THE TOLEDO EDISON COMPANY
SELECTED FINANCIAL DATA
Nov. 8- Jan. 1-
1999 1998 Dec. 31, 1997 Nov. 7, 1997 1996 1995
- ----------------------------------------------------------------------------------------------------------------
(Dollars in thousands)
GENERAL FINANCIAL INFORMATION: |
|
Operating Revenues $ 921,159 $ 957,037 $ 122,669 | $ 772,707 $ 897,259 $ 873,675
========== ========== ========== | ========== ========== ==========
Operating Income $ 163,772 $ 180,261 $ 19,055 | $ 123,282 $ 156,815 $ 188,068
========== ========== ========== | ========== ========== ==========
Income Before Extraordinary Item $ 99,945 $ 106,582 $ 7,616 | $ 41,769 $ 57,289 $ 96,762
========== ========== ========== | ========== ========== ==========
Net Income (Loss) $ 99,945 $ 106,582 $ 7,616 | $ (150,132) $ 57,289 $ 96,762
========== ========== ========== | ========== ========== ==========
Earnings (Loss) on Common Stock $ 83,707 $ 92,972 $ 7,616 | $ (169,567) $ 40,363 $ 78,510
========== ========== ========== | ========== ========== ==========
Total Assets $2,666,928 $2,768,765 $2,758,152 | $3,428,175 $3,532,714
========== ========== ========== | ========== ==========
|
CAPITALIZATION: |
Common Stockholder's Equity $ 551,704 $ 575,692 $ 531,650 | $ 803,237 $ 762,877
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
Long-Term Debt 981,029 1,083,666 1,210,190 | 1,051,517 1,119,294
---------- ---------- ---------- | ---------- ----------
Total Capitalization $1,742,733 $1,869,358 $1,953,530 | $2,068,109 $2,097,191
========== ========== ========== | ========== ==========
|
CAPITALIZATION RATIOS: |
Common Stockholder's Equity 31.7% 30.8% 27.2% | 38.8% 36.4%
Preferred Stock- |
Not Subject to Mandatory |
Redemption 12.0 11.2 10.8 | 10.2 10.0
Subject to Mandatory Redemption -- -- 0.1 | 0.2 0.2
Long-Term Debt 56.3 58.0 61.9 | 50.8 53.4
----- ----- ----- | ----- -----
Total Capitalization 100.0% 100.0% 100.0% | 100.0% 100.0%
===== ===== ===== | ===== =====
|
KILOWATT-HOUR SALES (Millions): |
Residential 2,127 2,252 355 | 1,718 2,145 2,164
Commercial 2,236 2,425 284 | 1,498 1,790 1,748
Industrial 5,449 5,317 847 | 4,003 4,301 4,174
Other 54 63 79 | 413 488 500
------ ------ ----- | ----- ------ ------
Total Retail 9,866 10,057 1,565 | 7,632 8,724 8,586
Total Wholesale 2,409 1,617 435 | 2,218 2,330 2,563
------ ------ ----- | ----- ------ ------
Total 12,275 11,674 2,000 | 9,850 11,054 11,149
====== ====== ===== | ===== ====== ======
|
CUSTOMERS SERVED: |
Residential 266,900 265,237 262,501 | 261,541 260,007
Commercial 32,481 31,982 29,367 | 27,411 26,508
Industrial 1,937 1,954 1,835 | 1,839 1,846
Other 398 359 347 | 2,136 2,119
------- ------- ------- | ------- -------
Total 301,716 299,532 294,050 | 292,927 290,480
======= ======= ======= | ======= =======
|
Number of Employees 977 997 1,532 | 1,643 1,809
THE TOLEDO EDISON COMPANY
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
Results of Operations
Financial results reflect the application of purchase accounting to
the merger of our former parent company, Centerior Energy Corporation
(Centerior), and Ohio Edison Company on November 8, 1997. 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
(including categories substantially unaffected by the merger or 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 to
1998.
Operating revenues decreased by $35.9 million in 1999 following a
$61.7 million increase in 1998. The sources of changes in operating revenues
during 1999 and 1998, as compared to the prior year, are summarized in the
following table.
Sources of Revenue Changes 1999 1998
- ----------------------------------------------------------
(In millions)
Change in retail kilowatt-hour sales $(14.8) $68.2
Decrease in average retail price (20.7) (8.8)
Change in wholesale sales 2.0 (6.6)
Other (2.4) 8.9
- -----------------------------------------------------------
Change in Operating Revenues $(35.9) $61.7
===========================================================
Electric Sales
After achieving record levels in 1998, operating revenues decreased
in 1999. Lower average retail prices and reduced kilowatt-hour sales
contributed to the decline. Kilowatt-hour sales to residential and commercial
customers were both lower in 1999, compared to 1998, with sales to industrial
customers increasing over the previous year. Despite the lower retail sales
in 1999, total sales increased as a result of a strong increase in sales to
the wholesale market resulting from weather-induced demand and available
internal generation. However, the increase in wholesale revenues did not
fully offset the decrease in retail revenues resulting from lower retail
kilowatt-hour sales and the impact from lower unit prices experienced in
1999.
In 1998, retail kilowatt-hour sales increased in all customer
groups compared to 1997. Retail sales benefited from moderate growth in the
customer base. Expanded production at the North Star BHP Steel (North Star)
facility was a major contributor to the increase in industrial kilowatt-hour
sales. The decrease in wholesale sales in 1998, compared to 1997, was
primarily related to generating unit outages (described below) which reduced
energy available for sale to the wholesale market. Changes in kilowatt-hour
sales by customer class in 1999 and 1998 are summarized in the following
table.
Changes in KWH Sales 1999 1998
- -----------------------------------------------
Residential (5.6%) 8.6%
Commercial (7.8%) 9.5%
Industrial 2.5% 9.6%
- -----------------------------------------------
Total Retail (1.9%) 9.4%
Wholesale 49.0% (39.1%)
Total Sales 5.1% (1.5)%
- -----------------------------------------------
Operating Expenses and Taxes
Total operating expenses and taxes decreased $19.4 million in 1999,
compared to 1998, and increased $23.7 million in 1998 from the preceding
year. Fuel and purchased power were the primary factors contributing to the
change in both years. The comparison of 1998 to 1997 also included various
merger-related differences, which are discussed below.
Purchased power costs accounted for all of the reduction in fuel
and purchased power in 1999. Much of the improvement in purchased power costs
occurred in the second quarter of 1999 due to the absence of unusual
conditions experienced in 1998. Those costs were incurred during a period of
record heat and humidity in late June 1998, which coincided with a regional
power shortage resulting in high prices for purchased power. During this
period, unscheduled outages at Beaver Valley Unit 2 and the Davis-Besse Plant
required us to purchase significant quantities of power on the spot market.
Although above normal temperatures were also experienced in 1999, we
maintained a stronger capacity position compared to the previous year and
better met customer demand from our own internal generation. In 1998, fuel
and purchased power increased $21.3 million from 1997 for the reasons
discussed above.
