THE TOLEDO EDISON COMPANY
2001 ANNUAL REPORT TO STOCKHOLDERS
The Toledo Edison Company is a wholly owned electric utility
operating subsidiary of FirstEnergy Corp. It engages in the generation,
distribution and sale of electric energy in an area of approximately 2,500
square miles in northwestern Ohio. It also engages in the sale, purchase and
interchange of electric energy with other electric companies. The area it serves
has a population of approximately 0.8 million.
Contents Page
- -------- ----
Selected Financial Data.......................................... 1
Management's Discussion and Analysis............................. 2-7
Consolidated Statements of Income................................ 8
Consolidated Balance Sheets...................................... 9
Consolidated Statements of Capitalization........................ 10-11
Consolidated Statements of Common Stockholder's Equity........... 12
Consolidated Statements of Preferred Stock....................... 12
Consolidated Statements of Cash Flows............................ 13
Consolidated Statements of Taxes................................. 14
Notes to Consolidated Financial Statements....................... 15-24
Report of Independent Public Accountants......................... 25
THE TOLEDO EDISON COMPANY
SELECTED FINANCIAL DATA
Nov. 8- Jan. 1-
2001 2000 1999 1998 Dec. 31, 1997 Nov. 7, 1997
- ------------------------------------------------------------------------------------------------------------
(Dollars in thousands)
GENERAL FINANCIAL INFORMATION:
Operating Revenues............. $1,094,903 $ 954,947 $ 921,159 $ 957,037 $ 122,669 | $ 772,707
========== ========== ========== ========== ========== | =========
|
Operating Income............... $ 105,484 $ 193,414 $ 163,772 $ 180,261 $ 19,055 | $ 123,282
========== ========== ========== ========== ========== | =========
|
Income Before Extraordinary |
Item.......................... $ 62,911 $ 137,233 $ 99,945 $ 106,582 $ 7,616 | $ 41,769
========== ========== ========== ========== ========== | =========
|
Net Income (Loss).............. $ 62,911 $ 137,233 $ 99,945 $ 106,582 $ 7,616 | $(150,132)
========== ========== ========== ========== ========== | =========
|
Earnings (Loss) on Common Stock $ 46,776 $ 120,986 $ 83,707 $ 92,972 $ 7,616 | $(169,567)
========== ========== ========== ========== ========== | =========
|
Total Assets................... $2,572,118 $2,652,267 $2,666,928 $2,768,765 $2,758,152 |
========== ========== ========== ========== ========== |
|
CAPITALIZATION: |
Common Stockholder's Equity.... $ 637,665 $ 605,587 $ 551,704 $ 575,692 $ 531,650 |
Preferred Stock- |
Not Subject to Mandatory |
Redemption.................. 126,000 210,000 210,000 210,000 210,000 |
Subject to Mandatory Redemption -- -- -- -- 1,690 |
Long-Term Debt................. 646,174 944,193 981,029 1,083,666 1,210,190 |
---------- ---------- ---------- ---------- ---------- |
Total Capitalization........... $1,409,839 $1,759,780 $1,742,733 $1,869,358 $1,953,530 |
========== ========== ========== ========== ========== |
|
CAPITALIZATION RATIOS: |
Common Stockholder's Equity.... 45.2% 34.4% 31.7% 30.8% 27.2%|
Preferred Stock- |
Not Subject to Mandatory |
Redemption.................. 9.0 11.9 12.0 11.2 10.8 |
Subject to Mandatory Redemption -- -- -- -- 0.1 |
Long-Term Debt................. 45.8 53.7 56.3 58.0 61.9 |
----- ----- ----- ----- ----- |
Total Capitalization........... 100.0% 100.0% 100.0% 100.0% 100.0%|
===== ===== ===== ===== ===== |
|
DISTRIBUTION KILOWATT-HOUR |
DELIVERIES (Millions): |
Residential.................... 2,258 2,183 2,127 2,252 355 | 1,718
Commercial..................... 2,667 2,380 2,236 2,425 284 | 1,498
Industrial..................... 5,397 5,595 5,449 5,317 847 | 4,003
Other.......................... 61 49 54 63 79 | 413
------ ------ ------ ------ ----- | -----
Total.......................... 10,383 10,207 9,866 10,057 1,565 | 7,632
====== ====== ===== ====== ===== | =====
|
CUSTOMERS SERVED: |
Residential.................... 270,589 269,071 266,900 265,237 262,501 |
Commercial..................... 31,680 31,413 32,481 31,982 29,367 |
Industrial..................... 1,898 1,917 1,937 1,954 1,835 |
Other.......................... 443 598 398 359 347 |
------- ------- ------- ------- ------- |
Total.......................... 304,610 302,999 301,716 299,532 294,050 |
======= ======= ======= ======= ======= |
|
Number of Employees (a)........ 507 539 977 997 1,532 |
|
<FN>
(a) Reduction in 2000 reflects transfer of responsibility for generation operations to
FirstEnergy Corp.'s competitive services unit.
</FN>
THE TOLEDO EDISON COMPANY
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
This discussion includes forward-looking statements based on
information currently available to management that is subject to certain risks
and uncertainties. Such statements typically contain, but are not limited to,
the terms anticipate, potential, expect, believe, estimate and similar words.
Actual results may differ materially due to the speed and nature of increased
competition and deregulation in the electric utility industry, economic or
weather conditions affecting future sales and margins, changes in markets for
energy services, changing energy and commodity market prices, legislative and
regulatory changes (including revised environmental requirements), and the
availability and cost of capital.
Corporate Separation
- --------------------
Beginning on January 1, 2001, Ohio customers were able to choose
their electricity suppliers as a result of legislation which restructured the
electric utility industry. That legislation required unbundling the price for
electricity into its component elements - including generation, transmission,
distribution and transition charges. Also, Ohio utilities that offer both
competitive and regulated retail electric services were required to implement a
corporate separation plan approved by the Public Utilities Commission of Ohio
(PUCO) -- one which provides a clear separation between regulated and
competitive operations. In connection with FirstEnergy's transition plan,
FirstEnergy separated its businesses into three distinct units -- a competitive
services unit, a utility services unit and a corporate support services unit. We
are included in the utility services unit and continue to deliver power to homes
and businesses through our existing distribution system and maintain the
"provider of last resort" (PLR) obligations under our rate plan.
As a result of the transition plan, FirstEnergy's electric utility
operating companies (EUOC) entered into power supply agreements whereby
FirstEnergy Solutions Corp. (FES) purchases all of the EUOC nuclear generation,
as well as generation from leased fossil generating facilities. FirstEnergy
Generation Corp. (FGCO), a wholly owned subsidiary of FES, leases fossil
generating units owned by the EUOC. We are a "full requirements" customer of FES
to enable us to meet our PLR responsibilities in our service area. We continue
to provide power directly to wholesale customers under previously negotiated
contracts as well as to alternative energy suppliers as part of our market
support generation of 160 megawatts (129 megawatts committed as of December 31,
2001).
The effect on our reported results of operations during 2001 from
FirstEnergy's corporate separation plan and our sale of transmission assets to
American Transmission Systems, Inc. (ATSI) in September 2000, are summarized in
the following tables:
Corporate Restructuring - 2001 Income Statement Effects
- --------------------------------------------------------------------------------
Increase (Decrease)
Corporate
Separation ATSI Total
---------- ---- -----
(In millions)
Operating Revenues:
Power supply agreement with FES..... $180.9 $ -- $180.9
Generating units rent............... 14.0 -- 14.0
Ground lease with ATSI.............. -- (0.2) (0.2)
- -------------------------------------------------------------------------
Total Operating Revenues Effect..... $194.9 $(0.2) $194.7
=========================================================================
Operating Expenses and Taxes:
Fossil fuel costs................... $(39.8)(a) $ -- $(39.8)
Purchased power costs............... 388.0 (b) -- 388.0
Other operating costs............... (21.6)(a) 7.6 (d) (14.0)
Provision for depreciation and
amortization -- (2.7)(e) (2.7)
General taxes....................... (2.0)(c) (3.3)(e) (5.3)
Income taxes........................ (50.4) 0.1 (50.3)
- -------------------------------------------------------------------------
Total Operating Expenses Effect..... $274.2 $ 1.7 $275.9
=========================================================================
Other Income.......................... $ -- $ 2.0 (f) $ 2.0
=========================================================================
(a) Transfer of fossil operations to FGCO.
(b) Purchased power from power supply agreement (PSA).
(c) Payroll taxes related to employees transferred to FGCO.
(d) Transmission services received from ATSI.
(e) Depreciation and property taxes related to transmission assets sold
to ATSI.
(f) Interest on note receivable from ATSI.
Results of Operations
- ---------------------
Earnings on common stock in 2001 decreased 61% to $46.8 million from
$121.0 million in 2000. Excluding the effects shown in the table above, earnings
on common stock increased by 4.1% in 2001 from 2000, being favorably affected by
reduced operating expenses and taxes, and lower net interest charges, which were
substantially offset by reduced operating revenues. In 2000, earnings on common
stock increased 45% to $121.0 million from $83.7 million in 1999. Results in
2000 were favorably affected by higher operating revenues and lower fuel and
purchased power costs, other operating costs and net interest charges.
Excluding the effects shown in the table above, operating revenues
decreased by $54.7 million or 5.7% in 2001 from 2000 following a $33.8 million
increase in 2000 from the prior year. Customer choice in Ohio and the influence
of a declining national economy on our regional business activity combined to
lower operating revenues. Sales of electric generation provided by other
suppliers in our service area represented 5.6% of total energy delivered in
2001. Retail generation sales declined in all customer categories resulting in
an overall 4.0% reduction in kilowatt-hour sales from the prior year.
Distribution deliveries increased 1.7% in 2001 from the prior year despite the
weaker national economic environment. As part of Ohio's electric utility
restructuring law, the implementation of a 5% reduction in generation charges
for residential customers reduced operating revenues by approximately $8.0
million in 2001, compared to 2000. Operating revenues were also lower in 2001
from the prior year due to the absence of revenues associated with the
low-income payment plan now administered by the Ohio Department of Development;
there was also a corresponding reduction in other operating costs associated
with that change. Revenues from kilowatt-hour sales to wholesale customers
declined $36.5 million in 2001 from last year, with a corresponding 37.2%
reduction in kilowatt-hour sales.
In 2000, additional kilowatt-hour sales to retail customers, which
were partially offset by lower average retail unit prices, and sales to the
wholesale market, were the primary contributors to higher operating revenues,
compared to 1999. Sales to wholesale customers in 2000 benefited from additional
available generating capacity. Kilowatt-hour sales to residential, commercial
and industrial customers were all higher in 2000, compared to the preceding
year. Transmission service revenues also contributed to the increase in
operating revenues.
