SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K/A
AMENDMENT No. 1
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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Commission Registrant; State of Incorporation; I.R.S. Employer
File Number Address; and Telephone Number Identification No.
----------- ----------------------------------- ------------------
333-21011 FIRSTENERGY CORP. 34-1843785
(An Ohio Corporation)
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402
AMENDMENT NO. 1
EXPLANATORY NOTE
As described in Note 2(L) to the consolidated financial statements,
FirstEnergy Corp. has revised certain classifications in its previously reported
Consolidated Statement of Income for the year ended December 31, 2002. The
revisions had no effect on previously reported net income or earning per share.
The following items have been amended:
PART I
ITEM 1. BUSINESS
PART II
ITEM 6. SELECTED FINANCIAL DATA
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PART III
ITEM 14. CONTROLS AND PROCEDURES
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Name of Each Exchange
Registrant Title of Each Class on Which Registered
---------------- ----------------------------- -------------------------
FirstEnergy Corp. Common Stock, $0.10 par value New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
None
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days: Yes (X) No ( )
- -
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. (X)
Indicate by check mark whether each registrant is an accelerated filer
(as defined in Rule 12b-2 of the Act): Yes (X) No ( )
- -
State the aggregate market value of the common stock held by
non-affiliates of the registrant: FirstEnergy Corp., $9,920,663,231 as of June
28, 2002.
Indicate the number of shares outstanding of the registrant's classes
of common stock, as of the latest practicable date:
OUTSTANDING
CLASS AS OF MARCH 24, 2003
----- --------------------
FirstEnergy Corp., $0.10 par value 297,636,276
Documents incorporated by reference (to the extent indicated herein):
PART OF FORM 10-K INTO WHICH
DOCUMENT DOCUMENT IS INCORPORTED
-------- ----------------------------
FirstEnergy Corp. Annual Report to
Stockholders for the fiscal year ended
December 31, 2002, as revised (Pages 1-66) Part II
FORM 10-K
TABLE OF CONTENTS
Page
Part I ----
Item 1. Business..................................................... 1
The Company................................................ 1
Divestitures-
International Operations................................. 2
Generating Assets........................................ 3
Utility Regulation......................................... 3
PUCO Rate Matters........................................ 4
NJBPU Rate Matters....................................... 4
PPUC Rate Matters........................................ 5
FERC Rate Matters........................................ 6
Regulatory Accounting.................................... 7
Capital Requirements....................................... 7
Met-Ed Capital Trust and Penelec Capital Trust............. 9
Nuclear Regulation......................................... 9
Nuclear Insurance.......................................... 10
Environmental Matters...................................... 11
Air Regulation........................................... 11
Water Regulation......................................... 12
Waste Disposal........................................... 12
Summary.................................................. 12
Fuel Supply................................................ 13
System Capacity and Reserves............................... 13
Regional Reliability....................................... 14
Competition................................................ 14
Research and Development................................... 15
Executive Officers......................................... 15
FirstEnergy Website........................................ 15
Item 2. Properties................................................... *
Item 3. Legal Proceedings............................................ *
Item 4. Submission of Matters to a Vote of Security Holders.......... *
Part II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters........................................ *
Item 6. Selected Financial Data...................................... 16
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations........................ 16
Item 8. Financial Statements and Supplementary Data.................. 16
Item 9. Changes In and Disagreements with Accountants on
Accounting and Financial Disclosure........................ *
Part III
Item 10. Directors and Executive Officers of the Registrant........... *
Item 11. Executive Compensation....................................... *
Item 12. Security Ownership of Certain Beneficial Owners and
Management and Related Shareholder Matters................. *
Item 13. Certain Relationships and Related Transactions............... *
Item 14. Controls and Procedures...................................... 16
Part IV
Item 15. Exhibits, Financial Statement Schedules and
Reports on Form 8-K....................................... 16
* Indicates the items that have not been revised and are not included in this
Form 10-K/A. Reference is made to the original 10-K for the complete text of
such items.
PART 1
ITEM 1. BUSINESS
The Company
FirstEnergy Corp. was organized under the laws of the State of Ohio in
1996. FirstEnergy's principal business is the holding, directly or indirectly,
of all of the outstanding common stock of its principal electric utility
operating subsidiaries, Ohio Edison Company (OE), The Cleveland Electric
Illuminating Company (CEI), Pennsylvania Power Company (Penn), The Toledo Edison
Company (TE), American Transmission Systems, Incorporated (ATSI), Jersey Central
Power & Light Company (JCP&L), Metropolitan Edison Company (Met-Ed) and
Pennsylvania Electric Company (Penelec). These utility subsidiaries are referred
to throughout as "Companies." FirstEnergy's consolidated revenues are primarily
derived from electric service provided by its utility operating subsidiaries and
the revenues of its other principal subsidiaries: FirstEnergy Solutions Corp.
(FES); FirstEnergy Facilities Services Group, LLC (FSG); MYR Group Inc. (MYR);
MARBEL Energy Corporation (MARBEL); GPU Capital, Inc.; and GPU Power, Inc. In
addition, FirstEnergy holds all of the outstanding common stock of other direct
subsidiaries including: FirstEnergy Properties, Inc., FirstEnergy Ventures
Corp., FirstEnergy Nuclear Operating Company (FENOC), FirstEnergy Securities
Transfer Company, GPU Diversified Holdings, LLC, GPU Telecom Services, Inc., GPU
Nuclear, Inc.; FirstEnergy Service Company (FECO); GPU Service, Inc. (GPUS); and
GPU Advanced Resources, Inc.
The Companies' combined service areas encompass approximately 37,200
square miles in Ohio, New Jersey and Pennsylvania. The areas they serve have a
combined population of approximately 11.1 million.
OE was organized under the laws of the State of Ohio in 1930 and owns
property and does business as an electric public utility in that state. OE also
has ownership interests in certain generating facilities located in the
Commonwealth of Pennsylvania (see Item 2 - Properties). OE engages in the
generation, distribution and sale of electric energy to communities in a 7,500
square mile area of central and northeastern Ohio. OE also engages in the sale,
purchase and interchange of electric energy with other electric companies. The
area it serves has a population of approximately 2.7 million.
OE owns all of Penn's outstanding common stock. Penn was organized
under the laws of the Commonwealth of Pennsylvania in 1930 and owns property and
does business as an electric public utility in that state. Penn is also
authorized to do business and owns property in the State of Ohio (see Item 2 -
Properties). Penn furnishes electric service to communities in a 1,500 square
mile area of western Pennsylvania. The area served by Penn has a population of
approximately 0.3 million.
CEI was organized under the laws of the State of Ohio in 1892 and does
business as an electric public utility in that state. CEI engages in the
generation, distribution and sale of electric energy in an area of approximately
1,700 square miles in northeastern Ohio. It also has ownership interests in
certain generating facilities in Pennsylvania (see Item 2 - Properties). CEI
also engages in the sale, purchase and interchange of electric energy with other
electric companies. The area CEI serves has a population of approximately 1.9
million.
TE was organized under the laws of the State of Ohio in 1901 and does
business as an electric public utility in that state. TE engages in the
generation, distribution and sale of electric energy in an area of approximately
2,500 square miles in northwestern Ohio. It also has interests in certain
generating facilities in Pennsylvania and Michigan (see Item 2 - Properties). TE
also engages in the sale, purchase and interchange of electric energy with other
electric companies. The area TE serves has a population of approximately 0.8
million.
ATSI was organized under the laws of the State of Ohio in 1998. ATSI
owns transmission assets that were formerly owned by OE, CEI and TE (Ohio
Companies) and Penn. ATSI owns and operates major, high-voltage transmission
facilities, which consist of approximately 7,100 circuit miles (5,778 pole
miles) of transmission lines with nominal voltages of 345 kilovolts (kV), 138 kV
and 69 kV. There are 37 interconnections with six neighboring control areas.
ATSI's transmission system offers gateways into the East through high capacity
ties with Pennsylvania-New Jersey-Maryland Interconnection LLC (PJM) through
Penelec, Duquesne Light Company (Duquesne) and Allegheny Energy, Inc.
(Allegheny), into the North through multiple 345 kV high capacity ties with
Michigan Electric Coordination Systems (MEC), and into the South through ties
with American Electric Power Company, Inc. (AEP) and Dayton Power & Light
Company (DPL). In addition, ATSI is the control area operator for the Ohio
Companies and Penn service areas. ATSI plans, operates and maintains the
transmission system in accordance with the requirements of the North American
Electric Reliability Council and applicable regulatory agencies to ensure
reliable service to FirstEnergy's customers (see FERC Rate Matters for
discussion on ATSI's participation in the Midwest Independent System Operator,
Inc. (MISO)).
JCP&L was organized under the laws of the State of New Jersey in 1925
and owns property and does business as an electric public utility in that state.
JCP&L provides transmission and distribution services in northern, western and
east central New Jersey. The area it serves has a population of approximately
2.5 million.
1
Met-Ed was organized under the laws of the Commonwealth of
Pennsylvania in 1922 and owns property and does business as an electric public
utility in that state. Met-Ed provides transmission and distribution services in
eastern and south central Pennsylvania. The area it serves has a population of
approximately 1.1 million.
Penelec was organized under the laws of the Commonwealth of
Pennsylvania in 1919 and owns property and does business as an electric public
utility in that state. Penelec provides transmission and distribution services
in western, northern and south central Pennsylvania. The area it serves has a
population of approximately 1.7 million. Penelec, as lessee of the property of
its subsidiary, The Waverly Electric Light & Power Company, also serves a
population of about 13,400 in Waverly, New York and vicinity.
FES was organized under the laws of the State of Ohio in 1997 and
provides energy-related products and services, and through its FirstEnergy
Generation Corp. (FGCO) subsidiary, operates FirstEnergy's nonnuclear generation
businesses. FSG is the parent company of several heating, ventilating, air
conditioning and energy management companies; MYR is a utility infrastructure
construction service company. MARBEL is a natural gas pipeline company whose
subsidiaries include MARBEL HoldCo, Inc. a holding company having a 50%
ownership interest in Great Lakes Energy Partners, LLC, an oil and natural gas
exploration and production venture, and Northeast Ohio Natural Gas Corp., a
public utility that provides gas distribution and transportation services. GPU
Capital owns and operates electric distribution systems in foreign countries and
GPU Power owns and operates generation facilities in foreign countries. FECO and
GPUS provide legal, financial and other corporate support services to affiliated
FirstEnergy companies.
Divestitures
International Operations
FirstEnergy identified certain former GPU international operations for
divestiture within one year of its merger with GPU, Inc. on November 7, 2001.