Nuclear operating costs increased in 1999 from the prior year
primarily due to expenses associated with the refueling outages at Beaver
Valley Unit 2 and the Perry Plant. Reduced nuclear operating costs in 1998
resulted from lower costs at the Perry Plant which were partially offset by
higher costs at the Beaver Valley and Davis-Besse plants. Other operating
costs increased in 1999 from 1998 principally due to higher customer and
sales expenses including expenditures for energy marketing programs,
information system requirements and other customer-related costs.
Lower depreciable asset balances, resulting from the purchase
accounting adjustment, reduced depreciation and amortization in 1998 and the
1997 post-merger period. These reductions were partially offset by the
amortization of goodwill recognized with the application of purchase
accounting.
Other Income
Interest income on trust notes acquired in connection with the
Bruce Mansfield Plant lease refinancing (see Note 2), which began in June
1997, increased 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.
Net Interest Charges
Net interest charges decreased in 1999 from the preceding year
primarily due to redemptions and refinancings of long-term debt. In 1998, net
interest charges decreased 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 from the Bruce Mansfield Plant lease financing exceeded the
expense reduction from the redemption and refinancing of debt securities.
Extraordinary Item
The pre-merger period of 1997 includes an after-tax write-off of
$191.9 million in regulatory assets attributable to nuclear operations
resulting from the discontinued application of Statement of Financial
Accounting Standards No. 71 (SFAS 71), "Accounting for the Effects of Certain
Types of Regulation" which is discussed in Note 1 - Regulatory Assets.
Preferred Stock Dividend Requirements
Preferred stock dividend requirements in 1999 were increased and in
1998 were reduced due to the declaration of $3 million of preferred dividends
as of the 1997 merger date for dividends attributable to 1998 (see Note 3c).
Earnings on Common Stock
Although purchased power costs and interest costs decreased in
1999, the lower sales revenues and increased nuclear and other operating
costs more than offset these reduced costs which resulted in lower earnings
on common stock in 1999 compared to 1998. Earnings on common stock decreased
to $83.7 million in 1999 from $93.0 million in 1998. Pre-merger earnings on
common stock in 1997 include 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.
Capital Resources and Liquidity
With the July 1999 passage of legislation in Ohio allowing retail
customers to purchase electricity from alternative energy suppliers beginning
January 2001, the arrival of new participants in the Ohio electricity market
is expected in the near future. We continue to take steps designed to enhance
our competitive position while seeking additional efficiencies.
Through economic refinancings and redemptions, we continued to
reduce the cost of debt and preferred stock, and improve our financial
position in 1999. Net redemptions of long-term debt and preferred stock
totaled $105.6 million in 1999, and we refinanced $91.0 million of long-term
debt. During 1999, we reduced our total debt by approximately $102 million.
Our common stockholder's equity percentage of capitalization increased to 32%
at December 31, 1999 from 27% at the end of 1997. The merger resulted in
improved credit ratings in 1997, which lowered the cost of new borrowings.
The following table summarizes changes in credit ratings resulting from the
merger:
Credit Ratings Before and After 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
- -----------------------------------------------------------------------------
Through economic refinancings and redemptions of higher cost debt,
we have reduced the average cost of outstanding debt from 9.48% in 1994 to
8.01% in 1999. Long-term debt redemptions and refinancings completed in 1999
are expected to generate annual savings of about $9 million.
Our cash requirements in 2000 for operating expenses, construction
expenditures, preferred stock redemptions and scheduled debt maturities are
expected to be met without issuing additional securities. We have cash
requirements of approximately $581.1 million for the 2000-2004 period to meet
scheduled maturities of long-term debt and preferred stock. Of that amount,
approximately $76.0 million relates to 2000.
We had about $8.2 million of cash and temporary investments and
$33.9 million of indebtedness to associated companies as of December 31,
1999. Under our first mortgage indenture, as of December 31, 1999, we would
have been permitted to issue up to $367.4 million of additional first
mortgage bonds on the basis of bondable property additions and retired bonds.
Based on our earnings coverage test and our charter, we could issue $250.3
million of preferred stock (assuming no additional debt was issued).
Our capital spending for the period 2000-2004 is expected to be
about $259 million (excluding nuclear fuel), of which approximately $97
million relates to 2000. Investments in additional nuclear fuel during the
2000-2004 period are estimated to be approximately $113 million, of which
about $39 million applies to 2000. During the same periods, our nuclear fuel
investments are expected to be reduced by approximately $106 million and $23
million, respectively, as the nuclear fuel is consumed. Also, we have
operating lease commitments, net of trust cash receipts, of approximately
$363 million for the 2000-2004 period of which approximately $69 million
relates to 2000. 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.
Comparison of Carrying Value to Fair Value
- -------------------------------------------------------------------------
There- Fair
2000 2001 2002 2003 2004 after Total Value
- -------------------------------------------------------------------------
(Dollars in millions)
Investments other than
Cash and Cash
Equivalents:
Fixed Income $ 15 $ 17 $ 20 $ 19 $ 9 $243 $323 $315
Average interest
rate 7.6% 7.6% 7.6% 7.6% 7.6% 7.2% 7.3%
- -------------------------------------------------------------------------
Liabilities
- -------------------------------------------------------------------------
Long-term Debt:
Fixed rate $ 76 $ 29 $164 $ 96 $215 $324 $904 $914
Average interest
rate 7.3% 9.2% 8.6% 7.9% 7.8% 7.8% 8.0%
Variable rate $ 91 $ 91 $ 88
Average interest
rate 5.2% 5.2%
Short-term Borrowings $ 34 $ 34 $ 34
Average interest
rate 6.5% 6.5%
- -------------------------------------------------------------------------
Outlook
We continue to face many competitive challenges as the electric
utility industry undergoes significant changes, including changing regulation
and the entrance of more energy suppliers into the marketplace. Recent
legislation allows retail customers in Ohio to purchase electricity from
alternative energy suppliers beginning in 2001. Our existing regulatory plan
provides us with a solid 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 transition plan ultimately approved by the Public
Utilities Commission of Ohio (PUCO) will supersede our current Ohio rate
plan.
FirstEnergy's Rate Reduction and Economic Development Plan,
approved in January 1997, provides interim rate credits to our customers
during the periods covered by the plan. Our regulatory plan includes a
commitment to accelerate depreciation on our regulatory books by recording an
additional $660 million of depreciation over the plan period ending 2005. The
plan does not provide for full recovery of nuclear operations; accordingly,
we ceased application of SFAS 71 for our nuclear operations when
implementation of the FirstEnergy regulatory plan became probable in October
1997.
In July 1999, Ohio's new electric utility restructuring
legislation, which will allow Ohio electric customers to select their
generation suppliers beginning January 1, 2001, was signed into law. Among
other things, the new law provides for a 5% reduction on the generation
portion of residential customers' bills and the opportunity to recover
transition costs, including regulatory assets, from January 1, 2001 through
December 31, 2005. The period for the recovery of regulatory assets only can
be extended up to December 31, 2010. The PUCO was authorized to determine the
level of transition cost recovery, as well as the recovery period for the
regulatory assets portion of those costs, in considering each Ohio electric
utility's transition plan application.
