Management Report
The consolidated financial statements were prepared by the
management of FirstEnergy Corp., who takes responsibility for their integrity
and objectivity. The statements were prepared in conformity with generally
accepted accounting principles and are consistent with other financial
information appearing elsewhere in this report. Arthur Andersen LLP,
independent public accountants, have expressed an opinion on the Company's
consolidated financial statements.
The Company's internal auditors, who are responsible to the Audit
Committee of the Board of Directors, review the results and performance of
operating units within the Company for adequacy, effectiveness and
reliability of accounting and reporting systems, as well as managerial and
operating controls.
The Audit Committee consists of five nonemployee directors whose
duties include: consideration of the adequacy of the internal controls of the
Company and the objectivity of financial reporting; inquiry into the number,
extent, adequacy and validity of regular and special audits conducted by
independent public accountants and the internal auditors; recommendation to
the Board of Directors of independent accountants to conduct the normal
annual audit and special purpose audits as may be required; and reporting to
the Board of Directors the Committee's findings and any recommendation for
changes in scope, methods or procedures of the auditing functions. The
Committee also reviews the results of management's programs to monitor
compliance with the Company's policies on business ethics and risk
management. The Audit Committee held six meetings in 1999.
Richard H. Marsh
Vice President and
Chief Financial Officer
Harvey L. Wagner
Controller and
Chief Accounting Officer
Report of Independent Public Accountants
To the Stockholders and Board of Directors of FirstEnergy Corp.:
We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of FirstEnergy Corp. (an Ohio
corporation) and subsidiaries as of December 31, 1999 and 1998, 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, 1999. These financial statements are the
responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used
and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audits provide
a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of FirstEnergy Corp.
and subsidiaries as of December 31, 1999 and 1998, and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1999, in conformity with generally accepted accounting
principles.
ARTHUR ANDERSEN LLP
Cleveland, Ohio
February 11, 2000
FIRSTENERGY CORP.
SELECTED FINANCIAL DATA
For the Years Ended December 31, 1999 1998 1997 1996 1995
- -------------------------------------------------------------------------------------------------
(In thousands, except per share amounts)
Revenues $ 6,319,647 $ 5,874,906 $ 2,961,125 $2,521,788 $2,500,770
-------------------------------------------------------------
Income Before Extraordinary Item $ 568,299 $ 441,396 $ 305,774 $ 302,673 $ 294,747
-------------------------------------------------------------
Net Income $ 568,299 $ 410,874 $ 305,774 $ 302,673 $ 294,747
-------------------------------------------------------------
Earnings per Share of Common
Stock:
Before Extraordinary Item $2.50 $1.95 $1.94 $2.10 $2.05
After Extraordinary Item $2.50 $1.82 $1.94 $2.10 $2.05
-------------------------------------------------------------
Dividends Declared per Share
of Common Stock $1.50 $1.50 $1.50 $1.50 $1.50
-------------------------------------------------------------
Total Assets $18,224,047 $18,192,177 $18,261,481 $9,218,623 $9,035,112
-------------------------------------------------------------
Capitalization at December 31:
Common Stockholders' Equity $ 4,563,890 $ 4,449,158 $ 4,159,598 $2,503,359 $2,407,871
Preferred Stock:
Not Subject to Mandatory
Redemption 648,395 660,195 660,195 211,870 211,870
Subject to Mandatory
Redemption 256,246 294,710 334,864 155,000 160,000
Long-Term Debt 6,001,264 6,352,359 6,969,835 2,712,760 2,786,256
-------------------------------------------------------------
Total Capitalization $11,469,795 $11,756,422 $12,124,492 $5,582,989 $5,565,997
=============================================================
PRICE RANGE OF COMMON STOCK
FirstEnergy Corp.'s Common Stock is listed on the New York Stock Exchange and is traded on
other registered exchanges.
1999 1998
- ------------------------------------------------------------------------
First Quarter High-Low 33-3/16 27-15/16 31-5/8 27-7/8
----------------------------------------
Second Quarter High-Low 32-1/8 27-15/16 31-7/8 28-1/2
----------------------------------------
Third Quarter High-Low 31-5/16 24-3/4 31-5/16 27-1/16
----------------------------------------
Fourth Quarter High-Low 26-9/16 22-1/8 34-1/16 29-3/16
----------------------------------------
Yearly High-Low 33-3/16 22-1/8 34-1/16 27-1/16
- ------------------------------------------------------------------------
<FN>
Prices are based on reports published in The Wall Street Journal for New York Stock Exchange
-----------------------
Transactions.
HOLDERS OF COMMON STOCK
There were 181,806 and 180,679 holders of the Company's Common Stock of the
232,454,287 shares as of December 31, 1999 and 231,959,541 shares as of
January 31, 2000, respectively. Information regarding retained earnings
available for payment of cash dividends is given in Note 3A.
FIRSTENERGY CORP.
Management's Discussion and Analysis of
Results of Operations and Financial Condition
Results of Operations
FirstEnergy Corp. was formed when the merger of Ohio Edison Company
(OE) and Centerior Energy Corporation (Centerior) became effective on
November 8, 1997. The merger was accounted for using purchase accounting
under the guidelines of Accounting Principles Board Opinion No. 16, "Business
Combinations." Under these guidelines, the results of operations for the
combined entity are reported from the point of consummation forward. As a
result, our financial statements for 1997 reflect 12 months of operations for
OE and its wholly owned subsidiary, Pennsylvania Power Company (Penn), but
include only 7 weeks (November 8, to December 31, 1997) for the former
Centerior companies - The Cleveland Electric Illuminating Company (CEI) and
The Toledo Edison Company (TE). Results for 1998 and 1999 include operations
for the entire year for OE and Penn (OE companies), CEI and TE.
During 1998 and 1999, we took additional steps to expand our
portfolio of energy-related products and services by completing a number of
acquisitions and forming a joint venture. During 1998, FirstEnergy Facilities
Services Group, LLC (FE Facilities), a wholly owned subsidiary, acquired
eight companies, which mainly provide heating, ventilating and air-
conditioning (HVAC) services. FE Facilities made one additional acquisition
in 1999, bringing its total number of acquisitions to 11 over the past three
years. On June 8, 1998, we acquired MARBEL Energy Corporation (MARBEL), a
fully integrated natural gas company. On September 30, 1999, MARBEL formed a
joint venture with Range Resources Corporation that combines both companies'
assets for the development of Appalachian Basin oil and natural gas
properties and related gas-gathering and transportation systems. This joint
venture is accounted for using the equity method of accounting with our
proportionate share of earnings reflected in our consolidated financial
results. During 1999, three additional retail gas acquisitions were added to
FirstEnergy Trading Services, Inc. (FETS). All acquisitions in 1998 and 1999
were accounted for using purchase accounting and are included in our
consolidated results from their respective acquisition dates.
As Ohio approaches customer choice of energy suppliers in 2001, we
continue to develop our unregulated retail sales strategy, in part through
acquisitions, which expand the products and services we can offer customers.
In addition, related changes to our sales and marketing activities were made
during 1999 to further support our retail sales strategy. As a result, we
increased our functional integration across organization lines to improve
economies and efficiencies to better serve customers in unregulated markets.
By taking advantage of the new markets made available by advancing
deregulation, we now cover a 13-state market area in the northeastern portion
of the U.S. This expanded market has yielded significant multi-year contracts
for us in 1999. We also completed major information systems during 1999,
which improve our capabilities while resolving Year 2000 concerns.
Total revenues increased by $445 million in 1999 and $2.9 billion
in 1998 compared to the prior year results. In 1999, the increased revenues
resulted primarily from contributions from the Electric Utility Operating
Companies' (EUOC) business segment and newly acquired businesses, which were
partially offset by reduced revenues from the FETS business segment due to
refocusing its activities to support our retail marketing activities. The
EUOC currently represent the more traditional vertically integrated electric
utility operations. In 1998, inclusion of a full 12 months of results for the
former Centerior companies in the EUOC business segment compared to only 7
weeks in 1997 was the largest factor contributing to the change in electric
sales, adding $2.2 billion. The sources of the increases in revenues during
1999 and 1998 are summarized in the following table.
Sources of Revenue Changes 1999 1998
- ----------------------------------------------------
(In millions)
Electric sales $213.2 $2,204.7
Other electric utility
revenues 3.1 115.0
- ----------------------------------------------------
Total EUOC 216.3 2,319.7
FETS (220.1) 367.6
New businesses acquired 341.5 220.0
Unregulated electric sales 54.0 6.5
Gain on sale of investment 53.0 --
- ----------------------------------------------------
Net Revenue Increase $444.7 $2,913.8
- ----------------------------------------------------
Electric Sales
EUOC revenues increased by $216.3 million in 1999, compared to
1998, benefiting from increased kilowatt-hour sales, offset in part by lower
unit prices. Residential, commercial and industrial customers all contributed
to higher EUOC retail sales. Retail kilowatt-hour sales increased due to
strong consumer-driven economic growth and, to a lesser extent, the weather.
Over 6,500 new EUOC customers were added in 1999. Weather-induced electricity
demand in the wholesale market and additional available internal generation
combined to increase sales to wholesale customers.
EUOC retail kilowatt-hour sales in 1998 increased substantially
over 1997 due to the merger with the former Centerior companies. Excluding
the impact of the merger, retail sales for the OE companies in 1998 were
approximately the same as the previous year after setting a new record in
1997. 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 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 lower industrial sales in 1998, compared to the prior year.
Changes in EUOC kilowatt-hour sales by customer class in 1999 and 1998 are
summarized in the following table.
EUOC KWH Sales Changes 1999 1998*
- --------------------------------------------
Residential 6.7% 1.7%
Commercial 3.9% 3.5%
Industrial 3.4% (3.6)%
- --------------------------------------------
Total Retail 4.4% --
Wholesale 28.4% 8.9%
- --------------------------------------------
Total Sales 6.6% 1.4%
- --------------------------------------------
<FN>
* Reflects OE companies only
Unregulated kilowatt-hour sales showed strong sales growth in 1999,
with sales to commercial customers accounting for most of the increase.
Revenues from commercial customers represented $53.1 million of the $60.5
million of 1999 revenues from unregulated markets. Over 12,000 new
unregulated customers were served in 1999. Several major contracts were
entered into in 1999, including one with Republic Technologies International,
Inc. (RTI). On August 17, 1999, FirstEnergy Services Corporation (FSC), a
wholly owned subsidiary, signed a Master Energy Services and Supply Agreement
with RTI. They are expected to use more than $1 billion in energy and related
services over the five-year contract period. FSC will manage: the supply and
delivery of all of RTI's electricity and natural gas needs; RTI's HVAC
requirements; and other energy-related services for RTI. Although unregulated
kilowatt-hour sales comprised only 1% of total revenues in 1999, these sales
increased substantially compared to 1998 and are expected to be a major
source of electric sales growth in future years.
Nonelectric Sales
Following an initial expansion of its trading activities in 1998,
FETS revenues decreased significantly in 1999, compared to the prior year
because of refocusing its activities on supporting our retail marketing
activities. Revenues from new business acquisitions increased significantly
in both 1999 and 1998 due to acquisitions made by FE Facilities and FETS. In
addition, we recognized a gain of $53 million from the sale of a partnership
investment in the fourth quarter of 1999, which is reflected in other
revenues. This one-time gain was offset by nonrecurring expenses recognized
in the fourth quarter of 1999, as further described below.
Operating Expenses
Total expenses increased $255.5 million in 1999 compared to 1998
reflecting higher levels of other expenses for EUOC and facilities services
activities, as well as additional depreciation and amortization. This
increase in other expenses was partially offset by lower fuel and purchased
power costs, as well as reduced expenses for FETS. In 1998, total expenses
increased $2.4 billion from the previous year primarily due to the inclusion
of a full 12 months of expenses for the former Centerior companies, compared
to only 7 weeks of expenses in the 1997 results.
Fuel and purchased power costs were $106.7 million lower in 1999,
compared to 1998. The EUOC purchased power costs accounted for all of the
reduction. Much of the improvement occurred in the second quarter due to the
absence of unusual conditions experienced in 1998, which resulted in an
additional $77.4 million of purchased power costs. Those costs were incurred
during a period of record heat and humidity in late June 1998, which
coincided with a regional power shortage resulting in high prices for
purchased power. Unscheduled outages at several of our power plants at the
same time required the EUOC to purchase significant amounts of power on the
spot market. Although above normal temperatures were also experienced in
1999, the EUOC maintained a stronger capacity position compared to the
previous year and better met customer demand from their own internal
generation. In 1998, fuel and purchased power costs were up $497.5 million
compared to 1997. Excluding the merger impact of the Centerior companies in
1998, fuel and purchased power costs for the OE companies increased $74.4
million for the reasons discussed above.
Other expenses for the EUOC rose in 1999 compared to 1998 for
several reasons. Refueling outages at Beaver Valley Unit 2 and the Perry
Plant, as well as full ownership of those units and Beaver Valley Unit 1
following the Duquesne Light Company (Duquesne) asset swap in early December
1999 and nonrecurring swap-related liabilities assumed, increased our nuclear
expenses. The EUOC incurred additional costs in 1999 related to improving the
availability of their fossil generating units. Also contributing to the
increase in other EUOC expenses in 1999 were higher customer, sales and
marketing expenses resulting from marketing programs and information system
costs; higher distribution expenses from storm damage, as well as line and
meter maintenance; and a nonrecurring expense related to a change in employee
vacation benefits. In 1998, other expenses for the EUOC increased from the
previous year principally as a result of the Centerior merger. Excluding the
former Centerior companies, 1998 nonnuclear costs decreased 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
expenses for that year. Lower nonnuclear expenses in 1998 were partially
offset by higher nuclear costs at the Beaver Valley Plant.
