructuring plan until January 1, 2004, when the Company no
longer has the obligation to supply electricity at the frozen
rate. The only exceptions to the rate freeze would be for
unexpected increases in taxes or new environmental requirements.
After January 1, 2004, supply prices would be set by the
competitive marketplace and delivery prices would be determined
by regulators.
For retail customers who do not wish to buy the supply
portion of their electric service from a source other than the
Company once they are free to do so, the Company proposes to
provide both supply and delivery service at the frozen rates
until January 1, 2004. For customers who enter the competitive
supply market, the Company proposes to provide them with a
"shopping credit" equal to the estimated market price for
electricity. The shopping credit would terminate on January 1,
2004.
Under the Company's proposal, the transition to customer
choice, including recovery of stranded costs, would be made
without any increase in prices to customers. Initially, prices
would be held at the levels in effect when competition begins for
customers who choose to buy both supply and delivery from the
Company. During the freeze, an implicit non-bypassable CTC will
be included in the frozen rate. After the end of the freeze in
January 2004, all customers would pay, as part of their delivery
charge, an explicit CTC that would successively decrease until
2021, when the last of the Company's pre-competition power
purchase contracts ends. The proposed CTC will allow the Company
the opportunity for full recovery of its prudent, non-mitigated
stranded costs, as contemplated by the Commission in its December
1997 orders, without causing an increase in rates.
In the Filing, the Company identifies stranded costs (the
total economic value of previously expected regulatory earnings
that will not be recovered in a deregulated energy market) having
74
a net after-tax present value of $600.4 million, which it
proposes be securitized and recovered over the period 2000
through 2010. The $600.4 million is comprised of $319.8 million
relating to generation assets, $242.6 million relating to power
purchase contracts, and $38 million in other stranded costs. The
Company proposes to recover additional stranded costs associated
with its long-term Panda and SMECO power purchase contracts,
having a present value of $42 million, over the period 2011 to
2021, which it does not propose be securitized. All stranded
cost recovery would be accomplished through the non-bypassable
CTC. The Company has also proposed a "true up" mechanism to
update prospectively in July 2004 its stranded cost estimates
taking into account changes in market price or other factors.
The stranded costs in the Filing predominately relate to costs
which are already included in the Company's rates. They have
been approved by regulators as being appropriate to recover
because they were found to have been prudently incurred to meet
the Company's regulatory-era obligation to provide reliable
service to everyone who wants it. The Company anticipates that
these costs would be amortized to match the revenues collected by
the CTC. As part of its plan, the Company proposes to securitize
a portion of its stranded cost recovery and thereby achieve
savings through a reduction in capital costs.
If a competitive market for generation supply is implemented
in Maryland, the Company believes that the Commission will follow
through on its commitment to provide a fair opportunity for the
Company to recover its prudently incurred stranded costs, and
that the stranded costs identified by the Company in the filing
will be determined to have been prudently incurred. The
inability of the Company to recover fully its stranded costs
could have a material adverse impact on the future earnings and
cash flows of the Company, and may result in consequences
including, but not limited to, increases in the cost of capital,
increases in rates for transmission and distribution services,
exposure to downgrades in credit ratings and involuntary layoffs
of employees.
On October 9, 1998, the Company and four other electric
utilities operating in Maryland - Allegheny Power, Choptank
Electric Cooperative, Inc., Conectiv and SMECO - filed separate
appeals in Baltimore City Circuit Court seeking a judicial review
of recent decisions by the Maryland Commission in which the
Commission asserted its authority to restructure the electric
utility industry without authorization from the Maryland State
Legislature. The Company believes that the proper way to ensure
progress is for the legislature, in its 1999 session, to grant
the Commission authority to proceed. Accordingly, the utilities
asked the court to defer action on the appeal until after
completion of the 1999 legislative session, which began in
January 1999. On December 18, 1998, the Company filed a motion
for voluntary dismissal of its appeal without prejudice. The
75
Company's motion was filed pursuant to an agreement among
Conectiv, Allegheny Power, SMECO, Choptank Electric Cooperative
and the Maryland Public Service Commission that the Commission's
restructuring orders were not "final orders" within the meaning
of the law governing the powers of the Commission and, further,
that the appeals challenging the Commission's authority to
implement retail choice without enabling legislation could be
filed after the Commission issues its order on the pending
applications for rehearing filed by the Company and several other
parties. All of the other utility appellants either have filed
or will file similar motions to dismiss their appeals.
District of Columbia
- --------------------
In September 1996, the District of Columbia Public Service
Commission issued an order designating the issues to be examined
regarding electric industry structure and competition. The
Company filed comments on the designated issues in early 1997,
and on August 31, 1998, the Commission Staff issued its proposal
for bringing choice of electric suppliers to District of Columbia
customers. The Staff's proposal is currently under the review of
the full Commission, which may ultimately reach different
conclusions. Pursuant to the Staff's recommendation, competition
would be phased in over a two-year period beginning January 1,
2001. Customers representing one-fifth of the electric load in a
particular customer class would be able to choose their electric
generation supplier at that time. On January 1, 2002, the
eligible group increases to one-half of any one customer class,
and all customers will then become eligible one year later. The
Staff proposed the establishment of working groups to address
issues such as conservation, environmental compliance, consumer
protection, provision of universal service, supplier
certification, and the need for legislation to pave the way for
choice. More difficult issues such as the design of unbundled
rates and stranded cost estimation and recovery would be
addressed in future adjudicatory proceedings. An order was
issued by the full Commission on December 30, 1998, in response
to the Staff report. The order requires that the Company file a
stranded cost study and unbundled rates for the District of
Columbia by February 1, 1999.