FirstEnergy filed a transition plan on our behalf as well as for
its other Ohio electric utility operating companies -- Ohio Edison Company
(OE) and The Cleveland Electric Illuminating Company (CEI) -- on December 22,
1999. The plan was originally filed with the PUCO on October 4, 1999, but was
refiled to conform to PUCO rules established on November 30, 1999. The new
filing also included additional information on our plan to turn over control,
and perhaps ownership, of our transmission assets to the Alliance Regional
Transmission Organization (Alliance), which is discussed below.
The transition plan itemizes, or unbundles, the current price of
electricity into separate components -- including generation, transmission,
distribution and transition charges. As required by the PUCO's rules,
FirstEnergy's filing also included proposals on corporate separation of
regulated and unregulated operations, operational and technical support
changes needed to accommodate customer choice, an education program to inform
customers of their options under the law, and how our transmission system
will be operated to ensure access to all users. Under our transition plan,
customers who remain with us as their generation provider will continue to
receive savings under our rate plan, expected to total $96.3 million between
2000 and 2005. In addition, FirstEnergy's Ohio utility customers will save
$358 million through reduced charges for taxes and a 5% reduction in the
price of generation for residential customers beginning January 1, 2001.
Customers' prices are expected to be frozen through a five-year market
development period (2001-2005), except for certain limited statutory
exceptions including the 5% reduction in the price of generation for
residential customers. The plan proposes recovery of generation-related
transition costs of approximately $859 million ($764 million, net of deferred
income taxes) over the market development period; transition costs related to
regulatory assets aggregating approximately $842 million ($573 million, net
of deferred income taxes) are expected to recovered over the period of 2001
through 2007.
When the transition plan is approved by the PUCO, the application
of SFAS 71 to our nonnuclear generation business will be discontinued. In the
meantime, we will continue to bill and collect cost-based rates related to
that business through the end of 2000. If the transition plan ultimately
approved by the PUCO does not provide adequate recovery of our nuclear
generating unit investments and regulatory assets, there would be a charge to
earnings which could have a material adverse effect on our results of
operations and financial condition. We believe that we will continue to bill
and collect cost-based rates for our transmission and distribution services,
which will remain regulated; accordingly, it is appropriate that we continue
the application of SFAS 71 to those operations after December 31, 2000.
We have been named as a "potentially responsible party" (PRP) for
three sites listed on the Superfund National Priorities List and are aware of
our potential involvement in the cleanup of several other sites. 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 PRPs 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 $627,000 liability as of December
31, 1999, 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.
On October 27, 1999, the Federal Energy Regulatory Commission
(FERC) approved FirstEnergy's plan to transfer our transmission assets and
those of OE, CEI and Pennsylvania Power Company to American Transmission
Systems Inc. (ATSI). We subsequently received approval from the PUCO in
February 2000. Regulatory approval is also required from the Securities and
Exchange Commission. The new subsidiary represents a first step toward the
goal of establishing or becoming part of a larger independent, regional
transmission organization (RTO). In working toward that goal, FirstEnergy
joined with four other companies -- American Electric Power, Consumers
Energy, Detroit Edison and Virginia Power -- to form the Alliance RTO. On
June 3, 1999, the Alliance submitted an application to FERC to form an
independent, for profit RTO. On December 15, 1999, FERC issued an order
conditionally approving the Alliance's application.
Recently Issued Accounting Standard
In June 1998, the Financial Accounting Standards Board (FASB)
issued Statement of Financial Accounting Standards No. 133 (SFAS 133),
"Accounting for Derivative Instruments and Hedging Activities". SFAS 133
establishes accounting and reporting standards requiring that every
derivative instrument (including derivative instruments embedded in other
contracts) be recorded on the balance sheet as either an asset or liability
measured at its fair value. SFAS 133 requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. Special accounting for qualifying hedges
allows a derivative's gains and losses to offset related results on the
hedged item in the income statement. We have not completed quantifying the
impacts of adopting SFAS 133 on our financial statements or determined the
method of its adoption. However, SFAS 133 could increase volatility in
earnings and other comprehensive income. We anticipate adopting the new
statement on its amended effective date of January 1, 2001.
Year 2000 Update
Based on the results of our remediation and testing efforts, we
filed documents with the North American Electric Reliability Council, Nuclear
Regulatory Commission, and PUCO that as of June 30, 1999, our generation,
transmission, and distribution systems were ready to serve customers in the
year 2000. We have since experienced no failures or interruptions of service
to our customers resulting from the Year 2000 issue, which was consistent
with our expectations. We spent $15.0 million on Year 2000 related costs
through December 31, 1999, which was slightly lower than previously
estimated. Of this total, $12.3 million was 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 $2.7 million was
expensed as incurred. We do not believe there are any continuing Year 2000
issues to be addressed, nor any additional material Year 2000 expenditures.
Forward-Looking Information
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.
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended
December 31,
------------------- Nov. 8- Jan. 1-
1999 1998 Dec. 31, 1997 Nov. 7, 1997
- ------------------------------------------------------------------------------------------------------------
(In thousands)|
|
OPERATING REVENUES (1) $921,159 $957,037 $122,669 | $ 772,707
-------- -------- -------- | ---------
OPERATING EXPENSES AND TAXES: |
Fuel and purchased power 169,153 202,239 22,926 | 158,027
Nuclear operating costs 175,015 160,080 29,372 | 138,559
Other operating costs 171,427 166,935 20,608 | 145,174
-------- -------- -------- | ---------
Total operation and maintenance expenses 515,595 529,254 72,906 | 441,760
Provision for depreciation and amortization 103,725 106,433 14,860 | 98,986
General taxes 87,862 86,661 13,126 | 77,426
Income taxes 50,205 54,428 2,722 | 31,253
-------- -------- -------- | --------
Total operating expenses and taxes 757,387 776,776 103,614 | 649,425
-------- -------- -------- | --------
|
OPERATING INCOME 163,772 180,261 19,055 | 123,282
|
OTHER INCOME 12,744 12,225 2,153 | 2,153
-------- -------- -------- | -------
|
INCOME BEFORE NET INTEREST CHARGES 176,516 192,486 21,208 | 125,435
-------- -------- -------- | -------
|
NET INTEREST CHARGES: |
Interest on long-term debt 82,204 88,364 13,689 | 74,264
Allowance for borrowed funds used during |
construction (1,443) (1,273) (138) | (259)
