THE TOLEDO EDISON COMPANY
CONSOLIDATED FINANCIAL AND OPERATING STATISTICS
Nov. 8 - Jan. 1 -
1998 Dec. 31, 1997 Nov. 7, 1997 1996 1995 1994
- -----------------------------------------------------------------------------------------------------------------------------
(Dollars in thousands)
GENERAL FINANCIAL INFORMATION: |
|
Operating Revenues $ 957,037 $ 122,669 | $ 772,707 $ 897,259 $ 873,657 $ 864,647
========== ========== | ========== ========== ========== ==========
Operating Income $ 180,261 $ 19,055 | $ 123,282 $ 156,815 $ 188,068 $ 179,499
========== ========== | ========== ========== ========== ==========
Income Before Extraordinary Item $ 106,582 $ 7,616 | $ 41,769 $ 57,289 $ 96,762 $ 82,531
========== ========== | ========== ========== ========== ==========
Net Income (Loss) $ 106,582 $ 7,616 | $ (150,132) $ 57,289 $ 96,762 $ 82,531
========== ========== | ========== ========== ========== ==========
Earnings (Loss) on Common Stock $ 92,972 $ 7,616 | $ (169,567) $ 40,363 $ 78,510 $ 62,311
========== ========== | ========== ========== ========== ==========
Net Utility Plant $1,168,216 $1,170,806 | $2,079,742 $2,122,266 $2,204,717
========== ========== | ========== ========== ==========
Total Assets $2,768,765 $2,758,152 | $3,428,175 $3,532,714 $3,546,628
========== ========== | ========== ========== ==========
|
CAPITALIZATION: |
Common Stockholder's Equity $ 575,692 $ 531,650 | $ 803,237 $ 762,877 $ 684,568
Preferred Stock- |
Not Subject to Mandatory Redemption 210,000 210,000 | 210,000 210,000 210,000
Subject to Mandatory Redemption -- 1,690 | 3,355 5,020 6,685
Long-Term Debt 1,083,666 1,210,190 | 1,051,517 1,119,294 1,241,331
---------- ---------- | ---------- ---------- ----------
Total Capitalization $1,869,358 $1,953,530 | $2,068,109 $2,097,191 $2,142,584
========== ========== | ========== ========== ==========
|
CAPITALIZATION RATIOS: |
Common Stockholder's Equity 30.8% 27.2% | 38.8% 36.4% 32.0%
Preferred Stock- |
Not Subject to Mandatory Redemption 11.2 10.8 | 10.2 10.0 9.8
Subject to Mandatory Redemption -- 0.1 | 0.2 0.2 0.3
Long-Term Debt 58.0 61.9 | 50.8 53.4 57.9
----- ----- | ----- ----- -----
Total Capitalization 100.0% 100.0% | 100.0% 100.0% 100.0%
===== ===== | ===== ===== =====
|
KILOWATT-HOUR SALES (Millions): |
Residential 2,252 355 | 1,718 2,145 2,164 2,056
Commercial 2,425 284 | 1,498 1,790 1,748 1,711
Industrial 5,317 847 | 4,003 4,301 4,174 4,099
Other 63 79 | 413 488 500 499
---------- ---------- | ---------- ---------- ---------- ----------
Total Retail 10,057 1,565 | 7,632 8,724 8,586 8,365
Total Wholesale 1,617 435 | 2,218 2,330 2,563 2,548
---------- ---------- | ---------- ---------- ---------- ----------
Total 11,674 2,000 | 9,850 11,054 11,149 10,913
========== ========== | ========== ========== ========== ==========
CUSTOMERS SERVED (Year-End): |
Residential 265,237 262,501 | 261,541 260,007 256,998
Commercial 31,982 29,367 | 27,411 26,508 25,921
Industrial 1,954 1,835 | 1,839 1,846 1,839
Other 359 347 | 2,136 2,119 1,858
---------- ---------- | --------- ---------- ----------
Total 299,532 294,050 | 292,927 290,480 286,616
========== ========== | ========= ========== ==========
|
Average Annual Residential kWh Usage 8,554 7,937 | 8,284 8,384 8,044
Peak Load-Megawatts 1,978 1,813 | 1,758 1,738 1,620
Number of Employees (Year-End) 997 1,532 | 1,643 1,809 1,887
THE TOLEDO EDISON COMPANY
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
This discussion includes forward-looking statements based on
information currently available to management that 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 market prices, legislative and
regulatory changes, and the availability and cost of capital and other
similar factors.
Results of Operations
We continued to take steps in 1998 to better position our
Company as competition continues to expand in the electric utility
industry. Investments were made in new information systems with enhanced
functionality which also address Year 2000 application deficiencies. We
also contributed to the 1998 cash savings of FirstEnergy Corp.
(FirstEnergy) totaling $173 million. These savings were captured from
initiatives implemented during the year in connection with merger-
related economies made possible by FirstEnergy's formation through the
merger of our former parent company, Centerior Energy Corporation, and
Ohio Edison Company on November 8, 1997.
Financial results reflect the application of purchase
accounting to the merger. This accounting resulted in fair value
adjustments, which were "pushed down" or reflected on the separate
financial statements of Centerior's direct subsidiaries as of the
merger date, including our financial statements. As a result, we
recorded purchase accounting fair value adjustments to: (1) revalue our
nuclear generating units to fair value, (2) adjust long-term debt to
fair value, (3) adjust our retirement and severance benefit
liabilities, and (4) record goodwill. Accordingly, the post-merger
financial statements reflect a new basis of accounting, and separate
financial statements are presented for the pre-merger and post-merger
periods. For the remainder of this discussion, for categories
substantially unaffected by the merger and with no significant pre-
merger or post-merger accounting events, we have combined the 1997 pre-
merger and post-merger periods and have compared the total for 1997 to
1998 and 1996.
Earnings on common stock were $93.0 million in 1998. Results
for 1998 were adversely affected by sharp increases in the spot market
price for electricity occasioned by a constrained power supply and heavy
customer demand in the latter part of June 1998, combined with
unscheduled generating unit outages, which resulted in spot market
purchases of power at prices which substantially exceeded amounts
recovered from retail customers. Pre-merger earnings on common stock in
1997 included an October 1997 write-off of certain regulatory assets.
Excluding this write-off, pre-merger earnings on common stock were $22.3
million. For the seven-week post-merger period, earnings on common stock
were $7.6 million. Earnings on common stock were $40.4 million in 1996.
After experiencing a decline in operating revenues in 1997,
compared to the previous year, we achieved record operating revenues in
1998. The following table summarizes the sources of changes in operating
revenues for 1998 and 1997 as compared to the prior year:
1998 1997
---- ----
(In millions)
Increase in retail kilowatt-hour sales $68.2 $ 14.4
Decrease in average retail price (8.8) (23.4)
Wholesale sales (6.6) 7.8
Other 8.9 (0.7)
- ---------------------------------------------------------------
Net Change $61.7 $ (1.9)
===============================================================
Total kilowatt-hour sales were down in 1998 from the prior
year after establishing a new record high in 1997. The decline was due
to a 39.1% decrease in sales to wholesale customers. Several generating
unit outages, described later in this report, reduced energy available
for sale to the wholesale market. Retail sales were up for all customer
groups; residential, commercial and industrial with increases of 8.6%,
9.5% and 9.6%, respectively, compared to 1997. Retail kilowatt-hour
sales benefited from growth in the customer base, which added almost
5,500 new customers during the year. Expanded production at the new
North Star BHP Steel (North Star) facility was a major contributor to
the increase in industrial kilowatt-hour sales. In 1997, North Star was
also a major contributor to industrial sales, which experienced a 12.8%
increase, compared to 1996. This increase was offset in part by reduced
kilowatt-hour sales to residential and commercial customers, which
declined 3.3% and 0.5%, respectively.
Operation and maintenance expenses increased in 1998 compared
to the prior year due to increased fuel and purchased power costs,
offset in part by a decrease in nuclear operating costs. Most of the
increase in fuel and purchased power occurred in the second quarter and
resulted from a combination of factors. In late June 1998, the
midwestern and southern regions of the United States experienced
electricity shortages caused mainly by record temperatures and humidity
and unscheduled generating unit outages. During this period, Beaver
Valley Unit 2 was out of service and the Davis-Besse Plant was removed
from service as a result of damage to transmission facilities caused by
a tornado. As a result, we purchased significant amounts of power on the
spot market at unusually high prices, causing the increase in purchased
power costs. An increase in purchased power costs also contributed to
the 1997 increase in fuel and purchased power costs, compared to 1996,
which was offset in part by lower fuel costs caused by an increase in
the mix of nuclear generation to coal-fired generation. Nuclear
operating costs were lower in 1998, compared to 1997, reflecting a
decrease in costs at the Perry Plant offset in part by higher costs at
the Beaver Valley and Davis-Besse plants. Nuclear operating costs in
1997 were relatively unchanged from 1996 with increased operating costs
at the Beaver Valley Plant substantially offset by lower operating costs
at the Perry and Davis-Besse plants. Other operating costs were higher
in 1997 than the previous year principally due to a $9.3 million
severance and early retirement charge in the 1997 pre-merger period. In
1998, other operating costs increased slightly, compared to 1997,
despite the absence of the severance and early retirement charge
recorded in 1997 primarily due to increased fossil plant costs.
Lower depreciable asset balances resulting from the purchase
accounting adjustment reduced depreciation in the 1998 and 1997 post-
merger period. These reductions were partially offset by the
amortization of goodwill recognized with the application of purchase
accounting. Depreciation in the 1997 pre-merger period increased
principally due to changes in depreciation rates approved in the April
1996 Public Utilities Commission of Ohio (PUCO) rate order.
Interest income on trust notes acquired in connection with the
Bruce Mansfield Plant lease refinancing (see Note 2), which began in
June 1997, was the principal cause of an increase in other income in
1998 and the 1997 post-merger period. In the pre-merger period of 1997,
interest income on the trust notes was substantially offset by merger-
related expenses. Total interest charges decreased in 1998 principally
due to the amortization of net premiums associated with the revaluation
of long-term debt in connection with the merger, which also contributed
to the decrease in interest charges in the post-merger period of 1997.
In the pre-merger period of 1997, interest charges were higher because
interest on new secured notes and short-term borrowings for the Bruce
Mansfield Plant lease refinancing exceeded the expense reduction from
the redemption and refinancing of debt securities.
Preferred stock dividend requirements in 1998 were reduced by
$3 million and in 1997 were increased by $3 million due to the
declaration of preferred dividends as of the merger date for dividends
attributable to the post-merger period (see Note 3c).
