OHIO EDISON COMPANY
SELECTED FINANCIAL DATA
1999 1998 1997 1996 1995
- --------------------------------------------------------------------------------------------------
(In thousands)
Operating Revenues $2,686,949 $2,519,662 $2,473,582 $2,469,785 $2,465,846
------------------------------------------------------------------
Operating Income $ 473,042 $ 486,920 $ 488,568 $ 530,069 $ 566,618
------------------------------------------------------------------
Income Before Extraordinary Item $ 297,689 $ 301,320 $ 293,194 $ 315,170 $ 317,241
------------------------------------------------------------------
Net Income $ 297,689 $ 270,798 $ 293,194 $ 315,170 $ 317,241
------------------------------------------------------------------
Earnings on Common Stock $ 286,142 $ 258,828 $ 280,802 $ 302,673 $ 294,747
------------------------------------------------------------------
Total Assets $8,700,746 $8,923,826 $9,158,141 $9,218,623 $9,035,112
------------------------------------------------------------------
Capitalization at December 31:
Common Stockholder's Equity $2,624,460 $2,681,873 $2,724,319 $2,503,359 $2,407,871
Preferred Stock:
Not Subject to Mandatory
Redemption 200,070 211,870 211,870 211,870 211,870
Subject to Mandatory
Redemption 140,000 145,000 150,000 155,000 160,000
Long-Term Debt 2,175,812 2,215,042 2,569,802 2,712,760 2,786,256
------------------------------------------------------------------
Total Capitalization $5,140,342 $5,253,785 $5,655,991 $5,582,989 $5,565,997
------------------------------------------------------------------
Capitalization Ratios:
Common Stockholder's Equity 51.1% 51.0% 48.2% 44.8% 43.3%
Preferred Stock:
Not Subject to Mandatory
Redemption 3.9 4.0 3.7 3.8 3.8
Subject to Mandatory
Redemption 2.7 2.8 2.7 2.8 2.9
Long-Term Debt 42.3 42.2 45.4 48.6 50.0
------------------------------------------------------------------
Total Capitalization 100.0% 100.0% 100.0% 100.0% 100.0%
------------------------------------------------------------------
Kilowatt-Hour Sales (Millions):
Residential 9,483 8,773 8,631 8,704 8,546
Commercial 8,238 7,590 7,335 7,246 7,151
Industrial 11,310 10,803 11,202 11,089 10,513
Other 151 150 150 147 146
------------------------------------------------------------------
Total Retail 29,182 27,316 27,318 27,186 26,356
Total Wholesale 6,881 5,706 5,241 7,076 6,920
------------------------------------------------------------------
Total 36,063 33,022 32,559 34,262 33,276
------------------------------------------------------------------
Customers Served:
Residential 1,016,793 1,004,552 995,605 988,179 978,118
Commercial 115,581 113,820 111,189 113,795 111,978
Industrial 4,627 4,598 4,568 4,590 4,268
Other 1,539 1,476 1,415 1,331 1,308
------------------------------------------------------------------
Total 1,138,540 1,124,446 1,112,777 1,107,895 1,095,672
------------------------------------------------------------------
Number of Employees 2,734 2,832 4,215 4,273 4,812
OHIO EDISON COMPANY
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
RESULTS OF OPERATIONS
Operating revenues increased by $167.3 million in 1999 following a
$46.1 million increase in 1998. This represents the fifth consecutive year of
record operating revenues. The sources of the increases in operating revenues
during 1999 and 1998 are summarized in the following table.
Sources of Revenue Changes 1999 1998
- ------------------------------------------------------------
(In millions)
Change in retail kilowatt-hour sales 151.3 (0.1)
Change in average retail price $(36.3) $27.0
Increase in wholesale sales 54.6 13.3
Other (2.3) 5.9
- -------------------------------------------------------------
Net Increase in Operating Revenues $167.3 $46.1
=============================================================
Electric Sales
Operating revenues increased in 1999 from 1998 as a result of
kilowatt-hour sales growth in both the 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 increase sales to wholesale
customers.
After setting a new record in 1997, total retail kilowatt-hour
sales in 1998 were about the same as 1997. Residential and commercial sales
benefited from continued growth in the retail customer base. The closure of
an electric arc furnace by a large steel customer in the latter part of 1997
and a general decline in electricity demand by steel manufacturers due to
intense foreign competition contributed to the lower industrial sales in
1998, compared to the prior year. Changes in kilowatt-hour sales by customer
class in 1999 and 1998 are summarized in the following table.
Changes in KWH Sales 1999 1998
- -----------------------------------------------------
Residential 8.1% 1.7%
Commercial 8.6% 3.5%
Industrial 4.7% (3.6%)
- ------------------------------------------------------
Total Retail 6.8% --
Wholesale 20.6% 8.9%
- ------------------------------------------------------
Total Sales 9.2% 1.4%
- ------------------------------------------------------
Operating Expenses and Taxes
Total operating expense and taxes increased $181.2 million in 1999,
compared to 1998, primarily due to additional depreciation and amortization.
Higher operation and maintenance costs also contributed to the increase. In
1998, total operating expenses and taxes increased $47.7 million due
primarily to unusually high purchased power costs.
The increase in operation and maintenance costs in 1999 from 1998
occurred despite a reduction in fuel and purchased power costs, which were
$35.9 million lower than the previous year. Purchased power costs accounted
for all of the reduction in 1999. 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 Units 1 and 2 at the same time required us to
purchase significant amounts of power on the spot market. Although above
normal temperatures were also experienced in 1999, we maintained a stronger
capacity position compared to the previous year and better met customer
demand from our own internal generation. In 1998, fuel and purchased power
increased $74.4 million from 1997 for the reasons discussed above.
Nuclear operating costs increased in 1999, compared to 1998, for
several reasons. Refueling outages at Beaver Valley Unit 2 and the Perry
Plant, as well as increased ownership of the Beaver Valley Plant following
the Duquesne Light Company (Duquesne) asset swap in early December 1999
(including nonrecurring swap-related liabilities assumed) increased 1999
nuclear operating expenses compared to 1998. Nuclear operating costs
increased in 1998 reflecting higher costs at the Beaver Valley Plant. Other
operating costs also rose in 1999 from the prior year primarily due to higher
customer and sales expenses including expenditures for energy marketing
programs, information system requirements and other customer-related costs,
as well as higher distribution costs from storm repairs and overhead line
maintenance. Offsetting a portion of the increase in other operating costs
were lower nonnuclear production costs from the Sammis generating plant.
Other operating costs decreased in 1998 from the previous year due
principally to the absence of expenses related to a 1997 voluntary retirement
program and estimated severance costs which increased other operating costs
for that year.
Accelerated cost recovery in connection with our rate plan was the
primary factor contributing $160.6 million of the increase in depreciation
and amortization in 1999, compared to the prior year. In 1998, depreciation
and amortization decreased $14.2 million from 1997 primarily due to the net
effect of the Ohio Edison Company (OE) and Pennsylvania Power Company (Penn)
rate plans. In 1998, general taxes increased from the prior year in part
because of gross receipts taxes on increased operating revenues.
Net Interest Charges
Net interest charges continued to trend downward in 1999 and 1998
primarily due to redemptions and refinancings of long-term debt.
Extraordinary Item
The Pennsylvania Public Utility Commission's (PPUC) authorization
of Penn's rate restructuring plan led to the discontinued application of
Statement of Financial Accounting Standards No. 71 (SFAS 71), "Accounting for
the Effects of Certain Types of Regulation," to Penn's generation business in
1998. This resulted in an after-tax write-down in 1998 of $30.5 million of
its nuclear generating unit investment and the recognition of a portion of
such investment -- recoverable through future customer rates -- as a
regulatory asset.
Earnings on Common Stock
Earnings on common stock increased to $286.1 million in 1999 from
$258.8 million in 1998. Results for 1999 were favorably affected by higher
sales revenues, the absence of the 1998 extraordinary charge and unusually
high purchased power costs experienced in 1998 and lower interest costs that
were principally offset by an increase in depreciation and amortization
expense. The decrease to $258.8 million experienced in 1998 from $280.8
million in 1997 was due in large part to the extraordinary charge in 1998
resulting from the discontinued application of SFAS 71 to Penn's generation
business discussed above.
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.