SMECO Agreement
- ---------------
The Company has had a rolling 10-year full service power supply
requirements contract with the SMECO, the Company's principal
wholesale customer with a peak load of approximately 600
megawatts. The wholesale portion currently represents
approximately 10% of the Company's total kilowatt-hour sales.
76
The contract, by its terms, is 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 contract allows SMECO to reduce, by up to 20% each the
percentage of its annual requirements that it is obligated to
purchase under the contract with a five-year advance notice for
each such reduction.
On December 31, 1998, the Company and SMECO entered into a
new full-requirements agreement that supersedes their existing
rolling-10-year power supply contract. The agreement will
continue the current total rate for electricity but with a non-
varying fuel component and will become effective as of January 1,
1999, if accepted by FERC without change or modification. The
agreement will expire on December 31, 2001, following which,
SMECO will make a one-time termination payment to the Company of
$19 million which compensates the Company for future earnings it
would otherwise have received under the 10-year contract. SMECO
may elect by January 15, 2000, however, to advance the
termination date to December 31, 2000, in which case the
termination payment would be $26 million. The Company filed the
agreement with FERC for acceptance on December 31, 1998, and
expects a decision during the first quarter of 1999. In light of
the information contained in the following paragraph, it
currently is anticipated that SMECO will elect a December 31,
2000 termination date. The Company will record the applicable
termination payment as income upon acceptance of the agreement by
FERC. After the termination date, capacity previously used to
supply SMECO would be used to serve the Company's retail
customers. To the extent the Company makes sales of such
capacity in the competitive marketplace, such sales would be used
to offset costs otherwise charged to retail customers.
Accordingly, applicable costs are expected to be fully recovered
in rates charged to retail customers under historical rate making
principles.
On January 25, 1999, a wholly owned unregulated subsidiary
of PCI, signed a contract with SMECO to supply SMECO's full
requirements for power (approximately 600 MW of peak load) during
the four year period starting January 1, 2001. This contract is
subject to acceptance by FERC of the agreement outlined in the
preceding paragraph. The subsidiary was the winning bidder in
response to SMECO's Summer 1998 call for proposals for a full
requirements provider of electricity. A firm commitment has been
secured from a third party for the delivery of power sufficient
to serve SMECO's full requirements. Both the sales commitment to
SMECO and the third party purchase agreement are at fixed prices
which do not vary with future changes in market conditions. The
subsidiary sells electricity and natural gas and also provides
energy services to commercial and industrial customers primarily
in the mid-Atlantic region. The new SMECO contract represents
the first wholesale electric power contract the subsidiary has
secured.
77
Leases
- ------
The Company leases its general office building and certain data
processing and duplicating equipment, motor vehicles,
communication system and construction equipment under long-term
lease agreements. The lease of the general office building
expires in 2002 and leases of equipment extend for periods of up
to 6 years. Charges under such leases are accounted for as
operating expenses or construction expenditures, as appropriate.
Rents, including property taxes and insurance, net of rental
income from subleases, aggregated approximately $18.4 million in
1998, $17.1 million in 1997 and $16.2 million in 1996. The
approximate annual commitments under all operating leases,
reduced by rentals to be received under subleases are $10.8
million in 1999, $7.9 million in 2000, $5.1 million in 2001, $1.6
million in 2002, $.6 million in 2003 and a total of $4.8 million
in the years thereafter.
The Company leases its consolidated control center, an
integrated energy management system used by the Company's power
dispatchers to centrally control the operation of the Company's
generating units, transmission system and distribution system.
The lease is accounted for as a capital lease, and was recorded
at the present value of future lease payments which totaled $152
million. The lease requires semi-annual payments of $7.6 million
over a 25-year period and provides for transfer of ownership of
the system to the Company for $1 at the end of the lease term.
Under SFAS No. 71, the amortization of leased assets is modified
so that the total of interest on the obligation and amortization
of the leased asset is equal to the rental expense allowed for
ratemaking purposes. This lease has been treated as an operating
lease for ratemaking purposes. Accordingly, electric plant in
service includes a regulatory asset of approximately $28 million
and $21 million at December 31, 1998 and 1997, respectively.
Fuel Contracts
- --------------
The Company has numerous coal contracts for aggregate annual
deliveries of approximately three million tons, all of which
expire by May 31, 1999. Deliveries under these contracts and the
replacement contracts are expected to provide approximately 75%
of the estimated system coal requirements in 1999. The Company
will purchase the balance of its coal requirements on a spot
basis from a variety of suppliers. Prices under the Company's
current coal contracts are generally determined by reference to
base amounts adjusted to reflect provisions for changes in
suppliers' costs, which in turn are determined by reference to
published indices and limited by current market prices.
