EXHIBIT 13
SELECTED FINANCIAL DATA
Year Ended December 31,
(Dollars in Thousands, Except Per Share Amounts) 1996 1995 1994 1993 1992
- - ----------------------------------------------------------------------------------------------------------------------------------
OPERATING RESULTS AND DATA
Operating Revenues $ 1,094,961 $ 995,103 $ 991,021 $ 970,607 $ 864,044
Operating Income $ 179,380 $ 178,406 $ 163,156(1) $ 164,139 $ 143,711(2)
Net Income $ 116,187 $ 117,488 $ 108,310(1) $ 111,076 $ 98,526(2)
Earnings Applicable to Common Stock $ 107,251 $ 107,546 $ 98,940(1) $ 101,074 $ 90,177(2)
Electric Sales (kWh 000)(3) 12,925,716 12,310,921 12,505,082 12,280,230 11,520,811
Gas Sold and Transported (mcf 000) 24,157 21,371 20,342 19,605 20,168
COMMON STOCK INFORMATION
Earnings Per Share of Common Stock $ 1.77 $ 1.79 $ 1.67(1) $ 1.76 $ 1.69(2)
Dividends Declared Per Share of
Common Stock $ 1.54 $ 1.54 $ 1.54 $ 1.54 $ 1.54
Average Shares Outstanding (000) 60,698 60,217 59,377 57,557 53,456
Year-End Common Stock Price $ 20 3/8 $ 22 3/4 $ 18 9/64 $ 23 5/8 $ 23 1/4
Book Value Per Common Share $ 15.41 $ 15.20 $ 14.85 $ 14.66 $ 13.77
Return on Average Common Equity 11.4% 11.7% 11.1% 12.0% 12.2%
CAPITALIZATION
Variable Rate Demand Bonds (VRDB)(4) $ 85,000 $ 86,500 $ 71,500 $ 41,500 $ 41,500
Long-Term Debt 904,033 853,904 774,558 736,368 787,387
Company Obligated Mandatorily Redeemable
Preferred Securities of Subsidiary Trust
Holding Solely Company Debentures 70,000 -- -- -- --
Preferred Stock 89,703 168,085 168,085 168,085 176,365
Common Stockholders' Equity 934,913 923,440 884,169 862,195 745,789
---------- ---------- ---------- ---------- ----------
Total Capitalization with VRDB $2,083,649 $2,031,929 $1,898,312 $1,808,148 $1,751,041
========== ========== ========== ========== ==========
OTHER INFORMATION
Total Assets $ 2,979,153 $ 2,866,685 $ 2,669,785 $ 2,592,479 $ 2,374,793
Long-Term Capital Lease Obligation $ 20,552 $ 20,768 $ 19,660 $ 23,335 $ 26,081
Construction Expenditures(5) $ 151,728 $ 135,614 $ 154,119 $ 159,991 $ 207,439
Internally Generated Funds (IGF)(6) $ 120,260 $ 137,394 $ 123,948 $ 108,693 $ 130,275
IGF as a Percent of Construction Expenditures 79% 101% 80% 68% 63%
(1) An early retirement offer decreased net income and earnings per share by
$10.7 million and $0.18, respectively.
(2) The settlement of a lawsuit increased net income and earnings per share by
$11.4 million and $0.21, respectively.
(3) Excludes interchange deliveries.
(4) 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 12, "Debt," to the Consolidated Financial Statements.
(5) Excludes Allowance for Funds Used During Construction.
(6) Net cash provided by operating activities less common and preferred
dividends.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EARNINGS SUMMARY
Earnings per share for 1996 were $1.77, a $0.02 decrease from 1995. In 1996 and
1995, the outages of the two units at the Salem Nuclear Generating Station
(Salem), which began in May and June 1995, caused increases in operation and
maintenance expenses and fuel-related costs, including replacement power. The
Salem outages decreased earnings per share by approximately $0.19 in 1996 and
$.09 in 1995. See "Salem Outages" for additional information. Excluding the
Salem outages, earnings rose $0.08 per share in 1996, primarily due to
additional revenues from customer growth, partly offset by higher depreciation
and other expenses. The Company held operation and maintenance expenses within
$1.3 million (0.6%) of 1995 expenses after excluding the effects of the Salem
outages and the Company's acquisition of the Conowingo Power Company (COPCO) in
June 1995, as discussed in Note 4, "Mergers and Acquisitions," to the
Consolidated Financial Statements. The Conowingo District's operating results
continued in 1996 to have a minimal impact on earnings, as expected. Earnings
from nonutility businesses were relatively flat as higher earnings from
operations of nonutility subsidiaries were offset by start-up costs of new,
nonutility businesses incurred by the parent company.
Earnings per share for 1995 were $1.79, a $0.12 increase from 1994. Excluding an
$0.18 per share charge in 1994 for an early retirement offer (ERO), earnings per
share decreased $0.06 in 1995 due to a $0.09 decrease attributed to utility
operations, partly offset by a $0.03 increase for nonutility subsidiaries. The
$0.09 per share decrease for utility operations resulted from additional costs
expensed for the Salem outages. Excluding the Salem outages and the 1994 charge
for the ERO, earnings per share from utility operations in 1995 were unchanged
from 1994, reflecting the Company's success in offsetting lower wholesale
(resale) revenues with a combination of cost reductions, retail sales growth,
and modest price increases.
DIVIDENDS
On December 12, 1996, the Board of Directors declared a common stock dividend of
$0.38 1/2 per share for the fourth quarter or $1.54 on an annualized basis. As
discussed under "Strategic Plans For Competition," on August 9, 1996, the
Company announced plans to merge with Atlantic Energy, Inc. (Atlantic). The
merger agreement restricts the Company's common stock dividend through the
merger's effective date to an amount which cannot exceed $1.54 per share. The
merger is part of the Company's growth strategy, which will require increased
reinvestment of earnings into new businesses. The business growth from these
investments and the payment of dividends on common stock are expected to
maximize stockholder value on a long-term basis.
SALEM OUTAGES
The Company owns 7.41% of Salem, which consists of two pressurized water nuclear
reactors and is operated by Public Service Electric & Gas Company (PSE&G). Salem
Units 1 and 2 were removed from operation by PSE&G in May and June 1995,
respectively, due to operational problems and maintenance concerns. Due to
degradation of a significant number of tubes in the Unit 1 steam generators,
PSE&G is replacing the Unit 1 steam generators and expects Unit 1 to return to
service in the fall of 1997. The Company's share of the costs to be capitalized
for the steam generators, including installation, will range from approximately
$11 million to $13 million. PSE&G has advised the Company that Unit 2 is
expected to return to service in the second quarter of 1997. The units' return
dates are subject to completion of the requirements of their respective restart
plans to the satisfaction of PSE&G and the Nuclear Regulatory Commission (NRC),
which encompasses a substantial review and improvement of personnel, process,
and equipment issues.
In 1996 and 1995, the Company incurred higher than expected operation and
maintenance costs at Salem of approximately $9 million and $5 million,
respectively, which were expensed as incurred.
The Company incurs replacement power costs while the units are out of service of
approximately $750,000 per month, per unit. Such amounts vary based on the cost
and availability of other Company-owned generation and the cost of purchased
energy. Replacement power costs typically are not incurred for routine refueling
and maintenance outages, and the recovery of replacement power costs is subject
to approval by the regulatory commissions having jurisdiction over the Company.
From the inception of the Salem unit outages through December 31, 1996,
approximately one-half of
estimated replacement power costs of $20.4 million has been expensed ($6.1
million expensed in 1996 and $4.1 million expensed in 1995) and the remaining
$10.2 million has been deferred on the Company's Consolidated Balance Sheet in
expectation of future recovery. The unavailability of the Salem units also
resulted in a $4 million charge to 1996 fuel expense for capacity deficiency
charges owed to the Pennsylvania-New Jersey-Maryland Interconnection Association
(PJM Interconnection).
The actual costs ultimately incurred by the Company may differ from the
foregoing estimates, since the periods projected by PSE&G during which the Salem
units will be out of service, the extent of the maintenance that will be
required, and the costs of replacement power and the extent of its recovery may
be different from those set forth above.
The Company began recovering one-half of the replacement power costs associated
with the Salem outages on an interim basis, subject to refund, from retail
electric customers in Virginia and Maryland in July and August 1996,
respectively. The Company expects the Virginia State Corporation Commission
(VSCC) and Maryland Public Service Commission (MPSC) to conduct full reviews of
the outages before making final determinations concerning replacement power cost
recovery.
On December 10, 1996, the Delaware Public Service Commission (DPSC) suspended
the portion of interim rates related to the Salem replacement power costs until
the earlier of June 1, 1997, or the end of the case concerning fuel rates
charged to customers. If the suspended interim rates go into effect prior to the
conclusion of the case, they would go into effect subject to refund pending the
final decision by the DPSC.
Since the 1995 shutdown of the units, the Company's objective has been to reduce
the negative financial impact on its stockholders and customers. As discussed in
Note 17 to the Consolidated Financial Statements, "Contingencies," the legal
actions initiated in the first quarter of 1996 by the Company against PSE&G and
Westinghouse Electric Corporation, which manufactured the steam generators
originally installed at Salem, are still pending.
COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT
As a result of federal legislation, electric resale customers can choose their
electric suppliers, resulting in a highly-competitive electric resale market.
Many states are considering, and a number of states have introduced, electric
retail wheeling, which results in retail customers purchasing electricity from
the suppliers of their choice at market-based prices. In addition, federal
legislation has been introduced and other bills are being drafted which could
lead to retail wheeling for the entire nation on varying dates. As subsequently
discussed under "Business Units," although prices charged to customers for the
production (or supply) of electricity may become deregulated, the transmission
and distribution (or delivery) of electricity is expected to remain subject to
regulation.
The transition to a competitive market could result in "stranded costs" for a
utility. Stranded costs generally are considered to be costs which may not be
recoverable in a competitive market due to market-based pricing or customers
choosing different energy suppliers. The states in which retail wheeling is
planned have allowed, or are considering allowing, utilities to recover some or
all of their stranded costs. Potential stranded costs could include (i) above-
market costs associated with generation facilities or long-term power purchase
agreements and (ii) regulatory assets, which are deferred expenses expected to
be recovered from customers in the future. Changes in the regulatory environment
potentially could require the Company to write down asset values, and such
write-downs could be material. However, given the uncertainty with respect to
the timing of regulatory changes, the resulting deregulated market prices for
capacity and energy, and the extent to which the Company's regulatory
commissions will allow for recovery of any previously incurred costs, it is not
possible to predict the level of unrecovered stranded costs, if any, which would
result. Potential write-offs of stranded costs or reductions in profit margins
due to competition would reduce the Company's common equity and could result in
lower credit ratings and higher financing costs. To the extent that additional
equity capital is required, issuance of common stock may be necessary and
earnings per share would decrease.
Based on the Company's initiative, a formal process has been established in
Delaware and an informal forum has been established in Maryland through which
the commissions and other interested parties are addressing changes in the
regulation of the electric utility industry. During 1996, Delaware and Maryland
forum meetings addressed issues such as retail wheeling, stranded costs,
environmental matters, social programs, rate redesign, and alternative forms of
regulation.
In October 1996, the MPSC issued an order instituting a proceeding to continue
its review of regulatory and competitive issues affecting the electric industry
in Maryland. In consultation with Maryland's electric utilities and other
stakeholders, the MPSC staff has been directed to evaluate regulatory and
competitive issues facing the electric utility industry, including electric
retail competition, developments in federal and state regulation, and the
interests of Maryland's customers and utilities. The MPSC instructed its staff
to submit their recommendations by May 31, 1997.
