Exhibit 28(a)
INDEPENDENT AUDITORS' REPORT
To Atlantic City Electic Company:
We have audited the accompanying consolidated balance sheets of
Atlantic City Electric Company and subsidiary as of December 31,
1995 and 1994 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, 1995. 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 audits 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,
1995 and 1994 and the results of their operations and their cash
flows for each of the three years in the period ended December
31, 1995 in conformity with generally accepted accounting
principles.
DELOITTE & TOUCHE LLP
Parsippany, New Jersey
February 2, 1996
REPORT OF MANAGEMENT
The management of Atlantic City Electric Co. and its subsidiary
is responsible for the preparation of the financial statements
presented in this Annual Report. 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 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, 1995, 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 provides
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 to management and the Audit Committee of the Board of
Directors. Management responds to such recommendations as
appropriate in the circumstances. None of the recommendations
made for the year ended December 31, 1995 represented significant
deficiencies in the design or operation of the Company's internal
control structure.
M. J. Chesser
President and Chief Operating Officer
M. J. Barron
Senior Vice President and Chief Financial Officer
February 2, 1996
CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars)
For the Years Ended December
31,
1995 1994
1993
Operating Revenues-Electric $953,779 $913,226
$865,799
Operating Expenses:
Energy 191,766 210,891
159,438
Purchased Capacity 190,570 130,929
110,781
Operations 152,277 157,047
162,840 Maintenance 34,414 37,662
45,452
Depreciation and Amortization 78,461 73,344
67,950
State Excise Taxes 102,811 97,072
104,280
Federal Income Taxes 45,876 42,529
45,277
Other Taxes 8,677 10,757
10,854
Total Operating Expenses 804,852 760,231
706,872
Operating Income 148,927 152,995
158,927
Other Income and Expense:
Allowance for Equity Funds Used
During Construction 817 3,364
2,368
Employee Separation Costs,
net of tax benefit of $9,265 - (17,335)
-
Litigation Settlement, net of tax
benefit of $1,321 - -
(2,564) Other-Net 10,208 9,568
9,865
Total Other Income and Expense 11,025 (4,133)
9,669
Income Before Interest Charges 159,952 148,862
168,596
Interest Charges:
Interest on Long Term Debt 60,329 57,346
59,385
Other Interest Expense 2,550 1,114
1,633
Total Interest Charges 62,879 58,460
61,018
Allowance for Borrowed Funds Used
During Construction (1,679) (2,772)
(1,448)
Net Interest Charges 61,200 55,688
59,570
Net Income $ 98,752 $ 93,174
$109,026
Earnings for Common Stock:
Net Income $ 98,752 $ 93,174
$109,026
Less Preferred Stock Dividend
Requirements 14,627 16,716
17,405
Income Available for Common Stock $ 84,125 $ 76,458 $
91,621
The accompanying Notes to Consolidated Financial Statements are
an integral part of these statements.
CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
For the Years Ended December 31,
1995 1994 1993
Cash Flows Of Operating Activities:
Net Income $ 98,752 $ 93,174 $109,026
Deferred Purchased Power Costs 15,721 14,920 (6,050)
Deferred Energy Costs (20,435) (3,819) (15,269)
Depreciation and Amortization 78,461 73,344 67,950
Deferred Income Taxes-Net 15,694 6,116 16,213
Prepaid State Excise Taxes 9,560 (40,128) (33,706)
Net (Increase) Decrease in Other
Working Capital (31,262) (22,913) 28,486
Employee Separation Costs (19,112) 26,600 -
Other-Net 10,048 1,403 7,559
Net Cash Provided by Operating 157,427 148,697 174,209
Activities
Cash Flows Of Investing Activities:
Construction Expenditures (100,904) (119,961) (138,111)
Leased Property (10,446) (10,713) (9,946)
Decommissioning Trust Fund Deposits (6,424) (6,424) (6,424)
Plant Removal Costs (4,525) (8,000) (1,943)
Other-Net 7,316 7,223 (3,824)
Net Cash Used by Investing Activities (114,983) (137,875) (160,248)
Cash Flows Of Financing Activities:
Proceeds from Long Term Debt 104,404 53,572 464,633
Retirement and Maturity of
Long Term Debt (57,489) (42,664) (360,414)
Increase (Decrease) in Short Term Debt 21,945 8,600 (14,600)
Proceeds from Capital Lease
Obligations 10,446 10,713 9,946
Redemption of Preferred Stock (24,500) (24,500) (5,469)
Dividends (95,866) (100,198) (98,752)
Capital Contributions 13 25,270 20,991
Other-Net (869) 1,601 (1,362)
Net Cash Used by Financing Activities (41,916) (67,606) (14,973)
Net Increase (Decrease) in Cash
and Temporary Investments 528 (56,784) 28,934
Cash and Temporary Investments,
beginning of year 3,459 60,243 31,309
Cash and Temporary Investments,
end of year $ 3,987 $ 3,459 $ 60,243
Supplemental Schedule of Payments:
Interest $ 58,274 $ 61,035 $ 51,331
Federal income taxes $ 31,999 $ 32,254 $ 25,809
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
December 31,
1995 1994
Assets
Electric Utility Plant:
In Service:
Production $1,187,169 $1,151,661
Transmission 366,242 357,389
Distribution 691,830 659,619
General 183,935 180,204
Total In Service 2,429,176 2,348,873
Less Accumulated Depreciation 794,479 725,999
Net 1,634,697 1,622,874
Construction Work in Progress 119,270 110,078
Land Held for Future Use 6,941 6,941
Leased Property-Net 40,878 42,030
Electric Utility Plant-Net 1,801,786 1,781,923
Investments and Nonutility Property:
Nuclear Decommissioning Trust Fund 61,802 52,004
Other 2,077 3,139
Total Investments and Nonutility Property 63,879 55,143
Current Assets:
Cash and Temporary Investments 3,987 3,459
Accounts Receivable:
Utility Service 66,099 54,554
Miscellaneous 17,379 15,804
Allowance for Doubtful Accounts (3,300) (3,300)
Unbilled Revenues 41,515 32,070
Fuel (at average cost) 25,459 28,030
Materials and Supplies (at average cost) 25,434 27,823
Working Funds 14,420 14,475
Deferred Energy Costs 31,434 10,999
Deferred Income Taxes - 12,141
Other Prepayments 21,002 11,760
Total Current Assets 243,429 207,815
Deferred Debits:
Unrecovered Purchased Power Costs 99,817 115,538
Recoverable Future Federal Income Taxes 85,858 85,854
Unrecovered State Excise Taxes 64,274 73,834
Unamortized Debt Costs 38,924 38,083
Other Regulatory Assets 54,568 47,055
Other 9,372 16,071
Total Deferred Debits 352,813 376,435
Total Assets $2,461,907 $2,421,316
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
December 31,
1995 1994
Liabilities and Capitalization
Capitalization:
Common Shareholder's Equity:
Common Stock $ 54,963 $ 54,963
Premium on Capital Stock 231,081 231,081
Contributed Capital 262,762 262,749
Capital Stock Expense (2,131) (2,300)
Retained Earnings 252,484 249,767
Total Common Shareholder's Equity 799,159 796,260
Preferred Stock:
Not Subject to Mandatory Redemption 40,000 40,000
