THE TOLEDO EDISON COMPANY
2000 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 2-6
Consolidated Statements of Income 7
Consolidated Balance Sheets 8
Consolidated Statements of Capitalization 9-10
Consolidated Statements of Common Stockholder's Equity 11
Consolidated Statements of Preferred Stock 11
Consolidated Statements of Cash Flows 12
Consolidated Statements of Taxes 13
Notes to Consolidated Financial Statements 14-23
Report of Independent Public Accountants 24
THE TOLEDO EDISON COMPANY
SELECTED FINANCIAL DATA
Nov. 8- Jan. 1-
2000 1999 1998 Dec. 31, 1997 Nov. 7, 1997 1996
- --------------------------------------------------------------------------------------------------------------------
(Dollars in thousands) |
|
|
GENERAL FINANCIAL INFORMATION: |
|
Operating Revenues $ 954,947 $ 921,159 $ 957,037 $ 122,669 | $ 772,707 $ 897,259
========== ========== ========== ========== | ========== ==========
|
Operating Income $ 193,414 $ 163,772 $ 180,261 $ 19,055 | $ 123,282 $ 156,815
========== ========== ========== ========== | ========== ==========
|
Income Before Extraordinary Item $ 137,233 $ 99,945 $ 106,582 $ 7,616 | $ 41,769 $ 57,289
========== ========== ========== ========== | ========== ==========
|
Net Income (Loss) $ 137,233 $ 99,945 $ 106,582 $ 7,616 | $ (150,132) $ 57,289
========== ========== ========== ========== | ========== ==========
|
Earnings (Loss) on Common Stock $ 120,986 $ 83,707 $ 92,972 $ 7,616 | $ (169,567) $ 40,363
========== ========== ========== ========== | ========== ==========
|
Total Assets $2,652,267 $2,666,928 $2,768,765 $2,758,152 | $3,428,175
========== ========== ========== ========== | ==========
|
|
CAPITALIZATION: |
Common Stockholder's Equity $ 605,587 $ 551,704 $ 575,692 $ 531,650 | $ 803,237
Preferred Stock- |
Not Subject to Mandatory Redemption 210,000 210,000 210,000 210,000 | 210,000
Subject to Mandatory Redemption -- -- -- 1,690 | 3,355
Long-Term Debt 944,193 981,029 1,083,666 1,210,190 | 1,051,517
---------- ---------- ---------- ---------- | ----------
Total Capitalization $1,759,780 $1,742,733 $1,869,358 $1,953,530 | $2,068,109
========== ========== ========== ========== | ==========
|
CAPITALIZATION RATIOS: |
Common Stockholder's Equity 34.4% 31.7% 30.8% 27.2%| 38.8%
Preferred Stock- |
Not Subject to Mandatory Redemption 11.9 12.0 11.2 10.8 | 10.2
Subject to Mandatory Redemption -- -- -- 0.1 | 0.2
Long-Term Debt 53.7 56.3 58.0 61.9 | 50.8
----- ----- ----- ----- | -----
Total Capitalization 100.0% 100.0% 100.0% 100.0%| 100.0%
===== ===== ===== ===== | =====
|
KILOWATT-HOUR SALES (Millions): |
Residential 2,183 2,127 2,252 355 | 1,718 2,145
Commercial 2,380 2,236 2,425 284 | 1,498 1,790
Industrial 5,595 5,449 5,317 847 | 4,003 4,301
Other 49 54 63 79 | 413 488
------ ------ ------ ----- | ----- ------
Total Retail 10,207 9,866 10,057 1,565 | 7,632 8,724
Total Wholesale 3,135 2,409 1,617 435 | 2,218 2,330
------ ------ ------ ----- | ----- ------
Total 13,342 12,275 11,674 2,000 | 9,850 11,054
====== ====== ====== ===== | ===== ======
|
CUSTOMERS SERVED: |
Residential 269,071 266,900 265,237 262,501 | 261,541
Commercial 31,413 32,481 31,982 29,367 | 27,411
Industrial 1,917 1,937 1,954 1,835 | 1,839
Other 598 398 359 347 | 2,136
------- ------- ------- ------- | -------
Total 302,999 301,716 299,532 294,050 | 292,927
======= ======= ======= ======= | =======
|
Number of Employees (a) 539 977 997 1,532 | 1,643
<FN>
(a) Reduction in 2000 reflects transfer of responsibility for generation
operations to FirstEnergy Corp.'s competitive services unit.
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.
Results of Operations
- ---------------------
Earnings on common stock increased 45% to $121.0 million in 2000
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. In 1999, earnings on common
stock decreased 10% to $83.7 million in 1999 from $93.0 million in 1998
due to lower operating revenues and increased nuclear and other operating
costs which more than offset reductions in purchased power costs and net
interest charges.
Operating revenues increased by $33.8 million in 2000 following
a $35.9 million decrease in 1999. The sources of changes in operating
revenues during 2000 and 1999, as compared to the prior year, are
summarized in the following table:
Sources of Revenue Changes 2000 1999
- --------------------------------------------------------------
Increase (Decrease) (In millions)
Change in retail kilowatt-hour sales $26.0 $(14.8)
Decrease in average retail price (9.1) (20.7)
Increase in wholesale sales 13.1 2.0
All other changes 3.8 (2.4)
- --------------------------------------------------------------
Net Change in Operating Revenues $33.8 $(35.9)
===============================================================
Electric Sales
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 in 2000, 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.
