Exhibit 28(a)
INDEPENDENT AUDITORS' REPORT
To Atlantic City Electric Company:
We have audited the accompanying consolidated balance sheets of
Atlantic City Electric Company and subsidiary as of December 31,
1994 and 1993, and the related consolidated statements of income,
changes in common shareholder's equity, and cash flows for each
of the three years in the period ended December 31, 1994. 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, such consolidated financial statements present
fairly, in all material respects, the financial position of
Atlantic City Electric Company and subsidiary at December 31,
1994 and 1993 and the results of their operations and their cash
flows for each of the three years in the period ended December
31, 1994 in conformity with generally accepted accounting
principles.
DELOITTE & TOUCHE LLP
February 9, 1995
Parsippany, New Jersey
REPORT OF MANAGEMENT
The management of Atlantic City Electric Company and subsidiary
(the Company) is responsible for the preparation of the financial
statements presented in this Annual Report on Form 10-K. The
financial statements have been prepared in conformity with
generally accepted accounting principles. In preparing the
financial statements, management made informed judgments and
estimates, as necessary, relating to events and transactions
reported. Management is also responsible for the preparation of
other financial information included elsewhere in this Annual
Report.
Management has established a system of internal accounting and
financial controls and procedures designed to provide reasonable
assurance as to the integrity and reliability of financial
reporting. In any system of financial reporting controls,
inherent limitations exist. Management continually examines the
effectiveness and efficiency of this system, and actions are
taken when opportunities for improvement are identified.
Management believes that, as of December 31, 1994, the system of
internal accounting and financial controls over financial
reporting is effective. Management also recognizes its
responsibility for fostering a strong ethical climate in which
the Company's affairs are conducted according to the highest
standards of corporate conduct. This responsibility is
characterized and reflected in the Company's code of ethics and
business conduct policy.
The financial statements have been audited by Deloitte & Touche
LLP, Certified Public Accountants. Deloitte & Touche LLP provides
an objective, independent audits as to management's discharge of
its responsibilities insofar as they relate to the fairness of
the financial statements. Their audits are based on procedures
believed by them to provide reasonable assurance that the
financial statements are free of material misstatement.
The Company's internal auditing function conducts audits and
appraisals of the Company's operations. It evaluates the system
of internal accounting, financial and operational controls and
compliance with established procedures. Both the external
auditors and the internal auditors periodically make
recommendations concerning the Company's internal control
structure, and management responds to such recommendations as
appropriate in the circumstances. None of the recommendations
made for the year ended December 31, 1994 represented significant
deficiencies in the design or operation of the Company's internal
control structure.
The Audit Committee of the Board of Directors of Atlantic Energy,
Inc., the parent of the Company, has oversight responsibility for
the ongoing examination of the Company's internal control
structure and determining that the Company's management has
fulfilled its obligation in the preparation of financial
statements. The Committee, comprised exclusively of independent
directors, discussed with the Company's internal auditors and
Deloitte & Touche LLP the overall scope and specific plans for
their respective activities concerning the Company.
The
Committee meets regularly with the internal auditors and Deloitte
& Touche LLP, without management present, to discuss the results
of the Company's financial reporting. The meetings are designed
to facilitate any private communication with the Committee
desired by the internal auditors or Deloitte & Touche LLP. No
significant actions by the Committee were required during the
year ended December 31, 1994 as a result of any private
communications conducted.
/s/ J. L. Jacobs /s/ F. F. Frankowski
J. L. Jacobs F. F. Frankowski
President and Controller - Vice President
Chief Executive Officer
February 9, 1995
CONSOLIDATED STATEMENT OF INCOME Atlantic City Electric Company
and Subsidiary
(Thousands of Dollars)
For the Years Ended December 31,
1994 1993 1992
Operating Revenues-Electric $913,226 $865,799 $816,931
Operating Expenses:
Energy 210,891 159,438 161,134
Purchased Capacity 130,929 110,781 103,173
Operations 157,047 162,840 149,604
Maintenance 37,662 45,452 49,926
Depreciation and Amortization 73,344 67,950 69,371
State Excise Taxes 97,072 104,280 97,969
Federal Income Taxes 42,529 45,277 37,143
Other Taxes 10,757 10,854 12,113
Total Operating Expenses 760,231 706,872 680,433
Operating Income 152,995 158,927 136,498
Other Income and Expense:
Allowance for Equity Funds
Used During Construction 3,634 2,368 2,212
Employee Separation Costs,
net of tax of $9,265 (17,335) - -
Litigation Settlement, net of tax of:
1993 - $(1,321); 1992 - $(4,982) - (2,564) 9,671
Other-Net 9,568 9,865 13,613
Total Other Income and Expense (4,133) 9,669 25,496
Income Before Interest Charges 148,862 168,596 161,994
Interest Charges:
Interest on Long Term Debt 57,346 59,385 53,284
Other Interest Expense 1,114 1,633 2,678
Total Interest Charges 58,460 61,018 55,962
Allowance for Borrowed Funds Used During
Construction (2,772) (1,448) (1,414)
Net Interest Charges 55,688 59,570 54,548
Net Income $ 93,174 $109,026 $107,446
Earnings for Common Stock:
Net Income $ 93,174 $109,026 $107,446
Less Preferred Stock Dividend Requirements 16,716 17,405 17,812
Income Available for Common Stock $ 76,458 $ 91,621 $ 89,634
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
CONSOLIDATED STATEMENT OF CASH FLOWS Atlantic City Electric Company
and Subsidiary
(Thousands of Dollars)
For the Years Ended December 31,
1994 1993 1992
Cash Flows Of Operating Activities:
Net Income $ 93,174 $ 109,026 $ 107,446
Deferred Purchased Power Costs 14,920 (6,050) 13,410
Deferred Energy Costs (3,819) (15,269) (6,143)
Depreciation and Amortization 73,344 67,950 69,371
Deferred Income Taxes-Net 6,116 16,213 13,531
Prepaid State Excise Taxes (37,029) (35,982) 540
Net (Increase) Decrease in Other Working
Capital (26,012) 30,762 8,661
Employee Separation Costs 26,600 - -
Other-Net 1,403 7,559 6,450
Net Cash Provided by Operating Activities 148,697 174,209 213,266
Cash Flows Of Investing Activities:
Utility Cash Construction Expenditures (119,961) (138,111) (130,700)
Leased Property (10,713) (9,946) (9,565)
Nuclear Decommissioning Trust Fund Deposits (6,424) (6,424) (6,424)
Utility Plant Removal Costs (8,000) (1,943) (4,936)
Other-Net 7,223 (3,824) (1,527)
Net Cash Used by Investing Activities (137,875) (160,248) (153,152)
Cash Flows Of Financing Activities:
Proceeds from Long Term Debt 53,572 464,633 59,655
Retirement and Maturity of Long Term Debt (42,664) (360,414) (10,350)
Increase (Decrease) in Short Term Debt 8,600 (14,600) (6,000)
Proceeds from Capital Lease Obligations 10,713 9,946 9,565
Preferred Stock Redemption (24,500) (5,469) (250)
Dividends (100,198) (98,752) (96,148)
Capital Contributions 25,270 20,991 14,605
Other-Net 1,601 (1,362) (2,822)
Net Cash (Used) Provided by
Financing Activities (67,606) 14,973 (31,745)
Net (Decrease) Increase in Cash and Temporary
Investments (56,784) 28,934 28,369
Cash and Temporary Investments,
beginning of year 60,243 31,309 2,940
Cash and Temporary Investments,
end of year $ 3,459 $ 60,243 $ 31,309
Supplemental Schedule of Payments:
Interest $ 61,035 $ 51,331 $ 53,593
Federal income taxes $ 32,254 $ 25,809 $ 36,399
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
CONSOLIDATED BALANCE SHEET
Atlantic City Electric Company
and Subsidiary
(Thousands of Dollars)
December 31,
1994 1993
Assets
Electric Utility Plant:
In Service:
Production $1,151,661 $1,054,217
Transmission 357,389 338,584
Distribution 659,619 627,649
General 180,204 173,206
Total In Service 2,348,873 2,193,656
Less Accumulated Depreciation 725,999 668,832
Net 1,622,874 1,524,824
Construction Work in Progress 110,078 156,590
Land Held for Future Use 6,941 6,901
Leased Property-Net 42,030 45,268
Electric Utility Plant-Net 1,781,923 1,733,583
Investments and Nonutility Property:
Nuclear Decommissioning Trust Fund 52,004 43,163
Nonutility Property and Equipment-Net 1,286 1,286
Other Investments and Funds 1,853 11
Total Investments and Nonutility Property 55,143 44,460
Current Assets:
Cash and Temporary Investments 3,459 60,243
Accounts Receivable:
Utility Service 54,554 51,502
Miscellaneous 15,804 10,940
Allowance for Doubtful Accounts (3,300) (3,000)
Unbilled Revenues 32,070 39,309
Fuel (at average cost) 28,030 14,635
Materials and Supplies (at average cost) 27,823 28,230
Working Funds 14,475 14,313
Other Prepayments 11,760 15,582
Deferred Energy Costs 10,999 7,180
Deferred Income Taxes 12,141 2,945
Total Current Assets 207,815 241,879
Deferred Debits:
Unrecovered Purchased Power Costs 115,538 130,458
Recoverable Future Federal Income Taxes 85,854 85,855
Unrecovered State Excise Taxes 73,834 33,706
Unamortized Debt Costs 38,083 39,185
Other Regulatory Assets 47,055 41,705
Other 16,071 12,753
Total Deferred Debits 376,435 343,662
Total Assets $2,421,316 $2,363,584
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
Atlantic City Electric
Company
and Subsidiary
(Thousands of Dollars)
December 31,
1994 1993
Liabilities and Capitalization
Capitalization:
Common Shareholder's Equity:
Common Stock $ 54,963 $ 54,963
Premium on Capital Stock 231,081 231,081
Contributed Capital 262,749 237,479
Capital Stock Expense (2,300) (2,470)
Retained Earnings 249,767 256,961
Total Common Shareholders' Equity 796,260 778,014
Preferred Stock:
Not Subject to Mandatory Redemption 40,000 40,000
Subject to Mandatory Redemption 149,250 173,750
Long Term Debt 763,288 751,101
Total Capitalization (excluding current portion) 1,748,798 1,742,865
Current Liabilities:
Preferred Stock Redemption Requirement 12,250 12,250
Capital Lease Obligations 928 861
Short Term Debt 8,600 -
Accounts Payable 65,632 63,819
Federal Income Taxes Payable - Affiliate 9,537 10,339
Other Taxes Accrued 3,490 6,873
Interest Accrued 19,048 22,038
Dividends Declared 24,681 24,910
Other 18,206 24,226
Accrued Employee Separation Costs 26,600 -
Total Current Liabilities 188,972 165,316
Deferred Credits and Other Liabilities:
Deferred Income Taxes 350,697 332,852
Deferred Investment Tax Credits 51,646 54,180
Capital Lease Obligations 41,102 44,407
Other 40,101 23,964
Total Deferred Credits and Other Liabilities 483,546 455,403
Commitments and Contingencies (Note 9)
Total Liabilities and Capitalization $2,421,316 $2,363,584
CONSOLIDATED STATEMENT OF CHANGES IN Atlantic City Electric Company
COMMON SHAREHOLDER'S EQUITY and Subsidiary
(Thousands of Dollars)
Premium on Capital
Common Capital Contributed Stock Retained
Stock Stock Capital Expense Earnings
Balance,
December 31, 1991 $54,963 $231,081 $201,883 $(2,502) $235,591
Net income 107,446
Capital stock expense 6 (6)
Capital contribution
from parent 14,605
Less dividends declared:
Preferred (17,812)
Common (78,336)
Balance,
December 31, 1992 54,963 231,081 216,488 (2,496) 246,883
Net income 109,026
Capital stock expense 26 (196)
Capital contribution
from parent 20,991
Less dividends declared:
Preferred (17,405)
Common (81,347)
Balance,
December 31, 1993 54,963 231,081 237,479 (2,470) 256,961
Net income 93,174
Capital stock expense 170 (170)
Capital contribution from
parent 25,270
Less dividends declared:
Preferred (16,716)
Common (83,482)
Balance,
December 31, 1994 $54,963 $231,081 $262,749 $(2,300) $249,767
As of December 31, 1993, the Company had 25 million authorized
shares of Common Stock at $3 par value. Shares outstanding at
December 31, 1993, 1992 and 1991 were 18,320,937.