Subject to Mandatory Redemption 114,750 149,250
Long Term Debt 802,356 763,288
Total Capitalization (excluding current
portion) 1,756,265 1,748,798
Current Liabilities:
Preferred Stock Redemption Requirement 22,250 12,250
Capital Lease Obligations 650 928
Long Term Debt - Current Portion 12,247 -
Short Term Debt 30,545 8,600
Accounts Payable 60,831 65,632
Federal Income Taxes Payable - Affiliate 11,574 9,537
Other Taxes Accrued 3,382 3,490
Interest Accrued 19,961 19,048
Dividends Declared 23,490 24,681
Accrued Employee Separation Costs 7,488 26,600
Deferred Income Taxes 2,569 -
Other 17,156 18,206
Total Current Liabilities 212,143 188,972
Deferred Credits and Other Liabilities:
Deferred Income Taxes 354,218 350,697
Deferred Investment Tax Credits 49,112 51,646
Capital Lease Obligations 40,227 41,102
Other 49,942 40,101
Total Deferred Credits and Other
Liabilities 493,499 483,546
Commitments and Contigencies (Note 8)
Total Liabilities and Capitalization $2,461,907 $2,421,316
CONSOLIDATED STATEMENT OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
(Thousands of Dollars)
Premium On Capital
Common Capital Contributed Stock Retained
Stock Stock Capital Expense Earnings
Balance,
December 31, 1992 $54,963 $231,081 $216,488 $(2,496) $246,883
Net Income 109,026
Capital stock
expense 26 (196)
Capital contritution
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
Net income 98,752
Capital stock
expense 169 (169)
Capital contribution
from parent 13
Less dividends
declared:
Preferred (14,627)
Common (81,239)
Balance,
December 31, 1995 $54,963 $231,081 $262,762 $(2,131) $252,484
As of December 31, 1995, the Company had $25 million authorized shares
of Common Stock at $3 par value. Shares outstanding at December 31,
1995, 1994 and 1992 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). The Company is
a public utility primarily engaged in the generation, transmission,
distribution and sale of electric energy. The Company's service
territory encompasses approximately 2,700 square miles within the
southern one-third of New Jersey with the majority of customers being
residential and commercial. Deepwater Operating Company is a wholly-
owned subsidiary of the Company which operates certain generating
facilities.
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 service for the
Company are subject to the regulations of the New Jersey Board of
Public Utilities (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 ratemaking 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 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 year for energy used by customers
subsequent to the last bill rendered for the calendar year.
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% since August 1, 1993. The AFDC rate was 8.95% prior to this
date.
Depreciation - The Company provides for straight-line depreciation
based on: transmission and distribution property - estimated
remaining life; nuclear property - remaining life of the related
plant operating license in existence at the time of the last base rate
case; other depreciable property - estimated average service life.
The overall composite rate of depreciation was 3.3% for the last three
years. Accumulated depreciation is charged with the cost of
depreciable property retired together with removal costs less salvage
and other recoveries.
Nuclear Plant Decommissioning Reserve - A reserve for decommissioning
costs is presented as a component of accumulated depreciation and
amounted to $60.9 million and $51.1 million at December 31, 1995 and
1994, respectively.
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,
or the impact on future 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. Generally, energy costs are recovered through
levelized rates over the period of projection, which is usually 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 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. The Company may elect to forgo recovery of
certain amounts of otherwise recoverable energy costs. Such amounts
are expensed.
Income Taxes - Deferred Federal 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. Investment
tax credits previously used for income tax purposes have been deferred
on the Consolidated Balance Sheet and are 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 tax liabilities or
benefits generated by the Company based on the separate return method.
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 50% owned by a wholly-owned subsidiary of Atlantic Energy
Enterprises, Inc. (AEE), which is a wholly-owned subsidiary of AEI.
Capacity costs totaled $23.8 million in 1995 and $23.0 million in 1994
and 1993. The Company sells electricity to subsidiaries of AEE. The
Company also rents office space from a wholly-owned subsidiary of AEE.
The electric sales recorded and the rents paid are not significant to
the Consolidated Income Statement. The amounts receivable from and
payable to affiliates for such transactions were not significant at
December 31, 1995 and 1994.
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
fixed geographic region.
Other - Debt premium, discount and expense 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 Company's weighted daily average interest
rate on short term debt was 6.3% for 1995 and 4.4% for 1994.
The preparation of financial statements in conformity with GAAP
requires management at times to make certain judgments, estimates and
assumptions that affect amounts and matters reported at the year end
dates and for the annual periods presented. Actual results could
differ from those estimates. Any change in the judgments, estimates
and assumptions used, which in management's opinion would have a
significant effect on the financial statements, will be reported when
management becomes aware of such changes.
New Accounting Standards - The FASB issued two new statements in 1995 -
Statement No. 121 "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to be Disposed Of" and Statement No. 123
"Accounting for Stock-Based Compensation". Both statements are
effective for the Company in 1996. Statement No. 121 primarily
concerns accounting for the impairment and disposal of property, plant
and equipment. Statement No. 123 permits a fair value-based method to
account for stock-based compensation as an alternative to the
intrinsic value-based method that is currently permitted. The Company
currently employs stock-based compensation which has not had a
material impact on the financial statements. Should the Company elect
to continue to use the intrinsic value-based method to account for
stock-based compensation, the statement requires, if material, certain
disclosures as if the fair value-based method was used. The Company
has not yet fully assessed the impacts on its financial statements of
the requirements of these new accounting standards.
