Exhibit (99)
Commonwealth Edison Company
Form 10-K File No. 1-1839
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 8-K/A-1
CURRENT REPORT
Pursuant to Section l3 or l5(d) of
the Securities Exchange Act of l934
Date of Report (Date of
earliest event reported): January 28, 1994
Commonwealth Edison Company
(Exact name of registrant as specified in its charter)
Illinois 1-1839 36-0938600
(State or other (Commission (IRS Employer
jurisdiction of File Number) Identification No.)
incorporation)
37th Floor, One First National Plaza,
Post Office Box 767, Chicago, Illinois 60690-0767
(Address of principal executive offices) (Zip Code)
Registrant's telephone number,
including area code: (312) 394-4321
The purpose of this Amendment No. 1 is to amend the exhibits to the
Registrant's (Commonwealth Edison Company) Current Report on Form 8-K dated
January 28, 1994, by refiling those exhibits in their entirety.
Item 7. Financial Statements, Pro Forma Financial
- ------- Information and Exhibits
-----------------------------------------
(c) Exhibits
--------
(23) Consent of Independent Public Accountants
(99) Commonwealth Edison Company and Subsidiary Companies -
Certain Financial Information as of and for the Year
Ended December 31, 1993:
--Management's Discussion and Analysis of Financial
Condition and Results of Operations
--Statements of Consolidated Income
--Consolidated Balance Sheets
--Statements of Consolidated Capitalization
--Statements of Consolidated Cash Flows
--Statements of Consolidated Retained Earnings
--Statements of Consolidated Premium on Common Stock
and Other Paid-in Capital
--Notes to Financial Statements
--Report of Independent Public Accountants
-2-
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
COMMONWEALTH EDISON COMPANY
(Registrant)
By: /s/ John C. Bukovski
--------------------------
John C. Bukovski
Vice President
Date: March 18, 1994
-3-
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
- ------ ----------------------
23 Consent of Independent Public Accountants
99 Commonwealth Edison Company and Subsidiary
Companies - Certain Financial Information as of
and for the Year Ended December 31, 1993:
--Management's Discussion and Analysis of
Financial Condition and Results of Operations
--Statements of Consolidated Income
--Consolidated Balance Sheets
--Statements of Consolidated Capitalization
--Statements of Consolidated Cash Flows
--Statements of Consolidated Retained Earnings
--Statements of Consolidated Premium on Common
Stock and Other Paid-in Capital
--Notes to Financial Statements
--Report of Independent Public Accountants
Exhibit (23)
Commonwealth Edison Company
Form 8-K/A-1 File No. 1-1839
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
-----------------------------------------
As independent public accountants, we hereby consent to the incorporation by
reference of our report dated March 18, 1994, on Commonwealth Edison Company and
subsidiary companies' consolidated financial statements as of and for the year
ended December 31, 1993, included as an Exhibit to this Form 8-K/A-1 Current
Report of Commonwealth Edison Company dated January 28, 1994, into Commonwealth
Edison Company's previously filed prospectuses as follows: (1) prospectus dated
June 1, 1988, constituting part of Form S-8 Registration Statement File No. 2-
76921 (relating to the Company's Employe Stock Purchase Plan); (2) prospectus
dated August 1, 1992, constituting part of Form S-8 Registration Statement File
Nos. 2-81592 and 33-5061, as amended (relating to the Company's Employe Savings
and Investment Plan); (3) prospectus dated August 21, 1986, constituting part of
Form S-3 Registration Statement File No. 33-6879, as amended (relating to the
Company's Debt Securities and Common Stock); (4) prospectus dated February 14,
1991, constituting part of Form S-3 Registration Statement File No. 33-38233
(relating to the Company's Debt Securities and Cumulative Preference Stock); (5)
prospectus dated January 7, 1994, constituting part of Form S-3 Registration
Statement File No. 33-51379 (relating to the Company's Debt Securities and
Cumulative Preference Stock); and (6) prospectus constituting part of Form S-4
Registration Statement File No. 33-52109, as amended (relating to Common Stock
of CECo Holding Company). We also consent to the application of our report to
the ratios of earnings to fixed charges and the ratios of earnings to fixed
charges and preferred and preference stock dividend requirements for each of the
years ended December 31, 1993, 1992 and 1991 appearing on page 22 of Exhibit 99
of this Form 8-K/A-1.
ARTHUR ANDERSEN & CO.
Chicago, Illinois
March 18, 1994
Exhibit (99)
Commonwealth Edison Company
Form 8-K File No. 1-1839
Management's Discussion and Analysis of Financial Condition and Results of
Operations
- ---------------------
Liquidity and Capital Resources
Capital Budgets. Commonwealth Edison Company (Company) and its
electric utility subsidiary, Commonwealth Edison Company of Indiana,
Inc. (collectively, companies), have a construction program for the
three-year period 1994-96 which consists principally of improvements
to the companies' existing nuclear and other electric production,
transmission and distribution facilities. It does not include funds
(other than for planning) to add new generating capacity to the
Company's system. The program, as approved by the Company in January
1994, calls for electric plant and equipment expenditures of
approximately $2,450 million (excluding nuclear fuel expenditures of
approximately $780 million). This amount reflects a decrease of
approximately $200 million compared with the common years (1994-95) of
the previously approved construction program. In part, the decrease
reflects a reduction in capital spending announced by the Company in
July 1992 due to adverse financial circumstances. For additional
information concerning the cost reduction plan, see "Rates and
Financial Condition" below. It is estimated that such construction
expenditures, with cost escalation computed at 4% annually, will be as
follows:
Three-Year
(millions of dollars) 1994 1995 1996 Total
----------------------------- ---- ---- ---- ----------
Production $295 $310 $250 $ 855
Transmission and Distribution 340 445 505 1,290
General 115 95 95 305
---------------------------------------------------------
Total $750 $850 $850 $2,450
---------------------------------------------------------
The Company's forecasts of peak load indicate a need for additional
resources to meet demand, either through generating capacity or
through equivalent purchased power or demand-side management
resources, in 1997 and each year thereafter through the year 2000. The
projected resource needs reflect the current planning reserve margin
recommendations of the Mid-America Interconnected Network (MAIN), the
reliability council of which the Company is a member. The Company's
forecasts indicate that the additional resource need during this
period would exist only during the summer months. The Company does not
expect to make expenditures for additional capacity to the extent the
need for capacity can be met through cost-effective demand-side
management resources, non-utility generation or other power purchases.
To assess the market potential to provide such cost-effective
resources, the Company solicited proposals to supply it with cost-
effective demand-side management resources, non-utility generation
resources and other-utility power purchases sufficient to meet
forecasted requirements through the year 2000. The responses to the
solicitation suggest that adequate resources to meet the Company's
needs could be obtained from those sources but the Company has not yet
determined whether those sources represent the most economical
alternative. If the Company were to build additional capacity to meet
its needs, it would need to make additional expenditures during the
1994-96 period.
The Company has not budgeted for a number of projects, particularly
at generating stations, which could be required, but which the Company
does not expect to be required during the budget period. In
particular, the Company has not budgeted for the construction of
scrubbers at its Kincaid generating station, for the replacement of
major amounts of piping at its boiling water reactor nuclear stations
or for the replacement of steam generators at its pressurized water
reactor nuclear stations.
10
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Purchase commitments, principally related to construction and
nuclear fuel, approximated $1,187 million at December 31, 1993. In
addition, the Company has substantial commitments for the purchase of
coal under long-term contracts as indicated in the following table.
Contract Period Commitment (1)
----------------------------------------------- --------- --------------
Black Butte Coal Co. 1994-2007 $1,212
Decker Coal Co. 1994-2015 $ 862
Peabody Coal Co. 1994 $ 34
Big Horn Coal Co. 1998 $ 21
-------------------------------------------------------------------------
(1) Estimated costs in millions of dollars FOB mine. No estimate of
future cost escalation has been made.
For additional information concerning these coal contracts and the
Company's fuel supply, see "Results of Operations" below and Notes 3,
17 and 19 of Notes to Financial Statements.
The construction program will be reviewed and modified as necessary
to adapt to changing economic conditions, rate levels and other
relevant factors including changing business and legal needs and
requirements. The Company cannot anticipate all such possible needs
and requirements. While regulatory needs in particular are more
likely, on balance, to require increases in construction expenditures
than decreases, the Company's financial condition may require
compensating or greater reductions in other construction expenditures.
See "Rates and Financial Condition" below for additional information
concerning the construction program.
Capital Resources. The Company has forecast that internal sources will
provide approximately one-half of the funds required for its
construction program and other capital requirements, including nuclear
fuel expenditures, contributions to nuclear decommissioning trusts,
sinking fund obligations and refinancing of scheduled debt maturities
(the annual sinking fund requirements for preference stock and
long-term debt are summarized in Notes 7 and 8
of Notes to Financial Statements). The
forecast takes into account the rate reduction
The construction program reflected in the Rate Matters Settlement
budget for 1994-96 (described below), and reflects the payments
reflects a decrease of required to be made to customers under the
approximately $200 Rate Matters Settlement and the Fuel Matters
million compared with the Settlement (described below).
common years 1994-95 of The type and amount of external financing
the previous construction will depend on financial market conditions and
budget. the needs and capital structure of the Company
at the time of such financing. Although the
Company's new money financing requirements
decreased significantly with the completion of
its nuclear generating capacity construction
program, they have subsequently increased due to higher expenditures and
lower operating cash flows resulting from reduced revenues due to customer
refunds and rate level adjustments ordered in various proceedings related
to the level of the Company's rates and the effect of the Rate Matters
Settlement and the Fuel Matters Settlement. See "Rates and Financial
Condition" below for information related to the Company's reductions to
operation and maintenance expenses and its construction program in
response to adverse regulatory and judicial decisions. A portion of the
Company's financing is expected to be provided through the continued sale
and leaseback of nuclear fuel. The Company has unused bank lines of credit
which may be borrowed at various interest rates and which may be secured
or unsecured. The interest rate is set at the time of a borrowing and is
based on several floating rate bank indices plus a spread which is
dependent upon the Company's credit ratings, or on a prime interest rate.
Collateral, if required for the borrowings, would consist of first
11
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mortgage bonds issued under and in accordance with the provisions of
the Company's mortgage. See Note 9 of Notes to Financial Statements
for information concerning lines of credit. See the Statements of
Consolidated Cash Flows for the construction expenditures and cash
flow from operating activities for the years 1993, 1992 and 1991.
During 1993, the Company issued an aggregate of 421,994 shares of
common stock for approximately $11,462,000 under its employe stock
plans; issued and sold 700,000 shares of $6.875 Cumulative Preference
Stock for approximately $69 million; sold and leased back an aggregate
of approximately $204,254,000 of nuclear fuel; issued $1,715 million
aggregate principal amount of first mortgage bonds; and issued $235
million of other long-term debt. On January 25, 1994, the Company
announced the closing of the sale of $66 million of Pollution Control
Revenue Refunding Bonds issued through the Illinois Development
Finance Authority. The proceeds of the first mortgage bonds issued
during 1993 were or will be used primarily to discharge or refund
outstanding debt securities.
The Company has an effective "shelf" registration statement with
the Securities and Exchange Commission for the future sale of up to an
additional $1,030 million of debt securities and cumulative preference
stock for general corporate purposes of the Company, including the
discharge or refund of other outstanding securities.
Rates and Financial Condition. The Company's financial condition is
dependent upon its ability to generate revenues to cover its costs. To
maintain a satisfactory financial condition, the Company must recover
the costs of and a return on completed construction projects,
including its three most recently completed generating units, and
maintain adequate debt and preferred and preference stock coverages
and common stock equity earnings. The Company has no significant
revenues other than from the sale of electricity. Under the economic
and political conditions prevailing in Illinois, the Company's
management recognizes that competitive and
regulatory circumstances may limit the
Workforce reductions Company's ability to raise its prices.
already implemented, Therefore, the Company's financial condition
combined with other will depend in large measure on the Company's
actions, are estimated to levels of sales, expenses and capital
have saved approximately expenditures. See "Business and Competition"
$130 million in operation below.
and maintenance expenses In response to the adverse regulatory and
during 1993. judicial decisions in the proceedings relating
to the level of the Company's rates, the
Company implemented a cost reduction plan in
1992 involving various management workforce
reductions through early retirement and
voluntary and involuntary separations. Such
reductions, when combined with other actions, are estimated by the Company
to have saved approximately $130 million in operation and maintenance
expenses during 1993. The management workforce reduction resulted in a
charge to income of approximately $23 million (net of income tax effects)
in 1992. In addition, the Company reached agreement in August 1993 with
its unions regarding certain cost reduction actions. The agreement
provides for a wage freeze until April 1, 1994, changes to reduce health
care plan cost, increased use of part-time employment and changes in
holiday provisions. The agreement also includes a continuation of
negotiations relative to other issues. Further, the Company has reduced
planned construction program expenditures by approximately $200 million
compared with the common years (1994-95) of the previously approved
construction program. See "Rate Proceedings" below and Note 12 of Notes to
Financial Statements.
In addition, the quarterly common stock dividends, payable on and
since November 1, 1992, were reduced by 47% from the seventy-five
cents per share amount paid quarterly since 1982 to forty cents
12
per share. Dividends have been declared on the outstanding shares of the
Company's preferred and preference stocks at their regular quarterly rates. The
Company's Board of Directors will continue to review quarterly the payment of
dividends.
The current ratings of the Company's securities by three principal securities
rating agencies are as follows:
----------------------------------------------------------------------
Standard Duff &
Moody's & Poor's Phelps
------- -------- ------
First mortgage and secured pollution control
bonds Baa2 BBB BBB
Publicly-held debentures and unsecured
pollution control obligations Baa3 BBB- BBB-
Convertible preferred stock baa3 BBB- BB+
Preference stock baa3 BBB- BB+
Commercial paper P2 A-2 Duff 2
----------------------------------------------------------------------
The foregoing ratings reflect downgradings during 1992 and in January 1993 as
a result of developments in the proceedings leading to, and the issuance of,
the Illinois Commerce Commission (ICC) rate order issued on January 6, 1993 (as
subsequently modified, the Remand Order). In December 1993, Standard & Poor's
affirmed its ratings of the Company's debt, although on October 27, 1993, it
changed its "outlook" on the Company's ratings from stable to negative as part
of its larger assessment of the electric utility industry. In September 1993,
Moody's and Duff & Phelps affirmed their ratings of the Company's securities,
and in October 1993, Moody's rating outlook on the Company remained stable.
Business and Competition. The electric utility business has historically been
characterized by retail service monopolies in state or locally franchised
service territories. Investor-owned electric utilities have tended to be
vertically integrated with all aspects of their business subject to pervasive
regulation. Although customers have normally been free to supply their electric
power needs through self-generation, they have not had a choice of electric
suppliers and self-generation has not generally been economical.
The market in which electric utilities like the Company operate has become
more competitive and many observers believe competition will intensify. Self-
generation can be economical for certain customers, depending on how and when
they use electricity and other customer-specific considerations. A number of
competitors are currently seeking to identify and do business with those
customers. In addition, suppliers of other forms of energy are increasingly
competing to supply energy needs which historically were supplied primarily or
exclusively by electricity.
The Energy Policy Act of 1992 will likely have a significant effect on
companies engaged in the generation, transmission, distribution, purchase and
sale of electricity. This Act, among other things, expands the authority of the
Federal Energy Regulatory Commission to order electric utilities to transmit or
"wheel" wholesale power for others, and facilitates the creation of non-utility
electric generating companies. Although the Company cannot now predict the full
impact of this Act, it will likely create and increase competition affecting
the Company.
