SELECTED FINANCIAL DATA
(Dollars in Thousands, Except Per Share Amounts)
Year Ended December 31,
1993 1992 1991 1990 1989
- ------------------------------------------------------------------------------------------------------------------------------------
OPERATING DATA
Operating Revenues $970,607 $864,044 $855,821 $812,217 $796,614
Operating Income $164,139 $143,711 $136,410 $144,473 $137,650
Income Before Cumulative Effect of a
Change in Accounting Principle $111,076 $98,526 $80,506 $37,311 $91,308
Cumulative Effect of a Change in
Accounting for Unbilled Revenues -- -- $12,730 -- --
Net Income $111,076 $98,526 $93,236 $37,311 $91,308
Electric Sales (kWh 000) 12,280,230 11,520,811 11,460,280 11,081,211 10,828,839
Interchange Deliveries (kWh 000) 2,225,384 998,679 1,113,423 726,090 894,402
Gas Sales (mcf 000) 18,066 17,013 15,574 16,069 16,645
Gas Transported (mcf 000) 1,539 3,155 2,610 2,194 677
COMMON STOCK DATA
Earnings Per Share of Common Stock:
Before Cumulative Effect of a Change
in Accounting Principle $1.76 $1.69 $1.44 $0.60 $1.80
Cumulative Effect of a Change in
Accounting for Unbilled Revenues -- -- $0.25 -- --
Total Earnings Per Share $1.76 $1.69 $1.69 $0.60 $1.80
Dividends Declared Per
Share of Common Stock $1.54 $1.54 $1.54 $1.54 $1.51
Average Shares Outstanding (000) 57,557 53,456 50,581 47,534 46,687
Year-End Common Stock Price $23 5/8 $23 1/4 $21 1/4 $18 1/8 $20 7/8
Book Value Per Common Share $14.66 $13.77 $13.42 $12.84 $13.67
Return on Average Common Equity 12.0% 12.2% 12.4% 4.3% 13.2%
CAPITALIZATION
Variable Rate Demand Bonds (VRDB)/(1)/ $ 41,500 $ 41,500 $ 41,500 $ 41,500 $ 41,500
Long-Term Debt 736,368 787,387 770,146 741,032 662,544
Preferred Stock 168,085 176,365 136,365 136,365 136,442
Common Stockholders' Equity 862,195 745,789 706,583 614,692 642,641
------------------------------------------------------------------------
Total Capitalization with VRDB $1,808,148 $1,751,041 $1,654,594 $1,533,589 $1,483,127
------------------------------------------------------------------------
OTHER INFORMATION
Total Assets $2,593,529 $2,374,793 $2,263,718 $2,125,715 $2,028,661
Long-Term Capital Lease Obligation $23,335 $26,081 $29,337 $32,354 $2,071
Construction Expenditures/(2)/ $159,991 $207,439 $181,820 $187,823 $175,843
Internally Generated Funds (IGF)/(3)/ $108,693 $130,275 $96,081 $112,551 $106,698
IGF as a Percent of Construction Expenditures 68% 63% 53% 60% 61%
(1) Although Variable Rate Demand Bonds are classified as current liabilities,
the Company intends to use the bonds as a source of long-term financing as
discussed in Note 9 to the Consolidated Financial Statements.
(2) Excludes Allowance for Funds Used During Construction.
(3) Net cash provided by operating activities less common and preferred
dividends.
-18-
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
EARNINGS
The earnings per average share of common stock attributed to the core utility
business and nonutility subsidiaries are shown below.
1993 1992 1991
---------------------------------
Core Utility
Operations $1.73 $1.47 $1.41
Peach Bottom lawsuit settlement -- 0.21 --
Cumulative effect of a change
in accounting for unbilled revenues -- -- 0.25
---------------------------------
1.73 1.68 1.66
Nonutility subsidiaries 0.03 0.01 0.03
---------------------------------
Total $1.76 $1.69 $1.69
=================================
DIVIDENDS
On December 30, 1993, the Board of Directors declared a common stock dividend
of $0.38 1/2 per share for the fourth quarter. For 1993, dividends declared
per share of common stock were $1.54. The Board believes that the current
dividend level is appropriate, secure and sustainable. The current dividend
level represents an above average yield in comparison to alternative utility
investments of similar quality and is reflective of the Company's future
financial prospects during a period of increasing competition. At the current
yield, the dividend supports the price of the Company's stock at a level which
is competitive with the industry average as measured by the ratio of market
price per share to book value per share.
CORE UTILITY EARNINGS
The components of change from the prior year in core utility earnings per
share are shown below.
1993 vs. 1992 1992 vs. 1991
---------------------------------
Operations
Electric revenues,
net of fuel expense
Rate increases $0.31 $0.33
Sales volume and other 0.37 (0.10)
Gas revenues,
net of fuel expense 0.01 0.09
Operation and
maintenance expense (0.17) (0.08)
Depreciation (0.07) (0.08)
Effect of increased number of
average common shares (0.13) (0.09)
Other (0.06) (0.01)
---------------------------------
0.26 0.06
Peach Bottom
lawsuit settlement (0.21) 0.21
Cumulative effect of a change
in accounting for
unbilled revenues -- (0.25)
---------------------------------
$0.05 $0.02
=================================
Earnings per share from core utility operations increased by $0.26 in 1993
compared to 1992 primarily due to growth in electric revenues attributed to
higher customer base rates and a 6.6% increase in kilowatt-hour (kWh) sales.
Electric sales benefited from hotter summer weather and a 2.0% increase in the
number of customers. Electric customer base rates were raised in 1993 to
recover higher costs, including the costs of adding electric generating
capacity to meet the demand for electricity within the Company's service
territory. (Refer to Note 2 to the Consolidated Financial Statements for
additional information concerning changes in customer base rates.) The
earnings growth from higher electric revenues was partially offset by
increased non-fuel expenses, including operation and depreciation expenses,
and also by the dilutive effect on earnings per share of more common shares
outstanding. Financing requirements associated with utility plant were
principally satisfied by issuing common stock in order to strengthen the
Company's capitalization and reduce the level of financial risk.
-19-
In 1992, earnings per share from core utility operations increased by $0.06 in
comparison to 1991, primarily due to additional electric and gas revenues from
higher customer base rates. The additional base revenues from higher customer
rates were partially offset by unfavorable effects of cooler summer weather on
electric revenues, increased non-fuel expenses, and an increase in the number
of common shares outstanding.
Core utility earnings for 1992 and 1991 include earnings from one-time,
unusual items, not related to ongoing utility operations. As discussed in Note
4 to the Consolidated Financial Statements, in 1992, net income and earnings
per share were increased by $11,397,000 and $0.21, respectively, due to
settlement of a lawsuit filed by the Company concerning the 1987-1989 shutdown
of the Peach Bottom Atomic Power Station by the Nuclear Regulatory Commission.
In 1991, as discussed in Note 1 to the Consolidated Financial Statements, a
change in accounting for unbilled revenues increased net income and earnings
per share by $12,730,000 and $0.25, respectively.
As a regulated public utility, the Company may file applications for customer
rate increases with regulatory commissions having jurisdiction over the
Company's utility business in order to recover cost increase associated with
supplying electricity and gas. The process of raising customer rates has
certain risks, including the possibility that protracted hearings may result
in a lag between the time when costs rise and when prices can be adjusted.
During 1992 and 1993, the Company increased customer rates in a timely manner
by amounts sufficient to recover higher costs. Even after these rate
increases, the Company's electric rates are comparable to 1983 levels and
lower than the average of utilities in the region.
COMPETITION
In October 1992, the Energy Policy Act of 1992 (the Energy Act) was enacted.
The Energy Act enabled the Federal Energy Regulatory Commission (FERC) to
order the provision of transmission service (wheeling of electricity) for
wholesale (resale) electricity producers and also provided for the creation of
a new category of electric power producers called exempt wholesale generators
(EWGs). These provisions of the Energy Act have enhanced the ability of
utilities and non-utility generators to compete to serve resale customers
currently served by a particular utility. Partly as a result of the Energy
Act, industry-wide resale markets are experiencing increased competition. In
1993, gross electric revenues from the Company's resale business were $105.0
million or 13.0% of billed electric sales revenues.
In response to the changing environment in the electric utility industry, the
Company has modified existing strategies and also developed new strategies.
From a customer or market perspective, the Company has concluded that focusing
on growing the retail portion of the business provides the best opportunity to
meet the twin objectives of satisfying customers' needs while providing a fair
return to shareholders. In order to maintain acceptable profitability levels
while keeping customer prices competitive, the Company is stepping up efforts
to find ways of reducing costs.
To facilitate implementation of this plan, the Company has developed market
specific strategies intended to grow retail sales. The Company's retail prices
are among the lowest in the region and the Company continues to maintain high
customer favorability ratings. The Company believes it should have the ability
to offer flexible pricing in order to compete to serve large retail customers.
Such changes in pricing methods could require modification to the existing
regulatory process. In Delaware, the Governor has convened a task force "to
recommend reforms to the existing regulatory process, structure, and
organization that will improve utility efficiency and encourage utility
innovation, while assuring continued availability of utility services at
affordable and competitive prices." The task force includes representatives
from the Delaware Public Service Commission, utilities (including the
Company), industrial customers, government, and the public.
In the resale market, the Company seeks to reduce the risk associated with a
customer switching energy suppliers on short notice because providing
electricity service requires investments in capital-intensive facilities which
have long lives and require long lead-times for construction. In the Company's
most recent resale base rate case, the resale customers agreed to provide a
two-year notice for load reductions up to 30% and a five-year notice for load
reductions greater than 30%.
Prior to this agreement, Old Dominion Electric Cooperative (ODEC), a resale
customer, advised the Company that it would purchase up to 150 megawatts (MW)
from another utility, beginning January 1, 1995. The Company is continuing to
negotiate a partial-requirements service agreement (to serve the balance of
ODEC's load) and a transmission service agreement (to transport the
electricity ODEC plans to purchase) with ODEC to become effective January 1,
1995. The maximum reduction in annual non-fuel revenues that could result from
ODEC's purchase of 150 MW from another utility is estimated to be about $24
million or $0.24 per share based on projected shares outstanding in 1995. To
mitigate the potential impact of this loss of business, the Company is
pursuing off-system sales of capacity and energy, intensifying cost control
efforts, and if necessary, may apply for increases in customer rates. The
Company expects that these strategies will reduce to approximately $0.08 or
less, or possibly eliminate, the adverse earnings per share effect; however,
the ultimate effect on future earnings depends on the degree of success
experienced by the Company in implementing its strategies.
-20-
OTHER UTILITY CUSTOMER MATTERS
The Company is exploring various opportunities for increasing power sales. As
part of the Company's efforts to grow its retail business, in December 1993,
the Company offered $103.5 million to purchase the electrical system of the
City of Dover, Delaware. The City of Dover has approximately 18,500 electric
customers and annual revenues from electricity sales of about $37 million.
Although the Company expects that the impact on earnings from the potential
purchase would be minimal over the first year or two, incremental earnings are
expected once economies of scale are achieved.
