SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q/A
AMENDMENT NO. 2
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
----------------- -----------------
Commission Registrant; State of Incorporation; I.R.S. Employer
File Number Address; and Telephone Number Identification No.
- ----------- ----------------------------------- ------------------
1-3583 THE TOLEDO EDISON COMPANY 34-4375005
(An Ohio Corporation)
c/o FirstEnergy Corp.
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402
Indicate by check mark whether each of the registrants (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
---- -----
Indicate by check mark whether each registrant is an accelerated filer
( as defined in Rule 12b-2 of the Act):
Yes X No
---- -----
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date:
OUTSTANDING
CLASS AS OF MAY 9, 2003
----- -----------------
The Toledo Edison Company, $5 par value 39,133,887
This Form 10-Q/A includes forward-looking statements based on
information currently available to management. Such statements are subject to
certain risks and uncertainties. These statements typically contain, but are not
limited to, the terms "anticipate", "potential", "expect", "believe", "estimate"
and similar words. This Form 10-Q includes forward-looking statements based on
information currently available to management. Such statements are subject to
certain risks and uncertainties. These 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, replacement power costs being higher than anticipated or inadequately
hedged, maintenance costs being higher than anticipated, legislative and
regulatory changes (including revised environmental requirements), availability
and cost of capital, inability of the Davis-Besse Nuclear Power Station to
restart (including because of an inability to obtain a favorable final
determination from the Nuclear Regulatory Commission) in the fall of 2003,
inability to accomplish or realize anticipated benefits from strategic goals,
further investigation into the causes of the August 14, 2003, power outage, and
other similar factors.
EXPLANATORY NOTE
We are filing this Amendment No. 2 to our Quarterly Report on Form 10-Q for the
quarter ended March 31, 2003 (the "Report") to correct typographical errors in
Item 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION of the Report. This Amendment has no effect on previously
reported results of operations or financial position.
The complete amended and restated Item 2, which is included in its entirety
below, reflects the following corrections:
Under the heading "RESTATEMENTS":
Under the subheading "Transition Cost Amortization":
In the last sentence of the second paragraph, the reference to the
three months ended June 30, 2002 and 2003 should have read March 31, 2002 and
2003.
Under the heading "CAPITAL RESOURCES AND LIQUIDITY":
Under the subheading "Cash Flows from Operating Activities", the column
in the table showing the 2003 amounts is corrected as follows:
Operating Cash Flows As originally filed As corrected
-------------------------------------------------------------
(In millions)
Cash earnings (1) $ 30 $ 37
Working capital and other (60) (67)
-------------------------------------------------------------
Total $(30) $(30)
=============================================================
(1) Includes net income, depreciation and amortization,
deferred income taxes, investment tax credits and major
noncash charges.
Under the subheading "Cash Flows from Operating Activities", the column
in the table showing the 2002 amounts is corrected as follows:
Operating Cash Flows As originally filed As corrected
-------------------------------------------------------------
(In millions)
Cash earnings (1) $29 $42
Working capital and other 37 24
-------------------------------------------------------------
Total $66 $66
=============================================================
(1) Includes net income, depreciation and amortization,
deferred income taxes, investment tax credits and major
noncash charges.
TABLE OF CONTENTS
Pages
Part I Financial Information
The Toledo Edison Company
Consolidated Statements of Income........................ *
Consolidated Balance Sheets.............................. *
Consolidated Statements of Cash Flows.................... *
Report of Independent Auditors........................... *
Management's Discussion and Analysis of Results of
Operations and Financial Condition..................... 1-9
Part II. Other Information
* Indicates the items that have not been revised and are not included in this
Form 10-Q/A. Reference is made to the original 10-Q, as previously amended,
for complete text of such items.
THE FOLLOWING ITEM HAS BEEN AMENDED IN THIS AMENDMENT No. 2:
PART I
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
THE TOLEDO EDISON COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
TE is a wholly owned, electric utility subsidiary of FirstEnergy. TE
conducts business in portions of Ohio, providing regulated electric distribution
services. TE also provides generation services to those customers electing to
retain them as their power supplier. TE provides power directly to wholesale
customers under previously negotiated contracts, as well as to alternative
energy suppliers under TE's transition plan. TE has unbundled the price of
electricity into its component elements - including generation, transmission,
distribution and transition charges. Power supply requirements of TE are
provided by FES - an affiliated company.
