MANAGEMENT REPORT
The consolidated financial statements were prepared by the management of
FirstEnergy Corp., who takes responsibility for their integrity and objectivity.
The statements were prepared in conformity with accounting principles generally
accepted in the United States and are consistent with other financial
information appearing elsewhere in this report. PricewaterhouseCoopers LLP,
independent auditors, have expressed an unqualified opinion on the Company's
2003 consolidated financial statements.
The Company's internal auditors, who are responsible to the Audit Committee of
the Board of Directors, review the results and performance of operating units
within the Company for adequacy, effectiveness and reliability of accounting and
reporting systems, as well as managerial and operating controls.
The Audit Committee consists of six independent directors whose duties include:
consideration of the adequacy of the internal controls of the Company and the
objectivity of financial reporting; inquiry into the number, extent, adequacy
and validity of regular and special audits conducted by independent auditors and
the internal auditors; and reporting to the Board of Directors the Committee's
findings and any recommendation for changes in scope, methods or procedures of
the auditing functions. The Committee is directly responsible for appointing the
Company's independent auditors (subject to shareholder approval) and is charged
with reviewing and approving all services performed for the Company by the
independent auditors and for reviewing the related fees. The Committee reviews
the independent auditors' internal quality control procedures and reviews all
relationships between the independent auditors and the Company, in order to
assess the auditors' independence. The Committee also reviews management's
programs to monitor compliance with the Company's policies on business ethics
and risk management. The Committee establishes procedures to receive and respond
to complaints received by the Company regarding accounting, internal accounting
controls, or auditing matters and allows for the confidential, anonymous
submission of concerns by employees. The Audit Committee held ten meetings in
2003.
Richard H. Marsh
Senior Vice President
and Chief Financial Officer
Harvey L. Wagner
Vice President, Controller
and Chief Accounting Officer
2
Report of Independent Auditors
To the Stockholders and Board of Directors of FirstEnergy Corp.:
In our opinion, the accompanying consolidated balance sheets and consolidated
statements of capitalization and the related consolidated statements of income,
common stockholders' equity, preferred stock, cash flows and taxes present
fairly, in all material respects, the financial position of FirstEnergy Corp.
and subsidiaries as of December 31, 2003 and 2002 and the results of their
operations and their cash flows for the years then ended in conformity with
accounting principles generally accepted in the United States of America. These
financial statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States of America, which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion. The consolidated financial statements of
FirstEnergy Corp. and subsidiaries for the year ended December 31, 2001, prior
to the revisions described in Notes 2(F), 2(L) and 8, were audited by other
independent auditors who have ceased operations. Those independent auditors
expressed an unqualified opinion on those financial statements in their report
dated March 18, 2002.
As discussed in Note 2(L) to the consolidated financial statements, the Company
changed its method of accounting for goodwill as of January 1, 2002. As
discussed in Note 2(F) to the consolidated financial statements, the Company
changed its method of accounting for asset retirement obligations as of January
1, 2003. As discussed in Note 9 to the consolidated financial statements, the
Company changed its method of accounting for the consolidation of variable
interest entities as of December 31, 2003.
As discussed above, the consolidated financial statements of FirstEnergy Corp.
and subsidiaries for the year ended December 31, 2001 were audited by other
independent auditors who have ceased operations. As described in Note 2(L) to
the consolidated financial statements, the financial statements have been
revised to include the transitional disclosures required by Statement of
Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets,
which was adopted by the Company as of January 1, 2002. As described in Note
2(F) to the consolidated financial statements, the financial statements have
been revised to include the transitional disclosures required by Statement of
Financial Accounting Standards No. 143, Accounting for Asset Retirement
Obligations, which was adopted by the Company as of January 1, 2003. As
described in Note 8 to the consolidated financial statements, the Company
changed the composition of its reportable segments in 2002. We audited the
transitional disclosures described in Notes 2(F) and 2(L) and the adjustments
that were applied to restate the 2001 reportable segments disclosures discussed
in Note 8. In our opinion, such adjustments to the reportable segments
disclosures are appropriate and have been properly applied and the transitional
disclosures for 2001 are appropriate. However, we were not engaged to audit,
review, or apply any procedures to the 2001 consolidated financial statements of
the Company other than with respect to such transitional disclosures and
adjustments to the reportable segments disclosures and, accordingly, we do not
express an opinion or any other form of assurance on the 2001 consolidated
financial statements taken as a whole.
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 25, 2004
3
The following report is a copy of a report previously issued by Arthur Andersen
LLP (Andersen). This report has not been reissued by Andersen and Andersen did
not consent to the incorporation by reference of this report into any of the
Company's registration statements.
As discussed in Note 2(L) to the consolidated financial statements, the Company
has revised its consolidated financial statements for the year ended December
31, 2001 to include the transitional disclosures required by Statement of
Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets."
As discussed in Note 2(F) to the consolidated financial statements, the Company
has revised its consolidated financial statements for the year ended December
31, 2001 to include the transitional disclosures required by Statement of
Financial Accounting Standards No. 143, "Accounting for Asset Retirement
Obligations." Additionally, as discussed in Note 8 to the consolidated financial
statements, the Company has revised its consolidated financial statements for
the year ended December 31, 2001 to reflect changes in the composition of its
reportable segments adopted in 2002. The Andersen report does not extend to
these changes. The revisions to the 2001 financial statements related to these
transitional disclosures and the revisions that were applied to restate the 2001
reportable segments disclosures were reported on by PricewaterhouseCoopers LLP,
as stated in their report appearing herein.
REPORT OF PREVIOUS INDEPENDENT PUBLIC ACCOUNTANTS
TO THE STOCKHOLDERS AND BOARD OF DIRECTORS OF FIRSTENERGY CORP.:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of FirstEnergy Corp. (an Ohio corporation) and
subsidiaries as of December 31, 2001 and 2000, and the related consolidated
statements of income, common stockholders' equity, preferred stock, cash flows
and taxes for each of the three years in the period ended December 31, 2001.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of FirstEnergy Corp. and
subsidiaries as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.
As explained in Note 1 to the consolidated financial statements, effective
January 1, 2001, the Company changed its method of accounting for derivative
instruments and hedging activities by adopting Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities", as amended.
ARTHUR ANDERSEN LLP
Cleveland, Ohio,
March 18, 2002
4
FIRSTENERGY CORP.
SELECTED FINANCIAL DATA
For the Years Ended December 31, 2003 2002* 2001 2000 1999
- -----------------------------------------------------------------------------------------------------------------------
(In thousands, except per share amounts)
Revenues....................................... $12,307,407 $12,047,348 $ 7,999,362 $ 7,028,961 $ 6,319,647
--------------------------------------------------------------------
Income Before Discontinued Operations
and Cumulative Effect of Accounting Changes. $ 421,996 $ 632,667 $ 654,946 $ 598,970 $ 568,299
--------------------------------------------------------------------
Net Income..................................... $ 422,764 $ 552,804 $ 646,447 $ 598,970 $ 568,299
--------------------------------------------------------------------
Basic Earnings per Share of Common Stock:
Before Discontinued Operations and
Cumulative Effect of Accounting Changes... $1.39 $2.16 $2.85 $2.69 $2.50
After Discontinued Operations and
Cumulative Effect of Accounting Changes... $1.39 $1.89 $2.82 $2.69 $2.50
--------------------------------------------------------------------
Diluted Earnings per Share of Common Stock:
Before Discontinued Operations and
Cumulative Effect of Accounting Changes... $1.39 $2.15 $2.84 $2.69 $2.50
After Discontinued Operations and
Cumulative Effect of Accounting Changes... $1.39 $1.88 $2.81 $2.69 $2.50
--------------------------------------------------------------------
Dividends Declared per Share of Common Stock... $1.50 $1.50 $1.50 $1.50 $1.50
--------------------------------------------------------------------
Total Assets................................... $32,909,948 $34,386,353 $37,351,513 $17,941,294 $18,224,047
-------------------------------------------------------------------
Capitalization as of December 31:
Common Stockholders' Equity................. $ 8,289,341 $ 7,050,661 $ 7,398,599 $ 4,653,126 $ 4,563,890
Preferred Stock:
Not Subject to Mandatory Redemption....... 335,123 335,123 480,194 648,395 648,395
Subject to Mandatory Redemption........... -- 428,388 594,856 161,105 256,246
Long-Term Debt.............................. 9,789,066 10,872,216 12,865,352 5,742,048 6,001,264
--------------------------------------------------------------------
Total Capitalization...................... $18,413,530 $18,686,388 $21,339,001 $11,204,674 $11,469,795
====================================================================
<FN>
* See Note 2(I) regarding reclassification of discontinued operations.
</FN>
PRICE RANGE OF COMMON STOCK
The Common Stock of FirstEnergy Corp.is listed on the New York Stock
Exchange under the symbol "FE" and is traded on other registered exchanges.
2003 2002
- ---------------------------------------------------------------------------
First Quarter High-Low......... $35.19 $27.04 $39.12 $30.30
Second Quarter High-Low........ 38.90 30.57 35.12 31.61
Third Quarter High-Low......... 38.75 25.82 34.78 24.85
Fourth Quarter High-Low........ 35.95 31.66 33.85 25.60
Yearly High-Low................ 38.90 25.82 39.12 24.85
- ---------------------------------------------------------------------------
Prices are based on reports published in The Wall Street Journal for New York
-----------------------
Stock Exchange Composite Transactions.
HOLDERS OF COMMON STOCK
There were 153,020 and 152,288 holders of 329,836,276 shares of
FirstEnergy's Common Stock as of December 31, 2003 and January 31, 2004,
respectively. Information regarding retained earnings available for payment of
cash dividends is given in Note 5(A).
5
FIRSTENERGY CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
This discussion includes forward-looking statements based on
information currently available to management. Such statements are subject to
certain risks and uncertainties. These statements typically contain, but are not
limited to, the terms "anticipate," "potential," "expect," "believe," "estimate"
and similar words. Actual results may differ materially due to the speed and
nature of increased competition and deregulation in the electric utility
industry, economic or weather conditions affecting future sales and margins,
changes in markets for energy services, changing energy and commodity market
prices, replacement power costs being higher than anticipated or inadequately
hedged, maintenance costs being higher than anticipated, legislative and
regulatory changes (including revised environmental requirements), adverse
regulatory or legal decisions and the outcome of governmental investigations,
availability and cost of capital, the continuing availability and operation of
generating units, inability of the Davis-Besse Nuclear Power Station to restart
(including because of an inability to obtain a favorable final determination
from the Nuclear Regulatory Commission) in early 2004, the inability to
accomplish or realize anticipated benefits from strategic goals, the ability to
improve electric commodity margins and to experience growth in the distribution
business, the ability to access the public securities market, further
investigation into the causes of the August 14, 2003, regional power outage and
the outcome, cost and other effects of present and potential legal and
administrative proceedings and claims related to the outage, a denial of or
material change to the Company's Application related to its Rate Stabilization
Plan, and other similar factors.
FIRSTENERGY'S BUSINESS
FirstEnergy Corp. is a registered public utility holding company
headquartered in Akron, Ohio that provides regulated and competitive energy
services (see Results of Operations - Business Segments). Our vision is to
become the leading retail energy and related services provider in the northeast
and mid-Atlantic region of the United States. Our eight electric utility
operating companies (EUOC) comprise the nation's fifth largest investor-owned
electric system, serving 4.4 million customers within 36,100 square miles of
Ohio, Pennsylvania and New Jersey.
Transmission and Distribution Services Area Served Customers Served
-------------------------------------- ----------- ----------------
Ohio Edison Company (OE) Central and northeastern Ohio 1,019,280
Pennsylvania Power Company (Penn) Western Pennsylvania 155,929
The Cleveland Electric Illuminating Company (CEI) Northeastern Ohio 752,537
The Toledo Edison Company (TE) Northwestern Ohio 307,893
Jersey Central Power & Light Company (JCP&L) Northern, western and east
central New Jersey 1,049,547
Metropolitan Edison Company (Met-Ed) Eastern Pennsylvania 516,536
Pennsylvania Electric Company (Penelec) Western Pennsylvania 585,089
American Transmission Systems, Incorporated (ATSI) Service areas of OE, Penn,
CEI and TE
Competitive services are principally provided by FirstEnergy
Solutions Corp. (FES), FirstEnergy Facilities Services Group, LLC (FSG), MARBEL
Energy Corporation, MYR Group, Inc., and our majority owned First
Communications, LLC. Through its 50% interest in Great Lakes Energy Partners,
LLC, MARBEL is involved in the exploration and production of oil and natural
gas, and transmission and marketing of natural gas. Other subsidiaries provide a
wide range of services, including heating, ventilating, air-conditioning,
refrigeration, process piping, plumbing, electrical and facility control systems
and high-efficiency electrotechnologies. Telecommunication services are also
provided - local and long-distance phone service is provided to more than 65,000
customers. While competitive revenues have increased since 2001, regulated
energy services continue to provide, in aggregate, the majority of FirstEnergy's
revenues and earnings.
Beginning in 2001, Ohio utilities that offered both competitive and
regulated retail electric services were required to implement a corporate
separation plan approved by the Public Utilities Commission of Ohio (PUCO) - one
which provided a clear separation between regulated and competitive operations.
FES provides competitive retail energy services while the EUOC provide regulated
transmission and distribution services. FirstEnergy Generation Corp.
6
(FGCO), a wholly owned subsidiary of FES, leases fossil and hydroelectric plants
from the EUOC and operates those plants. Under the terms of the current
corporate separation plan, the transfer of ownership of EUOC non-nuclear
generating assets to FGCO would be substantially completed by the end of the
Ohio market development period. All of the EUOC power supply requirements for
the Ohio Companies (OE, CEI, and TE) and Penn are provided by FES to satisfy
their provider of last resort (PLR) obligations, as well as their grandfathered
wholesale contracts.
FirstEnergy acquired international assets in the merger with GPU,
Inc. in November 2001. GPU Capital, Inc. and its subsidiaries had provided
electric distribution services in foreign countries (see Results of Operations -
Discontinued Operations). GPU Power, Inc. and its subsidiaries owned and
operated generation facilities in foreign countries. As of January 30, 2004, all
of the international operations had been divested (see Note 3) because those
assets were not consistent with the role we envision for FirstEnergy in the
energy industry.
ORDERLY TRANSITION OF LEADERSHIP
On January 13, 2004, FirstEnergy Chairman and Chief Executive Officer
H. Peter Burg, passed away. Mr. Burg had taken a leave of absence beginning
December 22, 2003, to undergo treatment for leukemia. At that time, the Board of
Directors of FirstEnergy named President and Chief Operating Officer Anthony J.
Alexander acting Chief Executive Officer. On January 20, 2004, the Board of
Directors elected Mr. Alexander President and Chief Executive Officer, and also
elected George M. Smart as Chairman. Mr. Smart was elected to Ohio Edison
Company's Board of Directors in 1988 and to FirstEnergy's Board of Directors in
1997. Mr. Smart will not hold an executive position with FirstEnergy.
STRATEGY AND RISKS
We continue to pursue our goal of being the leading regional supplier
of energy and related services in the northeast and mid-Atlantic region, where
we see the best opportunities for growth. Our fundamental business strategy
remains stable and unchanged. While we continue to build toward a strong
regional presence, key elements for our strategy are in place and management's
focus continues to be on execution. We intend to continue providing
competitively priced, high-quality products and value-added services - energy
sales and services, energy delivery, power supply and supplemental services
related to our core business. As our industry changes to a more competitive
environment, we have taken and expect to take actions designed to create a
larger, stronger regional enterprise that will be positioned to compete in the
changing energy marketplace.
Our current focus includes: (1) minimizing unplanned extended
generation outages; (2) improving our system reliability; (3) optimizing our
generation portfolio; (4) effectively managing commodity supplies and risks; (5)
reducing our cost structure; (6) enhancing our credit profile and financial
flexibility; (7) managing the skills and diversity of our workforce; and (8)
satisfactory resolution of the pending Ohio rate plan.
Risks
We face a number of industry and enterprise risks and challenges,
among which include:
o Weather and other weather-related phenomena (short-term and
long-term)
o General economic conditions and the resulting impact on our
service area economies
o Conditions in capital markets affecting availability of funds and
interest rates
o Environmental laws and regulations
o Fluctuations in commodity prices
o Actions taken by regulatory agencies
o Changing competitive landscape
o Potential acts of terrorism
Supply Plan
Our affiliates are obligated to provide generation service with an
estimated power supply of 100,000 gigawatt-hours for 2004. These obligations
arise from customers who have elected to continue to receive generation service
from our EUOCs under regulated retail rate tariffs and from customers who have
selected FES as their alternate generation provider. Geographically,
approximately 64% of the total generation service obligation is for customers
located in the Midwest Independent System Operator (ISO) market area and 36% for
customers located in the PJM Interconnection, LLC ISO market area. Included in
the PJM ISO market area are obligations of FES to provide power to electric
distribution companies in the state of New Jersey, including JCP&L. FES incurred
this obligation as a successful bidder in the State of New Jersey's auction of
basic generation service (BGS).
7
Within the franchise territories of the EUOC, alternative energy
suppliers currently provide generation service to approximate 1,400 megawatts
(summer peak) of load with an estimated energy requirement of 6,700
gigawatt-hours. If these alternate suppliers fail to deliver power to their
customers located in the EUOC's service areas, the EUOC must procure replacement
power in the role of PLR (see Note 2(D) for discussion of the auction of JCP&L's
PLR obligation). The EUOC costs for any replacement power would be recovered
under the applicable state regulatory rules.
To meet these generation service obligations, our affiliates own and
operate 13,387 megawatts (MW) of installed generating capacity which for 2004 is
expected to provide approximately 75% of the power supply required. The balance
of the power supply expected to be required in 2004 has been secured through a
mix of long-term purchases (term of contract greater than one year) and
short-term purchases (term of contract less than one year). Changes in power
supply requirements will be met through spot market transactions.
Davis-Besse Restoration
On April 30, 2002, the Nuclear Regulatory Commission (NRC) initiated
a formal inspection process at the Davis-Besse nuclear plant. This action was
taken in response to corrosion found by FirstEnergy Nuclear Operating Company
(FENOC) in the reactor vessel head near the nozzle penetration hole during a
refueling outage in the first quarter of 2002. The purpose of the formal
inspection process is to establish criteria for NRC oversight of the licensee's
performance and to provide a record of the major regulatory and licensee actions
taken, and technical issues resolved, leading to the NRC's approval of restart
of the plant.
Restart activities include both hardware and management issues. In
addition to refurbishment and installation work at the plant, we made
significant management and human performance changes with the intent of
re-establishing the proper safety culture throughout the workforce. Work was
completed on the reactor head during 2002 and efforts continued in 2003 to focus
on design enhancements to the unit's reliability and performance. We also
accelerated maintenance work that had been planned for future refueling and
maintenance outages. We installed a state-of-the-art leak-detection system
around the reactor, as well as modified high-pressure injection pumps. Testing
of the bottom of the reactor for leaks was completed in October 2003 and no
indication of leakage was discovered. The focus of activities now involves
management and human performance issues. As a result, incremental maintenance
and capital expenditures declined in 2003 as emphasis shifted to performance
issues; replacement power costs were higher in 2003. We anticipate that
Davis-Besse will be ready for restart in the first quarter of 2004. The NRC must
authorize restart of the plant following its formal inspection process before
the unit can be returned to service. Delays in Davis-Besse's return to service
contributed to Standard & Poor's (S&P's) reduction in our credit rating in the
fourth quarter of 2003 (see Cash Flows from Financing Activities below).
Incremental costs associated with the extended Davis-Besse outage for
2003 and 2002 were as follows:
Costs of Davis-Besse Increase
Extended Outage 2003 2002 (Decrease)
-----------------------------------------------------------------------------
(In millions)
Incremental Expense
Replacement power.............. $196 $120 $ 76
Maintenance.................... 93 115 (22)
- ------------------------------------------------------------------------------
Total...................... $289 $235 $ 54
=============================================================================
Incremental Net of Tax Expense... $170 $138 $ 32
============================================================================
Capital Expenditures............. $ 21 $ 63 $(42)
=============================================================================
We anticipate spending $10 million in 2004 for remaining non-capital
restart activities, expected NRC inspection activities after Davis-Besse's
return to service and other related activities. No additional capital
expenditures related to the restoration are expected. Replacement power costs
are expected to be $15-20 million per month during the remaining period of the
outage. We have hedged the on-peak replacement energy supply for Davis-Besse for
the expected length of the outage. If there are significant delays in the NRC
approval process, replacement power costs will continue to be incurred,
adversely affecting FirstEnergy's cash flows and results of operations.
Power Outage
On August 14, 2003, various states in the northeast United States and
southern Canada experienced a widespread power outage. That outage affected
approximately 1.4 million customers in FirstEnergy's service area. FirstEnergy
continues to accumulate data and evaluate the status of its electrical system
prior to and during the outage event, and continues to cooperate with the
U.S.-Canada Power System Outage Task Force (Task Force) investigating the August
14th outage. The interim report issued by the Task Force on November 18, 2003
concluded that the problems leading up to the outage began in FirstEnergy's
service area. Specifically, the interim report concludes, among other
8
things, that the initiation of the August 14th outage resulted from the
coincidence on that afternoon of the following events: (1) inadequate
situational awareness at FirstEnergy; (2) FirstEnergy's failure to adequately
manage tree growth in its transmission rights of way; and (3) failure of the
interconnected grid's reliability organizations (Midwest ISO and PJM
Interconnection) to provide effective diagnostic support. We remain convinced
that the interim report does not provide a complete and comprehensive picture of
the conditions that contributed to the August 14th outage and that it does not
adequately address the underlying causes of the outage. We believe that the
outage cannot be explained by events on any one utility's system. On November
25, 2003, the PUCO ordered FirstEnergy to file a plan with the PUCO no later
than March 1, 2004, illustrating how FirstEnergy will correct problems
identified by the Task Force as events contributing to the August 14th outage
and addressing how FirstEnergy proposes to upgrade its control room computer
hardware and software and improve the training of control room operators to
ensure that similar problems do not occur in the future. The PUCO, in
consultation with the North American Electric Reliability Council, will review
the plan before determining the next steps in the proceeding. On December 24,
2003, the Federal Energy Regulatory Commission (FERC) ordered FirstEnergy to pay
for an independent study of part of Ohio's power grid. The study has commenced
and will examine the stability of the grid in critical points in the Cleveland
and Akron areas; the status of projected power reserves during summer 2004
through 2008; and the need for new transmission lines or other grid projects.
The FERC ordered the study to be completed within 120 days. At this time, we do
not know how the results of the study will impact FirstEnergy.
RESTATEMENTS AND RECLASSIFICATIONS
We filed an amended Form 10-K during 2003 to restate our consolidated
financial statements for the year ended December 31, 2002 to reflect a change in
the method of amortizing costs being recovered under the Ohio transition plan
and to recognize above-market liabilities of certain leased generation
facilities. In addition, the restated Consolidated Statement of Income for the
year ended December 31, 2002 reflects reclassifying the results of divested
businesses as discontinued operations (see Note 2(I)). Financial comparisons
described below reflect the effect of these restatements and reclassifications
of 2002 financial results. The 2001 results of the divested entities were not
significant and the 2001 Consolidated Statement of Income was not reclassified
to separately report discontinued operations.
MERGER WITH GPU
On November 7, 2001, the merger of FirstEnergy and GPU became
effective with FirstEnergy as the surviving company. The merger was accounted
for using purchase accounting under the guidelines of Statement of Financial
Accounting Standards No. (SFAS) 141, "Business Combinations." Under purchase
accounting, the results of operations for the combined entity are reported from
the point of consummation forward. As a result, our financial statements for
2001 reflect twelve months of operations for our pre-merger organization and
seven weeks of operations (November 7, 2001 to December 31, 2001) for the former
GPU companies. In 2003 and 2002, our financial statements include twelve months
of operations for both our pre-merger organization and the former GPU companies.
Additional goodwill resulting from the merger ($3.8 billion) as of December 31,
2003, is not being amortized, reflecting the application of SFAS 142, "Goodwill
and Other Intangible Assets." Goodwill is subject to review, at least annually,
for potential impairment (see Critical Accounting Policies - Goodwill). As a
result of the merger, we issued nearly 73.7 million shares of our common stock,
which are reflected in the calculation of earnings per share of common stock in
2003 and 2002 and for the seven-week period outstanding in 2001.
RESULTS OF OPERATIONS
Net Income and Earnings Per Share
Net income decreased to $423 million in 2003, compared to $553
million in 2002 and $646 million in 2001. Net income in 2003 and 2002 included
after-tax charges for discontinued operations of $101 million and $80 million,
respectively, or $0.33 and $0.27 per share (basic and diluted), primarily
reflecting losses on the sale or abandonment of remaining international
operations acquired through the merger with GPU (see Discontinued Operations
below). Results for 2003 also include an after-tax credit of $102 million from
the cumulative effect of an accounting change (basic and diluted earnings per
share of $0.33). The 2003 credit resulted from the January 2003 adoption of SFAS
143, "Accounting for Asset Retirement Obligations." Net income in 2001 also
included the cumulative effect of an accounting change resulting in a net
after-tax charge of $9 million (see Cumulative Effect of Accounting Change
below).
Major factors reducing net income in 2003, compared to 2002, included
the adverse impact from the JCP&L rate case decision to disallow costs of $109
million ($0.36 per share of common stock), a non-cash goodwill impairment charge
of $81 million ($0.27 per share of common stock), asset impairments of $47
million ($0.15 per share of common stock) and increased costs associated with
the Davis-Besse extended outage of $32 million ($0.09 per share of common
stock). Of the $81 million goodwill impairment charge, $3 million is included in
the net of tax loss from discontinued operations. Partially offsetting these
charges was a gain of $99 million or $0.33 per share of common stock
representing net proceeds from the settlement of our claim against NRG Energy,
Inc. NRG relating to the terminated sale of four fossil power plants.
9
On September 17, 2003, we completed the issuance and sale of 32.2
million shares of common stock (see Cash Flows from Financing Activities below)
which were included in the calculation of earnings per share on a weighted
average basis in 2003. The additional shares reduced earnings per share of
common stock by $0.04 (basic and diluted). If the shares had been outstanding
for the entire year, basic and diluted earnings would have been reduced by $0.13
per share of common stock.