In December 1992, General Motors announced plans to close its Delaware
manufacturing plant in 1996. The plant's closing could increase Delaware's
unemployment rate by one to two percentage points. The direct impact on the
Company's revenues from the loss of General Motors as a utility customer would
be a decrease in non-fuel revenues of approximately $4 million or $0.04 per
share.
COMPONENTS OF UTILITY REVENUES
Fuel and energy costs billed to customers (fuel revenues) are based on rates
in effect in fuel adjustment clauses which are adjusted periodically to
reflect cost changes and are subject to regulatory approval. Rates for
non-fuel costs billed to customers are dependent on rates determined in base
rate proceedings before regulatory commissions. Changes in non-fuel (base
rate) revenues can directly affect the earnings of the Company. Fuel revenues,
or fuel costs billed to customers, generally do not affect net income since
the expense recognized as fuel costs is adjusted to match the fuel revenues.
The amount of under- or over-recovered fuel costs is generally deferred until
it is subsequently recovered from or returned to utility customers.
Electric revenues also include interchange delivery revenues which result from
the sale of electric power to the Pennsylvania-New Jersey-Maryland
Interconnection Association (PJM Interconnection) and certain utilities. The PJM
Interconnection is an electric power pool comprised of a number of utilities
in the region, including the Company. The power pool provides both capital and
operating economies to member utilities. Interchange delivery revenues are
reflected in the calculation of rates charged to customers under fuel
adjustment clauses. Due to this ratemaking treatment, interchange delivery
revenues do not affect net income.
(A graph titled "Regional Electric Price Comparison" is displayed on page 21
of the 1993 Annual Report to Stockholders. A description of this graph is
included in the Appendix to Management's Discussion and Analysis of Financial
Condition and Results of Operations.
-21-
ELECTRIC REVENUES AND SALES
In 1993, the percentages of total billed sales revenues contributed by the
various customer classes were as follows: residential--37.9%; commercial
- --29.5%; industrial--18.7%; resale--13.0%; and other--0.9%.
Details of the changes in the various components of electric revenues are
shown below.
Comparative Increase (Decrease) from
Prior Year in Electric Revenues
(Dollars in Millions) 1993 1992
---------------------
Non-fuel (Base Rate) Revenue
Increased Rates $26.6 $27.4
Sales Volume and Other 32.2 (5.1)
Fuel Revenue 5.9 (23.8)
Interchange Delivery Revenue 30.8 (2.9)
----------------------
Total $95.5 $(4.4)
======================
The increases in non-fuel revenues shown above as "Increased Rates" of $26.6
million for 1993, and $27.4 million for 1992, resulted from the increases in
electric customer base rates discussed in Note 2 to the Consolidated Financial
Statements.
The non-fuel revenue variances shown in the above table as "Sales Volume and
Other" are attributable to changes in sales volume, sales mix, and other
factors. "Sales Volume and Other" variances for 1993 compared to 1992 were
principally due to a 6.6% increase in total kWh sold. Sales to residential,
commercial, and resale customers increased by 8.4%, 6.3% and 7.3%
respectively, mainly due to increased kWh usage during the 1993 summer cooling
season, which was hotter than normal (based on a historical 21-year average)
and much hotter than 1992. Residential and commercial sales also benefited
from increases in the number of customers served of 2.0% and 2.1%
respectively. Industrial sales increased 3.7% due to increased production
levels of certain large customers and more kWh sales to a major customer which
provides some of its own power.
Despite a 0.5% increase in total kWh sold during 1992 in comparison to 1991,
"Sales Volume and Other" variances resulted in a $5.1 million decrease in 1992
non-fuel revenues due to adverse effects of unusually cool summer weather on
revenues. Charges billed to resale and other large customers for peak demand
usage decreased, and a disproportionately lower volume of residential sales
occurred during the summer when customer rates are higher. For 1992 sales
compared to 1991, residential sales were relatively flat, but commercial and
resale sales, which were not as strongly affected by the cool summer weather,
increased by 1.3% and 1.8%, respectively, primarily due to customer growth.
Industrial sales in 1992 remained at about the 1991 level due to the slow
economic recovery.
Electric fuel revenues increased $5.9 million in 1993 due to higher kWh sales
partially offset by lower rates charged to customers under the fuel adjustment
clauses. In 1992, electric fuel revenues decreased $23.8 million due to lower
fuel adjustment clause rates.
Interchange delivery revenues increased $30.8 million in 1993 mainly due to
higher sales to the PJM Interconnection which resulted from increased demand
for electricity in the region and greater availability of the Company's
generating units. In 1992, interchange delivery revenues decreased $2.9
million due to extended maintenance outages at the Company's generating units,
which reduced potential sales to the PJM Interconnection.
GAS REVENUES, SALES, AND TRANSPORTATION
The Company earns gas revenues from the sale of gas to customers and also from
transporting gas through the Company's system for some customers who purchase
gas directly from gas producers and pipelines.
Total 1993 gas revenues increased $11.1 million from 1992 due to a $1.2
million increase in non-fuel revenues and a $9.9 million increase in fuel
revenues. Non-fuel revenues increased despite a 2.8% decrease in total cubic
feet of gas sold and transported mainly due to increased sales to firm
customers which are billed at higher rates than sales to non-firm
(interruptible) and transportation customers. Firm sales increased 1.8% due
to growth in the number of residential space-heating and commercial customers.
The $9.9 million increase in gas fuel revenues was principally attributed to
higher average fuel rates.
In 1992, total gas revenues increased $12.6 million in comparison to 1991 due
to a $7.0 million increase in non-fuel revenues and a $5.6 million increase in
fuel revenues. Non-fuel revenues increased due to $3.2 million of additional
revenue from higher customer base rates, as discussed in Note 2 to the
Consolidated Financial Statements, and due to a $3.8 million increase in sales
volume. Total cubic feet of gas sold and transported in 1992 increased 10.9%
over 1991 due to colder winter weather and new customers. Gas fuel revenues
increased $5.6 million in 1992 primarily due to higher sales and bill-credits
made to customers during 1991 for previously over-collected fuel costs.
-22-
ELECTRIC FUEL AND PURCHASED POWER EXPENSES
The components of the changes in electric fuel and purchased power expenses
are shown in the table below.
Comparative Increase (Decrease) from Prior Year in Electric Fuel and Purchased
Power Expenses
(Dollars in Millions) 1993 1992
------------------
Average Cost of Electric Fuel
and Purchased Power $(6.9) $ (9.9)
Increased (Decreased) kWh Output 39.2 (1.9)
Deferral of Energy Costs 4.2 (12.0)
-----------------
Total $36.5 $(23.8)
-----------------
In 1993, the "Average Cost of Electric Fuel and Purchased Power" decreased
$6.9 million from 1992 primarily due to addition to the electric system on
June 1, 1993 of Hay Road Unit 4, a 175 MW combined cycle unit which uses
exhaust heat from the three existing Hay Road combustion turbine units as its
energy source. Lower oil prices also contributed to the decrease. The 1992
"Average Cost of Electric Fuel and Purchased Power" decreased $9.9 million
from 1991 mainly due to lower coal and oil prices and increased power purchases
at lower prices.
The $39.2 million increase in 1993 shown as "Increased (Decreased) kWh Output"
was due to higher aggregate output from electric generating units and
purchased power. Output rose in 1993 due to greater electric sales demand in
the Company's service territory and increased interchange deliveries. In 1992,
the $1.9 million decrease in kWh output was due to extended maintenance
outages at certain generating units.
The kWh output required to serve load within the Company's service territory
is equivalent to total output less interchange deliveries. In 1993, the
Company's output for load within its service territory was provided by 46.7%
coal generation, 14.6% nuclear generation, 26.0% oil and gas generation, and
12.7% net purchased power, which consisted primarily of purchases under an
agreement with PECO Energy Company (PECO).
The variances shown in the table as "Deferral of Energy Costs" were due to
varying levels of under- and/or over-collections of fuel costs which are
subsequently recovered from or returned to utility customers.
OPERATION, MAINTENANCE, DEPRECIATION, AND INCOME TAX EXPENSES
In 1993, operation and maintenance expenses increased by $15.0 million from
1992 largely due to higher administrative and general expenses, including
increases for salaries and wages, and postretirement benefits other than
pensions due to adoption of the accounting required by Statement of Financial
Accounting Standards (SFAS) No. 106. (Refer to Note 11 to the Consolidated
Financial Statements for information on SFAS No. 106.) Although future
increases in operation and maintenance expenses are expected due to additions
of new utility plant, aging of existing utility plant, and normal inflationary
pressures, the Company is actively working to minimize any such increases.
Operation and maintenance expenses increased by $6.8 million in 1992 in
comparison to 1991 primarily due to higher maintenance outage costs for
electric generating units and due to charges for the purchase of 48 MW of
capacity which began June 1, 1992. These increases were partially offset by
decreases in administrative and general expenses, including pension cost, and
lower costs of operating and maintaining the electric transmission and
distribution systems.
Depreciation expense increased $5.6 million in 1993 and $6.7 million in 1992
principally due to additions to the electric system, which included Hay Road
Unit 4 in 1993 and a new stack for the Indian River power plant in 1992. The
1992 increase also reflects a full year's depreciation for Hay Road Unit 3
which was completed on June 1, 1991. Depreciation expense is expected to
continue to increase as new electric plant is added and capital projects for
environmental compliance are completed.
Income tax expense on operations increased $18.7 million in 1993 and $3.5
million in 1992 primarily due to higher pre-tax income. The 1993 increase also
includes $1.6 million due to the increase in the federal income tax rate from
34% to 35%, effective January 1, 1993. Due to adoption in 1993 of SFAS No.
109, "Accounting for Income Taxes," deferred charges and deferred income tax
liabilities increased $144.5 million. Cash flow and earnings were not
materially affected and are not expected to be materially affected in the
future due to anticipated recovery of the deferred tax liability through
customer rates. Refer to Note 3 to the Consolidated Financial Statements for
additional information on SFAS No. 109.
(Graphs titled "1993 Sources of Electricity" and "Electric Operation &
Maintenance Expenses per kWh sold" are displayed on page 23 of the 1993 Annual
Report to Stockholders. Descriptions of these graphs are included in the
Appendix to Management's Discussion and Analysis of Financial Condition and
Results of Operations.)
-23-
UTILITY FINANCING COSTS
Interest charges on debt of the core utility decreased $5.2 million in 1993
and $1.3 million in 1992 primarily due to lower interest rates which enabled
the Company to reduce the average cost of its outstanding long-term debt
through refinancings. The 1993 decrease in interest expense also reflects the
effect of redeeming $50 million of 10% First Mortgage Bonds on June 1, 1993
with proceeds from a public offering of common stock. The Company refinanced
$133.2 million, $255.5 million, and $85.5 million of its long-term debt in
1993, 1992, and 1991, respectively, resulting in annualized interest savings
of $7.5 million in total. The interest savings are ultimately reflected in
rates charged to utility customers.
Dividends on preferred stock increased $1.7 million in 1993 mainly because $40
million of 7 3/4% preferred stock issued in August 1992 was outstanding for
all of 1993 compared to part of 1992. In 1992, the increase in preferred
dividends due to issuance of the 7 3/4% preferred stock was largely offset by
lower dividend payments on $61.1 million of the Company's preferred stock
which has market-based dividend rates.
