OHIO EDISON COMPANY
SELECTED FINANCIAL DATA
1998 1997 1996 1995 1994
- ------------------------------------------------------------------------------------------------------
(In thousands)
Operating Revenues $2,519,662 $2,473,582 $2,469,785 $2,465,846 $2,368,191
----------------------------------------------------------
Operating Income $ 486,920 $ 488,568 $ 530,069 $ 566,618 $ 557,254
----------------------------------------------------------
Income Before Extraordinary Item $ 301,320 $ 293,194 $ 315,170 $ 317,241 $ 303,531
----------------------------------------------------------
Net Income $ 270,798 $ 293,194 $ 315,170 $ 317,241 $ 303,531
----------------------------------------------------------
Earnings on Common Stock $ 258,828 $ 280,802 $ 302,673 $ 294,747 $ 281,852
----------------------------------------------------------
Total Assets $8,733,151 $8,977,455 $9,054,457 $8,892,088 $9,045,255
----------------------------------------------------------
Capitalization at December 31:
Common Stockholders' Equity $2,681,873 $2,724,319 $2,503,359 $2,407,871 $2,317,197
Preferred Stock:
Not Subject to Mandatory Redemption 211,870 211,870 211,870 211,870 328,240
Subject to Mandatory Redemption 145,000 150,000 155,000 160,000 40,000
Long-Term Debt 2,215,042 2,569,802 2,712,760 2,786,256 3,166,593
----------------------------------------------------------
Total Capitalization $5,253,785 $5,655,991 $5,582,989 $5,565,997 $5,852,030
----------------------------------------------------------
Capitalization Ratios:
Common Stockholders' Equity 51.0% 48.2% 44.8% 43.3% 39.6%
Preferred Stock:
Not Subject to Mandatory Redemption 4.0 3.7 3.8 3.8 5.6
Subject to Mandatory Redemption 2.8 2.7 2.8 2.9 0.7
Long-Term Debt 42.2 45.4 48.6 50.0 54.1
----------------------------------------------------------
Total Capitalization 100.0% 100.0% 100.0% 100.0% 100.0%
----------------------------------------------------------
Kilowatt-Hour Sales (Millions):
Residential 8,773 8,631 8,704 8,546 8,201
Commercial 7,590 7,335 7,246 7,151 6,885
Industrial 10,803 11,202 11,089 10,513 9,841
Other 150 150 147 146 144
----------------------------------------------------------
Total Retail 27,316 27,318 27,186 26,356 25,071
Total Wholesale 5,706 5,241 7,076 6,920 5,879
----------------------------------------------------------
Total 33,022 32,559 34,262 33,276 30,950
----------------------------------------------------------
Customers Served:
Residential 1,004,552 995,605 988,179 978,118 968,483
Commercial 113,820 111,189 113,795 111,978 109,832
Industrial 4,598 4,568 4,590 4,268 3,786
Other 1,476 1,415 1,331 1,308 1,226
----------------------------------------------------------
Total 1,124,446 1,112,777 1,107,895 1,095,672 1,083,327
----------------------------------------------------------
Average Annual Residential kWh Usage 8,780 8,720 8,861 8,787 8,524
Cost of Fuel per Million Btu $1.15 $1.10 $1.13 $1.18 $1.21
Peak Load-Megawatts 6,840 6,225 6,027 6,332 5,744
Number of Employees 1,944 4,215 4,273 4,812 5,166
PRICE RANGE OF COMMON STOCK
The Company's Common Stock became wholly owned by FirstEnergy
Corp. effective with the November 8, 1997 merger date. Prices shown below
are for the period through November 7, 1997.
1997
-----------------------------------------------
First Quarter High-Low 23-7/8 20-7/8
---------------------
Second Quarter High-Low 22 19-1/4
---------------------
Third Quarter High-Low 23-5/8 21-3/4
---------------------
Fourth Quarter High-Low -- --
---------------------
Yearly High-Low -- --
---------------------
<FN>
Prices are based on reports published in The Wall Street Journal for New York Stock Exchange Composite
Transactions.
OHIO EDISON COMPANY
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
This discussion includes forward-looking statements based on
information currently available to management that are subject to
certain risks and uncertainties. These statements typically contain,
but are not limited to, the terms anticipate, potential, expect,
believe, estimate and similar words. Actual results may differ
materially due to the speed and nature of increased competition and
deregulation in the electric utility industry, economic or weather
conditions affecting future sales and margins, changes in markets for
energy services, changing energy market prices, legislative and
regulatory changes, and the availability and cost of capital and other
similar factors.
Results of Operations
We continued to take steps in 1998 to better position our
Company as competition continues to expand in the electric utility
industry. Investments were made in new information systems with
enhanced functionality which also address Year 2000 application
deficiencies. We also contributed to 1998 cash savings of FirstEnergy
Corp. (FirstEnergy) totaling $173 million which were captured from
initiatives implemented during the year in connection with our November
1997 merger with Centerior Energy Corporation to form FirstEnergy.
Earnings on common stock were $258.8 million in 1998 compared
to $280.8 million in 1997. Results for 1998 were adversely affect by a
one-time, extraordinary charge of $30.5 million after taxes, related to
Penn's discontinued application of Statement of Financial Accounting
Standards No. 71 (SFAS 71), "Accounting for the Effects of Certain
Types of Regulation", to its generation business, as discussed later in
this report. Additionally, sharp increases in the spot market price for
electricity occasioned by a constrained power supply and heavy customer
demand in the latter part of June 1998, combined with unscheduled
generating unit outages, resulted in spot market purchases of power at
prices which substantially exceeded amounts recovered from retail
customers. Earnings on common stock for 1997 were affected by net
nonrecurring charges, resulting from merger-related staffing
reductions, amounting to $26.4 million, and an increase in accelerated
depreciation and amortization of nuclear and regulatory assets under
our rate plans, totaling $20 million after taxes.
For the fourth consecutive year, we achieved record operating
revenues. The following table summarizes the sources of increases in
operating revenues for 1998 and 1997 as compared to the previous year:
1998 1997
---- ----
(In millions)
Increase in average retail price $27.0 $ 13.3
Change in retail kilowatt-hour sales (0.1) 7.8
Wholesale sales 13.3 (27.3)
Other 5.9 10.0
- -----------------------------------------------------------
Net Increase $46.1 $ 3.8
===========================================================
Retail kilowatt-hour sales were approximately the same as the
previous year at 27.3 billion kilowatt-hours after setting a new record
in 1997. Residential and commercial kilowatt-hour sales increased 1.7%
and 3.5%, respectively from 1997, offset by a 3.6% decrease in
industrial sales. Residential and commercial kilowatt-hour sales
benefited from continued growth in the retail customer base, with over
11,000 new retail customers added in 1998 compared to approximately
4,900 new retail customers in 1997. 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.
Sales to wholesale customers increased 8.9% contributing to an increase
in total kilowatt-hour sales of 1.4%. In 1997, commercial and
industrial kilowatt-hour sales increased 1.2% and 1.0%, respectively,
from 1996, partially offset by an 0.8% decrease in residential sales
resulting in a 0.5% increase in retail kilowatt-hour sales. A decrease
in kilowatt-hour sales to wholesale customers contributed to a 5.0%
decline in total kilowatt-hour sales in 1997 compared to 1996.
