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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 8-K
CURRENT REPORT
PURSUANT TO SECTIONS 13 OR 15(D) OF THE
SECURITIES AND EXCHANGE ACT OF 1934
Date of Report (Date of earliest event reported) March 3, 1998
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DELMARVA POWER & LIGHT COMPANY
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(EXACT NAME OF REGISTRANT AS SPECIFIED IN CHARTER)
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<S> <C> <C>
Delaware and Virginia I-1405 51-0084283
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(STATE OR OTHER JURISDICTION (COMMISSION (IRS EMPLOYER
OF INCORPORATION) FILE NUMBER) IDENTIFICATION NO.)
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800 King Street, P.O. Box 231, Wilmington, Delaware 19899
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(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
Registrant's Telephone Number, Including Area Code 302-429-3114
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None
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(FORMER NAME OR FORMER ADDRESS, IF CHANGED SINCE LAST REPORT)
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ITEM 5. OTHER EVENTS
This report on Form 8-K includes the financial information listed below for
Delmarva Power & Light Company (the Company).
Selected Financial Data (1997 to 1993)
Management's Discussion and Analysis of Financial Condition and Results of
Operations (for the three years ended December 31, 1997)
Report of Management
Report of Independent Accountants
Consolidated Statements of Income for the three years ended December 31, 1997
Consolidated Balance Sheets as of December 31, 1997 and 1996
Consolidated Statements of Cash Flows for the three years ended
December 31, 1997
Consolidated Statements of Changes in Common Stockholders' Equity for the three
years ended December 31, 1997
Notes to Consolidated Financial Statements
2
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Delmarva Power & Light Company
SELECTED FINANCIAL DATA
Year Ended December 31,
(Dollars in Thousands, Except Per Share Amounts) 1997 1996 1995 1994 1993
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Operating Results and Data
Operating Revenues (1) $1,423,502 $1,175,575 $1,055,725 $1,033,442 $1,007,851
Operating Income (1) $234,429 $257,300 $254,425 $233,244(2) $233,091
Net Income $105,709 $116,187 $117,488 $108,310(2) $111,076
Earnings Applicable to Common Stock $101,218 $107,251 $107,546 $98,940(2) $101,074
On System Electric Sales (kWh 000) (3) 13,231,766 12,925,716 12,310,921 12,505,082 12,280,230
On System Gas Sold and Transported (mcf 000) 22,855 22,424 21,371 20,342 19,605
Common Stock Information
Basic and Diluted Earnings Per Share of Common Stock $1.66 $1.77 $1.79 $1.67(2) $1.76
Dividends Declared Per Share of
Common Stock $1.54 $1.54 $1.54 $1.54 $1.54
Average Shares Outstanding (000) 61,122 60,698 60,217 59,377 57,557
Year-End Common Stock Price $23 1/16 $20 3/8 $22 3/4 $18 9/64 $23 5/8
Book Value Per Common Share $15.59 $15.41 $15.20 $14.85 $14.66
Return on Average Common Equity 10.6 % 11.4 % 11.7 % 11.1 % 12.0 %
Capitalization
Variable Rate Demand Bonds (VRDB) (4) $71,500 $85,000 $86,500 $71,500 $41,500
Long-Term Debt 983,672 904,033 853,904 774,558 736,368
Company Obligated Mandatorily Redeemable
Preferred Securities of Subsidiary Trust
Holding Solely Company Debentures 70,000 70,000 - - -
Preferred Stock 89,703 89,703 168,085 168,085 168,085
Common Stockholders' Equity 954,496 934,913 923,440 884,169 862,195
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Total Capitalization with VRDB $2,169,371 $2,083,649 $2,031,929 $1,898,312 $1,808,148
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Other Information
Total Assets $3,015,481 $2,931,855 $2,866,685 $2,669,785 $2,592,479
Long-Term Capital Lease Obligation $19,877 $20,552 $20,768 $19,660 $23,335
Capital Expenditures $173,008 $169,012 $142,833 $166,938 $166,222
</TABLE>
(1) Beginning in 1997 operating revenues and operating income include the
results of non regulated subsidiaries with prior years reclassified for
comparative purposes.
(2) An early retirement offer decreased earnings net of income taxes and
earnings per share by $10.7 million and $0.18, 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 13 to the Consolidated Financial Statements.
3
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Delmarva Power & Light Company
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
MERGER WITH ATLANTIC
Effective March 1, 1998, Delmarva Power & Light Company (the "Company") and
Atlantic Energy, Inc. (Atlantic) merged into a new company named Conectiv.
Additional information about the merger is included in Note 4 to the
Consolidated Financial Statements and in the registration statement on Form S-4
dated December 26, 1996.
Prior to the merger, Atlantic owned Atlantic City Electric Company (ACE), an
electric utility, and subsidiaries engaged in nonutility businesses. ACE serves
approximately 481,000 customers in a 2,700 square mile area in southern New
Jersey. Atlantic's 1997 operating revenues and net income were $1,102.4 million
and $74.4 million, respectively, and its total assets were $2,723.9 million as
of December 31, 1997.
The benefits expected from the merger include increased scale, cost savings,
competitive prices and services, a more balanced customer base, and increased
financial flexibility. The companies expect cost savings from merger synergies
of approximately $500 million over 10 years.
Approximately 50% to 75% of estimated cost savings from the merger with Atlantic
will serve to reduce customers' rates and the balance of the cost savings
realized will benefit Conectiv stockholders. Pursuant to settlement agreements
approving the merger, the Company will decrease retail customer non-fuel (base)
rates by an aggregate total of $13 million in Delaware, Maryland, and Virginia.
In New Jersey, ACE will share approximately 75% of the merger savings with its
customers through a $15.75 million electric rate reduction.
Concurrent with the merger, the Company and Atlantic plan to achieve workforce
reductions through enhanced retirement offers (ERO) and other employee
separation programs. The cost of the Company's employee separation programs and
other merger related expenditures are currently estimated to be $55 million to
$60 million before income taxes ($33 million to $36 million after income taxes).
Effective March 1, 1998, Conectiv owns the Company, Atlantic, and their
subsidiaries. Each outstanding share of the Company's common stock, par value
$2.25 per share, is being 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, is being 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. Class A common stock gives holders of Atlantic common stock a
proportionately greater opportunity to share in the growth prospects of, and a
proportionately greater exposure to the uncertainties associated with the
electric utility business of ACE. Earnings applicable to Class A common stock
will be equal to 30% of the net of (1) earnings attributable to ACE's regulated
electric utility business, as the business existed on August 9, 1996, less (2)
$40 million per year. Earnings applicable to Conectiv common stock will be the
consolidated earnings of Conectiv less earnings applicable to Class A common
stock.
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EARNINGS RESULTS SUMMARY
The Company's earnings per share for 1997 were $1.66 compared to $1.77 for 1996.
Earnings from the Company's traditional, regulated utility operations were
relatively flat, and the $0.11 per share earnings decrease was primarily
attributed to expenses of non-regulated activities, as discussed below. For the
utility business, the positive effects of higher net electric revenues and lower
outage expenses for the Salem nuclear generating units were offset by
anticipated higher capital costs. Net electric revenues grew despite milder
weather due to customer growth and a strong economy.
The earnings decrease from non-regulated activities resulted from planned cost
increases associated with investments in new businesses, branding, and other
expenditures which are positioning the Company to compete in deregulated energy
markets. Part of the Company's strategy for competition (in deregulated
markets) involves the divestiture of non-strategic assets. A $0.22 per share
gain from the Company's sale of Pine Grove, Inc., which owned a landfill and
related waste-hauling company, mitigated the earnings decrease. This sale freed
up capital invested in a non-strategic asset and enabled the Company to absorb
additional investments to grow new businesses.
Earnings per share for 1996 were $1.77, a $0.02 decrease from 1995. Excluding
the adverse impact of 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, including marketing expenses for new
value-added (energy-related) services.
DIVIDENDS
On December 11, 1997, the Board of Directors declared a dividend on common stock
of $0.38 1/2 per share for the fourth quarter or $1.54 on an annualized basis.
The Company's growth strategy 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. Following the merger, dividends on Conectiv common stock are
expected to be paid at the rate of $1.54 per year, subject to periodic
evaluation of Conectiv's results of operations, financial condition, capital
requirements and other relevant considerations. Dividends on Class A common
stock are expected to be paid at the rate of $3.20 per share for three years
following the merger. After the three-year period, dividends on Class A common
stock are expected to be equal to approximately 90% of earnings available for
Class A common stock. However, if dividends on Class A common stock exceed
earnings available for Class A common stock during the three year period, that
may influence the Board's determination of the amount of Class A common stock
dividends to be paid after the three year period.
ELECTRIC UTILITY INDUSTRY RESTRUCTURING
Prices charged to electric utility customers have historically been a "bundled"
price which includes the electricity production cost and the delivery cost
(transmission and distribution). State regulatory commissions and legislatures
throughout the country are considering or have approved changes to laws and
regulations governing the sale and pricing of electricity. Generally, the
component of the price charged to a customer for the production of electricity
would be deregulated, and electric suppliers would compete to supply electricity
to customers. Competition is expected to reduce gross margins earned from the
supply of electricity. Customers would continue to pay the local utility a
regulated price for the delivery of the electricity over the transmission and
distribution system. Discussed below are proposals concerning deregulation of
the electric utility industry in Delaware, Maryland, and Virginia (which have
jurisdiction over the Company's retail electric utility business), New Jersey
(which regulates Atlantic's retail electric utility business), and Pennsylvania.
5
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DELAWARE
In response to a request from the Delaware House of Representatives, on January
27, 1998, the Delaware Public Service Commission (DPSC) submitted its report on
electric utility industry restructuring to the Delaware General Assembly. The
report includes the following recommendations:
All customers in Delaware would be able to choose their electricity supplier
beginning twelve months after the restructuring legislation is signed into
law.
The incumbent utility would serve as the default electricity supplier during a
DPSC determined transition period. During this period, the retail generation
rates for default customers would be market-based, but would continue to be
regulated.
Each utility would have an opportunity to recover all DPSC approved non-
mitigated stranded costs (or costs which would not be recovered under
competitive pricing). Stranded cost recovery would occur through a separate,
non-bypassable charge, which would be applied to all transmission and
distribution customers. A "true-up" process would be established to adjust
for fluctuations in stranded cost recovery due to sales volumes.
Utilities would file their estimates of potential, non-mitigated stranded
costs with the DPSC approximately three months after the restructuring was
enacted. The estimates would be reviewed in a proceeding before the DPSC to
determine the level of stranded cost recovery.
A legal divestiture of generation assets would not be required; however, the
generation business would have to be functionally separated from the remaining
regulated utility business.
The distribution and transmission services provided to retail customers by
utilities, as well as some customer service functions, would continue to be
regulated by the DPSC. Distribution services would continue to be priced
based on cost-of-service. The DPSC also recommends that it oversee pricing of
retail transmission services for some period; however, the Federal Regulatory
Energy Commission (FERC) has indicated that it has jurisdiction over pricing
of such transmission services.
The DPSC recognized that alternative plans should be considered without
necessitating changes to the restructuring legislation. Accordingly, the DPSC
recommended that it be authorized to consider such alternatives and implement
them, if they achieve the same customer choice goals and are in the public
interest.
Restructuring legislation may be considered by the Delaware legislature during
this session, which ends on June 30, 1998.
MARYLAND
On December 3, 1997, the Maryland Public Service Commission (MPSC) issued an
order concluding that retail electric competition is in the public interest and
should be phased-in over a three-year period, one-third of the customers per
year, beginning April 1, 1999. The order established a schedule for filing of
additional information, roundtables, and proceedings. Enabling legislation and
resolution of complex issues such as stranded costs and utility taxation will be
necessary for implementation of retail electric competition in Maryland.
6
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On December 31, 1997, the MPSC ordered a delay in the start of the three-year
phase in period from April 1, 1999 to July 1, 2000 and also suspended all
mandated filing dates. The MPSC subsequently adopted a revised schedule for
this proceeding. The Company and other Maryland utilities supported the
adoption of this schedule.
Certain key provisions of the MPSC's order are as follows:
A price cap would be in effect during the three year phase-in period.
Utilities would be given the opportunity to recover their verifiable and
prudently incurred stranded costs subject to full mitigation. Securitization
of stranded costs would be permitted. Utilities are to file with the MPSC
their estimates of stranded costs and proposed recovery mechanisms.
