115
EXHIBIT 13
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Earnings and Dividends
Earnings per common share in 1993 were $2.45 compared to $1.90 in 1992. The
increase in earnings was primarily due to the settlement of the litigation in
connection with the 1987 shutdown of the Peach Bottom Atomic Power Station
(Peach Bottom), which reduced 1992 earnings by $0.27 per share; more favorable
weather in 1993, which increased earnings by $0.26 per share; and the
Company's on-going debt and preferred stock refinancing and redemption
program, which increased earnings by $0.18 per share. These improvements were
partially offset by non-recurring federal income tax settlements, which
increased 1992 earnings by $0.10 per share, and the higher 1993 federal income
tax rate, which decreased earnings by $0.04 per share.
As a result of its improved financial condition, the Company increased its
annual common stock dividend by 9% to $1.52 per share, effective with the
dividend paid in December 1993.
Operating Revenues
Electric Revenue Increase/(Decrease)
(Millions of Dollars) '93 vs '92 '92 vs '91
Sales $ 100 $ (103)
Tax Adjustment Revenues (19) 48
Fuel Adjustment Revenue (106) (22)
Energy and Capacity Sales 33 12
----------- -----------
$ 8 $ (65)
=========== ==========
1993 vs 1992
Electric revenues increased $8 million in 1993 compared to 1992 primarily as a
result of favorable weather and higher sales to other utilities, partially
offset by the pass-through of lower fuel costs to customers and lower revenues
from large commercial and industrial customers.
Effective April 1, 1993, the Energy Cost Adjustment (ECA) was changed from a
credit value of 3.764 mills per kilowatthour (kWh) to a credit value of 7.600
mills per kWh, which represents a decrease in annual revenue of $123 million.
Gas revenues increased $17 million in 1993 compared to 1992 primarily as a
result of higher interruptible sales resulting from favorable market
conditions and an increase in gas being used at the Company's electric gen-
erating stations.
1992 vs 1991
Electric revenues decreased $65 million in 1992 compared to 1991 primarily as
a result of lower sales to residential customers and large commercial and
industrial customers and the pass-through of lower fuel costs to customers.
This was partially offset by increased sales to house-heating customers and
small commercial and industrial customers. The unusually cool summer of 1992
was the major reason for decreased residential sales.
Gas revenues increased $9 million in 1992 compared to 1991 primarily as a
result of higher sales to house-heating customers due to the cooler weather
and an increase in house-heating customers.
116
Fuel and Energy Interchange Expense
1993 vs 1992
Fuel and energy interchange costs decreased $50 million in 1993 compared to
1992 primarily due to the Company's increased nuclear generation, which
reduced higher-cost interchange purchases, and lower cost of fuel. Nuclear
generation utilizes the Company's lowest cost fuel. These decreases were
partially offset by increased output.
1992 vs 1991
Fuel and energy interchange costs decreased $70 million in 1992 compared to
1991 primarily due to lower fuel costs and to slightly lower output.
Other Operating and Maintenance Expenses
1993 vs 1992
Other operating and maintenance expenses decreased $44 million in 1993
compared to 1992 primarily due to lower charges for uncollectible accounts,
lower administrative and general expenses primarily as a result of a reduction
in the number of employees and the 1992 charge for the Nuclear Group Voluntary
Early Retirement Program and Voluntary Separation Package. These decreases
were partially offset by increases in other operating and maintenance charges
related to the Company's generating units.
1992 vs 1991
Other operating and maintenance expenses increased $85 million in 1992
compared to 1991 primarily due to higher charges for uncollectible accounts,
non-recurring maintenance expenditures incurred at the Company's nuclear
generating facilities, the charge for the Nuclear Group Voluntary Early
Retirement Program and Voluntary Separation Package, higher accruals for
environmental liabilities and increases in other administrative and general
expenses.
Depreciation Expense
Depreciation expense increased in both 1993 and 1992 compared to the prior
year primarily due to additions to plant in service.
Allowance for Funds Used During Construction
1993 vs 1992
Allowance for Funds Used During Construction (AFUDC) increased in 1993
compared to 1992 primarily due to an increase in Construction Work in
Progress, partially offset by a decrease in the 1993 AFUDC rate.
1992 vs 1991
AFUDC decreased in 1992 compared to 1991 primarily due to a decrease in the
1992 AFUDC rate.
Income Taxes
As discussed further in note 12 of Notes to Consolidated Financial Statements,
the Financial Accounting Standards Board (FASB) issued Statement of Financial
Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes," which was
adopted in the first quarter of 1993. Adoption of SFAS No. 109 did not have a
material effect upon the Company's results of operations as the Company
expects to receive recovery for taxes when paid.
117
1993 vs 1992
Income taxes charged to operations and to other income increased in 1993
compared to 1992 due to the cost associated with the 1992 settlement of the
Peach Bottom co-owners' litigation, higher pre-tax income, lower interest
expense, the reduction in 1992 income taxes as a result of the settlement of
the Company's 1984-1986 federal income tax returns and the change in the
federal income tax rate from 34% to 35% in 1993. These increases were
partially offset by a first-quarter 1993 adjustment of excess deferred federal
income taxes. This adjustment resulted from a change in estimate to ratably
decrease deferred federal income taxes in accord-ance with the tax-rate
decrease mandated by the Tax Reform Act of 1986.
1992 vs 1991
Income taxes charged to operations and to other income decreased in 1992
compared to 1991 primarily due to lower pre-tax income and the cost associated
with the settlement of the Peach Bottom co-owners' litigation.
Other Taxes
1993 vs 1992
Other taxes increased in 1993 compared to 1992 primarily due to a settlement
of the 1990 Pennsylvania Capital Stock Tax and an adjustment of the 1991
Pennsylvania Capital Stock Tax in 1992, and an increase in the real estate tax
base.
1992 vs 1991
Other taxes increased in 1992 compared to 1991 primarily due to the refunds in
1991 of prior years' real estate tax over-collections.
Interest Charges
1993 vs 1992
Interest charges decreased in 1993 compared to 1992 primarily due to the
Company's on-going program to refinance and redeem higher-interest long-term
debt.
1992 vs 1991
Interest charges decreased in 1992 compared to 1991 primarily due to the
Company's on-going program to refinance and redeem higher-interest long-term
debt and lower interest rates on bank borrowings.
Preferred Stock Dividends
Preferred stock dividends decreased in both 1993 and 1992 compared to the
prior year primarily due to the reduced number of preferred shares outstanding
and the refinancing of higher-cost preferred stock.
Liquidity and Capital Resources
The Company's capital requirements are primarily for capital expenditures for
its construction program and for debt service. Capital resources available to
meet these requirements and dividend payments are funded from cash provided by
utility operations and, to the extent necessary, external financing.
The Company meets its short-term liquidity requirements primarily through
bank lines of credit, which were $351.2 million at December 31, 1993, against
which $119.4 million was outstanding, and through a $150 million commercial
paper program. No amounts were outstanding at year-end under the commercial
paper program. The Company believes these sources of short-term liquidity are
adequate.
During 1993 and 1992, the Company met its capital requirements with cash
generated through operations. Net cash provided by operating activities for
1993 was $1.3 billion. For 1994 through 1997, the Company expects that all of
its capital needs will be provided through internally generated funds.
118
Construction program expenditures for 1993 were $575 million and are
estimated to be $575 million in 1994 and $1.5 billion for 1995 to 1997. The
estimated expenditures do not include any amounts for cooling towers at Salem
Generating Station (Salem) that may be required for environmental reasons.
The Company does not presently anticipate that construction of the Salem
cooling towers will be required; however, if mandated, the estimated cost to
the Company would be $230 to $300 million and may require external sources of
financing. Certain facilities under construction and to be constructed may
require permits and licenses which the Company has no assurance will be
granted.
The current level of the Company's capital expenditures, as a result of the
completion of its nuclear construction program, has improved the Company's
financial condition. Also contributing to this improvement were the effects of
the Company's cost-containment program, an aggressive bill-collection program
and revenues from sales of capacity and energy to other utilities.
Influenced by favorable financial market conditions, the Company has
continued its aggressive refinancing and redemption program. During 1993, $2.1
billion of long-term debt and preferred stock were sold to replace debt and
preferred stock carrying significantly higher rates of interest and dividends.
Also during 1993, the Company utilized internally generated cash to repay $154
million of debt and to redeem $45 million of preferred stock. These
transactions resulted in a reduction of approximately $49 million in
annualized interest and $6 million in annualized preferred stock dividends.
The ratios under the Company's mortgage indenture and Articles of
Incorporation at December 31, 1993 were 4.20 and 2.47 times, respectively,
compared with minimum issuance requirements of 2.00 and 1.50.
During 1993, Dividend Reinvestment and Stock Purchase Plan requirements were
satisfied by the purchase of shares of common stock on the open market.
Depending on the Company's specific requirements, the Company will decide
whether to issue shares or purchase shares on the open market in the future.
The Company's capital structure as of December 31, 1993 was common equity,
42.6%; preferred stock, 6.1%; and long-term debt, 51.3%; compared to its
capital structure as of December 31, 1992 of common equity, 40.3%; preferred
stock, 6.6%; and long-term debt, 53.1%. The Company anticipates that its
improved financial condition will allow it to further strengthen its balance
sheet.
Outlook
The Company's financial condition and its future operating results are
dependent on a number of factors affecting the Company and the utility
industry in general. These factors include the regulation and operation of
nuclear generating facilities, increased competition, regulatory and
accounting changes and compliance with environmental regulations.
General Business Outlook
The Company's financial condition and future operating results are in part
dependent on the continued successful operation of its nuclear generating
facilities. The Company's nuclear generating facilities represent
approximately 44% of its installed generating capacity. During 1993, the
Company's nuclear plants operated at a 78% weighted average capacity factor
and produced 60% of the Company's output. Substantial nuclear generation is
the most cost-effective way for the Company to meet customer needs and any
commitments for off-system sales. In addition, continued operation of the
nuclear plants above 60% of capacity is necessary to avoid penalties under the
ECA. Additionally, the terms of the 1991 settlement of the Limerick Unit No. 2
119
rate case afford the Company the opportunity, through sales to other
utilities and the efficient operation of Limerick, to increase future
earnings. See note 2 of Notes to Consolidated Financial Statements for a
description of the ECA and the terms of the Limerick Unit No. 2 rate case
settlement.
At December 31, 1993, the Company had agreements with other utilities to
sell up to 799 megawatts (mW) of installed generating capacity and/or
associated energy. All of these agreements are either for weekly purchases of
energy only or expire during 1994. The Company expects to renew these
agreements or negotiate new agreements and to sell over $100 million of
capacity and/or energy through such agreements in 1994. The Company's future
results of operations are dependent in part on its ability to successfully
market its excess generating capacity and associated energy.