RESTATEMENTS
As further discussed in Note 1 to the Consolidated Financial
Statements, FirstEnergy is restating its consolidated financial statements for
the year ended December 31, 2002 and the three months ended March 31, 2003 and
2002. The restatements reflect a change in the method of amortizing the costs
being recovered under the Ohio transition plan and recognition of above-market
values of certain leased generation facilities.
Transition Cost Amortization
As discussed in Note 4 - Regulatory Matters, FirstEnergy's Ohio
electric utilities recover transition costs, including regulatory assets,
through an approved transition plan filed under Ohio's electric utility
restructuring legislation. The plan, which was approved in July 2000, provides
for the recovery of costs from January 1, 2001 through a fixed number of
kilowatt-hour sales to all customers that continue to receive regulated
transmission and distribution service, which is expected to end in 2007 for TE.
FirstEnergy and the Ohio utilities amortize transition costs using the
effective interest method. The amortization schedules originally developed at
the beginning of the transition plan in 2001 in applying this method were based
on total transition revenues, including revenues designed to recover costs which
have not yet been incurred or that were recognized on the regulatory financial
statements (fair value purchase accounting adjustments) but not in the financial
statements prepared under GAAP. The Ohio electric utilities have revised their
amortization schedules under the effective interest method to consider only
revenues relating to transition regulatory assets recognized on the GAAP balance
sheet. The impact of this change will result in higher amortization of these
regulatory assets in the first several years of the transition cost recovery
period, versus the method previously applied. The change in method results in no
change in total amortization of the regulatory assets recovered under the
transition period through the end of 2009. The amortization expense under the
revised method (see Note 1) increased by $16.4 million and $15.4 million for the
three months ended March 31, 2002 and 2003, respectively.
Above-Market Lease Costs
In 1997, FirstEnergy Corp. was formed through a merger between OE and
Centerior Energy Corp. The merger was accounted for as an acquisition of
Centerior, the parent company of TE, under the purchase accounting rules of
Accounting Principles Board (APB) Opinion No. 16. In connection with the
reassessment of the accounting for the transition plan, FirstEnergy reassessed
its accounting for the Centerior purchase and determined that above market lease
liabilities should have been recorded at the time of the merger. Accordingly, as
of 2002, FirstEnergy recorded additional adjustments associated with the 1997
merger between OE and Centerior to reflect certain above market lease
liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant, for which TE
had previously entered into sale-leaseback arrangements. and TE recorded an
increase in goodwill related to the above market lease costs for Beaver Valley
Unit 2 since regulatory accounting for nuclear generating assets had been
discontinued prior to the merger date and it was determined that this additional
liability would have increased goodwill at the date of the merger. The
corresponding impact of the above market lease liabilities for the Bruce
Mansfield Plant were recorded as regulatory assets because regulatory accounting
had not been discontinued at that time for the fossil generating assets and
recovery of these liabilities was provided for under the transition plan.
1
The total above market lease obligation of $111 million associated
with Beaver Valley Unit 2 will be amortized through the end of the lease term in
2017. The additional goodwill has been recorded on a net basis, reflecting
amortization that would have been recorded through 2001 when goodwill
amortization ceased with the adoption of SFAS 142. The total above market lease
obligation of $298 million associated with the Bruce Mansfield Plant is being
amortized through the end of 2016. Before the start of the transition plan in
2001, the regulatory asset would have been amortized at the same rate as the
lease obligation. Beginning in 2001, the remaining unamortized regulatory asset
would have been included in TE's amortization schedule for regulatory assets and
amortized through the end of the recovery period - approximately 2007 for TE.
RESULTS OF OPERATIONS
Earnings on common stock in the first quarter of 2003 increased to
$21.9 million from a loss of $4.4 million in the first quarter of 2002. Earnings
on common stock in the first quarter of 2003 included an after-tax credit of
$25.6 million from the cumulative effect of an accounting change due to the
adoption of SFAS 143, "Accounting for Asset Retirement Obligations." Loss before
the cumulative effect was $1.4 million in the first quarter of 2003, compared to
net income of $0.3 million for the same period of 2002. Improved results in the
first quarter of 2003 reflected reduced financing costs and lower operating
expenses. Substantially offsetting these improvements were lower operating
revenues from reduced kilowatt-hour sales.