Our improving financial position reflects ongoing efforts to
increase competitiveness and enhance shareholder value. We have continued to
strengthen our financial position over the past five years by improving our
fixed charge coverage ratios. Our corporate indenture ratio, which is used to
measure our ability to issue first mortgage bonds, increased from 5.34 in
1994 to 6.89 in 1999, which enhances our financial flexibility. Over the same
period, our charter ratio, a measure of our ability to issue preferred stock,
improved from 2.11 to 2.62 and our common stockholder's equity as a
percentage of capitalization rose from approximately 40% at the end of 1994
to 51% at the end of 1999. Net redemptions of long-term debt and preferred
stock totaled $245.3 million, including $18.3 million of optional redemptions
in 1999. In addition, we completed $240.9 million of refinancings. Over the
last five years, we have reduced the average cost of long-term debt from
8.17% in 1994 to 7.22% at the end of 1999.
We had about $87.2 million of cash and temporary investments and
$358.3 million of short-term indebtedness as of December 31, 1999. Our unused
borrowing capability included $76.5 million under revolving lines of credit
and a $7.0 million bank facility that provides for borrowings on a short-term
basis at the bank's discretion. At the end of 1999, we had the capability to
issue $1.1 billion of additional first mortgage bonds on the basis of
property additions and retired bonds. Based upon applicable earnings coverage
tests and our respective charters, we could issue $1.3 billion of preferred
stock (assuming no additional debt were issued).
Our cash requirements in 2000 for operating expenses, construction
expenditures, scheduled debt maturities and preferred stock redemptions are
expected to be met without issuing new securities. During 1999, we reduced
our total debt by approximately $125 million. We have cash requirements of
approximately $1.2 billion for the 2000-2004 period to meet scheduled
maturities of long-term debt and preferred stock. Of that amount,
approximately $206 million relates to 2000.
Our capital spending for the period 2000-2004 is expected to be
about $1.0 billion (excluding nuclear fuel), of which approximately $251
million applies to 2000. Investments for additional nuclear fuel during the
2000-2004 period are estimated to be approximately $218 million, of which
about $65 million relates to 2000. During the same periods, our nuclear fuel
investments are expected to be reduced by approximately $215 million and $46
million, respectively, as the nuclear fuel is consumed. Also, we have
operating lease commitments, net of PNBV Capital Trust cash receipts, of
approximately $358 million for the 2000-2004 period, of which approximately
$71 million relates to 2000.
On December 3, 1999, we completed the exchange of generating assets
between Duquesne and FirstEnergy, which increased FirstEnergy's portfolio of
generation resources. 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 Beaver Valley Plant, and an additional interest in the Bruce
Mansfield Plant while providing Duquesne with our ownership interest in the
New Castle and Niles generating plants.
At the end of 1999, Penn transferred its interest in Penn Power
Energy, Inc., a wholly owned subsidiary selling energy in Pennsylvania's
unregulated generation market, to FirstEnergy Services Corp., an affiliated
company. For FirstEnergy, the transaction centralized unregulated electricity
sales and marketing activities in one entity.
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 PNBV 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 $ 17 $ 23 $ 26 $ 30 $305 $511 $ 912 $ 922
Average interest rate 7.3% 7.6% 7.8% 7.9% 7.8% 7.8% 7.8%
- ---------------------------------------------------------------------------------------------------------
Liabilities
- ---------------------------------------------------------------------------------------------------------
Long-term Debt:
Fixed rate $201 $ 17 $327 $246 $ 95 $839 $1.725 $1,710
Average interest rate 7.0% 8.0% 7.8% 8.2% 7.3% 7.1% 7.4%
Variable rate $190 $568 $ 758 $ 749
Average interest rate 7.5% 4.3% 5.1%
Short-term Borrowings $358 $ 358 $ 358
Average interest rate 6.3% 6.3%
- ---------------------------------------------------------------------------------------------------------
Preferred Stock $ 5 $ 5 $ 1 $ 1 $ 1 $132 $ 145 $ 142
Average dividend rate 8.5% 8.5% 7.6% 7.6% 7.6% 8.9% 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. Retail
wheeling, which began in 1999 in our Pennsylvania service area, allows retail
customers to purchase electricity from alternative energy suppliers. Recent
legislation provides for similar changes beginning in 2001 in Ohio. Our
existing Ohio regulatory plan provides us with a solid foundation to meet the
challenges we are facing by significantly reducing fixed costs and lowering
rates to a more competitive level. Our Rate Reduction and Economic
Development Plan, approved by the PUCO in 1995, provides for accelerated
capital recovery and interim rate credits to customers during the period
covered by the plan. The transition plan ultimately approved by the Public
Utilities Commission of Ohio (PUCO) will supersede our current Ohio rate
plan; however, rate reductions under the existing regulatory plan will
continue.
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 refiled a transition plan on our behalf, as well as for
its other Ohio electric utility operating companies -- The Cleveland Electric
Illuminating Company (CEI) 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 $422 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.
Customer 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 $1.8 billion ($1.6 billion, net of deferred
income taxes) over the market development period; transition costs related to
regulatory assets aggregating approximately $1.5 billion ($1.0 billion, net
of deferred income taxes) are expected to be recovered over the period 2001
through 2004.
When the transition plan is approved by the PUCO, the application
of SFAS 71 to our Ohio generation business will be discontinued. In the
meantime, we will continue to bill and collect cost-based rates in Ohio
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.
For Penn, application of SFAS 71 was discontinued for the
generation portion of its business in 1998 following PPUC approval of its
restructuring plan. Under the plan, a phase-in period for customer choice
began with 66% of Penn's customers able to select their energy supplier
beginning January 2, 1999, and all remaining customers able to select their
energy providers starting January 1, 2001. Penn is entitled to recover $236
million of stranded costs through a competitive transition charge that
started in 1999 and ends in 2006.
In the second half of 1999, we received notification of pending
legal actions based on alleged violations of the Clean Air Act at our Sammis
Plant involving the states of New York and Connecticut, as well as the U.S.
Department of Justice. The civil complaint filed by the U.S. Department of
Justice requests installation of "best available control technology" as well
as civil penalties of up to $27,500 per day. We believe the Sammis Plant is
in full compliance with the Clean Air Act and the legal actions to be without
merit. However, we are unable to predict the outcome of this litigation.
Penalties could be imposed if the Sammis Plant continues to operate without
correcting the alleged violations and a court determines that the allegations
are valid. We expect the Sammis Plant to continue to operate while the matter
is being decided.
On October 27, 1999, the Federal Energy Regulatory Commission
(FERC) approved FirstEnergy's plan to transfer our transmission assets and
those of CEI and TE to American Transmission Systems Inc. (ATSI). The PUCO
approved the transfer in February 2000. PPUC and Securities and Exchange
Commission regulatory approvals are also required. The new FirstEnergy
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, PUCO and PPUC 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 $41.4 million on Year
2000 related costs through December 31, 1999, which was slightly lower than
previously estimated. Of this total, $32.9 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 $8.5 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.