The accompanying Notes to Consolidated Financial Statements are
an integral part of these statements.
Notes to Consolidated Financial Statements
Note 1. SIGNIFICANT ACCOUNTING POLICIES
Organization - Atlantic City Electric Company (the Company) is a
wholly-owned subsidiary of Atlantic Energy, Inc. (AEI).
Deepwater Operating Company, which operates certain generating
facilities owned by the Company, is a wholly-owned subsidiary of
the Company. The Company is a public utility primarily engaged
in the generation, transmission, distribution and sale of
electric energy. Rates for service are regulated by the New
Jersey Board of Public Utilities (BPU), formerly the New Jersey
Board of Regulatory Commissioners. The Company's service
territory encompasses approximately 2,700 square miles within the
southern one-third of New Jersey. The majority of the Company's
customers are residential and commercial.
Principles of Consolidation - The consolidated financial
statements include the accounts of the Company and its
subsidiary. All significant intercompany accounts and
transactions have been eliminated in consolidation.
Regulation - The accounting policies and rates of the Company are
subject to the regulations of the BPU and in certain respects to
the Federal Energy Regulatory Commission (FERC). The Company
follows generally accepted accounting principles (GAAP) and
financial reporting requirements employed by all industries as
specified by the Financial Accounting Standards Board (FASB) and
the Securities and Exchange Commission (SEC). However,
accounting for rate regulated industries may depart from GAAP
applied by other industries as permitted by Statement of
Financial Accounting Standards No. 71 (SFAS No. 71). SFAS No. 71
provides guidance on circumstances where the economic effect of a
regulator's decision warrants different applications of GAAP as a
result of the rate making process. In setting rates, a regulator
may provide recovery of an incurred cost in a year or years other
than the year the cost is incurred. As permitted by SFAS No. 71,
costs ordered by a regulator to be deferred or capitalized for
future recovery are recorded as a regulatory asset because the
regulator's rate action provides reasonable assurance of future
economic benefits attributable to these costs. In a non-rate
regulated industry, such costs may be charged to expense in the
year incurred. SFAS No. 71 further specifies that a regulatory
liability is recorded when a regulator orders a refund to
customers of revenues previously collected, or when existing
rates provide for recovery of future costs not yet incurred.
Such treatment is not afforded to non-rate regulated companies.
When collection of regulatory assets or relief of regulatory
liabilities is no longer probable, the assets and liabilities are
applied to income in the year that the probability assessment is
made. Specific regulatory assets and liabilities that have been
recorded are discussed elsewhere in the notes to the consolidated
financial statements.
Electric Operating Revenues - Revenues are recognized when
electric energy services are rendered, and include estimates for
amounts unbilled at the end of the period for energy used
subsequent to the last billing cycle.
Nuclear Fuel - Fuel costs associated with the Company's
participation in jointly-owned nuclear generating stations,
including spent nuclear fuel disposal costs, are charged to
Energy expense based on the units of thermal energy produced.
Electric Utility Plant - Property is stated at original cost.
Generally, the plant is subject to a first mortgage lien. The
cost of property additions, including replacement of units of
property and betterments, is capitalized. Included in certain
property additions is an Allowance for Funds Used During
Construction (AFDC), which is defined in the applicable
regulatory system of accounts as the cost during the period of
construction of borrowed funds used for construction purposes and
a reasonable rate on other funds when so used. AFDC has been
calculated using a semi-annually compounded rate of 8.25%, as
approved by the BPU, since
August 1, 1993. The AFDC rate was 8.95%, as approved by the BPU,
prior to this date.
Depreciation - The Company provides for straight-line
depreciation based on the estimated remaining life of
transmission and distribution property, remaining life of the
related nuclear plant operating license for nuclear property and
estimated average service life for all other depreciable
property. The overall composite rate of depreciation was
approximately 3.3% in 1994 and 1993 and 3.5% in 1992.
Accumulated depreciation is charged with the cost of depreciable
property retired together with removal costs less salvage and
other recoveries.
Nuclear Decommissioning Trust - The Company has a trust to fund
the future costs of decommissioning each of the five nuclear
units in which it has an ownership interest. The current annual
funding amount, as authorized by the BPU, totals $6.4 million and
is provided for in rates charged to customers. The funding
amount is based on estimates of the future cost of
decommissioning each of the units, dates that decommissioning
activities are expected to occur and return to be earned by the
assets of the fund. The present value of the Company's nuclear
decommissioning obligation, based on 1987 site specific studies
used by the BPU for approval in 1991 and restated in 1994
dollars, is $152.2 million. The BPU has further established that
decommissioning activities are expected to begin in 2006 and
continue through 2032. Actual costs and timing of
decommissioning activities may vary from the current estimates.
The Company will seek to adjust these estimates and the level of
rates collected from customers in future BPU proceedings to
reflect changes in decommissioning cost estimates and the
expected levels of inflation and interest to be earned by the
assets in the trust. As of December 31, 1994, the present value
of such contributions based on estimates for future
decommissioning costs and the dates such activities are expected
to occur is $111.4 million, without earnings on or appreciation
of the fund assets. As of December 31, 1994, the cost and market
value of the trust were $52 million. Trust contributions of the
related $36.9 million qualify for Federal income tax purposes.
The related reserve for decommissioning costs are presented as a
component of accumulated depreciation and amount to $51.1 million
at December 31, 1994 and $42.2 million at December 31, 1993.
The SEC has questioned certain accounting practices employed by
the electric utility industry concerning decommissioning costs
for nuclear generating facilities. The FASB is currently
reviewing this issue within the broad context of removal costs
relative to all industries. At this time, the Company cannot
predict what future accounting practices may be required by the
FASB and SEC concerning this issue, nor the impact on the
financial statements that any new accounting practices may have.
Deferred Energy Costs - As approved by the BPU, the Company has a
Levelized Energy Clause (LEC) through which energy and energy-
related costs (energy) are charged to customers. LEC rates are
based on projected energy costs and prior period underrecoveries
or overrecoveries of energy costs. Energy costs are recovered
through levelized rates over the period of projection, which is
generally a 12-month period. In any period, the actual amount of
LEC revenues recovered from customers may be greater or less than
the recoverable amount of actual energy costs incurred in that
period. Energy expense is adjusted to match the associated LEC
revenues. Any underrecovery (an asset representing energy costs
incurred that are to be collected from customers) or overrecovery
(a liability representing previously collected energy costs to be
returned to customers) of costs is deferred on the Consolidated
Balance Sheet as Deferred Energy Costs. These deferrals are
recognized in the Consolidated Statement of Income as Energy
expense during the period in which they are subsequently included
in the LEC.