78
Capacity Purchase Agreements
- ----------------------------
The Company's long-term capacity purchase agreements with
FirstEnergy Corp. (FirstEnergy, formerly Ohio Edison), and
Allegheny Energy, Inc. (AEI) commenced June 1, 1987, and are
expected to continue at the 450 megawatt level through 2005.
Under the terms of the agreements with FirstEnergy and AEI, the
Company is required to make capacity payments, subject to certain
contingencies, which include a share of FirstEnergy's fixed
operating and maintenance cost. The Company also has a 25-year
agreement with Panda-Brandywine, L.P. (Panda) for a 230- megawatt
gas-fueled combined-cycle cogenerator project in Prince George's
County, Maryland. In addition, the Company continues to purchase
capacity and associated energy from a municipally financed
resource recovery facility in Montgomery County, Maryland. The
capacity expense under these agreements, including an allocation
of a portion of FirstEnergy's fixed operating and maintenance
costs, was $149.8 million, $145.2 million and $120 million in
1998, 1997 and 1996, respectively. Commitments under these
agreements, are estimated at $203 million in 1999, $204 million
in 2000, $209 million in 2001, $210 million in 2002 and 2003, and
$1.2 billion in the years thereafter.
The Company began a 25-year purchase agreement in June 1990
with SMECO for 84 megawatts of capacity supplied by a combustion
turbine installed and owned by SMECO at the Company's Chalk Point
Generating Station. The Company is responsible for all costs
associated with operating and maintaining the facility. The
Company is accounting for this agreement as a capital lease,
recorded at fair market value which totaled $37.1 million at the
date construction was completed. The capacity payment to SMECO
is approximately $5.5 million per year. Under SFAS No. 71,
amortization of leased assets is modified so that the total of
interest on the obligation and amortization of the leased asset
is equal to rental expense allowed for ratemaking purposes. This
agreement has been treated as an operating lease for ratemaking
purposes. Accordingly, electric plant in service includes a
regulatory asset of approximately $9 million and $8 million at
December 31, 1998 and 1997, respectively.
Environmental Contingencies
- ---------------------------
The Company is subject to contingencies associated with
environmental matters, principally related to possible
obligations to remove or mitigate the effects on the environment
of the disposal of certain substances at the sites discussed
below.
On May 22, 1998, the State of Maryland issued final
regulations entitled "Post RACT Requirements for Nitrogen Oxides
(NOx) Sources (NOx Budget Proposal)," requiring a 65% reduction
79
in NOx emissions at the Company's Maryland generating units by
May 1, 1999. The regulations allow the purchase or trade of NOx
emission allowances to fulfill this obligation. The Company
appealed this regulation to the Circuit Court for Charles County,
Maryland on June 19, 1998, on the basis that the regulation does
not provide adequate time for the installation of NOx emission
reduction technology and that there is no functioning NOx
allowance market. On July 17, 1998, the case was moved to the
Circuit Court for Baltimore City and consolidated with a similar
appeal filed by Baltimore Gas and Electric Company. The Company
believes it is unlikely that a market containing NOx allowances
sufficient to ensure compliance will be functioning by May 1999;
presently, eight states have enacted the rules necessary to
create such a market. A preliminary plan for installing the best
available removal technology on the Company's largest coal-fired
units would require capital expenditures of approximately $170
million and would yield NOx reductions of nearly 85% beginning in
year 2004. The Company cannot predict the outcome of this
litigation and is evaluating its options in the event of an
adverse decision. Also, on September 24, 1998, the EPA issued
rules for reducing interstate transport of ozone. The Company's
preliminary plan for NOx reductions of 85% by 2004 appears to be
consistent with the EPA rules.
The Company's generating stations operate under National
Pollutant Discharge Eliminating System (NPDES) permits. A NPDES
renewal application submitted in July 1993 for the Benning
station is pending. NPDES permits were issued for the Potomac
River station in February 1994, the Morgantown station in
February 1995, the Dickerson station in August 1996 and the Chalk
Point station in September 1996. An NPDES renewal application
was submitted for the Potomac River station in August 1998.
In October 1997, the Company received notice from the EPA
that it, along with 68 other parties, may be a Potentially
Responsible Party (PRP) under the Comprehensive Environmental
Response Compensation and Liability Act (CERCLA or Superfund) at
the Butler Mine Tunnel Superfund site in Pittstown Township,
Luzerne County, Pennsylvania. The site is a mine drainage tunnel
with an outfall on the Susquehanna River where oil waste was
disposed via a borehole in the tunnel. The letter notifying the
Company of its potential liability also contained a request for a
reimbursement of approximately $.8 million for response costs
incurred by EPA at the site. The letter requested that the
Company submit a good faith proposal to conduct or finance the
remedial action contained in a July 1996 Record of Decision
(ROD). The EPA estimates the present cost of the remedial action
to be $3.7 million. While the Company cannot predict its
liability at this site, the Company believes that it will not
have a material adverse effect on its financial position or
results of operations.
80
In December 1995, the Company received notice from the EPA
that it is a PRP with respect to the release or threatened
release of radioactive and mixed radioactive and hazardous wastes
at a site in Denver, Colorado, operated by RAMP Industries, Inc.
Evidence indicates that the Company's connection to the site
arises from an agreement with a vendor to package, transport and
dispose of two laboratory instruments containing small amounts of
radioactive material at a Nevada facility. While the Company
cannot predict its liability at this site, the Company believes
that it will not have a material adverse effect on its financial
position or results of operations.