Cost-of-service regulation of electric generation would be discontinued at the
end of the three-year period, while distribution service would remain subject
to cost-of-service regulation.
The local utility will supply customers who do not select alternate suppliers
during the three-year period.
Reciprocity from out-of-state suppliers will not be required.
Restructuring legislation is being considered by the Maryland legislature.
VIRGINIA
On November 7, 1997, the Virginia State Corporation Commission (VSCC) Staff
report recommended that electric competition should be studied and tested over a
five year period before determining if retail competition should be implemented.
Restructuring legislation is being considered by the Virginia legislature.
NEW JERSEY
In New Jersey, the Board of Public Utilities (BPU) has recommended that retail
choice begin with 10% of customers on October 1, 1998 and be available to 100%
of the customers by July 1, 2000. New Jersey electric utilities, as directed by
the BPU, have filed complete restructuring plans, stranded cost estimates and
unbundled rates. Proceedings are currently underway to address restructuring
issues.
PENNSYLVANIA
In December 1996, the Pennsylvania legislature enacted the Pennsylvania
Electricity Generation Customer Choice and Competition Act (Competition Act)
which provides for the restructuring of the electric industry in Pennsylvania,
including retail competition beginning in 1999. The Competition Act requires
that all customers be allowed to choose their suppliers by January 1, 2001. In
accordance with the Competition Act, pilot programs, open to 5% of each customer
class, began on November 1, 1997. The Company is currently selling electricity
under the Conectiv brand name in the pilot programs and has acquired
approximately 32,200 new customers. The Company plans to continue to evaluate
market opportunities in Pennsylvania.
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In December 1997, the Pennsylvania Public Utility Commission approved a
restructuring plan for PECO Energy Company (PECO) under which two-thirds of
PECO's customers can choose their energy supplier on January 2, 1999, and the
remaining PECO customers can choose as of January 1, 2000. Starting in 1999,
PECO's residential customers who purchase electricity from another supplier will
receive a credit of 5.2 cents per kilowatt hour. This credit will allow
electricity suppliers, such as the Company, a better opportunity than under
previous terms to earn a profit from electricity sales to PECO's existing
customers.
STRANDED COSTS
The transition to a competitive market could result in "stranded costs" for a
utility. Stranded costs are generally costs which may not be recoverable in a
competitive market due to market-based pricing or customers choosing different
energy suppliers. Potential stranded costs could include (i) above-market costs
associated with generation facilities or long-term power purchase agreements and
(ii) regulatory assets (see Note 9 to the Consolidated Financial Statements) if
cost recovery does not continue under a transition plan.
Authoritative accounting guidance issued in 1997 prescribes that a utility
should cease to apply Statement of Financial Accounting Standards (SFAS) No. 71,
"Accounting for the Effects of Certain Types of Regulation," for any separable
portion of the business, such as the electricity production portion of its
business, no later than the date that a specific deregulation plan is finalized.
Stranded costs and regulatory assets attributed to electricity production would
continue to be recognized to the extent that a transition plan provides for
their recovery through cash flows from the regulated transmission and
distribution business.
As previously discussed, proposals concerning deregulation of the electric
utility industry are being considered in Delaware, Maryland, and Virginia, but
no deregulation plan has yet been finalized. Due to the uncertainty surrounding
the outcome of the restructuring plans, the Company cannot currently predict if
or when it would cease applying SFAS No. 71. To the extent stranded cost
recovery is not provided for, the Company would be required to write down asset
values, and such write-downs could be material.
BUSINESS PLANS
As deregulation of the electric utility industry continues to unfold, the
Company is moving ahead with its plan to become a prominent regional player by
being first into new markets that complement its utility business and by
enhancing its ability to serve additional customers outside of its traditional
borders. The Company is growing its businesses by building long-term customer
relationships, establishing the Conectiv brand name, marketing products and
services that complement the Company's core energy business, and serving more
customers in a larger geographic area. To accomplish these goals, the Company
has increased investments in marketing/branding programs, new businesses, and
infrastructure systems.
On June 30, 1997, the Company launched a campaign to introduce the new Conectiv
brand and Conectiv's products and services. The campaign explained that
Conectiv is more than a power company which is offering one-stop shopping for
energy, telecommunications, heating and cooling, and related services for homes
and businesses. Customer response to the new Conectiv brand name has been very
positive, as evidenced by name recognition and the Company's success in
competitive retail energy pilot programs. The Company is marketing an array of
products and services--energy, local and long-distance phone service, heating,
ventilation, and cooling (HVAC) services, and other services--under the
"umbrella" of the Conectiv name. The Company plans to continue its advertising
campaigns and other support of the Conectiv brand name.
8
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Over the next year or two, the Company's earnings are expected to be constrained
by on-going start-up costs for new businesses, including telecommunications and
HVAC. After this start-up period, these investments are expected to contribute
to long-term consolidated earnings growth which exceeds the utility industry
average.
The Company's business plans will be carried out by its three business groups:
Conectiv Energy Delivery; Conectiv Energy Supply; and Conectiv Enterprises. The
business groups are aligned with customers' needs, markets, and the future
structure of the utility industry. The business groups are discussed below.
For financial information concerning the Company's business segments and the
expected impact of SFAS No. 131, "Disclosure About Segments of an Enterprise and
Related Information", see Note 21 to the Consolidated Financial Statements.
CONECTIV ENERGY DELIVERY
Conectiv Energy Delivery will provide common carrier services for the delivery
of electricity and gas to retail and wholesale customers within its regulated
franchise service territory. These delivery services are structured into
various forms of price-regulated offers, some including the energy commodity, so
that customers may choose the combination that provides the best value.
Conectiv Energy Delivery aims to build customer loyalty to enhance the Conectiv
brand image. Customer satisfaction is expected to remain high due to the
Company's reliable delivery systems, superior customer service, and competitive
cost and pricing structures.
CONECTIV ENERGY SUPPLY
Conectiv Energy Supply will manage the generating assets, bulk energy marketing
and trading activities, and the transition of those assets and activities from a
regulated to a competitive environment. Its principal products are electric
power and natural gas, supplemented by other fuels and related energy management
services. Its customers are bulk energy users and retail aggregators in the
region stretching from the Delmarva peninsula north through New England and west
to Ohio.
CONECTIV ENTERPRISES
Conectiv Enterprises will be comprised of the following five start-up
businesses: Conectiv Communications, Inc. (CCI); Conectiv Energy; Conectiv
Services, Inc. (CSI); Conectiv Solutions, and Conectiv Thermal Systems
(currently Atlantic Thermal Systems). These businesses provide an opportunity
to grow Conectiv's customer base throughout the Mid-Atlantic region and
strengthen its relationship with customers in its traditional service territory
through the sales of local and long distance telephone services, HVAC services,
customized energy solutions, competitive energy, and custom thermal heating and
cooling systems. Conectiv Enterprises expects to incur operating losses for the
first year or two after the merger due to start-up costs.
Conectiv Communications, Inc.
CCI is a full range facilities based telecommunications company initially
operating in the region that includes Delaware, Southeastern Pennsylvania,
Southern New Jersey, and Eastern Maryland. CCI's product and service offerings
include all local and long distance services as well as carrier, network, and
data services. CCI is marketing its products and services to business,
residential, and carrier customers. CCI will focus on providing a facilities-
based solution to its customers, and will also resell Bell Atlantic service.
This strategy requires capital expenditures for further expansion of CCI's
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existing fiber optic network over the next several years. CCI currently
operates in a duopoly local service environment with Bell Atlantic. Competition
may increase from other telecommunications companies seeking to establish a
local service presence in the region.
Conectiv Energy
Conectiv Energy currently sells competitive natural gas, electricity, and energy
related products and services to residential and commercial customers in the
Mid-Atlantic region. Retail customers' favorable response to the Conectiv brand
has been a key to acquiring new retail customers in competitive markets. In
1997, Conectiv Energy obtained approximately 7,700 gas customers and 32,200
electric customers. The costs associated with acquiring new customers, timing of
market entry, gross margins on sales, and regulations governing the transition
to competition are factors critical to this business.
Conectiv Services, Inc.
CSI is a full-service HVAC business operating in the Mid-Atlantic region. CSI
provides commercial customers with mechanical HVAC/piping construction and
installation, design services, sheet metal fabrication, preventative maintenance
and repair services. Residential offerings include HVAC installation,
maintenance, repair and related plumbing services. The regional HVAC and
plumbing industry is highly competitive, fragmented, and rapidly consolidating.
The sales and earnings of HVAC businesses are affected by weather conditions.
CSI originated through acquisitions of established businesses, and its future
growth will be impacted by the availability of acquisition candidates and any
regulatory limits imposed on market access.
Conectiv Solutions
As a full-service energy company with a long-term community presence, Conectiv
Solutions is building close customer relationships by understanding individual
customers' energy-related needs, and meeting those needs with customized,
turnkey solutions. Conectiv Solutions provides large commercial and industrial
customers, primarily within the Delaware Valley region, with energy and energy-
related value-added services and products. These products and services are
built around occupant comfort, reliability of systems, and cost containment and
reduction. Conectiv Solutions provides energy efficiency services, power
systems consulting, custom on-site energy systems' services and construction,
telecommunication services, and energy procurement.
Conectiv Thermal Systems
After the merger, Atlantic Thermal Systems (ATS), owned by Atlantic, will become
Conectiv Thermal Systems (CTS). CTS will provide products and services offered
by ATS, including heating, cooling and related energy services to large
commercial and industrial customers. In conjunction with these services, ATS
develops, finances, constructs, owns and operates thermal energy production and
distribution plants. Targeted customer groups include gaming/hotel resort
complexes, colleges and universities, health care facilities and industrial
complexes. ATS offers a highly customized service tailored to meet each
customer's specific energy needs. Through ATS's energy outsourcing programs,
customers are able to reduce their capital expenditures on non-strategic assets,
realize energy cost savings, and free themselves from energy matters which are
incidental to their principal business activities.
10
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PRICE REGULATION OF ENERGY REVENUES
Through 1997, customer rates for non-fuel costs represented a "bundled" price,
including production costs and delivery costs, and have been set in past base
rate proceedings before utility regulatory commissions. Changes in non-fuel (or
base rate) revenues due to volume, or rate changes, generally affect the
earnings of the Company.
Energy costs, including fuel and purchased energy, are currently billed to
customers located within the Company's service territory under regulated fuel
adjustment clause rates. These rates are adjusted periodically for cost changes
and are subject to review by utility regulatory commissions. "Fuel revenues",
or energy costs billed to customers, do not generally affect net income, because
the amount of under- or over-recovered fuel costs is generally deferred until it
is subsequently recovered from or returned to utility customers.
As the utility industry is restructured, fuel adjustment clauses are expected to
be eliminated, and any differences between energy costs and related revenues
will impact future earnings. The Company is currently managing the price risk
associated with its unregulated, off-system energy sales through commodity
hedging activities as discussed in Note 6 to the Consolidated Financial
Statements. When energy sales are deregulated in the Company's service
territory, price risk is expected to be managed similarly for these sales.
Electric revenues also include interchange delivery revenues, which result
primarily from the sale of electric power to utilities in the Pennsylvania-New
Jersey-Maryland (PJM) Interconnection. The PJM Interconnection is an electric
power pool comprised of eight utilities in the region, including the Company.
Interchange delivery revenues are currently reflected in the calculation of
rates charged to customers under fuel adjustment clauses and, thus, do not
affect net income. The future deregulation of the generation function will
cause the margins from interchange delivery revenues to impact earnings.
Merchant revenues result from off-system energy sales in competitive markets
outside the Company's traditional service territory. These sales are not
subject to price regulation and include retail competition pilot programs and
bulk commodity sales.
ELECTRIC REVENUES AND SALES
The Company's sources of electric revenues as a percentage of total electric
revenues are shown below.
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<CAPTION>
1997 1996 1995
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Retail revenues 81.0% 85.7% 88.3%
Resale revenues 6.3% 6.7% 6.5%
Interchange delivery revenues 3.3% 7.6% 5.2%
Merchant revenues 9.4% - -
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Electric retail revenues provide the highest gross margin (revenues less fuel
and purchased energy costs) of the revenue categories shown above and are
currently subject to price regulation. The electric resale and electric
merchant businesses' gross margins, as a percent of revenue, are lower due to
product differences, greater volume per customer, and competitive/unregulated
pricing. However, the Company's new electric merchant business contributed an
incremental amount of gross margin in 1997, which enhanced the Company's overall
profitability.