With FETS activities changing in 1999 to support our retail
marketing efforts, other expenses in this business segment decreased
significantly from 1998. Also, FETS expenses were significantly lower in 1999
due to the absence of costs incurred in 1998 associated with credit losses
and related replacement power costs resulting from the period of sharp price
increases in the spot market for electricity in June 1998. The acquisitions
in the facility services and natural gas businesses, as well as costs
attributable to unregulated sales activity, combined to increase other
expenses in both 1999 and 1998 from the previous years.
Accelerated cost recovery in connection with the OE rate reduction
plan was the primary factor contributing $160.6 million to the increase in
depreciation and amortization in 1999, compared to the prior year. Excluding
the effect of the former Centerior companies, depreciation and amortization
in 1998 decreased $14.2 million from the prior year mainly due to the net
effect of the OE and Penn rate plans.
Interest Expense
Interest expense decreased $33.7 million in 1999, from the prior
year, because of long-term debt redemptions and refinancings. In 1998,
interest expense increased, compared to 1997, due to the inclusion of the
former Centerior companies. Excluding the impact of the merger, interest on
long-term debt for the OE companies continued to trend downward due to
refinancings and redemptions of long-term debt.
Extraordinary Item
The Pennsylvania Public Utility Commission's (PPUC) authorization
of Penn's rate restructuring plan led to the discontinued application of
Statement of Financial Accounting Standards No. 71 (SFAS 71), "Accounting for
the Effects of Certain Types of Regulation," to Penn's generation business in
1998. This resulted in a write-down of $30.5 million, or $.13 per common
share, of its nuclear generating unit investment and the recognition of a
portion of such investment -- recoverable through future customer rates -- as
a regulatory asset.
Net Income
As a result of higher sales revenues, the absence of unusually high
purchased power costs experienced in 1998 and lower interest costs, net
income increased significantly in 1999 to $568.3 million, compared to $410.9
million in 1998 and $305.8 million in 1997. Basic and diluted earnings per
share of common stock were $2.50 in 1999, compared to $1.82 in 1998 and $1.94
in 1997.
Capital Resources and Liquidity
We continue to pursue cost efficiencies to fund strategic
investments while also strengthening our financial position. During 1999, our
financing costs continued their downward trend. Net redemptions of long-term
debt and preferred stock totaled $528.9 million, including $18.3 million of
optional redemptions in 1999. In addition, we completed $359.6 million of
refinancings. Combined, these actions are expected to generate annual savings
of about $50 million. The average cost of long-term debt was reduced to 7.65%
in 1999 from 8.02% at the end of 1997. As of December 31, 1999, our common
equity as a percentage of capitalization increased to 40% from 34% at the end
of 1997, following the merger with Centerior.
We had approximately $111.8 million of cash and temporary
investments and $417.8 million of short-term indebtedness on December 31,
1999. Our unused borrowing capability included $136.5 million under revolving
lines of credit. At the end of 1999, the EUOC had the capability to issue
$2.1 billion of additional first mortgage bonds on the basis of property
additions and retired bonds. Based upon applicable earnings coverage tests
and their respective charters, OE, Penn and TE could issue $1.6 billion of
preferred stock (assuming no additional debt was issued). CEI has no
restrictions on the issuance of preferred stock.
Our cash requirements in 2000 for operating expenses, construction
expenditures, scheduled debt maturities, preferred stock redemptions, and
common stock repurchases are expected to be met without issuing new
securities. During 1999, we reduced our total debt by approximately $300.0
million. We have cash requirements of approximately $2.8 billion for the
2000-2004 period to meet scheduled maturities of long-term debt and sinking
fund requirements of preferred stock. Of that amount, approximately $494
million applies to 2000. During 1999, we repurchased and retired 4.6 million
shares of our common stock at an average price of $28.08 per share. We have
authority to repurchase up to 15 million shares of common stock. We also
entered into an equity forward purchase contract, which enables us to
purchase an additional 1.4 million shares in November 2000 at an average
price of $24.22 per share.
Our capital spending for the period 2000-2004 is expected to be
about $3.0 billion (excluding nuclear fuel), of which approximately $650
million applies to 2000. Investments for additional nuclear fuel during the
2000-2004 period are estimated to be approximately $497 million, of which
about $159 million applies to 2000. During the same period, our nuclear fuel
investments are expected to be reduced by approximately $480 million and $106
million, respectively, as the nuclear fuel is consumed. Also, we have
operating lease commitments, net of trust cash receipts, of nearly $782
million for the 2000-2004 period, of which approximately $146 million relates
to 2000.
Two transactions were completed in 1999, which modified our
portfolio of generation resources. On July 26, CEI completed its purchase of
the remaining 20 percent interest in the Seneca pumped- storage hydroelectric
generation plant from GPU, Inc. for $43 million. The purchase makes available
87 megawatts of additional capacity and provides CEI with full ownership of
the plant. On December 3, the generating asset transfer with Duquesne was
completed. Duquesne transferred 1,436 megawatts it owned at five generating
plants to us in exchange for 1,328 megawatts at three plants owned by our
EUOC. The transaction provides us with exclusive ownership and operating
control of all generating assets which were formerly jointly owned and
operated under the Central Area Power Coordination Group agreement.
Additional generating capacity is under construction, and is
expected to go into service in early June 2000 to supply electricity for peak
demand periods, reducing our requirements for purchased power. In total, we
will be adding 390 megawatts of gas-fired combustion turbines by the end of
2000 to meet this need. Another 150 megawatts of diesel generation will be
available to us on a limited basis during the summer of 2000.
We completed four acquisitions during 1999, which further expand
energy-related products and services available to our customers. FE
Facilities acquired one company having total annual revenues of approximately
$14 million. Collectively, the FE Facilities companies now produce more than
$500 million in annual revenues and have approximately 3,400 employees. In
addition, FETS acquired three retail gas companies having combined annual
revenues of $239 million and more than 43,000 customers. These three
acquisitions further expanded our retail natural gas business in Ohio and
surrounding states, bringing our total annual revenues in that business to
approximately $500 million.
MARBEL and Range Resources Corporation formed a joint venture,
Great Lakes Energy Partners L.L.C., on September 30, 1999. This joint venture
combined each company's Appalachian oil and natural gas properties and
related gas gathering and transportation systems with the objective of
lowering operating costs, and increasing natural gas market share in the
Appalachian Basin. As exclusive marketing agent for the new joint venture, we
continue to expand our network of gas assets to supply our retail customer
base.
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 investments in capital trusts effectively reduce 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.
Comparison of Carrying Value to Fair Value
- ----------------------------------------------------------------------------------------------
There- Fair
2000 2001 2002 2003 2004 after Total Value
- ----------------------------------------------------------------------------------------------
(Dollars in millions)
Investments other than Cash
and Cash Equivalents:
Fixed Income $111 $ 60 $ 84 $ 97 $314 $1,370 $2,036 $2,022
Average interest rate 6.5% 7.0% 7.7% 7.7% 7.8 7.5% 7.5%
- ------------------------------------------------------------------------------------------------
Liabilities
- ------------------------------------------------------------------------------------------------
Long-term Debt:
Fixed rate $456 $105 $724 $459 $591 $3,009 $5,344 $5,307
Average interest rate 7.1% 8.6% 7.9% 8.0% 7.7% 7.5% 7.6%
Variable rate $190 $847 $1,037 $1,024
Average interest rate 7.5% 4.4% 5.0%
Short-term Borrowings $418 $418 $ 418
Average interest rate 6.5% 6.5%
- ------------------------------------------------------------------------------------------------
Preferred Stock $ 38 $ 85 $ 20 $ 2 $ 2 $137 $ 284 $ 280
Average dividend rate 8.9% 8.9% 8.9% 7.5% 7.5% 8.8% 8.8%
- ------------------------------------------------------------------------------------------------
Market Risk - Commodity Prices
We are exposed to market risk due to fluctuations in electricity,
natural gas and oil prices. To manage the volatility relating to these
exposures, we use a variety of derivative instruments, including forward
contracts, options and futures contracts. These derivatives are used
principally for hedging purposes and, to a lesser extent, for trading
purposes. A sensitivity analysis has been prepared to estimate our exposure
to the market risk of our commodity position. A hypothetical 10 percent
adverse shift in quoted market prices in the near term on both our trading
and nontrading instruments would not have a material effect on our
consolidated financial position, results of operations or cash flows as of or
for the year ended December 31, 1999.
Outlook
We continue to face many competitive challenges as the electric
utility industry undergoes significant changes, including changing regulation
and the entrance of more energy suppliers into the marketplace. Retail
wheeling, which began in 1999 in our Pennsylvania service area, allows retail
customers to purchase electricity from alternative energy suppliers. Recent
legislation provides for similar changes beginning in 2001 in Ohio. Our
existing regulatory plans provide us with a solid foundation to position us
to meet the challenges we are facing by significantly reducing fixed costs
and lowering rates to a more competitive level. The transition plan
ultimately approved by the Public Utilities Commission of Ohio (PUCO) will
supersede our current Ohio rate plans.
OE's Rate Reduction and Economic Development Plan, approved by the
PUCO in 1995, and FirstEnergy's Rate Reduction and Economic Development Plan
for CEI and TE, approved in January 1997, provide interim rate credits to
customers during the periods covered by the plans. The OE regulatory plan
provides for accelerated capital recovery. The regulatory plan for CEI and TE
includes a commitment to accelerate depreciation on the regulatory books. The
CEI/TE plan does not provide for full recovery of nuclear operations;
accordingly, CEI and TE ceased application of SFAS 71 for their nuclear
operations when implementation of the FirstEnergy regulatory plan became
probable.
In July 1999, Ohio's new electric utility restructuring
legislation, which will allow Ohio electric customers to select their
generation suppliers beginning January 1, 2001, was signed into law. Among
other things, the new law provides for a 5% reduction on the generation
portion of residential customers' bills and the opportunity to recover
transition costs, including regulatory assets, from January 1, 2001 through
December 31, 2005. The period for the recovery of regulatory assets only can
be extended up to December 31, 2010. The PUCO was authorized to determine the
level of transition cost recovery, as well as the recovery period for the
regulatory assets portion of those costs, in considering each Ohio electric
utility's transition plan application.
On behalf of our Ohio electric utility operating companies -- OE,
CEI and TE, we refiled our transition plan on December 22, 1999. The plan was
originally filed with the PUCO on October 4, 1999, but was refiled to conform
to PUCO rules established on November 30, 1999. The new filing also included
additional information on our plans to turn over control, and perhaps
ownership, of our transmission assets to the Alliance Regional Transmission
Organization (Alliance), which is discussed below.
The transition plan itemizes, or unbundles, the current price of
electricity into separate components - including generation, transmission,
distribution and transition charges. As required by the PUCO's rules, our
filing also included our proposals on corporate separation of our regulated
and unregulated operations, operational and technical support changes needed
to accommodate customer choice, an education program to inform customers of
their options under the law, and how our transmission system will be operated
to ensure access to all users. Under the plan, customers who remain with OE,
CEI or TE as their generation provider will continue to receive savings under
our rate plans, expected to total $759 million between 2000 and 2005. In
addition, customers will save $358 million through reduced charges for taxes
and a 5% reduction in the price of generation for residential customers
beginning January 1, 2001. Customer prices are expected to be frozen through
a five-year market development period (2001-2005), except for certain limited
statutory exceptions including the 5% reduction in the price of generation
for residential customers. The plan proposes recovery of generation-related
transition costs of approximately $4.5 billion ($4.0 billion, net of deferred
income taxes) over the market development period; transition costs related to
regulatory assets aggregating approximately $4.2 billion ($2.9 billion, net
of deferred income taxes) are expected to be recovered over the period of
2001 through early 2004 for OE; 2001 through 2007 for TE; and 2001 through
2010 for CEI.
When the transition plan is approved by the PUCO, the application
of SFAS 71 to OE's generation business and the nonnuclear generation
businesses of CEI and TE will be discontinued. In the meantime, we will
continue to bill and collect cost-based rates relating to CEI's and TE's
nonnuclear operations and all of OE's operations through the end of 2000. If
the transition plans ultimately approved by the PUCO for OE, CEI and TE do
not provide adequate recovery of their nuclear generating unit investments
and regulatory assets, there would be a charge to earnings which could have a
material adverse effect on our results of operations and financial condition
and those of our Ohio EUOC. The EUOC believe they will continue to bill and
collect cost-based rates for their transmission and distribution services,
which will remain regulated; accordingly, it is appropriate that the EUOC
continue the application of SFAS 71 to those operations after December 31,
2000.
For Penn, application of SFAS 71 was discontinued for the
generation portion of its business in 1998 following PPUC approval of its
restructuring plan. Under the plan, a phase-in period for customer choice
began with 66% of Penn's customers able to select their energy supplier
beginning January 2, 1999, and all remaining customers able to select their
energy providers starting January 1, 2001. Penn is entitled to recover $236
million of stranded costs through a competitive transition charge that
started in 1999 and ends in 2006.
In the second half of 1999, we received notification of pending
legal actions based on alleged violations of the Clean Air Act at our W. H.