The Company is facing increased competition from several non-utility
businesses which seek to provide energy services to users of electricity,
especially larger customers such as industrial, commercial and wholesale
customers. Such suppliers include independent power producers and unregulated
energy services companies. In this regard, natural gas utilities operating in
the Company's service area have established subsidiary ventures to provide
heating, ventilating and air conditioning services, attempting to attract the
Company's customers. Also, several utilities in the United States have
established unregulated energy services subsidiaries which pursue business
opportunities wherever they exist. In
13
addition, cogeneration and energy services companies have begun
soliciting the Company's customers to provide alternatives to using
the Company's electricity.
On July 13, 1993, legislation became effective in Illinois which
permits the Company to create certain unregulated subsidiaries, and to
form a holding company, without being required to obtain the approval
of the ICC. The legislation gives the Company and its affiliates
flexibility to compete with unregulated competitors to provide energy
services. The Company has created an unregulated subsidiary to engage
in energy service activities and is preparing to obtain necessary
shareholder and Federal regulatory approvals to form a holding
company.
Regulation. The companies are subject to state and federal regulation
in the conduct of their operations. Such regulation includes rates,
securities issuance, nuclear operations, environmental and other
matters. Particularly in the cases of nuclear operations and
environmental matters, such regulation can and does affect the
companies' operational and capital expenditures.
During the past several years, the Nuclear Regulatory Commission
(NRC) has placed two of the Company's nuclear generating stations,
Zion station and Dresden station, on its list of plants to be
monitored closely. Generally, such status can be expected to result,
and has resulted, in increased expenditures to address deficiencies in
station management and/or operations. The Company has restructured its
management of its nuclear stations and committed additional resources
to their operations. The Zion station was removed from the list of
plants to be monitored closely in February 1993; however, the Dresden
station remains on that list. On January 27, 1994, the NRC noted
adverse performance trends at Quad-Cities station as well as at
LaSalle County station. The Company had already identified and was
working to correct most of the problems cited. In addition, the
Company anticipates that it will need to make significant capital
expenditures in future years in connection with certain of its nuclear
generating units.
The Company estimates that it will expend approximately $15 billion for
decommissioning costs primarily during the period from 2007 through 2032.
Such costs, which are estimated to aggregate approximately $4.06 billion,
in current-year (1993) dollars, are expected to be funded by the external
decommissioning trust funds which the Company established in compliance
with Illinois law and into which the Company has been making annual
contributions. See Note 1 of Notes to Financial Statements under
"Depreciation" for additional information regarding decommissioning
costs.
The Clean Air Act Amendments of 1990 (Amendments) will require
reductions in sulfur dioxide emissions from the Company's Kincaid
station. The Amendments also bar future utility sulfur dioxide
emissions except to the extent utilities hold allowances for their
emissions. Allowances which authorize their holder to emit sulfur
dioxide will be issued by the United States Environmental Protection
Agency based largely on historical levels of sulfur dioxide emissions.
These allowances will be transferable and marketable. The Company's
ability to increase generation in the future to meet expected
increased demand for electricity will depend in part on the Company's
ability to acquire additional allowances or to reduce emissions below
otherwise allowable levels from its existing generating plants. In
addition, the Amendments require studies to determine what controls,
if any, should be imposed on utilities to control air toxic emissions,
including mercury. The Company's Clean Air Compliance Plan for Kincaid
station was approved by the ICC on July 8, 1993. In late 1993,
however, a federal court declared the Illinois law under which the
approval was received to be unconstitutional and compliance plans
prepared and approved in reliance on the law to be void. Under the
Plan approved by the ICC, the Company would have been allowed to burn
low sulfur Illinois coal at Kincaid station without the installation
of pollution control equipment for the years 1995 through 1999, and to
purchase any necessary emission allowances that are expected to be
available under the Amendments during this period. Also, under the
Plan, the Company expected to install pollution control equipment for
Kincaid station by the year 2000. When the final outcome of the
federal litigation is known, the Company will determine whether any
changes are required.
The Amendments also will require reductions in nitrogen oxide
emissions from the Company's fossil fuel generating units. The
Illinois Environmental Protection Agency has proposed rules with
respect to such emissions which would require modifications to certain
of the Company's boilers. The Company's construction program for the
three-year period 1994-96 includes $25 million for such modifications.
14
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Capital Structure. The Company's ratio of long-term debt to total
capitalization has increased to 55.0% at December 31, 1993 from 54.0%
at December 31, 1992. This increase is related primarily to the
decrease in retained earnings resulting principally from the recording
in 1993 of the settlements discussed in "Rate Proceedings" below.
- ------------
Rate Proceedings
The Company's revenues, net income, cash flows and plant carrying
costs have been affected directly by various rate-related proceedings.
During the periods presented in the financial statements, the Company
was involved in proceedings concerning its October 1985 ICC rate order
(which related principally to the recovery of costs associated with
its Byron Unit 1 nuclear generating unit), proceedings concerning its
March 1991 ICC rate order (which related principally to the recovery
of costs associated with its Byron Unit 2 and Braidwood Units 1 and 2
nuclear generating units (Units)), proceedings concerning the
reduction in the difference between the Company's summer and non-
summer residential rates that was effected in the summer of 1988, and
ICC fuel reconciliation proceedings principally concerning the
recoverability of the costs of the Company's western coal. In
addition, there were outstanding issues related to the appropriate
interest rate and rate design to be applied to a refund that was made
in 1990 following the reversal of a December 1988 ICC rate order and a
rider to the Company's rates that the Company was required to file as
a result of the change in the federal corporate income tax rate made
by the Tax Reform Act of 1986. The uncertainties associated
with such proceedings and issues, among other things, led to the Rate
Matters Settlement and the Fuel Matters Settlement (which are
discussed below).
The effects of the aforementioned rate proceedings during the
periods presented are discussed below under "Results of Operations."
For additional information regarding such proceedings, see Notes
2 and 3 of Notes to Financial Statements in
the Company's Quarterly Report on Form 10-Q
The Company has for the quarterly period ended June 30, 1993.
restructured its
management of its nuclear Settlements Relating to Certain Rate Matters.
stations and committed On September 24, 1993, the Company's Board of
additional resources to Directors approved two proposed settlements
their operations. which the Company's management had reached
with parties involved in several of the
proceedings and matters relating to the level
of the Company's rates for electric service.
One of the proposed settlements (Rate Matters
Settlement) concerns the proceedings relating
to the Company's 1985 and 1991 ICC rate orders,
the proceedings relating to the reduction in the difference between the
Company's summer and non- summer residential rates, the outstanding
interest rate and rate design issues, and a rider related to the change in
the federal corporate income tax rate made by the Tax Reform Act of 1986.
The other proposed settlement (Fuel Matters Settlement) relates to the ICC
fuel reconciliation proceedings involving the Company for the period from
1985 through 1988 and to future challenges by the settling parties to the
prudency of the Company's western coal costs for the period from 1989
through 1992. Each of these settlements was subject to appropriate action
by the ICC or the courts having jurisdiction over the proceedings.
As a result of subsequent ICC and judicial actions, the Rate Matters
Settlement became final on November 4, 1993. Under the Rate Matters
Settlement, effective as of November 4, 1993, the Company reduced its
rates by approximately $339 million annually and commenced refunding
approximately $1.26 billion (including revenue taxes), plus interest
at five percent on the unpaid
15
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balance, through temporarily reduced rates over an initial refund
period scheduled to be twelve months (to be followed by a
reconciliation period of no more than five months). The Company had
previously deferred the recognition of revenues during 1993 as a
result of developments in the proceedings related to the March 1991
ICC rate order, which resulted in a reduction to 1993 net income of
approximately $160 million. The recording of the effects of the Rate
Matters Settlement in October 1993 reduced the Company's 1993 net
income and retained earnings by approximately $292 million or $1.37
per common share, in addition to the effect of the deferred
recognition of revenues and after the partially offsetting effect of
recording approximately $269 million (or $1.26 per common share) in
deferred carrying charges, net of income taxes, authorized in the
Remand Order. In January 1994, a purported class action was filed in
the Circuit Court of Cook County, Illinois challenging the method in
which the refunds are being made to residential customers in the Rate
Matters Settlement. The Company does not believe that the complaint
has any merit.
In the Remand Order, the rate determination was based upon, among
other things, findings by the ICC with respect to the extent to which
the Units were "used and useful" during the 1991 test year period of
the rate order. With respect to the "used and useful" issue, the ICC
applied a needs and economic benefits methodology, using a twenty
percent reserve margin and forecasted peak demand, and found Byron
Unit 2 and Braidwood Units 1 and 2 to be 93%, 21% and 0%,
respectively, "used and useful." The Company has not recorded any
disallowances related to the "used and useful" issue.
The Company considers the "used and useful"
disallowance in the Remand Order to be
temporary. The ICC concluded in the Remand
Order that the forecasts in the record in that
Kilowatthour sales to proceeding indicate that Braidwood Units 1 and
ultimate consumers 2 will be fully "used and useful" within the
increased 4.6% in 1993, reasonably foreseeable future.
the result of increased As a result of subsequent ICC actions, the
sales to all major Fuel Matters Settlement became final on
classes of customers. November 15, 1993. Under the Fuel Matters
Settlement, effective as of December 2, 1993,
the Company commenced paying approximately
$108 million (including revenue taxes) to its
customers through
temporarily reduced collections under its fuel adjustment clause over
a twelve-month period. The Company recorded the effects of the Fuel
Matters Settlement in October 1993, which effects reduced the
Company's net income and retained earnings by approximately $62
million or $0.29 per common share.
- ---------------
Results of Operations
Earnings Per Common Share. The Company's earnings per common share
were $0.22 in 1993, $2.08 in 1992 and $0.08 in 1991. The 1993 results
were significantly affected by the recording of the effects of the
Rate Matters Settlement and the Fuel Matters Settlement, which reduced
net income by approximately $354 million or $1.66 per common share, in
addition to the effect of the deferred recognition of revenues which
the Company had recorded during 1993, and after the partially
offsetting effect of recording approximately $269 million or $1.26 per
common share in deferred carrying charges, net of income taxes, as
authorized in the Remand Order. The 1993 earnings also reflect the
favorable cumulative effect ($9.7 million or $0.05 per common share)
of the Company's adoption of Statement of Financial Accounting
Standards (SFAS) No. 109, Accounting for Income Taxes, in January
1993. The effect of the non-recurring items was partially offset by a
higher level of kilowatthour sales and
16
lower operation and maintenance expenses. Excluding non-recurring items,
earnings in 1993 would have been $1.83 per common share.
The 1992 results were significantly affected by the decreased level of
kilowatthour sales due to a cooler than normal summer, higher operation and
maintenance expenses, higher revenues resulting from the full effect of the
rate increase which became effective on March 20, 1991, lower fuel and
purchased power costs and the 1992 reduction to net income of $50 million or
$0.24 per common share to reflect a provision for additional refunds and
interest related to the 1985 ICC rate order. Excluding non-recurring items,
earnings in 1992 would have been $2.32 per common share.
The 1991 results were significantly affected by the recording of the effects
of the unreasonable plant cost disallowance applicable to the Units included in
the ICC's March 1991 rate order, which reduced net income by approximately $734
million or $2.59 per common share. The rate increase authorized by the March
1991 ICC order, which became effective on March 20, 1991, partially offset
these reductions. Excluding the non-recurring adjustments, earnings in 1991
would have been $2.67 per common share.
See "Rate Proceedings" above for information relating to various rate
proceedings which have affected the Company's earnings per common share.
Kilowatthour Sales. Kilowatthour sales to ultimate consumers increased 4.6% in
1993, the result of increased sales to all classes of customers (except
railroads, which decreased), due primarily to more normal summer weather in
1993 as compared to 1992. Kilowatthour sales to ultimate consumers decreased
4.6% in 1992 principally reflecting lower kilowatthour sales to residential
consumers as a result of a cooler than normal summer. Kilowatthour sales to
ultimate consumers increased 5.2% in 1991, the result of increased sales to all
classes of customers and a warmer summer in 1991 than 1990. Kilowatthour sales
including sales for resale increased 16.0% in 1993, decreased 3.7% in 1992 and
increased 1.2% in 1991.
Electric Operating Revenues. Operating revenues decreased $766 million in 1993
principally reflecting the recording of the effects of the Rate Matters
Settlement and the Fuel Matters Settlement, which reduced 1993 electric
operating revenues by $1,282 million. This reduction was partially offset by a
higher level of kilowatthour sales and an increase in the recovery of energy
costs under the fuel adjustment provision in the Company's rates. See "Rate
Proceedings" above and "Earnings per Common Share" herein and Note 2 of Notes
to Financial Statements for additional information.
Operating revenues decreased $249 million in 1992 principally reflecting a
lower level of kilowatthour sales due to a cooler than normal summer, a
decrease in the recovery of energy costs
under the fuel adjustment provision in the Company's rates and a provision for
revenue refunds of approximately $18 million related to the 1985 ICC rate
order. The decrease more than offset the full effect of the rate increase
authorized in the March 1991 ICC order, which became effective March 20, 1991.
See "Rate Proceedings" above for additional information.
Operating revenues increased $965 million in 1991 due to the rate increase
which became effective on March 20, 1991, higher kilowatthour sales in 1991 and
the favorable comparison to 1990 in which rates were rolled back as a result of
the reversal of a December 1988 ICC rate order and provisions for revenue
refunds which were made as a result of developments in the proceedings related
to the 1985 ICC rate order and the reversal of the December 1988 ICC rate
order. See "Rate Proceedings" above for additional information.
Operating revenues for 1994 will be affected by the Rate Matters Settlement
(discussed above), which lowered the level of the Company's rates.
17
Fuel Costs. Changes in fuel expense for 1993, 1992 and 1991 primarily
result from changes in the average cost of fuel consumed, changes in
the mix of fuel sources of electric energy generated and changes in
net generation of electric energy. Fuel mix is determined primarily by
system load, the costs of fuel consumed and the availability of
nuclear generating units. The cost of fuel consumed, net generation of
electric energy and fuel sources of kilowatthour generation were as
follows:
1993 1992 1991
---------------------------------------------- ------ ------ ------
Cost of fuel consumed (per million Btu):
Nuclear $0.52 $0.52 $0.49
Coal $2.89 $2.96 $2.84
Oil $3.03 $3.02 $3.37
Natural gas $2.70 $2.36 $2.48
Average all fuels $1.15 $0.97 $1.07
Net generation of electric energy (millions of
kilowatthours) 94,266 79,889 82,046
Fuel sources of kilowatthour generation:
Nuclear 75% 83% 77%
Coal 23 15 21
Oil 1 1 1
Natural gas 1 1 1
------------------------------------------------------------------------
100% 100% 100%
------------------------------------------------------------------------
The cost of nuclear fuel consumed in 1991 reflects an accrual for a
$46 million court ordered refund from the Department of Energy (DOE)
relating to spent nuclear fuel disposal costs. An offsetting amount was
included in deferred under or overrecovered energy costs in December 1991
and was refunded to the Company's ratepayers through the fuel adjustment
clause in February 1992. In connection with the Energy Policy Act of 1992,
investor-owned electric utilities that have purchased enrichment services
from the DOE will be assessed annually for a fifteen-year period amounts
to fund a portion of the cost for the decontamination and decommissioning
of three nuclear enrichment facilities previously operated by the DOE. The
Company's portion of such assessments is estimated to be approximately $15
million per year (to be adjusted annually for inflation). The Act provides
that such assessments are to be treated as a cost of fuel. See Note 1 of
Notes to Financial Statements for information related to the accounting
for such costs.