Annual and quarterly operating results can be affected by weather, which can
have a significant positive or negative impact. For example, 1993 earnings
compared to 1992 were favorably impacted by $0.26 per share due to the summer
being one of the hottest in Company history. Conversely, the Company's
earnings were negatively impacted by $0.35 per share in 1992 compared to 1991
due to one of the coolest summers ever experienced in the Company's service
territory.
Inflation impacts the Company through increased operating costs and
increased capital costs for utility plant. The Company expects that it would
recover any increased operating costs, but in times of high inflation, the
Company could be adversely impacted by the regulatory lag in reflecting these
increased costs in rates. In addition, the replacement costs of the Company's
utility plant are significantly higher than the historical costs reflected in
the financial statements.
The Company expects its level of capital investment in utility plant to
remain relatively stable since it has sufficient electric generating capacity
to meet the anticipated needs of its service territory well into the next
decade. Because of the Company's substantial investment in and reliance on its
nuclear generating units, any changes in regulations by the Nuclear Regulatory
Commission (NRC) requiring additional investments or resulting in increased
operating costs of nuclear generating units could adversely affect the
Company.
The Company's budgeted capital expenditures through 1997 include all costs
of compliance with Phase I of the Clean Air Act of 1990 (Clean Air Act),
including its share of the costs of scrubbers being installed at Conemaugh
Generating Station. As a result of its prior investments in scrubbers for
Eddystone and Cromby and its investment in nuclear generating capacity, the
Company believes that compliance with the Clean Air Act will have less impact
on the Company's electric rates than on the rates of other Pennsylvania
utilities which are more dependent on coal-fired generation.
An evaluation of Company sites for potential environmental clean-up
liability is on-going, including approximately 20 sites where manufactured gas
plant activities may have resulted in site contamination. Past activities at
several sites have resulted in actual site contamination. The Company is
presently engaged in performing detailed evaluations at certain of these sites
to define the nature and extent of the contamination, to determine the
necessity of remediation and to identify possible remedi-ation alternatives.
As of December 31, 1993 and 1992, the Company has accrued $17 and $13 million,
respectively, of study and remediation costs that currently can be reasonably
estimated. The Company cannot currently predict whether it will incur other
significant liabilities for any additional remediation costs at these or
additional sites identified by the Company, environmental agencies or others.
120
SFAS No. 112, "Employers' Accounting for Postemploy-ment Benefits," must be
adopted by the first quarter of 1994. The Company cannot currently determine
the effect of this statement upon the results of operations.
The Company would ultimately seek to recover through the ratemaking process
all capital costs and any increased operating costs, including those
associated with NRC regulation of the Company's nuclear generating stations
and environmental compliance and remediation, although such recovery is not
assured.
Regulatory Assets
At December 31, 1993, the Company had deferred on its balance sheet certain
regulatory assets for which current recovery has not yet been approved by the
PUC. These regulatory assets include $91 million of operating and maintenance
expenses, depreciation and accrued carrying charges on its investment in
Limerick Unit No. 2 and 50% of Limerick common facilities, deferred pursuant
to a Declaratory Order of the PUC; $45 million of costs not associated with
construction activity related to the adoption of SFAS No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions"; and $107 million
recognized for the effect on deferred taxes of the change in the statutory
federal income tax rate from 34% to 35% in 1993. See notes 2, 6 and 12,
respectively, of Notes to Consolidated Financial Statements.
These and other regulatory assets are deferred pursuant to PUC action. Any
deferred costs that are not recovered through base rates would be charged
against income immediately. The Company has announced its intention not to
seek an electric retail base-rate increase in 1994.
Competition
The electric utility industry, in particular power generation to serve the
needs of large users such as municipal customers and for off-system sales, has
become increasingly competitive. Companies that are able to provide energy at
a lower cost are likely to benefit from this competition. Competitors include
co-generators and independent power producers. Nonutility generation has
resulted, and in the future could result, in the loss of revenues from
industrial customers. These factors will continue to challenge the Company to
maintain current revenue levels.
The National Energy Policy Act of 1992 (Energy Act) encourages competition
among utilities and nonutility generators by allowing access to utility
transmission facilities for wholesale wheeling. The Energy Act directs the
Federal Energy Regulatory Commission (FERC) to set prices for wheeling to
allow utilities to recover all legitimate, verifiable and economic costs for
providing wheeling services, including the cost of expanding their
transmission facilities to accommodate required transmission access. Retail
wheeling is prohibited under the Energy Act. Retail wheeling would, however,
challenge the Company to assure that it continues to be the provider of
service to its large commercial and industrial customers and that it positions
itself to take advantage of opportunities to expand its customer base by
marketing its reliable power sources.
The Company is currently involved in deliberations before the Maryland
Public Service Commission (MdPSC) and FERC concerning the continued purchase
by Conowingo Power Company (COPCO), a wholly owned subsidiary of the Company,
of all of its power from the Company. COPCO's purchases from the Company
represent less than 2% of the Company's annual revenues. Hearings on this
matter are to commence in September 1994 and result from a MdPSC order that
COPCO perform a study of its power supply alternatives, including competitive
bidding. The Company has filed with the FERC a proposal to add an exit fee for
the recovery from COPCO of the stranded investment costs, if the power supply
needs of COPCO are obtained from a source other than the Company.
121
In September 1993, the Board of Directors of the Company approved a plan to
reorganize the Company's operations to better enable it to meet the challenges
of a competitive environment. The Company's operations will be divided into
five strategic business units by January 1, 1995. The business units will be
Consumer Energy Services Group, Bulk Power Enterprises, Power Generation
Group, Nuclear Generation Group, and Gas Services Group. The plan calls for
each business unit to eventually operate as an individual profit center,
separate from the other business units.
In October, in response to its perception of business risk created by
intensifying competition within the electric utility industry, the Standard &
Poor's (S&P) rating agency tightened the financial ratio benchmarks it uses to
rate electric utility company debt. This action has affected a significant
portion of the investor-owned electric utility industry. Although the
Company's current debt ratings have been affirmed by S&P, the Company's
outlook, along with 47 other electric utilities, has been changed from
"stable" to "negative." The Company and 21 other electric utilities have had
their business positions categorized as "below average." S&P determined the
Company's business position to be "below average" because it is considered to
be a high-cost producer of electricity with a high dependency on its nuclear
generation. Also, the perceived outlook for the economy of the Company's
service territory and the Northeast in general contributed to this
characterization.
Moody's Investors Service (Moody's) has also announced that the changing
electric utility business environment could, over the next three to five
years, lead to bond rating downgrades. Moody's also believes that business
risk in the electric utility industry is rising due to deregulation and the
resulting competition.
For a discussion of other contingencies, see notes 2 and 3 of Notes to
Consolidated Financial Statements.
122
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders and Board of Directors
PECO Energy Company:
We have audited the accompanying consolidated balance sheets of PECO
Energy Company and Subsidiary Companies as of December 31, 1993 and 1992, and
the related consolidated statements of income, cash flows, and changes in
common shareholders' equity and preferred stock for each of the three years in
the period ended December 31, 1993. These financial statements are the
responsibility of the Companies' management. Our responsibility is to express
an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of PECO Energy
Company and Subsidiary Companies as of December 31, 1993 and 1992, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1993, in conformity with
generally accepted accounting principles.
As discussed in Note 4 of the consolidated financial statements, the Company
changed its methods of accounting for non-pension postretirement employee
benefits and income taxes in 1993.
123
2400 Eleven Penn Center
Philadelphia, Pennsylvania
January 31, 1994
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of Dollars) For the Years Ended December 31,
Operating Revenues 1993 1992 1991
Electric $3,605,425 $3,597,141 $3,662,573
Gas 382,704 365,328 356,013
Total Operating Revenues 3,988,129 3,962,469 4,018,586
Operating Expenses
Fuel and Energy Interchange 659,580 709,115 778,674
Other Operating 851,254 906,346 842,375
Maintenance 364,409 353,502 332,269
Depreciation 424,952 413,779 400,572
Income Taxes 354,391 264,483 308,945
Other Taxes 298,132 281,868 274,561
Total Operating Expenses 2,952,718 2,929,093 2,937,396
Operating Income 1,035,411 1,033,376 1,081,190
Other Income and Deductions
Allowance for Other Funds Used
During Construction 11,885 10,461 10,619
Settlement of Peach Bottom Litigation ---- (103,078) ----
Income Taxes (11,808) 40,160 (16,442)
Other, Net 11,980 3,392 28,696
Total Other Income and Deductions 12,057 (49,065) 22,873
Income Before Interest Charges 1,047,468 984,311 1,104,063
Interest Charges
Long-Term Debt 432,707 484,153 545,488
Short-Term Debt 36,002 31,419 36,360
Total Interest Charges 468,709 515,572 581,848
Allowance for Borrowed Funds Used
During Construction (11,889) (10,202) (12,465)
Net Interest Charges 456,820 505,370 569,383
Net Income 590,648 478,941 534,680
Preferred Stock Dividends 49,058 60,731 66,104
Earnings Applicable to Common Stock $ 541,590 $ 418,210 $ 468,576
Average Shares of Common Stock
Outstanding (Thousands) 221,072 220,245 218,234
Earnings Per Average Common
Share (Dollars) $ 2.45 $ 1.90 $ 2.15
Dividends Per Common Share (Dollars) $ 1.43 $ 1.325 $ 1.225
See Notes to Consolidated Financial Statements.
124
CONSOLIDATED BALANCE SHEETS
Assets December 31,
(Thousands of Dollars) 1993 1992
Utility Plant, at Original Cost
Electric $13,102,088 $12,797,389
Gas 843,205 781,708
Common 203,747 162,061
14,149,040 13,741,158
Less Accumulated Provision
for Depreciation 3,946,805 3,587,317
10,202,235 10,153,841
Nuclear Fuel, Net 179,529 188,609
Construction Work in Progress 381,247 348,792
Leased Property, Net 194,702 209,994
Net Utility Plant 10,957,713 10,901,236
Current Assets
Cash and Temporary Cash Investments 46,923 50,369
Accounts Receivable, Net
Customers 122,581 138,880
Other 47,768 62,571
Inventories, at Average Cost
Fossil Fuel 67,040 63,688
Materials and Supplies 142,132 156,706
Deferred Income Taxes 30,185 39,285
Other 58,205 38,466
Total Current Assets 514,834 549,965
Deferred Debits and Other Assets
Recoverable Deferred Income Taxes 2,297,368 ----
Deferred Limerick Costs 433,605 455,161
Deferred Non-Pension Postretirement
Benefit Costs 44,691 ----
Investments 218,636 202,422
Loss on Reacquired Debt 343,004 273,120
Other 222,476 196,323
Total Deferred Debits and Other
Assets 3,559,780 1,127,026
Total $15,032,327 $12,578,227
See Notes to Consolidated Financial Statements.