Income Taxes - Effective January 1, 1993, deferred Federal and
state income taxes are provided on all significant temporary
differences between book bases and tax bases of assets and
liabilities, transactions that reflect taxable income in a year
different than book income, and tax carryforwards. Deferred
Federal and state income taxes for 1992 were provided on all
significant current transactions for which the timing of
recognition differs for book and tax purposes. Investment tax
credits, which are used to reduce current Federal income taxes,
are deferred on the Consolidated Balance Sheet and recognized in
book income over the life of the related property. The Company
files a consolidated Federal income tax return with AEI. An
agreement with AEI provides for allocation to the Company of the
tax liabilities or benefits generated by the Company based on the
separate return method. Such tax liabilities and benefits are
periodically settled on a cash basis.
Unrecovered Purchased Power Costs - The Company has an
arrangement that commenced in 1983 to purchase capacity and
related energy through September 30, 2000. Levelized base rates
over the term of the arrangement were approved by the BPU to
recover costs estimated at commencement to be incurred. During
the first half of the term, estimated costs that exceeded
levelized revenues were deferred on the Consolidated Balance
Sheet as Unrecovered Purchased Power Costs. Since then,
levelized revenues have been greater than the estimated costs,
permitting the deferred costs to be charged to Purchased Capacity
expense on the Consolidated Statement of Income. The BPU granted
a return on the unrecovered deferred balance throughout the term
of the arrangement. The unrecovered deferred balance at December
31, 1994 and 1993 were $95.9 million and $110.5 million,
respectively. Also included within Unrecovered Purchased Power
Costs are costs incurred in renegotiating a contract with an
independent power producer. These costs are amortized to expense
over the BPU-approved recovery period of 20 years beginning in
1994. The unrecovered balances were $19.6 million and $20
million at December 31, 1994 and 1993, respectively.
Related Party Transactions - The Company has a contract for a
total of 106 MWS of capacity and related energy from a
cogeneration facility that is owned 50% by a wholly-owned
subsidiary of AEI. Capacity costs totaled $23.0 million in 1994
and 1993 and $18.4 million in 1992 and energy costs totaled $13.4
million, $13.2 million and $8.7 million in 1994, 1993 and 1992,
respectively. The Company also rents office space from and sells
electricity to another wholly-owned subsidiary of AEI. The rents
paid and the electric sales recorded are not significant to the
Consolidated Statement of Income. The amounts receivable and
payable to such affiliates were not significant at December 31,
1994 and 1993.
Regulatory Assets and Liabilities - Costs incurred by the Company
that have been permitted by the BPU to be deferred for recovery
in rates in more than one year, or for which future recovery is
probable, have been recorded as regulatory assets. Regulatory
assets are amortized to expense over the period of recovery.
Total regulatory assets on the Consolidated Balance Sheet at
December 31, 1994 and 1993 were $365.5 million and $332.1
million, respectively. Unamortized costs currently being
recovered in rates at December 31, 1994 and 1993, respectively,
and remaining recovery periods at December 31, 1994 are:
Unrecovered State Excise Taxes of $73.8 million and $33.7
million, with a remaining recovery period of eight years;
decommissioning and decontaminating Federally-owned nuclear units
of $7.2 million and $8.4 million, with a remaining recovery
period of 14 years; and asbestos removal of $9.6 million and $9.9
million for which the recovery period is over the remaining
depreciable life of the related generating station of 36 years.
Property Abandonment Costs at their net present value of $5
million and $6.3 million at December 31, 1994 and 1993,
respectively, are being recovered through rates with no return on
the unamortized balances of $6.5 million and $8.5 million,
respectively. Such costs were written down to their net present
values at the date of abandonment with subsequent accretions of
the unamortized balances over the recovery period. These costs
have a recovery period between two and seven years. Also
included in Other Regulatory Assets are amounts for which future
recovery is probable of $9.4 million and $9.1 million at December
31, 1994 and 1993, respectively. Costs associated with debt
reacquired by refundings, included in Unamortized Debt Costs, are
amortized over the life of the newly issued debt as permitted by
the BPU in accordance with FERC guidelines. The unamortized
balances of these costs were $32.2 million and $33.2 million at
December 31, 1994 and 1993, respectively. Recovery of regulatory
assets for Unrecovered Purchased Power Costs (Note 1), Deferred
Energy Costs (Note 1), Recoverable Future Federal Income Taxes
(Note 2) and Postretirement Benefits Other Than Pensions (Note 4)
are separately discussed in the Notes to Consolidated Financial
Statements where indicated. No regulatory liabilities existed at
December 31, 1994 and 1993.
Financial Instruments - A number of items within Current Assets
and Current Liabilities on the Consolidated Balance Sheet are
considered to be financial instruments because they are cash or
are to be settled in cash. Due to their short term nature, the
carrying values of these items approximate their fair market
values. Accounts Receivable - Utility Service and Unbilled
Revenues are subject to concentration of credit risk because they
pertain to utility service conducted within a confined geographic
region.
Other - Debt premium, discount and expenses of the Company are
amortized over the life of the related debt. Temporary
investments considered as cash equivalents for Consolidated
Statement of Cash Flows purposes represent purchases of highly
liquid debt instruments maturing in three months or less. The
weighted daily average interest rates on short term debt was 4.4%
for 1994 and 3.2% for 1993.
Certain prior year amounts have been reclassified to conform to
the current year reporting of these items.
NOTE 2. FEDERAL INCOME TAXES
For the Years Ended December 31,
(000) 1994 1993 1992
The components of Federal income tax expense are as follows:
Current $ 30,013 $ 29,679 $ 33,660
Deferred 6,116 16,214 13,531
Total Federal Income Tax Expense 36,129 45,893 47,191
Less Amounts Included in Other Income (6,400) 616 10,048
Federal Income Taxes Included in
Operating Expenses $ 42,529 $ 45,277 $ 37,143
A reconciliation of the expected Federal income taxes compared to the reported
Federal income tax expense computed by applying the statutory rate follows:
Statutory Federal Income Tax Rate 35% 35% 34%
Income Tax Computed at the Statutory Rate $ 45,256 $ 54,221 $ 52,577
Plant Basis Differences (27) (5,171) 2,022
Investment Tax Credits (2,534) (2,534) (2,534)
Tax Adjustments (4,874) (750) (3,757)
Other-Net (1,692) 127 (1,117)
Total Federal Income Tax Expense $ 36,129 $ 45,893 $ 47,191
Effective Federal Income Tax Rate 28% 30% 31%
Items comprising deferred tax amounts are as follows at December 31, 1994 and
1993:
1994 1993
Deferred Tax Liabilities:
Plant Basis Differences $304,476 $295,445
Unrecovered Purchased Power Costs 33,557 38,792
State Excise Taxes 25,842 11,797
Other 22,573 21,057
Total Deferred Tax Liabilities 386,448 367,091
Deferred Tax Assets:
Deferred Investment Tax Credits 27,879 29,247
Employee Separation Costs 6,932 -
Other 13,081 7,938
Total Deferred Tax Assets 47,892 37,185
Total Deferred Taxes-Net $338,556 $329,906
The deferred tax costs associated with additional deferred tax
liabilities resulting from a change in accounting standards
regarding deferred taxes effective in 1993 are recorded on the
Consolidated Balance Sheet as Recoverable Future Federal Income
Taxes. Such recognition is given in respect of the probable
amount of revenue to be collected from ratepayers for these
additional taxes to be paid in future years.
NOTE 3: RATE MATTERS
Energy Clause Proceedings
Changes in Levelized Energy Clause Rates
1992 - 1994
Amount Amount
Date Requested Granted Date
Filed (millions) (millions) Effective
2/92 $(6.6) $(8.5) 10/92
3/93 14.2 10.9 10/93
2/94 63.0 55.0 7/94
The Company's Levelized Energy Clause (LEC) is subject to annual
review by the BPU.
In February 1992, the Company filed a petition with the BPU for
the LEC period June 1, 1992 through May 31, 1993 requesting no
change in LEC rates. In April 1992, the Company filed a revision
to their petition requesting a $6.6 million decrease in LEC rates
based on an update for the projected overrecovery of prior LEC
costs and an amount allocated to customers from the litigation
settlement with PECO Energy (PECO) related to the Peach Bottom
Atomic Power Station. In October 1992, the BPU approved a
reduction in annual LEC revenues of $8.5 million which included
the recovery of $10.4 million over a three-year period of certain
deferred costs relating to the Salem Nuclear Generating Station.
The PECO settlement allocation was subject to review by the BPU
in the Company's 1993 LEC proceeding.
In March 1993, the Company filed a petition with the BPU
requesting a $14.2 million increase in LEC revenues for the June
1, 1993 through May 31, 1994 LEC period. Effective for service
rendered on and after October 1, 1993, the BPU approved an
increase of $10.9 million which included the following: 1) an
additional $3.8 million of the PECO settlement together with
accrued interest to be returned to customers during the 1994-1995
LEC period; 2) recovery of $400 thousand for the annual
assessment for the Department of Energy (DOE) decommissioning and
decontamination fund; 3) full LEC recovery of all future
assessments for the DOE decommissioning and decontamination fund
and 4) recognition of the $48 thousand penalty for 1992 nuclear
operations as required by the Nuclear Performance Standard. The
additional allocation of the PECO settlement was provided for in
the 1993 financial results and the reimbursement was made through
the 1994 LEC.
On February 8, 1994, the Company filed a petition with the BPU
requesting an increase in LEC revenues of $63 million for the
period June 1, 1994 through May 31, 1995. The increase was due
primarily to the additional costs incurred from two new
independent power producers (IPPs) scheduled to begin commercial
operation during the 1994/1995 LEC period. The total projected
costs for fuel and capacity for the LEC period were $147 million.