Operating revenues decreased by $20.7 million or 8.2% in the first
quarter of 2003 from the same period in 2002. The lower revenues resulted from
reduced kilowatt-hour sales which were partially offset by the effects of colder
weather on distribution deliveries to residential and commercial customers.
Kilowatt-hour sales to retail customers declined by 3.5% in the first quarter of
2003 from the same quarter of 2002, which reduced generation sales revenue by
$11.6 million. Electric generation services provided by alternative suppliers as
a percent of total sales deliveries in TE's franchise area increased to 21.8% in
the first quarter of 2003 from 14.4% in the first quarter of 2002.
Distribution deliveries increased 5.8% in the first quarter of 2003
compared to the corresponding quarter of 2002, with increases in all customer
sectors (residential, commercial and industrial). As a result, revenues from
electricity throughput increased by $20.7 million in the first quarter of 2003
from the first quarter of 2002. The increase reflected higher unit prices, which
accounted for two-thirds of the increase and higher volumes. Distribution
deliveries benefited from substantially higher residential and commercial
demand, due in larger part to colder than normal weather, that was moderated by
the continued effect of a sluggish economy and its impact on demand by
industrial customers in TE's franchise area.
Transition plan incentives, provided to customers to encourage
switching to alternative energy providers, reduced operating revenues by $2.2
million in the first quarter of 2003 compared with the same period last year.
These revenue reductions are deferred for future recovery under TE's transition
plan and do not materially affect current period earnings.
Sales revenues from wholesale customers decreased by $21.0 million
(primarily to FES) in the first quarter of 2003 compared with the first quarter
of 2002, due to reduced nuclear generation from the extended outage of the
Davis-Besse Plant (see Davis-Besse Restoration).
Changes in electric generation sales and distribution deliveries in
the first quarter of 2003 from the first quarter of 2002 are summarized in the
following table:
Changes in Kilowatt-Hour Sales
----------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail................................ (3.5)%
Wholesale............................. (28.1)%
----------------------------------------------------
Total Electric Generation Sales........... (15.2)%
====================================================
Distribution Deliveries:
Residential........................... 10.9%
Commercial............................ 11.7%
Industrial............................ 0.3%
---------------------------------------------------
Total Distribution Deliveries............. 5.8%
===================================================
Operating Expenses and Taxes
Total operating expenses and taxes decreased by $15.5 million in the
first quarter of 2003 from the first quarter of 2002. The following table
presents changes from the prior year by expense category.
2
Operating Expenses and Taxes - Change
----------------------------------------------------------------
Increase (Decrease) (In millions)
(Revised)
Fuel............................................. $ (3.7)
Purchased power costs............................ (8.2)
Nuclear operating costs.......................... (9.1)
Other operating costs............................ 6.9
----------------------------------------------------------------
Total operation and maintenance expenses....... (14.1)
Provision for depreciation and amortization...... (2.2)
General taxes.................................... 1.3
Income taxes..................................... (0.5)
----------------------------------------------------------------
Total operating expenses and taxes............. $(15.5)
================================================================
Lower fuel costs in the first quarter of 2003, compared with the same
quarter of 2002, resulted from reduced nuclear generation (down 30%). The lower
purchased power costs reflected fewer kilowatt-hours required for customer
needs. Two scheduled refueling outages in the first quarter of 2002 (Beaver
Valley Unit 2 and Davis-Besse) and the absence of refueling outages in the first
quarter of 2003 more than offset incremental costs associated with the extended
outage of Davis-Besse, producing the lower nuclear operating costs. The increase
in other operating costs resulted in part from higher employee benefit costs.
Charges for depreciation and amortization decreased $2.2 million in
the first quarter of 2003 compared with the first quarter of 2002, attributable
to several factors - higher shopping incentive deferrals ($2.2 million) and
lower charges resulting from the implementation of SFAS 143 ($4.0 million),
including revised service life assumptions for generating plants ($3.0 million).