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In 1997, the percentage of electric retail revenues contributed by the various
retail customer classes were as follows: residential-42.6%; commercial-33.9%;
industrial-19.6%; and other-3.9%.
Details of the changes in the various components of electric revenues are shown
below.
COMPARATIVE INCREASE (DECREASE) FROM PRIOR YEAR IN ELECTRIC REVENUES
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<CAPTION>
(Dollars in Millions) 1997 1996
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Retail and Resale Revenues
Non-fuel (Base Rate) Revenues $ 8.9 $27.2
Fuel Revenues 32.7 26.8
Interchange Delivery Revenues (38.8) 28.0
Merchant Revenues 102.4 -
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$105.2 $82.0
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For 1997 compared to 1996, electric non-fuel revenues increased $8.9 million
mainly due to a 2.6% increase in total retail kilowatt-hour (kWh) sales. The
sales increase was due to a 1.4 % increase in the number of regulated retail
customers and favorable economic conditions, partly offset by milder weather's
unfavorable effect on sales. For 1996 compared to 1995, electric non-fuel
revenues increased $27.2 million due to a 4.5% increase in total retail kWh
sales which was attributed primarily to a full year of Conowingo District sales
in 1996 versus a half year in 1995. As discussed in Note 4 to the Consolidated
Financial Statements, the Company acquired Conowingo Power Company (COPCO) in
June 1995.
In 1997 and 1996, electric fuel revenues increased $32.7 million and $26.8
million, respectively, due to higher average fuel rates and increased kWh sales.
In 1997, more output was sold off-system through the Company's merchant program
(discussed below), reducing kWh deliveries to and revenues from the PJM
Interconnection. 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.
Electric merchant revenues, which are not subject to price regulation, increased
$102.4 million due to the start-up of the Company's new merchant group which
sells power in competitive markets outside the Company's traditional service
territory.
ELECTRIC RESALE BUSINESS
With electric resale customers free to choose their electric supplier, the
electric resale business continues to be highly competitive. If a supplier
other than the local utility is selected, then the local utility receives a fee
for delivering the electricity to the resale customer. The status of the
Company's contract with its largest electric resale customer, Old Dominion
Electric Cooperative (ODEC), is discussed below. Other electric resale
customers of the Company have electricity supply contracts with the Company
which expire in 2001 to 2004.
Under notice provisions in its electricity supply contract, ODEC informed the
Company in August 1996 that it will reduce its load of approximately 200
megawatts (MW) by 60 MW on September 1, 1998, and will further reduce its load
to zero on September 1, 2001. The Company and ODEC have signed a new contract
under which the Company will supply part of the 60 MW. Due to lower pricing and
12
<PAGE>
capacity supplied under this new contract beginning September 1, 1998,
annualized earnings per share will decrease by $0.04 to $0.05 based on
historical common shares outstanding, which equates to about $0.03 based on pro
forma Conectiv common shares outstanding. If ODEC further reduces its load to
zero on September 1, 2001, then annualized earnings per share would decrease by
an additional $0.04 to $0.05 based on historical common shares outstanding, or
about $0.03 to $0.04 based on pro forma Conectiv common shares outstanding.
These projected earnings decreases are net of the expected savings from avoided
capacity costs, which are expected to rise in price substantially during 1998-
2000.
GAS REVENUES, SALES AND TRANSPORTATION
The Company earns gas revenues from gas sales on-system and off-system (merchant
sales) and from the transportation of gas for customers. Transportation
customers may purchase gas from the Company or other suppliers.
Details of the changes in the various components of gas revenues are shown
below.
COMPARATIVE INCREASE (DECREASE) FROM PRIOR YEAR IN GAS REVENUES
<TABLE>
<CAPTION>
(Dollars in Millions) 1997 1996
- ----------------------------------------------------------
<S> <C> <C>
Non-fuel (Base Rate) Revenues $(1.2) $ 3.7
Fuel Revenues 8.8 10.5
Merchant Revenues 82.2 4.6
--------------
$89.8 $18.8
--------------
</TABLE>
The total number of on-system gas customers served by the Company increased by
2.3% in 1997 and 2.5% in 1996.
Gas non-fuel revenues decreased $1.2 million in 1997 principally due to a 9.8%
decline in residential gas sales from milder winter weather, partly offset by
sales to new customers. In 1996, gas non-fuel revenues increased $3.7 million
mainly due to customer growth and a colder heating season.
Gas fuel revenues increased $8.8 million in 1997 primarily due to higher fuel
rates. In 1996, gas fuel revenues increased $10.5 million due to a prior year
refund of over-recovered fuel costs, higher sales, and higher average rates.
The Company launched its gas merchant business in 1996 and ramped-up operations
in 1997. Gas merchant revenues increased $82.2 million in 1997 primarily due to
higher off-system gas sales. Similar to electric merchant revenues, the margin
provided by gas merchant revenues in excess of related purchased gas costs is
relatively small due to the competitive nature of bulk commodity sales.
13
<PAGE>
OTHER SERVICES REVENUES
Other service revenues were comprised of the following:
<TABLE>
<CAPTION>
(Dollars in millions) 1997 1996 1995
--------------------
<S> <C> <C> <C>
HVAC $ 62.8 $ 7.1 $ -
Operation of power plants (1) 23.5 21.5 26.6
Landfill and waste hauling 12.7 14.1 13.5
Other (2) 28.3 31.7 15.3
--------------------
Total $127.3 $74.4 $55.4
--------------------
</TABLE>
(1) Primarily the Company's operation of the Delaware City power plant which
supplies power to Star Enterprises' oil refinery.
(2) Other includes real estate activities, value-added (energy-related )
services, leveraged leasing, telecommunications and other miscellaneous
services.
HVAC revenues increased $55.7 million and $7.1 million in 1997 and 1996,
respectively, due to acquisitions by CSI of companies which provide HVAC and
plumbing services. (For information concerning CSI, see "Business Plans.")
Revenues classified above as "Landfill and waste hauling operations" were earned
by Pine Grove, Inc. which was sold in the fourth quarter of 1997, as discussed
in Note 5, to the Consolidated Financial Statements. In 1996, "Other" revenues
increased $16.4 million due to increased revenues from real estate activities
and value-added (energy-related) services.
ELECTRIC FUEL AND PURCHASED ENERGY EXPENSES
In 1997, electric fuel and purchased energy expenses increased $89.2 million
compared to 1996 primarily due to greater volumes of energy sold and lower
amounts of energy expenses deferred under fuel adjustment clauses.
In 1996, electric fuel and purchased energy expenses increased $59.6 million
mainly due to higher kWh sales and interchange deliveries, and higher fuel and
purchased energy prices. Lower energy expense recognition due to higher amounts
deferred under fuel adjustment clauses mitigated the increase.
For information concerning the Salem outage's impact on electric fuel and
purchased energy expenses, see Note 18 to the Consolidated Financial Statements.
The kWh output required to serve load within the Company's service territory is
substantially equivalent to total output less interchange deliveries and off-
system sales. In 1997, the Company's output for load within its service
territory was provided by 35% coal generation, 35% net purchased power, 20% oil
and gas generation, and 10% nuclear generation.
GAS PURCHASED
In 1997, gas purchased increased $91.8 million due primarily to larger volumes
of gas purchased for resale off-system. In 1996, gas purchased increased $12.6
million principally due to higher prices for purchased gas and less purchased
gas costs deferred under the fuel adjustment clause.
14
<PAGE>
OTHER SERVICES' COST OF SALES
Other services' cost of sales increased to $85.2 million in 1997 from $55.3
million in 1996 due to acquisitions of HVAC service companies, partly offset by
decreased volume in real estate activities and landfill / waste hauling
operations. In 1996, other services' cost of sales increased by $16.3 million
primarily due to acquisitions of HVAC service companies and higher volume of
real estate activities and value-added (energy-related) services.
OPERATION AND MAINTENANCE EXPENSES
Operation and maintenance expenses increased to $331.8 million in 1997 from
$277.9 million in 1996. The $53.9 million increase was mainly due to the start-
up of the HVAC, telecommunications, retail energy, and merchant businesses, and
costs associated with establishing the Conectiv brand name and gaining new
customers. Lower pension cost and Salem outage expenses partly reduced the
total increase in operation and maintenance expenses.
In 1996, operation and maintenance expenses increased $12.5 million primarily
due to marketing expenses for value-added (energy-related) services, increased
costs associated with the Salem outages, and a full year's operation of the
Conowingo District.
YEAR 2000
A Conectiv project team has been formed to address the issue of computer
programs not properly recognizing the Year 2000. The project team is
identifying, analyzing, correcting and reporting on all systems, equipment, and
processes suspected of putting Conectiv's businesses or customers at risk. The
Year 2000 project team has developed a detailed plan to address the problem.
The project team's goal is to resolve Year 2000 related problems associated with
all core systems by the close of 1998. The recent implementation of a new
management information system has resolved a substantial portion of the "Year
2000" problem. The Company has also contacted major vendors to review
remediation of their Year 2000 issues. The Company believes it will
successfully resolve its Year 2000 issues in a timely manner and does not expect
related costs to be material to the Company's results of operations or financial
position.
DEPRECIATION EXPENSE
Depreciation expense increased $7.8 million in 1997 due to completion of on-
going construction projects and installation of new systems. Depreciation
expense increased $9.2 million in 1996 due to the completion of on-going
construction projects and the acquisition of COPCO in mid-1995.
OTHER INCOME
In 1997, other income increased to $28.2 million from $7.6 million in 1996
primarily due to a $22.9 million pre-tax gain on the sale of the Pine Grove
landfill and waste-hauling operations. On an after-tax basis, the gain was
$13.7 million or $0.22 per common share.
15
<PAGE>
FINANCING COSTS
Financing costs reflected in the consolidated income statement include interest
charges, allowance for funds used during construction (AFUDC), dividends on
preferred securities of a subsidiary trust, and dividends on preferred stock.
In 1997, financing costs increased $9.9 million primarily due to higher interest
charges from the issuance of $124.2 million of Medium-Term Notes in February
1997 and $42.0 million of Medium-Term Notes in the fourth quarter of 1997,
partly offset by savings from the refinancing of $78.4 million of preferred
stock in the fourth quarter of 1996. In 1996, financing costs increased $3.2
million primarily due to debt issued in mid-1995 to finance the acquisition of
COPCO.
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 of 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. In
the foreseeable future, the Company expects that incremental demand for
electricity will be supplied with purchased power. This expectation, and the
Company's strategy to grow new businesses, has shifted a larger proportion of
the Company's capital resources into new businesses.
Capital expenditures increased $4.0 million in 1997 and $26.2 million in 1996.
The 1997 increase was principally due to $35 million of capital expenditures to
expand CCI's fiber optic network, partially offset by a $30 million decrease in
utility construction expenditures, including deferred merger-related costs. In
1996, capital expenditures increased $26.2 million primarily due to higher
utility construction.
The Company's cash expenditures for business acquisitions of $17.6 million and
$4.9 million in 1997 and 1996, respectively, were due to CSI's acquisition of
HVAC and related businesses. In 1995, the Company acquired COPCO for $157.0
million, net of cash acquired, with $125.8 million of long-term debt and the
balance with short-term debt.
Operating activities provided net cash inflows of $221.3 million in 1997, $222.7
million in 1996, and $239.4 million in 1995. In 1997, increased cash flows from
higher regulated fuel revenues, net of amounts paid for fuel and purchased
energy, were offset by planned cost increases associated with investments in new
businesses. In 1996, net cash flow from operating activities decreased $16.7
million due to lower electric fuel revenues, net of amounts paid for electric
fuel and purchased energy.
After deducting common and preferred dividend payments of $98.0 million in 1997,
$102.4 million in 1996, and $102.0 million in 1995, internally generated funds
were $123.2 million in 1997, $120.3 million in 1996, and $137.4 million in 1995.
Internally generated funds provided 110%, 79%, and 101% of the cash required for
utility construction in 1997, 1996, and 1995, respectively.
"Sales of nonutility assets" under cash flows from investing activities includes
$33.4 million of pre-tax proceeds from the 1997 sale of Pine Grove Inc.'s
landfill and waste-hauling operations. The principal effects of the sale on the
consolidated balance sheet were a $23.7 million decrease in nonutility property
and an $11.7 million decrease in variable rate demand bonds.
Long-term financings during 1995-1997, net of long-term refinancings and
redemptions, raised $292.8 million of net capital. Sources of cash from long-
term financings, net of refinancings and redemptions, included the following:
16
<PAGE>
$28.9 million of common stock; $260.6 million of long-term debt; $11.7 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 during this period.