Changes in KWH Sales 2001 2000
------------------------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail................................ (4.0)% 3.5%
Wholesale............................. (37.2)%* 30.1%
------------------------------------------------------------------
Total Electric Generation Sales......... (11.8)% 8.7%
==================================================================
Distribution Deliveries:
Residential........................... 3.4% 2.6%
Commercial and industrial............. 1.1% 3.8%
------------------------------------------------------------------
Total Distribution Deliveries........... 1.7% 3.5%
==================================================================
* Excluding PSA kilowatt-hour sales related to restructuring.
Operating Expenses and Taxes
Total operating expenses and taxes increased by $227.9 million in
2001 and by $4.2 million in 2000 from the prior year. Excluding the effects of
restructuring, total 2001 operating expenses and taxes were $48.0 million lower
than the prior year. The following table presents changes from the prior year by
expense category excluding the impact of restructuring.
Operating Expenses and Taxes - Changes 2001 2000
--------------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel and purchased power...................... $(49.8) $(10.1)
Nuclear operating costs....................... (16.5) 3.0
Other operating costs......................... 8.9 (15.1)
---------------------------------------------------------------------
Total operation and maintenance expenses.... 57.4 (22.2)
Provision for depreciation and amortization... 28.0 1.2
General taxes................................. (27.7) 3.0
Income taxes.................................. 9.1 22.2
--------------------------------------------------------------------
Total operating expenses and taxes.......... $(48.0) $ 4.2
====================================================================
The following discussion excludes the effects shown in the preceding
table related to the impact of restructuring.
The decrease in fuel and purchased power costs in 2001, compared to
2000, reflects the transfer of fossil operations to FGCO with our power
requirements being provided under the PSA. In 2000, fuel and purchased power
costs decreased $10.1 million, compared to 1999. A $13.2 million reduction in
fuel expense was partially offset by a $3.1 million increase in purchased power
costs. The reduction in fuel expense in 2000 from the preceding year occurred
despite a 1.4% increase in internal generation. Factors contributing to the
lower fuel expense included the expiration of an above-market coal contract at
the end of 1999 and continued improvement in coal blending strategies.
There was one less nuclear refueling outage in 2001, compared to
2000, resulting in a $16.5 million decrease in nuclear operating costs from the
prior year. In 2000, nuclear operating costs increased slightly by $3.0 million,
compared to 1999. Higher outage-related costs at the Davis-Besse Plant and
Beaver Valley Unit 2 were substantially offset by lower operating costs at the
Perry Plant. Other operating costs increased by $8.9 million in 2001 from the
prior year reflecting planned maintenance work at the Bruce Mansfield Plant and
the absence in 2001 of gains from the sale of emission allowances, offset in
part by a reduction in low-income payment plan customer costs and decreased
storm damage costs. and the absence of costs incurred in 2000 related to the
development of a distribution communications system. In 2000, other operating
costs decreased $15.1 million, compared to 1999, principally due to increased
gains of $18.9 million realized from the sale of emission allowances in 2000.
Depreciation and amortization increased by $28.0 million in 2001 from
the prior year due to incremental transition cost amortization under our
transition plan, partially offset by new deferrals for shopping incentives.
General taxes decreased by $27.7 million in 2001 from 2000 due to
reduced property taxes and other state tax changes in connection with the Ohio
electric industry restructuring. The reduction in general taxes was partially
offset by $6.5 million of new Ohio franchise taxes in 2001, which are classified
as state income taxes on the Consolidated Statements of Income.
Net Interest Charges
Net interest charges continued to trend lower decreasing by $6.6
million in 2001 and by $11.7 million in 2000, compared to the prior year. We
continued to redeem our outstanding debt during 2001 -- net redemptions totaled
$29.4 million and will result in annualized savings of $2.7 million.
Capital Resources and Liquidity
- -------------------------------
Through net debt and preferred stock redemptions, we continued to
reduce the cost of debt and preferred stock, and improve our financial position
in 2001. During 2001, we reduced our total debt by approximately $91 million.
Our common stockholder's equity as a percentage of capitalization increased to
45% as of December 31, 2001 from 27% at the end of 1997. We have reduced the
average cost of outstanding debt from 9.13% in 1996 to 7.41% in 2001.
Following approval of the merger of FirstEnergy and GPU by the New
Jersey Board of Public Utilities on September 26, 2001, Standard & Poor's
upgraded our credit ratings. Following a period of review and after the
Securities and Exchange Commission's approval of the merger on October 29, 2001,
Moody's also upgraded our credit ratings. The following table summarizes the
changes:
Credit Ratings Before and After Upgrade
Before Upgrade After Upgrade
- -----------------------------------------------------------------------------
Moody's Moody's
Standard Investors Standard Investors
& Poor's Service & Poor's Service
- -----------------------------------------------------------------------------
Corporate/Issuer BB+ Ba1 BBB Baa3
Senior Secured Debt BB+ Baa3 BBB Baa2
Preferred Stock B+ Ba3 BB+ Ba2
We had about $7.9 million of cash and temporary investments and $17.2
million of short-term indebtedness as of December 31, 2001. Under our first
mortgage indenture, as of December 31, 2001, we had the capability to issue $415
million of additional first mortgage bonds on the basis of property additions
and retired bonds. Based on our earnings in 2001 under the earnings coverage
test contained in our charter, we could issue $102.4 million of preferred stock
(assuming no additional debt was issued).
Our cash requirements in 2002 for operating expenses, construction
expenditures, scheduled debt maturities and preferred stock redemptions are
expected to be met without increasing our net debt and preferred stock
outstanding. Major contractual obligations for future cash payments are
summarized in the following table:
Contractual Obligations
- ---------------------------------------------------------------------------------------------------------
There-
2002 2003 2004 2005 2006 after Total
- ----------------------------------------------------------------------------------------------------------
(In millions)
Long-term debt................ $165 $ 96 $215 $ -- $ -- $ 413 $ 889
Short-term borrowings......... 17 -- -- -- -- -- 17
Operating leases*............. 73 76 74 80 82 761 1,146
Unconditional fuel purchases.. 43 23 34 14 -- -- 114
- ---------------------------------------------------------------------------------------------------------
Total......................... $298 $195 $323 $ 94 $ 82 $1,174 $2,166
=========================================================================================================
<FN>
* Operating lease payments are net of capital trust receipts of $395.3 million (see Note 2).
</FN>
Our capital spending for the period 2002-2006 is expected to be about
$228 million (excluding nuclear fuel) of which approximately $72 million applies
to 2002. Investments for additional nuclear fuel during the 2002-2006 period are
estimated to be approximately $120 million, of which about $12 million relates
to 2002. During the same periods, our nuclear fuel investments are expected to
be reduced by approximately $114 million and $22 million, respectively, as the
nuclear fuel is consumed.
Off balance sheet obligations primarily consist of sale and leaseback
arrangements involving the Bruce Mansfield Plant and Beaver Valley Unit 2, which
is reflected in the operating lease payments above (see Note 2 - Leases). The
present value as of December 31, 2001, of these sale and leaseback operating
lease commitments, net of trust investments, total $621 million. We sell
substantially all of our retail customer receivables, which provided $103
million of off balance sheet financing as of December 31, 2001.
On November 29, 2001, FirstEnergy reached an agreement to sell our
648 MW Bay Shore Plant (with an aggregate net book value of $80 million as of
December 31, 2001). The net, after-tax gain from the sale, based on the
difference between the sale price of the plant and its fair value as defined in
our Ohio restructuring transition plan, will be credited to customers by
reducing the transition cost recovery period. The sale is expected to close in
mid-2002.
Interest Rate Risk
- ------------------
Our exposure to fluctuations in market interest rates is reduced
since a significant portion of our debt has fixed interest rates, as noted in
the table below. We are subject to the inherent risks related to refinancing
maturing debt by issuing new debt securities. As discussed in Note 2, our
investment in the Shippingport Capital Trust effectively reduces future lease
obligations, also reducing interest rate risk. Changes in the market value of
our nuclear decommissioning trust funds are recognized by making corresponding
changes to the decommissioning liability, as described in Note 1 - Utility Plant
and Depreciation.
The table below presents principal amounts and related weighted
average interest rates by year of maturity for our investment portfolio and debt
obligations.
Comparison of Carrying Value to Fair Value
- -------------------------------------------------------------------------------------------------------------------
There- Fair
2002 2003 2004 2005 2006 after Total Value
- --------------------------------------------------------------------------------------------------------------------
(Dollars in millions)
Investments other than Cash
and Cash Equivalents:
Fixed Income................. $ 20 $20 $ 9 $134 $12 $284 $479 $493
Average interest rate..... 7.6% 7.6% 7.6% 7.8% 7.6% 7.0% 7.3%
- -------------------------------------------------------------------------------------------------------------------
Liabilities
- -------------------------------------------------------------------------------------------------------------------
Long-term Debt:
Fixed rate................... $165 $96 $215 $224 $700 $746
Average interest rate .... 8.6% 7.9% 7.8% 7.7% 8.0%
Variable rate................ $189 $189 $191
Average interest rate..... 3.4% 3.4%
Short-term Borrowings........ $ 17 $ 17 $ 17
Average interest rate..... 3.6% 3.6%
- -------------------------------------------------------------------------------------------------------------------
Outlook
- -------
Our industry continues to transition to a more competitive
environment. We continue to deliver power to homes and businesses through our
existing distribution system, which remains regulated. Customer rates have been
restructured into separate components to support customer choice. In Ohio, we
have a continuing responsibility to provide power to those customers not
choosing to receive power from an alternative energy supplier. Adopting new
approaches to regulation and experiencing new forms of competition has created
new uncertainties.
Regulatory Matters
Beginning on January 1, 2001 Ohio customers were able to choose their
electricity suppliers. Ohio customer rates were restructured to establish
separate charges for transmission, distribution, transition cost recovery and a
generation-related component. When one of our customers elects to obtain power
from an alternative supplier, we
reduce the customer's bill with a "generation shopping credit," based on the
regulated generation component plus an incentive, and the customer receives a
generation charge from the alternative supplier. We have continuing
responsibility to provide energy to our franchise customers as the PLR through
December 31, 2005.