Certain prior year amounts have been reclassified to conform to the
current year reporting of these items.
NOTE 2. INCOME TAXES
The components of Federal income tax expense for the years ended
December 31 are as follows:
(000) 1995 1994 1993
Current $ 32,457 $ 30,013 $ 29,679
Deferred 15,694 6,116 16,214
Total Federal Income Tax Expense 48,151 36,129 45,893
Less Amounts in Other Income 2,275 (6,400) 616
Federal Income Taxes in
Operating Expenses $ 45,876 $ 42,529 $ 45,277
A reconciliation of the expected Federal income taxes compared to the
reported Federal income tax expense computed by applying the statutory
rate for the years ended December 31 follows:
1995 1994 1993
Statutory Federal Income Tax Rate 35% 35% 35%
(000)
Income Tax Computed at the
Statutory Rate $ 51,417 $ 45,256 $ 54,221
Plant Basis Differences 1,307 (27) (5,171)
Amortization of Investment Tax
Credits (2,534) (2,534) (2,534)
Tax Adjustments - (4,874) (750)
Other-Net (2,039) (1,692) 127
Total Federal Income Tax Expense $ 48,151 $ 36,129 $ 45,893
Effective Federal Income Tax Rate 33% 28% 30%
Items comprising deferred tax balances as of December 31 are as
follow:
(000) 1995 1994
Deferred Tax Liabilities:
Plant Basis Differences $316,834 $304,476
Unrecovered Purchased Power Costs 28,209 33,557
State Excise Taxes 22,527 25,842
Other 29,519 22,573
Total Deferred Tax Liabilities 397,089 386,448
Deferred Tax Assets:
Deferred Investment Tax Credits 26,511 27,879
Employee Separation Costs 2,621 6,932
Other 11,169 13,081
Total Deferred Tax Assets 40,301 47,892
Total Deferred Taxes-Net $356,788 $338,556
Deferred tax costs associated with additional deferred tax
liabilities resulting from a prior year accounting change are
recorded on the Consolidated Balance Sheet as Recoverable Future
Federal Income Taxes. This recognition is given for 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
1993 - 1995
Amount Amount
Date Requested Granted Date
Filed (millions) (millions) Effective
3/93 $14.2 $10.9 10/93
2/94 63.0 55.0 7/94
4/95 37.0 37.0 7/95
The Company's Levelized Energy Clause (LEC) is subject to annual
review by the BPU.
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. The request was reduced primarily to
return to customers an additional 25%, or $3.8 million, of a
$15.5 million litigation settlement with the operator of the
Peach Bottom Atomic Power Station.
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
primarily due to the additional costs incurred from two new
independent power producers (IPPs) scheduled to begin commercial
operation during the 1994/1995 LEC period. The requested amount
was reduced 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 energy costs that the
Company will incur during the LEC period. On November 30, 1994,
the BPU rendered its final decision approving the continuation of
a provisional LEC rate increase of $55 million that had been in
effect since July 26, 1994.
On April 17, 1995, the Company filed a petition with the BPU
requesting a $37 million increase in LEC revenues for the period
June 1, 1995 through May 31, 1996. This filing represents the
first that includes a full year of costs for capacity and energy
with all four of the IPPs with which the Company is under
contract. The requested amount had been reduced by the Company
from $67.6 million by forgoing $10 million in LEC revenues under
the SNJEI and deferring $20.6 million of LEC costs that the
Company will incur during the 1995/1996 LEC period for recovery
in a future LEC period. Effective July 7, 1995, the BPU approved
a provisional increase of $37 million effective for service
rendered on and after July 7, 1995. On November 15, 1995, the
Administrative Law Judge (ALJ) recommended that the provisional
rates be made final. On December 1, 1995, the Ratepayer
Advocate, the BPU Staff and the Company agreed to a stipulation
recommending that the ALJ's findings be accepted by the BPU. A
final decision is expected from the BPU by the end of March 1996.
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. 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. The effect of this change
was not material to the results of operations.
On September 14, 1994, the BPU issued an order supporting the
investigation of the double recovery of capacity costs from
nonutility generation projects. This issue relates to the
Ratepayer Advocate's allegation that the Company, along with
other New Jersey electric utility companies, is recovering
cogeneration capacity costs concurrently in base rates and LEC
rates. The order confirmed the establishment of a generic
proceeding to review the nonutility 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 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 double
recovery found to exist for each utility for the relevant
periods; 3) a determination of an appropriate remedy or
adjustment if double recovery is found to occur and the periods
of time over which 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. In September
1995, the Ratepayer Advocate filed testimony that claims the
Company's overrecovery of capacity costs for the four-year period
June 1991 through May 1995 is $46 million. The Ratepayer
Advocate also filed testimony supporting similar claims for other
New Jersey electric utilities. In December 1995, the Company and
the other electric utilities filed testimony rebutting the
Ratepayer Advocate's claims. Litigation is expected to continue
in 1996; the BPU's final decision is not expected until the
latter part of 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 include:
(000) 1995 1994 1993
Service cost-benefits earned
during the period $ 6,363 $ 6,871 $ 7,196
Interest cost on projected benefit
obligation 14,794 15,390 16,016
Actual return on plan assets (44,067) (860) (23,200)
Other-net 28,379 (16,885) 5,496
Net periodic pension costs $ 5,469 $ 4,516 $ 5,508
Of these costs, $3.0 million were charged to operating expense in both
1995 and 1994 and $5.2 million in 1993. The remaining costs, which
are associated with construction labor, were charged to the cost of
new utility plant. Actual return on plan assets and other-net for
1995 primarily reflect the favorable market conditions from the
investment of plan assets and expected returns versus the unfavorable
market conditions in 1994.