FirstEnergy 2003 2002 2001
--------------------------------------------------------------------------------------
(In millions)
Total revenues.................................. $12,307 $12,047 $7,999
Income before interest and income taxes......... 1,640 2,115 1,685
Income before discontinued operations
and cumulative effect of accounting changes.. 422 633 655
Discontinued operations......................... (101) (80) --
Cumulative effect of accounting changes......... 102 -- (9)
--------------------------------------------------------------------------------------
Net Income...................................... 423 553 646
--------------------------------------------------------------------------------------
Basic Earnings Per Share:
Income before discontinued operations and
cumulative effect of accounting changes $1.39 $2.16 $2.85
Discontinued operations...................... (0.33) (0.27) --
Cumulative effect of accounting changes...... 0.33 -- (.03)
--------------------------------------------------------------------------------------
Net Income...................................... $1.39 $1.89 $2.82
======================================================================================
Diluted Earnings Per Share:
Income before discontinued operations and
cumulative effect of accounting changes $1.39 $2.15 $2.84
Discontinued operations...................... (0.33) (0.27) --
Cumulative effect of accounting changes...... 0.33 -- (0.03)
--------------------------------------------------------------------------------------
Net Income...................................... $1.39 $1.88 $2.81
======================================================================================
Unusual Items
Unusual charges (credits) included in income before discontinued
operations and the cumulative effect of accounting changes are summarized in the
following table:
Unusual Items (pre-tax) 2003 2002 2001
----------------------------------------------------------------------------------------------
(In millions)
Investment impairments................................... $ 56 $ 101 $ --
Regulatory assets disallowance - JCP&L................... 185 -- --
Lake plants transaction - net settlement proceeds........ (168) -- --
- depreciation & sales costs..... -- 29 --
Goodwill impairment...................................... 117 -- --
Environmental liability.................................. 15 -- --
Long-term derivative contract adjustment................. -- 18 --
Generation project cancellation.......................... -- 17 --
Severance costs.......................................... -- 11 --
Uncollectible reserve and contract losses................ -- -- 9
Early retirement costs................................... -- -- 9
Estimated claim settlement............................... -- 17 --
----------------------------------------------------------------------------------------------
Decrease in Pre-tax Earnings............................. $ 205 $ 193 $ 18
==============================================================================================
Reduction to earnings per share of common stock:
Basic.................................................... $0.47 $0.40 $0.05
Diluted.................................................. $0.47 $0.40 $0.05
10
Results of Operations - 2003 Compared With 2002
Sources of changes in total revenues are summarized in the
following table:
Increase
Sources of Revenue Changes 2003 2002 (Decrease)
---------------------------------------------------------------------------
(In millions)
Retail Electric Sales:
Regulated services................ $ 7,926 $ 8,229 $(303)
Competitive services.............. 566 348 218
Wholesale Electric Sales:
Regulated services................ 593 550 43
Competitive services.............. 1,182 570 612
- ---------------------------------------------------------------------------
Electric Sales...................... 10,267 9,697 570
Gas Sales........................... 624 613 11
Other Revenues:
Regulated - principally
transmission services........... 459 386 73
Competitive products and services. 886 964 (78)
International....................... 25 294 (269)
Other............................... 46 93 (47)
---------------------------------------------------------------------------
Total Revenues...................... $12,307 $12,047 $ 260
==========================================================================
Changes in electric generation sales and distribution deliveries in
2003 are summarized in the following table:
Increase
Changes in KWH Sales (Decrease)
------------------------------------------------------
Electric Generation Sales:
Retail -
Regulated services.................... (7.2)%
Competitive services.................. 53.0%
Wholesale............................... 40.2%
---------------------------------------------------
Total Electric Generation Sales........... 8.3%
===================================================
EUOC Distribution Deliveries:
Residential............................. (0.7)%
Commercial and industrial............... 0.3%
---------------------------------------------------
Total Distribution Deliveries............. --%
===================================================
Retail electric sales from our regulated services segment declined
principally due to increased sales by alternative suppliers in our franchise
areas. Alternative suppliers provided 21.8% of the total energy delivered to
retail customers in 2003, compared to 15.7% in 2002. As a result, generation
kilowatt-hour sales to retail customers of our regulated services were 7.2%
lower, which reduced retail electric sales revenues by $250 million. Additional
credits provided to customers under the Ohio transition plan to promote customer
shopping for alternative suppliers further reduced regulated retail electric
sales revenues by $45 million. The latter decreases in revenues are deferred for
future recovery under our Ohio transition plan and do not materially affect
current period earnings.
Revenues from distribution deliveries decreased $8 million with
kilowatt-hour deliveries to franchise customers unchanged in 2003. The slight
decrease in revenues resulted from additional distribution deliveries to the
commercial sector due to the strengthening in the service area economy toward
the end of 2003 which nearly offset a slight decline in distribution deliveries
to residential and industrial customers. Regulated retail revenues were reduced
by the New Jersey Board of Public Utilities (NJBPU) decision in July 2003 (see
State Regulatory Matters - New Jersey) that lowered JCP&L's base electric rates
effective August 1, 2003, on an annualized basis, by approximately $62 million.
Retail sales by our competitive services segment increased by $218
million as a result of a 53% increase in kilowatt-hour sales. That increase
primarily resulted from retail customers within our Ohio franchise areas
switching to FES under Ohio's electricity choice program and from growth in
competitive retail sales outside our franchise areas.
Revenues from the wholesale market increased significantly by $655
million and kilowatt-hour sales rose by 40%. A majority of the increase was due
to sales by our competitive services segment for a portion of New Jersey's BGS
requirements and sales in the spot market.
Higher electric sales revenues were more than offset by increased
fuel and purchased power costs. Purchased power costs increased by $889 million
due to higher unit costs and additional quantities purchased. Increased volumes
were required to supply obligations assumed by FES for BGS sales in New Jersey,
as well as other wholesale commitments, and additional supplies were required to
replace reduced nuclear generation (down 14%). Reduced nuclear generation output
resulted from additional refueling outage work performed at the Perry and Beaver
Valley plants
11
in 2003. Reported purchased power costs in 2003 also included $153 million of
power costs that were disallowed in the JCP&L rate case decision (see State
Regulatory Matters - New Jersey). Electric sales revenues net of fuel and
purchased power reduced income before interest and taxes by $328 million.
Other factors contributing to reduced income before interest and
taxes in 2003 include:
o Asset impairment charges of $56 million incurred in 2003
including a $26 million non-cash charge related to the
divestiture of our interest in Termobarranquilla S.A., Empresa
de Servicios Publicos (TEBSA), a Colombian electric generation
operation; a $13 million impairment on the monetization of the
note received from the sale of our 79.9% interest in Avon
Energy Partners Holding's (see Note 3); an additional $5 million
impairment upon the divestiture of our remaining interest in
Avon; and $12 million related to the disposition of Northeast
Ohio Natural Gas (see Note 2(I)) and the write down of our
investment in Pantellos, an internet business-to-business
marketplace serving the utility sector.
o A non-cash goodwill impairment charge of $117 million recorded
in the third quarter of 2003 reducing the carrying value of FSG.
This charge reflects the continued slow down in the development
of competitive retail markets and depressed economic conditions
that affect the value of FSG.
o Increased energy delivery costs of $86 million principally due
to storm restoration expenses and an accelerated reliability
program within JCP&L's service territory.
o Higher nuclear production costs of $54 million as a result of an
additional nuclear refueling outage in 2003 and unplanned work
performed during the refueling outages at the Perry Plant and
Beaver Valley Unit 1. The higher production costs were partially
offset by lower maintenance costs at the Davis-Besse Plant.
o Planned maintenance outages at three of our fossil generating
plants during the fourth quarter of 2003 increased non-nuclear
operating expenses by approximately $25 million.
o Increased postretirement plan expenses (see Postretirement Plans
below) offset in part by lower incentive compensation costs
contributed to a net cost increase of $94 million.
o Revenues less operating expenses for energy-related services
declined $17 million due to general declines associated with
economic conditions.
o An estimated environmental liability of $15 million was
recognized in the fourth quarter of 2003.
Partially offsetting these higher costs were three factors:
o A settlement of our claim against NRG for the terminated sale of
four fossil plants resulted in a $168 million gain.
o Charges for depreciation and amortization decreased by $17
million due to: higher shopping incentive deferrals under the
Ohio transition plan ($45 million), lower charges resulting from
the implementation of SFAS 143 ($61 million), revised service
life assumptions for nuclear generating plants ($28 million) and
reduced depreciation rates resulting from the JCP&L rate case
($18 million). Partially offsetting these decreases were higher
charges resulting from increased amortization of the Ohio
transition regulatory assets ($70 million), termination of tax
related deferrals in 2003 ($36 million), and costs disallowed in
the JCP&L rate case decision ($33 million).
o The absence of unusual charges recognized in 2002 resulted in
a further net reduction of other operating expenses ($181
million) in 2003.
Income before discontinued operations and the cumulative effect of
accounting changes decreased $211 million from the prior period. The change also
reflects reduced net interest charges ($146 million) and income taxes ($118
million), in addition to the changes discussed above. The decrease in interest
expenses reflects debt and preferred stock redemptions and financing activities
and the sale of our 79.9% interest in Avon in 2002. Redemption and refinancing
activities for debt and preferred stock aggregated approximately $2.582 billion
during 2003. Proceeds from the issuance of 32.2 million shares of common stock
in September 2003 accelerated the repayment of debt. The redemption and
refinancing activities and pollution control note repricings are expected to
result in annualized savings of $125 million. We also exchanged existing
fixed-rate payments on outstanding debt (notional amount of $1.15 billion at
year end 2003) for short-term variable rate payments through interest rate swap
transactions (see Market Risk Information - Interest Rate Swap Agreements
below). Net interest charges were reduced by $27 million in 2003 as a result of
these swaps. Counterparties called $594 million of our swaps during 2003
yielding total payments to FirstEnergy
12
of $20 million. Interest expense in 2003 was reduced $4 million due to
cancellation of the swaps related primarily to our unregulated generation
capacity.
Discontinued Operations
In 2003 and 2002, discontinued operations were reflected for GPU
Empresa Distribuidora Electrica Regional S.A. and affiliates (Emdersa) and
Empresa Guaracachi S.A. (EGSA), as we substantially completed our exit from
foreign operations acquired through the merger with GPU in 2001. In addition,
the results for the FSG subsidiaries, Colonial Mechanical, Webb Technologies and
Ancoma, Inc. and the MARBEL subsidiary, Northeast Ohio Natural Gas Corp., which
were divested in 2003, have been reported as discontinued operations for the
years 2003 and 2002. The following table summarizes the sources of losses from
discontinued operations:
Discontinued Operations (Net of tax) 2003 2002
------------------------------------------------------------------
(In millions)
Emdersa - Abandonment........................ $ (67) $ --
EGSA - Loss on sale.......................... (33) --
Ancoma - Loss on sale........................ (3) --
-----------------------------------------------------------------
Total losses.............................. (103) --
Reclassification of operating income (loss)..
to discontinued operations................ 2 (80)
------------------------------------------------------------------
Total........................................ $(101) $(80)
==================================================================
Cumulative Effect of Accounting Change
Results in 2003 include an after-tax credit to net income of $102
million recorded upon the adoption of SFAS 143 in January 2003 (see discussion
below). FirstEnergy identified applicable legal obligations as defined under the
new standard for nuclear power plant decommissioning, reclamation of a sludge
disposal pond at the Bruce Mansfield Plant and two coal ash disposal sites. As a
result of adopting SFAS 143 in January 2003, asset retirement costs of $602
million were recorded as part of the carrying amount of the related long-lived
asset, offset by accumulated depreciation of $415 million. The ARO liability at
the date of adoption was $1.107 billion, including accumulated accretion for the
period from the date the liability was incurred to the date of adoption. As of
December 31, 2002, FirstEnergy had recorded decommissioning liabilities of
$1.244 billion. FirstEnergy expects substantially all of its nuclear
decommissioning costs for Met-Ed, Penelec, JCP&L and Penn to be recoverable in
rates over time. Therefore, FirstEnergy recognized a regulatory liability of
$185 million upon adoption of SFAS 143 for the transition amounts related to
establishing the ARO for nuclear decommissioning for those companies. The
remaining cumulative effect adjustment for unrecognized depreciation and
accretion, offset by the reduction in the existing decommissioning liabilities
and the reversal of accumulated estimated removal costs for non-regulated
generation assets, was a $175 million increase to income, or $102 million net of
income taxes.
Earnings Effect of SFAS 143
The application of SFAS 143 (excluding the cumulative adjustment
described above) resulted in the following changes to expense categories and net
income in 2003:
Increase
Effect of SFAS 143 (Decrease)
----------------------------------------------------------------------
(In millions)
Other operating expense:
Cost of removal expenditures (previously included
in depreciation)...................................... $ 10
Depreciation:
Elimination of decommissioning expense.................. (89)
Depreciation of asset retirement cost................... 2
Accretion of asset retirement liability................. 42
Elimination of removal cost component................... (16)
------------------------------------------------------------------
Net decrease to depreciation............................ (61)
------------------------------------------------------------------
Income taxes............................................ 21
-----------------------------------------------------------------
Net income effect....................................... $ 30
=================================================================
13
Results of Operations - 2002 Compared With 2001
Net income in 2002 included an after-tax loss of $80 million for
discontinued operations. The loss primarily resulted from our divesting
ownership of Emdersa through the abandonment of our shares in the parent company
of the Argentina operation. We reclassified the results of Emdersa for the year
ended December 31, 2002, recording its after-tax loss as discontinued
operations. In the fourth quarter of 2002 we recognized a $50 million impairment
charge on our remaining 20.1% interest in Avon. Originally acquired as
part of the merger with GPU, we previously sold a 79.9% equity interest
in Avon to Aquila in May 2002.
As a result of our merger with GPU, results for 2002 include twelve
months of operations for the former GPU companies compared to only seven weeks
in 2001. The following table and related discussion excludes results for the
former GPU companies in the 2002 and 2001 periods in order to provide a
meaningful comparison.
Increase
FirstEnergy 2002 2001 (Decrease)
-------------------------------------------------------------------------------------------
(In millions)
Total revenues.............................. $7,235 $7,366 $(131)
Income before interest and income taxes..... 1,171 1,561 (390)
Income before discontinued operations and
cumulative effect of accounting change... 391 624 (233)
Discontinued operations..................... 2 -- 2
Cumulative effect of accounting change...... -- (9) 9
------------------------------------------------------------------------------------------
Net Income.................................. 393 615 (222)
------------------------------------------------------------------------------------------
Sources of changes in pre-merger revenues are summarized in the
following table:
Increase
Sources of Revenue Changes 2002 2001 (Decrease)
---------------------------------------------------------------------------------------------
(In millions)
Retail Electric Sales:
Regulated services .............................. $4,282 $4,610 $(328)
Competitive services.............................. 348 212 136
Wholesale Electric Sales:
Regulated services .............................. 319 303 16
Competitive services:
Nonaffiliated.................................. 570 430 140
Affiliated (former GPU companies).............. 378 33 345
------------------------------------------------------------------------------------------
Electric Sales...................................... 5,897 5,588 309
Gas Sales........................................... 613 792 (179)
Other Revenues:
Regulated - principally transmission services..... 248 246 2
Competitive products and services................. 477 740 (263)
------------------------------------------------------------------------------------------
Total Revenues...................................... $7,235 $7,366 $(131)
==========================================================================================
Changes in electric generation sales and distribution deliveries in
2002 for our pre-merger companies are summarized in the following table:
Increase
Changes in KWH Sales (Decrease)
---------------------------------------------
Electric Generation Sales:
Retail -
Regulated services............. (14.2)%
Competitive services........... 59.0%
Wholesale........................ 122.6%
--------------------------------------------
Total Electric Generation Sales.... 22.0%
============================================
EUOC Distribution Deliveries:
Residential...................... 6.3%
Commercial and industrial........ (3.2)%
--------------------------------------------
Total Distribution Deliveries...... (0.5)%
============================================
Retail electric sales from our regulated services segment declined
due in large part to increased sales by alternative suppliers in our franchise
areas (23.6% of total energy delivered in 2002 versus 11.3% in 2001). Generation
kilowatt-hour sales to retail customers were 14.2% lower in 2002 than the prior
year, which reduced retail electric sales revenues by $230 million.
14
Revenue from distribution deliveries decreased by $12 million or 0.4%
in 2002 compared to 2001. Kilowatt-hour deliveries to franchise customers were
lower due to a decline in kilowatt-hour deliveries to commercial and industrial
customers as a result of sluggish economic conditions, offset in part by higher
kilowatt-hour deliveries to residential customers primarily due to warmer summer
weather in 2002.
The remaining decrease in regulated retail electric sales revenues
resulted from additional transition plan incentives provided to customers to
promote customer shopping for alternative suppliers - $86 million of additional
credits. These reductions to revenues are deferred for future recovery under our
Ohio transition plan and do not materially affect current period earnings.
Retail sales by our competitive services segment increased by $136
million as a result of a 59% increase in kilowatt-hour sales. That increase
resulted from retail customers switching to FES, our unregulated subsidiary,
under Ohio's electricity choice program. The higher kilowatt-hour sales in Ohio
were partially offset by lower retail sales in markets outside of Ohio.
Revenues from the wholesale market increased $501 million in 2002
from 2001 as kilowatt-hour sales more than doubled. More than half of the
increase resulted from additional affiliated company sales by FES to Met-Ed and
Penelec. FES assumed the supply obligation in the third quarter of 2002 for a
portion of Met-Ed's and Penelec's PLR supply requirements (see State Regulatory
Matters - Pennsylvania). The increase also included sales into the New Jersey
market as an alternative supplier for a portion of New Jersey's BGS.
Reduced gas revenues resulted principally from lower prices combined
with a slight decline in sales volume. The elimination of coal trading
activities in the second half of 2001 also contributed to the reduction in other
competitive revenues along with reduced revenues from FSG primarily reflecting
the divestiture of Colonial Mechanical and Webb Technologies in early 2003.
Higher electric revenues were more than offset by increased fuel and
purchased power costs. Purchased power costs increased by $332 million due to
additional volumes to cover supply obligations assumed by FES. Fuel expense
increased $100 million principally due to additional internal generation (5.4%
higher) and an increased mix of higher cost coal and natural gas generation in
2002. The extended outage at the Davis-Besse nuclear plant produced a 15%
decline in nuclear generation. An increase in natural gas margins resulted from
purchased gas costs (i.e., lower unit costs) declining more than our gas sales
prices.
Higher other operating expenses also reduced income before interest
and income taxes. Nuclear operating costs increased $125 million primarily due
to $115 million of incremental Davis-Besse costs related to its extended outage
(see Davis-Besse Restoration). An aggregate increase in administrative and
general expenses and non-operating costs of $127 million resulted in large part
from higher employee benefit expenses.
FSG revenues, net of related expenses, reduced income before interest
and taxes by $13 million. A number of unusual charges further contributed to the
decrease as follows:
Increase
Unusual Charges -- Pre-Merger Companies (pre-tax) 2002 2001 (Decrease)
-------------------------------------------------------------------------------------------------
(In millions)
Investment impairments........................................ $ 48 $-- $48
Lake Plants - sales costs..................................... 17 -- 17
Long-term derivative contract adjustment...................... 18 -- 18
Generation project cancellation............................... 17 -- 17
Severance costs - 2002........................................ 11 -- 11
Uncollectible reserve and contract losses..................... -- 9 (9)
Early retirement costs - 2001................................. -- 9 (9)
Estimated claim settlement.................................... 5 -- 5
------------------------------------------------------------------------------------------------
$116 $18 $98
================================================================================================
Charges for depreciation and amortization increased $74 million. This
increase resulted from several factors: (1) higher amortization costs under the
Ohio transition plan; (2) higher depreciation from the start-up of a new
fluidized bed boiler in January 2002, owned by Bayshore Power Company, a wholly
owned subsidiary; (3) new combustion turbine capacity added in late 2001; and
(4) two months of 2001 depreciation ($12 million) recorded in 2002 (for the four
fossil plants we chose not to sell) increased depreciation expense in 2002.
However, two factors offset a portion of the above increase: shopping incentive
deferrals and tax deferrals under the Ohio transition plan ($109 million) and
the cessation of goodwill amortization ($56 million) beginning January 1, 2002.
General taxes increased $28 million principally due to additional
property taxes and the absence in 2002 of a benefit of $15 million resulting
from the successful resolution of certain property tax issues in the prior year.
15
Partially offsetting these higher costs were the elimination in the
second half of 2001 of coal trading activities ($95 million) and the reversal of
lease obligations related to the Bruce Mansfield fossil facility and Beaver
Valley nuclear facility which reduced other operating expenses by $85 million.
Income before discontinued operations and cumulative effect of
accounting changes decreased $233 million. The change reflects reduced net
interest charges ($62 million) and income taxes ($95 million) in addition to the
changes discussed above. Continued redemption and refinancing of our outstanding
debt and preferred stock during 2002, maintained our downward trend in financing
costs, before the effects of the merger with GPU. Excluding activities related
to the former GPU companies, redemption and refinancing activities for debt and
preferred stock aggregated approximately $1.2 billion during 2002 and is
expected to result in annualized savings of $86 million. We also exchanged
existing fixed-rate payments on outstanding debt (principal amount of $594
million at year end 2002) for short-term variable rate payments through interest
rate swap transactions (see Market Risk Information - Interest Rate Swap
Agreements below). Net interest charges for both pre-merger and post-merger
companies were reduced by $17 million in 2002 as a result of these swaps. The
related cash premiums will be recognized as a component of interest expense over
the remaining maturity of each respective hedged security. The effective tax
rate was 45.2% for 2002 compared to 42.0% in 2001. The increase in the effective
tax rate was primarily attributable to new Ohio Franchise and Municipal income
taxes implemented in 2002 as a result of Ohio Electric Restructuring.
Discontinued Operations
The divestiture of Colonial, Webb, Ancoma and Northeast Ohio Natural
Gas resulted in their revenues and expenses, with net after-tax earnings of $2
million, being reported as discontinued operations in 2002.
Cumulative Effect of Accounting Change
In 2001, we adopted SFAS 133 (as amended), "Accounting for Derivative
Instruments and Hedging Activities" resulting in a $9 million after-tax charge.
POSTRETIREMENT PLANS
Declines in equity markets in 2001 and 2002 and a reduction in our
assumed discount rate in 2002 have combined to produce a negative trend in
pension expenses. Also, increases in health care payments and a related increase
in projected trend rates have led to higher other postemployment benefits
(OPEB). The following table includes the portion of postretirement costs that
were expensed in 2003 and 2002.
Postretirement Expenses (Income) 2003 2002 Increase
-----------------------------------------------------------------
(In millions)
Pension........................ $123 $(14) $137
OPEB........................... 156 102 54
- ----------------------------------------------------------------
Total.......................... $279 $ 88 $191
================================================================
The following table presents the pre-tax pension and OPEB expenses
for 2002 and 2001 excluding the former GPU companies.
Postretirement Expenses (Income) 2002 2001 Increase
-----------------------------------------------------------------
(In millions)
Pension........................ $ 16 $(11) $27
OPEB........................... 99 87 12
- ----------------------------------------------------------------
Total.......................... $115 $ 76 $39
================================================================
The pension and OPEB expense increases are included in various cost
categories and have contributed to other cost increases discussed above. See
"Critical Accounting Policies - Pension and Other Postretirement Benefits
Accounting" for a discussion of the impact of underlying assumptions on
postretirement expenses.
PJM INTERCONNECTION TRANSACTIONS
Our subsidiaries record purchase and sales transactions with PJM
Interconnection ISO, an independent system operator, on a gross basis in
accordance with Emerging Issues Task Force (EITF) Issue No. 99-19, "Reporting
Revenue Gross as a Principal versus Net as an Agent." This gross basis
classification of revenues and costs may not be comparable to other energy
companies that operate in regions that have not established ISOs and do not meet
EITF 99-19 criteria.
The aggregate purchase and sales transactions for the three years
ended December 31, 2003, are summarized as follows:
16
2003 2002 2001
- ---------------------------------------------------------------
(In millions)
Sales............. $ 990 $453 $142
Purchases......... 1,019 687 204
--------------------------------------------------------------
Our revenues on the Consolidated Statements of Income include
wholesale electricity sales revenues from the PJM ISO for power sales (as
reflected in the table above) during periods when we had additional available
power for sale. Revenues also include our sales of power sourced from the PJM
ISO (reflected as purchases in the table above) during periods when we required
additional power to meet our retail load requirements and, secondarily, to sell
in the wholesale market.
RESULTS OF OPERATIONS - BUSINESS SEGMENTS
We manage our business as two separate major business segments -
regulated services and competitive services. The regulated services segment
operates and maintains our regulated domestic transmission and distribution
systems and also provides generation services to franchise customers who have
not chosen an alternative generation supplier. The Ohio Companies (OE, CEI and
TE) and Penn obtain generation through a power supply agreement with the
competitive services segment. The competitive services segment also supplies a
substantial portion of the PLR requirements for Met-Ed and Penelec through a
wholesale contract. The competitive services segment includes all competitive
energy and energy-related services including commodity sales (both electricity
and natural gas) in the retail and wholesale markets, marketing, generation,
trading and sourcing of commodity requirements, as well as other competitive
energy application services such as heating, ventilation and air-conditioning.
International operations, corporate support costs and interest costs on holding
company debt are included in the aggregate "other" segment (see Note 8 for
further discussion). Our two major business segments include all or a portion of
the following business entities:
o Regulated operations include the regulated sale of electricity
and distribution and transmission services by OE, CEI, TE, Penn,
JCP&L, Met-Ed, Penelec and ATSI.
o Competitive operations include the operation of generation
facilities owned by OE, CEI, TE and Penn, and all operations of
FES, FSG, MYR, MARBEL and First Communications.
Financial results discussed below include revenues and expenses from
transactions among our business segments. A reconciliation of segment financial
results to consolidated financial results is provided in Note 8 to the
consolidated financial statements. Net income (loss) by business segment was as
follows:
Net Income (Loss)
By Business Segment 2003 2002 2001
-----------------------------------------------------------------
(In millions)
Regulated services......... $ 986 $ 928 $729
Competitive services....... (210) (109) (32)
Other...................... (353) (266) (51)
------------------------------------------------------------------
Total...................... $ 423 $ 553 $646
===================================================================
Excluding the results associated with the former GPU companies,
comparable results for 2002 and 2001 are as follows:
Net Income (Loss)
By Business Segment 2002 2001
--------------------------------------------------
(In millions)
Regulated Services...... $ 560 $674
Competitive Services.... (114) (35)
Other................... (53) (24)
-------------------------------------------------
Total................... $ 393 $615
================================================
17
Regulated Services
2003 versus 2002:
Financial results for 2003 and 2002 include an entire year of
operations for the former GPU companies.
Increase
Regulated Services 2003 2002 (Decrease)
----------------------------------------------------------------------------------------
(In millions)
Total revenues............................... $10,070 $10,218 $(148)
Income before interest and income taxes....... 2,034 2,214 (180)
Income before cumulative effect of accounting
changes.................................... 885 928 (43)
Net Income.................................... 986 928 58
----------------------------------------------------------------------------------------
The change in operating revenues resulted from the following sources:
Increase
Sources of Revenue Changes 2003 2002 (Decrease)
----------------------------------------------------------------------
(In millions)
Electric:
External sales.......... $ 8,519 $ 8,779 $(260)
Internal sales.......... 777 741 36
-------------------------------------------------------------------
9,296 9,520 (224)
-------------------------------------------------------------------
Other:
External sales.......... 459 387 72
Internal sales.......... 315 311 4
-------------------------------------------------------------------
774 698 76
-------------------------------------------------------------------
Total Revenues............. $10,070 $10,218 $(148)
-------------------------------------------------------------------
External electric sales revenues declined $260 million, reflecting a
$303 million decrease in retail revenues partially offset by a $43 million
increase in sales to wholesale customers. The net decline in retail revenues
resulted from the following factors:
o Reduced generation sales revenue of $250 million on a 7.2%
reduction in kilowatt-hour sales (6.1 percentage point increase
in generation provided to customers by alternative suppliers);
o Additional reductions to revenues from increased credits of $45
million provided to customers to promote shopping for
alternative suppliers; and
o Lower revenues from distribution deliveries of $8 million.
The additional internal sales resulted from sales by the EUOC to FES.
Lower electric sales revenue due to reduced kilowatt-hour sales, an
increase in purchased power costs and higher energy delivery and other costs,
particularly employee benefit costs, combined to reduce income before interest
and taxes by $391 million. The increase of $86 million in energy delivery costs
was principally due to storm restoration expenses and an accelerated reliability
plan within JCP&L's service territory. Partially offsetting these factors were:
o Settlement of our claim against NRG for the terminated sale of
four fossil plants resulted in our recording a $168 million
pre-tax credit to earnings.
o Charges for depreciation and amortization decreased $25 million.