Fuel Supply. Compared to other utilities, the Company has relatively
low average fuel costs. This results from the Company's reliance
predominantly on lower cost nuclear generation. The Company's coal
costs, however, are high compared to those of other utilities. The
Company's western coal contracts and its rail contracts for delivery
of the western coal were renegotiated during 1992 effective as of
January 1, 1993, to provide, among other things, for significant
reductions in the delivered price of the coal over the duration of the
contracts. However, the renegotiated contracts provide for the
purchase of certain coal at prices substantially above currently
prevailing market prices and the Company has significant purchase
commitments under its contracts. Coal and fuel oil, at average cost,
included in the Consolidated Balance Sheets, decreased approximately
$215 million in 1993 as compared to 1992, primarily due to lower
inventory levels at year-end, reflecting the Company's present policy
of maintaining coal inventories equal to 30 days of high utilization.
Lower average costs per ton of coal due to renegotiated coal and rail
contracts, which became effective January 1, 1993, also contributed to
the decrease in 1993. For additional information concerning the
Company's coal purchase commitments, fuel reconciliation proceedings
and coal reserves, see "Liquidity and Capital Resources" above and
Notes 2, 3, 17 and 19 of Notes to Financial Statements.
18
- ------------------------------
Purchased Power. Amounts of purchased power are primarily affected by
system load, the availability of the Company's generating units and
the availability and cost of power from other utilities.
The number and average cost of kilowatthours purchased were as
follows:
1993 1992 1991
----------------------------------------------- ---- ----- -----
Kilowatthours (millions) 644 2,555 3,374
Cost per kilowatthour 1.91c 1.78c 2.16c
------------------------------------------------
Deferred Under or Overrecovered Energy Costs--Net. Electric operating
expenses for the years 1993, 1992 and 1991 reflect the net change in
under or overrecovered allowable energy costs. See "Fuel Costs" and
"Fuel Supply" above and Notes 1 and 3 of Notes to Financial
Statements.
Operation and Maintenance Expenses. Total operation and maintenance
expenses decreased approximately 4% during 1993 and increased
approximately 9% and 18% during 1992 and 1991, respectively. The
decrease in 1993 primarily reflects a decrease in operation and
maintenance expenses associated with nuclear generating stations,
lower costs of pension benefits, lower expenses related to fossil
generating station and customer-related activities, a decrease in the
number of employes and lower research costs, partially offset by
higher costs of other employe benefits, including postretirement
health care benefits, and the cost related to a special incentive plan
for employes. The increases in 1992 and 1991 primarily reflect an
increase in operation and maintenance expenses associated with nuclear
generating stations, cost of pension and other employe benefits,
including postretirement health care benefits, and an increased number
of employes. The increase in 1991 also reflects an increase related to
transmission and distribution activities. Wage increases, the effects
of which are reflected in the increases and decreases discussed below,
have increased operation and maintenance expenses during 1992 and
1991. Wages in 1993 were not increased over 1992 levels. The effects
of inflation, which are also reflected in the increases and decreases
discussed below, have increased operation and
maintenance expenses during the periods. The
Compared to other cost of pension benefits (net of amounts
utilities, the Company charged to construction) decreased $16 million
has relatively low in 1993 and increased $21 million and $31
average fuel costs. This million in 1992 and 1991, respectively. The
results from the 1992 pension increase reflects the effect of
Company's reliance the Company's workforce reduction program in
predominantly on lower which a charge to income of $26 million was
cost nuclear generation. recorded in 1992 (see Note 12 of Notes to
Financial Statements for additional
information). Additional costs associated with
the Company's management workforce reduction
program of approximately $11 million were
recorded in 1992, which adversely impacted operation and maintenance
expenses for 1992. The cost of postretirement health care benefits (net of
amounts charged to construction) increased $14 million, $29 million and
$19 million in 1993, 1992 and 1991, respectively. The $14 million increase
for 1993 reflects an increase in the cost of postretirement health care
benefits of $17 million as a result of the Company adopting on January 1,
1993, SFAS No. 106, Employers' Accounting for Postretirement Benefits
Other Than Pensions (see Note 13 of Notes to Financial Statements for
additional information). Nuclear operation and maintenance expenses
decreased approximately $74 million in 1993 and increased $105 million and
$79 million in 1992 and 1991, respectively. The decrease at the nuclear
generating stations in 1993 includes the effects of the Company's cost
reduction efforts. Operation and maintenance expenses associated with
nuclear generating stations in future years may be significantly affected
by regulatory, operational and other requirements. Operation and
maintenance expenses associated with the Company's transmission and
19
- ------------------------------
distribution system which increased $41 million in 1991, and remained
stable in 1992 and 1993, may increase in future years due, in part, to
the effect of increased customer expectations regarding reliability.
Operation and maintenance expenses associated with the fossil
generating stations in 1993 decreased $13 million and research costs
decreased $10 million from the prior period due primarily to the
effects in 1993 of the Company's cost reduction efforts. Costs of
customer-related activities in 1993 decreased $13 million. Operation
and maintenance expenses in 1993 also reflect a $36 million special
incentive plan cost for employes related to a sharing of operation and
maintenance savings below budgeted levels. In 1993, the Company
recorded a provision of $5 million which reflects the low end of the
range of its estimate of the liability associated with cleanup costs
of remediation sites other than former manufactured gas plant (MGP)
sites. In 1991, the Company recorded a provision of $25 million which
reflects the low end of the range of its estimate of the liability
associated with former MGPs. See Note 19 of Notes to Financial
Statements for additional information concerning cleanup costs of
remediation sites and former MGPs. For further information regarding
the cost reduction plan and its effect on future operation and
maintenance expenses, see "Liquidity and Capital Resources,"
subcaption "Rates and Financial Condition" above.
Depreciation. Depreciation expense increased in 1993 as a result of
additions to plant in service. Depreciation expense increased in 1992
as a result of reflecting in expense a full year's effect of increased
decommissioning costs allowed by the March 1991 ICC rate order, which
became effective March 20, 1991. Depreciation expense in 1991
decreased compared to 1990 due primarily to lower average
annual composite depreciation rates as well as
Average interest rate on the reduction to depreciable plant facilities in
long-term debt 1991 reflecting the effects of recording
outstanding has been disallowed plant costs, partially offset by the
significantly reduced, increase in decommissioning expense resulting
primarily through from the March 1991 ICC rate order. As discussed
refinancings at generally in Note 1 of Notes to Financial Statements,
lower rates of interest. the Company has revised its estimate of
decommissioning costs to aggregate
approximately $4.06 billion, in current-year (1993) dollars, from the
approximate $2.32 billion estimate of decommissioning costs, in current-year
(1993) dollars, reflected in its current rates. The current accrual of
approximately $127 million reflected in the Company's rates coupled with
accumulated earnings on the tax-qualified and nontax-qualified trust funds
based on after-tax earnings assumptions of 7.30% and 6.26%, respectively, is
expected to provide sufficient funds to pay estimated decommissioning costs
assuming a 4.5% escalation rate. Should the expected trust fund and trust fund
earnings be less than the current forecast, the Company believes that it is
probable that decommissioning costs not funded by the trust fund, including
trust fund earnings, would ultimately be recoverable through rates. See Note 1
of Notes to Financial Statements for information concerning depreciation rates
and decommissioning costs.
Interest on Debt. Changes in interest on long-term debt and notes payable for
the years 1993, 1992 and 1991 were due to changes in average interest rates and
in the amounts of long-term debt and notes payable outstanding. Changes in
interest on long-term debt reflect new issues of debt and the retirement and
redemption of issues which were refinanced at generally lower rates of interest.
The average amounts of long-term debt and notes payable outstanding and average
interest rates thereon were as follows:
1993 1992 1991
-------------------------------------- -------- -------- --------
Long-term debt outstanding:
Average amount (millions) $8,105.1 $7,699.9 $7,314.3
Average interest rate 8.03% 8.58% 9.09%
Notes payable outstanding:
Average amount (millions) $5.7 $17.5 $1.9
Average interest rate 5.83% 4.43% 8.22%
-----------------------------------------------------------------------
Recovery/(Deferral) of Regulatory Assets--Net. In the March 1991 ICC
rate order, the ICC provided that, for ratemaking purposes, certain
rate case and consultant costs associated with the prudency audits for
the Units could be deferred and amortized. Approximately $43 million
of such costs were capitalized and resulted in an increase to net
income in 1991 of approximately $24 million or $0.11 per common share.
20
In the Remand Order, the ICC provided that, for ratemaking purposes,
deferred carrying charges on the reasonable and "used and useful"
plant costs of the Units for the period April 1, 1989 until
approximately March 20, 1991, the date the Units were reflected in
rates, could be deferred and amortized. Approximately $438 million of
such costs were capitalized in October 1993 and resulted in an
increase to net income of approximately $269 million or $1.26 per
common share.
Taxes. In the third quarter of 1993, the President of the United
States signed into law a deficit-reduction plan that includes, among
other things, an increase in the federal statutory corporate income
tax rate from 34% to 35%, effective January 1, 1993. The estimated
effect of the higher rate would be to increase the Company's costs by
approximately $12 million per year. The Company began recording the
effects of the increased taxes in the third quarter of 1993. In
addition to the effects on income discussed above, the Company
recorded in the third quarter of 1993 a net increase in the deferred
income tax liability which was primarily offset by regulatory assets
net of regulatory liabilities, reflecting the increase in taxes
recoverable in rates to settle net income tax liabilities recorded in
prior years.
Further, the Company recorded in the third quarter of 1993 the
effects of the elimination of a scheduled reduction in a component of
the statutory Illinois income tax rate which was to have declined to
4.4% from 4.8%, effective July 1, 1993.
In 1993, the Company recorded a loss for income tax purposes. Income
tax overpayments made prior to the determination of such loss of
approximately $185 million are included in the Consolidated Balance
Sheet in receivables.
See Note 14 of Notes to Financial Statements for information
concerning the accounting standard adopted by the Company in January
1993 which requires the Company to use an asset and liability approach
for financial accounting and reporting for income taxes rather than
the deferred method.
Decommissioning. The staff of the SEC has questioned certain of the
current accounting practices of the electric utility industry, including
the Company, regarding the recognition, measurement and classification of
decommissioning costs for nuclear generating stations in financial
statements of electric utilities. In response to these questions the
electric utility industry has requested the Financial Accounting Standards
Board to review the accounting for removal costs, including
decommissioning. If current electric utility industry accounting practices
for such decommissioning are changed: (1) annual provisions for
decommissioning could increase; (2) the estimated cost for decommissioning
could be recorded as a liability rather than as accumulated depreciation;
and (3) trust fund income from the external decommissioning trusts could
be reported as investment income rather than as a reduction to
decommissioning expense. The Company does not believe that such changes,
if required, would have an adverse effect on results of operations due to
its current and future ability to recover decommissioning costs through
rates.
Regulatory Assets and Liabilities. The balance of Regulatory Assets
increased from December 31, 1992 to December 31, 1993 by approximately
$2,220 million. The increase is due primarily to the Company's
adoption of SFAS No. 109 effective January 1, 1993. The effect of the
implementation entry was to record regulatory assets of approximately
$1,546 million. Further, as discussed under the subcaption "Taxes"
above, in the third quarter of 1993, the Company began recording the
effects of the increased federal statutory corporate income tax rate
effective January 1, 1993, in addition to recording the effects of the
elimination of a scheduled reduction in a component of the statutory
Illinois income tax rate, effective July 1, 1993, which in total
resulted in an increase to regulatory assets of approximately $224
million. Approximately $436 million of the increase in regulatory assets
reflects the unamortized balance of deferred carrying charges recorded by
the Company in 1993 on the Units, as discussed under the subcaption
"Recovery/(Deferral) of Regulatory Assets--Net" above. The remaining
increase is related primarily to losses from reacquisition in 1993 of
first mortgage bonds prior to their scheduled maturity dates, which were
deferred consistent with regulatory treatment. A regulatory liability was
also recorded in compliance with SFAS No. 109. See Notes 1 and 14 of Notes
to Financial Statements for additional information.
Other Items. The amounts of allowance for funds used during
construction (AFUDC) reflect changes in the average levels of
investment subject to AFUDC and changes in the average annual rates as
discussed in Note 1 of Notes to Financial Statements. AFUDC does not
contribute to the current cash flow of the Company.
The approximate $720 million increase in other cash investments, at
cost, and temporary cash investments, at cost, in 1993 as compared to
1992, reflects additional cash flow from higher operating revenues
collected prior to the finalization of the Rate Matters Settlement as
well as a reduction in
21
operation and maintenance expenses, construction expenditures and dividends
paid on capital stock. Although the Company recorded the provisions for revenue
refunds in 1993, the majority of the refunds to its customers will be made in
1994.
The ratios of earnings to fixed charges for the years 1993, 1992 and 1991
were 1.19, 2.06 and 1.59, respectively. The ratios of earnings to fixed charges
and preferred and preference stock dividend requirements for the years 1993,
1992 and 1991 were 1.03, 1.78 and 1.36, respectively.
Business corporations in general have been adversely affected by inflation
because amounts retained after the payment of all costs have been inadequate to
replace, at increased costs, the productive assets consumed. Electric utilities
in particular have been especially affected as a result of their capital
intensive nature and regulation which limits capital recovery and prescribes
installation or modification of facilities to comply with increasingly
stringent safety and environmental requirements. Because the regulatory process
limits the amount of depreciation expense included in the Company's revenue
allowance to the original cost of utility plant investment, the resulting cash
flows are inadequate to provide for replacement of that investment in future
years or preserve the purchasing power of common equity capital previously
invested.
22
Report of Independent Public Accountants
To the Shareholders of Commonwealth Edison Company:
We have audited the accompanying consolidated balance sheets and
statements of consolidated capitalization of Commonwealth Edison
Company (an Illinois corporation) and subsidiary companies as of
December 31, 1993 and 1992, and the related statements of consolidated
income, retained earnings, premium on common stock and other paid-in
capital, and cash flows for each of the three years in the period
ended December 31, 1993. These financial statements are the
responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of
Commonwealth Edison Company and subsidiary companies as of December
31, 1993 and 1992, and the 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 Notes 13 and 14, effective January 1, 1993, the
Company changed its method of accounting for postretirement health
care benefits and income taxes, respectively.
[LOGO-Sig. of Arthur Andersen & Co.]
Chicago, Illinois
March 18, 1994
25
Summary of Selected Consolidated Financial Data
(millions of dollars except per share data) 1993 1992 1991 1990 1989
------------------------------------------- ------- ------- ------- ------- -------
Electric operating revenues $ 5,260 $ 6,026 $ 6,276 $ 5,311 $ 5,819
Net income $ 112 $ 514 $ 95 $ 128 $ 694
Earnings per common share $ 0.22 $ 2.08 $ 0.08 $ 0.22 $ 2.83
Cash dividends declared per common share $ 1.60 $ 2.30 $ 3.00 $ 3.00 $ 3.00
Total assets (at end of year) $23,963 $20,993(1) $17,365 $17,889 $17,948
Long-term obligations at end of year
excluding current portion:
Long-term debt and preference stock
subject to mandatory redemption
requirements $ 7,861 $ 7,913 $ 7,081 $ 7,341 $ 7,002
Accrued spent nuclear fuel disposal
fee and related interest $ 567 $ 549 $ 530 $ 500 $ 462
Capital lease obligations $ 321 $ 347 $ 396 $ 387 $ 413
Other long-term obligations $ 1,303 $ 666 $ 341 $ 225 $ 214
-----------------------------------------------------------------------------------------
(1)SEE NOTE 14 OF NOTES TO FINANCIAL STATEMENTS FOR ADDITIONAL INFORMATION.