Other interest expense (credit) (4,190) (1,187) 41 | 9,661
-------- -------- -------- | --------
Net interest charges 76,571 85,904 13,592 | 83,666
-------- -------- -------- | --------
|
INCOME BEFORE EXTRAORDINARY ITEM 99,945 106,582 7,616 | 41,769
|
EXTRAORDINARY ITEM (NET OF INCOME |
TAXES) (Note 1) -- -- -- | (191,901)
-------- -------- -------- | --------
|
NET INCOME (LOSS) 99,945 106,582 7,616 | (150,132)
|
PREFERRED STOCK DIVIDEND |
REQUIREMENTS 16,238 13,610 -- | 19,435
-------- -------- -------- | ---------
EARNINGS (LOSS) ON COMMON STOCK $ 83,707 $ 92,972 $ 7,616 | $(169,567)
======== ======== ======== | =========
<FN>
(1) Includes electric sales to associated companies of $123.3 million, $123.6 million, $17.7 million
and $98.5 million in 1999, 1998, the November 8 - December 31, 1997 period and the
January 1-November 7, 1997 period, 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, 1999 1998
- ---------------------------------------------------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service $1,776,534 $1,757,364
Less-Accumulated provision for depreciation 670,866 626,942
---------- ----------
1,105,668 1,130,422
---------- ----------
Construction work in progress-
Electric plant 95,854 26,603
Nuclear fuel 386 11,191
---------- ----------
96,240 37,794
---------- ----------
1,201,908 1,168,216
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Shippingport Capital Trust (Note 2) 295,454 310,762
Nuclear plant decommissioning trusts 123,500 102,749
Other 4,678 3,656
---------- ----------
423,632 417,167
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents 312 4,140
Receivables-
Customers 12,965 7,338
Associated companies 40,998 30,006
Other (less accumulated provision of
$100,000 for uncollectible accounts
in 1998) 9,827 31,688
Notes receivable from associated companies 7,863 101,236
Materials and supplies, at average cost-
Owned 23,243 25,745
Under consignment 20,232 18,148
Prepayments and other 25,931 25,647
---------- ----------
141,371 243,948
---------- ----------
DEFERRED CHARGES:
Regulatory assets 385,284 417,704
Goodwill 465,169 474,593
Property taxes 43,448 42,842
Other 6,116 4,295
---------- ----------
900,017 939,434
---------- ----------
$2,666,928 $2,768,765
========== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements
of Capitalization):
Common stockholder's equity $ 551,704 $ 575,692
Preferred stock-
Not subject to mandatory redemption 210,000 210,000
Long-term debt 981,029 1,083,666
---------- ----------
1,742,733 1,869,358
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt and
preferred stock 95,765 130,426
Accounts payable-
Associated companies 20,537 34,260
Other 27,100 34,275
Notes payable to associated companies 33,876 --
Accrued taxes 57,742 62,288
Accrued interest 21,961 24,965
Other 60,414 39,639
---------- ----------
317,395 325,853
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes 172,236 151,321
Accumulated deferred investment tax credits 38,748 40,670
Nuclear plant decommissioning costs 130,116 109,366
Pensions and other postretirement benefits 122,986 122,314
Other 142,714 149,883
---------- ----------
606,800 573,554
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES
(Notes 2 and 5) ---------- ----------
$2,666,928 $2,768,765
========== ==========
<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, 1999 1998
- --------------------------------------------------------------------------------------------------------------------------
(Dollars in thousands, except per share amounts)
COMMON STOCKHOLDER'S EQUITY:
Common stock, $5 par value, authorized 60,000,000 shares
39,133,887 shares outstanding $ 195,670 $ 195,670
Other paid-in capital 328,559 328,559
Retained earnings (Note 3A) 27,475 51,463
---------- ----------
Total common stockholder's equity 551,704 575,692
---------- ----------
Number of Shares Optional
Outstanding Redemption Price
---------------- -------------------
1999 1998 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 $ -- -- 1,690
Redemption Within One Year -- (1,690)
--------- --------- -------- ---------- ----------
Total Subject to Mandatory
Redemption -- 16,900 $ -- -- --
========= ========= ======== ---------- ----------
LONG-TERM DEBT (Note 3E):
First mortgage bonds:
7.250% due 1999 -- 85,000
8.000% due 2000-2003 34,925 35,325
7.875% due 2004 145,000 145,000
---------- ----------
Total first mortgage bonds 179,925 265,325
---------- ----------
Unsecured notes and debentures:
5.750% due 2000-2003 -- 3,600
10.000% due 2000-2010 1,000 1,000
8.700% due 2002 135,000 135,000
* 4.850% due 2030 34,850 --
* 5.100% due 2033 5,700 --
* 5.250% due 2033 31,600 --
* 5.580% due 2033 18,800 --
---------- ----------
Total unsecured notes and debentures 226,950 139,600
---------- ----------
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont.)
At December 31 1999 1998
- ------------------------------------------------------------------------------------------------------------------------
(In thousands)
LONG-TERM DEBT (Cont.):
Secured notes:
7.720% due 1999 -- 15,000
8.470% due 1999 -- 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
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
8.000% due 2023 30,500 49,300
6.100% due 2027 10,100 10,100
5.375% due 2028 3,751 3,751
---------- ----------
Total secured notes 587,751 693,601
---------- ----------
Capital lease obligations (Note 2) 45,247 67,453
---------- ----------
Net unamortized premium on debt 36,921 46,423
---------- ----------
Long-term debt due within one year (95,765) (128,736)
---------- ----------
Total long-term debt 981,029 1,083,666
---------- ----------
TOTAL CAPITALIZATION $1,742,733 $1,869,358
========== ==========
<FN>
* Denotes variable rate issue with December 31, 1999 interest rate shown for only December 31, 1999
balances and December 31, 1998 interest rate shown for only December 31, 1998 balances.
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 Other
Income (Loss) Number Par Paid-In Retained
(Note 3B) of Shares Value Capital Earnings
------------- --------- ----- ------- --------
(Dollars in Thousands)
Balance, January 1, 1997 39,133,887 $195,687 $ 602,113 $ 5,437
Net loss $(150,132) (150,132)
=========
Cash dividends on preferred stock (20,973)
___________________________________________________________________________________________________________
Purchase accounting fair value
adjustment (17) (273,749) 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
Net income $ 99,945 99,945
=========
Cash dividends on preferred stock (17,582)
Cash dividends on common stock (106,351)
- ---------------------------------------------------------------------------------------------------------
Balance, December 31, 1999 39,133,887 $195,670 $ 328,559 $ 27,475
==========================================================================================================
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, 1997 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
Redemptions-
$100 par $9.375 (16,900) (1,690)
- -----------------------------------------------------------------------------------------------------
Balance, December 31, 1999 5,700,000 $210,000 -- $ --
=====================================================================================================
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended
December 31,
------------------- Nov. 8- Jan. 1-
1999 1998 Dec. 31, 1997 Nov. 7, 1997
- ---------------------------------------------------------------------------------------------------------------------------
(In thousands) |
|
CASH FLOWS FROM OPERATING ACTIVITIES: |