125
CONSOLIDATED BALANCE SHEETS
Capitalization and Liabilities December 31,
(Thousands of Dollars) 1993 1992
Capitalization Common Shareholders' Equity
Common Stock $3,488,477 $3,459,131
Other Paid-In Capital 1,214 1,214
Retained Earnings 773,727 561,824
4,263,418 4,022,169
Preferred and Preference Stock
Without Mandatory Redemption 422,472 422,472
With Mandatory Redemption 186,500 231,130
Long-Term Debt 4,884,343 5,203,961
Total Capitalization 9,756,733 9,879,732
Current Liabilities
Notes Payable, Bank 119,350 110,500
Long-Term Debt Due Within One Year 252,263 98,998
Capital Lease Obligations Due Within One Year 60,500 58,998
Accounts Payable 242,239 241,462
Taxes Accrued 24,939 24,334
Deferred Energy Costs 48,691 72,999
Interest Accrued 97,540 15,923
Dividends Payable 18,345 19,459
Other 90,710 87,887
Total Current Liabilities 954,577 830,560
Deferred Credits and Other Liabilities
Capital Lease Obligations 134,202 150,996
Deferred Income Taxes 3,386,136 1,001,939
Unamortized Investment Tax Credits 386,162 302,508
Pension Obligation for Early Retirement Plan 135,286 141,675
Non-Pension Postretirement Benefits Obligation 51,781 ----
Other 227,450 270,817
Total Deferred Credits and Other Liabilities 4,321,017 1,867,935
Commitments and Contingencies (Notes 2 and 3)
Total $15,032,327 $12,578,227
See Notes to Consolidated Financial Statements.
126
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
(Thousands of Dollars)
Cash Flows From Operating Activities 1993 1992 1991
Net Income $590,648 $478,941 $534,680
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities:
Depreciation and Amortization 507,069 491,186 499,675
Deferred Income Taxes 139,846 81,943 77,836
Unrecovered Phase-In Plan Revenue ----- 142,267 96,705
Deferred Energy Costs (24,308) 52,959 16,593
Sale of Accounts Receivable ----- ----- 125,000
Amortization of Leased Property 58,400 54,600 59,400
Changes in Working Capital:
Accounts Receivable 31,102 82,151 (70,907)
Inventories 11,222 1,395 (26,926)
Accounts Payable 777 (47,403) 36,326
Other Current Assets and Liabilities (34,694) (136,627) 54,633
Other Items Affecting Operations (18,287) (28,569) 20,073
Net Cash Flows Provided by Operating
Activities 1,261,775 1,172,843 1,423,088
Cash Flows From Investing Activities
Investment in Plant (568,076) (571,829) (473,448)
Increase in Other Investments (16,214) (32,769) (43,827)
Net Cash Flows Used by Investing Activities (584,290) (604,598) (517,275)
Cash Flows From Financing Activities
Change in Short-Term Debt 8,850 10,500 (68,500)
Issuance of Common Stock 29,346 12,465 66,453
Issuance of Preferred Stock 142,700 140,000 ----
Retirement of Preferred Stock (187,330) (224,462) (15,330)
Issuance of Long-Term Debt 1,994,765 1,369,540 278,000
Retirement of Long-Term Debt (2,148,963) (1,504,877) (692,867)
Loss on Reacquired Debt (69,884) (85,380) (58,419)
Dividends on Preferred and Common Stock (366,081) (349,856) (333,319)
Change in Dividends Payable (1,114) (16,607) 8,575
Expenses of Issuing Long-Term Debt and
Preferred Stock (24,820) (11,660) (68)
Capital Lease Payments (58,400) (54,600) (59,400)
Net Cash Flows from Financing Activities (680,931) (614,937) (874,875)
(Decrease) Increase in Cash and
Cash Equivalents (3,446) (46,692) 30,938
Cash and Cash Equivalents at beginning
of period 50,369 97,061 66,123
Cash and Cash Equivalents at end of period $46,923 $50,369 97,061
See Notes to Consolidated Financial Statements.
127
CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON STOCKHOLDERS' EQUITY AND PREFERRED STOCK
Other
Common Stock Paid-In Retained Preferred Stock
(All Amounts in Thousands) Shares Amount Capital Earnings Shares Amount
Balance, January 1, 1991 216,953 $3,380,213 $1,214 $243,106 7,534 $753,394
Net Income 534,680
Cash Dividends Declared
Preferred Stock
(at specified annual rates) (65,966)
Common Stock ($1.225 per share) (267,353)
Expenses of Capital Stock Activity (68)
Issuance of Stock
Dividend Reinvestment and
Stock Purchase Plan 2,925 63,207
Long-Term Incentive Plan 152 3,246
Redemptions (153) (15,330)
Balance, December 31, 1991 220,030 3,446,666 1,214 444,399 7,381 738,064
Net Income 478,941
Cash Dividends Declared
Preferred Stock
(at specified annual rates) (58,021)
Common Stock ($1.325 per share) (291,835)
Expenses of Capital Stock Activity (11,660)
Issuance of Stock
Long-Term Incentive Plan 504 12,465
Issuances 1,400 140,000
Redemptions (2,245) (224,462)
Balance, December 31, 1992 220,534 3,459,131 1,214 561,824 6,536 653,602
Net Income 590,648
Cash Dividends Declared
Preferred Stock
(at specified annual rates) (49,919)
Common Stock
($1.43 per share) (316,162)
Expenses of Capital Stock Activity (5,625)
Issuance of Stock
Long-Term Incentive Plan 982 29,346 (7,039)
Issuances 1,427 142,700
Redemptions (1,873) (187,330)
Balance, December 31, 1993 221,516 $3,488,477 $1,214 773,727 6,090 $608,972
See Notes to Consolidated Financial Statements.
128
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Significant Accounting Policies
General
The consolidated financial statements of PECO Energy Company (Company),
formerly known as Philadelphia Electric Company, include the accounts of its
utility subsidiary companies, all of which are wholly owned. Non-utility
subsidiaries are not material and are accounted for on the equity method.
Accounting policies are in accord-ance with those prescribed by the regulatory
authorities having jurisdiction, principally the Pennsylvania Public Utility
Commission (PUC) and the Federal Energy Regulatory Commission (FERC).
Revenues
Customers' meters are read and bills are prepared on a cycle basis. At the end
of each month, the Company accrues an estimate for the unbilled amount of
energy delivered to customers.
Pursuant to a phase-in plan approved by the PUC in its electric base-rate
order dated April 19, 1990, the Company recorded revenue equal to the full
amount of the rate increase approved, based on kilowatthours rendered to
customers. On April 5, 1991, that plan was amended by the PUC as part of the
settlement of all appeals arising from the Limerick Generating Station
(Limerick) Unit No. 2 rate proceeding to permit recovery of the remaining
unrecovered revenue by December 31, 1992 (see note 2). As of December 31, 1993
and 1992, the Company had no unrecovered phase-in plan revenue.
Fuel and Energy Cost Adjustment Clauses
The Company's classes of service are subject to fuel adjustment clauses
designed to recover or refund the differences between actual costs of fuel,
energy interchange, and purchased power and gas, and the amounts of such costs
included in base rates. Differences between the amounts billed to customers
and the actual costs recoverable are deferred and recovered or refunded in
future periods by means of prospective adjustments to rates. Generally, such
rates are adjusted every twelve months. In addition to reconciling fuel costs
and revenues, the Company's Energy Cost Adjustment (ECA), established by the
PUC, incorporates a nuclear performance standard which allows for financial
bonuses or penalties depending upon whether the Company's system nuclear
capacity factor exceeds or falls below a specified range (see note 2).
Nuclear Fuel
Nuclear fuel is capitalized and charged to fuel expense on the unit of
production method. Estimated costs of nuclear fuel disposal are charged to
fuel expense as the related fuel is consumed. The Company's share of nuclear
fuel at Peach Bottom Atomic Power Station (Peach Bottom) and Salem Generating
Station (Salem) is accounted for as a capital lease. Nuclear fuel at Limerick
is owned.
Depreciation and Decommissioning
The annual provision for depreciation is provided over the estimated service
lives of plant on the straight-line method. Annual depreciation provisions for
financial reporting purposes, expressed as a percent of average depreciable
utility plant in service, were approximately 2.75% in 1993 and 1992 and 2.74%
in 1991.
The Company's share of the estimated costs for decommissioning nuclear
generating stations currently is being charged to operations over the expected
service life of the related plant. The amounts recovered from customers are
deposited in escrow and trust accounts and invested for funding of future
costs and credited to accumulated depreciation (see note 3).
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Income Taxes
In 1993, the Company adopted Statement of Financial Accounting Standards
(SFAS) No. 109, "Accounting for Income Taxes," which requires an asset and
liability approach for financial accounting and reporting of income taxes. In
addition, the effects of the Alternative Minimum Tax (AMT) are normalized.
Investment Tax Credit (ITC) is deferred and amortized to income over the
estimated useful lives of the related utility plant. ITC related to plant in
service, not included in rate base, is accounted for on the flow-through
method.
Allowance for Funds Used During Construction (AFUDC)
AFUDC is the cost, during the period of construction, of debt and equity funds
used to finance construction pro-jects. AFUDC is recorded as a charge to
Construction Work in Progress, and the credits are to Interest Charges for the
pre-tax cost of borrowed funds and to Other In-come and Deductions for the
remainder as the allowance for other funds. The rates used for capitalizing
AFUDC, which averaged 9.39% in 1993, 10.61% in 1992 and 10.88% in 1991, are
computed under a method prescribed by the regulatory authorities. AFUDC is not
included in regular taxable income and the depreciation of capitalized AFUDC
is not tax deductible.
Nuclear Outage Costs
Incremental nuclear maintenance and refueling outage costs are accrued over
the unit operating cycle. For each unit, an accrual for incremental nuclear
maintenance and refueling outage expense is estimated based upon the latest
planned outage schedule and estimated costs for the outage. Differences
between the accrued and actual expense for the outage are recorded when such
differences are known.
Capitalized Software Costs
Software projects which exceed $5 million are capitalized. At December 31,
1993 and 1992, capitalized software costs totalled $56 million and $40 million
(net of $3 million and $1 million accumulated amortization), respectively.
Such capitalized amounts are amortized ratably over the expected lives of the
projects when they become operational, not to exceed 10 years.
Gains and Losses on Reacquired Debt
Gains and losses on reacquired debt are deferred and amortized to interest
expense over the period approved for ratemaking purposes.
SFAS No. 112
SFAS No. 112, "Employers' Accounting for Postemployment Benefits," must be
adopted by the first quarter of 1994. The Company cannot currently determine
the effect of this statement upon the results of operations.
Reclassifications
Certain prior-year amounts have been reclassified for comparative purposes.
These reclassifications had no effect on net income.
2. Rate Matters
Limerick Unit No. 2 Electric Rate Order As part of the April 19, 1990 PUC
order, the PUC approved recovery of $285 million of deferred Limerick costs
representing carrying charges and depreciation associated with 50% of Limerick
common facilities. These costs are included in base rates and are being
recovered over the life of Limerick. The PUC also approved recovery of $137
million of Limerick Unit No. 1 costs which had previously been deferred
pursuant to a Declaratory Order dated September 28, 1984. These costs are
being recovered over a ten-year period without a return on investment.