Operating revenues in 1999 decreased, after achieving record
levels in 1998, due to lower retail revenues resulting from both lower
average retail prices and reduced kilowatt-hour sales. Despite the lower
retail sales in 1999, total kilowatt-hour sales increased as a result of a
strong increase in sales to the wholesale market resulting from weather-
induced demand and available internal generation. However, the increase in
wholesale revenues did not fully offset the decrease in retail revenues
experienced in 1999. Changes in kilowatt-hour sales by customer class in
2000 and 1999 are summarized in the following table:
Changes in KWH Sales 2000 1999
- --------------------------------------------------
Increase (Decrease)
Residential 2.6% (5.6)%
Commercial 6.4% (7.8)%
Industrial 2.7% 2.5%
- -------------------------------------------------
Total Retail 3.5% (1.9)%
Wholesale 30.1% 49.0%
- -------------------------------------------------
Total Sales 8.7% 5.1%
- -------------------------------------------------
Operating Expenses and Taxes
Total operating expenses and taxes increased by $4.1 million in
2000 and decreased $19.4 million in 1999, compared to the preceding year.
The moderate increase in operating expenses and taxes in 2000 occurred as
a result of a $22.2 million increase in income taxes resulting from higher
taxable income and offsetting reductions in fuel and purchased power costs
and other operating costs. In 1999, fuel and purchased power costs were
the primary factors contributing to lower operating expenses and taxes.
Fuel and purchased power costs decreased $10.1 million in 2000,
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. In
1999, purchased power costs accounted for all of the reduction in fuel and
purchased power costs. Much of the decrease in purchased power costs
occurred in the second quarter of 1999, due to the absence of unusual
conditions experienced in 1998. The higher purchased power costs were
incurred during a period of record heat and humidity in late June 1998,
which coincided with a regional power shortage resulting in high prices
for purchased power. During this period, unscheduled outages at Beaver
Valley Unit 2 and the Davis-Besse Plant required us to purchase
significant quantities of power on the spot market. Although above normal
temperatures were also experienced in 1999, we maintained a stronger
capacity position compared to the previous year and better met customer
demand from our own internal generation.
Nuclear operating costs increased slightly by $3.0 million in
2000. 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. Expenses associated with refueling outages at the Perry Plant
and Beaver Valley Unit 2 in 1999 contributed to the $14.9 million increase
in nuclear operating costs, compared to 1998. Other operating costs
decreased $15.1 million in 2000 primarily due to increased gains of $18.9
million realized from the sale of emission allowances in 2000. Partially
offsetting the higher gains were additional transmission expenses.
Net Interest Charges
Net interest charges decreased by $11.7 million in 2000 and $9.3
million in 1999, compared to the prior year. We continue to redeem our
outstanding debt, thus maintaining the downward trend in our financing
costs during 2000. Net redemptions of long-term debt totaled $174 million
in 2000.
Effects of SFAS 71 Discontinuation and Impairment
- -------------------------------------------------
The application of the Statement of Financial Accounting
Standards No. (SFAS) 71, "Accounting for the Effects of Certain Types of
Regulation," was discontinued for our nonnuclear generation business
effective with approval by the Public Utilities Commission of Ohio (PUCO)
of the Ohio transition plan. We continue to bill and collect cost-based
rates for transmission and distribution services, which remain subject to
cost-based regulation; accordingly, it is appropriate that we continue the
application of SFAS 71 to those operations. All generating plant
investments were reviewed for impairment due to anticipated changes to our
cash flows resulting from the transition plan. The June 30, 2000 balance
sheet reflects the effect of that review with plant investment being
reduced by a total of $53 million with a corresponding recognition of
regulatory assets for the impaired plant, which is recoverable through
future regulatory cash flows.
Financial Condition, Capital Resources and Liquidity
- ----------------------------------------------------
On September 1, 2000, FirstEnergy Corp.'s electric utility
operating companies transferred $1.2 billion of their transmission assets
to American Transmission Systems, Inc. (ATSI), an affiliated company. ATSI
represents a first step toward the goal of establishing a larger
independent, regional transmission organization. As part of the transfer,
we sold to ATSI $150.2 million of our transmission assets, net of $77.0
million of accumulated depreciation and $1.7 million of investment tax
credits for $32.2 million in cash and $39.3 million in long-term notes.
Through net security redemptions, we continued to reduce the
cost of debt and preferred stock, and improve our financial position in
2000. We reduced total debt by approximately $68 million during 2000. Our
common stockholder's equity percentage of capitalization increased to 34%
as of December 31, 2000 from 27% at the end of 1997. We have reduced the
average capital cost of outstanding debt from 9.23% in 1995 to 7.84% in
2000. Annual savings from net security redemptions in 2000 are expected to
total about $8 million. Also, approval by the PUCO of our transition plan
on July 19, 2000 (see Outlook), was cited as an important reason that
Moody's Investors Service and Fitch upgraded our debt ratings during the
second half of 2000. The improved credit ratings should lower the cost of
future borrowings. Our credit ratings remain under review for further
possible upgrades by Moody's. The improved credit ratings are summarized
in the following table:
Credit Ratings Before Upgrade After Upgrade
- -------------------------------------------------------------------
Moody's Moody's
Investors Investors
Service Fitch Service Fitch
- --------------------------------------------------------------------
First mortgage bonds Ba1 BB+ Baa3 BBB-
Subordinated debt Ba3 B+ Ba1 BB
Preferred stock b1 B ba1 BB
Our cash requirements in 2001 for operating expenses,
construction expenditures, preferred stock redemptions and scheduled debt
maturities are expected to be met without issuing additional securities.
We have cash requirements of approximately $505.1 million for the 2001-
2005 period to meet scheduled maturities of long-term debt and preferred
stock. Of that amount, approximately $29.4 million relates to 2001.
We had about $34.0 million of cash and temporary investments and
$41.9 million of indebtedness to associated companies as of December 31,
2000. Under our first mortgage indenture, as of December 31, 2000, we
would have been permitted to issue up to $543.7 million of additional
first mortgage bonds on the basis of property additions and retired bonds.
Under the earnings coverage test contained in our charter, we could issue
$463.4 million of preferred stock (assuming no additional debt was issued)
based on our 2000 earnings.