This decrease resulted from several factors: higher shopping
incentive deferrals under the Ohio transition plan, lower
charges resulting from the implementation of SFAS 143, revised
service life assumptions for nuclear generating plants and
reduced depreciation rates resulting from the JCP&L rate case.
Partially offsetting these decreases were increased charges
resulting from increased amortization of the Ohio transition
regulatory assets, termination of tax related deferrals in 2003,
and costs disallowed in the JCP&L rate case decision.
o The absence of unusual charges recognized in 2002 resulted in
a further net reduction of other operating expenses ($35
million) from last year.
2002 versus 2001:
Excluding the results associated with the former GPU companies,
comparable results for 2002 and 2001 are as follows:
18
Regulated Services (Pre-Merger) 2002 2001 (Decrease)
- -------------------------------------------------------------------------------
(In millions)
Total revenues........................... $5,870 $6,400 $(530)
Income before interest and income taxes.. 1,407 1,713 (306)
Net Income............................... 560 674 (114)
- ------------------------------------------------------------------------------
Lower generation sales, additional transition plan incentives and a
slight decline in revenue from distribution deliveries combined for a $312
million reduction in external revenues in 2002 from the prior year. Shopping by
Ohio customers from alternative energy suppliers together with the effect of a
sluggish national economy on our regional business reduced retail electric sales
revenues. In addition, a $188 million decline in revenues resulted from lower
sales to FES, due to the extended outage of the Davis-Besse nuclear plant, which
reduced generation available for sale.
A reduction in purchased power costs of $180 million reflects the
impact of the lower generation kilowatt-hour sales discussed above. Excluding
the net effect of lower electric revenues and purchased power, income before
interest and taxes increased $44 million. The increase was caused by reduced
operating costs ($114 million) offset in part by higher depreciation ($59
million) and general taxes ($11 million). The increase in depreciation resulted
from higher incremental transition costs partially offset by new deferred
regulatory assets under the Ohio transition plan and the cessation of goodwill
amortization beginning January 1, 2002.
Net income decreased $114 million. The change reflects decreased net
interest charges ($132 million) and reduced income taxes ($60 million) in
addition to the changes discussed above.
Competitive Services
2003 versus 2002:
Financial results for 2003 and 2002 include a full twelve months of
operations for the former GPU companies.
Increase
Competitive Services 2003 2002 (Decrease)
- --------------------------------------------------------------------------------
(In millions)
Total revenues................................ $5,402 $4,526 $ 876
Loss before interest and income tax benefit... (287) (154) (133)
Loss before discontinued operations and
cumulative effect of accounting changes.... (205) (111) (94)
Net loss...................................... (210) (109) (101)
- -------------------------------------------------------------------------------
The change in total revenues resulted from the following sources:
Increase
Sources of Revenue Changes 2003 2002 (Decrease)
- ------------------------------------------------------------------------
(In millions)
Electric:
External sales.............. $1,748 $ 918 $ 830
Internal sales.............. 2,168 2,044 124
- ---------------------------------------------------------------------
3,916 2,962 954
- ---------------------------------------------------------------------
Other External:
Natural Gas sales........... 624 613 11
Energy-related sales........ 766 904 (138)
Other....................... 96 47 49
- ---------------------------------------------------------------------
1,486 1,564 (78)
- ----------------------------------------------------------------------
Total Revenues................. $5,402 $4,526 $ 876
- ----------------------------------------------------------------------
The increase in external electric revenues resulted from:
o Retail sales increased by $218 million as a result of a 53%
increase in kilowatt-hour sales. The increase primarily resulted
from retail customers within our Ohio franchise areas switching
to FES under Ohio's electricity choice program and from growth
in competitive retail sales outside our franchise areas.
o Revenues from the wholesale market increased $612 million and
kilowatt-hour sales rose by 75%. The increase reflects sales as
an alternative supplier for a portion of New Jersey's BGS
requirements.
Internal electric revenues increased from sales by FES to the EUOC to
meet their energy requirements. Revenues from energy-related services declined
15% due to declines associated with weak economic conditions.
Electric revenue, net of purchased power costs and the absence of $69
million of unusual charges (representing the net of unusual charges in 2003 and
2002), contributed $185 million to income before interest and taxes. Offsetting
these increases were:
19
o Recognition of a non-cash goodwill impairment charge of $117
million (excluding amount in discontinued operations) in the
third quarter of 2003 reducing the carrying value of FSG. This
charge reflects the continued slow down in the development of
competitive retail markets and depressed economic conditions
that affect the value of FSG.
o Nuclear production costs increased $54 million as a result of an
additional nuclear refueling outage in 2003 and longer outages
involving additional maintenance work, offset in part by reduced
maintenance work at Davis-Besse.
o Planned maintenance outages at three of our fossil generating
plants during the fourth quarter of 2003 increased non-nuclear
operating expenses by approximately $25 million.
o Revenues less expenses for energy-related services declined $17
million due to declines associated with economic conditions.
o General taxes increased $15 million in 2003 compared to last
year. Higher payroll and kilowatt-hour taxes in 2003 were the
principal factors contributing to the increase.
o Higher depreciation and employee benefits costs also contributed
to the decrease in income before interest and taxes.
2002 versus 2001:
Excluding the results associated with the former GPU companies,
comparable results for 2002 and 2001 are as follows:
Increase
Competitive Services (Pre-Merger) 2002 2001 (Decrease)
----------------------------------------------------------------------------------------
(In millions)
Total revenues................................. $4,005 $3,948 $ 57
Loss before interest and income tax benefit.... (162) (27) (135)
Loss before discontinued operations and
cumulative effect of accounting changes..... (116) (26) (90)
Net loss....................................... (114) (35) (79)
---------------------------------------------------------------------------------------
The $57 million increase in revenues in 2002, compared to 2001, is
the net effect of several factors. Kilowatt-hour sales in the wholesale market
more than doubled in 2002, increasing revenues by $485 million. More than half
of the increase resulted from additional kilowatt-hour sales to Met-Ed and
Penelec to supply a portion of their PLR requirements in Pennsylvania, as well
as BGS sales in New Jersey and sales under several other contracts. Retail
revenues increased by $137 million as a result of additional kilowatt-hour sales
within Ohio under Ohio's electricity choice program. Total electric sales
revenue increased $622 million in 2002 from 2001, accounting for almost all of
the net increase in revenues. Offsetting the higher electric sales revenue were
reduced natural gas revenues ($179 million) primarily due to lower prices, and
less revenue from FSG ($213 million) reflecting its reclassification to
discontinued operations and the sluggish economy. Internal sales to the
regulated services segment decreased $180 million in large part due to the
impact of customer shopping reducing requirements by the regulated services
segment.
Higher electric revenues were nearly offset by increased fuel and
purchased power costs. Higher purchased power costs resulted from additional
volumes to cover supply obligations assumed by FES. Fuel costs increased in part
due to an increased mix of higher cost fossil generation in 2002. The extended
outage at the Davis-Besse nuclear plant produced a 15% decline in nuclear
generation. Lower purchased gas costs due to lower unit costs more than offset
reduced gas revenues resulting in an improvement in gas margins.
Nuclear operating costs increased $125 million primarily due to $115
million of incremental Davis-Besse costs related to its extended outage (see
Davis-Besse Restoration). A number of unusual charges discussed above increased
other expenses by $76 million in 2002.
Loss before discontinued operations and cumulative effect of
accounting changes increased $90 million. The change reflects increased net
interest charges ($20 million) and increased income tax benefit ($66 million),
as well as the changes discussed above.
The divestiture of Colonial, Webb, Ancoma and Northeast Ohio Natural
Gas resulted in their revenues and expenses, with net after-tax earnings of $2
million, being reported as discontinued operations in 2002.
20
Net income in 2001 also includes the cumulative effect of an
accounting change from the adoption of SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities" which resulted in an after-tax charge of $9
million.
CAPITAL RESOURCES AND LIQUIDITY
Changes in Cash Position
The primary source of ongoing cash for FirstEnergy, as a holding
company, is cash dividends from its subsidiaries. The holding company also has
access to $1.25 billion through revolving credit facilities. In 2003,
FirstEnergy received $864 million of cash dividends on common stock from its
subsidiaries and paid $453 million in cash dividends on common stock to its
shareholders. There are no material restrictions on the payments of cash
dividends by FirstEnergy's subsidiaries.
As of December 31, 2003, we had $114 million of cash and cash
equivalents, compared with $196 million as of December 31, 2002. Cash and cash
equivalents as of December 31, 2003 included $32 million received in December
2003 which was included in the NRG settlement claim sold in January 2004 (see
Note 3). Cash and cash equivalents as of December 31, 2002 included $50 million
used for the redemption of long-term debt in January 2003. The major sources for
changes in these balances are summarized below.
Cash Flows From Operating Activities
Our consolidated net cash from operating activities is provided by
our regulated and competitive energy services businesses (see Results of
Operations - Business Segments above). Net cash provided from operating
activities was $1.952 billion in 2003, $1.915 billion in 2002 and $1.282 billion
in 2001, summarized as follows:
Operating Cash Flows 2003 2002 2001
------------------------------------------------------------
(In millions)
Cash earnings (1).............. $1,829 $1,655 $1,294
Working capital and other...... 123 260 (12)
--------------------------------------------------------------
Total.......................... $1,952 $1,915 $1,282
=============================================================
(1) Includes net income, depreciation and amortization,
deferred income taxes, investment tax credits and major
noncash charges.
Net cash provided from operating activities increased $37 million in
2003 compared to 2002 due to a $174 million increase in cash earnings and a $137
million decrease from changes in working capital. Net cash from operating
activities in 2001 included seven weeks of results of the former GPU companies.
Excluding the former GPU companies, 2002 and 2001 cash flows from operating
activities totaled $1.464 billion and $1.572 billion, respectively, with the
decrease principally reflecting reduced cash earnings.
Cash Flows From Financing Activities
In 2003 and 2002, the net cash used for financing activities of
$1.322 billion and $1.123 billion, respectively, primarily reflects the
redemptions of debt and preferred stock shown below. The following table
provides details regarding new issues and redemptions during 2003 and 2002:
Securities Issued or Redeemed 2003 2002
------------------------------------------------------------------------
(In millions)
New Issues
Pollution Control Notes................. $ -- $ 143
Transition Bonds (See Note 5(H))........ -- 320
Secured Notes........................... 400 --
Unsecured Notes......................... 627 210
Other, principally debt discounts....... -- (4)
------------------------------------------------------------------------
$1,027 $ 669
Redemptions
First Mortgage Bonds.................... $1,483 $ 728
Pollution Control Notes................. 238 93
Secured Notes........................... 323 278
Unsecured Notes ........................ 85 189
Preferred Stock......................... 127 522
Other, principally redemption premiums.. -- 21
------------------------------------------------------------------------
$2,256 $1,831
Short-term Borrowings, Net....................... $ (575) $ 479
------------------------------------------------------------------------
21
Net cash used for financing activities increased by $199 million in
2003 as compared to 2002. The increase in funds used for financing activities
resulted from an increase in net redemptions of debt and preferred securities of
$1.1 billion partially offset by $934 million of common equity financing in
2003.
We had approximately $522 million of short-term indebtedness at the
end of 2003 compared to approximately $1.1 billion at the end of 2002. Available
borrowing capability as of December 31, 2003 included the following:
FirstEnergy
Borrowing Capability Holding Company OE TE Total
--------------------------------------------------------------------------------------
(In millions)
Long-Term Revolver.............. $ 875 $375 $ -- $1,250
Utilized........................ (270) (40) -- (310)
Letters of Credit............... (184) -- -- (184)
--------------------------------------------------------------------------------------
Net............................. 421 335 -- 756
-------------------------------------------------------------------------------------
Short-Term Facilities:
Revolver........................ 375 125 -- 500
Bank ........................... -- 34 70 104
-------------------------------------------------------------------------------------
375 159 70 604
Utilized:
Revolver........................ (280) -- -- (280)
Bank............................ -- (17) (70) (87)
--------------------------------------------------------------------------------------
Net............................. 95 142 -- 237
-------------------------------------------------------------------------------------
Amount Available................ $ 516 $477 $ -- $ 993
=====================================================================================
At the end of 2003, the Ohio companies and Penn had the aggregate
capability to issue approximately $3.1 billion of additional first mortgage
bonds (FMB) on the basis of property additions and retired bonds, although
unsecured senior note indentures entered into by OE and CEI in 2003 limit each
company's ability to issue secured debt, including FMBs, subject to certain
exceptions. JCP&L, Met-Ed and Penelec no longer issue FMB other than as
collateral for senior notes, since their senior note indentures prohibit them
(subject to certain exceptions) from issuing any debt which is senior to the
senior notes. As of December 31, 2003, JCP&L, Met-Ed and Penelec had the
aggregate capability to issue $339 million of additional senior notes using FMB
collateral. Based upon applicable earnings coverage tests in their respective
charters, OE, Penn, TE and JCP&L could issue a total of $2.8 billion of
preferred stock (assuming no additional debt was issued) as of the end of 2003.
CEI, Met-Ed and Penelec have no restrictions on the issuance of preferred stock
(see Note 5(E)) - Long-Term Debt for discussion of debt covenants).
In March 2003, we filed a registration statement with the U.S.
Securities and Exchange Commission covering securities in the aggregate of up to
$2 billion. The shelf registration provides the flexibility to issue and sell
various types of securities, including common stock, debt securities, and share
purchase contracts and related share purchase units. In September 2003, we used
approximately one-half of the amount available with a common stock issuance of
32.2 million shares at $30 per share for net proceeds of approximately $935
million.
At the end of 2003, our common equity as a percentage of
capitalization stood at 45% compared to 38% and 35% at the end of 2002 and 2001,
respectively. The higher common equity percentage in 2003 compared to 2001
reflects net redemptions of preferred stock and long-term debt, the issuance of
equity discussed above, and the increase in retained earnings.
In October 2003, FirstEnergy restructured its $1 billion 364-day
revolving credit facility through a syndicated bank offering that was completed
on October 23, 2003. The new syndicated FirstEnergy facilities consist of a $375
million 364-day revolving credit facility and a $375 million three-year
revolving credit facility. Also on October 23, 2003, OE entered into a
syndicated $125 million 364-day revolving credit facility and a syndicated $125
million three-year revolving credit facility. Combined with an existing
syndicated $500 million three-year facility for FirstEnergy, maturing in
November 2004, and an existing syndicated $250 million two-year facility for OE,
maturing in May 2005, FirstEnergy's primary syndicated credit facilities total
$1.75 billion. These facilities are intended to provide liquidity to meet the
short-term working capital requirements of FE and its subsidiaries. Available
borrowing capacity under existing facilities totaled $993 million at December
31, 2003.
Borrowings under these facilities are conditioned on FirstEnergy
and/or OE maintaining compliance with certain financial covenants in the
agreements. FirstEnergy, under its $375 million 364-day and $375 million
three-year facilities, and OE, under its $125 million 364-day and $250 million
two-year facilities, are each required to maintain a debt to total
capitalization ratio of no more than .65 to 1 and a contractually-defined fixed
charge coverage ratio of no less than 2 to 1. Under its $500 million three-year
facility, FirstEnergy is required to maintain a debt to total capitalization
ratio of no more than .69 to 1 and a contractually-defined fixed charge coverage
ratio for the most recent fiscal quarter of no less than 1.5 to 1. FirstEnergy
and OE are in compliance with all of these financial covenants. The ability to
draw on each of these facilities is also conditioned upon FirstEnergy or OE
making certain representations and warranties to the lending
22
banks prior to drawing on their respective facilities, including a
representation that there has been no material adverse change in its business,
its condition (financial or otherwise), its results of operations, or its
prospects.
None of FirstEnergy's or OE's primary credit facilities contain
provisions, whereby their ability to borrow would be restricted or denied, or
repayment of outstanding loans under the facilities accelerated, as a result of
any change in the credit ratings of FirstEnergy or OE by any of the
nationally-recognized rating agencies. Borrowings under each of the primary
facilities do contain "pricing grids", whereby the cost of funds borrowed under
the facilities is related to the credit ratings of the company borrowing the
funds.
Our regulated companies have the ability to borrow from each other
and the holding company to meet their short-term working capital requirements. A
similar but separate arrangement exists among our competitive companies.
FirstEnergy Service Company administers these two money pools and tracks surplus
funds of FirstEnergy and the respective regulated and competitive subsidiaries,
as well as proceeds available from bank borrowings. For the regulated companies,
available bank borrowings include $1.75 billion from FirstEnergy's and OE's
revolving credit facilities. For the competitive companies, available bank
borrowings include only the $1.25 billion of FirstEnergy's revolving credit
facility. Companies receiving a loan under the money pool agreements must repay
the principal amount of such a loan, together with accrued interest, within 364
days of borrowing the funds. For the regulated and competitive money pools, the
rate of interest is the same for each company receiving a loan from their
respective pool and is based on the average cost of funds available through the
pool. The average interest rate for borrowings in 2003 was 1.47% for the
regulated companies' pool and 1.90% for the competitive companies' pool.
Our access to capital markets and costs of financing are dependent on
the ratings of our securities. The following table shows our securities' ratings
following the downgrade by Moody's Investors Service in February 2004. The
ratings outlook on all securities is stable.
Ratings of Securities
- -------------------------------------------------------------------------------
Securities S&P Moody's Fitch
- -------------------------------------------------------------------------------
FirstEnergy Senior unsecured BB+ Baa3 BBB-
OE Senior secured BBB Baa1 BBB+
Senior unsecured BB+ Baa2 BBB
Preferred stock BB Ba1 BBB-
CEI Senior secured BBB- Baa2 BBB-
Senior unsecured BB+ Baa3 BB
Preferred stock BB Ba2 BB-
TE Senior secured BBB- Baa2 BBB-
Senior unsecured BB+ Baa3 BB
Preferred stock BB Ba2 BB-
Penn Senior secured BBB- Baa1 BBB+
Senior unsecured (1) BB+ Baa2 BBB
Preferred stock BB Ba1 BBB-
JCP&L Senior secured BBB Baa1 BBB+
Preferred stock BB Ba1 BBB
Met-Ed Senior secured BBB Baa1 BBB+
Penelec Senior secured BBB Baa1 BBB+
Senior unsecured BBB- Baa2 BBB
- ------------------------------------------------------------------------------
(1) Penn's only senior unsecured debt obligations are pollution control revenue
refunding bonds issued in the name of the Ohio Air Quality Development
Authority to which this rating applies.
On September 30, 2003, Fitch Ratings lowered the senior unsecured
ratings of FirstEnergy to "BBB-" from "BBB." Fitch also lowered the senior
secured, senior unsecured, and preferred stock ratings of Met-Ed, Penelec, CEI,
and TE. In addition, Fitch affirmed the ratings of OE, Penn and JCP&L. Fitch
announced that the Rating Outlook is Stable for the securities of FirstEnergy,
and all of the securities of its electric utility operating companies. Fitch
stated that the changes to the long-term ratings were "driven by the high debt
leverage of the parent, FirstEnergy. Despite management's commitment to reduce
debt related to the GPU merger, subsequent cash flows have been vulnerable to
unfavorable events, slowing the pace of FirstEnergy's debt reduction efforts.
The Stable Outlook reflects the success of FirstEnergy's recent common equity
offering and management's focus on a relatively conservative integrated utility
strategy."
On December 23, 2003, S&P lowered its corporate credit ratings on
FirstEnergy and its regulated utility subsidiaries to "BBB-" from "BBB" and
lowered FirstEnergy's senior unsecured debt rating to "BB+" from "BBB-". Except
23
for OE's senior secured issue rating, which was left unchanged, all other
subsidiary ratings were lowered one notch as well (see table above). The ratings
were removed from CreditWatch with negative implications, where they had been
placed by S&P on August 18, 2003, and the Ratings Outlook returned to Stable.
The rating action followed a revision in S&P's assessment of our consolidated
business risk profile to `6' from `5' (`1' equals low risk, `10' equals high
risk), with S&P citing operational and management challenges as well as
heightened regulatory uncertainty for its revision of our business risk
assessment score. S&P's rationale for its revisions in our ratings included
uncertainty regarding the timing of the Ohio Rate Plan filing (see State
Regulatory Matters), the pending final report on the August 14th power outage
(see Power Outage), the outcome of the remedial phase of litigation relating to
the Sammis plant (see Environmental Matters), and the extended Davis-Besse
outage and the related pending subpoena (see Davis-Besse Restoration). S&P
further stated that the restart of Davis-Besse and a supportive Ohio Rate Plan
extension will be vital positive developments that would aid an upgrade of
FirstEnergy's ratings. S&P's reduction of our credit ratings in December 2003
triggered cash and letter-of-credit collateral calls (see Guarantees and Other
Assurances below) in addition to higher interest rates for some outstanding
borrowings.
On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured
debt to Baa3 from Baa2 and downgraded the senior secured debt of JCP&L, Met-Ed
and Penelec to Baa1 from A2. Moody's also downgraded the preferred stock rating
of JCP&L to Ba1 from Baa2 and the senior unsecured rating of Penelec to Baa2
from A2. The ratings of OE, CEI, TE and Penn were confirmed. Moody's said that
the lower ratings were prompted by: "1) high consolidated leverage with
significant holding company debt, 2) a degree of regulatory uncertainty in the
service territories in which the company operates, 3) risks associated with
investigations of the causes of the August 2003 blackout, and related securities
litigation, and 4) a narrowing of the ratings range for the FirstEnergy
operating utilities, given the degree to which FirstEnergy increasingly manages
the utilities as a single system and the significant financial interrelationship
among the subsidiaries."
Cash Flows From Investing Activities
Net cash flows used in investing activities totaled $712 million in
2003. The net cash used for investing was principally for property additions.
Regulated services expenditures for property additions primarily include
expenditures supporting the distribution of electricity. Expenditures for
property additions by the competitive services segment are principally
generation-related, including $21 million for capital additions at the
Davis-Besse nuclear plant during its extended outage. The following table
summarizes 2003 investments by our regulated services and competitive services
segments:
Summary of 2003 Cash Flows Property
Used for Investing Activities Additions Investments Other Total
-----------------------------------------------------------------------------
Sources (Uses) (In millions)
Regulated Services............. $(434)(1) $(38)(3) $ 16 $(456)
Competitive Services........... (345)(2) 2 (4) (13) (356)
Other.......................... (77) 101 (5) 76 100
-----------------------------------------------------------------------------
Total..................... $(856) $ 65 $ 79 $(712)
=============================================================================
(1) Property additions primarily for transmission and distribution
facilities.
(2) Property additions to generation facilities.
(3) Net of several items from cash and other investments and Penelec's NUG
trust offset in part by investments in nuclear decommissioning trusts.
(4) Net proceeds from sale of assets.
(5) Proceeds from Aquila Note.
In 2002, net cash flows used in investing activities totaled $816
million, principally due to property additions ($998 million) which were
partially offset by proceeds from the sale of Midlands ($155 million).
Net cash used for investing activities decreased by $104 million in
2003 compared to 2002 primarily due to decreased capital expenditures partially
offset by net changes in nuclear decommissioning and NUG trust investments and
decreased proceeds from sale of assets.
Our cash requirements in 2004 for operating expenses, construction
expenditures, scheduled debt maturities and preferred stock redemptions are
expected to be met without increasing our net debt and preferred stock
outstanding. In addition, a refunding payment of $50 million was made to the NUG
trust fund (see State Regulatory Matters - Pennsylvania) in January 2004.
Available borrowing capacity under existing credit facilities will be used to
manage working capital requirements. Over the next three years, we expect our
cash requirements will be met with cash from operations and funds from the
capital markets, if needed.
Our capital spending for the period 2004-2006 is expected to be about
$2.3 billion (excluding nuclear fuel), of which approximately $713 million
applies to 2004. Investments for additional nuclear fuel during the 2004-2006
period
24
are estimated to be approximately $323 million, of which about $90
million applies to 2004. During the same period, our nuclear fuel investments
are expected to be reduced by approximately $285 million and $93 million,
respectively, as the nuclear fuel is consumed.
CONTRACTUAL OBLIGATIONS
Contractual Obligations
Our cash contractual obligations as of December 31, 2003 that we
consider firm obligations are as follows:
2005- 2007-
Contractual Obligations Total 2004 2006 2008 Thereafter
- ---------------------------------------------------------------------------------------------------------------
(In millions)
Long-term debt................... $11,471 $1,256 $1,964 $ 572 $ 7,679
Short-term borrowings............ 522 522 -- -- --
Preferred stock (1).............. 19 2 4 13 --
Capital leases (2)............... 24 6 10 2 6
Operating leases (2)............. 2,545 182 363 358 1,642
Pension funding (3).............. 835 -- 546 289 --
Purchases (4).................... 15,145 2,603 3,886 3,325 5,331
- --------------------------------------------------------------------------------------------------------------
Total........................ $30,561 $4,571 $6,773 $4,559 $14,658
==============================================================================================================
<FN>
(1) Subject to mandatory redemption.
(2) See Note 4.
(3) Amounts represent our estimate of the contributions necessary to maintain
our defined benefit pension plan's funding at a minimum required level as
determined by government regulations. Amounts are subject to change based
on the performance of the assets in the plan as well as the discount rate
used to determine the obligation. We are unable to estimate the projected
contributions beyond 2007.
(4) Fuel and power purchases under contracts with fixed or minimum quantities
and approximate timing.
</FN>
Guarantees and Other Assurances
As part of normal business activities, we enter into various
agreements on behalf of our subsidiaries to provide financial or performance
assurances to third parties. Such agreements include contract guarantees, surety
bonds, and letters of credit. Some contracts contain ratings contingent
collateralization provisions.
As of December 31, 2003, the maximum potential future payments under
outstanding guarantees and other assurances totaled approximately $1.9 billion,
as summarized below:
Maximum
Guarantees and Other Assurances Exposure
--------------------------------------------------------
(In millions)
FirstEnergy Guarantees of Subsidiaries
Energy and Energy-Related Contracts(1) ..... $ 857
Other (2)................................... 174
--------------------------------------------------------
1,031
Surety Bonds.................................. 161
Letters of Credit (3)(4)...................... 678
--------------------------------------------------------
Total Guarantees and Other Assurances....... $1,870
========================================================
(1) Issued for a one-year term, with a 10-day termination right by FirstEnergy.
(2) Issued for various terms.
(3) Includes letters of credit of $184 million issued for various terms under
letter of credit capacity available in FirstEnergy's revolving credit
agreement.
(4) Includes unsecured letters of credit of approximately $216 million pledged
in connection with the sale and leaseback of Beaver Valley Unit 2 by CEI
and TE (see Note 5 (E)), as well as collateralized letters of credit of
$278 million pledged in connection with the sale and leaseback of Beaver
Valley Unit 2 by OE (see Note 4).
We guarantee energy and energy-related payments of our subsidiaries
involved in energy marketing activities - principally to facilitate normal
physical transactions involving electricity, gas, emission allowances and coal.
We also provide guarantees to various providers of subsidiary financing
principally for the acquisition of property, plant and equipment. These
agreements legally obligate us and our subsidiaries to fulfill the obligations
of our subsidiaries directly involved in these energy and energy-related
transactions or financings where the law might otherwise limit the
counterparties' claims. If demands of a counterparty were to exceed the ability
of a subsidiary to satisfy existing
25
obligations, our guarantee enables the counterparty's legal claim to be
satisfied by our other assets. The likelihood that such parental guarantees will
increase amounts otherwise paid by us to meet our obligations incurred in
connection with ongoing energy and energy-related contracts is remote.