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 1999 1998 1997
- ------------------------------------------------------------------------------------------
(In thousands)
OPERATING REVENUES $2,686,949 $2,519,662 $2,473,582
---------- ---------- ----------
OPERATING EXPENSES AND TAXES:
Fuel and purchased power 475,792 511,645 437,223
Nuclear operating costs 312,289 279,917 267,681
Other operating costs 432,476 411,985 446,778
---------- ---------- ----------
Total operation and maintenance expenses 1,220,557 1,203,547 1,151,682
Provision for depreciation and amortization 582,197 411,979 426,205
General taxes 240,281 242,524 234,964
Income taxes 170,872 174,692 172,163
---------- ---------- ----------
Total operating expenses and taxes 2,213,907 2,032,742 1,985,014
---------- ---------- ----------
OPERATING INCOME 473,042 486,920 488,568
OTHER INCOME 45,846 47,621 52,847
---------- ---------- ----------
INCOME BEFORE NET INTEREST CHARGES 518,888 534,541 541,415
---------- ---------- ----------
NET INTEREST CHARGES:
Interest on long-term debt 178,217 184,915 204,285
Allowance for borrowed funds used during
construction and capitalized interest (4,159) (2,096) (2,699)
Other interest expense 31,971 34,976 31,209
Subsidiaries' preferred stock dividend
requirements 15,170 15,426 15,426
---------- ---------- ----------
Net interest charges 221,199 233,221 248,221
---------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM 297,689 301,320 293,194
EXTRAORDINARY ITEM (NET OF INCOME TAXES)
(Note 1) -- (30,522) --
---------- ---------- ----------
NET INCOME 297,689 270,798 293,194
PREFERRED STOCK DIVIDEND REQUIREMENTS 11,547 11,970 12,392
---------- ---------- ----------
EARNINGS ON COMMON STOCK $ 286,142 $ 258,828 $ 280,802
========== ========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
At December 31, 1999 1998
- ------------------------------------------------------------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service $8,118,783 $8,158,763
Less-Accumulated provision for depreciation 3,713,781 3,610,155
---------- ----------
4,405,002 4,548,608
---------- ----------
Construction work in progress-
Electric plant 205,671 174,418
Nuclear Fuel 10,059 17,003
---------- ----------
215,730 191,421
---------- ----------
4,620,732 4,740,029
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
PNBV Capital Trust (Note 2) 469,124 475,087
Letter of credit collateralization (Note 2) 277,763 277,763
Nuclear plant decommissioning trusts 236,903 130,572
Other (Note 3B) 425,872 407,839
---------- ----------
1,409,662 1,291,261
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents 87,175 33,213
Receivables-
Customers (less accumulated provisions of $6,452,000
and $6,397,000, respectively, for uncollectible
accounts) 278,484 215,257
Associated companies 221,653 229,854
Other (less accumulated provision of $1,000,000
for uncollectible accounts in 1999) 36,281 47,684
Materials and supplies, at average cost-
Owned 69,119 76,756
Under consignment 55,278 48,341
Prepayments and other 73,682 78,618
---------- ----------
821,672 729,723
---------- ----------
DEFERRED CHARGES:
Regulatory assets 1,618,319 1,913,808
Property taxes 100,906 101,360
Unamortized sale and leaseback costs 85,100 90,098
Other 44,355 57,547
---------- ----------
1,848,680 2,162,813
---------- ----------
$8,700,746 $8,923,826
========== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements of
Capitalization):
Common stockholder's equity $2,624,460 $2,681,873
Preferred stock-
Not subject to mandatory redemption 160,965 160,965
Subject to mandatory redemption 5,000 10,000
Preferred stock of consolidated subsidiary-
Not subject to mandatory redemption 39,105 50,905
Subject to mandatory redemption 15,000 15,000
Company obligated mandatorily redeemable preferred
securities of subsidiary trust holding solely
Company subordinated debentures 120,000 120,000
Long-term debt 2,175,812 2,215,042
---------- ----------
5,140,342 5,253,785
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock 422,838 528,792
Short-term borrowings (Note 4)-
Associated companies 35,583 88,732
Other 322,713 249,451
Accounts payable 114,102 99,659
Accrued taxes 207,362 188,295
Accrued interest 37,572 45,221
Other 94,967 114,162
---------- ----------
1,235,137 1,314,312
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes 1,468,478 1,601,887
Accumulated deferred investment tax credits 143,336 154,538
Nuclear plant decommissioning costs 239,695 132,349
Other postretirement benefits 148,421 136,856
Other 325,337 330,099
---------- ----------
2,325,267 2,355,729
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES
(Notes 2 and 5) ---------- ----------
$8,700,746 $8,923,826
========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 1999 1998
- -----------------------------------------------------------------------------------------------------------------------------
(Dollars in thousands, except per share amounts)
COMMON STOCKHOLDER'S EQUITY:
Common stock, $9 par value, authorized 175,000,000 shares-100 shares outstanding $ 1 $ 1
Other paid-in capital 2,098,728 2,098,728
Retained earnings (Note 3A) 525,731 583,144
---------- ----------
Total common stockholder's equity 2,624,460 2,681,873
---------- ----------
Number of Shares Optional
Outstanding Redemption Price
----------------------- -----------------------
1999 1998 Per Share Aggregate
---- ---- ---------- ----------
PREFERRED STOCK (Note 3D):
Cumulative, $100 par value-
Authorized 6,000,000 shares
Not Subject to Mandatory Redemption:
3.90% 152,510 152,510 $103.63 $ 15,804 15,251 15,251
4.40% 176,280 176,280 108.00 19,038 17,628 17,628
4.44% 136,560 136,560 103.50 14,134 13,656 13,656
4.56% 144,300 144,300 103.38 14,917 14,430 14,430
--------- --------- -------- ---------- ----------
609,650 609,650 63,893 60,965 60,965
--------- --------- -------- ---------- ----------
Cumulative, $25 par value-
Authorized 8,000,000 shares
Not Subject to Mandatory Redemption:
7.75% 4,000,000 4,000,000 25.00 100,000 100,000 100,000
--------- --------- -------- ---------- ----------
Total Not Subject to Mandatory
Redemption 4,609,650 4,609,650 $163,893 160,965 160,965
========= ========= ======== ---------- ----------
Cumulative, $100 par value-
Subject to Mandatory Redemption
(Note 3E):
8.45% 100,000 150,000 10,000 15,000
Redemption Within One Year (5,000) (5,000)
--------- --------- ---------- ----------
Total Subject to
Mandatory Redemption 100,000 150,000 5,000 10,000
========= ========= ---------- ----------
PREFERRED STOCK OF CONSOLIDATED
SUBSIDIARY (Note 3D):
Pennsylvania Power Company-
Cumulative, $100 par value-
Authorized 1,200,000 shares
Not Subject to Mandatory Redemption:
4.24% 40,000 40,000 $103.13 $ 4,125 4,000 4,000
4.25% 41,049 41,049 105.00 4,310 4,105 4,105
4.64% 60,000 60,000 102.98 6,179 6,000 6,000
7.64% -- 60,000 -- -- -- 6,000
7.75% 250,000 250,000 -- -- 25,000 25,000
8.00% -- 58,000 -- -- -- 5,800
--------- --------- -------- ---------- ----------
Total Not Subject to Mandatory
Redemption 391,049 509,049 $ 14,614 39,105 50,905
========= ========= ======== ---------- ----------
Subject to Mandatory Redemption
(Note 3E):
7.625% 150,000 150,000 106.10 $ 15,915 15,000 15,000
========= ========= ======== ---------- ----------
COMPANY OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF SUBSIDIARY TRUST
HOLDING SOLELY COMPANY SUBORDINATED
DEBENTURES (Note 3F):
Cumulative, $25 par value-
Authorized 4,800,000 shares
Subject to Mandatory Redemption:
9.00% 4,800,000 4,800,000 120,000 120,000
========= ========= ---------- ----------
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont.)