Allowance for equity and borrowed funds used during construction (AFUDC)
decreased $1.0 million in 1993 mainly because construction of Hay Road Unit 4
was completed on May 31, 1993, resulting in lower average construction
work-in-progress balances. AFUDC as a percentage of net income decreased from
8.3% in 1992 to 6.6% in 1993. In 1992, AFUDC increased $2.1 million from 1991,
principally due to higher average construction work-in-progress balances
attributable to construction of Hay Road Unit 4.
Due to increased common equity financing, the average number of shares of
common stock outstanding increased in 1993 and 1992. Rates charged to
customers are designed to result in sufficient revenues to offset the dilution
of earnings per share due to increased common equity financing. The adverse
effect on earnings per share of $0.13 in 1993 and $0.09 in 1992 from
additional common shares outstanding was largely offset by revenues from base
rate increases.
ENERGY SUPPLY
The Challenge 2000 Plan is the Company's strategy for providing an adequate,
reliable supply of electricity to customers at reasonable rates, while
minimizing adverse impacts on the environment. The Company's plan, which is
updated periodically, is based on forecasts of demand for electricity in the
service territory and PJM Interconnection reserve requirements. The Company's
plan combines customer energy conservation and load management programs ("Save
Some"), power purchases ("Buy Some"), and new power plants ("Build Some"). The
plan is flexible and balanced. The plan's flexibility was recently
demonstrated when the Company delayed the planned date of a power purchase by
two years due to the decision of a resale customer (ODEC) to purchase 150 MW
of its load from another utility beginning January 1, 1995.
As an electric utility, the Company must balance the potential risks of
providing too much or not enough capacity. The main risks of excess capacity
are that customer rates may become uncompetitive and regulators may not allow
the associated costs to be recovered from ratepayers. The principal risks of
inadequate capacity are reliability of service and that capacity deficiency
charges would be owed to the PJM Interconnection which requires the Company to
plan for and provide a certain capacity level.
During the past three years, the Challenge 2000 Plan has included 95 MW of
additional load reduction from energy management programs, a 48 MW capacity
purchase which began in 1992, and 297 MW of capacity from two new power
plants, Hay Road Unit 3 and Unit 4, which were completed in 1991 and 1993,
respectively. Looking forward through 2003, the Company's current plans for
meeting the demand for energy include the following:
(1) "Save Some"--Approximately 140 MW of additional load reduction from
various customer-oriented energy management programs.
(2) "Buy Some"--205 MW of capacity purchases, including 165 MW beginning in
1998 or later, and 40 MW in 1999 or later.
(3) "Build Some"--The Company has filed for a Certificate of Public
Convenience and Necessity to preserve the option of constructing by the year
2000 or later a 300 MW pulverized coal-fired baseload unit in Dorchester
County, Maryland. The power plant, as currently planned, has an estimated
construction cost of $695 million, including AFUDC.
-24-
LIQUIDITY AND CAPITAL RESOURCES
The Company's primary capital resources are internally generated funds (net
cash provided by operating activities less common and preferred dividends) and
external financings. These resources provide capital for investments in utility
plant and other capital requirements, such as repayment of maturing debt and
capital lease obligations.
Operating activities provided net cash inflows of $206.7 million in 1993,
$220.8 million in 1992, and $181.1 million in 1991. In 1992, operating cash
flow was increased by $11.4 million, net of income taxes, from receipt of a
payment for settlement of the Peach Bottom lawsuit. Common dividends paid
during 1993, 1992, and 1991 were $88.0 million, $82.0 million, and $77.1
million, respectively. These amounts represented 43%, 37%, and 43% of net cash
provided by operating activities in 1993, 1992, and 1991, respectively. The
ratio of common dividends paid per share to earnings per share was 88% in
1993, and 91% in 1992 and 1991.
Utility construction expenditures, the Company's largest capital requirement,
are affected by many factors, including growth in demand for electricity,
compliance with environmental regulations, and the need for improvement and
replacement of existing facilities. Utility construction expenditures were
$160.0 million in 1993, $207.4 million in 1992, and $181.8 million in 1991.
Construction expenditures decreased $47.4 million in 1993 primarily because
construction of Hay Road Unit 4 was completed in May 1993. Construction
expenditures in 1993 included $9.2 million for projects attributed to
environmental compliance. Internally generated funds provided 68%, 63%, and 53%
of the cash required for construction in 1993, 1992, and 1991, respectively.
Capital raised from financial markets during 1991-1993, net of $557 million of
refinancings and redemptions, consisted of $229 million of common stock, $32
million of preferred stock, and $20 million of long-term debt. After considering
the costs associated with issuing and refinancing debt and equity securities
during 1991-1993 of approximately $37 million, the net amount of capital raised
from external financings during this period was $244 million.
Sales of various equity interests in leveraged leases by the Company's
nonutility subsidiaries resulted in a $21.5 million cash inflow during 1993.
The Company issued $158.2 million of long-term debt in 1993 at an average
interest rate of 6.0% and redeemed $184.2 million of long-term debt which had
an average interest rate of 8.1%. Debt refinancings in 1993 also included
$15.5 million of variable rate demand bonds which were refinanced with similar
bonds that have more favorable terms and an additional 14 years until
maturity. The Company also refinanced its 7.88% and 7.84% series of preferred
stock, $28.28 million in total, with $20 million of 6 3/4% preferred stock,
and cash. The Company issued $109.5 million of common stock in 1993, including
$77.1 million from a public offering of 3,300,000 shares in March 1993. Book
value per share of common stock increased from $13.77 as of December 31, 1992,
to $14.66 as of December 31, 1993. Approximately 70(cents) of the 89(cents)
increase resulted from the sale of common stock at prices exceeding book
value. The Company's capital structure as of December 31, 1993 and 1992
expressed as a percentage of total capitalization is shown below.
1993 1992
-------------------
Long-term debt and variable
rate demand bonds 43.0% 47.3%
Preferred stock 9.3% 10.1%
Common stockholders' equity 47.7% 42.6%
Capital requirements for the period 1994-1995 are estimated to be $395 million,
including $25 million for maturity of First Mortgage Bonds in 1994 and $334
million for utility construction, excluding AFUDC. The estimate of 1994-1995
utility construction requirements includes $44 million of environmental
construction expenditures primarily related to plans for compliance with
provisions of the Clean Air Act. During 1996-1998, an additional $65 million of
construction expenditures (excluding AFUDC) related to compliance with
environmental regulations are planned.
The Company anticipates that $250 million will be generated internally (net of
common and preferred dividends) during 1994-1995. Forecasted internally
generated funds for 1994-1995 represent 63% of estimated capital requirements
and 75% of estimated utility construction expenditures. The balance is expected
to be externally financed. During 1994-1995, long-term external financings are
presently estimated at $140 million, including $90 million of long-term debt and
$50 million (market value) of common stock.
After a recent review of the electric utility industry, bond rating agencies
adopted more stringent rating guidelines for electric utilities due to increased
risk associated with competition and other factors. The higher standards could
potentially result in increased borrowing costs for the industry in general.
Moody's and Duff & Phelps maintained their ratings of the Company's senior
secured debt as "A2" and "A+," respectively. Standard & Poor's lowered its
rating of the Company's senior secured debt to "A" from "A+." The Company
views positively the relatively minimal movement in ratings of its senior
secured debt after considering the higher standards adopted by the rating
agencies.
(A graph titled "Internally Generated Funds & Construction Expenditures" is
displayed on page 25 of the 1993 Annual Report to Stockholders. A description of
this graph is included in the Appendix to Management's Discussion and Analysis
of Financial Condition and Results of Operations.)
-25-
NONUTILITY SUBSIDIARIES
Information on the Company's nonutility subsidiaries, in addition to the
following discussion, can be found in Notes 1 and 16 to the Consolidated
Financial Statements.
Nonutility subsidiaries earned $0.03 per share in 1993 primarily due to
after-tax gains on sales of equity and residual value interests in leveraged
leases. Earnings also reflect income from ongoing leveraged leasing
operations, operating services (management and operation of power plants), and
landfill and waste hauling activities. Such income was offset by
administrative and general expenses.
Nonutility subsidiaries earned $0.01 per share in 1992 primarily due to
earnings from leveraged leases, operating services, and other businesses.
These earnings were largely offset by an operating loss for landfill and waste
hauling activities and by administrative and general expenses.
In 1991, the nonutility subsidiaries earned $0.03 per share. Gains from sales
of purchase options on leveraged leases, which contributed $0.07 to 1991
earnings per share, were partly offset by an operating loss for landfill and
waste hauling activities, accruals for potential settlements of litigation,
and administrative and general expenses.
One of the nonutility subsidiaries leases five aircraft, in total, to Northwest
Airlines, Inc.; Singapore Airlines Limited; and Express Airlines I, Inc. as
part of its leveraged leasing business. The airline industry continues to be
intensely competitive and certain airlines, which are not lessees of the
Company's subsidiaries, have filed for protection under the bankruptcy laws.
The Company's aircraft lessees are current on their lease payments.
In 1993, total subsidiary revenues, including gains, were $37.6 million
compared to $14.4 million in 1992. The revenue increase was mainly due to the
transfer of the contract for operation and maintenance of the Delaware City
Power Plant (owned by Star Enterprise) from the parent company to a nonutility
subsidiary.
-26-
REPORT OF MANAGEMENT
Management is responsible for the information and representations contained
in the Company's financial statements. Our financial statements have been
prepared in conformity with generally accepted accounting principles, based
upon currently available facts and circumstances and management's best
estimates and judgments of the expected effects of events and transactions.
Delmarva Power & Light Company maintains a system of internal controls
designed to provide reasonable, but not absolute, assurance of the reliability
of the financial records and the protection of assets. The internal control
system is supported by written administrative policies, a program of internal
audits, and procedures to assure the selection and training of qualified
personnel.
Coopers & Lybrand, independent accountants, are engaged to audit the financial
statements and express their opinion thereon. Their audits are conducted in
accordance with generally accepted auditing standards which include a review
of selected internal controls to determine the nature, timing, and extent of
audit tests to be applied.
The Audit Committee of the Board of Directors, composed of outside directors
only, meets with management, internal auditors, and independent accountants to
review accounting, auditing, and financial reporting matters. The independent
accountants are appointed by the Board on recommendation of the Audit
Committee, subject to stockholder approval.
Howard E. Cosgrove
Chairman of the Board, President and
Chief Executive Officer
Barbara S. Graham
Vice President and
Chief Financial Officer
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders
Delmarva Power & Light Company
Wilmington, Delaware
We have audited the accompanying consolidated balance sheets and statements of
capitalization of Delmarva Power & Light Company and Subsidiary Companies as of
December 31, 1993 and 1992, and the related consolidated statements of income,
changes in common stockholders' equity, and cash flows for each of the three
years in the period ended December 31, 1993. 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 in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatements. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Delmarva Power &
Light Company and Subsidiary Companies as of December 31, 1993 and 1992, and
the consolidated results of their operations and their cash flows for each of
the three years in the period ended December 31, 1993 in conformity with
generally accepted accounting principles.