A reconciliation of the funded status of the plan as of December 31 is
as follows:
(000) 1995 1994
Fair value of plan assets $212,000 $190,200
Projected benefit obligation 213,470 206,742
Plan assets less than
projected benefit obligation (1,470) (16,542)
Unrecognized net transition asset (1,550) (1,722)
Unrecognized prior service cost 282 306
Unrecognized net loss 10,006 24,106
Prepaid pension cost $ 7,268 $ 6,148
Accumulated benefit obligation:
Vested benefits $169,044 $166,602
Nonvested benefits 3,413 485
Total $172,457 $167,087
At December 31, 1995, approximately 65% of plan assets were invested
in equity securities, 21% in fixed income securities and 14% in other
investments. The assumed rates used in determining the actuarial
present value of the projected benefit obligation at December 31 were
as follows:
1995 1994
Weighted average discount 7.0% 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
1995 and 1994.
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.
Net periodic other postretirement benefit costs include:
(000) 1995 1994 1993
Service cost-benefits attributed to
service during the period $ 2,891 $ 3,817 $ 3,045
Interest cost on accumulated
postretirement benefits obligation 8,107 8,450 7,133
Actual return on plan assets (1,437) 100 (255)
Amortization of unrecognized
transition obligation 3,893 3,893 3,893
Other-net 404 (700) (711)
Net periodic other postretirement
cost $13,858 $15,560 $13,105
These costs were allocated as follows:
(millions) 1995 1994 1993
Operating expense $5.0 $5.6 $3.3
New utility plant-associated with
construction labor .6 .2 1.7
Regulatory asset 8.3 9.8 8.1
The regulatory asset represents the amount of cost recognized 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.
A reconciliation of the funded status of the plan as of December 31 is
as follows:
(000) 1995 1994
Accumulated benefits obligation:
Retirees $ 64,516 $ 43,265
Fully eligible active plan participants 6,954 18,010
Other active plan participants 33,649 60,588
Total accumulated benefits obligation 105,119 121,863
Less fair value of plan assets 16,500 14,700
Accumulated benefits obligation in
excess of plan assets 88,619 107,163
Unrecognized net loss (15,335) (19,223)
Unamortized unrecognized transition
obligation (47,057) (70,075)
Accrued other postretirement benefits
cost obligation $ 26,227 $ 17,865
The accumulated benefit obligation for retirees and other active plan
participants for 1995 reflect the impact of the Company's workforce
reduction program and a lower discount rate effective in 1995. The
unamortized unrecognized transition obligation for 1995 was reduced by
certain changes to the plan.
At December 31, 1995, approximately 80% of plan assets were invested
in fixed income securities and 20% in other investments.
The assumed health care costs trend rate for 1996 is 9% and is assumed
to evenly decline to an ultimate constant rate of 5% in the year 2001
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 1995 net periodic benefits cost would increase
by $1.8 million, and the accumulated postretirement benefits
obligation at December 31, 1995 would increase by $12.1 million. The
weighted average discount rate assumed in determining the accumulated
benefits obligation was 7% for 1995 and 7.5% for 1994. The assumed
long term return rate on plan assets was 7% for both 1995 and 1994.
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):
1995 $12,719 $35,371 $128,398 $214,306 $239,499
1994 11,293 26,607 125,003 206,804 238,980
Accumulated Depreciation (000):
1995 $ 3,277 $ 6,445 $ 58,870 $ 84,611 $ 60,998
1994 3,180 6,237 55,190 79,898 53,746
Construction Work in Progress (000):
1995 $ 442 $ 873 $ 11,056 $ 11,198 $ 655
1994 1,216 2,649 11,002 8,727 387
Operations and Maintenance Expenses (including fuel)(000):
1995 $ 5,143 $ 7,252 $ 29,647 $ 28,306 $ 10,360
1994 5,085 7,211 29,530 27,731 10,471
1993 5,323 6,855 31,479 27,021 9,764
Working Funds (000):
1995 $ 44 $ 69 $ 4,505 $ 5,782 $ 1,919
1994 44 69 5,051 5,199 2,013
Generation (MWHr):
1995 285,899 451,211 1,232,921 334,572 352,316
1994 257,561 419,313 1,214,776 836,725 355,390
1993 293,876 416,263 1,043,485 840,043 440,118
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 decrease in Salem's generation is due to both units being taken
out of service in May and June 1995, respectively, by its operator
Public Service Electric and Gas Company, pending review and resolution
of certain equipment and management issues. (See Note 8 for further
information).
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
Par 1995 1994 Redemption
Series 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 50,000 $ 5,000 55,000 $ 5,500 104.45
$8.53 None 120,000 12,000 360,000 36,000 101.00
$8.20 None 500,000 50,000 500,000 50,000 -
$7.80 None 700,000 70,000 700,000 70,000 -
Total 137,000 161,500
Less portion due within
one year 22,250 12,250
Total $114,750 $149,250
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 each of the years 1995
and 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 each of the years 1995 and 1994. The Company redeemed the
remainder of this series at a price of $101.00 in February 1996.
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. The Company 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.
At December 31, 1995, the minimum annual sinking fund requirements of
the Cumulative Preferred Stock Subject to Mandatory Redemption for the
next five years are $22.25 million in 1996 and $10.25 million in each
of the years 1997 through 2000.
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, 1995
and 1994 was approximately $172 million and $185 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 1995 1994 (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
Medium Term Notes Series C (6.86%) 2001 40,000 -
7-1/2% First Mortgage Bonds 4/1/2002 20,000 20,000
Medium Term Notes Series C (7.02%) 2002 30,000 -
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
Medium Term Notes Series C (7.15%) 2004 9,000 -
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 C (7.15%) 2007 1,000 -
Medium Term Notes Series B (6.76%) 2008 50,000 50,000
Medium Term Notes Series C (7.25%) 2010 1,000 -
10-1/2% Pollution Control Series B 7/15/2012 - 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
Medium Term Notes Series C (7.63%) 2014 7,000 -
Medium Term Notes Series C (7.68%) 2015 15,000 -
Medium Term Notes Series C (7.68%) 2016 2,000 -
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
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 23,150
7.20% Pollution Control Series A 11/1/2029 25,000 25,000
7% Pollution Control Series B 11/1/2029 6,500 6,500
Total 812,571 762,278
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 (2,854) (3,876)
Total Long Term Debt of ACE 814,603 763,288
Less Portion Due within One Year 12,247 -
$802,356 $763,288
Medium Term Notes have varying maturity dates and are shown with the
weighted average interest rate of the related issues within the year
of maturity.