In December 1996, the forum participants issued to the DPSC and MPSC reports
which discussed the issues and the positions of stakeholders, but did not reach
any conclusions. While there was consensus on some issues, such as the need for
unbundled costs and tariffs, there were many issues where consensus was not
reached, such as the need for and benefits of retail wheeling, recovery of
stranded costs, environmental and social program issues, franchise and property
rights, rate design, and performance-based ratemaking.
The issues mentioned above continue to be discussed by the Company, the DPSC
Staff, and other interested parties. The Company expects to develop formal
proposals on deregulation which are expected to be filed in mid-1997 with the
DPSC. In Maryland, the participants decided in January 1997 to suspend the
collaborative process until the MPSC Staff files its report.
In response to a directive from the VSCC, the VSCC Staff issued in July 1996 a
report on restructuring the electric industry, which included, among other
recommendations, a recommendation for a "go slow" approach to restructuring. In
November 1996, the VSCC issued an order indicating that more evaluation is
necessary to determine what, if any, restructuring may best serve the public
interest in Virginia. The VSCC established a new docket and directed its Staff
to monitor and file separate studies in 1997 regarding the development of a
competitive wholesale market in Virginia, service quality standards, and the
results of retail wheeling experiments in other states. Also, several utilities,
excluding the Company, were directed to file unbundled cost studies and tariffs.
STRATEGIC PLANS FOR COMPETITION
The Company intends to grow its businesses by building long-term customer
relationships, offering new products and services that complement the Company's
core energy business and are targeted to individual customer needs, and serving
more customers in a larger geographical area. The Company plans to develop new
distribution channels throughout the region for its products and services. To
retain existing customers and attract new customers, the Company plans to
differentiate itself from its competitors by providing exceptional service,
maintaining quality and competitive prices, and expanding connections with
customers through new services. The Company believes that its growth strategy
will maximize long-term stockholder value. In the short term, implementation of
this strategy may result in moderate downward pressure on earnings due to costs
for the start-up of new businesses, building a regional distribution platform,
expanding the Company's marketing and sales organization, and upgrading
information technology systems.
The Company plans to sell energy and related premium products and services to
existing customers and to new customers who may be outside the Company's current
service territory. Current developments in the adjoining states of Pennsylvania
and New Jersey indicate future opportunities for the Company to serve more
electric customers. In Pennsylvania, electric retail wheeling is scheduled to be
phased-in over a three year period beginning in 1999. The New Jersey Board of
Public Utilities has recommended that retail electric competition be fully
phased-in by April 2001.
BUSINESS UNITS
In 1996, the Company reorganized into three separate business units (Energy
Supply, Regulated Delivery, and Energy Services) which strengthen the Company's
ability to meet customers' needs and also reflect the anticipated future
structure of the utility industry. Although the products and services of each
business unit are different and each business unit has a separate strategy, the
business units' plans complement and support each other.
Energy Supply produces, buys, and sells energy in a multi-regional marketplace
that is expected eventually to be competitive and have deregulated, market-based
prices. Energy Supply's mission is to provide new and existing customers with a
complete and competitive portfolio of merchant energy products and services,
while maximizing the value of the Company's generation assets.
Regulated Delivery delivers energy over the Company's transmission and
distribution systems at prices which are expected to continue to be regulated by
the public utility commissions. Regulated Delivery's mission is to provide high-
value utility delivery services to customers in the region. By continuing to
maintain a high level of customer satisfaction through high-quality customer
service, Regulated Delivery will help the Company retain existing customers who
may become eligible to choose alternative energy suppliers in the future.
Energy Services packages and sells energy and related premium products and
services to customers within the competitive regional marketplace. Energy
Services is starting new businesses which include heating, ventilation, and air
conditioning (HVAC) services, telecommunications, and other products and
services which complement the Company's core energy business. In
telecommunications, Energy Services provides fiber optic construction and
engineering services to customers and plans to provide retail telephone services
and carrier service for long-distance phone companies.
PENDING MERGER WITH ATLANTIC
On August 9, 1996, the Company announced plans to merge with Atlantic, an
investor-owned holding company, which owns Atlantic City Electric Company, an
electric utility, and nonutility businesses. Atlantic is located in southern New
Jersey. Atlantic's 1996 operating revenues and net income were $980.3 million
and $58.8 million, respectively, and its total assets were $2,670.8 million as
of December 31, 1996. The merger is expected to facilitate success in the
competitive marketplace and is part of the Company's integrated strategy to
build a regional delivery platform over which a portfolio of products and
services can be distributed. Other anticipated benefits of the merger include
increased scale, cost savings, competitive prices and services, a more balanced
customer base, and increased financial flexibility. On January 30, 1997, the
stockholders of the Company and Atlantic approved the merger. Various federal
and state regulatory approvals are also required for the merger to become
effective. The regulatory approval process is expected to be completed during
late 1997 to early 1998. Refer to Note 4, "Mergers and Acquisitions," to the
Consolidated Financial Statements for additional information on the merger.
ELECTRIC RESALE BUSINESS
The Company's total electric resale revenues as a percent of total billed
electric sales revenues were 7.4% in 1996, 7.0% in 1995, and 13.0% in 1994.
Resale non-fuel revenues decreased $24.2 million in 1995, primarily because Old
Dominion Electric Cooperative (ODEC), the Company's largest resale customer,
began purchasing about one-half of its capacity and energy requirements from
other suppliers. The reduction in 1995 resale non-fuel revenues was offset
through cost reductions, retail sales growth, and modest price increases.
The Company has substantially reduced the financial risk related to its resale
business. In 1994 and 1995, the Company entered into long-term contracts with
all of its municipal customers. In addition, the Company negotiated extended
notice provisions on the remaining portion of ODEC's capacity and energy
requirements served by the Company. The notice provisions require ODEC to
provide the Company with two years' notice for up to a 30% load reduction and
five years' notice for load reductions greater than 30%.
The Company currently provides approximately 200 megawatts (MW) of load to ODEC,
which represented 3.8% of the Company's 1996 total billed electric sales
revenues, including about $24 million of non-fuel (base rate) revenues. On
August 16, 1996, ODEC notified the Company that it will reduce its load by 60 MW
effective September 1, 1998, and will further reduce its load to zero effective
September 1, 2001.
ODEC had issued a request for proposals in March 1996 to replace eventually
ODEC's capacity and energy agreements with its current suppliers. On July 1,
1996, the Company submitted its proposal to ODEC to continue to serve all of the
load currently supplied by the Company. ODEC expects to select a supplier by
March 1997 for the 60 MW it will cease purchasing under its existing contract
with the Company, effective September 1, 1998.
If ODEC selects a new electric supplier for some or all of the load currently
supplied by the Company, the decrease in non-fuel revenues would be offset
partially by avoided purchased capacity costs. Also, the Company would continue
to receive transmission wheeling revenues from ODEC. The Company estimates that
earnings per share would decrease by $0.06 to $0.08, on an annualized basis,
after September 1, 1998 if ODEC reduces its load by 60 MW. Earnings per share
would decrease by an additional $0.10 to $0.12, on an annualized basis, after
September 1, 2001, if ODEC further reduces its load to zero. Any such earnings
decrease would be mitigated by natural load growth in the Company's service
territory and by any of ODEC's load that the Company may obtain through the
bidding process.
COMPONENTS OF UTILITY REVENUES
Fuel and energy costs billed to customers (fuel revenues) generally 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 affect directly 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 generally is deferred until it is
subsequently recovered from or returned to utility customers.
Electric revenues also include interchange delivery revenues, which result
primarily from the sale of electric power to utilities in the PJM
Interconnection. The PJM Interconnection is an electric power pool comprised of
eight 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 generally do not affect net income.
ELECTRIC REVENUES AND SALES
In 1996, the percentage of total billed electric sales revenues contributed by
the various customer classes were as follows: residential - 42.3%; commercial -
32.0%; industrial - 17.5%; resale - 7.4%; and other - 0.8%.
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) 1996 1995
- - ---------------------------------------------------------------------------------------------
Non-fuel (Base Rate) Revenues
Retail Sales Volume $21.6 $ 54.9
Resale Sales Volume -- (24.2)
Increased Rates 1.8 3.3
Fuel Revenues 26.8 (6.9)
Interchange Delivery Revenues 28.0 (15.1)
Other Operating Revenues 2.8 4.5
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Total $81.0 $ 16.5
===== ======
For 1996 compared to 1995, Non-fuel Revenues increased $21.6 million from
"Retail Sales Volume" due to a 4.5% increase in total retail kilowatt-hour (kWh)
sales, which reflects Conowingo District sales for all of 1996, versus about
one-half of 1995, and other sales growth. Excluding the Conowingo District,
retail sales increased 0.7% mainly due to 1.3% growth in the number of retail
customers, partly offset by lower sales to industrial customers.
For 1995 compared to 1994, Non-fuel Revenues increased $54.9 million from
"Retail Sales Volume" due to a 7.3% increase in total kWh sales, which resulted
primarily from Conowingo District sales beginning June 19, 1995. Excluding the
Conowingo District, retail sales increased 2.9% mainly due to a 1.4% increase in
the number of retail customers and 4.5% commercial sales growth.
Changes in Non-fuel Revenues from "Resale Sales Volume" were insignificant for
1996 compared to 1995. Non-fuel resale revenues decreased $24.2 million in 1995
because ODEC changed electric suppliers on January 1, 1995 for one-half of its
electricity requirements.
The increases in Non-fuel Revenues from "Increased Rates" of $1.8 million in
1996 and $3.3 million in 1995 resulted from an increase in Delaware retail
electric rates that became effective May 1, 1995. The rate increase was designed
to recover the costs of "limited issues," which primarily were costs imposed by
government.
In 1996, Fuel Revenues increased $26.8 million due to increased kWh sales and
higher average fuel rates. In 1995, Fuel Revenues decreased $6.9 million mainly
due to lower kWh sales to resale customers.
In 1996, Interchange Delivery Revenues increased $28.0 million principally due
to increased energy purchases which enabled the Company to sell more of its
higher-cost peaking unit output to utilities in the PJM Interconnection. In
1995, Interchange Delivery Revenues decreased $15.1 million mainly due to lower
sales and billing rates to the PJM Interconnection.
GAS REVENUES, SALES AND TRANSPORTATION
The Company earns gas revenues from the sale and transportation of gas for
customers. Transportation customers may purchase gas from the Company or other
suppliers. The total number of gas customers served by the Company increased by
2.5% in 1996 and 2.9% in 1995.
In 1996, total gas revenues increased $18.8 million due to a $5.5 million
increase in non-fuel revenues and a $13.3 million increase in fuel revenues.
Non-fuel revenues increased $5.5 million mainly due to customer growth and a
colder heating season which resulted in a 4.9% increase in total gas sold and
transported on the Company's system. Including off-system sales which began in
1996, total gas sold and transported increased 13.0%. Fuel revenues increased
$13.3 million due to a prior year $6.8 million refund of over-recovered fuel
costs, higher sales, and higher average rates.
In 1995, total gas revenues decreased $12.5 million from 1994 because of a $16.5
million decrease in fuel revenues, partly offset by a $4.0 million increase in
non-fuel revenues. The $4.0 million increase in non-fuel revenues was due to
$2.7 million of additional revenue from a base rate increase which became
effective November 1, 1994, and a $1.3 million increase in sales volume. Fuel
revenues decreased $16.5 million in 1995 due to lower average fuel rates charged
to customers and a $6.8 million refund in 1995 of over-recovered fuel costs.