Nearly offsetting these decreases were increased amortization of regulatory
assets being recovered under TE's transition plan ($2.5 million) and recognition
of depreciation on the Bay Shore generating plant ($1.5 million), which had been
held pending sale in the first quarter of 2002 but was subsequently retained by
FirstEnergy in the fourth quarter of 2002.
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $4.7
million in the first quarter of 2003 from the same period last year, reflecting
security redemptions and refinancings since the end of the first quarter of
2002. TE's net debt redemptions totaled $53.4 million during the first quarter
of 2003, which will result in annualized savings of $4.2 million.
Cumulative Effect of Accounting Change
Upon adoption of SFAS 143 in the first quarter of 2003, TE recorded an
after-tax credit to net income of $25.6 million. TE identified applicable legal
obligations as defined under the new accounting standard for nuclear power plant
decommissioning and reclamation of a sludge disposal pond at the Bruce Mansfield
Plant. As a result of adopting SFAS 143 in January 2003, asset retirement costs
of $41.1 million were recorded as part of the carrying amount of the related
long-lived asset, offset by accumulated depreciation of $5.5 million. The asset
retirement obligation liability at the date of adoption was $172 million,
including accumulated accretion for the period from the date the liability was
incurred to the date of adoption. As of December 31, 2002, TE had recorded
decommissioning liabilities of $179.6 million. The cumulative effect adjustment
for unrecognized depreciation, accretion offset by the reduction in the existing
decommissioning liabilities and ceasing the accounting practice of depreciating
non-regulated generation assets using a cost of removal component was a $43.8
million increase to income, or $25.6 million net of income taxes.
CAPITAL RESOURCES AND LIQUIDITY
TE's cash requirements in 2003 for operating expenses, construction
expenditures, scheduled debt maturities and preferred stock redemptions are
expected to be met without increasing its net debt and preferred stock
outstanding. Available borrowing capacity under short-term credit facilities
will be used to manage working capital requirements. Over the next three years,
TE expects to meet its contractual obligations with cash from operations.
Thereafter, TE expects to use a combination of cash from operations and funds
from the capital markets.
Changes in Cash Position
As of March 31, 2003, TE had $1.4 million of cash and cash
equivalents, compared with $20.7 million as of December 31, 2002. The major
sources for changes in these balances are summarized below.
3
Cash Flows From Operating Activities
Cash provided by (used for) operating activities during the first
quarter of 2003, compared with the corresponding period in 2002 were as follows:
Operating Cash Flows 2003 2002
-------------------------------------------------------------
(In millions)
Cash earnings (1).................... $37 $42
Working capital and other............ (67) 24
-------------------------------------------------------------
Total................................ $(30) $66
=============================================================
(1) Includes net income, depreciation and
amortization, deferred income taxes, investment
tax credits and major noncash charges.
Net cash used for operating activities was $30 million in the first
quarter of 2003, a $96 million change from the $66 million provided by operating
activities in the first quarter of 2002. The decrease in funds from operating
activities resulted from a $97 million decrease in working capital - principally
reduced accounts payable (primarily to associated companies) which contributed
$56.8 million to the decrease in working capital requirements.
Cash Flows From Financing Activities
In the first quarter of 2003, net cash provided from financing
activities increased to $23 million from net cash used for financing of $25
million in the first quarter of 2002. The increase in cash provided from
financing activities primarily resulted from additional short-term borrowings
from associated companies and a slight reduction in security redemptions and
repayments.
TE had approximately $7.9 million of cash and temporary investments
and approximately $248 million of short-term indebtedness as of March 31, 2003.
TE is currently precluded from issuing first mortgage bonds or preferred stock
based upon applicable earnings coverage tests as of March 31, 2003.
Cash Flows From Investing Activities
Net cash used for investing activities decreased $26 million between
the first quarter of 2003 and the same quarter of 2002 due to reduced capital
expenditures and a reduction in the Shippingport Capital Trust investment.
During the last three quarters of 2003, capital requirements for
property additions and capital leases are expected to be about $52 million,
including $9 million for nuclear fuel. TE has additional requirements of
approximately $43 million to meet sinking fund requirements for preferred stock
and maturing long-term debt during the remainder of 2003. These cash
requirements are expected to be satisfied from internal cash and short-term
credit arrangements.