At December 31, 1999 1998 1999 1998 1999 1998
- ---------------------------------------------------------------------------------------------------------------------------
(In thousands)
LONG-TERM DEBT (Note 3G):
First mortgage bonds:
Ohio Edison Company- Pennsylvania Power Company-
6.875% due 1999 -- 150,000 9.740% due 2000-2019 19,513 20,000
6.375% due 2000 80,000 80,000 7.500% due 2003 40,000 40,000
7.375% due 2002 120,000 120,000 6.375% due 2004 20,500 20,500
7.500% due 2002 34,265 34,265 6.625% due 2004 14,000 14,000
8.250% due 2002 125,000 125,000 8.500% due 2022 27,250 27,250
8.625% due 2003 150,000 150,000 7.625% due 2023 6,500 6,500
6.875% due 2005 80,000 80,000 ------- -------
8.750% due 2022 50,960 50,960
7.625% due 2023 75,000 75,000
7.875% due 2023 93,500 100,000
------- -------
Total first mortgage bonds. 808,725 965,225 127,763 128,250 936,488 1,093,475
------- ------- ------- ------- ---------- ----------
Secured notes:
Ohio Edison Company- Pennsylvania Power Company-
7.450% due 2000 47,725 47,725 6.080% due 2000 23,000 23,000
8.100% due 2000 30,000 30,000 8.100% due 2000 5,200 5,200
7.930% due 2002 28,386 39,936 5.400% due 2013 1,000 1,000
7.680% due 2005 200,000 200,000 5.400% due 2017 10,600 10,600
6.750% due 2015 40,000 40,000 7.150% due 2017 17,925 17,925
7.100% due 2018 26,000 26,000 5.900% due 2018 16,800 16,800
7.050% due 2020 60,000 60,000 7.150% due 2021 14,482 14,482
7.000% due 2021 69,500 69,500 6.150% due 2023 12,700 12,700
7.150% due 2021 443 443 * 5.450% due 2027 10,300 10,300
7.625% due 2023 -- 50,000 6.450% due 2027 14,500 14,500
7.750% due 2024 -- 108,000 5.375% due 2028 1,734 1,734
5.375% due 2028 13,522 13,522 5.450% due 2028 6,950 6,950
5.625% due 2029 50,000 50,000 6.000% due 2028 14,250 14,250
5.950% due 2029 56,212 56,212 5.950% due 2029 238 238
5.450% due 2033 14,800 14,800 ------- -------
Limited Partnerships-
7.59% weighted average
interest rate due
2000-2007 12,574 11,320
------- -------
649,162 817,458 149,679 149,679 798,841 967,137
------- ------- ------- ------- ---------- ----------
OES Fuel-
6.85% weighted average
interest rate 81,260 79,524
---------- ----------
Total secured notes 880,101 1,046,661
---------- ----------
Unsecured notes:
Ohio Edison Company- Pennsylvania Power Company-
*5.963% due 1999 -- 115,000 *5.900% due 2033 5,200 --
*6.025% due 1999 -- 85,000 ------- -------
*6.088% due 1999 -- 50,000
*7.300% due 2002 140,000 --
*8.113% due 2002 50,000 --
*4.300% due 2012 50,000 50,000
*3.950% due 2014 50,000 50,000
*2.950% due 2015 50,000 50,000
*5.800% due 2016 47,725 --
*4.200% due 2018 57,100 57,100
*3.750% due 2018 56,000 56,000
*3.100% due 2032 53,400 53,400
*4.250% due 2033 50,000 --
*4.650% due 2033 108,000 --
*5.400% due 2033 30,000 --
------- -------
Total unsecured notes 742,225 566,500 5,200 -- 747,425 566,500
------- ------- ------- ------- ---------- ----------
Capital lease obligations
(Note 2) 33,852 36,891
---------- ----------
Net unamortized discount on debt (4,216) (4,693)
---------- ----------
Long-term debt due within one year (417,838) (523,792)
---------- ----------
Total long-term debt 2,175,812 2,215,042
---------- ----------
TOTAL CAPITALIZATION $5,140,342 $5,253,785
========== ==========
<FN>
* Denotes variable rate issue with December 31, 1999 interest rate shown for only December 31, 1999
balances and December 31, 1998 interest rate shown for only December 31, 1998 balances.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
Accumulated
Other Unallocated
Comprehensive Other Comprehensive ESOP
Income Number Par Paid-In Income Retained Common
(Note 3C) of Shares Value Capital (Note 3C) Earnings Stock
------------- --------- ----- -------- ------------- -------- -----------
(Dollars in thousands)
Balance, January 1, 1997 152,569,437 $1,373,125 $ 728,261 $(659) $ 557,642 $(155,010)
Net income $293,194 293,194
Minimum liability for unfunded
retirement benefits, net of
$26,000 of income taxes 44 44
--------
Comprehensive income $293,238
========
FirstEnergy merger (152,569,337) (1,373,124) 1,373,124 146,977
Allocation of ESOP shares 1,874 8,033
Cash dividends on preferred
stock (12,392)
Cash dividends on common stock (216,770)
- ------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1997 100 1 2,103,259 (615) 621,674 --
Net income $270,798 270,798
Transfer of minimum liability
for unfunded retirement
benefits to parent 615 615
--------
Comprehensive income $271,413
========
Transfer of ESOP premium to
parent (4,531)
Cash dividends on preferred
stock (11,952)
Cash dividends on common stock (297,376)
- ------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1998 100 1 2,098,728 -- 583,144 --
Net income $297,689 297,689
========
Transfer of Penn Power
Energy to FirstEnergy
Services Corp. 3,302
Cash dividends on preferred stock (11,401)
Cash dividends on common stock (347,003)
- -------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1999 100 $ 1 $2,098,728 $ -- $ 525,731 $ --
================================================================================================================================
CONSOLIDATED STATEMENTS OF PREFERRED STOCK
Not Subject to Subject to
Mandatory Redemption Mandatory Redemption
-------------------- --------------------
Par or Par or
Number Stated Number Stated
of Shares Value of Shares Value
--------- -------- --------- --------
(Dollars in thousands)
Balance, January 1, 1997 5,118,699 $211,870 5,200,000 $160,000
Redemptions-
8.45% Series (50,000) (5,000)
- ---------------------------------------------------------------------------------
Balance, December 31, 1997 5,118,699 211,870 5,150,000 155,000
Redemptions-
8.45% Series (50,000) (5,000)
- ---------------------------------------------------------------------------------
Balance, December 31, 1998 5,118,699 211,870 5,100,000 150,000
Redemptions-
7.64% Series (60,000) (6,000)
8.00% Series (58,000) (5,800)
8.45% Series (50,000) (5,000)
- ----------------------------------------------------------------------------------
Balance, December 31, 1999 5,000,699 $200,070 5,050,000 $145,000
===================================================================================
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1999 1998 1997
- -----------------------------------------------------------------------------------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income $297,689 $270,798 $293,194
Adjustments to reconcile net income to net
cash from operating activities:
Provision for depreciation and amortization 582,197 411,979 426,205
Nuclear fuel and lease amortization 45,850 35,086 49,251
Deferred income taxes, net (120,149) (55,817) (36,741)
Investment tax credits, net (13,793) (14,290) (15,031)
Extraordinary item -- 51,730 --
Receivables (43,623) (144,549) (23,887)
Materials and supplies 18,257 (1,627) (10,557)
Accounts payable 14,443 (8,455) 32,531
Other 14,442 64,552 21,755
-------- -------- --------
Net cash provided from operating activities 795,313 609,407 736,720
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt 242,601 117,265 89,773
Short-term borrowings, net 20,113 35,954 --
Redemptions and Repayments-
Preferred stock 17,005 5,000 5,000
Long-term debt 396,410 225,241 292,409
Short-term borrowings, net -- -- 47,251
Dividend Payments-
Common stock 347,003 297,746 237,848
Preferred stock 11,512 11,865 12,559
-------- -------- --------
Net cash used for financing activities 509,216 386,633 505,294
-------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions 237,199 186,139 179,328
Other (5,064) 8,102 52,671
-------- -------- --------
Net cash used for investing activities 232,135 194,241 231,999
-------- -------- --------
Net increase (decrease) in cash and cash equivalents 53,962 28,533 (573)
Cash and cash equivalents at beginning of year 33,213 4,680 5,253
-------- -------- --------
Cash and cash equivalents at end of year $ 87,175 $ 33,213 $ 4,680
======== ======== ========
SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized) $203,749 $201,064 $212,987
======== ======== ========
Income taxes $308,052 $219,226 $228,399
======== ======== ========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF TAXES
For the Years Ended December 31, 1999 1998 1997
- ----------------------------------------------------------------------------------------------------
(In thousands)
GENERAL TAXES:
Real and personal property $ 111,222 $ 116,868 $ 114,111
State gross receipts 106,926 104,175 99,262
Social security and unemployment 14,432 12,701 14,113
Other 7,701 8,780 7,478
---------- ---------- ----------
Total general taxes $ 240,281 $ 242,524 $ 234,964
========== ========== ==========
PROVISION FOR INCOME TAXES:
Currently payable-
Federal $ 307,462 $ 229,164 $ 225,529
State 18,315 14,732 17,784
---------- ---------- ----------
325,777 243,896 243,313
---------- ---------- ----------
Deferred, net-
Federal (113,347) (50,310) (30,791)
State (6,802) (5,507) (5,950)
---------- ---------- ----------
(120,149) (55,817) (36,741)
---------- ---------- ----------
Investment tax credit amortization (13,793) (14,290) (15,031)
---------- ---------- ----------
Total provision for income taxes $ 191,835 $ 173,789 $ 191,541
========== ========== ==========
INCOME STATEMENT CLASSIFICATION
OF PROVISION FOR INCOME TAXES:
Operating income $ 170,872 $ 174,692 $ 172,163
Other income 20,963 20,305 19,378
Extraordinary item -- (21,208) --
---------- ---------- ----------
Total provision for income taxes $ 191,835 $ 173,789 $ 191,541
========== ========== ==========
RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT
STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES:
Book income before provision for income taxes $ 489,524 $ 444,587 $ 484,735
========== ========== ==========
Federal income tax expense at statutory rate $ 171,333 $ 155,605 $ 169,657
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits (13,793) (14,290) (15,031)
State income taxes, net of federal income tax
benefit 7,483 5,996 7,692
Amortization of tax regulatory assets 24,950 29,961 30,642
Other, net 1,862 (3,483) (1,419)
---------- ---------- ----------
Total provision for income taxes $ 191,835 $ 173,789 $ 191,541
========== ========== ==========
ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31:
Property basis differences $ 847,479 $ 880,645 $1,019,952
Allowance for equity funds used during construction 152,846 169,780 210,136
Deferred nuclear expense 229,366 237,602 252,946
Competitive transition charge 115,277 135,730 --
Customer receivables for future income taxes 163,500 164,618 204,643
Deferred sale and leaseback costs (26,966) 45,521 47,796
Unamortized investment tax credits (51,521) (55,495) (67,208)
Other 38,497 23,486 30,089
---------- ---------- ----------
Net deferred income tax liability $1,468,478 $1,601,887 $1,698,354
========== ========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
The consolidated financial statements include Ohio Edison Company
(Company), and its wholly owned subsidiaries. Pennsylvania Power Company
(Penn) is the Company's principal operating subsidiary. All significant
intercompany transactions have been eliminated. The Company became a wholly
owned subsidiary of FirstEnergy Corp. (FirstEnergy) on November 8, 1997.