ELECTRIC FUEL AND PURCHASED ENERGY EXPENSES
In 1996, electric fuel and purchased energy expenses increased $59.6 million
compared to 1995. The increase was due to a $32.2 million increase for higher
kWh output; a $21.4 million increase, net of amounts deferred pursuant to fuel
adjustment clauses, due to higher oil, gas, and purchased energy prices; and a
$6.0 million increase in replacement power and PJM capacity charges expensed due
to the Salem outages.
In 1995, electric fuel and purchased energy expenses decreased $14.7 million
from 1994 primarily due to lower kWh output and lower purchased energy prices,
which were partly offset by $4.1 million of replacement power costs expensed due
to the Salem outages.
The kWh output required to serve load within the Company's service territory is
substantially equivalent to total output less interchange deliveries. In 1996,
the Company's output for load within its service territory was provided by 37.6%
coal generation, 28.6% oil and gas generation, 24.5% net purchased power, and
9.3% nuclear generation.
GAS PURCHASED
Gas purchased increased $12.6 million in 1996 compared to 1995, due primarily to
higher average prices paid for gas and a prior year $6.8 million customer refund
of over-recovered fuel costs. The $6.8 million customer refund reduced 1995 gas
purchased expense because fuel expense is adjusted to match fuel revenues as
explained under "Components of Utility Revenues."
For 1995 compared to 1994, gas purchased decreased $15.2 million primarily due
to the $6.8 million customer refund in 1995 and due to variances in fuel costs
deferred and subsequently amortized under the Company's fuel adjustment clause.
PURCHASED ELECTRIC CAPACITY
Purchased electric capacity increased from $3.4 million in 1994 to $29.1 million
in 1995 due to an interim purchased power contract with PECO, effective from
June 19, 1995 to February 1, 1996, that was associated with the Company's
purchase of COPCO. Pursuant to agreements made in conjunction with the COPCO
purchase, in February 1996, a long-term contract with lower-priced capacity
replaced the interim contract. In 1996, purchased electric capacity increased
$3.0 million since electric capacity associated with COPCO was purchased during
the entire year. The increase was mitigated substantially by lower-priced
capacity purchased under the long-term contract.
OPERATION, MAINTENANCE, AND DEPRECIATION EXPENSES
In 1996, operation and maintenance expenses increased $7.3 million due to a $3.7
million increase associated with the Salem outages, a $2.3 million increase from
a full year's operation of the Conowingo District, and $1.3 million of
miscellaneous increases.
In 1995, operation and maintenance expenses decreased $17.8 million in
comparison to 1994, principally due to the $17.5 million expense recorded in
1994 for the ERO. Higher than expected costs of approximately $5 million due to
Salem's operational problems were largely offset by lower payroll costs
attributed to reduced staff levels.
Depreciation expense increased in 1996 and 1995 due to completion of on-going
utility construction projects and the addition of the Conowingo District in June
1995.
UTILITY FINANCING COSTS
For information concerning the 1996 issuance of $70 million of mandatorily
redeemable preferred securities by the Company's subsidiary trust and related
redemptions of preferred stock, see "Liquidity and Capital Resources" and Note
10 to the Consolidated Financial Statements, "Company Obligated Mandatorily
Redeemable Preferred Securities of Subsidiary Trust Holding Solely Company
Debentures."
Interest expense increased $3.6 million in 1996 and $6.3 million in 1995,
primarily due to debt issued in 1995 to finance the acquisition of COPCO.
Allowance for equity and borrowed funds used during construction (AFUDC)
increased $2.2 million in 1996, primarily due to higher average construction
work-in-progress balances, including the cost of software to support the
reporting of financial results by business units beginning in 1997. AFUDC
decreased $2.4 million in 1995, mainly due to a lower AFUDC rate.
Due to common equity financing, the average number of shares of common stock
increased in 1996 and 1995, which lowered earnings per share by $0.01 and $0.03,
respectively.
ENERGY SUPPLY
The Company's energy supply plan reflects its strategy to provide an adequate,
reliable supply of electricity to customers and keep prices competitive, while
minimizing adverse impacts on the environment. The Company's plan, which is
updated annually, is based on forecasts of demand for electricity in the service
territory and reserve requirements of the PJM Interconnection. The Company's
plan emphasizes balance and flexibility, and may be accelerated, slowed, or
altered in response to changing energy demands, fluctuating fuel prices, and
emerging technologies. The plan combines customer-oriented load management and
strategic conservation programs with short-term power purchases, long-term power
contracts, and renovated power plants.
The Company's current plan would enable the Company to meet customers' energy
requirements without making large investments for new resources. The Company
must balance the potential risks of providing too much or insufficient capacity.
The main risks of excess capacity are that the Company's prices may become
uncompetitive or that regulators may not allow the associated costs to be
recovered through customer rates. The principal risks of inadequate capacity are
unreliable service or the payment of capacity deficiency charges to the PJM
Interconnection. The PJM Interconnection requires the Company to plan for and to
provide an adequate capacity level.
During the past three years, the Company's plan has reduced customers' demand
for electricity by an additional 39 MW, and has provided 205 MW of capacity from
a long-term purchased power contract with PECO Energy Company, which began in
1996. Under an amendment to a long-term purchased power contract, the Company's
purchase of 48 MW of peaking capacity from Star Enterprise has been suspended
from October 1, 1996 until June 1, 2000, due to the availability of lower cost
power.
Beginning in 1997 and continuing through 2001, the Company expects it may
purchase up to 200 MW of power under short-term agreements in addition to the
currently existing long-term purchases mentioned above. The Company plans to
keep peak load reductions achieved through customer-oriented load management
programs at existing levels.
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 utility construction
expenditures, expansion into new business lines and other capital requirements,
such as repayment of maturing debt and capital lease obligations. Utility
construction expenditures are the Company's largest on-going capital requirement
and are affected by many factors including growth in demand for electricity,
compliance with environmental regulations, and the periodic need for upgrading
or replacing information systems.
Operating activities provided net cash inflows of $222.7 million in 1996, $239.4
million in 1995, and $224.6 million in 1994. The $16.7 million decrease in 1996
net cash flow from operating activities reflects electric fuel revenues which
were less than electric fuel and energy costs. See "Salem Outages" for a
discussion of the Company's recent electric fuel rate changes and filings.
After deducting common and preferred dividend payments of $102.4 million in
1996, $102.0 million in 1995, and $100.6 million in 1994, internally generated
funds were $120.3 million in 1996, $137.4 million in 1995, and $124.0 million in
1994. Internally generated funds provided 79%, 101%, and 80% of the cash
required for utility construction in 1996, 1995, and 1994, respectively.
Utility construction expenditures, excluding AFUDC, were $151.7 million in 1996,
$135.6 million in 1995, and $154.1 million in 1994. Construction expenditures in
1996, 1995, and 1994 included $4.4 million, $16.4 million, and $20.7 million,
respectively, for projects attributed to environmental compliance. In 1995, the
Company acquired COPCO for $158.2 million ($157.0 million net of cash acquired)
with $125.8 million of long-term debt and the balance with short-term debt.
The amount of cash used to purchase or construct nonutility assets was $15.0
million in 1996, $3.6 million in 1995, and $11.0 million in 1994. Nonutility
assets purchased or constructed during 1994-1996 included construction
expenditures at the Pine Grove Landfill during all three years, assets related
to the start-up of new businesses including HVAC services in 1996, and purchase
of an office building in 1994.
Long-term financings during 1994-1996, net of long-term refinancings and
redemptions, raised $159.2 million of capital. Sources of cash, net of
refinancings and redemptions, included the following: $32.6 million of common
stock; $91.5 million of long-term debt; $43.5 million of variable rate demand
bonds; and $70.0 million of Company obligated mandatorily redeemable preferred
securities issued by the Company's subsidiary trust (as discussed below).
Preferred stock outstanding was reduced by $78.4 million.
In 1994 and 1995, cash was raised from common stock primarily through the
Dividend Reinvestment and Common Share Purchase Plan (DRIP). Depending on the
financing needs of the Company, shares issued through the DRIP may be either
newly issued shares or shares purchased in the open market. In 1996, shares for
the DRIP were purchased in the open market until December 31 when the Company
began raising cash again by issuing new common shares.
In October 1996, a subsidiary trust of the Company issued $70 million of 8.125%
Company obligated mandatorily redeemable preferred securities and loaned the
proceeds to the Company. On a consolidated basis, this financing vehicle results
in a tax benefit which is equivalent to the tax effect of a deduction for
distributions on the preferred securities. The proceeds from the issuance of the
preferred securities and additional short-term debt were used to retire $63.4
million of the Company's preferred stock, which had an average dividend rate of
6.73%, and the Company's $15.0 million, 7.52% series preferred stock in October
and December 1996, respectively. On an after-tax basis, the refinancing will
save approximately $1.5 million annually.
From February 4, 1997 to February 7, 1997, the Company issued $77.0 million of
unsecured Medium Term Notes with maturities of 10 to 30 years and interest rates
of 7.06% to 7.72%. The proceeds were used to repay short-term borrowings which
were outstanding as of December 31, 1996. In recognition of this refinancing,
$77.0 million of short-term debt has been reclassified to long-term debt on the
consolidated balance sheet as of December 31, 1996.
Long-term debt due within one year increased from $1.5 million as of December
31, 1995 to $27.7 million as of December 31, 1996 primarily due to the scheduled
maturity of the Company's 6 3/8% Series First Mortgage Bond on September 1,
1997.
The Company's capital structure as of December 31, 1996 and 1995, expressed as a
percentage of total capitalization, is shown below.
1996 1995
---- ----
Long-term debt and variable rate demand bonds 47.5% 46.3%
Mandatorily redeemable preferred securities 3.3% --
Preferred stock 4.3% 8.3%
Common stockholders' equity 44.9% 45.4%
Capital requirements for the period 1997-1998 are estimated to be $453 million,
including $230 million for utility construction (excluding AFUDC), $64 million
for payment of long-term debt maturities, and $159 million of other requirements
primarily for investments in new business lines.
The Company anticipates that $282 million will be generated internally during
1997-1998, net of power purchase commitments. This represents 62% of estimated
capital requirements and 123% of estimated utility construction expenditures for
1997-1998. During 1997-1998, long-term external financings are presently
estimated at $216 million, including $160 million of long-term debt and $56
million of common stock.
NONUTILITY SUBSIDIARIES
Information on the Company's nonutility subsidiaries, in addition to the
following discussion, can be found in Notes 1, "Significant Accounting
Policies," and 18, "Nonutility Subsidiaries," to the Consolidated Financial
Statements.
Earnings per share resulting from nonutility subsidiaries were $0.10 in 1996,
$0.07 in 1995, and $0.04 in 1994. Start-up costs for new nonutility businesses
incurred in 1996 by the parent company (reflected in "Other income, net of
income taxes") offset the $0.03 increase in 1996 earnings per share of
nonutility subsidiaries. During 1996, 1995, and 1994, nonutility earnings were
generated primarily from the recovery of previously written-off joint venture
assets, the operation of power plants for other parties, gains from the sale of
real estate, and leveraged lease operations.
Earnings per share contributed by nonutility subsidiaries increased in 1996
primarily due to higher recoveries of previously written-off joint venture
assets. Partial year 1996 operating results for the Company's new HVAC and
telecommunication business lines had a minimal effect on earnings.
Nonutility subsidiary earnings in 1994 were reduced by a write-down of oil and
gas wells.