As discussed in Notes 1, 3 and 11, respectively, to the consolidated financial
statements, in 1991 the Company changed its method of accounting for unbilled
revenues and in 1993 changed its method of accounting for income taxes and
postretirement benefits other than pensions.
Coopers & Lybrand
2400 Eleven Penn Center
Philadelphia, Pennsylvania
February 4, 1994
-27-
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
(Dollars in Thousands) 1993 1992 1991
- -------------------------------------------------------------------------------------------------------------
Operating Revenues
Electric $875,663 $780,175 $784,599
Gas 94,944 83,869 71,222
-----------------------------------
970,607 864,044 855,821
-----------------------------------
Operating Expenses
Electric fuel and purchased power 298,307 261,784 285,595
Gas purchased 53,631 43,797 38,140
Operation and maintenance 248,052 233,038 226,240
Depreciation 100,929 95,285 88,610
Taxes other than income taxes 37,419 37,037 34,918
Income taxes 68,130 49,392 45,908
-----------------------------------
806,468 720,333 719,411
-----------------------------------
Operating Income 164,139 143,711 136,410
-----------------------------------
Other Income
Nonutility Subsidiaries
Revenues and gains 37,636 14,397 15,448
Expenses including interest and income taxes (35,828) (13,908) (14,170)
-----------------------------------
Net earnings of nonutility subsidiaries 1,808 489 1,278
Allowance for equity funds used during construction 5,309 5,631 4,199
Other income, net of income taxes 511 12,855 4,042
-----------------------------------
7,628 18,975 9,519
-----------------------------------
Income Before Utility Interest Charges 171,767 162,686 145,929
-----------------------------------
Utility Interest Charges
Debt 60,431 65,667 66,952
Other 3,664 2,570 1,907
Allowance for borrowed funds used during construction (3,404) (4,077) (3,436)
-----------------------------------
60,691 64,160 65,423
-----------------------------------
Earnings
Income before cumulative effect of a change in accounting principle 111,076 98,526 80,506
Cumulative effect of a change in accounting for unbilled revenues -- -- 12,730
-----------------------------------
Net income 111,076 98,526 93,236
Dividends on preferred stock 10,002 8,349 7,977
-----------------------------------
Earnings applicable to common stock $101,074 $ 90,177 $ 85,259
===================================
Average Shares of Common Stock Outstanding (000) 57,557 53,456 50,581
Earnings Per Average Share of Common Stock
Before cumulative effect of a change in accounting principle $1.76 $1.69 $1.44
Cumulative effect of a change in accounting for unbilled revenues -- -- 0.25
-----------------------------------
Total earnings per share $1.76 $1.69 $1.69
===================================
Dividends Declared Per Share of Common Stock $1.54 $1.54 $1.54
See accompanying Notes to Consolidated Financial Statements.
-28-
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands) Year Ended December 31,
1993 1992 1991
- -------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $111,076 $98,526 $93,236
Adjustments to reconcile net income to
net cash provided by operating activities
Depreciation and amortization 112,926 105,624 99,313
Allowance for equity funds used during construction (5,309) (5,631) (4,199)
Investment tax credit adjustments, net (2,515) (2,417) (2,844)
Deferred income taxes, net (1,171) 10,749 12,870
Net change in:
Accounts receivable (15,851) (4,384) (26,528)
Inventories 5,314 9,696 (171)
Accounts payable (3,749) 8,779 (12,428)
Other current assets & liabilities/(1)/ 11,441 (680) 22,338
Other, net (5,438) 491 (462)
---------------------------------------------------
Net cash provided by operating activities 206,724 220,753 181,125
---------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Construction expenditures, excluding AFUDC (159,991) (207,439) (181,820)
Allowance for borrowed funds used during construction (3,404) (4,077) (3,436)
Change in working capital for construction 3,123 (9,823) 14,538
Cash flows from leveraged leases
Sale of interests in leveraged leases 21,542 -- 5,375
Insurance proceeds from casualty loss -- 4,115 --
Other 1,511 1,858 4,750
Investment in subsidiary projects and operations (2,827) (7,013) (4,504)
Net (increase)/decrease in bond proceeds held in trust funds 1,152 6,076 (205)
Deposits to nuclear decommissioning trust funds (2,657) (3,770) (1,831)
Sale of utility plant and inventory -- -- 4,733
Other, net (389) (2,677) (1,332)
---------------------------------------------------
Net cash used by investing activities (141,940) (222,750) (163,732)
---------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends: Common (87,989) (81,986) (77,097)
Preferred (10,042) (8,492) (7,947)
Issuances: Long-term debt/(2)/ 148,200 273,335 117,000
Variable rate demand bonds 15,500 -- --
Common stock 109,463 32,200 87,900
Preferred stock 20,000 40,000 --
Redemptions: Long-term debt (184,206) (257,178) (86,794)
Variable rate demand bonds (15,500) -- --
Common stock (748) (259) --
Preferred stock (28,280) -- --
Principal portion of capital lease payments (9,956) (10,339) (10,593)
Net change in term loan 10,000 -- --
Net change in short-term debt (17,000) 5,950 (12,250)
Cost of issuances and refinancings (13,097) (16,187) (7,900)
---------------------------------------------------
Net cash provided/(used) by financing activities (63,655) (22,956) 2,319
---------------------------------------------------
Net change in cash and cash equivalents 1,129 (24,953) 19,712
Beginning of year cash and cash equivalents 21,888 46,841 27,129
---------------------------------------------------
End of year cash and cash equivalents $23,017 $21,888 $46,841
===================================================
(1) Other than debt and deferred income taxes classified as current.
(2) Excluding net change in term loan.
See accompanying Notes to Consolidated Financial Statements.
-29-
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands) As of December 31,
1993 1992
- -------------------------------------------------------------------------------------
ASSETS
Utility Plant--At Original Cost
Electric $2,561,507 $2,345,869
Gas 176,167 163,139
Common 122,182 127,852
---------------------------------
2,859,856 2,636,860
Less: Accumulated depreciation 989,351 929,869
---------------------------------
Net utility plant in service 1,870,505 1,706,991
Construction work-in-progress 91,001 187,844
Leased nuclear fuel, at amortized cost 33,905 36,782
---------------------------------
1,995,411 1,931,617
---------------------------------
Investments and Nonutility Property
Investment in leveraged leases 50,914 72,858
Funds held by trustee 17,577 15,274
Other investments and nonutility property, net 55,248 59,163
---------------------------------
123,739 147,295
---------------------------------
Current Assets
Cash and cash equivalents 23,017 21,888
Accounts receivable
Customers 98,472 88,499
Other 18,405 12,527
Inventories, at average cost
Fuel (coal, oil, and gas) 27,335 32,624
Materials and supplies 37,687 39,055
Prepayments 9,534 7,907
Deferred income taxes, net 10,713 8,236
---------------------------------
225,163 210,736
---------------------------------
Deferred Charges and Other Assets
Unamortized debt expense 11,222 11,219
Deferred debt refinancing costs 28,794 22,510
Deferred recoverable plant costs 15,613 15,019
Deferred recoverable income taxes 144,463 --
Other 49,124 36,397
---------------------------------
249,216 85,145
---------------------------------
Total $2,593,529 $2,374,793
=================================
See accompanying Notes to Consolidated Financial Statements.
-30-
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands) As of December 31,
1993 1992
- ----------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES
Capitalization (See Statements of Capitalization)
Common stock, $2.25 par value; 90,000,000 shares authorized;
shares outstanding: 1993--58,829,283, 1992--54,143,853 $ 132,366 $ 121,824
Additional paid-in capital 470,997 374,976
Retained earnings 259,507 249,176
Unearned compensation (675) (187)
------------------------------------
Total common stockholders' equity 862,195 745,789
Preferred stock 168,085 176,365
Long-term debt 736,368 787,387
------------------------------------
1,766,648 1,709,541
------------------------------------
Current Liabilities
Short-term debt -- 17,000
Long-term debt due within one year 25,986 946
Variable rate demand bonds 41,500 41,500
Accounts payable 55,175 56,389
Taxes accrued 10,987 11,593
Interest accrued 15,522 15,190
Dividends declared 22,664 20,900
Current capital lease obligation 12,684 12,709
Deferred energy costs 14,229 7,933
Other 32,681 25,265
------------------------------------
231,428 209,425
------------------------------------
Deferred Credits and Other Liabilities
Deferred income taxes, net 497,457 352,474
Deferred investment tax credits 49,475 51,990
Long-term capital lease obligation 23,335 26,081
Other 25,186 25,282
------------------------------------
595,453 455,827
------------------------------------
Commitments and Contingencies (Notes 12, 13, and 14) -- --
------------------------------------
Total $2,593,529 $2,374,793
====================================
See accompanying Notes to Consolidated Financial Statements.
-31-
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Dollars in Thousands) As of December 31,
1993 1992
- -----------------------------------------------------------------------------------------------------------------------
COMMON STOCKHOLDERS' EQUITY
Total common stockholders' equity/(1)/ $ 862,195 $ 745,789
------------------------------
CUMULATIVE PREFERRED STOCK
Par value $1 per share, 10,000,000 shares authorized, none issued --- ---
Par value $25 per share, 3,000,000 shares authorized,
7 3/4% Series, 1,600,000 shares issued/(2)/ 40,000 40,000
Par value $100 per share, 1,800,000 shares authorized:
Current call
Series Shares outstanding price per share
- -------------------------------------------------------------------------------
(1993 and 1992)
3.70%-5% 320,000 and 320,000 $103.00-$105.00 32,000 32,000
6 3/4% 200,000 and 0 /(3)/ 20,000 ---
7.52% 150,000 and 150,000 $103.50 15,000 15,000
7.84%-7.88% 0 and 282,800 --- --- 28,280
Adjustable---5.54%, 5.83%/(4)/ 160,850 and 160,850 $103.00 16,085 16,085
Auction rate---2.71%, 3.05%/(4)/ 450,000 and 450,000 $100.00 45,000 45,000
------------------------------
168,085 176,365
------------------------------
LONG-TERM DEBT
First Mortgage Bonds:
12/31/93 12/31/92
Maturity Interest Rates Interest Rates
- -------------------------------------------------------------------------------
1994 4 5/8% 4 5/8% 25,000 25,000
1997 6 3/8% 6 3/8% 25,000 25,000
1998 --- 7% --- 25,000
2002-2003 6.40%-6.95% 6.95%-8% 120,000 120,000
2004 --- 6.60% --- 18,200
2014-2015 7.30%-8.15% 7.30%-8.15% 81,000 81,000
2018-2022 5.90%-8.50% 6.75%-10% 208,200 240,000
2032 6.05% --- 15,000 ---
------------------------------
474,200 534,200
Other Bonds, due 2011-2017, 7.15%-7.50% 54,500 54,500
Pollution Control Notes:
Series 1973, due 1994-1998, 5.75% 6,500 6,650
Series 1976, due 1994-2006, 7 1/8%-7 1/4% 3,300 3,400
Medium Term Notes, due 1998, 5.69% 25,000 ---
Medium Term Notes, due 1999, 7 1/2% 30,000 30,000
Medium Term Notes, due 2002-2004, 8.30%-9.29% 39,000 39,000
Medium Term Notes, due 2007, 8 1/8% 50,000 50,000
Medium Term Notes, due 2020-2021, 8.96%-9.95% 61,000 61,000
First Mortgage Notes, 9.65%/(5)/ 8,244 8,809
Term Loan, due 1996, 3.27%/(6)/ 10,000 ---
Other Obligations, due 1994-2000, 8.5% 1,307 1,497
Unamortized premium and discount, net (697) (723)
Current maturities of long-term debt (25,986) (946)
------------------------------
Total long-term debt 736,368 787,387
------------------------------
Total capitalization 1,766,648 1,709,541
------------------------------
Variable Rate Demand Bonds/(7)/ 41,500 41,500
------------------------------
Total capitalization with Variable Rate Demand Bonds $1,808,148 $1,751,041
==============================
(1) Refer to Consolidated Statements of Changes in Common Stockholders' Equity
for additional information.
