SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q/A
AMENDMENT NO. 1
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 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 AUGUST 8, 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. 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. 1 to our Quarterly Report on Form 10-Q for the
quarter ended June 30, 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 "RESULTS OF OPERATIONS":
Under the subheading "Net Interest Charges":
In the first sentence, the decrease in net interest charges of $7.5
million in the first half of 2003 should have read $8.2 million.
Under the heading "SIGNIFICANT ACCOUNTING POLICIES",
Under the subheading "Regulatory Accounting":
In the fifth sentence of the first paragraph, total regulatory assets
as of June 30, 2003 of $548.5 million should have read $537.3 million.
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 for complete text of
such items.
THE FOLLOWING ITEM HAS BEEN AMENDED IN THIS AMENDMENT NO.1:
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, TE identified certain accounting matters that require restatement of
the consolidated financial statements for the year ended December 31, 2002 and
the three months ended March 31, 2003. The revisions reflect a change in the
method of amortizing the costs associated with 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, TE recovers 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.
TE amortizes transition costs using the effective interest method. The
amortization schedules developed in applying this method were previously 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). TE has subsequently
revised the amortization schedules under the effective interest method to
consider only revenues relating to transition regulatory assets recognized on
the balance sheet. The amortization expense under the revised method (see Note
1) increased by $17.6 million for the three months and $34 million for the six
months ended June 30, 2002.
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. 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.
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
fiscal 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.
1
RESULTS OF OPERATIONS
TE experienced a loss of $11.9 million on common stock in the second
quarter of 2003 or a decrease of $26.2 million from earnings of $14.3 million in
the second quarter of 2002. Earnings on common stock in the first six months of
2003 increased to $10.0 million from $9.9 million in the first half of 2002.
Results in the first six months of 2003 included an after-tax credit of $25.60
million from the cumulative effect of an accounting change due to the adoption
of SFAS 143, "Accounting for Asset Retirement Obligations." The loss before the
cumulative effect was $11.1 million in the first half of 2003, compared to
income of $16.9 million for the same period of 2002. The lower results in the
second quarter and the first six months of 2003 before the cumulative effect
reflected higher nuclear operating costs and lower operating revenues which were
partially offset by lower fuel, purchased power, depreciation and amortization,
and financing costs.
Operating revenues decreased by $34.3 million or 13.7% in the second
quarter and $55.1 million or 10.9% in the first six months of 2003 from the same
periods in 2002. The lower revenues resulted from reduced kilowatt-hour sales
due, in large part, to the cooler-than-normal temperatures in the second quarter
of 2003. These results were moderated in the first half of 2003 as compared to
the corresponding period of 2002 by the effects of colder weather in the first
quarter of 2003 which increased heating demands. Kilowatt-hour sales to retail
customers declined by 16.4% in the second quarter of 2003 and 10.2% in the first
half of 2003 from the same periods of 2002, which reduced generation sales
revenue by $15.5 million and $27.1 million, respectively. Electric generation
services provided to retail customers by alternative suppliers as a percent of
total sales delivered in TE's franchise area increased 7.5 percentage points in
the second quarter and first six months of 2003 from the corresponding periods
last year.
Distribution deliveries decreased 8.3% in the second quarter and 1.5%
in the first six months of 2003 compared to the corresponding periods of 2002.
Decreases occurred in all customer sectors (residential, commercial and
industrial) in the second quarter of 2003 and only residential sales increased
in the first half of 2003. As a result, revenues from electricity throughput
decreased by $10.8 million in the second quarter of 2003 from the second quarter
of 2002. Revenues from electricity throughput increased by $9.8 million in the
first six months of 2003 due to an increase in industrial sales revenues of
$10.6 million which reflected the effect of higher unit prices partially offset
by a 3.1% kilowatt-hour sales decrease as compared to the same period of 2002.
Transition plan incentives, provided to customers to encourage
switching to alternative energy providers, reduced operating revenues by $1.2
million in the second quarter and $3.4 million in the first six months of 2003
compared with the same periods 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 $6.3 million and
$27.4 million (primarily to FES) in the second quarter and the first six months
of 2003 compared with the same periods in 2002, due to reduced nuclear
generation from the extended outage of the Davis-Besse Plant and a longer than
planned refueling outage at Perry Plant. Available nuclear generation declined
32.4% in the second quarter and 30.8% in the first half of 2003 compared to the
corresponding periods of 2002.
Changes in electric generation sales and distribution deliveries in
the second quarter and the first half of 2003 from the second quarter and first
half of 2002 are summarized in the following table:
Changes in Kilowatt-Hour Sales Three Months Six Months
--------------------------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail (16.4)% (10.2)%
Wholesale............................. (17.1)% (23.2)%
-------------------------------------------------------------------
Total Electric Generation Sales......... (16.7)% (15.9)%
===================================================================
Distribution Deliveries:
Residential (10.2)% 1.3%
Commercial (12.4)% (1.0)%
Industrial............................ (6.0)% (3.1)%
-------------------------------------------------------------------
Total Distribution Deliveries........... (8.3)% (1.5)%
===================================================================
Operating Expenses and Taxes
Total operating expenses and taxes decreased by $4.6 million in the
second quarter and $20.1 million in the first six months of 2003 from the same
periods in 2002. The following table presents changes from the prior year by
expense category.