The transition cost portion of rates provides for recovery of certain
amounts not otherwise recoverable in a competitive generation market (such as
regulatory assets). Transition costs are paid by all customers whether or not
they choose an alternative supplier. Under the PUCO-approved transition plan, we
assumed the risk of not recovering up to $80 million of transition revenue if
the rate of customers (excluding contracts and full-service accounts) switching
from our service to an alternative supplier does not reach 20% for any
consecutive twelve-month period by December 31, 2005 - the end of the market
development period. As of December 31, 2001, the customer-switching rate, on an
annualized basis, implies that our risk of not recovering transition revenue has
been reduced to approximately $35 million. We are also committed under the
transition agreement to make available 160 MW of our generating capacity to
marketers, brokers, and aggregators at set prices, to be used for sales only to
retail customers in our service area. Through December 31, 2001, approximately
129 MW of the 160 MW supply commitment had been secured by alternative
suppliers. We began accepting customer applications for switching to alternative
suppliers on December 8, 2000; as of December 31, 2001 we had been notified that
almost 93,000 of our customers requested generation service from other
authorized suppliers, including FES, an affiliated company.
Environmental Matters
We are in compliance with the current sulfur dioxide (SO2) and
nitrogen oxide (NOx) reduction requirements under the Clean Air Act Amendments
of 1990. In 1998, the Environmental Protection Agency (EPA) finalized
regulations requiring additional NOx reductions in the future from our Ohio and
Pennsylvania facilities. Various regulatory and judicial actions have since
sought to further define NOx reduction requirements (see Note 5 - Environmental
Matters). We continue to evaluate our compliance plans and other compliance
options.
Violations of federally approved SO2 regulations can result in
shutdown of the generating unit involved and/or civil or criminal penalties of
up to $27,500 for each day a unit is in violation. The EPA has an interim
enforcement policy for SO2 regulations in Ohio that allows for compliance based
on a 30-day averaging period. We cannot predict what action the EPA may take in
the future with respect to the interim enforcement policy.
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants. The EPA identified mercury as the hazardous air pollutant of
greatest concern. The EPA established a schedule to propose regulations by
December 2003 and issue final regulations by December 2004. The future cost of
compliance with these regulations may be substantial.
As a result of the Resource Conservation and Recovery Act of 1976, as
amended, and the Toxic Substances Control Act of 1976, federal and state
hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous waste
disposal requirements pending the EPA's evaluation of the need for future
regulation. The EPA has issued its final regulatory determination that
regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the
EPA announced that it will develop national standards regulating disposal of
coal ash under its authority to regulate nonhazardous waste.
We have been named as a "potentially responsible party" (PRP) at
waste disposal sites which may require cleanup under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980. Allegations of
disposal of hazardous substances at historical sites and the liability involved,
are often unsubstantiated and subject to dispute. Federal law provides that all
PRPs for a particular site be held liable on a joint and several basis. We have
accrued a liability of $0.2 million as of December 31, 2001, based on estimates
of the total costs of cleanup, the proportionate responsibility of other PRPs
for such costs and the financial ability of other PRPs to pay. We believe that
waste disposal costs will not have a material adverse effect on our financial
condition, cash flows, or results of operations.
Legal Matters
Various lawsuits, claims and proceedings related to our normal
business operations are pending against FirstEnergy and its subsidiaries. The
most significant applicable to us are described above.
Significant Accounting Policies
- -------------------------------
We prepare our consolidated financial statements in accordance with
accounting principles generally accepted in the United States. Application of
these principles often requires a high degree of judgment, estimates and
assumptions that affect our financial results. All of our assets are subject to
their own specific risks and uncertainties and are continually reviewed for
impairment. Assets related to the application of the policies discussed below
are similarly
reviewed with their risks and uncertainties reflecting these specific factors.
Our more significant accounting policies are described below.
Regulatory Accounting
We are subject to regulation that sets the prices (rates) we are
permitted to charge our customers based on our costs that the regulatory
agencies determine we are permitted to recover. At times, regulators permit the
future recovery through rates of costs that would be currently charged to
expense by an unregulated company. This rate-making process results in the
recording of regulatory assets based on anticipated future cash inflows. As a
result of the changing regulatory framework in Ohio, significant amounts of
regulatory assets have been recorded -- $389 million as of December 31, 2001. We
continually review these assets to assess their ultimate recoverability within
the approved regulatory guidelines. Impairment risk associated with these assets
relates to potentially adverse legislative, judicial or regulatory actions in
the future. As disclosed in Note 1 - Regulatory Plans, our full recovery of
transition costs is dependent on achieving 20% customer shopping levels in any
twelve-month period by December 31, 2005.
Revenue Recognition
We follow the accrual method of accounting for revenues, recognizing
revenue for kilowatt-hour that have been delivered but not yet been billed
through the end of the year. The determination of unbilled revenues requires
management to make various estimates including:
o Net energy generated or purchased for retail load
o Losses of energy over distribution lines
o Allocations to distribution companies within the FirstEnergy system
o Mix of kilowatt-hour usage by residential, commercial and industrial
customers
o Kilowatt-hour usage of customers receiving electricity from alternative
suppliers
Recently Issued Accounting Standards
- ------------------------------------
The Financial Accounting Standards Board (FASB) approved SFAS 142,
"Goodwill and Other Intangible Assets," on June 29, 2001. Under SFAS 142,
amortization of existing goodwill will cease January 1, 2002. Instead, goodwill
will be tested for impairment at least on an annual basis, and no impairment of
goodwill is anticipated as a result of a preliminary analysis. In 2001, we
amortized about $12 million of goodwill.
In July 2001, the FASB issued Statement of Financial Accounting
Standards No. (SFAS) 143, "Accounting for Asset Retirement Obligations." The new
statement provides accounting standards for retirement obligations associated
with tangible long-lived assets, with adoption required by January 1, 2003. SFAS
143 requires that the fair value of a liability for an asset retirement
obligation be recorded in the period in which it is incurred. The associated
asset retirement costs are capitalized as part of the carrying amount of the
long-lived asset. Over time the capitalized costs are depreciated and the
present value of the asset retirement liability increases resulting in a period
expense. Upon retirement, a gain or loss will be recorded if the cost to settle
the retirement obligation differs from the carrying amount. We are currently
assessing the new standard and have not yet determined the impact on our
financial statements.
In September 2001, the FASB issued SFAS 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS 144 supersedes SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of." The Statement also supersedes the accounting and reporting
provisions of Accounting Principles Board Opinion No. 30, "Reporting the Results
of Operations - Reporting the Effects of Disposal of a Segment of a Business and
Extraordinary, Unusual and Infrequently Occurring Events and Transactions." Our
adoption of this Statement, effective January 1, 2002, will result in our
accounting for any future impairments or disposals of long-lived assets under
the provisions of SFAS 144, but will not change the accounting principles used
in previous asset impairments or disposals. Application of SFAS 144 is not
anticipated to have a major impact on our accounting for impairments or disposal
transactions compared to the prior application of SFAS 121 or APB 30.
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2001 2000 1999
- ------------------------------------------------------------------------------------------------------------------
(In thousands)
OPERATING REVENUES (a)........................................... $1,094,903 $954,947 $921,159
---------- -------- --------
OPERATING EXPENSES AND TAXES:
Fuel and purchased power...................................... 457,444 159,039 169,153
Nuclear operating costs....................................... 161,532 178,063 175,015
Other operating costs......................................... 151,244 156,286 171,427
---------- -------- --------
Total operation and maintenance expenses.................... 770,220 493,388 515,595
Provision for depreciation and amortization................... 130,196 104,914 103,725
General taxes................................................. 57,810 90,837 87,862
Income taxes.................................................. 31,193 72,394 50,205
---------- -------- --------
Total operating expenses and taxes.......................... 989,419 761,533 757,387
---------- -------- --------
OPERATING INCOME................................................. 105,484 193,414 163,772
OTHER INCOME..................................................... 15,652 8,669 12,744
---------- -------- --------
INCOME BEFORE NET INTEREST CHARGES............................... 121,136 202,083 176,516
---------- -------- --------
NET INTEREST CHARGES:
Interest on long-term debt.................................... 66,463 72,892 82,204
Allowance for borrowed funds used during
construction................................................ (3,848) (6,523) (1,443)
Other interest expense (credit)............................... (4,390) (1,519) (4,190)
---------- -------- --------
Net interest charges........................................ 58,225 64,850 76,571
---------- -------- --------
NET INCOME....................................................... 62,911 137,233 99,945
PREFERRED STOCK DIVIDEND
REQUIREMENTS.................................................. 16,135 16,247 16,238
---------- -------- --------
EARNINGS ON COMMON STOCK......................................... $ 46,776 $120,986 $ 83,707
========== ======== ========
<FN>
(a) Includes electric sales to associated companies of $180.9 million, $142.3 million
and $123.3 million in 2001, 2000 and 1999, respectively.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31, 2001 2000
- -------------------------------------------------------------------------------------------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service.................................................................... $1,578,943 $1,637,616
Less-Accumulated provision for depreciation................................... 645,865 597,397
---------- ----------
933,078 1,040,219
---------- ----------
Construction work in progress-
Electric plant.............................................................. 40,220 73,565
Nuclear fuel................................................................ 19,854 10,720
---------- ----------
60,074 84,285
---------- ----------
993,152 1,124,504
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Shippingport Capital Trust (Note 2)........................................... 262,131 279,836
Nuclear plant decommissioning trusts.......................................... 156,084 132,442
Long-term notes receivable from associated companies.......................... 162,347 39,084
Other......................................................................... 4,248 4,601
---------- ----------
584,810 455,963
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents..................................................... 302 1,385
Receivables-
Customers................................................................... 5,922 6,618
Associated companies........................................................ 64,667 62,271
Other....................................................................... 9,709 1,572
Notes receivable from associated companies.................................... 7,607 32,617
Materials and supplies, at average cost-
Owned....................................................................... 13,996 17,388
Under consignment........................................................... 17,050 21,994
Prepayments and other......................................................... 14,580 27,151
---------- ----------
133,833 170,996
---------- ----------
DEFERRED CHARGES:
Regulatory assets............................................................. 388,846 412,682
Goodwill...................................................................... 445,732 458,164
Property taxes................................................................ 23,836 22,916
Other......................................................................... 1,909 7,042
---------- ----------
860,323 900,804
---------- ----------
$2,572,118 $2,652,267
========== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity................................................... $ 637,665 $ 605,587
Preferred stock not subject to mandatory redemption........................... 126,000 210,000
Long-term debt................................................................ 646,174 944,193
---------- ----------
1,409,839 1,759,780
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock.......................... 347,593 56,230
Accounts payable-
Associated companies........................................................ 53,960 36,564
Other....................................................................... 27,418 25,070
Notes payable to associated companies......................................... 17,208 41,936
Accrued taxes................................................................ 39,848 57,519
Accrued interest.............................................................. 19,918 19,946
Other......................................................................... 40,222 49,908
---------- ----------
546,167 287,173
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes............................................. 213,145 196,944
Accumulated deferred investment tax credits................................... 31,342 35,174
Nuclear plant decommissioning costs........................................... 162,426 138,784
Pensions and other postretirement benefits.................................... 120,561 119,327
Other......................................................................... 88,638 115,085
---------- ----------
616,112 605,314
---------- ----------
COMMITMENTS AND CONTINGENCIES
(Notes 2 and 5)............................................................... ---------- ----------
$2,572,118 $2,652,267
========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.