These operations constitute individual "lines of business" as defined in
Accounting Principles Board Opinion (APB) No. 30, "Reporting the Results of
Operations - Reporting the Effects of Disposal of a Segment of a Business, and
Extraordinary, Unusual and Infrequently Occurring Events and Transactions," with
physically and operationally separable activities. Application of Emerging
Issues Task Force (EITF) Issue No. 87-11, "Allocation of Purchase Price to
Assets to Be Sold," required that expected, pre-sale cash flows, including
incremental interest costs on related acquisition debt, of these operations be
considered part of the purchase price allocation. Accordingly, subsequent to the
merger date, results of operations and incremental interest costs related to
these international subsidiaries were not included in FirstEnergy's 2001
Consolidated Statements of Income. Additionally, assets and liabilities of these
international operations were segregated under separate captions on the
Consolidated Balance Sheet as of December 31, 2001 as "Assets Pending Sale" and
"Liabilities Related to Assets Pending Sale."
Upon completion of its merger with GPU, FirstEnergy accepted an
October 2001 offer from Aquila, Inc. (formerly UtiliCorp United) to purchase
Avon Energy Partners Holdings (Avon), FirstEnergy's wholly owned holding company
for Midlands Electricity plc, for $2.1 billion (including the assumption of $1.7
billion of debt). The transaction closed on May 8, 2002 and reflected the March
2002 modification of Aquila's initial offer such that Aquila acquired a 79.9
percent equity interest in Avon for approximately $1.9 billion (including the
assumption of $1.7 billion of debt). Proceeds to FirstEnergy included $155
million in cash and a note receivable for approximately $87 million
(representing the present value of $19 million per year to be received over six
years beginning in 2003) from Aquila for its 79.9 percent interest. FirstEnergy
and Aquila together own all of the outstanding shares of Avon through a jointly
owned subsidiary, with each company having an ownership voting interest.
Originally, in accordance with applicable accounting guidance, the earnings of
those foreign operations were not recognized in current earnings from the date
of the GPU acquisition. However, as a result of the decision to retain an
ownership interest in Avon, EITF Issue No. 90-6, "Accounting for Certain Events
Not Addressed in Issue No. 87-11 relating to an Acquired Operating Unit to be
Sold" required FirstEnergy to reallocate the purchase price of GPU based on
amounts as of the purchase date as if Avon had never been held for sale,
including reversal of the effects of having applied EITF Issue No. 87-11, to the
transaction. The effect of reallocating the purchase price and reversal of the
effects of EITF Issue No. 87-11, including the allocation of capitalized
interest, has been reflected in the Consolidated Statement of Income for the
year ended December 31, 2002 by reclassifying certain revenue and expense
amounts related to activity during the quarter ended March 31, 2002 to their
respective income statement classifications. See Note 2(L) of Notes to
FirstEnergy's Consolidated Financial Statements for the effects of the change in
classification. In the fourth quarter of 2002, FirstEnergy recorded a $50
million charge ($32.5 million net of tax) to reduce the carrying value of its
remaining 20.1 percent interest.
GPU's former Argentina operations were also identified by FirstEnergy
for divestiture within one year of the merger. FirstEnergy determined the fair
value of its Argentina operations, GPU Empresa Distribuidora Electrica Regional
S.A. and affiliates (Emdersa), based on the best available information as of the
date of the merger. Subsequent to that date, a number of economic events have
occurred in Argentina which may have an impact on FirstEnergy's ability to
realize Emdersa's estimated fair value. These events include currency
devaluation, restrictions on repatriation of cash, and the anticipation of
future asset sales in that region by competitors. FirstEnergy did not reach a
2
definitive agreement to sell Emdersa as of December 31, 2002. Therefore, these
assets were no longer classified as "Assets Pending Sale" on the Consolidated
Balance Sheet as of December 31, 2002 and Emdersa's results of operations were
included in FirstEnergy's 2002 Consolidated Statement of Income. Additionally,
under EITF Issue No. 90-6, FirstEnergy recorded in the fourth quarter of 2002 a
one-time, non-cash charge included as a "Cumulative Adjustment for
Retained Businesses Previously Held for Sale" on its 2002 Consolidated Statement
of Income related to Emdersa's cumulative results of operations from November 7,
2001 through September 30, 2002. The amount of this one-time, after-tax charge
was $93.7 million, or $0.32 per share of common stock (comprised of $108.9
million in currency transaction losses arising principally from U.S. dollar
denominated debt, offset by $15.2 million of operating income). See Note 2(L) of
Notes to First Energy's Consolidated Financial Statements for the effects of the
change in classification.
On October 1, 2002, FirstEnergy began consolidating the results of
Emdersa's operations in its financial statements. In addition to the currency
transaction losses of $108.9 million, FirstEnergy recognized a currency
translation adjustment (CTA) in other comprehensive income (OCI) of $91.5
million as of December 31, 2002, which reduced FirstEnergy's common
stockholders' equity. This adjustment represents the impact of translating
Emdersa's financial statements from its functional currency to the U.S. dollar
for financial reporting in conformity with accounting principles generally
accepted in the United States (GAAP).
On April 18, 2003, FirstEnergy divested its ownership in Emdersa
through the abandonment of its shares in Emdersa's parent company, GPU Argentina
Holdings, Inc. The abandonment was accomplished by relinquishing FirstEnergy's
shares to the independent Board of Directors of GPU Argentina Holdings,
relieving FirstEnergy of all rights and obligations relative to this business.
As a result of the abandonment, FirstEnergy will recognize a one-time, non-cash
charge of $63 million, or $0.21 per share of common stock in the second quarter
of 2003. This charge is the result of realizing the CTA losses through the
current period earnings ($90 million, or $0.30 per share), partially offset by
the gain recognized from eliminating its investment in Emdersa ($27 million, or
$0.09 per share). Since FirstEnergy has previously recorded $90 million of CTA
adjustments in OCI, the net effect of the $63 million charge will be an increase
in common stockholders' equity of $27 million.
The $63 million charge does not include the anticipated income tax
benefits related to the abandonment. These tax benefits will be fully reserved
during the second quarter. FirstEnergy anticipates tax benefits of approximately
$129 million, of which $50 million would increase net income in the period that
it becomes probable those benefits will be realized. The remaining $79 million
tax benefits would reduce goodwill recognized in connection with the acquisition
of GPU.
Generating Assets
In November 2001, FirstEnergy reached an agreement to sell four
coal-fired power plants totaling 2,535 megawatts (MW) to NRG Energy Inc. On
August 8, 2002, FirstEnergy notified NRG that it was canceling the agreement
because NRG stated that it could not complete the transaction under the original
terms of the agreement. FirstEnergy also notified NRG that FirstEnergy reserves
the right to pursue legal action against NRG, its affiliate and its parent, Xcel
Energy, for damages, based on the anticipatory breach of the agreement. On
February 25, 2003, the U.S. Bankruptcy Court in Minnesota approved FirstEnergy's
request for arbitration against NRG.
In December 2002, FirstEnergy announced it would retain ownership of
these plants after reviewing other bids it subsequently received from other
parties who had expressed interest in purchasing the plants. Since FirstEnergy
did not execute a sales agreement by year-end, it reflected approximately $74
million ($43 million net of tax), or $0.15 per share of common stock, of
previously unrecognized depreciation and transaction costs in the fourth quarter
of 2002 related to these plants from November 2001 through December 2002 on its
Consolidated Statement of Income.
Utility Regulation
As a registered public utility holding company, FirstEnergy is subject
to regulation by the Securities and Exchange Commission (SEC) under the Public
Utility Holding Company Act of 1935 (1935 Act). The SEC has determined that the
electric facilities of the Companies constitute a single integrated public
utility system under the standards of the 1935 Act. The 1935 Act regulates
FirstEnergy with respect to accounting, the issuance of securities, the
acquisition and sale of utility assets, securities or any other interest in any
business, and entering into, and performance of, service, sales and construction
contracts among its subsidiaries, and certain other matters. The 1935 Act also
limits the extent to which FirstEnergy may engage in nonutility businesses or
acquire additional utility businesses. Each of the Companies' retail rates,
conditions of service, issuance of securities and other matters are subject to
regulation in the state in which each operates - in Ohio by the Public Utilities
Commission of Ohio (PUCO), in New Jersey by the New Jersey Board of Public
Utilities (NJBPU) and in Pennsylvania by the Pennsylvania Public Utility
Commission (PPUC). With respect to their wholesale and interstate electric
operations and rates, the Companies are subject to regulation, including
regulation of their accounting policies and practices, by the Federal Energy
Regulatory Commission (FERC). Under Ohio law, municipalities may regulate rates,
subject to appeal to the PUCO if not acceptable to the utility.
3
In Ohio, New Jersey and Pennsylvania, laws applicable to electric
industry deregulation included the similar provisions which are reflected in the
Companies' respective state regulatory plans:
o allowing the Companies' electric customers to select their
generation suppliers;
o establishing provider of last resort (PLR) obligations to
customers in the Companies' service areas;
o allowing recovery of potentially stranded investment (sometimes
referred to as transition costs);
o itemizing (unbundling) the current price of electricity into its
component elements - including generation, transmission,
distribution and stranded costs recovery charges;
o deregulating the Companies' electric generation businesses; and
o continuing regulation of the Companies' transmission and
distribution systems.
PUCO Rate Matters
In July 1999, Ohio's electric utility restructuring legislation, which
allowed Ohio electric customers to select their generation suppliers beginning
January 1, 2001, was signed into law. Among other things, the legislation
provided 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 (market development
period). 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.
In July 2000, the PUCO approved FirstEnergy's transition plan for the
OE, CEI and TE (Ohio Companies) as modified by a settlement agreement with major
parties to the transition plan. The application of SFAS 71, "Accounting for the
Effects of Certain Types of Regulation" to OE's generation business and the
nonnuclear generation businesses of CEI and TE was discontinued with the
issuance of the PUCO transition plan order, as described further below. Major
provisions of the settlement agreement consisted of approval of recovery of
generation-related transition costs as filed of $4.0 billion net of deferred
income taxes (OE-$1.6 billion, CEI-$1.6 billion and TE-$0.8 billion) and
transition costs related to regulatory assets as filed of $2.9 billion net of
deferred income taxes (OE-$1.0 billion, CEI-$1.4 billion and TE-$0.5 billion),
with recovery through no later than 2006 for OE, mid-2007 for TE and 2008 for
CEI, except where a longer period of recovery is provided for in the settlement
agreement. The generation-related transition costs include $1.4 billion, net of
deferred income taxes, (OE-$1.0 billion, CEI-$0.2 billion and TE-$0.2 billion)
of impaired generating assets recognized as regulatory assets as described
further below, $2.4 billion, net of deferred income taxes, (OE-$1.2 billion,
CEI-$0.4 billion and TE-$0.8 billion) of above market operating lease costs and
$0.8 billion, net of deferred income taxes, (CEI-$0.5 billion and TE-$0.3
billion) of additional plant costs that were reflected on CEI's and TE's
regulatory financial statements.