Depending on its financing needs, the Company periodically raises cash by
issuing common stock through its Dividend Reinvestment and Common Share Purchase
Plan (DRIP). Alternatively, the Company at times provides DRIP shares to
investing stockholders by purchasing its common shares in the open market.
In February 1997, the Company issued $124.2 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 debt. On the consolidated balance
sheet as of December 31, 1996, $77.0 million of short-term debt was reclassified
to long-term debt to recognize the amount of short-term debt refinanced with the
Medium Term Notes.
In September 1997, $25.0 million of 6 3/8% First Mortgage Bonds were redeemed at
maturity. In June 1998, $25 million of 5.69%, Medium Term Notes are scheduled
to mature.
In the fourth quarter of 1997, the Company repaid short-term debt with proceeds
from the issuance of $42 million of unsecured Medium-Term Notes with maturities
of 5 to 9 years and interest rates of 6.6% to 6.8%.
In January 1998, the Company issued $33.0 million of 6.81% Medium-Term Notes,
which mature in 20 years, and used $25.4 million of the proceeds to repay short-
term debt. In recognition of this refinancing, $25.4 million of short-term debt
was reclassified to long-term debt on the consolidated balance sheet as of
December 31, 1997.
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 $78.4
million of the Company's preferred stock, which had an average dividend rate of
6.9%. On an after-tax basis, the refinancing lowers financing costs by
approximately $1.5 million annually.
The Company's capital structure as of December 31, 1997 and 1996, expressed as a
percentage of total capitalization, is shown below.
<TABLE>
<CAPTION>
1997 1996
------------
<S> <C> <C>
Long-term debt and variable rate demand bonds 48.7% 47.5%
Mandatorily redeemable preferred securities 3.2% 3.3%
Preferred stock 4.1% 4.3%
Common stockholders' equity 44.0% 44.9%
</TABLE>
17
<PAGE>
Presented below are Conectiv's estimated capital requirements, including
anticipated expenditures for business acquisitions.
<TABLE>
<CAPTION>
(Dollars in Millions) 1998 1999 2000 2001 2002
---------------------------------------
<S> <C> <C> <C> <C> <C>
Conectiv Enterprises
Conectiv Communications, Inc. $ 32.8 $ 34.2 $ 38.6 $ 36.6 $ 25.1
Conectiv Energy 0.9 0.5 0.1 0.2 -
Conectiv Services, Inc. 31.5 27.7 2.9 1.2 1.2
Conectiv Solutions 7.3 40.2 28.3 31.7 36.0
Conectiv Thermal Systems 25.3 - 16.5 12.3 -
---------------------------------------
97.8 102.6 86.4 82.0 62.3
Conectiv Energy Delivery 131.1 142.2 148.0 136.3 134.6
Conectiv Energy Supply 54.0 82.7 59.3 96.1 61.7
---------------------------------------
Subtotal 282.9 327.5 293.7 314.4 258.6
Debt Maturities and Other 111.5 69.9 56.2 62.6 118.2
---------------------------------------
Consolidated Conectiv $394.4 $397.4 $349.9 $377.0 $376.8
---------------------------------------
</TABLE>
Over the five year forecast period Conectiv's capital requirements, exclusive of
maturing debt, are expected to be funded by internally generated funds.
External financing, during the five year period, is anticipated only for the
refunding of maturing debt.
NONUTILITY SUBSIDIARIES
For summarized financial information on the Company's nonutility subsidiaries,
please refer to Note 20 to the Consolidated Financial Statements.
FORWARD-LOOKING STATEMENTS
The Private Securities Litigation Reform Act of 1995 (Litigation Reform Act)
provides a "safe harbor" for forward-looking statements to encourage such
disclosures without the threat of litigation, provided those statements are
identified as forward-looking and are accompanied by meaningful, cautionary
statements identifying important factors that could cause the actual results to
differ materially from those projected in the statement. Forward-looking
statements have been made in this report. Such statements are based on
management's beliefs as well as assumptions made by and information currently
available to management. When used herein, the words "will," "anticipate,"
"estimate," "expect," "objective," and similar expressions are intended to
identify forward-looking statements. In addition to any assumptions and other
factors referred to specifically in connection with such forward-looking
statements, factors that could cause actual results to differ materially from
those contemplated in any forward-looking statements include, among others, the
following: deregulation and the unbundling of energy supplies and services; an
increasingly competitive energy marketplace; sales retention and growth; federal
and state regulatory actions; costs of construction; operating restrictions;
increased costs and construction delays attributable to environmental
regulations; nuclear decommissioning and the availability of reprocessing and
storage facilities for spent nuclear fuel; and credit market concerns. The
Company undertakes no obligation to publicly update or revise any forward-
looking statements, whether as a result of new information, future events or
otherwise. The foregoing review of factors pursuant to the Litigation Reform Act
should not be construed as exhaustive or as any admission regarding the adequacy
of disclosures made by the Company prior to the effective date of the Litigation
Reform Act.
18
<PAGE>
Delmarva Power & Light Company
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
March 1, 1998
19
<PAGE>
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, 1997 and 1996, 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, 1997. 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, 1997 and 1996, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1997, in conformity with generally
accepted accounting principles.
Coopers & Lybrand L.L.P.
2400 Eleven Penn Center
Philadelphia, Pennsylvania
February 6, 1998, except as to
the information presented in
Note 4 under Merger with
Atlantic Energy, Inc., for
which the effective date of the
merger is March 1, 1998
20
<PAGE>
<TABLE>
<CAPTION>
Delmarva Power & Light Company
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
(Dollars in Thousands) 1997 1996 1995
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING REVENUES
Electric $1,092,144 $986,921 $904,904
Gas 204,057 114,284 95,441
Other services 127,301 74,370 55,380
-----------------------------------------------------------
1,423,502 1,175,575 1,055,725
-----------------------------------------------------------
OPERATING EXPENSES
Electric fuel and purchased power 416,640 327,464 267,885
Gas purchased 153,027 61,208 48,615
Other services' cost of sales 85,192 55,276 38,970
Purchased electric capacity 28,470 32,126 29,116
Operation and maintenance 331,770 277,893 265,400
Depreciation 136,340 128,571 119,393
Taxes other than income taxes 37,634 35,737 31,921
-----------------------------------------------------------
1,189,073 918,275 801,300
-----------------------------------------------------------
OPERATING INCOME 234,429 257,300 254,425
-----------------------------------------------------------
OTHER INCOME
Allowance for equity funds used during construction 1,337 1,338 708
Other income 28,187 7,595 4,716
-----------------------------------------------------------
29,524 8,933 5,424
-----------------------------------------------------------
INTEREST EXPENSE
Interest charges 83,398 74,242 69,191
Allowance for borrowed funds used during
construction and capitalized interest (2,996) (3,926) (2,370)
-----------------------------------------------------------
80,402 70,316 66,821
-----------------------------------------------------------
DIVIDENDS ON PREFERRED SECURITIES
OF A SUBSIDIARY TRUST 5,687 1,390 -
-----------------------------------------------------------
INCOME BEFORE INCOME TAXES 177,864 194,527 193,028
INCOME TAXES 72,155 78,340 75,540
-----------------------------------------------------------
NET INCOME 105,709 116,187 117,488
DIVIDENDS ON PREFERRED STOCK 4,491 8,936 9,942
-----------------------------------------------------------
EARNINGS APPLICABLE TO COMMON STOCK $101,218 $107,251 $107,546
===========================================================
Common Stock
Average Shares of Common Stock Outstanding (000) 61,122 60,698 60,217
Basic and Diluted Earnings Per Average Share
of Common Stock $1.66 $1.77 $1.79
Dividends Declared Per Share of Common Stock $1.54 $1.54 $1.54
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
21
<PAGE>
<TABLE>
<CAPTION>
Delmarva Power & Light Company
CONSOLIDATED BALANCE SHEETS
As of December 31,
(Dollars in Thousands) 1997 1996
- -----------------------------------------------------------------------------------------
<S> <C> <C>
ASSETS
Current Assets
Cash and cash equivalents $35,339 $36,533
Accounts receivable 197,561 142,431
Inventories, at average cost
Fuel (coal, oil and gas) 37,425 36,584
Materials and supplies 40,518 41,292
Prepayments 11,255 20,233
Deferred energy costs 18,017 31,127
Deferred income taxes, net 776 -
-----------------------------------
340,891 308,200
-----------------------------------
Investments
Investment in leveraged leases 46,375 46,961
Funds held by trustee 48,086 38,923
Other investments 9,500 4,155
-----------------------------------
103,961 90,039
-----------------------------------
Property, Plant and Equipment
Electric utility plant 3,010,060 2,961,940
Gas utility plant 241,580 229,362
Common utility plant 154,791 136,897
-----------------------------------
3,406,431 3,328,199
Less: Accumulated depreciation 1,373,676 1,296,513
-----------------------------------
Net utility plant in service 2,032,755 2,031,686
Utility construction work-in-progress 93,017 118,208
Leased nuclear fuel, at amortized cost 31,031 31,513
Nonutility property, net 74,811 55,408
Goodwill, net 92,602 83,505
-----------------------------------
2,324,216 2,320,320
-----------------------------------
Deferred Charges and Other Assets
Prepaid employee benefits costs 58,111 35,146
Unamortized debt expense 12,911 13,858
Deferred debt refinancing costs 18,760 21,366
Deferred recoverable income taxes 88,683 90,263
Other 67,948 52,663
-----------------------------------
246,413 213,296
-----------------------------------
Total Assets $3,015,481 $2,931,855
====================================
See accompanying Notes to Consolidated Financial Statements.
</TABLE>
22
<PAGE>
<TABLE>
<CAPTION>
Delmarva Power & Light Company
CONSOLIDATED BALANCE SHEETS
As of December 31,
(Dollars in Thousands) 1997 1996
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
Current Liabilities
Short-term debt $23,254 $74,355
Long-term debt due within one year 33,318 27,676
Variable rate demand bonds 71,500 85,000
Accounts payable 103,607 81,628
Taxes accrued 10,723 -
Interest accrued 19,902 16,193
Dividends payable 23,775 23,265
Current capital lease obligation 12,516 12,598
Deferred income taxes, net - 7,276
Other 35,819 31,489
---------------------------------
334,414 359,480
---------------------------------
Deferred Credits and Other Liabilities
Deferred income taxes, net 492,792 479,151
Deferred investment tax credits 39,942 42,501
Long-term capital lease obligation 19,877 20,552
Other 30,585 31,522
---------------------------------
583,196 573,726
---------------------------------
Capitalization
Common stock, $2.25 par value; 90,000,000 shares authorized;
shares outstanding: 1997 - 61,210,262, 1996 - 60,682,719 139,116 136,765
Additional paid-in capital 526,812 508,300
Retained earnings 300,757 293,604
---------------------------------
966,685 938,669
Treasury shares, at cost:
1997--619,237 shares, 1996--101,831 shares (11,687) (2,138)
Unearned compensation (502) (1,618)
---------------------------------
Total common stockholders' equity 954,496 934,913
Cumulative preferred stock 89,703 89,703
Company obligated mandatorily redeemable
preferred securities of subsidiary trust holding
solely Company debentures 70,000 70,000
Long-term debt 983,672 904,033
----------------------------------
2,097,871 1,998,649
----------------------------------
Commitments and Contingencies (Notes 15 and 19)
Total Capitalization and Liabilities $3,015,481 $2,931,855
==================================
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
23
<PAGE>
<TABLE>
<CAPTION>
Delmarva Power & Light Company
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
(Dollars in Thousands) 1997 1996 1995
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Cash Flows From Operating Activities
Net income $105,709 $116,187 $117,488
Adjustments to reconcile net income to
net cash provided by operating activities
Depreciation and amortization 142,734 134,109 127,268
Allowance for equity funds used during construction (1,337) (1,338) (708)
Investment tax credit adjustments, net (2,560) (2,560) (2,516)
Deferred income taxes, net 7,169 33,218 15,992
Net change in:
Accounts receivable (53,911) (5,030) (14,022)
Inventories 4,763 (4,489) 18,590
Accounts payable 16,394 18,418 3,269
Other current assets & liabilities (1) 43,450 (48,383) (14,349)
Gains on sales of nonutility assets (22,896) (380) (3,420)
Other, net (18,250) (17,100) (8,164)
---------------------------------------------------
Net cash provided by operating activities 221,265 222,652 239,428
---------------------------------------------------
Cash Flows From Investing Activities
Acquisition of businesses, net of cash acquired (17,594) (4,884) (157,014)
Capital expenditures (173,008) (169,012) (142,833)
Change in working capital for construction 55 (4,880) 1,102
Sales of nonutility assets 34,880 793 4,970
Decrease in bond proceeds held in trust funds 2,002 7,163 2,658
Deposits to nuclear decommissioning trust funds (4,240) (4,238) (3,612)
Other, net 1,132 1,195 (351)
---------------------------------------------------
Net cash used by investing activities (156,773) (173,863) (295,080)
---------------------------------------------------
Cash Flows From Financing Activities
Dividends: Common (93,811) (93,290) (92,221)
Preferred (4,233) (9,102) (9,813)
Issuances: Long-term debt (2) 166,200 - 125,800
Variable rate demand bonds - - 15,000
Common stock 17,807 486 24,693
Preferred securities (3) - 70,000 -
Redemptions: Long-term debt (2) (28,540) (1,504) (1,388)
Variable rate demand bonds (1,800) (1,500) -
Common stock (7,323) (5,466) (1,253)
Preferred stock - (78,383) -
Principal portion of capital lease payments (6,813) (5,538) (7,875)
Net change in term loan (4) - - (45,000)
Net change in short-term debt (102,671) 86,498 53,154
Cost of issuances and refinancings (4,502) (3,408) (1,523)
---------------------------------------------------
Net cash used by financing activities (65,686) (41,207) 59,574
---------------------------------------------------
Net change in cash and cash equivalents (1,194) 7,582 3,922
Beginning of year cash and cash equivalents 36,533 28,951 25,029
---------------------------------------------------
End of year cash and cash equivalents $35,339 $36,533 $28,951
===================================================
</TABLE>
(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.