The subsidiaries' solid waste businesses, including the Pine Grove Landfill,
contributed earnings in 1994, but incurred an operating loss in 1995 and 1996. A
permit for expansion of the Pine Grove Landfill is currently pending before the
Pennsylvania Department of Environmental Protection (PADEP). In August 1996, the
Governor of Pennsylvania issued an executive order suspending consideration of
landfill expansion applications until new regulations were written. The Company
is revising its landfill expansion permit application to comply with the new
PADEP guidelines issued in January 1997. The Company will comply with all new
regulations and expects to receive permit approval to avoid any interruption in
landfill services.
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 L.L.P., 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 Barbara S. Graham
Chairman of the Board, President Senior Vice President
and Chief Executive Officer 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 of Delmarva Power &
Light Company and Subsidiary Companies as of December 31, 1996 and 1995, 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, 1996. 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
misstatement. 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, 1996 and 1995, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1996, in conformity with generally
accepted accounting principles.
Coopers & Lybrand L.L.P.
2400 Eleven Penn Center
Philadelphia, Pennsylvania
February 7, 1997
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
(Dollars in Thousands) 1996 1995 1994
- - -----------------------------------------------------------------------------------------------
OPERATING REVENUES
Electric $ 980,677 $ 899,662 $ 883,115
Gas 114,284 95,441 107,906
----------- ----------- -----------
1,094,961 995,103 991,021
----------- ----------- -----------
OPERATING EXPENSES
Electric fuel and purchased energy 327,464 267,885 282,570
Gas purchased 61,208 48,615 63,814
Purchased electric capacity 32,126 29,116 3,370
Operation and maintenance 253,367 246,049 263,837
Depreciation 123,174 113,022 109,523
Taxes other than income taxes 42,386 38,449 38,585
Income taxes 75,856 73,561 66,166
----------- ----------- -----------
915,581 816,697 827,865
----------- ----------- -----------
OPERATING INCOME 179,380 178,406 163,156
----------- ----------- -----------
OTHER INCOME
Nonutility Subsidiaries
Revenues and gains 65,390 52,042 43,142
Expenses including interest and income taxes (59,192) (47,896) (40,790)
----------- ----------- -----------
Net earnings of nonutility subsidiaries 6,198 4,146 2,352
Allowance for equity funds used during
construction 1,338 708 3,389
Other income, net of income taxes (928) 557 (285)
----------- ----------- -----------
6,608 5,411 5,456
----------- ----------- -----------
INCOME BEFORE UTILITY INTEREST CHARGES
AND DIVIDENDS ON PREFERRED SECURITIES 185,988 183,817 168,612
----------- ----------- -----------
UTILITY INTEREST CHARGES
Interest expense 72,026 68,395 62,076
Allowance for borrowed funds used during
construction (3,615) (2,066) (1,774)
----------- ----------- -----------
68,411 66,329 60,302
----------- ----------- -----------
DIVIDENDS ON PREFERRED SECURITIES OF A
SUBSIDIARY TRUST 1,390 -- --
----------- ----------- -----------
EARNINGS
Net income 116,187 117,488 108,310
Dividends on preferred stock 8,936 9,942 9,370
----------- ----------- -----------
Earnings applicable to common stock $ 107,251 $ 107,546 $ 98,940
=========== =========== ===========
COMMON STOCK
Average shares of common stock outstanding (000) 60,698 60,217 59,377
Earnings per average share of common stock $1.77 $1.79 $1.67
Dividends declared per share of common stock $1.54 $1.54 $1.54
See accompanying Notes to Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
(Dollars in Thousands) 1996 1995 1994
- - ----------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 116,187 $ 117,488 $ 108,310
Adjustments to reconcile net income to
net cash provided by operating activities
Depreciation and amortization 128,712 120,897 120,803
Deferred income taxes, net 33,218 15,992 4,829
Provision for early retirement offer -- -- 17,500
Net change in:
Accounts receivable (5,030) (14,022) 7,980
Inventories (4,489) 18,590 (21,409)
Accounts payable 18,418 3,269 5,811
Other current assets & liabilities(1) (48,383) (14,349) (10,668)
Other, net (15,981) (8,437) (8,569)
--------- --------- ---------
Net cash provided by operating activities 222,652 239,428 224,587
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Construction expenditures, excluding AFUDC (151,728) (135,614) (154,119)
Allowance for borrowed funds used during construction (3,615) (2,066) (1,774)
Change in working capital for construction (4,880) 1,102 (439)
Acquisition of COPCO, net of cash acquired -- (157,014) --
Sales of nonutility assets 693 4,970 4,596
Nonutility assets purchased or constructed (15,036) (3,645) (11,045)
Net (increase)/decrease in bond proceeds held in trust funds 7,163 2,658 (11,816)
Deposits to nuclear decommissioning trust funds (4,238) (3,612) (2,438)
Other, net (2,222) (1,859) (744)
--------- --------- ---------
Net cash used by investing activities (173,863) (295,080) (177,779)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends: Common (93,290) (92,221) (91,175)
Preferred (9,102) (9,813) (9,464)
Issuances: Long-term debt(2) -- 125,800 4,640
Variable rate demand bonds -- 15,000 30,000
Common stock 486 24,693 14,974
Preferred securities(3) 70,000 -- --
Redemptions: Long-term debt(2) (1,504) (1,388) (26,096)
Variable rate demand bonds (1,500) -- --
Common stock (5,466) (1,253) (794)
Preferred stock (78,383) -- --
Principal portion of capital lease payments (5,538) (7,875) (11,280)
Net change in term loan(4) -- (45,000) 35,000
Net change in short-term debt 86,498 53,154 10,000
Cost of issuances and refinancings (3,408) (1,523) (601)
--------- --------- ---------
Net cash provided/(used) by financing activities (41,207) 59,574 (44,796)
--------- --------- ---------
Net change in cash and cash equivalents 7,582 3,922 2,012
Beginning of year cash and cash equivalents 28,951 25,029 23,017
--------- --------- ---------
End of year cash and cash equivalents $ 36,533 $ 28,951 $ 25,029
========= ========= =========
(1) Other than debt and deferred income taxes classified as current.
(2) Excluding net change in term loan.
(3) Company obligated mandatorily redeemable preferred securities of subsidiary
trust holding solely Company debentures.
(4) As of December 31, 1994, the Company had a $45.0 million term loan which was
classified as long-term debt.
See accompanying Notes to Consolidated Financial Statements.
CONSOLIDATED BALANCE SHEETS
As of December 31,
(Dollars in Thousands) 1996 1995
- - -----------------------------------------------------------------------------------------
ASSETS
UTILITY PLANT--AT ORIGINAL COST
Electric $3,037,830 $2,942,969
Gas 229,362 208,245
Common 136,897 130,949
---------- ----------
3,404,089 3,282,163
Less: Accumulated depreciation 1,292,325 1,189,269
---------- ----------
Net utility plant in service 2,111,764 2,092,894
Construction work-in-progress 118,208 105,588
Leased nuclear fuel, at amortized cost 31,513 31,661
---------- ----------
2,261,485 2,230,143
---------- ----------
OTHER PROPERTY AND INVESTMENTS
Nonutility property, net 63,023 50,011
Investment in leveraged leases 46,961 48,367
Funds held by trustee 34,735 36,275
Other investments 4,155 4,770
---------- ----------
148,874 139,423
---------- ----------
CURRENT ASSETS
Cash and cash equivalents 36,533 28,951
Accounts receivable 142,431 131,236
Inventories, at average cost
Fuel (coal, oil, and gas) 36,584 30,076
Materials and supplies 41,292 36,823
Prepayments 20,233 12,969
Deferred energy costs 31,127 --
Deferred income taxes, net -- 5,400
---------- ----------
308,200 245,455
---------- ----------
DEFERRED CHARGES AND OTHER ASSETS
Prepaid employee benefit costs 35,146 16,899
Unamortized debt expense 13,858 12,256
Deferred debt refinancing costs 21,366 23,972
Deferred recoverable income taxes 137,561 151,250
Other 52,663 47,287
---------- ----------
260,594 251,664
---------- ----------
Total $2,979,153 $2,866,685
========== ==========
See accompanying Notes to Consolidated Financial Statements.
CONSOLIDATED BALANCE SHEETS
As of December 31,
(Dollars in Thousands) 1996 1995
- - ------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock, $2.25 par value; 90,000,000 shares authorized;
shares outstanding: 1996--60,682,719, 1995--60,759,365 $ 136,765 $ 136,713
Additional paid-in capital 508,300 506,328
Retained earnings 293,604 281,862
---------- ----------
938,669 924,903
Treasury shares, at cost:
1996--101,831 shares, 1995-1,320 shares (2,138) (30)
Unearned compensation (1,618) (1,433)
---------- ----------
Total common stockholders' equity 934,913 923,440
Cumulative preferred stock 89,703 168,085
Company obligated mandatorily redeemable
preferred securities of subsidiary trust holding
solely Company debentures 70,000 --
Long-term debt 904,033 853,904
---------- ----------
1,998,649 1,945,429
---------- ----------
CURRENT LIABILITIES
Short-term debt 74,355 63,154
Long-term debt due within one year 27,676 1,485
Variable rate demand bonds 85,000 86,500
Accounts payable 81,628 64,056
Interest accrued 16,193 16,355
Dividends declared 23,265 23,426
Current capital lease obligation 12,598 12,604
Deferred income taxes, net 7,276 --
Other 31,489 36,773
---------- ----------
359,480 304,353
---------- ----------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes, net 526,449 519,597
Deferred investment tax credits 42,501 45,061
Long-term capital lease obligation 20,552 20,768
Other 31,522 31,477
---------- ----------
621,024 616,903
---------- ----------
Commitments and Contingencies (Notes 14 and 17) -- --
Total $2,979,153 $2,866,685
========== ==========
See accompanying Notes to Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCKHOLDERS' EQUITY
Common Additional Unearned
Shares Par Paid-in Retained Treasury Compen-
(Dollars in Thousands) Outstanding Value (1) Capital Earnings Stock sation Total
- - --------------------------------------------------------------------------------------------------------------------------------
Balance as of January 1, 1994 58,829,283 $132,366 $470,997 $259,507 $ -- $ (675) $862,195
Net income 108,310 108,310
Cash dividends declared
Common stock ($1.54 per share) (91,436) (91,436)
Preferred stock (9,370) (9,370)
Issuance of common stock
DRIP(2) 703,726 1,584 13,199 14,783
Other issuance 8,997 20 171 191
Reacquired common stock (36,840) (794) (794)
Common shares granted(3) 36,840 794 (794) --
Amortization of unearned compensation 289 289
Other 10 (9) 1
---------- -------- -------- -------- ------- ------- --------
Balance as of December 31, 1994 59,542,006 133,970 484,377 267,002 -- (1,180) 884,169
Net income 117,488 117,488
Cash dividends declared
Common stock ($1.54 per share) (92,686) (92,686)
Preferred stock (9,942) (9,942)
Issuance of common stock
DRIP(2) 1,210,048 2,723 21,806 24,529
Stock options 3,900 9 63 72
Other issuance 4,731 11 82 93
Reacquired common stock (63,370) (1,253) 19 (1,234)
Common shares granted(3) 62,050 1,223 (1,223) --
Amortization of unearned compensation 951 951
---------- -------- -------- -------- ------- ------- --------
Balance as of December 31, 1995 60,759,365 136,713 506,328 281,862 (30) (1,433) 923,440
Net income 116,187 116,187
Cash dividends declared
Common stock ($1.54 per share) (93,294) (93,294)
Preferred stock (8,936) (8,936)
Issuance of common stock
Business acquisitions 212,350 4,396 4,396
DRIP(2) 21,465 47 388 435
Stock options 2,400 5 45 50
Expenses (72) (72)
Reacquired common stock (312,861) 532 (6,504) 363 (5,609)
Amortization of unearned compensation 687 (548) 139
Refinancing of preferred stock 392 (2,215) (1,823)
---------- -------- -------- -------- ------- ------- --------
Balance as of December 31, 1996 60,682,719 $136,765 $508,300 $293,604 $(2,138) $(1,618) $934,913
========== ======== ======== ======== ======= ======= ========
(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, 1996, 4,979,971 shares remained available under the Company's
registration statement filed with the Securities and Exchange Commission
for issuance of shares 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SIGNIFICANT ACCOUNTING POLICIES
Nature of Business
The Company is predominately a public utility that provides electric and gas
service. The Company provides electric service to retail (residential,
commercial, and industrial) and wholesale (resale) customers in Delaware, ten
primarily Eastern Shore counties in Maryland, and the Eastern Shore area of
Virginia in an area consisting of about 6,000 square miles with a population of
approximately 1.2 million. In 1996, 90% of the Company's operating revenues were
derived from the sale of electricity. The Company provides gas service to retail
and transportation customers in an area consisting of about 275 square miles
with a population of approximately 475,000 in northern Delaware, including the
City of Wilmington.