Sammis Plant involving the states of New York and Connecticut as well as the
U.S. Department of Justice. The civil complaint filed by the U.S. Department
of Justice requests installation of "best available control technology" as
well as civil penalties of up to $27,500 per day. We believe the Sammis Plant
is in full compliance with the Clean Air Act and the legal actions are
without merit. However, we are unable to predict the outcome of this
litigation. Penalties could be imposed if the Sammis Plant continues to
operate without correcting the alleged violations and a court determines that
the allegations are valid. We expect the Sammis Plant to continue to operate
while the matter is being decided.
CEI and TE have been named as "potentially responsible parties"
(PRPs) for three sites listed on the Superfund National Priorities List and
are aware of their potential involvement in the cleanup of several other
sites. Allegations that CEI and TE disposed of hazardous waste at these
sites, and the amount involved are often unsubstantiated and subject to
dispute. Federal law provides that all PRPs for a particular site be held
liable on a joint and several basis. If CEI and TE were held liable for 100%
of the cleanup costs of all sites, the ultimate liability could be as high as
$340 million. However, we believe that the actual cleanup costs will be
substantially lower than $340 million, that CEI's and TE's share of any
cleanup costs will be substantially less than 100% and that most of the other
PRPs are financially able to contribute their share. CEI and TE have accrued
liabilities of $5.4 million as of December 31, 1999, based on estimates of
the costs of cleanup and their proportionate responsibility for such costs.
CEI and TE believe that the waste disposal costs will not have a material
adverse effect on their financial condition, cash flows or results of
operations.
On October 27, 1999, the Federal Energy Regulatory Commission
(FERC) approved our plan to transfer our transmission assets to American
Transmission Systems Inc. (ATSI), a wholly owned subsidiary. The PUCO
approved the transfer in February 2000. PPUC and Securities and Exchange
Commission regulatory approvals are also required. The new subsidiary
represents a first step toward the goal of establishing or becoming part of a
larger independent, regional transmission organization (RTO). We believe that
such an entity better addresses the FERC's stated transmission objectives of
non-discriminatory service, while providing for streamlined and cost-
effective operation. In working toward that goal, we joined with four other
companies - American Electric Power, Consumers Energy, Detroit Edison and
Virginia Power - to form the Alliance RTO. On June 3, 1999, the Alliance
submitted an application to the FERC to form an independent, for profit RTO.
On December 15, 1999, the FERC issued an order conditionally approving the
Alliance's application.
Recently Issued Accounting Standard
In June 1998, the Financial Accounting Standards Board (FASB)
issued Statement of Financial Accounting Standards No. 133 (SFAS 133),
"Accounting for Derivative Instruments and Hedging Activities." SFAS 133
establishes accounting and reporting standards requiring that every
derivative instrument (including derivative instruments embedded in other
contracts) be recorded on the balance sheet as either an asset or liability
measured at its fair value. SFAS 133 requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. Special accounting for qualifying hedges
allows a derivative's gains and losses to offset related results on the
hedged item in the income statement. We have not completed quantifying the
impacts of adopting SFAS 133 on our financial statements or determined the
method of its adoption. However, SFAS 133 could increase volatility in
earnings and other comprehensive income. We anticipate adopting the new
statement on its amended effective date of January 1, 2001.
Year 2000 Update
Based on the results of our remediation and testing efforts, we
filed documents with the North American Electric Reliability Council, Nuclear
Regulatory Commission, PUCO and PPUC that as of June 30, 1999, our
generation, transmission, and distribution systems were ready to serve
customers in the year 2000. We have since experienced no failures or
interruptions of service to our customers resulting from the Year 2000 issue,
which was consistent with our expectations. We spent $84.9 million on Year
2000-related costs through December 31, 1999, which was slightly lower than
previously estimated. Of this total, $68.3 million was capitalized since
those costs are attributable to the purchase of new software for total system
replacements because the Year 2000 solution comprises only a portion of the
benefits resulting from the system replacements. The remaining $16.6 million
was expensed as incurred. We do not believe there are any continuing Year
2000 issues to be addressed, nor any additional material Year 2000
expenditures.
Forward-Looking Information
This discussion includes forward-looking statements based on
information currently available to management that are subject to certain
risks and uncertainties. These statements typically contain, but are not
limited to, the terms anticipate, potential, expect, believe, estimate and
similar words. Actual results may differ materially due to the speed and
nature of increased competition and deregulation in the electric utility
industry, economic or weather conditions affecting future sales and margins,
changes in markets for energy services, changing energy market prices,
legislative and regulatory changes, and the availability and cost of capital
and other similar factors.
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 1999 1998 1997
- ------------------------------------------------------------------------------------------
(In thousands, except per share amounts)
REVENUES:
Electric sales $5,192,876 $4,979,718 $2,774,996
Other-electric utilities 260,887 257,750 142,742
Facilities services 502,990 198,336 --
Trading services 190,634 410,728 43,145
Other 172,260 28,374 242
---------- ---------- ----------
Total revenues 6,319,647 5,874,906 2,961,125
---------- ---------- ----------
EXPENSES:
Fuel and purchased power 876,986 983,735 486,267
Other expenses:
Electric utilities 1,632,638 1,492,461 851,146
Facilities services 469,176 184,440 --
Trading services 196,474 517,001 44,032
Other 126,926 41,337 --
Provision for depreciation and amortization 937,976 758,865 474,679
General taxes 544,052 550,908 282,163
---------- ---------- ----------
Total expenses 4,784,228 4,528,747 2,138,287
---------- ---------- ----------
INCOME BEFORE INTEREST AND INCOME TAXES 1,535,419 1,346,159 822,838
---------- ---------- ----------
NET INTEREST CHARGES:
Interest expense 509,169 542,819 284,180
Allowance for borrowed funds used during
construction and capitalized interest (13,355) (7,642) (3,469)
Subsidiaries' preferred stock dividends 76,479 65,799 27,818
---------- ---------- ----------
Net interest charges 572,293 600,976 308,529
---------- ---------- ----------
INCOME TAXES 394,827 303,787 208,535
---------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM 568,299 441,396 305,774
EXTRAORDINARY ITEM (NET OF INCOME TAX BENEFIT OF
$21,208,000) (Note 1) -- (30,522) --
---------- ---------- ----------
NET INCOME $ 568,299 $ 410,874 $ 305,774
========== ========== ==========
WEIGHTED AVERAGE NUMBER OF COMMON
SHARES OUTSTANDING 227,227 226,373 157,464
========== ========== ==========
BASIC AND DILUTED EARNINGS PER SHARE OF
COMMON STOCK (Note 3C):
Income before extraordinary item $2.50 $1.95 $1.94
Extraordinary item (Net of income taxes) (Note 1) -- (.13) --
----- ----- -----
Net income $2.50 $1.82 $1.94
===== ===== =====
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $1.50 $1.50 $1.50
===== ===== =====
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
At December 31, 1999 1998
- ----------------------------------------------------------------------------------------
(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 111,788 $ 77,798
Receivables--
Customers (less accumulated provisions of $6,719,000 and
$6,397,000, respectively, for uncollectible accounts) 322,687 239,183
Other (less accumulated provisions of $5,359,000 and
$46,251,000, respectively, for uncollectible accounts) 445,242 322,186
Materials and supplies, at average cost--
Owned 154,834 145,926
Under consignment 99,231 110,109
Prepayments and other 167,894 171,931
----------- -----------
1,301,676 1,067,133
----------- -----------
PROPERTY, PLANT AND EQUIPMENT:
In service 14,645,131 14,961,664
Less--Accumulated provision for depreciation 5,919,170 6,012,761
----------- -----------
8,725,961 8,948,903
Construction work in progress 367,380 293,671
----------- -----------
9,093,341 9,242,574
----------- -----------
INVESTMENTS:
Capital trust investments (Note 2) 1,281,834 1,329,010
Letter of credit collateralization (Note 2) 277,763 277,763
Nuclear plant decommissioning trusts 543,694 358,371
Other 599,443 391,855
----------- -----------
2,702,734 2,356,999
----------- -----------
DEFERRED CHARGES:
Regulatory assets 2,543,427 2,887,437
Goodwill 2,129,902 2,167,968
Other 452,967 470,066
----------- -----------
5,126,296 5,525,471
----------- -----------
$18,224,047 $18,192,177
=========== ===========
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock $ 762,520 $ 876,470
Short-term borrowings (Note 4) 417,819 254,470
Accounts payable 360,379 247,353
Accrued taxes 409,724 401,688
Accrued interest 125,397 141,575
Other 301,572 255,158
----------- -----------
2,377,411 2,176,714
----------- -----------
CAPITALIZATION (See Consolidated Statements of
Capitalization):
Common stockholders' equity 4,563,890 4,449,158
Preferred stock of consolidated subsidiaries--
Not subject to mandatory redemption 648,395 660,195
Subject to mandatory redemption 136,246 174,710
Ohio Edison obligated mandatorily redeemable preferred
securities of subsidiary trust holding solely Ohio Edison
subordinated debentures 120,000 120,000
Long-term debt 6,001,264 6,352,359
----------- -----------
11,469,795 11,756,422
----------- -----------
DEFERRED CREDITS:
Accumulated deferred income taxes 2,231,265 2,282,864
Accumulated deferred investment tax credits 269,083 286,154
Other postretirement benefits 498,184 463,642
Nuclear plant decommissioning costs 562,295 375,958
Other 816,014 850,423
----------- -----------
4,376,841 4,259,041
----------- -----------
COMMITMENTS AND CONTINGENCIES (Notes 2 and 5) ----------- -----------
$18,224,047 $18,192,177
=========== ===========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral
part of these balance sheets.