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On April 5, 1991, the PUC approved the settlement of all appeals arising
from the Limerick Unit No. 2 rate order. Under the terms of the settlement,
the Company is allowed to retain for shareholders any proceeds above the
average energy cost for sales of up to 399 megawatts (mW) of capacity and/or
associated energy, since the PUC had ruled that the Company had 399 mW of
near-term excess capacity in the Limerick Unit No. 2 rate order. Beginning on
April 1, 1994, the settlement provides for the Company to share in the
benefits which result from the operation of both Limerick Unit No. 1 and Unit
No. 2 through the retention of 16.5% of the energy savings. Through 1994, the
Company's potential benefit from the sale of up to 399 mW of capacity and/or
associated energy and the retained Limerick energy savings is limited to $106
million per year, with any excess accruing to customers. Beginning in 1995, in
addition to retaining the first $106 million, the Company will share in any
excess above $106 million with the Company's share of the excess being 10% in
1995, 20% in 1996 and 30% in 1997 and thereafter. During 1993, 1992 and 1991,
the Company recorded as revenue net of fuel costs $38, $34 and $25 mil- lion,
respectively, as a result of the sale of the 399 mW of capacity and/or
associated energy.
As a part of the settlement, the Company agreed not to file an electric
base-rate increase before April 1, 1994, except as allowed by the PUC or for
emergency or single-issue rate filings to recover costs associated with new
legislation or regulations.
Single-Issue Electric Base-Rate Increase Filed On September 11, 1992, the
Company filed with the PUC a request for a 1.5% electric base-rate increase
designed to recover the increased costs associated with the implementation of
SFAS No. 106, "Employers' Accounting for Post-retirement Benefits Other Than
Pensions." See notes 4 and 6.
On March 25, 1993, the PUC issued a policy statement for implementation of
SFAS No. 106 which states that the PUC "intends to move all jurisdictional
utilities to SFAS No. 106 accrual accounting for ratemaking purposes with-in
approximately five years and to allow the recovery in base rates of all
deferred amounts in approximately 20 years to the extent that costs are
prudently incurred and examined in a base-rate proceeding prior to rate
recognition."
On September 2, 1993, the PUC issued an order denying the Company current
recovery of these costs, stating that the settlement of all appeals arising
from the PUC's 1990 Limerick Unit No. 2 order precluded the Company from
seeking an increase in electric base rates for these costs before April 1,
1994. The September 2, 1993 order authorized the Company to defer the
additional SFAS No. 106 expense as a regulatory asset in accordance with the
PUC policy statement. On September 30, 1993, the Company filed with the
Commonwealth Court of Pennsylvania a petition for review of the PUC's final
order.
Recovery through rates of the Company's SFAS No. 106 transition obligation
of $505 million and amounts deferred pursuant to the PUC's September 2, 1993
Order will be permitted only if included in a general base-rate case within
approximately five years and deemed prudently incurred. The Company's future
earnings will be adversely affected to the extent that the Company is not
ultimately permitted to recover the additional non-pension postretirement
benefits costs resulting from the adoption of SFAS No. 106 through the
ratemaking process. While non-pension postretirement benefits costs
traditionally have been allowed for ratemaking on a pay-as-you-go basis,
recovery of the deferred costs through the rate making process is not assured.
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Limerick Unit No. 2 Declaratory Order
Pursuant to a Declaratory Order of the PUC, the Company deferred the operating
and maintenance expenses, depreciation and accrued carrying charges on its
capital investment in Limerick Unit No. 2 and 50% of Limerick common
facilities during the period from January 8, 1990, the commercial operation
date of Limerick Unit No. 2, until April 20, 1990, the effective date of the
Limerick Unit No. 2 rate order. At December 31, 1993 and 1992, such costs
included in Deferred Limerick Costs totalled $91 million. Recovery of such
costs deferred pursuant to the Declaratory Order will be addressed by the PUC
in a subsequent electric base-rate case, although such recovery is not
assured. Any amounts not recovered would be charged against income.
Energy Cost Adjustment
The Company is subject to a PUC-established electric ECA which, in addition to
reconciling fuel costs and revenues, incorporates a nuclear performance
standard which allows for financial bonuses or penalties depending on whether
the Company's system nuclear capacity factor exceeds or falls below a
specified range. The bonuses or penalties are based upon average system
replacement energy costs. If the capacity factor is within the range of 60-
70%, there is no bonus or penalty. If the capacity factor exceeds the
specified range, progressive incremental bonuses are earned and, if the
capacity factor falls below the specified range, progressive incremental
penalties are incurred.
For the years ended December 31, 1993, 1992 and 1991, the Company's nuclear
capacity factors were 78%, 71% and 75%, respectively. This entitled the
Company to bonuses reflected in 1993, 1992 and 1991 income of $10, $1 and $5
million, respectively.
3. Commitments and Contingencies
Construction Expenditures
Construction expenditures are estimated to be $575 million for 1994 and $1.5
billion for 1995-1997. For 1994-1997, the Company expects that all of its
capital needs will be provided through internally generated funds. These
construction expenditure estimates are reviewed and revised periodically to
reflect changes in economic conditions, re-vised load forecasts and other
appropriate factors. Certain facilities under construction and to be
constructed may require permits and licenses which the Company has no
assurance will be granted.
The Company's operations have in the past and may in the future require
substantial capital expenditures in order to comply with environmental laws.
The Company expects that any capital expenditures to construct facilities for
compliance with environmental laws and the operating costs of such facilities
would be recoverable through the rate-making process, although such recovery
is not assured.
Nuclear Insurance
The Price-Anderson Act, as amended (Price-Anderson Act), sets the limit of
liability of approximately $9.4 billion for claims that could arise from an
incident involving any licensed nuclear facility in the nation. The limit is
subject to increase to reflect the effects of inflation and changes in the
number of licensed reactors. All utilities with nuclear generating units,
including the Company, have obtained coverage for these potential claims
through a combination of private insurances of $200 million and mandatory
participation in a financial protection pool. Under the Price-Anderson Act,
all nuclear reactor licensees can be assessed up to $76 million per reactor
per incident, payable at $10 million per reactor per incident per year. This
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assessment is subject to inflation, state premium taxes and an additional
surcharge of 5% if the total amount of claims and legal costs exceeds the
basic assessment.
If the damages from an incident at a licensed nuclear facility exceed $9.4
billion, the President of the United States is to submit to Congress a plan
for providing additional compensation to the injured parties. Congress could
impose further revenue-raising measures on the nuclear industry to pay claims.
The Price-Anderson Act and the extensive regulation of nuclear safety by the
Nuclear Regulatory Commission (NRC) do not preempt claims under state law for
personal, property or punitive damages related to radiation hazards.
The Company maintains property insurance, including decontamination expense
coverage and premature decommissioning coverage, for loss or damage to its
nuclear facilities. Although it is not possible to determine the total amount
of the loss that may result from an occurrence at these facilities, the
Company maintains its $2.75 billion proportionate share for each station.
Under the terms of the various insurance agreements, the Company could be
assessed up to $35 million for losses incurred at any plant insured by the
insurance companies. The Company is self-insured to the extent that any losses
may exceed the amount of insurance maintained. Any such losses, if not
recovered through the ratemaking process, could have a material adverse effect
on the Company's financial condition.
The Company is a member of an industry mutual insurance company which
provides replacement power cost insurance in the event of a major outage at a
nuclear station. The premium for this coverage is subject to an assessment for
adverse loss experience. The Company's maximum share of any assessment is $17
million per year.
Nuclear Decommissioning and Spent Fuel Storage
In conjunction with the PUC's April 19, 1990 electric baserate order, the PUC
recognized a revised decommissioning cost estimate based upon total cost. The
Company's share of this revised cost is $643 million expressed in 1990
dollars, which the Company believes would be substantially unchanged at
December 31, 1993.
Under a contract with the U.S. Department of Energy (DOE), the DOE is
obligated ultimately to take possession of all spent nuclear fuel generated by
the Company's nuclear units for long-term storage by no later than 1998. The
contract currently requires that a spent fuel disposal fee of one mill ($.001)
per net kilowatthour generated be paid to the DOE. The fee may be adjusted
prospectively in order to ensure full cost recovery.
The DOE has stated that it will not be able to open a permanent, high-level
nuclear waste storage facility until 2010, at the earliest. The DOE stated
that the delay was a result of its seeking new data about the suitability of
the proposed storage facility site at Yucca Mountain, Nevada, opposition to
this location for the respository and the DOE's revision of its civilian
nuclear waste program. The DOE stated that it would seek legislation from
Congress for the construction of a temporary storage facility which would
accept spent nuclear fuel from utilities in 1998 or soon thereafter. Although
progress is being made at Yucca Mountain and several communities have
expressed interest in providing a temporary storage site, the Company cannot
predict when the temporary and permanent federal storage facilities will
become available.
Peach Bottom and Limerick have on-site storage facilities with the capacity
to store spent fuel discharged from the units through the late 1990's and, by
further modifying spent fuel storage facilities, capacity could be provided
until approximately 2010. Salem has spent fuel storage capacity through 1998
for Unit No. 1 and 2002 for Unit No. 2. Public Service Electric and Gas
(PSE&G) is planning expansion of the fuel storage capacity of Salem.
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The National Energy Policy Act of 1992 (Energy Act) provides, among other
things, that utilities with nuclear reactors must pay for the decommissioning
and decontamination of the DOE nuclear fuel enrichment facilities. The total
costs are estimated to be $150 million per year for 15 years, of which the
Company's share was estimated at December 31, 1992 to be $6 million per year,
subsequently revised to $5 million in September 1993. The Energy Act provides
that these costs are to be recoverable in the same manner as other fuel costs.
The Company has recorded the liability and a related regulatory asset, which
at December 31, 1993 and 1992 was $69 and $96 million, respectively.
The Company is currently recovering in rates costs for nuclear
decommissioning and decontamination and spent fuel storage. The Company
believes that the ultimate costs of decommissioning and decontamination, spent
fuel disposal and any assessment under the Energy Act will continue to be
recoverable through rates, although such recovery is not assured.
Environmental Issues
Under federal and state environmental laws, the Company is generally liable
for the costs of remediating environmental contamination of property now or
formerly owned by the Company and of property contaminated by hazardous waste
generated by the Company. The Company owns or leases a substantial number of
real estate parcels, including parcels on which its operations or the
operations of others may have resulted in contamination by substances which
are considered hazardous under the environmental laws. The Company is
currently involved in a number of proceedings relating to sites where
hazardous waste has been deposited and may be subject to additional
proceedings in the future. An evaluation of Company sites for potential
environmental clean-up liability is on-going, including approximately 20 sites
where manufactured gas plant activities may have resulted in site
contamination. Past activities at several sites have resulted in actual site
contamination. The Company is presently engaged in performing detailed
evaluations at certain of these sites to define the nature and extent of the
contamination, to determine the necessity of remediation and to identify
possible remediation alternatives. As of December 31, 1993 and 1992, the
Company had accrued $17 and $13 million, respectively, for various
investigation and remedi-ation costs that currently can be reasonably
estimated. The Company cannot currently predict whether it will incur other
significant liabilities for additional investigation and remediation costs at
these or additional sites identified by the Company, environmental agencies or
others, or whether any such costs will be recoverable through rates or from
third parties.