In addition, the Company and its wholly owned subsidiaries are engaged in
nonutility activities. The Company is developing and marketing energy-related
products and services primarily targeted to customers in retail markets. The
Company's primary nonutility activities are heating, ventilation, and air-
conditioning (HVAC) services; telecommunication services; landfill and
wastehauling operations; operation and maintenance of energy-related projects;
real estate sales and developments; and leveraged equipment leases.
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
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, the transmission of electricity, the wholesale sale of
electricity, and interchange and other purchases and sales of electricity
involving other utilities. The FERC also regulates the price and other terms of
transportation of natural gas purchased by the Company. The percentage of
electric and gas utility operating revenues regulated by each Commission for the
year ended December 31, 1996, was as follows: DPSC, 61.9%; MPSC, 28.8%; VSCC,
2.8%; and FERC, 6.5%.
Refer to Note 8, "Regulatory Assets," to the Consolidated Financial Statements
for a discussion of regulatory assets arising from the financial effects of rate
regulation.
Reporting of Subsidiaries
The consolidated financial statements include the accounts of the Company's
wholly owned subsidiaries. All significant intercompany accounts and
transactions are eliminated in consolidation. The results of operations of the
Company's nonutility subsidiaries are reported in the Consolidated Statements of
Income as "Other Income." Refer to Note 18, "Nonutility Subsidiaries," to the
Consolidated Financial Statements for financial information about the Company's
nonutility subsidiaries.
Use of Estimates
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make certain estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Utility Revenues
At the end of each month, there is an amount of electric and gas service
rendered from the last meter reading to the month-end which has not yet been
billed to customers. The non-fuel (base rate) revenues associated with such
unbilled services are accrued by the Company.
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 generally are 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 Consolidated Balance Sheets 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 3.6% for 1996, 1995 and
1994. Depreciation expense includes a provision for the Company's share of the
estimated cost of decommissioning nuclear power plant reactors based on amounts
billed to customers for such costs. Refer to Note 6, "Nuclear Decommissioning,"
to the Consolidated Financial Statements for additional information on nuclear
decommissioning.
Income Taxes
Refer to Note 3, "Income Taxes," for the Company's accounting policy on income
taxes and investment tax credits.
Debt Refinancing Costs
Costs of refinancing debt are deferred and amortized over the period during
which the refinancing costs are recovered in utility rates.
Interest Expense
The amortization of debt discount, premium, and expense, including refinancing
expenses, is included in interest expense.
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. In the Consolidated Statements
of Income, the borrowed funds component of AFUDC is reported under "Utility
Interest Charges" as a reduction of interest expense and the equity funds
component of AFUDC is reported as "Other Income." AFUDC was capitalized on
utility plant construction at the rates of 6.7% in 1996, 7.1% in 1995, and 9.3%
in 1994.
Stock-based Employee Compensation
Refer to Note 9, "Common Stock," for the Company's accounting policy on stock-
based employee compensation.
Capitalized Software Costs
The Company capitalizes software projects which exceed $1 million. Capitalized
software costs net of accumulated depreciation were $31.6 million as of December
31, 1996 and $8.2 million as of December 31, 1995. Capitalized software costs
are amortized over periods of 5 to 10 years.
Leveraged Leases
As of December 31, 1996, the Company's portfolio of leveraged leases, held by a
nonutility subsidiary, consists of five aircraft which are leased to three
separate airlines. 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 include deposits in the Company's external
nuclear decommissioning trusts and unexpended, restricted, tax-exempt bond
proceeds. Earnings on such trust funds are also reflected in the balance.
Cash Equivalents
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.
2. SUPPLEMENTAL CASH FLOW INFORMATION
CASH PAID DURING THE YEAR
(Dollars in Thousands) 1996 1995 1994
- - -------------------------------------------------------------------------------
Interest, net of capitalized amount $67,596 $62,660 $57,837
Income taxes, net of refunds $56,582 $66,764 $67,922
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.
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
portion of the Company's deferred tax liability applicable to utility operations
that has not been reflected in current customer rates represents income taxes
recoverable through future rates and is reflected on the Consolidated Balance
Sheets as "Deferred recoverable income taxes." Deferred recoverable income taxes
were $137.6 million and $151.3 million as of December 31, 1996 and 1995,
respectively.
Deferred income tax expense represents the net change during the reporting
period in the net deferred tax liability and deferred recoverable income taxes.
Investment tax credits (ITC) from regulated operations are being amortized over
the useful lives of the related utility plant. ITC associated with leveraged
leases are being amortized over the lives of the related leases during the
periods in which the net investment is positive.
COMPONENTS OF CONSOLIDATED INCOME TAX EXPENSE
(Dollars in Thousands) 1996 1995 1994
- - --------------------------------------------------------------------------------
Operation
Federal: Current $32,937 $46,517 $50,276
Deferred 31,670 16,452 5,592
State: Current 6,536 9,851 11,268
Deferred 7,273 3,257 928
Investment tax credit adjustments, net (2,560) (2,516) (1,898)
------- ------- -------
Total Operation 75,856 73,561 66,166
------- ------- -------
Other income
Federal: Current 8,016 5,263 2,789
Deferred (5,539) (3,686) (2,008)
State: Current 193 433 349
Deferred (186) (31) 317
------- ------- -------
Total Other Income 2,484 1,979 1,447
------- ------- -------
Total income tax expense $78,340 $75,540 $67,613
======= ======= =======
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.
1996 1995 1994
(Dollars in Thousands) Amount Rate Amount Rate Amount Rate
- - --------------------------------------------------------------------------------------------------------------------------------
Statutory federal income
tax expense $68,084 35% $67,560 35% $ 61,574 35%
Increase (decrease) due to
State income taxes, net of
federal tax benefit 8,980 5 8,792 5 8,361 4
Other, net 1,276 -- (812) (1) (2,322) (1)
------- -- ------- -- -------- --
Total income tax expense $78,340 40% $75,540 39% $ 67,613 38%
======= == ======= == ======== ==
COMPONENTS OF DEFERRED INCOME TAXES
The tax effect of temporary differences that give rise to the Company's net
deferred tax liability are shown below.
As of December 31,
(Dollars in Thousands) 1996 1995
- - ---------------------------------------------------------------------------------------------
Deferred Tax Liabilities
Utility plant basis differences
Accelerated depreciation $310,343 $307,346
Other 107,186 99,941
Leveraged leases 41,604 44,662
Deferred recoverable income taxes 58,747 64,376
Deferred energy costs 13,240 --
Other 75,005 54,507
-------- --------
Total deferred tax liabilities 606,125 570,832
-------- --------
Deferred Tax Assets
Deferred ITC 14,876 15,719
Other 57,524 40,916
-------- --------
Total deferred tax assets 72,400 56,635
-------- --------
Total deferred taxes, net $533,725 $514,197
======== ========
Valuation allowances for deferred tax assets were not material as of December
31, 1996 and 1995.
4. MERGERS AND ACQUISITIONS
Pending Merger with Atlantic Energy, Inc.
On August 9, 1996, the Company and Atlantic Energy, Inc. (Atlantic) announced
plans for a business combination of the Company and Atlantic in a merger of
equals. Conectiv, Inc., a Delaware corporation, was newly formed to accomplish
the merger and its outstanding capital stock is owned 50% by the Company and 50%
by Atlantic. After the merger, Conectiv, Inc. will become the parent company of
the Company and its direct and indirect subsidiaries and of the direct and
indirect subsidiaries of Atlantic. Conectiv, Inc., whose name will be changed to
Conectiv at the time of the merger, will be a holding company registered under
the Public Utility Holding Company Act of 1935, as amended.
Atlantic is a public utility holding company with three wholly owned
subsidiaries, Atlantic City Electric Company (ACE), Atlantic Energy Enterprises,
Inc., and Atlantic Energy International, Inc. ACE, which is Atlantic's regulated
utility subsidiary, is primarily engaged in the generation, transmission,
distribution, and sale of electric energy to about 478,000 customers in an area
consisting of 2,700 square miles in southern New Jersey. Atlantic's 1996
operating revenues and net income were $980.3 million and $58.8 million,
respectively, and its total assets were $2,670.8 million as of December 31,
1996.
On January 30, 1997 the merger was approved by the stockholders of the Company
and Atlantic. The merger is expected to close shortly after all remaining
conditions to the consummation of the merger, including obtaining applicable
regulatory approvals, are met or waived. The regulatory approval process is
expected to be completed in late 1997 or early 1998.
As a result of the merger, each outstanding share of the Company's common stock,
par value $2.25 per share, will be exchanged for one share of Conectiv's common
stock, par value $0.01 per share. Each share of Atlantic's common stock, no par
value per share, will be exchanged for 0.75 of one share of Conectiv's common
stock and 0.125 of one share of Conectiv's Class A common stock, par value $0.01
per share. The preferred stock of the Company will remain outstanding and
unchanged. The purchase method of accounting will be used to account for the
merger.
The total consideration to be paid to Atlantic's common stockholders, measured
by the average daily closing market price of Atlantic's common stock for the ten
trading days following the public announcement of the merger, is $948.6 million.
The consideration paid plus estimated acquisition costs and liabilities assumed
in connection with the merger are expected to exceed the net book value of
Atlantic's net assets by approximately $204.5 million, which will be recorded as
goodwill. The goodwill will be amortized over 40 years.
Acquisition of Conowingo Power Company
On June 19, 1995, the Company acquired Conowingo Power Company (COPCO), the
Maryland retail electric subsidiary of PECO Energy Company (PECO), for $158.2
million ($157.0 million net of cash acquired). The Company financed the
acquisition with $125.8 million of long-term debt and the balance with short-
term debt. COPCO was merged into the Company and is now being operated as the
Conowingo District. Approximately 37,500 electric retail customers were added to
the Company's customer base.
The acquisition was accounted for as a purchase and, accordingly, the operating
results of the Conowingo District are included in the Consolidated Statements of
Income starting June 19, 1995. The purchase price included $76 million of
goodwill which is being amortized on a straight-line basis over 40 years.
Assuming that the COPCO acquisition had occurred at the beginning of 1995 and
1994, the Company's pro forma operating results for these years would not have
been materially different from the operating results reported.
5. EARLY RETIREMENT OFFER
In the third quarter of 1994, the Company completed a voluntary early retirement
offer (ERO) for all management and union employees at least 55 years old with at
least 10 years of continuous service by December 31, 1994. The ERO was accepted
by 10.5% of the Company's workforce (296 people), which represented an 82%
participation rate among eligible employees. In accordance with Statement of
Financial Accounting Standards (SFAS) No. 88, "Employers' Accounting for
Settlements and Curtailments of Defined Benefit Pension Plans and for
Termination Benefits," the Company expensed $17.5 million of costs associated
with the ERO ($10.7 million after taxes or $0.18 per share).