The Company reduced the requested amount by $84 million as a
result of the utilization of $56 million of current base rate
revenues associated with a utility power purchase contract
expiring in May 1994 and the Southern New Jersey Economic
Initiative (SNJEI), a Company initiative that forgoes the
recovery of $28 million of fuel costs. Included in the Company's
request was the recovery over five years of $20 million paid by
the Company in December 1993 in connection with contract
renegotiations with an IPP. Effective July 26, 1994, the BPU
approved a provisional increase of $55 million based on an
adjustment to actual costs for fuel and capacity. On November
30, 1994, the BPU rendered its decision on the Company's LEC
request approving the continuation of provisional LEC rates, the
recovery of the $20 million in renegotiation costs and the
reduction for the $28 million SNJEI.
Base Rate Case Proceedings
Effective October 1992, the BPU authorized a net increase in
annual base rate revenues of $12.9 million. In March 1994, in
response to an appeal filed by the Ratepayer Advocate in December
1992, the Superior Court of New Jersey, Appellate Division,
affirmed the BPU's decision to allow an increase in base rates
relating to changes in the state excise tax.
Other Rate Proceedings
In November 1993, the Company filed a petition with the BPU
requesting that hotel-casino customers be permitted to take
service under rate schedules offered to all other commercial and
industrial customers. On June 23, 1994, the BPU approved the
request with a provision that the Company not seek recovery of
lost revenues resulting from the hotel-casinos being permitted to
shift to other rate schedules prior to the Company's next base
rate case. The BPU also allowed for a one-time adjustment to be
billed to hotel-casino customers for the associated underrecovery
in the Company's fuel clause. Prior to BPU approval, hotel-
casino customers were served under the Hotel Casino Service rate
schedule, the highest rate for service of all the Company's
service classes. Effective July 1, 1994, all hotel-casino
customers began taking service under a general service rate
schedule which could reduce annual base rate revenues by
approximately $7 million. Effective July 25, 1994, the Hotel
Casino Service rate schedules were no longer offered for electric
service.
In July 1993, the BPU initiated a generic proceeding to address
the recovery of the capacity costs associated with purchases of
power from nonutility generation projects. This issue relates to
the Ratepayer Advocate's contention that present BPU policy which
permits full recovery of these costs through the LEC provides for
a "double recovery" of cogeneration capacity costs. In August
1993, the Ratepayer Advocate identified the Company as one of the
electric utilities for which they considered the double recovery
of capacity costs to be at issue. Pursuant to its February 18,
1994 decision supporting the investigation of the double recovery
of capacity costs from nonutility generation projects, the BPU
issued its written order on September 16, 1994. The order
confirmed the establishment of a generic proceeding to review the
nonutility purchase power capacity cost recovery methodology and
ordered that the matter be reviewed in a two phase proceeding.
The scope of the issues to be resolved during the first phase of
the proceeding will include: 1) the determination of the
existence, or lack of existence, of the double recovery as a
result of the traditional LEC pass-through of nonutility
generation capacity costs; 2) the quantification of any such
double recovery found to exist for each utility for the relevant
periods; and 3) a determination of an appropriate remedy or
adjustment if such double recovery is found to occur and the
periods of time over which such an adjustment would be
applicable. Following the conclusion of the first phase of the
proceeding, the BPU, in the second phase, will render a final
decision regarding the specific findings of the Office of
Administrative Law and address the broader issues relating to the
appropriate prospective purchase power capacity cost recovery
methods. Evidentiary hearings have been scheduled through
December 1995. The BPU's final decision is not anticipated until
1996. At this time, the Company cannot predict the outcome of
this proceeding and cannot estimate the impact that the double
recovery issue may have on future rates.
NOTE 4. RETIREMENT BENEFITS
Pension
The Company has a noncontributory defined benefit pension plan
covering substantially all of its employees and those of its
wholly-owned subsidiary. Benefits are based on an employee's
years of service and average final pay. The Company's policy is
to fund pension costs within the guidelines of the minimum
required by the Employee Retirement Income Security Act and the
maximum allowable as a tax deduction. Each company is allocated
its participative share of plan costs and contributions.
Net periodic pension costs for 1994, 1993 and 1992 included the following
components:
(000) 1994 1993 1992
Service cost - benefits earned during the period $ 6,871 $ 7,196 $ 7,310
Interest cost on projected benefit obligation 15,390 16,016 17,301
Actual return on plan assets (860) (23,200) (13,283)
Other-net (16,885) 5,496 (3,795)
Net periodic pension costs $ 4,516 $ 5,508 $ 7,533
Approximately $3 million, $5.2 million and $4.8 million of these
costs were charged to operating expense in 1994, 1993 and 1992,
respectively, and the remaining costs, which are associated with
construction labor, were charged to the cost of new utility
plant.
A reconciliation of the funded status of the plan as of December 31, 1994 and
1993 is as follows:
(000)
1994 1993
Fair value of plan assets $190,200 $213,600
Projected benefit obligation 206,742 207,246
Plan assets (less than)in excess of
projected benefit obligation (16,542) 6,354
Unrecognized net transition asset (1,722) (1,894)
Unrecognized prior service cost 306 329
Unrecognized net loss (gain) 24,106 (638)
Prepaid pension cost $ 6,148 $ 4,151
Accumulated benefit obligation:
Vested benefits $166,602 $165,872
Nonvested benefits 485 1,216
Total $167,087 $167,088
At December 31, 1994, approximately 60% of plan assets were
invested in equity securities, 18% in fixed income securities and
22% in other investments. The assumed rates used in determining
the actuarial present value of the projected benefit obligation
at year-end were as follows:
1994 1993
Weighted average discount 7.5% 7.5%
Anticipated increase in compensation 3.5% 3.5%
The assumed long term rate of return on plan assets was 8.5% for
both 1994 and 1993 and 8% for 1992.
Other Postretirement Benefits
The Company and its subsidiary provide certain health care and
life insurance benefits for retired employees and their eligible
dependents. Substantially all employees may become eligible for
these benefits if they reach retirement age while working for the
companies. Benefits are provided through insurance companies and
other plan providers whose premiums and related plan costs are
based on the benefits paid during the year. The Company has a
tax qualified trust to fund these benefits. Each company is
allocated its participative share of plan costs and
contributions.
The cost of other postretirement benefits was $15.6 million,
$13.1 million and $6 million in 1994, 1993 and 1992,
respectively. These costs were allocated as follows:
(millions) 1994 1993 1992
Operating expense $5.6 $3.3 $3.8
New utility plant-associated with
construction labor .2 1.7 2.2
Regulatory asset 9.8 8.1 -
The regulatory assets represent the amount of cost recognized
under accounting standards effective January 1, 1993 in excess of
the amount of cost currently recovered in rates. These excess
costs are deferred as authorized by an accounting order of the
BPU pending future recovery through rates.
Net periodic other postretirement benefits cost as calculated in
accordance with accounting standards in effect since January 1,
1993 include:
1994 1993
(000)
Service cost-benefits attributed to service during
the period $ 3,817 $ 3,045
Interest cost on accumulated postretirement
benefits obligation 8,450 7,133
Actual return on plan assets 100 (255)
Amortization of unrecognized transition
obligation 3,893 3,893
Other-net (700) (711)
Net periodic other postretirement cost $15,560 $13,105
A reconciliation of the funded status of the plan and the obligation for other
postretirement benefits recognized in the Consolidated Balance Sheet as of
December 31, 1994 and 1993 is as follows:
(000) 1994 1993
Accumulated benefits obligation:
Retirees $ 43,265 $ 32,720
Fully eligible active plan participants 18,010 21,267
Other active plan participants 60,588 49,125
Total accumulated benefits obligation 121,863 103,112
Less fair value of plan assets 14,700 14,400
Accumulated benefits obligation in excess
of plan assets 107,163 88,712
Unrecognized net loss (19,223) (6,639)
Unamortized unrecognized transition obligation (70,075) (73,968)
Accrued other postretirement
benefits cost obligation $ 17,865 $ 8,105
At December 31, 1994, approximately 81% of plan assets were
invested in fixed income securities and 19% in other investments.
The assumed health care costs trend rate for 1994 is 10% and is
assumed to evenly decline to an ultimate constant rate of 5% in
the year 2000 and thereafter. If the assumed health care costs
trend rate was increased by 1% in each future year, the aggregate
service and interest costs of the 1994 net periodic benefits cost
would increase by $1.9 million, and the accumulated
postretirement benefits obligation at December 31, 1994 would
increase by $16.7 million. The weighted average discount rate
assumed in determining the accumulated benefits obligation was
7.5% for 1994 and 1993. The assumed long term return rate on
plan assets was 7% for 1994 and 1993.
NOTE 5. JOINTLY-OWNED GENERATING STATIONS
The Company owns jointly with other utilities several electric
production facilities. The Company is responsible for its pro-
rata share of the costs of construction, operation and
maintenance of each facility.
The amounts shown represent the Company's share of each facility
at, or for the year ending, December 31, including AFDC as
appropriate.