Net Income (Loss) $ 99,945 $ 106,582 $ 7,616 | $(150,132)
Adjustments to reconcile net income (loss) to net |
cash from operating activities: |
Provision for depreciation and amortization 103,725 106,433 14,860 | 98,986
Nuclear fuel and lease amortization 25,166 24,071 5,316 | 30,354
Deferred income taxes, net 27,551 38,840 1,386 | (121,002)
Investment tax credits, net (1,922) (2,595) (400) | (3,601)
Allowance for equity funds used during construction -- -- (61) | (776)
Extraordinary item -- -- -- | 295,233
Receivables 5,242 (32,169) 1,923 | 317
Materials and supplies 418 (2,463) (4,430) | 6,543
Accounts payable (20,898) 4,559 (12,989) | 18,679
Other 1,427 19,172 (29,443) | 55,233
--------- -------- -------- | --------
Net cash provided from (used for) operating activities 240,654 262,430 (16,222) | 229,834
--------- -------- -------- | --------
|
CASH FLOWS FROM FINANCING ACTIVITIES: |
New Financing- |
Long-term debt 89,330 3,629 -- | 149,804
Short-term borrowings, net 33,876 -- -- | --
Redemptions and Repayments- |
Preferred stock 1,690 1,665 -- | 1,665
Long-term debt 226,695 90,929 -- | 85,419
Dividend Payments- |
Common stock 106,351 50,483 -- | --
Preferred stock 16,238 16,378 4,156 | 12,589
--------- -------- -------- | --------
Net cash provided from (used for) financing |
activities (227,768) (155,826) (4,156) | 50,131
--------- -------- -------- | --------
CASH FLOWS FROM INVESTING ACTIVITIES: |
Property additions 107,338 45,870 6,568 | 36,680
Loans to associated companies -- 60,434 -- | --
Loan payments from associated companies (93,373) -- (15,297) | (25,718)
Capital trust investments (15,308) (2,111) (7,314) | 320,187
Other 18,057 20,441 (6,585) | 10,350
--------- --------- -------- | ---------
Net cash used for (provided from) investing activities 16,714 124,634 (22,628) | 341,499
--------- --------- -------- | ---------
Net increase (decrease) in cash and cash equivalents (3,828) (18,030) 2,250 | (61,534)
Cash and cash equivalents at beginning of period 4,140 22,170 19,920 | 81,454
--------- --------- -------- | ---------
Cash and cash equivalents at end of period $ 312 $ 4,140 $ 22,170 | $ 19,920
========= ========= ======== | =========
SUPPLEMENTAL CASH FLOWS INFORMATION: |
Cash Paid During the Period- |
Interest (net of amounts capitalized) $ 84,538 $ 93,828 $ 16,652 | $ 72,757
========= ========= ======== | =========
Income taxes $ 40,461 $ 6,935 $ 28,000 | $ 25,300
========= ========= ======== | =========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF TAXES
For the Years Ended
December 31,
-------------------- Nov. 8- Jan. 1-
1999 1998 Dec. 31, 1997 Nov. 7, 1997
- ------------------------------------------------------------------------------------------------------------------
(In thousands) |
|
GENERAL TAXES: |
Real and personal property $ 44,280 $ 44,993 $ 5,998 | $ 40,495
State gross receipts 35,706 35,114 5,826 | 28,590
Social security and unemployment 6,801 5,065 818 | 4,444
Other 1,075 1,489 484 | 3,897
-------- -------- --------- | ---------
Total general taxes $ 87,862 $ 86,661 $ 13,126 | $ 77,426
======== ======== ========= | =========
PROVISION FOR INCOME TAXES: |
Currently payable- |
Federal $ 29,728 $ 22,767 $ 2,859 | $ 55,192
State* 1,489 1,954 209 | --
-------- -------- --------- | ---------
31,217 24,721 3,068 | 55,192
-------- -------- --------- | ---------
Deferred, net- |
Federal 27,745 38,851 1,404 | (121,002)
State* (194) (11) (18) | --
-------- -------- --------- | ---------
27,551 38,840 1,386 | (121,002)
-------- -------- --------- | ---------
Investment tax credit amortization (1,922) (2,595) (400) | (3,601)
-------- -------- --------- | ---------
Total provision for income taxes $ 56,846 $ 60,966 $ 4,054 | $ (69,411)
======== ======== ========= | =========
INCOME STATEMENT CLASSIFICATION |
OF PROVISION FOR INCOME TAXES: |
Operating income $ 50,205 $ 54,428 $ 2,722 | $ 31,253
Other income 6,641 6,538 1,332 | 2,667
Extraordinary item -- -- -- | (103,331)
-------- -------- --------- | ---------
Total provision for income taxes $ 56,846 $ 60,966 $ 4,054 | $ (69,411)
======== ======== ========= | =========
RECONCILIATION OF FEDERAL INCOME TAX |
EXPENSE AT STATUTORY RATE TO TOTAL |
PROVISION FOR INCOME TAXES: |
Book income before provision for income taxes $156,791 $167,548 $ 11,670 | $(219,543)
======== ======== ========= | =========
Federal income tax expense at statutory rate $ 54,877 $ 58,642 $ 4,085 | $ (76,840)
Increases (reductions) in taxes resulting from- |
Amortization of investment tax credits (1,922) (2,595) (400) | (3,601)
Depreciation -- -- -- | 3,428
Amortization of tax regulatory assets (1,735) (1,739) (145) | --
Amortization of goodwill 4,280 4,421 670 | --
Other, net 1,346 2,237 (156) | 7,602
-------- -------- --------- | ---------
Total provision for income taxes $ 56,846 $ 60,966 $ 4,054 | $ (69,411)
======== ======== ========= | =========
ACCUMULATED DEFERRED INCOME TAXES |
AT DECEMBER 31: |
Property basis differences $195,326 $195,948 $ 190,636 |
Deferred nuclear expense 76,449 79,355 83,052 |
Deferred sale and leaseback costs (21,443) (20,623) (17,431) |
Unamortized investment tax credits (18,324) (19,515) (20,960) |
Unused alternative minimum tax credits (30,055) (66,322) (108,156) |
Other (29,717) (17,522) (22,598) |
-------- -------- --------- |
Net deferred income tax liability $172,236 $151,321 $ 104,543 |
======== ======== ========= |
<FN>
* For the period 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, 1999 or 1998, with respect to any particular
segment of the Company's customers.
The Company and CEI 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 was to maintain current base electric rates
for the Company through December 31, 2005. At the end of the regulatory plan
period, the Company's base rates were to be reduced by $93 million
(approximately 15 percent below 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 would be frozen through the
regulatory plan period, subject to limited periodic adjustments. As part of
the regulatory plan, transition rate credits were implemented for customers,
which are expected to reduce operating revenues for the Company by
approximately $111 million during the regulatory plan period.
In July 1999, Ohio's new electric utility restructuring
legislation which will allow Ohio electric customers to select their
generation suppliers beginning January 1, 2001, was signed into law. Among
other things, the new law provides for a five percent reduction on the
generation portion of residential customers' bills and the opportunity to
recover transition costs, including regulatory assets, from January 1, 2001
through December 31, 2005. The period for the recovery of regulatory assets
only can be extended up to December 31, 2010. The PUCO was authorized to
determine the level of transition cost recovery, as well as the recovery
period for the regulatory assets portion of those costs, in considering each
Ohio electric utility's transition plan application.
FirstEnergy, on behalf of its Ohio electric utility operating
companies - the Company, CEI and Ohio Edison Company (OE) - on December 22,
1999 refiled its transition plan under Ohio's new electric utility
restructuring law. The plan was originally filed with the PUCO on October 4,
1999, but was refiled to conform to PUCO rules established on November 30,
1999. The new filing also included additional information on FirstEnergy's
plans to turn over control, and perhaps ownership, of its transmission
assets to the Alliance Regional Transmission Organization. The PUCO
indicated that it will endeavor to issue its order in FirstEnergy's case
within 275 days of the initial October filing date.
