THE CLEVELAND ELECTRIC ILLUMINATING 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 $1,864,954 $1,795,997 $ 254,892 | $1,537,459 $1,798,850 $1,768,737
========== ========== ========== | ========== ========== ==========
Operating Income $ 394,766 $ 382,523 $ 50,431 | $ 315,777 $ 367,509 $ 397,899
========== ========== ========== | ========== ========== ==========
Income Before Extraordinary Item $ 194,089 $ 164,891 $ 19,290 | $ 95,191 $ 116,553 $ 183,719
========== ========== ========== | ========== ========== ==========
Net Income (Loss) $ 194,089 $ 164,891 $ 19,290 | $ (229,247) $ 116,553 $ 183,719
========== ========== ========== | ========== ========== ==========
Earnings (Loss) on Common Stock $ 160,565 $ 140,097 $ 19,290 | $ (274,276) $ 77,810 $ 141,275
========== ========== ========== | ========== ========== ==========
Total Assets $6,208,761 $6,318,183 $6,440,284 | $6,962,297 $7,222,416
========== ========== ========== | ========== ==========
|
CAPITALIZATION: |
Common Stockholder's Equity $ 966,616 $1,008,238 $ 950,904 | $1,044,283 $1,126,762
Preferred Stock- |
Not Subject to Mandatory Redemption 238,325 238,325 238,325 | 238,325 240,871
Subject to Mandatory Redemption 116,246 149,710 183,174 | 186,118 215,420
Long-Term Debt 2,682,795 2,888,202 3,189,590 | 2,523,030 2,759,492
---------- ---------- ---------- | ---------- ----------
Total Capitalization $4,003,982 $4,284,475 $4,561,993 | $3,991,756 $4,342,545
========== ========== ========== | ========== ==========
|
CAPITALIZATION RATIOS: |
Common Stockholder's Equity 24.1% 23.5% 20.9%| 26.2% 25.9%
Preferred Stock- |
Not Subject to Mandatory Redemption 6.0 5.6 5.2 | 6.0 5.6
Subject to Mandatory Redemption 2.9 3.5 4.0 | 4.6 5.0
Long-Term Debt 67.0 67.4 69.9 | 63.2 63.5
----- ----- ----- | ----- -----
Total Capitalization 100.0% 100.0% 100.0%| 100.0% 100.0%
===== ===== ===== | ===== =====
|
KILOWATT-HOUR SALES (Millions): |
Residential 5,278 4,949 790 | 4,062 4,958 5,063
Commercial 6,509 6,353 893 | 4,990 5,908 5,946
Industrial 8,069 8,024 1,285 | 6,710 7,977 7,994
Other 166 165 89 | 476 522 550
------ ------ ----- | ------ ------ ------
Total Retail 20,022 19,491 3,057 | 16,238 19,365 19,553
Total Wholesale 2,607 1,275 575 | 2,408 2,155 1,694
------ ------ ----- | ------ ------ ------
Total 22,629 20,766 3,632 | 18,646 21,520 21,247
====== ====== ===== | ====== ====== ======
|
CUSTOMERS SERVED: |
Residential 667,954 668,470 671,265 | 663,130 669,725
Commercial 69,954 68,896 74,751 | 70,886 72,259
Industrial 5,090 5,336 6,515 | 6,545 6,649
Other 223 221 278 | 446 442
------- ------- ------- | ------- -------
Total 743,221 742,923 752,809 | 741,007 749,075
======= ======= ======= | ======= =======
|
Number of Employees 1,694 1,798 3,162 | 3,282 3,636
THE CLEVELAND ELECTRIC ILLUMINATING 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 (OE)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 increased by $69.0 million in 1999 following a
$13.0 million increase in 1998. The sources of increases 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)
Increase in retail kilowatt-hour sales $46.1 $ 12.7
Change in average retail price (1.5) 5.9
Change in wholesale sales 15.2 (15.7)
Other 9.2 0.7
- -------------------------------------------------------------
Net Increase in Operating Revenues $69.0 $ 3.6
==============================================================
Electric Sales
Operating revenues increased in 1999 from 1998 as a result of
kilowatt-hour sales growth in both retail and wholesale markets. Increases in
sales to residential, commercial and industrial customers produced the higher
retail sales. Strong consumer-driven economic growth, and to a lesser extent
the weather, contributed to the increased retail sales. Weather-induced
electricity demand in the wholesale market and additional available internal
generation combined to more than double sales to wholesale customers in 1999
compared to 1998.
After setting a new record in 1997, total kilowatt-hour sales were
down in 1998 from the previous year. The decrease was due to a decrease in
sales to wholesale customers. Several generating unit outages (described
below) reduced energy available for sale to the wholesale market. Retail
sales increased in 1998, compared to 1997, with higher kilowatt-hour sales to
residential and commercial customers and sales to industrial customers nearly
unchanged.
Changes in KWH Sales 1999 1998
- -----------------------------------------------
Residential 6.6% 1.5%
Commercial 2.5% 0.3%
Industrial 0.6% --
- -----------------------------------------------
Total Retail 2.7% 0.5%
Wholesale 104.5% (57.5%)
- -----------------------------------------------
Total Sales 9.0% (7.3%)
- -----------------------------------------------
Operating Expenses and Taxes
Total operating expense and taxes increased $56.7 million in 1999
compared to 1998. The increase resulted primarily from an increase in
operation and maintenance expenses from higher nuclear operating costs and
other operating costs, which were partially offset by lower fuel and
purchased power. The comparison of 1998 to 1997 includes various merger-
related differences, which are discussed below.