Peach Hope
Keystone Conemaugh Bottom Salem Creek
Energy Source Coal Coal Nuclear Nuclear Nuclear
Company's Share
(%/MWs) 2.47/42.3 3.83/65.4 7.51/157.0 7.41/164.0 5.00/52.0
Electric Plant in Service (000):
1994 $11,293 $26,607 $125,003 $206,804 $238,980
1993 10,746 18,055 123,428 203,858 237,496
Accumulated Depreciation (000):
1994 $3,180 $6,237 $55,190 $79,898 $53,746
1993 3,231 5,971 51,871 78,383 46,933
Construction Work in Progress (000):
1994 $1,216 $2,649 $11,002 $ 8,727 $ 387
1993 758 9,956 7,983 10,799 1,022
Working Funds (000):
1994 $44 $69 $5,051 $5,199 $2,013
1993 44 69 4,772 5,249 2,061
Operation and Maintenance Expenses
(including fuel)(000):
1994 $5,085 $7,211 $29,530 $27,731 $10,471
1993 5,323 6,855 31,479 27,021 9,764
1992 4,976 7,194 29,618 25,461 9,541
Generation (MWH):
1994 257,561 419,313 1,214,776 836,725 355,390
1993 293,876 416,263 1,043,485 840,043 440,118
1992 294,222 457,771 958,740 737,356 351,672
The Company provides financing during the construction period for
its share of the jointly-owned facilities and includes its share
of direct operations and maintenance expenses in the Consolidated
Statement of Income. Additionally, the Company provides an
amount of working funds to the operators of the facilities to
fund operational needs. The increase in Electric Plant in
Service and decrease in Construction Work in Progress for
Conemaugh is primarily due to the placement in service of flue
gas disulfurization equipment (scrubber).
NOTE 6. CUMULATIVE PREFERRED STOCK
The Company has authorized 799,979 shares of Cumulative Preferred
Stock, $100 Par Value, two million shares of No Par Preferred
Stock and three million shares of Preference Stock, No Par Value.
Information relating to outstanding shares at December 31 is
shown in the table below.
Current
Optional
1994 1993 Redemption
Series Par Value Shares (000) Shares (000) Price
Not Subject to Mandatory Redemption:
4% $100 77,000 $ 7,700 77,000 $ 7,700 $105.50
4.10% 100 72,000 7,200 72,000 7,200 101.00
4.35% 100 15,000 1,500 15,000 1,500 101.00
4.35% 100 36,000 3,600 36,000 3,600 101.00
4.75% 100 50,000 5,000 50,000 5,000 101.00
5% 100 50,000 5,000 50,000 5,000 100.00
7.52% 100 100,000 10,000 100,000 10,000 101.88
Total $ 40,000 $ 40,000
Subject to Mandatory Redemption:
$8.25 None 55,000 $ 5,500 60,000 $ 6,000 104.66
$8.53 None 360,000 36,000 600,000 60,000 102.00
$8.20 None 500,000 50,000 500,000 50,000 -
$7.80 None 700,000 70,000 700,000 70,000 -
Total 161,500 186,000
Less portion due within one year 12,250 12,250
Total $149,250 $173,750
Cumulative Preferred Stock Not Subject to Mandatory Redemption is
redeemable solely at the option of the Company.
On November 1 of each year, 2,500 shares of the $8.25 No Par
Preferred Stock must be redeemed through the operation of a
sinking fund at a redemption price of $100 per share. The
Company may redeem not more than an additional 2,500 shares on
any sinking fund date without premium. The Company redeemed 5,000
shares in both 1994 and 1993.
Commencing in 1994, on November 1 of each year, 120,000 shares of
the $8.53 No Par Preferred Stock must be redeemed through the
operation of a sinking fund at a redemption price of $100 per
share. At the option of the Company, not more than an additional
120,000 shares may be redeemed on any sinking fund date without
premium. The Company redeemed 240,000 shares in 1994.
Beginning August 1, 1996 and annually thereafter, 100,000 shares
of the $8.20 No Par Preferred Stock must be redeemed through the
operation of a sinking fund at a redemption price of $100 per
share. At the option of the Company, not more than an additional
100,000 shares may be redeemed on any sinking fund date without
premium. This series is not refundable prior to August 1, 2000.
Beginning May 1, 2001 and annually through 2005, 115,000 shares
of $7.80 No Par Preferred Stock must be redeemed through the
operation of a sinking fund at a redemption price of $100 per
share. On May 1, 2006, the remaining shares outstanding must be
redeemed at $100 per share. ACE has the option to redeem up to
an additional 115,000 shares without premium on each May 1
through 2005. This series is not refundable prior to May 1,
2006.
For the next five years, the annual minimum sinking fund
requirements of the Cumulative Preferred Stock Subject to
Mandatory Redemption is $12.25 million for the year 1995, and
$22.25 million in each of the years 1996 and 1997 and $10.25
million in each of the years 1998 and 1999.
Cumulative Preferred Stock of the Company is not widely held and
trades infrequently. The estimated aggregate fair market value
of the Company's outstanding Cumulative Preferred Stock at
December 31, 1994 and 1993 was approximately $185 million and
$231 million, respectively. The fair market value has been
determined using market information available from actual trades
of similar instruments of companies with similar credit quality
and rate.
NOTE 7. LONG TERM DEBT
Maturity December 31
Series Date 1994 1993
(Medium Term Notes (MTNs) have varying maturity dates and are shown with the
weighted average interest rate of the related issues within the year of
maturity.)
(000)
5-1/8% First Mortgage Bonds 2/1/1996 $ 9,980 $ 9,980
Medium Term Notes Series B (6.28%) 1998 56,000 56,000
Medium Term Notes Series A (7.52%) 1999 30,000 30,000
Medium Term Notes Series B (6.83%) 2000 46,000 46,000
7-1/2% First Mortgage Bonds 4/1/2002 20,000 20,000
Medium Term Notes Series B (7.18%) 2003 20,000 20,000
7-3/4% First Mortgage Bonds 6/1/2003 29,976 29,976
Medium Term Notes Series A (7.98%) 2004 30,000 30,000
Medium Term Notes Series B (7.125%) 2004 28,000 28,000
7-5/8% Pollution Control 1/1/2005 - 6,500
Medium Term Notes Series B (6.45%) 2005 40,000 40,000
6-3/8% Pollution Control 12/1/2006 2,500 2,500
Medium Term Notes Series B (6.76%) 2008 50,000 50,000
10-1/2% Pollution Control Series B 7/15/2012 850 850
6-5/8% First Mortgage Bonds 8/1/2013 75,000 75,000
7-3/8% Pollution Control Series A 4/15/2014 18,200 18,200
10-1/2% Pollution Control Series C 7/15/2014 - 23,150
8-1/4% Pollution Control Series A 7/15/2017 4,400 4,400
9-1/4% First Mortgage Bonds 10/1/2019 53,857 65,767
6.80% Pollution Control Series A 3/1/2021 38,865 38,865
7% First Mortgage Bonds 9/1/2023 75,000 75,000
5.60% Pollution Control Series A 11/1/2025 4,000 4,000
7% First Mortgage Bonds 8/1/2028 75,000 75,000
6.15% Pollution Control Series A 6/1/2029 23,150 -
7.20% Pollution Control Series A 11/1/2029 25,000 -
7% Pollution Control Series B 11/1/2029 6,500 -
Total 762,278 749,188
Debentures:
5-1/4% 2/1/1996 2,267 2,267
7-1/4% 5/1/1998 2,619 2,619
Total 4,886 4,886
Unamortized Premium and Discount-Net (3,876) (2,973)
Total Long Term Debt $763,288 $751,101
In 1994, the Company redeemed its 10-1/2% Pollution Control Bonds
Series C due 7/15/2014 and its 7-5/8% Pollution Control Bonds due
1/1/2005. The Company acquired and retired $11.9 million
principal amount of First Mortgage Bonds, 9-1/4% Series due
10/1/2019. The aggregate cost of these redemptions was $1.2
million, net of related Federal income taxes.
Sinking fund deposits are required for retirement of the 5-1/4%
Debentures annually on February 1 through 1995 and for the 7-1/4%
Debentures annually on May 1 through 1997 in amounts in each case
sufficient to redeem $100,000 principal amount. The Company may,
at its option, redeem an additional $100,000 annually in each
case. Through December 31, 1994, the Company acquired and
cancelled $333 thousand and $181 thousand principal amount of the
5-1/4% and 7-1/4% Debentures, respectively, which will be used to
satisfy its requirements for 1995. Certain series of First
Mortgage Bonds contain provisions for deposits of cash or
certification of bondable property currently amounting to $100
thousand, which the Company may elect to satisfy through property
additions. For the next five years, the annual amount of
scheduled maturities and sinking fund requirements of the
Company's long term debt are $12.266 million in 1996, $175
thousand in 1997, $58.575 million in 1998 and $30.075 million in
1999.
The Company's long term debt securities are not widely held and
generally trade infrequently. The estimated aggregate fair
market value of the Company's outstanding long term debt at
December 31, 1994 and 1993 was $693 million and $768 million,
respectively. The fair market value has been determined based on
quoted market prices for the same or similar debt issues or on
debt instruments of companies with similar credit quality, coupon
rates and maturities.
NOTE 8. COMMITMENTS AND CONTINGENCIES
Construction Program
The Company's cash construction expenditures for 1995, which
excludes AFDC and customer contributions, are estimated to be
approximately $116 million. Current commitments for the
construction of major production and transmission facilities
approximate $23 million, of which it is estimated that $19
million will be expended in 1995.
Insurance Programs
The Company is a member of certain insurance programs that
provide coverage for decontamination and property damage to
members' nuclear generating plants. Facilities at the Peach
Bottom, Salem and Hope Creek stations are insured against
property damage losses up to $2.75 billion per site under these
programs.
In addition, the Company is a member of an insurance program
which provides coverage for the cost of replacement power during
prolonged outages of nuclear units caused by certain specific
conditions. The insurer for nuclear extra expense insurance
provides stated value coverage for replacement power costs
incurred in the event of an outage at a nuclear unit resulting
from physical damage to the nuclear unit. The stated value
coverage is subject to a deductible period of the first 21 weeks
of any outage. Limitations of coverage include, but are not
limited to, outages (1) not resulting from physical damage to the
unit, (2) resulting from any government mandated shutdown of the
unit, (3) resulting from any gradual deterioration, corrosion,
wear and tear, etc. of the unit, (4) resulting from any
intentional acts committed by an insured and (5) resulting from
certain war risk conditions. Under the property and replacement
power insurance programs, the Company could be assessed
retrospective premiums in the event the insurers' losses exceed
their reserves. As of December 31, 1994, the maximum amount of
retrospective premiums the Company could be assessed for losses
during the current policy year was $6.6 million under these
programs.