</FN>
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31, 2001 2000
- ------------------------------------------------------------------------------------------------------------------------
(Dollars in thousands, except per share amounts)
COMMON STOCKHOLDER'S EQUITY:
Common stock, $5 par value, authorized 60,000,000 shares
39,133,887 shares outstanding.................................................. $ 195,670 $ 195,670
Other paid-in capital............................................................ 328,559 328,559
Retained earnings (Note 3A)...................................................... 113,436 81,358
---------- ----------
Total common stockholder's equity.............................................. 637,665 605,587
---------- ----------
Number of Shares Optional
Outstanding Redemption Price
------------------ -----------------------
2001 2000 Per Share Aggregate
---- ---- --------- ---------
PREFERRED STOCK (Note 3C):
Cumulative, $100 par value-
Authorized 3,000,000 shares
Not Subject to Mandatory Redemption:
$ 4.25........................... 160,000 160,000 $104.63 $ 16,740 16,000 16,000
$ 4.56........................... 50,000 50,000 101.00 5,050 5,000 5,000
$ 4.25........................... 100,000 100,000 102.00 10,200 10,000 10,000
$ 8.32........................... 100,000 100,000 102.46 10,246 10,000 10,000
$ 7.76........................... 150,000 150,000 102.44 15,366 15,000 15,000
$ 7.80........................... 150,000 150,000 101.65 15,248 15,000 15,000
$10.00........................... 190,000 190,000 101.00 19,190 19,000 19,000
--------- --------- -------- ---------- ----------
900,000 900,000 92,040 90,000 90,000
Redemption Within One Year (59,000)
--------- --------- -------- ---------- ----------
900,000 900,000 92,040 31,000 90,000
--------- --------- -------- ---------- ----------
Cumulative, $25 par value-
Authorized 12,000,000 shares
Not Subject to Mandatory Redemption:
$2.21............................. 1,000,000 1,000,000 25.25 25,250 25,000 25,000
$2.365............................ 1,400,000 1,400,000 27.75 38,850 35,000 35,000
Adjustable Series A............... 1,200,000 1,200,000 25.00 30,000 30,000 30,000
Adjustable Series B............... 1,200,000 1,200,000 25.00 30,000 30,000 30,000
--------- --------- -------- ---------- ----------
4,800,000 4,800,000 124,100 120,000 120,000
Redemption Within One Year.......... (25,000) --
--------- --------- -------- ---------- ----------
4,800,000 4,800,000 124,100 95,000 120,000
--------- --------- -------- ---------- ----------
Total Not Subject to Mandatory
Redemption.................... 5,700,000 5,700,000 $216,140 126,000 210,000
========= ========= ======== ---------- ----------
LONG-TERM DEBT (Note 3D):
First mortgage bonds:
8.000% due 2002-2003............................................................... 34,125 34,525
7.875% due 2004.................................................................... 145,000 145,000
---------- ----------
Total first mortgage bonds........................................................ 179,125 179,525
---------- ----------
Unsecured notes and debentures:
10.000% due 2002-2010............................................................... 940 970
8.700% due 2002.................................................................... 135,000 135,000
* 4.850% due 2030.................................................................... 34,850 34,850
* 4.000% due 2033.................................................................... 5,700 5,700
* 5.250% due 2033.................................................................... 31,600 31,600
* 5.580% due 2033.................................................................... 18,800 18,800
---------- ----------
Total unsecured notes and debentures.............................................. 226,890 226,920
---------- ----------
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)
As of December 31 2001 2000
- -----------------------------------------------------------------------------------------------------------------------
(In thousands)
LONG-TERM DEBT (Cont'd):
Secured notes:
8.500% due 2001.................................................................. -- 8,000
9.500% due 2001.................................................................. -- 21,000
8.180% due 2002.................................................................. 17,000 17,000
8.620% due 2002.................................................................. 7,000 7,000
8.650% due 2002.................................................................. 5,000 5,000
7.760% due 2003.................................................................. 5,000 5,000
7.780% due 2003.................................................................. 1,000 1,000
7.820% due 2003.................................................................. 38,400 38,400
7.850% due 2003.................................................................. 15,000 15,000
7.910% due 2003.................................................................. 3,000 3,000
7.670% due 2004.................................................................. 70,000 70,000
7.130% due 2007.................................................................. 30,000 30,000
7.625% due 2020.................................................................. 45,000 45,000
7.750% due 2020.................................................................. 54,000 54,000
9.220% due 2021.................................................................. 15,000 15,000
10.000% due 2021.................................................................. 15,000 15,000
6.875% due 2023.................................................................. 20,200 20,200
8.000% due 2023.................................................................. 30,500 30,500
* 1.900% due 2024.................................................................. 67,300 67,300
6.100% due 2027.................................................................. 10,100 10,100
5.375% due 2028.................................................................. 3,751 3,751
* 1.600% due 2033.................................................................. 30,900 30,900
---------- ----------
Total secured notes............................................................. 483,151 512,151
---------- ----------
Capital lease obligations (Note 2)................................................... 263 56,859
---------- ----------
Net unamortized premium on debt...................................................... 20,338 24,968
---------- ----------
Long-term debt due within one year................................................... (263,593) (56,230)
---------- ----------
Total long-term debt............................................................ 646,174 944,193
---------- ----------
TOTAL CAPITALIZATION................................................................. $1,409,839 $1,759,780
========== ==========
<FN>
* Denotes variable rate issue with December 31, 2001 interest rate shown.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
Other
Comprehensive Number Par Paid-In Retained
Income of Shares Value Capital Earnings
------------- --------- ----- ------- --------
(Dollars in thousands)
Balance, January 1, 1999............... 39,133,887 $195,670 $328,559 $ 51,463
Net income.......................... $ 99,945 99,945
========
Cash dividends on preferred stock... (17,582)
Cash dividends on common stock...... (106,351)
- ---------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1999............. 39,133,887 195,670 328,559 27,475
Net income.......................... $137,233 137,233
========
Cash dividends on preferred stock... (16,250)
Cash dividends on common stock...... (67,100)
- ---------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2000............. 39,133,887 195,670 328,559 81,358
Net income.......................... $ 62,911 62,911
========
Cash dividends on preferred stock... (16,133)
Cash dividends on common stock...... (14,700)
- ---------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2001............. 39,133,887 $195,670 $328,559 $113,436
=====================================================================================================================
CONSOLIDATED STATEMENTS OF PREFERRED STOCK
Not Subject to Subject to
Mandatory Redemption Mandatory Redemption
-------------------- --------------------
Number Par Number Par
of Shares Value of Shares Value
--------- ----- --------- -----
(Dollars in thousands)
Balance, January 1, 1999..... 5,700,000 $210,000 16,900 $ 1,690
Redemptions-
$100 par $9.375.......... (16,900) (1,690)
--------------------------------------------------------------------------------
Balance, December 31, 1999... 5,700,000 210,000 -- --
--------------------------------------------------------------------------------
Balance, December 31, 2000... 5,700,000 210,000 -- --
--------------------------------------------------------------------------------
Balance, December 31, 2001... 5,700,000 $210,000 -- $ --
================================================================================
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2001 2000 1999
- ----------------------------------------------------------------------------------------------------------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income...................................................... $ 62,911 $137,233 $ 99,945
Adjustments to reconcile net income to net
cash from operating activities:
Provision for depreciation and amortization................... 130,196 104,914 103,725
Nuclear fuel and lease amortization........................... 22,222 23,881 25,166
Deferred income taxes, net.................................... 11,897 20,376 27,551
Investment tax credits, net................................... (3,832) (1,827) (1,922)
Receivables................................................... (9,837) (6,671) 5,242
Materials and supplies........................................ 8,336 4,093 418
Accounts payable.............................................. 19,744 13,997 (20,898)
Other......................................................... (51,781) (38,180) 1,427
--------- -------- --------
Net cash provided from operating activities................. 189,856 257,816 240,654
--------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt................................................ -- 96,405 89,330
Short-term borrowings, net.................................... -- 8,060 33,876
Redemptions and Repayments-
Preferred stock............................................... -- -- 1,690
Long-term debt................................................ 42,265 200,633 226,695
Short-term borrowings, net.................................... 24,728 -- --
Dividend Payments-
Common stock.................................................. 14,700 67,100 106,351
Preferred stock............................................... 16,135 16,247 16,238
--------- -------- --------
Net cash used for financing activities...................... 97,828 179,515 227,768
--------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions................................................ 112,451 92,860 107,338
Loans to associated companies..................................... 123,438 63,838 --
Loan payments from associated companies........................... (25,185) -- (93,373)
Capital trust investments......................................... (17,705) (15,618) (15,308)
Sale of assets to associated companies............................ (123,438) (81,014) --
Other............................................................. 23,550 17,162 18,057
--------- -------- --------
Net cash used for investing activities...................... 93,111 77,228 16,714
--------- -------- --------
Net increase (decrease) in cash and cash equivalents.............. (1,083) 1,073 (3,828)
Cash and cash equivalents at beginning of year.................... 1,385 312 4,140
--------- -------- --------
Cash and cash equivalents at end of year.......................... $ 302 $ 1,385 $ 312
========= ======== ========
SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)........................... $ 63,159 $ 71,009 $ 84,538
========= ======== ========
Income taxes.................................................... $ 33,210 $ 65,553 $ 40,461
========= ======== ========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF TAXES
For the Years Ended December 31, 2001 2000 1999
- ------------------------------------------------------------------------------------------------------------------
(In thousands)
GENERAL TAXES:
Real and personal property......................................... $ 23,624 $ 46,302 $ 44,280
Ohio kilowatt-hour excise.......................................... 19,576 -- --
State gross receipts............................................... 12,789 36,813 35,706
Social security and unemployment................................... 1,128 7,220 6,801
Other.............................................................. 693 502 1,075
-------- -------- --------
Total general taxes......................................... $ 57,810 $ 90,837 $ 87,862
======== ======== ========
PROVISION FOR INCOME TAXES:
Currently payable-
Federal......................................................... $ 25,640 $ 56,631 $ 29,728
State........................................................... 5,937 1,811 1,489
-------- -------- --------
31,577 58,442 31,217
-------- -------- --------