Capital Resources and Liquidity
We continue to actively pursue economic refinancings and
optional redemptions to reduce the cost of debt and preferred stock, and
improve our financial position. In 1998, we completed $26 million of
optional redemptions. We reduced total debt by approximately $66 million
during 1998. Our common stockholder's equity percentage of
capitalization increased to 31% at December 31, 1998 from 27% at the end
of the previous year. The merger resulted in improved credit ratings in
1997, which have lowered the cost of new issues. The following table
summarizes changes in credit ratings resulting from the merger:
Pre-Merger Post-Merger
------------------------- --------------------------
Standard Moody's Standard Moody's
& Poor's Investors & Poor's Investors
Corporation Service, Inc. Corporation Service, Inc.
----------- ------------- ----------- -------------
First mortgage bonds BB Ba2 BB+ Ba1
Subordinated debt B+ B1 BB- Ba3
Preferred Stock B b2 BB- b1
Excluding the effect of the Bruce Mansfield Plant lease
refinancing, interest costs on long-term debt were reduced by
approximately $4 million in 1998, compared to 1997. Through economic
refinancings and redemptions of higher cost debt we have reduced the
average cost of outstanding debt from 9.19% in 1993 to 8.25% in 1997
and 8.08% in 1998. We continue to streamline our operations, as
evidenced by a 50% increase in FirstEnergy's customer/employee ratio,
which has increased from 165 at the end of 1993 to 247 as of December
31, 1998. Merger-related savings through consolidation of activities
have contributed to these results.
Our cash requirements in 1999 for operating expenses,
construction expenditures and scheduled debt maturities are expected
to be met without issuing additional securities. We have cash
requirements of approximately $475.2 million for the 1999-2003 period
to meet scheduled maturities of long-term debt and preferred stock. Of
that amount, approximately $105.9 million applies to 1999.
We had about $105.4 million of cash and temporary
investments and no short-term indebtedness on December 31, 1998. Upon
completion of the merger, application of purchase accounting reduced
bondable property such that we are not currently able to issue
additional first mortgage bonds, except in connection with
refinancing. Together with The Cleveland Electric Illuminating
Company, as of December 31, 1998, we had unused borrowing capability
of $100 million under a FirstEnergy revolving line of credit.
Our capital spending for the period 1999-2003 is expected to
be about $257 million (excluding nuclear fuel), of which approximately
$58 million applies to 1999. Investments in additional nuclear fuel
during the 1999-2003 period are estimated to be approximately $102
million, of which about $9 million applies to 1999. During the same
periods, our nuclear fuel investments are expected to be reduced by
approximately $120 million and $26 million, respectively, as the
nuclear fuel is consumed. Also, we have operating lease commitments
net of trust cash receipts of approximately $360 million for the 1999-
2003 period, of which approximately $70 million relates to 1999. We
recover the cost of nuclear fuel consumed and operating leases through
our electric rates.
Interest Rate Risk
Our exposure to fluctuations in market interest rates is
mitigated since a significant portion of our debt has fixed interest
rates, as noted in the table below. We are subject to the inherent
interest rate risks related to refinancing maturing debt by issuing
new debt securities. As discussed in Note 2, our investment in the
Shippingport Capital Trust effectively reduces future lease
obligations, also reducing interest rate risk. Changes in the market
value of our nuclear decommissioning trust funds are recognized by
making a corresponding change to the decommissioning liability, as
described in Note 1.
The table below presents principal amounts and related
weighted average interest rates by year of maturity for our investment
portfolio, debt obligations and preferred stock with mandatory
redemption provisions.
- ----------------------------------------------------------------------------------------------------
There- Fair
1999 2000 2001 2002 2003 after Total Value
(Dollars in Millions)
- ---------------------------------------------------------------------------------------------------
Investments other than Cash and
Cash Equivalents:
Fixed Income $ 15 $ 15 $17 $ 20 $19 $241 $ 327 $ 334
Average interest rate 7.6% 7.6% 7.6% 7.6% 7.6% 7.3% 7.4%
- ---------------------------------------------------------------------------------------------------
Liabilities
- ---------------------------------------------------------------------------------------------------
Long-term Debt:
Fixed rate $104 $ 76 $30 $165 $98 $594 $1,067 $1,143
Average interest rate 7.4% 7.3% 9.2% 8.6% 7.9% 7.8% 7.9%
Variable rate $ 31 $ 31 $ 31
Average interest rate 3.1% 3.1%
- ---------------------------------------------------------------------------------------------------
Preferred Stock $ 2 $ 2 $ 2
Average dividend rate 9.4% 9.4%
- ---------------------------------------------------------------------------------------------------
Outlook
We face many competitive challenges in the years ahead as
the electric utility industry undergoes significant changes, including
regulation and the entrance of more energy suppliers into the
marketplace. Retail wheeling, which would allow retail customers to
purchase electricity from other energy producers, will be one of those
challenges. The FirstEnergy Rate Reduction and Economic Development
Plan provides the foundation to position us to meet the challenges we
are facing by significantly reducing fixed costs and lowering rates to
a more competitive level. The plan was approved by the PUCO in January
1997, and initially maintains current base electric rates through
December 31, 2005. The plan also revised our fuel recovery method.
As part of the regulatory plan, the base rate freeze is to
be followed by a $93 million base rate reduction in 2006; interim
reductions which began in June 1998 of $3 per month will increase to
$5 per month per residential customer by July 1, 2001. Total savings
of $111 million are anticipated over the term of the plan for our
customers. We have committed $35 million for economic development and
energy efficiency programs.
We have been authorized by the PUCO to recognize, for
regulatory accounting purposes, additional depreciation related to our
generating assets and additional amortization of regulatory assets
during the regulatory plan period of at least $647 million more than
the amounts that would have been recognized if the regulatory plans
were not in effect. For regulatory purposes these additional charges
will be reflected over the rate plan period. Our regulatory plan does
not provide for full recovery of nuclear operations. Accordingly,
regulatory assets representing customer receivables for future income
taxes related to nuclear assets of $295 million were written off ($192
million net of income taxes) prior to consummation of the merger since
we ceased application of Statement of Financial Accounting Standards
No. 71 (SFAS 71), "Accounting for the Effects of Certain Types of
Regulation" for our nuclear operations when implementation of the
FirstEnergy regulatory plan became probable.
Based on the current regulatory environment and our
regulatory plan, we believe we will continue to be able to bill and
collect cost-based rates relating to our nonnuclear operations. As a
result, we will continue the application of SFAS 71. However, changes
in the regulatory environment appear to be on the horizon for electric
utilities in Ohio. As further discussed below, the Ohio legislature is
in the discussion stages of restructuring the State's electric utility
industry. Although we believe that regulatory changes are possible in
1999, we cannot currently estimate the ultimate impact.
At the consummation of the merger in November 1997, we
recognized a fair value purchase accounting adjustment, which
decreased the carrying value of our nuclear assets by approximately
$842 million based upon cash flow models. The fair value adjustment to
nuclear plant recognized for financial reporting purposes will
ultimately satisfy the asset reduction commitment contained in our
regulatory plan.
We continue to actively pursue the enactment of fair
legislation calling for deregulation of Ohio's investor-owned electric
utility industry. In early 1998, a deregulation proposal was
introduced, leading to the creation of a working group to recommend
legislation. As requested by legislative leadership, investor-owned
utilities introduced a deregulation plan with objectives to (1) treat
all major stakeholders in Ohio's electric system fairly; (2) protect
public schools and local governments from revenue loss; and (3) allow
utilities an opportunity to recover costs of government-mandated
investments. The utilities have submitted proposals, which incorporate
these objectives and also recognize the complexity of restructuring
the industry. The overlying objective is to do the job right the first
time. Currently, the working group, comprised of legislative leaders,
representatives of the electric utility companies and other interested
stakeholders are meeting to discuss and mold these proposals. Most
recently, placeholder bills containing statements of principle (that
will be replaced by specific proposals as they are agreed upon) have
been introduced. Legislative leaders have placed a high priority on
enacting a deregulation bill by mid-year.
The Clean Air Act Amendments of 1990, discussed in Note 5,
require additional emission reductions by 2000. We are pursuing cost-
effective compliance strategies for meeting these reduction
requirements.
On September 24, 1998, the Federal Environmental Protection
Agency issued a final rule establishing tighter nitrogen oxide
emission requirements for fossil fuel-fired utility boilers in Ohio,
Pennsylvania and twenty other eastern states, including the District
of Columbia (see "Environmental Matters" in Note 5). Controls must be
in place by May 2003, with required reductions achieved during the
five-month summer ozone season (May through September). The new rule
is expected to increase the cost of producing electricity; however, we
believe that we are in a better position than a number of other
utilities to achieve compliance due to our nuclear generation
capacity.
We are aware of our potential involvement in the cleanup of
several sites containing hazardous waste. Although these sites are not
on the Superfund National Priorities List, they are generally being
administered by various governmental entities in the same manner as
they would be administered if they were on such a list. Allegations
that we disposed of hazardous waste at these sites, and the amount
involved are often unsubstantiated and subject to dispute. Federal law
provides that all "potentially responsible parties" for a particular
site be held liable on a joint and several basis. If we were held
liable for 100% of the cleanup costs of all the sites referred to
above, the cost could be as high as $101 million. However, we believe
that the actual cleanup costs will be substantially less than 100% and
that most of the other parties involved are financially able to
contribute their share. We have accrued a $1.1 million liability as of
December 31, 1998, based on estimates of the costs of cleanup and our
proportionate responsibility for such costs. We believe that the
ultimate outcome of these matters will not have a material adverse
effect on our financial condition, cash flows or results of
operations.
In connection with FirstEnergy's regulatory plan to reduce
fixed costs and lower rates, we continue to take steps to restructure
our operations. FirstEnergy announced plans to transfer our
transmission assets into a new subsidiary, American Transmission
Systems, Inc., with the transfer expected to be finalized in 1999.
The new subsidiary represents a first step toward the goal of
establishing or becoming part of a larger independent transmission
company (TransCo). We believe that a TransCo better addresses the
Federal Energy Regulatory Commission's (FERC) stated transmission
objectives of providing non-discriminatory service, while providing
for streamlined and cost-efficient operation. In working toward the
goal of forming a larger regional transmission entity, FirstEnergy,
American Electric Power, Virginia Power and Consumers Energy
announced in November 1998 that they would prepare a FERC filing
during 1999 for such a regional transmission entity. The entity would
be designed to meet the goals of reducing transmission costs that
result when transferring power over several transmission systems,
ensuring transmission reliability and providing non-discriminatory
access to the transmission grid.
Year 2000 Readiness
The Year 2000 issue is the result of computer programs
being written using two digits rather than four to identify the
applicable year. Any of our programs that have date-sensitive
software may recognize a date using "00" as the year 1900 rather than
the year 2000. Because so many of our computer functions are date
sensitive, this could cause far-reaching problems, such as system-
wide computer failures and miscalculations, if no remedial action is
taken.