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 1999 1998
- ------------------------------------------------------------------------------------------------------
(Dollars in thousands, except per share amounts)
COMMON STOCKHOLDERS' EQUITY:
Common stock, $.10 par value - authorized 300,000,000 shares
232,454,287 and 237,069,087 shares outstanding, respectively $ 23,245 $ 23,707
Other paid-in capital 3,722,375 3,846,513
Accumulated other comprehensive income (Note 3D) (195) (439)
Retained earnings (Note 3A) 945,241 718,409
Unallocated employee stock ownership plan common stock-
6,778,905 and 7,406,332 shares, respectively (Note 3B) (126,776) (139,032)
---------- ----------
Total common stockholders' equity 4,563,890 4,449,158
---------- ----------
Number of Shares Optional
Outstanding Redemption Price
---------------- --------------------
1999 1998 Per Share Aggregate
------ ------ --------- ---------
PREFERRED STOCK OF CONSOLIDATED
SUBSIDIARIES (Note 3E):
Ohio Edison Company (OE)
Cumulative, $100 par value-
Authorized 6,000,000 shares
Not Subject to Mandatory Redemption:
3.90% 152,510 152,510 $103.63 $ 15,804 15,251 15,251
4.40% 176,280 176,280 108.00 19,038 17,628 17,628
4.44% 136,560 136,560 103.50 14,134 13,656 13,656
4.56% 144,300 144,300 103.38 14,917 14,430 14,430
--------- --------- -------- ---------- -----------
609,650 609,650 63,893 60,965 60,965
--------- --------- -------- ---------- -----------
Cumulative, $25 par value-
Authorized 8,000,000 shares
Not Subject to Mandatory Redemption:
7.75% 4,000,000 4,000,000 25.00 100,000 100,000 100,000
--------- --------- -------- ---------- -----------
Total Not Subject to
Mandatory Redemption 4,609,650 4,609,650 $163,893 160,965 160,965
========= ========= ======== ---------- -----------
Cumulative, $100 par value-
Subject to Mandatory Redemption
(Note 3F):
8.45% 100,000 150,000 10,000 15,000
Redemption Within One Year (5,000) (5,000)
--------- --------- ---------- -----------
100,000 150,000 5,000 10,000
========= ========= ---------- -----------
Pennsylvania Power Company
Cumulative, $100 par value-
Authorized 1,200,000 shares
Not Subject to Mandatory Redemption:
4.24% 40,000 40,000 103.13 $ 4,125 4,000 4,000
4.25% 41,049 41,049 105.00 4,310 4,105 4,105
4.64% 60,000 60,000 102.98 6,179 6,000 6,000
7.64% -- 60,000 -- -- -- 6,000
7.75% 250,000 250,000 -- -- 25,000 25,000
8.00% -- 58,000 -- -- -- 5,800
--------- --------- -------- ---------- -----------
Total Not Subject to Mandatory
Redemption 391,049 509,049 $ 14,614 39,105 50,905
========= ========= ======== ---------- -----------
Subject to Mandatory Redemption
(Note 3F):
7.625% 150,000 150,000 106.10 $ 15,915 15,000 15,000
========= ========= ======== ---------- -----------
OE OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF SUBSIDIARY
TRUST HOLDING SOLELY OE SUBORDINATED
DEBENTURES (Note 3G):
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
========= ========= ---------- -----------
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)
At December 31, 1999 1998
- ------------------------------------------------------------------------------------------------------
(Dollars in thousands, except per share amounts)
Number of Shares Optional
Outstanding Redemption Price
---------------- --------------------
1999 1998 Per Share Aggregate
------ ------ --------- ---------
PREFERRED STOCK OF CONSOLIDATED
SUBSIDIARIES (Cont'd)
Cleveland Electric Illuminating Company
Cumulative, without par value-
Authorized 4,000,000 shares
Not Subject to Mandatory Redemption:
$ 7.40 Series A 500,000 500,000 $ 101.00 $ 50,500 $ 50,000 $ 50,000
$ 7.56 Series B 450,000 450,000 102.26 46,017 45,071 45,071
Adjustable Series L 474,000 474,000 100.00 47,400 46,404 46,404
$42.40 Series T 200,000 200,000 500.00 100,000 96,850 96,850
--------- --------- -------- ---------- ---------
Total Not Subject to Mandatory
Redemption 1,624,000 1,624,000 $243,917 238,325 238,325
========= ========= ======== ---------- ---------
Subject to Mandatory Redemption:
$ 7.35 Series C 90,000 100,000 101.00 $ 9,090 9,110 10,110
$88.00 Series E 3,000 6,000 1,000.00 3,000 3,000 6,000
$91.50 Series Q 21,430 32,144 1,000.00 21,430 21,430 32,144
$88.00 Series R 50,000 50,000 -- -- 55,000 55,000
$90.00 Series S 55,250 74,000 -- -- 61,170 79,920
--------- --------- -------- ---------- ---------
219,680 262,144 33,520 149,710 183,174
Redemption Within One Year (33,464) (33,464)
--------- --------- -------- ---------- ---------
Total Subject to Mandatory
Redemption 219,680 262,144 $ 33,520 116,246 149,710
========= ========= ======== ---------- ---------
Toledo Edison Company
Cumulative, $100 Par Value-
Authorized 3,000,000 shares
Not Subject to Mandatory Redemption:
$ 4.25 160,000 160,000 104.63 $ 16,740 16,000 16,000
$ 4.56 50,000 50,000 101.00 5,050 5,000 5,000
$ 4.25 100,000 100,000 102.00 10,200 10,000 10,000
$ 8.32 100,000 100,000 102.46 10,246 10,000 10,000
$ 7.76 150,000 150,000 102.44 15,366 15,000 15,000
$ 7.80 150,000 150,000 101.65 15,248 15,000 15,000
$10.00 190,000 190,000 101.00 19,190 19,000 19,000
--------- --------- -------- ---------- ---------
900,000 900,000 92,040 90,000 90,000
--------- --------- -------- ---------- ---------
Cumulative, $25 Par Value-
Authorized 12,000,000 shares
Not Subject to Mandatory Redemption:
$2.21 1,000,000 1,000,000 25.25 25,250 25,000 25,000
$2.365 1,400,000 1,400,000 27.75 38,850 35,000 35,000
Adjustable Series A 1,200,000 1,200,000 25.00 30,000 30,000 30,000
Adjustable Series B 1,200,000 1,200,000 25.00 30,000 30,000 30,000
--------- --------- -------- ---------- ---------
4,800,000 4,800,000 124,100 120,000 120,000
--------- --------- -------- ---------- ---------
Total Not Subject to Mandatory
Redemption 5,700,000 5,700,000 $216,140 210,000 210,000
========= ========= ======== ---------- ---------
Cumulative, $100 par value-
Subject to Mandatory Redemption:
$9.375 -- 16,900 $ -- -- 1,690
Redemption Within One Year -- (1,690)
--------- --------- -------- ---------- ---------
Total Subject to Mandatory
Redemption -- 16,900 $ -- -- --
========= ========= ======== ---------- ---------
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)
LONG-TERM DEBT (Note 3H) (Interest rates reflect weighted average rates) (In thousands)
- --------------------------------------------------------------------------------------------------------------------------------
FIRST MORTGAGE BONDS SECURED NOTES UNSECURED NOTES TOTAL
- --------------------------------------------------------------------------------------------------------------------------------
At December 31, 1999 1998 1999 1998 1999 1998 1999 1998
---- ---- ---- ---- ---- ---- ---- ----
Ohio Edison Co. -
Due 1999-2004 7.81% $ 509,265 $ 659,265 7.57% $ 269,152 $ 203,062 5.40% $ 742,225 $566,500
Due 2005-2009 6.88% 80,000 80,000 7.65% 49,534 48,194 -- -- --
Due 2010-2014 -- -- -- -- -- -- -- -- --
Due 2015-2019 -- -- -- 6.89% 66,000 113,725 -- -- --
Due 2020-2024 7.99% 219,460 225,960 7.02% 129,942 317,943 -- -- --
Due 2025-2029 -- -- -- 5.75% 119,734 119,734 -- -- --
Due 2030-2034 -- -- -- 5.45% 14,800 14,800 -- -- --
---------- ---------- ---------- ---------- ---------- -------- ----------- -----------
Total-Ohio Edison 808,725 965,225 649,162 817,458 742,225 566,500 $ 2,200,112 $ 2,349,183
---------- ---------- ---------- ---------- ---------- -------- ----------- -----------
Cleveland Electric
Illuminating Co. -
Due 1999-2004 7.54% 295,000 295,000 7.64% 559,650 704,180 5.58% 27,700 --
Due 2005-2009 8.72% 425,000 425,000 7.29% 271,700 271,700 -- -- --
Due 2010-2014 -- -- -- 8.00% 78,700 78,700 -- -- --
Due 2015-2019 -- -- -- 6.74% 412,630 412,630 -- -- --
Due 2020-2024 9.00% 150,000 150,000 6.66% 264,160 291,860 -- -- --
Due 2025-2029 -- -- -- 7.59% 148,843 148,843 -- -- --
Due 2030-2034 -- -- -- 4.56% 104,895 104,895 -- -- --
---------- ---------- ---------- ---------- ---------- -------- ----------- -----------
Total-Cleveland
Electric 870,000 870,000 1,840,578 2,012,808 27,700 -- 2,738,278 2,882,808
---------- ---------- ---------- ---------- ---------- -------- ----------- -----------
Toledo Edison Co. -
Due 1999-2004 7.90% 179,925 265,325 7.84% 266,000 284,500 7.28% 226,100 138,750
Due 2005-2009 -- -- -- 7.13% 30,000 30,000 10.00% 150 150
Due 2010-2014 -- -- -- 4.98% -- 31,250 10.00% 700 700
Due 2015-2019 -- -- -- 8.00% 67,300 67,300 -- -- --
Due 2020-2024 -- -- -- 7.89% 210,600 266,700 -- -- --
Due 2025-2029 -- -- -- 5.90% 13,851 13,851 -- -- --
Due 2030-2034 -- -- -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- -------- ----------- -----------
Total-Toledo
Edison 179,925 265,325 587,751 693,601 226,950 139,600 994,626 1,098,526
---------- ---------- ---------- ---------- ---------- -------- ----------- -----------
Pennsylvania Power Co. -
Due 1999-2004 7.19% 79,370 79,857 6.45% 28,200 23,000 5.90% 5,200 --
Due 2005-2009 9.74% 4,870 4,870 -- -- -- -- -- --
Due 2010-2014 9.74% 4,870 4,870 5.40% 1,000 1,000 -- -- --
Due 2015-2019 9.74% 4,903 4,903 6.28% 45,325 45,325 -- -- --
Due 2020-2024 8.33% 33,750 33,750 6.68% 27,182 32,382 -- -- --
Due 2025-2029 -- -- -- 6.03% 47,972 47,972 -- -- --
Due 2030-2034 -- -- -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- -------- ----------- -----------
Total-Penn Power 127,763 128,250 149,679 149,679 5,200 -- 282,642 277,929
---------- ---------- ---------- ---------- ---------- -------- ----------- -----------
OES Fuel -- -- 6.85% 81,260 79,524 -- -- -- 81,260 79,524
Bay Shore Power -- -- 6.72% 147,500 147,500 -- -- -- 147,500 147,500
MARBEL Energy Corp. -- -- 6.40% -- 12,418 8.00% 692 -- 692 12,418
Facilities Services
Group -- -- 6.61% 14,782 10,237 7.29% 1,887 3,917 16,669 14,154
---------- ---------- ---------- ---------- ---------- -------- ----------- -----------
Total $1,986,413 $2,228,800 $3,470,712 $3,923,225 $1,004,654 $710,017 6,461,779 6,862,042
========== ========== ========== ========== ========== ======== ----------- -----------
Capital lease
obligations 158,303 199,491
----------- -----------
Net unamortized
premium on debt 105,238 127,142
----------- -----------
Long-term debt due
within one year (724,056) (836,316)
----------- -----------
Total long-term debt 6,001,264 6,352,359
----------- -----------
TOTAL CAPITALIZATION $11,469,795 $11,756,422
=================================================================================================================================
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
Accumulated
Other Unallocated
Comprehensive Other Comprehensive ESOP
Income- Number Par Paid-In Income- Retained Common
Note 3D of Shares Value Capital Note 3D Earnings Stock
------------- ----------- ---------- ---------- ------------ --------- -----------
(Dollars in thousands)
Balance, January 1, 1997 152,569,437 $1,373,125 $ 728,261 $(659) $ 557,642 $(155,010)
Net income $305,774 305,774
Minimum liability for
unfunded retirement
benefits, net of
$26,000 of income taxes 45 45
--------
Comprehensive income $305,819
========
Centerior acquisition 77,637,704 (1,350,104) 2,907,387
Allocation of ESOP Shares 1,874 8,033
Cash dividends on common
stock (216,770)
- -------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1997 230,207,141 23,021 3,637,522 (614) 646,646 (146,977)
Net income $410,874 410,874
Minimum liability for
unfunded retirement
benefits, net of
$53,000 of income taxes 175 175
--------
Comprehensive income $411,049
========
Business acquisitions 6,861,946 686 203,496
Allocation of ESOP Shares 5,495 7,945
Cash dividends on common
stock (339,111)
- -------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1998 237,069,087 23,707 3,846,513 (439) 718,409 (139,032)
Net income $568,299 568,299
Minimum liability for unfunded
retirement benefits, net of
$160,000 of income taxes 244 244
--------
Comprehensive income $568,543
========
Reacquired common stock (4,614,800) (462) (129,671)
Centerior acquisition
adjustment (468)
Allocation of ESOP Shares 6,001 12,256
Cash dividends on common
stock (341,467)
- --------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1999 232,454,287 $ 23,245 $3,722,375 $(195) $ 945,241 $(126,776)
===========================================================================================================================
CONSOLIDATED STATEMENTS OF PREFERRED STOCK
Not Subject to Subject to
Mandatory Redemption Mandatory Redemption
-------------------- --------------------
Par or Par or
Number Stated Number Stated
of Shares Value of Shares Value
---------- -------- --------- -------
(Dollars in thousands)
- ------------------------------------------------------------------------------------------------
Balance, January 1, 1997 5,118,699 $211,870 5,200,000 $160,000
Centerior acquisition 7,324,000 448,325 319,408 201,243
Redemptions-
8.45% Series (50,000) (5,000)
- ------------------------------------------------------------------------------------------------
Balance, December 31, 1997 12,442,699 660,195 5,469,408 356,243
Redemptions-
8.45% Series (50,000) (5,000)
$ 7.35 Series C (10,000) (1,000)
$88.00 Series E (3,000) (3,000)
$91.50 Series Q (10,714) (10,714)
$9.375 Series (16,650) (1,665)
- -----------------------------------------------------------------------------------------------
Balance, December 31, 1998 12,442,699 660,195 5,379,044 334,864
Redemptions-
7.64% Series (60,000) (6,000)
8.00% Series (58,000) (5,800)
8.45% Series (50,000) (5,000)
$ 7.35 Series C (10,000) (1,000)
$88.00 Series E (3,000) (3,000)
$91.50 Series Q (10,714) (10,714)
$90.00 Series S (18,750) (18,750)
$9.375 Series (16,900) (1,690)
- -----------------------------------------------------------------------------------------------
Balance, December 31, 1999 12,324,699 $648,395 5,269,680 $294,710
================================================================================================
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income $ 568,299 $ 410,874 $ 305,774
Adjustments to reconcile net income to net
cash from operating activities:
Provision for depreciation and amortization 937,976 758,865 474,679
Nuclear fuel and lease amortization 104,928 94,348 61,960
Other amortization, net (10,730) (13,007) (1,187)
Deferred income taxes, net (45,054) (23,763) (29,093)
Investment tax credits, net (19,661) (22,070) (16,252)
Allowance for equity funds used during construction -- -- (201)
Extraordinary item -- 51,730 --
Receivables (203,567) 35,515 21,846
Materials and supplies 19,631 (14,235) (18,909)
Accounts payable 82,578 (73,205) 57,087
Other 53,906 (49,727) 733
---------- ---------- ----------
Net cash provided from operating activities 1,488,306 1,155,325 856,437
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Common stock -- 204,182 1,558,237
Long-term debt 364,832 499,975 89,773
Ohio Schools Council prepayment program -- 116,598 --
Short-term borrowings, net 163,327 -- --
Redemptions and Repayments-
Common stock 130,133 -- --
Preferred stock 52,159 21,379 5,000
Long-term debt 847,006 804,780 335,909
Short-term borrowings, net -- 48,354 47,251
Common Stock Dividend Payments 341,467 339,111 237,848
----------- ---------- ----------
Net cash provided from (used for) financing activities (842,606) (392,869) 1,022,002
----------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Centerior acquisition -- -- 1,582,459
Property additions 624,901 652,852 203,839
Cash investments (41,213) 47,804 8,934
Other 28,022 82,239 62,237
----------- ---------- ----------
Net cash used for investing activities 611,710 782,895 1,857,469
----------- ---------- ----------
Net increase (decrease) in cash and cash equivalents 33,990 (20,439) 20,970
Cash and cash equivalents at beginning of period* 77,798 98,237 77,267
----------- ---------- ----------
Cash and cash equivalents at end of year $ 111,788 $ 77,798 $ 98,237
=========== ========== ==========
SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized) $ 520,072 $ 536,064 $ 281,670
Income taxes $ 441,067 $ 326,268 $ 265,615
<FN>
* 1997 beginning balance includes Centerior cash and cash equivalents as of the November 8, 1997 acquisition date.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF TAXES
For the Years Ended December 31, 1999 1998 1997
- -------------------------------------------------------------------------------------------------
(In thousands)
GENERAL TAXES:
Real and personal property $ 276,227 $ 292,503 $ 137,816
State gross receipts 220,117 217,633 118,390
Social security and unemployment 37,019 27,363 16,551
Other 10,689 13,409 9,406
---------- ---------- ----------
Total general taxes $ 544,052 $ 550,908 $ 282,163
========== ========== ==========
PROVISION FOR INCOME TAXES:
Currently payable-
Federal $ 433,872 $ 313,960 $ 235,728
State 25,670 14,452 18,152
---------- ---------- ----------
459,542 328,412 253,880
---------- ---------- ----------
Deferred, net-
Federal (36,021) (14,259) (23,204)
State (9,033) (9,504) (5,889)
---------- ---------- ----------
(45,054) (23,763) (29,093)
---------- ---------- ----------
Investment tax credit amortization (19,661) (22,070) (16,252)
---------- ---------- ----------
Total provision for income taxes $ 394,827 $ 282,579 $ 208,535
========== ========== ==========
RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT
STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES:
Book income before provision for income taxes $ 963,126 $ 693,453 $ 514,309
========== ========== ==========
Federal income tax expense at statutory rate $ 337,094 $ 242,709 $ 180,008
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits (19,661) (22,070) (16,252)
State income taxes, net of federal income tax benefit 10,814 3,216 7,971
Amortization of tax regulatory assets 23,908 28,915 30,735
Amortization of goodwill 19,341 17,868 2,685
Preferred stock dividends 22,988 19,250 5,956
Other, net 343 (7,309) (2,568)
---------- ---------- ----------
Total provision for income taxes $ 394,827 $ 282,579 $ 208,535
========== ========== ==========
ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31:
Property basis differences $1,878,904 $1,938,735 $2,091,207
Deferred nuclear expense 421,837 436,601 454,902
Customer receivables for future income taxes 159,577 159,526 262,428
Competitive transition charge 115,277 135,730 --
Deferred sale and leaseback costs (129,775) (61,506) (121,974)
Unamortized investment tax credits (96,036) (102,085) (116,593)
Unused alternative minimum tax credits (101,185) (190,781) (243,039)
Other (17,334) (33,356) (22,626)
---------- ---------- ----------
Net deferred income tax liability $2,231,265 $2,282,864 $2,304,305
========== ========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
<PAGE
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
The consolidated financial statements include FirstEnergy Corp.