The increase in operation and maintenance costs in 1999 from 1998
occurred despite a reduction in fuel and purchased power costs, which were
$26.5 million lower than the previous year. Purchased power costs accounted
for almost all of the reduction. Much of the decrease in purchased power
costs occurred in the second quarter of 1999 due to the absence of unusual
conditions experienced in 1998. 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. Unscheduled
outages at Beaver Valley Unit 2, the Davis-Besse Plant and Avon Lake Unit 9
required us to purchase significant quantities of power on the spot market
during that period. 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 $14.3 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 due to higher customer and sales expenses
including expenditures for energy marketing programs, information system
requirements and other customer-related costs. In 1998, other operating costs
were lower partially due to the absence of a 1997 pre-merger charge for
estimated severance 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. In 1999, general taxes decreased from the prior year as a result
of an adjustment made to real estate taxes resulting from new Pennsylvania
legislation and a favorable outcome to an Ohio tax settlement affecting
personal property taxes.
Other Income (Expense)
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, merger-related expenses partially offset the
interest income on trust notes.
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 premiums
associated with the revaluation of long-term debt in connection with the
merger, which also contributed to the decrease in interest charges in the
post-merger period of 1997. In the pre-merger period of 1997, interest
charges were higher because interest on new secured notes and short-term
borrowings for the Bruce Mansfield Plant lease refinancing exceeded the
expense reduction from the redemption and refinancing of debt securities.
Extraordinary Item
The pre-merger period of 1997 includes an after-tax write-off of
$324.4 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 reported in 1999 were higher
due to a reduction in 1998 resulting from the declaration of $9 million of
preferred dividends as of the 1997 merger date, for dividends attributable to
1998 (see Note 3c).
Earnings on Common Stock
Earnings on common stock increased to $160.6 million in 1999 from
$140.1 million in 1998. Results in 1999 were favorably affected by higher
sales revenues, the absence of unusually high purchased power costs
experienced in 1998, reduced general taxes and lower interest costs. Pre-
merger earnings on common stock in 1997 include an extraordinary item
resulting from the write-off of certain regulatory assets. Excluding this
write-off, pre-merger earnings on common stock were $50.2 million. For the
seven-week post-merger period, earnings on common stock were $19.3 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 $178.0 million in 1999 and we refinanced $27.7 million of long-term
debt. During 1999, we reduced our total debt by approximately $150 million.
Our common stockholder's equity percentage of capitalization increased to 24%
at December 31, 1999 from 21% at the end of 1997. The merger resulted in
improved credit ratings in 1997, which have 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+ Ba3 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 8.96% in 1994 to
7.92% in 1999. Long-term debt redemptions and refinancings completed in 1999
are expected to generate annual savings of about $13 million.
Our cash requirements in 2000 for operating expenses, construction
expenditures and scheduled debt maturities are expected to be met without
issuing additional securities. We have cash requirements of approximately
$988.6 million for the 2000-2004 period to meet scheduled maturities of long-
term debt and preferred stock. Of that amount, approximately $208.5 million
relates to 2000.
We had about $0.4 million of cash and temporary investments and
$103.5 million of short-term indebtedness to associated companies on December
31, 1999. Under our first mortgage indenture, as of December 31, 1999, we
would have been permitted to issue up to $615 million of additional first
mortgage bonds on the basis of property additions and retired bonds. We have
no restrictions on the issuance of preferred stock.
Our capital spending for the period 2000-2004 is expected to be
about $529 million (excluding nuclear fuel), of which approximately $112
million applies to 2000. Investments for additional nuclear fuel during the
2000-2004 period are estimated to be approximately $166 million, of which
about $56 million relates to 2000. During the same periods, our nuclear fuel
investments are expected to be reduced by approximately $158 million and $36
million, respectively, as the nuclear fuel is consumed. Also, we have
operating lease commitments net of trust cash receipts of approximately $61
million for the 2000-2004 period, of which approximately $6 million relates
to 2000. We recover the cost of nuclear fuel consumed and operating leases
through our electric rates.
Two transactions were completed in 1999, which modified our
portfolio of generation resources in 1999. On July 26, 1999, we completed our
purchase of the remaining 20 percent interest in the Seneca pumped storage
hydroelectric generation plant from GPU, Inc. for $43 million. The purchase
makes available 87 megawatts of additional capacity and provides us with full
ownership of the plant. On December 3, 1999, we completed the exchange of
generating assets between Duquesne Light Company (Duquesne) and FirstEnergy.
Duquesne transferred 1,436 megawatts at five generating plants in exchange
for 1,328 megawatts at three plants owned by FirstEnergy operating companies.
In the exchange, we received all of Duquesne's ownership interest in the
Perry Plant, Sammis Unit 7, Eastlake Unit 5, and an additional interest in
the Bruce Mansfield Plant while providing Duquesne with our ownership
interest in the Avon Lake Plant.
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 $ 24 $ 15 $ 38 $ 48 $ -- $442 $ 567 $ 552
Average interest rate 7.6% 7.8% 7.7% 7.6% 8.1% 7.3% 7.4%
- ---------------------------------------------------------------------------------------------------------
Liabilities
- ---------------------------------------------------------------------------------------------------------
Long-term Debt:
Fixed rate $175 $ 57 $228 $115 $280 $1,695 $2,550 $2,524
Average interest rate 7.2% 8.6% 7.7% 7.4% 7.7% 7.7% 7.7%
Variable rate $ 188 $ 188 $ 187
Average interest rate 4.4% 4.4%
Short-term Borrowings $103 $ 103 $ 103
Average interest rate 6.4% 6.4%
- ---------------------------------------------------------------------------------------------------------
Preferred Stock $ 33 $ 81 $ 19 $ 1 $ 1 $ 4 $ 139 $ 139
Average dividend rate 9.0% 8.9% 8.9% 7.4% 7.4% 7.4% 8.8%
- ---------------------------------------------------------------------------------------------------------
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 $1.34 billion of depreciation over the plan period ending in 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 - OE and The Toledo
Edison Company (TE) -- 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 $241.2 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 $1.9 billion ($1.6 billion, net of deferred
income taxes) over the market development period; transition costs related to
regulatory assets aggregating approximately $1.9 billion ($1.4 billion, net
of deferred income taxes) are expected to be recovered over the period of
2001 through 2010.