We have developed a multi-phase program for Year 2000
compliance that consists of an assessment of our systems and
operations that could be affected by the Year 2000 problem;
remediation or replacement of noncompliant systems and components;
and testing of systems and components following such remediation or
replacement. We have focused our Year 2000 review on three areas:
centralized system applications, noncentralized systems and
relationships with third parties (including suppliers as well as end-
use customers). Our review of system readiness extends to systems
involving customer service, safety, shareholder needs and regulatory
obligations.
We are committed to taking appropriate actions to
eliminate or lessen negative effects of the Year 2000 issue on our
operations. We have completed an inventory of all computer systems
and hardware including equipment with embedded computer chips and
have determined which systems need to be converted or replaced to
become Year 2000-ready and are in the process of remediating them.
Based on our timetable, we expect to have all identified repairs,
replacements and upgrades completed to achieve Year 2000 readiness by
September 1999.
Most of our Year 2000 issues will be resolved through
system replacement. Of our major centralized systems, the general
ledger system and inventory management, procurement and accounts
payable systems were replaced at the end of 1998. Our payroll system
was enhanced to be Year 2000 compliant in July 1998. The customer
service system is due to be replaced in mid-1999.
We have completed formal communications with most of our key
suppliers to determine the extent to which we are vulnerable to those
third parties' failure to resolve their own Year 2000 problems. For
suppliers having potential compliance problems, we are developing
alternate sources and services in the event such noncompliance occurs.
We are also identifying areas requiring higher inventory levels based
on compliance uncertainties. There can be no guarantee that the
failure of companies to resolve their own Year 2000 issue will not
have a material adverse effect on our business, financial condition
and results of operations.
We are using both internal and external resources to
reprogram and/or replace and test our software for Year 2000
modifications. Of the $17 million total project cost, approximately
$14 million will be capitalized since those costs are attributable to
the purchase of new software for total system replacements because
the Year 2000 solution comprises only a portion of the benefits
resulting from the system replacements. The remaining $3 million will
be expensed as incurred. As of December 31, 1998, we have spent $11
million for Year 2000 capital projects and had expensed approximately
$2 million for Year 2000-related maintenance activities. Our total
Year 2000 project cost, as well as our estimates of the time needed
to complete remedial efforts, are based on currently available
information and do not include the estimated costs and time
associated with the impact of third party Year 2000 issues.
We believe we are managing the Year 2000 issue in such a
way that our customers will not experience any interruption of
service. We believe the most likely worst-case scenario from the Year
2000 issue will be disruption in power plant monitoring systems,
thereby producing inaccurate data and potential failures in
electronic switching mechanisms at transmission junctions. This would
prolong localized outages, as technicians would have to manually
activate switches. Such an event could have a material, but currently
undeterminable, effect on our financial results. We are developing
contingency plans to address the effects of any delay in becoming
Year 2000 compliant and expect to have contingency plans completed by
June 1999.
The costs of the project and the dates on which we plan to
complete the Year 2000 modifications are based on management's best
estimates, which were derived from numerous assumptions of future
events including the continued availability of certain resources, and
other factors. However, there can be no guarantee that this project
will be completed as planned and actual results could differ
materially from the estimates. Specific factors that might cause
material differences include but are not limited to, the availability
and cost of trained personnel, the ability to locate and correct all
relevant computer code, and similar uncertainties.
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Year For the Year
Ended Ended
December 31, Nov. 8 - Jan. 1 - December 31,
1998 Dec. 31, 1997 Nov. 7, 1997 1996
- ---------------------------------------------------------------------------------------------------------------------------
(In thousands)
|
OPERATING REVENUES (1) $957,037 $122,669 | $ 772,707 $897,259
|
OPERATING EXPENSES AND TAXES: |
Fuel and purchased power 202,239 22,926 | 158,027 177,517
Nuclear operating costs 160,080 29,372 | 138,559 168,458
Other operating costs 166,935 20,608 | 145,174 157,785
-------- -------- | --------- --------
Total operation and maintenance expenses 529,254 72,906 | 441,760 503,760
Provision for depreciation and amortization 94,703 13,133 | 98,986 115,083
General taxes 86,661 13,126 | 77,426 89,647
Income taxes 66,158 4,449 | 31,253 31,954
-------- -------- | --------- --------
Total operating expenses and taxes 776,776 103,614 | 649,425 740,444
-------- -------- | --------- --------
OPERATING INCOME 180,261 19,055 | 123,282 156,815
|
OTHER INCOME (EXPENSE) 12,225 2,153 | 2,153 (4,585)
-------- -------- | --------- --------
INCOME BEFORE NET INTEREST CHARGES 192,486 21,208 | 125,435 152,230
-------- -------- | --------- --------
NET INTEREST CHARGES: |
Interest on long-term debt 88,364 13,689 | 74,264 85,535
Allowance for borrowed funds used during |
construction (1,273) (138) | (259) (827)
Other interest expense (1,187) 41 | 9,661 10,233
-------- -------- | -------- --------
Net interest charges 85,904 13,592 | 83,666 94,941
-------- -------- | -------- --------
INCOME BEFORE EXTRAORDINARY ITEM 106,582 7,616 | 41,769 57,289
|
EXTRAORDINARY ITEM (NET OF INCOME |
TAXES) (Note 1) -- -- | (191,901) --
-------- -------- | --------- --------
NET INCOME (LOSS) 106,582 7,616 | (150,132) 57,289
|
PREFERRED STOCK DIVIDEND |
REQUIREMENTS 13,610 -- | 19,435 16,926
-------- -------- | --------- --------
EARNINGS (LOSS) ON COMMON STOCK $ 92,972 $ 7,616 | $(169,567) $ 40,363
======== ======== | ========= ========
<FN>
(1) Includes electric sales to associated companies of $123.6 million, $17.7 million,
$98.5 million and $105.0 million in 1998, the November 8-December 31, 1997 period,
the January 1-November 7, 1997 period and 1996, respectively.
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
At December 31, 1998 1997
- ------------------------------------------------------------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service $1,757,364 $1,763,495
Less--Accumulated provision for depreciation 626,942 619,222
---------- ----------
1,130,422 1,144,273
---------- ----------
Construction work in progress--
Electric plant 26,603 19,901
Nuclear fuel 11,191 6,632
---------- ----------
37,794 26,533
---------- ----------
1,168,216 1,170,806
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Shippingport Capital Trust (Note 2) 310,762 312,873
Nuclear plant decommissioning trusts 102,749 85,956
Other 3,656 3,164
---------- ----------
417,167 401,993
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents 4,140 22,170
Receivables--
Customers 36,710 19,071
Associated companies 30,006 15,199
Other 2,316 2,593
Notes receivable from associated companies 101,236 40,802
Materials and supplies, at average cost--
Owned 25,745 31,892
Under consignment 18,148 9,538
Prepayments and other 25,647 26,437
---------- ----------
243,948 167,702
---------- ----------
DEFERRED CHARGES:
Regulatory assets 417,704 442,724
Goodwill 474,593 514,462
Property taxes 42,842 45,338
Other 4,295 15,127
---------- ----------
939,434 1,017,651
---------- ----------
$2,768,765 $2,758,152
========== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements
of Capitalization):
Common stockholder's equity $ 575,692 $ 531,650
Preferred stock--
Not subject to mandatory redemption 210,000 210,000
Subject to mandatory redemption -- 1,690
Long-term debt 1,083,666 1,210,190
---------- ----------
1,869,358 1,953,530
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred
stock 130,426 69,979
Accounts payable--
Associated companies 34,260 21,173
Other 61,587 60,756
Accrued taxes 62,288 34,441
Accrued interest 24,965 26,633
Other 14,862 22,603
---------- ----------
328,388 235,585
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes 151,321 104,543
Accumulated deferred investment tax credits 40,670 43,265
Pensions and other postretirement benefits 122,314 113,254
Other 256,714 307,975
---------- ----------
571,019 569,037
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES
(Notes 2 and 5) ---------- ---------
$2,768,765 $2,758,152
========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral
part of these balance sheets.
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 1998 1997
- --------------------------------------------------------------------------------------------------------------------------------
(Dollars in thousands, except per share amounts)
COMMON STOCKHOLDER'S EQUITY:
Common stock, $5 par value, authorized 60,000,000 shares-
39,133,887 shares outstanding $ 195,670 $ 195,670
Premium on capital stock 328,559 328,364
Retained earnings (Note 3A) 51,463 7,616
---------- ----------
Total common stockholder's equity 575,692 531,650
---------- ----------
Number of Shares Optional
Outstanding Redemption Price
------------------ ----------------------
1998 1997 Per Share Aggregate
---- ---- --------- ---------
PREFERRED STOCK (Note 3C):
Cumulative, $100 par value-
Authorized 3,000,000 shares
Not Subject to Mandatory Redemption:
$ 4.25 160,000 160,000 $104.63 $ 16,740 16,000 16,000
$ 4.56 50,000 50,000 101.00 5,050 5,000 5,000
$ 4.25 100,000 100,000 102.00 10,200 10,000 10,000
$ 8.32 100,000 100,000 102.46 10,246 10,000 10,000
$ 7.76 150,000 150,000 102.44 15,366 15,000 15,000
$ 7.80 150,000 150,000 101.65 15,248 15,000 15,000
$10.00 190,000 190,000 101.00 19,190 19,000 19,000
--------- --------- --------- ---------- ----------
900,000 900,000 92,040 90,000 90,000
--------- --------- --------- ---------- ----------
Cumulative, $25 par value-
Authorized 12,000,000 shares
Not Subject to Mandatory Redemption:
$ 2.21 1,000,000 1,000,000 25.25 25,250 25,000 25,000
$ 2.365 1,400,000 1,400,000 27.75 38,850 35,000 35,000
Adjustable Series A 1,200,000 1,200,000 25.00 30,000 30,000 30,000
Adjustable Series B 1,200,000 1,200,000 25.00 30,000 30,000 30,000
--------- --------- -------- ---------- ----------
4,800,000 4,800,000 124,100 120,000 120,000
--------- --------- -------- ---------- ----------
Total not subject to mandatory
redemption 5,700,000 5,700,000 $216,140 210,000 210,000
========= ========= ======== ---------- ----------
Cumulative, $100 par value-
Subject to Mandatory Redemption
(Note 3D):
$9.375. 16,900 33,550 100.00 $ 1,690 1,690 3,355
Redemption within one year (1,690) (1,665)
--------- --------- -------- ---------- ----------
Total subject to mandatory
redemption 16,900 33,550 $ 1,690 -- 1,690
========= ========= ======== ---------- ----------
LONG-TERM DEBT (Note 3E):
First mortgage bonds:
7.250% due 1999 85,000 85,000
7.500% due 2002 -- 26,000
8.000% due 2003 35,325 35,725
7.875% due 2004 145,000 145,000
---------- ----------
Total first mortgage bonds 265,325 291,725
---------- ----------
Unsecured notes and debentures:
5.750% due 1999-2003 3,600 3,900
10.000% due 2000-2010 1,000 1,000
8.700% due 2002 135,000 135,000
---------- ----------
Total unsecured notes and debentures 139,600 139,900
---------- ----------
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont.)