Price Range* and Dividends Paid Per Share of Common Stock
1993 (by quarters) 1992 (by quarters)
--------------------------- ---------------------------
Fourth Third Second First Fourth Third Second First
------ ------ ------ ------ ------ ------ ------ ------
Price Range:
High 30 5/8 31 5/8 29 7/8 28 1/4 26 27 5/8 34 1/4 40 1/8
Low 27 3/8 27 3/8 25 5/8 22 7/8 21 3/4 22 7/8 26 5/8 33 3/4
Dividends Paid 40c 40c 40c 40c 40c 75c 75c 75c
*As reported as NYSE Composite Transactions.
------------------------------------------------------------------------
The Company's common stock is traded on the New York, Chicago and Pacific stock
exchanges, with the ticker symbol CWE. At December 31, 1993, there were
approximately 196,000 holders of record of the Company's common stock.
1993 Revenues and Sales
Electric
Operating Increase/ Kilowatthour Increase/ Increase/
Revenues(1) (Decrease) Sales (Decrease) (Decrease)
(thousands) Over 1992 (millions) Over 1992 Customers Over 1992
----------- ---------- ------------ ---------- --------- ----------
Residential $2,341,155 9.1 % 20,818 8.0 % 3,009,508 1.0 %
Small commercial and
industrial 1,962,662 4.7 % 23,463 3.5 % 283,764 0.6 %
Large commercial and
industrial 1,437,680 4.6 % 22,917 3.4 % 1,503 (1.6)%
Public authorities 474,034 4.8 % 6,741 2.7 % 12,023 1.2 %
Electric railroads 27,593 (0.1)% 405 (1.4)% 2 -- %
---------------------------------------------------------------------------------------------
Ultimate
consumers--total $6,243,124 6.3 % 74,344 4.6 % 3,306,800 0.9 %
Provisions for
revenue refunds--
ultimate consumers (1,281,788) -- --
---------------------------------------------------------------------------------------------
Ultimate
consumers--net $4,961,336 74,344 3,306,800
---------------------------------------------------------------------------------------------
Sales for resale $ 242,550
Provisions for revenue
refunds--sales for
resale (4,977)
---------------------------------------------------------------------------------------------
Sales for resale--net $ 237,573 13,417 17
Other revenues 61,531 -- --
---------------------------------------------------------------------------------------------
$5,260,440 (12.7)% 87,761 16.0 % 3,306,817 0.9 %
---------------------------------------------------------------------------------------------
(1) See Note 2 of Notes to Financial Statements and the Statements of
Consolidated Income for information related to revenue refunds.
26
Statements of Consolidated Income
Commonwealth Edison Company and Subsidiary Companies
(thousands except per share data) 1993 1992 1991
---------------------------------- ---------- ---------- -----------
Electric operating revenues
(Notes 2 and 3):
Operating revenues $6,547,205 $6,044,693 $ 6,276,384
Provisions for revenue refunds (1,286,765) (18,372) (851)
-------------------------------------------------------------------------
$5,260,440 $6,026,321 $ 6,275,533
- -------------------------------------------------------------------------------
Electric operating expenses and taxes:
Fuel (Notes 1, 2, 3, 10 and 19) $1,170,935 $ 841,321 $ 968,176
Purchased power 12,303 45,579 72,980
Deferred (under)/overrecovered
energy costs--net
(Notes 1 and 3) (1,757) (30,254) 31,204
Operation 1,457,689 1,529,849 1,412,366
Maintenance 581,714 587,778 527,489
Depreciation (Note 1) 862,766 836,129 825,837
Recovery/(deferral) of regulatory
assets--net 5,235 3,330 (39,704)
Taxes (except income) (Note 15) 701,913 743,909 742,570
Income taxes (Notes 1 and 14)--
Current --Federal (19,930) 139,857 236,369
--State (7,623) 21,531 53,068
Deferred --Federal--net 88,052 97,066 123,479
--State--net 34,752 45,829 38,558
Investment tax credits deferred--
net (Notes 1 and 14) (29,424) (32,506) (32,054)
-------------------------------------------------------------------------
$4,856,625 $4,829,418 $ 4,960,338
- -------------------------------------------------------------------------------
Electric operating income $ 403,815 $1,196,903 $ 1,315,195
- -------------------------------------------------------------------------------
Other income and (deductions):
Interest on long-term debt $ (651,181) $ (660,429) $ (664,946)
Interest on notes payable (334) (775) (152)
Allowance for funds used during
construction (Note 1)--
Borrowed funds 16,930 17,213 13,500
Equity funds 20,618 19,960 18,272
Income taxes applicable to
nonoperating activities (Notes 1
and 14) 29,913 6,275 (10,842)
Disallowed plant costs (Note 3) -- -- (644,862)
Income tax reduction for
disallowed plant costs (Note 3) 791 -- 76,579
Deferred carrying charges (Note 2) 438,183 -- --
Interest and other costs for 1993
Settlements (Note 2) (98,674) -- --
Miscellaneous--net (57,359) (65,166) (7,857)
-------------------------------------------------------------------------
$ (301,113) $ (682,922) $(1,220,308)
- -------------------------------------------------------------------------------
Net income before cumulative effect of
change in accounting for income taxes $ 102,702 $ 513,981 $ 94,887
Cumulative effect of change in accounting
for income taxes 9,738 -- --
- -------------------------------------------------------------------------------
Net income $ 112,440 $ 513,981 $ 94,887
Provision for dividends on preferred and
preference stocks 66,052 70,539 78,288
- -------------------------------------------------------------------------------
Net income on common stock $ 46,388 $ 443,442 $ 16,599
- -------------------------------------------------------------------------------
Average number of common shares outstanding 213,508 212,929 212,452
Earnings per common share before cumulative
effect of change in accounting for
income taxes $0.17 $2.08 $0.08
Cumulative effect of change in accounting
for income taxes 0.05 -- --
- -------------------------------------------------------------------------------
Earnings per common share $0.22 $2.08 $0.08
- -------------------------------------------------------------------------------
Cash dividends declared per common share $1.60 $2.30 $3.00
- -------------------------------------------------------------------------------
The accompanying Notes to Financial Statements are an integral part of the
above statements.
27
Consolidated Balance Sheets
(thousands of dollars) December 31, 1993 1992
--------------------------------------------- ----------- -----------
ASSETS
Utility plant
(Notes 1, 3, 8, 16, 17 and 18):
Plant and equipment, at original cost
(includes construction work in progress of
$1,040 million and $1,165 million,
respectively) $26,097,934 $25,400,822
Less--Accumulated provision for depreciation 8,868,024 8,146,445
-------------------------------------------------------------------------
$17,229,910 $17,254,377
Nuclear fuel, at amortized cost 662,562 665,964
-------------------------------------------------------------------------
$17,892,472 $17,920,341
- -------------------------------------------------------------------------------
Investments:
Nuclear decommissioning funds, at cost (Notes
1 and 11) $ 706,841 $ 533,463
Subsidiary companies (Notes 1 and 17) 122,332 112,900
Other investments, at cost (Note 17) 72,379 123,324
-------------------------------------------------------------------------
$ 901,552 $ 769,687
- -------------------------------------------------------------------------------
Current assets:
Cash $ 743 $ --
Temporary cash investments, at cost which
approximates market 247,119 145,749
Other cash investments, at cost which
approximates market 641,575 22,226
Special deposits, at cost which approximates
market (Note 11) 32,635 260,899
Receivables (Note 1)--
Customers 427,613 445,676
Income taxes 186,687 5,159
Other 66,963 75,089
Provisions for uncollectible accounts (10,910) (12,976)
Coal and fuel oil, at average cost 111,752 327,134
Materials and supplies, at average cost 402,714 404,548
Deferred underrecovered energy costs (Notes 1
and 3) 4,728 2,971
Deferred income taxes related to current
assets and liabilities (Note 14)--
Loss carryforward 175,197 --
Other 166,102 115,137
Prepayments and other 42,190 37,659
-------------------------------------------------------------------------
$ 2,495,108 $ 1,829,271
- -------------------------------------------------------------------------------
Deferred charges:
Regulatory assets (Notes 1 and 14) $ 2,619,442 $ 399,453
Other 54,078 74,591
-------------------------------------------------------------------------
$ 2,673,520 $ 474,044
-------------------------------------------------------------------------
$23,962,652 $20,993,343
- -------------------------------------------------------------------------------
The accompanying Notes to Financial Statements are an integral part of the
above statements.
28
Commonwealth Edison Company and Subsidiary Companies
(thousands of dollars) December 31, 1993 1992
------------------------------------------------ ----------- -----------
LIABILITIES
Capitalization
(see accompanying statements):
Common stock equity $ 5,421,893 $ 5,707,832
Preferred and preference stocks without
mandatory redemption requirements 441,445 442,142
Preference stock subject to mandatory redemption
requirements 309,964 312,789
Long-term debt 7,550,762 7,600,692
--------------------------------------------------------------------------
$13,724,064 $14,063,455
- --------------------------------------------------------------------------------
Current liabilities:
Notes payable--bank loans (Note 9) $ 5,950 $ 5,600
Current portion of long-term debt, redeemable
preference stock and capitalized lease
obligations (Note 11) 630,050 564,538
Accounts payable 489,080 457,918
Accrued interest 186,825 192,658
Accrued taxes 132,362 165,763
Dividends payable 101,047 101,961
Estimated revenue refunds and related interest 1,166,308 2,833
Customer deposits 45,757 47,578
Other 98,519 83,580
--------------------------------------------------------------------------
$ 2,855,898 $ 1,622,429
- --------------------------------------------------------------------------------
Deferred credits and other noncurrent liabilities:
Deferred income taxes (Note 14) $ 4,445,173 $ 2,968,899
Accumulated deferred investment tax credits
(Notes 1 and 14) 746,508 775,932
Accrued spent nuclear fuel disposal fee and
related interest
(Note 10) 566,527 549,422
Obligations under capital leases (Note 16) 321,393 347,413
Regulatory liability (Notes 1 and 14) 592,770 --
Other (Notes 1, 12 and 13) 710,319 665,793
--------------------------------------------------------------------------
$ 7,382,690 $ 5,307,459
- --------------------------------------------------------------------------------
Commitments and contingent liabilities (Note 19)
- --------------------------------------------------------------------------------
$23,962,652 $20,993,343
- --------------------------------------------------------------------------------
The accompanying Notes to Financial Statements are an integral part of the
above statements.
29
Statements of Consolidated Capitalization
Commonwealth Edison Company and Subsidiary Companies
(thousands of dollars) December 31, 1993 1992
---------------------------------------------- ----------- -----------
Common stock equity
(Notes 4, 5 and 19):
Common stock, $12.50 par value per share--
Outstanding--213,751,147 shares and
213,305,404 shares, respectively $ 2,671,889 $ 2,666,318
Premium on common stock and other paid-in
capital 2,217,110 2,210,524
Capital stock and warrant expense (16,258) (16,196)
Retained earnings (Note 2) 549,152 847,186
--------------------------------------------------------------------------
$ 5,421,893 $ 5,707,832
- --------------------------------------------------------------------------------
Preferred and preference stocks without mandatory redemption requirements
(Notes 4, 6 and 11):
Preference stock, cumulative, without par
value--
Outstanding--10,499,549 shares $ 432,320 $ 432,320
$1.425 convertible preferred stock,
cumulative, without par value--
Outstanding--286,949 shares and 308,891
shares, respectively 9,125 9,822
Prior preferred stock, cumulative, $100 par
value per share--
No shares outstanding -- --
--------------------------------------------------------------------------
$ 441,445 $ 442,142
- --------------------------------------------------------------------------------
Preference stock subject to mandatory redemption requirements
(Notes 4, 7 and 11):
Preference stock, cumulative, without par
value--
Outstanding--3,290,290 shares and 4,425,445
shares, respectively $ 327,653 $ 348,442
Current redemption requirements for preference
stock included in current liabilities (17,689) (35,653)
--------------------------------------------------------------------------
$ 309,964 $ 312,789
- --------------------------------------------------------------------------------
Long-term debt
(Notes 8, 11 and 20):
First mortgage bonds:
Maturing 1993 through 1998--5 1/4% to 10 1/8% $ 818,000 $ 1,013,000
Maturing 1999 through 2008--6 3/8% to 10 3/8% 2,204,600 2,149,655
Maturing 2009 through 2018--7 1/4% to 12% 956,000 1,311,000
Maturing 2019 through 2023--7 3/4% to 9 7/8% 2,020,000 1,460,000
--------------------------------------------------------------------------
$ 5,998,600 $ 5,933,655
Sinking fund debentures, due 1999 through
2011--2 3/4% to 7 5/8% 120,185 121,093
Pollution control obligations, due 2004
through 2014--5 7/8% to 11 3/8% 353,200 353,200
Other long-term debt 1,598,625 1,613,246
Current maturities of long-term debt included
in current liabilities (446,724) (351,124)
Unamortized net debt discount and premium
(Note 1) (73,124) (69,378)
--------------------------------------------------------------------------
$ 7,550,762 $ 7,600,692
- --------------------------------------------------------------------------------
$13,724,064 $14,063,455
- --------------------------------------------------------------------------------
The accompanying Notes to Financial Statements are an integral part of the
above statements.
30
Statements of Consolidated Cash Flows
Commonwealth Edison Company and Subsidiary Companies
(thousands of dollars) 1993 1992 1991
------------------------------- ----------- ----------- ----------
Cash flow from operating activities:
Net income $ 112,440 $ 513,981 $ 94,887
Adjustments to reconcile net
income to net cash provided by
operating activities:
Depreciation and amortization 911,136 874,156 874,660
Deferred income taxes and
investment tax credits--net 85,079 109,850 65,154
Cumulative effect of change in
accounting for income taxes (9,738) -- --
Equity component of allowance
for funds used
during construction (20,618) (19,960) (18,272)
Provisions for revenue refunds
and related interest 1,354,197 73,370 12,584
Revenue refunds and related
interest (190,723) (248,360) (90,332)
Disallowed plant costs -- -- 644,862
Recovery/(deferral) of
regulatory assets/deferred
carrying charges--net (432,948) 3,330 (39,704)
Provisions/(payments) for
liability for early
retirement and separation
costs--net (1,816) 27,814 --
Provisions/(payments) for
liabilities associated with
remediation costs and
manufactured gas plants--net 5,000 (478) 25,000
Net effect on cash flows of
changes in:
Receivables (157,405) 70,776 (196,558)
Coal and fuel oil 215,382 (111,333) 95,779
Materials and supplies 1,834 1,990 (36,496)
Accounts payable adjusted for
nuclear fuel lease principal
payments and
provisions/(payments) for
liability for early
retirement and separation
costs--net 278,946 315,822 280,131
Accrued interest and taxes (39,234) (85,633) 101,259
Other changes in certain
current assets and
liabilities (6,637) (9,031) 40,891
Other--net 144,318 61,328 83,452
------------------------------------------------------------------------
$ 2,249,213 $ 1,577,622 $1,937,297
- ------------------------------------------------------------------------------
Cash flow from investing activities:
Construction expenditures $ (841,525) $ (995,881) $ (961,168)
Nuclear fuel expenditures (261,370) (220,347) (250,559)
Equity component of allowance
for funds used during
construction 20,618 19,960 18,272
Investment in nuclear
decommissioning funds (173,378) (156,017) (117,294)
Investment in coal reserves (43) (79,961) (78,678)
Investment in subsidiary
companies -- (268) --
Other cash investments (619,349) 23,853 416,144
------------------------------------------------------------------------
$(1,875,047) $(1,408,661) $ (973,283)
- ------------------------------------------------------------------------------
Cash flow from financing activities:
Issuance of securities--
Long-term debt $ 1,927,296 $ 1,962,737 $ 736,281
Capital stock 80,585 15,568 13,334
Retirement and redemption of
securities--
Long-term debt (1,900,540) (1,214,730) (795,236)
Capital stock (93,081) (50,069) (75,546)
Deposits and securities held
for retirement and redemption
of securities 241,731 (245,028) 4,043
Premium paid on early
redemption of long-term debt (78,395) (10,809) (25,855)
Cash dividends paid on capital
stock (408,285) (635,370) (716,849)
Proceeds from sale/leaseback of
nuclear fuel 204,254 190,830 240,263
Nuclear fuel lease principal
payments (245,968) (245,877) (231,150)
Increase in short-term
borrowings 350 3,600 250
------------------------------------------------------------------------
$ (272,053) $ (229,148) $ (850,465)
- ------------------------------------------------------------------------------
Increase (Decrease) in cash and
temporary cash investments $ 102,113 $ (60,187) $ 113,549
Cash and temporary cash
investments at beginning of
year 145,749 205,936 92,387
- ------------------------------------------------------------------------------
Cash and temporary cash
investments at end of year $ 247,862 $ 145,749 $ 205,936
- ------------------------------------------------------------------------------
The accompanying Notes to Financial Statements are an integral part of the
above statements.