(Company) and its principal electric utility operating subsidiaries, Ohio
Edison Company (OE), The Cleveland Electric Illuminating Company (CEI),
Pennsylvania Power Company (Penn) and The Toledo Edison Company (TE). The
Company and its utility subsidiaries are referred to throughout as
"Companies." The Company's 1997 results of operations include the results of
CEI and TE for the period November 8, 1997 through December 31, 1997. The
consolidated financial statements also include the Company's other principal
subsidiaries: FirstEnergy Facilities Services Group, LLC. (FE Facilities);
FirstEnergy Trading Services, Inc. (FETS); and MARBEL Energy Corporation
(MARBEL). FE Facilities is the parent company of several heating,
ventilating, air conditioning and energy management companies. FETS markets
and trades electricity and natural gas in unregulated markets. MARBEL is a
fully integrated natural gas company. Significant intercompany transactions
have been eliminated. The 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 northern Ohio and western Pennsylvania. The
Companies' retail customers are metered on a cycle basis. Revenue is
recognized for unbilled electric service through the end of the year.
Receivables from customers include sales to residential, commercial
and industrial customers located in the Companies' service area and sales to
wholesale customers. There was no material concentration of receivables at
December 31, 1999 or 1998, with respect to any particular segment of the
Companies' customers.
CEI and TE sell substantially all of their retail customer accounts
receivable to Centerior Funding Corp. under an asset-backed securitization
agreement which expires in 2001. Centerior Funding completed a public sale of
$150 million of receivables-backed investor certificates in 1996 in a
transaction that qualified for sale accounting treatment.
REGULATORY PLANS-
The PUCO approved OE's Rate Reduction and Economic Development Plan
in 1995 and FirstEnergy's Rate Reduction and Economic Development Plan for
CEI and TE in January 1997. These regulatory plans were to maintain current
base electric rates for OE, CEI and TE through December 31, 2005. At the end
of the regulatory plan periods, OE base rates were to be reduced by $300
million (approximately 20 percent below current levels) and CEI and TE base
rates were to be reduced by a combined $310 million (approximately 15 percent
below current levels). The plans also revised the Companies' fuel cost
recovery methods. The Companies formerly recovered fuel-related costs not
otherwise included in base rates from retail customers through separate
energy rates. In accordance with the respective regulatory plans, OE's, CEI's
and TE's fuel rates would be frozen through the regulatory plan period,
subject to limited periodic adjustments. As part of OE's and FirstEnergy's
regulatory plans, transition rate credits were implemented for customers,
which are expected to reduce operating revenues for OE by approximately $600
million and CEI and TE by approximately $391 million during the regulatory
plan period.
In July 1999, Ohio's new electric utility restructuring legislation
which will allow Ohio electric customers to select their generation suppliers
beginning January 1, 2001, was signed into law. Among other things, the new
law provides for a five percent reduction on the generation portion of
residential customers' bills and the opportunity to recover transition costs,
including regulatory assets, from January 1, 2001 through December 31, 2005.
The period for the recovery of regulatory assets only can be extended up to
December 31, 2010. The PUCO was authorized to determine the level of
transition cost recovery, as well as the recovery period for the regulatory
assets portion of those costs, in considering each Ohio electric utility's
transition plan application.
The Company, on behalf of its Ohio electric utility operating
companies -- OE, CEI and TE -- on December 22, 1999 refiled its transition
plan under Ohio's new electric utility restructuring law. The plan was
originally filed with the PUCO on October 4, 1999, but was refiled to conform
to PUCO rules established on November 30, 1999. The new filing also included
additional information on FirstEnergy's plans to turn over control, and
perhaps ownership, of its transmission assets to the Alliance Regional
Transmission Organization. The PUCO indicated that it will endeavor to issue
its order in the Company's case within 275 days of the initial October filing
date.
The transition plan itemizes, or unbundles, the current price of
electricity into its component elements - including generation, transmission,
distribution and transition charges. As required by the PUCO's rules, the
Company's filing also included its proposals on corporate separation of its
regulated and unregulated operations, operational and technical support
changes needed to accommodate customer choice, an education program to inform
customers of their options under the new law, and how the Company's
transmission system will be operated to ensure access to all users. Under the
plan, customers who remain with OE, CEI, or TE as their generation provider
will continue to receive savings under the Company's rate plans, expected to
total $759 million between 2000 and 2005. In addition, customers will save
$358 million through reduced charges for taxes and a five percent reduction
in the price of generation for residential customers beginning January 1,
2001. Customer prices are expected to be frozen through a five-year market
development period (2001-2005), except for certain limited statutory
exceptions including the five percent reduction in the price of generation
for residential customers. The plan proposes recovery of generation-related
transition costs of approximately $4.5 billion ($4.0 billion, net of deferred
income taxes) over the market development period; transition costs related to
regulatory assets aggregating approximately $4.2 billion ($2.9 billion, net
of deferred income taxes) will be recovered over the period of 2001 through
early 2004 for OE; 2001 through 2007 for TE; and 2001 through 2010 for CEI.
In June 1998, the PPUC authorized a rate restructuring plan for
Penn which essentially resulted in the deregulation of Penn's generation
business as of June 30, 1998. Penn was required to remove from its balance
sheet all regulatory assets and liabilities related to its generation
business and assess all other assets for impairment. The Securities and
Exchange Commission (SEC) issued interpretive guidance regarding asset
impairment measurement which concluded that any supplemental regulated cash
flows such as a competitive transition charge (CTC) should be excluded from
the cash flows of assets in a portion of the business not subject to
regulatory accounting practices. If those assets are impaired, a regulatory
asset should be established if the costs are recoverable through regulatory
cash flows. Consistent with the SEC guidance, Penn reduced its nuclear
generating unit investments by approximately $305 million, of which
approximately $227 million was recognized as a regulatory asset to be
recovered through a CTC over a seven-year transition period; the remaining
net amount of $78 million was written off. The charge of $51.7 million ($30.5
million after income taxes) for discontinuing the application of Statement of
Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation" (SFAS 71), to Penn's generation business was
recorded as a 1998 extraordinary item on the Consolidated Statement of
Income.
All of the Companies' regulatory assets are being recovered under
provisions of the regulatory plans. In addition, the PUCO has authorized OE
to recognize additional capital recovery related to its generating assets
(which is reflected as additional depreciation expense) and additional
amortization of regulatory assets during the regulatory plan period of at
least $2 billion, and the PPUC had authorized Penn to accelerate at least
$358 million, more than the amounts that would have been recognized if the
regulatory plans were not in effect. These additional amounts are being
recovered through current rates. As of December 31, 1999, OE's and Penn's
cumulative additional capital recovery and regulatory asset amortization
amounted to $1.048 billion (including Penn's impairment discussed above and
CTC recovery). CEI and TE recognized a fair value purchase accounting
adjustment of $2.55 billion in connection with the FirstEnergy merger; that
fair value adjustment recognized for financial reporting purposes will
ultimately satisfy the $2 billion asset reduction commitment contained in the
CEI and TE regulatory plan. For regulatory purposes, CEI and TE will
recognize the accelerated amortization over the period that their rate plan
is in effect.
Application of SFAS 71 was discontinued in 1997 with respect to
CEI's and TE's nuclear operations (see "Regulatory Assets" below) and in 1998
with respect to Penn's generation operations (as described above). The
following summarizes net assets included in property, plant and equipment
relating to operations for which the application of SFAS 71 was discontinued,
compared with the respective company's total assets at December 31, 1999.
SFAS 71
Discontinued
Net Assets Total Assets
------------ ------------
(In millions)
CEI $977 $6,209
TE 530 2,667
Penn 76 1,016
PROPERTY, PLANT AND EQUIPMENT-
Property, plant and equipment reflects original cost (except for
CEI's, TE's and Penn's nuclear generating units which were adjusted to fair
value), including payroll and related costs such as taxes, employee benefits,
administrative and general costs, and interest costs.
The Companies provide for depreciation on a straight-line basis at
various rates over the estimated lives of property included in plant in
service. The annual composite rate for OE's electric plant was approximately
3.0% in 1999, 1998 and 1997. The annual composite rate for Penn's electric
plant was approximately 2.5% in 1999 and 3.0% in 1998 and 1997. CEI's and
TE's composite rates were both approximately 3.4% in 1999 and 1998. In
addition to the straight-line depreciation recognized in 1999, 1998 and 1997,
OE and Penn recognized additional capital recovery of $95 million, $141
million (excluding Penn's impairment) and $172 million, respectively, as
additional depreciation expense in accordance with their regulatory plans.
Such additional charges in the accumulated provision for depreciation were
$517 million and $422 million as of December 31, 1999 and 1998, respectively.
Annual depreciation expense in 1999 included approximately $31.0
million for future decommissioning costs applicable to the Companies'
ownership and leasehold interests in four nuclear generating units. The
Companies' future decommissioning costs reflect the increase in their
ownership interests related to the asset transfer with Duquesne Light Company
(Duquesne) discussed below in "Common Ownership of Generating Facilities."
The Companies' share of the future obligation to decommission these units is
approximately $1.8 billion in current dollars and (using a 4.0% escalation
rate) approximately $4.5 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 $315
million for decommissioning through their electric rates from customers
through December 31, 1999. If the actual costs of decommissioning the units
exceed the funds accumulated from investing amounts recovered from customers,
the Companies expect that additional amount to be recoverable from their
customers. The Companies have approximately $543.7 million invested in
external decommissioning trust funds as of December 31, 1999. This includes
additions to the trust funds and the corresponding liability of $123 million
as a result of the asset transfer. Earnings on these funds are reinvested
with a corresponding increase to the decommissioning liability. The Companies
have also recognized an estimated liability of approximately $36.7 million
related to decontamination and decommissioning of nuclear enrichment
facilities operated by the United States Department of Energy (DOE), as
required by the Energy Policy Act of 1992.
The Financial Accounting Standards Board (FASB) issued a proposed
accounting standard for nuclear decommissioning costs in 1996. If the
standard is adopted as proposed: (1) annual provisions for decommissioning
could increase; (2) the net present value of estimated decommissioning costs
could be recorded as a liability; and (3) income from the external
decommissioning trusts could be reported as investment income. The FASB
subsequently expanded the scope of the proposed standard to include other
closure and removal obligations related to long-lived assets. A revised
proposal may be issued by the FASB in the first quarter of 2000.
COMMON OWNERSHIP OF GENERATING FACILITIES-
The Companies and Duquesne constituted the Central Area Power
Coordination Group (CAPCO). The CAPCO companies formerly owned and/or leased,
as tenants in common, various power generating facilities. Each of the
companies is obligated to pay a share of the costs associated with any
jointly owned facility in the same proportion as its interest. The companies'
portions of operating expenses associated with jointly owned facilities are
included in the corresponding operating expenses on the Consolidated
Statements of Income.