At December 31, 1998 1997
- -------------------------------------------------------------------------------------------------------------------------------
(In thousands)
LONG-TERM DEBT (Cont.):
Secured notes:
7.940% due 1998 -- 5,000
8.000% due 1998 -- 7,000
9.300% due 1998 -- 26,000
10.000% due 1998 -- 650
7.720% due 1999 15,000 15,000
8.470% due 1999 3,500 3,500
7.190% due 2000 45,000 45,000
7.380% due 2000 14,000 14,000
7.460% due 2000 16,500 16,500
7.500% due 2000 100 100
8.500% due 2001 8,000 8,000
9.500% due 2001 21,000 21,000
8.180% due 2002 17,000 17,000
8.620% due 2002 7,000 7,000
8.650% due 2002 5,000 5,000
7.760% due 2003 5,000 5,000
7.780% due 2003 1,000 1,000
7.820% due 2003 38,400 38,400
7.850% due 2003 15,000 15,000
7.910% due 2003 3,000 3,000
7.670% due 2004 70,000 70,000
7.130% due 2007 30,000 30,000
3.050% due 2011* 31,250 31,250
8.000% due 2019 67,300 67,300
7.625% due 2020 45,000 45,000
7.750% due 2020 54,000 54,000
9.220% due 2021 15,000 15,000
10.000% due 2021 15,000 15,000
7.400% due 2022 30,900 30,900
6.875% due 2023 20,200 20,200
7.550% due 2023 37,300 37,300
8.000% due 2023 49,300 49,300
6.100% due 2027 10,100 10,100
5.375% due 2028 3,751 --
---------- ----------
Total secured notes 693,601 728,500
---------- ----------
Capital lease obligations (Note 2) 67,453 64,843
---------- ----------
Net unamortized premium on debt 46,423 53,536
---------- ----------
Long-term debt due within one year (128,736) (68,314)
---------- ----------
Total long-term debt 1,083,666 1,210,190
---------- ----------
TOTAL CAPITALIZATION $1,869,358 $1,953,530
========== ==========
<FN>
*Denotes variable rate issue with December 31, 1998 interest rate shown.
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
Comprehensive Premium Other Retained
Income (Loss) Number Par on Capital Paid-In Earnings
(Note 3B) of Shares Value Stock Capital (Deficit)
------------ --------- ------- ---------- -------- ---------
(Dollars in thousands)
Balance, January 1, 1996 39,133,887 $195,687 $ 481,057 $ 121,059 $ (34,926)
Net income $ 57,289 57,289
=========
Unrealized loss on securities (3)
Cash dividends on preferred stock (16,926)
- ---------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1996 39,133,887 195,687 481,057 121,056 5,437
Net (loss) $(150,132) (150,132)
=========
Cash dividends on preferred stock (20,973)
- ---------------------------------------------------------------------------------------------------------------------------
Purchase accounting fair value adjustment (17) (152,693) (121,056) 165,668
Net income $ 7,616 7,616
=========
- ----------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1997 39,133,887 195,670 328,364 -- 7,616
Purchase accounting fair value adjustment 195
Net income $ 106,582 106,582
=========
Cash dividends on preferred stock (12,252)
Cash dividends on common stock (50,483)
- ----------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1998 39,133,887 $195,670 $ 328,559 $ -- $ 51,463
=============================================================================================================================
CONSOLIDATED STATEMENTS OF PREFERRED STOCK
Not Subject to Subject to
Mandatory Redemption Mandatory Redemption
-------------------- --------------------
Number Par Number Par
of Shares Value of Shares Value
--------- --------- ----------- -------
(Dollars in thousands)
Balance, January 1, 1996 5,700,000 $210,000 66,850 $ 6,685
Redemptions-
$100 par $9.375 (16,650) (1,665)
---------------------------------------------------------------------------------------------
Balance, December 31, 1996 5,700,000 210,000 50,200 5,020
Redemptions-
$100 par $9.375 (16,650) (1,665)
---------------------------------------------------------------------------------------------
Balance, December 31, 1997 5,700,000 210,000 33,550 3,355
Redemptions-
$100 par $9.375 (16,650) (1,665)
---------------------------------------------------------------------------------------------
Balance, December 31, 1998 5,700,000 $210,000 16,900 $ 1,690
=============================================================================================
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Year For the Year
Ended Ended
December 31, Nov. 8 - Jan. 1 - December 31,
1998 Dec. 31, 1997 Nov. 7, 1997 1996
- -----------------------------------------------------------------------------------------------------------------------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES: |
Net Income (Loss) $ 106,582 $ 7,616 | $(150,132) $ 57,289
Adjustments to reconcile net income to net |
cash from operating activities: |
Provision for depreciation and amortization 94,703 13,133 | 98,986 115,083
Nuclear fuel and lease amortization 24,071 5,316 | 30,354 33,294
Deferred income taxes, net 50,570 3,113 | (121,002) 17,919
Investment tax credits, net (2,595) (400) | (3,601) (4,321)
Allowance for equity funds used during construction -- (61) | (776) (1,045)
Extraordinary item -- -- | 295,233 --
Receivables (32,169) 1,923 | 317 (9,610)
Net proceeds from accounts receivable securitization -- -- | -- 78,461
Materials and supplies (2,463) (4,430) | 6,543 5,697
Accounts payable 31,871 (12,989) | 18,679 (9,737)
Other (8,140) (29,443) | 55,233 (1,509)
--------- -------- | --------- ---------
Net cash provided from (used for) operating |
activities 262,430 (16,222) | 229,834 281,521
--------- -------- | --------- ---------
|
CASH FLOWS FROM FINANCING ACTIVITIES: |
New Financing-- |
Long-term debt 3,629 -- | 149,804 (260)
Redemptions and Repayments-- |
Preferred stock 1,665 -- | 1,665 1,665
Long-term debt 90,929 -- | 85,419 110,108
Short-term borrowings, net -- -- | -- 20,950
Dividend Payments-- |
Common stock 50,483 -- | -- --
Preferred stock 16,378 4,156 | 12,589 16,926
--------- -------- | --------- ---------
Net cash provided from (used for) financing |
activities (155,826) (4,156) | 50,131 (149,909)
--------- -------- | --------- ---------
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
Property additions 45,870 6,568 | 36,680 47,961
Loans to associated companies 60,434 -- | -- 81,817
Loan payments from associated companies -- (15,297) | (25,718) --
Capital trust investments (2,111) (7,314) | 320,187 --
Other 20,441 (6,585) | 10,350 14,049
--------- -------- | --------- ---------
Net cash used for (provided from) investing |
activities 124,634 (22,628) | 341,499 143,827
--------- -------- | --------- ---------
Net increase (decrease) in cash and cash equivalents (18,030) 2,250 | (61,534) (12,215)
Cash and cash equivalents at beginning of period 22,170 19,920 | 81,454 93,669
--------- -------- | --------- ---------
Cash and cash equivalents at end of period $ 4,140 $ 22,170 | $ 19,920 $ 81,454
========= ======== | ========= =========
|
SUPPLEMENTAL CASH FLOWS INFORMATION: |
Cash Paid During the Period-- |
Interest (net of amounts capitalized) $ 94,000 $ 16,000 | $ 73,000 $ 92,000
========= ======== | ========= =========
Income taxes $ 6,935 $ 28,000 | $ 25,300 $ 15,950
========= ======== | ========= =========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF TAXES
For the Year For the Year
Ended Ended
December 31, Nov. 8 - Jan. 1 - December 31,
1998 Dec. 31, 1997 Nov. 7, 1997 1996
- --------------------------------------------------------------------------------------------------------
(In thousands)
GENERAL TAXES: |
Real and personal property $ 44,993 $ 5,998 | $ 40,495 $ 45,446
State gross receipts 35,114 5,826 | 28,590 33,793
Social security and unemployment 5,065 818 | 4,444 5,689
Other 1,489 484 | 3,897 4,719
-------- --------- | --------- --------
Total general taxes $ 86,661 $ 13,126 | $ 77,426 $ 89,647
======== ========= | ========= ========
PROVISION FOR INCOME TAXES: |
Currently payable-- |
Federal $ 22,767 $ 2,859 | $ 55,192 $ 13,582
State * 1,954 209 | -- --
-------- --------- | --------- --------
24,721 3,068 | 55,192 13,582
-------- --------- | --------- --------
Deferred, net-- |
Federal 50,337 3,096 | (121,002) 17,919
State * 233 17 | -- --
-------- --------- | --------- --------
50,570 3,113 | (121,002) 17,919
-------- --------- | --------- --------
Investment tax credit amortization (2,595) (400) | (3,601) (4,321)
-------- --------- | --------- --------
Total provision for income taxes $ 72,696 $ 5,781 | $ (69,411) $ 27,180
======== ========= | ========= ========
INCOME STATEMENT CLASSIFICATION |
OF PROVISION FOR INCOME TAXES: |
Operating income $ 66,158 $ 4,449 | $ 31,253 $ 31,954
Other income 6,538 1,332 | 2,667 (4,774)
Extraordinary item -- -- | (103,331) --
-------- --------- | --------- --------
Total provision for income taxes $ 72,696 $ 5,781 | $ (69,411) $ 27,180
======== ========= | ========= ========
RECONCILIATION OF FEDERAL INCOME TAX |
EXPENSE AT STATUTORY RATE TO TOTAL |
PROVISION FOR INCOME TAXES: |
Book income before provision for income taxes $179,278 $ 13,397 | $(219,543) $ 84,469
======== ========= | ========= ========
Federal income tax expense at statutory rate $ 62,747 $ 4,689 | $ (76,840) $ 29,564
Increases (reductions) in taxes resulting |
from-- |
Amortization of investment tax credits (2,595) (400) | (3,601) (4,321)
Depreciation -- -- | 3,428 (3,742)
Amortization of tax regulatory assets 5,728 955 | -- --
Amortization of goodwill 4,421 670 | -- --
Other, net 2,395 (133) | 7,602 5,679
-------- --------- | --------- --------
Total provision for income taxes $ 72,696 $ 5,781 | $ (69,411) $ 27,180
======== ========= | ========= ========
ACCUMULATED DEFERRED INCOME TAXES |
AT DECEMBER 31: |
Property basis differences $195,948 $ 190,636 | $612,000
Deferred nuclear expense 79,355 83,052 | 84,000
Deferred sale and leaseback costs (20,623) (17,431) | --
Unamortized investment tax credits (19,515) (20,960) | (44,000)
Unused alternative minimum tax credits (66,322) (108,156) | (99,837)
Other (17,522) (22,598) | 13,437
-------- --------- | --------
Net deferred income tax liability $151,321 $ 104,543 | $565,600
======== ========= | ========
<FN>
* For periods prior to November 8, 1997, state income taxes are included
in the General Taxes section above. These amounts are not material and
no restatement was made.