On January 21, 2003, Standard and Poor's (S&P) indicated its concern
about FirstEnergy's disclosure of non-cash charges related to deferred costs in
Pennsylvania, pension and other post-retirement benefits, and Emdersa, which
were higher than anticipated in the third quarter of 2002. S&P identified the
restart of the Davis-Besse nuclear plant "...without significant delay beyond
April 2003..." as key to maintaining FirstEnergy's current debt ratings. S&P
also identified other issues it would continue to monitor including:
FirstEnergy's deleveraging efforts, free cash generated during 2003, the JCP&L
rate case, successful hedging of its short power position, and continued capture
of projected merger savings.
On April 14, 2003, S&P again affirmed its "BBB" corporate credit
rating for FirstEnergy. The S&P outlook remained negative, but S&P improved
FirstEnergy's business position from a "6" to a "5" (on a scale of 1 to 10 with
1 considered the least risky). S&P also reiterated that the key issues being
monitored by the agency included the timely restart of Davis-Besse, the JCP&L
rate case, capture of merger synergies, and controlling capital expenditures at
estimated levels. Significant delays in the planned date of Davis-Besse's return
to service or other factors (identified above) affecting the speed with which
FirstEnergy reduces debt, could put additional pressure on the credit ratings of
FirstEnergy and, correspondingly, its subsidiaries, including TE.
On August 14, 2003, Moody's Investors Service placed the debt ratings
of FirstEnergy and all of its subsidiaries under review for possible downgrade.
Moody's stated that the review was prompted by: (1) weaker than expected
operating performance and cash flow generation; (2) less progress than expected
in reducing debt; (3) continuing high leverage relative to its peer group; and
(4) negative impact on cash flow and earnings from the continuing nuclear plant
outage at Davis-Besse. Moody's further stated that, in anticipation of
Davis-Besse returning to service in the near future and FirstEnergy's continuing
to significantly reduce debt and improve its financial profile, "Moody's does
not expect that the outcome of the review will result in FirstEnergy's senior
unsecured debt rating falling below investment-grade."
4
Other Obligations
Obligations not included on TE's Consolidated Balance Sheet primarily
consist of sale and leaseback arrangements involving the Bruce Mansfield Plant
and Beaver Valley Unit 2. As of March 31, 2003, the present value of these sale
and leaseback operating lease commitments, net of trust investments, totaled
$509 million. TE sells substantially all of its retail customer receivables,
which provided $49 million of off-balance sheet financing as of March 31, 2003.
EQUITY PRICE RISK
Included in TE's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $90
million as of March 31, 2003 and December 31, 2002. A hypothetical 10% decrease
in prices quoted by stock exchanges would result in a $9 million reduction in
fair value as of March 31, 2003.
OUTLOOK
Beginning in 2001, TE's customers were able to select alternative
energy suppliers. TE continues to deliver power to residential homes and
businesses through its existing distribution system, which remains regulated.
Customer rates have been restructured into separate components to support
customer choice. TE has a continuing responsibility to provide power to those
customers not choosing to receive power from an alternative energy supplier
subject to certain limits. Adopting new approaches to regulation and
experiencing new forms of competition have created new uncertainties.
Regulatory Matters
In 2001, Ohio customer rates were restructured to establish separate
charges for transmission, distribution, transition cost recovery and a
generation-related component. When one of TE's Ohio customers elects to obtain
power from an alternative supplier, TE reduces 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. TE has continuing PLR responsibility to its franchise
customers through December 31, 2005.
Regulatory assets are costs which have been authorized by The Public
Utilities Commission of Ohio (PUCO) and the Federal Energy Regulatory Commission
for recovery from customers in future periods and, without such authorization,
would have been charged to income when incurred. Regulatory assets declined
$20.8 million to $557.4 million as of March 31, 2003 from the balance as of
December 31, 2002, resulting from recovery of transition plan regulatory assets.
As part of TE's transition plan it is obligated to supply electricity
to customers who do not choose an alternative supplier. TE is also required to
provide 160 megawatts (MW) of low cost supply to unaffiliated alternative
suppliers that serve customers within its service area. TE's competitive retail
sales affiliate, FES, acts as an alternate supplier for a portion of the load in
its franchise area.