FirstEnergy was formed on that date by the merger of the Company and
Centerior Energy Corporation (Centerior). FirstEnergy holds directly all of
the issued and outstanding common shares of the Company and all of the issued
and outstanding common shares of Centerior's former direct subsidiaries,
which include, among others, The Cleveland Electric Illuminating Company
(CEI) and The Toledo Edison Company (TE). The Company and Penn (Companies)
follow the accounting policies and practices prescribed by the Public
Utilities Commission of Ohio (PUCO), the Pennsylvania Public Utility
Commission (PPUC) 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 Companies' principal business is providing electric service to
customers in central and northeastern Ohio and western Pennsylvania. The
Companies' 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 Companies' 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
Companies' customers.
REGULATORY PLANS-
The PUCO approved the Company's Rate Reduction and Economic
Development Plan in 1995. This 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 $300
million (approximately 20 percent below current levels). The 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 separate energy rates. In accordance with the regulatory
plan, the Company's fuel rates will be frozen through the regulatory plan
period, subject to limited periodic adjustments. As part of the Company's
regulatory plan, transition rate credits were implemented for customers,
which are expected to reduce operating revenues for the Company by
approximately $600 million.
In July 1999, Ohio's new electric utility restructuring legislation
which will allow Ohio electric customers to select their generation suppliers
beginning January 1, 2001, was signed into law. Among other things, the new
law provides for a five percent reduction on the generation portion of
residential customers' bills and the opportunity to recover transition costs,
including regulatory assets, from January 1, 2001 through December 31, 2005.
The period for the recovery of regulatory assets only can be extended up to
December 31, 2010. The PUCO was authorized to determine the level of
transition cost recovery, as well as the recovery period for the regulatory
assets portion of those costs, in considering each Ohio electric utility's
transition plan application.
FirstEnergy, on behalf of its Ohio electric utility operating
companies - the Company, CEI and 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
$422 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 $1.8 billion
($1.6 billion, net of deferred income taxes) over the market development
period; its transition costs related to regulatory assets aggregating
approximately $1.5 billion ($1.0 billion, net of deferred income taxes) will
be recovered over the period of 2001 through 2004.
In June 1998, the PPUC authorized a rate restructuring plan for
Penn, which essentially resulted in the deregulation of Penn's generation
business as of June 30, 1998. Penn was required to remove from its balance
sheet all regulatory assets and liabilities related to its generation
business and assess all other assets for impairment. The Securities and
Exchange Commission (SEC) issued interpretive guidance regarding asset
impairment measurement which concluded that any supplemental regulated cash
flows such as a competitive transition charge (CTC) should be excluded from
the cash flows of assets in a portion of the business not subject to
regulatory accounting practices. If those assets are impaired, a regulatory
asset should be established if the costs are recoverable through regulatory
cash flows. Consistent with the SEC guidance, Penn reduced its nuclear
generating unit investments by approximately $305 million, of which
approximately $227 million was recognized as a regulatory asset to be
recovered through a CTC over a seven-year transition period; the remaining
net amount of $78 million was written off. The charge of $51.7 million ($30.5
million after income taxes) for discontinuing the application of Statement of
Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation" (SFAS 71), to Penn's generation business was
recorded as a 1998 extraordinary item on the Consolidated Statement of
Income. Penn's net assets included in utility plant relating to the
operations for which the application of SFAS 71 was discontinued and Penn's
total assets as of December 31, 1999 were $76 million and $1.016 billion,
respectively.
All of the Companies' regulatory assets are being recovered under
provisions of the regulatory plans. In addition, the PUCO has authorized the
Company to recognize additional capital recovery related to its generating
assets (which is reflected as additional depreciation expense) and additional
amortization of regulatory assets during the regulatory plan period of at
least $2 billion, and the PPUC had authorized Penn to accelerate at least
$358 million more than the amounts that would have been recognized if the
regulatory plans were not in effect. These additional amounts are being
recovered through current rates. As of December 31, 1999, the Companies'
cumulative additional capital recovery and regulatory asset amortization
amounted to $1.048 billion (including Penn's impairment discussed above and
CTC recovery).
UTILITY PLANT AND DEPRECIATION-
Utility plant reflects the original cost of construction, (except
for Penn's nuclear generating units which were adjusted to fair value as
discussed above), including payroll and related costs such as taxes, employee
benefits, administrative and general costs, and interest costs.
The Companies provide for depreciation on a straight-line basis at
various rates over the estimated lives of property included in plant in
service. The annual composite rate for OE's electric plant was approximately
3.0% in 1999, 1998 and 1997. The annual composite rate for Penn's electric
plant was approximately 2.5% in 1999 and 3.0% in 1998 and 1997. In addition
to the straight-line depreciation recognized in 1999, 1998 and 1997, the
Companies recognized additional capital recovery of $95 million, $141 million
(excluding Penn's impairment) and $172 million, respectively, as additional
depreciation expense in accordance with their regulatory plans. Such
additional charges in the accumulated provision for depreciation were $517
million and $422 million as of December 31, 1999 and 1998, respectively.
Annual depreciation expense includes approximately $9.4 million for
future decommissioning costs applicable to the Companies' ownership and
leasehold interests in three nuclear generating units. The Companies' future
decommissioning costs reflect the increase in Penn's ownership interest
related to the asset transfer with Duquesne Light Company (Duquesne)
discussed below in "Common Ownership of Generating Facilities." The
Companies' share of the future obligation to decommission these units is
approximately $777 million in current dollars and (using a 4.0% escalation
rate) approximately $1.9 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 Companies have recovered approximately $92
million for decommissioning through their 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 Companies expect that additional amount to be recoverable from their
customers. The Companies have approximately $236.9 million invested in
external decommissioning trust funds as of December 31, 1999. This includes
additions to the trust funds and the corresponding liability of $89 million
as a result of the asset transfer. Earnings on these funds are reinvested
with a corresponding increase to the decommissioning liability. The Companies
have also recognized an estimated liability of approximately $18.7 million
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 Companies, together with the other FirstEnergy utilities, CEI
and TE, and Duquesne 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 Companies' portions of
operating expenses associated with jointly owned facilities are 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 Companies and
CEI. As part of this exchange, the Companies transferred their 246-megawatt
Niles Plant and 339-megawatt New Castle Plant to Duquesne. The Companies
acquired Duquesne's ownership interest in the Beaver Valley Station and
acquired, with CEI, 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 Companies and CEI 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 was no longer a participant in the CAPCO arrangements after the
exchange. The amounts reflected on the Consolidated Balance Sheet under
utility plant at December 31, 1999 include the following:
Companies'
Utility Accumulated Construction Ownership/
Plant Provision for Work in Leasehold
Generating Units in Service Depreciation Progress Interest
- ----------------------------------------------------------------------------------
(In millions)
W. H. Sammis #7 $ 307.4 $ 134.9 $ 6.7 68.80%
Bruce Mansfield #1,
#2 and #3 1,010.7 538.0 19.7 67.18%
Beaver Valley
#1 and #2 1,665.6 653.2 22.8 77.81%
Perry 1,281.7 853.1 8.7 35.24%
- --------------------------------------------------------------------------------
Total $4,265.4 $2,179.2 $57.9
================================================================================
NUCLEAR FUEL-
Nuclear fuel is recorded at original cost, which includes material,
enrichment, fabrication and interest costs incurred prior to reactor load.