Deferred, net-
Federal......................................................... 11,736 20,865 27,745
State........................................................... 161 (489) (194)
-------- -------- --------
11,897 20,376 27,551
-------- -------- --------
Investment tax credit amortization................................. (3,832) (1,827) (1,922)
-------- -------- --------
Total provision for income taxes............................ $ 39,642 $ 76,991 $ 56,846
======== ======== ========
INCOME STATEMENT CLASSIFICATION
OF PROVISION FOR INCOME TAXES:
Operating income................................................... $ 31,193 $ 72,394 $ 50,205
Other income....................................................... 8,449 4,597 6,641
-------- -------- --------
Total provision for income taxes............................ $ 39,642 $ 76,991 $ 56,846
======== ======== ========
RECONCILIATION OF FEDERAL INCOME TAX
EXPENSE AT STATUTORY RATE TO TOTAL
PROVISION FOR INCOME TAXES:
Book income before provision for income taxes...................... $102,553 $214,224 $156,791
======== ======== ========
Federal income tax expense at statutory rate....................... $ 35,894 $ 74,978 $ 54,877
Increases (reductions) in taxes resulting from-
State income taxes, net of federal income tax benefit........... 3,964 859 842
Amortization of investment tax credits.......................... (3,832) (1,827) (1,922)
Amortization of tax regulatory assets........................... (2,367) (1,737) (1,735)
Amortization of goodwill........................................ 4,351 4,334 4,280
Other, net...................................................... 1,632 384 504
-------- -------- --------
Total provision for income taxes............................ $ 39,642 $ 76,991 $ 56,846
======== ======== ========
ACCUMULATED DEFERRED INCOME TAXES
AT DECEMBER 31:
Property basis differences......................................... $171,976 $163,537 $195,326
Competitive transition charge...................................... 135,462 70,264 55,006
Unamortized investment tax credits................................. (12,184) (16,689) (18,324)
Unused alternative minimum tax credits............................. -- (5,100) (30,055)
Deferred gain for asset sale to affiliated company................. 16,305 15,330 --
Other.............................................................. (98,414) (30,398) (29,717)
-------- -------- --------
Net deferred income tax liability............................... $213,145 $196,944 $172,236
======== ======== ========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
The consolidated financial statements include The Toledo Edison
Company (Company) and its 90% owned subsidiary, The Toledo Edison Capital
Corporation (TECC). The subsidiary was formed in 1997 to make equity investments
in a business trust in connection with the financing transactions related to the
Bruce Mansfield Plant sale and leaseback (see Note 2). The Cleveland Electric
Illuminating Company (CEI), an affiliate, has a 10% interest in TECC. All
significant intercompany transactions have been eliminated. The Company is a
wholly owned subsidiary of FirstEnergy Corp. FirstEnergy holds directly all of
the issued and outstanding common shares of its principal electric utility
operating subsidiaries, including, the Company, CEI, Ohio Edison Company (OE),
American Transmission Systems, Inc. (ATSI), Jersey Central Power & Light Company
(JCP&L), Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company
(Penelec). JCP&L, Met-Ed and Penelec were formerly wholly owned subsidiaries of
GPU, Inc. which merged with FirstEnergy on November 7, 2001.
The Company follows the accounting policies and practices prescribed
by the Public Utilities Commission of Ohio (PUCO) and the Federal Energy
Regulatory Commission (FERC). The preparation of financial statements in
conformity with accounting principles generally accepted in the United States
(GAAP) requires management to make periodic estimates and assumptions that
affect the reported amounts of assets, liabilities, revenues and expenses and
disclosure of contingent assets and liabilities. Actual results could differ
from these estimates.
REVENUES-
The Company's principal business is providing electric service to
customers in northwestern Ohio. The Company's retail customers are metered on a
cycle basis. Revenue is recognized for unbilled electric service through the end
of the year.
Receivables from customers include sales to residential, commercial
and industrial customers located in the Company's service area and sales to
wholesale customers. There was no material concentration of receivables at
December 31, 2001 or 2000, with respect to any particular segment of the
Company's customers.
The Company and CEI sell substantially all of their retail customer
receivables to Centerior Funding Corp. (CFC), a wholly owned subsidiary of CEI.
CFC subsequently transfers the receivables to a trust under an asset-backed
securitization agreement. The trust completed private sales of $50 million and
$150 million of receivables-backed investor certificates in 2000 and 2001
respectively, in transactions that qualified for sale accounting treatment.
CFC's creditors are entitled to be satisfied first out of the proceeds of
FirstEnergy's assets. The 2001 private sale was used to repay a 1996 public sale
of $150 million of receivables-backed investor certificates which was replaced
under an amended securitization agreement. FirstEnergy's retained interest in
the pool of receivables held by the trust (34% as of December 31, 2001) is
stated at fair value reflecting adjustments for anticipated credit losses.
Sensitivity analyses reflecting a 10% and 20% increase in the rate of
anticipated credit losses did not significantly affect FirstEnergy's retained
interest in the pool of receivables. Collections from receivables previously
transferred to the trust were used for the purchase of new receivables from CFC
during 2001 and totaled approximately $2.2 billion. As of December 31, 2001,
receivables recorded on the Consolidated Balance Sheet were reduced by
approximately $103 million due to receivables sold to the trust. The Company and
CEI processed receivables for the trust and received servicing fees of
approximately $4.5 million ($1.5 million applicable to the Company) in 2001.
Expenses associated with the factoring discount related to the sale of
receivables were $12 million in 2001.
REGULATORY PLAN-
Ohio's 1999 electric utility restructuring law allowed Ohio electric
customers to select their generation suppliers beginning January 1, 2001,
provided for a five percent reduction on the generation portion of residential
customers' bills and the opportunity for utilities to recover transition costs,
including regulatory assets. Under this law, the PUCO approved FirstEnergy's
transition plan in 2000 as modified by a settlement agreement with major parties
to the transition plan, which it filed on behalf of the Company, OE and CEI. The
settlement agreement included approval for recovery of the amounts of transition
costs filed in the transition plan through no later than mid-2007 for the
Company, except where a longer period of recovery is provided for in the
settlement agreement. The settlement also granted preferred access over
FirstEnergy's subsidiaries to nonaffiliated marketers, brokers and aggregators
to 160 megawatts of generation capacity through 2005 at established prices for
sales to the Company's retail customers. The Company's base electric rates for
distribution service under its prior regulatory plan were extended from December
31, 2005 through December 31, 2007. The transition rate credits for customers
under its prior regulatory plan were also extended through the Company's
transition cost recovery period.
The transition plan itemized, or unbundled, the current price of
electricity into its component elements -- including generation, transmission,
distribution and transition charges. As required by the PUCO's rules,
FirstEnergy's transition plan also resulted in the corporate separation of its
regulated and unregulated operations, operational and technical support changes
needed to accommodate customer choice, an education program to inform customers
of their options under the law, and planned changes in how FirstEnergy's
transmission system will be operated to ensure access to all users. Customer
prices are frozen through a five-year market development period (2001-2005),
except for certain limited statutory exceptions including a 5% reduction in the
price of generation for residential customers.
The Company's customers electing alternative suppliers receive an
additional incentive applied to the shopping credit of 45% for residential
customers, 30% for commercial customers and 15% for industrial customers. The
amount of the incentive serves to reduce the amortization of transition costs
during the market development period and will be recovered through the extension
of the transition cost recovery period. If the customer shopping goal
established in the agreement are not achieved by the end of 2005, the transition
cost recovery period could be shortened for the Company to reduce recovery by as
much as $80 million, but any such adjustment would be computed on a
class-by-class and pro-rata basis. Based on annualized shopping levels as of
December 31, 2001, the Company believes that the maximum potential recovery
reduction was approximately $35 million.
The application of Statement of Financial Accounting Standards (SFAS)
No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71),
to the Company's generation business was discontinued with the issuance of the
PUCO transition plan order. The Securities and Exchange Commission (SEC) issued
interpretive guidance regarding asset impairment measurement that concluded any
supplemental regulated cash flows such as a competitive transition charge should
be excluded from the cash flows of assets in a portion of the business not
subject to regulatory accounting practices. If those assets are impaired, a
regulatory asset should be established if the costs are recoverable through
regulatory cash flows. Consistent with the SEC guidance $53 million of impaired
plant investments were recognized by the Company as regulatory assets
recoverable as transition costs through future regulatory cash flows. Net assets
included in utility plant relating to the operations for which the application
of SFAS 71 was discontinued, were $601 million as of December 31, 2001. All of
the Company's regulatory assets are expected to continue to be recovered under
provisions of the Ohio transition plan.
UTILITY PLANT AND DEPRECIATION-
Utility plant reflects the original cost of construction (except for
the Company's nuclear generating units which were adjusted to fair value),
including payroll and related costs such as taxes, employee benefits,
administrative and general costs, and interest costs.
The Company provides for depreciation on a straight-line basis at
various rates over the estimated lives of property included in plant in service.
The annualized composite rate was approximately 3.5% in 2001 and 3.4% in 2000
and 1999.
Annual depreciation expense includes approximately $28.5 million for
future decommissioning costs applicable to the Company's ownership interests in
three nuclear generating units. The 2001 amounts reflected an increase of
approximately $18 million from implementing the Company's transition plan in
2001. The Company's share of the future obligation to decommission these units
is approximately $456 million in current dollars and (using a 4.0% escalation
rate) approximately $1.0 billion in future dollars. The estimated obligation and
the escalation rate were developed based on site specific studies. Payments for
decommissioning are expected to begin in 2016, when actual decommissioning work
begins. The Company has recovered approximately $139 million for decommissioning
through its electric rates from customers through December 31, 2001. The Company
has also recognized an estimated liability of approximately $5.9 million related
to decontamination and decommissioning of nuclear enrichment facilities operated
by the United States Department of Energy, as required by the Energy Policy Act
of 1992.
In July 2001, the Financial Accounting Standards Board issued SFAS
143, "Accounting for Asset Retirement Obligations." The new statement provides
accounting treatment for retirement obligations associated with tangible
long-lived assets with adoption required as of January 1, 2003. SFAS 143
requires that the fair value of a liability for an asset retirement obligation
be recorded in the period in which it is incurred. The associated asset
retirement costs are capitalized as part of the carrying amount of the
long-lived asset. Over time the capitalized costs are depreciated and the
present value of the asset retirement liability increases, resulting in a period
expense. Upon retirement, a gain or loss will be recorded if the cost to settle
the retirement obligation differs from the carrying amount. Under the new
standard, additional assets and liabilities relating principally to nuclear
decommissioning obligations will be recorded, the pattern of expense recognition
will change and income from the external decommissioning trust will be recorded
as investment income. The Company is currently assessing the new standard and
has not yet quantified the impact on its financial statements.