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 $239 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 $4.7 million 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, TE 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 $28.5 million on Year 2000 related costs
through December 31, 1999, which was slightly lower than previously
estimated. Of this total, $23.1 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 $5.4 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 CLEVELAND ELECTRIC ILLUMINATING 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 $1,864,954 $1,795,997 $254,892 | $1,537,459
|
OPERATING EXPENSES AND TAXES: |
Fuel and purchased power 409,282 435,752 53,239 | 368,243
Nuclear operating costs 138,686 97,914 16,791 | 85,207
Other operating costs 368,103 335,621 57,852 | 286,384
---------- ---------- -------- | ----------
Total operation and maintenance expenses 916,071 869,287 127,882 | 739,834
Provision for depreciation and |
amortization 231,225 234,348 33,438 | 211,827
General taxes 211,636 221,077 33,912 | 194,400
Income taxes 111,256 88,762 9,229 | 75,621
---------- ---------- -------- | ----------
Total operating expenses and taxes 1,470,188 1,413,474 204,461 | 1,221,682
---------- ---------- -------- | ----------
OPERATING INCOME 394,766 382,523 50,431 | 315,777
|
OTHER INCOME (EXPENSE) 9,141 11,772 3,643 | (10,921)
---------- ---------- -------- | ----------
|
INCOME BEFORE NET INTEREST CHARGES 403,907 394,295 54,074 | 304,856
---------- ---------- -------- | ----------
|
NET INTEREST CHARGES: |
Interest on long-term debt 211,842 234,795 35,300 | 197,323
Allowance for borrowed funds used during |
construction (1,755) (2,079) (631) | (1,928)
Other interest expense (credit) (269) (3,312) 115 | 14,270
---------- ---------- -------- | ----------
Net interest charges 209,818 229,404 34,784 | 209,665
---------- ---------- -------- | ----------
|
INCOME BEFORE EXTRAORDINARY ITEM 194,089 164,891 19,290 | 95,191
|
EXTRAORDINARY ITEM (NET OF INCOME |
TAXES) (Note 1) -- -- -- | (324,438)
---------- ---------- -------- | ----------
NET INCOME (LOSS) 194,089 164,891 19,290 | (229,247)
|
PREFERRED STOCK DIVIDEND |
REQUIREMENTS 33,524 24,794 -- | 45,029
---------- ---------- -------- | ----------
|
EARNINGS (LOSS) ON COMMON STOCK $ 160,565 $ 140,097 $ 19,290 | $ (274,276)
========== ========== ======== | ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
At December 31, 1999 1998
- ----------------------------------------------------------------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service $4,479,098 $4,648,725
Less-Accumulated provision for depreciation 1,498,798 1,631,974
---------- ----------
2,980,300 3,016,751
---------- ----------
Construction work in progress-
Electric plant 55,002 42,428
Nuclear fuel 408 14,864
---------- ----------
55,410 57,292
---------- ----------
3,035,710 3,074,043
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Shippingport Capital Trust (Note 2) 517,256 543,161
Nuclear plant decommissioning trusts 183,291 125,050
Other 20,708 21,059
---------- ----------
721,255 689,270
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents 376 19,526
Receivables-
Customers 17,010 16,588
Associated companies 18,318 15,636
Other (less accumulated provisions of $1,000,000
and $491,000, respectively, for uncollectible
accounts) 171,274 142,834
Notes receivable from associated companies -- 53,509
Materials and supplies, at average cost-
Owned 39,294 38,213
Under consignment 23,721 43,620
Prepayments and other 56,447 58,342
---------- ----------
326,440 388,268
---------- ----------
DEFERRED CHARGES:
Regulatory assets 539,824 555,925
Goodwill 1,440,283 1,471,563
Property taxes 132,643 126,464
Other 12,606 12,650
---------- ----------
2,125,356 2,166,602
---------- ----------
$6,208,761 $6,318,183
========== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity $ 966,616 $1,008,238
Preferred stock-
Not subject to mandatory redemption 238,325 238,325
Subject to mandatory redemption 116,246 149,710
Long-term debt 2,682,795 2,888,202
---------- ----------
4,003,982 4,284,475
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock 240,684 208,050
Accounts payable-
Associated companies 85,950 47,680
Other 50,570 62,315
Notes payable to associated companies 103,471 80,618
Accrued taxes 177,006 192,359
Accrued interest 60,740 66,685
Other 83,292 64,199
---------- ----------
801,713 721,906