(2) Redeemable beginning September 30, 2002, at $25 per share.
(3) Redeemable beginning November 1, 2003, at $100 per share.
(4) Average rates during 1993 and 1992, respectively.
(5) Repaid through monthly payments of principal and interest over 15 years
ending November 2002.
(6) Refer to item 7 of Note 9 to the Consolidated Financial Statements.
(7) Classified under current liabilities as discussed in item 9 of Note 9 to the
Consolidated Financial Statements.
See accompanying Notes to Consolidated Financial Statements.
-32-
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCKHOLDERS' EQUITY
(Dollars in Thousands)
Common Additional Unearned
Shares Par Paid-in Retained Treasury Compen-
Outstanding Value/(1)/ Capital Earnings Stock sation Total
- --------------------------------------------------------------------------------------------------------------------------------
Balance as of January 1, 1991 47,889,358 $107,751 $271,694 $235,247 -- -- $614,692
Net income 93,236 93,236
Cash dividends declared
Common stock ($1.54) (78,937) (78,937)
Preferred stock (7,977) (7,977)
Issuance of common stock
Public offering 3,500,000 7,875 56,000 63,875
DRIP/(2)/ 1,126,802 2,535 18,640 21,175
Stock options 150,450 339 2,471 2,810
Other issuance 2,354 5 35 40
Expenses (2,331) (2,331)
-----------------------------------------------------------------------------------------
Balance as of December 31, 1991 52,668,964 118,505 346,509 241,569 -- -- 706,583
Net income 98,526 98,526
Cash dividends declared
Common stock ($1.54) (82,570) (82,570)
Preferred stock (8,349) (8,349)
Issuance of common stock
DRIP/(2)/ 1,336,871 3,008 26,471 29,479
Stock options 129,500 292 2,256 2,548
Other issuance 8,518 19 154 173
Expenses of common and preferred
stock issuances (414) (414)
Reacquired shares (12,490) (259) (259)
Shares granted/(3)/ 12,490 259 (259) --
Amortization of unearned compensation 72 72
-----------------------------------------------------------------------------------------
Balance as of December 31, 1992 54,143,853 121,824 374,976 249,176 -- (187) 745,789
Net income 111,076 111,076
Cash dividends declared
Common stock ($1.54) (89,792) (89,792)
Preferred stock (10,002) (10,002)
Issuance of common stock
Public offering 3,300,000 7,425 69,713 77,138
DRIP/(2)/ 1,246,380 2,804 26,519 29,323
Stock options 139,050 313 2,689 3,002
Expenses (2,627) (2,627)
Reacquired shares (31,490) (748) (748)
Shares granted/(3)/ 31,490 748 (748) --
Amortization of unearned compensation 260 260
Refinancing of preferred stock (273) (951) (1,224)
-----------------------------------------------------------------------------------------
Balance as of December 31, 1993 58,829,283 $132,366 $470,997 $259,507 -- $ (675) $862,195
=========================================================================================
/(1)/ The Company's common stock has a par value of $2.25 per share and
90,000,000 shares are authorized.
/(2)/ Dividend Reinvestment and Common Share Purchase Plan (DRIP) -- As
of December 31, 1993, 2,818,536 shares were reserved for issuance through
the DRIP.
/(3)/ Shares of restricted common stock granted under the Company's Long Term
Incentive Plan.
See accompanying Notes to Consolidated Financial Statements.
-33-
1. SIGNIFICANT ACCOUNTING POLICIES
NATURE OF BUSINESS
The Company is predominantly a public utility that provides electric service
on the Delmarva Peninsula in an area consisting of about 5,700 square miles
with a population of approximately 1.0 million. The Company also provides gas
service in an area consisting of about 275 square miles with a population of
approximately 457,000 in northern Delaware, including the City of Wilmington.
In addition, the Company has wholly owned subsidiaries engaged in nonutility
activities.
REGULATION OF UTILITY OPERATIONS
The Company is subject to regulation with respect to its retail utility sales
by the Delaware and Maryland Public Service Commissions (DPSC and MPSC,
respectively) and the Virginia State Corporation Commission (VSCC), which have
broad powers over rate matters, accounting, and terms of service. Gas sales
are subject to regulation by the DPSC. The Federal Energy Regulatory
Commission (FERC) exercises jurisdiction with respect to the Company's
accounting systems and policies, and the wholesale (resale) transmission and
sale of electric energy. FERC also regulates the price and other terms of
transportation of natural gas purchased by the Company. The percentage of
utility operating revenues regulated by each Commission for the year ended
December 31, 1993 was as follows: DPSC 64%, MPSC 22%, VSCC 3%, and FERC 11%.
In conformity with generally accepted accounting principles, the Company's
accounting policies reflect the financial effects of rate regulation and
decisions issued by regulatory commissions having jurisdiction over the
Company's utility business. In accordance with the provisions of Statement of
Financial Accounting Standards No. 71, "Accounting for the Effects of Certain
Types of Regulation," the Company defers expense recognition of certain costs
("deferred charges"). Deferred charges are subsequently amortized to expense
over the period that the cost is recovered through customer rates.
REPORTING OF SUBSIDIARIES
The consolidated financial statements include the accounts of the Company and
its wholly owned subsidiaries--Delmarva Energy Company; Delmarva Industries,
Inc.; Delmarva Services Company; and Delmarva Capital Investments, Inc. and
its subsidiaries. The results of operations of the Company's nonutility
subsidiaries are reported in the consolidated statements of income as "Other
income." Refer to Note 16 to the Consolidated Financial Statements for
financial information about the Company's subsidiaries.
UTILITY REVENUES
Prior to 1991, the Company recorded revenues as billed to its customers on a
monthly cycle billing basis. At the end of each month, there was an amount of
unbilled electric and gas service that had been rendered from the last meter
reading to the month-end. Effective January 1, 1991, the Company began
recording non-fuel (base rate) revenues for services provided but not yet
billed to more closely match revenues with expenses. The cumulative effect of
the one-time change in accounting for unbilled revenues increased 1991 net
income by $12,730,000 ($0.25 per share).
When interim rates are placed in effect subject to refund, the Company
recognizes revenues based on expected final rates.
FUEL EXPENSE
Fuel costs charged to the Company's results of operations are generally
adjusted to match fuel costs included in customer billings (fuel revenues).
The difference between fuel revenues and actual fuel costs incurred is
reported on the balance sheet as "deferred energy costs." The deferred balance
is subsequently recovered from or returned to utility customers.
The Company's share of nuclear fuel at the Peach Bottom Atomic Power Station
(Peach Bottom) and the Salem Nuclear Generating Station (Salem) is financed
through a contract which is accounted for as a capital lease. Nuclear fuel
costs, including a provision for the future disposal of spent nuclear fuel,
are charged to fuel expense on a unit of production basis.
DEPRECIATION EXPENSE
The annual provision for depreciation on utility property is computed on the
straight-line basis using composite rates by classes of depreciable property.
The relationship of the annual provision for depreciation for financial
accounting purposes to average depreciable property was 3.7% for 1993, 3.6%
for 1992, and 3.7% for 1991. Depreciation expense includes a provision for the
Company's share of the estimated cost of decommissioning (decontaminating and
removing) nuclear power plant reactors based on amounts billed to customers
for such costs. Refer to Note 6 to the Consolidated Financial Statements for
information on nuclear decommissioning.
INTEREST EXPENSE
The amortization of debt discount, premium, and expense, including refinancing
expenses, is included in other interest charges. On a consolidated basis,
total interest charges incurred were $65,421,000 in 1993, $70,156,000 in 1992,
and $72,456,000 in 1991.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
Allowance for funds used during construction (AFUDC) is included in the cost
of utility plant and represents the cost of borrowed and equity funds used to
finance construction of new utility facilities. The amount of AFUDC capitalized
is also reported in the Consolidated Statements of Income as a reduction of
interest charges for the borrowed funds component and as other income for the
equity funds component. AFUDC was capitalized on utility plant construction at
the rates of 9.6% in 1993 and 1992, and 9.9% in 1991.
LEVERAGED LEASES
The Company's investment in leveraged leases includes the aggregate of rentals
receivable (net of principal and interest on nonrecourse indebtedness) and
estimated residual values of the leased equipment less unearned and deferred
income (including investment tax credits). Unearned and deferred income is
recognized at a level rate of return during the periods in which the net
investment is positive.
FUNDS HELD BY TRUSTEE
Funds held by trustee generally includes deposits in the Company's external
nuclear decommissioning trusts and unexpended, restricted or tax exempt bond
proceeds. Earnings on such trust funds are also reflected in the balance.
-34-
2. BASE RATE MATTERS
Electric base rate increases were filed with regulatory commissions beginning
in October 1992 to recover higher costs associated with Hay Road Unit 4 which
was placed in service on June 1, 1993, postretirement benefit costs under SFAS
No. 106, and other items including general inflation. Base rate increases
which became effective in 1993 are summarized below.
Annualized Base Effective
Jurisdiction Revenue Increase Date
- ----------------------------------------------------------
Retail electric
Delaware(1) $24.9 million or 5.8% 06/01/93
Maryland(2) $ 7.8 million or 4.3% 04/01/93
Virginia(3) $ 1.3 million or 7.2% 10/05/93
Resale (FERC)(4) $ 1.5 million or 1.5% 06/03/93
(1) Based on a settlement agreement approved by the DPSC on October 5, 1993,
which included an 11.5% return on equity. Net of fuel savings from Hay
Road Unit 4, customer rates increased 3.7%.
(2) Based on a settlement agreement approved by the MPSC on March 26, 1993.
Although a return on equity was not specified in the settlement agreement,
the Company believes that the implied return on equity approaches 12%. Net
of fuel savings from Hay Road Unit 4, customer rates increased 2.3%.
(3) Based on a pending settlement agreement which is subject to approval by
the VSCC. The agreement reflects an 11.05% return on equity.
(4) Based on a settlement agreement which is subject to approval by the FERC.
Changes in base rates which became effective in 1992 are summarized below.
Annualized Base Effective
Jurisdiction Revenue Increase Date
- ----------------------------------------------------------
Retail electric
Delaware(1) $18.5 million or 4.3% 01/01/92
Maryland(2) $ 5.5 million or 3.3% 01/01/92
Virginia(3) $ 1.15 million or 5.1% 07/01/92
Resale (FERC)(4) $ 4.125 million or 4.4% 02/19/92
Delaware Gas(5) $ 4.1 million or 5.6% 02/02/92
(1) Included a 12.5% return on equity.