While these types of guarantees are normally parental commitments for
the future payment of subsidiary obligations, subsequent to the occurrence of a
credit rating-downgrade or "material adverse event" the immediate payment of
cash collateral or provision of a letter of credit may be required. The
following table summarizes collateral provisions as of December 31, 2003:
Collateral Paid
Total ---------------------------- Remaining
Collateral Provisions Exposure Cash Letters of Credit Exposure (1)
- --------------------------------------------------------------------------------
(In millions)
Rating downgrade...... $187 $68 $ 5 $114
Adverse event......... 235 -- 65 170
--------------------------------------------------------------------------
Total................. $422 $68 $70 $284
==========================================================================
(1) As of February 11, 2004, we had a remaining exposure of $282
million with $106 million of cash and $87 million of letters of
credit provided as collateral.
Most of our surety bonds are backed by various indemnities common
within the insurance industry. Surety bonds and related guarantees provide
additional assurance to outside parties that contractual and statutory
obligations will be met in a number of areas including construction contracts,
environmental commitments and various retail transactions.
We have guaranteed the obligations of the operators of the TEBSA
project, up to a maximum of $6.0 million (subject to escalation) under the
project's operations and maintenance agreement. In connection with the sale of
TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss
under this guarantee. We have provided the TEBSA project lenders a $50 million
letter of credit (LOC) (under our existing $250 million LOC capacity available
as part of our $1.25 billion credit facilities) to obtain TEBSA lender consent
as substitute collateral for the release of the assets for us to abandon our
Argentina operations, Emdersa (see Note 3). In December 2003, a replacement LOC
was issued in the amount of $60 million, which is renewable and declines yearly
based upon the senior outstanding debt of TEBSA. This LOC granted us the ability
to sell our remaining 20.1% interest in Avon, as well as abandon the Argentina
assets in April 2003.
OFF-BALANCE SHEET ARRANGEMENTS
We have obligations that are not included on our Consolidated Balance
Sheets related to the sale and leaseback arrangements involving Perry Unit 1,
Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are reflected as part
of the operating lease payments disclosed above (see Notes 4 and 9). The present
value of these sale and leaseback operating lease commitments, net of trust
investments, total $1.4 billion as of December 31, 2003.
CEI and TE sell substantially all of their retail customer
receivables to Centerior Funding Corporation (CFC), a wholly owned subsidiary of
CEI. CFC subsequently transfers the receivables to a trust (a "qualified special
purpose entity)" under SFAS 140, "Accounting for Transfers and Servicing of
Financial Assets and Extinguishment of Liabilities," under an asset-backed
securitization agreement. This provided $200 million of off-balance sheet
financing as of December 31, 2003. See Note 2(C) for additional discussion about
this arrangement.
As of December 31, 2003, off-balance sheet arrangements include
certain statutory business trusts created by CEI, Met-Ed and Penelec to issue
trust preferred securities aggregating $285 million. These trusts were included
in the consolidated financial statements of FirstEnergy prior to adoption of
FASB Interpretation No. 46, "Consolidation of Variable Interest Entities", but
have subsequently been deconsolidated under "FIN 46R" (see Note 9 - New
Accounting Standards and Interpretations). This has not resulted in any change
in outstanding debt.
FirstEnergy has equity ownership interests in certain various
businesses that are accounted for using the equity method. There are no
undisclosed material contingencies related to these investments. Certain
guarantees that we do not expect to have a material current or future effect on
our financial condition, liquidity or results of operations are disclosed under
contractual obligations above.
MARKET RISK INFORMATION
We use various market risk sensitive instruments, including
derivative contracts, primarily to manage the risk of price and interest rate
fluctuations. Our Risk Policy Committee, comprised of executive officers,
exercises an independent risk oversight function to ensure compliance with
corporate risk management policies and prudent risk management practices.
26
Commodity Price Risk
We are exposed to market risk primarily due to fluctuations in
electricity, natural gas and coal prices. To manage the volatility relating to
these exposures, we use a variety of non-derivative and derivative instruments,
including forward contracts, options, futures contracts and swaps. The
derivatives are used principally for hedging purposes and, to a much lesser
extent, for trading purposes. Most of our non-hedge derivative contracts
represent non-trading positions that do not qualify for hedge treatment under
SFAS 133. The change in the fair value of commodity derivative contracts related
to energy production during 2003 is summarized in the following table:
Increase (Decrease) in the Fair Value of Derivative Contracts Non-Hedge Hedge Total
- --------------------------------------------------------------------------------------------------------
(In millions)
Change in the fair value of commodity derivative contracts
Outstanding net asset as of January 1, 2003........................ $ 54 $ 24 $ 78
Additions/Increase in value of existing contracts.................. 8 35 43
Change in techniques/assumptions................................... 9 -- 9
Settled contracts.................................................. (4) (47) (51)
- -------------------------------------------------------------------------------------------------------
Outstanding net asset as of December 31, 2003 (1).................. 67 12 79
- -------------------------------------------------------------------------------------------------------
Non-commodity net assets as of December 31, 2003:
Interest Rate Swaps (2)......................................... -- (6) (6)
- -------------------------------------------------------------------------------------------------------
Net Assets - Derivatives Contracts as of December 31, 2003 (3)..... $ 67 $ 6 $ 73
=======================================================================================================
Impact of Changes in Commodity Derivative Contracts (4)
Income Statement Effects (Pre-Tax)................................. $(13) $ -- $(13)
Balance Sheet Effects:
OCI (Pre-Tax)................................................... $ -- $(12) $(12)
Regulatory Liability............................................ $ 26 $ -- $ 26
<FN>
(1) Includes $61 million in non-hedge commodity derivative contracts which are offset by a
regulatory liability.
(2) Interest rate swaps are primarily treated as fair value hedges. Changes in derivative
values of the fair value hedges are offset by changes in the hedged debts' premium or
discount (see Interest Rate Swap Agreements below).
(3) Excludes $17 million of derivative contract fair value decrease, representing our 50% share
of Great Lakes Energy Partners, LLC.
(4) Represents the increase in value of existing contracts, settled contracts and changes in
techniques/ assumptions.
</FN>
Derivatives are included on the Consolidated Balance Sheet as of
December 31, 2003 as follows:
Non-Hedge Hedge Total
- -----------------------------------------------------------------------
(In millions)
Current-
Other Assets.................... $13 $ 2 $ 15
Other Liabilities................ (8) -- (8)
Non-Current-
Other Deferred Charges........... 62 14 76
Other Noncurrent Liabilities..... -- (10) (10)
----------------------------------------------------------------------
Net assets..................... $67 $ 6 $ 73
======================================================================
The valuation of derivative contracts is based on observable market
information to the extent that such information is available. In cases where
such information is not available, we rely on model-based information. The model
provides estimates of future regional prices for electricity and an estimate of
related price volatility. We use these results to develop estimates of fair
value for financial reporting purposes and for internal management decision
making. Sources of information for the valuation of commodity derivative
contracts by year are summarized in the following table:
Source of Information
- - Fair Value by Contract Year 2004 2005 2006 2007 Thereafter Total
- ----------------------------------------------------------------------------------------------------------
(In millions)
Prices actively quoted(1)............. $11 $ 1 $ -- $-- $-- $12
Other external sources(2)............. 15 10 -- -- -- 25
Prices based on models................ -- -- 10 9 23 42
- ---------------------------------------------------------------------------------------------------------
Total(3).......................... $26 $11 $10 $ 9 $23 $79
=========================================================================================================
<FN>
(1) Exchange traded.
(2) Broker quote sheets.
(3) Includes $61 million from an embedded option that is offset by a regulatory liability and does
not affect earnings.
</FN>
27
We perform sensitivity analyses to estimate our exposure to the market
risk of our commodity positions. A hypothetical 10% adverse shift in quoted
market prices in the near term on both our trading and nontrading derivative
instruments would not have had a material effect on our consolidated financial
position or cash flows as of December 31, 2003. We estimate that if energy
commodity prices experienced an adverse 10% change, net income for the next
twelve months would decrease by approximately $3 million.
Interest Rate Risk
Our exposure to fluctuations in market interest rates is reduced
since a significant portion of our debt has fixed interest rates, as noted in
the table below.
Comparison of Carrying Value to Fair Value
- ---------------------------------------------------------------------------------------------------------------------
There- Fair
Year of Maturity 2004 2005 2006 2007 2008 after Total Value
- ---------------------------------------------------------------------------------------------------------------------
(Dollars in millions)
Assets
Investments other than Cash
and Cash
Equivalents-Fixed Income... $326 $ 64 $ 82 $ 77 $ 57 $1,882 $ 2,488 $ 2,597
Average interest rate...... 7.5% 7.8% 7.8% 7.9% 7.7% 6.2% 6.6%
_____________________________________________________________________________________________________________________
Liabilities
- --------------------------------------------------------------------------------------------------------------------
Long-term Debt and Other
Long-Term Obligations:
Fixed rate (1)................ $986 $547 $1,377 $237 $335 $6,644 $10,126 $10,625
Average interest rate ..... 7.3% 7.3% 5.7% 6.6% 5.3% 6.7% 6.6%
Variable rate (1)............. $270 $ 40 $1,035 $ 1,345 $ 1,345
Average interest rate...... 2.4% 2.3% 2.3% 2.4%
Preferred Stock Subject to
Mandatory Redemption....... $ 2 $ 2 $ 2 $ 12 $ 1 $ 19 $ 19
Average dividend rate...... 7.5% 7.5% 7.5% 7.6% 7.4% 7.6%
Short-term Borrowings......... $522 $ 522 $ 522
Average interest rate...... 2.1% 2.1%
- ---------------------------------------------------------------------------------------------------------------------
<FN>
(1) Balances and rates do not reflect the fixed-to-floating interest rate swap agreements discussed below.
</FN>
We are subject to the inherent interest rate risks related to
refinancing maturing debt by issuing new debt securities. As discussed in Note 4
to the consolidated financial statements, our investments in capital trusts
effectively reduce future lease obligations, also reducing interest rate risk.
While fluctuations in the fair value of our Ohio EUOC decommissioning trust
balances will eventually affect earnings (affecting OCI initially) based on the
guidance provided by SFAS 115, our non-Ohio EUOC have the opportunity to recover
from customers the difference between the investments held in trust and their
decommissioning obligations. Thus, there is not expected to be an earnings
effect from fluctuations in their decommissioning trust balances. As of December
31, 2003, decommissioning trust balances totaled $1.352 billion, with $797
million held by our Ohio EUOC and the balance held by our non-Ohio EUOC. As of
year end 2003, trust balances of our Ohio EUOC included 62% of equity securities
and 38% of debt instruments.
Interest Rate Swap Agreements
We have entered into various fixed-to-floating interest rate swap
agreements, as part of our ongoing effort to manage the interest rate risk of
our debt portfolio. These derivatives are treated as fair value hedges of
fixed-rate, long-term debt issues - protecting against the risk of changes in
the fair value of fixed-rate debt instruments due to lower interest rates. Swap
maturities, call options, fixed interest rates and interest payment dates match
those of the underlying obligations. Reductions to interest expense recorded in
2003 and 2002 due to the difference between fixed and variable debt rates
totaled $27 million and $17 million, respectively. As of December 31, 2003, the
debt underlying the interest rate swaps had a weighted average fixed interest
rate of 5.39%, which the swaps have effectively converted to a current weighted
average variable interest rate of 2.06%. GPU Power (through a subsidiary) used
existing dollar-denominated interest rate swap agreements in 2003. The swaps
convert variable-rate debt to fixed-rate debt to manage the risk of increases in
variable interest rates. GPU Power's swaps had a weighted average fixed interest
rate of 6.68% in 2003 and 2002. The following summarizes the principal
characteristics of the swap agreements:
28
December 31, 2003 December 31, 2002
----------------------------- ------------------------------
Notional Maturity Fair Notional Maturity Fair
Interest Rate Swaps Amount Date Value Amount Date Value
--------------------------------------------------------------------------------------------
(Dollars in millions)
Fixed to Floating Rate
(Fair value hedges) $200 2006 $ 1
50 2008 --
100 2010 1
100 2011 1
350 2013 (1)
150 2015 (10)
150 2018 1
50 2019 1
-- -- -- $444 2023 $16
-- -- -- 150 2025 6
Floating to Fixed Rate*
(Cash flow hedges) $ 7 2005 $ -- $ 16 2005 $(1)
---------------------------------------------------------------------------------------------
<FN>
* FirstEnergy no longer had the cash flow hedges as of January 30, 2004 as a result of GPU Power
divestiture (see Note 3).
</FN>
Equity Price Risk
Included in nuclear decommissioning trusts are marketable equity
securities carried at their market value of approximately $779 million and $532
million as of December 31, 2003 and 2002, respectively. A hypothetical 10%
decrease in prices quoted by stock exchanges, would result in a $78 million
reduction in fair value as of December 31, 2003 (see Note 2(M) - Cash and
Financial Instruments).
Foreign Currency Risk
Due to the disposition of foreign operations, we are no longer
exposed to foreign currency risk from investments in international business
operations. In 2002, we experienced net foreign currency translation losses in
connection with our Argentina operations (see Note 3 - Divestitures).
CREDIT RISK
Credit risk is the risk of an obligor's failure to meet the terms of
any investment contract, loan agreement or otherwise perform as agreed. Credit
risk arises from all activities in which success depends on issuer, borrower or
counterparty performance, whether reflected on or off the balance sheet. We
engage in transactions for the purchase and sale of commodities including gas,
electricity, coal and emission allowances. These transactions are often with
major energy companies within the industry.
We maintain stringent credit policies with respect to our
counterparties that management believes minimizes overall credit risk. This
includes performing independent risk evaluations, actively monitoring portfolio
trends and using collateral and contract provisions to mitigate exposure. As
part of our credit program, we aggressively manage the quality of our portfolio
of energy contracts evidenced by a current weighted risk S&P rating for energy
contract counterparties of "BBB." As of December 31, 2003, the largest credit
concentration to any counterparty was 8 percent - which is a currently rated
investment grade counterparty.
STATE REGULATORY MATTERS
In Ohio, New Jersey and Pennsylvania, laws applicable to electric
industry deregulation included similar provisions which are reflected in our
EUOC's respective state regulatory plans. However, despite these similarities,
the specific approach taken by each state and for each of our EUOCs varies.
Those provisions include:
o allowing the EUOC's electric customers to select their generation
suppliers;
o establishing PLR obligations to customers in the EUOC's service
areas;
o allowing recovery of transition costs (sometimes referred to
as stranded investment) not otherwise recoverable in a
competitive generation market;
o itemizing (unbundling) the price of electricity into its
component elements - including generation, transmission,
distribution and transition costs recovery charges;
o deregulating the electric generation businesses;
o continuing regulation of the EUOC's transmission and distribution
systems; and
29
o requiring corporate separation of regulated and unregulated
business activities.
Regulatory assets are costs which the respective regulatory agencies
have authorized for recovery from customers in future periods and, without such
authorization, would have been charged to income when incurred. All of the
regulatory assets are expected to continue to be recovered under the provisions
of the respective transition and regulatory plans as discussed below. The
regulatory assets of the individual companies are as follows:
Regulatory Assets
As of December 31 2003 2002 (Decrease)
---------------------------------------------------------------------------------------
(In millions)
OE....................................... $1,451 $1,787 $ (336)
CEI...................................... 1,056 1,145 (89)
TE....................................... 459 545 (86)
Penn..................................... 28 151 (123)
JCP&L.................................... 2,558 3,058 (500)
Met-Ed................................... 1,028 1,179 (151)
Penelec.................................. 497 600 (103)
--------------------------------------------------------------------------------------
Total.................................... $7,077 $8,465 $(1,388)
======================================================================================
Regulatory assets by source are as follows:
Regulatory Assets By Source Increase
As of December 31 2003 2002 (Decrease)
---------------------------------------------------------------------------------------
(In millions)
Regulatory transition charge............. $6,427 $7,608 $(1,181)
Customer shopping incentives............. 371 188 183
Customer receivables for future income
taxes.................................. 340 394 (54)
Societal benefits charge................. 81 144 (63)
Loss on reacquired debt.................. 75 74 1
Postretirement benefits.................. 77 88 (11)
Nuclear decommissioning,
decontamination and spent fuel
disposal costs......................... (96) 99 (195)
Asset removal costs...................... (321) (288) (33)
Property losses and unrecovered plant
costs.................................. 70 88 (18)
Other.................................... 53 70 (17)
---------------------------------------------------------------------------------------
Total.................................... $7,077 $8,465 $(1,388)
=======================================================================================
Ohio
FirstEnergy's transition plan for the Ohio EUOC included approval for
recovery of transition costs, including regulatory assets, 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; granting preferred access
over our subsidiaries to nonaffiliated marketers, brokers and aggregators, to
1,120 MW of generation capacity through 2005 at established prices for sales to
the Ohio EUOC's retail customers; and freezing customer prices through a
five-year market development period (2001-2005), except for certain limited
statutory exceptions including a 5% reduction in the price of generation for
residential customers. In February 2003, the Ohio EUOC were authorized increases
in 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.
Our 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. Subject to approval by the PUCO, recovery will be
accomplished by extending the respective transition cost recovery period.
On October 21, 2003, the Ohio EUOC filed an application with the PUCO
to establish generation service rates beginning January 1, 2006, in response to
expressed concerns by the PUCO about price and supply uncertainty following the
end of the market development period. The filing included two options:
o A competitive auction, which would establish a price for
generation that customers would be charged during the period
covered by the auction, or
o A Rate Stabilization Plan, which would extend current generation
prices through 2008, ensuring adequate generation supply at
stable prices, and continuing our support of energy efficiency
and economic development efforts.
Under the first option, an auction would be conducted to secure
generation service for our Ohio EUOC's customers. Beginning in 2006, customers
would pay market prices for generation as determined by the auction.
30
Under the Rate Stabilization Plan option, customers would have price
and supply stability through 2008 - three years beyond the end of the market
development period - as well as the benefits of a competitive market. Customer
benefits would include: customer savings by extending the current five percent
discount on generation costs and other customer credits; maintaining current
distribution base rates through 2007; market-based auctions that may be
conducted annually to ensure that customers pay the lowest available prices;
extension of our support of energy-efficiency programs and the potential for
continuing the program to give preferred access to nonaffiliated entities to
generation capacity if shopping drops below 20%. Under the proposed plan, we are
requesting:
o Extension of the transition cost amortization period for
OE from 2006 to 2007; for CEI from 2008 to 2009 and for TE from
mid-2007 to 2008;
o Deferral of interest costs on the accumulated shopping
incentives and other cost deferrals as new regulatory assets;
and
o Ability to initiate a request to increase generation rates under
certain limited conditions.
On January 7, 2004, the PUCO staff filed testimony on the proposed
rate plan generally supporting the Rate Stabilization Plan as opposed to the
competitive auction proposal. Hearings began on February 11, 2004. On February
24, 2004, after consideration of PUCO Staff comments and testimony as well as
those provided by some of the intervening parties, FirstEnergy made certain
modifications to the Rate Stabilization Plan. A decision is expected from the
PUCO in the Spring of 2004.
On November 25, 2003, the PUCO ordered FirstEnergy to file a plan
with the PUCO no later than March 1, 2004, illustrating how FirstEnergy will
address certain problems identified by the U.S.-Canada Power System Outage Task
Force (in connection with the August 14, 2003 regional power outage) and
addressing how FirstEnergy proposes to upgrade its control room computer
hardware and software, improve its control room training procedures and improve
the training of control room operators to ensure that similar problems do not
occur in the future. The PUCO, in consultation with the North American Electric
Reliability Council, will review the plan before determining the next steps in
the proceeding.
New Jersey
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. JCP&L's two August 2002 rate
filings requested increases in base electric rates of approximately $98 million
annually and requested the recovery of deferred energy costs that exceeded
amounts being recovered under the current market transition charge (MTC) and
societal benefits charge (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 (see Note 5(H)). On
July 25, 2003, the NJBPU announced its JCP&L base electric rate proceeding
decision which reduced JCP&L's annual revenues by approximately $62 million
effective August 1, 2003. The NJBPU decision also provided for an interim return
on equity of 9.5 percent on JCP&L's rate base for the next six to twelve months.
During that period, JCP&L will initiate another proceeding to request recovery
of additional costs incurred to enhance system reliability. In that proceeding,
the NJBPU could increase the return on equity to 9.75% or decrease it to 9.25%,
depending on its assessment of the reliability of JCP&L's service. Any reduction
would be retroactive to August 1, 2003. The revenue decrease in the decision
consists of a $223 million decrease in the electricity delivery charge, a $111
million increase due to the August 1, 2003 expiration of annual customer credits
previously mandated by the New Jersey transition legislation, a $49 million
increase in the MTC tariff component, and a net $1 million increase in the SBC
charge. The MTC allows for the recovery of $465 million in deferred energy costs
over the next ten years on an interim basis, thus disallowing $153 million of
the $618 million provided for in a preliminary settlement agreement between
certain parties. As a result, JCP&L recorded charges to net income for the year
ended December 31, 2003, aggregating $185 million ($109 million net of tax)
consisting of the $153 million deferred energy costs and other regulatory
assets. JCP&L filed a motion for rehearing and reconsideration with the NJBPU on
August 15, 2003 with respect to the following issues: (1) the disallowance of
the $153 million deferred energy costs; (2) the reduced rate of return on
equity; and (3) $42.7 million of disallowed costs to achieve merger savings. On
October 10, 2003, the NJBPU held the motion in abeyance until the final NJBPU
decision and order is issued. This is expected to occur in the first quarter of
2004.
On July 5, 2003, JCP&L experienced a series of 34.5 kilo-volt
sub-transmission line faults that resulted in outages on the New Jersey shore.
The NJBPU instituted an investigation into these outages, and directed that a
Special Reliability Master be hired to oversee the investigation. On December 8,
2003, the Special Reliability Master issued his Interim Report recommending that
JCP&L implement a series of actions to improve reliability in the area affected
by the outages. The NJBPU adopted the findings and recommendations of the
Interim Report on December 17, 2003, and ordered JCP&L to implement the
recommended actions on a staggered basis, with initial actions to be completed
by March 31, 2004. JCP&L expects to spend $12.5 million implementing these
actions during 2004.
31
Pennsylvania
In June 2001, the Pennsylvania Public Utility Commission (PPUC)
approved the Settlement Stipulation with all of the major parties in the
combined merger and rate proceedings which approved the FirstEnergy/GPU merger
and provided PLR deferred accounting treatment for energy costs, permitting
Met-Ed and Penelec to defer, for future recovery, energy costs in excess of
amounts reflected in their capped generation rates retroactive to January 1,
2001. This PLR deferral accounting procedure was later reversed in a February
2002 Commonwealth Court of Pennsylvania decision. The court decision affirmed
the PPUC decision regarding approval of the merger, remanding the decision to
the PPUC only with respect to the issue of merger savings. FirstEnergy
established reserves in 2002 for Met-Ed's and Penelec's PLR deferred energy
costs which aggregated $287.1 million, reflecting the potential adverse impact
of the then pending Pennsylvania Supreme Court decision whether to review the
Commonwealth Court decision. We recorded in 2002 an aggregate non-cash charge of
$55.8 million ($32.6 million net of tax) to income 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 April 2, 2003, the PPUC remanded the issue relating to merger
savings to the Office of Administrative Law Judge (ALJ) for hearings, directed
Met-Ed and Penelec to file a position paper on the effect of the Commonwealth
Court order on the Settlement Stipulation and allowed other parties to file
responses to the position paper. Met-Ed and Penelec filed a letter with the ALJ
on June 11, 2003, voiding the Stipulation in its entirety and reinstating
Met-Ed's and Penelec's restructuring settlement previously approved by the PPUC.
On October 2, 2003, the PPUC issued an order concluding that the
Commonwealth Court reversed the PPUC's June 20, 2001 order in its entirety. The
PPUC directed Met-Ed and Penelec to file tariffs within thirty days of the order
to reflect the competitive transition charge (CTC) rates and shopping credits
that were in effect prior to the June 21, 2001 order to be effective upon one
day's notice. In response to that order, Met-Ed and Penelec filed these
supplements to their tariffs to become effective October 24, 2003.
On October 8, 2003, Met-Ed and Penelec filed a petition for
clarification relating to the October 2, 2003 order on two issues: to establish
June 30, 2004 as the date to fully refund the NUG trust fund and to clarify that
the ordered accounting treatment regarding the CTC rate/shopping credit swap
should follow the ratemaking, and that the PPUC's findings would not impair
their rights to recover all of their stranded costs. On October 9, 2003, ARIPPA
(an intervenor in the proceedings) petitioned the PPUC to direct Met-Ed and
Penelec to reinstate accounting for the CTC rate/shopping credit swap
retroactive to January 1, 2002. Several other parties also filed petitions. On
October 16, 2003, the PPUC issued a reconsideration order granting the date
requested by Met-Ed and Penelec for the NUG trust fund refund and, denying
Met-Ed's and Penelec's other clarification requests and granting ARIPPA's
petition with respect to the retroactive accounting treatment of the changes to
the CTC rate/shopping credit swap. On October 22, 2003, Met-Ed and Penelec filed
an Objection with the Commonwealth Court asking that the Court reverse the
PPUC's finding that requires Met-Ed and Penelec to treat the stipulated CTC
rates that were in effect from January 1, 2002 on a retroactive basis. Met-Ed
and Penelec are considering filing an appeal to the Commonwealth Court on the
PPUC orders as well.
On October 27, 2003, one Commonwealth Court judge issued an Order
denying Met-Ed's and Penelec's objection without explanation. Due to the
vagueness of the Order, Met-Ed and Penelec, on October 31, 2003, filed an
Application for Clarification with the judge. Concurrent with this filing,
Met-Ed and Penelec, in order to preserve their rights, also filed with the
Commonwealth Court both a Petition for Review of the PPUC's October 16 and
October 22 Orders, and an application for reargument, if the judge, in his
clarification order, indicates that Met-Ed's and Penelec's objection was
intended to be denied on the merits. In addition to these findings, Met-Ed and
Penelec, in compliance with the PPUC's Orders, filed revised PPUC quarterly
reports for the twelve months ended December 31, 2001 and 2002, and for the
first two quarters of 2003, reflecting balances consistent with the PPUC's
findings in their Orders.
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 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 assumed the supply
obligation and the 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 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 a fixed price 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 on-peak obligation through 2004 and a portion of
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 current market prices.
In late 2003, the PPUC issued a Tentative Order implementing new
reliability benchmarks and standards. In connection therewith, the PPUC
commenced a rulemaking procedure to amend the Electric Service Reliability
Regulations to implement these new benchmarks, and create additional reporting
on reliability. Although neither the Tentative Order nor the Reliability
Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to
begin
32
filing quarterly reports on November 1, 2003. The comment period for both
the Tentative Order and the Proposed Rulemaking Order has closed. We are
currently awaiting the PPUC to issue a final order in both matters. The order
will determine (1) the standards and benchmarks to be utilized, and (2) the
details required in the quarterly and annual reports. It is expected that these
Orders will be finalized in March 2004.
On January 16, 2004, the PPUC initiated a formal investigation of
Met-Ed's, Penelec's and Penn's levels of compliance with the Public Utility Code
and the PPUC's regulations and orders with regard to reliable electric service.
Hearings will be held in August in this investigation and the ALJ has been
directed to issue a Recommended Decision by September 30, 2004, in order to
allow the PPUC time to issue a Final Order before December 16, 2004. We are
unable to predict the outcome of the investigation or the impact of the PPUC
Order.