COMMON OWNERSHIP OF GENERATING FACILITIES-
The Company, together with CEI and OE and its wholly owned
subsidiary, Pennsylvania Power Company (Penn), own and/or lease, as tenants in
common, various power generating facilities. Each of the companies is obligated
to pay a share of the costs associated with any jointly owned facility in the
same proportion as its interest. The Company's portion of operating expenses
associated with jointly owned facilities is included in the corresponding
operating expenses on the Consolidated Statements of Income. The amounts
reflected on the Consolidated Balance Sheet under utility plant at December 31,
2001 include the following:
Utility Accumulated Construction Ownership/
Plant Provision for Work in Leasehold
Generating Units in Service Depreciation Progress Interest
- -------------------------------------------------------------------------------
(In millions)
Bruce Mansfield
Units 2 and 3....... $ 46.5 $15.1 $12.3 18.61%
Beaver Valley Unit 2.. 0.8 0.3 5.7 19.91%
Davis-Besse........... 215.8 36.8 9.2 48.62%
Perry................. 338.7 48.6 2.1 19.91%
----------------------------------------------------------------------------
Total............... $601.8 $100.8 $29.3
=============================================================================
The Bruce Mansfield Plant and Beaver Valley Unit 2 are being leased
through sale and leaseback transactions (see Note 2) and the above-related
amounts represent construction expenditures subsequent to the transaction.
NUCLEAR FUEL-
Nuclear fuel is recorded at original cost, which includes material,
enrichment, fabrication and interest costs incurred prior to reactor load. The
Company amortizes the cost of nuclear fuel based on the rate of consumption.
INCOME TAXES-
Details of the total provision for income taxes are shown on the
Consolidated Statements of Taxes. Deferred income taxes result from timing
differences in the recognition of revenues and expenses for tax and accounting
purposes. Investment tax credits, which were deferred when utilized, are being
amortized over the recovery period of the related property. The liability method
is used to account for deferred income taxes. Deferred income tax liabilities
related to tax and accounting basis differences are recognized at the statutory
income tax rates in effect when the liabilities are expected to be paid. The
Company is included in FirstEnergy's consolidated federal income tax return. The
consolidated tax liability is allocated on a "stand-alone" company basis, with
the Company recognizing any tax losses or credits it contributed to the
consolidated return.
RETIREMENT BENEFITS-
FirstEnergy's trusteed, noncontributory defined benefit pension plan
covers almost all of the Company's full-time employees. Upon retirement,
employees receive a monthly pension based on length of service and compensation.
On December 31, 2001, the GPU pension plans were merged with the FirstEnergy
plan. The Company uses the projected unit credit method for funding purposes and
was not required to make pension contributions during the three years ended
December 31, 2001. The assets of the FirstEnergy pension plan consist primarily
of common stocks, United States government bonds and corporate bonds. The
FirstEnergy and GPU postretirement benefit plans are currently separately
maintained; the information shown below is aggregated as of December 31, 2001.
The Company provides a minimum amount of noncontributory life
insurance to retired employees in addition to optional contributory insurance.
Health care benefits, which include certain employee deductibles and copayments,
are also available to retired employees, their dependents and, under certain
circumstances, their survivors. The Company pays insurance premiums to cover a
portion of these benefits in excess of set limits; all amounts up to the limits
are paid by the Company. The Company recognizes the expected cost of providing
other postretirement benefits to employees and their beneficiaries and covered
dependents from the time employees are hired until they become eligible to
receive those benefits.
The following sets forth the funded status of the plans and amounts
recognized on FirstEnergy's Consolidated Balance Sheets as of December 31:
Other
Pension Benefits Postretirement Benefits
---------------- -----------------------
2001 2000 2001 2000
- ----------------------------------------------------------------------------------------------------------
(In millions)
Change in benefit obligation:
Benefit obligation as of January 1...... $1,506.1 $1,394.1 $ 752.0 $ 608.4
Service cost............................ 34.9 27.4 18.3 11.3
Interest cost........................... 133.3 104.8 64.4 45.7
Plan amendments......................... 3.6 41.3 -- --
Actuarial loss.......................... 123.1 17.3 73.3 121.7
Voluntary early retirement program...... -- 23.4 2.3 --
GPU acquisition......................... 1,878.3 -- 716.9 --
Benefits paid........................... (131.4) (102.2) (45.6) (35.1)
-------------------------------------------------------------------------------------------
Benefit obligation as of December 31.... 3,547.9 1,506.1 1,581.6 752.0
-------------------------------------------------------------------------------------------
Change in fair value of plan assets:
Fair value of plan assets as of January 1 1,706.0 1,807.5 23.0 4.9
Actual return on plan assets............ 8.1 0.7 12.7 (0.2)
Company contribution.................... -- -- 43.3 18.3
GPU acquisition......................... 1,901.0 -- 462.0 --
Benefits paid........................... (131.4) (102.2) (6.0) --
-------------------------------------------------------------------------------------------
Fair value of plan assets as of December 31 3,483.7 1,706.0 535.0 23.0
-------------------------------------------------------------------------------------------
Funded status of plan................... (64.2) 199.9 (1,046.6) (729.0)
Unrecognized actuarial loss (gain)...... 222.8 (90.9) 212.8 147.3
Unrecognized prior service cost......... 87.9 93.1 17.7 20.9
Unrecognized net transition obligation
(asset) -- (2.1) 101.6 110.9
-------------------------------------------------------------------------------------------
Prepaid (accrued) benefit cost.......... $ 246.5 $ 200.0 $ (714.5) $(449.9)
===========================================================================================
Company's share of prepaid (accrued)
benefit cost.......................... $ 1.6 $ 0.9 $ (119.1) $(117.1)
===========================================================================================
Assumptions used as of December 31:
Discount rate........................... 7.25% 7.75% 7.25% 7.75%
Expected long-term return on plan assets 10.25% 10.25% 10.25% 10.25%
Rate of compensation increase........... 4.00% 4.00% 4.00% 4.00%
FirstEnergy's net pension and other postretirement benefit costs for
the three years ended December 31, 2001 were computed as follows:
Other
Pension Benefits Postretirement Benefits
---------------- -----------------------
2001 2000 1999 2001 2000 1999
-------------------------------------------------------------------------------------------------------
(In millions)
Service cost............................ $ 34.9 $ 27.4 $ 28.3 $18.3 $11.3 $ 9.3
Interest cost........................... 133.3 104.8 102.0 64.4 45.7 40.7
Expected return on plan assets.......... (204.8) (181.0) (168.1) (9.9) (0.5) (0.4)
Amortization of transition obligation
(asset) (2.1) (7.9) (7.9) 9.2 9.2 9.2
Amortization of prior service cost...... 8.8 5.7 5.7 3.2 3.2 3.3
Recognized net actuarial loss (gain).... -- (9.1) -- 4.9 -- --
Voluntary early retirement program...... 6.1 17.2 -- 2.3 -- --
-------------------------------------------------------------------------------------------------------
Net benefit cost........................ $ (23.8) $ (42.9) $ (40.0) $92.4 $68.9 $62.1
=======================================================================================================
Company's share of net benefit cost..... $ (0.7) $ (12.7) $ (8.3) $ 3.5 $15.1 $12.6
-------------------------------------------------------------------------------------------------------
The composite health care trend rate assumption is approximately 10%
in 2002, 9% in 2003 and 8% in 2004, trending to 4%-6% in later years. Assumed
health care cost trend rates have a significant effect on the amounts reported
for the health care plan. An increase in the health care trend rate assumption
by one percentage point would increase the total service and interest cost
components by $14.6 million and the postretirement benefit obligation by $151.2
million. A decrease in the same assumption by one percentage point would
decrease the total service and interest cost components by $12.7 million and the
postretirement benefit obligation by $131.3 million.
TRANSACTIONS WITH AFFILIATED COMPANIES-
Operating revenues, operating expenses and other income include
transactions with affiliated companies, primarily CEI, OE, Penn, ATSI,
FirstEnergy Solutions Corp. (FES) and FirstEnergy. The Ohio transition plan, as
discussed in the "Regulatory Plans" section, resulted in the corporate
separation of FirstEnergy's regulated and unregulated operations in 2001.
Unregulated operations under FES now operate the generation businesses of the
Company, CEI, OE and Penn. As a result, the Company entered into power supply
agreements (PSA) whereby FES purchases all of the Company's nuclear generation
and the generation from leased fossil generating facilities and the Company
purchases its power from FES to meet its "provider of last resort" obligations.
CFC serves as the transferor in connection with the accounts receivable
securitization for the Company and CEI. The primary affiliated companies
transactions, including the effects of the PSA beginning in 2001, the sale and
leaseback of the Company's transmission assets to ATSI in September 2000 and
FirstEnergy's providing support services at cost, are as follows:
2001 2000 1999
- ----------------------------------------------------------------------------
(In millions)
Operating Revenues:
PSA revenues with FES............... $180.9 $ -- $ --
Generating units rent with FES...... 14.0 -- --
Electric sales to CEI............... 97.0 106.8 106.1
Ground lease with ATSI.............. 1.7 1.9 --
Operating Expenses:
Purchased power under PSA........... 388.0 -- --
ATSI rent expense................... 17.0 9.4 --
FirstEnergy support services........ 23.8 36.0 59.4
Other Income:
Interest income from ATSI........... 3.0 1.0 --
Interest income from FES............ 9.7 -- --
- ----------------------------------------------------------------------------
The Company is selling 150 megawatts of its Beaver Valley Unit 2
leased capacity entitlement to CEI. Operating revenues for this transaction were
$97.0 million, $104.0 million and $104.3 million in 2001, 2000 and 1999,
respectively. This sale is expected to continue through the end of the lease
period. (See Note 2.)
SUPPLEMENTAL CASH FLOWS INFORMATION-
All temporary cash investments purchased with an initial maturity of
three months or less are reported as cash equivalents on the Consolidated
Balance Sheets at cost, which approximates their fair market value. Noncash
financing and investing activities included capital lease transactions amounting
to $1.0 million, $36.1 million and $8.5 million in 2001, 2000 and 1999,
respectively.