Also as part of the settlement agreement, FirstEnergy is giving
preferred access over its subsidiaries to nonaffiliated marketers, brokers and
aggregators to 1,120 megawatts (MW) of generation capacity through 2005 at
established prices for sales to the Ohio Companies' retail customers. Customer
prices are frozen through the five-year market development period except for
certain limited statutory exceptions, including the 5% reduction referred to
above. In February 2003, the Ohio Companies were authorized increases in annual
revenues aggregating approximately $50 million (OE-$41 million, CEI-$4 million
and TE-$5 million) to recover their higher tax costs resulting from the Ohio
deregulation legislation.
FirstEnergy's Ohio customers choosing alternative suppliers receive an
additional incentive applied to the shopping credit (generation component) of
45% for residential customers, 30% for commercial customers and 15% for
industrial customers. The amount of the incentive is deferred for future
recovery from customers - recovery will be accomplished by extending the
respective transition cost recovery period. If the customer shopping goals
established in the agreement had not been achieved by the end of 2005, the
transition cost recovery periods could have been shortened for OE, CEI and TE to
reduce recovery by as much as $500 million (OE - $250 million, CEI - $170
million and TE - $80 million). The Ohio Companies achieved all of their required
20% customer shopping goals in 2002. Accordingly, FirstEnergy believes that
there will be no regulatory action reducing the recoverable transition costs.
NJBPU Rate Matters
JCP&L's 2001 Final Decision and Order (Final Order) with respect to
its rate unbundling, stranded cost and restructuring filings confirmed rate
reductions set forth in its 1999 Summary Order, which remain in effect at
increasing levels through July 2003. The Final Order also confirmed the
establishment of a non-bypassable societal benefits charge (SBC) to recover
costs which include nuclear plant decommissioning and manufactured gas plant
remediation, as well as a non-bypassable market transition charge (MTC)
primarily to recover stranded costs. The NJBPU has deferred making a final
determination of the net proceeds and stranded costs related to prior generating
4
asset divestitures until JCP&L's request for an Internal Revenue Service (IRS)
ruling regarding the treatment of associated federal income tax benefits is
acted upon. Should the IRS ruling support the return of the tax benefits to
customers, there would be no effect to FirstEnergy's or JCP&L's net income since
the contingency existed prior to the merger.
In addition, the Final Order provided for the ability to securitize
stranded costs associated with the divested Oyster Creek Nuclear Generating
Station. In February 2002, JCP&L received NJBPU authorization to issue $320
million of transition bonds to securitize the recovery of these costs. The NJBPU
order also provided for a usage-based non-bypassable transition bond charge and
for the transfer of the bondable transition property to another entity. JCP&L
sold $320 million of transition bonds through its wholly owned subsidiary, JCP&L
Transition Funding LLC, in June 2002 - those bonds are recognized on the
Consolidated Balance Sheet.
JCP&L's PLR obligation to provide basic generation service (BGS) to
non-shopping customers is supplied almost entirely from contracted and open
market purchases. JCP&L is permitted to defer for future collection from
customers the amounts by which its costs of supplying BGS to non-shopping
customers and costs incurred under nonutility generation (NUG) agreements exceed
amounts collected through BGS and MTC rates. As of December 31, 2002, the
accumulated deferred cost balance totaled approximately $549 million. The NJBPU
also allowed securitization of JCP&L's deferred balance to the extent permitted
by law upon application by JCP&L and a determination by the NJBPU that the
conditions of the New Jersey restructuring legislation are met. There can be no
assurance as to the extent, if any, that the NJBPU will permit such
securitization.
Under New Jersey transition legislation, all electric distribution
companies were required to file rate cases to determine the level of unbundled
rate components to become effective August 1, 2003. On August 1, 2002, JCP&L
submitted two rate filings with the NJBPU. The first filing requested increases
in base electric rates of approximately $98 million annually. The second filing
was a request to recover deferred costs that exceeded amounts being recovered
under the current MTC and SBC rates; one proposed method of recovery of these
costs is the securitization of the deferred balance. This securitization
methodology is similar to the Oyster Creek securitization discussed above.
Hearings began in February 2003. On March 18, 2003, a report prepared by
independent auditors addressing costs deferred by JCP&L from August 1, 1999
through July 31, 2002, was transmitted to the Office of Administrative Law,
where JCP&L's rate case is being heard. While the auditors concluded that
JCP&L's energy procurement strategy and process was reasonable and prudent, they
identified potential disallowances totaling $17.3 million. The report subjected
$436 million of deferred costs to a retrospective prudence review during a
period of extreme price uncertainty and volatility in the energy markets.
Although JCP&L disagrees with the potential disallowances, it is pleased with
the report's major conclusions and overall tone. Hearings concluded on April 28,
2003, and initial briefs were filed on May 7, 2003. The Administrative Law
Judge's recommended decision is due by the end of June 2003 and the NJBPU's
subsequent decision is due in July 2003.
In 1997, the NJBPU authorized JCP&L to recover from customers, subject
to possible refund, $135 million of costs incurred in connection with a 1996
buyout of a power purchase agreement. JCP&L has recovered the full $135 million;
the NJBPU has established a procedural schedule to take further evidence with
respect to the buyout to enable it to make a final prudence determination
contemporaneously with the resolution of the pending rate case.
In December 2001, the NJBPU authorized the auctioning of BGS for the
period from August 1, 2002 through July 31, 2003 to meet the electricity demands
of all customers who have not selected an alternative supplier. The auction
results were approved by the NJBPU in February 2002, removing JCP&L's BGS
obligation of 5,100 MW for the period August 1, 2002 through July 31, 2003. In
February 2003, the NJBPU approved the BGS auction results for the period
beginning August 1, 2003. The auction covered a fixed price bid (applicable to
all residential and smaller commercial and industrial customers) and an hourly
price bid (applicable to all large industrial customers) process. JCP&L will
sell all self-supplied energy (NUGs and owned generation) to the wholesale
market with offsets to its deferred energy balances.
PPUC Rate Matters
The PPUC authorized 1998 rate restructuring plans for Penn, Met-Ed and
Penelec. In 2000, the PPUC disallowed a portion of the requested additional
stranded costs above those amounts granted in Met-Ed's and Penelec's 1998 rate
restructuring plan orders. The PPUC required Met-Ed and Penelec to seek an IRS
ruling regarding the return of certain unamortized investment tax credits and
excess deferred income tax benefits to customers. Similar to JCP&L's situation,
if the IRS ruling ultimately supports returning these tax benefits to customers,
there would be no effect to FirstEnergy's, Met-Ed's or Penelec's net income
since the contingency existed prior to the merger.
As a result of their generating asset divestitures, Met-Ed and Penelec
obtained their supply of electricity to meet their PLR obligations almost
entirely from contracted and open market purchases. In 2000, Met-Ed and Penelec
filed a petition with the PPUC seeking permission to defer, for future recovery,
energy costs in excess of amounts reflected in their capped generation rates;
the PPUC subsequently consolidated this petition in January 2001 with the
FirstEnergy/GPU merger proceeding.
5
In June 2001, the PPUC entered orders approving the Settlement
Stipulation with all of the major parties in the combined merger and rate relief
proceedings which approved the merger and provided Met-Ed and Penelec PLR
deferred accounting treatment for energy costs. The PPUC permitted Met-Ed and
Penelec to defer for future recovery the difference between their actual energy
costs and those reflected in their capped generation rates, retroactive to
January 1, 2001. Correspondingly, in the event that energy costs incurred by
Met-Ed and Penelec would be below their respective capped generation rates, that
difference would have reduced costs that had been deferred for recovery in
future periods. This PLR deferral accounting procedure was denied in a court
decision discussed below. Met-Ed's and Penelec's PLR obligations extend through
December 31, 2010; during that period competitive transition charge (CTC)
revenues would have been applied to their stranded costs. Met-Ed and Penelec
would have been permitted to recover any remaining stranded costs through a
continuation of the CTC after December 31, 2010 through no later than December
31, 2015. Any amounts not expected to be recovered by December 31, 2015 would
have been written off at the time such nonrecovery became probable.
Several parties had filed Petitions for Review in June and July 2001
with the Commonwealth Court of Pennsylvania regarding the June 2001 PPUC orders.
On February 21, 2002, the Court affirmed the PPUC decision regarding the
FirstEnergy/GPU merger, remanding the decision to the PPUC only with respect to
the issue of merger savings. The Court reversed the PPUC's decision regarding
the PLR obligations of Met-Ed and Penelec, and rejected those parts of the
settlement that permitted the companies to defer for accounting purposes the
difference between their wholesale power costs and the amount that they collect
from retail customers. FirstEnergy and the PPUC each filed a Petition for
Allowance of Appeal with the Pennsylvania Supreme Court on March 25, 2002,
asking it to review the Commonwealth Court decision. Also on March 25, 2002,
Citizens Power filed a motion seeking an appeal of the Commonwealth Court's
decision to affirm the FirstEnergy and GPU merger with the Pennsylvania Supreme
Court. In September 2002, FirstEnergy established reserves for Met-Ed's and
Penelec's PLR deferred energy costs which aggregated $287.1 million. The
reserves reflected the potential adverse impact of a pending Pennsylvania
Supreme Court decision whether to review the Commonwealth Court ruling.
FirstEnergy recorded an aggregate non-cash charge to income of $55.8 million
($32.6 million net of tax), or $0.11 per share of common stock, for the deferred
costs incurred subsequent to the merger. The reserve for the remaining $231.3
million of deferred costs increased goodwill by an aggregate net of tax amount
of $135.3 million.
On January 17, 2003, the Pennsylvania Supreme Court denied further
appeals of the February 21, 2002 Pennsylvania Commonwealth Court decision, which
effectively affirmed the PPUC's order approving the merger between FirstEnergy
and GPU, let stand the Commonwealth Court's denial of PLR rate relief for Met-Ed
and Penelec and remanded the merger savings issue back to the PPUC. Because
FirstEnergy had already reserved for the deferred energy costs and FES has
largely hedged the anticipated PLR energy supply requirements for Met-Ed and
Penelec through 2005 as discussed further below, FirstEnergy, Met-Ed and Penelec
believe that the disallowance of continued CTC recovery of PLR costs will not
have a future adverse financial impact.
Effective September 1, 2002, Met-Ed and Penelec assigned their PLR
responsibility to their FES affiliate through a wholesale power sale agreement.