Davis-Besse Restoration
On April 30, 2002, the Nuclear Regulatory Commission (NRC) initiated a
formal inspection process at the Davis-Besse nuclear plant. This action was
taken in response to corrosion found by FENOC in the reactor vessel head near
the nozzle penetration hole during a refueling outage in the first quarter of
2002. The purpose of the formal inspection process is to establish criteria for
NRC oversight of the licensee's performance and to provide a record of the major
regulatory and licensee actions taken, and technical issues resolved, leading to
the NRC's approval of restart of the plant.
Restart activities include both hardware and management issues. In
addition to refurbishment and installation work at the plant, FirstEnergy has
made significant management and human performance changes with the intent of
establishing the proper safety culture throughout the workforce. Work was
completed on the reactor head during 2002 and is continuing on efforts designed
to enhance the unit's reliability and performance. FirstEnergy is also
accelerating maintenance work that had been planned for future refueling and
maintenance outages. At a meeting with the NRC in November 2002, FirstEnergy
discussed plans to test the bottom of the reactor for leaks and to install a
state-of-the-art leak-detection system around the reactor. The additional
maintenance work being performed has expanded the previous estimates of
restoration work. FirstEnergy anticipates that the unit will be ready for
restart in the first half of the summer of 2003 after completion of the
additional maintenance work and regulatory reviews. The NRC must authorize
restart of the plant following its formal inspection process before the unit can
be returned to service. While the additional maintenance work has delayed
FirstEnergy's plans to reduce debt levels FirstEnergy believes such investments
in the unit's future safety, reliability and performance to be essential.
5
Significant delays in Davis-Besse's return to service, which depends on the
successful resolution of the management and technical issues as well as NRC
approval, could trigger an evaluation for impairment of the nuclear plant (see
Significant Accounting Policies below).
Incremental expenses associated with the extended Davis-Besse outage
in the first quarter of 2003 totaled $88.6 million, including $36.3 million for
maintenance work and $52.3 million for fuel and purchased power. TE's ownership
share is 48.62% of those expenses. It is anticipated that an additional $13.7
million in maintenance costs will be spent during the remainder of the
Davis-Besse outage. Replacement power costs are expected to be $15 million per
month in the non-summer months and $20-25 million per month during the summer.
Environmental Matters
TE believes it is 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 2C - Environmental
Matters). TE continues to evaluate its 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 $31,500 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.
TE believes it 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 Companies' 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 New Jersey, 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 Companies' Pennsylvania facilities by May 1, 2003 and Ohio submitted a SIP
that requires compliance with the NOx budgets at the Companies' Ohio facilities
by May 31, 2004.
TE 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; however, federal law provides that all
PRPs for a particular site be held liable on a joint and several basis.
Therefore, potential environmental liabilities have been recognized on the
Consolidated Balance Sheet as of March 31, 2003, based on estimates of the total
costs of cleanup, TE's proportionate responsibility for such costs and the
financial ability of other nonaffiliated entities to pay. TE has total accrued
liabilities of approximately $0.2 million as of March 31, 2003.
The effects of compliance on TE with regard to environmental matters
could have a material adverse effect on its earnings and competitive position.
These environmental regulations affect its earnings and competitive position to
the extent TE competes with companies that are not subject to such regulations
6
and therefore do not bear the risk of costs associated with compliance, or
failure to comply, with such regulations. TE believes it is in material
compliance with existing regulations, but is unable to predict how and when
applicable environmental regulations may change and what, if any, the effects of
any such change would be.
Legal Matters
Various lawsuits, claims and proceedings relayed to TE's normal
business operations are pending against TE, the most significant of which are
described above.
SIGNIFICANT ACCOUNTING POLICIES
TE prepares its consolidated financial statements in accordance with
accounting principles that are generally accepted in the United States.
Application of these principles often requires a high degree of judgment,
estimates and assumptions that affect TE's financial results. All of TE's assets
are subject to their own specific risks and uncertainties and are regularly
reviewed for impairment. Assets related to the application of the policies
discussed below are similarly reviewed with their risks and uncertainties
reflecting those specific factors. TE's more significant accounting policies are
described below.