(2) A specific return on equity was not stated in the settlement agreement
approved by the MPSC.
(3) Included on 11.5% return on equity.
(4) A specific return on equity was not stated in the settlement agreement
approved by the FERC.
(5) Included a 12.5% return on equity.
-35-
3. INCOME TAXES
The Company and its wholly owned subsidiaries file a consolidated federal
income tax return. Income taxes are allocated to the Company's utility
business and subsidiaries based upon their respective taxable incomes, tax
credits, and effects of the alternative minimum tax, if any.
Prior to January 1, 1993, deferred income taxes were provided on timing
differences between the tax and financial accounting recognition of certain
income and expenses. Effective January 1, 1993, the Company adopted SFAS No.
109, "Accounting for Income Taxes," which replaced the deferred method of
income tax accounting with the liability method. Under the liability method,
deferred income tax assets and liabilities represent the tax effects of
temporary differences between the financial statement and tax bases of
existing assets and liabilities and are measured using presently enacted tax
rates. The principle effects on the Company's financial statements of adopting
SFAS No. 109 were a $144.5 million increase in net deferred tax liabilities
and a $144.5 million increase in "deferred recoverable income taxes," which is
an asset representing future recovery of the deferred taxes over the lives of
the related assets through rates charged to utility customers. These amounts
include $17.4 million of adjustments to recognize the effect of the increase
in the federal income tax rate from 34% to 35% during 1993. Deferred income
tax expense under SFAS No. 109 represents the net change during the reporting
period in the net deferred tax liability and deferred recoverable income
taxes.
Investment tax credits from regulated operations are being amortized over the
useful lives of the related utility plant. Investment tax credits associated
with leveraged leases are being amortized over the lives of the related leases
during the periods in which the net investment is positive.
-36-
COMPONENTS OF CONSOLIDATED INCOME TAX EXPENSE
(Dollars in Thousands) 1993 1992 1991
- ----------------------------------------------------------------------------------------------------------
Operation
Federal: Current $50,264 $30,819 $31,777
Deferred 7,710 11,597 8,924
State: Current 10,839 6,755 6,596
Deferred 1,832 2,638 1,455
Investment tax credit adjustments, net (2,515) (2,417) (2,844)
Other income
Federal: Current 9,398 7,559 (4,773)
Deferred (9,398) (3,482) 2,336
State: Current 287 1,369 (34)
Deferred (1,315) (4) (188)
Income taxes on cumulative effect of a
change in accounting for unbilled revenues -- -- 8,520
------------------------------------------
Total income tax expense $67,102 $54,834 $51,769
==========================================
RECONCILIATION OF EFFECTIVE INCOME TAX RATE
The amount computed by multiplying income before tax by the federal statutory
rate is reconciled below to the total income tax expense.
1993 1992 1991
(Dollars in Thousands) Amount Rate Amount Rate Amount Rate
- -----------------------------------------------------------------------------------------------------------------------------
Statutory federal income
tax expense $62,362 35% $52,142 34% $49,302 34%
Increase (decrease) due to
Depreciation not normalized 1,676 1 1,959 1 2,103 1
ITC amortization (2,832) (2) (2,780) (2) (3,456) (2)
State income taxes, net of
federal tax benefit 7,567 4 7,099 5 6,120 4
Other, net (1,671) -- (3,586) (2) (2,300) (1)
---------------------------------------------------------------------------------
Total income tax expense $67,102 38% $54,834 36% $51,769 36%
=================================================================================
COMPONENTS OF DEFERRED INCOME TAXES
The tax effect of temporary differences which give rise to the Company's net
deferred tax liability are shown below.
As of
(Dollars in Thousands) 12/31/93
- --------------------------------------------------------------------
Deferred Tax Liabilities
Utility plant basis differences
Accelerated depreciation $292,655
Other 97,530
Leveraged leases 49,339
Deferred recoverable income taxes 62,124
Other 30,630
-----------
Total deferred tax liabilities 532,278
-----------
Deferred Tax Assets
Deferred investment tax credits 17,316
Other 28,218
-----------
Total deferred tax assets 45,534
-----------
Total deferred taxes, net $486,744
===========
Valuation allowances for deferred tax assets were not material as of
December 31, 1993.
-37-
4. OTHER INCOME
The components of "Other income, net of income taxes" as presented in the
Consolidated Statements of Income are shown in the table below. Effective
January 1, 1993, the contract for operation and maintenance of the Delaware
City Power Plant (owned by Star Enterprise) was transferred from the parent
company to a nonutility subsidiary. The 1993 revenues and expenses associated
with the contract are included in the operating results of the Company's
nonutility subsidiaries as reported in Note 16 to the Consolidated Financial
Statements.
(Dollars in Thousands) 1993 1992 1991
- --------------------------------------------------------------------------------
Revenues and Income
Revenues $2,413 $14,837 $22,509
Peach Bottom lawsuit settlement -- 18,538 --
Interest, dividends, other income 2,457 2,424 3,966
Expenses
Operating and other expenses 4,793 15,326 22,192
Income tax expense (benefit) (434) 7,618 241
------------------------------------------
Net $ 511 $12,855 $ 4,042
==========================================
On July 27, 1988, the Company, Atlantic City Electric Company, and Public
Service Electric and Gas Company filed lawsuits against PECO to recover
replacement power and other costs incurred as a result of the shutdown of
Peach Bottom by the Nuclear Regulatory Commission (NRC) on March 31, 1987. The
Company's share of costs resulting from the shutdown were charged against
earnings during the period of the shutdown (March 1987 through November 1989).
On March 31, 1992, the Peach Bottom co-owners reached a settlement agreement
under which PECO paid $18,538,000 to the Company. The settlement increased
1992 net income by $11,397,000 ($0.21 per share).
5. JOINTLY OWNED PLANT
The Company's balance sheet includes its proportionate share of assets and
liabilities related to jointly owned plant. The Company's share of operating and
maintenance expenses of the jointly owned plant is included in the corresponding
expenses in the Consolidated Statements of Income. The Company is responsible
for providing its share of financing for the jointly owned facilities.
Information with respect to the Company's share of jointly owned plant as of
December 31, 1993 was as follows:
Megawatt Construction
Ownership Capability Plant in Accumulated Work in
(Dollars in Thousands) Share Owned Service Depreciation Progress
- ------------------------------------------------------------------------------------
Nuclear
Peach Bottom 7.51% 157 MW $122,955 $ 57,881 $ 6,386
Salem 7.41% 164 MW 199,737 85,077 10,584
Coal-Fired
Keystone 3.70% 63 MW 16,020 6,823 695
Conemaugh 3.72% 63 MW 17,236 7,723 8,388
Transmission Facilities Various 4,563 1,932 --
--------------------------------------
Total $360,511 $159,436 $26,053
======================================
-38-
6. NUCLEAR RECOMMISSIONING
The Company is funding its share of the estimated future cost of
decommissioning (decontaminating and removing) the Peach Bottom and Salem
nuclear reactors over the remaining lives of the plants. The Company estimates
its share of future decommissioning costs based on NRC regulations concerning
the minimum nuclear decommissioning financial assurance amount. The ultimate
cost of decommissioning the Peach Bottom and Salem nuclear reactors may exceed
the NRC minimum nuclear decommissioning financial assurance amount. This
amount is updated annually for inflation and increased in 1993 to
approximately $117 million from the Company's previous estimate of $53.7
million primarily due to higher estimated costs for disposing of low level
radioactive waste. The Company's accrued decommissioning liability, which is
reflected in the accumulated reserve for depreciation, was $29.1 million as of
December 31, 1993. External trust funds established by the Company for the
purpose of funding decommissioning costs had an aggregate balance of $17.3
million and a fair market value of $18.6 million as of December 31, 1993. The
Company is recovering, through rates charged to electric customers, nuclear
decommissioning costs based on an amount approximating the Company's previous
liability estimate of $53.7 million. Based on prior decisions by regulatory
commissions, the Company expects that customer rates will be adjusted to
provide for recovery of the Company's 1993 estimate of future decommissioning
costs of $117 million.
7. COMMON STOCK
1) The Company's Restated Certificate and Articles of Incorporation and the
Mortgage and Deed of Trust securing the Company's outstanding bonds contain
restrictions on the payment of dividends on common stock. Such restrictions
would become applicable if the Company's capital and retained earnings fall
below certain specific levels or if preferred dividends are in arrears. Under
the most restrictive of these provisions, as of December 31, 1993,
approximately $223.8 million was available for payment of common dividends.
2) Prior to January 1, 1993, the Company had a nonqualified stock option plan
for certain employees. Options were priced at the actual market value on the
grant date. Effective January 1, 1993, the Company's Board of Directors
declared that no new stock options will be granted and that the
performance-based restricted stock program will be the program under the Long
Term Incentive Plan which is in effect. Changes in stock options are
summarized below.
1993 1992 1991
Number Option Number Option Number Option
of Shares Price of Shares Price of Shares Price
- ------------------------------------------------------------------------------------------------------------------------
Beginning-of-year
balance 192,100 $17 1/2-$21 1/4 270,200 $17 1/2-$21 1/4 302,900 $17 1/2-$21 1/4
Options granted -- -- 59,900 $20 1/2 117,750 $18 1/8
Options exercised 139,050 $17 1/2-$21 1/4 129,500 $17 1/2-$21 1/4 150,450 $17 1/2-$17 3/4
Options forfeited -- -- 8,500 $21 1/4 -- --
End-of-year balance 53,050 $17 1/2-$21 1/4 192,100 $17 1/2-$21 1/4 270,200 $17 1/2-$21 1/4
Exercisable 53,050 $17 1/2-$21 1/4 132,200 $17 1/2-$21 1/4 152,450 $17 1/2-$21 1/4
8. PREFERRED STOCK
1) On November 4, 1993, the Company issued 200,000 shares of 6 3/4%, cumulative
preferred stock, $100 per share par value, for $20 million. The dividend is
cumulative and is payable quarterly. Beginning on November 1, 2003, the 6 3/4%
preferred stock will be redeemable, at any time at the option of the Company, in
whole or in part, at $100 per share plus unpaid accumulated dividends, if any.
On December 1, 1993, the Company used the proceeds and cash on-hand to redeem
$18.28 million of the Company's 7.88% preferred stock and $10.0 million of the
Company's 7.84% preferred stock.
2) On August 4, 1992, the Company issued 1,600,000 shares of 7 3/4%, cumulative
preferred stock, $25 per share par value, for $40 million.
-39-
9. DEBT
1) Substantially all utility plant of the Company now or hereafter owned is
subject to the lien of the Mortgage and Deed of Trust.
2) On June 1, 1993, $50 million of 10% First Mortgage Bonds, due December 1,
2018, were redeemed with a portion of the proceeds received from a public
offering of common stock.