24
<PAGE>
Delmarva Power & Light Company
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
Common Additional Unearned
Shares Par Paid-in Retained Treasury Compen-
(Dollars in Thousands) Outstanding Value (1) Capital Earnings Stock sation Total
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance as of January 1, 1995 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 shares (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
Net income 105,709 105,709
Cash dividends declared
Common stock ($1.54 per share) (94,065) (94,065)
Preferred stock (4,491) (4,491)
Issuance of common stock
DRIP (2) 965,655 2,173 15,485 17,658
LTIP (3) 71,103 160 1,200 (1,360) -
Stock options 5,450 12 88 100
Other issuance 2,741 6 47 53
Reacquired common stock (517,406) 230 (9,549) 2,162 (7,157)
Amortization of unearned compensation 1,462 314 1,776
-------------------------------------------------------------------------------------------
Balance as of December 31, 1997 61,210,262 $139,116 $526,812 $300,757 ($11,687) ($502) $954,496
===========================================================================================
</TABLE>
(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, 1997, 3,742,677 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.
25
<PAGE>
Delmarva Power & Light Company
Notes to Consolidated Financial Statements
1. SIGNIFICANT ACCOUNTING POLICIES
NATURE OF BUSINESS
As discussed in Note 4 to the Consolidated Financial Statements, Delmarva Power
& Light Company (the "Company") and Atlantic Energy, Inc. (Atlantic) merged on
March 1, 1998 to form a new company named Conectiv.
In 1997, the Company's revenues were earned from the following sources: 77% from
the sale and delivery of electricity, 14% from the sale and transportation of
gas, and 9% from other services.
The Company provides regulated electric service (supply and delivery) to
approximately 448,300 customers located on the Delmarva Peninsula and also sells
electricity off-system in markets which are not subject to price regulation. The
Company's traditional electric service territory on the Delmarva Peninsula,
which includes Delaware, ten primarily Eastern Shore counties in Maryland, and
the Eastern Shore of Virginia, encompasses an area consisting of about 6,000
square miles with a population of approximately 1.2 million.
The Company provides regulated gas service (supply and/or transportation) to
approximately 103,200 customers located in an area consisting of about 275
square miles with a population of approximately 480,000 in northern Delaware,
including the City of Wilmington. The Company also sells gas off-system in
markets which are not subject to price regulation.
"Other services," which are not subject to utility regulation, are sold by the
Company and its wholly owned subsidiaries. As of December 31, 1997, other
services' business activities were conducted primarily by three subsidiaries:
Conectiv Services, Inc., which provides heating, ventilation, and air-
conditioning (HVAC) sales, installation and services; Conectiv Communications,
Inc., which provides local and long-distance phone service; and Delmarva Capital
Investments, Inc., which is involved in power plant operating services, real
estate activities, and leveraged equipment leases. Delmarva Capital
Investments, Inc. sold its landfill and waste-hauling operations in 1997 as
discussed in Note 5 to the Consolidated Financial Statements.
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. Excluding off-system
sales not subject to price regulation, the percentage of electric and gas
utility operating revenues regulated by each Commission for the year ended
December 31, 1997, was as follows: DPSC, 64.0%; MPSC, 27.0%; VSCC, 2.7%; and
FERC, 6.3%.
Refer to Note 9 to the Consolidated Financial Statements for a discussion of
regulatory assets arising from the financial effects of rate regulation.
26
<PAGE>
CONSOLIDATION POLICY
The consolidated financial statements include the accounts of the Company's
wholly owned subsidiaries. All significant intercompany accounts and
transactions are eliminated in consolidation. Certain reclassifications, not
affecting net income, have been made to conform amounts previously reported to
the current presentation. Primarily, the operating results of nonutility
subsidiaries were reclassified from "Other income" into other classifications
within the income statement.
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.
FINANCIAL INSTRUMENTS
The Company's Energy Supply business group uses futures, options and swap
agreements to hedge firm commitments or anticipated transactions of commodities
associated with the energy sector (natural gas and electricity). In order to
qualify for hedge accounting a derivative, at its inception and on an ongoing
basis, must be expected to substantially offset adverse price movements in the
firm commitment or anticipated transaction that it is hedging. Gains and losses
related to qualifying hedges are deferred and are recognized in income when the
underlying transaction occurs. If subsequent to being hedged, underlying
transactions are no longer likely to occur or the hedge is no longer effective,
the related derivatives gains or losses are recognized currently in income.
Gains and losses on derivatives that do not qualify as hedges are recognized
currently in revenues. Premiums paid for options are included as current assets
in the consolidated balance sheet until they are exercised or expire. Margin
requirements for futures contracts are also recorded as current assets.
Unrealized gains and losses on all futures contracts are deferred on the
consolidated balance sheet as either current assets or deferred credits. The
27
<PAGE>
cash flows from derivatives are included in the cash flows from operations
section of the cash flow statement.
DEPRECIATION EXPENSE
The annual provision for depreciation on utility property is computed on the
straight-line basis using composite rates by classes of depreciable property.
The relationship of the annual provision for depreciation for financial
accounting purposes to average depreciable property was 3.7% for 1997 and 3.6%
for 1996 and 1995. 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 7 to the
Consolidated Financial Statements for additional information on nuclear
decommissioning.
INCOME TAXES
Refer to Note 3 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 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
7.5% in 1997, 6.7% in 1996, and 7.1% in 1995.
STOCK-BASED EMPLOYEE COMPENSATION
Refer to Note 10 to the Consolidated Financial Statements for the Company's
accounting policy on stock-based employee compensation.
GOODWILL
The Company amortizes goodwill arising from business acquisitions over the
shorter of the estimated useful life or 40 years.
28
<PAGE>
LEVERAGED LEASES
As of December 31, 1997, the Company's portfolio of leveraged leases, held by a
nonutility subsidiary, consisted of five aircraft 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 are stated at fair market value and generally include
deposits in the Company's external nuclear decommissioning trusts and
unexpended, restricted, tax-exempt bond proceeds.
EARNINGS PER SHARE
Earnings per share has been computed in accordance with Statement of Financial
Accounting Standards (SFAS) No. 128, "Earnings Per Share." Under SFAS No. 128,
basic earnings per share is computed based on earnings applicable to common
stock (net income less preferred dividends) divided by the weighted average
number of common shares outstanding for the period. Diluted earnings per share
is computed based on earnings applicable to common stock divided by the weighted
average number of shares of common stock outstanding during the period after
giving effect to securities considered to be dilutive common stock equivalents.
The effect of dilutive common stock equivalents was not significant,
consequently for 1997, 1996, and 1995, the Company's basic and diluted earnings
per share were the same amounts.
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
<TABLE>
<CAPTION>
CASH PAID DURING THE YEAR
(Dollars in Thousands) 1997 1996 1995
-------------------------
<S> <C> <C> <C>
Interest, net of capitalized amount $73,211 $67,596 $62,660
Income taxes, net of refunds $53,550 $56,582 $66,764
</TABLE>
29
<PAGE>
3. INCOME TAXES
The Company files a consolidated federal income tax return which includes its
wholly owned subsidiaries. Income taxes are allocated to the Company's
subsidiaries based upon the taxable income or loss of each subsidiary.
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 $88.7 million and $90.3 million as of December 31, 1997 and 1996,
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
<TABLE>
<CAPTION>
(Dollars in Thousands) 1997 1996 1995
----------------------------
<S> <C> <C> <C> <C>
Federal: Current $58,737 $40,953 $51,780
Deferred 6,589 26,131 12,766
State: Current 8,810 6,729 10,284
Deferred 579 7,087 3,226
Investment tax credit adjustments, net (2,560) (2,560) (2,516)
----------------------------
$72,155 $78,340 $75,540
----------------------------
</TABLE>
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.
<TABLE>
<CAPTION>
1997 1996 1995
(Dollars in Thousands) Amount Rate Amount Rate Amount Rate
<S> <C> <C> <C> <C> <C> <C>
- ------------------------------------------------------------------------------
Statutory federal income
tax expense $62,252 35% $68,084 35% $67,560 35%
Increase (decrease) due to
State income taxes, net of
federal tax benefit 6,102 4 8,980 5 8,792 5
Other, net 3,801 2 1,276 - (812) (1)
-----------------------------------------------
Total income tax expense $72,155 41% $78,340 40% $75,540 39%
===============================================
</TABLE>
30
<PAGE>
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.
<TABLE>
<CAPTION>
As of December 31,
(Dollars in Thousands) 1997 1996
- --------------------------------------------------------
<S> <C> <C>
Deferred Tax Liabilities
Utility plant basis differences
Accelerated depreciation $300,558 $275,230
Other 109,303 111,891
Leveraged leases 38,288 41,604
Deferred recoverable income taxes 41,061 42,556
Deferred energy costs 7,054 13,240
Other 81,482 75,332
------------------
Total deferred tax liabilities 577,746 559,853
Deferred Tax Assets
Deferred ITC 14,815 15,902
Other 70,915 57,524
------------------
Total deferred tax assets 85,730 73,426
------------------
Total deferred taxes, net $492,016 $486,427
==================
</TABLE>
Valuation allowances for deferred tax assets were not material as of December
31, 1997 and 1996.
4. MERGERS AND ACQUISITIONS
MERGER WITH ATLANTIC ENERGY, INC.
On August 12, 1996, the Company announced plans to merge with Atlantic Energy,
Inc. (Atlantic). On March 1, 1998 the two companies merged into a new company
named Conectiv. Prior to the merger, Atlantic owned Atlantic City Electric
Company (ACE), an electric utility, and subsidiaries engaged in nonutility
businesses. ACE serves approximately 481,000 customers in a 2,700 square mile
area in southern New Jersey. For financial information about Atlantic and ACE,
see the tables presented at the end of this note.
Under the merger approval settlement agreements with the DPSC, MPSC, and VSCC,
the Company will reduce retail base rates in order to share with utility
customers a portion (ranging from approximately 50% to 60%) of the net cost
savings expected to result from the merger. The annualized amounts of the
retail base rate decreases are as follows:
<TABLE>
<CAPTION>
Annualized Base
Jurisdiction Rate Decrease Effective Date
- ---------------------------- ----------------- --------------
<S> <C> <C>
Delaware retail electric $7.5 million (1.5%) March 1, 1998
Delaware retail electric $0.6 million (0.1%) March 1, 1999
Delaware retail electric $0.4 million (0.1%) March 1, 2000
Delaware gas $0.5 million (0.5%) March 1, 1999
Maryland retail electric $3.5 million (1.3%) March 1, 1998
Virginia retail electric $0.5 million (1.5%) March 1, 1998
</TABLE>
31
<PAGE>
Under the merger order of the Board of Public Utilities (BPU) in New Jersey, ACE
will share approximately 75% of the estimated merger savings with its customers
through a $15.75 million (on an annualized basis) electric rate reduction.