The PLR sale, which initially ran through the end of 2002, was extended through
December 2003 and will be automatically extended for each successive calendar
year unless any party elects to cancel the agreement by November 1 of the
preceding year. Under the terms of the wholesale agreement, FES assumes the
supply obligation and the energy supply profit and loss risk, for the portion of
power supply requirements not self-supplied by Met-Ed and Penelec under their
NUG contracts and other existing power contracts with nonaffiliated third party
suppliers. This arrangement reduces Met-Ed's and Penelec's exposure to high
wholesale power prices by providing power at or below the shopping credit for
their uncommitted PLR energy costs during the term of the agreement with FES.
FES has hedged most of Met-Ed's and Penelec's unfilled PLR obligation through
2005, the period during which deferred accounting was previously allowed under
the PPUC's order. Met-Ed and Penelec are authorized to continue deferring
differences between NUG contract costs and amounts recovered through their
capped generation rates.
FERC Rate Matters
The Companies provide wholesale power and transmission service subject
to the jurisdiction of the FERC.
Following the FirstEnergy/GPU merger the transmission facilities of
JCP&L, Met-Ed and Penelec continue to be operated by PJM. PJM was approved by
the FERC as a regional transmission organization (RTO) on December 20, 2002.
Transmission service over the facilities of FirstEnergy's PJM operating
companies is provided under the PJM Open Access Tariff.
On December 20, 2001, the FERC issued an order that reversed prior
findings that the Alliance RTO had adequate scope and concluded that there
should be only one RTO (the Midwest ISO) in the Midwest. The FERC directed the
former Alliance companies, including ATSI, to file their new RTO choices with
the FERC. On July 31, 2002, the FERC approved the RTO choices of the former
Alliance companies, but directed the formation of a single market for the MISO
and PJM by October 1, 2004. This single market would include all of the
generation and transmission facilities of the FirstEnergy operating companies.
FERC also initiated an investigation pursuant to Section 206 of the Federal
6
Power Act concerning the existing "through and out" transmission rates between
the MISO and PJM. Hearings on this proceeding concluded in January 2003, and an
Initial Decision is expected from the Administrative Law Judge by March 28,
2003.
ATSI proposes to transfer its transmission facilities in the East
Central Area Reliability Agreement (ECAR) area to the MISO RTO as part of
GridAmerica, LLC, an independent transmission company. On December 19, 2002, the
FERC conditionally accepted GridAmerica's filing to become an independent
transmission company within the MISO. GridAmerica will operate ATSI's
transmission facilities and expects to begin operations in the second quarter of
2003 subject to approval of certain compliance filings with the FERC. The
compliance filings were made by the GridAmerica companies (ATSI, Ameren Services
Company and Northern Indiana Public Service Company) on January 31, 2003 and
February 19, 2003.
On July 31, 2002, the FERC initiated a rulemaking designed to
standardize the terms and conditions under which wholesale electric service is
provided in regions with independent transmission operators, including the MISO
and PJM. FirstEnergy filed comments and reply comments on the proposed rule.
Implementation of the proposed rule was expected to begin on July 31, 2003.
However, the FERC has indicated that it will delay implementation of Standard
Market Design in order to accommodate substantial changes in the proposed rule.
A FERC "white paper" is expected to be issued in April 2003 outlining changes in
the proposed rule.
Regulatory Accounting
All of the Companies' regulatory assets (deferred costs) are expected
to continue to be recovered under provisions of the Ohio transition plan and the
respective Pennsylvania and New Jersey regulatory plans. The application of
Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the
Effects of Certain Types of Regulation" (SFAS 71), has been discontinued with
respect to the Companies' generation operations.
Capital Requirements
Capital expenditures for the Companies, FES and FirstEnergy's other
subsidiaries for the years 2002 through 2007, excluding nuclear fuel, are shown
in the following table. Such costs include expenditures for the betterment of
existing facilities and for the construction of generating capacity, facilities
for environmental compliance, transmission lines, distribution lines,
substations and other assets. See "Environmental Matters" below with regard to
possible environmental-related expenditures not included in the forecast.
Capital Expenditures Forecast
2002 --------------------------------------
Actual 2003 2004-2007 Total
------ ---- --------- -----
(In millions)
OE.................. $ 81 $ 86 $ 182 $ 268
Penn................ 40 53 70 123
CEI................. 137 96 216 312
TE.................. 91 54 115 169
JCP&L............... 100 102 360 462
Met-Ed.............. 43 53 235 288
Penelec............. 49 54 274 328
ATSI................ 27 25 106 131
FES................. 185 124 699 823
Other subsidiaries.. 151 80 67 147
---- ---- ------ ------
Total............... $904 $727 $2,324 $3,051
During the 2003-2007 period, maturities of, and sinking fund
requirements for, long-term debt and preferred stock of FirstEnergy and its
subsidiaries are:
Preferred Stock and Long-Term Debt
Redemption Schedule
------------------------------------------
2003 2004-2007 Total
---- --------- -----
(In millions)
OE.............................. $ 210 $ 207 $ 417
Penn............................ 42 52 94
CEI............................. 146 704 850
TE.............................. 116 245 361
JCP&L........................... 174 510 684
Met-Ed.......................... 60 292 352
Penelec......................... -- 137 137
FirstEnergy..................... -- 1,695 1,695
Other subsidiaries.............. 327 40 367
------ ------ ------
Total........................... $1,075 $3,882 $4,957
7
The Companies' and FES's respective investments for additional nuclear
fuel, and nuclear fuel investment reductions as the fuel is consumed, during the
2003-2007 period are presented in the following table. The table also displays
the Companies' operating lease commitments, net of capital trust cash receipts
for the 2003-2007 period.
Nuclear Fuel Forecasts
----------------------------------------------------- Net
New Investments Consumption Operating Lease Commitments
----------------------- ------------------------- ----------------------------
2003 2004-2007 Total 2003 2004-2007 Total 2003 2004-2007 Total
---- --------- ----- ---- --------- ----- ---- --------- -----
(In millions)
OE.................. $23 $ 32 $ 55 $24 $ 27 $ 51 $ 74 $321 $395
Penn................ 19 23 42 17 17 34 -- 1 1
CEI................. 15 38 53 28 31 59 (2) 70 68
TE.................. 12 22 34 19 21 40 75 311 386
JCP&L............... -- -- -- -- -- -- 3 6 9
Met-Ed.............. -- -- -- -- -- -- 3 5 8
FES................. -- 301 301 -- 299 299 -- -- --
--- ---- ---- --- ---- ---- ---- ---- ----
Total............... $69 $416 $485 $88 $395 $483 $153 $714 $867
Short-term borrowings outstanding as of December 31, 2002, consisted
of $1.093 billion of bank borrowings (FirstEnergy-$910.0 million, OE-$22.6
million and FSG-$0.5 million) and $159.7 million of OES Capital, Incorporated
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. FirstEnergy had $177 million available under $1.5
billion of revolving lines of credit as of December 31, 2002. FirstEnergy may
borrow under its facility and could transfer any of its borrowings to affiliated
companies. OE and MYR had $19 million and $46 million, respectively, of unused
bank facilities as of December 31, 2002. An additional source of ongoing cash
for FirstEnergy, as a holding company, is cash dividends from its subsidiaries.
In 2002, the holding company received $447 million of cash dividends on common
stock from its subsidiaries.
Based on their present plans, the Companies could provide for their
cash requirements in 2003 from the following sources: funds to be received from
operations; available cash and temporary cash investments as of December 31,
2002 (Company's nonutility subsidiaries-$93 million, OE-$20 million, Penn-$1
million, CEI-$30 million, TE-$21 million, JCP&L-$5 million, Met-Ed-$16 million
and Penelec-$10 million); the issuance of long-term debt (for refunding
purposes); and funds available under revolving credit arrangements.
The extent and type of future financings will depend on the need for
external funds as well as market conditions, the maintenance of an appropriate
capital structure and the ability of the Companies to comply with coverage
requirements in order to issue first mortgage bonds and preferred stock. The
Companies will continue to monitor financial market conditions and, where
appropriate, may take advantage of economic opportunities to refund debt and
preferred stock to the extent that their financial resources permit.
The coverage requirements contained in the first mortgage indentures
under which the Companies issue first mortgage bonds provide that, except for
certain refunding purposes, the Companies may not issue first mortgage bonds
unless applicable net earnings (before income taxes), calculated as provided in
the indentures, for any period of twelve consecutive months within the fifteen
calendar months preceding the month in which such additional bonds are issued,
are at least twice annual interest requirements on outstanding first mortgage
bonds, including those being issued. Under OE's first mortgage indenture, the
availability of property additions is more restrictive than the earnings test at
the present time and would limit the amount of first mortgage bonds issuable
against property additions to $172 million. OE is currently able to issue $1.195
billion principal amount of first mortgage bonds against previously retired
bonds without the need to meet the above restrictions. Under Penn's first
mortgage indenture, other requirements also apply and are more restrictive than
the earnings test at the present time. Penn is currently able to issue $323
million principal amount of first mortgage bonds, with up to $150 million of
such amount issuable against property additions; the remainder could be issued
against previously retired bonds. CEI and TE can issue $379 million and $144
million principal amount of first mortgage bonds against a combination of
previously retired bonds and property additions, respectively. TE cannot
currently issue first mortgage bonds. JCP&L, Met-Ed and Penelec are able to
issue $393 million, $74 million and $7 million principal amount, respectively,
of first mortgage bonds against previously retired bonds.
OE's, Penn's, TE's and JCP&L's respective articles of incorporation
prohibit the sale of preferred stock unless applicable gross income, calculated
as provided in the articles of incorporation, is equal to at least 1-1/2 times
the aggregate of the annual interest requirements on indebtedness and annual
dividend requirements on preferred stock outstanding immediately thereafter.
Based upon earnings for 2002, an assumed dividend rate of 9%, and no additional
indebtedness, OE, Penn and JCP&L would be permitted, under the earnings coverage
test contained in their respective charters, to issue at least $2.8 billion,
$251 million and $1.2 billion of preferred stock, respectively; TE cannot
currently issue preferred stock. There are no restrictions on the ability of
CEI, Met-Ed and Penelec to issue preferred stock.
8
To the extent that coverage requirements or market conditions restrict
the Companies' abilities to issue desired amounts of first mortgage bonds or
preferred stock, the Companies may seek other methods of financing. Such
financings could include the sale of preferred and/or preference stock or of
such other types of securities as might be authorized by applicable regulatory
authorities which would not otherwise be sold and could result in annual
interest charges and/or dividend requirements in excess of those that would
otherwise be incurred.