Other Litigation
On April 11, 1991, 33 former employees of the Company filed an amended class
action suit against the Company in the United States District Court for the
Eastern District of Pennsylvania (Eastern District Court) on behalf of
approximately 141 persons who retired from the Company between January and
April 1990. The lawsuit, filed under the Employee Retirement Income Security
Act (ERISA), alleges that the Company fraudulently and/or negligently
misrepresented or concealed facts concerning the Company's 1990 Early
Retirement Plan and thus induced the plaintiffs to retire or not to defer
retirement immediately before the initiation of the Early Retirement Plan,
thereby depriving the plaintiffs of substantial pension and salary benefits.
On June 6, 1991, the plaintiffs filed amended complaints adding additional
plaintiffs. The lawsuit names the Company, the Company's Service Annuity Plan
(SAP) and two Company officers as defendants. The plaintiffs seek
approximately $20 million in damages representing, among other things,
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increased pension benefits and nine months' salary pursuant to the terms of
the Early Retirement Plan, as well as punitive damages. The ultimate outcome
of this matter is not expected to have a material adverse effect on the
Company's financial condition.
On May 2, 1991, 37 former employees of the Company filed an amended class
action suit against the Company, the SAP and three former Company officers in
the Eastern District Court, on behalf of 147 former employees who retired from
the Company from January through June 1987. The lawsuit was filed under ERISA
and concerns the August 1, 1987 amendment to the SAP. The plaintiffs claim
that the Company concealed or misrepresented the fact that the amendment to
the SAP was planned to increase retirement benefits and, as a consequence,
they retired prior to the amendment to the SAP and were deprived of
significant retirement benefits. The complaint does not specify any dollar
amount of damages. The ultimate outcome of this matter is not expected to have
a material adverse effect on the Company's financial condition.
On May 25, 1993, the Company received a letter from attorneys on behalf of a
shareholder demanding that the Company's Board of Directors commence legal
action against certain Company officers and directors with respect to the
Company's credit and collections practices. The basis of the demand is the
findings and conclusions contained in the Credit and Collection section of the
May 1991 PUC Management Audit Report prepared by Ernst & Young. At its June
28, 1993 meeting, the Board of Directors appointed a special committee of
directors to consider whether such legal action is in the best interest of the
Company and its shareholders.
On July 26, 1993, attorneys on behalf of two shareholders reinstituted a
shareholder derivative action against several of the Company's present and
former officers alleging mismanagement, waste of corporate assets and breach
of fiduciary duty in connection with the Company's credit and collections
practices. This action is also based on the findings and conclusions contained
in the Credit and Collections section of the May 1991 PUC Management Audit
Report prepared by Ernst & Young. The plaintiffs seek, among other things, an
unspecified amount of damages and the awarding to the plaintiffs of the costs
and disbursements of the action, including attorneys' fees.
Any monetary damages which may be recovered, net of expenses, would be paid
to the Company because the lawsuit is brought derivatively by shareholders on
behalf of the Company.
The Company is involved in various other litigation matters, the ultimate
outcomes of which, while uncertain, are not expected to have a material
adverse effect on the Company's financial condition; however, they could have
a material effect on quarterly operating results when resolved in a future
period.
4. Changes in Accounting
Effective January 1, 1993, the Company adopted SFAS No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions," which requires
the recognition of the expected costs of the benefits during the years
employees render service, but not later than the date eligible for retirement
using the prescribed accrual method. For 1992 and prior, the Company
recognized these costs on a pay-as-you-go basis. The Company is currently
recovering in base rates the pay-as-you-go costs. Adoption of SFAS No. 106
resulted in a transition obligation of $505 million, which is being amortized
on a straight-line basis over 20 years. Adoption of SFAS No. 106 had no impact
on the Company's results of operations as the Company is deferring these
increased costs (see note 6).
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Effective January 1, 1993, the Company adopted SFAS No. 109, "Accounting for
Income Taxes," which requires an asset and liability approach for financial
accounting and reporting for income taxes utilizing the cumulative method of
adoption. As a result, the Company recognized a charge of $3 million or $0.02
per share during 1993. The Company has also recorded an additional accumulated
deferred income tax liability along with a corresponding recoverable deferred
income tax asset of $2.3 billion at December 31, 1993 (see note 12).
5. Retirement Benefits
The Company and its subsidiaries have non-contributory trusteed retirement
plans applicable to all regular employees. The benefits are based primarily
upon employees' years of service and average earnings prior to retirement. The
Company's funding policy is to contribute, at a minimum, amounts sufficient to
meet ERISA requirements. Approximately 71%, 78% and 79% of pension costs were
charged to operations in 1993, 1992 and 1991, respectively, and the remainder,
associated with construction labor, to the cost of new utility plant.
Pension costs for 1993, 1992 and 1991 included the following components:
(Thousands of Dollars) 1993 1992 1991
Service cost * benefits
earned during the period $33,673 $ 30,191 $ 23,692
Interest cost on projected benefit
obligations 134,658 129,000 121,826
Actual return on plan assets (226,240) (122,869) (345,677)
Amortization of transition asset (4,538) (4,539) (4,539)
Amortization and deferral 87,733 (5,741) 227,038
Net pension cost $25,286 $26,042 $ 22,340
The changes in net periodic pension costs in 1993, 1992 and 1991 were as
follows:
(Thousands of Dollars) 1993 1992 1991
Change in number, characteristics and
salary levels of participants and net
actuarial gain $(756) $ (840) $ 3,402
Change in plan provisions ---- ---- 1,978
Change in actuarial assumptions ---- 4,542 4,754
Net change (756) $ 3,702 $10,134
Plan assets consist principally of common stock, U.S. government obligations
and other fixed income instruments. In determining pension costs, the assumed
long-term rate of return on assets was 9.50% for 1993, 1992 and 1991.
The weighted-average discount rate used in determin-ing the actuarial
present value of the projected benefit obligation was 7% at December 31, 1993
and 7.75% at December 31, 1992 and 1991. The average rate of increase in
future compensation levels ranged from 4% to 6% at December 31, 1993 and
ranged from 4.5% to 6.5% at December 31, 1992 and 1991.
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Prior service cost is amortized on a straight-line basis over the average
remaining service period of employees expected to receive benefits under the
plan. The funded status of the plan at December 31, 1993 and 1992 is
summarized as follows:
(Thousands of Dollars) 1993 1992
Actuarial present value of accumulated
plan benefit obligations:
Vested benefit obligations $(1,482,868) $(1,315,292)
Accumulated benefit obligation $(1,600,768) (1,410,777)
Projected benefit obligation for
services rendered to date (1,972,332) $(1,740,013)
Plan assets at fair value 1,844,281 1,709,802
Funded status (128,051) (30,211)
Unrecognized transition asset (53,865) (58,402)
Unrecognized prior service costs 95,728 101,955
Unrecognized net gain (77,245) (183,820)
Pension liability $(163,433) $ (170,478)
6. Non-Pension Postretirement Benefits
The Company provides certain health care and life insurance benefits for
retired employees. Company employees will become eligible for these benefits
if they retire from the Company with ten years of service. These benefits and
similar benefits for active employees are provided by an insurance company
whose premiums are based upon the benefits paid during the year. In the past,
the Company has recognized the cost of providing these benefits by charging
the annual insurance premiums to expense.
The transition obligation resulting from the adoption of SFAS No. 106 was
$505 million at December 31, 1993, which represents the previously
unrecognized accumulated non-pension postretirement benefit obligation. The
transition obligation is being amortized on a straight-line basis over an
allowed 20-year period. The annual accrual for non-pension postretirement
benefits costs (including amortization of the transition obligation) is $83
million. The Company's comparable pay-as-you-go costs for these benefits,
which are currently being recovered in base rates, were $31 million in 1993.
On September 11, 1992, the Company filed with the PUC a request for a 1.5%
electric base-rate increase designed to recover the costs associated with the
implementation of SFAS No. 106 (see note 2).
The transition obligation was determined by applica-tion of the terms of
medical, dental and life insurance plans, including the effects of established
maximums on covered costs, together with relevant actuarial assumptions and
health care cost trend rates, which are projected to range from 12% in 1993 to
5% in 2002. The effect of a 1% annual increase in these assumed cost trend
rates would increase the accumulated postretirement benefit obligation by $50
million and the annual service and interest costs by $8 million.
Total costs for all plans amounted to $83, $17 and $15 million in 1993, 1992
and 1991, respectively, for 6,000 retirees during 1993, 1992 and 1991 and for
9,723 active employees during 1993. The cost was higher in 1993 than in 1992
primarily due to the adoption of SFAS No. 106.
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The net periodic benefits costs for 1993 included the following components:
(Thousands of Dollars)
Service cost - benefits earned during the period $15,615
Interest cost on projected benefit obligations 41,708
Amortization of the transition obligation 25,251
Actual return on plan assets ----
Amortization and deferral ----
Net periodic postretirement benefits costs $82,574
The funded status of the plan at December 31, 1993 is summarized as follows:
(Thousands of Dollars)
Accumulated postretirement benefit obligation:
Retirees $476,059
Fully eligible active plan participants 39,367
Other active plan participants 79,808
Total 595,234
Plan assets at fair value ----
Accumulated postretirement benefit obligation in
excess of plan assets 595,234
Unrecognized transition obligation (479,778)
Unrecognized net gain (63,675)
Accrued postretirement benefits cost
recognized on the balance sheet $51,781
Measurement of the accumulated postretirement benefits obligation was based on
a 7.25% assumed discount rate.
7. Accounts Receivable
Accounts receivable at December 31, 1993 and 1992 in-cluded unbilled operating
revenues of $115 and $111 million, respectively. Accounts receivable at
December 31, 1993 and 1992 were net of an allowance for uncollectible accounts
of $15 and $18 million, respectively.
The Company is party to an agreement with a financial institution whereby it
can sell on a daily basis and with limited recourse an undivided interest in
up to $325 million of designated accounts receivable until January 24, 1996.
At December 31, 1993 and 1992, the Company had sold a $325 million interest in
accounts receivable under this agreement. The Company retains the servicing
responsibility for these receivables.
By terms of this agreement, under certain circumstances, a portion of
deferred Limerick costs may be included in the pool of eligible receivables.
At December 31, 1993, $43 million of deferred Limerick costs were included in
the pool of eligible receivables.
8. Common Stock
At December 31, 1993 and 1992, common stock without par value consisted of
500,000,000 shares authorized and 221,516,299 and 220,534,048 shares
outstanding, respectively. At December 31, 1993, there were 4,800,000 shares
reserved for issuance under stock purchase plans.