On June 26, 1997, the Company and Atlantic announced that enhanced retirement
offers (ERO) and other employee separation programs were expected to be utilized
to achieve workforce reductions concurrent with the merger of the two companies.
As of December 31, 1997, the ERO and other employee separation programs were
contingent on consummation of the merger. Employee separation costs and other
merger costs related to Delmarva will be expensed and are estimated to be
approximately $55 million to $60 million before taxes ($33 million to $36
million after taxes).
Conectiv, a corporation formed to accomplish the merger, holds the common stock
of the Company and ACE and is a registered holding company under the Public
Utility Holding Company Act of 1935. Each outstanding share of the Company's
common stock, par value $2.25 per share, is being 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, is being 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. Class A common stock gives holders of
Atlantic common stock a proportionately greater opportunity to share in the
growth prospects of, and a proportionately greater exposure to the uncertainties
associated with the electric utility business of ACE. Earnings applicable to
Class A common stock will be equal to 30% of the net of (1) earnings
attributable to ACE's regulated electric utility business, as the business
existed on August 9, 1996, less (2) $40 million per year. Earnings applicable
to Conectiv common stock will be the consolidated earnings of Conectiv less
earnings applicable to Class A common stock.
The merger is being accounted for under the purchase method of accounting, with
the Company as the acquirer. 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 three trading days immediately preceding and the
three trading days immediately following the public announcement of the merger,
is $921.0 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 $200.5 million, which will
be recorded as goodwill. The actual amount of goodwill recorded will be based
on Atlantic's net assets as of the merger date and, accordingly, will vary from
the preceding estimate which is based on Atlantic's net assets as of December
31, 1997. The goodwill will be amortized over 40 years.
Pro forma unaudited financial information for Conectiv on a consolidated basis,
giving effect to the merger as if it had occurred on January 1, 1997, and actual
reported financial information for Atlantic and ACE is presented below. The pro
forma information excludes expected one-time charges related to the merger such
as the ERO and other employee separation costs. The pro forma information is
not necessarily indicative of the results that would have occurred in 1997, or
that will occur in the future.
32
<PAGE>
SUMMARIZED INCOME STATEMENT INFORMATION (UNAUDITED)
<TABLE>
<CAPTION>
Year Ended December 31, 1997
----------------------------
(Dollars in Thousands except PRO FORMA
per share amounts) CONECTIV ATLANTIC ACE
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues $2,525,862 $1,102,360 $1,084,890
Net Income $ 185,923 $ 74,405 $ 85,747
Earnings Applicable to Common Stock:
Common stock $ 170,005 $ 74,405 $ 80,926
Class A common stock (1) $ 15,918
Average common shares outstanding (000)
Common stock 100,500 52,280
Class A common stock 6,563
Basic and Diluted Earnings per average
share outstanding of:
Common stock $ 1.69 $ 1.42
Class A common stock $ 2.43
</TABLE>
(1) The calculation of pro forma 1997 earnings applicable to Class A common
stock is shown below.
<TABLE>
<CAPTION>
(Dollars in Thousands)
<S> <C>
ACE earnings applicable to common stock $ 80,926
Add: Termination of employee benefit plans due to merger 15,600
Less: Net earnings of nonutility activities specifically excluded (3,466)
Less: Fixed amount of $40 million per year (40,000)
--------
Subtotal 53,060
Percentage applicable to Class A common stock 30%
--------
Earnings applicable to Class A common stock $ 15,918
--------
</TABLE>
SUMMARIZED BALANCE SHEET INFORMATION (UNAUDITED)
<TABLE>
<CAPTION>
As of December 31, 1997
-----------------------
(Dollars in Thousands except PRO FORMA
per share amounts) CONECTIV ATLANTIC ACE
- --------------------------------------------------------------------------
<S> <C> <C> <C>
Current assets $ 599,747 $ 268,022 $ 239,751
Noncurrent assets 5,329,687 2,455,862 2,197,004
----------------------------------
Total assets $5,929,434 $2,723,884 $2,436,755
----------------------------------
Current liabilities $ 774,458 $ 342,526 $ 181,880
Noncurrent liabilities 3,033,099 1,472,325 1,347,892
Preferred stock and securities 283,653 123,950 123,950
Common shareholders' equity 1,838,224 785,083 783,033
----------------------------------
Total capitalization and liabilities $5,929,434 $2,723,884 $2,436,755
----------------------------------
</TABLE>
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 operated as the Conowingo
District. Approximately 37,500 electric retail customers were added to the
33
<PAGE>
Company's customer base. The acquisition was accounted for as a purchase and,
accordingly, the operating results of the Conowingo District since June 19, 1995
are included in the Consolidated Statements of Income. 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, the
Company's pro forma operating results for 1995 would not have been materially
different from the operating results reported.
ACQUISITION OF OTHER SERVICE COMPANIES
The Company's expenditures for HVAC and other service companies acquired in 1997
and 1996 were $17.6 million and $9.3 million (including non-cash consideration),
respectively.
5. SALE OF PINE GROVE LANDFILL AND WASTE HAULING COMPANIES
In the fourth quarter 1997, a subsidiary of the Company sold the Pine Grove
Landfill and its related waste-hauling company. The subsidiaries which were
sold had a net book value of approximately $11.3 million and reported revenues
in 1997 of approximately $12.7 million. Pre-tax proceeds received from the sale
were $34.2 million ($33.4 million net of cash sold), resulting in a pre-tax gain
of $22.9 million ($13.7 million after income taxes) or $0.22 per common share.
6. COMMODITY HEDGING ACTIVITIES
The Company's Energy Supply business group engages in commodity hedging
activities to minimize the risk of market fluctuations associated with the
purchase and sale of energy commodities (natural gas and electricity). Some
hedging activities are conducted using energy derivatives. Most of the
Company's hedging activity is conducted by backing physical transactions with
offsetting physical positions. Currently, commodity hedging activities using
derivatives are only conducted in conjunction with transactions that are not
subject to price regulation. The hedging objectives include the assurance of
stable and known minimum cash flows and the fixing of favorable prices and
margins when they become available. Under internal guidelines, risk exposure is
mitigated to acceptable risk tolerance levels.
Energy Supply utilizes futures, options and swap agreements to manage risk.
Futures help manage commodity price risk by fixing purchase or sales prices.
Options provide a floor or ceiling on future purchases or sales prices while
allowing the Company to benefit from favorable price movements. Swaps are
structured to provide the same risk protection as futures and options. Basis
swaps are used to manage risk by fixing the basis differential that exists
between a delivery location index and the commodity futures price.
At December 31, 1997, there were 220 open futures contracts and 30 open options
contracts to purchase natural gas, representing a notional quantity of 2.5
billion cubic feet (Bcf) through October of 1999, at an average price of $2.35
per thousand cubic feet (Mcf), and 60 open options contracts, to sell natural
gas, representing a notional quantity of 0.6 Bcf through July of 1998 at an
average price of $2.38 per Mcf. At December 31, 1997, there was 1 swap contract
to sell electricity, representing a notional quantity of 68,000 megawatt-hours
(MWh), through August of 1998 at an average price of $31.91 per MWh. These open
contracts were entered into to hedge the gas and electric marketing activities
of the Energy Supply business unit through October 1999. A total of $0.3 million
of unrealized losses were deferred on the consolidated balance sheet as of
December 31, 1997.
34
<PAGE>
The Company is exposed to credit losses in the event of nonperformance by
counterparties to its various hedging contracts. Management has evaluated and
implemented policies and procedures to monitor such risk and believes that the
overall business risk is minimized as a result.
7. 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 Nuclear Regulatory Commission
(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 $48.8 million as of December 31,
1997. The provision reflected in depreciation expense for nuclear
decommissioning was $4.2 million in 1997, $4.2 million in 1996, and $3.6 million
in 1995. External trust funds established by the Company for the purpose of
funding nuclear decommissioning costs had an aggregate book balance of $46.5 as
of December 31, 1997. 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 proposed
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 were 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 of
decommissioning expense. The FASB is uncertain when it will issue a final
Statement or a revised Exposure Draft.
35
<PAGE>
8. 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, 1997 was as follows:
<TABLE>
<CAPTION>
Megawatt Construction
Ownership Capability Plant in Accumulated Work in
(Dollars in Thousands) Share Owned Service Depreciation Progress
- ---------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Nuclear
Peach Bottom 7.51% 164 MW $133,598 $ 83,708 $11,487
Salem 7.41% 164 MW 237,597 105,367 10,558
Coal-Fired
Keystone 3.70% 63 MW 20,582 8,924 112
Conemaugh 3.72% 63 MW 33,295 11,009 176
Transmission Facilities Various 4,567 2,306 -
Other Facilities Various 1,791 233 2,534
---------------------------------
Total $431,430 $211,547 $24,867
=================================
</TABLE>
36
<PAGE>
9. 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 are
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, 1997, the Company had $156.5 million of regulatory assets,
which included the following: deferred energy costs--$18.0 million; deferred
debt refinancing costs--$18.8 million; deferred recoverable income taxes--$88.7
million (refer to Note 3 to the Consolidated Financial Statements); deferred
recoverable plant costs--$7.8 million; deferred costs for decontamination and
decommissioning of United States Department of Energy gaseous diffusion
enrichment facilities--$6.3 million; deferred demand-side management costs--$6.2
million; and other regulatory assets--$10.7 million. The costs of these assets
are either 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.
Prices charged to electric utility customers have historically been a "bundled"
price which includes the electricity production cost and the delivery cost
(transmission and distribution). Various state regulatory commissions and
legislatures, as well as federal legislators, are considering or have approved
changes to laws and regulations governing the pricing of electricity. These
changes would generally deregulate the component of the price charged to a
customer for the production of electricity. Under existing plans, the
transmission and distribution of electricity would continue to be regulated.
Authoritative accounting guidance issued in 1997 prescribes that a utility
should cease to apply SFAS No. 71 for any separable portion of the business,
such as the electricity production portion of the business no later than the
date that a specific deregulation plan is finalized. Stranded costs and
regulatory assets attributed to electricity production would continue to be
recognized to the extent that a transition plan provides for their recovery
through cash flows from the regulated transmission and distribution business.
Proposals concerning deregulation of the electric utility industry are being
considered in Delaware, Maryland, and Virginia (the states which have
jurisdiction over the Company's retail electric utility business), but no
deregulation plan has yet been finalized. Thus, at this time, the Company
cannot predict if or when it would cease applying SFAS No. 71, and the related
financial impacts of discontinuing SFAS No. 71.
10. COMMON STOCK
For information concerning issuances and redemptions of common stock during
1995-1997, please refer to the Consolidated Statements of Changes in Common
Stockholders' Equity.
Through the effective date of the Company's merger with Atlantic (March 1,
1998), the Company's Long-Term Incentive Plan (LTIP) provided long-term
incentives to key employees through contingent awards of performance-based
restricted stock. The restricted stock is earned over a four-year period to the
extent that performance targets are satisfied. Restrictions on shares
contingently granted in 1994-1996 will
37
<PAGE>
lapse upon the earlier of March 1, 1998 or the end of the four year vesting
period. Restrictions on shares contingently granted in 1997 do not lapse on
March 1, 1998. During 1997, 1996, and 1995, the number of restricted shares
contingently granted and their fair values as of grant date was as follows:
1997--110,670 shares, $19 1/8 per share fair value; 1996--48,750 shares, $22 3/4
per share fair value; 1995--62,050 shares, $18 9/64 per share fair value.
Changes in stock options granted under the LTIP are summarized below.
<TABLE>
<CAPTION>
1997 1996 1995
---- ---- ----
Number Weighted Number Weighted Number Weighted
of Shares Average Price of Shares Average Price of Shares Average Price
----------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Beginning-of-year
balance 43,950 $20.19 46,350 $20.16 53,050 $20.03
Options exercised 5,450 $17.61 2,400 $19.69 3,900 $17.85
Options forfeited - - - - 2,800 $20.98
End-of-year balance 38,500 $20.55 43,950 $20.19 46,350 $20.16
Exercisable 38,500 $20.55 43,950 $20.19 46,350 $20.16
=========================================================================
</TABLE>
For options outstanding as of December 31, 1997, the range of exercise prices
was $17.50 to $21.25 and the weighted average remaining contractual life was 2.8
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 $2.2 million in 1997,
$0.3 million in 1996, and $1.3 million in 1995. Pro forma net income, based on
the application of SFAS No. 123, "Accounting for Stock-Based Compensation",
would have changed by $0.5 million or less in 1997, 1996, and 1995, and earnings
per share would have changed by less than $0.01 per share in each year.