In October 1995, the Company received notice from the EPA
that it, along with several hundred other companies, may be a PRP
in connection with the Spectron Superfund Site located in Elkton,
Maryland. The site was operated as a hazardous waste disposal,
recycling, and processing facility from 1961 to 1988. A group of
PRPs allege, based on records they have collected, that the
Company's share of liability at this site is .0042%. The EPA has
also indicated that a de minimis settlement is likely to be
appropriate for this site. While the outcome of negotiations and
the ultimate liability with respect to this site cannot be
predicted, the Company believes that its liability at this site
will not have a material adverse effect on its financial position
or results of operations.
In December 1987, the Company was notified by the EPA that
it, along with several other utilities and nonutilities, is a PRP
in connection with the polychlorinated biphenyl compounds (PCBs)
contamination of a Philadelphia, Pennsylvania site owned by a
nonaffiliated company. In the early 1970's, 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)
including a number of possible remedies was submitted to the EPA.
In December 1997, the EPA signed a ROD that set forth a selected
remedial action plan with estimated implementation costs of
approximately $17 million. On June 26, 1998, the EPA issued a
unilateral Administrative Order to the Company and 12 other PRPs
to conduct the design and actions called for in the ROD. To
date, the Company has accrued $1.7 million for its share of these
costs.
Litigation
- ----------
During 1993, the Company was served with Amended Complaints filed
in three jurisdictions (Prince George's County, Baltimore City,
and Baltimore County), in separate ongoing, consolidated
proceedings each denominated "In re: Personal Injury Asbestos
Case". The Company (and other defendants) were brought into
these cases on a theory of premises liability under which
plaintiffs argue that the Company was negligent in not providing
81
a safe work environment for employees of its contractors who
allegedly were exposed to asbestos while working on the Company's
property. Initially, a total of approximately 448 individual
plaintiffs added the Company to their Complaints. While the
pleadings are not entirely clear, it appears that each plaintiff
seeks $2 million in compensatory damages and $4 million in
punitive damages from each defendant. In a related proceeding in
the Baltimore City case, the Company was served, in September
1993, with a third party complaint by Owens Corning Fiberglass,
Inc. (Owens Corning) alleging that Owens Corning was in the
process of settling approximately 700 individual asbestos-related
cases and seeking a judgment for contribution against the Company
on the same theory of alleged negligence set forth above in the
plaintiffs' case. Subsequently, Pittsburgh Corning Corp.
(Pittsburgh Corning) filed a third party complaint against the
Company, seeking contribution for the same plaintiffs involved in
the Owens Corning third party complaint. Since the initial
filings in 1993, approximately 65 additional individual suits
have been filed against the Company. The third party complaints
involving Pittsburgh Corning and Owens Corning were dismissed by
the Baltimore City Court during 1994 without any payment by the
Company. Through December 31, 1998, approximately 400 of the
individual plaintiffs have dismissed their claims against the
Company. No payments were made by the Company in connection with
the dismissals. While the aggregate amount specified in the
remaining suits would exceed $400 million, the Company believes
the amounts are greatly exaggerated as were the claims already
disposed of. The amount of total liability, if any, and any
related insurance recovery cannot be precisely determined at this
time; however, based on information and relevant circumstances
known at this time, the Company does not believe these suits will
have a material adverse effect on its financial position.
However, an unfavorable decision rendered against the Company
could have a material adverse effect on results of operations in
the year in which a decision is rendered.
The Company is involved in other legal and administrative
(including environmental) proceedings before various courts and
agencies with respect to matters arising in the ordinary course
of business. Management is of the opinion that the final
disposition of these proceedings will not have a material adverse
effect on the Company's financial position or results of
operations.
Labor Agreement
- ---------------
A new four-year Agreement between the Company and Local 1900 of
the International Brotherhood of Electrical Workers (IBEW) was
ratified on December 18, 1998, by Union members. The Agreement
provides for a general wage increase of 3% each year in 1999,
2000 and 2001, beginning February 14, 1999 and a 3% increase in
wages in the fourth year of the contract (2002) unless either
82
party elects to reopen the Agreement. The Company also agreed to
a 3% lump-sum payment for the period of January 3, 1999, to
February 14, 1999. In addition, the Agreement resolves important
issues that would arise in the event of a divestiture of the
Company's generating assets and establishes a framework for
ongoing progress towards improving management and union relations
with joint committees. At December 31, 1998, 2,286 of the
Company's 3,716 employees were represented by the IBEW.
Termination of Proposed Merger
- ------------------------------
In December 1997, the Company and Baltimore Gas and Electric
Company announced the cancellation of their proposed merger (the
Merger) to create Constellation Energy Corporation. As a result,
the Company recorded a $52.5 million non-operating charge ($32.6
million net of income tax or 28 cents per share) to write off its
cumulative deferred Merger-related costs.
83
(14) Selected Nonutility Subsidiary Financial Information
----------------------------------------------------
Selected financial information of PCI is presented below.
Subsidiary equity at December 31, 1998, and December 31, 1997,
was $243.4 million and $227 million, respectively. These amounts
include $7.8 million and $6.5 million of unrealized appreciation,
at December 31, 1998 and 1997, respectively, relating to the
marketable securities portfolio on an after-tax basis.