Our capital spending for the period 2001-2005 is expected to be
about $218 million (excluding nuclear fuel), of which approximately $49
million relates to 2001. Investments for additional nuclear fuel during
the 2001-2005 period are estimated to be approximately $79 million, of
which about $7 million applies to 2001. During the same periods, our
nuclear fuel investments are expected to be reduced by approximately $99
million and $22 million, respectively, as the nuclear fuel is consumed.
Also, we have operating lease commitments, net of trust cash receipts, of
approximately $374 million for the 2001-2005 period, of which
approximately $72 million relates to 2001.
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 interest rate 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.
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
2001 2002 2003 2004 2005 after Total Value
- ------------------------------------------------------------------------------------------------
(Dollars in millions)
Investments other than
Cash and Cash
Equivalents:
Fixed Income $17 $ 20 $20 $ 9 $ 10 $280 $356 $360
Average interest rate 7.6% 7.6% 7.6% 7.6% 7.6% 7.2% 7.3%
- ------------------------------------------------------------------------------------------------
Liabilities
- ------------------------------------------------------------------------------------------------
Long-term Debt:
Fixed rate $30 $165 $96 $215 $ -- $224 $730 $764
Average interest rate 9.2% 8.6% 7.9% 7.8% 10.0% 7.7% 8.0%
Variable rate $189 $189 $188
Average interest rate 5.0% 5.0%
Short-term Borrowings $42 $ 42 $ 42
Average interest rate 6.8% 6.8%
- ------------------------------------------------------------------------------------------------
Outlook
- -------
On July 19, 2000, the PUCO approved FirstEnergy's plan for
transition to customer choice in Ohio (see Note 1), filed on our behalf,
as well as for our affiliated Ohio electric utility operating companies -
OE and CEI. As part of its authorization, the PUCO approved a settlement
agreement between FirstEnergy and major groups representing most of
FirstEnergy's Ohio customers regarding the transition to customer choice
in selection of electricity suppliers. On January 1, 2001, electric choice
became available to FirstEnergy's Ohio customers. Under the plan, we
continue to deliver power to homes and businesses through our existing
distribution system, which remains regulated. However, our rates have been
restructured to establish separate charges for transmission and
distribution, transition cost recovery and a generation-related component.
When one of our Ohio customers elects to obtain power from an alternative
supplier, we reduce the customer's bill with a "generation shopping
credit," based on market prices plus an incentive, and the customer
receives a generation charge from the alternative supplier.
The transition cost portion of rates provides for recovery of
certain amounts not otherwise recoverable in a competitive generation
market (such as regulatory assets). The transition costs will be paid by
all customers regardless of whether or not they choose an alternative
supplier. Under the plan, we assume the risk of not recovering up to $80
million of transition revenue if the rate of customers (excluding
contracts and full-service accounts), switching their service from us has
not reached an average of 20% over any consecutive twelve-month period by
December 31, 2005 - the end of the market development period. We 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 Ohio service areas.
Through February 8, 2001, approximately 80 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 February 8, 2001, we had been notified that about 2,000 of
our customers requested generation services from other authorized
suppliers, including FirstEnergy Services Corp. (FE Services), an
affiliated company.
Beginning in 2001, Ohio utilities that offer both competitive
and regulated retail electric services must implement a corporate
separation plan approved by the PUCO -- one which provides a clear
separation between regulated and competitive operations. Since
FirstEnergy's regionally-focused retail sales strategy envisions the
continued operation of both regulated and competitive operations, its
transition plan included details for our corporate separation. The
approved plan is consistent with the way FirstEnergy managed its
businesses in 2000, through a competitive services unit, a utility
services unit and a corporate support services unit. FE Services provides
competitive retail energy services while we continue to provide regulated
transmission and distribution services. FirstEnergy Generation Corp. (FE
Generation), an associated company, leases fossil plants from us and
operates these plants. We expect that the transfer of ownership of our
fossil generating assets to FE Generation will be completed by the end of
the market development period. All of our power supply requirements are
provided by FE Services to satisfy our "provider of last resort"
obligation under the FirstEnergy transition plan, as well as grandfathered
wholesale contracts.
We are in compliance with current sulfur dioxide and nitrogen
oxides (NOx) reduction requirements under the Clean Air Act Amendments of
1990. In 1998, the EPA finalized regulations requiring additional NOx
reductions in the future from our Ohio and Pennsylvania facilities (see
Note 5). We continue to evaluate our compliance plans and other compliance
options.
In July 1997, the EPA changed 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 on the manner in which they are ultimately implemented, if
at all, by the states in which we operate affected facilities.
Under federal environmental law and related federal and state
waste regulations, 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 as a
nonhazardous waste.
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.
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 an accrued liability totaling $0.2
million as of December 31, 2000, 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 flow or results of operation.
On August 8, 2000, our parent company, FirstEnergy Corp.,
entered into an agreement to merge with GPU, Inc, a Pennsylvania
corporation, headquartered in Morristown, New Jersey. The target date for
completing the merger is by the end of the second quarter of 2001. We will
continue to be a wholly owned subsidiary of FirstEnergy Corp.
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2000 1999 1998
- ---------------------------------------------------------------------------------
(In thousands)
OPERATING REVENUES (1) $954,947 $921,159 $957,037
-------- -------- --------
OPERATING EXPENSES AND TAXES:
Fuel and purchased power 159,039 169,153 202,239
Nuclear operating costs 178,063 175,015 160,080
Other operating costs 156,286 171,427 166,935
-------- -------- --------
Total operation and maintenance expenses 493,388 515,595 529,254
Provision for depreciation and amortization 104,914 103,725 106,433
General taxes 90,837 87,862 86,661
Income taxes 72,394 50,205 54,428
-------- -------- --------
Total operating expenses and taxes 761,533 757,387 776,776
-------- -------- --------
OPERATING INCOME 193,414 163,772 180,261
OTHER INCOME 8,669 12,744 12,225
-------- -------- --------
INCOME BEFORE NET INTEREST CHARGES 202,083 176,516 192,486
-------- -------- --------
NET INTEREST CHARGES:
Interest on long-term debt 72,892 82,204 88,364
Allowance for borrowed funds used during
construction (6,523) (1,443) (1,273)
Other interest expense (credit) (1,519) (4,190) (1,187)
-------- -------- --------
Net interest charges 64,850 76,571 85,904
-------- -------- --------
NET INCOME 137,233 99,945 106,582
PREFERRED STOCK DIVIDEND
REQUIREMENTS 16,247 16,238 13,610
-------- -------- --------
EARNINGS ON COMMON STOCK $120,986 $ 83,707 $ 92,972
======== ======== ========
<FN>
(1) Includes electric sales to associated companies of $142.3 million,
$123.3 million and $123.6 million in 2000, 1999 and 1998, respectively.