31
Statements of Consolidated Retained Earnings
Commonwealth Edison Company and Subsidiary Companies
(thousands of dollars) 1993 1992 1991
----------------------------------- -------- ---------- ----------
Balance Beginning of year $847,186 $ 893,702 $1,513,894
Add
Net income 112,440 513,981 94,887
--------------------------------------------------------------------
$959,626 $1,407,683 $1,608,781
- --------------------------------------------------------------------------
Deduct
Cash dividends declared on--
Common stock $341,683 $ 489,768 $ 637,480
Preferred and preference stocks 65,688 70,101 77,599
Loss on reacquired preference stock 3,103 628 --
--------------------------------------------------------------------
$410,474 $ 560,497 $ 715,079
- --------------------------------------------------------------------------
Balance
End of year $549,152 $ 847,186 $ 893,702
- --------------------------------------------------------------------------
Statements of Consolidated Premium on Common Stock and Other Paid-In Capital
Commonwealth Edison Company and Subsidiary Companies
(thousands of dollars) 1993 1992 1991
----------------------------------- ---------- ---------- ----------
Balance Beginning of year $2,210,524 $2,202,496 $2,194,314
Add
Premium on issuance of common stock
and gain on reacquired preference
stock 6,586 8,028 8,182
- ----------------------------------------------------------------------------
Balance
End of year $2,217,110 $2,210,524 $2,202,496
- --------------------------------------------------------------------------------
The accompanying Notes to Financial Statements are an integral part of the
above statements.
32
Notes to Financial Statements
Commonwealth Edison Company and Subsidiary Companies
- --------------------------------
1 Summary of Significant Accounting Policies
Regulation. Commonwealth Edison Company (Company) is subject to the
regulation of the Illinois Commerce Commission (ICC) and Federal
Energy Regulatory Commission (FERC). The Company's accounting policies
and the accompanying consolidated financial statements conform to
generally accepted accounting principles applicable to rate-regulated
enterprises and reflect the effects of the ratemaking process. Such
effects concern mainly the time at which various items enter into the
determination of net income in order to follow the principle of
matching costs and revenues. See "Management's Discussion and Analysis
of Financial Condition and Results of Operations," subcaption
"Liquidity and Capital Resources," for information related to the
Company's rates and financial condition.
Principles of Consolidation. The consolidated financial statements
include the accounts of the Company and its wholly-owned subsidiary,
Commonwealth Edison Company of Indiana, Inc. (collectively,
companies), the only subsidiary engaged in the electric utility
business. The consolidated financial statements also include the
accounts of the Company's wholly-owned subsidiary, CECo Enterprises
Inc., an unregulated subsidiary engaged in energy service activities.
All significant intercompany transactions have been eliminated. The
investments in other subsidiary companies, which are not material in
relation to the Company's financial position and results of
operations, are accounted for in accordance with the equity method of
accounting.
Customer Receivables and Revenues. The Company is engaged principally
in the production, purchase, transmission, distribution and sale of
electricity to a diverse base of residential, commercial and
industrial customers. The Company's electric service territory has an
area of approximately 11,540 square miles and an estimated population
of approximately 8.1 million as of December 31, 1993, approximately
8.2 million as of December 31, 1992 and approximately 8.1 million as
of December 31, 1991. It includes the city of Chicago, an area of
about 225 square miles with an estimated population of three million
from which the Company derived approximately one-third of its ultimate
consumer revenues in 1993. The Company had approximately 3.3 million
electric customers at December 31, 1993.
Depreciation. Depreciation is provided on the straight-line basis by
amortizing the cost of depreciable plant and equipment over estimated
composite service lives. Such provisions for depreciation were at
average annual rates of 3.12%, 3.12% and 3.22% of average depreciable
utility plant and equipment for the years 1993, 1992 and 1991,
respectively. The ICC's March 8, 1991 rate order directs the Company
to depreciate non-nuclear plant and equipment at annual rates
developed for each class of plant based on their composite service
lives. The annual rate for nuclear plant and equipment is 2.88% which
excludes decommissioning costs. The provisions for chemical cleaning
are reflected in the Statements of Consolidated Income in maintenance
expense and in the Consolidated Balance Sheets in other noncurrent
liabilities.
Nuclear plant decommissioning costs are accrued over the expected
service life of the related nuclear generating stations. The accrual is
based on an annual levelized cost of the unrecovered portion of
decommissioning costs which are escalated for expected inflation to the
expected time of decommissioning and are net of expected earnings on the
trust fund. See "Decommissioning" under "Management's Discussion and
Analysis of Financial Condition and Results of Operations," subcaption
"Results of Operations," for a discussion of questions raised by the staff
of the Securities and Exchange Commission regarding the electric utility
industry accounting for decommissioning costs. Decommissioning is expected
to occur relatively soon after the end of the useful life of each related
generating station using a prompt removal method authorized by the Nuclear
Regulatory Commission (NRC) guidelines. The Company's twelve operating
units have estimated remaining service lives ranging from 13 to 34 years.
The Company's first nuclear unit is retired and will be decommissioned
with the operating units at that station, which is consistent with the
regulatory treatment for the related decommissioning costs.
The Company has recently completed a study which determined that
decommissioning costs, including the costs of decontamination, dismantling
and site restoration are estimated to aggregate $4.06 billion, in current-
year (1993) dollars. This compares to the estimate for decommissioning
costs of $2.32 billion, in current-year (1993) dollars, reflected in the
Company's last rate order of March 8, 1991. The $4.06 billion estimate is
based on plant location and cost characteristics for the Company's nuclear
plants. The estimate includes additional low level waste burial costs,
higher labor costs due to expected reduced NRC annual dose limit
requirements and higher costs resulting from an additional five year
period in the decommissioning process to allow sufficient cooling of on-
site spent nuclear fuel before it is removed from the fuel pool.
On February 10, 1994, the Company filed a rate increase request with the
ICC. As part of that request, the Company proposed to increase its annual
accrual of decommissioning costs to approximately $170 million from the
current level of $127 million approved in the March 8, 1991 rate order.
The assumptions used to calculate the $43 million proposed increase in the
annual accrual of decommissioning costs (such as the current
decommissioning costs estimate of $4.06 billion, after-tax earnings on the
tax-qualified and nontax-qualified decommissioning funds of 7.30% and
6.26%, respectively, as well as a future escalation rate of 5.3% in
decommissioning costs) reflect some uncertainty. The rate filing is
designed to provide greater assurance than current rate levels that
sufficient funds will be available in the external decommissioning trusts
for decommissioning expenditures when the nuclear plants are retired. The
current accrual of $127 million, coupled with accumulated earnings on the
trust fund assets, would provide approximately the same amount of funds to
pay estimated decommissioning costs if a 4.5% escalation rate is assumed.
Decommissioning costs are recorded as portions of depreciation expense
and accumulated provision for depreciation on the Statements of
Consolidated Income and the Consolidated Balance Sheets. As of December
31, 1993, the total decommissioning costs included in the accumulated
provision for depreciation was approximately $914 million. Illinois law
requires the Company to establish external trusts, and the ICC has
approved the Company's funding plan and requires annual contributions of
current accruals and ratable contributions of past accruals over the
remaining service lives of the nuclear plants. The book value of funds
accumulated in the external trusts at December 31, 1993 was approximately
$707 million. The earnings on the external trusts accumulate in the fund
balance and in the accumulated provision for depreciation. Such earnings
on the external trust funds for the years 1993, 1992, and 1991, which have
been recorded as a component of depreciation expense in the Company's
Statements of Consolidated Income, were $40,829,000, $32,443,000 and
$24,231,000, respectively.
33
Amortization of Nuclear Fuel. The cost of nuclear fuel is amortized to
fuel expense based on the quantity of heat produced using the unit of
production method. As authorized by the ICC, provisions for spent
nuclear fuel disposal costs have been recorded at a level required to
recover the fee payable on current nuclear-generated and sold
electricity and the current interest accrual on the one-time fee
payable to the Department of Energy (DOE) for nuclear generation prior
to April 7, 1983. The one-time fee and interest thereon have been
recovered and the current fee and current interest on the one-time fee
are currently being recovered through the fuel adjustment clause. See
Note 10 for further information concerning the disposal of spent
nuclear fuel, the one-time fee and the current interest accrual on the
one-time fee. Nuclear fuel expenses, including leased fuel costs and
provisions for spent nuclear fuel disposal costs, for the years 1993,
1992 and 1991 were $385,894,000, $366,821,000 and $331,913,000,
respectively.
In connection with the Energy Policy Act of 1992, investor-owned
electric utilities that have purchased enrichment services from the
DOE will be assessed annually for a fifteen-year period amounts to
fund a portion of the cost for the decontamination and decommissioning
of three nuclear enrichment facilities previously operated by the DOE.
The Company's portion of such assessments is estimated to be
approximately $15 million per year (to be adjusted annually for
inflation). The Act provides that such assessments are to be treated
as a cost of fuel. At December 31, 1993, the Company had recorded a
liability of approximately $177 million in other noncurrent
liabilities and approximately $29 million in other current
liabilities. The related asset was recorded in regulatory assets.
Approximately $15 million and $4 million associated with such
assessments were amortized to fuel expense in 1993 and 1992,
respectively, and were reflected in the fuel adjustment clause.
Income Taxes. Deferred income taxes are provided for income and
expense items recognized for financial accounting purposes in periods
that differ from those for income tax purposes. Income taxes deferred
in prior years are charged or credited to income as the book/tax
timing differences reverse. Prior years' deferred investment tax
credits are amortized through credits to income generally over the
lives of the related property. Income tax credits resulting from
interest charges applicable to nonoperating activities, principally
construction, are classified as other income.
For additional information relating to income taxes, including
information related to the Company's adoption in January 1993 of
Statement of Financial Accounting Standards (SFAS) No. 109, which
requires an asset and liability approach to accounting for income
taxes, see Note 14. In addition, see "Taxes" under the subcaption
"Results of Operations," in "Management's Discussion and Analysis of
Financial Condition and Results of Operations."
Allowance for Funds Used During Construction (AFUDC). In accordance
with uniform systems of accounts prescribed by regulatory authorities,
the Company capitalizes AFUDC, compounded semiannually, which
represents the estimated cost of funds used to finance its
construction program. The equity component of AFUDC is recorded on an
after-tax basis and the borrowed funds component of AFUDC is recorded
on a pre-tax basis. The average annual capitalization rates for the
years 1993, 1992 and 1991 were 10.05%, 10.31% and 11.07%,
respectively.
34
For additional information regarding AFUDC, see Note 14 and "Other
Items," under the subcaption "Results of Operations," in "Management's
Discussion and Analysis of Financial Condition and Results of
Operations."
Interest. Total interest costs incurred on debt, leases and other
obligations for the years 1993, 1992 and 1991 were $778,639,000,
$777,122,000 and $767,860,000, respectively.
Debt Discount, Premium and Expense. Discount, premium and expense on
long-term debt are being amortized over the lives of the respective
issues.
Loss on Reacquired Debt. Consistent with regulatory treatment, the net
loss from reacquisition of first mortgage bonds, debentures and
pollution control obligations prior to their scheduled maturity date
is deferred and amortized over the lives of the long-term debt or
notes issued to finance the reacquisition.
Deferred Recovery of Energy Costs. The uniform fuel adjustment clause
adopted by the ICC provides for the recovery of changes in fossil and
nuclear fuel costs and the energy portion of purchased power costs as
compared to the fuel and purchased energy costs included in base
rates. As authorized by the ICC, the Company has recorded under or
overrecoveries of allowable fuel and energy costs which, under the
clause, are recoverable or refundable in subsequent months. For
information relating to the annual reconciliation proceedings held by
the ICC with respect to the Company's fuel and power purchases, see
Note 3.
Regulatory Assets and Liabilities. Regulatory assets include the
unamortized portions of certain rate case and consultant costs
associated with the prudency audits of Byron and Braidwood stations
which the ICC allowed to be deferred and amortized for ratemaking
purposes, unamortized deferred depreciation related to Byron Unit 1
which the ICC allowed to be deferred and amortized over the remaining
life of the unit, unamortized losses on reacquired debt, unamortized
deferred carrying charges associated with the Byron and Braidwood
stations which the ICC allowed to be deferred and amortized for
ratemaking purposes, a regulatory asset for the Company's unamortized
balance of a fifteen-year assessment by the DOE for the
decontamination and decommissioning of certain enrichment facilities
and a regulatory asset recorded in compliance with SFAS No. 109, which
the Company adopted in January 1993. A regulatory liability was also
recorded in compliance with SFAS No. 109.
For additional information relating to rate case and consultant
costs and deferred carrying charges, see "Recovery/(Deferral) of
Regulatory Assets--Net," under the subcaption "Results of Operations,"
in "Management's Discussion and Analysis of Financial Condition and
Results of Operations."
35
Statements of Cash Flows. For purposes of the statements of
consolidated cash flows, temporary cash investments, generally
investments maturing in three months or less at the time of purchase,
are considered to be cash equivalents. Supplemental information
required by SFAS No. 95 for the years 1993, 1992 and 1991 is as
follows:
(thousands of dollars) 1993 1992 1991
------------------------------------------- -------- -------- --------
Supplemental cash flow information:
Cash paid during the year for:
Interest (net of amount capitalized) $677,669 $652,501 $700,876
Income taxes $103,014 $238,052 $210,714
Supplemental schedule of non-cash investing
and
financing activities:
Capital lease obligations incurred $213,758 $193,677 $244,030
------------------------------------------------------------------------
- ---------------------------------
2 Settlements Relating to Certain Rate Matters
On September 24, 1993, the Company's Board of Directors approved two
proposed settlements which the Company's management had reached with
parties involved in several of the proceedings and matters relating to
the level of the Company's rates for electric service. One of the
proposed settlements (Rate Matters Settlement) concerns the
proceedings relating to the Company's 1985 and 1991 ICC rate orders
(which orders relate to, among other things, the recovery of costs
associated with the Company's four most recently completed nuclear
generating plants, Byron Units 1 and 2 and Braidwood Units 1 and 2),
the proceedings relating to the reduction in the difference between
the Company's summer and non-summer residential rates that was
effected in the summer of 1988, outstanding issues relating to the
appropriate interest rate and rate design to be applied to a refund
made by the Company during 1990 relating to a December 1988 ICC rate
order, and matters related to a rider to the Company's rates that the
Company was required to file as a result of the change in the federal
corporate income tax rate made by the Tax Reform Act of 1986. The
other proposed settlement (Fuel Matters Settlement) relates to the ICC
fuel reconciliation proceedings involving the Company for the period
from 1985 through 1988 and to future challenges by the settling
parties to the prudency of the Company's western coal costs for the
period from 1989 through 1992. Each of these settlements was subject
to appropriate action by the ICC or the courts having jurisdiction
over the proceedings.