The Company maintains a Long-Term Incentive Plan (LTIP) for certain full-
time salaried employees of the Company. The types of long-term incentive
awards which may be granted under the LTIP are non-qualified options to
purchase shares of the Company's common stock, dividend equivalents and shares
of restricted common stock. Pursuant to the LTIP, 1,961,882 shares of stock
were authorized for issuance upon exercise of options at December 31, 1993.
138
The following table summarizes option activity during 1993, 1992 and 1991:
1993 1992 1991
Balance at
January 1 2,445,833 1,656,244 1,126,675
Options granted 533,800 1,380,000 1,018,500
Options exercised (981,551) (504,411) (151,996)
Options cancelled (36,200) (86,000) (336,935)
Balance at
December 31 1,961,882 2,445,833 1,656,244
Exercisable at
December 31 1,447,282 1,162,833 800,744
Options were exercised at average option prices of $22.66 per share, $24.73
per share and $21.35 per share in 1993, 1992 and 1991, respectively. The
average exercise prices of shares under option were $25.12 per share, $23.18
per share and $20.34 per share at December 31, 1993, 1992 and 1991,
respectively.
9. Preferred and Preference Stock
At December 31, 1993 and 1992, Series Preference Stock consisted of
100,000,000 shares authorized, of which no shares were outstanding. At
December 31, 1993 and 1992, cumulative Preferred Stock, no par value,
consisted of 15,000,000 shares authorized.
Current Shares Amount
Redemption Outstanding (Thousands of Dollars)
Price (a) 1993 1992 1993 1992
Series (without mandatory redemption)
$10.75 ---- ---- 500,000 ---- 50,000
$7.85 101.00 500,000 500,000 $ 50,000 50,000
$7.80 101.00 750,000 750,000 75,000 75,000
$7.75 101.00 200,000 200,000 20,000 20,000
$4.68 104.00 150,000 150,000 15,000 15,000
$4.40 112.50 274,720 274,720 27,472 27,472
$4.30 102.00 150,000 150,000 15,000 15,000
$3.80 106.00 300,000 300,000 30,000 30,000
$7.96(b) (c) 1,400,000 1,400,000 140,000 140,000
$7.48 (d) 500,000 ---- 50,000 ----
4,224,720 4,224,720 422,472 422,472
Series (with mandatory redemption) (e)
$9.875 102.50 390,000 650,000 39,000 65,000
$9.52 ---- ---- 200,000 ---- 20,000
$9.50 1986 Series ---- ---- 675,000 ---- 67,500
$8.75 1978 Series ---- ---- 200,300 ---- 20,030
$7.325 101.46 300,000 330,000 30,000 33,000
$7.00 101.00 248,000 256,000 24,800 25,600
$6.12 (f) 927,000 ---- 92,700 ----
1,865,000 2,311,300 186,500 231,130
Total Preferred Stock 6,089,720 6,536,020 $608,972 $653,602
139
(a) Redeemable, at the option of the Company, at the indicated dollar amounts
per share, plus accrued dividends.
(b) Ownership of this series of preferred stock is evidenced by depositary
receipts, each representing one-fourth of a share of preferred stock.
(c) None of the shares of this series are subject to redemption prior to
October 1, 1997.
(d) None of the shares of this series are subject to redemption prior to April
1, 2003.
(e) Sinking fund requirements ($100 per share) in the period 1994-1996 are
$16,800,000 annually and $3,800,000 annually in the period 1997-1998.
(f) None of the shares of this series are subject to redemption prior to
August 1, 1999.
10. Long-Term Debt
(Thousands of Dollars) At December 31,
Series Due 1993 1992
First and Refunding Mortgage Bonds (a) 6 1/2% 1993 ---- $60,000
4 1/2% - 13.05% 1994 $170,000 170,000
9% 1995 ---- 51,200
8 1/4% 1996 ---- 80,000
6 1/8% 1997 75,000 75,000
5 3/8% - 10% 1998 225,000 250,000
5 5/8% - 11% 1999-2003 1,635,069 1,255,200
6% - 10 1/4% 2004-2008 131,875 384,437
(b) 2009-2013 154,200 ----
8 7/8% - 11% 2014-2018 129,900 479,900
6 5/8% - 10 1/2% 2019-2024 1,776,561 1,207,130
Total First and Refunding Mortgage Bonds 4,297,605 4,012,867
Notes Payable -- Banks (c) 1993-1996 167,000 372,000
Revolving Credit and Term Loan Agreements (d) 1995-1997 425,000 525,000
Pollution Control Notes (e) 1997-2025 65,565 173,700
Debentures 10.05% - 11% 1993-2011 62,000 87,000
Medium-Term Notes (f) 1994-2005 150,000 150,000
Sinking Fund Debentures --
PECO Energy Power Company, a Subsidiary 4 1/2% 1995 10,550 11,350
Unamortized Debt Discount and Premium, Net (41,114) (28,958)
Total Long-Term Debt 5,136,606 5,302,959
Due Within One Year (g) 252,263 98,998
Long-Term Debt included in Capitalization (h) $ 4,884,343 $5,203,961
(a) Utility Plant is subject to the lien of the Company's mortgage.
(b) Floating rates, which were an average annual interest rate of 2.40% at
December 31, 1993.
(c) The Company has entered into interest rate swap agree-ments to fix the
effective interest rates on certain of these notes. At December 31, 1993
and 1992, the Company had two and three interest rate swap agreements
outstanding with commercial banks, for a total notional principal amount
of $167 and $242 million, respectively. These agreements are subject to
performance by the commercial banks, which are counterparties to the
interest rate swaps. However, the Company does not anticipate
nonperformance by the counterparties. The annual interest rate for these
notes, giving effect to the interest rate swaps, was 10.61% at December
31, 1993.
140
(d) The Company has a $525 million revolving credit and term loan agreement
with a group of banks. The revolving credit arrangement converts into a
term loan on October 3, 1994. The borrowings are due in six semi-annual
installments with the first payment due six months after the conversion
into the term loan. Interest on outstanding borrowings is based on
specific formulas selected by the Company involving yields on several
types of debt instruments. There is an annual commitment fee of 0.15% on
the unused amount. The average annual interest rate for this revolving
credit agreement was 3.64% at December 31, 1993. The Company also has a
$150 million revolving credit and term loan agree-ment with a group of
banks. The revolving credit agreement converts into a term loan in July
1995 and the commitment terminates in 1997. There is an annual commitment
fee of 0.2% on the unused amount. At December 31, 1993 and 1992, no amount
was outstanding under this agreement.
(e) Floating rates, which were an average annual interest rate of 2.24% at
December 31, 1993.
(f) Medium-term notes collateralized by mortgage bonds. The average annual
interest rate was 7.61% at December 31, 1993.
(g) Long-term debt maturities, including mandatory sink-ing fund requirements,
in the period 1995-1998 are as follows: 1995-$201,213,000; 1996-
$393,463,000; 1997-$266,463,000; 1998-$241,463,000.
(h) The annualized interest on long-term debt at December 31, 1993, was $368
million, of which $326 million was associated with mortgage bonds and $42
million was associated with other long-term debt.
11. Short-Term Debt
(Thousands of Dollars) 1993 1992 1991
Average Borrowings $113,193 $50,161 $13,493
Average Interest Rates, Computed
on Daily Basis 3.35% 3.72% 6.17%
Maximum Borrowings Outstanding $368,400 $255,500 $81,000
Average Interest Rates at December 31 3.45% 3.72% ----
At December 31, 1993, the Company had formal and informal lines of credit with
banks aggregating $351 million against which $119 million of short-term debt
was outstanding. The Company does not have formal compensating balance
arrangements with these banks. The Company has a $150 million commercial paper
program and at December 31, 1993, there was no commercial paper outstanding.
141
12. Income Taxes
(Thousands of Dollars) 1993 1992 1991
Included in Operating Income:
Federal
Current $117,535 $131,054 120,646
Deferred 113,054 66,281 67,914
Investment Tax Credit, Net 43,344 (3,495) 58,078
State
Current 70,740 78,546 71,516
Deferred 9,718 (7,903) (9,209)
354,391 264,483 308,945
Included in Other Income and Deductions:
Federal
Current (3,650) (45,295) (1,957)
Deferred 15,926 20,237 16,483
State
Current (1,615) (18,430) (732)
Deferred 1,147 3,328 2,648
11,808 (40,160) 16,442
Total $366,199 $224,323 $325,387
In accordance with SFAS No. 109, the Company has also recorded an additional
accumulated net deferred income tax liability and pursuant to SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation," a corresponding
recoverable deferred income tax asset of $2.3 billion at December 31, 1993,
representing primarily the cumulative amount of federal and state income taxes
associated with the elimination of the net-of-tax AFUDC accounting
methodology.
The $2.3 billion accumulated net deferred income tax liability reflects the
tax effect of anticipated revenues and reverses as the related temporary
differences reverse over the life of the related depreciable assets concurrent
with the recovery of their cost in rates.
Also included in the accumulated deferred income tax liability are other
accumulated deferred income taxes, principally associated with liberalized tax
depreciation, established in accordance with the ratemaking policies of the
PUC based on flow-through accounting.
ITC and other general business credits reduced federal income taxes
currently payable by $60, $41 and $71 million in 1993, 1992 and 1991,
respectively. Under the Tax Reform Act of 1986, ITC was repealed effective
January 1, 1986 with the exception of transition property. The Company
believes that Limerick Unit No. 2 qualifies as transition property eligible
for ITC.
Approximately $36 million of additional business credits generated from 1988
through 1992 have not been utilized due to limitations based on taxable
income. These credits, which expire between 2003 and 2007, may be used to
reduce federal income taxes in future years.
The Internal Revenue Service (IRS) has completed its examinations of the
Company's federal income tax returns through 1986. The 1987 federal income tax
return has not been audited and the 1988 through 1990 federal income tax
returns are currently under examination.
For the years 1987 through 1990, the Company's current tax liability was
determined under the AMT method resulting in a cumulative tax credit of $176
million which can be utilized in future years when regular tax liability
exceeds AMT liability.
142
The tax effect of temporary differences which give rise to the Company's net
deferred tax liability as of December 31, 1993 are as follows:
(Millions of Dollars) Liability
Nature of Temporary Difference: or (Asset)
Utility Plant
Accelerated Depreciation $1,270
Deferred Investment Tax Credits 346
AMT Credits (176)
Other Plant Related Temporary Differences 1,335
Taxes Recoverable Through Future Rates, Net 980
Deferred Debt Refinancing Costs 142
Other, Net (155)
Deferred Income Taxes per the Balance Sheet $3,742
The net deferred tax liability shown above is comprised of $4.182 billion of
deferred tax liabilities partly offset by $440 million of deferred tax assets.