11. 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 uses 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
38
<PAGE>
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 received from the trust
to purchase and retire $32,087,500 of its $25 par value, 7.75% series preferred
stock, and $31,295,200 of various series of its $100 par value preferred stock
which had an average dividend rate of 5.68%. 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.
12. 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 11 to the Consolidated Financial Statements.
<TABLE>
<CAPTION>
Current Shares Amount
Redemption Outstanding (Dollars in Thousands)
Series Price 1997 1996 1997 1996
- --------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
$25 per share par value
7 3/4% (1) 316,500 316,500 $ 7,913 $ 7,913
$100 per share par value
3.70%-5% $103.00-$105.00 181,698 181,698 18,170 18,170
6 3/4% (2) 35,000 35,000 3,500 3,500
Adjustable rate(3) $ 100 151,200 151,200 15,120 15,120
Auction rate(4) $ 100 450,000 450,000 45,000 45,000
----------------------------------------------------------
$89,703 $89,703
==========================================================
</TABLE>
(1) Redeemable beginning September 30, 2002, at $25 per share.
(2) Redeemable beginning November 1, 2003, at $100 per share.
(3) Average rates were 5.5% during 1997 and 1996.
(4) Average rates were 4.1% during 1997 and 1996.
39
<PAGE>
13. 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, 1997, the Company had $200 million of bank lines of credit
available for borrowing except for amounts supporting outstanding short-term
debt. Two separate revolving credit facilities aggregating to $500 million have
been arranged for Conectiv effective on March 1, 1998. The Conectiv credit
facilities are comprised of a $300 million credit facility which expires five
years after becoming effective and a $200 million credit facility which expires
one year after becoming effective. The Conectiv revolving credit facilities
will replace the Company's and Atlantic's credit lines and certain other short-
term credit facilities which existed as of December 31, 1997.
The weighted average interest rates on short-term debt outstanding as of
December 31, 1997 and 1996 were 6.6% and 5.6%, respectively.
Maturities of long-term debt and sinking fund requirements during the next five
years are as follows: 1998--$33.3 million; 1999--$35.7 million; 2000--$2.7
million; 2001--$3.6 million; 2002--$49.2 million.
In February 1997, the Company issued $124.2 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 refinance short-term debt. On the consolidated
balance sheet as of December 31, 1996, $77.0 million of short-term debt was
reclassified to long-term debt in order to recognize the amount of short-term
debt which had been refinanced with Medium-Term Notes.
In September 1997, the Company redeemed $25 million of 6 3/8% First Mortgage
Bonds at maturity through the issuance of short-term debt.
In October 1997, the Company initiated a public offering of up to $75 million of
unsecured Medium-Term Notes. Through December 31, 1997, the Company had issued
$42 million of unsecured Medium-Term Notes with maturities of 5 to 9 years and
interest rates of 6.6% to 6.8%. The proceeds were used to refinance short-term
debt.
In January 1998, the Company issued $33.0 million of 6.81% unsecured Medium-Term
Notes which mature in 20 years. The Company used $25.4 million of the proceeds
to refinance short-term debt. In recognition of this refinancing $25.4 million
of short-term debt has been reclassified to long-term debt on the consolidated
balance sheet as of December 31, 1997.
40
<PAGE>
Long-term debt outstanding as of December 31, 1997 and 1996 is presented below:
<TABLE>
<CAPTION>
(Dollars in Thousands) Interest Rates Due 1997 1996
- ------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
First Mortgage Bonds 6 3/8% 1997 $ - $ 25,000
6.95% 2002 30,000 30,000
6.40% 2003 90,000 90,000
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% 1998-2008 25,103 25,800
-----------------------------------------------
Total First Mortgage Bonds 549,303 575,000
Other Bonds 7.15%-7.50% 2011-2017 54,500 54,500
Pollution Control Notes:
Series 1973 5.75% 1998 6,000 6,125
Series 1976 7.125%-7.25% 1998-2006 2,900 3,000
Medium Term Notes: 5.69% 1998 25,000 25,000
7.50% 1999 30,000 30,000
6.59%-9.29% 2002 16,000 4,000
8.30% 2004 35,000 35,000
6.84% 2005 10,000 -
6.75% 2006 20,000 -
7.06%-8.125% 2007 91,500 81,000
7.54%-7.62% 2017 40,700 10,000
6.81% 2018 25,430 -
7.61%-9.95% 2019-2021 73,000 67,000
7.72% 2027 30,000 30,000
Other Obligations: 6.00%-9.50% 1998-2002 232 1,502
8.00% 1999 (1) 3,660 3,970
9.65% 2002 (2) 5,354 6,184
Unamortized premium and discount, net (1,589) (572)
Current maturities of long-term debt (33,318) (27,676)
------------------
Total long-term debt 983,672 904,033
Variable Rate Demand Bonds (3) 71,500 85,000
------------------
Total long-term debt
and Variable Rate Demand Bonds $1,055,172 $989,033
=====================
</TABLE>
- --------------------------------------------------------------------------------
(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 $71.5 million as of December 31, 1997 and $85.0 million as of
December 31, 1996. 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 $71.5 million balance of VRDB outstanding as of December 31, 1997,
matures in 2017 ($26 million), 2028 ($15.5 million), and 2029 ($30 million).
Average annual interest rates on the VRDB were 3.8% in 1997 and 3.6% in
1996.
41
<PAGE>
14. 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.
<TABLE>
<CAPTION>
1997 1996
Carrying Fair Carrying Fair
(Dollars in Thousands) Amount Value Amount Value
- ----------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Funds held by trustee $ 48,086 $ 48,086 $ 38,923 $ 38,923
Company Obligated Mandatorily
Redeemable Preferred Securities
of Subsidiary Trust Holding
Solely Company Debentures $ 70,000 $ 72,464 $ 70,000 $ 71,064
Long-Term Debt $983,672 $1,053,810 $904,033 $944,670
</TABLE>
15. COMMITMENTS
The Company's expected capital and acquisition expenditures are estimated to be
approximately $187 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, started at 205 MW,
is currently 212 MW, and increases annually to 279 MW in 2006. The Company also
has a contract with Electric Clearinghouse to purchase 100 MW of energy from
January 1, 1998 to December 31, 2005. Under the terms of these agreements, the
Company's expected commitments for capacity and energy charges are as follows:
1998--$79.5 million; 1999--$87.4 million; 2000--$95.7 million; 2001--$99.2
million; 2002--$103.1 million; after 2002--$410.3 million; total--$875.2
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 $31.0 million as of
December 31, 1997.
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 $150.5 million in aggregate. The Company also has long-
term leases for certain other facilities and equipment. Minimum commitments as
of December 31, 1997 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: 1998--$6.7
million; 1999--$6.6 million; 2000--$5.4 million; 2001--$5.3 million; 2002--$4.6
million; after 2002--$133.9 million; total--$162.5 million. Approximately 93%
of the minimum lease commitments shown above are payments due under the Merrill
Creek Reservoir lease.
42
<PAGE>
RENTALS CHARGED TO OPERATING EXPENSES
The following amounts were charged to operating expenses for rental payments
under both capital and operating leases.
<TABLE>
<CAPTION>
(Dollars in Thousands) 1997 1996 1995
- -----------------------------------------------------------
<S> <C> <C> <C>
Interest on capital leases $ 1,548 $ 1,628 $ 1,773
Amortization of capital leases 6,499 5,653 8,044
Operating leases 11,590 13,795 13,619
-------------------------
$19,637 $21,076 $23,436
=========================
</TABLE>
16. PENSION PLAN
The Company currently 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, contributions have not been
necessary during 1995-1997 due to the pension expense credit and the plans'
funding status.
Based on fair values as of December 31, 1997, pension plan assets were comprised
of the following: publicly traded equity securities ($466.5 million or 60%),
U.S. government obligations ($121.5 million or 16%), and primarily investment
grade corporate and other fixed income obligations ($183.3 million or 24%).
The following schedules show the funded status of the plan, the components of
pension cost, and assumptions.
RECONCILIATION OF FUNDED STATUS OF THE PLAN
<TABLE>
<CAPTION>
As of December 31,
(Dollars in Thousands) 1997 1996
- --------------------------------------------------------------------------------
<S> <C> <C>
Accumulated benefit obligation
Vested $ 365,698 $ 330,639
Nonvested 36,015 24,869
---------------------
401,713 355,508
Effect of estimated future compensation increases 113,877 95,132
---------------------
Projected benefit obligation 515,590 450,640
Plan assets at fair value 771,257 676,189
---------------------
Excess of plan assets over projected benefit obligation 255,667 225,549
Unrecognized prior service cost 26,945 28,980
Unrecognized net gain (205,732) (196,496)
Unrecognized net transition asset (23,199) (26,513)
---------------------
Prepaid pension cost $ 53,681 $ 31,520
=====================
</TABLE>
43
<PAGE>
COMPONENTS OF NET PENSION COST
<TABLE>
<CAPTION>
(Dollars in Thousands) 1997 1996 1995
- -----------------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost--benefits earned during period $ 12,779 $ 13,172 $ 9,719
Interest cost on projected benefit obligation 34,173 32,531 30,654
Actual return on plan assets (115,982) (82,488) (135,850)
Net amortization and deferral 46,869 22,164 83,981
---------------------------------
Net pension cost $ (22,161) $(14,621) $ (11,496)
=================================
ASSUMPTIONS 1997 1996 1995
- ----------------------------------------------------------------------------------
Discount rates used to determine projected
benefit obligation as of December 31 7.00% 7.50% 7.00%
Rates of increase in compensation levels 5.00% 5.00% 5.00%
Expected long-term rates of return on assets 9.00% 9.00% 8.75%
</TABLE>
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 $3.0 million
1997, $2.4 million in 1996, and $2.3 million in 1995.
17. 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, 1997,
the plan's assets consisted of $35.7 million (73%) of equity securities,
including mutual funds and directly owned publicly traded securities, and $12.9
million (27%) 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
<TABLE>
<CAPTION>
As of December 31,
(Dollars in Thousands) 1997 1996
- ---------------------------------------------------------------------------
<S> <C> <C>
Accumulated postretirement benefit obligation (APBO)
Active employees fully eligible for benefits $ 6,361 $ 4,568
Other active employees 26,365 23,900
Current retirees 47,774 45,373
-------------------
80,500 73,841
Plan assets at fair value 48,591 36,075
-------------------
APBO in excess of plan assets (31,909) (37,766)
Unrecognized prior service cost 317 370
Unrecognized net gain (18,238) (16,855)
Unrecognized transition obligation 54,259 57,876
-------------------
Prepaid postretirement benefit cost $ 4,429 $ 3,625
===================
</TABLE>
44
<PAGE>
ANNUAL COST OF POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
<TABLE>
<CAPTION>
(Dollars in Thousands) 1997 1996 1995
- ---------------------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost--benefits earned during period $ 2,393 $ 2,512 $ 2,152
Interest cost on projected benefit obligation 5,547 5,213 6,601
Actual return on plan assets (9,108) (4,241) (1,008)
Amortization of the unrecognized transition obligation 3,617 3,617 3,617
Other, net 5,869 2,072 149
----------------------------
Net postretirement benefit cost $ 8,318 $ 9,173 $11,511
============================
ASSUMPTIONS 1997 1996 1995
- --------------------------------------------------------------------------------------
Discount rates used to determine
APBO as of December 31 7.00% 7.50% 7.00%
Rates of increase in compensation levels 5.00% 5.00% 5.00%
Expected long-term rates of return on assets 9.00% 9.00% 8.75%
Health-care cost trend rate 7.50% 8.00% 10.50%
</TABLE>
The health-care cost trend rate, or the expected rate of increase in health-care
costs, is assumed to decrease to 7.0% in 1998 and gradually decrease to 5.4% by
2002. Increasing the health-care cost trend rates of future years by one
percentage point would increase the accumulated postretirement benefit
obligation by $5.1 million and would increase annual aggregate service and
interest costs by $0.5 million.