6. NUCLEAR DECOMMISSIONING
The Company records a liability for its share of the estimated cost of
decommissioning the Peach Bottom and Salem nuclear reactors over the remaining
lives of the plants based on amounts collected in rates charged to electric
customers. For utility rate-setting purposes, the Company estimates its share of
future nuclear decommissioning costs based on NRC regulations concerning the
minimum financial assurance amount for nuclear decommissioning. The Company is
presently recovering, through electric rates in the Delaware and Virginia
jurisdictions, nuclear decommissioning costs based on the current NRC minimum
financial assurance amount of approximately $130 million. In the Maryland and
FERC jurisdictions, the Company is presently recovering nuclear decommissioning
costs based on the 1990 NRC minimum financial assurance amount of approximately
$50 million.
The Company's accrued nuclear decommissioning liability, which is reflected in
the accumulated reserve for depreciation, was $42.9 million as of December 31,
1996. The provision reflected in depreciation expense for nuclear
decommissioning was $4.2 million in 1996, $3.6 million in 1995, and $2.4 million
in 1994. External trust funds established by the Company for the purpose of
funding nuclear decommissioning costs had an aggregate book balance of $31.1
million (fair value of $35.3 million) as of December 31, 1996. Earnings on the
trust funds are recorded as an increase to the accrued nuclear decommissioning
liability, which, in effect, reduces the expense recorded for nuclear
decommissioning.
The ultimate cost of nuclear decommissioning for the Peach Bottom and Salem
reactors may exceed the NRC minimum financial assurance amount, which is updated
annually under a NRC prescribed formula.
The staff of the Securities and Exchange Commission has questioned certain of
the current accounting practices of the electric utility industry, including the
Company, regarding the recognition, measurement and classification of
decommissioning costs for nuclear generating stations in the financial
statements of electric utilities. In February 1996, the Financial Accounting
Standards Board (FASB) issued the Exposure Draft, "Accounting for Certain
Liabilities Related to Closure or Removal of Long-Lived Assets," which proposes
changes in the accounting for closure and removal costs of long-lived assets,
including the recognition, measurement, and classification of decommissioning
costs for nuclear generating stations. If the proposed changes are adopted: (1)
annual provisions for decommissioning would increase, (2) the estimated cost for
decommissioning would be recorded as a liability rather than as accumulated
depreciation, and (3) trust fund income from the external decommissioning trusts
would be reported as investment income rather than as a reduction to
decommissioning expense.
7. JOINTLY OWNED PLANT
The Company's Consolidated Balance Sheets include 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, 1996 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% 164 MW $130,196 $ 76,251 $12,426
Salem 7.41% 164 MW 216,788 102,568 24,548
Coal-Fired
Keystone 3.70% 63 MW 19,943 8,236 307
Conemaugh 3.72% 63 MW 33,274 9,821 342
Transmission Facilities Various 4,564 2,205 --
Other Facilities Various 1,746 179 1,633
-------- -------- -------
Total $406,511 $199,260 $39,256
======== ======== =======
8. REGULATORY ASSETS
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 SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation," the Company defers
expense recognition of certain costs and records an asset, a result of the
effects of rate regulation. Except for Deferred Energy Costs which is classified
as a current asset, these "regulatory assets" are included on the Company's
Consolidated Balance Sheets under "Deferred Charges and Other Assets." As of
December 31, 1996, the Company had $219.7 million of regulatory assets, which
included the following: Deferred Energy Costs--$31.1 million; Deferred debt
refinancing costs--$21.4 million; Deferred recoverable income taxes--$137.6
million (refer to Note 3, "Income Taxes," to the Consolidated Financial
Statements); Deferred recoverable plant costs--$7.9 million; Deferred costs for
decontamination and decommissioning of United States Department of Energy
gaseous diffusion enrichment facilities--$6.8 million; Deferred demand-side
management costs--$6.1 million; and other regulatory assets--$8.8 million. The
costs of these assets either are being recovered or are probable of being
recovered through customer rates. Generally, the costs of these assets are
recognized in operating expenses over the period the cost is recovered from
customers.
9. COMMON STOCK
Refer to the Consolidated Statements of Changes in Common Stockholders' Equity
for information concerning issuances and redemptions of common stock during
1994-1996.
The merger agreement with Atlantic (discussed in Note 4, "Mergers and
Acquisitions") contains a restriction on the payment of dividends on common
stock. Under the merger agreement, the Company's annual per share common stock
dividend cannot exceed $1.54 through the effective date of the merger.
The Company's Long Term Incentive Plan (LTIP) provides long-term incentives to
key employees through awards of stock-based compensation. Up to 1,500,000 shares
of common stock may be issued under the LTIP during the ten-year period from May
31, 1996 through May 30, 2006. Currently, awards granted under the LTIP consist
entirely of shares of performance-based restricted stock which are contingently
granted and earned over a four-year period to the extent that performance
targets are satisfied. Restrictions on shares contingently granted in 1994-1996
will lapse upon the earlier of the effective date of the pending merger with
Atlantic or the end of the four year vesting period. Restrictions will not lapse
due to consummation of the merger on shares contingently granted in 1997 through
the effective date of the pending merger with Atlantic. During 1996, 1995, and
1994, the number of restricted shares contingently granted and their fair value
as of grant date was as follows: 1996--48,750 shares, $22 3/4 per share fair
value; 1995--62,050 shares, $18 9/64 per share fair value; 1994--36,840 shares,
$23 5/8 per share fair value. Formerly, the LTIP also provided for stock options
and dividend rights; some of the stock options are still outstanding. Changes in
stock options are summarized below.
1996 1995 1994
Number Weighted Number Weighted Number Weighted
of Shares Average Price of Shares Average Price of Shares Average Price
- - -----------------------------------------------------------------------------------------------------------
Beginning-of-year
balance 46,350 $20.16 53,050 $20.03 53,050 $20.03
Options exercised 2,400 $19.69 3,900 $17.85 --- ---
Options forfeited ---- ---- 2,800 $20.98 --- ---
End-of-year balance 43,950 $20.19 46,350 $20.16 53,050 $20.03
Exercisable 43,950 $20.19 46,350 $20.16 53,050 $20.03
For options outstanding as of December 31, 1996, the range of exercise prices
was $17 1/2 to $21 1/4 and the weighted average remaining contractual life was
3.5 years.
The Company recognizes compensation costs for its stock-based employee
compensation plans based on the accounting prescribed by Accounting Principles
Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees." Stock-
based employee compensation costs charged to expense were $0.3 million in 1996,
$1.3 million in 1995, and $0.6 million in 1994. Pro forma net income and
earnings per share for 1996, 1995, and 1994, based on application of SFAS No.
123, "Accounting for Stock-Based Compensation" are not materially different from
net income and earnings per share as reported.
10. COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY
TRUST HOLDING SOLELY COMPANY DEBENTURES
A wholly owned subsidiary trust (Delmarva Power Financing I) was established in
1996 as a financing subsidiary of the Company for the purposes of issuing common
and preferred trust securities and holding 8.125% Junior Subordinated Debentures
(the Debentures). The Debentures held by the trust are its only assets. The
trust will use interest payments received on the Debentures it holds to make
cash distributions on the trust securities.
The combination of the obligations of the Company pursuant to the Debentures,
agreements to pay the expenses of the trust and the Company's guarantee of
distributions with respect to trust securities, to the extent the trust has
funds available therefor, constitute a full and unconditional guarantee by the
Company of the obligations of the trust under
the trust securities the trust has issued. The Company is the owner of all of
the common securities of the trust, which constitute approximately 3% of the
liquidation amount of all of the trust securities issued by the trust.
In October 1996, the trust issued $70 million in aggregate liquidation amount of
8.125% Cumulative Trust Preferred Capital Securities (representing 2,800,000
preferred securities at $25 per security). At the same time, $72,165,000 in
aggregate principal amount of 8.125% Junior Subordinated Debentures, Series I,
due 2036 were issued to the trust. For consolidated financial reporting
purposes, the Debentures are eliminated in consolidation against the trust's
investment in the Debentures. The preferred trust securities are subject to
mandatory redemption upon payment of the Debentures at maturity or upon
redemption. The Debentures are subject to redemption, in whole or in part at the
option of the Company, at 100% of their principal amount plus accrued interest,
after an initial period during which they may not be redeemed and at any time
upon the occurrence of certain events.
In October 1996, the Company used part of the proceeds from the trust to
purchase and retire $63,382,700 (par value) of its preferred stock as follows:
$1,013,400 of the 3.70% series ($100 par value); $2,012,600 of the 4% series
($100 par value); $2,459,600 of the 4.2% series ($100 par value); $2,154,000 of
the 4.28% series ($100 par value); $3,042,900 of the 4.56% series ($100 par
value); $3,147,700 of the 5% series ($100 par value); $16,500,000 of the 6.75%
series ($100 par value); $32,087,500 of the 7.75% series ($25 par value), and
$965,000 of the Adjustable Rate series ($100 par value). In December 1996, the
Company used the balance of the proceeds and cash from short-term debt to fund
the redemption of its entire 7.52% preferred stock series which had a total par
value of $15,000,000.
11. CUMULATIVE PREFERRED STOCK
The Company has $1, $25, and $100 par value per share preferred stock for which
10,000,000; 3,000,000; and 1,800,000 shares are authorized, respectively. No
shares of the $1 par value per share preferred stock are outstanding. Shares
outstanding for each series of the $25 and $100 par value per share preferred
stock are listed below. Redemptions of preferred stock in 1996 are discussed in
Note 10 to the Consolidated Financial Statements, "Company Obligated Mandatorily
Redeemable Preferred Securities of Subsidiary Trust Holding Solely Company
Debentures."
Current Shares Amount
Redemption Outstanding (Dollars in Thousands)
Series Price 1996 1995 1996 1995
- - ------------------------------------------------------------------------------------------------
$25 per share par value
7 3/4% (1) 316,500 1,600,000 $ 7,913 $40,000
$100 per share par value
3.70%-5% $103.00-$105.00 181,698 320,000 18,170 32,000
6 3/4% (2) 35,000 200,000 3,500 20,000
7.52% -- -- 150,000 -- 15,000
Adjustable rate(3) $100 151,200 160,850 15,120 16,085
Auction rate(4) $100 450,000 450,000 45,000 45,000
------- --------
$89,703 $168,085
======= ========
(1) Redeemable beginning September 30, 2002, at $25 per share.
(2) Redeemable beginning November 1, 2003, at $100 per share.
(3) Average rates during 1996 and 1995 were 5.5% and 5.6%, respectively.
(4) Average rates during 1996 and 1995 were 4.1% and 4.5%, respectively.
12. DEBT
Substantially all utility plant of the Company is subject to the lien of the
Mortgage and Deed of Trust collateralizing the Company's First Mortgage Bonds.
As of December 31, 1996, the Company had $150 million of unused bank lines of
credit. The Company generally is required to pay annual commitment fees of 0.10%
for its credit lines. The lines of credit are reviewed periodically by the
Company, at which time they may be renewed or cancelled. The weighted average
interest rates on short-term debt outstanding as of December 31, 1996 and 1995
were 5.6% and 5.3%, respectively.
Maturities of long-term debt and sinking fund requirements during the next five
years are as follows: 1997--$29.4 million; 1998--$35.1 million; 1999--$37.5
million; 2000--$4.2 million; 2001--$5.2 million.