The transition plan itemizes, or unbundles, the current price of
electricity into its component elements - including generation,
transmission, distribution and transition charges. As required by the PUCO's
rules, FirstEnergy's filing also included its proposals on corporate
separation of its regulated and unregulated operations, operational and
technical support changes needed to accommodate customer choice, an
education program to inform customers of their options under the new law,
and how FirstEnergy's transmission system will be operated to ensure access
to all users. Under the plan, customers who remain with the Company as their
generation provider will continue to receive savings under the Company's
rate plans, expected to total $96 million between 2000 and 2005. In
addition, FirstEnergy's Ohio utility customers will save $358 million
through reduced charges for taxes and a five percent reduction in the price
of generation for residential customers beginning January 1, 2001. Customer
prices are expected to be frozen through a five-year market development
period (2001-2005), except for certain limited statutory exceptions
including the five percent reduction in the price of generation for
residential customers. The plan proposes recovery of the Company's
generation-related transition costs of approximately $859 million ($764
million, net of deferred income taxes) over the market development period;
its transition costs related to regulatory assets aggregating approximately
$842 million ($573 million, net of deferred income taxes) will be recovered
over the period of 2001 through 2007.
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
$530 million as of December 31, 1999.
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) in 1999 and 1998
and 2.6% in the post-merger period in 1997.
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 $422 million
in current dollars and (using a 4.0% escalation rate) approximately $1.0
billion in future dollars. The estimated obligation and the escalation rate
were developed based on site specific studies. Payments for decommissioning
are expected to begin in 2016, when actual decommissioning work begins. The
Company has recovered approximately $101 million for decommissioning through
its electric rates from customers through December 31, 1999. 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 $123.5 million invested in external decommissioning trust
funds as of December 31, 1999. Earnings on these funds are reinvested with a
corresponding increase to the decommissioning liability. The Company has
also recognized an estimated liability of approximately $7.7 million at
December 31, 1999 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 the first quarter of 2000.
COMMON OWNERSHIP OF GENERATING FACILITIES-
The Company, CEI, Duquesne Light Company (Duquesne), OE and its
wholly owned subsidiary, Pennsylvania Power Company (Penn), constituted the
Central Area Power Coordination Group (CAPCO). The CAPCO companies formerly
owned and/or leased, 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.
On March 26, 1999, FirstEnergy completed its agreements with
Duquesne to exchange certain generating assets. All regulatory approvals
were received by October 1999. In December 1999, Duquesne transferred 1,436
megawatts owned by Duquesne at eight CAPCO generating units in exchange for
1,328 megawatts at three non-CAPCO power plants owned by CEI, OE and Penn.
Under the agreements, Duquesne was no longer a participant in the CAPCO
arrangements after the exchange. The amounts reflected on the Consolidated
Balance Sheet under utility plant at December 31, 1999 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 $ 40.6 $12.6 $ 4.4 18.61%
Beaver Valley Unit 2 58.2 5.7 3.2 19.91%
Davis-Besse 212.1 15.7 4.4 48.62%
Perry 332.7 26.0 4.9 19.91%
- ------------------------------------------------------------------------
Total $643.6 $60.0 $16.9
========================================================================
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
$30 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
and compensation. In 1998, the Centerior Pension Plan was merged into the
FirstEnergy pension plan. 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 FirstEnergy pension plan consist primarily of common stocks, United
States government bonds and corporate bonds.
The Company provides a minimum amount of noncontributory life
insurance to retired employees in addition to optional contributory
insurance. Health care benefits, which include certain employee deductibles
and copayments, are also available to retired employees, their dependents
and, under certain circumstances, their survivors. The Company pays
insurance premiums to cover a portion of these benefits in excess of set
limits; all amounts up to the limits are paid by the Company. The Company
recognizes the expected cost of providing other postretirement benefits to
employees and their beneficiaries and covered dependents from the time
employees are hired until they become eligible to receive those benefits.
The following sets forth the funded status of the FirstEnergy
plans in 1999 and 1998 and amounts recognized on the Consolidated Balance
Sheets as of December 31:
Other
Pension Benefits Postretirement Benefits
-------------------- -----------------------
1999 1998 1999 1998
- ------------------------------------------------------------------------
(In millions)
Change in benefit
obligation:
Benefit obligation as
of January 1 $1,500.1 $1,327.5 $ 601.3 $ 534.1
Service cost 28.3 25.0 9.3 7.5
Interest cost 102.0 92.5 40.7 37.6
Plan amendments -- 44.3 -- 40.1
Actuarial loss (gain) (155.6) 101.6 (17.6) 10.7
Net increase from
asset swap 14.8 -- 12.5 --
Benefits paid (95.5) (90.8) (37.8) (28.7)
- -------------------------------------------------------------------------
Benefit obligation
as of December 31 1,394.1 1,500.1 608.4 601.3
- -------------------------------------------------------------------------
Change in plan assets:
Fair value of plan
assets as of
January 1 1,683.0 1,542.5 3.9 2.8
Actual return on
plan assets 220.0 231.3 0.6 0.7
Company contribution -- -- 0.4 0.4
Benefits paid (95.5) (90.8) -- --
- -------------------------------------------------------------------------
Fair value of plan
assets as of
December 31 1,807.5 1,683.0 4.9 3.9
- -------------------------------------------------------------------------
Funded status of plan 413.4 182.9 (603.5) (597.4)
Unrecognized
actuarial loss (gain) (303.5) (110.8) 24.9 30.6
Unrecognized prior service
cost 57.3 63.0 24.1 27.4
Unrecognized net transition
obligation (asset) (10.1) (18.0) 120.1 129.3
- -------------------------------------------------------------------------
Prepaid (accrued) benefit
cost $ 157.1 $ 117.1 $(434.4) $(410.1)
=========================================================================
Assumptions used as of
December 31:
Discount rate 7.75% 7.00% 7.75% 7.00%
Expected long-term return
on plan assets 10.25% 10.25% 10.25% 10.25%
Rate of compensation increase 4.00% 4.00% 4.00% 4.00%
The Consolidated Balance Sheet classification of Pensions and
Other Postretirement Benefits at December 31, 1999 and 1998 includes the
Company's share of the net pension liability of $11.8 million and $17.3
million, respectively; and the Company's share of the accrued postretirement
benefit liability of $110.2 million and $105.0 million, respectively.