2
Operating Expenses and Taxes - Changes Three Months Six Months
-------------------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel......................................... $ (1.7) $ (5.4)
Purchased power costs........................ (5.1) (13.3)
Nuclear operating costs...................... 22.5 13.4
Other operating costs........................ 1.1 8.0
------------------------------------------------------------------------
Total operation and maintenance expenses... 16.8 2.7
Provision for depreciation and amortization.. (2.7) (4.8)
General taxes................................ 0.5 1.8
Income taxes................................. (19.2) (19.8)
-------------------------------------------------------------------------
Net decrease in operating expenses and taxes $ (4.6) $ (20.1)
=========================================================================
Lower fuel costs in the second quarter and first half of 2003,
compared with the same quarter and six months of 2002, resulted from reduced
nuclear generation (down 32.4% and 30.8%, respectively). The lower purchased
power costs reflected fewer kilowatt-hours required for customer needs which
more than offset an increase in unit costs. Increased nuclear costs resulted
from additional incremental costs associated with the extended Davis-Besse
outage and unplanned work performed during the Perry nuclear plant's 56-day
refueling outage (19.91% ownership) in the second quarter of 2003, compared with
the 24-day refueling outage at Beaver Valley Unit 2 (19.91% ownership) in the
first quarter of 2002. The increase in other operating costs resulted in part
from higher employee benefit costs.
Charges for depreciation and amortization decreased by $2.7 million in
the second quarter of 2003, compared with the second quarter of 2002 primarily
from three factors - higher shopping incentive deferrals ($1.2 million), lower
charges resulting from the implementation of SFAS 143 ($4.5 million) and revised
service life assumptions for generating plants ($2.6 million). Partially
offsetting these decreases were increased amortization of regulatory assets
being recovered under TE's transition plan ($3.4 million), recognition of
depreciation on the Bay Shore generating plant ($1.2 million) which had been
held pending sale in the second quarter of 2002 but was subsequently retained by
FirstEnergy in the fourth quarter of 2002 and reduced regulatory asset deferrals
($0.7 million).
In the first six months of 2003, depreciation and amortization
decreased by $4.8 million compared to the corresponding period of 2002 as a
result of the same factors which impacted the second quarter comparison - higher
shopping incentive deferrals ($3.4 million), lower charges resulting from
implementation of SFAS 143 ($8.2 million) and revised service life assumptions
($5.0 million). Partially offsetting these decreases were increased amortization
of regulatory assets being recovered under TE's transition plan ($7.7 million),
recognition of depreciation on the Bay Shore generating plant ($2.4 million) and
reduced regulatory asset deferrals ($1.6 million).
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $3.5
million in the second quarter and $8.2 million in the first half of 2003 from
the same periods last year, reflecting security redemptions and refinancings
since the beginning of the second quarter of 2002.
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 $25.5 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 $180.8 million, including unrealized gains on the
decommissioning trust funds of $1.9 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 significantly 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.
3
Changes in Cash Position
As of June 30, 2003, TE had $10.3 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.
Cash Flows From Operating Activities
Cash provided by (used for) operating activities during the second
quarter and first six months of 2003, compared with the corresponding periods in
2002 were as follows:
Three Months Ended Six Months Ended
June 30, June 30,
Operating Cash Flows 2003 2002 2003 2002
------------------------------------------------------------------------
(In millions)
Cash earnings (1)........ $24 $ 52 $ 62 $ 87
Working capital and other (9) (76) (77) (46)
------------------------------------------------------------------------
Total.................... $15 $(24) $(15) $ 41
========================================================================
(1) Includes net income, depreciation and amortization,
deferred income taxes, investment tax credits and major
noncash charges.
Net cash provided from operating activities was $15 million in the
second quarter and $15 million of net cash used in the first half of 2003
compared with $24 million and $41 million, respectively, in the corresponding
periods of 2002. The second quarter increase in funds from operating activities
resulted from a $67 million decrease in cash used for working capital.
Cash Flows From Financing Activities
In the second quarter of 2003, net cash provided from financing
activities decreased to $22 million from $34 million in the second quarter of
2002. This decrease in cash provided from financing activities primarily
resulted from lower short-term borrowings from associated companies and a slight
reduction in security redemptions and repayments.
TE had approximately $21.1 million of cash and temporary investments
and approximately $281.2 million of short-term indebtedness as of June 30, 2003.
TE is currently precluded from issuing first mortgage bonds or preferred stock
based upon applicable earnings coverage tests as of June 30, 2003.
Cash Flows From Investing Activities
Net cash used for investing activities increased $17 million between
the second quarter of 2003 and the same quarter of 2002 due to a reduction in
2002 in the Shippingport Capital Trust investment.