Operation and maintenance expenses increased in 1998 compared
to the prior year due to increased fuel and purchased power costs. Most
of the increase occurred in the second quarter and resulted from a
combination of factors. In late June 1998, the midwestern and southern
regions of the United States experienced electricity shortages caused
mainly by record temperatures and humidity and unscheduled generating
unit outages. Due in part to unscheduled outages at the Beaver Valley
Plant at that time, our production capabilities were reduced to the
point that we purchased significant amounts of power at unusually high
spot market prices, causing the increase in purchased power costs. In
1997, fuel and purchased power costs were down from the previous year
due to lower total kilowatt-hour sales. Nuclear operating costs
increased in 1998 and in 1997 reflecting higher costs at the Beaver
Valley Plant. Other operating costs decreased in 1998 from the previous
year due primarily to the absence of expenses related to a 1997
voluntary retirement program and estimated severance costs which
increased other operating costs for that year.
Depreciation and amortization decreased in 1998 compared to
the prior year due primarily to the net effect of our rate plans. Total
accelerated depreciation and amortization of our nuclear and regulatory
assets under our rate plans was $173 million in 1998; down from $190
million the previous year. In 1997, the increase in depreciation and
amortization resulted from accelerations under the regulatory plans.
General taxes increased in 1998 compared to 1997 in part because of
gross receipts taxes on increased operating revenue. This followed a
decrease in 1997 due to lower property taxes and an adjustment in the
second quarter of that year which reduced the liabilities for gross
receipts taxes.
Interest on long-term debt continued to trend downward due to
refinancings and redemptions of long-term debt. Other interest expense
increased as a result of increased short-term borrowings.
Capital Resources and Liquidity
We have significantly improved our financial position over
the past five years. Excluding nonrecurring charges, our fixed charge
coverage ratios continue to improve. Our corporate indenture ratio,
which is used to measure our ability to issue first mortgage bonds,
improved from 4.13 at the end of 1993 to 6.17 at the end of 1998. Over
the same period, our charter ratio, a measure of our ability to issue
preferred stock, improved from 2.02 to 2.49 and our common
stockholders' equity percentage of capitalization rose from
approximately 40% at the end of 1993 to 51% at the end of 1998. Our
improving financial position reflects ongoing efforts to increase
competitiveness. We continue to streamline our operations as evidenced
by the 50% increase in FirstEnergy's customer/employee ratio, which has
increased from 165 at the end of 1993 to 247 as of December 31, 1998.
Merger-related savings achieved through consolidation of activities
have contributed to these results. Also, net debt redemptions and
refinancings have lowered our average cost of long-term debt over the
last five years from 8.27% in 1993 to 7.55% at the end of 1998.
We had about $33.2 million of cash and temporary investments
and $338.2 million of short-term indebtedness as of December 31, 1998.
Our unused borrowing capability included $46.5 million under revolving
lines of credit and a $2.0 million bank facility that provides for
borrowings on a short-term basis at the bank's discretion.
Our cash requirements in 1999 for operating expenses,
construction expenditures and scheduled debt maturities are expected to
be met without issuing new securities. During 1998, we reduced our
total debt by approximately $69 million. We have cash requirements of
approximately $1.2 billion for the 1999-2003 period to meet scheduled
maturities of long-term debt and preferred stock. Of that amount,
approximately $417 million applies to 1999.
Our capital spending for the period 1999-2003 is expected to
be about $1.0 billion (excluding nuclear fuel), of which approximately
$169 million applies to 1999. Investments for additional nuclear fuel
during the 1999-2003 period are estimated to be approximately $167
million, of which about $23 million applies to 1999. During the same
periods, our nuclear fuel investments are expected to be reduced by
approximately $169 million and $35 million, respectively, as the
nuclear fuel is consumed. Also, we have operating lease commitments,
net of PNBV Capital Trust cash receipts, of approximately $365 million
for the 1999-2003 period, of which approximately $82 million relates to
1999.
FirstEnergy signed an agreement in principle with Duquesne
Light Company (Duquesne) that would result in the transfer of 1,436
megawatts owned by Duquesne at five generating plants in exchange for
1,328 megawatts at three plants owned by FirstEnergy's electric utility
operating companies (see "Common Ownership of Generating Facilities" in
Note 1). A final agreement on the exchange of assets, which will be
structured as a tax-free transaction to the extent possible, is being
negotiated. The transaction benefits the FirstEnergy's utility
operating companies by providing exclusive ownership and operating
control of all generating assets that are now jointly owned and
operated under the Central Area Power Coordination Group agreement.
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.
- ---------------------------------------------------------------------------------------------
There- Fair
1999 2000 2001 2002 2003 after Total Value
(Dollars in Millions)
- ---------------------------------------------------------------------------------------------
Investments other than Cash and
Cash Equivalents:
Fixed Income $ 6 $ 17 $23 $ 26 $ 30 $ 724 $ 826 $ 912
Average interest rate 5.5% 7.3% 7.7% 7.8% 7.9% 7.9% 7.9%
- ----------------------------------------------------------------------------------------------
Liabilities
- ----------------------------------------------------------------------------------------------
Long-term Debt:
Fixed rate $164 $118 $17 $326 $246 $1,179 $2,050 $2,196
Average interest rate 7.0% 6.5% 8.0% 7.8% 8.2% 7.2% 7.4%
Variable rate $250 $ 327 $ 577 $ 579
Average interest rate 6.0% 4.1% 4.9%
Short-term Borrowings $338 $ 338 $ 338
Average interest rate 5.6% 5.6%
- ----------------------------------------------------------------------------------------------
Preferred Stock $ 5 $ 5 $ 5 $ 1 $ 1 $ 133 $ 150 $ 155
Average dividend rate 8.5% 8.5% 8.5% 7.6% 7.6% 8.9% 8.8%
- ----------------------------------------------------------------------------------------------
Outlook
We face many competitive challenges in the years ahead
as the electric utility industry undergoes significant changes,
including changing regulation and the entrance of more energy
suppliers into the marketplace. Retail wheeling, which has begun
in our Pennsylvania service area, allows retail customers to
purchase electricity from other energy producers. Our regulatory
plans have provided a solid foundation to position us to meet the
challenges we are facing by significantly reducing fixed costs
and lowering rates to a more competitive level.
Our Rate Reduction and Economic Development Plan was
approved by the Public Utilities Commission of Ohio (PUCO) in
1995. This plan maintains our base electric rates through
December 31, 2005 and revises our fuel cost recovery method.
Penn's Rate Stability and Economic Development Plan, which was
approved by the PPUC in the second quarter of 1996, ended in 1998
with the PPUC's authorization of Penn's rate restructuring plan.
As part of our regulatory plan, transition rate credits
were implemented for customers, which are expected to reduce
operating revenues by approximately $600 million during the
regulatory plan period, which is to be followed by a base rate
reduction of approximately $300 million in 2006.
The PUCO has authorized additional capital recovery
related to our 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 more than the amount that would have been recognized
if the regulatory plan was not in effect. This additional amount
is being recovered through current rates.