FERC REGULATORY MATTERS
On December 19, 2002, the FERC granted unconditional Regional
Transmission Organization status to PJM Interconnection, LLC which includes
JCP&L, Met-Ed and Penelec as transmission owners. The FERC also conditionally
accepted GridAmerica's filing to become an independent transmission company
within Midwest Independent System Operator, Inc. (MISO). GridAmerica will
operate ATSI's transmission facilities. Effective October 1, 2003, MISO received
operational control of ATSI's transmission facilities. Transmission service over
the facilities of ATSI is now provided under the MISO Open Access Transmission
Tariff. A settlement of all rate matters related to ATSI's integration into MISO
was filed with the FERC on December 18, 2003 and has been certified to the
Commission as an uncontested settlement.
PJM and MISO were ordered by the FERC to develop a common market
between the regions by October 31, 2004. The FERC also initiated a Section 206
investigation into the reasonableness of the "through-and-out" transmission
rates charged by PJM and MISO. By order issued November 17, 2003, MISO, PJM and
certain unaffiliated transmission owners in the Midwest were directed to
eliminate rates for point-to-point service between the two RTOs effective April
1, 2004. A settlement judge has been appointed by the FERC to resolve compliance
filings by the affected transmission providers. AEP, Commonwealth Edison and
other utilities have appealed the FERC's November 17, 2003 order to the federal
court of appeals for the District of Columbia.
ENVIRONMENTAL MATTERS
We believe we are in material compliance with current sulfur dioxide
(SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act
Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized
regulations requiring additional NOx reductions from the Companies' Ohio and
Pennsylvania facilities. Various regulatory and judicial actions have since
sought to further define NOx reduction requirements (see Note 7(D) -
Environmental Matters). We continue to evaluate our compliance plans and other
compliance options.
Clean Air Act Compliance
Violations of federally approved SO2 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. We cannot predict what action the EPA may take in
the future with respect to the interim enforcement policy.
W. H. Sammis Plant
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. The NOV and complaint allege violations of the Clean Air Act based on
operation and maintenance of the W. H. Sammis Plant dating back to 1984. The
complaint requests permanent injunctive relief to require the installation of
"best available control technology" and civil penalties of up to $27,500 per day
of violation. On August 7, 2003, the United States District Court for the
Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis
Plant between 1984 and 1998 required pre-construction permits under the Clean
Air Act. The ruling concludes the liability phase of the case, which deals with
applicability of Prevention of Significant Deterioration provisions of the Clean
Air Act. The remedy phase, which is currently scheduled to be ready for trial
beginning July 19, 2004, will address civil penalties and what, if any, actions
should be taken to further reduce emissions at the plant. In the ruling, the
Court indicated that the remedies it "may consider and impose involved a much
broader, equitable analysis, requiring the Court to consider air quality, public
health, economic impact, and employment consequences. The Court may also
consider the less than consistent efforts of the EPA to apply and further
enforce the Clean Air Act." The potential penalties that may be imposed, as well
as the capital expenditures necessary to comply with substantive remedial
measures that may be required, could have a material adverse impact on the
Company's financial condition and results of operations. Management is unable to
predict the ultimate outcome of this matter and no liability has been accrued as
of December 31, 2003.
33
Regulation of Hazardous Waste
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 subsequently determined 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 EUOC 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, environmental liabilities that are considered probable have been
recognized on the Consolidated Balance Sheet as of December 31, 2003, 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 a non-bypassable societal benefits charge. The
Companies have total accrued liabilities aggregating approximately $65 million
as of December 31, 2003.
Climate Change
In December 1997, delegates to the United Nations' climate summit in
Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global
warming by reducing the amount of man-made greenhouse gases emitted by developed
countries by 5.2% from 1990 levels between 2008 and 2012. The United States
signed the Protocol in 1998 but failed to receive the two-thirds vote of the
U.S. Senate required for ratification. However, the Bush administration has
committed the United States to a voluntary climate change strategy to reduce
domestic greenhouse gas intensity - the ratio of emissions to economic output -
by 18% through 2012.
We cannot currently estimate the financial impact of climate change
policies although the potential restrictions on carbon dioxide (CO2) emissions
could require significant capital and other expenditures. However, the CO2
emissions per kilowatt-hour of electricity generated by FirstEnergy is lower
than many regional competitors due to FirstEnergy's diversified generation
sources which includes the low or non-CO2 emitting gas-fired and nuclear
generators.
OTHER LEGAL MATTERS
A number of legal and regulatory proceedings have been filed against
FirstEnergy in connection with, among other things, the restatements of
earnings, the August 14th regional outage described above, and the extended
outage at Davis-Besse, alleging violations of federal securities laws, breaches
of fiduciary duties by its directors and officers or damages as a result of one
or more of those events. All shareholder derivative actions filed in federal
court have been consolidated into one action, as have all federal securities
actions.Three tort actions seeking damages allegedly caused by the August 14th
power outage were filed in Ohio State court and were dismissed on jurisdictional
grounds. Two of those decisions have been appealed and the third case was
refiled at the PUCO. We were also named as a respondent in two regulatory
proceedings initiated at the PUCO in response to complaints alleging failure to
provide reasonable and adequate service. Two tort actions relating to the power
outage were preliminarily commenced in New York State court, but have not been
pursued to date. We intend to defend all of these actions vigorously, but cannot
predict the outcome of any of these proceedings or whether any further
regulatory proceedings or legal actions may be instituted against us. In
particular, if we were ultimately determined to have legal liability in
connection with any of these proceedings, it could have a material adverse
effect on our financial condition and results of operations.
FENOC recently received a subpoena from a grand jury sitting in the
United States District Court for the Northern District of Ohio, Eastern Division
requesting the production of certain documents and records relating to the
inspection and maintenance of the reactor vessel head at the Davis-Besse plant.
We are unable to predict the outcome of this investigation. In addition, FENOC
remains subject to possible civil enforcement action by the NRC in connection
with the events leading to the Davis-Besse outage. If it were ultimately
determined that FirstEnergy has legal liability or is otherwise made subject to
regulatory or civil enforcement action with respect to the Davis-Besse outage,
it could have a material adverse effect on FirstEnergy's financial condition and
results of operations.
CRITICAL ACCOUNTING POLICIES
We prepare our consolidated financial statements in accordance with
accounting principles that are generally accepted in the United States.
Application of these principles often requires a high degree of judgment,
estimates and assumptions that affect financial results. All of our assets are
subject to their own specific risks and uncertainties and are regularly reviewed
for impairment. Assets related to the application of the policies discussed
below are similarly reviewed with their risks and uncertainties reflecting these
specific factors. Our more significant accounting policies are described below.
34
Regulatory Accounting
Our regulated services segment is subject to regulation that sets the
prices (rates) it is permitted to charge its customers based on costs that the
regulatory agencies determine we are permitted to recover. At times, regulators
permit the future recovery through rates of costs that would be currently
charged to expense by an unregulated company. This rate-making process results
in the recording of regulatory assets based on anticipated future cash inflows.
As a result of the changing regulatory framework in each state in which we
operate, a significant amount of regulatory assets have been recorded - $7.1
billion as of December 31, 2003. We regularly review these assets to assess
their ultimate recoverability within the approved regulatory guidelines.
Impairment risk associated with these assets relates to potentially adverse
legislative, judicial or regulatory actions in the future.
Derivative Accounting
Determination of appropriate accounting for derivative transactions
requires the involvement of management representing operations, finance and risk
assessment. In order to determine the appropriate accounting for derivative
transactions, the provisions of the contract need to be carefully assessed in
accordance with the authoritative accounting literature and management's
intended use of the derivative. New authoritative guidance continues to shape
the application of derivative accounting. Management's expectations and
intentions are key factors in determining the appropriate accounting for a
derivative transaction and, as a result, such expectations and intentions are
documented. Derivative contracts that are determined to fall within the scope of
SFAS 133, as amended, must be recorded at their fair value. Active market prices
are not always available to determine the fair value of the later years of a
contract, requiring that various assumptions and estimates be used in their
valuation. We continually monitor our derivative contracts to determine if our
activities, expectations, intentions, assumptions and estimates remain valid. As
part of our normal operations, we enter into a significant number of commodity
contracts, as well as interest rate swaps, which increase the impact of
derivative accounting judgments.
Revenue Recognition
We follow the accrual method of accounting for revenues, recognizing
revenue for electricity that has been delivered to customers but not yet billed
through the end of the accounting period. The determination of unbilled revenues
requires management to make various estimates including:
o Net energy generated or purchased for retail load
o Losses of energy over transmission and distribution lines
o Mix of Kilowatt-hour usage by residential, commercial and
industrial customers
o Kilowatt-hour usage of customers receiving electricity from
alternative suppliers
Pension and Other Postretirement Benefits Accounting
Our reported costs of providing non-contributory defined pension
benefits and postemployment benefits other than pensions are dependent upon
numerous factors resulting from actual plan experience and certain assumptions.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions we make to the plans, and earnings on plan assets. Such factors
may be further affected by business combinations (such as our merger with GPU,
Inc. in November 2001), which impacts employee demographics, plan experience and
other factors. Pension and OPEB costs are also affected by changes to key
assumptions, including anticipated rates of return on plan assets, the discount
rates and health care trend rates used in determining the projected benefit
obligations for pension and OPEB costs.
Plan amendments to retirement health care benefits in 2003 and 2002,
related to changes in benefits provided and cost-sharing provisions, reduced
FirstEnergy's obligation by $123 million and $121 million, respectively. In
early 2004, FirstEnergy announced that it would amend the benefit provisions of
its health care benefits plan and both employees and retirees would share in
more of the benefit costs.
In accordance with SFAS 87, "Employers' Accounting for Pensions" and
SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions," changes in pension and OPEB obligations associated with these factors
may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
35
In selecting an assumed discount rate, we consider currently
available rates of return on high-quality fixed income investments expected to
be available during the period to maturity of the pension and other
postretirement benefit obligations. Due to recent declines in corporate bond
yields and interest rates in general, we reduced the assumed discount rate as of
December 31, 2003 to 6.25% from 6.75% and 7.25% used as of December 31, 2002 and
2001, respectively.
Our assumed rate of return on pension plan assets considers
historical market returns and economic forecasts for the types of investments
held by our pension trusts. In 2003, 2002 and 2001, plan assets actually earned
24.0%, (11.3)% and (5.5)%, respectively. Our pension costs in 2003 were computed
assuming a 9.0% rate of return on plan assets based upon projections of future
returns and our pension trust investment allocation of approximately 70%
equities, 27% bonds, 2% real estate and 1% cash.
As a result of the increased market value of our pension plan assets,
we reduced our minimum liability as prescribed by SFAS 87 as of December 31,
2003 by $253 million, recording a decrease of $6 million in an intangible asset
and crediting OCI by $145 million (offsetting previously recorded deferred tax
benefits by $102 million). The remaining balance in OCI of $299 million will
reverse in future periods to the extent the fair value of trust assets exceeds
the accumulated benefit obligation. The accrued pension cost was reduced to $438
million as of December 31, 2003.
Based on pension assumptions and pension plan assets as of December
31, 2003, we will not be required to fund our pension plans in 2004. However,
health care cost trends have significantly increased and will affect future OPEB
costs. Pension and OPEB expenses in 2004 are expected to decrease by $38 million
and $34 million, respectively. These reductions reflect the actual performance
of pension plan assets and amendments to the health care benefits plan announced
in early 2004 which result in employees and retirees sharing more of the benefit
costs. The reduction in OPEB costs for 2004 does not reflect the impact of the
new Medicare law signed by President Bush in December 2003 due to uncertainties
regarding some of its new provisions (see Note 2(K)). The 2003 and 2002
composite health care trend rate assumptions are approximately 10%-12% gradually
decreasing to 5% in later years. In determining our trend rate assumptions, we
included the specific provisions of our health care plans, the demographics and
utilization rates of plan participants, actual cost increases experienced in our
health care plans, and projections of future medical trend rates. The effect on
our pension and OPEB costs and liabilities from changes in key assumptions are
as follows:
Increase in Costs from Adverse Changes in Key Assumptions
---------------------------------------------------------
Assumption Adverse Change Pension OPEB Total
------------------------------------------------------------------------------------------------
(In millions)
Discount rate................ Decrease by 0.25% $ 10 $ 5 $ 15
Long-term return on assets... Decrease by 0.25% $ 8 $ 1 $ 9
Health care trend rate....... Increase by 1% na $ 26 $ 26
Increase in Minimum Liability
-----------------------------
Discount rate................ Decrease by 0.25% $104 na $104
----------------------------------------------------------------------------------------------
Ohio Transition Cost Amortization
In connection with FirstEnergy's restructuring plan, the PUCO
determined allowable transition costs based on amounts recorded on the
regulatory books of the Ohio electric utilities. These costs exceeded those
deferred or capitalized on FirstEnergy's balance sheet prepared under GAAP since
they included certain costs which have not yet been incurred or that were
recognized on the regulatory financial statements (fair value purchase
accounting adjustments). FirstEnergy uses an effective interest method for
amortizing its transition costs, often referred to as a "mortgage-style"
amortization. The interest rate under this method is equal to the rate of return
authorized by the PUCO in the transition plan for each respective company. In
computing the transition cost amortization, FirstEnergy includes only the
portion of the transition revenues associated with transition costs included on
the balance sheet prepared under GAAP. Revenues collected for the off-balance
sheet costs and the return associated with these costs are recognized as income
when received.
Long-Lived Assets
In accordance with SFAS 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," we periodically evaluate our long-lived assets
to determine whether conditions exist that would indicate that the carrying
value of an asset might not be fully recoverable. The accounting standard
requires that if the sum of future cash flows (undiscounted) expected to result
from an asset is less than the carrying value of the asset, an asset impairment
must be recognized in the financial statements. If impairment has occurred, we
recognize a loss - calculated as the difference between the carrying value and
the estimated fair value of the asset (discounted future net cash flows).
36
The calculation of future cash flows is based on assumptions,
estimates and judgement about future events. The aggregate amount of cash flows
determines whether an impairment is indicated. The timing of the cash flows is
critical in determining the amount of the impairment.
Nuclear Decommissioning
In accordance with SFAS 143, we recognize an ARO for the future
decommissioning of our nuclear power plants. The ARO liability represents an
estimate of the fair value of our current obligation related to nuclear
decommissioning and the retirement of other assets. A fair value measurement
inherently involves uncertainty in the amount and timing of settlement of the
liability. We used an expected cash flow approach (as discussed in FASB Concepts
Statement No. 7, "Using Cash Flow Information and Present Value in Accounting
Measurements") to measure the fair value of the nuclear decommissioning ARO.
This approach applies probability weighting to discounted future cash flow
scenarios that reflect a range of possible outcomes. The scenarios consider
settlement of the ARO at the expiration of the nuclear power plants' current
license and settlement based on an extended license term.
Goodwill
In a business combination, the excess of the purchase price over the
estimated fair values of the assets acquired and liabilities assumed is
recognized as goodwill. Based on the guidance provided by SFAS 142, we evaluate
goodwill for impairment at least annually and would make such an evaluation more
frequently if indicators of impairment should arise. In accordance with the
accounting standard, if the fair value of a reporting unit is less than its
carrying value (including goodwill), the goodwill is tested for impairment. When
impairment is indicated we recognize a loss - calculated as the difference
between the implied fair value of a reporting unit's goodwill and the carrying
value of the goodwill. Our annual review was completed in the third quarter of
2003. As a result of that review, a non-cash goodwill impairment charge of $122
million was recognized in the third quarter of 2003, reducing the carrying value
of FSG. Of this amount, $117 million is reported as an operating expense and $5
million is included, net of tax, in the loss from discontinued operations. The
impairment charge reflects the continued slow down in the development of
competitive retail markets and depressed economic conditions that affect the
value of FSG. The forecasts used in our evaluations of goodwill reflect
operations consistent with our general business assumptions. Unanticipated
changes in those assumptions could have a significant effect on our future
evaluations of goodwill. The impairment analysis includes a significant source
of cash representing the EUOC recovery of transition costs as described in Note
2(D). A summary of the changes in our goodwill for the twelve months ended
December 31, 2003 is shown below:
Segments
-----------------------
Regulated Competitive Total
--------- ----------- -----
(In millions)
Balance as of December 31, 2002...... $5,993 $ 285 $6,278
Impairment charges................... -- (122) (122)
FSG divestitures..................... -- (41) (41)
Other................................ -- 13 13
------ ------ ------
Balance as of December 31, 2003...... $5,993 $ 135 $6,128
====== ====== ======
NEW ACCOUNTING STANDARDS AND INTERPRETATIONS ADOPTED
FIN 46 (revised December 2003), "Consolidation of Variable Interest
Entities"
In December 2003, the FASB issued a revised interpretation of
Accounting Research Bulletin No. 51, "Consolidated Financial Statements",
referred to as FIN 46R, which requires the consolidation of a VIE by an
enterprise if that enterprise is determined to be the primary beneficiary of the
VIE. As required, FirstEnergy adopted FIN 46R for interests in VIEs or potential
VIEs commonly referred to as special-purpose entities effective December 31,
2003. We will adopt FIN 46R for all other types of entities effective March 31,
2004.
FirstEnergy currently has transactions with entities in connection
with sale and leaseback arrangements which fall within the scope of this
interpretation and which meet the definition of a VIE in accordance with FIN
46R. Upon adoption of FIN 46R effective December 31, 2003, FirstEnergy
consolidated the PNBV Capital Trust (PNBV) and the Shippingport Capital Trust
(Shippingport) which were created in 1996 and 1997, respectively, to refinance
debt in connection with sale and leaseback transactions. Consolidation of PNBV
changed the trust investment of $361 million to an investment in collateralized
lease bonds of $372 million. The $11 million increase represents the minority
interest in the total assets of the trust. Prior to the adoption of FIN 46R, the
assets and liabilities of Shippingport were included on a proportionate basis in
the financial statements of CEI and TE. Adoption of FIN 46R did not impact
FirstEnergy with respect to this trust, but did result in recording all of the
trust assets and liabilities on CEI's financial statements.
37
As described in Note 5(G), CEI, Met-Ed and Penelec created statutory
business trusts to issue trust preferred securities in the aggregate of $285
million. Application of the guidance in FIN 46R resulted in the holders of the
preferred securities being considered the primary beneficiaries of these trusts.
Therefore, FirstEnergy has deconsolidated the trusts and recognized an equity
investment in the trusts of $9 million ($3 million each for CEI, Met-Ed and
Penelec) and subordinated debentures to the trusts of $294 million ($103 million
for CEI, $96 million for Met-Ed and $95 million for Penelec) as of December 31,
2003.
In August 1995, Los Amigos Leasing Company, Ltd. (Los Amigos) was
formed as a consolidated subsidiary of GPU Power to own and lease to TEBSA
equipment comprised of an 895 megawatt plant constructed and operated by TEBSA.
Upon application of FIN 46R, Los Amigos met the criteria of a VIE and
FirstEnergy was determined not to be its primary beneficiary. Therefore,
effective December 31, 2003 Los Amigos was deconsolidated, resulting in the
removal of approximately $243 million of total assets (primarily unbilled lease
receivable) and liabilities (primarily senior and subordinated debt) from
FirstEnergy's Consolidated Balance Sheets. Los Amigos was sold as part of the
TEBSA divestiture on January 30, 2004.
We have evaluated numerous entities with which the Companies have
contractual, ownership, or other financial interests and we continue to evaluate
other entities that meet the deferral criteria and may be subject to
consolidation under FIN 46R as of March 31, 2004. See Note 9 for further
discussion of FIN 46R.
SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity"
In May 2003, the FASB issued SFAS 150, which establishes standards
for how an issuer classifies and measures certain financial instruments with
characteristics of both liabilities and equity. In accordance with the standard,
certain financial instruments that embody obligations for the issuer are
required to be classified as liabilities. SFAS 150 was effective immediately for
financial instruments entered into or modified after May 31, 2003 and effective
at the beginning of the first interim period beginning after June 15, 2003 for
all other financial instruments.
Upon adoption of SFAS 150, effective July 1, 2003, FirstEnergy
reclassified as debt the preferred stock of consolidated subsidiaries subject to
mandatory redemption with a carrying value of approximately $18.5 million ($5.0
million for CEI and $13.5 million for Penn) as of December 31, 2003. Adoption of
SFAS 150 had no impact on FirstEnergy's Consolidated Statements of Income
because the preferred dividends were previously included in net interest charges
and required no reclassification.
SFAS 143, "Accounting for Asset Retirement Obligations"
In January 2003, FirstEnergy implemented SFAS 143 which provides
accounting standards for retirement obligations associated with tangible
long-lived assets. This statement requires recognition of the fair value of a
liability for an asset retirement obligation in the period in which it is
incurred. See "Cumulative Effect of Accounting Change" and "Earnings Effect of
SFAS 143" discussed above and Notes 2(F) and 2(J) for further discussions of
SFAS 143.
38
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2003 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
(See Note 2(I))
(In thousands, except per share amounts)
REVENUES:
Electric utilities.................................................... $ 8,978,021 $ 9,165,805 $ 5,729,036
Unregulated businesses................................................ 3,329,026 2,881,543 2,270,326
----------- ------------ -----------
Total revenues.................................................... 12,307,047 12,047,348 7,999,362
----------- ------------ -----------
EXPENSES:
Fuel and purchased power.............................................. 4,567,859 3,670,844 1,421,525
Purchased gas......................................................... 586,799 587,860 820,031
Other operating expenses.............................................. 3,643,575 3,725,587 2,727,794
Provision for depreciation and amortization........................... 1,281,690 1,298,290 889,550
Goodwill impairment (Note 2(L))....................................... 116,988 -- --
General taxes......................................................... 638,465 649,898 455,340
----------- ------------ -----------
Total expenses.................................................... 10,835,376 9,932,479 6,314,240
----------- ------------ -----------
CLAIM SETTLEMENT (Note 3)................................................ 167,937 -- --
----------- ------------ -----------
INCOME BEFORE INTEREST AND INCOME TAXES.................................. 1,639,608 2,114,869 1,685,122
----------- ------------ -----------
NET INTEREST CHARGES:
Interest expense...................................................... 801,184 906,970 519,131
Capitalized interest.................................................. (31,900) (24,474) (35,473)
Subsidiaries' preferred stock dividends............................... 42,369 75,647 72,061
----------- ------------ -----------
Net interest charges.............................................. 811,653 958,143 555,719
----------- ------------ -----------
INCOME TAXES............................................................. 405,959 524,059 474,457
----------- ------------ -----------
INCOME BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE
EFFECT OF ACCOUNTING CHANGES.......................................... 421,996 632,667 654,946
Discontinued operations (net of income taxes (benefit) of ($1,499,000)
and $4,635,000, respectively) (Note 2(I))........................... (101,379) (79,863) --
Cumulative effect of accounting changes (net of income taxes (benefit) of
$72,516,000 and ($5,839,000), respectively) (Note 2(J))............. 102,147 -- (8,499)
----------- ------------ -----------
NET INCOME............................................................... $ 422,764 $ 552,804 $ 646,447
=========== ============ ===========
BASIC EARNINGS PER SHARE OF COMMON STOCK:
Income before discontinued operations and cumulative effect of accounting
changes............................................................. $1.39 $2.16 $ 2.85
Discontinued operations (Note 2(I))................................... (0.33) (0.27) --
Cumulative effect of accounting changes (Note 2(J))................... 0.33 -- (0.03)
----- ----- ------
Net income............................................................ $1.39 $1.89 $ 2.82
===== ===== ======
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING...................... 303,582 293,194 229,512
======= ======= =======
DILUTED EARNINGS PER SHARE OF COMMON STOCK:
Income before discontinued operations and cumulative effect of accounting
changes............................................................. $1.39 $2.15 $ 2.84
Discontinued operations (Note 2(I))................................... (0.33) (0.27) --
Cumulative effect of accounting changes (Note 2(J))................... 0.33 -- (0.03)
----- ----- ------
Net income............................................................ $1.39 $1.88 $ 2.81
===== ===== ======
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING.................... 304,972 294,421 230,430
======= ======= =======
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK............................. $1.50 $1.50 $1.50
===== ===== =====
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
39
FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
As of December 31, 2003 2002
- ---------------------------------------------------------------------------------------------------------------------
(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents......................................................... $ 113,975 $ 196,301
Receivables-
Customers (less accumulated provisions of $50,247,000 and $52,514,000
respectively, for uncollectible accounts)...................................... 1,000,259 1,153,486
Other (less accumulated provisions of $18,283,000 and $12,851,000
respectively, for uncollectible accounts)...................................... 505,241 469,606
Materials and supplies, at average cost-
Owned............................................................................ 325,303 253,047
Under consignment................................................................ 95,719 174,028
Prepayments and other.............................................................. 202,814 203,630
----------- -----------
2,243,311 2,450,098
PROPERTY, PLANT AND EQUIPMENT:
In service......................................................................... 21,594,746 20,372,224
Less--Accumulated provision for depreciation....................................... 9,105,303 8,264,075
---------- -----------
12,489,443 12,108,149
Construction work in progress...................................................... 779,479 859,016
----------- -----------
13,268,922 12,967,165
INVESTMENTS:
Nuclear plant decommissioning trusts............................................... 1,351,650 1,049,560
Investments in lease obligation bonds (Note 4)..................................... 989,425 1,079,435
Letter of credit collateralization (Note 4)........................................ 277,763 277,763
Other.............................................................................. 878,853 918,874
----------- -----------
3,497,691 3,325,632
DEFERRED CHARGES:
Regulatory assets.................................................................. 7,076,923 8,464,549
Goodwill........................................................................... 6,127,883 6,278,072
Other.............................................................................. 695,218 900,837
----------- -----------
13,900,024 15,643,458
$32,909,948 $34,386,353
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock............................... $ 1,754,197 $ 1,702,822
Short-term borrowings (Note 6)..................................................... 521,540 1,092,817
Accounts payable................................................................... 725,239 906,468
Accrued taxes...................................................................... 669,529 455,121
Lease market valuation liability................................................... 84,800 84,800
Other.............................................................................. 716,862 1,009,215
----------- -----------
4,472,167 5,251,243
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholders' equity........................................................ 8,289,341 7,050,661
Preferred stock of consolidated subsidiaries--
Not subject to mandatory redemption.............................................. 335,123 335,123
Subject to mandatory redemption.................................................. -- 18,521
Subsidiary-obligated mandatorily redeemable preferred securities................... -- 409,867
Long-term debt and other long-term obligations--
Preferred stock of consolidated subsidiaries subject to mandatory redemption..... 16,764 --
Subordinated debentures to affiliated trusts..................................... 294,324 --
Other............................................................................ 9,477,978 10,872,216
----------- -----------
18,413,530 18,686,388
NONCURRENT LIABILITIES:
Accumulated deferred income taxes.................................................. 2,178,075 2,069,682
Asset retirement obligations (Note 2(F))........................................... 1,179,493 --
Nuclear plant decommissioning costs................................................ -- 1,243,558
Power purchase contract loss liability............................................. 2,727,892 3,136,538
Retirement benefits................................................................ 1,591,006 1,564,930
Lease market valuation liability................................................... 1,021,000 1,105,800
Other.............................................................................. 1,326,785 1,328,214
----------- -----------
10,024,251 10,448,722
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Notes 4 and 7).............................
----------- -----------
$32,909,948 $34,386,353
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.