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31, 2000 1999
- ---------------------------------------------------------------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service $1,637,616 $1,776,534
Less-Accumulated provision for depreciation 597,397 670,866
---------- ----------
1,040,219 1,105,668
---------- ----------
Construction work in progress-
Electric plant 73,565 95,854
Nuclear fuel 10,720 386
---------- ----------
84,285 96,240
---------- ----------
1,124,504 1,201,908
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Shippingport Capital Trust (Note 2) 279,836 295,454
Nuclear plant decommissioning trusts 132,442 123,500
Long-term notes receivable from associated companies 39,084 --
Other 4,601 4,678
---------- ----------
455,963 423,632
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents 1,385 312
Receivables-
Customers 6,618 12,965
Associated companies 62,271 40,998
Other 1,572 9,827
Notes receivable from associated companies 32,617 7,863
Materials and supplies, at average cost-
Owned 17,388 23,243
Under consignment 21,994 20,232
Prepayments and other 27,151 25,931
---------- ----------
170,996 141,371
---------- ----------
DEFERRED CHARGES:
Regulatory assets 412,682 385,284
Goodwill 458,164 465,169
Property taxes 22,916 43,448
Other 7,042 6,116
---------- ----------
900,804 900,017
---------- ----------
$2,652,267 $2,666,928
========== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements of
Capitalization):
Common stockholder's equity $ 605,587 $ 551,704
Preferred stock not subject to mandatory redemption 210,000 210,000
Long-term debt 944,193 981,029
---------- ----------
1,759,780 1,742,733
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term 56,230 95,765
Accounts payable-
Associated companies 36,564 20,537
Other 25,070 27,100
Notes payable to associated companies 41,936 33,876
Accrued taxes 57,519 57,742
Accrued interest 19,946 21,961
Other 49,908 60,414
---------- ----------
287,173 317,395
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes 196,944 172,236
Accumulated deferred investment tax credits 35,174 38,748
Nuclear plant decommissioning costs 138,784 130,116
Pensions and other postretirement benefits 119,327 122,986
Other 115,085 142,714
---------- ----------
605,314 606,800
---------- ----------
COMMITMENTS AND CONTINGENCIES
(Notes 2 and 5) ---------- ----------
$2,652,267 $2,666,928
========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an
integral part of these balance sheets.
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31, 2000 1999
- ----------------------------------------------------------------------------------------------------------------------
(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) 81,358 27,475
---------- ----------
Total common stockholder's equity 605,587 551,704
---------- ----------
Number of Shares Optional
Outstanding Redemption Price
---------------- --------------------
2000 1999 Per Share Aggregate
---- ---- --------- ---------
PREFERRED STOCK (Note 3B):
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
--------- --------- -------- ---------- ----------
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
--------- --------- -------- ---------- ----------
Total Not Subject to Mandatory
Redemption 5,700,000 5,700,000 $216,140 210,000 210,000
========= ========= ======== ---------- ----------
LONG-TERM DEBT (Note 3C):
First mortgage bonds:
8.000% due 2001-2003 34,525 34,925
7.875% due 2004 145,000 145,000
---------- ----------
Total first mortgage bonds 179,525 179,925
---------- ----------
Unsecured notes and debentures:
10.000% due 2001-2010 970 1,000
8.700% due 2002 135,000 135,000
* 4.850% due 2030 34,850 34,850
* 5.100% 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 226,920 226,950
---------- ----------
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)
As of December 31 2000 1999
- ----------------------------------------------------------------------------------------------------------------------
(In thousands)
LONG-TERM DEBT (Cont'd):
Secured notes:
7.190% due 2000 -- 45,000
7.380% due 2000 -- 14,000
7.460% due 2000 -- 16,500
7.500% due 2000 -- 100
8.500% due 2001 8,000 8,000
9.500% due 2001 21,000 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
8.000% due 2019 -- 67,300
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
7.400% due 2022 -- 30,900
6.875% due 2023 20,200 20,200
8.000% due 2023 30,500 30,500
*4.900% due 2024 67,300 --
6.100% due 2027 10,100 10,100
5.375% due 2028 3,751 3,751
*4.550% due 2033 30,900 --
---------- ----------
Total secured notes 512,151 587,751
---------- ----------
Capital lease obligations (Note 2) 56,859 45,247
---------- ----------
Net unamortized premium on debt 24,968 36,921
---------- ----------
Long-term debt due within one year (56,230) (95,765)
---------- ----------
Total long-term debt 944,193 981,029
---------- ----------
TOTAL CAPITALIZATION $1,759,780 $1,742,733
========== ==========
<FN>
* Denotes variable rate issue with December 31, 2000 interest
rate shown.