Based on the current regulatory environment and our
regulatory plan, we believe we will continue to be able to bill
and collect cost-based rates. As a result, we will continue the
application of SFAS 71. However, changes in the regulatory
environment appear to be on the horizon for electric utilities in
Ohio. As further discussed below, the Ohio legislature is in the
discussion stages of restructuring the State's electric utility
industry. Although we believe that regulatory changes are
possible in 1999, we cannot currently estimate the ultimate
impact.
For Penn, application of SFAS 71 was discontinued for
the generation portion of its business in June 1998 following
PPUC approval of the rate restructuring plan. Customer choice
will be phased in over two years with 66% of each customer class
able to choose alternative suppliers of generation on January 2,
1999, and all remaining customers having choice as of January 2,
2000. Under the plan, Penn continues to deliver power to homes
and businesses through its transmission and distribution system,
which remains regulated. However, Penn's rates have been
restructured to establish separate charges for transmission and
distribution; generation, which is subject to competition; and
stranded cost recovery. In the event customers obtain power from
an alternative source, the generation portion of Penn's rates
will be excluded from their bill and the customers will receive a
generation charge from the alternative supplier. The stranded
cost recovery portion of rates provides for recovery of certain
amounts not otherwise considered recoverable in a competitive
generation market, including regulatory assets. Penn is entitled
to recover $234 million of stranded costs through a competitive
transition charge that starts in 1999 and ends in 2005.
We continue to actively pursue the enactment of fair
legislation calling for deregulation of Ohio's investor-owned
electric utility industry. In early 1998, a deregulation proposal
was introduced, leading to the creation of a working group to
recommend legislation. As requested by legislative leadership,
investor-owned utilities introduced a deregulation plan with
objectives to (1) treat all major stakeholders in Ohio's electric
system fairly; (2) protect public schools and local governments
from revenue loss; and (3) allow utilities an opportunity to
recover costs of government-mandated investments. The utilities
have submitted proposals which incorporate these objectives and
also recognize the complexity of restructuring the industry. The
overlying objective is to do the job right the first time.
Currently, the working group, comprised of legislative leaders,
representatives of the electric utility companies and other
interested stakeholders are meeting to discuss and mold these
proposals. Most recently, placeholder bills containing statements
of principle (that will be replaced by specific proposals as they
are agreed upon) have been introduced. Legislative leaders have
placed a high priority on enacting a deregulation bill by mid-
year.
The Clean Air Act Amendments of 1990, discussed in Note
5, require additional emission reductions by 2000. We are
pursuing cost-effective compliance strategies for meeting these
reduction requirements.
On September 24, 1998, the Federal Environmental
Protection Agency issued a final rule establishing tighter
nitrogen oxide emission requirements for fossil fuel-fired
utility boilers in Ohio, Pennsylvania and twenty other eastern
states, including the District of Columbia (see "Environmental
Matters" in Note 5). Controls must be in place by May 2003, with
required reductions achieved during the five-month summer ozone
season (May through September). The new rule is expected to
increase the cost of producing electricity; however, we believe
that we are in a better position than a number of other utilities
to achieve compliance due to our nuclear generation capacity.
In connection with our regulatory plans to reduce fixed
costs and lower rates, we continue to take steps to restructure
our operations. FirstEnergy announced plans to transfer the
Companies' transmission assets into a new subsidiary, American
Transmission Systems, Inc., with the transfer expected to be
finalized in 1999. The new subsidiary represents a first step
toward the goal of establishing or becoming part of a larger
independent transmission company (TransCo). We believe that a
TransCo better addresses the Federal Energy Regulatory
Commission's (FERC) stated transmission objectives of providing
non-discriminatory service, while providing for streamlined and
cost-efficient operation. In working toward the goal of forming a
larger regional transmission entity, FirstEnergy, American
Electric Power, Virginia Power and Consumers Energy announced in
November 1998 that they would prepare a FERC filing during 1999
for such a regional transmission entity. The entity would be
designed to meet the goals of reducing transmission costs that
result when transferring power over several transmission systems,
ensuring transmission reliability and providing non-
discriminatory access to the transmission grid.
Year 2000 Readiness
The Year 2000 issue is the result of computer programs
being written using two digits rather than four to identify the
applicable year. Any of our programs that have date-sensitive
software may recognize a date using "00" as the year 1900 rather
than the year 2000. Because so many of our computer functions are
date sensitive, this could cause far-reaching problems, such as
system-wide computer failures and miscalculations, if no remedial
action is taken.
We have developed a multi-phase program for Year 2000
compliance that consists of an assessment of our systems and
operations that could be affected by the Year 2000 problem;
remediation or replacement of noncompliant systems and
components; and testing of systems and components following such
remediation or replacement. We have focused our Year 2000 review
on three areas: centralized system applications, noncentralized
systems and relationships with third parties (including suppliers
as well as end-use customers). Our review of system readiness
extends to systems involving customer service, safety,
shareholder needs and regulatory obligations.
We are committed to taking appropriate actions to
eliminate or lessen negative effects of the Year 2000 issue on
our operations. We have completed an inventory of all computer
systems and hardware including equipment with embedded computer
chips and have determined which systems need to be converted or
replaced to become Year 2000-ready and are in the process of
remediating them. Based on our timetable, we expect to have all
identified repairs, replacements and upgrades completed to
achieve Year 2000 readiness by September 1999.
Most of our Year 2000 issues will be resolved through
system replacement. Of our major centralized systems, the general
ledger system and inventory management, procurement and accounts
payable systems were replaced at the end of 1998. Our payroll
system was enhanced to be Year 2000 compliant in July 1998. The
customer service system is due to be replaced in mid-1999.
We have completed formal communications with most of
our key suppliers to determine the extent to which we are
vulnerable to those third parties' failure to resolve their own
Year 2000 problems. For suppliers having potential compliance
problems, we are developing alternate sources and services in the
event such noncompliance occurs. We are also identifying areas
requiring higher inventory levels based on compliance
uncertainties. There can be no guarantee that the failure of
companies to resolve their own Year 2000 issue will not have a
material adverse effect on our business, financial condition and
results of operations.
We are using both internal and external resources to
reprogram and/or replace and test our software for Year 2000
modifications. Of the $43 million total project cost,
approximately $34 million will be capitalized since those costs
are attributable to the purchase of new software for total system
replacements because the Year 2000 solution comprises only a
portion of the benefits resulting from the system replacements.
The remaining $9 million will be expensed as incurred. As of
December 31, 1998, we have spent $24 million for Year 2000
capital projects and had expensed approximately $4 million for
Year 2000-related maintenance activities. Our total Year 2000
project cost, as well as our estimates of the time needed to
complete remedial efforts, are based on currently available
information and do not include the estimated costs and time
associated with the impact of third party Year 2000 issues.
We believe we are managing the Year 2000 issue in such
a way that our customers will not experience any interruption of
service. We believe the most likely worst-case scenario from the
Year 2000 issue will be disruption in power plant monitoring
systems, thereby producing inaccurate data and potential failures
in electronic switching mechanisms at transmission junctions.
This would prolong localized outages, as technicians would have
to manually activate switches. Such an event could have a
material, but currently undeterminable, effect on our financial
results. We are developing contingency plans to address the
effects of any delay in becoming Year 2000 compliant and expect
to have contingency plans completed by June 1999.