Met-Ed Capital Trust and Penelec Capital Trust
In 1999, Met-Ed Capital Trust, a wholly owned subsidiary of Met-Ed,
issued $100 million of trust preferred securities (Met-Ed Trust Preferred
Securities) at 7.35%, due 2039. The sole assets of Met-Ed Capital Trust are the
7.35% Cumulative Preferred Securities of Met-Ed Capital II, L.P. (Met-Ed
Partnership Preferred Securities) and its only revenues are the quarterly cash
distributions it receives on the Met-Ed Partnership Preferred Securities. Each
Met-Ed Trust Preferred Security represents a Met-Ed Partnership Preferred
Security. Met-Ed Capital II, L.P. is a wholly-owned subsidiary of Met-Ed and the
sponsor of Met-Ed Capital Trust. The sole assets of Met-Ed Capital II, L.P. are
Met-Ed's 7.35% Subordinated Debentures, Series A, due 2039, which have an
aggregate principal amount of $103.1 million. Distributions were made on the
Trust Preferred Securities during 2002 in the aggregate amount of $7,350,000.
Expenses of Met-Ed Trust for 2002 were approximately $13,000, all of which were
paid by Met-Ed Preferred Capital II, Inc., the general partner of Met-Ed Capital
II, L.P. The Trust Preferred Securities are issued in book-entry form only so
that there is only one holder of record. Met-Ed has fully and unconditionally
guaranteed the Met-Ed Partnership Preferred Securities, and, therefore, the
Met-Ed Trust Preferred Securities.
In 1999, Penelec Capital Trust, a wholly owned subsidiary of Penelec,
issued $100 million of trust preferred securities (Penelec Trust Preferred
Securities) at 7.34%, due 2039. The sole assets of Penelec Capital Trust are the
7.34% Cumulative Preferred Securities of Penelec Capital II, L.P. (Penelec
Partnership Preferred Securities) and its only revenues are the quarterly cash
distributions it receives on the Penelec Partnership Preferred Securities. Each
Penelec Trust Preferred Security represents a Penelec Partnership Preferred
Security. Penelec Capital II, L.P. is a wholly-owned subsidiary of Penelec and
the sponsor of Penelec Capital Trust. The sole assets of Penelec Capital II,
L.P. are Penelec's 7.34% Subordinated Debentures, Series A, due 2039, which have
an aggregate principal amount of $103.1 million. Distributions were made on the
Trust Preferred Securities during 2002 in the aggregate amount of $7,340,000.
Expenses of Penelec Trust for 2002 were approximately $13,000, all of which were
paid by Penelec Preferred Capital II, Inc., the general partner of Penelec
Capital II, L.P. The Trust Preferred Securities are issued in book-entry form
only so that there is only one holder of record. Penelec has fully and
unconditionally guaranteed the Penelec Partnership Preferred Securities, and,
therefore, the Penelec Trust Preferred Securities.
Nuclear Regulation
The construction, operation and decommissioning of nuclear generating
units are subject to the regulatory jurisdiction of the Nuclear Regulatory
Commission (NRC) including the issuance by it of construction permits, operating
licenses, and possession only licenses for decommissioning reactors. The NRC's
procedures with respect to the amendment of nuclear reactor operating licenses
afford opportunities for interested parties to request adjudicatory hearings on
health, safety and environmental issues subject to meeting NRC "standing"
requirements. The NRC may require substantial changes in operation or the
installation of additional equipment to meet safety or environmental standards,
subject to the backfit rule requiring the NRC to justify such new requirements
as necessary for the overall protection of public health and safety. The
possibility also exists for modification, denial or revocation of licenses. As a
result of the merger with GPU, FirstEnergy now owns the Three Mile Island Unit 2
(TMI-2) and the Saxton Nuclear Experimental Facility. Both facilities are in
various stages of decommissioning. TMI-2 is in a post-defueling monitored
storage condition, with decommissioning planned in 2014. Saxton is in the final
stages of decommissioning, with license termination scheduled for the end of
2003 and final site restoration scheduled for the first quarter of 2003. Beaver
Valley Unit 1 was placed in commercial operation in 1976, and its operating
license expires in 2016. Davis-Besse was placed in commercial operation in 1977,
and its operating license expires in 2017. Perry Unit 1 and Beaver Valley Unit 2
were placed in commercial operation in 1987, and their operating licenses expire
in 2026 and 2027, respectively.
Davis-Besse, which is operated by FENOC, began its scheduled refueling
outage on February 16, 2002. The plant was originally scheduled to return to
service by the end of March 2002. During the refueling outage, visual and
ultrasonic testings were conducted on all 69 of the Control Rod Drive Mechanism
penetration nozzles. This testing was performed to check for the kind of
circular or circumferential cracking in these nozzles that had been found at
some other plants similar in design and vintage to Davis-Besse. Based on the
inspection and test results, five nozzles were scheduled for repair during the
refueling outage.
As repair work began on one of the nozzles, FENOC found corrosion in
the reactor vessel head near some of the penetration holes, created by boric
acid deposits from leaks in the nozzles. As a result, the NRC issued a
confirmatory action letter stating that restart of the plant would be subject to
prior NRC approval, and it established an Inspection Manual Chapter 0350
Oversight Panel to ensure close NRC oversight of Davis-Besse's corrective
actions.
9
In response to the reactor vessel head degradation, FENOC initiated a
number of root cause analyses and other assessments, and established a Return to
Service Plan to correct the causes and ensure a safe and reliable return to
service. The Return to Service Plan includes actions to: replace the reactor
vessel head, inspect and correct other components in the containment that may
have been affected by boric acid, review important systems and programs to
ensure their readiness for restart, and improve management and human
performance. FENOC has completed many of the actions under the Return to Service
Plan and is currently implementing corrective actions and performing tests to
ensure the readiness of the plant to restart.
FENOC anticipates that Davis-Besse will be ready for restart in the
first half of the summer of 2003. However, the NRC must authorize restart of the
plant following its formal inspection process before the unit can be returned to
service. In 2002, FENOC spent approximately $115 million in additional
nuclear-related operation and maintenance costs, approximately $120 million in
replacement power costs and approximately $63 million in capital expenditures
related to the reactor head and restart. For 2003, FENOC expects to spend
approximately $50 million in additional nuclear-related operation and
maintenance costs and approximately $12-18 million in replacement power costs
per month. These costs could increase if the length of the outage increases.
The NRC has promulgated and continues to promulgate orders and
regulations related to the safe operation of nuclear power plants and standards
for decommissioning clean-up and final license termination. The Companies cannot
predict what additional orders and regulations (including post-September 11,
2001 security enhancements) may be promulgated, design changes required or the
effect that any such regulations or design changes or additional clean-up
standards for final site release, or the consideration thereof, may have upon
their nuclear plants. Although the Companies have no reason to anticipate an
accident at any of their nuclear plants, if such an accident did happen, it
could have a material but currently undeterminable adverse effect on
FirstEnergy's consolidated financial position. In addition, such an accident at
any operating nuclear plant, whether or not owned by the Companies, could result
in regulations or requirements that could affect the operation, licensing, or
decommissioning of plants that the Companies do own with a consequent but
currently undeterminable adverse impact, and could affect the Companies'
abilities to raise funds in the capital markets.
Nuclear Insurance
The Price-Anderson Act limits the public liability which can be
assessed with respect to a nuclear power plant to $9.5 billion (assuming 105
units licensed to operate) for a single nuclear incident, which amount is
covered by: (i) private insurance amounting to $300 million; and (ii) $9.2
billion provided by an industry retrospective rating plan required by the NRC
pursuant thereto. Under such retrospective rating plan, in the event of a
nuclear incident at any unit in the United States resulting in losses in excess
of private insurance, up to $88.1 million (but not more than $10 million per
unit per year in the event of more than one incident) must be contributed for
each nuclear unit licensed to operate in the country by the licensees thereof to
cover liabilities arising out of the incident. Based on their present nuclear
ownership and leasehold interests, the Companies' maximum potential assessment
under these provisions would be $352.4 million (OE-$94.2 million, Penn-$74.0
million, CEI-$106.3 million and TE-$77.9 million) per incident but not more than
$40.0 million (OE-$10.7 million, Penn-$8.4 million, CEI-$12.1 million and
TE-$8.8 million) in any one year for each incident.
In addition to the public liability insurance provided pursuant to the
Price-Anderson Act, the Companies have also obtained insurance coverage in
limited amounts for economic loss and property damage arising out of nuclear
incidents. The Companies are members of Nuclear Electric Insurance Limited
(NEIL) which provides coverage (NEIL I) for the extra expense of replacement
power incurred due to prolonged accidental outages of nuclear units. Under NEIL
I, the Companies have policies, renewable yearly, corresponding to their
respective nuclear interests, which provide an aggregate indemnity of up to
approximately $1.182 billion (OE-$315 million, Penn-$222 million, CEI-$382
million and TE-$263 million) for replacement power costs incurred during an
outage after an initial 12-week waiting period. Members of NEIL I pay annual
premiums and are subject to assessments if losses exceed the accumulated funds
available to the insurer. The Companies' present maximum aggregate assessment
for incidents at any covered nuclear facility occurring during a policy year
would be approximately $11.1 million (OE-$3.1 million, Penn-$2.2 million,
CEI-$3.4 million and TE-$2.4 million).
The Companies are insured as to their respective nuclear interests
under property damage insurance provided by NEIL to the operating company for
each plant. Under these arrangements, $2.75 billion of coverage for
decontamination costs, decommissioning costs, debris removal and repair and/or
replacement of property is provided. The Companies pay annual premiums for this
coverage and are liable for retrospective assessments of up to approximately
$57.3 million (OE-$15.5 million, Penn-$10.9 million, CEI-$17.9 million, TE-$12.2
million, JCP&L-$0.2 million, Met-Ed-$0.4 million and Penelec-$0.2 million)
during a policy year.
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
10
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.
The NRC requires nuclear power plant licensees to obtain minimum
property insurance coverage of $1.06 billion or the amount generally available
from private sources, whichever is less. The proceeds of this insurance are
required to be used first to ensure that the licensed reactor is in a safe and
stable condition and can be maintained in that condition so as to prevent any
significant risk to the public health and safety. Within 30 days of
stabilization, the licensee is required to prepare and submit to the NRC a
cleanup plan for approval. The plan is required to identify all cleanup
operations necessary to decontaminate the reactor sufficiently to permit the
resumption of operations or to commence decommissioning. Any property insurance
proceeds not already expended to place the reactor in a safe and stable
condition must be used first to complete those decontamination operations that
are ordered by the NRC. The Companies are unable to predict what effect these
requirements may have on the availability of insurance proceeds to the Companies
for the Companies' bondholders.