The Omnibus Budget Reconciliation Act of 1993 changed the federal income tax
rate for corporations to 35% from 34%, effective January 1, 1993. This change
resulted in an $8 million increase in Income Taxes in the Consolidated
Statement of Income for the year ended December 31, 1993. This change also
resulted in a $107 million increase in the Deferred Income Taxes liability on
the December 31, 1993 Consolidated Balance Sheet, because the Company expects
to receive recovery of all taxes when paid.
Provisions for deferred income taxes consist of the tax effects of the
following timing differences:
(Thousands of Dollars) 1993 1992 1991
Depreciation and Amortization $ 78,324 $93,469 $89,760
Deferred Energy Costs 19,013 (18,033) (19,916)
Early Retirement Plan ---- 1,865 16,024
Incremental Nuclear Maintenance and
Refueling Outage Costs (827) (1,627) (5,629)
Uncollectible Accounts 625 (2,629) (7,750)
Reacquired Debt 28,959 39,123 18,688
Unrecovered Revenue (806) (56,050) (43,983)
Alternative Minimum Tax ---- ---- 6,331
Limerick Plant Disallowances and
Phase-In Plan 17,073 15,118 16,634
Other (2,516) 10,707 7,677
Total $139,845 $81,943 $77,836
143
The total income tax provisions differed from amounts computed by applying the
federal statutory tax rate to income and adjusted income before income taxes
as shown below:
(Thousands of Dollars) 1993 1992 1991
Net Income $590,648 $478,941 $534,680
Total Income Tax Provisions 366,199 224,323 325,387
Income Before Income Taxes 956,847 703,264 860,067
Deduct: Allowance for Funds Used
During Construction 23,774 20,663 23,084
Adjusted Income Before Income Taxes $933,073 $682,601 $836,983
Income Taxes on Above at Federal Statutory
Rate of 35% in 1993 and 34% in 1992 and 1991 $326,576 $232,084 $284,574
Increase (Decrease) due to:
Depreciation Timing Differences Not Normalized 9,721 10,427 15,258
Limerick Plant Disallowances and Phase-In Plan 5,094 2,159 3,490
Unbilled Revenues Not Normalized ---- (5,766) 5,620
State Income Taxes, Net of Federal
Income Tax Benefits 51,994 36,657 42,387
Amortization of Investment Tax Credits (13,470) (24,624) (17,030)
Prior Period Income Taxes (3,942) (20,655) (13,227)
Other, Net (9,774) (5,959) 4,315
Total Income Tax Provisions $366,199 $224,323 $325,387
Provisions for Income Taxes as a Percent of:
Income Before Income Taxes 38.3% 31.9% 37.8%
Adjusted Income Before Income Taxes 39.2% 32.9% 38.9%
13. Taxes, Other Than Income - Operating
(Thousands of Dollars) 1993 1992 1991
Gross Receipts $155,407 $158,314 $158,719
Capital Stock 38,990 28,013 34,924
Real Estate 71,445 63,593 43,023
Payroll 31,490 29,410 31,439
Other 800 2,538 6,456
Total $298,132 $281,868 $274,561
14. Leases
Leased property included in Utility Plant at December 31, was as follows:
(Thousands of Dollars) 1993 1992
Nuclear Fuel $448,203 $471,276
Electric Plant 2,169 2,234
Gross Leased Property 450,372 473,510
Accumulated Amortization (255,670) (263,516)
Net Leased Property $194,702 $209,994
144
The nuclear fuel obligation is amortized as the fuel is consumed. Amortization
of leased property totalled $58, $55 and $59 million for the years ended
December 31, 1993, 1992 and 1991, respectively. Other operating expenses
included interest on capital lease obligations of $8, $7 and $10 million in
1993, 1992 and 1991, respectively. Minimum future lease payments as of
December 31, 1993 were:
Year Ending December 31, Capital Operating
(Thousands of Dollars) Leases Leases Total
1994 $70,413 $97,982 $168,395
1995 65,988 96,821 162,809
1996 59,273 60,501 119,774
1997 18,220 59,538 77,758
1998 92 55,861 55,953
Remaining Years 1,181 616,834 618,015
Total Minimum Future Lease Payments $215,167 $987,537 $1,202,704
Imputed Interest (rates ranging from
6.5% to 17.0%) (20,465)
Present Value of Net Minimum Future
Lease Payments $194,702
Rental expense under operating leases totalled $99, $94 and $89 million in
1993, 1992 and 1991, respectively.
15. Jointly Owned Electric Utility Plant
The Company's ownership interests in jointly owned electric utility plant at
December 31, 1993 were as follows:
Transmission and
Production Plants Other Plant
Peach
Bottom Salem Keystone Conemaugh
Operator PECO Public Service Pennsylvania Pennsylvania
Energy Electric and Electric Electric Various
Company Gas Company Company Company Companies
Participating Interest 42.49% 42.59% 20.99% 20.72% 21% to 43%
Company's share of (Thousands of Dollars)
Utility Plant 708,532 $1,174,379 $86,742 $91,299 $87,809
Accumulated Depreciation 253,057 370,825 42,735 43,443 26,795
Construction Work in Progress 21,764 40,562 10,850 54,252 991
The Company's participating interests are financed with Company funds and,
when placed in service, all operations are accounted for as if such
participating interests were wholly owned facilities.
On April 2, 1992, the United States District Court for the District of New
Jersey approved a settlement of the lawsuits filed against the Company by the
other co-owners of Peach Bottom concerning the 1987 shutdown of Peach Bottom
ordered by the NRC. As part of the settlement, the Company paid $131 million
to the other co-owners on October 1, 1992 and the Company recognized a charge
against income ($76 million, net of taxes) in the first quarter of 1992.
145
In 1990, the Company received net proceeds of $28 million ($16 million, net
of taxes) in settlement of a shareholders' derivative suit in connection with
the 1987 Peach Bottom shutdown. Recognition of the $28 million had been
deferred pending the resolution of the co-owners' litigation. As a result of
the settlement of the co-owners' litigation, the $28 million was recognized as
other income in the first quarter of 1992 and reported as an offset against
the amount of the above-mentioned charge relating to the settlement of the co-
owners' litigation.
16. Segment Information
(Thousands of Dollars) 1993 1992 1991
Electric Operations
Operating Revenues $3,605,425 $3,597,141 $3,662,573
Operating Expenses, excluding
Depreciation 2,228,507 2,236,907 2,253,159
Depreciation 400,851 90,846 379,607
Operating Income $976,067 $969,388 $1,029,807
Utility Plant Additions $458,125 $461,407 $422,780
Gas Operations
Operating Revenues $382,704 $365,328 $356,013
Operating Expenses, excluding
Depreciation 299,259 278,407 283,665
Depreciation 24,101 22,933 20,965
Operating Income $59,344 $63,988 $51,383
Utility Plant Additions $72,481 $74,858 $55,098
Identifiable Assets*
Electric $10,395,488 $10,393,449 $10,213,296
Gas 727,690 658,825 590,151
Nonallocable Assets 3,909,149 1,525,953 1,720,013
Total Assets $15,032,327 $12,578,227 $12,523,460
*Includes Utility Plant less accumulated depreciation, inventories and
allocated common utility property.
17. Cash and Cash Equivalents
For purposes of the Statements of Cash Flows, the Company considers all highly
liquid debt instruments purchased with a maturity of three months or less to
be cash equivalents. The following disclosures supplement the accompanying
Statements of Cash Flows:
(Thousands of Dollars) 1993 1992 1991
Cash Paid During the Year:
Interest (net of amount capitalized) $474,735 $515,696 $551,944
Income taxes (net of refunds) 182,751 224,352 193,340
Noncash Investing and Financing:
Capital lease obligations incurred 42,484 40,757 41,905
146
18. Investments
(Thousands of Dollars) December 31,
1993 1992
Trusts and Escrow Deposits for Decommissioning
Nuclear Plants $149,932 $125,703
Real Estate Developments and Other Ventures 46,741 48,273
Nonutility Property 21,262 23,141
Gas Exploration and Development Joint Ventures 625 5,026
Other Deposits 76 279
Total $218,636 $202,422
19. Financial Instruments
SFAS No. 107, "Disclosure About Fair Value of Financial Instruments,"
requires additional disclosure about the fair value of financial instruments,
including liabilities, for which it is practicable to estimate fair value.
Fair values are estimated based on quoted market prices for the same or
similar issues. The carrying amounts and fair values of the Company's
financial instruments as of December 31, 1993 and 1992 were as follows:
1993 1992
Carrying Fair Carrying Fair
(Thousands of Dollars) Amount Value Amount Value
Cash and Temporary Cash Investments $46,923 $46,923 $50,369 $50,369
Long-Term Debt
(including amounts due within one year) 5,136,606 5,375,427 5,302,959 5,546,896
Trusts and Escrow Accounts
for Decommissioning Nuclear Plants 149,932 160,141 125,703 131,138
Financial instruments which potentially subject the Company to concentrations
of credit risk consist principally of temporary cash investments and customer
accounts receivable. The Company places its temporary cash investments with
high-credit, quality financial institutions. At times, such investments may be
in excess of the Federal Depository Insurance Corporation limit.
Concentrations of credit risk with respect to customer accounts receivable are
limited due to the Company's large number of customers and their dispersion
across many industries.
20. Nuclear Fuel Agreement with Long Island Power Authority (LIPA)
On March 1, 1993, the Company entered into an agreement with LIPA and other
parties, subsequently revised on September 14, 1993, to receive $46 million as
compensation for accepting slightly irradiated nuclear fuel from Shoreham
Nuclear Power Station. The Company is to receive the $46 million in
installments as the shipments of nuclear fuel are accepted. The first of the
thirty-three shipments arrived at Limerick on September 28, 1993. As of
December 31, 1993, the Company had received 18 shipments of the nuclear fuel.
The payments from LIPA, in excess of related costs, are being recognized in
income. The Company recognized $20 million as other income in the Consolidated
Statement of Income for the year ended December 31, 1993, and deferred $6
million of payments received on the December 31, 1993 Consolidated Balance
Sheet, pursuant to this agreement. The Company estimates that the acquisition
of the fuel will result in benefits to the Company's customers of $70 million
over the next 12 to 15 years due to reduced fuel-purchase requirements.
147
21. Quarterly Data (Unaudited)
The data shown below include all adjustments which the Company considers
necessary for a fair presentation of such amounts:
(Thousands of Dollars) Operating Revenues Operating Income Net Income
Quarter Ended 1993 1992 1993 1992 1993 1992
March 31 $1,071,492 $1,079,890 $281,734 $274,580 $162,356 $ 88,401
June 30 901,703 903,245 223,196 222,426 107,691 94,325
September 30 1,073,134 996,138 290,937 268,699 181,683 142,338
December 31 941,800 983,196 239,544 267,671 138,918 153,877
Earnings Applicable Average Shares Earnings
(Thousands of Dollars) to Common Stock Outstanding Per Average Share
Quarter Ended 1993 1992 1993 1992 1993 1992
March 31 $149,305 $ 72,013 220,609 220,068 $0.68 $0.33
June 30 94,540 78,207 220,856 220,170 0.43 0.35
September 30 169,727 128,754 221,318 220,327 0.77 0.59
December 31 128,018 139,236 221,493 220,411 0.58 0.63
1992 first quarter results include a net charge of $103 million ($60
million, net of taxes), or $0.27 per share, as a result of the settlement of
the litigation concerning the 1987 shutdown of Peach Bottom (see note 15).