The Companies amortize the cost of nuclear fuel based on the rate of
consumption. The Companies' electric rates include amounts for the future
disposal of spent nuclear fuel based upon the formula used to compute
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. Since November 8, 1997, the
Companies are included in FirstEnergy's consolidated federal income tax
return. The consolidated tax liability is allocated on a "stand-alone"
company basis, with the Companies recognizing any tax losses or credits they
contributed to the consolidated return.
RETIREMENT BENEFITS-
FirstEnergy's trusteed, noncontributory defined benefit pension
plan covers almost all of the Companies' full-time employees. Upon
retirement, employees receive a monthly pension based on length of service
and compensation. In 1998, the Companies' pension plans and the Centerior
pension plan were merged into the FirstEnergy pension plan. The Companies use
the projected unit credit method for funding purposes and were not required
to make pension contributions during the three years ended December 31, 1999.
The assets of the FirstEnergy pension plan consist primarily of common
stocks, United States government bonds and corporate bonds.
The Companies provide 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 Companies pay
insurance premiums to cover a portion of these benefits in excess of set
limits; all amounts up to the limits are paid by the Companies. The Companies
recognize 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 on the Consolidated Balance Sheets as of December 31 (which
includes the Companies' share of the FirstEnergy 1999 plans' net prepaid
pension cost and accrued other postretirement benefits cost of $194.8 million
and $145.7 million, respectively, and the Companies' share of the FirstEnergy
1998 plans' net prepaid pension cost and accrued other postretirement
benefits cost of $175.9 million and $132.8 million, respectively):
Other
Pension Benefits Postretirement Benefits
-------------------- -----------------------
1999 1998 1999 1998
- -------------------------------------------------------------------------------------------------
(In millions)
Change in benefit obligation:
Benefit obligation as of January 1 $1,500.1 $1,327.5 $ 601.3 $ 534.1
Service cost 28.3 25.0 9.3 7.5
Interest cost 102.0 92.5 40.7 37.6
Plan amendments -- 44.3 -- 40.1
Actuarial loss (gain) (155.6) 101.6 (17.6) 10.7
Net increase from asset swap 14.8 -- 12.5 --
Benefits paid (95.5) (90.8) (37.8) (28.7)
- -----------------------------------------------------------------------------------------------
Benefit obligation as of December 31 1,394.1 1,500.1 608.4 601.3
- -----------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets as of January 1 1,683.0 1,542.5 3.9 2.8
Actual return on plan assets 220.0 231.3 0.6 0.7
Company contribution -- -- 0.4 0.4
Benefits paid (95.5) (90.8) -- --
- -----------------------------------------------------------------------------------------------
Fair value of plan assets as of December 31 1,807.5 1,683.0 4.9 3.9
- -----------------------------------------------------------------------------------------------
Funded status of plan 413.4 182.9 (603.5) (597.4)
Unrecognized actuarial loss (gain) (303.5) (110.8) 24.9 30.6
Unrecognized prior service cost 57.3 63.0 24.1 27.4
Unrecognized net transition obligation (asset) (10.1) (18.0) 120.1 129.3
- -----------------------------------------------------------------------------------------------
Prepaid (accrued) benefit cost $ 157.1 $ 117.1 $(434.4) $(410.1)
===============================================================================================
Assumptions used as of December 31:
Discount rate 7.75% 7.00% 7.75% 7.00%
Expected long-term return on plan assets 10.25% 10.25% 10.25% 10.25%
Rate of compensation increase 4.00% 4.00% 4.00% 4.00%
<FN>
Net pension and other postretirement benefit costs for the three years ended December 31, 1999
(FirstEnergy plans in 1999 and 1998 and the Companies' plans in 1997) were computed as follows:
Other
Pension Benefits Postretirement Benefits
--------------------- ----------------------
1999 1998 1997 1999 1998 1997
- -------------------------------------------------------------------------------------------------------
(In millions)
Service cost $ 28.3 $ 25.0 $ 12.9 $ 9.3 $ 7.5 $ 4.1
Interest cost 102.0 92.5 49.8 40.7 37.6 17.6
Expected return on plan assets (168.1) (152.7) (91.9) (0.4) (0.3) (0.2)
Amortization of transition obligation (asset) (7.9) (8.0) (8.0) 9.2 9.2 8.2
Amortization of prior service cost 5.7 2.3 2.1 3.3 (0.8) 0.3
Recognized net actuarial loss (gain) -- (2.6) (0.9) -- -- --
Voluntary early retirement program expense -- -- 31.5 -- -- 1.9
- -------------------------------------------------------------------------------------------------------
Net benefit cost $ (40.0) $ (43.5) $ (4.5) $62.1 $53.2 $31.9
=======================================================================================================
Companies' share of total plan costs $ (16.9) $ (39.7) $ (4.5) $25.5 $31.2 $31.9
- -------------------------------------------------------------------------------------------------------
The FirstEnergy plan's health care trend rate assumption is 5.3% in
2000, 5.2% in 2001 and 5.0% for 2002 and later years. Assumed health care
cost trend rates have a significant effect on the amounts reported for the
health care plan. An increase in the health care trend rate assumption by one
percentage point would increase the total service and interest cost
components by $4.5 million and the postretirement benefit obligation by $72.0
million. A decrease in the same assumption by one percentage point would
decrease the total service and interest cost components by $3.5 million and
the postretirement benefit obligation by $58.2 million.
TRANSACTIONS WITH AFFILIATED COMPANIES-
Operating revenues and operating expenses include amounts for
affiliated transactions with CEI and TE since the November 8, 1997 merger
date. The Companies' transactions with CEI and TE from the merger date were
primarily for electric sales. The amounts related to CEI and TE were $27.7
million and $18.1 million, respectively, for 1999, $17.8 million and $12.7
million, respectively, for 1998 and $4.3 million and $0.4 million,
respectively, for the November 8-December 31, 1997 period.
FirstEnergy provided support services at cost to the Companies and
other affiliated companies. FirstEnergy billed the Companies $118.2 million
and $114.2 million in 1999 and 1998, 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, 1999 and 1998, cash and cash equivalents
included $83 million and $16 million, respectively, to be used for the
redemption of long-term debt in the first quarter of 2000 and in 1999,
respectively. The Companies reflect temporary cash investments at cost, which
approximates their market value. Noncash financing and investing activities
included capital lease transactions amounting to $1.4 million, $1.6 million
and $3.0 million for the years 1999, 1998 and 1997, respectively. Commercial
paper transactions of OES Fuel, Incorporated (OES Fuel) (a wholly owned
subsidiary of the Company) that have initial maturity periods of three months
or less are reported net within financing activities under long-term debt and
are reflected as long-term debt on the Consolidated Balance Sheets (see Note
3G).
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 $2,483 $2,459 $2,627 $2,775
Preferred stock $ 145 $ 142 $ 150 $ 155
Investments other than cash
and cash equivalents:
Debt securities
-Maturity (5-10 years) $ 475 $ 476 $ 481 $ 520
-Maturity (more than 10 years) 258 267 258 305
Equity securities 14 14 14 14
All other 301 311 170 179
- --------------------------------------------------------------------
$1,048 $1,068 $ 923 $1,018
====================================================================
The fair values of long-term debt and preferred stock 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 Companies' ratings.
The fair value of investments other than cash and cash equivalents
represent cost (which approximates fair value) or the present value of the
cash inflows based on the yield to maturity. The yields assumed were based on
financial instruments with similar characteristics and terms. Investments
other than cash and cash equivalents include decommissioning trust
investments. Unrealized gains and losses applicable to the decommissioning
trusts have been recognized in the trust investment with a corresponding
change to the decommissioning liability. The other debt and equity securities
referred to above are in the held-to-maturity category. The Companies have no
securities held for trading purposes.