As a result of subsequent ICC and judicial actions, the Rate Matters
Settlement became final on November 4, 1993. Under the Rate Matters
Settlement, effective as of November 4, 1993, the Company reduced its
rates by approximately $339 million annually and commenced refunding
approximately $1.26 billion (including revenue taxes), plus interest
at five percent on the unpaid balance, through temporarily reduced
rates over an initial refund period scheduled to be twelve months (to
be followed by a reconciliation period of no more than five months).
The Company had previously deferred the recognition of revenues during
1993 as a result of developments in the proceedings related to the
March 1991 ICC rate order, which resulted in a reduction to 1993 net
income of approximately $160 million. The recording of the effects of
the Rate Matters Settlement in October 1993 reduced the Company's 1993
net income and retained earnings by approximately $292 million or
$1.37 per common share, in addition to the effect of the deferred
recognition of revenues and after the partially offsetting effect of
recording approximately $269 million (or $1.26 per common share) in
deferred carrying charges, net of income taxes, authorized in the ICC
rate order issued on January 6, 1993 (as subsequently modified, the
Remand Order). In January 1994, a purported class action was filed in
the Circuit Court of Cook County, Illinois (Circuit Court) challenging
the method in which the refunds are being made to residential
customers in the Rate Matters Settlement. The Company does not believe
that the complaint has any merit.
36
In the Remand Order, the rate determination was based upon, among
other things, findings by the ICC with respect to the extent to which
Byron Unit 2 and Braidwood Units 1 and 2 (Units) were "used and
useful" during the 1991 test year period of the rate order. With
respect to the "used and useful" issue, the ICC applied a needs and
economic benefits methodology, using a twenty percent reserve margin
and forecasted peak demand, and found Byron Unit 2 and Braidwood Units
1 and 2 to be 93%, 21% and 0%, respectively, "used and useful." The
Company has not recorded any disallowances related to the "used and
useful" issue. The Company considers the "used and useful"
disallowance in the Remand Order to be temporary. The ICC concluded in
the Remand Order that the forecasts in the record in that proceeding
indicate that Braidwood Units 1 and 2 will be fully "used and useful"
within the reasonably foreseeable future.
As a result of subsequent ICC actions, the Fuel Matters Settlement
became final on November 15, 1993. Under the Fuel Matters Settlement,
effective as of December 2, 1993, the Company commenced paying
approximately $108 million (including revenue taxes) to its customers
through temporarily reduced collections under its fuel adjustment
clause over a twelve-month period. The Company recorded the effects of
the Fuel Matters Settlement in October 1993, which effects reduced the
Company's net income and retained earnings by approximately $62
million or $0.29 per common share.
For additional information regarding the proceedings and matters
settled, see Notes 3, 17 and 19.
- -----------
3 Rate Matters
The Company's revenues, net income, cash flows and plant carrying
costs have been affected directly by various rate-related proceedings.
During the periods presented in the financial statements, the Company
was involved in proceedings concerning its October 1985 ICC rate order
(which related principally to the recovery of costs associated with
its Byron Unit 1 nuclear generating unit), proceedings concerning its
March 1991 ICC rate order (which related principally to the recovery
of costs associated with the Units), proceedings concerning the
reduction in the difference between the Company's summer and non-
summer residential rates that was effected in the summer of 1988, and
ICC fuel reconciliation proceedings principally concerning the
recoverability of the costs of the Company's western coal. In
addition, there were outstanding issues related to the appropriate
interest rate and rate design to be applied to a refund that was made
in 1990 following the reversal of a December 1988 ICC rate order and a
rider to the Company's rates that the Company was required to file as
a result of the change in the federal corporate income tax rate made
by the Tax Reform Act of 1986. The uncertainties associated with such
proceedings and issues, among other things, led to the Rate Matters
Settlement and the Fuel Matters Settlement. See Note 2 for additional
information.
For additional information regarding the foregoing proceedings, see
Notes 2 and 3 of Notes to Financial Statements in the Company's
Quarterly Report on Form 10-Q for the quarterly period ended June 30,
1993.
- --------------------------------------
4 Authorized Shares and Voting Rights of Capital Stock
At December 31, 1993, the authorized shares of capital stock were:
common stock--250,000,000 shares; preference stock--23,600,290 shares;
$1.425 convertible preferred stock--286,949 shares; and prior
preferred stock--850,000 shares. The prior preferred and preference
stocks are issuable in series and may be issued with or without
mandatory redemption requirements. Holders of shares at any time
outstanding, regardless of class, are entitled to one vote for each
share held on each matter submitted to a vote at a meeting of
shareholders, with the right to cumulate votes in all elections for
directors.
37
- -------------
5 Common Stock
At December 31, 1993, shares of common stock were reserved for the
following purposes:
Common stock reserved
-----------------------------------------------------------
1993 Stock Incentive Plan 4,000,000
Employe Stock Purchase Plan 1,422,368
Employe Savings and Investment Plan 565,803
Conversion of $1.425 convertible preferred stock 292,687
Conversion of warrants 42,899
------------------------------------------------------------
6,323,757
------------------------------------------------------------
Shares of common stock for the years 1993, 1992 and 1991 were issued
as follows:
Common stock issued 1993 1992 1991
---------------------- ------- ------- -------
Employe Stock Purchase
Plan 268,594 374,815 228,738
Employe Savings and
Investment Plan 153,400 235,900 132,140
Conversion of $1.425
convertible preferred
stock 22,375 16,221 28,146
Conversion of warrants 1,374 1,300 2,773
------------------------------------------------
445,743 628,236 391,797
------------------------------------------------
At December 31, 1993 and 1992, 128,699 and 133,003 common stock
purchase warrants, respectively, were outstanding. The warrants
entitle the holders to convert such warrants into common stock at a
conversion rate of one share of common stock for three warrants.
- -------------------------------------------------------
6 Preferred and Preference Stocks Without Mandatory Redemption Requirements
No shares of preferred or preference stocks without mandatory
redemption requirements were issued or redeemed by the Company during
1993, 1992 and 1991. The series of preference stock without mandatory
redemption requirements outstanding at December 31, 1993 are
summarized as follows:
Aggregate
Stated Value Involuntary
Shares (thousands Redemption Liquidation
Series Outstanding of dollars) Price(a) Price(a)
------ ----------- ------------ ---------- -----------
$1.90 4,249,549 $106,239 $ 25.25 $25.00
$2.00 2,000,000 51,560 $ 26.04 $25.00
$1.96 2,000,000 52,440 $ 27.11 $25.00
$7.24 750,000 74,340 $101.00 $99.12
$8.40 750,000 74,175 $101.00 $98.90
$8.38 750,000 73,566 $100.16 $98.09
------------------------------------------------------------------------------
10,499,549 $432,320
------------------------------------------------------------------------------
(a) Per share plus accrued and unpaid dividends, if any.
The outstanding shares of the $1.425 convertible preferred stock are
convertible at the option of the holders thereof, at any time, into
common stock at the rate of 1.02 shares of common stock for each share
of convertible preferred stock, subject to future adjustment. The
convertible preferred stock may be redeemed by the Company at $42 per
share, plus accrued and unpaid dividends, if any. The involuntary
liquidation price of the $1.425 convertible preferred stock is $31.80
per share, plus accrued and unpaid dividends, if any. During 1993,
1992 and 1991, 21,942 shares, 15,911 shares and 27,606 shares,
respectively, of the convertible preferred stock were converted into
common stock.
38
- ----------------------------------------------
7 Preference Stock Subject to Mandatory Redemption Requirements
During 1993, 700,000 shares of preference stock subject to mandatory
redemption requirements were issued. During 1992 and 1991, no shares
of preference stock subject to mandatory redemption requirements were
issued. The series of preference stock subject to mandatory redemption
requirements outstanding at December 31, 1993 are summarized as
follows:
Aggregate
Stated
Value
(thousands
Shares of
Series Outstanding dollars) Optional Redemption Price(a)
-------------- ----------- ---------- ---------------------------------------
$8.20 321,420 $ 32,142 $103 through October 31, 1997; and $101
thereafter
$8.40 Series B 418,870 41,605 $101
$8.85 375,000 37,500 $103 through July 31, 1998; and $101
thereafter
$9.25 825,000 82,500 $105 through July 31, 1994; $103
through July 31, 1999; and $101
thereafter
$9.00 650,000 64,431 Non-callable
$6.875 700,000 69,475 Non-callable
-------------------------------------------------------------------------------
3,290,290 $327,653
-------------------------------------------------------------------------------
(a) Per share plus accrued and unpaid dividends, if any.
The annual sinking fund requirements and sinking fund and
involuntary liquidation prices per share of the outstanding series of
preference stock subject to mandatory redemption requirements are
summarized as follows:
Sinking Fund Involuntary
Series Annual Sinking Fund Requirement Price(a) Liquidation Price(a)
-------------- ----------------------------------- ------------ --------------------
$8.20 35,715 shares $100 $100.00
$8.40 Series B 30,000 shares(b) $100 $ 99.326
$8.85 37,500 shares $100 $100.00
$9.25 75,000 shares $100 $100.00
$9.00 130,000 shares beginning in 1996(b) $100 $ 99.125
$6.875 (c) $100 $ 99.25
--------------------------------------------------------------------------------------
(a) Per share plus accrued and unpaid dividends, if any.
(b) The Company has a non-cumulative option to increase the annual
sinking fund payment on each sinking fund redemption date to
retire an additional number of shares, not in excess of the
sinking fund requirement, at the applicable redemption price.
(c) All shares are required to be redeemed on May 1, 2000.
Annual remaining sinking fund requirements through 1998 on
preference stock outstanding at December 31, 1993 will aggregate
$17,709,000 in 1994, $17,822,000 in 1995, $30,822,000 in 1996,
$30,822,000 in 1997 and $30,822,000 in 1998. During 1993, 1992 and
1991, 1,835,155 shares, 793,132 shares and 1,093,038 shares,
respectively, of preference stock subject to mandatory redemption
requirements were reacquired to meet sinking fund requirements.
Sinking fund requirements due within one year are included in
current liabilities.
On November 1, 1991, the Company redeemed 80,000 shares of its
$11.125 Series of preference stock at the sinking fund redemption
price of $100 per share, plus accrued and unpaid dividends and
redeemed all of the remaining 80,000 shares at the optional redemption
price of $100 per share, plus accrued and unpaid dividends.
On November 1, 1992, the Company redeemed 300,000 shares of its
$2.875 Series of preference stock at the optional redemption price of
$25 per share and 75,000 shares of its $11.70 Series of preference
stock at the optional redemption price of $100 per share, plus accrued
and unpaid dividends.
39
On June 28, 1993, the Company redeemed all 170,810 shares of its
$2.875 Series of preference stock and all 1,050,000 shares of its
$2.375 Series of preference stock, both at the optional redemption
price of $25.25 per share, plus accrued and unpaid dividends.
On November 1, 1993, the Company redeemed the remaining 75,000
shares of its $11.70 Series of preference stock (150,000 shares had
been redeemed on August 1, 1993 at the optional redemption price of
$105 per share, plus accrued and unpaid dividends). Of the remaining
75,000 shares, 37,500 shares were redeemed to meet the November 1,
1993 mandatory sinking fund requirement and 37,500 shares were
redeemed as a permitted optional sinking fund payment, both at the
sinking fund redemption price of $100 per share, plus accrued and
unpaid dividends.
On November 1, 1993, the Company redeemed all 210,000 shares of its
$9.30 Series of preference stock, of which 70,000 shares were redeemed
at the optional redemption price of $101.03 per share, plus accrued
and unpaid dividends, 70,000 shares were redeemed to meet the November
1, 1993 mandatory sinking fund requirement and 70,000 shares were
redeemed as a permitted optional sinking fund payment, the latter two
at the sinking fund redemption price of $100 per share, plus accrued
and unpaid dividends.
- -------------
8 Long-Term Debt
Sinking fund requirements and scheduled maturities remaining through
1998 for first mortgage bonds, debentures and other long-term debt
outstanding at December 31, 1993, after deducting debentures and first
mortgage bonds reacquired for satisfaction of future sinking fund
requirements, are summarized as follows: 1994 -- $446,724,000; 1995 --
$496,027,000; 1996 -- $233,449,000; 1997 -- $395,038,000; and 1998 --
$350,027,000.
At December 31, 1993, the Company had outstanding first mortgage
bonds maturing 1994 through 1998 as follows:
Principal Amount
Series (thousands of dollars)
--------------------------- ----------------------
6 1/8% due May 15, 1995 $103,000
5 1/4% due April 1, 1996 50,000
5 3/4% due November 1, 1996 50,000
5 3/4% due December 1, 1996 50,000
7% due February 1, 1997 150,000
5 3/8% due April 1, 1997 50,000
6 1/4% due October 1, 1997 60,000
6 1/4% due February 1, 1998 50,000
6% due March 15, 1998 130,000
6 3/4% due July 1, 1998 50,000
6 3/8% due October 1, 1998 75,000
----------------------------------------------------
$818,000
----------------------------------------------------
40
Other long-term debt outstanding at December 31, 1993 is summarized
as follows:
Principal Amount
Debt Security (thousands of dollars) Interest Rate Provisions
-------------------------------- ---------------------- ---------------------------------------------
Notes
Medium Term Notes, Series 1N $ 82,500 Interest rates ranging from 9.27% to
due various dates through 10.48%
April 1, 1998
Medium Term Notes, Series 2N 56,300 Interest rates ranging from 9.57% to
due various dates through 9.874%
July 1, 1996
Medium Term Notes, Series 3N 399,000 Interest rates ranging from 8.77% to
due various dates through 9.20%
October 15, 2004
Medium Term Notes, Series 4N 195,000 Interest rates ranging from 7.90% to
due various dates through 8.875%
May 15, 1997
Notes due April 15, 1994 180,000 Fixed interest rate of 5.75%
Notes due July 15, 1995 100,000 Fixed interest rate of 5.50%
Notes due July 15, 1997 100,000 Fixed interest rate of 6.50%
Notes due October 15, 2005 235,000 Fixed interest rate of 6.40%
-------------------------------------------------------------------------------------------------------
$1,347,800
-------------------------------------------------------------------------------------------------------
Long-Term Notes Payable to Banks
Note due January 9, 1995 $ 100,000 Prevailing interest rate of 4.00% at
December 31, 1993
Notes due July 31, 1995 150,000 Prevailing interest rates averaging 3.875% at
December 31, 1993
-------------------------------------------------------------------------------------------------------
$ 250,000
-------------------------------------------------------------------------------------------------------
Purchase Contract Obligations
Woodstock due January 2, 1997 $ 273 Fixed interest rate of 4.50%
Hinsdale due April 30, 2005 552 Fixed interest rate of 3.00%
-------------------------------------------------------------------------------------------------------
$ 825
-------------------------------------------------------------------------------------------------------
$1,598,625
-------------------------------------------------------------------------------------------------------
Long-term debt maturing within one year has been included in current
liabilities.