The Price-Anderson provisions of the Atomic Energy Act of 1954,
as amended by the Price-Anderson Amendments Act of 1988, govern
liability and indemnification for nuclear incidents. All nuclear
facilities could be assessed, after exhaustion of private
insurance, up to $79.275 million each, payable at $10 million per
year, per reactor and per incident. Based on its ownership share
of nuclear facilities, the Company could be assessed up to $27.6
million per incident. This amount would be payable at $3.48
million per year, per incident.
Energy and Capacity Arrangements
UTILITY SOURCES
The Company has an arrangement for the purchase of 125 MWs of
capacity and related energy from Pennsylvania Power and Light
through September 30, 2000. Capacity costs, including certain
deferred charges, totaled $26.6 million, $24.4 million and $25.1
million, and energy costs totaled $10.8 million, $11.2 million
and $13.4 million in 1994, 1993 and 1992, respectively.
Commitments for capacity costs expected to be incurred are $11.7
million, $12.0 million, $12.3 million, $12.6 million, $14.2
million and $12.3 million in each of the years 1995-2000,
respectively.
The Company's arrangement for the purchase of 200 MWs of capacity
and related energy from PECO expired May 31, 1994. Capacity
costs charged to Purchased Capacity expense totaled $25.6 million
through May 1994 and $55.9 million and $52.5 million for 1993 and
1992, respectively. Energy costs for the same periods amounted
to $11.4 million, $21.0 million and $19.2 million, respectively.
ACE also had another arrangement with PECO for the purchase of
energy only which terminated in October 1994. Energy costs under
this arrangement amounted to $32.5 million, $19.0 million and
$17.5 million in 1994, 1993 and 1992, respectively.
The Company is a member of the Pennsylvania-New Jersey-Maryland
Interconnection (PJM), an integrated power pool that is connected
with other utilities for the interchange of energy on an
as-needed and as-available basis. The Company is required to
plan for reserve capacity based on aggregate PJM requirements
allocated to member companies. The Company has satisfied its
current reserve requirements. The Company also has an
interchange agreement with the City of Vineland, New Jersey,
which operates a municipal utility located in the Company's
service territory. The cost of energy purchased through
interchange agreements totaled $10.4 million, $9.9 million and
$9.4 million in 1994, 1993 and 1992, respectively.
NONUTILITY SOURCES
The Company has contracted for a total of 569 MWs of capacity and
related energy from four non utility sources. The last two
projects under contract for 388 MWs became operational in 1994.
Nonutility capacity costs totaled $77.0 million, $30.2 million
and $24.4 million, and energy costs totaled $62.5 million, $36.0
million and $27.6 million, in 1994, 1993 and 1992, respectively.
Capacity and energy costs from nonutility sources are recovered
through the LEC.
Environmental Matters
The provisions of Title IV of the Clean Air Act Amendments of
1990 (CAAA) will require, among other things, phased reductions
of sulfur dioxide (SO2) emissions by 10 million tons per year,
and a limit on S02 emissions nationwide by the year 2000, and
reductions in emissions of nitrogen oxides (NOx) by approximately
2 million tons per year. The Company's wholly-owned B.L. England
Units 1 and 2 and its jointly-owned Conemaugh Station Units 1 and
2 are affected during Phase I (1995) and all of the Company's
other fossil-fuel steam generating units are affected by Phase II
(2000) of the CAAA. The Company has installed a scrubber on B.L.
England Unit 2 at a cost of $81 million which went into service
in December 1994. By scrubbing B.L. England Unit 2, Phase I S02
emission requirements are met for both B.L. England Units 1 and
2. The Conemaugh owners installed a scrubber on Conemaugh Unit 1
which went into service in December 1994. The Company's 3.83%
share of the cost was $11 million. A scrubber on Conemaugh Unit
2 is to be completed in 1995, with the Company's share of the
cost estimated to be $4 million. The jointly-owned Keystone
Station is impacted by the SO2 and NOx provisions of Title IV of
the CAAA during Phase II. Currently, the Keystone owners plan to
rely on utilizing emission allowances, and modified fuel content
to a lesser extent, to meet compliance with the CAAA through the
year 2000. In addition, certain purchase power arrangements will
be affected by the CAAA, in amounts that are not presently
determinable.
Federal and state legislation authorize various governmental
authorities to issue orders compelling responsible parties to
take cleanup action at sites determined to present danger from
releases of hazardous substances. The various statutes impose
joint and several liability without regard to fault for certain
investigative and cleanup costs for all potentially responsible
parties. The Company has received notification with respect to
two sites within New Jersey as one of a number of alleged
responsible parties for cleanup and remedial actions. The
Company's maximum expense for these claims is not expected to
exceed $1 million. The Company believes that insurance coverage
is available to satisfy any amounts in excess of the self-insured
limits associated with these particular claims should any
liability result. The insurer for pollution liability insurance
provides comprehensive excess general liability coverage,
including pollution liability, for environmental costs incurred
in the event of bodily injury or property damage resulting from
the discharge or release of pollutants into or upon the land,
atmosphere or water. Limitations of coverage include any
pollution liability 1) resulting subsequent to the disposal of
such pollutants, 2) resulting from the operation of a storage
facility of such pollutants, 3) resulting in the formation of
acid rain, 4) caused to property owned by an insured and 5)
resulting from any intentional acts committed by an insured.
Other
The Company is subject to a performance standard for all of its
jointly-owned nuclear units. This standard is used by the BPU in
determining recovery of replacement energy costs resulting from
poor nuclear performance. The standard establishes a target
aggregate capacity factor within a zone of reasonable performance
to be achieved by the units. Performance outside of the zone
results in penalties or rewards. Any penalties incurred would not
be permitted to be recovered from customers and would be charged
against income. For 1994, the aggregate capacity factor of the
Company's nuclear units is within the reasonable performance
zone, which results in no penalty or reward.
A contract with an industrial company whereby the Company
delivered process steam, water and by-product electricity was
terminated by this company effective June 30, 1994. In 1993, the
Company received approximately $12 million from this company for
services and energy sales. In accordance with the termination
agreement, the Company received $4.2 million in cash proceeds,
45,165 emission allowances valued at $6.5 million and made
provisions to retire certain equipment. A net gain of $2.4
million net of tax resulted. The steam and electricity needs of
this company are provided by a nonutility cogeneration facility.
The Company has a contract for the purchase of 188 MWs of
capacity and energy from this facility.
In November 1994, the Company announced a program to reduce its
workforce by up to 20% or 350 people. This program was initiated
so that the Company can better position itself for the more
competitive environment within the electric industry. Under the
program, certain employees will separate from the Company and be
entitled to a severance package, including salary continuation,
lump sum payments, extended medical benefits and outplacement
services. In December 1994, the Company accrued the costs of the
workforce reduction in the amount of $17.3 million, net of tax of
$9.3 million. Included is the Company's share of an early
retirement program of a jointly-owned nuclear station. The
Company's employee separations are expected to be substantially
completed by March 1, 1995.
The Energy Policy Act of 1992 permits the Federal government to
assess investor-owned electric utilities that have ownership
interests in nuclear generating facilities an amount to fund the
decontamination and decommissioning of three Federally operated
nuclear enrichment facilities. Based on its ownership in five
nuclear generating units, the Company recorded a liability of
$6.6 million and $8 million at December 31, 1994 and 1993,
respectively, for its obligation to be paid over the next 13
years. The Company has an associated regulatory asset of $7.2
million and $8.4 million at December 31, 1994 and 1993,
respectively. Amounts are currently being recovered in rates for
this liability and the regulatory asset is concurrently being
amortized to expense based on the annual assessment billed by the
Federal government.
NOTE 9. LEASES
The Company leases various types of property and equipment for
use in its operations. Certain of these lease agreements are
capital leases consisting of the following at December 31:
(000) 1994 1993
Production plant $13,521 $13,521
Less accumulated amortization 9,707 8,846
Net 3,814 4,675
Nuclear fuel 38,216 40,593
Leased property-net $42,030 $45,268
The Company has a contractual obligation to obtain nuclear fuel
for the Salem, Hope Creek and Peach Bottom stations. The asset
and related obligation for the leased fuel are reduced as the
fuel is burned and are increased as additional fuel purchases are
made. No commitments for future payments beyond satisfaction of
the outstanding obligation exist. Operating expenses for 1994,
1993 and 1992 include leased nuclear fuel costs of $14.1 million,
$13.9 million and $13.5 million, respectively, and rentals and
lease payments for all other capital and operating leases of $5.9
million, $5.5 million and $5.5 million, respectively. Future
minimum rental payments for all noncancellable lease agreements
are not significant to the Company's operations. Rental charges
of other subsidiary companies are not significant.
NOTE 10. QUARTERLY FINANCIAL RESULTS (UNAUDITED)
Quarterly financial data, reflecting all adjustments necessary in
the opinion of the Company for a fair presentation of such
amounts, are as follows:
Operating Operating Net Earnings for
Quarter Revenues Income Income Common Stock
1994 (000) (000) (000)
1st $232,134 $ 39,580 $27,130 $22,821
2nd 205,861 30,299 20,635 16,326
3rd 272,769 58,321 49,679 45,370
4th 202,461 24,794 (4,272) (8,059)
Annual $913,226 $152,995 $93,174 $76,458
1993
1st $203,672 $ 35,264 $ 23,770 $19,331
2nd 192,561 27,203 14,885 10,548
3rd 268,927 68,421 55,477 51,157
4th 200,637 28,039 14,894 10,585
Annual $865,799 $158,927 $109,026 $91,621
Individual quarters may not add to the total due to rounding, and
the effect on earnings per share of changing average number of
common shares outstanding.