On March 26, 1999, FirstEnergy completed its agreements with
Duquesne to exchange certain generating assets. All regulatory approvals were
received by October 1999. In December 1999, Duquesne transferred 1,436
megawatts owned by Duquesne at eight CAPCO generating units in exchange for
1,328 megawatts at three non-CAPCO power plants owned by the Companies. The
agreements for the exchange of assets, which was structured as a like-kind
exchange for tax purposes, provides the Companies with exclusive ownership
and operating control of all CAPCO generating units. The three FirstEnergy
plants transferred are being sold by Duquesne to a wholly owned subsidiary of
Orion Power Holdings, Inc. (Orion). The Companies will continue to operate
those plants until the assets are transferred to the new owners. Duquesne
funded decommissioning costs equal to its percentage interest in the three
nuclear generating units that were transferred to FirstEnergy. The Duquesne
asset transfer to the Orion subsidiary could take place by the middle of
2000. Under the agreements, Duquesne is no longer a participant in the CAPCO
arrangements after the exchange.
NUCLEAR FUEL-
OE's and Penn's nuclear fuel is recorded at original cost, which
includes material, enrichment, fabrication and interest costs incurred prior
to reactor load. CEI and TE severally lease their respective portions of
nuclear fuel and pay for the fuel as it is consumed (see Note 2). 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. Alternative minimum tax credits of
$101 million, which may be carried forward indefinitely, are available to
reduce future federal income taxes.
RETIREMENT BENEFITS-
The Companies' trusteed, noncontributory defined benefit pension
plan covers almost all full-time employees. Upon retirement, employees
receive a monthly pension based on length of service and compensation. In
1998, the Centerior Energy Corporation (Centerior) pension plan was merged
into the FirstEnergy pension plan. The Companies use the projected unit
credit method for funding purposes and were not required to make pension
contributions during the three years ended December 31, 1999. The assets of
the pension plan consist primarily of common stocks, United States government
bonds and corporate bonds.
The Companies provide a minimum amount of noncontributory life
insurance to retired employees in addition to optional contributory
insurance. Health care benefits, which include certain employee deductibles
and copayments, are also available to retired employees, their dependents
and, under certain circumstances, their survivors. The Companies pay
insurance premiums to cover a portion of these benefits in excess of set
limits; all amounts up to the limits are paid by the Companies. The Companies
recognize the expected cost of providing other postretirement benefits to
employees and their beneficiaries and covered dependents from the time
employees are hired until they become eligible to receive those benefits.
The following sets forth the funded status of the plans and amounts
recognized on the Consolidated Balance Sheets as of December 31:
Other
Pension Benefits Postretirement Benefits
---------------- --------------------- -
1999 1998 1999 1998
- ----------------------------------------------------------------------------------------------------
(In millions)
Change in benefit obligation:
Benefit obligation as of January 1 $1,500.1 $1,327.5 $ 601.3 $ 534.1
Service cost 28.3 25.0 9.3 7.5
Interest cost 102.0 92.5 40.7 37.6
Plan amendments -- 44.3 -- 40.1
Actuarial loss (gain) (155.6) 101.6 (17.6) 10.7
Net increase from asset swap 14.8 -- 12.5 --
Benefits paid (95.5) (90.8) (37.8) (28.7)
- ---------------------------------------------------------------------------------------------------
Benefit obligation as of December 31 1,394.1 1,500.1 608.4 601.3
- ---------------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets as of January 1 1,683.0 1,542.5 3.9 2.8
Actual return on plan assets 220.0 231.3 0.6 0.7
Company contribution -- -- 0.4 0.4
Benefits paid (95.5) (90.8) -- --
- ---------------------------------------------------------------------------------------------------
Fair value of plan assets as of December 31 1,807.5 1,683.0 4.9 3.9
- ---------------------------------------------------------------------------------------------------
Funded status of plan 413.4 182.9 (603.5) (597.4)
Unrecognized actuarial loss (gain) (303.5) (110.8) 24.9 30.6
Unrecognized prior service cost 57.3 63.0 24.1 27.4
Unrecognized net transition obligation (asset) (10.1) (18.0) 120.1 129.3
- ---------------------------------------------------------------------------------------------------
Prepaid (accrued) benefit cost $ 157.1 $ 117.1 $(434.4) $(410.1)
====================================================================================================
Assumptions used as of December 31:
Discount rate 7.75% 7.00% 7.75% 7.00%
Expected long-term return on plan assets 10.25% 10.25% 10.25% 10.25%
Rate of compensation increase 4.00% 4.00% 4.00% 4.00%
Net pension and other postretirement benefit costs for the
three years ended December 31, 1999 were computed as follows:
Other
Pension Benefits Postretirement Benefits
---------------------------- -----------------------
1999 1998 1997 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------
(In millions)
Service cost $ 28.3 $ 25.0 $ 15.2 $ 9.3 $ 7.5 $ 4.6
Interest cost 102.0 92.5 55.9 40.7 37.6 20.4
Expected return on plan assets (168.1) (152.7) (99.7) (0.4) (0.3) (0.2)
Amortization of transition obligation (asset) (7.9) (8.0) (8.0) 9.2 9.2 8.2
Amortization of prior service cost 5.7 2.3 2.1 3.3 (0.8) 0.3
Recognized net actuarial loss (gain) -- (2.6) (0.9) -- -- --
Voluntary early retirement program expense -- -- 54.5 -- -- 1.9
- -------------------------------------------------------------------------------------------------------------
Net benefit cost $ (40.0) $ (43.5) $ 19.1 $62.1 $53.2 $35.2
=============================================================================================================
The health care trend rate assumption is 5.3% in 2000, 5.2% in 2001
and 5.0% for 2002 and later years. Assumed health care cost trend rates have
a significant effect on the amounts reported for the health care plan. An
increase in the health care trend rate assumption by one percentage point
would increase the total service and interest cost components by $4.5 million
and the postretirement benefit obligation by $72.0 million. A decrease in the
same assumption by one percentage point would decrease the total service and
interest cost components by $3.5 million and the postretirement benefit
obligation by $58.2 million.
SUPPLEMENTAL CASH FLOWS INFORMATION-
All temporary cash investments purchased with an initial maturity
of three months or less are reported as cash equivalents on the Consolidated
Balance Sheets. At December 31, 1999 and 1998, cash and cash equivalents
included $83 million and $26 million, respectively, to be used for the
redemption of long-term debt in the first quarter of 2000 and in 1999,
respectively. The Companies reflect temporary cash investments at cost, which
approximates their fair market value. Noncash financing and investing
activities included capital lease transactions amounting to $36.2 million,
$61.8 million and $3.0 million for the years 1999, 1998 and 1997,
respectively. Commercial paper transactions of OES Fuel, Incorporated (OES
Fuel) (a wholly owned subsidiary of OE) 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 3H).
All borrowings with initial maturities of less than one year are
defined as financial instruments under generally accepted accounting
principles and are reported on the Consolidated Balance Sheets at cost, which
approximates their fair market value. The following sets forth the
approximate fair value and related carrying amounts of all other long-term
debt, preferred stock subject to mandatory redemption and investments other
than cash and cash equivalents as of December 31:
1999 1998
- --------------------------------------------------------------------
Carrying Fair Carrying Fair
Value Value Value Value
- --------------------------------------------------------------------
(In millions)
Long-term debt $6,381 $6,331 $6,783 $7,247
Preferred stock $ 295 $ 280 $ 335 $ 340
Investments other than cash
and cash equivalents:
Debt securities
-Maturity (5-10 years) $ 475 $ 476 $ 481 $ 520
-Maturity (more than 10
years) 1,068 1,013 1,109 1,139
Equity securities 17 17 17 17
All other 852 874 520 533
- --------------------------------------------------------------------
$2,412 $2,380 $2,127 $2,209
====================================================================
The fair values of long-term debt and preferred stock reflect the
present value of the cash outflows relating to those securities based on the
current call price, the yield to maturity or the yield to call, as deemed
appropriate at the end of each respective year. The yields assumed were based
on securities with similar characteristics offered by a corporation with
credit ratings similar to the Companies' ratings.
The fair value of investments other than cash and cash equivalents
represent cost (which approximates fair value) or the present value of the
cash inflows based on the yield to maturity. The yields assumed were based on
financial instruments with similar characteristics and terms. Investments
other than cash and cash equivalents include decommissioning trust
investments. Unrealized gains and losses applicable to the decommissioning
trusts have been recognized in the trust investment with a corresponding
change to the decommissioning liability. The debt and equity securities
referred to above are in the held-to-maturity category. The Companies have no
securities held for trading purposes.
Effective December 31, 1998, the Company began accounting for its
commodity price derivatives, entered into specifically for trading purposes,
on a mark-to-market basis in accordance with Emerging Issues Task Force Issue
98-10, "Accounting for Energy Trading and Risk Management Activities," with
gains and losses recognized currently in the Consolidated Statements of
Income. The contracts that were marked to market are included in the
Consolidated Balance Sheets as Deferred Charges and Deferred Credits at their
fair values. The impact on the consolidated financial statements was
immaterial.
REGULATORY ASSETS-
The Companies recognize, as regulatory assets, costs which the
FERC, PUCO and PPUC have authorized for recovery from customers in future
periods. Without such authorization, the costs would have been charged to
income as incurred. All regulatory assets are being recovered from customers
under the Companies' respective regulatory plans. Based on those regulatory
plans, at this time, the Companies are continuing to bill and collect cost-
based rates relating to all of OE's operations, CEI's and TE's nonnuclear
operations, and Penn's nongeneration operations and they continue the
application of SFAS 71 to those respective operations. OE and Penn recognized
additional cost recovery of $257 million, $50 million and $39 million in
1999, 1998 and 1997, respectively, as additional regulatory asset
amortization in accordance with their regulatory plans. FirstEnergy's
regulatory plan does not provide for full recovery of CEI's and TE's nuclear
operations. As a result, in October 1997, CEI and TE discontinued application
of SFAS 71 for their nuclear operations and decreased their regulatory assets
of customer receivables for future income taxes related to the nuclear assets
by $794 million.
The PUCO indicated that it will endeavor to issue its order related
to the Company's transition plan by mid-2000. The application of SFAS 71 to
OE's generation business and the nonnuclear generation businesses of CEI and
TE will be discontinued at that time. If the transition plans ultimately
approved by the PUCO for OE, CEI and TE do not provide adequate recovery of
their nuclear generating unit investments and regulatory assets, there would
be a charge to earnings which could have a material adverse effect on the
results of operations and financial condition for the Company, OE, CEI and
TE. The Companies will continue to bill and collect cost-based rates for
their transmission and distribution services, which will remain regulated;
accordingly, it is appropriate that the Companies continue the application of
SFAS 71 to those respective operations after December 31, 2000.
Net regulatory assets on the Consolidated Balance Sheets are
comprised of the following:
1999 1998
- -------------------------------------------------------------------
(In millions)
Nuclear unit expenses $1,123.0 $1,164.8
Customer receivables for future income taxes 444.3 444.0
Rate stabilization program deferrals 420.1 440.1
Sale and leaseback costs 17.8 218.7
Competitive transition charge 280.4 331.0
Loss on reacquired debt 173.9 183.5
Employee postretirement benefit costs 24.8 28.9
DOE decommissioning and decontamination costs 29.5 32.9
Other 29.6 43.5
- --------------------------------------------------------------------
Total $2,543.4 $2,887.4
====================================================================
2. LEASES:
The Companies lease certain generating facilities, nuclear fuel,
office space and other property and equipment under cancelable and
noncancelable leases.
OE 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. CEI and TE also sold
portions of their ownership interests in Beaver Valley Unit 2 and Bruce
Mansfield Units 1, 2 and 3 and entered into similar operating leases for
lease terms of approximately 30 years. During the terms of their respective
leases, OE, CEI and TE continue to be responsible, to the extent of their
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. They
have the right, at the end of the respective basic lease terms, to renew
their respective leases. They also have the right to purchase the facilities
at the expiration of the basic lease term or renewal term (if elected) at a
price equal to the fair market value of the facilities. The basic rental
payments are adjusted when applicable federal tax law changes.
OES Finance, Incorporated (OES Finance), a wholly owned subsidiary
of OE, maintains deposits pledged as collateral to secure reimbursement
obligations relating to certain letters of credit supporting OE'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
OE as sole owner of OES Finance common stock.
Nuclear fuel is currently financed for CEI and TE through leases
with a special-purpose corporation. As of December 31, 1999, $116 million of
nuclear fuel was financed under a lease financing arrangement totaling $145
million ($30 million of intermediate-term notes and $115 million from bank
credit arrangements). The notes mature in August 2000 and the bank credit
arrangements expire in September 2000. Lease rates are based on intermediate-
term note rates, bank rates and commercial paper rates.