The costs of the project and the dates on which we plan
to complete the Year 2000 modifications are based on management's
best estimates, which were derived from numerous assumptions of
future events including the continued availability of certain
resources, and other factors. However, there can be no guarantee
that this project will be completed as planned and actual results
could differ materially from the estimates. Specific factors that
might cause material differences include but are not limited to,
the availability and cost of trained personnel, the ability to
locate and correct all relevant computer code, and similar
uncertainties.
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 1998 1997 1996
- ----------------------------------------------------------------------------------------------------
(In thousands)
OPERATING REVENUES $2,519,662 $2,473,582 $2,469,785
---------- ---------- ----------
OPERATING EXPENSES AND TAXES:
Fuel and purchased power 511,645 437,223 456,629
Nuclear operating costs 279,917 267,681 247,708
Other operating costs 411,985 446,778 420,523
---------- ---------- ----------
Total operation and maintenance expenses 1,203,547 1,151,682 1,124,860
Provision for depreciation and amortization 415,715 429,941 383,441
General taxes 242,524 234,964 241,998
Income taxes 170,956 168,427 189,417
---------- ---------- ----------
Total operating expenses and taxes 2,032,742 1,985,014 1,939,716
---------- ---------- ----------
OPERATING INCOME 486,920 488,568 530,069
OTHER INCOME 47,621 52,847 37,537
---------- ---------- ----------
INCOME BEFORE NET INTEREST CHARGES 534,541 541,415 567,606
---------- ---------- ----------
NET INTEREST CHARGES:
Interest on long-term debt 173,781 204,285 211,935
Allowance for borrowed funds used during
construction and capitalized interest (2,096) (2,699) (3,136)
Other interest expense 46,110 31,209 28,211
Subsidiaries' preferred stock dividend requirements 15,426 15,426 15,426
---------- ---------- ----------
Net interest charges 233,221 248,221 252,436
---------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM 301,320 293,194 315,170
EXTRAORDINARY ITEM (NET OF INCOME TAXES) (Note 1) (30,522) -- --
---------- ---------- ----------
NET INCOME 270,798 293,194 315,170
PREFERRED STOCK DIVIDEND REQUIREMENTS 11,970 12,392 12,497
---------- ---------- ----------
EARNINGS ON COMMON STOCK $ 258,828 $ 280,802 $ 302,673
========== ========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
At December 31, 1998 1997
- ---------------------------------------------------------------------------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service $8,158,763 $8,666,272
Less--Accumulated provision for depreciation 3,610,155 3,546,594
---------- ----------
4,548,608 5,119,678
---------- ----------
Construction work in progress--
Electric plant 174,418 99,158
Nuclear fuel 17,003 21,360
---------- ----------
191,421 120,518
---------- ----------
4,740,029 5,240,196
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
PNBV Capital Trust (Note 2) 475,087 482,220
Letter of credit collateralization (Note 2) 277,763 277,763
Other (Note 3B) 538,411 529,408
---------- ----------
1,291,261 1,289,391
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents 33,213 4,680
Receivables--
Customers (less accumulated provisions of $6,397,000 and
$5,618,000, respectively, for uncollectible accounts) 215,257 235,332
Associated companies 229,854 25,348
Other 47,684 87,566
Materials and supplies, at average cost--
Owned 76,756 75,580
Under consignment 48,341 47,890
Prepayments and other 78,618 78,348
---------- ----------
729,723 554,744
---------- ----------
DEFERRED CHARGES:
Regulatory assets 1,723,133 1,601,709
Unamortized sale and leaseback costs 90,098 95,096
Property taxes 101,360 100,043
Other 57,547 96,276
---------- ----------
1,972,138 1,893,124
---------- ----------
$8,733,151 $8,977,455
========== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholders' equity $2,681,873 $2,724,319
Preferred stock--
Not subject to mandatory redemption 160,965 160,965
Subject to mandatory redemption 10,000 15,000
Preferred stock of consolidated subsidiary--
Not subject to mandatory redemption 50,905 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 2,215,042 2,569,802
---------- ----------
5,253,785 5,655,991
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock 528,792 278,492
Short-term borrowings (Note 4)--
Associated companies 88,732 --
Other 249,451 302,229
Accounts payable 99,659 115,836
Accrued taxes 188,295 157,095
Accrued interest 45,221 53,165
Other 114,162 115,256
---------- ----------
1,314,312 1,022,073
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes 1,601,887 1,698,354
Accumulated deferred investment tax credits 154,538 184,804
Pensions and other postretirement benefits 136,856 158,038
Other 271,773 258,195
---------- ----------
2,165,054 2,299,391
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES
(Notes 2 and 5 ) ---------- ----------
$8,733,151 $8,977,455
========== ==========
<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, 1998 1997
- -----------------------------------------------------------------------------------------------------------------------------
(Dollars in thousands, except per share amounts)
COMMON STOCKHOLDERS' EQUITY:
Common stock, $9 par value, authorized 175,000,000 shares-100 shares outstanding $ 1 $ 1
Other paid-in capital 2,098,728 2,103,259
Accumulated other comprehensive income (Note 3C) -- (615)
Retained earnings (Note 3A) 583,144 621,674
---------- ----------
Total common stockholders' equity 2,681,873 2,724,319
---------- ----------
Number of Shares Optional
Outstanding Redemption Price
---------------- ---------------------
1998 1997 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 4,000,000 100,000 100,000
--------- --------- ------- ---------- ----------
Total not subject to
mandatory redemption 4,609,650 4,609,650 $63,893 160,965 160,965
========= ========= ======= ---------- ----------
Cumulative, $100 par value-
Subject to Mandatory Redemption (Note 3E):
8.45% 150,000 200,000 15,000 20,000
Redemption within one year (5,000) (5,000)
--------- --------- ---------- ----------
Total subject to mandatory redemption 150,000 200,000 10,000 15,000
========= ========= ---------- ----------
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 60,000 101.42 6,085 6,000 6,000
7.75% 250,000 250,000 -- -- 25,000 25,000
8.00% 58,000 58,000 102.07 5,920 5,800 5,800
--------- --------- ------- ---------- ----------
Total not subject to mandatory
redemption 509,049 509,049 $26,619 50,905 50,905
========= ========= ======= ---------- ----------
Subject to Mandatory Redemption (Note 3E):
7.625% 150,000 150,000 106.86 $16,029 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, 1998 1997 1998 1997 1998 1997
- --------------------------------------------------------------------------------------------------------------------------------
(In thousands)
LONG-TERM DEBT (Note 3G):
First mortgage bonds:
Ohio Edison Company- Pennsylvania Power Company-
8.750% due 1998 -- 150,000 9.740% due 1999-2019 20,000 20,000
6.875% due 1999 150,000 150,000 7.500% due 2003 40,000 40,000
6.375% due 2000 80,000 80,000 6.375% due 2004 20,500 20,500
7.375% due 2002 120,000 120,000 6.625% due 2004 14,000 14,000
7.500% due 2002 34,265 34,265 8.500% due 2022 27,250 27,250
8.250% due 2002 125,000 125,000 7.625% due 2023 6,500 6,500
8.625% due 2003 150,000 150,000 ------- -------
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 100,000 100,000
------- ---------
Total first mortgage
bonds. 965,225 1,115,225 128,250 128,250 1,093,475 1,243,475
------- --------- ------- ------- ---------- ----------
Secured notes:
Ohio Edison Company- Pennsylvania Power Company-
7.930% due 2002 39,936 50,646 4.750% due 1998 -- 850
7.680% due 2005 200,000 200,000 6.080% due 2000 23,000 23,000
6.750% due 2015 40,000 40,000 5.400% due 2013 1,000 1,000