In 1995, the Company redeemed its 10-1/2% Pollution Control Bonds
Series B due 7/15/2012 and the remaining outstanding principal amount
of its 9-1/4% First Mortgage Bonds due 10/1/2019. The aggregate cost
of these redemptions was $2.6 million, net of related Federal income
taxes.
Sinking fund deposits are required for retirement of First Mortgage
Bonds, 6-3/8% Pollution Control Series due 2006 annually beginning
December 1, 1997 in amounts sufficient to redeem $75 thousand
principal amount. Sinking fund deposits are also required for
retirement of 7-1/4% Debentures annually on May 1 through 1997 in
amounts sufficient to redeem $100 thousand principal amount. The
Company may, at its option, redeem an additional $100 thousand
annually. Through December 31, 1995, the Company acquired and
cancelled $81 thousand principal amount of the 7-1/4% Debentures,
which will be used to satisfy its requirements for 1996. 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, $30.075 million in 1999 and $46.075 million in 2000.
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, 1995
and 1994 was $851 million and $693 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
Cash construction expenditures for 1996 are estimated to be
approximately $92 million.
Insurance Programs
Nuclear
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,
1995, the maximum amount of retrospective premiums the Company could
be assessed for losses during the current policy year was $6.4 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 reactor per incident, payable at $10 million per
year. Based on its ownership share of nuclear facilities, the Company
could be assessed up to an aggregate of $27.6 million per incident.
This amount would be payable at an aggregate of $3.48 million per
year, per incident.
Other
The Company's comprehensive general liability insurance provides
pollution liability coverage, subject to certain terms and limitations
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.
Nuclear Plant Decommissioning
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, the dates that decommissioning
activities are expected to begin and return to be earned by the assets
of the fund. The present value of the Company's nuclear
decommissioning obligation, based on costs adopted by the BPU in 1991
and restated in 1995 dollars, is $157 million. Decommissioning
activities as approved by the BPU were expected to begin in 2006 and
continue through 2032. 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. The total estimated value of the trust at
December 31, 1995, inclusive of the present value of future funding,
based on current annual funding amounts and expected decommissioning
dates approved by the BPU, is approximately $131 million, without
earnings on or appreciation of the fund assets. As of December 31,
1995, the market value of the trust approximated the book value. In
accordance with BPU requirements, updated site specific studies are
underway. Amounts to be recognized and recovered in rates based on
the updated studies are not presently determinable.
Purchased Capacity and Energy Arrangements
The Company arranges with various providers of bulk energy to obtain
sufficient supplies of energy to satisfy current and future energy
requirements of the company. Arrangements may be for generating
capacity and associated energy or for energy only. Terms of the
arrangements vary in length to enable the Company to optimally manage
its supply portfolio in response to changing near and long term market
conditions. At December 31, 1995, the Company has contracted for 707
megawatts (MW's) of purchased capacity with terms remaining of 3 to 29
years. Additionally, the Company has contracted for capacity of 125
MW's commencing in 1998 for 2 years and for 175 MW's commencing in
1999 for 10 years.
Information regarding these arrangements relative to the Company was
as follows:
1995 1994 1993
As a % of Capacity (year end) 30% 29% 23%
As a % of Generation 52% 48% 46%
Capacity charges (millions) $190.6 $130.9 $110.8
Energy charges (millions) $135.4 $128.6 $98.3
Amounts for purchased capacity are shown on the Consolidated Statement
of Income as Purchased Capacity. Of these amounts, charges of certain
nonutility providers are recoverable through the LEC, which amounted
to $162.7 million, $77.0 million and $30.2 million in 1995, 1994 and
1993, respectively. Future purchases of energy and payments for
purchased capacity and energy under contracts with remaining terms in
excess of one year from December 31, 1995 generally are contingent
upon provider performance and availability, and as such are not
presently determinable.
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, a limit on SO2
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 in compliance with Phase I
requirements as the result of recent installation of scrubbers at each
station. All of the Company's other fossil-fuel steam generating
units are affected by Phase II (2000) of the CAAA. A compliance plan
for these units initially estimates capital expenditures of
approximately $10 million in 1996 through 2000. The jointly-owned
Keystone Station is impacted by the SO2 and NOx provisions of Title IV
of the CAAA during Phase II. The Keystone owners plan to primarily
rely on emission allowances to comply with the CAAA through the year
2000.
Other
The Company is a 7.41% owner of the Salem Nuclear Generating Station
(Salem) operated by Public Service Electric & Gas Company (PS). Salem
Units 1 and 2 were taken out of service on May 16, 1995 and June 7,
1995, respectively. Unit 2 is expected to return to service in the
third quarter of 1996. A thorough assessment of the equipment and
management issues that have affected the operation of the unit and
station are being resolved and necessary corrections are being made to
assure safe and reliable operation over the long term. Unit 1 is
undergoing extended testing of its steam generation equipment and its
return has been delayed to an indefinite period. The Company's
expenses associated with restart activities totalled $2.6 million for
1995 and are estimated to be $5.6 million for 1996. The additional
incremental cost of replacement power during the outages is
approximately $1.4 million per month.
The Company is a 5% owner in the Hope Creek Nuclear Generating Station
(Hope Creek) also operated by PS. Hope Creek went into a scheduled
refueling and maintenance outage on November 11, 1995 which has been
extended to correct maintenance and performance problems. The unit is
expected to return to service in March 1996. The incremental
replacement power costs associated with the Hope Creek outage is
approximately $400 thousand per month.
The Company is subject to a performance standard for its five
jointly-owned nuclear units. This standard is used by the BPU in
determining recovery of replacement energy costs. The standard
establishes a target aggregate capacity factor within a zone of
reasonable performance to be achieved by the units. Underperformance
results in penalties. Penalties incurred are not permitted to be
recovered from customers and are charged against income. For 1995,
the Company recorded $845 thousand after tax for a performance penalty
because the aggregate capacity factor of the Company's nuclear units
was below the reasonable performance zone as a result of the Salem
outage noted above.