Regulatory Accounting
TE is subject to regulation that sets the prices (rates) it is
permitted to charge its customers based on the costs that the regulatory
agencies determine TE is 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, a significant amount of
regulatory assets have been recorded. As of March 31, 2003, TE's regulatory
assets totaled $557.4 million. TE regularly reviews 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.
Revenue Recognition
TE follows the accrual method of accounting for revenues, recognizing
revenue for kilowatt-hours that have been delivered but not yet been billed
through the end of the accounting period. 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
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory defined
pension benefits and postemployment benefits other than pensions (OPEB) are
dependent upon numerous factors resulting from actual plan experience and
certain assumptions.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions FirstEnergy makes to the plans, and earnings on plan assets.
Pension and OPEB costs may also be affected by changes to key assumptions,
including anticipated rates of return on plan assets, the discount rates and
health care trend rates used in determining the projected benefit obligations
for pension and OPEB costs.
In accordance with SFAS 87, "Employers' Accounting for Pensions" and
SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions," changes in pension and OPEB obligations associated with these factors
may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
7
In selecting an assumed discount rate, FirstEnergy considers currently
available rates of return on high-quality fixed income investments expected to
be available during the period to maturity of the pension and other
postretirement benefit obligations. Due to the significant decline in corporate
bond yields and interest rates in general during 2002, FirstEnergy reduced the
assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001.
FirstEnergy's assumed rate of return on pension plan assets considers
historical market returns and economic forecasts for the types of investments
held by its pension trusts. The market values of FirstEnergy's pension assets
have been affected by sharp declines in the equity markets since mid-2000. In
2002 and 2001, plan assets earned (11.3)% and (5.5)%, respectively.
FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of
return on plan assets. As of December 31, 2002 the assumed return on plan assets
was reduced to 9.00% based upon FirstEnergy's projection of future returns and
pension trust investment allocation of approximately 60% large cap equities, 10%
small cap equities and 30% bonds.
Based on pension assumptions and pension plan assets as of December
31, 2002, FirstEnergy will not be required to fund its pension plans in 2003.
While OPEB plan assets have also been affected by sharp declines in the equity
market, the impact is not as significant due to the relative size of the plan
assets. However, health care cost trends have significantly increased and will
affect future OPEB costs. The 2003 composite health care trend rate assumption
is approximately 10%-12% gradually decreasing to 5% in later years, compared to
the 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6%
in later years. In determining its trend rate assumptions, FirstEnergy included
the specific provisions of its health care plans, the demographics and
utilization rates of plan participants, actual cost increases experienced in its
health care plans, and projections of future medical trend rates.
Ohio Transition Cost Amortization
In developing TE's restructuring plan, the PUCO determined allowable
transition costs based on amounts recorded on the EUOC's regulatory books. These
costs exceeded those deferred or capitalized on TE's balance sheet prepared
under GAAP since they included certain costs which have not yet been incurred or
that were recognized on the regulatory financial statements (fair value purchase
accounting adjustments). TE uses an effective interest method for amortizing its
transition costs, often referred to as a "mortgage-style" amortization. The
interest rate under this method is equal to the rate of return authorized by the
PUCO in the transition plan for each respective company. In computing the
transition cost amortization, TE includes only the portion of the transition
revenues associated with transition costs included on the balance sheet prepared
under GAAP. Revenues collected for the off balance sheet costs and the return
associated with these costs are recognized as income when received.
Long-Lived Assets
In accordance with SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," TE periodically evaluates its long-lived assets
to determine whether conditions exist that would indicate that the carrying
value of an asset may not be fully recoverable. The accounting standard requires
that if the sum of future cash flows (undiscounted) expected to result from an
asset is less than the carrying value of the asset, an asset impairment must be
recognized in the financial statements. If impairment other than of a temporary
nature has occurred, TE recognizes a loss - calculated as the difference between
the carrying value and the estimated fair value of the asset (discounted future
net cash flows).