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes 567,478 524,285
Accumulated deferred investment tax credits 86,999 90,946
Nuclear plant decommissioning costs 192,484 134,243
Pensions and other postretirement benefits 220,731 217,719
Other 335,374 344,609
---------- ----------
1,403,066 1,311,802
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES
(Notes 2 and 5) ---------- ----------
$6,208,761 $6,318,183
========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 1999 1998
- --------------------------------------------------------------------------------------------------------------------
(Dollars in thousands, except per share amounts)
COMMON STOCKHOLDER'S EQUITY:
Common stock, without par value, authorized 105,000,000 shares
79,590,689 shares outstanding $ 931,962 $ 931,962
Retained earnings (Note 3A) 34,654 76,276
---------- ----------
Total common stockholder's equity 966,616 1,008,238
---------- ----------
Number of Shares Optional
Outstanding Redemption Price
---------------- --------------------
1999 1998 Per Share Aggregate
---- ---- --------- ---------
PREFERRED STOCK (Note 3C):
Cumulative, without par value-
Authorized 4,000,000 shares
Not Subject to Mandatory Redemption:
$ 7.40 Series A 500,000 500,000 $ 101.00 $ 50,500 50,000 50,000
$ 7.56 Series B 450,000 450,000 102.26 46,017 45,071 45,071
Adjustable Series L 474,000 474,000 100.00 47,400 46,404 46,404
$42.40 Series T 200,000 200,000 500.00 100,000 96,850 96,850
--------- --------- -------- ---------- ----------
Total Not Subject to Mandatory
Redemption 1,624,000 1,624,000 $243,917 238,325 238,325
========= ========= ======== ---------- ----------
Subject to Mandatory Redemption (Note 3D):
$ 7.35 Series C 90,000 100,000 101.00 $ 9,090 9,110 10,110
$88.00 Series E 3,000 6,000 1,000.00 3,000 3,000 6,000
$91.50 Series Q 21,430 32,144 1,000.00 21,430 21,430 32,144
$88.00 Series R 50,000 50,000 -- -- 55,000 55,000
$90.00 Series S 55,250 74,000 -- -- 61,170 79,920
Redemption Within One Year (33,464) (33,464)
--------- --------- -------- ---------- ----------
Total Subject to Mandatory
Redemption 219,680 262,144 $ 33,520 116,246 149,710
========= ========= ======== ---------- ----------
LONG-TERM DEBT (Note 3E):
First mortgage bonds:
7.625% due 2002 195,000 195,000
7.375% due 2003 100,000 100,000
9.500% due 2005 300,000 300,000
6.860% due 2008 125,000 125,000
9.000% due 2023 150,000 150,000
---------- ----------
Total first mortgage bonds 870,000 870,000
---------- ----------
Unsecured notes:
*5.580% due 2033 27,700 --
---------- ----------
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont.)
At December 31, 1999 1998
- -------------------------------------------------------------------------------------------------------------------
(In thousands)
LONG-TERM DEBT (Cont.):
Secured notes:
7.250% due 1999 -- 12,000
7.670% due 1999 -- 3,000
7.770% due 1999 -- 17,000
7.850% due 1999 -- 25,000
8.290% due 1999 -- 10,000
9.250% due 1999 -- 52,500
9.300% due 1999 -- 25,000
7.000% due 2000-2009 1,850 1,880
7.190% due 2000 175,000 175,000
7.420% due 2001 10,000 10,000
8.540% due 2001 3,000 3,000
8.550% due 2001 5,000 5,000
8.560% due 2001 3,500 3,500
8.680% due 2001 15,000 15,000
9.050% due 2001 5,000 5,000
9.200% due 2001 15,000 15,000
7.850% due 2002 5,000 5,000
8.130% due 2002 28,000 28,000
7.750% due 2003 15,000 15,000
7.670% due 2004 280,000 280,000
7.130% due 2007 120,000 120,000
7.430% due 2009 150,000 150,000
8.000% due 2013 78,700 78,700
* 3.715% due 2015 39,835 39,835
7.880% due 2017 300,000 300,000
* 3.679% due 2018 72,795 72,795
* 5.350% due 2020 47,500 47,500
6.000% due 2020 62,560 62,560
6.100% due 2020 70,500 70,500
9.520% due 2021 7,500 7,500
6.850% due 2023 30,000 30,000
8.000% due 2023 46,100 73,800
7.625% due 2025 53,900 53,900
7.700% due 2025 43,800 43,800
7.750% due 2025 45,150 45,150
5.375% due 2028 5,993 5,993
4.400% due 2030 23,255 23,255
4.600% due 2030 81,640 81,640
---------- ----------
Total secured notes 1,840,578 2,012,808
---------- ----------
Capital lease obligations (Note 2) 79,204 94,568
---------- ----------
Net unamortized premium on debt 72,533 85,412
---------- ----------
Long-term debt due within one year (207,220) (174,586)
---------- ----------
Total long-term debt 2,682,795 2,888,202
---------- ----------
TOTAL CAPITALIZATION $4,003,982 $4,284,475
========== ==========
<FN>
* Denotes variable rate issue with December 31, 1999 interest rate shown.