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
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, 1998 39,133,887 $195,670 $328,364 $ 7,616
Purchase accounting fair value adjustment 195
Net income $ 106,582 106,582
=========
Cash dividends on preferred stock (12,252)
Cash dividends on common stock (50,483)
- -----------------------------------------------------------------------------------------------------------
Balance, December 31, 1998 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
===========================================================================================================
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, 1998 5,700,000 $210,000 33,550 $ 3,355
Redemptions-
$100 par $9.375 (16,650) (1,665)
- ------------------------------------------------------------------------------------------
Balance, December 31, 1998 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 -- $ --
==========================================================================================
<FN>
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2000 1999 1998
- ----------------------------------------------------------------------------------------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income $137,233 $ 99,945 $106,582
Adjustments to reconcile net income to net
cash from operating activities:
Provision for depreciation and amortization 104,914 103,725 106,433
Nuclear fuel and lease amortization 23,881 25,166 24,071
Deferred income taxes, net 20,376 27,551 38,840
Investment tax credits, net (1,827) (1,922) (2,595)
Receivables (6,671) 5,242 (32,169)
Materials and supplies 4,093 418 (2,463)
Accounts payable 13,997 (20,898) 4,559
Other (38,180) 1,427 19,172
-------- -------- --------
Net cash provided from operating activities 257,816 240,654 262,430
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt 96,405 89,330 3,629
Short-term borrowings, net 8,060 33,876 --
Redemptions and Repayments-
Preferred stock -- 1,690 1,665
Long-term debt 200,633 226,695 90,929
Dividend Payments-
Common stock 67,100 106,351 50,483
Preferred stock 16,247 16,238 16,378
-------- -------- --------
Net cash used for financing activities 179,515 227,768 155,826
-------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions 92,860 107,338 45,870
Loans to associated companies 63,838 -- 60,434
Loan payments from associated companies -- (93,373) --
Capital trust investments (15,618) (15,308) (2,111)
Sale of assets to associated companies (81,014) -- --
Other 17,162 18,057 20,441
-------- -------- --------
Net cash used for investing activities 77,228 16,714 124,634
-------- -------- --------
Net increase (decrease) in cash and cash equivalents 1,073 (3,828) (18,030)
Cash and cash equivalents at beginning of year 312 4,140 22,170
-------- -------- --------
Cash and cash equivalents at end of year $ 1,385 $ 312 $ 4,140
======== ======== ========
SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized) $ 71,009 $ 84,538 $ 93,828
======== ======== ========
Income taxes $ 65,553 $ 40,461 $ 6,935
======== ======== ========
<FN>
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF TAXES
For the Years Ended December 31, 2000 1999 1998
- ------------------------------------------------------------------------------------------
(In thousands)
GENERAL TAXES:
Real and personal property $ 46,302 $ 44,280 $ 44,993
State gross receipts 36,813 35,706 35,114
Social security and unemployment 7,220 6,801 5,065
Other 502 1,075 1,489
-------- -------- --------
Total general taxes $ 90,837 $ 87,862 $ 86,661
======== ======== ========
PROVISION FOR INCOME TAXES:
Currently payable-
Federal $ 56,631 $ 29,728 $ 22,767
State 1,811 1,489 1,954
-------- -------- --------
58,442 31,217 24,721
-------- -------- --------
Deferred, net-
Federal 20,865 27,745 38,851
State (489) (194) (11)
-------- -------- --------
20,376 27,551 38,840
-------- -------- --------
Investment tax credit amortization (1,827) (1,922) (2,595)
-------- -------- --------
Total provision for income taxes $ 76,991 $ 56,846 $ 60,966
======== ======== ========
INCOME STATEMENT CLASSIFICATION
OF PROVISION FOR INCOME TAXES:
Operating income $ 72,394 $ 50,205 $ 54,428
Other income 4,597 6,641 6,538
-------- -------- --------
Total provision for income taxes $ 76,991 $ 56,846 $ 60,966
======== ======== ========
RECONCILIATION OF FEDERAL INCOME TAX
EXPENSE AT STATUTORY RATE TO TOTAL
PROVISION FOR INCOME TAXES:
Book income before provision for income taxes $214,224 $156,791 $167,548
======== ======== ========
Federal income tax expense at statutory rate $ 74,978 $ 54,877 $ 58,642
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits (1,827) (1,922) (2,595)
Amortization of tax regulatory assets (1,737) (1,735) (1,739)
Amortization of goodwill 4,334 4,280 4,421
Other, net 1,243 1,346 2,237
-------- -------- --------
Total provision for income taxes $ 76,991 $ 56,846 $ 60,966
======== ======== ========
ACCUMULATED DEFERRED INCOME TAXES
AT DECEMBER 31:
Property basis differences $163,537 $195,326 $195,948
Deferred nuclear expense 73,695 76,449 79,355
Impaired generating assets 18,843 -- --
Deferred sale and leaseback costs (22,274) (21,443) (20,623)
Unamortized investment tax credits (16,689) (18,324) (19,515)
Unused alternative minimum tax credits (5,100) (30,055) (66,322)
Deferred gain for asset sale to affiliated company 15,330 -- --
Other (30,398) (29,717) (17,522)
-------- -------- --------
Net deferred income tax liability $196,944 $172,236 $151,321
======== ======== ========
<FN>
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
<PAGE
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). FirstEnergy holds directly all of the issued and
outstanding common shares of the Company and its other principal electric
utility operating subsidiaries, CEI and Ohio Edison Company (OE). On
September 1, 2000, the Company sold its transmission assets to
FirstEnergy's wholly owned subsidiary, American Transmission Systems, Inc.
(ATSI). As a result, ATSI owns and operates FirstEnergy's major
high-voltage transmission facilities and has interconnections with other
regional utilities.
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.
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, 2000 or 1999, 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 Corporation (CFC), a wholly
owned subsidiary of CEI. CFC subsequently transfers the receivables to a
trust under an asset-backed securitization agreement. The trust completed
a public sale of $150 million and private sales of $50 million of
receivables-backed investor certificates in 1996 and 2000, respectively,
in transactions that qualified for sale accounting treatment. CFC's
retained interest in the pool of receivables held by the trust (15.15% as
of December 31, 2000) is stated at fair value reflecting adjustments for
anticipated credit losses. Collections of receivables previously
transferred to the trust used to purchase new receivables from CFC during
2000, totaled approximately $2.5 billion. Expenses associated with the
factoring discount related to the sale of receivables were $13 million in
2000. As of December 31, 2000, the Company's receivables recorded on its
Consolidated Balance Sheet were reduced by $103 million due to these
sales.