The Company's outstanding first mortgage bonds are secured by a lien
on substantially all property and franchises, other than expressly
excepted property, owned by the Company.
- ------------
9 Lines of Credit
The Company had total bank lines of credit of approximately $981
million and unused bank lines of credit of approximately $975 million
at December 31, 1993. Of that amount, $975 million (of which $175
million expires October 3, 1994, $40 million expires in equal
quarterly installments commencing on December 31, 1994 and ending on
September 30, 1996, $188 million expires in equal quarterly
installments commencing on December 31, 1995 and ending on September
30, 1997 and $572 million expires in equal quarterly installments
commencing on December 31, 1996 and ending on September 30, 1998) may
be borrowed on secured or unsecured notes of the Company at various
interest rates. The interest rate is set at the time of a borrowing
and is based on several floating rate bank indices plus a spread which
is dependent upon the Company's credit ratings, or on a prime interest
rate. Amounts under the remaining lines of credit may be borrowed at
prevailing prime interest rates on
41
unsecured notes of the Company. Collateral, if required for the
borrowings, would consist of first mortgage bonds issued under and in
accordance with the provisions of the Company's mortgage. The Company
is obligated to pay commitment fees with respect to $975 million of
such lines of credit.
- -----------------------
10 Disposal of Spent Nuclear Fuel
Under the Nuclear Waste Policy Act of 1982, the DOE is responsible for
the selection and development of repositories for, and the disposal
of, spent nuclear fuel and high-level radioactive waste. The Company,
as required by that Act, has signed a contract with the DOE to provide
for the disposal of spent nuclear fuel and high-level radioactive
waste from the Company's nuclear generating stations beginning not
later than January 1998. The contract with the DOE requires the
Company to pay the DOE a one-time fee applicable to nuclear generation
through April 6, 1983 of approximately $277 million, with interest to
date of payment, and a fee payable quarterly equal to one mill per
kilowatthour of nuclear-generated and sold electricity after April 6,
1983. The Company has elected to pay the one-time fee, with interest,
just prior to the first scheduled delivery of spent nuclear fuel to
the DOE, which is scheduled to occur not later than January 1998;
however, this delivery schedule is expected to be delayed
significantly. The Company has recorded the liability for the one-time
fee and the related interest.
- ---------------------------
11 Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair
value of financial instruments held by or issued and outstanding by
the companies. The disclosure of such information does not purport to
be a market valuation of the Company as a whole. The impact of any
realized or unrealized gains or losses related to such financial
instruments on the Company's financial position or results of
operations is dependent on the treatment authorized under future
ratemaking proceedings.
Investments. The estimated fair value of the Nuclear Decommissioning
Funds, as determined by the trustee for those funds, is based on
published market data. Financial instruments included in Other
Investments at a cost of approximately $4 million at December 31, 1993
and 1992, are not material in relation to other financial instruments
of the Company; therefore, an estimate of the fair value of these
instruments has not been made.
Current Assets. The carrying value of Cash, Temporary Cash Investments
and Other Cash Investments, which includes U.S. Government Obligations
and other short-term marketable securities, and Special Deposits,
which primarily includes cash deposited for the redemption, refund or
discharge of debt securities, approximates their fair value because of
the short maturity of these instruments.
Capitalization. The estimated fair value of Preferred and Preference
Stocks (Without and Subject to Mandatory Redemption Requirements) and
Long-Term Debt, including the current portion thereof, has been
obtained from an independent consultant. Estimated fair values exclude
accrued interest and preferred and preference dividends. Purchase
contract obligations included in Long-Term Debt at a cost of
approximately $1 million at December 31, 1993 and 1992, are not
material in relation to other financial instruments of the Company;
therefore, an estimate of the fair value of these instruments has not
been made. Long-Term Notes Payable to Banks in the amount of $250
million at December 31, 1993 and 1992, for which interest is paid at
prevailing rates are included in the financial statements at cost,
which approximates their fair value.
42
Current Liabilities. The carrying value of Notes Payable, which
consists of commercial paper and/or bank loans having a maturity of
less than one year, approximates their fair value because of the short
maturity of these instruments. See "Capitalization" above for a
discussion of the fair value of the current portion of long-term debt
and redeemable preference stock.
Other Noncurrent Liabilities. The carrying value of Accrued Spent
Nuclear Fuel Disposal Fee and Related Interest represents the
settlement value as of December 31, 1993 and 1992; therefore, the
carrying value is equal to the fair value.
The estimated fair values of the Company's financial instruments
other than those instruments reflected in the financial statements at
cost which approximates market, as of December 31, 1993 and 1992, are
as follows:
(thousands of dollars) December 31, 1993 December 31, 1992
------------------------- --------------------- ---------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
---------- ---------- ---------- ----------
Nuclear Decommissioning
Funds $ 706,841 $ 768,823 $ 533,463 $ 564,476
Capitalization (including
current portion):
Preferred and Preference
Stocks (without and
subject to mandatory
redemption
requirements) $ 769,098 $ 776,113 $ 790,584 $ 828,913
Long-Term Debt $7,819,785 $8,158,975 $7,770,248 $8,025,191
-----------------------------------------------------------------------
- --------------
12 Pension Benefits
The companies have non-contributory defined benefit pension plans
which cover all regular employes. Benefits under these plans reflect
each employe's compensation, years of service and age at retirement.
Funding is based upon actuarially determined contributions that take
into account the amount deductible for income tax purposes and the
minimum contribution required under the Employee Retirement Income
Security Act of 1974, as amended. Actuarial valuations were determined
as of January 1, 1993 and 1992.
During 1992, the companies implemented a workforce reduction program
designed to reduce the management workforce. This program included an
early retirement program and voluntary and involuntary separation
plans. The early retirement program resulted in the recognition for
the year 1992 of an additional $26 million of pension cost and the
disclosure of an additional $39 million of unrecognized net loss at
December 31, 1992 as reflected in the following table. The companies
also recognized in 1992 a charge to expense of $11 million primarily
related to the cost of the separation plans. The total charge to
income of $37 million in 1992 is approximately $23 million after
reflecting income tax effects.
43
The funded status of these plans at December 31, 1993 and 1992 was
as follows:
(thousands of dollars) December 31, 1993 1992
--------------------------------------------- ----------- -----------
Actuarial present value of accumulated
pension plan benefits:
Vested benefit obligation $(2,350,000) $(2,232,000)
Nonvested benefit obligation (118,000) (112,000)
-------------------------------------------------------------------------
Accumulated benefit obligation $(2,468,000) $(2,344,000)
Effect of projected future compensation
levels (477,000) (454,000)
-------------------------------------------------------------------------
Projected benefit obligation $(2,945,000) $(2,798,000)
Fair value of plan assets, invested primarily
in equity index funds, other managed equity
and fixed income investments, U.S.
Government, government-sponsored corporation
and agency securities and listed corporate
obligations 2,741,000 2,577,000
-------------------------------------------------------------------------
Plan assets less than projected benefit
obligation $ (204,000) $ (221,000)
Unrecognized prior service cost 24,000 25,000
Unrecognized transition asset (168,000) (181,000)
Unrecognized net loss 131,000 211,000
-------------------------------------------------------------------------
Accrued pension liability $ (217,000) $ (166,000)
-------------------------------------------------------------------------
The assumed discount rate was 7.5% and the assumed annual rate of
increase in future compensation levels was 4.0% at December 31, 1993
and 1992. These rates were used in determining the projected benefit
obligations, the accumulated benefit obligations and the vested
benefit obligations.
Pension costs were determined under the rules prescribed by SFAS No.
87, including the use of the projected unit credit actuarial cost
method and the following actuarial assumptions for periods during
1993, 1992 and 1991:
1993 1992 1991
----------------------------------------------------- ----- ----- -----
Annual discount rate 7.50% 7.50% 8.50%
Annual rate of increase in future compensation levels 4.00% 4.00% 5.00%
Annual long-term rate of return on plan assets 9.50% 9.50% 9.50%
-------------------------------------------------------------------------
The components of pension costs, portions of which were recorded as
components of construction costs, for the years 1993, 1992 and 1991
were as follows:
(thousands of dollars) 1993 1992 1991
---------------------------------- --------- --------- ---------
Service cost $ 96,000 $ 98,000 $ 81,000
Interest cost on projected benefit
obligation 204,000 189,000 174,000
Actual return on plan assets (310,000) (179,000) (495,000)
Early retirement program cost -- 26,000 --
Net amortization and deferral 61,000 (67,000) 286,000
---------------------------------------------------------------------
$ 51,000 $ 67,000 $ 46,000
---------------------------------------------------------------------
In addition, the companies provide an employe savings and investment
plan available to all regular employes who have completed three months
of service. Each participating employe may contribute up to 20% of
such employe's base pay and the companies match such contribution
equal to 70% of up to the first 5% of contributed base salary. During
1993, 1992 and 1991, the Company contributed $21,948,000, $20,023,000
and $14,643,000, respectively.
44
- ----------------------------
13 Postretirement Health Care Benefits
The companies provide certain postretirement health care benefits for
retirees and their dependents and for the surviving dependents of
eligible employes and retirees. Substantially all of the companies'
employes become eligible for postretirement health care benefits when
they reach retirement age while working for the companies. In 1980,
the companies began funding the liability for postretirement health
care benefits through a trust fund, and the estimated cost of
postretirement health care benefits has been accrued and funded over
the working lives of the employes. Funding is based upon actuarially
determined contributions that take into account the amount deductible
for income tax purposes.
For the years 1980 through 1992, the liability for postretirement
health care benefits and the related provisions for postretirement
health care were equivalent to actuarial normal costs attributed over
participants' employment periods from date of hire to the expected
retirement date based on the aggregate cost method. On January 1,
1993, the companies adopted SFAS No. 106, Employers' Accounting for
Postretirement Benefits Other Than Pensions, which requires that
postretirement benefits be determined based on the projected unit
credit actuarial cost method and attributed over employment periods of
plan participants to the date of eligibility for postretirement
benefits rather than over the entire employment period. By adopting
the new standard, the companies estimate that for the year ended
December 31, 1993, postretirement costs increased $20 million
resulting in a decrease in net income of $10 million or $0.05 per
common share, net of income taxes and the portion of the costs charged
to construction. The transition obligation of $588 million shown in
the following schedule is being amortized over 20.6 years. The
ultimate effects on income are dependent on the treatment authorized
in future ratemaking proceedings. As indicated in the previous
paragraph, the companies have accounted for postretirement health care
benefits on an accrual basis since 1980 and accrual basis costs have
been reflected in rates in ratemaking proceedings.
Actuarial valuations were determined as of January 1, 1993. The
funded status of the plan at January 1, 1993 and December 31, 1993 was
as follows:
(thousands of dollars) January 1, 1993 December 31, 1993
----------------------------------- --------------- -----------------
Actuarial present value of
accumulated postretirement health
care obligation:
Retirees $ (407,000) $ (444,000)
Active fully eligible participants (60,000) (65,000)
Other participants (538,000) (586,000)
-------------------------------------------------------------------------
Accumulated benefit obligation $(1,005,000) $(1,095,000)
Fair value of plan assets, invested
primarily in S&P 500 common
stocks, equity and fixed income
mutual funds, and U.S. Government
and listed corporate obligations 365,000 458,000
-------------------------------------------------------------------------
Plan assets less than accumulated
postretirement health care
obligation $ (640,000) $ (637,000)
Unrecognized transition obligation 588,000 559,000
Unrecognized net gain -- (9,000)
-------------------------------------------------------------------------
Accrued liability for
postretirement health care $ (52,000) $ (87,000)
-------------------------------------------------------------------------
For 1993, different health care cost trends are used for pre-
Medicare and post-Medicare expenses. Pre-Medicare trend rates are
14.5% for 1993 grading down in 0.5% annual increments to 5%. Post-
Medicare trend rates are 12% for 1993 grading down in 0.5% annual
increments to 5%. The effect of a 1% increase in the assumed health
care cost trend rates for each future year would increase the
45
accumulated postretirement health care obligation at January 1, 1993
by approximately $184 million and increase the aggregate of the
service and interest cost components of plan costs by approximately
$27 million for the year ended December 31, 1993. The annual discount
rate used was 7.5% and the annual long-term rate of return on plan
assets was 9.5%, or 9.1% after including income tax effects.
The components of postretirement health care costs, portions of
which were recorded as components of construction costs, for 1993 were
as follows:
(thousands of dollars) 1993
----------------------------------------------- --------
Service cost $ 45,000
Interest cost on accumulated benefit obligation 74,000
Actual return on plan assets (42,000)
Amortization of transition obligation 29,000
Other net deferral 10,000
-----------------------------------------------------------
$116,000
-----------------------------------------------------------
- ------------
14 Income Taxes
The components of the net deferred income tax liability at January 1,
1993 and December 31, 1993 are as follows:
January 1, December 31,
(thousands of dollars) 1993 1993
--------------------------------------------- ---------- ------------
Deferred tax liabilities:
Accelerated cost recovery and liberalized
depreciation, net of removal costs $2,831,103 $3,095,855
Overheads capitalized 145,951 286,287
Repair allowance 231,647 210,302
Regulatory assets recoverable through future
rates 1,545,643 1,729,890
Deferred tax assets:
Postretirement benefits (101,086) (134,590)
Unbilled revenues (91,410) (98,164)
Loss carryforward -- (175,197)
Alternative minimum tax (111,961) (137,328)
Unamortized investment tax credits to be
settled through future rates (487,184) (490,047)
Other regulatory liabilities to be settled
through future rates (89,490) (102,383)
Other--net (51,753) (80,751)
-------------------------------------------------------------------------
Net deferred income tax liability $3,821,460 $4,103,874
-------------------------------------------------------------------------
The $282 million increase in the net deferred income tax liability
from January 1, 1993 to December 31, 1993 is comprised of $114 million
deferred income tax expense and a $168 million increase in regulatory
assets net of regulatory liabilities pertaining to income taxes for
the period.
For the $282 million increase in the net deferred income tax
liability from January 1, 1993 to December 31, 1993, approximately
$185 million resulted from an increase in the federal statutory
corporate income tax rate from 34% to 35% effective January 1, 1993,
and from the elimination of a scheduled reduction in a component of
the statutory Illinois income tax rate which was to have declined to
4.4% from 4.8%, effective July 1, 1993. The $185 million net increase
resulted from recording an increase to regulatory assets of
approximately $224 million and an increase to regulatory liabilities
of approximately $39 million. See "Taxes" and "Regulatory Assets"
under the subcaption "Results of Operations," in "Management's
Discussion and Analysis of Financial Condition and Results of
Operations."