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
Comprehensive Other Retained
Income (Loss) Number Carrying Paid-In Earnings
(Note 3B) of Shares Value Capital (Deficit)
------------- ---------- ---------- -------- ---------
(Dollars in thousands)
Balance, January 1, 1997 79,590,689 $1,241,287 $ 79,454 $(276,458)
Net (loss) $(229,247) (229,247)
=========
Equity contributions from parent 4,500
Carrying value adjustments for preferred
stock redemptions 25
Cash dividends on preferred stock (35,848)
Cash dividends on common stock (123,602)
Other, primarily preferred stock
redemption expenses (232)
___________________________________________________________________________________________________________________
Purchase accounting fair value adjustment (309,698) (83,954) 665,387
Net income $ 19,290 19,290
=========
- -------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1997 79,590,689 931,614 -- 19,290
Purchase accounting fair value adjustment 348
Net income $ 164,891 164,891
=========
Cash dividends on preferred stock (21,947)
Cash dividends on common stock (85,958)
- -------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1998 79,590,689 931,962 -- 76,276
Net income $ 194,089 194,089
=========
Cash dividends on preferred stock (36,737)
Cash dividends on common stock (198,974)
- -------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1999 79,590,689 $ 931,962 $ -- $ 34,654
===================================================================================================================
CONSOLIDATED STATEMENTS OF PREFERRED STOCK
Not Subject to Subject to
Mandatory Redemption Mandatory Redemption
-------------------- --------------------
Number Carrying Number Carrying
of Shares Value of Shares Value
--------- -------- --------- --------
(Dollars in thousands)
Balance, January 1, 1997 1,624,000 $238,325 459,572 $215,626
Redemptions-
$ 7.35 Series C (10,000) (1,000)
$88.00 Series E (3,000) (3,000)
$9.125 Series N (150,000) (14,794)
$91.50 Series Q (10,714) (10,714)
_________________________________________________________________________________________________
Purchase accounting fair value
adjustment-
$ 7.35 Series C 110
$88.00 Series R 5,000
$90.00 Series S 6,660
- -------------------------------------------------------------------------------------------------
Balance, December 31, 1997 1,624,000 238,325 285,858 197,888
Redemptions-
$ 7.35 Series C (10,000) (1,000)
$88.00 Series E (3,000) (3,000)
$91.50 Series Q (10,714) (10,714)
- -------------------------------------------------------------------------------------------------
Balance, December 31, 1998 1,624,000 238,325 262,144 183,174
Redemptions-
$ 7.35 Series C (10,000) (1,000)
$88.00 Series E (3,000) (3,000)
$91.50 Series Q (10,714) (10,714)
$90.00 Series S (18,750) (18,750)
- -------------------------------------------------------------------------------------------------
Balance, December 31, 1999 1,624,000 $238,325 219,680 $149,710
=================================================================================================
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
THE CLEVELAND ELECTRIC ILLUMINATING 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) $ 194,089 $ 164,891 $ 19,290 | $ (229,247)
Adjustments to reconcile net income (loss) |
to net cash from operating activities: |
Provision for depreciation and amortization 231,225 234,348 33,438 | 211,827
Nuclear fuel and lease amortization 33,912 35,361 7,393 | 42,577
Other amortization (10,730) (12,677) -- | --
Deferred income taxes, net 33,060 13,031 6,263 | (126,693)
Investment tax credits, net (3,947) (5,185) (822) | (6,670)
Allowance for equity funds used during |
construction -- -- (140) | (1,647)
Extraordinary item -- -- -- | 499,135
Receivables (31,544) (38,527) 51,213 | (3,974)
Materials and supplies 18,818 (8,933) (3,922) | 6,363
Accounts payable 26,525 (10,481) (777) | (7,938)
Other (11,283) (22,772) 18,839 | (2,566)
--------- --------- -------- | ----------
Net cash provided from operating activities 480,125 349,056 130,775 | 381,167
--------- --------- -------- | ----------
CASH FLOWS FROM FINANCING ACTIVITIES: |
New Financing- |
Long-term debt 26,355 232,919 -- | 1,176,781
Ohio Schools Council prepayment program -- 116,598 -- | --
Short-term borrowings, net 22,853 23,816 703 | --
Redemptions and Repayments- |
Preferred stock 33,464 14,714 -- | 29,714
Long-term debt 214,405 488,610 43,500 | 701,843
Short-term borrowings, net -- -- -- | 55,519
Dividend Payments- |
Common stock 198,974 85,958 34,785 | 88,816
Preferred stock 33,524 34,841 7,191 | 29,311
--------- --------- -------- | ----------
Net cash provided from (used for) financing |
activities (431,159) (250,790) (84,773) | 271,578
--------- --------- -------- | ----------
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
Property additions 122,194 72,130 17,943 | 104,230
Loans to associated companies -- 53,509 -- | --
Loan payments from associated companies (53,509) -- -- | --
Capital trust investments (25,905) (31,923) 16,248 | 558,836
Other 25,336 18,799 (4,288) | 2,276
--------- --------- -------- | ----------
Net cash used for investing activities 68,116 112,515 29,903 | 665,342
--------- --------- -------- | ----------
Net increase (decrease) in cash and cash equivalents (19,150) (14,249) 16,099 | (12,597)
Cash and cash equivalents at beginning of period 19,526 33,775 17,676 | 30,273
--------- --------- -------- | ----------
Cash and cash equivalents at end of period $ 376 $ 19,526 $ 33,775 | $ 17,676
========= ========= ======== | ==========
|
SUPPLEMENTAL CASH FLOWS INFORMATION: |
Cash Paid During the Period- |
Interest (net of amounts capitalized) $ 221,360 $ 239,950 $ 35,598 | $ 188,044
========= ========= ======== | ==========
Income taxes $ 92,555 $ 100,107 $ 9,000 | $ 26,300
========= ========= ======== | ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
THE CLEVELAND ELECTRIC ILLUMINATING 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 $ 120,725 $ 130,642 $ 17,707 | $ 114,393
State gross receipts 78,197 78,344 13,302 | 65,966
Social security and unemployment 10,941 9,029 1,548 | 6,296
Other 1,773 3,062 1,355 | 7,745
--------- --------- -------- | ---------
Total general taxes $ 211,636 $ 221,077 $ 33,912 | $ 194,400
========= ========= ======== | =========
|
PROVISION FOR INCOME TAXES: |
Currently payable- |
Federal $ 92,627 $ 90,690 $ 6,969 | $ 37,605
State * 2,129 2,158 159 | --
--------- --------- -------- | ---------
94,756 92,848 7,128 | 37,605
--------- --------- -------- | ---------
Deferred, net- |
Federal 33,369 12,981 6,183 | (126,693)
State * (309) 50 80 | --
--------- --------- -------- | ---------
33,060 13,031 6,263 | (126,693)
--------- --------- -------- | ---------