Consistent with the regulatory treatment, the rentals for capital
and operating leases are charged to operating expenses on the Consolidated
Statements of Income. Such costs for the three years ended December 31, 1999,
are summarized as follows:
1999 1998 1997
- -----------------------------------------------------------
(In millions)
Operating leases
Interest element $208.6 $201.2 $149.9
Other 110.3 147.8 45.2
Capital leases
Interest element 17.5 17.6 6.1
Other 76.1 66.3 6.0
- ----------------------------------------------------------
Total rentals $412.5 $432.9 $207.2
==========================================================
The future minimum lease payments as of December 31, 1999, are:
Operating Leases
-----------------------------
Capital Lease Capital
Leases Payments Trusts Net
- ------------------------------------------------------------------------------------
(In millions)
2000 $ 75.4 $ 296.5 $ 150.6 $ 145.9
2001 45.2 307.5 146.1 161.4
2002 29.7 312.7 169.5 143.2
2003 16.0 326.6 176.5 150.1
2004 12.1 291.8 110.7 181.1
Years thereafter 71.6 3,645.8 1,364.3 2,281.5
- -----------------------------------------------------------------------------------
Total minimum lease payments 250.0 $5,180.9 $2,117.7 $3,063.2
Executory costs 26.9 ======== ======== ========
- --------------------------------------------
Net minimum lease payments 223.1
Interest portion 64.8
- --------------------------------------------
Present value of net minimum
lease payments 158.3
Less current portion 55.2
- --------------------------------------------
Noncurrent portion $103.1
============================================
OE invested in the PNBV Capital Trust, which was established to
purchase a portion of the lease obligation bonds issued on behalf of lessors
in OE's Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback
transactions. CEI and TE established the Shippingport Capital Trust to
purchase the lease obligation bonds issued on behalf of lessors in their
Bruce Mansfield Units 1, 2 and 3 sale and leaseback transactions. The PNBV
and Shippingport capital trust arrangements effectively reduce lease costs
related to those transactions.
3. CAPITALIZATION:
(A) RETAINED EARNINGS-
There are no restrictions on retained earnings for payment of cash
dividends on the Company's common stock.
(B) EMPLOYEE STOCK OWNERSHIP PLAN-
The Companies fund 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 OE and acquired 10,654,114 shares of OE's common
stock through market purchases; the shares were converted into the Company's
common stock in connection with the merger. 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 1999, 1998 and 1997, 627,427 shares,
423,206 shares and 429,515 shares, respectively, were allocated to employees
with the corresponding expense recognized based on the shares allocated
method. The fair value of 6,778,905 shares unallocated as of December 31,
1999, was approximately $153.8 million. Total ESOP-related compensation
expense was calculated as follows:
1999 1998 1997
- ----------------------------------------------------------------
(In millions)
Base compensation $18.3 $13.5 $ 9.9
Dividends on common stock held by
the ESOP and used to service debt (4.5) (3.9) (3.4)
- -----------------------------------------------------------------
Net expense $13.8 $ 9.6 $ 6.5
==================================================================
(C) STOCK COMPENSATION PLANS-
Under the Centerior Equity Compensation Plan (Centerior Plan)
adopted in 1994, common stock options were granted to management employees.
Upon consummation of the merger, outstanding options became exercisable for
the Company's common stock with option prices and the number of shares
adjusted to reflect the merger conversion ratio. All options under the
Centerior Plan expire on or before February 25, 2007.
On April 30, 1998, the Company adopted the Executive and Director
Incentive Compensation Plan (FE Plan). The FE Plan permits awards to be made
to key employees in the form of restricted stock, stock options, stock
appreciation rights, performance shares or cash. Common stock granted under
the FE Plan may not exceed 7.5 million shares. No stock appreciation rights
or performance shares have been issued under the FE Plan. A total of 20,000
shares of restricted stock were granted in 1998, with a per share market
price of $30.78. Restrictions on the restricted stock lapse in 25% annual
increments beginning in the fourth year from date of grant. Dividends on the
1998 grant are not restricted. An additional 8,000 shares of restricted stock
were granted in 1999, in five separate awards with a weighted average market
price per share of $30.89 and weighted average cliff vesting period of 5.8
years. Dividends on the 1999 grants are being restricted. Options were
granted in 1998 and 1999, and are exercisable after four years from the date
of grant with some acceleration of vesting possible based on performance.
Stock option activity for the converted Centerior Plan stock options and FE
Plan stock options was as follows:
Number of Weighted Average
Stock Option Activity Options Exercise Price
- -------------------------------------------------------------------
Balance at December 31, 1996 -- $ --
Options granted (at merger) 743,086 23.85
Options exercised 222,023 22.13
Options forfeited 3,675 22.75
Balance at December 31, 1997 517,388 24.59
(517,388 options exercisable)
Options granted 189,491 29.82
Options exercised 335,058 24.67
Options forfeited 7,535 29.82
Balance at December 31, 1998 364,286 27.13
(182,330 options exercisable)
Options granted 1,811,658 24.90
Options exercised 22,575 21.42
Balance at December 31, 1999 2,153,369 25.32
(159,755 options exercisable)
- ----------------------------------------------------------------
As of December 31, 1999, the weighted average remaining contractual
life of outstanding stock options was 6.2 years.
Under the Executive Deferred Compensation Plan, adopted January 1,
1999, employees can direct a portion of their Annual Incentive Award and/or
Long Term Incentive Award into an unfunded FirstEnergy Stock Account to
receive vested stock units. An additional 20% premium is received in the form
of stock units based on the amount allocated to the FirstEnergy Stock
Account. Dividends are calculated quarterly on stock units outstanding and
are paid in the form of additional stock units. Upon withdrawal, stock units
are converted to FirstEnergy shares. Payout occurs three years from the date
of deferral. As of December 31, 1999, there were 61,465.81 stock units
outstanding.
The Company continues to apply APB Opinion 25, "Accounting for
Stock Issued to Employees." As required by SFAS 123, "Accounting for Stock-
Based Compensation," the Company has determined pro forma earnings as though
the Company had accounted for employee stock options under the fair value
method. The weighted average assumptions used in valuing the options and
their resulting fair values are as follows:
1999 1998 1997
- -------------------------------------------------------------
Valuation assumptions:
Expected option term (years) 6.4 10 8
Expected volatility 20.03% 15.50% 16.00%
Expected dividend yield 5.97% 5.68% 5.80%
Risk-free interest rate 5.97% 5.65% 5.94%
Fair value per option $3.42 $3.25 $2.92
- --------------------------------------------------------------
The pro forma effects of applying fair value accounting to the
Company's stock options would be to reduce net income and earnings per share.
The following table summarizes the pro forma effect.
1999 1998
- ------------------------------------------
Net Income (000)
As Reported $568,299 $410,874
Pro Forma $567,876 $410,839
Earnings Per Share
of Common Stock -
Basic and Diluted
As Reported $2.50 $1.82
Pro Forma $2.50 $1.82
- -------------------------------------------
(D) COMPREHENSIVE INCOME-
In 1998, the Company adopted SFAS 130, "Reporting Comprehensive
Income," and applied the standard to all periods presented in the
Consolidated Statements of Common Stockholders' Equity. Comprehensive income
includes net income as reported on the Consolidated Statements of Income and
all other changes in common stockholders' equity except those resulting from
transactions with common stockholders.
(E) PREFERRED AND PREFERENCE STOCK-
Penn's 7.75% series of preferred stock has a restriction which
prevents early redemption prior to July 2003. OE's 8.45% series of preferred
stock has no optional redemption provision. CEI's $88.00 Series R preferred
stock is not redeemable before December 2001 and its $90.00 Series S has no
optional redemption provision. All other preferred stock may be redeemed by
the Companies in whole, or in part, with 30-90 days' notice.
Preference stock authorized for the Companies are 8 million shares
without par value for OE; 3 million shares without par value for CEI; and 5
million shares, $25 par value for TE. No preference shares are currently
outstanding.
(F) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION-
Annual sinking fund provisions for the Companies' preferred stock
are as follows:
Redemption
Price Per
Series Shares Share Date Beginning
- ------------------------------------------------------------------
OE 8.45% 50,000 $ 100 (i)
CEI $ 7.35 C 10,000 100 (i)
88.00 E 3,000 1,000 (i)
91.50 Q 10,714 1,000 (i)
90.00 S 18,750 1,000 (i)
88.00 R 50,000 1,000 December 1 2001
Penn 7.625% 7,500 100 October 1 2002
- ------------------------------------------------------------------
<FN>
(i) Sinking fund provisions are in effect.
Annual sinking fund requirements for the next five years are $38
million in 2000, $85 million in 2001, $19 million in 2002, $2 million in 2003
and $2 million in 2004. A liability of $19 million was included in the net
assets acquired from CEI and TE for preferred dividends declared attributable
to the post-merger period. Accordingly, no accruals for CEI and TE preferred
dividends are included in the Company's Consolidated Statement of Income for
the period November 8, 1997 through December 31, 1997.
(G) OHIO EDISON OBLIGATED MANDATORILY REDEEMABLE PREFERRED
SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY OHIO EDISON
SUBORDINATED DEBENTURES-
Ohio Edison Financing Trust, a wholly owned subsidiary of OE, has
issued $120 million of 9% Cumulative Trust Preferred Capital Securities. OE
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 OE
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.
OE'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 OE of payments due on the Preferred Securities.
(H) LONG-TERM DEBT-
The first mortgage indentures and their supplements, which secure
all of the Companies' first mortgage bonds, serve as direct first mortgage
liens on substantially all property and franchises, other than specifically
excepted property, owned by the Companies.
Based on the amount of bonds authenticated by the Trustees through
December 31, 1999, OE's, TE's and Penn's annual sinking and improvement fund
requirements for all bonds issued under the mortgage amounts to $31 million.
OE, TE and Penn expect to deposit funds in 2000 that will be withdrawn upon
the surrender for cancellation of a like principal amount of bonds, which are
specifically authenticated for such purposes against unfunded property
additions or against previously retired bonds. This method can result in
minor increases in the amount of the annual sinking fund requirement.
Sinking fund requirements for first mortgage bonds and maturing
long-term debt (excluding capital leases) for the next five years are:
(In millions)
---------------------------
2000 $668.8
2001 375.7
2002 945.8
2003 459.0
2004 833.3
---------------------------
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 $397.3 million. To the extent that
drawings are made under those letters of credit to pay principal of, or
interest on, the pollution control revenue bonds, OE, Penn and/or CEI are
entitled to a credit against their obligation to repay those bonds. The
Companies pay annual fees of 0.43% to 1.10% of the amounts of the letters of
credit to the issuing banks and are obligated to reimburse the banks for any
drawings thereunder.
OE had unsecured borrowings of $190 million at December 31, 1999,
supported by a $250 million long-term revolving credit facility agreement
which expires November 18, 2002. OE must pay an annual facility fee of 0.20%
on the total credit facility amount. In addition, the credit agreement
provides that OE maintain unused first mortgage bond capability for the full
credit agreement amount under OE's indenture as potential security for the
unsecured borrowings.
CEI and TE have letters of credit of approximately $222 million in
connection with the sale and leaseback of Beaver Valley Unit 2 that expire in
May 2002. The letters of credit are secured by first mortgage bonds of CEI
and TE in the proportion of 40% and 60%, respectively (see Note 2).
OE's and Penn's nuclear fuel purchases are financed through the
issuance of OES Fuel commercial paper and loans, both of which are supported
by a $180.5 million long-term bank credit agreement which expires March 31,
2001. Accordingly, the commercial paper and loans are reflected as long-term
debt on the Consolidated Balance Sheets. OES Fuel must pay an annual facility
fee of 0.20% on the total line of credit and an annual commitment fee of
0.0625% on any unused amount.
4. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT:
Short-term borrowings outstanding at December 31, 1999, consisted
of $257.8 million of bank borrowings and $160.0 million of OES Capital,
Incorporated (OES Capital) commercial paper. OES Capital is a wholly owned
subsidiary of OE whose borrowings are secured by customer accounts
receivable. OES Capital can borrow up to $170 million under a receivables
financing agreement at rates based on certain bank commercial paper and is
required to pay an annual fee of 0.20% on the amount of the entire finance
limit. The receivables financing agreement expires in 2002.
The Companies have various credit facilities with domestic banks
that provide for borrowings of up to $205 million under various interest rate
options. OE's short-term borrowings may be made under its lines of credit on
its unsecured notes. To assure the availability of these lines, the Companies
are required to pay annual commitment fees that vary from 0.125% to 0.50%.
These lines expire at various times during 2000. The weighted average
interest rates on short-term borrowings outstanding at December 31, 1999 and
1998, were 6.51% and 5.67%, respectively.
5. COMMITMENTS AND CONTINGENCIES:
CAPITAL EXPENDITURES-
The Companies' current forecasts reflect expenditures of
approximately $3.0 billion for property additions and improvements from 2000-
2004, of which approximately $650 million is applicable to 2000. Investments
for additional nuclear fuel during the 2000-2004 period are estimated to be
approximately $497 million, of which approximately $159 million applies to
2000. During the same periods, the Companies' nuclear fuel investments are
expected to be reduced by approximately $480 million and $106 million,
respectively, as the nuclear fuel is consumed.
STOCK REPURCHASE PROGRAM-
On November 17, 1998, the Board of Directors authorized the
repurchase of up to 15 million shares of the Company's common stock over a
three-year period beginning in 1999. Repurchases are made on the open market,
at prevailing prices, and are funded primarily through the use of operating
cash flows. During 1999, the Company repurchased and retired 4.6 million
shares of its common stock at an average price of $28.08 per share. The
Company also entered into a forward contract with Credit Suisse First Boston
Corporation for the purchase of 1.4 million shares of the Company's common
stock at an average price of $24.22 per share to be settled on November 3,
2000. The contract may be settled through gross physical settlement, net
share settlement or net cash settlement at the Company's election.