40
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31, 2003 2002
- ---------------------------------------------------------------------------------------------------------------------
(Dollars in thousands, except per share amounts)
COMMON STOCKHOLDERS' EQUITY:
Common stock, $0.10 par value - authorized 375,000,000 shares-
329,836,276 and 297,636,276 shares outstanding, respectively......................... $ 32,984 $ 29,764
Other paid-in capital.................................................................. 7,062,825 6,120,341
Accumulated other comprehensive loss (Note 5(I))....................................... (352,649) (656,148)
Retained earnings (Note 5(A)).......................................................... 1,604,385 1,634,981
Unallocated employee stock ownership plan common stock-
2,896,951 and 3,966,269 shares, respectively (Note 5(B))............................. (58,204) (78,277)
---------- ------------
Total common stockholders' equity.................................................... 8,289,341 7,050,661
---------- -----------
Number of Shares Optional
Outstanding Redemption Price
---------------- -----------------------
2003 2002 Per Share Aggregate
---- ---- --------- ---------
PREFERRED STOCK OF CONSOLIDATED
SUBSIDIARIES (Note 5(D)):
Ohio Edison Company
Cumulative, $100 par value-
Authorized 6,000,000 shares
Not Subject to Mandatory Redemption:
3.90%.............................. 152,510 152,510 $103.63 $ 15,804 15,251 15,251
4.40%.............................. 176,280 176,280 108.00 19,038 17,628 17,628
4.44%.............................. 136,560 136,560 103.50 14,134 13,656 13,656
4.56%.............................. 144,300 144,300 103.38 14,917 14,430 14,430
------- ------- -------- ------ ------
Total Not Subject to
Mandatory Redemption............... 609,650 609,650 $ 63,893 60,965 60,965
======= ======== ======== ------ ------
Pennsylvania Power Company
Cumulative, $100 par value-
Authorized 1,200,000 shares
Not Subject to Mandatory Redemption:
4.24%.............................. 40,000 40,000 103.13 $ 4,125 4,000 4,000
4.25%.............................. 41,049 41,049 105.00 4,310 4,105 4,105
4.64%.............................. 60,000 60,000 102.98 6,179 6,000 6,000
7.75%.............................. 250,000 250,000 100.00 25,000 25,000 25,000
------- ------- --------- ---------- --------
Total Not Subject to Mandatory
Redemption......................... 391,049 391,049 $ 39,614 39,105 39,105
======= ======= ========= ---------- ------
Subject to Mandatory Redemption (Note 5(F)):
7.625%*............................ -- 142,500 -- 14,250
Redemption Within One Year*.......... -- (750)
------- ------- ---------- ------
Total Subject to Mandatory Redemption* -- 142,500 -- 13,500
Cleveland Electric Illuminating Company
Cumulative, without par value-
Authorized 4,000,000 shares
Not Subject to Mandatory Redemption:
$ 7.40 Series A................... 500,000 500,000 101.00 $ 50,500 50,000 50,000
Adjustable Series L................ 474,000 474,000 100.00 47,400 46,404 46,404
------- ------- --------- ---------- -----------
Total Not Subject to Mandatory
Redemption......................... 974,000 974,000 $ 97,900 96,404 96,404
======= ======= ========= ========== ===========
Subject to Mandatory Redemption (Note 5(F)):
$ 7.35 Series C*.................. -- 60,000 -- 6,021
Redemption Within One Year*.......... -- (1,000)
------- ------- ---------- -----------
Total Subject to Mandatory Redemption* -- 60,000 -- 5,021
======= ======= ---------- -----------
41
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)
As of December 31, 2003 2002
- ---------------------------------------------------------------------------------------------------------------------
(Dollars in thousands, except per share amounts)
Number of Shares Optional
Outstanding Redemption Price
---------------- ------------------------
2003 2002 Per Share Aggregate
---- ---- --------- ---------
PREFERRED STOCK OF CONSOLIDATED SUBSIDIARIES (Cont'd)
Toledo Edison Company
Cumulative, $100 par value- Authorized 3,000,000 shares
Not Subject to Mandatory Redemption:
$ 4.25............................ 160,000 160,000 $104.63 $ 16,740 $ 16,000 $ 16,000
$ 4.56............................ 50,000 50,000 101.00 5,050 5,000 5,000
$ 4.25............................ 100,000 100,000 102.00 10,200 10,000 10,000
--------- --------- --------- --------- ---------
310,000 310,000 31,990 31,000 31,000
--------- --------- --------- --------- ---------
Cumulative, $25 par value-
Authorized 12,000,000 shares
Not Subject to Mandatory Redemption:
$2.365............................. 1,400,000 1,400,000 27.75 38,850 35,000 35,000
Adjustable Series A................ 1,200,000 1,200,000 25.00 30,000 30,000 30,000
Adjustable Series B................ 1,200,000 1,200,000 25.00 30,000 30,000 30,000
--------- --------- --------- --------- ---------
3,800,000 3,800,000 98,850 95,000 95,000
--------- --------- --------- --------- ---------
Total Not Subject to Mandatory
Redemption....................... 4,110,000 4,110,000 $ 130,840 126,000 126,000
========= ========= ========= --------- ---------
Jersey Central Power & Light Company
Cumulative, $100 stated value-
Authorized 15,600,000 shares
Not Subject to Mandatory Redemption:
4.00% Series....................... 125,000 125,000 106.50 $ 13,313 12,649 12,649
========= =========== ========= --------- ---------
SUBSIDIARY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY
TRUST OR LIMITED PARTNERSHIP HOLDING SOLELY SUBORDINATED DEBENTURES OF
SUBSIDIARIES (NOTE 5(G)):
Cleveland Electric Illuminating Co.
Cumulative, $25 stated value-
Authorized 4,000,000 shares
9.00%................................ -- 4,000,000 -- 100,000
========= =========== --------- ---------
Jersey Central Power & Light Co.
Cumulative, $25 stated value-
Authorized 5,000,000 shares
8.56%................................ -- 5,000,000 -- 125,244
========= =========== --------- ---------
Metropolitan Edison Co.
Cumulative, $25 stated value-
Authorized 4,000,000 shares
7.35%................................ -- 4,000,000 -- 92,409
========= =========== --------- ---------
Pennsylvania Electric Co.
Cumulative, $25 stated value-
Authorized 4,000,000 shares
7.34%................................ -- 4,000,000 -- 92,214
========= =========== --------- ---------
42
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)
LONG-TERM DEBT (Note 5(E)) (Interest rates reflect weighted average rates) (In thousands)
- -----------------------------------------------------------------------------------------------------------------------
FIRST MORTGAGE BONDS SECURED NOTES UNSECURED NOTES TOTAL
- -----------------------------------------------------------------------------------------------------------------------
As of December 31, 2003 2002 2003 2002 2003 2002 2003 2002
---- ---- ---- ---- ---- ---- ---- ----
Ohio Edison Co. -
Due 2003-2008 6.88% $ 80,000 $230,000 5.62% $ 227,761 $ 189,264 3.95% $526,725 $441,725
Due 2009-2013 -- -- -- 6.98% 2,752 2,753 -- -- --
Due 2014-2018 -- -- -- 5.01% 59,000 59,000 5.45% 150,000 --
Due 2019-2023 7.99% -- 219,460 7.01% 60,443 60,443 -- -- --
Due 2024-2028 -- -- -- 5.38% 13,522 13,522 -- -- --
Due 2029-2033 -- -- -- 3.10% 308,012 308,012 -- -- --
-------- -------- --------- --------- -------- -------- ---------- ----------
Total-Ohio Edison 80,000 449,460 671,490 632,994 676,725 441,725 $1,428,215 $1,524,179
-------- --------- --------- --------- -------- -------- ---------- ----------
Cleveland Electric
Illuminating Co. -
Due 2003-2008 6.86% 125,000 525,000 6.78% 470,905 680,205 5.58% 27,700 27,700
Due 2009-2013 -- -- -- 7.43% 151,580 151,580 5.72% 378,700 78,700
Due 2014-2018 -- -- -- 6.03% 412,630 300,000 -- -- --
Due 2019-2023 9.00% -- 150,000 6.67% 186,660 216,660 -- -- --
Due 2024-2028 -- -- -- 7.59% 148,843 148,843 -- -- --
Due 2029-2033 -- -- -- 1.45% 30,000 30,000 9.00% 103,093 --
-------- -------- --------- --------- -------- ------- --------- ----------
Total-Cleveland
Electric 125,000 675,000 1,400,618 1,527,288 509,493 106,400 2,035,111 2,308,688
-------- -------- --------- --------- -------- ------- --------- ----------
Toledo Edison Co. -
Due 2003-2008 7.88% 145,000 178,725 7.51% 100,000 229,700 4.88% 85,250 91,130
Due 2009-2013 -- -- -- -- -- -- 10.00% -- 730
Due 2019-2023 -- -- -- 7.92% 144,500 164,700 -- -- --
Due 2024-2028 -- -- -- 5.90% 13,851 13,851 -- -- --
Due 2029-2033 -- -- -- 1.43% 51,100 51,100 -- -- --
-------- -------- --------- --------- -------- ------- --------- ----------
Total-Toledo Edison 145,000 178,725 309,451 459,351 85,250 91,860 539,701 729,936
-------- -------- --------- ---------- -------- ------- --------- ----------
Pennsylvania Power Co. -
Due 2003-2008 6.88% 39,370 80,344 2.59% 10,300 10,300 3.40% 19,700 19,700
Due 2009-2013 9.74% 4,870 4,870 5.40% 1,000 1,000 -- -- --
Due 2014-2018 9.74% 4,870 4,870 4.00% 45,325 45,325 -- -- --
Due 2019-2023 8.37% 34,757 34,757 3.62% 27,182 27,182 -- -- --
Due 2024-2028 -- -- -- 5.79% 22,934 22,934 -- -- --
Due 2029-2033 -- -- -- 5.95% 238 238 -- -- --
-------- -------- --------- --------- -------- ------- --------- ----------
Total-Penn Power 83,867 124,841 106,979 106,979 19,700 19,700 210,546 251,520
-------- -------- --------- --------- -------- ------- --------- ----------
Jersey Central Power & Light Co. -
Due 2003-2008 7.01% 251,575 442,989 5.75% 217,336 241,135 7.69% 99 115
Due 2009-2013 7.13% 4,725 4,725 5.64% 130,024 130,024 7.69% 144 144
Due 2014-2018 7.10% 12,200 12,200 5.34% 248,841 98,841 7.69% 208 208
Due 2019-2023 7.75% 205,000 241,586 -- -- -- 7.69% 302 302
Due 2024-2028 7.18% 200,000 200,000 -- -- -- 7.69% 437 437
Due 2029-2033 -- -- -- -- -- -- 7.69% 633 633
Due 2034-2038 -- -- -- -- -- -- 7.69% 917 917
Due 2039-2043 -- -- -- -- -- -- 7.69% 228 228
-------- -------- --------- --------- -------- ------- --------- ----------
Total-Jersey Central 673,500 901,500 596,201 470,000 2,968 2,984 1,272,669 1,374,484
-------- -------- --------- --------- -------- ------- --------- ----------
Metropolitan Edison Co. -
Due 2003-2008 6.44% 128,265 208,700 5.79% 150,000 150,000 7.69% 199 230
Due 2009-2013 -- -- -- 4.75% 250,000 -- 7.69% 288 288
Due 2014-2018 -- -- -- -- -- -- 7.69% 417 417
Due 2019-2023 6.10% 28,500 208,500 -- -- -- 7.69% 603 604
Due 2024-2028 5.95% 13,690 13,690 -- -- -- 7.69% 874 874
Due 2029-2033 -- -- -- -- -- -- 7.69% 1,266 1,266
Due 2034-2038 -- -- -- -- -- -- 7.69% 1,834 1,834
Due 2039-2043 -- -- -- -- -- -- 7.98% 96,166 455
-------- -------- --------- --------- -------- ------- --------- ----------\
Total-Metropolitan
Edison 170,455 430,890 400,000 150,000 101,647 5,968 672,102 586,858
-------- -------- --------- --------- -------- ------- --------- ----------
43
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)
LONG-TERM DEBT (Interest rates reflect weighted average rates) (Cont'd) (In thousands)
- -----------------------------------------------------------------------------------------------------------------------------
FIRST MORTGAGE BONDS SECURED NOTES UNSECURED NOTES TOTAL
- -----------------------------------------------------------------------------------------------------------------------------
As of December 31, 2003 2002 2003 2002 2003 2002 2003 2002
---- ---- ---- ---- ---- ---- ---- ----
Pennsylvania Electric Co. -
Due 2003-2008 6.13% $ 3,700 $ 3,905 -- $ -- $ -- 5.86% $ 133,099 $ 133,115
Due 2009-2013 5.35% 24,310 24,310 -- -- -- 6.55% 135,144 135,144
Due 2014-2018 -- -- -- -- -- -- 7.69% 208 208
Due 2019-2023 5.80% 20,000 20,000 -- -- -- 6.63% 125,302 125,302
Due 2024-2028 6.05% 25,000 25,000 -- -- -- 7.69% 437 437
Due 2029-2033 -- -- -- -- -- -- 7.69% 633 633
Due 2034-2038 -- -- -- -- -- -- 7.69% 917 917
Due 2039-2043 -- -- -- -- -- -- 7.98% 95,748 228
----------- ---------- ---------- ---------- ---------- ---------- ----------- -----------
Total-Pennsylvania
Electric 73,010 73,215 -- -- 491,488 395,984 $ 564,498 $ 469,199
----------- ---------- ---------- ---------- ---------- ---------- ----------- -----------
FirstEnergy Corp. -
Due 2003-2008 -- -- -- -- -- -- 5.58% 1,570,000 1,695,000
Due 2009-2013 -- -- -- -- -- -- 6.45% 1,500,000 1,500,000
Due 2029-2033 -- -- -- -- -- -- 7.38% 1,500,000 1,500,000
---------- ---------- ---------- ---------- ---------- ---------- ----------- -----------
Total-FirstEnergy -- -- -- -- 4,570,000 4,695,000 4,570,000 4,695,000
---------- ---------- ---------- ---------- ---------- ---------- ----------- -----------
Bay Shore Power -- -- 6.24% 140,600 143,200 -- -- -- 140,600 143,200
Facilities Services Group -- -- 6.72% 7,754 13,205 -- -- -- 7,754 13,205
FirstEnergy Generation -- -- -- -- -- 5.00% 15,000 15,000 15,000 15,000
FirstEnergy Properties -- -- 7.89% 9,438 9,679 -- -- -- 9,438 9,679
Warrenton River Terminal -- -- 5.00% 410 634 -- -- -- 410 634
First Communications -- -- -- -- -- 6.21% 5,407 -- 5,407 --
GPU Capital -- -- -- -- -- 5.78% -- 101,467 -- 101,467
GPU Power -- -- 7.14% -- 174,760 11.87% -- 67,372 -- 242,132
---------- ---------- ---------- --------- ---------- ---------- ----------- -----------
Total $1,350,832 $2,833,631 $3,642,941 $3,688,090 $6,477,678 $5,943,460 11,471,451 12,465,181
========== ========== ========== ========== ========== ========== ----------- -----------
Preferred stock subject
to mandatory redemption*................................................................... 18,514 --
Capital lease obligations..................................................................... 13,313 15,761
Net unamortized premium on debt............................................................... 39,985 92,346
Long-term debt due within one year*........................................................... (1,754,197) (1,701,072)
----------- -----------
Total long-term debt*......................................................................... 9,789,066 10,872,216
----------- -----------
TOTAL CAPITALIZATION* $18,413,530 $18,686,388
- -----------------------------------------------------------------------------------------------------------------------------
* The December 31, 2003 balance for Preferred Stock subject to Mandatory Redemption is classified as debt under SFAS 150
(see Note 9).
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
44
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
Accumulated Unallocated
Other Other ESOP
Comprehensive Number Par Paid-In Comprehensive Retained Common
Income of Shares Value Capital Income (Loss) Earnings Stock
------------- --------- ------- ------- ------------- -------- -----------
(Dollars in thousands)
Balance, January 1, 2001........................ 224,531,580 $22,453 $3,531,821 $ 593 $1,209,991 $(111,732)
GPU acquisition.............................. 73,654,696 7,366 2,586,097
Net income................................... $646,447 646,447
Minimum liability for unfunded retirement
benefits, net of $(182,000) of income
taxes...................................... (268) (268)
Unrealized loss on derivative hedges, net
of $(116,521,000) of income taxes (169,408) (169,408)
Unrealized gain on investments, net of
$56,000 of income taxes.................... 81 81
Currency translation adjustments, net
of $(1,000) of income taxes................ (1) (1)
--------
Comprehensive income......................... $476,851
========
Reacquired common stock...................... (550,000) (55) (15,253)
Allocation of ESOP shares.................... 10,595 14,505
Cash dividends on common stock............... (334,633)
- ----------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2001...................... 297,636,276 29,764 6,113,260 (169,003) 1,521,805 (97,227)
Net income................................... $552,804 552,804
Minimum liability for unfunded retirement
benefits, net of $(316,681,000) of
income taxes............................... (449,615) (449,615)
Unrealized gain on derivative hedges, net
of $37,458,000 of income taxes. 59,187 59,187
Unrealized loss on investments, net of
$(3,796,000) of income taxes............... (5,269) (5,269)
Currency translation adjustments............. (91,448) (91,448)
---------
Comprehensive income......................... $ 65,659
========
Stock options exercised...................... (8,169)
Allocation of ESOP shares.................... 15,250 18,950
Cash dividends on common stock............... (439,628)
- ----------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2002...................... 297,636,276 29,764 6,120,341 (656,148) 1,634,981 (78,277)
Net income................................... $422,764 422,764
Minimum liability for unfunded retirement
benefits, net of $101,950,000 of
income taxes............................... 144,236 144,236
Unrealized loss on derivative hedges, net
of $(241,000) of income taxes.............. (347) (347)
Unrealized gain on investments, net of
$53,431,000 of income taxes................ 68,162 68,162
Currency translation adjustments. 91,448 91,448
--------
Comprehensive income......................... $726,263
========
Stock options exercised...................... (3,502)
Common stock issued.......................... 32,200,000 3,220 930,918
Allocation of ESOP shares.................... 15,068 20,073
Cash dividends on common stock............... (453,360)
- ----------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2003...................... 329,836,276 $32,984 $7,062,825 $(352,649) $1,604,385 $(58,204)
==================================================================================================================================
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
45
CONSOLIDATED STATEMENTS OF PREFERRED STOCK
Not Subject to Subject to
Mandatory Redemption Mandatory Redemption
-------------------- --------------------
Par or Par or
Number Stated Number Stated
of Shares Value of Shares Value
--------- ------ --------- -------
(Dollars in thousands)
Balance, January 1, 2001 12,324,699 $ 648,395 5,177,216 $ 246,571
GPU acquisition 125,000 12,649 13,515,001 365,151
Issues-
9.00% Series 4,000,000 100,000
Redemptions-
8.45% Series (50,000) (5,000)
$ 7.35 Series C (10,000) (1,000)
$88.00 Series R (50,000) (50,000)
$91.50 Series Q (10,716) (10,716)
$90.00 Series S (18,750) (18,750)
Amortization of fair market
value adjustments-
$ 7.35 Series C (11)
$88.00 Series R (1,128)
$90.00 Series S (668)
- --------------------------------------------------------------------------------
Balance, December 31, 2001 12,449,699 661,044 22,552,751 624,449
Redemptions-
7.75% Series (4,000,000) (100,000)
$7.56 Series B (450,000) (45,071)
$42.40 Series T (200,000) (96,850)
$8.32 Series (100,000) (10,000)
$7.76 Series (150,000) (15,000)
$7.80 Series (150,000) (15,000)
$10.00 Series (190,000) (19,000)
$2.21 Series (1,000,000) (25,000)
7.625% Series (7,500) (750)
$7.35 Series C (10,000) (1,000)
$90.00 Series S (17,750) (17,010)
8.65% Series J (250,001) (26,750)
7.52% Series K (265,000) (28,951)
9.00% Series (4,800,000) (120,000)
Amortization of fair market
value adjustments-
$ 7.35 Series C (9)
$90.00 Series S (258)
8.56% Series (6)
7.35% Series 209
7.34% Series 214
- --------------------------------------------------------------------------------
Balance, December 31, 2002 6,209,699 335,123 17,202,500 430,138
Redemptions-
7.625% Series (7,500) (750)
$7.35 Series C (10,000) (1,000)
8.56% Series (5,000,000) (125,242)
FIN 46 Deconsolidation-
9.00% Series (4,000,000) (100,000)
7.35% Series (4,000,000) (92,618)
7.34% Series (4,000,000) (92,428)
Amortization of fair market
value adjustments-
$ 7.35 Series C (7)
8.56% Series (2)
7.35% Series 209
7.34% Series 214
- --------------------------------------------------------------------------------
Balance, December 31, 2003 6,209,699 $335,123 185,000 $ 18,514*
================================================================================
* The December 31, 2003 balance for Preferred Stock subject to
mandatory redemption is classified as debt under SFAS 150 (see
Note 9).
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
46
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2003 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income...................................................... $ 422,764 $ 552,804 $ 646,447
Adjustments to reconcile net income to net
cash from operating activities:
Provision for depreciation and amortization................ 1,281,690 1,298,290 889,550
Nuclear fuel and capital lease amortization................ 66,072 80,507 98,178
Other amortization and accruals, net (Note 2(M))........... (16,278) (16,593) (11,927)
Deferred costs recoverable as regulatory assets............ (216,829) (362,956) (31,893)
Goodwill impairment (Note 2(L))............................ 116,988 -- --
Disallowed purchased power costs........................... 152,500 -- --
Investment impairments (Note 3)............................ 43,803 50,000 --
Deferred income taxes, net................................. 80,043 103,293 31,625
Investment tax credits, net................................ (26,404) (26,507) (22,545)
Cumulative effect of accounting change..................... (174,663) -- 14,338
Loss from discontinued operations (see Note 2(I)).......... 101,379 79,863 --
Receivables................................................ 66,311 (73,392) 53,099
Materials and supplies..................................... 5,399 (29,134) (50,052)
Accounts payable........................................... (169,652) 218,226 (84,572)
Deferred lease costs....................................... (119,398) (84,800) --
Other (Note 10)............................................ 338,737 125,686 (250,564)
----------- ----------- -----------
Net cash provided from operating activities.............. 1,952,462 1,915,287 1,281,684
----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Common stock................................................. 934,138 -- --
Preferred stock.............................................. -- -- 96,739
Long-term debt............................................... 1,027,312 668,676 4,338,080
Short-term borrowings, net................................... -- 478,520 --
Redemptions and Repayments-
Common stock................................................. -- -- (15,308)
Preferred stock.............................................. (127,087) (522,223) (85,466)
Long-term debt............................................... (2,128,567) (1,308,814) (394,017)
Short-term borrowings, net................................... (575,391) -- (1,641,484)
Common Stock Dividend Payments.................................. (453,360) (439,628) (334,633)
----------- ----------- -----------
Net cash provided from (used for) financing activities... (1,322,955) (1,123,469) 1,963,911
----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
GPU acquisition, net of cash.................................... -- -- (2,013,218)
Property additions.............................................. (856,316) (997,723) (852,449)
Proceeds from sale of assets.................................... 78,743 155,034 --
Avon cash and cash equivalents (Note 3)......................... -- 31,326 --
Net assets held for sale........................................ -- (31,326) --
Cash investments (Note 2(M)).................................... 52,884 81,349 24,518
Other (Note 10)................................................. 12,856 (54,355) (233,526)
----------- ----------- -----------
Net cash used for investing activities................... (711,833) (815,695) (3,074,675)
----------- ----------- -----------
Net increase (decrease) in cash and cash equivalents............ (82,326) (23,877) 170,920
Cash and cash equivalents at beginning of year.................. 196,301 220,178 49,258
----------- ----------- -----------
Cash and cash equivalents at end of year*....................... $ 113,975 $ 196,301 $ 220,178
=========== =========== ===========
SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)........................ $ 730,277 $ 881,515 $ 425,737
Income taxes................................................. $ 161,915 $ 389,180 $ 433,640
* 2001 excludes amounts in "Assets Pending Sale" on the Consolidated Balance Sheet as of December 31, 2001.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
47
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF TAXES
For the Years Ended December 31, 2003 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
(In thousands)
GENERAL TAXES:
Real and personal property........................................... $ 183,694 $ 218,683 $ 176,916
State gross receipts*................................................ 130,244 132,622 102,335
Kilowatt-hour excise*................................................ 228,216 219,970 117,979
Social security and unemployment..................................... 68,019 46,345 44,480
Other................................................................ 28,292 32,709 13,630
----------- ----------- -----------
Total general taxes........................................... $ 638,465 $ 650,329 $ 455,340
=========== =========== ===========
PROVISION FOR INCOME TAXES:
Currently payable-
Federal........................................................... $ 306,347 $ 326,417 $ 375,108
State............................................................. 118,155 104,867 84,322
Foreign........................................................... (1,165) 20,624 108
----------- ----------- -----------
423,337 451,908 459,538
----------- ----------- -----------
Deferred, net-
Federal........................................................... 71,910 81,934 37,888
State............................................................. 8,133 7,759 (6,177)
Foreign........................................................... -- 13,600 (86)
----------- ----------- -----------
80,043 103,293 31,625
----------- ----------- -----------
Investment tax credit amortization................................... (26,404) (26,507) (22,545)
----------- ----------- -----------
Total provision for income taxes.............................. $ 476,976 $ 528,694 $ 468,618
=========== =========== ===========
RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT
STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES:
Book income before provision for income taxes........................ $ 899,740 $ 1,081,498 $ 1,115,065
=========== =========== ===========
Federal income tax expense at statutory rate......................... $ 314,909 $ 378,524 $ 390,273
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits............................ (26,404) (26,507) (22,545)
State income taxes, net of federal income tax benefit............. 82,088 73,207 50,794
Amortization of tax regulatory assets............................. 31,909 29,296 30,419
Amortization of goodwill.......................................... -- -- 18,416
Preferred stock dividends......................................... 7,202 13,634 19,733
Reserve for foreign operations.................................... 44,305 48,587 --
Other, net........................................................ 22,967 11,953 (18,472)
----------- ----------- ------------
Total provision for income taxes.............................. $ 476,976 $ 528,694 $ 468,618
=========== =========== ===========
ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31:
Property basis differences........................................... $ 2,293,209 $ 2,052,594 $ 1,996,937
Customer receivables for future income taxes......................... 139,335 144,073 178,683
Regulatory transition charge......................................... 1,084,871 1,408,232 1,289,438
Deferred sale and leaseback costs.................................... (95,474) (99,647) (77,099)
Nonutility generation costs.......................................... (221,063) (228,476) (178,393)
Unamortized investment tax credits................................... (70,054) (78,227) (86,256)
Other comprehensive income........................................... (243,743) (398,883) (115,395)
Lease market valuation liability..................................... (455,074) (490,698) --
Other (Note 10)...................................................... (253,932) (239,286) (323,696)
------------ ----------- -----------
Net deferred income tax liability**........................... $ 2,178,075 $ 2,069,682 $ 2,684,219
=========== =========== ===========
* Collected from customers through regulated rates and included in revenue on the Consolidated Statements of Income.
** 2001 excludes amounts in "Liabilities Related to Assets Pending Sale" on the Consolidated Balance Sheet as of
December 31, 2001.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
48
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. GENERAL:
The consolidated financial statements include FirstEnergy Corp., a
registered public utility holding company, and 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, Inc. (ATSI), Jersey Central Power &
Light Company (JCP&L), Metropolitan Edison Company (Met-Ed) and Pennsylvania
Electric Company (Penelec). ATSI owns and operates FirstEnergy's transmission
facilities within the service areas of OE, CEI and TE (Ohio Companies) and Penn.
The operating utility subsidiaries are referred to throughout as "Companies."