Investment tax credit amortization (3,947) (5,185) (822) | (6,670)
--------- --------- -------- | ---------
Total provision for income taxes $ 123,869 $ 100,694 $ 12,569 | $ (95,758)
========= ========= ======== | =========
INCOME STATEMENT CLASSIFICATION |
OF PROVISION FOR INCOME TAXES: |
Operating income $ 111,256 $ 88,762 $ 9,229 | $ 75,621
Other income 12,613 11,932 3,340 | 3,318
Extraordinary item -- -- -- | (174,697)
--------- --------- -------- | ---------
Total provision for income taxes $ 123,869 $ 100,694 $ 12,569 | $ (95,758)
========= ========= ======== | =========
|
RECONCILIATION OF FEDERAL INCOME TAX |
EXPENSE AT STATUTORY RATE TO TOTAL |
PROVISION FOR INCOME TAXES: |
Book income before provision for income taxes $ 317,958 $ 265,585 $ 31,859 | $(325,005)
========= ========= ======== | =========
Federal income tax expense at statutory rate $ 111,285 $ 92,955 $ 11,151 | $(113,752)
Increases (reductions) in taxes resulting from- |
Amortization of investment tax credits (3,947) (5,185) (822) | (6,670)
Depreciation -- -- -- | 14,780
Amortization of tax regulatory assets 693 693 238 | --
Amortization of goodwill 13,282 13,447 2,015 | --
Other, net 2,556 (1,216) (13) | 9,884
--------- --------- -------- | ---------
Total provision for income taxes $ 123,869 $ 100,694 $ 12,569 | $ (95,758)
========= ========= ======== | =========
|
ACCUMULATED DEFERRED INCOME TAXES AT |
DECEMBER 31: |
Property basis differences $ 663,294 $ 672,283 $676,853 |
Deferred nuclear expense 128,008 132,818 133,281 |
Deferred sale and leaseback costs (106,611) (113,884) (118,611) |
Unamortized investment tax credits (38,172) (40,241) (42,743) |
Unused alternative minimum tax credits (71,130) (124,459) (133,442) |
Other (7,911) (2,232) (18,901) |
--------- --------- -------- |
Net deferred income tax liability $ 567,478 $ 524,285 $496,437 |
========= ========= ======== |
<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.
<PAGE
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
The consolidated financial statements include The Cleveland
Electric Illuminating Company (Company) and its wholly owned subsidiary,
Centerior Funding Corporation (Centerior Funding). The subsidiary was formed
in 1995 to serve as the transferor in connection with an accounts receivable
securitization completed in 1996. 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 The Toledo Edison Company (TE) 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 northeastern 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 TE sell on a daily basis substantially all of their
retail customer accounts receivable to Centerior Funding 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 become 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 $217 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 $280
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, Ohio Edison Company (OE) and TE - 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
$241 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 $1.9 billion
($1.6 billion, net of deferred income taxes) over the market development
period; its transition costs related to regulatory assets aggregating
approximately $1.9 billion ($1.4 billion, net of deferred income taxes) will
be recovered over the period of 2001 through 2010.
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 $1.71 billion in connection with the
FirstEnergy merger (see Note 7); that fair value adjustment recognized for
financial reporting purposes will ultimately satisfy the $1.4 billion asset
reduction commitment contained in the regulatory plan. For regulatory
purposes, the Company will recognize the $1.4 billion 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
$977 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
2.8% in the post-merger period in 1997.
Annual depreciation expense includes approximately $11.7 million
for future decommissioning costs applicable to the Company's ownership
interests in three nuclear generating units. The Company's future
decommissioning costs reflect the increase in its ownership interests related
to the asset transfer with Duquesne Light Company (Duquesne) discussed below
in "Common Ownership of Generating Facilities." The Company's share of the
future obligation to decommission these units is approximately $606 million
in current dollars and (using a 4.0% escalation rate) approximately $1.6
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 $122 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 $183.3 million invested in external decommissioning trust funds
as of December 31, 1999. This includes additions to the trust funds and the
corresponding liability of $33.5 million as a result of the asset transfer.
Earnings on these funds are reinvested with a corresponding increase to the
decommissioning liability. The Company has also recognized an estimated
liability of approximately $10.3 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, TE, 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 the Company, OE and
Penn. As part of this exchange, the Company transferred the 743-megawatt Avon
Lake Plant to Duquesne. The Company acquired Duquesne's ownership interest in
the Perry Plant, Sammis Unit 7 and Eastlake Unit 5. The Company also
acquired, with OE and Penn, Duquesne's ownership interest in the Bruce
Mansfield Plant. The agreements for the exchange of assets, which was
structured as a like-kind exchange for tax purposes, provides FirstEnergy's
utility operating companies with exclusive ownership and operating control of
all CAPCO generating units. The three FirstEnergy plants transferred are
being sold by Duquesne to a wholly owned subsidiary of Orion Power Holdings,
Inc. (Orion). The Company, OE and Penn will continue to operate those plants
until the assets are transferred to the new owners. Duquesne funded
decommissioning costs equal to its percentage interest in the three nuclear
generating units that were transferred to FirstEnergy. The Duquesne asset
transfer to the Orion subsidiary could take place by the middle of 2000.
Under the agreements, Duquesne is 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)
W. H. Sammis Unit 7 $ 196.7 $114.5 $ 0.7 31.20%
Bruce Mansfield
Units 1, 2 and 3 75.0 30.2 7.2 20.42%
Beaver Valley
Unit 2 343.2 33.3 4.1 24.47%
Davis-Besse 206.6 2.9 4.3 51.38%
Perry 632.2 91.2 8.2 44.85%
- --------------------------------------------------------------------
Total $1,453.7 $272.1 $24.5
====================================================================
The Bruce Mansfield Plant is being leased through a sale and
leaseback transaction (see Note 2) and the above-related amounts represent
construction expenditures subsequent to the transaction.