REGULATORY ASSETS-
The Companies recognize, as regulatory assets, costs which the
FERC, PUCO and PPUC 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 are being recovered from customers
under the Companies' respective regulatory plans. Based on those regulatory
plans, at this time, the Companies are continuing to bill and collect cost-
based rates relating to all of the Company's operations and Penn's
nongeneration operations and they continue the application of SFAS 71 to
those respective operations. The Companies also recognized additional cost
recovery of $257 million, $50 million and $39 million in 1999, 1998 and 1997,
respectively, as additional regulatory asset amortization in accordance with
their regulatory plans.
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 generation business 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 Companies will continue to bill and collect cost-based
rates for their transmission and distribution services, which will remain
regulated; accordingly, it is appropriate that the Companies continue the
application of SFAS 71 to those respective operations after December 31,
2000.
Regulatory assets on the Consolidated Balance Sheets are comprised
of the following:
1999 1998
- ------------------------------------------------------------------------
(In millions)
Nuclear unit expenses $ 643.0 $ 666.7
Customer receivables for future income taxes 455.3 458.3
Competitive transition charge 280.4 331.0
Sale and leaseback costs 120.5 318.4
Loss on reacquired debt 79.7 81.9
Employee postretirement benefit costs 24.8 28.9
DOE decommissioning and decontamination costs 10.7 12.2
Other 3.9 16.4
- -----------------------------------------------------------------------
Total $1,618.3 $1,913.8
=======================================================================
2. LEASES
The Companies lease certain generating facilities, certain
transmission facilities, office space and other property and equipment under
cancelable and noncancelable leases.
The Company sold portions of its ownership interest in Perry Unit 1
and Beaver Valley Unit 2 and entered into operating leases on the portions
sold for basic lease terms of approximately 29 years. During the terms of the
leases, the Company continues to be responsible, to the extent of its
individual combined ownership and leasehold interests, for costs associated
with the units including construction expenditures, operation and maintenance
expenses, insurance, nuclear fuel, property taxes and decommissioning. The
Company has the right, at the end of the respective basic lease terms, to
renew the leases for up to two years. The Company also has 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. The basic rental payments are adjusted when applicable federal
tax law changes.
OES Finance, Incorporated (OES Finance), a wholly owned subsidiary
of the Company, maintains deposits pledged as collateral to secure
reimbursement obligations relating to certain letters of credit supporting
the Company's obligations to lessors under the Beaver Valley Unit 2 sale and
leaseback arrangements. The deposits pledged to the financial institution
providing those letters of credit are the sole property of OES Finance. In
the event of liquidation, OES Finance, as a separate corporate entity, would
have to satisfy its obligations to creditors before any of its assets could
be made available to the Company as sole owner of OES Finance common stock.
Consistent with the regulatory treatment, the rentals for capital
and operating leases are charged to operating expenses on the Consolidated
Statements of Income. Such costs for the three years ended December 31, 1999,
are summarized as follows:
1999 1998 1997
- --------------------------------------------------------
(In millions)
Operating leases
Interest element $108.5 $110.0 $111.3
Other 34.4 28.9 23.2
Capital leases
Interest element 5.3 5.3 6.1
Other 4.4 4.8 6.0
- --------------------------------------------------------
Total rentals $152.6 $149.0 $146.6
========================================================
<FN>
The future minimum lease payments as of December 31, 1999, are:
Operating Leases
-----------------------------
Capital Lease PNBV Capital
Leases Payments Trust Net
- --------------------------------------------------------------------
(In millions)
2000 $ 10.4 $ 125.1 $ 54.6 $ 70.5
2001 9.7 127.7 59.5 68.2
2002 8.8 125.2 61.0 64.2
2003 8.6 137.4 62.6 74.8
2004 8.4 138.3 58.3 80.0
Years thereafter 62.6 1,704.9 530.9 1,174.0
- --------------------------------------------------------------------
Total minimum lease payments 108.5 $2,358.6 $826.9 $1,531.7
Executory costs 26.9 ======== ====== ========
- -------------------------------------
Net minimum lease payments 81.6
Interest portion 47.7
- -------------------------------------
Present value of net minimum
lease payments 33.9
Less current portion 3.3
- -------------------------------------
Noncurrent portion $ 30.6
=====================================
The Company invested in the PNBV Capital Trust, which was
established to purchase a portion of the lease obligation bonds issued on
behalf of lessors in the Company's Perry Unit 1 and Beaver Valley Unit 2 sale
and leaseback transactions. The PNBV capital trust arrangement effectively
reduces lease costs related to those transactions.
3. CAPITALIZATION:
(A) RETAINED EARNINGS-
Under the Company's first mortgage indenture, the Company's
consolidated retained earnings unrestricted for payment of cash dividends on
the Company's common stock were $460.9 million at December 31, 1999.
(B) EMPLOYEE STOCK OWNERSHIP PLAN-
The Companies were funding the matching contribution for their
401(k) savings plan through an ESOP Trust. All full-time employees eligible
for participation in the 401(k) savings plan are covered by the ESOP. The
ESOP borrowed $200 million from the Company and acquired 10,654,114 shares of
the Company's common stock through market purchases; the shares were
converted into FirstEnergy's common stock in connection with the OE-Centerior
merger. The ESOP loan is included in Other Property and Investments on the
Consolidated Balance Sheets as of December 31, 1999 and 1998 as an investment
with FirstEnergy related to the FirstEnergy savings plan. Dividends on ESOP
shares are used to service the debt. Shares are released from the ESOP on a
pro rata basis as debt service payments are made. In 1997, 429,515 shares
were allocated to the Companies' employees with the corresponding expense
recognized based on the shares allocated method. Total ESOP-related
compensation expense reflected on the 1997 Consolidated Statement of Income
was calculated as follows:
- -----------------------------------------
1997
- -----------------------------------------
(In millions)
Base compensation $ 9.9
Dividends on common stock
held by the ESOP and used to
service debt (3.4)
- -----------------------------------------
Net expense $ 6.5
=========================================
(C) COMPREHENSIVE INCOME-
In 1998, the Companies 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.
(D) PREFERRED AND PREFERENCE STOCK-
Penn's 7.75% series of preferred stock has a restriction which
prevents early redemption prior to July 2003. The Company's 8.45% series of
preferred stock has no optional redemption provision. All other preferred
stock may be redeemed by the Companies in whole, or in part, with 30-60 days'
notice.
The Company has 8 million authorized and unissued shares of
preference stock having no par value.
(E) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION-
The Company's 8.45% series of preferred stock has an annual sinking
fund requirement for 50,000 shares. Penn's 7.625% series has an annual
sinking fund requirement for 7,500 shares beginning on October 1, 2002.
The Companies' preferred shares are retired at $100 per share plus
accrued dividends. Annual sinking fund requirements are $5 million in each
year 2000-2001 and $1 million in each year 2002-2004.
(F) COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED
SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY COMPANY
SUBORDINATED DEBENTURES-
Ohio Edison Financing Trust, a wholly owned subsidiary of the
Company, has issued $120 million of 9% Cumulative Trust Preferred Capital
Securities. The Company purchased all of the Trust's Common Securities and
simultaneously issued to the Trust $123.7 million principal amount of 9%
Junior Subordinated Debentures due 2025 in exchange for the proceeds that the
Trust received from its sale of Preferred and Common Securities. The sole
assets of the Trust are the Subordinated Debentures whose interest and other
payment dates coincide with the distribution and other payment dates on the
Trust Securities. Under certain circumstances the Subordinated Debentures
could be distributed to the holders of the outstanding Trust Securities in
the event the Trust is liquidated. The Subordinated Debentures may be
optionally redeemed by the Company beginning December 31, 2000, at a
redemption price of $25 per Subordinated Debenture plus accrued interest, in
which event the Trust Securities will be redeemed on a pro rata basis at $25
per share plus accumulated distributions. The Company's obligations under the
Subordinated Debentures along with the related Indenture, amended and
restated Trust Agreement, Guarantee Agreement and the Agreement for expenses
and liabilities, constitute a full and unconditional guarantee by the Company
of payments due on the Preferred Securities.