- -----------------------------------------------------------------
For the year ended
December 31,
1998 1997 1996
- -----------------------------------------------------------------
(Millions of Dollars)
Income
Leasing activities $ 73.3 $ 75.6 $ 91.7
Marketable securities 19.3 28.6 33.7
Energy services 28.0 6.3 -
Utility related services 14.5 16.2 7.7
Other 8.4 (1.6) (11.5)
------- ------- -------
143.5 125.1 121.6
------- ------- -------
Expenses
Interest 56.2 69.0 83.4
Operating and other 57.4 35.2 34.6
Depreciation 23.5 35.6 41.3
Income tax credit (8.7) (31.8) (54.6)
------- ------- -------
128.4 108.0 104.7
------- ------- -------
Net earnings from
nonutility subsidiary $ 15.1 $ 17.1 $ 16.9
======= ======= =======
84
Marketable Securities
- ---------------------
PCI's marketable securities, primarily preferred stocks with
mandatory redemption features, are classified as available-for-
sale for financial reporting purposes. Net unrealized gains or
losses on such securities are reflected, net of tax, in
stockholder's equity. The net unrealized gains on marketable
securities, which relate primarily to mandatory redeemable
preferred stock, are shown below:
- -----------------------------------------------------------------
December 31,
1998 1997 1996
- -----------------------------------------------------------------
(Millions of Dollars)
Market Value $ 231.1 $ 302.5 $ 377.2
Cost 219.1 292.6 375.6
------- ------- -------
Net unrealized gain $ 12.0 $ 9.9 $ 1.6
======= ======= =======
- -----------------------------------------------------------------
Included in net unrealized gains and losses are gross
unrealized gains of $12.4 million and gross unrealized losses of
$.4 million at December 31, 1998, gross unrealized gains of $13.9
million and gross unrealized losses of $4 million at December 31,
1997, and gross unrealized gains of $9.9 million and gross
unrealized losses of $8.3 million at December 31, 1996.
In determining gross realized gains and losses on sales or
maturities of securities, specific identification is used. Gross
realized gains were $4.7 million, $7.5 million and $4.7 million
in 1998, 1997 and 1996, respectively. Gross realized losses were
$2.5 million, $.6 million and $1.1 million in 1998, 1997 and
1996, respectively.
At December 31, 1998, the contractual maturities for
mandatorily redeemable preferred stock are $12.9 million within
one year, $91.8 million from one to five years, $76.2 million
from five to 10 years and $37.3 million for over 10 years.
85
Leasing Activities
- ------------------
PCI's net investment in finance leases is summarized below.
- -----------------------------------------------------------------
December 31,
1998 1997
- -----------------------------------------------------------------
(Millions of Dollars)
Rents receivable $ 555.1 $ 664.2
Estimated residual values 69.7 88.0
Less: Unearned and deferred income (225.6) (288.6)
------- -------
Investment in finance leases 399.2 463.6
Less: Deferred taxes arising from
finance leases (134.3) (119.5)
------- -------
Net investment in finance leases $ 264.9 $ 344.1
======= =======
- -----------------------------------------------------------------
Minimum lease payments receivable from finance leases,
primarily aircraft, for each of the years 1999 through 2003 are
$26.7 million, $29.5 million, $29 million, $19.3 million, and
$19.4 million, respectively. Net income from leveraged leases
was $14.7 million in 1998, $16.4 million in 1997 and $22.5
million in 1996.
Rent payments receivable from aircraft operating leases for
each of the years 1999 through 2003 are $31.2 million in 1999,
$27.7 million in 2000, $21.5 million in 2001, $2.6 million in
2002 and zero in 2003.
86
(15) Segment Information
The Company has identified the utility and nonutility business
operations as its two segments. The factors used to identify
these segments are that the Company organizes its business around
differences in products, services, and regulatory environments
and that the operating results for each segment are regularly
reviewed by the Company's chief operating decision maker in order
to make decisions about resources and assess performance.
Revenues for the utility segment are derived from the
generation, transmission, distribution and sale of electric
energy. The nonutility segment, which primarily consists of the
operations of the Company's wholly owned subsidiary, PCI, derives
its revenue from investment programs, energy-related businesses
and telecommunication services.