1992 fourth quarter results include a net benefit of $24 million, or $0.11
per share, as a result of the settlement of the Company's 1984-1986 federal
income tax returns.
148
FINANCIAL STATISTICS
Summary of Earnings and Financial Condition (Millions of Dollars)
For the Year Ended 1993 1992 1991 1990 1989 1988
Operating Revenues $3,988.1 $3,962.5 $4,018.6 $3,786.7 $3,473.8 $3,246.3
Operating Income 1,035.4 1,033.4 1,081.2 767.7 809.3 742.6
Income from Continuing
Operations 590.6 478.9 534.7 105.8 590.5 566.0
Net Income 590.6 478.9 534.7 214.2 590.5 566.0
Earnings Applicable
to Common Stock 541.6 418.2 468.6 123.9 493.9 468.8
Earnings Per Average
Common Share From Continuing
Operations (Dollars) 2.45 1.90 2.15 0.07 2.36 2.33
Earnings Per Average Common
Share (Dollars) 2.45 1.90 2.15 0.58 2.36 2.33
Dividends Per Common
Share (Dollars) 1.43 1.325 1.225 1.45 2.20 2.20
Common Stock Equity (Per Share) 19.25 18.24 17.69 16.71 17.67 17.39
Average Shares of Common Stock
Outstanding (Millions) 221.1 220.2 218.2 214.4 208.9 201.5
At December 31
Net Utility Plant,
at Original Cost $10,763.0 $10,691.2 $10,598.4 $10,591.3 $10,720.8 $10,048.5
Leased Property, Net 194.7 210.0 223.8 241.3 273.5 287.5
Total Current Assets 514.8 550.0 783.2 745.0 655.0 502.5
Total Deferred Debits
and Other Assets 3,559.8 1,127.0 918.1 938.6 972.8 953.9
Total Assets $15,032.3 $12,578.2 $12,523.5 $12,516.2 $12,622.1 $11,792.4
Common Shareholders' Equity $ 4,263.4 $ 4,022.2 $ 3,892.3 $ 3,624.5 $ 3,744.8 $ 3,592.6
Preferred and Preference Stock
Without Mandatory Redemption 422.5 422.5 422.5 422.5 622.4 622.4
With Mandatory Redemption 186.5 231.1 315.6 330.9 351.1 368.1
Long-Term Debt 4,884.3 5,203.9 5,415.6 5,830.8 5,762.7 5,219.5
Total Capitalization 9,756.7 9,879.7 10,046.0 10,208.7 10,481.0 9,802.6
Total Current Liabilities 954.6 830.6 823.4 783.8 790.5 662.4
Total Deferred Credits and
Other Liabilities 4,321.0 1,867.9 1,654.1 1,523.7 1,350.6 1,327.4
Total Capitalization
and Liabilities $15,032.3 $12,578.2 $12,523.5 $12,516.2 $12,622.1 $11,792.4
149
OPERATING STATISTICS
Electric Operations
1993 1992 1991 1990 1989 1988
Output (Millions of Kilowatthours)
Fossil 10,352 8,082 7,376 7,913 10,470 10,225
Nuclear 27,026 24,428 25,735 23,715 12,890 12,328
Hydro 1,699 1,803 1,388 2,266 1,743 1,307
Pumped Storage Output 1,478 1,597 1,653 1,437 1,354 1,515
Pumped Storage Input (2,192) (2,217) (2,355) (2,059) (1,937) (2,163)
Purchase and Interchange 6,447 8,675 8,603 5,787 11,192 11,802
Internal Combustion 56 29 79 152 348 285
Other ---- ---- ---- 180 1,063 ----
Total Electric Output 44,866 42,397 42,479 39,391 37,123 35,299
Sales (Millions of Kilowatthours)
Residential 10,657 9,894 10,311 9,815 9,974 10,058
Small Commercial and Industrial 5,773 5,367 5,284 5,066 4,921 4,666
Large Commercial and Industrial 15,935 15,770 16,177 16,554 16,749 16,516
Other 771 962 1,029 1,010 1,031 999
Service Territory 33,136 31,993 32,801 32,445 32,675 32,239
Interchange Sales 457 1,231 1,612 2,751 2,027 435
Sales to Other Utilities 8,670 6,699 5,445 1,865 ---- ----
Total Electric Output 42,263 39,923 39,858 37,061 34,702 32,674
Number of Customers, December 31
Residential 1,341,873 1,333,926 1,324,795 1,320,126 1,309,717 1,296,784
Small Commercial
and Industrial 142,363 141,253 140,901 140,305 138,244 135,274
Large Commercial and Industrial 3,742 3,972 4,162 4,344 4,449 4,520
Other 888 857 840 817 775 779
Total Electric Customers 1,488,866 1,480,008 1,470,698 1,465,592 1,453,185 1,437,357
Operating Revenues (Millions of Dollars)
Residential $ 1,354.1 $ 1,304.5 $ 1,342.3 $ 1,229.8 $ 1,157.0 $ 1,127.8
Small Commercial
and Industrial 678.9 669.8 641.0 595.2 537.1 489.4
Large Commercial
and Industrial 1,164.0 1,223.2 1,278.9 1,247.1 1,182.0 1,089.3
Other 161.2 168.0 170.4 166.9 143.9 143.8
Service Territory 3,358.2 3,365.5 3,432.6 3,239.0 3,020.0 2,850.3
Interchange Sales 14.3 32.1 42.8 81.5 68.2 17.6
Sales to Other Utilities 232.9 199.5 187.2 81.1 ---- ----
Total Electric Revenues $ 3,605.4 $ 3,597.1 $ 3,662.6 $ 3,401.6 $ 3,088.2 $ 2,867.9
Operating Expenses (Millions of Dollars)
Operating Expenses, excluding
Depreciation $ 2,228.5 $ 2,236.9 $ 2,253.2 $ 2,325.2 $ 2,077.4 $ 1,931.3
Depreciation 400.8 390.8 379.6 337.7 257.4 245.5
Total Operating Expenses $ 2,629.3 $ 2,627.7 $ 2,632.8 $ 2,662.9 $ 2,334.8 $ 2,176.8
Electric Operating Income $ 976.1 $ 969.4 $ 1,029.8 $ 738.7 $ 753.4 $ 691.1
Average Use per Residential Customer
(kilowatthours)
Without Electric Heating 6,727 6,259 6,707 6,376 6,488 6,667
With Electric Heating 17,096 16,298 16,201 16,038 17,250 17,738
Total 7,970 7,443 7,801 7,464 7,655 7,807
Electrical Peak Load, Demand
(thousands of kilowatts) 7,100 6,617 7,096 6,755 6,467 6,826
Net Electric Generating Capacity --
Year-End Summer Rating
(thousands of kilowatts) 8,877 8,836 8,766 8,766 7,759 7,762
Cost of Fuel per Million Btu $ 0.90 $ 0.82 $ 0.92 $ 1.13 $ 1.37 $ 1.19
Btu per Net
Kilowatthour Generated 10,675 10,657 10,849 10,844 10,894 10,881
150
OPERATING STATISTICS
Gas Operations
1993 1992 1991 1990 1989 1988
Sales (Millions of Cubic Feet)
Residential 1,637 1,819 1,746 1,778 1,951 1,933
House Heating 30,687 29,750 26,423 25,303 28,301 28,112
Commercial and Industrial 22,943 21,497 20,492 23,228 30,038 39,073
Other 5,656 2,146 534 1,567 2,344 2,228
Total Gas Sales 60,923 55,212 49,195 51,876 62,634 71,346
Gas Transported for Customers 22,946 22,060 21,414 24,413 18,033 9,272
Total Gas Sales & Transported 83,869 77,272 70,609 76,289 80,667 80,618
Number of Customers, December 31
Residential 59,573 59,859 62,444 63,267 65,544 66,599
House Heating 277,500 269,577 260,473 254,564 246,273 239,022
Commercial and Industrial 31,573 30,956 30,204 29,456 28,369 27,119
Total Gas Customers 368,646 360,392 353,121 347,287 340,186 332,740
Operating Revenues (Millions of Dollars)
Residential $ 15.0 $ 16.4 $ 17.0 $ 18.1 $ 18.0 $ 17.0
House Heating 205.5 201.9 192.4 200.8 195.8 180.6
Commercial and Industrial 124.2 121.1 123.6 144.7 152.5 165.1
Other 15.2 2.8 2.2 5.6 7.3 6.6
Subtotal $ 359.9 $ 342.2 $ 335.2 $ 369.2 $ 373.6 $ 369.3
Other Revenues (including Transported
for Customers) 22.8 23.1 20.8 15.8 12.1 9.1
Total Gas Revenues $ 382.7 $ 365.3 $ 356.0 $ 385.0 $ 385.7 $ 378.4
Operating Expenses (Millions of Dollars)
Operating Expenses,
excluding Depreciation $ 299.3 $ 278.4 $ 283.7 $ 336.2 $ 310.2 $ 308.3
Depreciation 24.1 22.9 21.0 19.8 19.6 18.6
Total Operating Expenses $ 323.4 $ 301.3 $ 304.7 $ 356.0 $ 329.8 $ 326.9
Gas Operating Income
(Millions of Dollars) $ 59.3 $ 64.0 $ 51.3 $ 29.0 $ 55.9 $ 51.5
Securities Statistics
Ratings on PECO Energy Company's Securities
Mortgage Bonds Debentures Preferred Stock
Agency Rating Date Established Rating Date Established Rating Date Established
Duff and Phelps, Inc. BBB+ 4/92 BBB 4/92 BBB- 8/91
Fitch Investors Service, Inc. A- 9/92 BBB+ 9/92 BBB+ 9/92
Moody's Investors Service Baal 4/92 Baa2 4/92 baa2 4/92
Standard & Poor's Corporation BBB+ 4/92 BBB 4/92 BBB 4/92
NYSE-Composite Common Stock Prices, Earnings and Dividends By Quarter (Per
Share)
1993 1992
Fourth Third Second First Fourth Third Second First
Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter
High Price $32-7/8 $33-1/2 $31-1/8 $30-3/8 $26-3/4 $26-3/4 $26-5/8 $26
Low Price $27-3/8 $30-3/8 $27-3/4 $25-1/2 $25 $25 $23-5/8 $22-5/8
Close $30-1/4 $32-3/4 $30-5/8 $30 $26-1/8 $26-3/8 $26-3/8 $24-5/8
Earnings 58c 77c 43c 68c 63c 59c 35c 33c
Dividends 38c 35c 35c 35c 35c 32.5c 32.5c 32.5c