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
The consolidated financial statements include The Toledo
Edison Company (Company) and its 90% owned subsidiary, The Toledo Edison
Capital Corporation (TECC). The subsidiary was formed in 1997 to make
equity investments in a business trust in connection with the financing
transactions related to the Bruce Mansfield Plant sale and leaseback
(see Note 2). The Cleveland Electric Illuminating Company (CEI), an
affiliate, has a 10% interest in TECC. All significant intercompany
transactions have been eliminated. The Company is a wholly owned
subsidiary of FirstEnergy Corp. (FirstEnergy). Prior to the merger in
November 1997 (see Note 7), the Company and CEI were the principal
operating subsidiaries of Centerior Energy Corporation (Centerior). The
merger was accounted for using the purchase method of accounting in
accordance with generally accepted accounting principles, and the
applicable effects were reflected on the separate financial statements
of Centerior's direct subsidiaries as of the merger date. Accordingly,
the post-merger financial statements reflect a new basis of accounting
and pre-merger period and post-merger period financial results
(separated by a heavy black line) are presented. The Company follows the
accounting policies and practices prescribed by the Public Utilities
Commission of Ohio (PUCO) and the Federal Energy Regulatory Commission
(FERC). The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make
periodic estimates and assumptions that affect the reported amounts of
assets, liabilities, revenues and expenses. Certain prior year amounts
have been reclassified to conform with the current year presentation.
REVENUES-
The Company's principal business is providing electric service
to customers in northwestern Ohio. The Company's retail customers are
metered on a cycle basis. Revenue is recognized for unbilled electric
service through the end of the year.
Receivables from customers include sales to residential,
commercial and industrial customers located in the Company's service
area and sales to wholesale customers. There was no material
concentration of receivables at December 31, 1998 or 1997, with respect
to any particular segment of the Company's customers.
In May 1996, the Company and CEI began to sell on a daily
basis substantially all of their retail customer accounts receivable to
Centerior Funding Corporation (Centerior Funding), a wholly owned
subsidiary of CEI, under an asset-backed securitization agreement which
expires in 2001. In July 1996, Centerior Funding completed a public sale
of $150 million of receivables-backed investor certificates in a
transaction that qualified for sale accounting treatment.
REGULATORY PLAN-
FirstEnergy's Rate Reduction and Economic Development Plan for
the Company was approved in January 1997, to be effective upon
consummation of the merger. The regulatory plan initially maintains
current base electric rates for the Company through December 31, 2005.
At the end of the regulatory plan period, the Company's base rates will
be reduced by $93 million (approximately 15 percent below current
levels). The regulatory plan also revised the Company's fuel cost
recovery method. The Company formerly recovered fuel-related costs not
otherwise included in base rates from retail customers through a
separate energy rate. In accordance with the regulatory plan, the
Company's fuel rate will be frozen through the regulatory plan period,
subject to limited periodic adjustments. As part of the regulatory plan,
transition rate credits were implemented for customers, which are
expected to reduce operating revenues for the Company by approximately
$111 million during the regulatory plan period.
All of the Company's regulatory assets related to its
nonnuclear operations are being recovered under provisions of the
regulatory plan (see "Regulatory Assets"). The Company recognized a fair
value purchase accounting adjustment to reduce nuclear plant by
$842 million in connection with the FirstEnergy merger (see Note 7);
that fair value adjustment recognized for financial reporting purposes
will ultimately satisfy the $647 million asset reduction commitment
contained in the regulatory plan. For regulatory purposes, the Company
will recognize the $647 million of accelerated amortization over the
regulatory plan period.
Application of Statement of Financial Accounting Standards
(SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation" (SFAS 71), was discontinued in 1997 with respect to the
Company's nuclear operations. The Company's net assets included in
utility plant relating to the operations for which the application of
SFAS 71 was discontinued were $579 million as of December 31, 1998.
UTILITY PLANT AND DEPRECIATION-
Utility plant reflects the original cost of construction
(except for the Company's nuclear generating units which were adjusted
to fair value in 1997), including payroll and related costs such as
taxes, employee benefits, administrative and general costs, and interest
costs.
The Company provides for depreciation on a straight-line basis
at various rates over the estimated lives of property included in plant
in service. The annualized composite rate was approximately 3.4%
(reflecting the nuclear asset fair value adjustment discussed above) and
2.6% in 1998 and the post-merger period in 1997, respectively. In its
April 1996 rate order, the PUCO approved depreciation rates for the
Company of 2.95% for nuclear property and 3.13% for nonnuclear property.
Annual depreciation expense includes approximately
$9.8 million for future decommissioning costs applicable to the
Company's ownership interests in three nuclear generating units. The
Company's share of the future obligation to decommission these units is
approximately $348 million in current dollars and (using a 4.0%
escalation rate) approximately $896 million in future dollars. The
estimated obligation and the escalation rate were developed based on
site specific studies. Payments for decommissioning are expected to
begin in 2016, when actual decommissioning work begins. The Company has
recovered approximately $91 million for decommissioning through its
electric rates from customers through December 31, 1998. If the actual
costs of decommissioning the units exceed the funds accumulated from
investing amounts recovered from customers, the Company expects that
additional amount to be recoverable from its customers. The Company has
approximately $102.7 million invested in external decommissioning trust
funds as of December 31, 1998. Earnings on these funds are reinvested
with a corresponding increase to the decommissioning liability. The
Company has also recognized an estimated liability of approximately $8.7
million at December 31, 1998 related to decontamination and
decommissioning of nuclear enrichment facilities operated by the United
States Department of Energy (DOE), as required by the Energy Policy Act
of 1992.
The Financial Accounting Standards Board (FASB) issued a
proposed accounting standard for nuclear decommissioning costs in 1996.
If the standard is adopted as proposed: (1) annual provisions for
decommissioning could increase; (2) the net present value of estimated
decommissioning costs could be recorded as a liability; and (3) income
from the external decommissioning trusts could be reported as investment
income. The FASB subsequently expanded the scope of the proposed
standard to include other closure and removal obligations related to
long-lived assets. A revised proposal may be issued by the FASB in 1999.
COMMON OWNERSHIP OF GENERATING FACILITIES-
The Company, CEI, Duquesne Light Company, Ohio Edison Company
(OE) and its wholly owned subsidiary, Pennsylvania Power Company (Penn),
constitute the Central Area Power Coordination Group (CAPCO). The CAPCO
companies own and/or lease, as tenants in common, various power
generating facilities. Each of the companies is obligated to pay a share
of the costs associated with any jointly owned facility in the same
proportion as its interest. The Company's portion of operating expenses
associated with jointly owned facilities is included in the
corresponding operating expenses on the Consolidated Statements of
Income. The amounts reflected on the Consolidated Balance Sheet under
utility plant at December 31, 1998 include the following:
Utility Accumulated Construction Ownership/
Plant Provision for Work in Leasehold
Generating Units in Service Depreciation Progress Interest
- ---------------------------------------------------------------------------
(In millions)
Bruce Mansfield
Units 2 and 3 $ 39.4 $11.1 $ 1.1 18.61%
Beaver Valley Unit 2 57.7 3.3 0.7 19.91%
Davis-Besse 202.5 4.8 6.2 48.62%
Perry 332.7 16.4 4.0 19.91%
- -------------------------------------------------------------------------
Total $632.3 $35.6 $12.0
=========================================================================
The Bruce Mansfield Plant and Beaver Valley Unit 2 are being
leased through sale and leaseback transactions (see Note 2) and the
above-related amounts represent construction expenditures subsequent
to the transaction.
NUCLEAR FUEL-
The Company leases its nuclear fuel and pays for the fuel as
it is consumed (see Note 2). The Company amortizes the cost of nuclear
fuel based on the rate of consumption. The Company's electric rates
include amounts for the future disposal of spent nuclear fuel based
upon the payments to the DOE.
INCOME TAXES-
Details of the total provision for income taxes are shown on
the Consolidated Statements of Taxes. Deferred income taxes result
from timing differences in the recognition of revenues and expenses
for tax and accounting purposes. Investment tax credits, which were
deferred when utilized, are being amortized over the recovery period
of the related property. The liability method is used to account for
deferred income taxes. Deferred income tax liabilities related to tax
and accounting basis differences are recognized at the statutory
income tax rates in effect when the liabilities are expected to be
paid. Alternative minimum tax credits of $66 million, which may be
carried forward indefinitely, are available to reduce future federal
income taxes. Since the Company became a wholly owned subsidiary of
FirstEnergy on November 8, 1997, the Company is included in
FirstEnergy's consolidated federal income tax return. The consolidated
tax liability is allocated on a "stand-alone" company basis, with the
Company recognizing any tax losses or credits it contributed to the
consolidated return.
RETIREMENT BENEFITS-
Centerior had sponsored jointly with the Company, CEI and
Centerior Service Company (Service Company) a noncontributory pension
plan (Centerior Pension Plan) which covered all employee groups. Upon
retirement, employees receive a monthly pension generally based on the
length of service. In 1998, the Centerior Pension Plan was merged into
the FirstEnergy pension plans. In connection with the OE-Centerior
merger, the Company recorded fair value purchase accounting
adjustments to recognize the net gain, prior service cost, and net
transition asset (obligation) associated with the pension and
postretirement benefit plans. The assets of the pension plans consist
primarily of common stocks, United States government bonds and
corporate bonds.
The Company provides a minimum amount of noncontributory
life insurance to retired employees in addition to optional
contributory insurance. Health care benefits, which include certain
employee deductibles and copayments, are also available to retired
employees, their dependents and, under certain circumstances, their
survivors. The Company pays insurance premiums to cover a portion of
these benefits in excess of set limits; all amounts up to the limits
are paid by the Company. The Company recognizes the expected cost of
providing other postretirement benefits to employees and their
beneficiaries and covered dependents from the time employees are hired
until they become eligible to receive those benefits.