REGULATORY PLAN-
The PUCO approved FirstEnergy's Rate Reduction and Economic
Development Plan for the Company in January 1997. The regulatory plan was
to maintain then current base electric rates for the Company through
December 31, 2005. At the end of the regulatory plan period, the Company's
base rates were to be reduced by $93 million (approximately 15 percent
below then current levels). The regulatory plan also revised the Company's
fuel cost recovery method so that the Company's fuel rate would be frozen
through the regulatory plan period, subject to limited periodic
adjustments. As part of the regulatory plan, transition rate credits were
implemented for customers, which were expected to reduce operating
revenues for the Company by approximately $111 million during the
regulatory plan period. The regulatory plan was terminated at the end of
2000 concurrent with the implementation of the FirstEnergy transition plan
as described further below.
In July 1999, Ohio's electric utility restructuring legislation,
which allowed Ohio electric customers to select their generation suppliers
beginning January 1, 2001, was signed into law. Among other things, the
legislation provides for a five percent reduction on the generation
portion of residential customers' bills and the opportunity to recover
transition costs, including regulatory assets, from January 1, 2001
through December 31, 2005. The period for the recovery of regulatory
assets only can be extended up to December 31, 2010. The PUCO was
authorized to determine the level of transition cost recovery, as well as
the recovery period for the regulatory assets portion of those costs, in
considering each Ohio electric utility's transition plan application.
FirstEnergy, on behalf of its Ohio electric utility operating
companies -- the Company, CEI and OE -- filed its transition plan under
Ohio's new electric utility restructuring law in late 1999. The filing
also included additional information on FirstEnergy's plans to turn over
control, and perhaps ownership, of its transmission assets to the Alliance
Regional Transmission Organization. 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, the Company's
transition plan also included its proposals on 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 new law, and how the Company's
transmission system will be operated to ensure access to all users.
Customer prices would be frozen through a five-year market development
period (2001-2005), except for certain limited statutory exceptions
including the five percent reduction in the price of generation for
residential customers. The plan proposed recovery of generation-related
transition costs of approximately $859 million ($764 million, net of
deferred income taxes) and transition costs related to regulatory assets
aggregating approximately $842 million ($573 million, net of deferred
income taxes).
On July 19, 2000, the PUCO approved FirstEnergy's transition plan
as modified by a settlement agreement with major parties to the transition
plan. Major parties to the settlement agreement included the PUCO staff, the
Ohio Consumers' Counsel, the Industrial Energy Users-Ohio, certain power
marketers and others. Major provisions of the settlement agreement consisted
of approval of recovery of transition costs in the amounts 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
Company will also give 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 base electric rates for distribution service
for the Company under its prior regulatory plan will be extended from
December 31, 2005 through December 31, 2007. The transition rate credits for
customers under its prior regulatory plan will also be extended through the
transition cost recovery period.
The application of Statement of Financial Accounting Standards
(SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation"
(SFAS 71), to the nonnuclear generation business of the Company 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 (CTC) 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.
The settlement agreement provides to the Company's Ohio customers
an additional incentive applied to the generation shopping credit of 45%
for residential customers, 30% for commercial customers and 15% for
industrial customers as reductions from their bills, when they select
alternative energy providers (the credits exceed the price the Company will
be offering to electricity suppliers relating to the 160 megawatts
described above). The amount of the incentive will serve to reduce the
amortization of transition costs during the market development period and
will be recovered over the remaining transition cost recovery period. If
the customer switching targets established in the settlement 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.
All of the Company's regulatory assets will continue to be
recovered under provisions of the Ohio transition plan. The Company
recognized a fair value purchase accounting adjustment to reduce nuclear
plant by $842 million in connection with the 1997 FirstEnergy merger; that
fair value adjustment recognized for financial reporting purposes
satisfied the $647 million asset reduction commitment contained in the
regulatory plan. For regulatory purposes, the Company recognized the
applicable accelerated amortization over the period that its rate plan was
in effect.
Application of SFAS 71 was discontinued in 1997 with respect to
the Company's nuclear operations and in mid-2000, as discussed above, with
respect to the Company's nonnuclear generation business. The Company's net
assets included in utility plant relating to operations for which the
application of SFAS 71 was discontinued were $623 million as of
December 31, 2000.
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 3.4% in 2000,
1999 and 1998.
Annual depreciation expense includes approximately $9.8 million
for future decommissioning costs applicable to the Company's ownership
interests in three nuclear generating units. Annual decommissioning costs
will increase by approximately $20 million from implementing the Company's
transition plan in 2001. The Company's share of the future obligation to
decommission these units is approximately $422 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 $111 million for decommissioning through its
electric rates from customers through December 31, 2000. The Company has
also recognized an estimated liability of approximately $6.9 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.
The Financial Accounting Standards Board (FASB) issued a
proposed accounting standard for nuclear decommissioning costs in 1996. If
the standard is adopted as proposed: (1) annual provisions for
decommissioning could change; (2) the net present value of estimated
decommissioning costs could be recorded as a liability; and (3) income
from the external decommissioning trusts could be reported as investment
income. The FASB subsequently expanded the scope of the proposed standard
to include other closure and removal obligations related to long-lived
assets. A final pronouncement is expected in the second quarter of 2001
and is anticipated to be implemented on January 1, 2002.
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, 2000
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 $ 39.3 $13.7 $-- 18.61%
Beaver Valley Unit 2 1.4 0.2 3.1 19.91%
Davis-Besse 211.6 24.8 3.2 48.62%
Perry 333.0 37.3 5.9 19.91%
- --------------------------------------------------------------------------
Total $585.3 $76.0 $12.2
==========================================================================
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-
The Company leases its nuclear fuel and pays for the fuel as it
is consumed (see Note 2). 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. Alternative minimum tax
credits of $5 million, which may be carried forward indefinitely, are
available to reduce future federal income taxes. 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. 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, 2000. The assets of the FirstEnergy
pension plan consist primarily of common stocks, United States government
bonds and corporate bonds.