The revenues of the Company are subject to seasonal fluctuations
due to increased sales and higher residential rates during the
summer months.
Net Income reflects special charges aggregating $18.7 million,
after tax of $10 million, recorded in Other Income during the
fourth quarter of 1994. One of the charges is an accrual of the
costs of workforce reductions for severance and benefits packages
in the amount of $17.3 million, net of tax of $9.3 million.
Another charge is an amount for the Company's share of deferred
costs for studies at a nuclear station in the amount of $1.4
million, net of tax of $735 thousand.
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Atlantic City Electric Company (the Company) is a wholly-owned
and the principal subsidiary of Atlantic Energy, Inc. (AEI). The
Company is an electric utility regulated by the New Jersey Board
of Public Utilities (BPU). The Company has a wholly-owned
subsidiary that operates certain generating facilities.
The emergence of competition in the area of electric generation,
slower growth in energy sales, Federal deregulation of wholesale
energy sales, prospective retail wheeling initiatives coupled
with a public utility's obligation to serve and the need to
mitigate future rate increases has caused the Company to re-
examine its traditional approach to its business.
The Company's current business plan recognizes the increasingly
competitive nature of the electric energy business in general and
the need to encourage economic growth and stability in the
service territory and surrounding region. The Company is re-
evaluating its revenue requirements and service pricing, the
implementation of additional cost controls and the development of
new sources of revenue.
Financial Results
Operating revenues for 1994, 1993 and 1992 were $913.2 million,
$865.8 million and $816.9 million, respectively. The increase in
1994 revenue reflects an increase in Levelized Energy Clause
(LEC) revenues as a result of a $55.0 million rate increase
effective July 1994 and an increase in sales for resale. The
increased revenues for 1993 reflect the effect of a rate increase
of $10.9 million effective in that year. The revenue increase in
1993 also reflects the contrast between the 1993 normal and the
1992 below normal summer temperatures. Income available for
common stock was $76.5 million, compared with $91.6 million in
1993 and $89.6 million in 1992.
The 1994 earnings include a reduction of $17.3 million, net of
tax of $9.3 million for the expected costs of the Company's
employee separation programs and $1.4 million, net of tax of $735
thousand for the write-off of deferred nuclear study costs. In
1993, results reflect increased kilowatt-hour sales due to the
contrast between 1993 and 1992 summer temperatures. The
Company's 1993 earnings were reduced as a result of
reorganization activities. The Company's 1992 earnings were
increased due to the litigation settlement with PECO Energy.
This increase was offset in part by lower energy sales due to
cooler summer temperatures and a decrease in industrial sales.
Liquidity and Capital Resources
Overview
Cash construction expenditures for the 1992-1994 period amounted
to $388.8 million and included expenditures for upgrades to
existing transmission and distribution facilities and compliance
with provisions of the Clean Air Act Amendments (CAAA) of 1990.
The Company's current estimate of cash construction expenditures
for the 1995-1997 period is $268 million. These estimated
expenditures reflect necessary improvements to transmission and
distribution facilities and further compliance with provisions of
the CAAA.
The Company also utilizes cash for mandatory redemptions of
Preferred Stock and maturities and redemption of long term debt.
Optional redemptions of securities are reviewed on an ongoing
basis with a view toward reducing the overall cost of funds.
Redemptions of Preferred Stock (at par or stated value) and
redemptions, reacquisitions and retirements, and maturities of
First Mortgage Bonds for the period 1992-1994 are shown as
follows:
1994 1993 1992
Preferred Stock
(Series)
9.96% (Shares) - 48,000 8,000
$8.53 (Shares) 240,000 - -
$8.25 (Shares) 5,000 5,000 2,500
Aggregate Amount (000) $24,500 $5,300 $1,050
First Mortgage Bonds redeemed or acquired and retired or matured
in the period 1992-1994 were as follows:
Date Series Principal Amount Price(%)
(000)
November 1994 7-5/8% due 2005 $ 6,500 100.00
June 1994 10-1/2% due 2014 23,150 102.00
Various 1994 Dates 9-1/4% due 2019 11,910 105.38*
September 1993 9-1/4% due 2019 69,233 110.95*
September 1993 8-7/8% due 2016 125,000 104.80
March 1993 8-7/8% due 2000 19,000 102.41
March 1993 8% due 2001 27,000 102.53
March 1993 8% due 1996 95,000 100.91
March 1993 4-3/8% due 1993 9,540 100.00
July 1992 4-1/2% due 1992 10,350 100.00
* Average price
Scheduled debt maturities and sinking fund requirements aggregate
$69 million for the years 1995-1997.
On or before April 1 of each year, the Company and other New
Jersey utilities are required to pay gross receipts and franchise
taxes (state excise taxes) to the State of New Jersey. In March
1994, the Company paid $137.5 million. Included in that amount
was approximately $50 million representing the second and final
installment for the additional one-half year's amount of tax due
as required by amended state law. This additional amount of
gross receipts and franchise tax payment, plus the additional
one-half year's payment in 1993 of $45 million, has been recorded
on the Consolidated Balance Sheet as Unrecovered State Excise
Taxes and is being recovered through rates by the Company. In
December 1993, the Company paid $20 million in connection with
renegotiation of a nonutility purchase power contract which the
Company is recovering through its LEC. The estimated savings of
this renegotiation based on currently forecasted fuel costs, is
$15 million to $20 million per year, net of the $20 million
payment.
On an interim basis, the Company finances that portion of its
construction costs and other capital requirements in excess of
internally generated funds through the issuance of unsecured
short term debt consisting of commercial paper and borrowings
from banks. As of December 31, 1994, the Company has arranged
for lines of credit of $150 million of which $141.4 million was
available. Permanent financing by the Company is undertaken by
the issuance of its long term debt and Preferred Stock and from
capital contributions by the parent company. The Company's
nuclear fuel requirements associated with its jointly-owned units
have been financed through arrangements with a third party.
In 1994, the Company issued and sold $54.65 million of its long
term debt consisting of Pollution Control Bonds. The proceeds
from the financings were used for refunding higher cost Pollution
Control Bonds and for construction purposes. Additionally, $125
million in debt securities were registered and are available for
issuance in 1995. In 1993, the Company issued and sold $469
million of long term debt consisting of $240 million of Series B
Medium Term Notes, $225 million of First Mortgage Bonds and $4
million of Pollution Control Bonds. The proceeds from the 1993
financings were also used for refunding higher cost debt and
construction purposes. In 1992, the Company issued and sold $60
million of Series A Medium Term Notes, the proceeds of which were
used for the Company's construction program. During 1995-1997,
the Company expects to issue $50 million in new long term debt to
be used for funding of construction and repayment of short term
debt.
Provisions of the Company's charter, mortgage and debenture
agreements can limit, in certain cases, the amount and type of
additional financing which may be used. At December 31, 1994,
the Company estimates additional funding capacities of $218
million of First Mortgage Bonds, or $530 million of Preferred
Stock, or $432 million of unsecured debt. These amounts are not
necessarily additive.
RESULTS OF OPERATIONS
Revenues
Operating Revenues - Electric increased 5.5% and 6.0% in 1994 and
1993, respectively. Components of the overall changes are shown
as follows:
(millions)
1994 1993
Base Revenues $(4.2) $12.2
Levelized Energy Clauses 30.3 (5.0)
Kilowatt-hour Sales 9.6 42.6
Unbilled Revenues (7.3) (1.2)
Sales for Resale 17.8 0.7
Other 1.2 (0.4)
Total $47.4 $48.9
Levelized Energy Clause (LEC) revenues increased in 1994 due to
rate increases of $55 million in July 1994 and $10.9 million in
October 1993. The decrease in 1993 LEC revenues was the net
result of the increase in October 1993 and an $8.5 million
decrease effective October 1992. Changes in kilowatt-hour sales
are discussed under "Billed Sales to Ultimate Customers."
Overall, the combined effects of changes in rates charged to
customers and kilowatt-hour sales resulted in increases of 3.1%
and 0.8% in revenues per kilowatt-hour in 1994 and 1993,
respectively. The changes in Unbilled Revenues are a result of
the amount of kilowatt-hours consumed by ultimate customers at
the end of the respective periods, which are affected by weather
and economic conditions, and the corresponding price per
kilowatt-hour. The changes in Sales for Resale are a function of
the Company's energy mix strategy, which in turn is dependent
upon the Company's needs for energy, the energy needs of other
utilities participating in the regional power pool of which the
Company is a member, and the sources and prices of energy
available. The increase in Sales for Resale for 1994 was the
result of meeting the demands of the regional power pool due to
the extreme weather conditions during the first six months of
1994.
Effective July 1, 1994, the BPU permitted hotel-casino customers
to take service under existing commercial rate schedules which is
expected to reduce annual revenue by approximately $7 million.
Billed Sales to Ultimate Utility Customers
Changes in kilowatt-hour sales are generally due to changes in
the average number of customers and average customer use, which
is affected by economic and weather conditions. Energy sales
statistics, stated as percentage changes from the previous year,
are shown as follows:
1994 1993
Avg Avg # Avg Avg #
Customer Class Sales Use of Cust Sales Use of Cust
Residential 1.5% .4% 1.1% 6.7% 5.9% .8 %
Commercial 2.6 .5 2.1 5.1 3.2 1.9
Industrial (2.9) (3.8) .9 2.6 4.6 (1.9)
Other 3.2 4.0 (.8) 1.2 1.6 (.4)
Total 1.3 - 1.2 5.4 4.4 .9
The 1994 increase in total kilowatt-hour sales was due to the
extreme weather conditions during the first quarter of 1994 and
an increased number of billing days in 1994 compared to 1993.