18. SALEM NUCLEAR GENERATING STATION
The Company owns 7.41% of the Salem Nuclear Generating Station (Salem), which
consists of two pressurized water nuclear reactors operated by Public Service
Electric & Gas Company (PSE&G). Salem Units 1 and 2 were removed from operation
by PSE&G in the second quarter of 1995 due to operational problems, and
maintenance and safety concerns. After receiving NRC authorization, PSE&G
returned Unit 2 to service on August 30, 1997. Due to degradation of a
significant number of tubes in the Unit 1 steam generators, PSE&G replaced the
Unit 1 steam generators. PSE&G expects Unit 1 will return to service in late-
March to early-April 1998, subject to approval of the NRC.
In May 1997, the Company settled its lawsuit against PSE&G concerning Salem
operations. Under the settlement's primary provision, PSE&G paid the Company
$12 million in settlement of all claims related to the lawsuit. In August 1997,
the DPSC approved a settlement regarding the ratemaking treatment of the PSE&G
settlement payment and the replacement power costs attributable to the Salem
outages. The DPSC settlement provided for recovery of approximately one-half of
the replacement power costs from electric customers and retention of two-thirds
of the PSE&G settlement payment by the Company's stockholders. Based on
expected similar ratemaking treatment in other regulatory jurisdictions and the
terms of these settlements, the Company charged $3.1 million, net of the
stockholder portion of the PSE&G settlement payment, to fuel expenses in 1997.
In 1996 and 1995, approximately $10.1 million and $4.1 million, respectively,
were charged to fuel expenses for replacement power costs and capacity
deficiency charges owed to the Pennsylvania-New Jersey-Maryland (PJM)
Interconnection. (Utilities which are parties to the PJM Interconnection
agreement are required to pay capacity deficiency charges if capacity levels are
lower than the level committed to by the PJM utility.) The aforementioned fuel-
related expenses decreased earnings for 1997, 1996, and 1995 because these
amounts were not expected to be recovered through customers' fuel rates. The
45
<PAGE>
Company also estimates that operation and maintenance costs were higher than
normal by $4 million, $9 million, and $5 million in 1997, 1996, and 1995,
respectively, because of the Salem outages.
As previously reported, on February 27, 1996, the co-owners of Salem, including
the Company, filed a complaint in the United States District Court for New
Jersey against Westinghouse Electric Corporation (Westinghouse), the designer
and manufacturer of the Salem steam generators. The complaint, which 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, alleges violations of federal and New Jersey Racketeer Influenced
and Corrupt Organizations Acts, fraud, negligent misrepresentation and breach of
contract. The estimated replacement cost of such generators is between $150
million and $170 million. On October 1, 1997, Westinghouse filed a motion for
summary judgment. The parties argued the summary judgment motion and a decision
on the motion is expected after March 1, 1998. No trial date has been set. The
Company cannot predict the outcome of this lawsuit.
19. CONTINGENCIES
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 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's current
liabilities included $2 million as of December 31, 1997 and 1996, respectively,
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 $3.2 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
46
<PAGE>
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.
20. NONUTILITY SUBSIDIARIES
The following presents summarized financial information about 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.
Excluding non-regulated energy sales conducted by operating divisions of the
Company, as of December 31, 1997, the following three subsidiaries conducted
substantially all of the Company's nonutility business: Conectiv Services, Inc.,
which provides HVAC sales, installation and services; Conectiv Communications,
Inc., which provides local and long-distance phone service; and Delmarva Capital
Investments, Inc.(DCI), which is involved in power plant operating services,
real estate activities, and leveraged equipment leases. Delmarva Capital
Investments, Inc. sold its landfill and waste-hauling operations in 1997 as
discussed in Note 5 to the Consolidated Financial Statements.
<TABLE>
<CAPTION>
1997 As of December 31, 1997
----------------------- ---------------------------
Operating Net Total Stockholders
(Dollars in thousands) Revenues Income/(loss) Assets Equity
----------------------- ---------------------------
<S> <C> <C> <C> <C>
Conectiv Services, Inc. $62,755 $(6,330) $53,208 $41,529
Conectiv Communications, Inc. $ 1,670 $(5,671) $46,486 $37,843
Delmarva Capital Investments, Inc. $49,557 $21,481 $76,469 $14,501
</TABLE>
DCI's net income was $6.3 million in 1996 and $4.1 million in 1995. DCI's total
assets were $101.1 million and $117.1 million at December 31, 1996 and 1995,
respectively. Conectiv Services, Inc. and Conectiv Communications, Inc. started
operations in late 1996.
21. SEGMENT INFORMATION
In 1997, the FASB issued SFAS No. 131, "Disclosure About Segments of an
Enterprise and Related Information." SFAS No. 131 will supersede SFAS No. 14,
"Financial Reporting for Segments of a Business Enterprise," and become
effective for the Company's annual financial statements in 1998. Under SFAS No.
131, operating segments will be based on the manner in which management operates
the business. The Company expects that its operating segments will be Conectiv
Energy Delivery, Conectiv Energy Supply, and Conectiv Enterprises, as described
in Management's Discussion and Analysis of Financial Condition and Results of
Operations. In brief, the businesses of these operating segments are as follows:
Conectiv Energy Supply--produces and purchases energy, and sells bulk energy in
competitive markets; Conectiv Energy Delivery--delivers energy to customers at
regulated prices over transmission and distribution systems; Conectiv
Enterprises--sells retail energy, HVAC services, local and long distance phone
service, and other services in competitive markets.
47
<PAGE>
The operating segments presented below are based on the criteria of SFAS No. 14.
For a description of the Electric, Gas, and Other Services' businesses, refer to
Note 1 to the Consolidated Financial Statements. Under SFAS No. 131, the energy
and delivery businesses embedded within both the Electric and Gas businesses
will be unbundled and reported under Conectiv Energy Supply and Conectiv Energy
Delivery, respectively. Unregulated retail electric and gas sales will be
reported within Conectiv Enterprises. The businesses in Other Services will
primarily be included in Conectiv Enterprises.
(Dollars in Thousands)
<TABLE>
<CAPTION>
1997 1996 1995
-----------------------------------
<S> <C> <C> <C>
Operating Revenues
Electric--service territory $ 953,356 $ 911,620 $ 857,633
Electric--interchange deliveries 36,430 75,301 47,271
Electric--off-system merchant 102,358 - -
-----------------------------------
Total electric 1,092,144 986,921 904,904
-----------------------------------
Gas--service territory 117,190 109,658 95,441
Gas--off-system merchant 86,867 4,626 -
-----------------------------------
Total gas 204,057 114,284 95,441
-----------------------------------
Other services 127,301 74,370 55,380
-----------------------------------
Total $1,423,502 $1,175,575 $1,055,725
-----------------------------------
OPERATING INCOME
Electric $ 223,164 $ 231,144 $ 233,430
Gas 20,801 24,092 18,537
Other services (9,536) 2,064 2,458
-----------------------------------
Total $ 234,429 $ 257,300 $ 254,425
-----------------------------------
DEPRECIATION EXPENSE
Electric $ 119,877 $ 115,448 $ 105,780
Gas 8,795 7,726 7,242
Other services 7,668 5,397 6,371
-----------------------------------
Total $ 136,340 $ 128,571 $ 119,393
-----------------------------------
CAPITAL EXPENDITURES
Electric $ 113,922 $ 137,886 $ 120,535
Gas 15,310 20,874 17,145
Other services 43,776 10,252 5,153
-----------------------------------
Total $ 173,008 $ 169,012 $ 142,833
-----------------------------------
IDENTIFIABLE ASSETS, NET
Electric $2,537,796 $2,490,212 $2,493,797
Gas 250,596 217,586 189,339
Other Services 161,432 135,482 119,098
Unallocated 65,657 88,575 64,451
-----------------------------------
Total $3,015,481 $2,931,855 $2,866,685
-----------------------------------
</TABLE>
48
<PAGE>
22. 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.
As discussed in Note 5 to the Consolidated Financial Statements, in the fourth
quarter of 1997, net income was increased by $13.7 million ($0.22 per average
common share) due to the sale of the Pine Grove Landfill and its related waste-
hauling company.
<TABLE>
<CAPTION>
Earnings
Applicable Average per
Quarter Operating Operating Net to Common Shares Average
Ended Revenue Income Income Stock Outstanding Share
(Dollars in Thousands) (In Thousands)
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
1997
March 31 $ 346,079 $ 63,150 $ 25,793 $ 24,578 60,856 $0.40
June 30 310,968 51,376 17,997 16,913 61,177 0.28
September 30 400,502 85,509 39,411 38,319 61,247 0.63
December 31 365,953 34,394 22,508 21,408 61,207 0.35
---------------------------------------------------------------------------------
$1,423,502 $234,429 $105,709 $101,218 61,122 $1.66
=================================================================================
1996
March 31 $ 308,619 $ 75,620 $ 35,143 $ 32,703 60,759 $0.54
June 30 267,783 52,316 22,325 19,902 60,703 0.33
September 30 308,340 77,536 37,035 34,605 60,667 0.57
December 31 290,833 51,828 21,684 20,041 60,665 0.33
----------------------------------------------------------------------------------
$1,175,575 $257,300 $116,187 $107,251 60,698 $1.77
==================================================================================
</TABLE>
49
<PAGE>
ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS
Exhibits
- --------
Exhibit No. 23 Consent of Independent Accountants
Exhibit No. 27 Financial Data Schedule
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Delmarva Power & Light Company
----------------------------------
(Registrant)
Date: March 3, 1998 /s/ B.S. Graham
------------- ----------------------------------
B.S. Graham, Senior Vice President
and Chief Financial Officer
50
<PAGE>
EXHIBIT INDEX
Exhibit
Number
- ------
23 Consent of Independent Accountants
27 Financial Data Schedule
<PAGE>
Exhibit 23
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the Registration Statements
of Delmarva Power & Light Company on Form S-3 (File Nos. 333-24059, 333-07281
and 333-00505) and on Form S-8 (File No. 333-20715) and Conectiv, Inc. on Form
S-3 (File Nos. 333-00505 and 333-44219) of our report dated February 6, 1998,
except as to the information presented in Note 4 under Merger with Atlantic
Energy, Inc., for which the effective date of the merger is March 1, 1998, on
our audits of the consolidated financial statements of Delmarva Power & Light
Company and Subsidiary Companies as of December 31, 1997 and 1996 and for each
of the three years in the period ended December 31, 1997, which report is
included in this Form 8-K.
COOPERS & LYBRAND L.L.P.
2400 Eleven Penn Center
Philadelphia, Pennsylvania
March 3, 1998
<TABLE> <S> <C>
<PAGE>
<ARTICLE> OPUR1
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED BALANCE SHEET AND STATEMENT OF INCOME INCLUDED IN THIS REPORT ON
FORM 8-K AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
INFORMATION.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> DEC-31-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,032,755
<OTHER-PROPERTY-AND-INVEST> 178,772
<TOTAL-CURRENT-ASSETS> 340,891
<TOTAL-DEFERRED-CHARGES> 246,413
<OTHER-ASSETS> 216,650
<TOTAL-ASSETS> 3,015,481
<COMMON> 139,116
<CAPITAL-SURPLUS-PAID-IN> 526,812
<RETAINED-EARNINGS> 300,757
<TOTAL-COMMON-STOCKHOLDERS-EQ> 954,496
70,000
89,703
<LONG-TERM-DEBT-NET> 983,672
<SHORT-TERM-NOTES> 23,254
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 33,318
0
<CAPITAL-LEASE-OBLIGATIONS> 19,877
<LEASES-CURRENT> 12,516
<OTHER-ITEMS-CAPITAL-AND-LIAB> 828,645
<TOT-CAPITALIZATION-AND-LIAB> 3,015,481
<GROSS-OPERATING-REVENUE> 1,423,502
<INCOME-TAX-EXPENSE> 72,155
<OTHER-OPERATING-EXPENSES> 1,189,073
<TOTAL-OPERATING-EXPENSES> 1,261,228
<OPERATING-INCOME-LOSS> 162,274
<OTHER-INCOME-NET> 29,524
<INCOME-BEFORE-INTEREST-EXPEN> 191,798
<TOTAL-INTEREST-EXPENSE> 86,089
<NET-INCOME> 105,709
4,491
<EARNINGS-AVAILABLE-FOR-COMM> 101,218
<COMMON-STOCK-DIVIDENDS> 94,065
<TOTAL-INTEREST-ON-BONDS> 83,398
<CASH-FLOW-OPERATIONS> 221,265
<EPS-PRIMARY> $1.66
<EPS-DILUTED> $1.66
</TABLE>