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
---------------------- -----------------------
2000 1999 2000 1999
- ------------------------------------------------------------------------------------------
(In millions)
Change in benefit obligation:
Benefit obligation as of January 1 $1,394.1 $1,500.1 $ 608.4 $ 601.3
Service cost 27.4 28.3 11.3 9.3
Interest cost 104.8 102.0 45.7 40.7
Plan amendments 41.3 -- -- --
Actuarial loss (gain) 17.3 (155.6) 121.7 (17.6)
Net increase from asset swap -- 14.8 -- 12.5
Voluntary early retirement program
expense 23.4 -- -- --
Benefits paid (102.2) (95.5) (35.1) (37.8)
- -----------------------------------------------------------------------------------------
Benefit obligation as of December 31 1,506.1 1,394.1 752.0 608.4
- -----------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets as of
January 1 1,807.5 1,683.0 4.9 3.9
Actual return on plan assets 0.7 220.0 (0.2) 0.6
Company contribution -- -- 18.3 0.4
Benefits paid (102.2) (95.5) -- --
- -----------------------------------------------------------------------------------------
Fair value of plan assets as of
December 31 1,706.0 1,807.5 23.0 4.9
- -----------------------------------------------------------------------------------------
Funded status of plan 199.9 413.4 ( 729.0) (603.5)
Unrecognized actuarial loss (gain) (90.9) (303.5) 147.3 24.9
Unrecognized prior service cost 93.1 57.3 20.9 24.1
Unrecognized net transition
obligation (asset) (2.1) (10.1) 110.9 120.1
- -----------------------------------------------------------------------------------------
Prepaid (accrued) benefit cost $ 200.0 $ 157.1 $(449.9) $(434.4)
==========================================================================================
Company's share of prepaid (accrued)
benefit cost $ 0.9 $ (11.8) $(117.1) $(110.2)
==========================================================================================
Assumptions used as of December 31:
Discount rate 7.75% 7.75% 7.75% 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, 2000 were computed as follows:
Other
Pension Benefits Postretirement Benefits
---------------------------- -------------------------
2000 1999 1998 2000 1999 1998
- ------------------------------------------------------------------------------------------------
(In millions)
Service cost $ 27.4 $ 28.3 $ 25.0 $11.3 $ 9.3 $ 7.5
Interest cost 104.8 102.0 92.5 45.7 40.7 37.6
Expected return on plan assets (181.0) (168.1) (152.7) (0.5) (0.4) (0.3)
Amortization of transition
obligation (asset) (7.9) (7.9) (8.0) 9.2 9.2 9.2
Amortization of prior service
cost 5.7 5.7 2.3 3.2 3.3 (0.8)
Recognized net actuarial loss
(gain) (9.1) -- (2.6) -- -- --
Voluntary early retirement
program expense 17.2 -- -- -- -- --
- ------------------------------------------------------------------------------------------------
Net benefit cost $ (42.9) $ (40.0) $ (43.5) $68.9 $62.1 $53.2
=================================================================================================
Company's share of total
plan costs $ (12.7) $ (8.3) $ (1.1) $15.1 $12.6 $ 7.5
- ------------------------------------------------------------------------------------------------
The FirstEnergy plan's health care trend rate assumption is 7.2%
in 2001, 7.0% in 2002 and 6.5% in 2003, trending to 5.0%-5.5% 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 $7.5 million and the
postretirement benefit obligation by $94.4 million. A decrease in the same
assumption by one percentage point would decrease the total service and
interest cost components by $8.5 million and the postretirement benefit
obligation by $111.0 million.
TRANSACTIONS WITH AFFILIATED COMPANIES-
Operating revenues, operating expenses and interest charges
include transactions with CEI, OE, Penn and ATSI. Primary transactions
include electric sales (see following paragraph), purchased power and
transmission facilities rent expenses of $9.4 million from ATSI starting
in 2000. CFC serves as the transferor in connection with the accounts
receivable securitization for the Company and CEI.
The Company is selling 150 megawatts of its Beaver Valley Unit 2
leased capacity entitlement to CEI. Operating revenues for this
transaction were $104.0 million, $104.3 million and $98.5 million in 2000,
1999 and 1998, respectively. This sale is expected to continue through the
end of the lease period. (See Note 2.)
FirstEnergy and, prior to 1999, the Centerior Service Company
(CSC), a wholly owned subsidiary of FirstEnergy, provides support services
at cost to the Company and other affiliated companies, for which the
Company was billed $36.0 million in 2000 and $59.4 million in 1999 by
FirstEnergy, and $39.0 million in 1998 by CSC.
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. The Company reflects temporary cash
investments at cost, which approximates their fair market value. Noncash
financing and investing activities included capital lease transactions
amounting to $36.1 million, $8.5 million and $27.9 million in 2000, 1999
and 1998, 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:
2000 1999
- ------------------------------------------------------------------
Carrying Fair Carrying Fair
Value Value Value Value
- -------------------------------------------------------------------
(In millions)
Long-term debt $919 $952 $995 $1,002
Investments other than cash
and cash equivalents:
Debt securities
- (Maturing in more than
10 years) $316 $307 $293 $ 270
Equity securities 3 3 3 3
All other 133 137 124 128
- -------------------------------------------------------------------
$452 $447 $420 $ 401
==================================================================
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 application of SFAS 71 to the
Company's nonnuclear generation business was discontinued effective with
the PUCO's approval of FirstEnergy's transition plan. All generating plant
investments were reviewed for impairment due to the anticipated regulatory
cash flows under the transition plan. The effect of that review was
reflected on the financial statements as of June 30, 2000, with the
reduction of plant investment and the corresponding recognition of
regulatory assets recoverable through future regulatory cash flows for
generating assets that were impaired of approximately $53 million for the
Company.