Environmental Matters
Various federal, state and local authorities regulate the Companies
with regard to air and water quality and other environmental matters.
FirstEnergy estimates additional capital expenditures for environmental
compliance of approximately $159 million, which is included in the construction
forecast provided under "Capital Requirements" for 2003 through 2007.
Air Regulation
Under the provisions of the Clean Air Act of 1970, the States of Ohio
and New Jersey and the Commonwealth of Pennsylvania have adopted ambient air
quality standards, and related emission limits, including limits for sulfur
dioxide (SO2) and particulates. In addition, the U.S. Environmental Protection
Agency (EPA) promulgated an SO2 regulatory plan for Ohio which became effective
for OE's, CEI's and TE's plants in 1977. Generating plants to be constructed in
the future and some future modifications of existing facilities will be covered
not only by the applicable state standards but also by EPA emission performance
standards for new sources. In Ohio, New Jersey and Pennsylvania the construction
or certain modifications of emission sources requires approval from appropriate
environmental authorities, and the facilities involved may not be operated
unless a permit or variance to do so has been issued by those same authorities.
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 $31,500 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.
The Companies believe they are in compliance with the current SO2 and
nitrogen oxide (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 using emission
allowances. NOx reductions are being achieved through combustion controls and
the generation of more electricity at lower-emitting plants. In September 1998,
the EPA finalized regulations requiring additional NOx reductions from the
Companies' Ohio, New Jersey and Pennsylvania facilities. The EPA's NOx Transport
Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction
in utility plant NOx emissions from projected 2007 emissions) across a region of
nineteen states and the District of Columbia, including New Jersey, Ohio and
Pennsylvania, based on a conclusion that such NOx emissions are contributing
significantly to ozone pollution in the eastern United States. State
Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx
budgets established by the EPA. Pennsylvania submitted a SIP that requires
compliance with the NOx budgets at the Companies' Pennsylvania facilities by May
1, 2003 and Ohio submitted a SIP that requires compliance with the NOx budgets
at the Companies' Ohio facilities by May 31, 2004. The Companies continue to
evaluate their compliance plans and other compliance options.
In July 1997, the EPA promulgated changes in the National Ambient Air
Quality Standard (NAAQS) for ozone emissions and proposed a new NAAQS for
previously unregulated ultra-fine particulate matter. In May 1999, the U.S.
Court of Appeals found constitutional and other defects in the new NAAQS rules.
In February 2001, the U.S. Supreme Court upheld the new NAAQS rules regulating
ultra-fine particulates but found defects in the new NAAQS rules for ozone and
decided that the EPA must revise those rules. The future cost of compliance with
these regulations may be substantial and will depend if and how they are
ultimately implemented by the states in which the Companies operate affected
facilities.
In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a
Compliance Order to nine utilities covering 44 power plants, including the W. H.
Sammis Plant. In addition, the U.S. Department of Justice filed eight 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, for which hearings began on February 3, 2003. 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
11
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 these proceedings, FirstEnergy 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. The Sammis Plant continues to operate while these proceedings are
pending.
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants. The EPA identified mercury as the hazardous air pollutant of
greatest concern. The EPA established a schedule to propose regulations by
December 2003 and issue final regulations by December 2004. The future cost of
compliance with these regulations may be substantial.
Water Regulation
Various water quality regulations, the majority of which are the
result of the federal Clean Water Act and its amendments, apply to the
Companies' plants. In addition, Ohio, New Jersey and Pennsylvania have water
quality standards applicable to the Companies' operations. As provided in the
Clean Water Act, authority to grant federal National Pollutant Discharge
Elimination System water discharge permits can be assumed by a state. Ohio, New
Jersey and Pennsylvania have assumed such authority.
Waste Disposal
As a result of the Resource Conservation and Recovery Act of 1976, as
amended, and the Toxic Substances Control Act of 1976, federal and state
hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous waste
disposal requirements pending the EPA's evaluation of the need for future
regulation. The EPA has issued its final regulatory determination that
regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the
EPA announced that it will develop national standards regulating disposal of
coal ash under its authority to regulate nonhazardous waste.
The Companies 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; however, federal law provides
that all PRPs for a particular site be held liable on a joint and several basis.
Therefore, potential environmental liabilities have been recognized on the
Consolidated Balance Sheet as of December 31, 2002, based on estimates of the
total costs of cleanup, the Companies' proportionate responsibility for such
costs and the financial ability of other nonaffiliated entities to pay. In
addition, JCP&L has accrued liabilities for environmental remediation of former
manufactured gas plants in New Jersey; those costs are being recovered by JCP&L
through its SBC. The Companies have total accrued liabilities aggregating
approximately $54.3 million as of December 31, 2002.
In 1980, Congress passed the Low-Level Radioactive Waste Policy Act
which provides that the disposal of low-level radioactive waste is the
responsibility of the state where such waste is generated. The Act encourages
states to form compacts among themselves to develop regional disposal
facilities. Failure by a state or compact to begin implementation of a program
could result in access denial to the two facilities currently accepting
low-level radioactive waste. Ohio is part of the Midwest Compact and has
responsibility for siting and constructing a disposal facility. On June 26,
1997, the Midwest Compact Commission (Compact) voted to cease all siting
activities in the host state of Ohio and to dismantle the Ohio Low-Level
Radioactive Waste Facility Development Authority, the statutory agency charged
with siting and constructing the low-level radioactive waste disposal facility.
While the Compact remains intact, it has no plans to site or construct a
low-level radioactive waste disposal facility in the Midwest. The Companies
continue to ship low-level radioactive waste from their nuclear facilities to
the Barnwell, South Carolina waste disposal facility.
Summary
Environmental controls are still developing and require, in many
instances, balancing the needs for additional quantities of energy in future
years and the need to protect the environment. As a result, the Companies cannot
now estimate the precise effect of existing and potential regulations and
legislation upon any of their existing and proposed facilities and operations or
upon their ability to issue additional first mortgage bonds under their
respective mortgages. These mortgages contain covenants by the Companies to
observe and conform to all valid governmental requirements at the time
applicable unless in course of contest, and provisions which, in effect, prevent
the issuance of additional bonds if there is a completed default under the
mortgage. The provisions of each of the mortgages, in effect, also require, in
the opinion of counsel for the respective Companies, that certification of
property additions as the basis for the issuance of bonds or other action under
the mortgages be accompanied by an opinion of counsel that the company
certifying such property additions has all governmental permissions at the time
necessary for its then current ownership and operation of such property
additions. The Companies intend to contest any requirements they deem
unreasonable or impossible for compliance or otherwise contrary to the public
interest. Developments in these and other areas of regulation may require the
Companies to modify, supplement or replace equipment and facilities, and may
12
delay or impede the construction and operation of new facilities, at costs which
could be substantial.
The effects of compliance on the Companies with regard to
environmental matters could have a material adverse effect on FirstEnergy's
earnings and competitive position. These environmental regulations affect
FirstEnergy's earnings and competitive position to the extent it competes with
companies that are not subject to such regulations and therefore do not bear the
risk of costs associated with compliance, or failure to comply, with such
regulations. FirstEnergy believes it is in material compliance with existing
regulations but is unable to predict whether environmental regulations will
change and what, if any, the effects of such change would be.
Fuel Supply
The Companies' sources of generation during 2002 were:
Fossil Nuclear
------ -------
OE.................... 74.5% 25.5%
Penn.................. 34.6% 65.4%
CEI................... 67.3% 32.7%
TE.................... 61.8% 38.2%
Total FirstEnergy..... 65.6% 34.4%
Generation from JCP&L's and Met-Ed's hydro and combustion turbine
generation facilities was minimal in 2002.
FirstEnergy currently has long-term coal contracts to provide
approximately 12,400,000 tons for the year 2003. The contracts are shared among
the Companies based on various economic considerations. This contract coal is
produced primarily from mines located in Pennsylvania, Kentucky and West
Virginia. The contracts expire at various times through December 31, 2019.
The Companies estimate their 2003 coal requirements to be
approximately 18,860,000 tons (OE - 7,250,000, Penn - 6,000,000, CEI -
4,170,000, and TE - 1,440,000) to be met from the long-term contracts discussed
above and spot market purchases. See "Environmental Matters" for factors
pertaining to meeting environmental regulations affecting coal-fired generating
units.
FirstEnergy has contracts for uranium material and conversion services
through 2006. The enrichment services are contracted for the majority of the
enrichment requirements for nuclear fuel through 2006. Fabrication services for
fuel assemblies are contracted for the next four reloads for Beaver Valley Unit
1, the next three reloads for Beaver Valley Unit 2 (through approximately 2007
and 2006, respectively), the next two reloads for Davis-Besse (through
approximately 2007) and through the operating license period for Perry (through
approximately 2026). In addition to the existing commitments, FirstEnergy
intends to make additional arrangements for the supply of uranium and for the
subsequent conversion, enrichment, fabrication, and waste disposal services.
On-site spent fuel storage facilities are expected to be adequate for
Perry through 2011; facilities at Beaver Valley Units 1 and 2 are expected to be
adequate through 2018 and 2009, respectively. With the plant modifications
completed in 2002, Davis-Besse has adequate storage through the remainder of its
operating license period. After current on-site storage capacity is exhausted,
additional storage capacity will have to be obtained either through plant
modifications, interim off-site disposal, or permanent waste disposal
facilities. The Federal Nuclear Waste Policy Act of 1982 provides for the
construction of facilities for the permanent disposal of high-level nuclear
wastes, including spent fuel from nuclear power plants operated by electric
utilities; however, the selection of a suitable site is embroiled in the
political process. FirstEnergy has contracts with the U.S. Department of Energy
(DOE) for the disposal of spent fuel for Beaver Valley, Davis-Besse and Perry.
On February 15, 2002, President Bush approved the DOE's recommendation of Yucca
Mountain for underground disposal of spent nuclear fuel from nuclear power
plants and high level waste from U.S. defense programs. The recommendation by
President Bush enables the process to proceed to the licensing phase. Based on
the DOE schedule published in the July 1999 Draft Environmental Impact
Statement, the Yucca Mountain Repository is currently projected to start
receiving spent fuel in 2010. FirstEnergy intends to make additional
arrangements for storage capacity as a contingency for further delays with the
DOE acceptance of spent fuel for disposal past 2010.
System Capacity and Reserves
The 2002 net maximum hourly demand for each of the Companies was:
OE-6,757 MW (including an additional 387 MW of firm power sales under a contract
which extends through 2005) on August 1, 2002; Penn-969 MW (including an
additional 63 MW of firm power sales under a contract which extends through
2005) on July 29, 2002; CEI-4,561 MW on August 1, 2002; TE-2,104 MW on July 3,
2002; JCP&L-5,802 MW on August 2, 2002; Met-Ed-2,616 MW on August 14, 2002; and
Penelec-2,693 MW on July 29, 2002. JCP&L's load was auctioned off in the New
13
Jersey BGS Auction, transferring the full 5,100 MW load obligation to
otherauction and won a segment of that load.