During the second half of 2003, capital requirements for property
additions and capital leases are expected to be about $34 million, including $6
million for nuclear fuel. TE has additional requirements of approximately $34
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 July 25, 2003, Standard & Poor's (S&P) issued comments on
FirstEnergy's debt ratings in light of the latest extension of the Davis-Besse
and the NJBPU decision on the JCP&L rate case. S&P noted that additional costs
from the Davis-Besse outage extension, the NJBPU ruling on recovery of deferred
energy costs and additional capital investments required to improve reliability
in the New Jersey shore communities will adversely affect FirstEnergy's cash
flow and deleveraging plans. S&P noted that it continues to assess FirstEnergy's
plans to determine if projected financial measures are adequate to maintain its
current rating.
On August 7, 2003, S&P affirmed its "BBB" corporate credit rating for
FirstEnergy. However, S&P stated that although FirstEnergy generates substantial
free cash, that its strategy for reducing debt had deviated substantially from
the one presented to S&P around the time of the GPU merger when the current
rating was assigned. S&P further noted that their affirmation of FirstEnergy's
corporate credit rating was based on the assumption that FirstEnergy would take
appropriate steps quickly to maintain its investment grade ratings including the
issuance of equity or possible sale of assets. Key issues being monitored by S&P
include the restart of Davis-Besse, FirstEnergy's liquidity position, its
ability to forecast provider-of-last-resort load and the performance of its
hedged portfolio and continued capture of merger synergies. On August 11, 2003,
S&P stated that a recent U.S. District Court ruling (see Environmental Matters
below) with respect to the Sammis Plant is negative for FirstEnergy's credit
quality.
4
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."
Pension and Other Postretirement Benefits
As a result of GPU Service Inc. merging with FirstEnergy Service
Company in the second quarter of 2003, operating company employees of GPU
Service were transferred to JCP&L, Met-Ed and Penelec. Accordingly, FirstEnergy
requested an actuarial study to update the pension and other post-employment
benefit (OPEB) assets and liabilities for each of its subsidiaries. Based on the
actuary's report, TE's accrued pension and OPEB costs as of June 30, 2003
decreased by $3.4 million and $24.5 million, respectively.
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 June 30, 2003, the present value of these sale
and leaseback operating lease commitments, net of trust investments, totaled
$474 million. TE sells substantially all of its retail customer receivables,
which provided $49 million of off-balance sheet financing as of June 30, 2003.
EQUITY PRICE RISK
Included in TE's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $107
million and $90 million as of June 30, 2003 and December 31, 2002, respectively.
A hypothetical 10% decrease in prices quoted by stock exchanges would result in
a $11 million reduction in fair value as of June 30, 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
$41.0 million to $537.3 million as of June 30, 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.
5
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 fall of 2003. 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 post-merger debt levels FirstEnergy believes such investments in the
unit's future safety, reliability and performance to be essential. 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 costs associated with the extended Davis-Besse outage
(TE's share - 48.62%) for the second quarter and first six months of 2003 and
2002 were as follows:
Three Months Ended Six Months Ended
Costs of Davis-Besse Extended Outage June 30 June 30
- --------------------------------------------------------------------------------
2003 2002 2003 2002
---- ---- ---- ----
(In millions)
Incremental Pre-Tax Expense
Replacement power $41.1 $33.6 $ 93.4 $33.6
Maintenance 22.4 12.1 58.6 12.1
- --------------------------------------------------------------------------------
Total $63.5 $45.7 $152.0 $45.7
================================================================================
Capital Expenditures $ 2.4 $12.0 $ 2.4 $12.0
================================================================================
It is anticipated that an additional $22 million in maintenance costs
will be expended over 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 months of July and August.
FirstEnergy has hedged the on-peak replacement energy supply for
Davis-Besse for the expected length of the outage.
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
6
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 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 June 30, 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 June 30, 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
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 June 30, 2003, TE's regulatory
assets totaled $537.3 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.
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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 and OPEB benefits 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.
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 FirstEnergy'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 FirstEnergy'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). FirstEnergy 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, FirstEnergy
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.
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Long-Lived Assets
In accordance with SFAS 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 June 30, 2003, TE had approximately
$505 million of goodwill.
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.
EITF Issue No. 01-08, "Determining whether an Arrangement Contains a
Lease"
In May 2003, the EITF reached a consensus regarding when arrangements
contain a lease. Based on the EITF consensus, an arrangement contains a lease if
(1) it identifies specific property, plant or equipment (explicitly or
implicitly), and (2) the arrangement transfers the right to the purchaser to
control the use of the property, plant or equipment. The consensus will be
applied prospectively to arrangements committed to, modified or acquired through
a business combination, beginning in the third quarter of 2003. TE is currently
assessing the new EITF consensus and has not yet determined the impact on its
financial position or results of operations following adoption.
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PART II. OTHER INFORMATION
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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 eight reports on Form 8-K since March 31, 2003. A report
dated April 16, 2003 reported Davis-Besse information. A report dated May 1,
2003 reported an updated Davis-Besse ready for restart schedule. 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 an updated Davis-Besse ready for restart schedule and cost estimates. 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.
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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