The following sets forth the funded status of the
FirstEnergy plans in 1998 and the former Centerior plans in 1997 and
amounts recognized on the Consolidated Balance Sheets as of December
31:
Other
Pension Benefits Postretirement Benefits
---------------- -----------------------
1998 1997 1998 1997
- -------------------------------------------------------------------------------------------------
(In millions)
Change in benefit obligation:
Benefit obligation as of January 1* $1,327.5 $395.0 $ 534.1 $ 211.9
Service cost 25.0 13.4 7.5 2.3
Interest cost 92.5 31.5 37.6 16.3
Plan amendments 44.3 7.1 40.1 --
Early retirement program expense -- 27.8 -- --
Actuarial loss 101.6 74.8 10.7 51.9
Benefits paid (90.8) (16.2) (28.7) (15.9)
- -----------------------------------------------------------------------------------------------
Benefit obligation as of December 31 1,500.1 533.4 601.3 266.5
- -----------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets as of January 1* 1,542.5 420.8 2.8 --
Actual return on plan assets 231.3 57.3 0.7 --
Company contribution -- -- 0.4 --
Benefits paid (90.8) (16.2) -- --
- -----------------------------------------------------------------------------------------------
Fair value of plan assets as of December 31 1,683.0 461.9 3.9 --
- -----------------------------------------------------------------------------------------------
Funded status of plan* 182.9 (71.5) (597.4) (266.5)
Unrecognized actuarial loss (gain) (110.8) 3.0 30.6 --
Unrecognized prior service cost 63.0 -- 27.4 --
Unrecognized net transition obligation (asset) (18.0) -- 129.3 --
- -----------------------------------------------------------------------------------------------
Prepaid (accrued) benefit cost $ 117.1 $(68.5) $(410.1) $(266.5)
===============================================================================================
Assumptions used as of December 31:
Discount rate 7.00% 7.25% 7.00% 7.25%
Expected long-term return on plan assets 10.25% 10.00% 10.25% 10.00%
Rate of compensation increase 4.00% 4.00% 4.00% 4.00%
<FN>
* 1998 beginning balances represents 1998 merger of Centerior
and OE plans into FirstEnergy plans.
The Consolidated Balance Sheet classification of Pensions
and Other Postretirement Benefits at December 31, 1998 and 1997
includes the Company's share of the net pension liability of $17.3
million and $18.1 million, respectively; and the Company's share of
the accrued postretirement benefit liability of $105.0 million and
$95.2 million, respectively.
Net pension and other postretirement benefit costs for the
three years ended December 31, 1998 (FirstEnergy plans in 1998 and
Centerior plans in 1997 and 1996) were computed as follows:
Pension Benefits Other Postretirement Benefits
----------------------------- ------------------------------
1997 1997
---------------- ----------------
Nov. 8- | Jan. 1- Nov. 8-| Jan. 1-
1998 Dec. 31 | Nov. 7 1996 1998 Dec. 31| Nov. 7 1996
- ------------------------------------------------|---------------------------------|-------------
| (In millions) |
| |
Service cost $ 25.0 $ 2.3 | $ 11.1 $ 12.6 $ 7.5 $0.5 | $ 1.8 $ 2.1
Interest cost 92.5 6.1 | 25.4 27.9 37.6 2.8 | 13.5 17.8
Expected return on plan assets (152.7) (7.7) | (38.0) (43.0) (0.3) -- | -- --
Amortization of transition | |
obligation (asset) (8.0) -- | (3.0) (3.5) 9.2 -- | 6.4 7.5
Amortization of prior service | |
cost 2.3 -- | 1.1 1.3 (0.8) -- | -- --
Recognized net actuarial loss | |
(gain) (2.6) -- | (0.5) (2.7) -- -- | (0.9) --
Voluntary early retirement | |
program expense -- 23.0 | 4.8 -- -- -- | -- --
- ------------------------------------------------|---------------------------------|-------------
Net benefit cost $ (43.5) $23.7 | $ 0.9 $ (7.4) $53.2 $3.3 | $20.8 $27.4
================================================|=================================|=============
Company's share of total plan | |
costs $ (1.1) $ 5.7 | $ 3.5 $ (2.4) $ 7.5 $1.5 | $ 8.9 $ 9.0
- ------------------------------------------------------------------------------------------------
The FirstEnergy plans' health care trend rate assumption is
5.5% in the first year gradually decreasing to 4.0% for the year 2008
and later. Assumed health care cost trend rates have a significant
effect on the amounts reported for the health care plan. An increase
in the health care trend rate assumption by one percentage point would
increase the total service and interest cost components by $4.0
million and the postretirement benefit obligation by $68.1 million. A
decrease in the same assumption by one percentage point would decrease
the total service and interest cost components by $3.2 million and the
postretirement benefit obligation by $55.2 million.
TRANSACTIONS WITH AFFILIATED COMPANIES-
Operating revenues, operating expenses and interest charges
include amounts for transactions with affiliated companies in the
ordinary course of business operations.
The Company's transactions with CEI and the other
FirstEnergy operating subsidiaries (OE and Penn) from the November 8,
1997 merger date are primarily for firm power, interchange power,
transmission line rentals and jointly owned power plant operations and
construction (see Note 7). Beginning in May 1996, Centerior Funding
began serving as the transferor in connection with the accounts
receivable securitization for the Company and CEI.
The Service Company (formerly a wholly owned subsidiary of
Centerior and now a wholly owned subsidiary of FirstEnergy) provided
support services at cost to the Company and other affiliated
companies. The Service Company billed the Company $39.0 million,
$13.9 million, $51.5 million and $59.8 million in 1998, the
November 8-December 31, 1997 period, the January 1-November 7, 1997
period and 1996, respectively, for such services.
SUPPLEMENTAL CASH FLOWS INFORMATION-
All temporary cash investments purchased with an initial
maturity of three months or less are reported as cash equivalents on
the Consolidated Balance Sheets. The Company reflects temporary cash
investments at cost, which approximates their fair market value.
Noncash financing and investing activities included capital lease
transactions amounting to $28 million, $2 million, $12 million and
$32 million in 1998, the November 8-December 31, 1997 period, the
January 1-November 7, 1997 period and 1996, respectively.
All borrowings with initial maturities of less than one year
are defined as financial instruments under generally accepted
accounting principles and are reported on the Consolidated Balance
Sheets at cost, which approximates their fair market value. The
following sets forth the approximate fair value and related carrying
amounts of all other long-term debt, preferred stock subject to
mandatory redemption and investments other than cash and cash
equivalents as of December 31:
1998 1997
- --------------------------------------------------------------------
Carrying Fair Carrying Fair
Value Value Value Value
- -------------------------------------------------------------------
(In millions)
Long-term debt $1,098 $1,174 $1,160 $1,218
Preferred stock $ 2 $ 2 $ 3 $ 3
Investments other than cash
and cash equivalents:
Debt securities
-(Maturing in more than 10 years) $ 308 $ 301 $ 295 $ 303
Equity securities 3 3 3 3
All other 103 105 86 85
- -------------------------------------------------------------------
$ 414 $ 409 $ 384 $ 391
====================================================================
The carrying value of long-term debt was adjusted to fair
value in connection with the OE-Centerior merger and reflects the
present value of the cash outflows relating to those securities based
on the current call price, the yield to maturity or the yield to call,
as deemed appropriate at the end of each respective year. The yields
assumed were based on securities with similar characteristics offered
by a corporation with credit ratings similar to the Company's ratings.
The fair value of investments other than cash and cash
equivalents represent cost (which approximates fair value) or the
present value of the cash inflows based on the yield to maturity. The
yields assumed were based on financial instruments with similar
characteristics and terms. Investments other than cash and cash
equivalents include decommissioning trusts investments. Unrealized
gains and losses applicable to the decommissioning trusts have been
recognized in the trust investments with a corresponding change to the
decommissioning liability. The other debt and equity securities
referred to above are in the held-to-maturity category. The Company
has no securities held for trading purposes.
REGULATORY ASSETS-
The Company recognizes, as regulatory assets, costs which
the FERC and PUCO have authorized for recovery from customers in
future periods. Without such authorization, the costs would have been
charged to income as incurred. All regulatory assets related to
nonnuclear operations are being recovered from customers under the
Company's regulatory plan. Based on the regulatory plan, at this time,
the Company believes it will continue to be able to bill and collect
cost-based rates (with the exception of the Company's nuclear
operations as discussed below); accordingly, it is appropriate that
the Company continues the application of SFAS 71 in the foreseeable
future for its nonnuclear operations.
The Company discontinued the application of SFAS 71 for its
nuclear operations in October 1997 when implementation of the
regulatory plan became probable. The regulatory plan does not provide
for full recovery of the Company's nuclear operations. In accordance
with SFAS No. 101, "Regulated Enterprises -- Accounting for the
Discontinuation of Application of SFAS 71," the Company was required
to remove from its balance sheet all regulatory assets and liabilities
related to the portion of its business for which SFAS 71 was
discontinued and to assess all other assets for impairment. Regulatory
assets attributable to nuclear operations of $295.2 million
($191.9 million after taxes) were written off as an extraordinary item
in October 1997. The regulatory assets attributable to nuclear
operations written off represent the net amounts due from customers
for future federal income taxes when the taxes become payable, which,
under the regulatory plan, are no longer recoverable from customers.
The remainder of the Company's business continues to comply with the
provisions of SFAS 71. All remaining regulatory assets of the Company
will continue to be recovered through rates set for the nonnuclear
portion of its business. For financial reporting purposes, the net
book value of the nuclear generating units was not impaired as a
result of the regulatory plan.
Net regulatory assets on the Consolidated Balance Sheets are
comprised of the following:
1998 1997
- ----------------------------------------------------------
(In millions)
Nuclear unit expenses $200.1 $207.4
Rate stabilization program deferrals 164.1 172.0
Sale and leaseback costs 41.3 40.2
Loss on reacquired debt 20.0 21.1
Other (7.8) 2.0
- ----------------------------------------------------------
Total $417.7 $442.7
==========================================================
2. LEASES:
The Company leases certain generating facilities, nuclear
fuel, certain transmission facilities, office space and other property
and equipment under cancelable and noncancelable leases.
The Company and CEI sold their ownership interests in Bruce
Mansfield Units 1, 2 and 3 and the Company sold a portion of its
ownership interest in Beaver Valley Unit 2. In connection with these
sales, which were completed in 1987, the Company and CEI entered into
operating leases for lease terms of approximately 30 years as co-
lessees. During the terms of the leases, the Company and CEI continue
to be responsible, to the extent of their combined ownership and
leasehold interest, for costs associated with the units including
construction expenditures, operation and maintenance expenses,
insurance, nuclear fuel, property taxes and decommissioning. The
Company and CEI have the right, at the end of the respective basic
lease terms, to renew the leases. The Company and CEI also have the
right to purchase the facilities at the expiration of the basic lease
term or renewal term (if elected) at a price equal to the fair market
value of the facilities.