NUCLEAR INSURANCE-
The Price-Anderson Act limits the public liability relative to a
single incident at a nuclear power plant to $9.5 billion. The amount is
covered by a combination of private insurance and an industry retrospective
rating plan. The Companies' maximum potential assessment under the industry
retrospective rating plan would be $352.4 million per incident but not more
than $40 million in any one year for each incident.
The Companies are also insured under policies for each nuclear
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 $1.43 billion of insurance coverage for replacement
power costs. Under these policies, the Companies can be assessed a maximum of
approximately $44 million for incidents at any covered nuclear facility
occurring during a policy year which are in excess of accumulated funds
available to the insurer for paying losses.
The Companies intend to maintain insurance against nuclear risks as
described above as long as it is available. To the extent that replacement
power, property damage, decontamination, decommissioning, repair and
replacement costs and other such costs arising from a nuclear incident at any
of the Companies' plants exceed the policy limits of the insurance in effect
with respect to that plant, to the extent a nuclear incident is determined
not to be covered by the Companies' insurance policies, or to the extent such
insurance becomes unavailable in the future, the Companies would remain at
risk for such costs.
ENVIRONMENTAL MATTERS-
Various federal, state and local authorities regulate the Companies
with regard to air and water quality and other environmental matters. The
Companies estimate additional capital expenditures for environmental
compliance of approximately $292 million, which is included in the
construction forecast provided under "Capital Expenditures" for 2000 through
2004.
The Companies are in compliance with the current sulfur dioxide
(SO2) and nitrogen oxides (NOx) reduction requirements under the Clean Air
Act Amendments of 1990. SO2 reductions are being achieved by burning lower-
sulfur fuel, generating more electricity from lower-emitting plants, and/or
purchasing emission allowances. NOx reductions are being achieved through
combustion controls and generating more electricity from lower-emitting
plants. In September 1998, the Environmental Protection Agency (EPA)
finalized regulations requiring additional NOx reductions from the Companies'
Ohio and Pennsylvania facilities by May 2003. The EPA's NOx Transport Rule
imposes uniform reductions of NOx emissions across a region of twenty-two
states and the District of Columbia, including Ohio and Pennsylvania, based
on a conclusion that such NOx emissions are contributing significantly to
ozone pollution in the eastern United States. In May 1999, the U.S. Court of
Appeals for the D.C. Circuit issued a stay which delays implementation of
EPA's NOx Transport Rule until the Court has ruled on the merits of various
appeals. Under the NOx Transport Rule, each of the twenty-two states are
required to submit revised State Implementation Plans (SIP) which comply with
individual state NOx budgets established by the EPA contemplating an
approximate 85% reduction in utility plant NOx emissions from projected 2007
emissions. A proposed Federal Implementation Plan accompanied the NOx
Transport Rule and may be implemented by the EPA in states which fail to
revise their SIP. In another separate but related action, eight states filed
petitions with the EPA under Section 126 of the Clean Air Act seeking
reductions of NOx emissions which are alleged to contribute to ozone
pollution in the eight petitioning states. The EPA suggests that the Section
126 petitions will be adequately addressed by the NOx Transport Program, but
a December 17, 1999 rulemaking established an alternative program which would
require nearly identical 85% NOx reductions at 392 utility plants, including
the Companies' Ohio and Pennsylvania plants, by May 2003, in the event
implementation of the NOx Transport Rule is delayed. New Section 126
petitions were filed by New Jersey, Maryland, Delaware and the District of
Columbia in mid-1999 and are still under evaluation by the EPA. The Companies
continue to evaluate their compliance plans and other compliance options.
The Companies are required to meet federally approved SO2
regulations. Violations of such regulations can result in shutdown of the
generating unit involved and/or civil or criminal penalties of up to $27,500
for each day the unit is in violation. The EPA has an interim enforcement
policy for SO2 regulations in Ohio that allows for compliance based on a 30-
day averaging period. The Companies cannot predict what action the EPA may
take in the future with respect to the interim enforcement policy.
In July 1997, the EPA promulgated changes in the National Ambient
Air Quality Standard (NAAQS) for ozone and proposed a new NAAQS for
previously unregulated ultra-fine particulate matter. In May 1999, the U.S.
Court of Appeals for the D.C. Circuit remanded both standards back to the EPA
finding constitutional and other defects in the new NAAQS rules. The D.C.
Circuit Court, on October 29, 1999, denied an EPA petition for rehearing. The
Companies cannot predict the EPA's action in response to the Court's remand
order. The cost of compliance with these regulations, if they are reinstated,
may be substantial and depends on the manner in which they are ultimately
implemented, if at all, by the states in which the Companies operate affected
facilities.
In September 1999, FirstEnergy received, and subsequently in
October 1999, OE and Penn received, a citizen suit notification letter from
the New York Attorney General's office alleging Clean Air Act violations at
the W. H. Sammis Plant. In November 1999, OE and Penn received a citizen suit
notification letter from the Connecticut Attorney General's office alleging
Clean Air Act violations at the Sammis Plant. On November 3, 1999, the EPA
issued Notices of Violation (NOV) or a Compliance Order to eight utilities
covering 32 power plants, including the Sammis Plant. In addition, the U.S.
Department of Justice filed seven civil complaints against various investor-
owned utilities, which included a complaint against OE and Penn in the U.S.
District Court for the Southern District of Ohio. The NOV and complaint
allege violations of the Clean Air Act based on operation and maintenance of
the Sammis Plant dating back to 1984. The complaint requests permanent
injunctive relief to require the installation of "best available control
technology" and civil penalties of up to $27,500 per day of violation.
Although unable to predict the outcome of this litigation, the Company
believes the Sammis Plant is in full compliance with the Clean Air Act and
the NOV and complaint are without merit. Penalties could be imposed if the
Sammis Plant continues to operate without correcting the alleged violations
and a court determines that the allegations are valid. It is anticipated at
this time that the Sammis Plant will continue to operate while the matter is
being decided.
CEI and TE have been named as "potentially responsible parties"
(PRPs) at waste disposal sites which may require cleanup under the
Comprehensive Environmental Response, Compensation and Liability Act of 1980.
Allegations of disposal of hazardous substances at historical sites and the
liability involved, are often unsubstantiated and subject to dispute. Federal
law provides that all PRPs for a particular site be held liable on a joint
and several basis. CEI and TE have accrued liabilities totaling $5.4 million
as of December 31, 1999, based on estimates of the costs of cleanup and the
proportionate responsibility of other PRPs for such costs. CEI and TE believe
that waste disposal costs will not have a material adverse effect on their
financial condition, cash flows or results of operations.
6. SEGMENT INFORMATION:
The Company's primary segment is its Electric Utility Operating
Companies which includes four regulated electric utility operating companies
that provide electric service in Ohio and Pennsylvania. Its other material
business segment is FETS which markets and trades electricity in nonregulated
markets. Financial data for these business segments and products and services
are as shown on the following page:
Segment Financial Information
- -----------------------------
Electric FE Trading All Reconciling
Utilities Services Other Eliminations Totals
--------- ---------- ------- ------------ --------
(In millions)
1999
----
External revenues $ 5,421 $191 $ 708 $ -- $ 6,320
Intersegment revenues 32 60 102 (194) --
Total revenues 5,453 251 810 (194) 6,320
Depreciation and amortization 913 -- 25 -- 938
Net interest charges 549 6 66 (49) 572
Income taxes 377 (5) 23 -- 395
Net income/Earnings on
common stock 545 (8) 35 (4) 568
Total assets 17,105 181 1,864 (926) 18,224
Property additions 417 -- 130 -- 547
Acquisitions -- 25 53 -- 78
1998
----
External revenues $ 5,215 $411 $ 249 $ -- $ 5,875
Intersegment revenues 32 26 97 (155) --
Total revenues 5,247 437 346 (155) 5,875
Depreciation and
amortization 748 -- 11 -- 759
Net interest charges 590 2 69 (60) 601
Income taxes 320 (35) (2) -- 283
Extraordinary item:
Pennsylvania restructuring (31) -- -- -- (31)
Net income/Earnings on
common stock 478 (52) 1 (16) 411
Total assets 18,316 54 1,742 (1,920) 18,192
Property additions 304 -- 64 -- 368
Acquisitions -- -- 285 -- 285
1997
----
External revenues $ 2,844 $ 43 $ 74 $ -- $ 2,961
Intersegment revenues 33 -- 106 (139) --
Total revenues 2,877 43 180 (139) 2,961
Depreciation and
amortization 470 -- 5 -- 475
Net interest charges 300 -- 60 (51) 309
Income taxes 206 -- 3 -- 209
Net income/Earnings on
common stock 335 (1) 4 (32) 306
Total assets 18,700 32 1,209 (1,680) 18,261
Property additions 166 -- 38 -- 204
Acquisitions -- -- 1,582 -- 1,582
Products and Services
- ---------------------
Oil & Gas Energy Related
Electricity Sales and Sales and
Year Sales Production Services
---- ----------- ---------- ---------------
(In millions)
1999 $5,253 $203 $503
1998 4,980 26 198
1997 2,775 -- --
</TABLE
7. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
The following summarizes certain consolidated operating results
by quarter for 1999 and 1998.
March 31, June 30, September 30, December 31,
Three Months Ended 1999 1999 1999 1999
- ------------------------------------------------------------------------------------
(In millions, except per share amounts)
Revenues $1,417.4 $1,523.9 $1,732.4 $1,645.9
Expenses 1,041.7 1,149.8 1,291.0 1,301.7
- ------------------------------------------------------------------------------------
Income Before Interest and
Income Taxes 375.7 374.1 441.4 344.2
Net Interest Charges 146.1 147.4 141.3 137.5
Income Taxes 92.9 101.4 114.3 86.2
- ------------------------------------------------------------------------------------
Net Income $ 136.7 $ 125.3 $ 185.8 $ 120.5
=====================================================================================
Earnings per Share of Common
Stock $ .60 $ .55 $ .82 $ .53
=====================================================================================
March 31, June 30, September 30, December 31,
Three Months Ended 1998 1998 1998 1998
- ------------------------------------------------------------------------------------
(In millions, except per share amounts)
Revenues $1,367.1 $1,464.0 $1,722.0 $1,321.8
Expenses 1,016.8 1,197.1 1,294.0 1,020.8
- ------------------------------------------------------------------------------------
Income Before Interest and
Income Taxes 350.3 266.9 428.0 301.0
Net Interest Charges 143.6 154.7 153.3 149.4
Income Taxes 83.0 52.2 111.7 56.9
- ------------------------------------------------------------------------------------
Income Before Extraordinary Item 123.7 60.0 163.0 94.7
Extraordinary Item
(Net of Income Taxes)
(Note 1) -- (30.5) -- --
- ------------------------------------------------------------------------------------
Net Income $ 123.7 $ 29.5 $ 163.0 $ 94.7
=======================================================================-=============
Earnings per Share of Common
Stock
Before Extraordinary Item $ .56 $ .27 $ .71 $ .41
Extraordinary Item
(Net of Income Taxes)
(Note 1) -- (.14) -- --
- ------------------------------------------------------------------------------------
Earnings per Share of
Common Stock $ .56 $ .13 $ .71 $ .41
=====================================================================================
8. PRO FORMA COMBINED CONDENSED FIRSTENERGY STATEMENT OF INCOME
(UNAUDITED):
The Company was formed on November 8, 1997 by the merger of OE and
Centerior. The merger was accounted for as a purchase of Centerior's net
assets with 77,637,704 shares of FirstEnergy Common Stock through the
conversion of each outstanding Centerior Common Stock share into 0.525 of a
share of FirstEnergy Common Stock (fractional shares were paid in cash).
Based on an imputed value of $20.125 per share, the purchase price was
approximately $1.582 billion, which also included approximately $20 million
of merger related costs. Goodwill of approximately $2.0 billion was
recognized (to be amortized on a straight-line basis over forty years), which
represented the excess of the purchase price over Centerior's net assets
after fair value adjustments.
Accumulated amortization of goodwill was approximately $109 million
as of December 31, 1999. The merger purchase accounting adjustments, which
were recorded in the records of Centerior's direct subsidiaries, included
recognizing estimated severance and other compensation liabilities ($80
million). The amount charged against the liability in 1998 relating to the
costs of involuntary employee separation was $41 million. In addition, the
liability was reduced to approximately $9 million as of December 31, 1998 to
represent potential costs associated with the separation of 493 CEI
employees. The liability adjustment was offset by a corresponding reduction
to goodwill recognized in connection with the Centerior acquisition.
The following pro forma statement of income of FirstEnergy gives
effect to the OE/Centerior merger as if it had been consummated on January 1,
1997, with the purchase accounting adjustments actually recognized in the
business combination.
Year Ended
December 31,
1997
- ------------------------------------------------------------
(In millions, except per share amounts)
Revenues $5,206
Expenses 3,800
- ------------------------------------------------------------
Income Before Interest and Income Taxes 1,406
Net Interest Charges 643
Income Taxes 336
- ------------------------------------------------------------
Net Income $ 427
============================================================
Earnings per Share of Common Stock $ 1.92
============================================================
Pro forma adjustments reflected above include: (1) adjusting CEI
and TE nuclear generating units to fair value based upon independent
appraisals and estimated discounted future cash flows based on management's
estimate of cost recovery; (2) goodwill recognized representing the excess of
the purchase price over Centerior's adjusted net assets; (3) elimination of
revenue and expense transactions between OE and Centerior; (4) amortization
of the fair value adjustment for long-term debt; and (5) adjustments for
estimated tax effects on the above adjustments.