7.450% due 2016 47,725 47,725 5.400% due 2017 10,600 10,600
7.100% due 2018 26,000 26,000 7.150% due 2017 17,925 17,925
7.050% due 2020 60,000 60,000 5.900% due 2018 16,800 16,800
7.000% due 2021 69,500 69,500 8.100% due 2020 5,200 5,200
7.150% due 2021 443 443 7.150% due 2021 14,482 14,482
7.625% due 2023 50,000 50,000 6.150% due 2023 12,700 12,700
8.100% due 2023 30,000 30,000 *4.150% due 2027 10,300 10,300
7.750% due 2024 108,000 108,000 6.450% due 2027 14,500 14,500
5.375% due 2028 13,522 -- 5.375% due 2028 1,734 --
5.625% due 2029 50,000 50,000 5.450% due 2028 6,950 6,950
5.950% due 2029 56,212 56,212 6.000% due 2028 14,250 14,250
5.450% due 2033 14,800 14,800 5.950% due 2029 238 238
------- -------
Limited Partnerships-
7.87% weighted
average interest
rate due 1999-2007 11,320 --
------- ---------
817,458 803,326 149,679 148,795 967,137 952,121
------- --------- ------- ------- ---------- ----------
OES Fuel-
5.97% weighted average
interest rate 79,524 80,755
---------- ----------
Total secured notes 1,046,661 1,032,876
---------- ----------
Unsecured notes:
Ohio Edison Company-
5.963% due 1999 115,000 --
6.025% due 1999 85,000 --
6.088% due 1999 50,000 --
6.338% due 1999 -- 40,000
6.400% due 1999 -- 175,000
*4.300% due 2012 50,000 50,000
*3.950% due 2014 50,000 50,000
*3.650% due 2015 50,000 50,000
*4.200% due 2018 57,100 57,100
*4.200% due 2018 56,000 56,000
*4.050% due 2032 53,400 53,400
---------- ----------
Total unsecured notes 566,500 531,500
---------- ----------
Capital lease obligations (Note 2) 36,891 40,614
---------- ----------
Net unamortized discount on debt (4,693) (5,171)
---------- ----------
Long-term debt due within one year (523,792) (273,492)
---------- ----------
Total long-term debt 2,215,042 2,569,802
---------- ----------
TOTAL CAPITALIZATION $5,253,785 $5,655,991
========== ==========
<FN>
* Denotes variable rate issue with December 31, 1998 interest rate shown.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' 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, 1996 152,569,437 $ 1,373,125 $ 726,915 $(608) $ 471,095 $(162,656)
Net income $315,170 315,170
Minimum liability for unfunded
retirement benefits, net of
$27,000 of income taxes (51) (51)
--------
Comprehensive income $315,119
========
Allocation of ESOP shares 1,346 7,646
Cash dividends on preferred stock (12,497)
Cash dividends on common stock (216,126)
- ------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1996 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 $ --
=================================================================================================================================
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, 1996 5,118,699 $211,870 5,200,000 $160,000
-------------------------------------------------------------------------------------
Balance, December 31, 1996 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
======================================================================================
<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, 1998 1997 1996
- --------------------------------------------------------------------------------------------------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income $ 270,798 $293,194 $315,170
Adjustments to reconcile net income to net cash from
operating activities:
Provision for depreciation and amortization 415,715 429,941 383,441
Nuclear fuel and lease amortization 35,086 49,251 52,784
Deferred income taxes, net (59,553) (40,478) 41,365
Investment tax credits, net (14,290) (15,031) (14,041)
Extraordinary item 51,730 -- --
Receivables (144,549) (23,887) 24,326
Materials and supplies (1,627) (10,557) (736)
Accounts payable (8,455) 32,531 962
Other 64,552 21,756 (42,954)
--------- -------- --------
Net cash provided from operating activities 609,407 736,720 760,317
--------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt 117,265 89,773 306,313
Short-term borrowings, net 35,954 -- 229,515
Redemptions and Repayments-
Preferred stock 5,000 5,000 1,016
Long-term debt 225,241 292,409 438,916
Short-term borrowings, net -- 47,251 --
Dividend Payments-
Common stock 297,746 237,848 218,656
Preferred stock 11,865 12,559 12,560
--------- -------- --------
Net cash used for financing activities 386,633 505,294 135,320
--------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions 186,139 179,328 148,189
PNBV capital trust investment -- -- 487,979
Other 8,102 52,671 13,406
--------- -------- --------
Net cash used for investing activities 194,241 231,999 649,574
--------- -------- --------
Net increase (decrease) in cash and cash equivalents 28,533 (573) (24,577)
Cash and cash equivalents at beginning of year 4,680 5,253 29,830
--------- -------- --------
Cash and cash equivalents at end of year $ 33,213 $ 4,680 $ 5,253
========= ======== ========
SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized) $ 201,064 $212,987 $224,541
========= ======== ========
Income taxes $ 219,226 $228,399 $157,477
========= ======== ========
<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, 1998 1997 1996
- ---------------------------------------------------------------------------------------------------
(In thousands)
GENERAL TAXES:
Real and personal property $ 116,868 $ 114,111 $ 115,443
State gross receipts 104,175 99,262 104,158
Social security and unemployment 12,701 14,113 14,602
Other 8,780 7,478 7,795
---------- ---------- ----------
Total general taxes $ 242,524 $ 234,964 $ 241,998
========== ========== ==========
PROVISION FOR INCOME TAXES:
Currently payable-
Federal $ 229,164 $ 225,529 $ 164,132
State 14,732 17,784 9,839
---------- ---------- ----------
243,896 243,313 173,971
---------- ---------- ----------
Deferred, net-
Federal (53,943) (34,429) 37,277
State (5,610) (6,048) 4,088
---------- ---------- ----------
(59,553) (40,477) 41,365
---------- ---------- ----------
Investment tax credit amortization (14,290) (15,031) (14,041)
---------- ---------- ----------
Total provision for income taxes $ 170,053 $ 187,805 $ 201,295
========== ========== ==========
INCOME STATEMENT CLASSIFICATION
OF PROVISION FOR INCOME TAXES:
Operating income $ 170,956 $ 168,427 $ 189,417
Other income 20,305 19,378 11,878
Extraordinary item (21,208) -- --
---------- ---------- ----------
Total provision for income taxes $ 170,053 $ 187,805 $ 201,295
========== ========== ==========
RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT
STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES:
Book income before provision for income taxes $ 440,851 $ 480,999 $ 516,465
========== ========== ==========
Federal income tax expense at statutory rate $ 154,298 $ 168,350 $ 180,763
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits (14,290) (15,031) (14,041)
State income taxes net of federal income tax benefit 5,929 7,628 9,053
Amortization of tax regulatory assets 27,599 28,277 26,945
Other, net (3,483) (1,419) (1,425)
---------- ---------- ----------
Total provision for income taxes $ 170,053 $ 187,805 $ 201,295
========== ========== ==========
ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31:
Property basis differences $ 880,645 $1,019,952 $1,086,533
Allowance for equity funds used during construction 169,780 210,136 233,345
Deferred nuclear expense 237,602 252,946 262,123
Competitive transition charge 135,730 -- --
Customer receivables for future income taxes 164,618 204,643 219,932
Deferred sale and leaseback costs 45,521 47,796 50,212
Unamortized investment tax credits (55,495) (67,208) (72,663)
Other 23,486 30,089 (2,396)
---------- ---------- ----------
Net deferred income tax liability $1,601,887 $1,698,354 $1,777,086
========== ========== ==========
<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, 1998 or 1997, 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 initially maintains
current base electric rates for the Company through December 31, 2005.