Based on existing capacity plans, ongoing arrangements for firm
purchase contracts, and anticipated term power sales and purchases, FirstEnergy
has sufficient supply resources to meet load obligations. The current
FirstEnergy capacity portfolio contains 13,387 MW of owned generation and
approximately 1,600 MW of long-term purchases from non-utility generators.
Any remaining load obligations will be met through a mix of multi-year
forward purchases, short-term forward purchases (less than one year) and spot
market purchases.
Regional Reliability
The Companies participate with 24 other electric companies operating
in nine states in ECAR, which was organized for the purpose of furthering the
reliability of bulk power supply in the area through coordination of the
planning and operation by the ECAR members of their bulk power supply
facilities. The ECAR members have established principles and procedures
regarding matters affecting the reliability of the bulk power supply within the
ECAR region. Procedures have been adopted regarding: i) the evaluation and
simulated testing of systems' performance; ii) the establishment of minimum
levels of daily operating reserves; iii) the development of a program regarding
emergency procedures during conditions of declining system frequency; and iv)
the basis for uniform rating of generating equipment.
Following the FirstEnergy/GPU merger the transmission facilities of
JCP&L, Met-Ed and Penelec continue to be operated by PJM. PJM is the
organization responsible for the operation and control of the bulk electric
power system throughout major portions of five Mid-Atlantic states and the
District of Columbia. PJM is dedicated to meeting the reliability criteria and
standards of the North American Electric Reliability Council and the
Mid-Atlantic Area Council.
Competition
The Companies traditionally competed with other utilities for
intersystem bulk power sales and for sales to municipalities and cooperatives.
The Companies compete with suppliers of natural gas and other forms of energy in
connection with their industrial and commercial sales and in the home climate
control market, both with respect to new customers and conversions, and with all
other suppliers of electricity. To date, there has been no substantial
cogeneration by the Companies' customers.
As a result of the actions taken by state legislative bodies over the
last few years, major changes in the electric utility business are occurring in
parts of the United States, including Ohio, New Jersey and Pennsylvania where
FirstEnergy's utility subsidiaries operate. These changes have resulted in
fundamental alterations in the way traditional integrated utilities and holding
company systems, like FirstEnergy, conduct their business. In accordance with
the Ohio electric utility restructuring law under which Ohio electric customers
could begin choosing their electric generation suppliers starting in January
2001, FirstEnergy has further aligned its business units to accommodate its
retail strategy and participate in the competitive electricity marketplace in
Ohio. The organizational changes deal with the unbundling of electric utility
services and new ways of conducting business.
Sales of electricity in deregulated markets are diversifying
FirstEnergy's revenue sources through its competitive subsidiaries in areas
outside of the Companies' franchise areas. This strategy has positioned
FirstEnergy to compete in the northeast quadrant of the United States - the
region targeted by FirstEnergy for growth. FirstEnergy's competitive
subsidiaries are actively participating in deregulated energy markets in Ohio,
Pennsylvania, New Jersey, Delaware, Maryland and Michigan. Currently, FES is
providing electric generation service to customers within those states. As
additional states within the northeast region of the United States become
deregulated, FES is preparing to enter these markets.
Competition in Ohio's electric generation began on January 1, 2001.
FirstEnergy moved the operation of the generation portion of its business to its
competitive business unit as reflected in its approved Ohio transition plan. The
Companies continue to provide generation services to regulated franchise
customers who have not chosen an alternative, competitive generation supplier,
except in New Jersey where JCP&L's obligation to provide BGS has been removed
through a transitional mechanism of auctioning the obligation (see "NJBPU Rate
Matters"). In September 2002, Met-Ed and Penelec assigned their PLR
responsibility to FES through a wholesale power sale agreement. Under the
agreement terms, FES assumes the supply obligation and the energy supply profit
and loss risk for the portion of power supply requirements not self-supplied by
Met-Ed and Penelec. The agreement is automatically extended on an annual basis
unless any party elects to cancel the agreement by November 1 of the preceding
year (see "PPUC Rate Matters" for further discussion). The Ohio Companies and
Penn obtain their generation through power supply agreements with FES. In
addition to electric generation, FES is also competing in deregulated natural
gas markets as well as offering other energy-related products and services.
14
Research and Development
The Companies participate in funding the Electric Power Research
Institute (EPRI), which was formed for the purpose of expanding electric
research and development under the voluntary sponsorship of the nation's
electric utility industry - public, private and cooperative. Its goal is to
mutually benefit utilities and their customers by promoting the development of
new and improved technologies to help the utility industry meet present and
future electric energy needs in environmentally and economically acceptable
ways. EPRI conducts research on all aspects of electric power production and
use, including fuels, generation, delivery, energy management and conservation,
environmental effects and energy analysis. The major portion of EPRI research
and development projects is directed toward practical solutions and their
applications to problems currently facing the electric utility industry. In
2002, approximately 69% of the Companies' research and development expenditures
were related to EPRI.
Executive Officers
The executive officers are elected at the annual organization meeting
of the Board of Directors, held immediately after the annual meeting of
stockholders, and hold office until the next such organization meeting, unless
the Board of Directors shall otherwise determine, or unless a resignation is
submitted.
Position Held During
Name Age Past Five Years Dates
----------------- --- -------------------------------------------------------------- --------------------
H. P. Burg 56 Chairman of the Board and Chief Executive Officer 2002-present
Vice Chairman of the Board and Chief Executive Officer 2001-2002
Chairman of the Board and Chief Executive Officer 2000-2001
President and Chief Executive Officer 1999-2000
President and Chief Operating Officer 1998-1999
President and Chief Financial Officer *-1998
A. J. Alexander 51 President and Chief Operating Officer 2001-present
President 2000-2001
Executive Vice President and General Counsel *-2000
A. R. Garfield 64 President - FirstEnergy Solutions 2001-present
Senior Vice President - Supply and Sales 2000-2001
Vice President - Business Development *-2000
R. F. Saunders 59 President and Chief Nuclear Officer
- FENOC 2000-present Vice President, Nuclear Site
Operations - Pennsylvania Power & Light 1998-2000
Vice President, Nuclear Engineering - Virginia
Power Company *-1998
E. T. Carey 60 Senior Vice President 2001-present
Vice President - Distribution *-2001
K. J. Keough 43 Senior Vice President 2001-present
Vice President - Business Planning & Ventures 1999-2001
Partner - McKinsey & Company *-1999
R. H. Marsh 52 Senior Vice President and Chief Financial Officer 2001-present
Vice President and Chief Financial Officer 1998-2001
Vice President - Finance *-1998
C. B. Snyder 57 Senior Vice President 2001-present
Executive Vice President - Corporate Affairs - GPU 1998-2001
Senior Vice President - Corporate Affairs - GPU *-1998
L. L. Vespoli 43 Senior Vice President and General Counsel 2001-present
Vice President and General Counsel 2000-2001
Associate General Counsel *-2000
H. L. Wagner 50 Vice President, Controller and Chief Accounting Officer 2001-present
Controller *-2001
Mrs. Vespoli and Messrs. Burg, Carey, Marsh and Wagner
are the executive officers, as noted above, of OE,
Penn, CEI, TE, Met-Ed and Penelec. Mrs. Vespoli
and Messrs. Carey, Marsh and Wagner are the
executive officers of JCP&L.
* Indicates position held at least since January 1, 1998.
FirstEnergy Website
Each of the registrant's annual report on Form 10-K, quarterly reports on Form
10-K, current reports on Form 8-K, and amendments to those reports filed with or
furnished to the SEC pursuant to Section 13(a) or 15(d) of the Securities
Exchange Act of 1934 are also made available free of charge on or through
FirstEnergy's internet website at www.firstenergycorp.com. These reports are
posted on the website as soon as reasonably practicable after they are
electronically filed with the SEC.
15
As of January 1, 2003, FirstEnergy's nonutility subsidiaries and the
Companies had a total of 17,560 employees located in the United States as
follows: FirstEnergy-1,744, OE-1,368, CEI-974, TE-508, Penn-201, JCP&L-39,
Met-Ed-61, ATSI-29, FES-2,072, FENOC-2,850, FSG-3,317, MARBEL-32 and GPUS-4,365
(primarily employees supporting JCP&L, Met-Ed and Penelec).
ITEM 6. SELECTED FINANCIAL DATA
ITEM 7 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required for items 6 through 8 is incorporated herein
by reference to Selected Financial Data, Management's Discussion and Analysis of
Results of Operations and Financial Condition and Financial Statements included
on the pages shown in the following table in FirstEnergy's 2002 Annual Report to
Stockholders, as revised (Exhibit 13 below).
Item 6 Item 7 Item 8
------ ------ ------
FirstEnergy.............. 4 5-28 29-66
ITEM 14. CONTROLS AND PROCEDURES
(a) Evaluation of Disclosure Controls and Procedures
The respective registrant's chief executive officer and chief
financial officer have reviewed and evaluated the registrant's disclosure
controls and procedures, as defined in the Securities Exchange Act of 1934 Rules
13a-14(c) and 15d-14(c), as of a date within 90 days prior to the filing date of
this report (Evaluation Date). Based on that evaluation those officers have
concluded that the registrant's disclosure controls and procedures are effective
and were designed to bring to their attention, during the period in which this
annual report was being prepared, material information relating to the
registrant and its consolidated subsidiaries by others within those entities.
(b) Changes in Internal Controls
There have been no significant changes in internal controls or in
other factors that could significantly affect those controls subsequent to the
Evaluation Date.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Financial Statements
Included in Part II of this report and incorporated herein by
reference to FirstEnergy's 2002 Annual Report to Stockholders, as revised
(Exhibit 13 below), at the pages indicated.
First-
Energy
------
Report of Independent Accountants....................................... 2
Statements of Income-Three Years Ended December 31, 2002 29
Balance Sheets-December 31, 2002 and 2001............................... 30
Statements of Capitalization-December 31, 2002 and 2001. 31-34
Statements of Common Stockholders' Equity-Three Years
Ended December 31, 2002............................................... 35
Statements of Preferred Stock-Three Years Ended December 31, 2002....... 36
Statements of Cash Flows-Three Years Ended December 31, 2002............ 37
Statements of Taxes-Three Years Ended December 31, 2002................. 38
Notes to Financial Statements........................................... 39-66
16
3. Exhibits - FirstEnergy
Exhibit
Number
------
3-1 -- Articles of Incorporation constituting FirstEnergy
Corp.'s Articles of Incorporation, dated September 17,
1996. (September 17, 1996 Form 8-K, Exhibit C)
3-1(a) -- Amended Articles of Incorporation of FirstEnergy Corp.