The Company acquired the remaining 20% share of the Seneca pumped-
storage unit in 1999 from a non-CAPCO Company.
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
$71 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, TE 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 tran-
sition 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 $39.9 million and $47.7 million,
respectively; and the Company's share of the accrued postretirement benefit
liability of $179.0 million and $170.0 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 $ (14.4) $( 2.7) $16.5 | $ (2.5) $22.0 $14.5 $2.6 | $11.4
- ------------------------------------------------------------------------------------------------------------
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 TE 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
TE.
The Company is buying 150 megawatts of TE's Beaver Valley Unit 2
leased capacity entitlement. Purchased power expense for this transaction was
$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 purchase 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 $109.1 million in 1999
and the Service Company billed the Company $80.6 million, $34.1 million and
$130.8 million in 1998, the November 8-December 31, 1997 period and the
January 1-November 7, 1997 period, respectively, for such services.
Fuel and purchased power expenses on the Consolidated Statements
of Income include the cost of power purchased from TE of $106.1 million,
$104.7 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.
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 $6
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 $26.2 million, $32.3 million, $3.2 million
and $12.9 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 $2,738 $2,711 $2,883 $3,120
Preferred stock $ 150 $ 139 $ 183 $ 184
Investments other than cash
and cash equivalents:
Debt securities
- (Maturing in more than
10 years) $ 517 $ 476 $ 543 $ 533
All other 193 200 135 136
- ---------------------------------------------------------------------
$ 710 $ 676 $ 678 $ 669
======================================================================
The carrying value of long-term debt and preferred stock subject to
mandatory redemption were adjusted to fair value in connection with the OE-
Centerior merger and reflect 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 debt 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 $499.1 million ($324.4 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 to 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 $287.1 $298.0
Customer receivables for future income taxes 23.0 13.0
Rate stabilization program deferrals 263.9 276.0
Sale and leaseback costs (136.4) (140.9)
Loss on reacquired debt 75.9 81.6
Other 26.3 28.2
- ----------------------------------------------------------------------
Total $539.8 $555.9
======================================================================
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 TE sold their ownership interests in Bruce
Mansfield Units 1, 2 and 3 and TE 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 TE entered into operating leases for lease terms of
approximately 30 years as co-lessees. During the terms of the leases, the
Company and TE 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
TE have the right, at the end of the respective basic lease terms, to renew
the leases. The Company and TE 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 TE, the Company is also obligated for TE's lease
payments. If TE is unable to make its payments under the Beaver Valley Unit 2
and Bruce Mansfield Plant leases, the Company would be obligated to make such
payments. No such payments have been made on behalf of TE. (TE's future
minimum lease payments as of December 31, 1999 were approximately $1.8
billion.)
Nuclear fuel is currently financed for the Company and TE through
leases with a special-purpose corporation. As of December 31, 1999, $116
million of nuclear fuel ($72 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
and are summarized as follows:
Nov. 8 - Jan. 1 -
1999 1998 Dec. 31, 1997 Nov. 7, 1997
- ----------------------------------------------------------------------
(In millions) |
|
Operating leases |
Interest element $ 38.6 $ 32.4 $10.6 | $ 56.0
Other 30.7 74.4 8.4 | 18.3
Capital leases |
Interest element 6.9 7.0 1.5 | 8.5
Other 41.3 36.1 7.5 | 43.4
- -------------------------------------------------------|-------------
Total rentals $117.5 $149.9 $28.0 | $126.2
=====================================================================
The future minimum lease payments as of December 31, 1999 are:
Operating Leases
-------------------------
Capital Lease Capital
Leases Payments Trust Net
- -----------------------------------------------------------------
(In millions)
2000 $40.4 $ 66.6 $ 60.5 $ 6.1
2001 21.4 71.7 50.2 21.5
2002 13.6 76.4 70.6 5.8
2003 5.0 77.5 77.9 (0.4)
2004 2.8 55.7 28.1 27.6
Years thereafter 8.6 720.5 536.2 184.3
- ----------------------------------------------------------------
Total minimum lease payments 91.8 $1,068.4 $823.5 $244.9
Interest portion 12.6 ======== ====== ======
- ------------------------------------
Present value of net minimum
lease payments 79.2
Less current portion 32.2
- ------------------------------------
Noncurrent portion $47.0
====================================
The Company and TE 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 ($575 million for the Company and $145 million for TE) 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 ($569.4
million for the Company and $337.1 million for TE) in a business trust, in
June 1997. The trust used these funds in July 1997 to purchase lease notes
and redeem all $873.2 million aggregate principal amount of 10-1/4% and 11-
1/8% secured lease obligation bonds (SLOBs) due 2003 and 2016. The SLOBs were
issued by a special-purpose-funding corporation in 1988 on behalf of lessors
in the two companies' 1987 sale and leaseback transaction. The Shippingport
capital trust arrangement effectively reduces lease costs related to that
transaction.
3. CAPITALIZATION:
(A) RETAINED EARNINGS-
There are no restrictions on retained earnings for payment of cash
dividends on the Company's common stock. 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-
The Company's $88.00 Series R preferred stock is not redeemable
before December 2001 and its $90.00 Series S has no optional redemption
provision. All other preferred stock may be redeemed by the Company in whole,
or in part, with 30-90 days' notice.
The preferred dividend rate on the Company's Series L fluctuates
based on prevailing interest rates and market conditions. The dividend rate
for this issue was 7% in 1999.