From February 4, 1997 to February 7, 1997, the Company issued $77.0 million of
unsecured Medium Term Notes with maturities of 10 to 30 years and interest rates
of 7.06% to 7.72%. The proceeds were used to repay short-term borrowings which
were outstanding as of December 31, 1996. In recognition of this refinancing,
$77.0 million of short-term debt has been reclassified to long-term debt on the
consolidated balance sheet as of December 31, 1996. Long-term debt outstanding
as of December 31, 1996 and 1995 is presented below:
(Dollars in Thousands) Interest Rates Due 1996 1995
- - ------------------------------------------------------------------------------------------------
First Mortgage Bonds: 6 3/8% 1997 $ 25,000 $ 25,000
6.40%-6.95% 2002-2003 120,000 120,000
7.30%-8.15% 2014-2015 81,000 81,000
5.90%-8.50% 2018-2022 208,200 208,200
7.71% 2025 100,000 100,000
6.05% 2032 15,000 15,000
Amortizing First Mortgage Bonds 6.95% 1997-2008 25,800 25,800
-------- --------
Total First Mortgage Bonds 575,000 575,000
Other Bonds 7.15%-7.50% 2011-2017 54,500 54,500
Pollution Control Notes:
Series 1973 5 3/4% 1997-1998 6,125 6,250
Series 1976 7 1/8%-7 1/4% 1997-2006 3,000 3,100
Medium Term Notes: 5.69% 1998 25,000 25,000
7 1/2% 1999 30,000 30,000
8.30%-9.29% 2002-2004 39,000 39,000
7.06%-8 1/8% 2007 81,000 50,000
7.55%-7.62% 2017 10,000 --
7.61%-9.95% 2020-2021 67,000 61,000
7.72% 2027 30,000 --
Other Obligations: 8.09% 1997-2002 1,502 940
8.00% 1999(1) 3,970 4,279
9.65% 2002(2) 6,184 6,938
Unamortized premium and discount, net (572) (618)
Current maturities of long-term debt (27,676) (1,485)
-------- --------
Total long-term debt 904,033 853,904
Variable Rate Demand Bonds(3) 85,000 86,500
-------- --------
Total long-term debt
and Variable Rate Demand Bonds $989,033 $940,404
======== ========
(1) Repaid through monthly payments of principal and interest using a 15-year
principal amortization, with the unpaid balance due in September 1999.
(2) Repaid through monthly payments of principal and interest over 15 years
ending November 2002.
(3) The Company's debt obligations included Variable Rate Demand Bonds (VRDB)
in the amounts of $85.0 million as of December 31, 1996 and $86.5 million
as of December 31, 1995. The VRDB are classified as current liabilities
because the VRDB are due on demand by the bondholder. However, bonds
submitted to Delmarva for purchase are remarketed by a remarketing agent on
a best efforts basis. Delmarva expects that bonds submitted for purchase
will continue to be remarketed successfully due to Delmarva's credit
worthiness and the bonds' interest rates being set at market. The Company
also may utilize one of the fixed rate/fixed term conversion options of the
bonds. Thus, the Company considers the VRDB to be a source of long-term
financing. The $85.0 million balance of VRDB outstanding as of December 31,
1996, matures in 2017 ($26 million), 2019 ($13.5 million), 2028 ($15.5
million), and 2029 ($30 million). Average annual interest rates on the VRDB
were 3.6% in 1996 and 4.0% in 1995.
13. FAIR VALUE OF FINANCIAL INSTRUMENTS
The year-end fair values of certain financial instruments are listed below. The
fair values were based on quoted market prices of the Company's securities or
securities with similar characteristics.
1996 1995
Carrying Fair Carrying Fair
(Dollars in Thousands) Amount Value Amount Value
- - ----------------------------------------------------------------------------------
Funds held by trustee $ 34,735 $ 38,908 $ 36,275 $ 37,060
Company Obligated Mandatorily
Redeemable Preferred Securities
of Subsidiary Trust Holding
Solely Company Debentures $ 70,000 $ 71,064 -- --
Long-Term Debt $904,033 $944,670 $853,904 $936,480
14. COMMITMENTS
The Company currently estimates its commitments for construction of utility
plant, excluding AFUDC, and purchases under fuel supply contracts, excluding
nuclear fuel, to be approximately $183 million in 1997 and $198 million in 1998.
The Company has a 26-year agreement with Star Enterprise effective through May
2018, to purchase 48 MW of capacity supplied by the Delaware City Power Plant.
By mutual agreement, the capacity portion of the contract has been suspended
from October 1, 1996 until June 1, 2000. In conjunction with the COPCO
acquisition, the Company agreed to purchase capacity and energy from PECO
effective June 19, 1995, through May 31, 2006. The base amount of the capacity
purchase, which is subject to certain possible adjustments, starts at 205
megawatts (MW) and increases annually to 279 MW in 2006. Under the terms of the
agreements with Star Enterprise and PECO, the Company's expected commitments for
capacity and energy charges are as follows: 1997--$57.7 million; 1998--$61.1
million; 1999--$68.6 million; 2000--$76.3 million; 2001--$79.4 million; after
2001--$431.5 million; total--$774.6 million.
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 $31.5 million as of
December 31, 1996.
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 $154.3 million in aggregate. The Company also has long-
term leases for certain other facilities and equipment. Minimum commitments as
of December 31, 1996 under the Merrill Creek Reservoir lease and all other
noncancelable lease agreements (excluding payments under the nuclear fuel energy
contract which cannot be reasonably estimated) are as follows: 1997--$6.5
million; 1998--$6.4 million; 1999--$6.2 million; 2000--$5.0 million; 2001--$4.9
million; after 2001--$137.0 million; total--$166.0 million. Approximately 93% of
the minimum lease commitments shown above are payments due under the Merrill
Creek Reservoir lease.
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) 1996 1995 1994
- - ----------------------------------------------------------------
Interest on capital leases $ 1,628 $ 1,773 $ 1,560
Amortization of capital leases 5,653 8,044 11,456
Operating leases 13,795 13,619 14,552
------- ------- -------
$21,076 $23,436 $27,568
======= ======= =======
15. 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.
Based on fair values as of December 31, 1996, pension plan assets were comprised
of the following: publicly traded equity securities ($472.5 million or 70%),
U.S. government obligations ($101.2 million or 15%), and primarily investment
grade corporate and other fixed income obligations ($102.5 million or 15%).
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) 1996 1995
- - -----------------------------------------------------------------------------------
Accumulated benefit obligation
Vested $ 330,639 $ 338,485
Nonvested 24,869 26,024
--------- ---------
355,508 364,509
Effect of estimated future compensation increases 95,132 109,706
--------- ---------
Projected benefit obligation 450,640 474,215
Plan assets at fair value 676,189 616,600
--------- ---------
Excess of plan assets over projected benefit obligation 225,549 142,385
Unrecognized prior service cost 28,980 29,191
Unrecognized net gain (196,496) (124,850)
Unrecognized net transition asset (26,513) (29,827)
--------- ---------
Prepaid pension cost $ 31,520 $ 16,899
========= =========
Components of Net Pension Cost
(Dollars in Thousands) 1996 1995 1994
- - ------------------------------------------------------------------------------------------------
Service cost--benefits earned during period $ 13,172 $ 9,719 $ 10,939
Interest cost on projected benefit obligation 32,531 30,654 26,574
Actual return on plan assets (82,488) (135,850) 3,349
Net amortization and deferral 22,164 83,981 (52,601)
--------- --------- ---------
Net pension cost $ (14,621) $ (11,496) $ (11,739)
========= ========= =========
Assumptions 1996 1995 1994
- - ------------------------------------------------------------------------------------------------
Discount rates used to determine projected
benefit obligation as of December 31 7.50% 7.00% 8.25%
Rates of increase in compensation levels 5.00% 5.00% 5.50%
Expected long-term rates of return on assets 9.00% 8.75% 8.25%
The net pension cost excludes the expense recorded in 1994 under SFAS No. 88 for
the Company's ERO. Prepaid pension cost as of December 31, 1994, was reduced by
the ERO. Refer to Note 5, "Early Retirement Offer," to the Consolidated
Financial Statements for additional information on the ERO.
The Company maintains a 401(k) savings plan for its employees. The plan provides
for employee contributions up to 15% of pay and for $0.50 in matching
contributions by the Company for each dollar contributed up to 5% of employee
pay. The Company's matching contributions charged to expense were $2.4 million
in 1996, and $2.3 million in 1995 and 1994.
16. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The Company provides health-care and life insurance benefits to its retired
employees and substantially all of the Company's employees may become eligible
for these benefits upon retirement. The Company's policy is to fund its
obligation to the extent that costs are reflected in customer rates, including
amounts which are capitalized. Based on fair values as of December 31, 1996, the
plan's assets consisted of $24.3 million (67%) of equity securities, including
mutual funds and directly owned publicly traded securities, and $11.8 million
(33%) of intermediate term investment grade bond mutual funds.
The following schedules show the funded status of the plan, the components of
the cost of postretirement benefits other than pensions, and assumptions.
Reconciliation of Funded Status of the Plan
As of December 31,
(Dollars in Thousands) 1996 1995
- - ----------------------------------------------------------------------------
Accumulated postretirement benefit obligation (APBO)
Active employees fully eligible for benefits $ 4,568 $ 6,019
Other active employees 23,900 23,990
Current retirees 45,373 63,629
-------- --------
73,841 93,638
Plan assets at fair value 36,075 24,900
-------- --------
APBO in excess of plan assets (37,766) (68,738)
Unrecognized prior service cost 370 423
Unrecognized net (gain)/loss (16,855) 5,212
Unrecognized transition obligation 57,876 61,493
-------- --------
Prepaid/(accrued) postretirement benefit cost $ 3,625 ($ 1,610)
======== ========
Annual Cost of Postretirement Benefits Other than Pensions
(Dollars in Thousands) 1996 1995 1994
- - ---------------------------------------------------------------------------------------------
Service cost--benefits earned during period $ 2,512 $ 2,152 $ 2,127
Interest cost on projected benefit obligation 5,213 6,601 5,520
Actual return on plan assets (4,241) (1,008) 100
Amortization of the unrecognized transition obligation 3,617 3,617 3,617
Other, net 2,072 149 (481)
-------- -------- --------
Net postretirement benefit cost $ 9,173 $ 11,511 $ 10,883
======== ======== ========
Assumptions
1996 1995 1994
- - ----------------------------------------------------------------------------------------------
Discount rates used to determine APBO as of December 31 7.50% 7.00% 8.25%
Rates of increase in compensation levels 5.00% 5.00% 5.50%
Expected long-term rates of return on assets 9.00% 8.75% 8.25%
Health-care cost trend rate 8.00% 10.50% 11.00%
The health-care cost trend rate, or the expected rate of increase in health-care
costs, is assumed to decrease to 7.5% in 1997 and gradually decrease to 5.0% by
2002. Increasing the health-care cost trend rates of future years by one
percentage point would increase the accumulated postretirement benefit
obligation by $4.2 million and would increase annual aggregate service and
interest costs by $0.4 million.
17. CONTINGENCIES
Salem Outages
The Company owns 7.41% of Salem Nuclear Generating Station (Salem), which
consists of two pressurized water nuclear reactors and is operated by Public
Service Electric & Gas Company (PSE&G). As of December 31, 1996, the Company's
net investment in plant in service for Salem was approximately $56 million for
Unit 1 and $60 million for Unit 2, including common plant allocated between the
two units. Each unit represents approximately 2% of the Company's total assets
and approximately 2.6% of the Company's installed electric generating capacity.