(Registration No. 333-21011, Exhibit (3)-1)
3-2 -- Regulations of FirstEnergy Corp. (September 17, 1996
Form 8-K, Exhibit D)
3-2(a) -- FirstEnergy Corp. Amended Code of Regulations.
Registration No. 333-21011, Exhibit (3)-2)
4-1 -- Rights Agreement (December 1, 1997 Form 8-K,
Exhibit 4.1)
4-2 -- FirstEnergy Corp. to The Bank of New York, Supplemental
Indenture, dated November 7, 2001. (2001 Form 10-K,
Exhibit 4-2)
10-1 -- FirstEnergy Corp. Executive and Director Incentive
Compensation Plan, revised November 15, 1999. (1999
Form 10-K, Exhibit 10-1)
10-2 -- Amended FirstEnergy Corp. Deferred Compensation Plan
for Directors, revised November 15, 1999. (1999
Form 10-K, Exhibit 10-2)
10-3 -- Employment, severance and change of control agreement
between FirstEnergy Corp. and executive officers.
(1999 Form 10-K, Exhibit 10-3)
10-4 -- FirstEnergy Corp. Supplemental Executive Retirement
Plan, amended January 1, 1999. (1999 Form 10-K,
Exhibit 10-4)
10-5 -- FirstEnergy Corp. Executive Incentive Compensation
Plan. (1999 Form 10-K, Exhibit 10-5)
10-6 -- Restricted stock agreement between FirstEnergy Corp.
and A. J. Alexander. (1999 Form 10-K, Exhibit 10-6)
10-7 -- FirstEnergy Corp. Executive and Director Incentive
Compensation Plan. (1998 Form 10-K, Exhibit 10-1)
10-8 -- Amended FirstEnergy Corp. Deferred Compensation Plan
for Directors, amended February 15, 1999. (1998
Form 10-K, Exhibit 10-2)
10-9 -- Restricted stock agreement between FirstEnergy Corp.
and A. J. Alexander. (2000 Form 10-K, Exhibit 10-9)
10-10 -- Restricted stock agreement between FirstEnergy Corp.
and H. P. Burg. (2000 Form 10-K, Exhibit 10-10)
10-11 -- Stock option agreement between FirstEnergy Corp. and
officers dated November 22, 2000. (2000 Form 10-K,
Exhibit 10-11)
10-12 -- Stock option agreement between FirstEnergy Corp. and
officers dated March 1, 2000. (2000 Form 10-K,
Exhibit 10-12)
10-13 -- Stock option agreement between FirstEnergy Corp. and
director dated January 1, 2000. (2000 Form 10-K,
Exhibit 10-13)
10-14 -- Stock option agreement between FirstEnergy Corp. and
two directors dated January 1, 2001. (2000 Form 10-K,
Exhibit 10-14)
10-15 -- Executive and Director Incentive Compensation Plan
dated May 15, 2001. (2001 Form 10-K, Exhibit 10-15)
17
10-16 -- Amended FirstEnergy Corp. Deferred Compensation Plan
for Directors, revised September 18, 2000. (2001
Form 10-K, Exhibit 10-16)
10-17 -- Stock Option Agreements between FirstEnergy Corp. and
Officers dated May 16, 2001. (2001 Form 10-K, Exhibit
10-17)
10-18 -- Restricted Stock Agreements between FirstEnergy Corp.
and Officers dated February 20, 2002. (2001 Form 10-K,
Exhibit 10-18)
10-19 -- Stock Option Agreements between FirstEnergy Corp. and
One Director dated January 1, 2002. (2001 Form 10-K,
Exhibit 10-19)
10-20 -- FirstEnergy Corp. Executive Deferred Compensation Plan.
(2001 Form 10-K, Exhibit 10-20)
10-21 -- Executive Incentive Compensation Plan-Tier 2. (2001
Form 10-K, Exhibit 20-21)
10-22 -- Executive Incentive Compensation Plan-Tier 3. (2001
Form 10-K, Exhibit 20-22)
10-23 -- Executive Incentive Compensation Plan-Tier 4. (2001
Form 10-K, Exhibit 10-23)
10-24 -- Executive Incentive Compensation Plan-Tier 5. (2001
Form 10-K, Exhibit 10-24)
10-25 -- Amendment to GPU, Inc. 1990 Stock Plan for Employees
of GPU, Inc. and Subsidiaries, effective April 5, 2001.
(2001 Form 10-K, Exhibit 10-25)
10-26 -- Form of Amendment, effective November 7, 2001, to GPU,
Inc. 1990 Stock Plan for Employees of GPU, Inc. and
Subsidiaries, Deferred Remuneration Plan for Outside
Directors of GPU, Inc., and Retirement Plan for Outside
Directors of GPU, Inc. (2001 Form 10-K, Exhibit 10-26)
10-27 -- GPU, Inc. Stock Option and Restricted Stock Plan for
MYR Group, Inc. Employees. (2001 Form 10-K, Exhibit
10-27)
10-28 -- Executive and Director Stock Option Agreement dated
June 11, 2002.
10-29 -- Director Stock Option Agreement.
10-30 -- Executive and Director Executive Incentive Compensation
Plan, Amendment dated May 21, 2002.
10-31 -- Directors Deferred Compensation Plan, Revised Nov. 19,
2002.
10-32 -- Executive Incentive Compensation Plan 2002.
10-33 -- GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc.
and Subsidiaries as amended and restated to reflect
amendments through June 3, 1999. (1999 Form 10-K,
Exhibit 10-V, File No. 1-6047, GPU, Inc.)
10-34 -- Form of 1998 Stock Option Agreement under the GPU, Inc.
1990 Stock Plan for Employees of GPU, Inc. and
Subsidiaries. (1997 Form 10-K, Exhibit 10-Q, File No.
1-6047, GPU, Inc.)
10-35 -- Form of 1999 Stock Option Agreement under the GPU, Inc.
1990 Stock Plan for Employees of GPU, Inc. and
Subsidiaries. (1999 Form 10-K, Exhibit 10-W, File No.
1-6047, GPU, Inc.)
10-36 -- Form of 2000 Stock Option Agreement under the GPU, Inc.
1990 Stock Plan for Employees of GPU, Inc. and
Subsidiaries. (2000 Form 10-K, Exhibit 10-W, File No.
1-6047, GPU, Inc.)
10-37 -- Deferred Remuneration Plan for Outside Directors of
GPU, Inc. as amended and restated effective August 8,
2000. (2000 Form 10-K, Exhibit 10-O, File No. 1-6047,
GPU, Inc.)
10-38 -- Retirement Plan for Outside Directors of GPU, Inc. as
amended and restated as of August 8, 2000. (2000
Form 10-K, Exhibit 10-N, File No. 1-6047, GPU, Inc.)
18
10-39 -- Forms of Estate Enhancement Program Agreements entered
into by certain former GPU directors. (1999 Form 10-K,
Exhibit 10-JJ, File No. 1-6047, GPU, Inc.)
* 12.1 -- Consolidated fixed charge ratios.
* 13 -- FirstEnergy 2002 Annual Report to Stockholders, as
revised. (Only those portions expressly incorporated
by reference in this Form 10-K/A are to be deemed
"filed" with the SEC.)
21 -- List of Subsidiaries of the Registrant at December 31,
2002.
* 23 -- Consent of Independent Accountants.
* 99.1 -- Chief Executive Officer Certification
* 99.2 -- Chief Financial Officer Certification
* Indicates revised exhibits included in this From 10-K/A in electronic
format. Reference is made to the original 10-K for the other exhibits filed
with it.
(b) Reports on Form 8-K
FirstEnergy-
FirstEnergy filed fourteen reports on Form 8-K since September 30,
2002. A report dated October 7, 2002 reported updated cost and schedule
estimates associated with efforts to return Davis-Besse Nuclear Power Station to
service. A report dated October 31, 2002 reported updated information associated
with Davis-Besse restoration efforts. A report dated December 2, 2002 reported
the merger of the GPU Employees Savings Plan into the FirstEnergy System Savings
Plan. A report dated December 3, 2002 reported updated FirstEnergy 2003 earnings
guidance. A report dated December 20, 2002 reported that FirstEnergy
subsidiaries would retain ownership of four power plants previously planned to
be sold. A report dated January 17, 2003 reported updated information related
with efforts to prepare Davis-Besse for a safe and reliable return to service
and the updated schedule for JCP&L rate proceedings. A report dated January 21,
2003 reported that the Pennsylvania Supreme Court denied further appeals of the
February 21, 2002 Pennsylvania Commonwealth Court decision, which effectively
affirmed the Pennsylvania Public Utility Commission's order approving the
FirstEnergy and GPU merger, let stand the Commonwealth Court's denial of PLR
relief for Met-Ed and Penelec and remanded the merger savings issue back to the
PPUC. A report dated March 11, 2003 reported updated Davis-Besse information
including the installation of the new reactor head on the reactor vessel. A
report dated March 17, 2003 reported updated Davis-Besse information, the filing
of a $2 billion shelf registration with the SEC and the status of the JCP&L rate
proceedings. A report dated March 18, 2003 reported NJBPU audit results of JCP&L
restructuring-related deferrals. A report dated April 16, 2003 reported updated
Davis-Besse information. A report dated April 18, 2003 reported FirstEnergy's
divestiture of its Argentina operations through the abandonment of its
investment resulting in a second quarter 2003 charge to net income of $63
million. A report dated May 1, 2003 reported FirstEnergy's first quarter 2003
results and other updated information including Davis-Besse updated ready for
restart schedule. A report dated May 9, 2003 reported updated Davis-Besse
information and a JCP&L rate proceedings update.
19
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
FIRSTENERGY CORP.
/s/Harvey L. Wagner
---------------------------------------
Harvey L. Wagner
Vice President, Controller
and Chief Accounting Officer
Date: May 9, 2003
20
Certification
I, H. Peter Burg, certify that:
1. I have reviewed this amended annual report on Form 10-K/A of FirstEnergy
Corp;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of the registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: May 9, 2003
/s/H. Peter Burg
H. Peter Burg
-------------------------
Chief Executive Officer
21
Certification
I, Richard H. Marsh, certify that:
1. I have reviewed this amended annual report on Form 10-K/A of FirstEnergy
Corp.
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of the registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: May 9, 2003
/s/Richard H. Marsh
----------------------------------
Richard H. Marsh
Chief Financial Officer
22