FirstEnergy's 2001 results include the results of JCP&L, Met-Ed and Penelec from
the period they were acquired on November 7, 2001 through December 31, 2001. The
consolidated financial statements also include FirstEnergy's other principal
subsidiaries: FirstEnergy Solutions Corp. (FES); FirstEnergy Facilities Services
Group, LLC (FSG); MYR Group, Inc.; MARBEL Energy Corporation; First
Communications, LLC; FirstEnergy Nuclear Operating Company (FENOC); GPU Capital,
Inc.; GPU Power, Inc.; and FirstEnergy Service Company (FESC). FES provides
energy-related products and services and, through its FirstEnergy Generation
Corp. (FGCO) subsidiary, operates FirstEnergy's nonnuclear generation business.
FENOC operates the Companies' nuclear generating facilities. FSG is the parent
company of several heating, ventilating, air conditioning and energy management
companies, and MYR is a utility infrastructure construction service company.
MARBEL holds FirstEnergy's interest in Great Lakes Energy Partners, LLC. First
Communications provides local and long-distance phone service. GPU Capital owned
and operated electric distribution systems in foreign countries and GPU Power
owned and operated generation facilities in foreign countries. FESC provides
legal, financial and other corporate support services to affiliated FirstEnergy
companies.
The Companies follow the accounting policies and practices prescribed
by the Securities and Exchange Commission (SEC), the Public Utilities Commission
of Ohio (PUCO), the Pennsylvania Public Utility Commission (PPUC), the New
Jersey Board of Public Utilities (NJBPU) and the Federal Energy Regulatory
Commission (FERC). The preparation of financial statements in conformity with
accounting principles generally accepted in the United States (GAAP) requires
management to make periodic estimates and assumptions that affect the reported
amounts of assets, liabilities, revenues and expenses and the disclosure of
contingent assets and liabilities. Actual results could differ from these
estimates. FirstEnergy's consolidated financial statements for the year ended
December 31, 2002 were restated to reflect a change in the method of amortizing
costs being recovered under the Ohio transition plan, recognition of
above-market liabilities of certain leased generation facilities, Ohio
transition plan regulatory assets and goodwill.
Certain prior year amounts have been reclassified to conform with the
current year presentation, as described further in Notes 2(F), 2(I) and 8.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
(A) CONSOLIDATION-
FirstEnergy consolidates all majority-owned subsidiaries over which
the Company exercises control and, when applicable, entities for which the
Company has a controlling financial interest. Intercompany transactions and
balances are eliminated in consolidation. Investments in nonconsolidated
affiliates (20-50 percent owned companies, joint ventures and partnerships) over
which the Company has the ability to exercise significant influence, but not
control, are accounted for on the equity basis.
(B) EARNINGS PER SHARE-
Basic earnings per share are computed using the weighted average of
actual common shares outstanding as the denominator. Diluted earnings per share
reflect the weighted average of actual common shares outstanding plus the
potential additional common shares that could result if dilutive securities and
agreements were exercised in the denominator. In 2003, 2002 and 2001,
stock-based awards to purchase shares of common stock totaling 3.3 million, 3.4
million and 0.1 million, respectively, were excluded from the calculation of
diluted earnings per share of common stock because their exercise prices were
greater than the average market price of common shares during the period. The
numerators for the calculations of basic and diluted earnings per share are
Income Before Discontinued Operations and Cumulative Effect of Accounting
Changes and Net Income. The following table reconciles the denominators for
basic and diluted earnings per share:
49
Years Ended December 31,
-------------------------------------
Denominator for Earnings per Share Calculations 2003 2002 2001
--------------------------------------------------------------------------------------------
(In thousands)
Denominator for basic earnings per share
(weighted average shares actually outstanding)... 303,582 293,194 229,512
Assumed exercise of dilutive securities or
agreements to issue common stock................. 1,390 1,227 918
-------------------------------------------------------------------------------------------
Denominator for diluted earnings per share......... 304,972 294,421 230,430
===========================================================================================
(C) REVENUES-
The Companies' principal business is providing electric service to
customers in Ohio, Pennsylvania and New Jersey. The Companies' retail customers
are metered on a cycle basis. Revenue is recognized for unbilled electric
service provided through the end of the year. See Note 10 - Other Information
for discussion of reporting of independent system operator (ISO) transactions.
Receivables from customers include sales to residential, commercial
and industrial customers and sales to wholesale customers. There was no material
concentration of receivables as of December 31, 2003 or 2002, with respect to
any particular segment of FirstEnergy's customers. Total customer receivables
were $1.0 billion (billed - $664 million and unbilled - $336 million) and $1.2
billion (billed - $808 million and unbilled - $345 million) as of December 31,
2003 and 2002, respectively.
CEI and TE sell substantially all of their retail customers'
receivables to Centerior Funding Corporation (CFC), a wholly owned subsidiary of
CEI. CFC subsequently transfers the receivables to a trust (a "qualified special
purpose entity") under Statement of Financial Accounting Standards (SFAS) No.
140, "Accounting for Transfers and Servicing of Financial Assets and
Extinguishment of Liabilities," under an asset-backed securitization agreement.
Transfers are made in return for an interest in the trust (19% as of December
31, 2003), which is stated at fair value, reflecting adjustments for anticipated
credit losses. The average collection period for billed receivables is 28 days.
Given the short collection period after billing, the fair value of CFC's
interest in the trust approximates the stated value of its retained interest in
underlying receivables after adjusting for anticipated credit losses.
Accordingly, subsequent measurements of the retained interest under SFAS 115,
"Accounting for Certain Investments in Debt and Equity Securities", (as an
available-for-sale financial instrument) result in no material change in value.
Sensitivity analyses reflecting 10% and 20% increases in the rate of anticipated
credit losses would not have significantly affected FirstEnergy's retained
interest in the pool of receivables through the trust. Of the $250 million sold
to the trust and outstanding as of December 31, 2003, FirstEnergy's retained
interests in $48 million of the receivables are included as other receivables on
the Consolidated Balance Sheets. Accordingly, receivables recorded on the
Consolidated Balance Sheets were reduced by approximately $202 million due to
these sales. Collections of receivables previously transferred to the trust and
used for the purchase of new receivables from CFC during 2003 totaled
approximately $2.4 billion. CEI and TE processed receivables for the trust and
received servicing fees of approximately $3.6 million in 2003. Expenses
associated with the factoring discount related to the sale of receivables were
$3.5 million, $4.7 million and $12.0 million in 2003, 2002 and 2001.
(D) REGULATORY MATTERS-
In Ohio, New Jersey and Pennsylvania, laws applicable to electric
industry deregulation contain 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 transition costs (sometimes referred to as
stranded investment);
o itemizing (unbundling) the price of electricity into its
component elements - including generation, transmission,
distribution and transition costs recovery charges;
o deregulating the Companies' electric generation businesses;
o continuing regulation of the Companies' transmission and
distribution system; and
o requiring corporate separation of regulated and unregulated
business activities.
50
Ohio
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 recovery period extension is related to
the customer shopping incentives recovery discussed below. 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 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 gives 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, which runs through the
end of 2005, 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. Subject to approval by the PUCO, recovery will be
accomplished by extending the respective transition cost recovery period.
On October 21, 2003, the Ohio Companies filed an application with the
PUCO to establish generation service rates beginning January 1, 2006, in
response to expressed concerns by the PUCO about price and supply uncertainty
following the end of the market development period. The filing included two
options:
o A competitive auction, which would establish a price for
generation that customers would be charged during the period
covered by the auction, or
A Rate Stabilization Plan, which would extend current generation
prices through 2008, ensuring adequate supply and continuing our
support of energy efficiency and economic development efforts.
Under the first option, an auction would be conducted to secure
generation service, including PLR responsibility, for the Ohio Companies'
customers. Beginning in 2006, customers would pay market prices for generation
as determined by the auction.
Under the Rate Stabilization Plan option, customers would have price
and supply stability through 2008 - three years beyond the end of the market
development period - as well as the benefits of a competitive market. Customer
benefits would include: customer savings by extending the current five percent
discount on generation costs and other customer credits; maintaining current
distribution base rates through 2007; market-based auctions that may be
conducted annually to ensure that customers pay the lowest available prices;
extension of the Ohio Companies' support of energy-efficiency programs and the
potential for continuing the program to give preferred access to nonaffiliated
entities to generation capacity if shopping drops below 20%. Under the proposed
plan, we are requesting:
o Extension of the transition cost amortization period for OE
from 2006 to 2007; for CEI from 2008 to 2009 and for TE from
mid-2007 to 2008;
51
o Deferral of interest costs on the accumulated shopping incentives
and other cost deferrals as new regulatory assets; and
o Ability to initiate a request to increase generation rates under
certain limited conditions.
On January 7, 2004, the PUCO staff filed testimony on the proposed
rate plan generally supporting the Rate Stabilization Plan as opposed to the
competitive auction proposal. Hearings began on February 11, 2004. On February
24, 2004, after consideration of PUCO Staff comments and testimony as well as
those provided by some of the intervening parties, FirstEnergy made certain
modifications to the Rate Stabilization Plan. A decision is expected from the
PUCO in the Spring of 2004.
On November 25, 2003, the PUCO ordered FirstEnergy to file a plan
with the PUCO no later than March 1, 2004, illustrating how FirstEnergy will
address certain problems identified by the U.S./Canada Power Outage Task Force
(in connection with the August 14, 2003 regional power outage) and addressing
how FirstEnergy proposes to upgrade its control room computer hardware and
software, improve its control room training procedures and improve the training
of control room operators to ensure that similar problems do not occur in the
future. The PUCO, in consultation with the North American Electric Reliability
Council, will review the plan before determining the next steps in the
proceeding.
New Jersey
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 had been 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
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 and there would be an adjustment to
goodwill.
In addition, the Final Order provided for the ability to securitize
stranded costs associated with the divested Oyster Creek Nuclear Generating
Station. Under NJBPU authorization in 2002, JCP&L issued through its wholly
owned subsidiary, JCP&L Transition Funding LLC, $320 million of transition bonds
(recognized on the Consolidated Balance Sheet) which securitized the recovery of
these costs and which provided for a usage-based non-bypassable transition bond
charge (TBC) and for the transfer of the bondable transition property to another
entity.
Prior to August 1, 2003, JCP&L's PLR obligation to provide basic
generation service (BGS) to non-shopping customers was 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, 2003, the accumulated deferred cost balance totaled approximately $440
million, after the charge discussed below. 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. JCP&L's two August 2002 rate
filings requested increases in base electric rates of approximately $98 million
annually and requested the recovery of 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. On July 25, 2003, the NJBPU announced its JCP&L base electric
rate proceeding decision, which reduced JCP&L's annual revenues by approximately
$62 million effective August 1, 2003. The NJBPU decision also provided for an
interim return on equity of 9.5% on JCP&L's rate base for six to twelve months.
During that period, JCP&L will initiate another proceeding to request recovery
of additional costs incurred to enhance system reliability. In that proceeding,
the NJBPU could increase the return on equity to 9.75% or decrease it to 9.25%,
depending on its assessment of the reliability of JCP&L's service. Any reduction
would be retroactive to August 1, 2003. The net revenue decrease from the
NJBPU's decision consists of a $223 million decrease in the electricity delivery
charge, a $111 million increase due to the August 1, 2003 expiration of annual
customer credits previously mandated by the New Jersey transition legislation, a
$49 million increase in the MTC tariff component, and a net $1 million increase
in the SBC charge. The MTC allows for the recovery of $465 million in deferred
energy costs over the next ten years on an interim basis, thus disallowing $153
million of the $618 million provided for in a preliminary settlement agreement
between certain parties. As a result, JCP&L recorded charges to net income for
the year ended December 31, 2003, aggregating $185 million ($109 million net of
tax) consisting of the $153 million of disallowed deferred energy costs and
52
other regulatory assets. JCP&L filed a motion for rehearing and reconsideration
with the NJBPU on August 15, 2003 with respect to the following issues: (1) the
disallowance of the $153 million deferred energy costs; (2) the reduced rate of
return on equity; and (3) $42.7 million of disallowed costs to achieve merger
savings. On October 10, 2003, the NJBPU held the motion in abeyance until the
final NJBPU decision and order which is expected to be issued in the first
quarter of 2004.
JCP&L's BGS obligation for the twelve month period beginning August
1, 2003 was auctioned in February 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 sells all self-supplied energy (NUGs and owned generation) to the
wholesale market with offsetting credits to its deferred energy balances. The
BGS auction for the subsequent period was completed in February 2004. The NJBPU
adjusted the generation component of JCP&L's retail rates on August 1, 2003 to
reflect the results of the BGS auction.
Pennsylvania
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 and would be an adjustment to
goodwill.
In June 2001, the PPUC approved the Settlement Stipulation with all
of the major parties in the combined merger and rate relief proceedings which
approved the FirstEnergy/GPU merger and provided PLR deferred accounting
treatment for energy costs, permitting Met-Ed and Penelec to defer, for future
recovery, energy costs in excess of amounts reflected in their capped generation
rates retroactive to January 1, 2001. This PLR deferral accounting procedure was
later denied in a February 2002 Commonwealth Court of Pennsylvania decision. The
court decision also affirmed the PPUC decision regarding approval of the merger,
remanding the decision to the PPUC only with respect to the issue of merger
savings. FirstEnergy established reserves in 2002 for Met-Ed's and Penelec's PLR
deferred energy costs which aggregated $287.1 million, reflecting the potential
adverse impact of the then pending Pennsylvania Supreme Court decision whether
to review the Commonwealth Court decision. As a result, FirstEnergy recorded in
2002 an aggregate non-cash charge of $55.8 million ($32.6 million net of tax) to
income 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 April 2, 2003, the PPUC remanded the issue relating to merger
savings to the Office of Administrative Law for hearings, directed Met-Ed and
Penelec to file a position paper on the effect of the Commonwealth Court order
on the Settlement Stipulation and allowed other parties to file responses to the
position paper. Met-Ed and Penelec filed a letter with the Administrative Law
Judge (ALJ) on June 11, 2003, voiding the Stipulation in its entirety and
reinstating Met-Ed's and Penelec's restructuring settlement previously approved
by the PPUC.
On October 2, 2003, the PPUC issued an order concluding that the
Commonwealth Court reversed the PPUC's June 20, 2001 order in its entirety. The
PPUC directed Met-Ed and Penelec to file tariffs within thirty days of the order
to reflect the competitive transition charge (CTC) rates and shopping credits
that were in effect prior to the June 21, 2001 order to be effective upon one
day's notice. In response to that order, Met-Ed and Penelec filed these
supplements to their tariffs to become effective October 24, 2003.
On October 8, 2003, Met-Ed and Penelec filed a petition for
clarification relating to the October 2, 2003 order on two issues: to establish
June 30, 2004 as the date to fully refund the NUG trust fund and to clarify that
the ordered accounting treatment regarding the CTC rate/shopping credit swap
should follow the ratemaking, and that the PPUC's findings would not impair
their rights to recover all of their stranded costs. On October 9, 2003, ARIPPA
(an intervenor in the proceedings) petitioned the PPUC to direct Met-Ed and
Penelec to reinstate accounting for the CTC rate/shopping credit swap
retroactive to January 1, 2002. Several other parties also filed petitions. On
October 16, 2003, the PPUC issued a reconsideration order granting the date
requested by Met-Ed and Penelec for the NUG trust fund refund, denying Met-Ed's
and Penelec's other clarification requests and granting ARIPPA's petition with
respect to the accounting treatment of the changes to the CTC rate/shopping
credit swap. On October 22, 2003, Met-Ed and Penelec filed an Objection with the
Commonwealth Court asking that the Court reverse the PPUC's finding that
requires Met-Ed and Penelec to treat the stipulated CTC rates that were in
effect from January 1, 2002 on a retroactive basis. Met-Ed and Penelec are
considering filing an appeal to the Commonwealth Court on the PPUC orders as
well.
On October 27, 2003, a Commonwealth Court judge issued an Order
denying Met-Ed's and Penelec's objection without explanation. Due to the
vagueness of the Order, Met-Ed and Penelec, on October 31, 2003, filed an
Application for Clarification with the judge. Concurrent with this filing,
Met-Ed and Penelec, in order to preserve their
53
rights, also filed with the Commonwealth Court both a Petition for Review of the
PPUC's October 16 and October 22 Orders, and an application for reargument, if
the judge, in his clarification order, indicates that Met-Ed's and Penelec's
objection was intended to be denied on the merits. In addition to these
findings, Met-Ed and Penelec, in compliance with the PPUC's Orders, filed
revised PPUC quarterly reports for the twelve months ended December 31, 2001 and
2002, and for the first two quarters of 2003, reflecting balances consistent
with the PPUC's findings in their Orders.
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 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 assumed the supply
obligation and the 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 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 a fixed price 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 on-peak obligation through 2004 and a portion of
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 current market prices.
In late 2003, the PPUC issued a Tentative Order implementing new
reliability benchmarks and standards. In connection therewith, the PPUC
commenced a rulemaking procedure to amend the Electric Service Reliability
Regulations to implement these new benchmarks, and create additional reporting
on reliability. Although neither the Tentative Order nor the Reliability
Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to
begin filing quarterly reports on November 1, 2003. The comment period for both
the Tentative Order and the Proposed Rulemaking Order has closed. Met-Ed,
Penelec and Penn are currently awaiting the PPUC to issue a final order in both
matters. The order will determine (1) the standards and benchmarks to be
utilized, and (2) the details required in the quarterly and annual reports. It
is expected that these Orders will be finalized in March of 2004.
On January 16, 2004, the PPUC initiated a formal investigation of
Met-Ed's, Penelec's and Penn's levels of compliance with the Public Utility Code
and the PPUC's regulations and orders with regard to reliable electric service.
Hearings will be held in August in this investigation and the ALJ has been
directed to issue a Recommended Decision by September 30, 2004, in order to
allow the PPUC time to issue a Final Order before December 16, 2004. FirstEnergy
is unable to predict the outcome of the investigation or the impact of the PPUC
order.
Transition Cost Amortization -
OE, CEI and TE amortize transition costs (see Regulatory Matters -
Ohio) using the effective interest method. Under the current Ohio transition
plan, total transition cost amortization is expected to approximate the
following for 2004 through 2009.
(In millions)
---------------------------------
2004.................. $794
2005.................. 922
2006.................. 371
2007.................. 208
2008.................. 164
2009.................. 46
------------------------------
The decrease in amortization beginning in 2006 results from the
termination of generation-related transition cost recovery under the Ohio
transition plan.
Regulatory Assets-
The Companies recognize, as regulatory assets, costs which the FERC,
PUCO, PPUC and NJBPU have authorized for recovery from customers in future
periods. Without such authorization, the costs would have been charged to income
as incurred. All regulatory assets are expected to continue to be recovered from
customers under the Companies' respective transition and regulatory plans. Based
on those plans, the Companies continue to bill and collect cost-based rates for
their transmission and distribution services, which remain regulated;
accordingly, it is appropriate that the Companies continue the application of
SFAS 71 to those operations. Regulatory assets which do not earn a current
return totaled approximately $625 million as of December 31, 2003.
54
Net regulatory assets on the Consolidated Balance Sheets are
comprised of the following:
2003 2002
- ------------------------------------------------------------------------------
(In millions)
Regulatory transition charge................... $6,427 $7,608
Customer shopping incentives................... 371 188
Customer receivables for future income taxes... 340 394
Societal benefits charge....................... 81 144
Loss on reacquired debt........................ 75 74
Employee postretirement benefit costs.......... 77 88
Nuclear decommissioning, decontamination and
spent fuel disposal costs.................... (96) 99
Component removal costs........................ (321) (288)
Property losses and unrecovered plant costs.... 70 88
Other.......................................... 53 70
- ---------------------------------------------------------------------------
Total.................................... $7,077 $8,465
- ---------------------------------------------------------------------------
Regulatory Accounting for Generation Operations-
The application of SFAS 71 was discontinued with respect to the
Companies' generation operations. The SEC's interpretive guidance regarding
asset impairment measurement providing that any supplemental regulated cash
flows such as a CTC should be excluded from the cash flows of assets in a
portion of the business not subject to regulatory accounting practices. If those
assets are impaired, a regulatory asset should be established if the costs are
recoverable through regulatory cash flows. Consistent with the SEC guidance,
$1.8 billion of impaired plant investments ($1.2 billion, $227 million, $304
million and $53 million for OE, Penn, CEI and TE, respectively) were recognized
as regulatory assets recoverable as transition costs through future regulatory
cash flows. The following summarizes net assets included in property, plant and
equipment relating to operations for which the application of SFAS 71 was
discontinued, compared with the respective company's total assets as of December
31, 2003.
SFAS 71
Discontinued
Net Assets Total Assets
--------------------------------------------
(In millions)
OE............. $ 976 $6,591
CEI............ 1,429 6,773
TE............. 561 2,855
Penn........... 92 879
JCP&L.......... 42 7,579
Met-Ed......... 15 3,474
---------------------------------------
(E) PROPERTY, PLANT AND EQUIPMENT-
Property, plant and equipment reflects original cost (except for
nuclear generating assets which were adjusted to fair value), including payroll
and related costs such as taxes, employee benefits, administrative and general
costs, and interest costs incurred to place the assets in service. JCP&L holds a
50% ownership interest in Yards Creek Pumped Storage Facility - its net book
value was approximately $20.7 million as of December 31, 2003. FirstEnergy also
had shared ownership interests in various foreign properties - all such assets
were divested by January 30, 2004. FirstEnergy's accounting policy for planned
major maintenance projects is to recognize liabilities as they are incurred.
The Companies provide for depreciation on a straight-line basis at
various rates over the estimated lives of property included in plant in service.
The respective annual composite rates for the Companies' electric plant in 2003,
2002 and 2001 (post-merger periods only for JCP&L, Met-Ed and Penelec) are shown
in the following table:
Annual Composite
Depreciation Rate
-------------------------
2003 2002 2001
------------------------------------------------
OE............... 2.8% 2.7% 2.7%
CEI.............. 3.0 3.4 3.2
TE............... 3.0 3.9 3.5
Penn............. 2.6 2.9 2.9
JCP&L............ 2.8 3.5 3.4
Met-Ed........... 2.7 3.0 3.0
Penelec.......... 2.7 3.0 2.9
------------------------------------------------
55
Nuclear Fuel -
Nuclear fuel is recorded at original cost, which includes material,
enrichment, fabrication and interest costs incurred prior to reactor load. The
Companies amortize the cost of nuclear fuel based on the rate of consumption.
(F) ASSET RETIREMENT OBLIGATION-
In January 2003, FirstEnergy implemented SFAS 143, "Accounting for
Asset Retirement Obligations", which provides accounting standards for
retirement obligations associated with tangible long-lived assets. This
statement requires recognition of the fair value of a liability for an asset
retirement obligation (ARO) in the period in which it is incurred. The
associated asset retirement costs are capitalized as part of the carrying amount
of the long-lived asset. Over time the capitalized costs are depreciated and the
present value of the asset retirement liability increases, resulting in a period
expense. However, rate-regulated entities may recognize a regulatory asset or
liability instead if the criteria for such treatment are met. Upon retirement, a
gain or loss would be recognized if the cost to settle the retirement obligation
differs from the carrying amount.
FirstEnergy identified applicable legal obligations as defined under
the new standard for nuclear power plant decommissioning, reclamation of a
sludge disposal pond related to the Bruce Mansfield Plant, and closure of two
coal ash disposal sites. The ARO liability as of the date of adoption of SFAS
143 was $1.107 billion, including accumulated accretion for the period from the
date the liability was incurred to the date of adoption. The ARO liability was
$1.179 billion as of December 31, 2003 and included $1.166 billion for nuclear
decommissioning of the Beaver Valley, Davis-Besse, Perry, and Three Mile Island
Unit 2 (TMI-2) nuclear generating facilities (discussed below). The Companies'
share of the obligation to decommission these units was developed based on site
specific studies performed by an independent engineer. FirstEnergy utilized an
expected cash flow approach (as discussed in FASB Concepts Statement No. 7,
"Using Cash Flow Information and Present Value in Accounting Measurements") to
measure the fair value of the nuclear decommissioning ARO. The Companies
maintain nuclear decommissioning trust funds that are legally restricted for
purposes of settling the nuclear decommissioning ARO. As of December 31, 2003,
the fair value of the decommissioning trust assets was $1.352 billion. Payments
for decommissioning of the nuclear generating units are expected to begin in
2014, when actual decommissioning work is expected to begin.
The following table provides the beginning and ending aggregate
carrying amount of the total ARO and the changes to the balance during 2003.
ARO Reconciliation 2003
- ----------------------------------------------------------------------------
(In millions)
Beginning balance as of January 1, 2003 ...................... $1,107
Liabilities incurred.......................................... --
Liabilities settled........................................... --
Accretion in 2003............................................. 72
Revisions in estimated cash flows............................. --
- ------------------------------------------------------------------------
Ending balance as of December 31, 2003........................ $1,179
- ------------------------------------------------------------------------
The following table provides the year-end balance of the ARO for
2002, as if SFAS 143 had been adopted on January 1, 2002.
Adjusted ARO Reconciliation 2002
- -----------------------------------------------------------------------------
(In millions)
Beginning balance as of January 1, 2002....................... $1,042
Accretion in 2002............................................. 65
- ------------------------------------------------------------------------
Ending balance as of December 31, 2002........................ $1,107
- ------------------------------------------------------------------------
In addition to the nuclear decommissioning ARO, FirstEnergy has also
recognized estimated liabilities for post defueling monitored storage at TMI-2
of $26 million and decontamination and decommissioning of nuclear enrichment
facilities of $28 million. Under terms of the NRC license, FirstEnergy is
required to monitor and maintain TMI-2 to ensure that there is no deterioration
of the facility. As required by the Energy Policy Act of 1992, FirstEnergy
participates in the decontamination and decommissioning of nuclear enrichment
facilities operated by the United States Department of Energy.
In accordance with SFAS 143, FirstEnergy ceased the accounting
practice of depreciating non-regulated generation assets using a cost of removal
component in the depreciation rates. That practice recognized accumulated
depreciation in excess of the historical cost of an asset because the removal
cost would exceed the estimated salvage value. Beginning in 2003, the cost of
removal related to non-regulated generation assets is charged to expense rather
than to the accumulated provision for depreciation. In accordance with SFAS 71,
the cost of removal on regulated plant assets continues to be accounted for as a
component of depreciation rates and is recognized as a regulatory liability.
56
The following table provides the effect on income as if SFAS 143 had
been applied during 2002 and 2001.
Effect of the Change in Accounting
Principle Applied Retroactively 2002 2001
--------------------------------------------------------------------------------------------------
(In millions, except per share amounts)
Reported net income............................................... $553 $646
Increase (Decrease):
Elimination of decommissioning expense............................ 88 88
Depreciation of asset retirement cost............................. (3) (3)
Accretion of ARO liability........................................ (38) (35)
Non-regulated generation cost of removal component, net........... 15 11
Income tax effect................................................. (25) (25)
-------------------------------------------------------------------------------------------
Net earnings increase............................................. 37 36
------------------------------------------------------------------------------------------
Net income adjusted............................................... $590 $682
==========================================================================================
Basic earnings per share of common stock:
Net income as previously reported................................. $1.89 $2.82
Adjustment for effect of change in
accounting principle applied retroactively...................... 0.12 0.16
- -------------------------------------------------------------------------------------------
Net income adjusted............................................... $2.01 $2.98
==========================================================================================
Diluted earnings per share of common stock:
Net income as previously reported................................. $1.88 $2.81
Adjustment for effect of change in
accounting principle applied retroactively...................... 0.12 0.16
- -------------------------------------------------------------------------------------------
Net income adjusted .............................................. $2.00 $2.97
==========================================================================================
(G) STOCK-BASED COMPENSATION-
FirstEnergy applies the recognition and measurement principles of
Accounting Principles Board Opinion No. 25 (APB 25), "Accounting for Stock
Issued to Employees" and related Interpretations in accounting for its
stock-based compensation plans (see Note 5(C)). No material stock-based employee
compensation expense is reflected in net income as all options granted under
those plans had an exercise price equal to the market value of the underlying
common stock on the grant date, resulting in substantially no intrinsic value.