46
The components of net income tax expense charged to continuing
operations are as follows:
(thousands of dollars) 1993 1992 1991
-------------------------------------- -------- -------- --------
Electric operating income:
Current income taxes $(27,553) $161,388 $289,437
Deferred income taxes 122,804 142,895 162,037
Investment tax credits deferred--net (29,424) (32,506) (32,054)
Other (income) and deductions (30,753) (6,214) (65,274)
----------------------------------------------------------------------
Net income taxes charged to continuing
operations $ 35,074 $265,563 $354,146
----------------------------------------------------------------------
Provisions for current and deferred federal and state income taxes
and amortization of investment tax credits resulted in the following
effective income tax rates for the years 1993, 1992 and 1991:
1993 1992 1991
---------------------------------- -------- -------- --------
Pre-tax book income (in thousands) $137,776 $779,544 $449,033
Effective income tax rate 25.5% 34.1% 78.9%
------------------------------------------------------------------
The principal differences between these rates and the federal
statutory corporate income tax rate of 35% for 1993 and 34% for 1992
and 1991 were as follows:
1993 1992 1991
------------------------------------------------- ----- ---- ----
Federal statutory corporate income tax rate 35.0% 34.0% 34.0%
Equity component of AFUDC which was excluded from
taxable income (5.2) (0.9) (1.4)
Amortization of investment tax credits (21.4) (3.4) (7.2)
State income tax, net of federal income tax 9.5 5.6 11.7
Disallowed plant costs -- -- 34.3
Differences between book and tax accounting
primarily for property related deductions 1.5 -- 5.5
Other--net 6.1 (1.2) 2.0
----------------------------------------------------------------------
Effective income tax rate 25.5% 34.1% 78.9%
----------------------------------------------------------------------
The Company has recorded current federal income tax liabilities that
include excess amounts of alternative minimum tax (AMT) over the
regular federal income tax, which amounts were also recorded as
decreases to deferred federal income taxes. As shown in the first
table, the cumulative excess amounts of AMT so recorded in the amount
of approximately $137 million as of December 31, 1993 can be carried
forward indefinitely as a credit against future years' regular federal
income tax liabilities. In 1993, the Company recorded a loss for
income tax purposes which may be carried forward through 2008. It is
currently expected that the income tax effect of the loss carryforward
in the amount of $175 million, as shown in the first table, will be
utilized by the expiration date.
The Company adopted SFAS No. 109, effective January 1, 1993. SFAS
No. 109 requires an asset and liability approach to accounting for
income taxes which replaces the deferred method formerly used. Under
the asset and liability approach, the deferred income tax liability
represents the income tax effect of temporary differences between
financial accounting and income tax bases of assets and liabilities
and is determined at the presently enacted income tax rates. The SFAS
No. 109 adjustments to the Company's deferred income tax liability
related to utility operations represents income taxes recoverable or
returnable through future rates and have been recorded as regulatory
assets and regulatory liabilities on the balance sheet. The cumulative
effect of the change in the method of accounting for income taxes
resulted in an increase to net income of $9.7 million or $0.05 per
common share, due primarily to the reduction of deferred income taxes
on nonregulated activities (primarily nonconsolidated subsidiaries)
accrued in prior years at income tax rates in excess of the presently
enacted income tax rates. The effect
47
of the implementation entry on regulated activities was to record
regulatory assets of $1,546 million primarily related to the equity
component of AFUDC which was previously recorded on an after-tax
basis, the borrowed funds component of AFUDC which was previously
recorded net of tax and other temporary differences for which the
related tax effects were not previously recorded; regulatory
liabilities of $577 million primarily related to recognition of the
deferred income tax effects of unamortized investment tax credits and
to the changes in prior years' income tax rates; and a net increase to
the deferred income tax liability of $969 million.
For comparability purposes in presentation, Deferred Income Taxes
shown on the Consolidated Balance Sheets as of December 31, 1992 were
reclassified from a valuation reserve deducted from Utility Plant to
Current Assets and to Deferred Credits and Other Noncurrent
Liabilities, consistent with the presentation as of December 31, 1993
required by the new accounting standard.
- ---------------------
15 Taxes, Except Income Taxes
Provisions for taxes, except income taxes, for the years 1993, 1992
and 1991 were as follows:
(thousands of dollars) 1993 1992 1991
-------------------------------- -------- -------- --------
Illinois public utility revenue $199,498 $204,004 $218,137
Illinois invested capital 111,126 107,207 111,872
Municipal utility gross receipts 107,232 129,250 128,302
Real estate 162,560 162,151 148,356
Municipal compensation 56,878 73,323 74,218
Other--net 64,619 67,974 61,685
-------------------------------------------------------------
$701,913 $743,909 $742,570
-------------------------------------------------------------
- ---------------
16 Lease Obligations
On November 23, 1993, the Company consolidated its nuclear fuel lease
arrangements into a new arrangement. Under the new arrangement, the
Company may sell and lease back nuclear fuel from a lessor who may
borrow an aggregate of $700 million (consisting of $300 million of
commercial paper or bank borrowings and $400 million of intermediate
term notes) to finance the transactions. The commercial paper/bank
borrowing portion currently will expire on November 23, 1996, but the
Company plans to ask for an extension of the expiration date. At
December 31, 1993, the Company's obligation to the lessor for leased
nuclear fuel amounted to $516 million. The Company has agreed to make
lease payments which cover the amortization of the nuclear fuel used
in the Company's reactors plus the lessor's related financing costs.
The Company has an obligation for spent nuclear fuel disposal costs of
leased nuclear fuel.
Future minimum rental payments, net of executory costs, at December
31, 1993 for capital leases, are estimated to aggregate $574 million,
including $224 million in 1994, $146 million in 1995, $97 million in
1996, $61 million in 1997, $31 million in 1998 and $15 million in
1999-2000. The estimated interest component of such rental payments
aggregates $53 million. The estimated portions of obligations due
within one year under capital leases are included in current
liabilities and approximated $166 million and $178 million at December
31, 1993 and 1992, respectively.
The Company has entered into an operating lease for new aluminum
coalporter rail cars. The lease covers only the cost of the rail cars,
thereby not including any operating, maintenance or other related
costs. Future minimum rental payments at December 31, 1993 for this
operating lease are estimated to aggregate $108 million, including $2
million in 1994, $5 million in 1995, $5 million in 1996, $5 million in
1997, $5 million in 1998 and $86 million in 1999-2013.
48
- --------------------------------------
17 Investments in Uranium- and Coal-Related Properties
At December 31, 1993, the Company and its subsidiaries had investments
of approximately $134 million in uranium-related properties, equipment
and activities and approximately $517 million in coal reserves.
Production of uranium from all of the uranium properties has been
deferred due to depressed market prices for uranium. The Company
currently expects ultimately to recover the cost of the uranium
properties in all material respects in relation to the Company's
financial position and its results of operations, but doing so depends
on substantially improved market conditions. However, the Company
continues to evaluate its ability ultimately to recover the cost of
its uranium properties. In prior years, the Company's commitments for
the purchase of coal under long-term contracts exceeded its
requirements. Rather than take all the coal it was required to take,
the Company agreed to purchase the coal in place in the form of coal
reserves. The Company has been allowed to recover from its customers
the costs of the coal reserves through its fuel adjustment clause as
the coal is used for the generation of electricity. However, the
Company is not earning a return on the expenditures for coal reserves
prior to the coal reserves being used for the generation of
electricity by including the coal reserves in rate base. See
"Management's Discussion and Analysis of Financial Condition and
Results of Operations," subcaptions "Liquidity and Capital Resources"
and "Results of Operations," for information concerning coal
commitments and the Company's fuel supply, respectively. See Note 19
for additional information concerning the Company's coal commitments.
During 1989 and 1991, actions were brought in federal and state
courts in Colorado against the Company and its subsidiary, Cotter
Corporation (Cotter), alleging that Cotter has permitted radioactive
and other hazardous material to be released from its mill into areas
owned or occupied by the plaintiffs resulting in property damage and
potential adverse health effects. The plaintiffs seek from Cotter and
the Company unspecified compensatory, exemplary and medical monitoring
fund damages, unspecified response costs under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980, and
temporary and permanent injunctive relief. Although the cases will
necessarily involve the resolution of numerous contested issues of
fact and law, the Company's determination is that these actions will
not have a material adverse impact on the Company's financial
statements.
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18 Joint Plant Ownership
The Company has a 75% undivided ownership interest in the Quad-Cities
nuclear generating station. Further, the Company is responsible for
75% of all costs which are charged to appropriate investment,
operation or maintenance accounts and provides its own financing. At
December 31, 1993, for its share of ownership in the station, the
Company had an investment of $533 million in production and
transmission plant in service (before reduction of $159 million for
the related accumulated provision for depreciation) and $53 million in
construction work in progress.
- -------------------------------------------------
19 Commitments, Contingent Liabilities and the Construction Program
Purchase commitments, principally related to construction and nuclear
fuel, approximated $1,187 million at December 31, 1993. In addition,
the Company has substantial commitments for the purchase of coal under
long-term contracts. The Company's coal costs are high compared to
those of other utilities. The Company's western coal contracts and its
rail contracts for delivery of the western coal were renegotiated
during 1992 effective as of January 1, 1993, to provide, among other
things, for significant reductions in the delivered price of the coal
over the duration of the contracts. However, the
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renegotiated contracts provide for the purchase of certain coal at
prices substantially above currently prevailing market prices and the
Company has significant purchase commitments under its contracts. See
"Management's Discussion and Analysis of Financial Condition and
Results of Operations," subcaption "Liquidity and Capital Resources,"
for additional information regarding the Company's purchase
commitments.
The Company is a member of Nuclear Mutual Limited (NML), established
to provide insurance coverage against property damage to members'
nuclear generating facilities. The members are subject to a
retrospective premium adjustment in the event losses exceed
accumulated reserve funds. Capital has been accumulated in the reserve
funds of NML to the extent that the Company would have no exposure in
the event of a single incident. However, the Company could be subject
to a maximum assessment of approximately $70 million in any policy
year, in the event losses exceed accumulated reserve funds.
If the Company had terminated its insurance coverages with NML
as of December 31, 1993, it would have a contingent right to receive
approximately $120 million, payable over a twenty-year period
commencing in 1996. Any unpaid amounts, however, are subject to
forfeiture in the event that NML's aggregate losses in any
subsequent two year period exceed $300 million or fifty percent
of its surplus. If any such asset were to be recorded, the Company
expects that a corresponding regulatory liability would also be
recorded.
The Company also is a member of Nuclear Electric Insurance Limited
(NEIL), which provides insurance coverage against the cost of
replacement power obtained during certain prolonged accidental outages
of nuclear generating units and coverage for property losses in excess
of $500 million occurring at nuclear stations. All companies insured
with NEIL are subject to retrospective premium adjustments if losses
exceed accumulated reserve funds. Capital has been accumulated in the
reserve funds of NEIL to the extent that the Company would have no
exposure in the event of a single incident under the replacement power
coverage and the property damage coverage. However, the Company could
be subject to maximum assessments, in any policy year, of
approximately $27 million and $87 million in the event losses exceed
accumulated reserve funds under the replacement power and property
damage coverages, respectively.
The NRC's indemnity for public liability coverage under the Price-
Anderson Act is supported by a mandatory industry-wide program under
which owners of nuclear generating facilities could be assessed in the
event of nuclear incidents. Based on the number of nuclear reactors
with operating licenses, the Company would currently be subject to a
maximum assessment of $991 million in the event of an incident,
limited to a maximum of $125 million in any calendar year. The current
maximum assessment was effective August 20, 1993 and represents an
increase of $164 million over the previous maximum assessment of $827
million. The Act requires that the assessment program be adjusted for
inflation every five years, and 1993 was an adjustment year.
In addition, the Company participates in the American Nuclear
Insurers and Mutual Atomic Energy Liability Underwriters Master Worker
Program which provides coverage for worker tort claims filed for
bodily injury caused by the nuclear energy hazard. The coverage
applies to workers whose "nuclear related employment" began after
January 1, 1988. The Company would currently be subject to a maximum
assessment of approximately $37 million in the event losses exceed
accumulated reserve funds.
See "Management's Discussion and Analysis of Financial Condition and
Results of Operations," subcaption "Liquidity and Capital Resources,"
for information relating to the Company's construction program and
rates and financial condition.
Shareholder derivative lawsuits were filed on October 1, 1992 and on
April 14, 1993 in the Circuit Court against current and former
directors of the Company alleging that they breached their fiduciary
duty and duty of care to the Company in connection with the management
of the activities associated with the construction of the Company's
four most recently completed nuclear generating units. The lawsuits
sought restitution to the Company by the defendants for unquantified
and undefined losses and costs alleged to have been incurred by the
Company. Both lawsuits were dismissed by the Circuit Court; however,
appeals are pending before the Illinois Appellate Court.
50
The Company is involved in administrative and legal proceedings
concerning air quality, water quality and other matters. The outcome
of these proceedings may require increases in the Company's future
construction expenditures and operating expenses. The Company and its
subsidiaries are or are likely to become parties to proceedings
initiated by the United States Environmental Protection Agency, state
agencies and/or other responsible parties under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980
(CERCLA) with respect to a number of sites, including manufactured gas
plant (MGP) sites, or may voluntarily undertake to investigate and
remediate sites for which they may be liable under CERCLA. While there
is a possibility that in the aggregate the cost of MGP site
investigation and remediation will be substantial over time, the
Company is not able to determine the most probable liability for MGPs.
In accordance with accounting standards, the Company recorded a
provision of $25 million in 1991 which reflects the low end of the
range of its estimate of the liability associated with former MGPs. In
1993, the Company recorded a provision of $5 million which reflects
the low end of the range of its estimate of the liability associated
with cleanup costs of remediation sites other than former MGP sites.
The Company presently estimates that its costs of investigating and
remediating these other sites pursuant to CERCLA and state
environmental laws will not in the aggregate be material to the
business or operations of the Company. These cost estimates are based
on currently available information regarding the responsible parties
likely to share in the costs of responding to site contamination, the
extent of contamination at sites for which the investigation has not
yet been completed and the cleanup levels to which sites are expected
to have to be remediated.
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20 Subsequent Events
On January 25, 1994, the Company announced the closing of the sale of
$66 million of Pollution Control Revenue Refunding Bonds issued
through the Illinois Development Finance Authority.
On January 25, 1994, the Company announced that the following
Illinois Environmental Facilities Financing Authority Pollution
Control Revenue Bonds will be redeemed: on March 11, 1994, all $50
million of the outstanding Series 1979 Bonds (consisting of $10
million of 8 3/8% bonds due November 1, 2004 and $40 million of 8 1/2%
bonds due November 1, 2009), and on April 1, 1994, all of the
outstanding Series 1983 Bonds, consisting of $16 million of 9 3/4%
bonds due April 1, 2013.
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21 Quarterly Financial Information
Net Average Earnings
Electric Income Number of (Loss)
Electric Operating Net (Loss) on Common Per
Operating Income Income Common Shares Common
Three Months Ended Revenues (Loss) (Loss) Stock Outstanding Share
------------------- ---------- --------- --------- --------- ----------- --------
(thousands except
per share data)
March 31, 1992 $1,422,557 $ 265,806 $ 67,254 $ 49,303(a) 212,713 $ 0.23
June 30, 1992 $1,431,749 $ 271,705 $ 105,825 $ 87,919(a) 212,860 $ 0.41
September 30, 1992 $1,708,880 $ 398,869 $ 235,865 $ 218,151 212,973 $ 1.02
December 31, 1992 $1,463,135 $ 260,523 $ 105,037 $ 88,069 213,170 $ 0.41
March 31, 1993 $1,483,385 $ 240,840 $ 77,212 $ 60,575 213,337 $ 0.28
June 30, 1993 $1,430,547 $ 237,223 $ 75,094 $ 58,051 213,466 $ 0.27
September 30, 1993 $1,872,448 $ 456,227 $ 287,123 $ 270,558 213,550 $ 1.27
December 31, 1993 $ 474,060 $(530,475) $(326,989) $(342,796)(b) 213,680 $(1.60)
------------------------------------------------------------------------------------------
(a) See "Earnings per Common Share" under the subcaption "Results of
Operations," in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" for information concerning
the reduction to net income recorded in 1992 which reflected a
provision for additional refunds and interest related to the 1985
ICC rate order.
(b) See Note 2 for information concerning the Rate Matters Settlement,
which lowered the level of the Company's rates and provides for
substantial customer refunds, and the Fuel Matters Settlement,
which provides for payments to customers.
51