At the end of the regulatory plan period, the Company's base rates will
be reduced by $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 June 1998, the PPUC authorized a rate restructuring plan
for Penn, which superseded the regulatory plan which had been in place
for Penn since 1996 and 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 an 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, 1998
were $146 million and $978 million, 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, 1998, the Companies' cumulative additional
capital recovery and regulatory asset amortization amounted to $696
million (including Penn's impairment discussed above).
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 electric plant was
approximately 3.0% in 1998, 1997, and 1996. In addition to the
straight-line depreciation recognized in 1998, 1997 and 1996, the
Companies recognized additional capital recovery of $141 million
(excluding Penn's impairment), $172 million and $144 million,
respectively, as additional depreciation expense in accordance with
their regulatory plans. Such additional charges in the accumulated
provision for depreciation were $422 million and $343 million as of
December 31, 1998 and 1997, 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' share of the future obligation to decommission these units is
approximately $511 million in current dollars and (using a 4.0%
escalation rate) approximately $1.4 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 $83 million for decommissioning through
their electric rates from customers through December 31, 1998. If the
actual costs of decommissioning the units exceed the funds accumulated
from investing amounts recovered from customers, the Companies expect
that additional amount to be recoverable from their customers. The
Companies have approximately $130.6 million invested in external
decommissioning trust funds as of December 31, 1998. Earnings on these
funds are reinvested with a corresponding increase to the
decommissioning liability. The Companies have also recognized an
estimated liability of approximately $13.7 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 1999.
COMMON OWNERSHIP OF GENERATING FACILITIES-
The Companies, together with the other FirstEnergy utilities,
CEI and TE, and Duquesne Light Company (Duquesne) constitute the Central
Area Power Coordination Group (CAPCO). The CAPCO companies own and/or
lease, as tenants in common, various power generating facilities. Each
of the companies is obligated to pay a share of the costs associated
with any jointly owned facility in the same proportion as its interest.
The Companies' portions of operating expenses associated with jointly
owned facilities are included in the corresponding operating expenses on
the Consolidated Statements of Income. The amounts reflected on the
Consolidated Balance Sheet under utility plant at December 31, 1998,
include the following:
Companies'
Utility Accumulated Construction Ownership/
Plant Provision for Work in Leasehold
Generating Units in Service Depreciation Progress Interest
- ---------------------------------------------------------------------
(In millions)
W.H. Sammis #7 $ 303.3 $ 101.3 $ 2.0 68.80%
Bruce Mansfield #1,
#2 and #3 791.9 399.7 8.3 50.68%
Beaver Valley
#1 and #2 1,653.0 599.9 10.1 47.11%
Perry 1,295.4 748.8 7.5 35.24%
- ------------------------------------------------------------------
Total $4,043.6 $1,849.7 $27.9
===================================================================
On October 15, 1998, FirstEnergy announced that it signed an
agreement in principle with Duquesne that would result in the transfer
of 1,436 megawatts owned by Duquesne at eight CAPCO generating units in
exchange for 1,328 megawatts at three non-CAPCO power plants owned by
the Company, Penn and CEI. As part of this exchange, the Companies will
transfer their 246-megawatt Niles Plant and 339-megawatt New Castle
Plant to Duquesne. A definitive agreement on the exchange of assets,
which will be structured as a tax-free transaction to the extent
possible, will provide FirstEnergy's utility operating companies with
exclusive ownership and operating control of all CAPCO generating units.
Duquesne will fund decommissioning costs equal to its percentage
interest in the three nuclear generating units to be transferred. The
asset transfer is expected to take twelve to eighteen months to close.
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-
The Companies' trusteed, noncontributory defined benefit
pension plans cover almost all 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 plans. 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, 1998. The assets of the pension plans 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 1998 and the Companies' plans in 1997 on the Consolidated
Balance Sheets as of December 31 (which includes 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):
<OPTION>
Other
Pension Benefits Postretirement Benefits
---------------------- -----------------------
1998 1997 1998 1997
- ------------------------------------------------------------------------------------------
(In millions)
Change in benefit obligation:
Benefit obligation as of January 1* $1,327.5 $ 688.5 $ 534.1 $ 241.1
Service cost 25.0 12.9 7.5 4.1
Interest cost 92.5 49.8 37.6 17.6
Plan amendments 44.3 3.0 40.1 --
Early retirement program expense -- 31.5 -- 1.9
Actuarial loss 101.6 62.9 10.7 17.0
Benefits paid (90.8) (54.5) (28.7) (14.1)
- ----------------------------------------------------------------------------------------
Benefit obligation as of December 31 1,500.1 794.1 601.3 267.6
- ----------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets as of
January 1* 1,542.5 946.3 2.8 2.0
Actual return on plan assets 231.3 188.8 0.7 0.5
Company contribution -- -- 0.4 0.3
Benefits paid (90.8) (54.5) -- --
- ----------------------------------------------------------------------------------------
Fair value of plan assets as of
December 31 1,683.0 1,080.6 3.9 2.8
- ----------------------------------------------------------------------------------------
Funded status of plan* 182.9 286.5 (597.4) (264.8)
Unrecognized actuarial loss (gain) (110.8) (139.5) 30.6 24.0
Unrecognized prior service cost 63.0 21.0 27.4 (13.5)
Unrecognized net transition obligation
(asset) (18.0) (25.9) 129.3 138.6
- ----------------------------------------------------------------------------------------
Prepaid (accrued) benefit cost $ 117.1 $ 142.1 $(410.1) $(115.7)
========================================================================================
Assumptions used as of December 31:
Discount rate 7.00% 7.25% 7.00% 7.25%
Expected long-term return on plan assets 10.25% 10.00% 10.25% 10.00%
Rate of compensation increase 4.00% 4.00% 4.00% 4.00%
<FN>
* 1998 beginning balances reflect 1998 merger of the Companies'
and Centerior plans into FirstEnergy plans.