In December 1994, the Company recorded the costs of an employee
separation program in the amount of $17.3 million, net of tax of $9.3
million, or $.32 in earnings per share. This program was initiated so
that the Company could be better positioned for the more competitive
environment within the electric industry. The balance of the accrued
separation costs on the Consolidated Balance Sheet at December 31,
1995 is $7.5 million compared to $26.6 million at December 31, 1994.
The Company expects payments in settlement of this obligation to be
substantially completed by the end of 1996.
The Energy Policy Act of 1992 permits the Federal government to assess
investor-owned electric utilities that have ownership interests in
nuclear generating facilities. The assessment funds the
decontamination and decommissioning of three Federally operated
nuclear enrichment facilities. Based on its ownership in five nuclear
generating units, the Company has a liability of $6.0 million and $6.6
million at December 31, 1995 and 1994, respectively, for its
obligation to be paid over the next 12 years. The Company has an
associated regulatory asset of $6.4 million and $7.2 million at
December 31, 1995 and 1994, 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.
In March 1995, FERC issued a Notice of Proposed Rulemaking regarding
several key electric utility industry issues such as transmission
access, transmission pricing and recovery guidelines for stranded
costs stemming from wholesale transactions. The focus of the proposal
is to establish policies that will provide a structure to facilitate
more competitive wholesale electric power markets. What is being
proposed is a departure from the existing regulatory framework. FERC
is considering comments on the proposal submitted by the Company and
other members of the industry, as well as other interested parties.
Associated with the FERC proposal are structural initiatives by the
BPU concerning New Jersey electric regulation and by the regional
power pool in which the Company participates regarding bulk power
transmission and generation dispatch within the region. At this time,
the Company cannot predict the outcomes of these sweeping initiatives
and the impacts on the Company that may ensue. The Company is taking
an active role in the development of these issues.
Note 9. 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, are recorded as regulatory assets.
Regulatory assets are amortized to expense over the period of
recovery. Total regulatory assets at December 31 are as follows:
Remaining
Recovery
(000) 1995 1994 Period*
Recoverable Future Federal
Income Taxes(see Note 2) $ 85,858 $ 85,854 (A)
Unrecovered Purchased Power Costs:
Capacity Costs 80,598 95,878 5 years
Contract Renegotiation Costs 19,219 19,660 19 years
Unrecovered State Excise Taxes 64,274 73,834 7 years
Unamortized Debt Costs-Refundings 33,110 32,227 1-29 years
Deferred Energy Costs(see Note 1) 31,434 10,999 (B)
Other Regulatory Assets:
Postretirement Benefits Other
Than Pensions (see Note 4) 26,227 17,865 (A)
Asbestos Removal Costs 9,356 9,625 34 years
Decommissioning/Decontaminating
Federally-owned Nuclear Units
(See Note 10) 6,404 7,231 13 years
Other 12,581 14,379
$369,061 $367,552
*From December 31, 1995
(A) Pending future recovery
(B) Recovered over annual LEC period
Unrecovered Purchased Power Capacity Costs represent deferrals of
prior capacity costs then in excess of levelized revenues associated
with a certain long term capacity arrangement. Levelized revenues
have since been greater than costs, permitting the deferred costs to
be amortized to expense. Contract Renegotiation Costs were incurred
through renegotiation of a long term capacity and energy contract with
a certain independent power producer. Unrecovered State Excise Taxes
represent additional amounts paid as a result of prior legislative
changes in the computation of state excise taxes. Unamortized Debt
Costs associated with debt reacquired by refundings are amortized over
the life of the related new debt. Asbestos Removal Costs were
incurred to remove asbestos insulation from a wholly-owned generating
station. Within Other are certain amounts being recovered over a
period of two to six years.
No regulatory liabilities existed at December 31, 1995 and 1994.
NOTE 10. LEASES
The Company leases from others 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) 1995 1994
Production plant $ 9,097 $13,521
Less accumulated amortization 6,810 9,707
Net 2,287 3,814
Nuclear fuel 38,591 38,216
Leased property-net $40,878 $42,030
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 1995, 1994 and 1993 include
leased nuclear fuel costs of $11.2 million, $14.1 million and $13.9
million, respectively, and rentals and lease payments for all other
capital and operating leases of $4.1 million, $5.9 million and $5.5
million, respectively. Future minimum rental payments for all
noncancellable lease agreements are not significant to the Company's
operations.
NOTE 11. QUARTERLY FINANCIAL RESULTS (UNAUDITED)
Quarterly financial data, reflecting all adjustments necessary in the
opinion of management for a fair presentation of such amounts, are as
follows:
Operating Operating Net Earnings for
Quarter Revenues Income Income Common Stock
1995 (000) (000) (000)
1st $218,666 $ 27,565 $15,779 $11,992
2nd 206,246 27,755 15,111 11,324
3rd 303,031 67,026 52,666 48,879
4th 225,836 26,581 15,195 11,930
Annual $953,779 $148,927 $98,752 $84,125
1994
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 $153,995 $93,174 $76,458
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.
Third quarter results generally exceed those of other quarters due to
increased sales and higher residential rates for the Company.
Net income in 1994 includes special charges aggregating $18.7 million,
after tax of $10.0, million recorded in Other Income during the fourth
quarter of 1994. These special charges consisted of costs of a
workforce reduction and write-off of certain deferred costs.
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Financial Summary
Consolidated operating revenues for 1995, 1994 and 1993 were
$953.8 million, $913.2 million and $865.8 million, respectively.
The increase in 1995 revenue over 1994 largely reflects a
provisional increase in annual Levelized Energy Clause (LEC)
revenues of $37.0 million granted in July 1995 and an increase in
unbilled revenues. The increase in 1994 revenue from 1993 was
primarily due to an increase of $55.0 million in LEC revenues
effective July 1994, accompanied by an increase in sales of
energy.
Liquidity and Capital Resources
Atlantic City Electric Company (the Company) is a wholly-owned
subsidiary of Atlantic Energy, Inc. (AEI). The Company is a
public utility primarily engaged in the generation, transmission,
distribution and sale of electric energy. The Company's service
territory encompasses approximately 2,700 square miles within the
southern one-third of New Jersey with the majority of customers
being residential and commercial. The Company has a wholly-owned
subsidiary that operates certain generating facilities.