The following table presents information about the Company's
reportable segments for the year ended December 31, 1998, 1997
and 1996:
87
<TABLE>
General Segment Information
- ---------------------------
(Millions of Dollars)
<CAPTION>
Segment
1998 Utility Nonutility Totals
---- ---------- ---------- ----------
<S> <C> <C> <C>
Revenues $ 2,063.9 $ 143.5 $ 2,207.4
---------- ---------- ----------
Operating expenses and other 1,334.8 57.4 1,392.2
Depreciation and amortization 239.8 23.5 263.3
Income tax expense (credit) 130.5 (8.7) 121.8
---------- ---------- ----------
Operating Income 358.8 71.3 430.1
Interest Expense 147.6 56.2 203.8
---------- ---------- ----------
Net Income $ 211.2 $ 15.1 $ 226.3
========== ========== ==========
Total Assets $ 5,843.2 $ 1,086.4 $ 6,929.6
Expenditures for Assets $ 206.2 $ - $ 206.2
Segment
1997 Utility Nonutility Totals
---- ---------- ---------- ----------
Revenues $ 1,863.5 $ 125.1 $ 1,988.6
---------- ---------- ----------
Operating expenses and other 1,210.2 35.2 1,245.4
Depreciation and amortization 232.0 35.6 267.6
Income tax expense (credit) 117.7 (31.8) 85.9
---------- ---------- ----------
Operating Income 303.6 86.1 389.7
Interest Expense 138.9 69.0 207.9
---------- ---------- ----------
Net Income $ 164.7 $ 17.1 $ 181.8
========== ========== ==========
Total Assets $ 5,779.3 $ 1,167.3 $ 6,946.6
Expenditures for Assets $ 217.2 $ - $ 217.2
Segment
1996 Utility Nonutility Totals
---- ---------- ---------- ----------
Revenues $ 2,010.3 $ 121.6 $ 2,131.9
---------- ---------- ----------
Operating expenses and other 1,293.7 34.6 1,328.3
Depreciation and amortization 223.0 41.3 264.3
Income tax expense (credit) 134.1 (54.6) 79.5
---------- ---------- ----------
Operating Income 359.5 100.3 459.8
Interest Expense 139.4 83.4 222.8
---------- ---------- ----------
Net Income $ 220.1 $ 16.9 $ 237.0
========== ========== ==========
Total Assets $ 5,724.8 $ 1,363.8 $ 7,088.6
Expenditures for Assets $ 179.9 $ - $ 179.9
The Company's revenues from external customers are earned primarily within the United States
and principally all of the Company's long-lived assets are held in the United States.
In addition, there were no material transactions between segments.
Total segment assets of $6,929.6 million, $6,946.6 million, and $7,088.6 million as of
December 31, 1998, 1997 and 1996, respectively, include $243.4 million, $227 million
and $196.3 million representing the utility segment's investment in the nonutility
subsidiary and $31.4 million, $12 million and $.4 million of intersegment net receivables.
As of December 31, 1998, 1997 and 1996, respectively, these amounts are eliminated in
consolidation and therefore not reflected in the Company's total assets as recorded
on the Consolidated Balance Sheets.
88
</TABLE>
<TABLE>
(16) Quarterly Financial Summary (Unaudited)
<CAPTION>
- -------------------------------------------------------------------------------------------------------
1st 2nd 3rd 4th
Quarter Quarter Quarter Quarter Total
- -------------------------------------------------------------------------------------------------------
(Millions of Dollars, except Per Share Data)
<S> <C> <C> <C> <C> <C>
1998
Operating Revenue $ 369.8 479.4 670.2 366.7 1,886.1
Total Revenue $ 380.4 528.5 750.8 404.2 2,063.9
Operating Expenses $ 344.5 432.8 564.8 367.5 1,709.6
Operating Income $ 35.9 95.7 186.0 36.7 354.3
Net Income (Loss) $ 7.5 66.0 153.1 (.3) 226.3
Earnings (Loss) for Common Stock $ 3.4 56.0 151.1 (2.2) 208.3
Basic Earnings (Loss) per Common Share $ .03 .47 1.27 (.02) 1.76
Diluted Earnings (Loss) per Common Share $ .03 .46 1.23 (.02) 1.73
Dividends per Share $ .415 .415 .415 .415 1.66
1997
Operating Revenue $ 374.5 439.5 618.2 378.6 1,810.8
Total Revenue $ 389.1 451.0 633.0 390.4 1,863.5
Operating Expenses $ 346.8 370.4 466.5 354.4 1,538.1
Operating Income $ 42.3 80.6 166.5 36.0 325.4
Net Income (Loss) $ 23.0 50.1 136.0 (27.3) 181.8
Earnings (Loss) for Common Stock $ 18.9 46.0 131.8 (31.4) 165.3
Basic Earnings (Loss) per Common Share $ .16 .39 1.11 (.27) 1.39
Diluted Earnings (Loss) per Common Share $ .16 .38 1.07 (.27) 1.38
Dividends per Share $ .415 .415 .415 .415 1.66
1996
Operating Revenue $ 385.3 462.7 614.3 372.5 1,834.8
Total Revenue $ 436.6 501.8 658.2 413.7 2,010.3
Operating Expenses $ 392.6 406.5 491.9 370.9 1,661.9
Operating Income $ 44.0 95.3 166.3 42.8 348.4
Net Income $ 14.7 72.3 138.7 11.3 237.0
Earnings for Common Stock $ 10.6 68.1 134.6 7.1 220.4
Basic Earnings per Common Share $ .09 .57 1.14 .06 1.86
Diluted Earnings per Common Share $ .09 .56 1.09 .06 1.82
Dividends per Share $ .415 .415 .415 .415 1.66
The Company's sales of electric energy are seasonal and, accordingly,
comparisons by quarter within a year are not meaningful.
The totals of the four quarterly basic earnings per common share and diluted
earnings per common share may not equal the basic earnings per common share and
diluted earnings per common share for the year due to changes in the number of
common shares outstanding during the year and, with respect to the diluted
earnings per common share, changes in the amount of dilutive securities.