Net pension and other postretirement benefit costs for the
three years ended December 31, 1998 (including the Companies' share
of FirstEnergy plans' 1998 pension benefits costs and other
postretirement benefit costs of $(39.7) million and $31.2 million,
respectively) were computed as follows:
Other
Pension Benefits Postretirement Benefits
---------------------- -----------------------
1998 1997 1996 1998 1997 1996
- ------------------------------------------------------------------------------------------------
(In millions)
Service cost $ 25.0 $ 12.9 $ 14.2 $ 7.5 $ 4.1 $ 4.3
Interest cost 92.5 49.8 49.3 37.6 17.6 17.4
Expected return on plan assets (152.7) (91.9) (83.2) (0.3) (0.2) (0.1)
Amortization of transition obligation
(asset) (8.0) (8.0) (8.0) 9.2 8.2 10.1
Amortization of prior service cost 2.3 2.1 2.3 (0.8) 0.3 (1.2)
Recognized net actuarial loss (gain) (2.6) (0.9) -- -- -- 0.1
Voluntary early retirement program
expense -- 31.5 12.5 -- 1.9 0.5
Plan curtailment loss (gain) -- -- (12.8) -- -- 13.1
- -----------------------------------------------------------------------------------------------
Net benefit cost $ (43.5) $ (4.5) $(25.7) $53.2 $31.9 $44.2
===============================================================================================
In accordance with SFAS 88 "Employers' Accounting for
Settlements and Curtailments of Defined Benefit Pension Plans and for
Termination Benefits," the 1996 net pension costs and postretirement
benefit costs shown above included curtailment effects (significant
changes in projected plan assumptions) relating to the pension and
postretirement benefit plans. The employee terminations reflected in
the Companies' 1996 voluntary early retirement program represented a
plan curtailment that significantly reduced the expected future
employee service years and the related accrual of defined pension and
postretirement benefits. In the pension plan, the reduction in the
benefit obligation increased the net pension asset and was shown as a
plan curtailment gain. In the postretirement benefit plan, the
unrecognized prior service cost associated with service years no
longer expected to be rendered as a result of the terminations, was
shown as a plan curtailment loss.
The FirstEnergy's plans' health care trend rate assumption
is 5.5% in the first year gradually decreasing to 4.0% for the year
2008 and later. Assumed health care cost trend rates have a
significant effect on the amounts reported for the health care plan.
An increase in the health care trend rate assumption by one
percentage point would increase the total service and interest cost
components by $4.0 million and the postretirement benefit obligation
by $68.1 million. A decrease in the same assumption by one percentage
point would decrease the total service and interest cost components
by $3.2 million and the postretirement benefit obligation by $55.2
million.
TRANSACTIONS WITH AFFILIATED COMPANIES-
Operating revenues 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 $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.
SUPPLEMENTAL CASH FLOWS INFORMATION-
All temporary cash investments purchased with an initial
maturity of three months or less are reported as cash equivalents on
the Consolidated Balance Sheets. The Companies reflect temporary cash
investments at cost, which approximates their market value. Noncash
financing and investing activities included capital lease transactions
amounting to $1.6 million, $3.0 million and $2.0 million for the years
1998, 1997 and 1996, 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:
1998 1997
- --------------------------------------------------------------------
Carrying Fair Carrying Fair
Value Value Value Value
- --------------------------------------------------------------------
(In millions)
Long-term debt $2,627 $2,775 $2,727 $2,835
Preferred stock $ 150 $ 155 $ 155 $ 161
Investments other than cash
and cash equivalents:
Debt securities
- Maturity (5-10 years) $ 481 $ 520 $ 486 $ 512
- Maturity (more than 10 years) 258 305 259 294
Equity securities 14 14 14 14
All other 170 179 145 147
- ---------------------------------------------------------------------
$ 923 $1,018 $ 904 $ 967
======================================================================
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 trust 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
believe they will continue to be able to bill and collect cost-based
rates relating to all of the Company's operations and Penn's
nongeneration operations; accordingly, it is appropriate that the
Companies continue the application of SFAS 71 to these respective
operations. The Companies also recognized additional cost recovery of
$50 million, $39 million and $34 million in 1998, 1997 and 1996,
respectively, as additional regulatory asset amortization in
accordance with their regulatory plans.
Regulatory assets on the Consolidated Balance Sheets are
comprised of the following:
1998 1997
- ----------------------------------------------------------------------
(In millions)
Nuclear unit expenses $ 666.7 $ 707.7
Customer receivables for future income taxes 458.3 560.7
Competitive transition charge 331.0 --
Sale and leaseback costs 127.7 134.3
Loss on reacquired debt 81.9 89.1
Employee postretirement benefit costs 28.9 25.9
Uncollectible customer accounts 6.8 18.9
Perry Unit 2 termination -- 36.7
DOE decommissioning and decontamination costs 12.2 16.5
Other 9.6 11.9
- ---------------------------------------------------------------------
Total $1,723.1 $1,601.7
=====================================================================
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 interests 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, 1998, are summarized as follows:
1998 1997 1996
- ------------------------------------------------------
(In millions)
Operating leases
Interest element $110.0 $111.3 $107.6
Other 28.9 23.2 18.3
Capital leases
Interest element 5.3 6.1 6.5
Other 4.8 6.0 6.3
- -----------------------------------------------------
Total rentals $149.0 $146.6 $138.7
=====================================================
The future minimum lease payments as of December 31, 1998,
are:
Operating Leases
----------------------------
Capital Lease PNBV Capital
Leases Payments Trust Net
- -------------------------------------------------------------------
(In millions)
1999 $ 12.0 $ 125.8 $ 44.0 $ 81.8
2000 10.4 125.0 54.6 70.4
2001 9.3 127.6 59.5 68.1
2002 8.8 130.8 61.0 69.8
2003 8.6 137.3 62.6 74.7
Years thereafter 69.8 1,842.4 589.2 1,253.2
- --------------------------------------------------------------------
Total minimum lease
payments 118.9 $2,488.9 $870.9 $1,618.0
======== ====== ========
Executory costs 29.5
- -----------------------------------
Net minimum lease payments 89.4
Interest portion 52.5
- -----------------------------------
Present value of net minimum
lease payments 36.9
Less current portion 4.0
- -----------------------------------
Noncurrent portion $ 32.9
===================================
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 $516.3 million at
December 31, 1998.
(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 merger. The ESOP loan is included in
Other Property and Investments on the Consolidated Balance Sheet as
of December 31, 1998 and 1997 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 and 1996,
429,515 and 404,522 shares, respectively, 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 and 1996 Consolidated Statements of
Income was calculated as follows:
- --------------------------------------------------------
1997 1996
- --------------------------------------------------------
(In millions)
Base compensation $ 9.9 $ 9.0
Dividends on common stock
held by the ESOP and used to
service debt (3.4) (2.9)
- ---------------------------------------------------------
Net expense $ 6.5 $ 6.1
=========================================================
(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 Stockholders'
Equity. Comprehensive income includes net income as reported on the
Consolidated Statements of Income and all other changes in common
stockholders' 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.
Preference stock authorized for the Company is 8,000,000
shares without par value. No preference shares are currently
outstanding.
(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 that began on September 16,
1997. 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 1999-2001 and $1 million in each year 2002-2003.