Salem Units 1 and 2 were removed from operation by PSE&G on May 16, 1995, and
June 7, 1995, respectively, due to operational problems and maintenance and
safety concerns. Their return dates are subject to completion of the
requirements of their respective restart plans to the satisfaction of PSE&G and
the NRC, which encompasses a substantial review and improvement of personnel,
process, and equipment issues.
With respect to Unit 1, PSE&G informed the Company in early 1996 that
inspections of the steam generators using a new testing technology indicated
degradation in a significant number of tubes. After evaluating several options,
in May 1996, replacement steam generators from the unfinished Seabrook Unit 2
nuclear power plant in New Hampshire were purchased from Northeast Utilities
Service Company for installation in Salem Unit 1. The replacement steam
generators arrived on site in October 1996. PSE&G expects Unit 1 to return to
service in the fall of 1997, after replacement of the unit's steam generators.
The Company's share of the costs to be capitalized for the steam generators,
including installation, will range from approximately $11 million to $13
million.
With respect to Unit 2, PSE&G also informed the Company in early 1996, that
inspections of the steam generators using the new testing technology confirmed
that the condition of the generators was within current repair limits. In
January 1997, PSE&G advised the Company that Unit 2 is expected to return to
service in the second quarter of 1997.
In 1996 and 1995, the Company incurred higher than expected operation and
maintenance costs at Salem of approximately $9 million and $5 million,
respectively, which were expensed as incurred.
The Company incurs replacement power costs while the units are out of service of
approximately $750,000 per month, per unit. Such amounts vary based on the cost
and availability of other Company-owned generation and the cost of purchased
energy. Replacement power costs typically are not incurred for routine refueling
and maintenance outages, and the recovery of replacement power costs is subject
to approval by the regulatory commissions having jurisdiction over the Company.
From the inception of the Salem unit outages through December 31, 1996,
approximately one-half of the estimated replacement power costs of $20.4 million
has been expensed ($6.1 million in 1996 and $4.1 million in 1995) and the
remaining $10.2 million has been deferred on the Company's Consolidated Balance
Sheet in expectation of future recovery. The unavailability of the Salem units
also resulted in a $4 million charge to 1996 fuel expense for capacity
deficiency charges owed to the PJM Interconnection.
The actual costs ultimately incurred by the Company may differ from the
foregoing estimates, since the periods projected by PSE&G during which the Salem
units will be out of service, the extent of the maintenance that will be
required, and the costs of replacement power and the extent of its recovery may
be different from those set forth above.
The Company began recovering one-half of the replacement power costs associated
with the Salem outages on an interim basis, subject to refund, from retail
customers in Virginia and Maryland in July and August 1996, respectively. The
Company expects the VSCC and MPSC to conduct full reviews of the outages before
making final determinations concerning replacement power cost recovery.
On December 10, 1996, the DPSC suspended the portion of interim rates related to
the Salem replacement power costs until the earlier of June 1, 1997, or the end
of the case concerning fuel rates charged to customers. If the suspended interim
rates go into effect prior to the conclusion of the case, they would go into
effect subject to refund pending the final decision by the DPSC.
Notwithstanding current discussions with regulators concerning deregulation of
the electric generation portion of the utility business, the Company believes it
is reasonable to assume that rates will be set at levels that will recover the
current and anticipated costs, including the costs needed to return the Salem
units to operating status, of the Company's investment in the Salem plant, and
such rates can be charged to and collected from customers.
On February 27, 1996, the co-owners of Salem, including the Company, filed a
complaint in the United States District Court for the District of New Jersey
against Westinghouse Electric Corporation (Westinghouse), the designer and
manufacturer of the Salem steam generators. The complaint seeks to recover from
Westinghouse the costs associated with and resulting from the cracks discovered
in Salem's steam generators and with replacing such steam generators. The
estimated replacement cost of such generators is between $150 million and $170
million. The Company cannot predict the outcome of this lawsuit.
On March 5, 1996, the Company and PECO filed a complaint in the United States
District Court for the Eastern District of Pennsylvania against Public Service
Enterprise Group, Inc. (Enterprise) and PSE&G. The lawsuit alleges that the
defendants failed to heed numerous citations, warnings, notices of violations,
and fines by the NRC as well as repeated warnings from the Institute of Nuclear
Power Operations about performance, safety, and management problems at Salem and
to take appropriate corrective action. The suit contends that as a result of
these actions and omissions, the Salem units were forced to shut down in 1995.
The suit asks for compensatory damages for breach of contract, negligence, and
punitive damages, in amounts to be specified. The Company cannot predict the
outcome of this lawsuit.
Environmental Matters
The Company is subject to regulation with respect to the environmental effects
of its operations, including air and water quality control, solid and hazardous
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 three federal superfund sites and is
alleged to be a third-party contributor at three other federal superfund sites.
The Company also has two former coal gasification sites in Delaware and one
former coal gasification site in Maryland, each of which is a state superfund
site. The Company is currently participating with the States of Delaware and
Maryland in evaluating the coal gasification sites to assess the extent of
contamination and risk to the environment. The Company has accrued a liability
of $2 million for clean-up and other potential costs related to the federal and
state superfund sites. The Company does not expect such future costs to have a
material effect on the Company's financial position or results of operations.
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
such third-party claims. In addition, Congress could impose a revenue-raising
measure on the nuclear industry to pay such claims.
The co-owners of Peach Bottom and Salem maintain property insurance coverage in
the aggregate amount of $2.8 billion for each unit for loss or damage to the
units, including coverage for decontamination expense and premature
decommissioning. 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 $3.7 million in any policy year for losses incurred at nuclear
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 $1.3 million per year.
Other
On February 6, 1997, a major customer of the Company filed a lawsuit in the
Delaware Superior Court alleging negligence and breach of contract against the
Company in relation to electric system outages that occurred on March 28, 1996,
and May 14, 1996. The complaint asks for actual damages in excess of $41 million
and for special and punitive damages in unspecified amounts. The Company
believes that its insurance will cover any amounts awarded in this lawsuit in
excess of $1 million for each outage. There is $2 million included in the
Company's current liabilities as of December 31, 1996 for claims related to the
outages. The Company cannot predict the outcome of this lawsuit.
18. NONUTILITY SUBSIDIARIES
The following presents condensed financial information of the Company's
nonutility wholly owned subsidiaries. Common general and administrative costs
are allocated to the Company's nonutility subsidiaries on the basis of cost
causative factors. The Company's management believes the cost allocations are
reasonable.
CONDENSED SUBSIDIARY STATEMENTS OF INCOME
(Dollars in Thousands) 1996 1995 1994
- - -------------------------------------------------------------------------
Revenues and Gains
Landfill and waste hauling $ 14,144 $ 13,505 $14,186
Operating services 21,457 26,564 22,468
Real estate 13,079 5,820 4,450
HVAC services 7,000 -- --
Recoveries of written-off
joint venture assets 6,911 2,812 572
Other revenue 2,799 3,341 1,466
-------- -------- -------
65,390 52,042 43,142
-------- -------- -------
Costs and Expenses
Operating expenses 54,798 45,594 38,499
Interest expense, net 1,000 492 370
Income tax expense 3,394 1,810 1,921
-------- -------- -------
59,192 47,896 40,790
-------- -------- -------
Net income $ 6,198 $ 4,146 $ 2,352
======== ======== =======
CONDENSED SUBSIDIARY BALANCE SHEETS
(Dollars in Thousands) As of December 31,
Assets 1996 1995
- - ------------------------------------------------------------
Current assets
Cash and cash equivalents $ 17,315 $ 19,483
Other 16,806 6,633
-------- --------
34,121 26,116
-------- --------
Noncurrent assets
Investment in
Leveraged leases 46,961 48,367
Other 4,550 9,925
Landfill & waste hauling
property, plant & equipment 24,389 24,177
Other 18,505 9,778
-------- --------
94,405 92,247
-------- --------
Total $128,526 $118,363
======== ========
Liabilities and As of December 31,
Stockholder's Equity 1996 1995
- - ------------------------------------------------------------
Current liabilities
Debt due within one year $ 4,524 $ 506
Variable rate demand bonds 13,500 15,000
Other 13,548 7,801
-------- --------
31,572 23,307
-------- --------
Noncurrent liabilities
Long-term debt 4,548 4,713
Deferred income taxes 44,974 50,064
Other 3,344 2,389
-------- --------
52,866 57,166
-------- --------
Stockholder's Equity 44,088 37,890
-------- --------
Total $128,526 $118,363
======== ========
Pine Grove Landfill, Inc.
One of the Company's indirect subsidiaries, Pine Grove Landfill, Inc. ("Pine
Grove"), which owns and operates a solid waste disposal facility in
Pennsylvania, currently has pending before the Pennsylvania Department of
Environmental Protection (PADEP) an application for expansion of the facility.
In August 1996, the Governor of Pennsylvania issued an executive order
suspending consideration of landfill expansion applications until new
regulations were written. The Company is revising its landfill expansion permit
application to comply with the new PADEP guidelines issued in January 1997. The
Company will comply with all new regulations and expects to receive permit
approval to avoid any interruption in landfill services.
19. SEGMENT INFORMATION
Segment information with respect to electric and gas operations was as follows:
(Dollars in Thousands) 1996 1995 1994
- - --------------------------------------------------------------------
OPERATING REVENUES
Electric $ 980,677 $ 899,662 $ 883,115
Gas 114,284 95,441 107,906
---------- ---------- ----------
Total $1,094,961 $ 995,103 $ 991,021
---------- ---------- ----------
OPERATING INCOME
Electric $ 164,300 $ 165,914 $ 153,409
Gas 15,080 12,492 9,747
---------- ---------- ----------
Total $ 179,380 $ 178,406 $ 163,156
---------- ---------- ----------
DEPRECIATION EXPENSE
Electric $ 115,448 $ 105,780 $ 102,746
Gas 7,726 7,242 6,777
---------- ---------- ----------
Total $ 123,174 $ 113,022 $ 109,523
---------- ---------- ----------
CONSTRUCTION EXPENDITURES
Electric $ 131,122 $ 118,655 $ 133,884
Gas 20,606 16,959 20,235
---------- ---------- ----------
Total $ 151,728 $ 135,614 $ 154,119
---------- ---------- ----------
IDENTIFIABLE ASSETS, NET
Electric $2,536,287 $2,493,797 $2,314,448
Gas 218,809 189,339 188,813
Assets not allocated 224,057 183,549 166,524
---------- ---------- ----------
Total $2,979,153 $2,866,685 $2,669,785
========== ========== ==========
20. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
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 because of 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)
- - ---------------------------------------------------------------------------------------------
1996
March 31 $ 292,630 $ 50,560 $ 35,143 $ 32,703 60,759 $0.54
June 30 250,593 38,523 22,325 19,902 60,703 0.33
September 30 291,356 54,263 37,035 34,605 60,667 0.57
December 31 260,382 36,034 21,684 20,041 60,665 0.33
---------- -------- -------- -------- ------ -----
$1,094,961 $179,380 $116,187 $107,251 60,698 $1.77
========== ======== ======== ======== ====== =====
1995
March 31 $ 257,600 $ 48,252 $ 35,408 $ 32,889 59,738 $0.55
June 30 213,228 34,178 19,444 16,962 60,109 0.28
September 30 283,065 60,960 42,714 40,238 60,372 0.67
December 31 241,210 35,016 19,922 17,457 60,651 0.29
---------- -------- -------- -------- ------ -----
$ 995,103 $178,406 $117,488 $107,546 60,217 $1.79
========== ======== ======== ======== ====== =====