All borrowings with initial maturities of less than one year are
defined as financial instruments under GAAP and are reported on the Consolidated
Balance Sheets at cost, which approximates their fair market value. The
following sets forth the approximate fair value and related carrying amounts of
all other long-term debt and investments other than cash and cash equivalents as
of December 31:
2001 2000
- ----------------------------------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Value Value Value Value
- ----------------------------------------------------------------------------------------------------------
(In millions)
Long-term debt....................................... $889 $937 $919 $952
Investments other than cash and cash equivalents:
Debt securities
- Maturity (5-10 years)........................... $123 $127 $ -- $ --
- Maturity (more than 10 years)................... 299 296 316 307
Equity securities................................. 2 2 3 3
All other......................................... 157 157 133 137
- ----------------------------------------------------------------------------------------------------------
$581 $582 $452 $447
==========================================================================================================
The fair value of long-term debt reflects the present value of the
cash outflows relating to those securities based on the current call price, the
yield to maturity or the yield to call, as deemed appropriate at the end of each
respective year. The yields assumed were based on securities with similar
characteristics offered by a corporation with credit ratings similar to the
Company's ratings.
The fair value of investments other than cash and cash equivalents
represent cost (which approximates fair value) or the present value of the cash
inflows based on the yield to maturity. The yields assumed were based on
financial instruments with similar characteristics and terms. Investments other
than cash and cash equivalents include decommissioning trust investments.
Unrealized gains and losses applicable to the decommissioning trusts have been
recognized in the trust investment with corresponding changes to the
decommissioning liability. The Company has no securities held for trading
purposes.
REGULATORY ASSETS-
The Company recognizes, as regulatory assets, costs which the FERC
and PUCO have authorized for recovery from customers in future periods. Without
such authorization, the costs would have been charged to income as incurred. All
regulatory assets will continue to be recovered from customers under the
Company's transition plan. Based on that plan, the Company continues to bill and
collect cost-based rates for its transmission and distribution services, which
will remain regulated; accordingly, it is appropriate that the Company continues
the application of SFAS 71 to those operations. The Company recognized
incremental transition cost recovery aggregating $37 million in accordance with
the current Ohio transition plan.
Net regulatory assets on the Consolidated Balance Sheets are
comprised of the following:
2001 2000
---------------------------------------------------------------------------
(In millions)
Regulatory transition costs...................... $394.7 $420.5
Loss on reacquired debt.......................... 3.2 3.6
Other............................................ (9.1) (11.4)
--------------------------------------------------------------------------
Total..................................... $388.8 $412.7
===========================================================================
2. LEASES:
The Company leases certain generating facilities, office space and
other property and equipment under cancelable and noncancelable leases.
The Company and CEI sold their ownership interests in Bruce Mansfield
Units 1, 2 and 3 and the Company sold a portion of its ownership interest in
Beaver Valley Unit 2. In connection with these sales, which were completed in
1987, the Company and CEI entered into operating leases for lease terms of
approximately 30 years as co-lessees. During the terms of the leases, the
Company and CEI continue to be responsible, to the extent of their combined
ownership and leasehold interest, for costs associated with the units including
construction expenditures, operation and maintenance expenses, insurance,
nuclear fuel, property taxes and decommissioning. The Company and CEI have the
right, at the end of the respective basic lease terms, to renew the leases. The
Company and CEI also have the right to purchase the facilities at the expiration
of the basic lease term or renewal term (if elected) at a price equal to the
fair market value of the facilities.
As co-lessee with CEI, the Company is also obligated for CEI's lease
payments. If CEI is unable to make its payments under the Bruce Mansfield Plant
lease, the Company would be obligated to make such payments. No such payments
have been made on behalf of CEI. (CEI's future minimum lease payments as of
December 31, 2001 were approximately $0.2 billion, net of trust cash receipts.)
Consistent with the regulatory treatment, the rentals for capital and
operating leases are charged to operating expenses on the Consolidated
Statements of Income. Such costs for the three years ended December 31, 2001 are
summarized as follows:
2001 2000 1999
- -----------------------------------------------------------------------------
(In millions)
Operating leases
Interest element............... $ 55.7 $ 58.7 $ 61.4
Other.......................... 52.4 46.2 45.3
Capital leases
Interest element............... 2.5 3.9 5.3
Other.......................... 14.1 24.1 30.4
- ---------------------------------------------------------------------------
Total rentals.................. $124.7 $132.9 $142.4
===========================================================================
The future minimum lease payments as of December 31, 2001 are:
Operating Leases
--------------------------------
Capital Lease Capital
Leases Payments Trust Net
- -------------------------------------------------------------------------------
(In millions)
2002.......................... $0.3 $ 111.0 $ 37.9 $ 73.1
2003.......................... -- 111.7 36.0 75.7
2004.......................... -- 97.9 24.3 73.6
2005.......................... -- 104.8 24.9 79.9
2006.......................... -- 107.8 25.6 82.2
Years thereafter.............. -- 1,007.9 246.6 761.3
-----------------------------------------------------------------------------
Total minimum lease payments.. 0.3 $1,541.1 $395.3 $1,145.8
======== ====== ========
Interest portion.............. --
----------------------------------------
Present value of net minimum
lease payments.............. 0.3
Less current portion.......... 0.3
----------------------------------------
Noncurrent portion............ $--
========================================
The Company and CEI refinanced high-cost fixed obligations related to
their 1987 sale and leaseback transaction for the Bruce Mansfield Plant through
a lower cost transaction in June and July 1997. In a June 1997 offering
(Offering), the two companies pledged $720 million aggregate principal amount
($145 million for the Company and $575 million for CEI) of first mortgage bonds
due through 2007 to a trust as security for the issuance of a like principal
amount of secured notes due through 2007. The obligations of the two companies
under these secured notes are joint and several. Using available cash,
short-term borrowings and the net proceeds from the Offering, the two companies
invested $906.5 million ($337.1 million for the Company and $569.4 million for
CEI) in a business trust, in June 1997. The trust used these funds in July 1997
to purchase lease notes and redeem all $873.2 million aggregate principal amount
of 10-1/4% and 11-1/8% secured lease obligations bonds (SLOBs) due 2003 and
2016. The SLOBs were issued by a special-purpose funding corporation in 1988 on
behalf of lessors in the two companies' 1987 sale and leaseback transaction. The
Shippingport Capital Trust arrangement effectively reduces lease costs related
to that transaction.
3. CAPITALIZATION:
(A) RETAINED EARNINGS-
The Company has a provision in its mortgage that requires common
stock dividends to be paid out of its total balance of retained earnings. The
1997 FirstEnergy merger purchase accounting adjustments included resetting the
retained earnings balance to zero at the November 8, 1997 merger date.
(B) STOCK COMPENSATION PLANS-
Employees of the Company participate in stock based plans
administered by FirstEnergy which include the Centerior Equity Plan (CE Plan)
and FirstEnergy Executive and Director Incentive Compensation Plan (FE Plan).
All options are fully vested under the CE Plan, and no further awards are
permitted. Outstanding options will expire on or before February 25, 2007. Under
the FE Plan, total awards cannot exceed 15 million shares of common stock or
their equivalent. Only stock options and restricted stock have been granted,
with vesting periods ranging from six months to seven years.
Under the Executive Deferred Compensation Plan, covered employees can
direct a portion of their Annual Incentive Award and/or Long Term Incentive
Award into an unfunded FirstEnergy Stock Account to receive vested stock units.
An additional 20% premium is received in the form of stock units based on the
amount allocated to the FirstEnergy Stock Account. Dividends are calculated
quarterly on stock units outstanding and are paid in the form of additional
stock units. Upon withdrawal, stock units are converted to FirstEnergy shares.
Payout occurs three years from the date of deferral.
The Company continues to apply APB 25, "Accounting for Stock Issued
to Employees." As required by SFAS 123, "Accounting for Stock-Based
Compensation," the Company has determined pro forma earnings as though the
Company had accounted for employee stock options under the fair value method.
The weighted average assumptions used in valuing the options and their resulting
fair values are as follows:
2001 2000 1999
- --------------------------------------------------------------------------
Valuation assumptions:
Expected option term (years) 8.3 7.6 6.4
Expected volatility......... 23.45% 21.77% 20.03%
Expected dividend yield..... 5.00% 6.68% 5.97%
Risk-free interest rate..... 4.67% 5.28% 5.97%
Fair value per option......... $4.97 $2.86 $3.42
- --------------------------------------------------------------------------
The following table summarizes the pro forma effect of applying fair
value accounting to the Company's stock options.
2001 2000 1999
- -----------------------------------------------------------------------------
Earnings on Common Stock (000)
As Reported................. $46,776 $120,986 $83,707
Pro Forma................... $46,623 $120,778 $83,615
- -----------------------------------------------------------------------------
(C) PREFERRED AND PREFERENCE STOCK-
Preferred stock may be redeemed by the Company in whole, or in part,
with 30-90 days' notice.
The preferred dividend rates on the Company's Series A and Series B
shares fluctuate based on prevailing interest rates and market conditions. The
dividend rates for these issues averaged 7.00% and 7.05%, respectively, in 2001.
The Company exercised its option to redeem all outstanding shares of
five series of preferred stock on February 1, 2002 as follows:
Series Outstanding Shares Call Price
-------------------------------------------------------
$ 7.76 150,000 $102.44
$ 7.80 150,000 $101.65
$ 8.32 100,000 $102.46
$10.00 190,000 $101.00
$ 2.21 1,000,000 $25.25
-------------------------------------------------------
The Company has five million authorized and unissued shares of $25
par value preference stock.
(D) LONG-TERM DEBT-
The first mortgage indenture and its supplements, which secure all of
the Company's first mortgage bonds, serve as direct first mortgage liens on
substantially all property and franchises, other than specifically excepted
property, owned by the Company.
Based on the amount of bonds authenticated by the Trustee through
December 31, 2001, the Company's annual sinking and improvement fund
requirements for all bonds issued under the mortgage amounts to $0.4 million.
The Company expects to deposit funds in 2002 that will be withdrawn upon the
surrender for cancellation of a like principal amount of bonds, which are
specifically authenticated for such purposes against unfunded property additions
or against previously retired bonds. This method can result in minor increases
in the amount of the annual sinking fund requirement.