The Company has 3 million authorized and unissued shares of
preference stock having no par value
A liability of $14 million was included in the Company's net assets
as of the merger date for preferred dividends declared attributable to the
post-merger period. Accordingly, no accrual for preferred stock dividend
requirements was included on the Company's November 8, 1997 to December 31,
1997 Consolidated Statement of Income. This liability was subsequently
reduced to zero in 1998.
(D) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION-
Annual sinking fund provisions for preferred stock are as follows:
Redemption
Price Per
Series Shares Share Date Beginning
- -----------------------------------------------------------------
$ 7.35 C 10,000 $ 100 (i)
88.00 E 3,000 1,000 (i)
91.50 Q 10,714 1,000 (i)
90.00 S 18,750 1,000 (i)
88.00 R 50,000 1,000 December 1 2001
- ----------------------------------------------------------------
<FN>
(i) Sinking fund provisions are in effect.
Annual sinking fund requirements for the next five years are $33.5
million in 2000, $80.5 million in 2001, $18.0 million in 2002 and $1.0
million in each year 2003 and 2004.
(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.
Sinking fund requirements for first mortgage bonds and maturing
long-term debt (excluding capital leases) for the next five years are:
(In millions)
- --------------------------
2000 $175.0
2001 56.5
2002 228.0
2003 115.0
2004 307.7
- ---------------------------
The Company's obligations to repay certain pollution control
revenue bonds are secured by several series of first mortgage bonds. One
pollution control revenue bond is entitled to the benefit of an irrevocable
bank letter of credit of $48.1 million. To the extent that drawings are made
under this letter of credit to pay principal of, or interest on, the
pollution control revenue bond, the Company is entitled to a credit against
its obligation to repay this bond. The Company pays an annual fee of 1.1% of
the amount of the letter of credit to the issuing bank and is obligated to
reimburse the bank for any drawings thereunder.
The Company and TE 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 TE in the proportion of 40% and 60%, 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 TE, with all borrowings
jointly and severally guaranteed by the Company and TE. The credit agreement
is secured with first mortgage bonds of the Company and TE in the proportion
of 40% and 60%, respectively. The credit agreement also provides the
participating banks with a subordinate mortgage security interest in the
properties of the Company and TE. 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 $103.5 million from its
affiliates with a weighted average interest rate of approximately 6.4%.
5. COMMITMENTS AND CONTINGENCIES:
CAPITAL EXPENDITURES-
The Company's current forecast reflects expenditures of
approximately $529 million for property additions and improvements from 2000-
2004, of which approximately $112 million is applicable to 2000. Investments
for additional nuclear fuel during the 2000-2004 period are estimated to be
approximately $166 million, of which approximately $56 million applies to
2000. During the same periods, the Company's nuclear fuel investments are
expected to be reduced by approximately $158 million and $36 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 $106.3
million per incident but not more than $12.1 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 $442.7 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 $13.1 million for incidents
at any covered nuclear facility occurring during a policy year which are in
excess of accumulated funds available to the insurer for paying losses.
The Company intends to maintain insurance against nuclear risks as
described above as long as it is available. To the extent that replacement
power, property damage, decontamination, decommissioning, repair and
replacement costs and other such costs arising from a nuclear incident at any
of the Company's plants exceed the policy limits of the insurance in effect
with respect to that plant, to the extent a nuclear incident is determined
not to be covered by the Company's insurance policies, or to the extent such
insurance becomes unavailable in the future, the Company would remain at risk
for such costs.
ENVIRONMENTAL MATTERS-
Various federal, state and local authorities regulate the Company
with regard to air and water quality and other environmental matters. The
Company estimates additional capital expenditures for environmental
compliance of approximately $84 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 $4.8 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 $418.8 $481.9 $534.5 $429.7
Operating Expenses and Taxes 337.3 375.3 395.6 362.0
- ----------------------------------------------------------------------------
Operating Income 81.5 106.6 138.9 67.7
Other Income (Expense) 6.5 (1.2) 1.3 2.7
Net Interest Charges 53.1 52.8 52.2 51.8
- ----------------------------------------------------------------------------
Net Income $ 34.9 $ 52.6 $ 88.0 $ 18.6
============================================================================
Earnings on Common Stock $ 26.4 $ 44.1 $ 79.7 $ 10.4
============================================================================
March 31, June 30, September 30, December 31,
Three Months Ended 1998 1998 1998 1998
- ----------------------------------------------------------------------------
(In millions)
Operating Revenues $415.0 $474.6 $514.6 $391.8
Operating Expenses and Taxes 324.3 377.8 389.5 321.9
- ----------------------------------------------------------------------------
Operating Income 90.7 96.8 125.1 69.9
Other Income (Expense) 7.6 (3.5) 6.2 1.4
Net Interest Charges 58.7 58.5 56.3 55.9
- ----------------------------------------------------------------------------
Net Income $ 39.6 $ 34.8 $ 75.0 $ 15.4
============================================================================
Earnings on Common Stock $ 38.6 $ 27.4 $ 66.5 $ 7.6
============================================================================
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 $82
million as of December 31, 1999. The merger purchase accounting adjustments
included recognizing estimated severance and other compensation liabilities
($56 million). The amount charged against the liability in 1998 relating to
the costs of involuntary employee separation was $30 million. The liability
was subsequently reduced to approximately $9 million as of December 31, 1998
to represent potential costs associated with the separation of 493 Company
employees. 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 $1,783
Operating Expenses and Taxes 1,418
------
Operating Income 365
Other Income 15
Net Interest Charges 232
------
Net Income $ 148
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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 TE INTO THE COMPANY:
In March 1994, Centerior announced a plan to merge TE into the
Company. 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 TE approved the merger and the
preferred shareholders of the Company 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 Directors of The Cleveland Illuminating
Company:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of The Cleveland Electric Illuminating 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 Cleveland Electric
Illuminating 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