Cash construction expenditures for 1993-1995 amounted to $359.0
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
1996-1998 is $255 million. These estimated expenditures reflect
necessary improvements to generation, transmission and distribu-
tion facilities.
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 capital.
Redemptions of Preferred Stock (at par or stated value) for the
period were as follows:
1995 1994 1993
Preferred Stock
(Series)
9.96% (Shares) - - 48,000
$8.53 (Shares) 240,000 240,000 -
$8.25 (Shares) 5,000 5,000 5,000
Aggregate Amount (000) $24,500 $24,500 $5,300
First Mortgage Bonds redeemed, acquired and retired or matured
in the period 1993-1995 were as follows:
Date Series Principal Price(%)
Amount
(000)
October 1995 9-1/4% due 2019 $ 53,857 105.15
October 1995 10-1/2% due 2014 850 101.00
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
* Average price
Scheduled debt maturities and sinking fund requirements aggregate
$113.8 million for 1996-1998.
On or before April 1 of each year, the Company and other New
Jersey utilities are required to pay excise taxes to the State of
New Jersey. In March 1995, the Company paid $98.7 million funded
through the issuance of short term debt. In 1994 and 1993, the
Company paid an additional $50 million and $45 million,
respectively, for the accelerated payment of one year's tax due
as required by amended state law. These accelerated payments are
being recovered through rates.
During 1995, the Company made $19.1 million in payments related
to its workforce reduction program. The Company expects payments
and settlement of the remaining obligation for this program of
$7.5 million to be substantially completed by the end of 1996.
On an interim basis, the Company finances 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, 1995, the Company has arranged for lines of credit
of $150 million of which $119.5 million was available. Permanent
financing by the Company is undertaken by the issuance of long
term debt and Preferred Stock, and at times from capital
contributions by AEI. The Company's nuclear fuel requirements
associated with its jointly-owned units have been financed
through arrangements with a third party.
A summary of the issue and sale of the Company's long term debt
for 1993-1995 is as follows:
(millions) 1995 1994 1993
First Mortgage Bonds - - $225
Medium Term Notes $105 - 240
Pollution Control Bonds - $55 4
The proceeds from these financings were used to refund higher
cost debt and for construction purposes. During 1996-1998, the
Company may issue up to $150 million in new long term debt to be
used for construction and repayment of short term debt. The
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, 1995,
the Company estimates additional funding capacities of $288
million of First Mortgage Bonds, or $490 million of Preferred
Stock, or $413 million of unsecured debt. These amounts are not
necessarily additive.
Revenues
Operating Revenues - Electric increased 4.4% and 5.5% in 1995 and
1994, respectively. Components of the overall changes are shown
as follows:
1995 1994
(millions)
Levelized Energy Clause $ 49.2 $30.3
Kilowatt-hour Sales (10.0) 9.6
Unbilled Revenues 16.6 (7.3)
Sales for Resale (11.9) 17.8
Other (3.3) (3.0)
Total $ 40.6 $47.4
LEC revenues increased in 1995 due to a provisional rate increase
of $37.0 million in July 1995 and a $55 million increase in July
1994. 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 5.9% and 3.1% in revenues per
kilowatt-hour in 1995 and 1994, respectively. The changes in
Unbilled Revenues are a result of the amount of kilowatt-hours
consumed by, but not yet billed to, 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 decline in the 1995 Sales for Resale reflects a
decrease in the demand of the power pool, the decline in market
prices and a reduction in excess energy sources when compared to
the previous year. The decrease in supplemental excess energy
sources reflect the expiration of a 200 megawatt purchase
capacity arrangement in May 1994, and expiration of other short
term purchase contracts. The increase in Sales for Resale for
1994 was the result of being able to meet the demands of the
regional power pool due to the extreme weather conditions during
the first six months of 1994.
Billed Sales to Ultimate 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:
1995 1994
Avg Avg # Avg Avg #
Customer Class Sales Use of Cust Sales Use of Cust
Residential (2.0)% (3.1)% 1.2% 1.5 % .4 % 1.1%
Commercial 1.4 (.1) 1.5 2.6 .5 2.1
Industrial (7.4) (9.0) 1.7 (2.9) (3.8) .9
Total (1.4) (2.6) 1.2 1.3 - 1.2
The 1995 decrease in total sales was attributed to weather
conditions that led to below normal electricity consumption for a
majority of the year and a decreased number of billing days in
1995 compared to 1994. The 1994 increase in total sales was due
to an increase in the number of billing days in 1994 compared to
1993 and, to a lesser extent, weather. The Commercial sector
experienced continued growth during 1995 due to sales increases
across all the major commercial subsectors. Commercial growth in
both years benefitted from night lighting programs. The sales
declines in the Industrial sector are primarily related to the
impact of two former customers taking energy service from
independent power producers commencing in June 1994 and January
1995.
Costs and Expenses
Total Operating Expenses increased 5.9% and 7.5% in 1995 and
1994, respectively. Included in these expenses are the costs of
energy, purchased capacity, operations, maintenance, depreciation
and taxes.
Energy expense reflects costs 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 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 power pool. The cost of energy is recovered from
customers primarily through the operation of the LEC. Excluding
the effects of the SNJEI (discussed below), earnings generally
are 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 $31.4 million and by $11 million at December
31, 1995 and 1994, respectively. The increase in 1995 is due to
the combination of the election to defer recovery of $20.6
million of recoverable fuel costs, lower than projected kilowatt-
hour sales and greater than projected purchased fuel as
replacement for Salem Station generation.
As a result of implementing the Southern New Jersey Economic
Initiative (SNJEI), the Company is forgoing the recovery of
energy costs in LEC rates in the amount of $10.0 million and
$28.0 million for the 1995 and 1994 LEC periods, respectively.
After tax net income has been reduced by $12.2 million and $10.1
million due to the effects of the initiative for 1995 and 1994,
respectively.
Energy expense decreased 9.0% in 1995 primarily due to the
increase in underrecovered fuel costs, offset in part by the
effects of the SNJEI referred to above. In 1994, Energy expense
increased 32.7% due to the SNJEI and the increase in the
levelized energy clause that reduced underrecovered fuel costs.
Production-related energy costs for 1995 decreased 1.9% due to
reduced generation. The average unit cost of energy decreased to
2.02 cents per kilowatt-hour in 1995 compared to 2.04 cents per
kilowatt-hour in 1994. 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 1993
cost per kilowatt-hour was 1.82 cents.