3) On June 7, 1993, the Delaware Economic Development Authority issued on
behalf of the Company $15 million of 6.05% Gas Facilities Revenue Bonds
(Series A), due June 1, 2032, and also issued $18.2 million of 5.90% Pollution
Control Refunding Revenue Bonds (Series B), due June 1, 2021. The proceeds
from the Series A Bonds are being used to finance additions to the Company's
gas system. The proceeds from the Series B Bonds were used on July 8, 1993 to
redeem $18.2 million of 6.6% Pollution Control Revenue Bonds, due July 1,
2004. Both the Series A and B Bonds are collateralized by First Mortgage
Bonds and are insured.
4) On June 23, 1993, the Company issued $25 million of unsecured, 5.69% Medium
Term Notes, due June 24, 1998. The proceeds were used on July 23, 1993 to
redeem $25 million of 7% First Mortgage Bonds, due November 1, 1998.
5) On July 1, 1993, the Company issued $90 million of 6.40% First Mortgage
Bonds, due July 1, 2003. The proceeds were used on August 2, 1993 to redeem
$90 million of First Mortgage Bonds comprised of the following series: $35
million, 7 5/8% Series due 2001; $30 million, 7 1/2% Series due 2002; and $25
million, 8% Series due 2003.
6) As of December 31, 1993, the fair market value of the Company's long-term
debt was $833,502,000 in comparison to the book value of $736,368,000. As of
December 31, 1992, the fair market value of the Company's long-term debt was
$822,494,000 in comparison to the book value of $787,387,000. The fair market
value of the Company's long-term debt was estimated using discounted cash flow
calculations, based on interest rates available to the Company for debt with
similar terms, maturities, and credit worthiness.
7) As of December 31, 1993, the Company had $125 million of bank lines of
credit, including $50 million of such credit lines under which the Company may
convert short-term borrowings to a term loan maturing on July 31, 1996 (or
earlier at the discretion of the Company). As of December 31, 1993, $10
million of short-term borrowings by the Company were classified as long-term
debt ("Term Loan") in recognition of the long-term financing capability
provided by the credit lines. The Company is generally required to pay
commitment fees for its credit lines. The lines of credit are periodically
reviewed by the Company, at which time they may be renewed or cancelled.
8) Maturities of long-term debt and sinking fund requirements during the next
five years are as follows: 1994--$26,486,000; 1995--$1,346,000;
1996--$11,422,000; 1997--$26,510,000; 1998--$32,239,000.
9) A total of $41.5 million of Variable Rate Demand Bonds were outstanding as
of December 31, 1993 and 1992, respectively. Although Variable Rate Demand
Bonds are classified as current liabilities, the Company intends to use the
Variable Rate Demand Bonds as a source of long-term financing by setting the
bonds' interest rates at market rates and, if advantageous, by utilizing one
of the fixed rate/fixed term conversion options of the bonds. The bonds are
due on demand or at maturity in the years 2017 and 2028 for principal amounts
of $26.0 million and $15.5 million, respectively. During 1993, $15.5 million
of Variable Rate Demand Bonds due in 2014 were refinanced with like bonds due
in 2028. Average annual interest rates on the Variable Rate Demand Bonds were
2.5% in 1993.
-40-
10. PENSION PLAN
The Company has a defined benefit pension plan covering all regular employees.
The benefits are based on years of service and the employee's compensation.
The Company's funding policy is to contribute each year the net periodic
pension cost for that year. However, the contribution for any year will not be
less than the minimum required contribution nor greater than the maximum tax
deductible contribution. There were no pension contributions in 1993, 1992, or
1991. Pension plan assets consist primarily of equity securities and public
bond securities.
The following schedules show the funded status of the plan, the components of
pension cost, and assumptions.
RECONCILIATION OF FUNDED STATUS OF THE PLAN As of December 31,
(Dollars in Thousands) 1993 1992
- -----------------------------------------------------------------------------------------------------------------------
Accumulated benefit obligation
Vested $ 236,209 $218,776
Nonvested 25,721 22,699
-------------------------------------------
261,930 241,475
Effect of estimated future compensation increases 123,562 112,941
-------------------------------------------
Projected benefit obligation 385,492 354,416
Plan assets at fair value 521,897 475,690
-------------------------------------------
Excess of plan assets over projected benefit obligation 136,405 121,274
Unrecognized prior service cost 19,255 18,988
Unrecognized net gain (108,183) (93,407)
Unrecognized net transition asset (36,455) (39,769)
-------------------------------------------
Prepaid pension cost $ 11,022 $ 7,086
===========================================
Year Ended December 31,
COMPONENTS OF NET PENSION COST 1993 1992 1991
- -----------------------------------------------------------------------------------------------------------------------
(Dollars in Thousands)
Service cost--benefits earned during period $13,152 $12,606 $ 9,815
Interest cost on projected benefit obligation 26,411 24,261 21,909
Actual return on plan assets (58,247) (39,104) (96,302)
Net amortization and deferral 14,748 (1,715) 64,438
-------------------------------------------
Net pension cost $(3,936) $(3,952) $ (140)
===========================================
ASSUMPTIONS 1993 1992 1991
- -----------------------------------------------------------------------------------------------------------------------
Discount rates used to determine projected
benefit obligations as of December 31 7.25% 7.25% 7.00%
Rates of increase in compensation levels 6.50% 6.50% 6.50%
Expected long-term rates of return on assets 8.25% 8.25% 8.00%
-41-
11. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Effective January 1, 1993, the Company adopted SFAS No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions," which requires
accrual accounting for postretirement benefits other than pensions. The
Company provides health-care and life insurance benefits for its retired
employees and substantially all of the Company's employees may become eligible
for these benefits upon retirement. Prior to adoption of SFAS No. 106, the
Company recognized the costs of these benefits by expensing the benefits as
paid. The amounts expensed in 1992 and 1991 were $4,496,000 and $4,176,000,
respectively.
The Company has elected to recognize the cost of its transition obligation
(the accumulated postretirement benefit obligation as of January 1, 1993) by
amortizing it on a straight-line basis over 20 years. The Company's SFAS No.
106 obligation and cost are based on a discount rate of 7.75% as of January 1,
1993 and 7.25% as of December 31, 1993. The assumed rate of increase in health-
care costs (health-care cost trend rate) was 12% in 1993, decreasing to 11% in
1994 and gradually decreasing to 5.5% by 2011. Increasing the health-care cost
trend rates of future years by one percentage point would increase the
accumulated postretirement benefit obligation by $3.3 million and would
increase annual aggregate service and interest costs by $0.3 million.
In December 1993, the Company contributed $5.8 million to external trust funds
in order to begin to fund the SFAS No. 106 obligation. The assets in the
trusts consist primarily of short-term taxable and tax-exempt marketable
securities. The Company's policy is to fund the obligation to the extent that
SFAS No. 106 costs are reflected in customer rates, including amounts which
are capitalized.
The following schedules show the funded status of the plan and the components
of the cost of postretirement benefits other than pensions.
RECONCILIATION OF FUNDED STATUS OF THE PLAN As of
(Dollars in thousands) 12/31/93
- ----------------------------------------------------------------------------
Accumulated postretirement benefit obligation (APBO):
Active employees fully eligible for benefits $17,380
Other active employees 20,351
Current retirees 43,118
-----------
80,849
Plan assets at fair value 5,825
-----------
APBO in excess of plan assets 75,024
Unrecognized transition obligation (68,728)
Unrecognized net loss (4,939)
-----------
Accrued postretirement benefit cost $ 1,357
===========
ANNUAL COST OF POSTRETIREMENT BENEFITS OTHER THAN PENSIONS Year ended
(Dollars in thousands) 12/31/93
- ----------------------------------------------------------------------------
Service cost--benefits earned during period $ 2,206
Interest cost on projected benefit obligation 5,613
Amortization of the unrecognized transition obligation 3,617
-----------
Net SFAS No. 106 cost $11,436
===========
-42-
12. COMMITMENTS
The Company estimates that approximately $155.3 million, excluding AFUDC, will
be expended for construction purposes in 1994.
The Company has a 26-year agreement with Star Enterprise effective through May
31, 2018 to purchase 48 MW of capacity supplied by the Delaware City Power
Plant, which the Company sold to Star Enterprise in December 1991. Under the
terms of the agreement, the maximum capacity charge for a year is $3.4 million,
if the unit's availability exceeds 85 percent.
The Company has an agreement for the future purchase of 165 MW of power over a
30-year period from a cogeneration facility to be constructed by the Delaware
Clean Energy Project (DCEP) and located in Delaware. On April 20, 1993, the
DPSC issued an order which neither approved nor disapproved the DCEP
agreement. The agreement, as amended, provides the Company and DCEP the right,
until November 1, 1994, to terminate the agreement. The date for the start of
commercial operations of the facility remains to be determined, but in any
event will not be prior to June 1, 1998. Assuming 93% availability, capacity
charges under the agreement are currently expected to be approximately $44.5
million per year for the first 16 years and $31.2 million per year for the
remaining 14 years.
In order to ensure adequate supplies of fuel, the Company has certain
commitments under long-term fuel supply contracts. Excluding nuclear fuel
discussed below, the Company's commitments under its long-term fuel supply
contracts are $76 million in 1994, $62 million in 1995, $57 million in 1996,
$45 million in 1997, and $38 million in 1998.
The Company's share of nuclear fuel at Peach Bottom and Salem is financed
through a nuclear fuel energy contract which is accounted for as a capital
lease. Payments under the contract are based on the quantity of nuclear fuel
burned by the plants. The Company's obligation under the contract is generally
the net book value of the nuclear fuel financed, which was $33.9 million as of
December 31, 1993.
The Company leases an 11.9% interest in the Merrill Creek Reservoir. The lease
is considered an operating lease and payments over the remaining lease term,
which ends in 2032, are $165.6 million in aggregate. The Company also has long-
term leases for certain other facilities and equipment. Minimum commitments as
of December 31, 1993 under all noncancelable lease agreements (excluding
payments under the nuclear fuel energy contract which cannot be reasonably
estimated) are as follows: 1994-$6,716,000; 1995-$6,691,000; 1996-$6,639,000;
1997-$5,552,000; 1998-$5,345,000; after 1998-$150,296,000; total-$181,239,000.
Approximately 91% of the minimum lease commitments shown above are payments
due under the Company's lease of an 11.9% interest in the Merrill Creek
Reservoir.
RENTALS CHARGED TO OPERATING EXPENSES
The following amounts were charged to operating expenses for rental payments
under both capital and operating leases:
(Dollars in Thousands) 1993 1992 1991
- -----------------------------------------------------------------------------
Interest on nuclear fuel capital lease $1,014 $1,111 $1,633
Interest on other capital leases 282 321 345
Amortization of nuclear fuel capital lease 9,956 10,231 10,242
Amortization of other capital leases 287 323 351
Operating leases 15,176 14,063 14,507
---------------------------------
$26,715 $26,049 $27,078
=================================
-43-
13. ENVIRONMENTAL MATTERS
The Company is subject to regulation with respect to the environmental effects
of its operations, including air and water quality control, solid waste
disposal and limitation on land use by various federal, regional, state and
local authorities. The Company has incurred, and expects to continue to
incur, capital expenditures and operating costs because of environmental
considerations and requirements. The disposal of Company-generated hazardous
substances can result in costs to clean up facilities found to be contaminated
due to past disposal practices. Federal and state statutes authorize
governmental agencies to compel responsible parties to clean up certain
abandoned or uncontrolled hazardous waste sites. The Company is currently a
potentially responsible party (PRP) at one such site and is alleged to be a
third party contributor at two other such sites. The Company also has three
former coal gasification sites and is currently conducting a study of
one of the three sites to assess the extent of contamination and risk to the
environment. The Company does not expect clean-up and other potential costs
related to the PRP and coal gasification sites, either separately or
cumulatively, to have a material effect on the Company's financial position or
results of operations.