As co-lessee with CEI, the Company is also obligated for
CEI's lease payments. If CEI is unable to make its payments under the
Bruce Mansfield Plant lease, the Company would be obligated to make
such payments. No such payments have been made on behalf of CEI.
(CEI's future minimum lease payments as of December 31, 1998 were
approximately $1.1 billion.)
The Company is selling 150 megawatts of its Beaver Valley
Unit 2 leased capacity entitlement to CEI. Operating revenues for this
transaction were $98.5 million, $16.8 million, $87.4 million and
$99.4 million in 1998, the November 8-December 31, 1997 period, the
January 1-November 7, 1997 period and 1996, respectively. This sale is
expected to continue through the end of the lease period. The future
minimum lease payments through 2017 associated with Beaver Valley
Unit 2 are approximately $1.1 billion.
Nuclear fuel is currently financed for the Company and CEI
through leases with a special-purpose corporation. As of December 31,
1998, $156 million of nuclear fuel ($67 million for the Company) was
financed under a lease financing arrangement totaling $175 million
($60 million of intermediate-term notes and $115 million from bank
credit arrangements). The notes mature from 1999 through 2000 and the
bank credit arrangements expire in September 2000. Lease rates are
based on intermediate-term note rates, bank rates and commercial paper
rates.
Consistent with the regulatory treatment, the rentals for
capital and operating leases are charged to operating expenses on the
Consolidated Statements of Income. Such costs for the three years
ended December 31, 1998 are summarized as follows:
Nov. 8 - Jan. 1 -
1998 Dec. 31, 1997 Nov. 7, 1997 1996
- ---------------------------------------------------------------------
(In millions)
|
Operating leases |
Interest element $ 59.2 $28.0 | $ 57.4 $ 82.5
Other 44.9 13.5 | 23.1 42.6
Capital leases |
Interest element 4.9 1.0 | 6.0 7.5
Other 25.1 5.3 | 30.4 38.6
- ----------------------------------------------|----------------------
Total rentals $134.1 $47.8 | $116.9 $171.2
=====================================================================
The future minimum lease payments as of December 31, 1998
are:
Operating Leases
----------------------------
Capital Lease Capital
Leases Payments Trust Net
- ------------------------------------------------------------------
(In millions)
1999 $28.7 $ 106.5 $ 36.3 $ 70.2
2000 19.4 104.8 35.4 69.4
2001 12.0 108.0 36.4 71.6
2002 5.8 111.0 37.9 73.1
2003 1.9 111.7 36.0 75.7
Years thereafter 0.4 1,318.4 321.4 997.0
- --------------------------------------------------------------------
Total minimum lease payments 68.2 $1,860.4 $503.4 $1,357.0
======== ====== ========
Interest portion 8.3
- -----------------------------------
Present value of net
minimum lease payments 59.9
Less current portion 24.5
- -----------------------------------
Noncurrent portion $35.4
===================================
The Company and CEI refinanced high-cost fixed obligations
related to their 1987 sale and leaseback transaction for the Bruce
Mansfield Plant through a lower cost transaction in June and July
1997. In a June 1997 offering (Offering), the two companies pledged
$720 million aggregate principal amount ($145 million for the Company
and $575 million for CEI) of first mortgage bonds due in 2000, 2004
and 2007 to a trust as security for the issuance of a like principal
amount of secured notes due in 2000, 2004 and 2007. The obligations of
the two companies under these secured notes are joint and several.
Using available cash, short-term borrowings and the net proceeds from
the Offering, the two companies invested $906.5 million
($337.1 million for the Company and $569.4 million for CEI) in a
business trust, in June 1997. The trust used these funds in July 1997
to purchase lease notes and redeem all $873.2 million aggregate
principal amount of 10-1/4% and 11-1/8% secured lease obligation bonds
(SLOBs) due 2003 and 2016. The SLOBs were issued by a special-purpose
funding corporation in 1988 on behalf of lessors in the two companies'
1987 sale and leaseback transaction. The Shippingport capital trust
arrangement effectively reduce lease costs related to that
transaction.
3. CAPITALIZATION:
(A) RETAINED EARNINGS-
The Company has a provision in its mortgage applicable to
$35.325 million of its 8.00% First Mortgage Bonds due 2003 that
requires common stock dividends to be paid out of its total balance of
retained earnings. The merger purchase accounting adjustments included
resetting the retained earnings balance to zero at the November 8,
1997 merger date.
(B) COMPREHENSIVE INCOME-
In 1998, the Company adopted SFAS 130, "Reporting
Comprehensive Income," and applied the standard to all periods
presented in the Consolidated Statements of Common Stockholder's
Equity. Comprehensive income includes net income as reported on the
Consolidated Statements of Income and all other changes in common
stockholder's equity except dividends to stockholders. Net income and
comprehensive income are the same for each period presented.
(C) PREFERRED AND PREFERENCE STOCK-
Preferred stock may be redeemed by the Company in whole, or
in part, with 30-90 days' notice.
The preferred dividend rates on the Company's Series A and
Series B fluctuate based on prevailing interest rates and market
conditions. The dividend rates for these issues averaged 7.00% and
7.07%, respectively, in 1998.
Preference stock authorized for the Company is 5,000,000
shares with a $25 par value. No preference shares are currently
outstanding.
A liability of $5 million was included in the Company's net
assets as of the merger date for preferred dividends declared
attributable to the post-merger period. Accordingly, no accrual for
preferred stock dividend requirements was included on the Company's
November 8, 1997 to December 31, 1997 Consolidated Statement of
Income. This liability was subsequently reduced to zero in 1998.
(D) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION-
Annual sinking fund requirements for the next five years
consist of $1.7 million in 1999.
(E) LONG-TERM DEBT-
The first mortgage indenture and its supplements, which
secure all of the Company's first mortgage bonds, serve as direct
first mortgage liens on substantially all property and franchises,
other than specifically excepted property, owned by the Company.
Based on the amount of bonds authenticated by the Trustees
through December 31, 1998, TE's annual sinking and improvement fund
requirements for all bonds issued under the mortgage amounts to $0.4
million. TE expects to deposit funds in 1999 that will be withdrawn
upon the surrender for cancellation of a like principal amount of
bonds, which are specifically authenticated for such purposes against
unfunded property additions or against previously retired bonds. This
method can result in minor increases in the amount of the annual
sinking fund requirement.
Sinking fund requirements for first mortgage bonds and
maturing long-term debt (excluding capital leases) for the next five
years are:
(In millions)
- -------------------------------
1999 $104.2
2000 76.3
2001 29.9
2002 165.4
2003 97.7
- -------------------------------
The Company's obligations to repay certain pollution control
revenue bonds are secured by several series of first mortgage bonds.
One pollution control revenue bond issue is entitled to the benefit of
an irrevocable bank letter of credit of $32.1 million. To the extent
that drawings are made under this letter of credit to pay principal
of, or interest on, the pollution control revenue bonds, the Company
is entitled to a credit against its obligation to repay those bonds.
The Company pays an annual fee of 1.875% of the amount of the letter
of credit to the issuing bank and is obligated to reimburse the bank
for any drawings thereunder.
The Company and CEI have letters of credit of approximately
$225 million in connection with the sale and leaseback of Beaver
Valley Unit 2 that expire in June 1999. The letters of credit are
secured by first mortgage bonds of the Company and CEI in the
proportion of 60% and 40%, respectively (see Note 2).
4. SHORT-TERM BORROWINGS:
FirstEnergy has a $100 million revolving credit facility
that expires in May 1999. FirstEnergy may borrow under the facility,
with all borrowings jointly and severally guaranteed by the Company
and CEI. FirstEnergy plans to transfer any of its borrowed funds to
the Company and CEI. The credit agreement is secured with first
mortgage bonds of the Company and CEI in the proportion of 60% and
40%, respectively. The credit agreement also provides the
participating banks with a subordinate mortgage security interest in
the properties of the Company and CEI. The banks' fee is 0.50% per
annum payable quarterly in addition to interest on any borrowings.
There were no borrowings under the facility at December 31, 1998.
Also, the Company may borrow from its affiliates on a short-term
basis.
5. COMMITMENTS, GUARANTEES AND CONTINGENCIES:
CAPITAL EXPENDITURES-
The Company's current forecast reflects expenditures of
approximately $257 million for property additions and improvements
from 1999-2003, of which approximately $58 million is applicable to
1999. Investments for additional nuclear fuel during the 1999-2003
period are estimated to be approximately $102 million, of which
approximately $9 million applies to 1999. During the same periods, the
Company's nuclear fuel investments are expected to be reduced by
approximately $120 million and $26 million, respectively, as the
nuclear fuel is consumed.
NUCLEAR INSURANCE-
The Price-Anderson Act limits the public liability relative
to a single incident at a nuclear power plant to $9.7 billion. The
amount is covered by a combination of private insurance and an
industry retrospective rating plan. Based on its present ownership and
leasehold interests in Beaver Valley Unit 2, the Davis-Besse Plant and
the Perry Plant, the Company's maximum potential assessment under the
industry retrospective rating plan (assuming the other co-owners
contribute their proportionate share of any assessments under the
retrospective rating plan) would be $77.9 million per incident but not
more than $8.8 million in any one year for each incident.
The Company is also insured as to its respective interests
in Beaver Valley Unit 2, the Davis-Besse Plant and the Perry Plant
under policies issued to the operating company for each plant. Under
these policies, up to $2.75 billion is provided for property damage
and decontamination and decommissioning costs. The Company has also
obtained approximately $354 million of insurance coverage for
replacement power costs for its respective interests in Beaver Valley
Unit 2, Davis-Besse and Perry. Under these policies, the Company can
be assessed a maximum of approximately $10.5 million for incidents at
any covered nuclear facility occurring during a policy year which are
in excess of accumulated funds available to the insurer for paying
losses.
The Company intends to maintain insurance against nuclear
risks as described above as long as it is available. To the extent
that replacement power, property damage, decontamination,
decommissioning, repair and replacement costs and other such costs
arising from a nuclear incident at any of the Company's plants exceed
the policy limits of the insurance in effect with respect to that
plant, to the extent a nuclear incident is determined not to be
covered by the Company's insurance policies, or to the extent such
insurance becomes unavailable in the future, the Company would remain
at risk for such costs.
GUARANTEE-
The Company, together with the other CAPCO companies, has
severally guaranteed certain debt and lease obligations in connection
with a coal supply contract for the Bruce Mansfield Plant. As of
December 31, 1998, the Company's share of the guarantee (which
approximates fair market value) was $5.5 million. The price under the
coal supply contract, which includes certain minimum payments, has
been determined to be sufficient to satisfy the debt and lease
obligations. The Company's total payments under the coal supply
contract were $32.9 million, $29.9 million and $31.4 million during
1998, 1997 and 1996, respectively. The Company's minimum payment for
1999 is approximately $9 million. The contract expires December 31,
1999.