Purchased Capacity expense reflects entitlement to generating
capacity owned by others. Purchased Capacity expense increased
45.5% and 18.2% in 1995 and 1994, respectively. The increases
reflect additional contract capacity supplied by nonutility power
producers in each year.
Operations expense decreased 3.0% and 3.6% in 1995 and 1994,
respectively. These decreases reflect the benefits of the
Company's restructuring programs, initiated in 1993 and 1994.
The 1995 decrease was offset in part by the additional costs
associated with Salem Station restart activities. Net after tax
savings approximated $8 million in 1995 related to the workforce
reduction recorded in 1994. Employee separations throughout the
Company of approximately 300 employees largely occurred on March
1, 1995. The original estimate of net after tax savings of $10
million was based on a full-year assessment. Maintenance expense
decreased 8.6% and 17.1% in 1995 and 1994, respectively, due to
cost saving measures.
Depreciation and Amortization expense increased 7.0% and 7.9% in
1995 and 1994, respectively, as a result of continued increases
in the Company's depreciable electric plant in service.
State Excise Taxes expense increased 5.9% in 1995 due to an
increase in the tax base used to calculate the tax in comparison
to the 1994 tax base. In 1994, State Excise Taxes expense
decreased 6.9% relative to the higher tax assessment in 1993.
Federal Income Taxes increased 7.9% in 1995 and decreased 6.1% in
1994 as a result of the level of taxable income during those
periods.
Employee Separation costs is the provision by the Company in 1994
for the reduction of its workforce. 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. The Litigation Settlement for 1993 represents an
additional allocation to customers of the proceeds from the 1992
settlement associated with the Peach Bottom Station shut down in
prior years.
Interest on Long Term Debt increased 5.2% in 1995 due to
increased amounts of debt outstanding during the year. In 1994,
interest on long term debt decreased 3.4% due to refunding of
higher cost debt. At December 31, 1995, 1994 and 1993, the
Company's embedded cost of long term debt was 7.5%, 7.6% and
7.8%, respectively.
Preferred Stock Dividend Requirements decreased 12.5% and 4% in
1995 and 1994, respectively, as a result of continuing mandatory
and optional redemptions. Embedded cost of Preferred Stock as of
December 31, 1995, 1994 and 1993 was 7.4%, 7.6% and 7.7%,
respectively.
Outlook
Factors such as regional economic trends, abnormal weather
conditions and inflation will continue to be important
determinants of the Company's financial performance. However,
continued competition from independent power producers and the
anticipated deregulation of the electric utility industry are
becoming the most critical strategic factors for the Company.
Fundamental changes in the industry have led to the emergence of
significant competitive issues for the Company, including
heightened competition in the wholesale bulk power market, the
growth of the independent power industry and the pressure to
offer more competitive rates to customers.
The Company is closely monitoring deregulation of the industry on
both a state and Federal level. The Federal Energy Regulatory
Commissions' (FERC) on-going rulemaking proceeding is proposing
changes to rules governing transmission access and pricing. FERC
is also establishing guidelines for recovery of stranded costs
and investments stemming from wholesale transactions. In
response to FERC's initiative, the power pool in which the
Company participates has proposed significant changes to its
structure and operation.
State jurisdictions across the country, including New Jersey, are
closely examining the issues surrounding deregulation or are
creating new regulations designed to foster a more competitive
industry. The Company is playing an active role in The New
Jersey Board of Public Utilities' (BPU) on-going Energy Master
Plan proceeding. Among other things, the proceeding is
investigating the extent to which utilities, in a competitive
environment, may be threatened with the inability to recover
investments or long term commitments prudently made, and placed
into rates under traditional ratemaking regulations. To date,
the BPU has made no formal policy pronouncement regarding
deregulation or the recovery of stranded commitments.
In anticipation of heightened competition in energy markets, the
Company is pursuing a number of initiatives designed to
strengthen its position in the marketplace. The cost of the
Company's power supply, including the cost of power purchased
from independent power producers, along with its retail prices
are expected to be critical success factors in a competitive
marketplace. The Company is focusing on cost and rate control
measures as well as the development of new energy-related
products and services. To allow for more flexibility and closer
cost control, the Company transferred its production operations
to its subsidiary, Deepwater Operating Company, on January 1,
1996. Alternate pricing mechanisms and long term discount power
contracts are being explored as a means of retaining key
customers that are at risk of leaving the Company's system.
While any such discounts are intended to have a long term
beneficial impact, they could have a detrimental effect on the
Company's operating revenues and net income in the short term.
The Company's net income and its levelized energy adjustment
rates may be affected by the operational performance of nuclear
generating facilities and a BPU-mandated nuclear unit performance
standard. Net income may also be affected by significant changes
in the decommissioning costs associated with the nuclear units.
At this time, it is not known what impact there may be on future
operations and financial condition associated with the uncertain
status of Salem Station Unit 1.
The electric utility industry continues to be capital intensive.
The Company has lowered its planned construction budget to $398
million for 1996-2000, with an expected reduction in its external
cash requirements. The Company's ability to generate cash flows
or access the capital markets to fund capital requirements will
be affected by competitive pressures on revenues and net income,
as well as regulatory initiatives and rate developments.
The FASB issued two new statements in 1995 - Statement No. 121
"Accounting for the Impairment of Long-Lived Assets and for Long-
Lived Assets to be Disposed Of" and Statement No. 123 "Accounting
for Stock-Based Compensation". Both statements are effective for
the Company in 1996. Statement No. 121 primarily concerns
accounting for the impairment and disposal of property, plant and
equipment. Statement No. 123 permits a fair value-based method
to account for stock-based compensation as an alternative to the
intrinsic value-based method currently permitted. The Company
currently employs stock-based compensation which has not had a
material impact on the financial statements. The Company has not
yet fully assessed the impacts on its financial statements of the
requirements of these new accounting standards.
Inflation
Inflation affects the level of operating expenses and also the
cost of new utility 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
utility plant. However, the ability to recover increased costs
through rates, whether resulting from inflation or otherwise,
depends upon both market circumstances and the frequency, timing
and results of rate case decisions.