This increase was partially offset by the abnormal weather
conditions during the last half of the year when kilowatt-hour
usage fell below 1993 levels. In 1993, total kilowatt-hour sales
increased primarily due to the colder winter temperatures during
the first quarter, and below normal temperatures during the
summer of 1992. Improved economic conditions also contributed to
the increase in 1993 sales. Commercial sales in both years
benefitted from night lighting programs. The decline in 1994
industrial sales is due to the loss of the Company's largest
customer to an independent power producer during the year.
KWH sales and electric revenues by customer class were as
follows:
Residential Commercial Industrial Other
KWH Sales (000)
1994 3,546,789 3,344,676 1,224,721 51,670
1993 3,495,722 3,259,541 1,261,069 50,080
1992 3,276,330 3,100,133 1,229,211 49,464
Revenues (000)
1994 $ 416,468 $ 336,459 $ 102,687 $ 10,973
1993 393,866 315,089 100,812 10,575
1992 364,232 299,866 97,475 10,548
Costs and Expenses
Total Operating Expenses increased 7.5% and 3.9% in 1994 and
1993, respectively. Included in these expenses are the costs of
energy, purchased capacity, operations, maintenance, depreciation
and taxes.
Energy expense reflects cost incurred for energy needed to meet
load requirements, various energy supply sources used and
operation of the LECs. Changes in costs reflect the varying
availability of low-cost generation from the Company-owned and
purchased energy sources, and the corresponding unit prices of
the energy sources used, as well as changes in the needs of other
utilities participating in the Pennsylvania-New Jersey-Maryland
Interconnection. The cost of energy is recovered from customers
primarily through the operation of the LEC. Until 1994, earnings
were generally not affected by energy costs because these costs
are adjusted to match the associated LEC revenues. In any
period, the actual amount of LEC revenue recovered from customers
may be greater or less than the actual amount of energy cost
incurred in that period. Such respective overrecovery or
underrecovery of energy costs is recorded on the Consolidated
Balance Sheet as a liability or an asset as appropriate. Amounts
in the balance sheet are recognized in the Consolidated Statement
of Income within Energy expense during the period in which they
are subsequently recovered through the LEC. The Company was
underrecovered by $11 million and by $7.2 million at December 31,
1994 and 1993, respectively.
As a result of implementing the Southern New Jersey Economic
Initiative in rates, effective July 19, 1994, the Company is
forgoing recovery of future energy costs in LEC rates of $28
million through May 31, 1995. After tax income has been reduced
by $10.1 million due to the effects of this initiative in 1994.
In 1994, Energy expense increased 32.7% due to the adoption of
the Southern New Jersey Economic Initiative and the increase in
the levelized energy clause that reduced underrecovered fuel
costs. Production-related energy costs for 1994 increased by
19.9% due to increased overall generation and the high cost of
energy from additional nonutility sources. The average unit cost
for energy in 1994 increased to 2.04 cents per kilowatt-hour
compared to 1.82 cents per kilowatt-hour in 1993. Energy expense
for 1993 decreased 1.1% primarily due to an increase in
underrecovered fuel costs in 1993 compared to 1992. Production-
related energy cost for 1993 increased by 6.7% largely due to
increased generation. The average unit cost for energy in 1993
increased to 1.82 cents per kilowatt-hour compared to 1.80 cents
per kilowatt-hour in 1992. The 1993 increase in the per unit
cost is a result of increased amounts of higher cost energy from
nonutility sources and a decreased supply of lower cost energy
from coal sources.
Purchased Capacity expense reflects entitlements to generating
capacity owned by others. Purchased Capacity expense increased
18.2% and 7.4% in 1994 and 1993, respectively. The increases in
Purchased Capacity reflect additional capacity supplied by
nonutility power producers that became operational in each year.
Operations expense decreased 3.5% in 1994 and increased 8.9% in
1993. The increase in 1993 was due primarily to corporate
reorganization activities by the Company. Maintenance expense
decreased 17.1% in 1994 due to cost saving measures in
maintenance activities. The 9% decrease in 1993 maintenance
expense was due to the scheduling of maintenance projects.
Depreciation and Amortization expense increased 7.9% in 1994 as a
result of an increase in the depreciable base of the Company's
electric plant in service. State Excise Taxes expense decreased
6.9% in 1994 and increased by 6.4% in 1993. The increase in 1993
is due to a higher tax assessment.
Federal Income Taxes decreased 6.1% in 1994 and increased 21.9%
in 1993 as a result of the level of taxable income during those
periods. The change in the 1993 amount reflects the increase in
the Federal income tax rate to 35% from 34%, effective in that
year.
Employee Separation Costs represents programs by the Company to
reduce its workforce by about 20%, or 350 people. Other-Net
within Other Income (Expense) decreased in 1994 due to the net
after tax impacts of the write-off of deferred nuclear study
costs of $1.4 million. Litigation Settlement in 1992 represents
the Company's share of the settlement of litigation concerning
the Nuclear Regulatory Commission imposed shutdown in earlier
years of the Peach Bottom Atomic Power Station. The Litigation
Settlement for 1993 represents an additional allocation to
customers of the proceeds from the 1992 settlement as ordered by
the BPU.
Interest on Long Term Debt decreased in 1994 due to refunding of
higher cost debt. Interest on Long Term Debt increased 11.4% in
1993 reflecting the net effects of issuance of $469 million of
First Mortgage Bonds during the year, and the maturity,
redemption and reacquisition of various series of First Mortgage
Bonds totaling $344.8 million principal amount. At December 31,
1994, 1993 and 1992, the Company's embedded cost of long term
debt was 7.6%, 7.8% and 8.8%, respectively.
Preferred Stock Dividend Requirements decreased as a result of
continuing mandatory and optional redemptions in each year.
Embedded cost of Preferred Stock as of December 31, 1994, 1993
and 1992 was 7.6%, 7.7% and 7.7%, respectively.
Outlook
The nature of the electric utility business is capital intensive.
The Company's ability to generate cash flows from operating
activities and its continued access to the capital markets is
affected by the timing and adequacy of rate relief, competition
and the economic vitality of its service territory. The Company
has lowered its planned capital expenditures for the period 1995-
1999 which will reduce its external cash requirements.
Additionally, the Company expects to review its revenue
requirements with a view toward overall rate stability in light
of expected price competition. The Company believes one of its
greatest assets is its high level of customer service and
reliability.
The financial performance of the Company will be affected in the
future by the level of sales of energy and the impacts of
regulation and competition. To better position itself for a more
competitive environment, the Company initiated cost reduction
programs in 1994. One such program was a workforce reduction
program which the Company expects will result in annual after tax
cost savings in excess of $10 million. Other issues which may
impact the electric utility business include public health,
safety and environmental legislation.
Changes in operating revenues in the future will result from
changes in customer rates, energy consumption and general
economic conditions in the service area, as well as the impacts
of load management and conservation programs instituted by the
Company. The Company's revenues could also be affected by the
increasing competition in the retail and wholesale energy market.
The emergence of competition among suppliers of electricity may
require the Company to create new rate structures and to offer
incentives to its Commercial and Industrial customers.
Net income of the Company may be affected by the operational
performance of nuclear generating facilities. The Company is
subject to a BPU-mandated nuclear unit performance standard.
Under the standard, penalties or rewards are based on the aggre-
gate capacity factor of the Company's five jointly-owned nuclear
units. Any penalties incurred would not be permitted to be
recovered from customers and would be charged against income.
The Energy Policy Act, enacted in October 1992, provides, among
other things, for increased competition between utility and
nonutility electric generators and permits wholesale transmission
access, or wheeling, with certain requirements. Other pressures
such as increased customer demands for competitive rates,
potential loss of municipal power sales, excess generating
capacity, together with the emergence of nonutility energy
sources, are expected to increase the amount of business risk for
electric utilities in the future. In addition, the extent to
which New Jersey public utility regulation is modified to be
reflective of these new competitive realities will be a key
factor affecting the Company.
Development of electric generating facilities by nonutilities has
occurred in the Company's service territory. Effects of
nonutility generation could be offset to some extent by natural
growth in the service territory and additional efforts by the
Company to reduce the impact of the potential loss of kilowatt-
hour sales and revenues.
The CAAA will require modifications at certain of the Company's
facilities. Compliance with the CAAA will cause ACE to incur
additional operating and/or capital costs. Presently, the
Company's construction budget for 1995 through 1997 includes
approximately $16 million related to the cost of compliance. In
addition, certain power purchase arrangements will be affected by
the CAAA, the effects of which are not presently determinable.
Federal and state legislation authorize various governmental
authorities to issue orders compelling responsible parties to
take cleanup action at sites determined to present danger from
releases of hazardous substances. The various statutes impose
joint and several liability without regard to fault for certain
investigative and cleanup costs for all potentially responsible
parties. The Company has received notification with respect to
two sites within New Jersey as one of a number of alleged
responsible parties for cleanup and remedial actions. The
Company's responsibility is not expected to exceed $1 million in
the aggregate.
Inflation
Inflation affects the level of operating expenses and also the
cost of new plant placed in service. Traditionally, the rate
making practices that have applied to the Company have involved
the use of historical test years and the actual cost of plant.
However, the ability to recover increased costs through rates,
whether resulting from inflation or otherwise, depends upon the
frequency, timing and results of rate case decisions.