ENVIRONMENTAL MATTERS-
Various federal, state and local authorities regulate the
Company with regard to air and water quality and other environmental
matters. The Company has estimated additional capital expenditures for
environmental compliance of approximately $44 million, which is
included in the construction forecast provided under "Capital
Expenditures" for 1999 through 2003.
The Company is in compliance with the current sulfur dioxide
(SO2) and nitrogen oxides (NOx) reduction requirements under the Clean
Air Act Amendments of 1990. SO2 reductions in 1999 will be achieved by
burning lower-sulfur fuel, generating more electricity from lower-
emitting plants, and/or purchasing emission allowances. Plans for
complying with reductions required for the year 2000 and thereafter
have not been finalized. In September 1998, the Environmental
Protection Agency (EPA) finalized regulations requiring additional NOx
reductions from the Company's Ohio and Pennsylvania facilities by May
2003. The EPA's NOx Transport Rule imposes uniform reductions of NOx
emissions across a region of twenty-two states and the District of
Columbia, including Ohio and Pennsylvania, based on a conclusion that
such NOx emissions are contributing significantly to ozone pollution
in the eastern United States. By September 1999, each of the twenty-
two states are required to submit revised State Implementation Plans
(SIP) which comply with individual state NOx budgets established by
the EPA. These state NOx budgets contemplate an 85% reduction in
utility plant NOx emissions from 1990 emissions. A proposed Federal
Implementation Plan accompanied the NOx Transport Rule and may be
implemented by the EPA in states which fail to revise their SIP. In
another separate but related action, eight states filed petitions with
the EPA under Section 126 of the Clean Air Act seeking reductions of
NOx emissions which are alleged to contribute to ozone pollution in
the eight petitioning states. The EPA suggests that the Section 126
petitions will be adequately addressed by the NOx Transport Program,
but a September 1998 proposed rulemaking established an alternative
program which would require nearly identical 85% NOx reductions at the
Company's Ohio and Pennsylvania plants by May 2003 in the event
implementation of the NOx Transport Rule is delayed. FirstEnergy
continues to evaluate its compliance plans and other compliance
options and currently estimates its additional capital expenditures
for NOx reductions may reach $500 million.
The Company is required to meet federally approved SO2
regulations. Violations of such regulations can result in shutdown of
the generating unit involved and/or civil or criminal penalties of up
to $25,000 for each day the 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. The Company cannot
predict what action the EPA may take in the future with respect to the
interim enforcement policy.
In July 1997, the EPA promulgated changes in the National
Ambient Air Quality Standard (NAAQS) for ozone and proposed a new
NAAQS for previously unregulated ultra-fine particulate matter. The
cost of compliance with these regulations may be substantial and
depends on the manner in which they are implemented by the states in
which the Company operates affected facilities.
The Company has been named as a "potentially responsible
party" (PRP) at waste disposal sites which may require cleanup under
the Comprehensive Environmental Response, Compensation and Liability
Act of 1980. Allegations that the Company disposed of hazardous
substances at historical sites and the liability involved, are often
unsubstantiated and subject to dispute. Federal law provides that all
PRPs for a particular site be held liable on a joint and several
basis. The Company has accrued a liability of $1 million as of
December 31, 1998, based on estimates of the costs of cleanup and the
proportionate responsibility of other PRPs for such costs. The Company
believes that waste disposal costs will not have a material adverse
effect on its financial condition, cash flows or results of
operations.
Legislative, administrative and judicial actions will
continue to change the way that the Company must operate in order to
comply with environmental laws and regulations. With respect to any
such changes and to the environmental matters described above, the
Company expects that while it remains regulated, any resulting
additional capital costs which may be required, as well as any
required increase in operating costs, would ultimately be recovered
from its customers.
6. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
The following summarizes certain consolidated operating
results by quarter for 1998 and 1997.
March 31, June 30, September 30, December 31,
Three Months Ended 1998 1998 1998 1998
- -------------------------------------------------------------------------------------------
(In millions)
Operating Revenues $221.1 $239.7 $253.3 $243.0
Operating Expenses and Taxes 169.1 201.9 202.1 203.7
- ----------------------------------------------------------------------------------------
Operating Income 52.0 37.8 51.2 39.3
Other Income 3.8 3.1 2.7 2.6
Net Interest Charges 21.8 21.8 21.2 21.1
- ----------------------------------------------------------------------------------------
Net Income $ 34.0 $ 19.1 $ 32.7 $ 20.8
========================================================================================
Earnings on Common Stock $ 32.6 $ 15.0 $ 28.5 $ 16.9
========================================================================================
Three Months Ended
----------------------------
Mar. 31, June 30, Sept. 30, Oct. 1 - Nov. 8 -
1997 1997 1997 Nov. 7, 1997 Dec. 31, 1997
- --------------------------------------------------------------------------------------------------
(In millions) |
|
Operating Revenues $217.1 $222.1 $241.3 $ 92.2 | $122.7
Operating Expenses and Taxes 184.7 186.1 191.9 86.7 | 103.6
- ----------------------------------------------------------------------------------|----------
Operating Income 32.4 36.0 49.4 5.5 | 19.1
Other Income (Expense) (0.4) 0.4 5.0 (2.9) | 2.1
Net Interest Charges 23.2 23.3 27.2 10.0 | 13.6
- ----------------------------------------------------------------------------------|----------
Income (Loss) Before Extraordinary |
Item 8.8 13.1 27.2 (7.4) | 7.6
Extraordinary Item (Net of Income |
Taxes) (Note 1) -- -- -- (191.9) | --
- ----------------------------------------------------------------------------------|----------
Net Income (Loss) $ 8.8 $ 13.1 $ 27.2 $(199.3) | $ 7.6
==================================================================================|==========
Earnings (Loss) on Common Stock $ 4.6 $ 8.9 $ 23.0 $(206.2) | $ 7.6
=============================================================================================
7. PRO FORMA COMBINED CONDENSED STATEMENTS OF INCOME (UNAUDITED):
FirstEnergy was formed on November 8, 1997 by the merger of
OE and Centerior. The merger was accounted for as a purchase of
Centerior's net assets with 77,637,704 shares of FirstEnergy Common
Stock through the conversion of each outstanding Centerior Common
Stock share into 0.525 of a share of FirstEnergy Common Stock
(fractional shares were paid in cash). Based on an imputed value of
$20.125 per share, the purchase price was approximately
$1.582 billion, which also included approximately $20 million of
merger related costs. Goodwill of approximately $2.0 billion was
recognized (to be amortized on a straight-line basis over forty
years), which represented the excess of the purchase price over
Centerior's net assets after fair value adjustments.
Accumulated amortization of goodwill was approximately
$15 million as of December 31, 1998. The merger purchase accounting
adjustments included recognizing estimated severance and other
compensation liabilities ($24 million). The amount charged against
the liability in 1998 relating to the costs of involuntary employee
separation was $11 million. The liability was subsequently reduced to
zero as of December 31, 1998. The liability adjustment was offset by
a corresponding reduction to goodwill recognized in connection with
the Centerior acquisition.
The following pro forma statements of income for the
Company give effect to the OE-Centerior merger as if it had been
consummated on January 1, 1996, with the purchase accounting
adjustments actually recognized in the business combination.
Year Ended December 31,
-----------------------
1997 1996
- ----------------------------------------------------------
(In millions)
Operating Revenues $895 $897
Operating Expenses and Taxes 742 728
---- ----
Operating Income 153 169
Other Income (Expense) 10 (3)
Net Interest Charges 91 89
---- ----
Net Income $ 72 $ 77
========================================================
Pro forma adjustments reflected above include: (1)
adjusting the Company's nuclear generating units to fair value based
upon independent appraisals and estimated discounted future cash
flows based on management's estimate of cost recovery; (2) the effect
of discontinuing SFAS 71 for the Company's nuclear operations; (3)
amortization of the fair value adjustment for long-term debt; (4)
goodwill recognized representing the excess of the Company's portion
of the purchase price over the Company's adjusted net assets; (5) the
elimination of merger costs; and (6) adjustments for estimated tax
effects of the above adjustments.
8. PENDING MERGER OF THE COMPANY INTO CEI:
In March 1994, Centerior announced a plan to merge the
Company into CEI. All necessary regulatory approvals have been
obtained, except the approval of the Nuclear Regulatory Commission
(NRC). This application was withdrawn at the NRC's request pending
the decision whether to complete this merger. No final decision
regarding the proposed merger has been reached.
In June 1995, the Company's preferred stockholders approved
the merger and CEI's preferred stockholders approved the
authorization of additional shares of preferred stock. If and when
the merger becomes effective, the Company's preferred stockholders
will exchange their shares for preferred stock shares of CEI having
substantially the same terms. Debt holders of the merging companies
will become debt holders of CEI.
For the merging companies, the combined pro forma operating
revenues were $2.621 billion, $2.527 billion and $2.554 billion and
the combined pro forma net income was $272 million, $220 million
(excluding the extraordinary item discussed in Note 1 and a similar
item for CEI) and $218 million for the years 1998, 1997 and 1996,
respectively. The pro forma data is based on accounting for the
merger of the Company and CEI on a method similar to a pooling of
interests and for 1997 and 1996 includes pro forma adjustments to
reflect the effect of the OE -Centerior merger. The pro forma data is
not necessarily indicative of the results of operations which would
have been reported had the merger been in effect during those years
or which may be reported in the future. The pro forma data should be
read in conjunction with the audited financial statements of both the
Company and CEI.
Report of Independent Public Accountants
To the Stockholders and Board of Directors of The Toledo Edison
Company:
We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of The Toledo Edison Company
(an Ohio corporation and wholly owned subsidiary of FirstEnergy Corp.)
and subsidiary as of December 31, 1998 and 1997, and the related
consolidated statements of income, common stockholder's equity,
preferred stock, cash flows and taxes for the year ended December 31,
1996, the period from January 1, 1997 to November 7, 1997 (pre-
merger), the period from November 8, 1997 to December 31, 1997 (post-
merger), and the year ended December 31, 1998. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements
based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well
as evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of The Toledo
Edison Company and subsidiary as of December 31, 1998 and 1997, and
the results of their operations and their cash flows for the year
ended December 31, 1996, the period from January 1, 1997 to
November 7, 1997 (pre-merger), the period from November 8, 1997 to
December 31, 1997 (post-merger), and the year ended December 31, 1998,
in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Cleveland, Ohio
February 12, 1999