Net pension and other postretirement benefit costs for the three
years ended December 31, 1999 (FirstEnergy plans in 1999 and 1998 and
Centerior plans in 1997) were computed as follows:
Pension Benefits Other Postretirement Benefits
------------------------------- -----------------------------
1997 1997
----------------- -------------------
Nov. 8- Jan. 1- Nov. 8- Jan. 1-
1999 1998 Dec. 31 Nov. 7 1999 1998 Dec. 31 Nov. 7
- --------------------------------------------------------------------------------------------------------
| (In millions) |
| |
Service cost $ 28.3 $ 25.0 $ 2.3 | $ 11.1 $ 9.3 $ 7.5 $0.5 | $ 1.8
Interest cost 102.0 92.5 6.1 | 25.4 40.7 37.6 2.8 | 13.5
Expected return on plan assets (168.1) (152.7) (7.7) | (38.0) (0.4) (0.3) -- | --
Amortization of transition | |
obligation (asset) (7.9) (8.0) -- | (3.0) 9.2 9.2 -- | 6.4
Amortization of prior service cost 5.7 2.3 -- | 1.1 3.3 (0.8) -- | --
Recognized net actuarial loss (gain) -- (2.6) -- | (0.5) -- -- -- | (0.9)
Voluntary early retirement | |
program expense -- -- 23.0 | 4.8 -- -- -- | --
- ----------------------------------------------------------------|--------------------------------------
Net benefit cost $(40.0) $(43.5) $23.7 | $ 0.9 $62.1 $53.2 $3.3 | $20.8
================================================================|==============================|=======
Company's share of total plan | |
costs $ (8.3) $ (1.1) $ 5.7 | $ 3.5 $12.6 $ 7.5 $1.5 | $ 8.9
- -------------------------------------------------------------------------------------------------------
The FirstEnergy plan's health care trend rate assumption is 5.3%
in 2000, 5.2% in 2001 and 5.0% for 2002 and later years. Assumed health care
cost trend rates have a significant effect on the amounts reported for the
health care plan. An increase in the health care trend rate assumption by
one percentage point would increase the total service and interest cost
components by $4.5 million and the postretirement benefit obligation by
$72.0 million. A decrease in the same assumption by one percentage point
would decrease the total service and interest cost components by $3.5
million and the postretirement benefit obligation by $58.2 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 Company is selling 150 megawatts of its Beaver Valley Unit 2
leased capacity entitlement to CEI. Operating revenues for this transaction
were $104.3 million, $98.5 million, $16.8 million and $87.4 million in 1999,
in 1998, the November 8-December 31, 1997 period and the January 1-November
7, 1997 period, respectively. This sale is expected to continue through the
end of the lease period. (See Note 2.)
FirstEnergy and, prior to 1999, 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. FirstEnergy billed the Company $59.4 million in 1999
and the Service Company billed the Company $39.0 million, $13.9 million and
$51.5 million in 1998, the November 8-December 31, 1997 period and the
January 1-November 7, 1997 period, 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. At December 31, 1998, cash and cash equivalents included $4
million to be used for the redemption of long-term debt in 1999. 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 $8.5 million, $27.9 million, $2.7 million
and $11.7 million in 1999, 1998, the November 8-December 31, 1997 period and
the January 1-November 7, 1997 period, 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:
1999 1998
- --------------------------------------------------------------------------
Carrying Fair Carrying Fair
Value Value Value Value
- --------------------------------------------------------------------------
(In millions)
Long-term debt $995 $1,002 $1,098 $1,174
Preferred stock $ -- $ -- $ 2 $ 2
Investments other than cash and
cash equivalents:
Debt securities
- (Maturing in more than 10 years) $293 $ 270 $ 308 $ 301
Equity securities 3 3 3 3
All other 124 128 103 105
- --------------------------------------------------------------------------
$420 $ 401 $ 414 $ 409
==========================================================================
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 trust
investments. Unrealized gains and losses applicable to the decommissioning
trusts have been recognized in the trust investment 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 is continuing to bill and collect
cost-based rates relating to nonnuclear operations and continues the
application of SFAS 71 to those operations. The PUCO indicated that it will
endeavor to issue its order related to FirstEnergy's transition plan by mid-
2000. The application of SFAS 71 to the Company's nonnuclear generation
businesses will be discontinued at that time. If the transition plan
ultimately approved by the PUCO for the Company does not provide adequate
recovery of its nuclear generating unit investments and regulatory assets,
there would be a charge to earnings which could have a material adverse
effect on the results of operations and financial condition for the Company.
The Company will continue to bill and collect cost-based rates for its
transmission and distribution services, which will remain regulated;
accordingly, it is appropriate that the Company continues the application of
SFAS 71 to those respective operations after December 31, 2000.
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 continue to be recovered
through rates applicable for the nonnuclear portion of the Company's
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:
1999 1998
- ---------------------------------------------------------------
(In millions)
Nuclear unit expenses $192.8 $200.1
Rate stabilization program deferrals 156.2 164.1
Sale and leaseback costs 33.7 41.3
Loss on reacquired debt 18.3 20.0
Other (15.7) (7.8)
- -----------------------------------------------------------------
Total $385.3 $417.7
=================================================================
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, 1999 were 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, 1999, $116
million of nuclear fuel ($44 million for the Company) was financed under a
lease financing arrangement totaling $145 million ($30 million of
intermediate-term notes and $115 million from bank credit arrangements). The
notes mature in August 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, 1999
are summarized as follows:
Nov. 8 - Jan. 1 -
1999 1998 Dec. 31, 1997 Nov. 7, 1997
- ------------------------------------------------------------------------
(In millions)
Operating leases
Interest element $ 61.4 $ 59.2 $28.0 $ 57.4
Other 45.3 44.9 13.5 23.1
Capital leases
Interest element 5.3 4.9 1.0 6.0
Other 30.4 25.1 5.3 30.4
- ----------------------------------------------------------------------
Total rentals $142.4 $134.1 $47.8 $116.9
======================================================================
The future minimum lease payments as of December 31, 1999 are:
Operating Leases
----------------------------
Capital Lease Capital
Leases Payments Trust Net
- --------------------------------------------------------------------
(In millions)
2000 $24.6 $ 104.8 $ 35.4 $ 69.4
2001 14.0 108.0 36.4 71.6
2002 7.3 111.0 37.9 73.1
2003 2.4 111.7 36.0 75.7
2004 0.9 97.9 24.3 73.6
Years thereafter 0.4 1,220.5 297.2 923.3
- --------------------------------------------------------------------
Total minimum lease payments 49.6 $1,753.9 $467.2 $1,286.7
Interest portion 4.4 ======== ====== ========
- -------------------------------------
Present value of net minimum
lease payments 45.2
Less current portion 19.7
- ------------------------------------
Noncurrent portion $ 25.5
====================================
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 obligations bonds (SLOBs) due 2003 and 2016.
The SLOBs were issued by a special-purpose funding corporation in 1988 on
behalf of lessors in the two companies' 1987 sale and leaseback transaction.
The Shippingport capital trust arrangement effectively reduce lease costs
related to that transaction.
3. CAPITALIZATION:
(A) RETAINED EARNINGS-
The Company has a provision in its mortgage applicable to $34.925
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 7.13%, respectively, in
1999.
The Company has 5 million authorized and unissued shares of
preference stock with a $25 par value.
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-
All preferred stock subject to mandatory redemption outstanding as
of December 31, 1998 was redeemed during 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 Trustee through
December 31, 1999, the Company's annual sinking and improvement fund
requirements for all bonds issued under the mortgage amounts to $0.4
million. The Company expects to deposit funds in 2000 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)
--------------------
2000 $ 76.0
2001 35.1
2002 196.0
2003 96.2
2004 268.7
--------------------
The Company and CEI have letters of credit of approximately $222
million in connection with the sale and leaseback of Beaver Valley Unit 2
that expire in May 2002. The letters of credit are secured by first mortgage
bonds of the Company and CEI in the proportion of 60% and 40%, respectively
(see Note 2).