89
</TABLE>
<TABLE>
Stock Market Information
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
1998 High Low 1997 High Low
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1st Quarter $25-11/16 $23-7/16 1st Quarter $26 $23-7/8
2nd Quarter $25-7/16 $23-1/16 2nd Quarter $24-7/8 $21-1/8
3rd Quarter $26-5/8 $23-1/8 3rd Quarter $23-3/4 $21
4th Quarter $27-13/16 $24-7/8 4th Quarter $26 $21
(Close $26-5/16) (Close $25-13/16)
Shareholders at December 31, 1998: 72,607
- ------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
Selected Consolidated Financial Data
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
1998 1997 1996 1995 1994 1993 1988
- ------------------------------------------------------------------------------------------------------------------------------------
(Millions, except Per Share Data)
<S> <C> <C> <C> <C> <C> <C> <C>
Operating Revenue $ 1,886.1 1,810.8 1,834.8 1,822.4 1,790.6 1,702.4 1,349.8
Total Revenue $ 2,063.9 1,863.5 2,010.3 1,876.1 1,823.1 1,725.2 1,411.6
Operating Expenses $ 1,709.6 1,538.1 1,661.9 1,528.4 1,498.6 1,400.5 1,138.6
Net Earnings (Loss) from
Nonutility Subsidiary $ 15.1 17.1 16.9 (124.4) 19.1 25.1 27.9
Net Income $ 226.3 181.8 237.0 94.4 227.2 241.6 211.1
Earnings for Common Stock $ 208.3 165.3 220.4 77.5 210.7 225.3 201.8
Basic Common Shares Outstanding (Average) 118.5 118.5 118.5 118.4 118.0 115.6 94.4
Diluted Common Shares Outstanding (Average) 124.2 124.3 124.3 118.5 124.0 121.6 97.3
Basic Earnings (Loss) Per Common Share
Utility Operations $ 1.63 1.25 <F1 1.72 1.70 1.63 1.73 1.84
Nonutility Subsidiary $ .13 .14 .14 (1.05) .16 .22 .30
Consolidated $ 1.76 1.39 <F1 1.86 .65 1.79 1.95 2.14
Diluted Earnings (Loss)
Per Common Share
Utility Operations $ 1.61 1.24 <F1 1.69 1.70 1.60 1.70 1.82
Nonutility Subsidiary $ .12 .14 .13 (1.05) .15 .21 .29
Consolidated $ 1.73 1.38 <F1 1.82 .65 1.75 1.91 2.11
Cash Dividends Per Common Share $ 1.66 1.66 1.66 1.66 1.66 1.64 1.38
Investment in Property and Plant $ 6,657.8 6,514.1 6,321.6 6,161.1 5,974.2 5,701.5 3,945.7
Net Investment in Property
and Plant $ 4,521.2 4,486.3 4,423.2 4,400.3 4,334.4 4,167.6 2,857.0
Utility Assets $ 5,568.4 5,540.2 5,526.3 5,503.1 5,327.6 5,036.8 3,267.5
Nonutility Subsidiary Assets $ 1,086.4 1,167.4 1,365.6 1,615.0 1,674.3 1,665.1 879.0
Total Assets $ 6,654.8 6,707.6 6,891.9 7,118.1 7,001.9 6,701.9 4,146.5
Long-Term Utility Obligations
(including redeemable preferred
stock) $ 2,034.0 2,042.5 1,910.1 1,960.6 1,867.0 1,736.6 1,243.5
- ------------------------------------------------------------------------------------------------------------------------------------
<FN>
<F1>Includes ($.28) as the net effect of the write-off of merger-related costs.
</FN>
90
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000079732
<NAME> POTOMAC ELECTRIC POWER COMPANY
<SUBSIDIARY>
<NUMBER> 1
<NAME> POTOMAC CAPITAL INVESTMENT CORPORATION
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-31-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,481,200
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 391,700
<TOTAL-DEFERRED-CHARGES> 655,500
<OTHER-ASSETS> 1,126,400
<TOTAL-ASSETS> 6,654,800
<COMMON> 118,500
<CAPITAL-SURPLUS-PAID-IN> 1,011,600
<RETAINED-EARNINGS> 747,300
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,877,400
50,000
100,000
<LONG-TERM-DEBT-NET> 1,859,000
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 191,700<F1>
<LONG-TERM-DEBT-CURRENT-PORT> 45,200
0
<CAPITAL-LEASE-OBLIGATIONS> 157,600
<LEASES-CURRENT> 20,800
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,353,100<F2>
<TOT-CAPITALIZATION-AND-LIAB> 6,654,800
<GROSS-OPERATING-REVENUE> 2,063,900
<INCOME-TAX-EXPENSE> 130,500
<OTHER-OPERATING-EXPENSES> 1,579,100
<TOTAL-OPERATING-EXPENSES> 1,709,600
<OPERATING-INCOME-LOSS> 354,300
<OTHER-INCOME-NET> 19,600
<INCOME-BEFORE-INTEREST-EXPEN> 373,900
<TOTAL-INTEREST-EXPENSE> 147,600
<NET-INCOME> 226,300
18,000<F3>
<EARNINGS-AVAILABLE-FOR-COMM> 208,300
<COMMON-STOCK-DIVIDENDS> 196,600
<TOTAL-INTEREST-ON-BONDS> 139,000<F4>
<CASH-FLOW-OPERATIONS> 417,200
<EPS-PRIMARY> 1.76<F5>
<EPS-DILUTED> $1.73
<FN>
<F1>Included on the Balance Sheet in the caption "short-term debt."