(G) LONG-TERM DEBT-
The first mortgage indentures and their supplements, which secure
all of the Companies' first mortgage bonds, serve as direct first mortgage
liens on substantially all property and franchises, other than specifically
excepted property, owned by the Companies.
Based on the amount of bonds authenticated by the Trustees through
December 31, 1999, the Companies' annual sinking and improvement fund
requirements for all bonds issued under the mortgage amounts to $31 million.
The Companies expect to deposit funds in 2000 that will be withdrawn upon the
surrender for cancellation of a like principal amount of bonds, which are
specifically authenticated for such purposes against unfunded property
additions or against previously retired bonds. This method can result in
minor increases in the amount of the annual sinking fund requirement.
Sinking fund requirements for first mortgage bonds and maturing
long-term debt (excluding capital leases) for the next five years are:
(In millions)
- --------------------
2000 $414.5
2001 281.4
2002 516.8
2003 246.3
2004 255.6
- --------------------
The Companies' obligations to repay certain pollution control
revenue bonds are secured by several series of first mortgage bonds and, in
some cases, by subordinate liens on the related pollution control facilities.
Certain pollution control revenue bonds are entitled to the benefit of
irrevocable bank letters of credit of $349.3 million. To the extent that
drawings are made under those letters of credit to pay principal of, or
interest on, the pollution control revenue bonds, the Companies are entitled
to a credit against their obligation to repay those bonds. The Companies pay
annual fees of 0.43% to 0.75% of the amounts of the letters of credit to the
issuing banks and are obligated to reimburse the banks for any drawings
thereunder.
The Company had unsecured borrowings of $190 million at December
31, 1999, supported by a $250 million long-term revolving credit facility
agreement which expires November 18, 2002. The Company must pay an annual
facility fee of 0.20% on the total credit facility amount. In addition, the
credit agreement provides that the Company maintain unused first mortgage
bond capability for the full credit agreement amount under the Company's
indenture as potential security for the unsecured borrowings.
Nuclear fuel purchases are financed through the issuance of OES
Fuel commercial paper and loans, both of which are supported by a $180.5
million long-term bank credit agreement which expires March 31, 2001.
Accordingly, the commercial paper and loans are reflected as long-term debt
on the Consolidated Balance Sheets. OES Fuel must pay an annual facility fee
of 0.20% on the total line of credit and an annual commitment fee of 0.0625%
on any unused amount.
4. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT:
Short-term borrowings outstanding at December 31, 1999, consisted
of $162.7 million of bank borrowings and $160.0 million of OES Capital,
Incorporated (OES Capital) commercial paper. OES Capital is a wholly owned
subsidiary of the Company whose borrowings are secured by customer accounts
receivable. OES Capital can borrow up to $170 million under a receivables
financing agreement at rates based on certain bank commercial paper and is
required to pay an annual fee of 0.20% on the amount of the entire finance
limit. The receivables financing agreement expires in 2002. At December 31,
1999, the Company also had total short-term borrowings of $35.6 million from
its affiliates.
The Company has lines of credit with domestic banks that provide
for borrowings of up to $55 million under various interest rate options.
Short-term borrowings may be made under these lines of credit on its
unsecured notes. To assure the availability of these lines, the Company is
required to pay annual commitment fees of 0.125% to 0.20%. These lines expire
at various times during 2000. The weighted average interest rates on short-
term borrowings outstanding at December 31, 1999 and 1998, were 6.27% and
5.61%, respectively.
5. COMMITMENTS AND CONTINGENCIES:
CAPITAL EXPENDITURES-
The Companies' current forecasts reflect expenditures of
approximately $1 billion for property additions and improvements from 2000-
2004, of which approximately $251 million is applicable to 2000. Investments
for additional nuclear fuel during the 2000-2004 period are estimated to be
approximately $218 million, of which approximately $65 million applies to
2000. During the same periods, the Companies' nuclear fuel investments are
expected to be reduced by approximately $215 million and $46 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 their present ownership and leasehold interests in the
Beaver Valley Station and the Perry Plant, the Companies' 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 $168.2 million per incident but
not more than $19.1 million in any one year for each incident.
The Companies are also insured as to their respective interests in
Beaver Valley 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 Companies
have also obtained approximately $706.3 million of insurance coverage for
replacement power costs for their respective interests in Beaver Valley and
Perry. Under these policies, the Companies can be assessed a maximum of
approximately $22 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 Companies intend 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 Companies' 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 Companies' insurance policies, or to the extent such
insurance becomes unavailable in the future, the Companies would remain at
risk for such costs.
ENVIRONMENTAL MATTERS-
Various federal, state and local authorities regulate the Companies
with regard to air and water quality and other environmental matters. The
Companies estimate additional capital expenditures for environmental
compliance of approximately $175 million, which is included in the
construction forecast provided under "Capital Expenditures" for 2000 through
2004.
The Companies are 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 Companies'
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 Companies' 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 Companies are 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 Companies 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
Companies 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 Companies operate affected
facilities.
In September 1999, FirstEnergy received, and subsequently in
October 1999, the Companies received a citizen suit notification letter from
the New York Attorney General's office alleging Clean Air Act violations at
the W. H. Sammis Plant. In November 1999, the Companies received a citizen
suit notification letter from the Connecticut Attorney General's office
alleging Clean Air Act violations at the Sammis Plant. On November 3, 1999,
the EPA issued Notices of Violation (NOV) or a Compliance Order to eight
utilities covering 32 power plants, including the Sammis Plant. In addition,
the U.S. Department of Justice filed seven civil complaints against various
investor-owned utilities, which included a complaint against the Companies in
the U.S. District Court for the Southern District of Ohio. The NOV and
complaint allege violations of the Clean Air Act based on operation and
maintenance of the Sammis Plant dating back to 1984. The complaint requests
permanent injunctive relief to require the installation of "best available
control technology" and civil penalties of up to $27,500 per day of
violation. The Companies believe the Sammis Plant is in full compliance with
the Clean Air Act and the NOV and complaint are without merit. However, the
Companies are unable to predict the outcome of this litigation. Penalties
could be imposed if the Sammis Plant continues to operate without correcting
the alleged violations and a court determines that the allegations are valid.
It is anticipated at this time that the Sammis Plant will continue to operate
while the matter is being decided.
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 $633.1 $646.7 $770.5 $636.6
Operating Expenses and Taxes 498.1 532.7 650.2 532.8
- ---------------------------------------------------------------------------------------
Operating Income 135.0 114.0 120.3 103.8
Other Income 9.3 13.1 10.2 13.2
Net Interest Charges 56.5 58.4 53.9 52.5
- ---------------------------------------------------------------------------------------
Net Income $ 87.8 $ 68.7 $ 76.6 $ 64.5
=======================================================================================
Earnings on Common Stock $ 84.9 $ 65.8 $ 73.7 $ 61.7
=======================================================================================
March 31, June 30, September 30, December 31,
Three Months Ended 1998 1998 1998 1998
- -----------------------------------------------------------------------------------------
(In millions)
Operating Revenues $597.8 $618.5 $696.2 $607.0
Operating Expenses and Taxes 486.7 524.9 555.5 465.5
- ---------------------------------------------------------------------------------------
Operating Income 111.1 93.6 140.7 141.5
Other Income 12.5 11.8 12.6 10.7
Net Interest Charges 59.3 59.1 58.6 56.2
- ---------------------------------------------------------------------------------------
Income Before Extraordinary Item 64.3 46.3 94.7 96.0
Extraordinary Item (Net of Income
Taxes) (Note 1) -- (30.5) -- --
- ---------------------------------------------------------------------------------------
Net Income $ 64.3 $ 15.8 $ 94.7 $ 96.0
=======================================================================================
Earnings on Common Stock $ 61.3 $ 12.8 $ 91.7 $ 93.0
=======================================================================================
Report of Independent Public Accountants
To the Stockholders and Board of Directors of Ohio Edison Company:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Ohio Edison Company (an Ohio corporation and
wholly owned subsidiary of FirstEnergy Corp.) and subsidiaries 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 each of the
three years in the period ended December 31, 1999. 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 Ohio Edison Company and
subsidiaries as of December 31, 1999 and 1998, and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1999, in conformity with generally accepted accounting
principles.
ARTHUR ANDERSEN LLP
Cleveland, Ohio
February 11, 2000