4. SHORT-TERM BORROWINGS:
FirstEnergy has a $150 million revolving credit facility that
expires in November 2000. FirstEnergy may borrow under the facility and
could transfer any of its borrowed funds to the Company and CEI, with all
borrowings jointly and severally guaranteed by 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.
(FirstEnergy had $90 million of borrowings under the facility at December
31, 1999.) Also, the Company may borrow from its affiliates on a short-term
basis. At December 31, 1999, the Company had total short-term borrowings of
$33.9 million from its affiliates with a weighted average interest rate of
approximately 6.5%.
5. COMMITMENTS AND CONTINGENCIES:
CAPITAL EXPENDITURES-
The Company's current forecast reflects expenditures of
approximately $259 million for property additions and improvements from
2000-2004, of which approximately $97 million is applicable to 2000.
Investments for additional nuclear fuel during the 2000-2004 period are
estimated to be approximately $113 million, of which approximately $39
million applies to 2000. During the same periods, the Company's nuclear fuel
investments are expected to be reduced by approximately $106 million and $23
million, respectively, as the nuclear fuel is consumed.
NUCLEAR INSURANCE-
The Price-Anderson Act limits the public liability relative to a
single incident at a nuclear power plant to $9.5 billion. The amount is
covered by a combination of private insurance and an industry retrospective
rating plan. Based on its present ownership and leasehold interests in
Beaver Valley Unit 2, the Davis-Besse Station and the Perry Plant, the
Company's maximum potential assessment under the industry retrospective
rating plan (assuming the other affiliate co-owners contribute their
proportionate shares of any assessments under the retrospective rating plan)
would be $77.9 million per incident but not more than $8.8 million in any
one year for each incident.
The Company is also insured as to its respective interests in
Beaver Valley Unit 2, Davis-Besse and Perry under policies issued to the
operating company for each plant. Under these policies, up to $2.75 billion
is provided for property damage and decontamination and decommissioning
costs. The Company has also obtained approximately $276.4 million of
insurance coverage for replacement power costs for its respective interests
in Beaver Valley Unit 2, Davis-Besse and Perry. Under these policies, the
Company can be assessed a maximum of approximately $8.8 million for
incidents at any covered nuclear facility occurring during a policy year
which are in excess of accumulated funds available to the insurer for paying
losses.
The Company intends to maintain insurance against nuclear risks as
described above as long as it is available. To the extent that replacement
power, property damage, decontamination, decommissioning, repair and
replacement costs and other such costs arising from a nuclear incident at
any of the Company's plants exceed the policy limits of the insurance in
effect with respect to that plant, to the extent a nuclear incident is
determined not to be covered by the Company's insurance policies, or to the
extent such insurance becomes unavailable in the future, the Company would
remain at risk for such costs.
ENVIRONMENTAL MATTERS-
Various federal, state and local authorities regulate the Company
with regard to air and water quality and other environmental matters. The
Company estimates additional capital expenditures for environmental
compliance of approximately $33 million, which is included in the
construction forecast provided under "Capital Expenditures" for 2000 through
2004.
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 are being achieved by burning lower-
sulfur fuel, generating more electricity from lower-emitting plants, and/or
purchasing emission allowances. NOx reductions are being achieved through
combustion controls and generating more electricity from lower-emitting
plants. 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. In May 1999, the U.S. Court of
Appeals for the D.C. Circuit issued a stay which delays implementation of
EPA's NOx Transport Rule until the Court has ruled on the merits of various
appeals. Under the NOx Transport Rule, 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 contemplating an
approximate 85% reduction in utility plant NOx emissions from projected 2007
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 December 17, 1999 rulemaking established an alternative program which
would require nearly identical 85% NOx reductions at 392 utility plants,
including the Company's Ohio and Pennsylvania plants, by May 2003 in the
event implementation of the NOx Transport Rule is delayed. New Section 126
petitions were filed by New Jersey, Maryland, Delaware and the District of
Columbia in mid-1999 and are still under evaluation by the EPA. FirstEnergy
continues to evaluate its compliance plans and other compliance options.
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 $27,500
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. In May 1999, the U.S.
Court of Appeals for the D.C. Circuit remanded both standards back to the
EPA finding constitutional and other defects in the new NAAQS rules. The
D.C. Circuit Court, on October 29, 1999, denied an EPA petition for
rehearing. The Company cannot predict the EPA's action in response to the
Court's remand order. The cost of compliance with these regulations, if they
are reinstated, may be substantial and depends on the manner in which they
are ultimately implemented, if at all, 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 of disposal of hazardous substances at historical sites
and the liability involved, are often unsubstantiated and subject to
dispute. Federal law provides that all PRPs for a particular site be held
liable on a joint and several basis. The Company has accrued a liability of
$0.6 million as of December 31, 1999, 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.
6. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
The following summarizes certain consolidated operating results
by quarter for 1999 and 1998.
March 31, June 30, September 30, December 31,
Three Months Ended 1999 1999 1999 1999
- -------------------------------------------------------------------------------
(In millions)
Operating Revenues $224.3 $235.2 $233.7 $228.0
Operating Expenses and Taxes 175.6 195.7 191.0 195.2
Operating Income 48.7 39.5 42.7 32.8
Other Income 2.9 3.2 2.8 3.7
Net Interest Charges 19.5 19.5 19.2 18.2
- -----------------------------------------------------------------------------
Net Income $ 32.1 $ 23.2 $ 26.3 $ 18.3
=============================================================================
Earnings on Common Stock $ 28.1 $ 19.1 $ 22.3 $ 14.2
=============================================================================
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
============================================================================
7. PRO FORMA COMBINED CONDENSED STATEMENT 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 $27 million
as of December 31, 1999. 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 statement of income for the Company gives
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
- -----------------------------------------------
(In millions)
Operating Revenues $895
Operating Expenses and Taxes 742
----
Operating Income 153
Other Income 10
Net Interest Charges 91
----
Net Income $ 72
==============================================
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. TERMINATION OF PROPOSED MERGER OF THE COMPANY INTO CEI:
In March 1994, Centerior announced a plan to merge the Company
into CEI. All regulatory approvals were granted (with the exception of the
Nuclear Regulatory Commission (NRC) as that application was withdrawn at the
NRC's request pending the decision whether to complete this merger). In
addition, the preferred shareholders of the Company approved the merger and
the preferred shareholders of CEI approved the authorization of additional
shares of preferred stock. However, the management of FirstEnergy and the
Company have decided not to complete the proposed merger.
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, 1999 and 1998, and the related consolidated
statements of income, common stockholder's equity, preferred stock, cash
flows and taxes for the years ended December 31, 1999 and 1998, the period
from January 1, 1997 to November 7, 1997 (pre-merger), and the period from
November 8, 1997 to December 31, 1997 (post-merger). 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, 1999 and 1998, and the results of
their operations and their cash flows for the years ended December 31, 1999
and 1998, the period from January 1, 1997 to November 7, 1997 (pre-merger),
and the period from November 8, 1997 to December 31, 1997 (post-merger), in
conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Cleveland, Ohio
February 11, 2000