<F2>Includes redeemable preferred securities of subsidiary trust.
<F3>Includes preferred stock redemption premium of $6,600.
<F4>Total annualized interest cost for all utility long-term debt and manditorily
redeemable preferred securities of subsidiary trust outstanding at December 31,
1998.
<F5>Basic earnings per share for the twelve months ended December 31, 1998 were
$1.76. Diluted earnings per share for the twelve months ended December 31,
1998 were $1.73.
</FN>
</TABLE>
Item 7
Exhibit 23
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Prospectuses
constituting parts of the Registration Statements on Form S-8 (Numbers 33-
36798, 33-53685 and 33-54197) and on Form S-3 (Numbers 33-58810, 33-61379,
333-33495 and 333-66127) of Potomac Electric Power Company of our report dated
January 25, 1999 appearing on page 38 of Exhibit 99 of the Current Report on
Form 8-K of Potomac Electric Power Company dated January 29, 1999.
/s/ PRICEWATERHOUSECOOPERS LLP
PricewaterhouseCoopers LLP
Washington, D.C.
January 29, 1999
<TABLE>
Item 7 Exhibit 12 Computation of Ratios
--------------- ----------------------------------
The computations of the coverage of fixed charges, before income taxes,
and the coverage of combined fixed charges and preferred dividends for
each of the years 1998 through 1994 on the basis of parent company operations
only, are as follows.
<CAPTION>
For The Year Ended December
-------------------------------------------------------
1998 1997 1996 1995 1994
-------------------------------------------------------
(Millions of Dollars)
<S> <C> <C> <C> <C> <C>
Net income $211.2 $164.7 $220.1 $218.8 $208.1
Taxes based on income 131.0 97.5 135.0 129.4 116.6
-------------------------------------------------------
Income before taxes 342.2 262.2 355.1 348.2 324.7
-------------------------------------------------------
Fixed charges:
Interest charges 151.8 146.7 146.9 146.6 139.2
Interest factor in rentals 23.8 23.6 23.6 23.4 6.3
-------------------------------------------------------
Total fixed charges 175.6 170.3 170.5 170.0 145.5
-------------------------------------------------------
Income before income taxes and fixed charges $517.8 $432.5 $525.6 $518.2 $470.2
====== ====== ====== ====== ======
Coverage of fixed charges 2.95 2.54 3.08 3.05 3.23
==== ==== ==== ==== ====
Preferred dividend requirements $18.0 $16.5 $16.6 $16.9 $16.5
-------------------------------------------------------
Ratio of pre-tax income to net income 1.62 1.59 1.61 1.59 1.56
-------------------------------------------------------
Preferred dividend factor $29.2 $26.2 $26.7 $26.9 $25.7
-------------------------------------------------------
Total fixed charges and preferred dividends $204.8 $196.5 $197.2 $196.9 $171.2
====== ====== ====== ====== ======
Coverage of combined fixed charges
and preferred dividends 2.53 2.20 2.66 2.63 2.75
==== ==== ==== ==== ====
</TABLE>
<TABLE>
Item 7 Exhibit 12 Computation of Ratios
--------------- ----------------------------------
The computations of the coverage of fixed charges, before income taxes,
and the coverage of combined fixed charges and preferred dividends for
each of the years 1998 through 1994 on a fully consolidated basis
are as follows.
<CAPTION>
For The Year Ended December
-------------------------------------------------------
1998 1997 1996 1995 1994
-------------------------------------------------------
(Millions of Dollars)
<S> <C> <C> <C> <C> <C>
Net income $226.3 $181.8 $237.0 $94.4 $227.2
Taxes based on income 122.3 65.6 80.4 43.7 94.0
-------------------------------------------------------
Income before taxes 348.6 247.4 317.4 138.1 321.2
-------------------------------------------------------
Fixed charges:
Interest charges 208.6 216.1 231.1 238.7 224.5
Interest factor in rentals 24.0 23.7 23.9 26.7 9.9
-------------------------------------------------------
Total fixed charges 232.6 239.8 255.0 265.4 234.4
-------------------------------------------------------
Nonutility subsidiary capitalized interest (0.6) (0.5) (0.7) (0.5) (0.5)
-------------------------------------------------------
Income before income taxes and fixed charges $580.6 $486.7 $571.7 $403.0 $555.1
====== ====== ====== ====== ======
Coverage of fixed charges 2.50 2.03 2.24 1.52 2.37
==== ==== ==== ==== ====
Preferred dividend requirements $18.0 $16.5 $16.6 $16.9 $16.5
-------------------------------------------------------
Ratio of pre-tax income to net income 1.54 1.36 1.34 1.46 1.41
-------------------------------------------------------
Preferred dividend factor $27.7 $22.4 $22.2 $24.7 $23.3
-------------------------------------------------------
Total fixed charges and preferred dividends $260.3 $262.2 $277.2 $290.1 $257.7
====== ====== ====== ====== ======
Coverage of combined fixed charges
and preferred dividends 2.23 1.86 2.06 1.39 2.15
==== ==== ==== ==== ====
</TABLE>