14. CONTINGENCIES
1) Nuclear Insurance
In the event of an incident at any commercial nuclear power plant in the
United States, the Company could be assessed for a portion of any third party
claims associated with the incident. Under the provisions of the Price
Anderson Act, if third party claims relating to such an incident exceed $200
million (the amount of primary insurance), the Company could be assessed up to
$23.7 million for third party claims. In addition, Congress could impose a
revenue raising measure on the nuclear power industry to pay such claims.
The co-owners of Peach Bottom and Salem maintain nuclear property damage and
decontamination insurance in the aggregate amount of $2.7 billion for each
station. The Company is self-insured, to the extent of its ownership
interest, for its share of property losses in excess of insurance coverages.
Under the terms of the various insurance agreements, the Company could be
assessed up to $3.5 million in any policy year for losses incurred at nuclear
power plants insured by the insurance companies.
The Company is a member of an industry mutual insurance company, which
provides replacement power cost coverage in the event of a major accidental
outage at a nuclear power plant. The premium for this coverage is subject to
retrospective assessment for adverse loss experience. The Company's present
maximum share of any assessment is $1.4 million per year.
2) Other
On December 14, 1993, Star Enterprise (Star) filed a lawsuit against the
Company seeking an accounting, a refund, and damages totalling $9.3 million.
Star alleges that the Company overcharged Star for pension and tax-related
costs under a contract entered into by the parties' predecessors in 1955 (the
"1955 Agreement"). The Company believes it acted properly under the 1955
Agreement and that it does not owe Star any amounts claimed in this lawsuit.
The Company cannot predict the outcome of the lawsuit.
The Company is involved in certain other legal and administrative proceedings
before various courts and governmental agencies concerning rates, fuel
contracts, tax filings, and other matters. The Company expects that the
ultimate disposition of these proceeding will not have a material effect on
the Company's financial position or results of operations.
15. SUPPLEMENTAL CASH FLOW INFORMATION
In the consolidated financial statements, the Company considers highly liquid
marketable securities and debt instruments purchased with a maturity of three
months or less to be cash equivalents.
CASH PAID DURING THE YEAR FOR Year Ended December 31,
(Dollars In Thousands) 1993 1992 1991
- -------------------------------------------------------------------------------------------------
Interest, net of capitalized amount $58,154 $62,127 $65,788
Income taxes, net of refunds $72,384 $46,310 $37,397
-44-
16. NONUTILITY SUBSIDIARIES
The following presents condensed financial information of the Company's
nonregulated wholly owned subsidiaries: Delmarva Energy Company; Delmarva
Industries, Inc; and Delmarva Capital Investments, Inc. A subsidiary which
leases real estate to the Company's utility business, Delmarva Services
Company, is excluded from these statements since its income is derived from
intercompany transactions which are eliminated in consolidation.
CONDENSED SUBSIDIARY STATEMENTS OF INCOME
(Dollars in Thousands)
1993 1992 1991
- -----------------------------------------------------------------------------------------------------
Revenues and Gains
Landfill and waste hauling $11,745 $9,021 $ 6,154
Operating services 22,118 3,038 2,939
Other revenues 2,117 998 1,129
Leveraged leases/(1)/ 835 61 5,044
Other investment income 821 1,279 182
--------------------------------------------
37,636 14,397 15,448
--------------------------------------------
Costs and Expenses
Operating expenses 36,424 15,765 15,509
Interest expense 246 550 1,704
Capitalized interest (246) (231) (143)
Income tax (benefit) (596) (2,176) (2,900)
--------------------------------------------
35,828 13,908 14,170
--------------------------------------------
Net income $ 1,808 $ 489 $ 1,278
============================================
Earnings per share of common stock attributed to
subsidiaries $ 0.03 $ 0.01 $ 0.03
/(1)/ On an after-tax basis, leveraged leasing, including gains on sales of
equity and residual value interests, contributed $1,754,000, $1,813,000, and
$4,663,000 to earnings in 1993, 1992, and 1991, respectively.
CONDENSED SUBSIDIARY BALANCE SHEETS
(Dollars In Thousands)
As of December 31, Liabilities and As of December 31,
Assets 1993 1992 Stockholder's Equity 1993 1992
- ---------------------------------------------------------------------------------------------------------------------------
Current Assets Current Liabilities
Cash and cash equivalents $15,929 $ 6,033 Debt due within
one year $ 193 $ 181
Other 7,489 2,477 Other 11,903 9,689
-------------------- ---------------------
23,418 8,510 12,096 9,870
---------------------
Noncurrent assets Noncurrent liabilities
Investment in Deferred income taxes 55,008 65,604
Leveraged leases 50,914 72,858 Other 3,089 3,196
Other 4,623 5,481 ---------------------
58,097 68,800
---------------------
Property, plant & equipment
Landfill & waste hauling 27,420 28,488
Other 3,512 2,089 Stockholder's Equity 40,392 39,981
Other 698 1,225
--------------------- ---------------------
Total $110,585 $118,651 Total $110,585 $118,651
===================== =====================
-45-
17. SEGMENT INFORMATION
Segment information with respect to electric and gas operations was as
follows:
(Dollars in Thousands) 1993 1992 1991
- --------------------------------------------------------------------------------
Electric Operations
Operating revenues $ 875,663 $ 780,175 $ 784,599
Operating income 154,412 134,260 129,295
Depreciation 94,549 89,421 83,363
Construction expenditures 142,238 192,493 163,399
Gas Operations
Operating revenues 94,944 83,869 71,222
Operating income 9,727 9,451 7,115
Depreciation 6,380 5,864 5,247
Construction expenditures 17,753 14,888 18,302
Identifiable Assets, Net
Electric 2,268,100 2,042,496 1,895,124
Gas 160,618 142,740 130,875
Assets not allocated 164,811 189,557 237,719
18. QUARTERLY FINANCIAL INFORMATION
The quarterly data presented below reflect all adjustments necessary in the
opinion of the Company for a fair presentation of the interim results.
Quarterly data normally vary seasonally with temperature variations,
differences between summer and winter rates, the timing of rate orders, and
the scheduled downtime and maintenance of electric generating units.
Earnings Earnings
Applicable Average per
Quarter Operating Operating Net to Common Shares Average
Ended Revenue Income Income Stock Outstanding Share
(Dollars in Thousands) (In Thousands)
- ------------------------------------------------------------------------------------------------------------
1993
March 31 $248,007 $ 46,278 $ 34,414 $ 31,911 55,135 $0.58
June 30 214,638 31,239 18,758 16,279 58,036 $0.27
September 30 275,385 59,015 44,279 41,789 58,372 $0.72
December 31 232,577 27,607 13,625 11,095 58,687 $0.19
--------------------------------------------------------------------------------
$970,607 $164,139 $111,076 $101,074 57,557 $1.76
================================================================================
1992
March 31 $225,130 $ 38,058 $34,789 $32,988 52,876 $0.62
June 30 193,797 29,279 14,259 12,464 53,285 $0.24
September 30 237,717 48,080 34,056 31,810 53,685 $0.59
December 31 207,400 28,294 15,422 12,915 53,980 $0.24
--------------------------------------------------------------------------------
$864,044 $143,711 $98,526 $90,177 53,456 $1.69
================================================================================
In the first quarter of 1992, the Company recorded the results of the Peach
Bottom lawsuit settlement (Note 4 to the Consolidated Financial Statements)
which increased 1992 net income by $11,397,000 ($0.21 per share).
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Appendix to Management's Discussion and Analysis of Financial
Condition and Results of Operations
Descriptions of Graphs
"Regional Electric Price Comparison"
- ------------------------------------
On page 21 of the 1993 Annual Report to Stockholders, a graph titled
"Regional Electric Price Comparison" is displayed. The graph compares
electric prices for Delmarva Power to a regional average of electric
utilities. The price comparisons are based on 1992 average electric prices
per kilowatt-hour (kWh) and are made for the residential, commercial, and
industrial customer classes.
For each of the customer classes (residential, commercial, and industrial),
two side-by-side vertical, rectangular bars are displayed. The bar on the
left represents the Delmarva Power price and the bar on the right represents
the regional average price. The y-axis is scaled in cents, beginning at
zero, increasing by increments of two cents, and ending at ten cents. The
prices graphed are as follows:
Delmarva Regional
Power Average
-------- --------
Residential 8.48 9.86
Commercial 7.04 8.64
Industrial 4.63 6.59
"1993 Sources of Electricity"
- -----------------------------
On page 23 of the 1993 Annual Report to Stockholders, a pie graph titled
"1993 Sources of Electricity" is displayed. The sources of electricity shown
on the pie graph are as follows:
Purchased Power, net 12.7%
Coal 46.7%
Oil and Gas 26.0%
Nuclear 14.6%
-1-
Appendix to Management's Discussion and Analysis of Financial
Condition and Results of Operations
Descriptions of Graphs
"Electric Operation & Maintenance Expenses Per kWh Sold"
- --------------------------------------------------------
On page 23 of the 1993 Annual Report to Stockholders, a graph titled
"Electric Operation & Maintenance Expenses Per kWh Sold" is displayed.
Electric operation and maintenance expenses, expressed in cents per kWh sold,
are graphed for Delmarva Power, a regional average of electric utilities, and
a national average of electric utilities. The y-axis is scaled in cents,
beginning at 1.00, increasing by increments of 0.25, and ending at 2.75. The
x-axis consists of the years 1988, 1989, 1990, 1991, 1992, and 1993. The
following data points, cents per kWh sold, are plotted as lines on the graph.
1988 1989 1990 1991 1992 1993
---- ---- ---- ---- ---- -----
(Cents Per kWh)
Delmarva Power 1.54 1.55 1.60 1.68 1.73 1.59
Regional Average 1.81 1.83 1.93 1.95 1.98 (1)
National Average 2.06 2.11 2.28 2.42 2.52 (1)
(1) Data not available and not graphed.
"Internally Generated Funds & Construction Expenditures"
- --------------------------------------------------------
On page 25 of the 1993 Annual Report to Stockholders, a graph titled
"Internally Generated Funds & Construction Expenditures" is displayed. The
y-axis is scaled in millions of dollars, beginning at zero, increasing by
increments of $30 million, and ending at $210 million. The x-axis consists
of the years 1991, 1992, 1993, 1994 (forecast), and 1995 (forecast). For
each year, two side-by-side vertical, rectangular bars are displayed. The
bar on the left is internally generated funds and the bar on the right is
construction expenditures. The graphed data are as follows:
1991 1992 1993 1994* 1995*
---- ---- ---- ----- -----
(millions of dollars)
Internally Generated
Funds 96 130 109 125* 125*
Construction
Expenditures 182 207 160 155* 179*
*Forecast
-2-