Sinking fund requirements for first mortgage bonds and maturing
long-term debt (excluding capital leases) for the next five years are:
(In millions)
---------------------------------------------
2002................................. $263.3
2003................................. 101.9
2004................................. 268.7
2005................................. --
2006................................. --
---------------------------------------------
The Company's obligations to repay certain pollution control revenue
bonds are secured by several series of first mortgage bonds. Certain pollution
control revenue bonds are entitled to the benefit of irrevocable bank letters of
credit of $68.0 million and a noncancelable municipal bond insurance policy of
$30.9 million to pay principal of, or interest on, the pollution control revenue
bonds. To the extent that drawings are made under the letters of credit, the
Company is entitled to a credit against its obligation to repay those bonds. The
Company pays an annual fee of 1.00% of the amounts of the letters of credit to
the issuing bank and is obligated to reimburse the bank for any drawings
thereunder.
The Company and CEI have letters of credit of approximately $222
million in connection with the sale and leaseback of Beaver Valley Unit 2 that
expire in May 2002. The letters of credit are secured by first mortgage bonds of
the Company and CEI in the proportion of 60% and 40%, respectively (see Note 2).
4. SHORT-TERM BORROWINGS:
The Company may borrow from its affiliates on a short-term basis. As
of December 31, 2001, the Company had total short-term borrowings of $17.2
million from its affiliates with a weighted average interest rate of
approximately 3.6%.
5. COMMITMENTS AND CONTINGENCIES:
CAPITAL EXPENDITURES-
The Company's current forecast reflects expenditures of approximately
$228 million for property additions and improvements from 2002-2006, of which
approximately $72 million is applicable to 2002. Investments for additional
nuclear fuel during the 2002-2006 period are estimated to be approximately $120
million, of which approximately $12 million applies to 2002. During the same
periods, the Company's nuclear fuel investments are expected to be reduced by
approximately $114 million and $22 million, respectively, as the nuclear fuel is
consumed.
NUCLEAR INSURANCE-
The Price-Anderson Act limits the public liability relative to a
single incident at a nuclear power plant to $9.5 billion. The amount is covered
by a combination of private insurance and an industry retrospective rating plan.
Based on its ownership and leasehold interests in Beaver Valley Unit 2, the
Davis Besse Station and the Perry Plant, the Company's maximum potential
assessment under the industry retrospective rating plan (assuming the other
affiliate co-owners contribute their proportionate shares of any assessments
under the retrospective rating plan) would be $77.9 million per incident but not
more than $8.8 million in any one year for each incident.
The Company is also insured as to its respective interests in Beaver
Valley Unit 2, Davis-Besse and Perry under policies issued to the operating
company for each plant. Under these policies, up to $2.75 billion is provided
for property damage and decontamination and decommissioning costs. The Company
has also obtained approximately $263.4 million of insurance coverage for
replacement power costs for its respective interests in Beaver Valley Unit 2,
Davis-Besse and Perry. Under these policies, the Company can be assessed a
maximum of approximately $15.1 million for incidents at any covered nuclear
facility occurring during a policy year which are in excess of accumulated funds
available to the insurer for paying losses.
The Company intends to maintain insurance against nuclear risks as
described above as long as it is available. To the extent that replacement
power, property damage, decontamination, decommissioning, repair and replacement
costs and other such costs arising from a nuclear incident at any of the
Company's plants exceed the policy limits of the insurance in effect with
respect to that plant, to the extent a nuclear incident is determined not to be
covered by the Company's insurance policies, or to the extent such insurance
becomes unavailable in the future, the Company would remain at risk for such
costs.
ENVIRONMENTAL MATTERS-
Various federal, state and local authorities regulate the Company
with regard to air and water quality and other environmental matters. In
accordance with the Ohio transition plan discussed in "Regulatory Plans" in Note
1, generation operations and any related additional capital expenditures for
environmental compliance are the responsibility of FirstEnergy's competitive
services business unit.
The Company is required to meet federally approved sulfur dioxide
(SO2) regulations. Violations of such regulations can result in shutdown of the
generating unit involved and/or civil or criminal penalties of up to $27,500 for
each day the unit is in violation. The Environmental Protection Agency (EPA) has
an interim enforcement policy for SO2 regulations in Ohio that allows for
compliance based on a 30-day averaging period. The Company cannot predict what
action the EPA may take in the future with respect to the interim enforcement
policy.
The Company is in compliance with the current SO2 and nitrogen oxides
(NOx) reduction requirements under the Clean Air Act Amendments of 1990. SO2
reductions are being achieved by burning lower-sulfur fuel, generating more
electricity from lower-emitting plants, and/or using emission allowances. NOx
reductions are being achieved through combustion controls and the generation of
more electricity at lower-emitting plants. In September 1998, the EPA finalized
regulations requiring additional NOx reductions from the Company's Ohio and
Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions
of NOx emissions (an approximate 85% reduction in utility plant NOx emissions
from projected 2007 emissions) across a region of nineteen states and the
District of Columbia, including Ohio and Pennsylvania, based on a conclusion
that such NOx emissions are contributing significantly to ozone pollution in the
eastern United States. State Implementation Plans (SIP) must comply by May 31,
2004 with individual state NOx budgets established by the EPA. Pennsylvania
submitted a SIP that requires compliance with the NOx budgets at the Company's
Pennsylvania facilities by May 1, 2003 and Ohio submitted a "draft" SIP that
requires compliance with the NOx budgets at the Company's Ohio facilities by May
31, 2004. FirstEnergy continues to evaluate its compliance plans and other
compliance options.
In July 1997, the EPA promulgated changes in the National Ambient Air
Quality Standard (NAAQS) for ozone emissions and proposed a new NAAQS for
previously unregulated ultra-fine particulate matter. In May 1999, the U.S.
Court of Appeals found constitutional and other defects in the new NAAQS rules.
In February 2001, the U.S. Supreme Court upheld the new NAAQS rules regulating
ultra-fine particulates but found defects in the new NAAQS rules for ozone and
decided that the EPA must revise those rules. The future cost of compliance with
these regulations may be substantial and will depend if and how they are
ultimately implemented by the states in which the Company operates affected
facilities.
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants. The EPA identified mercury as the hazardous air pollutant of
greatest concern. The EPA established a schedule to propose regulations by
December 2003 and issue final regulations by December 2004. The future cost of
compliance with these regulations may be substantial.
As a result of the Resource Conservation and Recovery Act of 1976, as
amended, and the Toxic Substances Control Act of 1976, federal and state
hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous waste
disposal requirements pending the EPA's evaluation of the need for future
regulation. The EPA has issued its final regulatory determination that
regulation of coal ash as a hazardous waste is unnecessary. On April 25, 2000,
the EPA announced that it will develop national standards regulating disposal of
coal ash under its authority to regulate nonhazardous waste.
The Company has been named as a "potentially responsible party" (PRP)
at waste disposal sites which may require cleanup under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980. Allegations of
disposal of hazardous substances at historical sites and the liability involved
are often unsubstantiated and subject to dispute. Federal law provides that all
PRPs for a particular site be held liable on a joint and several basis. The
Company has accrued a liability of $0.2 million as of December 31, 2001, based
on estimates of the total costs of cleanup, the proportionate responsibility of
other PRPs for such costs and the financial ability of other PRPs to pay. The
Company believes that waste disposal costs will not have a material adverse
effect on its financial condition, cash flows or results of operations.
OTHER LEGAL PROCEEDINGS-
Various lawsuits, claims and proceedings related to the Company's
normal business operations are pending against FirstEnergy and its subsidiaries.
The most significant applicable to the Company are described above.
6. SALE OF GENERATING ASSETS:
On November 29, 2001, FirstEnergy reached an agreement to sell four
coal-fired power plants (with an aggregate net book value of $539 million as of
December 31, 2001) totaling 2,535 MW to NRG Energy Inc. (NRG) for $1.5 billion
($1.355 billion in cash and $145 million in debt assumption). The sale includes
the 648 MW Bay Shore plant owned by the Company (with an aggregate net book
value of $80 million as of December 31, 2001). The net, after-tax gain from the
sale, based on the difference between the sale price of the plants and their
market price used in our Ohio restructuring transition plan, will be credited to
customers by reducing the transition cost recovery period. FirstEnergy also
entered into a power purchase agreement (PPA) with NRG. Under the terms of the
PPA, NRG is obligated to sell up to 10.5 billion kilowatt-hours of electricity
annually, similar to the average annual output of the plants, through 2005. The
sale is expected to close in mid-2002.
7. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
The following summarizes certain consolidated operating results by
quarter for 2001 and 2000.
March 31, June 30, September 30, December 31,
Three Months Ended 2001 2001 2001 2001
- -------------------------------------------------------------------------------------------------------------
(In millions)
Operating Revenues.......................... $271.6 $263.0 $306.5 $253.8
Operating Expenses and Taxes................ 243.3 229.6 278.9 237.6
- -------------------------------------------------------------------------------------------------------------
Operating Income............................ 28.3 33.4 27.6 16.2
Other Income................................ 3.8 2.2 3.9 5.7
Net Interest Charges........................ 15.9 12.6 15.1 14.6
- -------------------------------------------------------------------------------------------------------------
Net Income.................................. $ 16.2 $ 23.0 $ 16.4 $ 7.3
=============================================================================================================
Earnings on Common Stock.................... $ 12.2 $ 18.9 $ 12.4 $ 3.3
=============================================================================================================
March 31, June 30, September 30, December 31,
Three Months Ended 2000 2000 2000 2000
- -------------------------------------------------------------------------------------------------------------
(In millions)
Operating Revenues.......................... $217.4 $235.4 $260.8 $241.3
Operating Expenses and Taxes................ 173.5 201.8 188.6 197.6
- -------------------------------------------------------------------------------------------------------------
Operating Income............................ 43.9 33.6 72.2 43.7
Other Income................................ 2.7 2.2 2.0 1.8
Net Interest Charges........................ 17.1 15.2 16.6 16.0
- -------------------------------------------------------------------------------------------------------------
Net Income.................................. $ 29.5 $ 20.6 $ 57.6 $ 29.5
=============================================================================================================
Earnings on Common Stock.................... $ 25.5 $ 16.4 $ 53.6 $ 25.5
=============================================================================================================
Report of Independent Public Accountants
To the Stockholders and Board of Directors of The Toledo Edison Company:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of The Toledo Edison Company (an Ohio corporation
and wholly owned subsidiary of FirstEnergy Corp.) and subsidiary as of December
31, 2001 and 2000, and the related consolidated statements of income, common
stockholder's equity, preferred stock, cash flows and taxes for each of the
three years in the period ended December 31, 2001. 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 auditing standards generally accepted
in the United States. 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 The Toledo Edison Company and
subsidiary as of December 31, 2001 and 2000, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 2001, in conformity with accounting principles generally accepted in the
United States.
ARTHUR ANDERSEN LLP
Cleveland, Ohio,
March 18, 2002.