Net regulatory assets on the Consolidated Balance Sheets are
comprised of the following:
2000 1999
- ----------------------------------------------------------------
(In millions)
Nuclear unit expenses $185.5 $192.8
Rate stabilization program deferrals 148.3 156.2
Sale and leaseback costs 26.2 33.7
Loss on reacquired debt 16.5 18.3
Impaired generating assets 53.1 --
Other (16.9) (15.7)
- ----------------------------------------------------------------
Total $412.7 $385.3
===============================================================
2. LEASES:
The Company leases certain generating facilities, nuclear fuel,
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, 2000 were approximately $0.2
billion, net of trust cash receipts.)
Nuclear fuel is currently financed for the Company and CEI
through leases with a special-purpose corporation. As of December 31,
2000, $142 million of nuclear fuel ($56 million for the Company) was
financed under a lease financing arrangement totaling $150 million from
bank credit arrangements. The bank credit arrangements expire in August
2001. Lease rates are based on bank rates and commercial paper rates.
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, 2000 are summarized as follows:
2000 1999 1998
- -------------------------------------------------------------
(In millions)
Operating leases
Interest element $ 58.7 $ 61.4 $ 59.2
Other 46.2 45.3 44.9
Capital leases
Interest element 3.9 5.3 4.9
Other 24.1 30.4 25.1
- --------------------------------------------------------------
Total rentals $132.9 $142.4 $134.1
=============================================================
The future minimum lease payments as of December 31, 2000 are:
Operating Leases
----------------------------
Capital Lease Capital
Leases Payments Trust Net
- ----------------------------------------------------------------------
(In millions)
2001 $28.0 $ 108.0 $ 36.4 $ 71.6
2002 17.2 111.0 37.9 73.1
2003 11.1 111.7 36.0 75.7
2004 5.0 97.9 24.3 73.6
2005 1.5 104.8 24.9 79.9
Years thereafter 0.8 1,115.7 272.2 843.5
- ----------------------------------------------------------------------
Total minimum lease payments 63.6 $1,649.1 $431.7 $1,217.4
Interest portion 6.7 ======== ====== ========
- ------------------------------------
Present value of net minimum
lease payments 56.9
Less current portion 21.1
- ------------------------------------
Noncurrent portion $35.8
====================================
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 reduce
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) 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 fluctuate based on prevailing interest rates and market
conditions. The dividend rates for these issues averaged 7.00% and 7.42%,
respectively, in 2000.
The Company has five million authorized and unissued shares of
$25 par value preference stock.
(C) 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, 2000, 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 2001 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)
- --------------------------
2001 $ 35.1
2002 196.0
2003 96.2
2004 268.7
2005 --
- --------------------------
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 1.375% 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, 2000, the Company had total short-term
borrowings of $41.9 million from its affiliates with a weighted average
interest rate of approximately 6.8%.
5. COMMITMENTS AND CONTINGENCIES:
CAPITAL EXPENDITURES-
The Company's current forecast reflects expenditures of
approximately $218 million for property additions and improvements from
2001-2005, of which approximately $49 million is applicable to 2001.
Investments for additional nuclear fuel during the 2001-2005 period are
estimated to be approximately $79 million, of which approximately
$7 million applies to 2001. During the same periods, the Company's nuclear
fuel investments are expected to be reduced by approximately $99 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
$176.1 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
$8.1 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. The Company estimates additional capital expenditures for
environmental compliance of approximately $16 million, which is included
in the construction forecast provided under "Capital Expenditures" for
2001 through 2005.
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 twenty-two 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. In March 2000, the U.S. Court of Appeals for the
D.C. Circuit upheld EPA's NOx Transport Rule except as applied to the
State of Wisconsin and portions of Georgia and Missouri. By October 2000,
states were to submit revised State Implementation Plans (SIP) to comply
by May 31, 2004 with individual state NOx budgets established by the EPA.
Pennsylvania recently 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. A Federal Implementation
Plan accompanied the NOx Transport Rule and may be implemented by the EPA
in states which fail to revise their SIP. In another separate but related
action, eight states filed petitions with the EPA under Section 126 of the
Clean Air Act seeking reductions of NOx emissions which are alleged to
contribute to ozone pollution in the eight petitioning states. The EPA
position is that the Section 126 petitions will be adequately addressed by
the NOx Transport Program, but a December 17, 1999 rulemaking established
an alternative program which would require nearly identical 85% NOx
reductions at 392 utility plants, including the Company's Ohio and
Pennsylvania plants, by May 2003, in the event implementation of the NOx
Transport Rule is not implemented by a state. Additional Section 126
petitions were filed by New Jersey, Maryland, Delaware and the District of
Columbia in mid-1999 and are still under evaluation by the EPA.
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 on the manner in which they are ultimately
implemented, if at all, 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, 2000, 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.
6. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
The following summarizes certain consolidated operating results
by quarter for 2000 and 1999.
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
=====================================================================
March 31, June 30, September 30, December 31,
Three Months Ended 1999 1999 1999 1999
- ------------------------------------------------------------------------
(In millions)
Operating Revenues $224.3 $235.2 $233.7 $228.0
Operating Expenses
and Taxes 175.6 195.7 191.0 195.2
- ----------------------------------------------------------------------
Operating Income 48.7 39.5 42.7 32.8
Other Income 2.9 3.2 2.8 3.7
Net Interest Charges 19.5 19.5 19.2 18.2
- ----------------------------------------------------------------------
Net Income $ 32.1 $ 23.2 $ 26.3 $ 18.3
======================================================================
Earnings on Common Stock $ 28.1 $ 19.1 $ 22.3 $ 14.2
======================================================================
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, 2000 and 1999, 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, 2000. 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, 2000 and 1999, and the results
of their operations and their cash flows for each of the three years in
the period ended December 31, 2000, in conformity with accounting
principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Cleveland, Ohio,
February 16, 2001.
1