(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 Trustee
through December 31, 1998, the Company's annual sinking and
improvement fund requirement for all bonds issued under the mortgage
amounts to $30 million. The Company expects to deposit funds in 1999
that will be withdrawn upon the surrender for cancellation of a like
principal amount of bonds, which are specifically authenticated for
such purposes against unfunded property additions or against
previously retired bonds. This method can result in minor increases
in the amount of the annual sinking fund requirement.
Sinking fund requirements for first mortgage bonds and
maturing long-term debt (excluding capital leases) for the next five
years are:
(In millions)
- --------------------------------
1999 $519.8
2000 328.8
2001 96.0
2002 326.4
2003 246.0
- -------------------------------
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
$338.8 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 Company is entitled to a credit against
their obligation to repay those bonds. The Company pays 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 $250 million at
December 31, 1998, which are supported by a $250 million long-term
revolving credit facility agreement which expires December 30, 1999.
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, 1998,
consisted of $129.5 million of bank borrowings and $120.0 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
$120 million under a receivables financing agreement at rates based on
certain bank commercial paper and is required to pay an annual fee of
0.26% on the amount of the entire finance limit. The receivables
financing agreement expires in 1999. At December 31, 1998, the Company
also had total short-term borrowings of $88.7 million from its
affiliates.
The Company has a line of credit with a domestic bank that
provides for borrowings of up to $75 million under various interest
rate options. Short-term borrowings may be made under this line of
credit on its unsecured notes. To assure the availability of this
line, the Company is required to pay an annual commitment fee of
0.20%. This line expires in May 1999. The weighted average interest
rates on short-term borrowings outstanding at December 31, 1998 and
1997, were 5.61% and 6.02%, respectively.
5. COMMITMENTS, GUARANTEES AND CONTINGENCIES:
CAPITAL EXPENDITURES-
The Companies' current forecasts reflect expenditures of
approximately $1 billion for property additions and improvements from
1999-2003, of which approximately $169 million is applicable to 1999.
Investments for additional nuclear fuel during the 1999-2003 period
are estimated to be approximately $167 million, of which approximately
$23 million applies to 1999. During the same periods, the Companies'
nuclear fuel investments are expected to be reduced by approximately
$169 million and $35 million, respectively, as the nuclear fuel is
consumed.
NUCLEAR INSURANCE-
The Price-Anderson Act limits the public liability relative
to a single incident at a nuclear power plant to $9.7 billion. The
amount is covered by a combination of private insurance and an
industry retrospective rating plan. Based on 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 co-owners contribute
their proportionate shares of any assessments under the retrospective
rating plan) would be $114.2 million per incident but not more than
$13 million in any one year for each incident.
The Companies are also insured as to their respective
interests in the Beaver Valley Station and the Perry Plant under
policies issued to the operating company for each plant. Under these
policies, up to $2.75 billion is provided for property damage and
decontamination and decommissioning costs. The Companies have also
obtained approximately $308.1 million of insurance coverage for
replacement power costs for their respective interests in Perry and
Beaver Valley. Under these policies, the Companies can be assessed a
maximum of approximately $15.4 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.
GUARANTEES-
The CAPCO companies have each severally guaranteed certain
debt and lease obligations in connection with a coal supply contract
for the Bruce Mansfield Plant. As of December 31, 1998, the Companies'
shares of the guarantees (which approximate fair market value) were
$28.4 million. The price under the coal supply contract, which
includes certain minimum payments, has been determined to be
sufficient to satisfy the debt and lease obligations. The Companies'
total payments under the coal supply contract were $134.7 million,
$119.5 million and $113.8 million during 1998, 1997 and 1996,
respectively. The Companies' minimum payment for 1999 is approximately
$35 million. The contract expires December 31, 1999.
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 $260
million, which is included in the construction forecast provided
under "Capital Expenditures" for 1999 through 2003.
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 in 1999 will be
achieved by burning lower-sulfur fuel, generating more electricity
from lower-emitting plants, and/or purchasing emission allowances.
Plans for complying with reductions required for the year 2000 and
thereafter have not been finalized. In September 1998, the
Environmental Protection Agency (EPA) finalized regulations requiring
additional NOx reductions from the 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. By September 1999, each
of the twenty-two states are required to submit revised State
Implementation Plans (SIP) which comply with individual state NOx
budgets established by the EPA. These state NOx budgets contemplate an
85% reduction in utility plant NOx emissions from 1990 emissions. A
proposed Federal Implementation Plan accompanied the NOx Transport
Rule and may be implemented by the EPA in states which fail to revise
their SIP. In another separate but related action, eight states filed
petitions with EPA under Section 126 of the Clean Air Act seeking
reductions of NOx emissions which are alleged to contribute to ozone
pollution in the eight petitioning states. The EPA suggests that the
Section 126 petitions will be adequately addressed by the NOx
Transport Program, but a September 1998 proposed rulemaking
established an alternative program which would require nearly
identical 85% NOx reductions at the Companies' Ohio and Pennsylvania
plants by May 2003 in the event implementation of the NOx Transport
Rule is delayed. FirstEnergy continues to evaluate its compliance
plans and other compliance options and currently estimates its
additional capital expenditures for NOx reductions may reach $500
million.
The 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 $25,000 for each day the unit is in violation. The EPA has an
interim enforcement policy for SO2 regulations in Ohio that allows for
compliance based on a 30-day averaging period. The 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. The
cost of compliance with these regulations may be substantial and
depends on the manner in which they are implemented by the states in
which the Companies operate affected facilities.
Legislative, administrative and judicial actions will
continue to change the way that the Companies must operate in order to
comply with environmental laws and regulations. With respect to any
such changes and to the environmental matters described above, the
Company expects that while it remains regulated, any resulting
additional capital costs which may be required, as well as any
required increase in operating costs, would ultimately be recovered
from its customers.
6. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
The following summarizes certain consolidated operating
results by quarter for 1998 and 1997.
March 31, June 30, September 30, December 31,
Three Months Ended 1998 1998 1998 1998
- --------------------------------------------------------------------------------------------
(In millions)
Operating Revenues $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
==========================================================================================
March 31, June 30, September 30, December 31,
Three Months Ended 1997 1997 1997 1997
- --------------------------------------------------------------------------------------------
(In millions)
Operating Revenues $604.8 $593.3 $652.7 $622.9
Operating Expenses and Taxes 478.5 467.3 511.6 527.7
- ------------------------------------------------------------------------------------------
Operating Income 126.3 126.0 141.1 95.2
Other Income 13.5 14.1 12.0 13.3
Net Interest Charges 63.8 63.2 61.3 60.0
- ------------------------------------------------------------------------------------------
Net Income $ 76.0 $ 76.9 $ 91.8 $ 48.5
==========================================================================================
Earnings on Common Stock $ 72.9 $ 73.8 $ 88.7 $ 45.4
==========================================================================================
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, 1998 and 1997, and the related
consolidated statements of income, common stockholders' equity,
preferred stock, cash flows and taxes for each of the three years in
the period ended December 31, 1998. These financial statements are
the responsibility of the Company's management. Our responsibility is
to express an opinion on these financial statements based on our
audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of Ohio
Edison Company and subsidiaries as of December 31, 1998 and 1997, and
the results of their operations and their cash flows for each of the
three years in the period ended December 31, 1998, in conformity with
generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Cleveland, Ohio
February 12, 1999