Goodwill
In a business combination, the excess of the purchase price over the
estimated fair values of the assets acquired and liabilities assumed is
recognized as goodwill. Based on the guidance provided by SFAS 142, TE evaluates
its goodwill for impairment at least annually and would make such an evaluation
more frequently if indicators of impairment should arise. In accordance with the
accounting standard, if the fair value of a reporting unit is less than its
carrying value including goodwill, an impairment for goodwill must be recognized
in the financial statements. If impairment were to occur, TE would recognize a
loss - calculated as the difference between the implied fair value of a
reporting unit's goodwill and the carrying value of the goodwill. TE's annual
review was completed in the third quarter of 2002. The results of that review
indicated no impairment of goodwill. The forecasts used in TE's evaluations of
goodwill reflect operations consistent with its general business assumptions.
Unanticipated changes in those assumptions could have a significant effect on
its future evaluations of goodwill. As of March 31, 2003, TE had approximately
$505 million of goodwill.
8
RECENTLY ISSUED ACCOUNTING STANDARD NOT YET IMPLEMENTED
FIN 46, "Consolidation of Variable Interest Entities - an interpretation
of ARB 51"
In January 2003, the FASB issued this interpretation of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. This Interpretation requires an enterprise to
disclose the nature of its involvement with a VIE if the enterprise has a
significant variable interest in the VIE and to consolidate a VIE if the
enterprise is the primary beneficiary. VIEs created after January 31, 2003 are
immediately subject to the provisions of FIN 46. VIEs created before February 1,
2003 are subject to this interpretation's provisions in the first interim or
annual reporting period beginning after June 15, 2003 (TE's third quarter of
2003). The FASB also identified transitional disclosure provisions for all
financial statements issued after January 31, 2003.
TE currently has transactions which may fall within the scope of this
interpretation and which are reasonably possible of meeting the definition of a
VIE in accordance with FIN 46. TE currently consolidates the majority of these
entities and believes it will continue to consolidate following the adoption of
FIN 46. One of these entities TE is currently consolidating is the Shippingport
Capital Trust, which reacquired a portion of the off-balance sheet debt issued
in connection with the sale and leaseback of its interest in the Bruce Mansfield
Plant. Ownership of the trust includes a 4.85 percent interest by nonaffiliated
parties and a 0.34 percent equity interest by Toledo Edison Capital Corp., a
majority owned subsidiary.
9
PART II. OTHER INFORMATION
- ---------------------------
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
Exhibit
Number
-------
TE
31.1 Certification letter from chief executive officer, as adopted
pursuant to Section 302 of the Sarbanes-Oxley Act.
31.2 Certification letter from chief financial officer, as adopted
pursuant to Section 302 of the Sarbanes-Oxley Act.
32.1 Certification letter from chief executive officer and chief
financial officer, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act.
Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, TE
has not filed as an exhibit to this Form 10-Q/A any instrument with
respect to long-term debt if the total amount of securities authorized
thereunder does not exceed 10% of the total assets of TE, but hereby
agrees to furnish to the Commission on request any such documents.
(b) Reports on Form 8-K
TE
TE filed eleven reports on Form 8-K since December 31, 2002. A report
dated January 17, 2003 reported updated information related with efforts to
prepare Davis-Besse for a safe and reliable return to service. A report dated
March 11, 2003 reported updated Davis-Besse information including the
installation of the new reactor head on the reactor vessel. A report dated March
17, 2003 reported updated Davis-Besse information. A report dated April 16, 2003
reported Davis-Besse information. A report dated May 1, 2003 reported an updated
Davis-Besse ready for restart schedules. A report dated May 9, 2003 reported
updated Davis-Besse information. A report dated June 5, 2003 reported updated
Davis Besse information. A report dated July 24, 2003, reported updates to the
schedule and cost estimates for Davis-Besse. A report dated August 5, 2003
reported the pending restatement of 2002 FE, OE, CEI and TE financial statements
and restatement and reaudit of 2001 CEI and TE financial statements. A report
dated August 7, 2003 reported the pending restatement and reaudit of 2000 CEI
and TE financial statements. A report dated September 12, 2003 reported that FE,
OE, CEI and TE have received an informal data request from the Securities and
Exchange Commission related to the recent restatement of their 2002 financial
statements.
10
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
September 24, 2003
THE TOLEDO EDISON COMPANY
Registrant
/s/ Harvey L. Wagner
----------------------------------------
Harvey L. Wagner
Vice President and Controller
Chief Accounting Officer
11