If FirstEnergy had elected to account for employee stock options
under the fair value method (as provided under SFAS 123, "Accounting for
Stock-Based Compensation") a higher value would have been assigned to the
options granted. The weighted average assumptions used in valuing the options
and their resulting estimated fair values would be as follows:
2003 2002 2001
----------------------------------------------------------------------------
Valuation assumptions:
Expected option term (years)... 7.9 8.1 8.3
Expected volatility............ 26.91% 23.31% 23.45%
Expected dividend yield........ 5.09% 4.36% 5.00%
Risk-free interest rate........ 3.67% 4.60% 4.67%
Fair value per option............ $5.09 $6.45 $4.97
----------------------------------------------------------------------------
If fair value accounting were applied to FirstEnergy's stock options,
net income and earnings per share would be reduced as summarized below.
2003 2002 2001
----------------------------------------------------------------------------------
(In thousands, except per share amounts)
Net Income, as reported.............. $422,764 $552,804 $646,447
Add back compensation expense
reported in net income, net of tax
(based on APB 25).................. 163 166 25
Deduct compensation expense based
upon estimated fair value, net
of tax............................. (12,354) (8,825) (3,748)
-----------------------------------------------------------------------------------
Adjusted net income.................. $410,573 $544,145 $642,724
-----------------------------------------------------------------------------------
Earnings Per Share of Common Stock -
Basic
As Reported...................... $1.39 $1.89 $2.82
Adjusted......................... $1.35 $1.86 $2.80
Diluted
As Reported...................... $1.39 $1.88 $2.81
Adjusted......................... $1.35 $1.85 $2.79
57
(H) INCOME TAXES-
Details of the total provision for income taxes are shown on the
Consolidated Statements of Taxes. The Company records income taxes in accordance
with the liability method of accounting. Deferred income taxes reflect the net
tax effect of temporary differences between the carrying amounts of assets and
liabilities for financial reporting purposes and the amounts used for tax
purposes. Investment tax credits, which were deferred when utilized, are being
amortized over the recovery period of the related property. Deferred income tax
liabilities related to tax and accounting basis differences and tax credit
carryforward items are recognized at the statutory income tax rates in effect
when the liabilities are expected to be paid.
FirstEnergy has capital loss carryforwards of approximately $1.1
billion, most of which expire in 2007. The deferred tax assets associated with
these capital loss carryforwards ($374 million) are fully offset by a valuation
allowance as of December 31, 2003, since management is unable to predict whether
sufficient capital gains will be generated to utilize all of these capital loss
carryforwards. Any ultimate utilization of capital loss carryforwards for which
valuation allowances were established through purchase accounting would adjust
goodwill.
The Company has also recorded valuation allowances of $92 million for
deferred tax assets associated with impairment losses related to certain
domestic assets and the divestiture of international assets acquired through the
merger with GPU (see Note 12).
FirstEnergy has net operating loss carryforwards for state and local
income tax purposes of approximately $693 million. A valuation allowance of $5
million has been recorded against the associated deferred tax assets of $30
million. These losses expire as follows:
Expiration Period Amount
-----------------------------------
(in millions)
2004-2008 $102
2009-2013 147
2014-2018 130
2019-2022 314
------------------------------
$693
==============================
(I) DISCONTINUED OPERATIONS -
FirstEnergy has included in "Discontinued Operations" on the
Consolidated Statements of Income for the years ended December 31, 2003 and 2002
operating income and losses on sales of its international operations in
Argentina and Bolivia and certain domestic subsidiaries of FSG and MARBEL, all
of which were sold in 2003. Discontinued operations in 2003 of $(101) million,
net of tax benefits of $2 million, included operating results of $2 million
(revenues of $52 million and pretax income of $2 million) and losses on sales or
abandonments of $103 million. A net operating loss of $80 million (revenues of
$284 million and pretax loss of $75 million) attributable to these entities was
included in discontinued operations in 2002. The 2001 results of the divested
entities were not significant and the 2001 Consolidated Statement of Income was
not reclassified to separately report discontinued operations.
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.
FirstEnergy included in discontinued operations Emdersa's net income of $7 and a
$67 million charge for the abandonment in the second quarter of 2003 (no income
tax benefit was recognized). An after-tax loss of $87 million (including $109
million in currency transaction losses arising principally from U.S. dollar
denominated debt) was included in discontinued operations in 2002.
In December 2003, Empresa Guaracachi S.A. (EGSA), GPU Power's Bolivia
subsidiary, was sold to Bolivia Integrated Energy Limited. FirstEnergy included
in discontinued operations a $33 million loss on the sale of EGSA in the fourth
quarter of 2003 (no income tax benefit was realized) and an operating loss for
the year of $2 million. Discontinued operations in 2002 include EGSA's operating
income of $6 million.
The FSG subsidiaries, Colonial Mechanical and Webb Technologies, were
sold in January 2003 and Ancoma, Inc. was sold in December 2003; the MARBEL
subsidiary, Northeast Ohio Natural Gas Corp. was sold in June 2003. The 2003 and
2002 results for these divested business operations included in discontinued
operations for the years ended December 2003 and 2002 totaled $(3) million and
$2 million, respectively.
The following table summarizes major assets and liabilities for all
of these divestitures included in FirstEnergy's Consolidated Balance Sheets as
of December 31, 2002.
58
As of December 31 2002
----------------------------------------------------------
(In millions)
Current assets................................ $106
Property and investments...................... 175
Deferred Charges.............................. 44
-----
Total assets.................................. $325
====
Current liabilities........................... $ 64
Capitalization................................ 205
Noncurrent liabilities........................ 56
----
Total liabilities and capitalization.......... $325
====
(J) CUMULATIVE EFFECT OF ACCOUNTING CHANGE
As a result of adopting SFAS 143 in January 2003, asset retirement
costs were recorded in the amount of $602 million as part of the carrying amount
of the related long-lived asset, offset by accumulated depreciation of $415
million. The ARO liability on the date of adoption was $1.107 billion, including
accumulated accretion for the period from the date the liability was incurred to
the date of adoption. The remaining cumulative effect adjustment for
unrecognized depreciation and accretion, offset by the reduction in the existing
decommissioning liabilities and the reversal of accumulated estimated removal
costs for non-regulated generation assets, was a $175 million increase to
income, $102 million net of tax, or $0.33 per share of common stock (basic and
diluted) in the year ended December 31, 2003 (see Note 9).
On January 1, 2001, FirstEnergy adopted SFAS 133 as amended,
"Accounting for Derivative Instruments and Hedging Activities". The cumulative
effect to January 1, 2001 was a charge of $9 million (net of $6 million of
income taxes) or $0.03 per share of common stock.
(K) PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
FirstEnergy provides noncontributory defined benefit pension plans
that cover substantially all of its employees. The trusteed plans provide
defined benefits based on years of service and compensation levels. The
Company's funding policy is based on actuarial computations using the projected
unit credit method. No pension contributions were required during the three
years ended December 31, 2003.
FirstEnergy provides a minimum amount of noncontributory life
insurance to retired employees in addition to optional contributory insurance.
Health care benefits, which include certain employee contributions, deductibles
and copayments, are also available to retired employees, their dependents and,
under certain circumstances, their survivors. The Company recognizes the
expected cost of providing other postretirement benefits to employees and their
beneficiaries and covered dependents from the time employees are hired until
they become eligible to receive those benefits.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions made to the plans, and earnings on plan assets. Such factors may
be further affected by business combinations (such as the merger with GPU, Inc.
in November 2001), which impact employee demographics, plan experience and other
factors. Pension and OPEB costs may also be affected by changes in key
assumptions, including anticipated rates of return on plan assets, the discount
rates and health care trend rates used in determining the projected benefit
obligations and pension and OPEB costs. FirstEnergy uses a December 31
measurement date for the majority of its plans.
Plan amendments to retirement health care benefits in 2003 and 2002,
relate to changes in benefits provided and cost-sharing provisions, which
reduced the Company's obligation by $123 million and $121 million, respectively.
In early 2004, the Company announced that it would amend the benefit provisions
of its health care benefits plan and both employees and retirees would share in
more of the benefit costs.
On December 8, 2003, President Bush signed into law a bill that
expands Medicare, primarily adding a prescription drug benefit for
Medicare-eligible retirees starting in 2006. FirstEnergy anticipates that the
benefits it pays after 2006 will be lower as a result of the new Medicare
provisions. Due to uncertainties surrounding some of the new Medicare provisions
and a lack of authoritative accounting guidance about these issues, FirstEnergy
deferred the recognition of the impact of the new Medicare provisions as
provided by FASB Staff Position 106-1. The final accounting guidance could
require changes to previously reported information.
59
Obligations and Funded Status Pension Benefits Other Benefits
---------------- --------------
As of December 31 2003 2002 2003 2002
------------------------------------------------------------------------------------------
(In millions)
Change in benefit obligation
Benefit obligation at beginning of year.. $3,866 $3,548 $ 2,077 $ 1,582
Service cost............................. 66 59 43 28
Interest cost............................ 253 249 136 114
Plan participants' contributions......... -- -- 6 --
Plan amendments.......................... -- -- (123) (121)
Actuarial loss........................... 222 268 323 440
GPU acquisition (Note 12)................ -- (12) -- 110
Benefits paid............................ (245) (246) (94) (76)
------ ------ ------- -------
Benefit obligation at end of year........ $4,162 $3,866 $ 2,368 $ 2,077
====== ====== ======= =======
Change in fair value of plan assets
Fair value of plan assets at beginning
of year................................ $2,889 $3,484 $ 473 $ 535
Actual return on plan assets............. 671 (349) 88 (57)
Company contribution..................... -- -- 68 31
Plan participants' contribution.......... -- -- 2 --
Benefits paid............................ (245) (246) (94) (36)
------ ------ ------- -------
Fair value of plan assets at end of year. $3,315 $2,889 $ 537 $ 473
====== ====== ======= =======
Funded status............................ $ (847) $ (977) $(1,831) (1,604)
Unrecognized net actuarial loss.......... 919 1,186 994 752
Unrecognized prior service cost
(benefit)............................... 72 78 (221) (107)
Unrecognized net transition obligation... -- -- 83 92
------ ------ ------- -------
Net asset (liability) recognized......... $ 144 $ 287 $ (975) $ (867)
====== ====== ======= =======
Amounts Recognized in the
Consolidated Balance Sheets
As of December 31
-----------------------------------------
Accrued benefit cost..................... $ (438) $ (548) $ (975) $ (867)
Intangible assets........................ 72 78 -- --
Accumulated other comprehensive loss..... 510 757 -- --
------ ------ ------- -------
Net amount recognized.................. $ 144 $ 287 $ (975) $ (867)
====== ====== ======= =======
Increase (decrease) in minimum liability
included in other comprehensive income
(net of tax)........................... $ (145) $ 444 -- --
Assumptions Used to Determine
Benefit Obligations As of December 31
----------------------------------------
Discount rate........................... 6.25% 6.75% 6.25% 6.75%
Rate of compensation increase........... 3.50% 3.50%
Allocation of Plan Assets
As of December 31
----------------------------------------
Asset Category
Equity securities..................... 70% 61% 71% 58%
Debt securities....................... 27 35 22 29
Real estate........................... 2 2 -- --
Cash.................................. 1 2 7 13
--- --- --- ---
Total................................. 100% 100% 100% 100%
=== === === ===
Information for Pension Plans With an
Accumulated Benefit Obligation in
Excess of Plan Assets 2003 2002
----------------------------------------- ---- ----
(In millions)
Projected benefit obligation............. $4,162 $3,866
Accumulated benefit obligation........... 3,753 3,438
Fair value of plan assets................ 3,315 2,889
Pension Benefits Other Benefits
---------------------- --------------------
Components of Net Periodic Benefit Costs 2003 2002 2001 2003 2002 2001
----------------------------------------------------------------------------------------------
(In millions)
Service cost............................ $ 66 $ 59 $ 35 $ 43 $ 29 $ 18
Interest cost........................... 253 249 133 137 114 65
Expected return on plan assets.......... (248) (346) (205) (43) (52) (10)
Amortization of prior service cost...... 9 9 9 (9) 3 3
Amortization of transition obligation
(asset)................................ -- -- (2) 9 9 9
Recognized net actuarial loss........... 62 -- -- 40 11 5
Voluntary early retirement program...... -- -- 6 -- -- 2
----- ----- ----- ----- ---- ----
Net periodic cost (income).............. $ 142 $ (29) $ (24) $ 177 $114 $ 92
===== ===== ===== ===== ==== ====
60
Weighted-Average Assumptions Used Pension Benefits Other Benefits
to Determine Net Periodic Benefit Cost ------------------------ --------------------
for Years Ended December 31 2003 2002 2001 2003 2002 2001
----------------------------------------------------------------------------------------------
Discount rate.......................... 6.75% 7.25% 7.75% 6.75% 7.25% 7.75%
Expected long-term return on plan
assets............................... 9.00% 10.25% 10.25% 9.00% 10.25% 10.25%
Rate of compensation increase.......... 3.50% 4.00% 4.00%
In selecting an assumed discount rate, FirstEnergy considers
currently available rates of return on high-quality fixed income investments
expected to be available during the period to maturity of the pension and other
postretirement benefit obligations. The assumed rate of return on pension plan
assets considers historical market returns and economic forecasts for the types
of investments held by the Company's pension trusts. The long-term rate of
return is developed considering the portfolio's asset allocation strategy.
Assumed Health Care Cost Trend Rates
As of December 31 2003 2002
- ------------------------------------------------------------------------------
Health care cost trend rate assumed for next
year (pre/post-Medicare).......................... 10%-12% 10%-12%
Rate to which the cost trend rate is assumed to
decline (the ultimate trend rate)................. 5% 5%
Year that the rate reaches the ultimate trend
rate (pre/post-Medicare).......................... 2009-2011 2008-2010
Assumed health care cost trend rates have a significant effect on the
amounts reported for the health care plans. A one-percentage-point change in
assumed health care cost trend rates would have the following effects:
1-Percentage- 1-Percentage-
Point Increase Point Decrease
- --------------------------------------------------------------------------------
(In millions)
Effect on total of service and interest cost.. $ 26 $ (19)
Effect on postretirement benefit obligation... $233 $(212)
FirstEnergy employs a total return investment approach whereby a mix
of equities and fixed income investments are used to maximize the long-term
return of plan assets for a prudent level of risk. Risk tolerance is established
through careful consideration of plan liabilities, plan funded status, and
corporate financial condition. The investment portfolio contains a diversified
blend of equity and fixed-income investments. Furthermore, equity investments
are diversified across U.S. and non-U.S. stocks, as well as growth, value, and
small and large capitalizations. Other assets such as real estate are used to
enhance long-term returns while improving portfolio diversification. Derivatives
may be used to gain market exposure in an efficient and timely manner; however,
derivatives are not used to leverage the portfolio beyond the market value of
the underlying investments. Investment risk is measured and monitored on a
continuing basis through periodic investment portfolio reviews, annual liability
measurements, and periodic asset/liability studies.
As a result of the increased market value of its pension plan assets,
FirstEnergy reduced its minimum liability as prescribed by SFAS 87 as of
December 31, 2003 by $253 million, recording a decrease of $6 million in an
intangible asset and crediting OCI by $145 million (offsetting previously
recorded deferred tax benefits by $102 million). The remaining balance in OCI of
$299 million will reverse in future periods to the extent the fair value of
trust assets exceeds the accumulated benefit obligation. The accrued pension
cost was reduced to $438 million as of December 31, 2003.
FirstEnergy does not expect to contribute to its pension plans in
2004 and expects to contribute $16 million to its other postretirement benefit
plans in 2004.
(L) GOODWILL-
In a business combination, the excess of the purchase price over the
estimated fair values of the assets acquired and liabilities assumed is
recognized as goodwill. Under SFAS 142, "Goodwill and Other Intangible Assets,"
amortization of existing goodwill ceased January 1, 2002. Instead, FirstEnergy
evaluates goodwill for impairment at least annually and makes such an evaluation
more frequently if indicators of impairment should arise. In accordance with the
accounting standard, if the fair value of a reporting unit is less than its
carrying value (including goodwill), the goodwill is tested for impairment. When
impairment is indicated, FirstEnergy recognizes a loss - calculated as the
difference between the implied fair value of a reporting unit's goodwill and the
carrying value of the goodwill. FirstEnergy's annual review was completed in the
third quarter of 2003. As a result of that review, a non-cash goodwill
impairment charge of $122 million was recognized in the third quarter of 2003,
reducing the carrying value of FSG. Of this amount, $117 million is reported as
an operating expense and $5 million is included, net of tax, in the loss from
discontinued operations. The
61
impairment charge reflects the continued slow down in the development of
competitive retail markets and depressed economic conditions that affect the
value of FSG. The fair value of FSG was estimated using primarily the expected
discounted future cash flows. The forecasts used in FirstEnergy's evaluations of
goodwill reflect operations consistent with its general business assumptions.
Unanticipated changes in those assumptions could have a significant effect on
FirstEnergy's future evaluations of goodwill. As of December 31, 2003,
FirstEnergy had $6.1 billion of goodwill that primarily relates to its regulated
services segment. The impairment analysis includes a significant source of cash
representing the Companies' recovery of transition costs as described above
under Note 2(D). FirstEnergy does not believe that completion of transition cost
recovery will result in an impairment of goodwill relating to its regulated
business segment.
The following table displays what net income and earnings per share
would have been if goodwill amortization had been excluded in 2001:
2003 2002 2001
---- ---- ----
(In thousands, except per share amounts)
Reported net income................... $422,764 $552,804 $646,447
Goodwill amortization (net of tax).... -- -- 54,584
-------- -------- --------
Adjusted net income................... $422,764 $552,804 $701,031
======== ======== ========
Basic earnings per common share:
Reported earnings per share........ $1.39 $1.89 $2.82
Goodwill amortization.............. -- -- 0.23
----- ----- -----
Adjusted earnings per share........ $1.39 $1.89 $3.05
===== ===== =====
Diluted earnings per common share:
Reported earnings per share........ $1.39 $1.88 $2.81
Goodwill amortization.............. -- -- 0.23
----- ----- -----
Adjusted earnings per share........ $1.39 $1.88 $3.04
===== ===== =====
A summary of the changes in FirstEnergy's goodwill for the years
ended December 31, 2002 and 2003 is shown below:
2003 2002
---- ----
(In millions)
Balance as of January 1................. $6,278 $5,983
Impairment charges...................... (122) --
FSG divestitures........................ (41) --
GPU acquisition (see Note 12)........... -- 286
Other................................... 13 9
------ ------
Balance as of December 31............... $6,128 $6,278
====== ======
(M) CASH AND FINANCIAL INSTRUMENTS-
All temporary cash investments purchased with an initial maturity of
three months or less are reported as cash equivalents on the Consolidated
Balance Sheets at cost, which approximates their fair market value. Cash and
cash equivalents as of December 31, 2003 included $32 million received in
December 2003 which was included in the NRG settlement claim sold in January
2004 (see Note 3). Cash and cash equivalents as of December 31, 2002 included
$50 million used for the redemption of long-term debt in January 2003. Noncash
financing and investing activities in 2001 included $2.6 billion of common stock
issued for the GPU acquisition and capital lease transactions amounting to $3
million. There were no capital lease transactions in 2003 or 2002. Net losses on
foreign currency exchange transactions reflected on FirstEnergy's 2002
Consolidated Statement of Income consisted of approximately $104 million from
FirstEnergy's Argentina operations (see Note 3 - Divestitures).
On the Consolidated Statements of Cash Flows, the amounts included in
"Cash investments" under Cash Flows From Investing Activities primarily consist
of changes in investments in collateralized lease bonds (see Note 4) of $85
million and other cash investments of $(32) million in 2003 and changes in
investments in collateralized lease bonds of $87 million and other cash
investments of $(6) million in 2002. The amounts included in "Other amortization
and accruals, net" under Cash Flows From Operating Activities include amounts
from the reduction of an electric service obligation under a CEI electric
service prepayment program.
All borrowings with initial maturities of less than one year are
defined as financial instruments under GAAP and are reported on the Consolidated
Balance Sheets at cost, which approximates their fair market value. The
following sets forth the approximate fair value and related carrying amounts of
all other long-term debt, preferred stock subject to mandatory redemption and
investments other than cash and cash equivalents as of December 31:
62
2003 2002
- ------------------------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Value Value Value Value
(In millions)
Long-term debt.......................... $11,471 $11,970 $12,465 $12,761
------------------------------------------------------------------------------------------------
Preferred stock*........................ $ 19 $ 19 $ 445 $ 454
------------------------------------------------------------------------------------------------
Investments other than cash
and cash equivalents:
Debt securities:
-Maturity (5-10 years)............ $ 452 $ 427 $ 502 $ 471
-Maturity (more than 10 years).... 871 1,005 927 1,030
Equity securities................... -- -- 15 15
All other........................... 1,944 1,944 1,668 1,669
- -------------------------------------------------------------------------------------------------
$ 3,267 $ 3,376 $ 3,112 $ 3,185
=================================================================================================
<FN>
* The December 31, 2003 amount is classified as debt under SFAS 150.
</FN>
The fair values of long-term debt and preferred stock reflect the
present value of the cash outflows relating to those securities based on the
current call price, the yield to maturity or the yield to call, as deemed
appropriate at the end of each respective year. The yields assumed were based on
securities with similar characteristics offered by corporations with credit
ratings similar to the Companies' ratings.
The fair value of investments other than cash and cash equivalents
represent cost (which approximates fair value) or the present value of the cash
inflows based on the yield to maturity. The yields assumed were based on
financial instruments with similar characteristics and terms. Investments other
than cash and cash equivalents include decommissioning trust investments. The
Companies have no securities held for trading purposes. See Note 10 for
discussion of SFAS 115 activity related to available-for-sale securities.
The investment policy for the nuclear decommissioning trust funds
restricts or limits the ability to hold certain types of assets including
private or direct placements, warrants, securities of FirstEnergy, investments
in companies owning nuclear power plants, financial derivatives, preferred
stocks, securities convertible into common stock and securities of the trust
fund's custodian or managers and their parents or subsidiaries. The investments
that are held in the decommissioning trusts (included as "All other" in the
table above) consist of equity securities ($779 million) and fixed income
securities ($573 million) as of December 31, 2003. In 2001, unrealized gains and
losses applicable to all of FirstEnergy's decommissioning trusts were recognized
in the trust investment with a corresponding change to the decommissioning
liability. In 2003 and 2002, unrealized gains and losses applicable to the
decommissioning trusts of FirstEnergy's Ohio Companies were reclassified to OCI
in accordance with SFAS 115, as fluctuations in the fair value of these trust
balances will eventually affect earnings. Realized gains (losses) are recognized
as additions (reductions) to trust asset balances. For 2003 and 2002, net
realized gains (losses) were approximately $6.0 million and $(15.6) million and
interest and dividend income totaled approximately $37.0 million and $33.2
million, respectively.
The Board of Directors authorized the repurchase of up to 15 million
shares of FirstEnergy's common stock over a three-year period beginning in 1999.
Repurchases were made on the open market, at prevailing prices, and were funded
primarily through the use of operating cash flows. During 2001, FirstEnergy
repurchased and retired 550,000 shares (average price of $27.82 per share).
FirstEnergy is exposed to financial risks resulting from the
fluctuation of interest rates and commodity prices, including electricity,
natural gas and coal. To manage the volatility relating to these exposures,
FirstEnergy uses a variety of non-derivative and derivative instruments,
including forward contracts, options, futures contracts and swaps. The
derivatives are used principally for hedging purposes, and to a lesser extent,
for trading purposes. FirstEnergy's Risk Policy Committee, comprised of
executive officers, exercises an independent risk oversight function to ensure
compliance with corporate risk management policies and prudent risk management
practices.
FirstEnergy uses derivatives to hedge the risk of price and interest
rate fluctuations. FirstEnergy's primary ongoing hedging activity involves cash
flow hedges of electricity and natural gas purchases. The maximum periods over
which the variability of electricity and natural gas cash flows are hedged are
two and three years, respectively. Gains and losses from hedges of commodity
price risks are included in net income when the underlying hedged commodities
are delivered. Also, gains and losses are included in net income when
ineffectiveness occurs on certain natural gas hedges. The impact of
ineffectiveness on earnings during 2003 was not material. FirstEnergy entered
into interest rate derivative transactions during 2001 to hedge a portion of the
anticipated interest payments on debt related to the GPU acquisition. Gains and
losses from hedges of anticipated interest payments on acquisition debt are
included in net income over the periods that hedged interest payments are made -
5, 10 and 30 years. Gains and losses from derivative contracts are included in
other operating expenses. Accumulated Other Comprehensive Loss (AOCL) as of
December 31, 2003 includes a net deferred loss of $111 million for derivative
hedging activity. The $1 million increase from the December 31, 2002 balance of
$110 million includes a $3 million reduction related to current hedging activity
and a $4 million increase
63
due to net hedge gains included in earnings during the year. Approximately $22
million (after tax) of the current net deferred loss on derivative instruments
in AOCL is expected to be reclassified to earnings during the next twelve months
as hedged transactions occur. However, the fair value of these derivative
instruments will fluctuate from period to period based on various market
factors.
During 2003, FirstEnergy and OE executed fixed-for-floating interest
rate swap agreements with notional values of $950 million and $200 million,
respectively, whereby FE and OE receive fixed cash flows based on the fixed
coupons of the hedged securities and pay variable cash flows based on short-term
variable market interest rates (6 month LIBOR index). These derivatives are
treated as fair value hedges of fixed-rate, long-term debt issues - protecting
against the risk of changes in the fair value of fixed-rate debt instruments due
to lower interest rates. Swap maturities, fixed interest rates received, and
interest payment dates match those of the underlying obligations. FirstEnergy
entered into interest rate swap agreements on a $950 million notional amount of
its and its subsidiaries' senior notes and first mortgage bonds with a weighted
average fixed interest rate of 5.46%. OE entered into interest rate swap
agreements on a $200 million notional amount of its senior notes with a weighted
average fixed interest rate of 5.09%. In addition, the cancellation options
(options with strike prices equivalent to that of the options embedded in the
call feature of the securities), on $593.5 million notional amount of cancelable
interest rate swaps on callable first mortgage bonds were exercised by swap
counterparties. As a result of the counterparties exercising these options,
FirstEnergy received $20.2 million in cash swap cancellation premiums during
2003. The amount of the cash premiums will be recognized over the remaining
maturity of each respective hedged security. As of December 31, 2003 interest
rate swap agreements with notional values totaling $1.15 billion were
outstanding.
FirstEnergy engages in the trading of commodity derivatives and
periodically experiences net open positions. FirstEnergy's risk management
policies limit the exposure to market risk from open positions and require daily
reporting to management of potential financial exposures.
3. DIVESTITURES:
INTERNATIONAL OPERATIONS-
FirstEnergy completed the sale of its international assets subsequent
to December 31, 2003 with the sales of its remaining 20.1 percent interest in
Avon (parent of Midlands Electricity in the United Kingdom) on January 16, 2004,
and its 28.67 percent interest in Termobarranquilla S.A., Empresa de Servicios
Publicos (TEBSA) for $12 million on January 30, 2004. An impairment loss of $26
million related to TEBSA was recorded in December 2003 in Other Operating
Expenses on the 2003 Consolidated Statement of Income and no gain or loss was
recognized upon the sale in 2004. Avon, TEBSA and other international assets
sold in 2003 were acquired as part of FirstEnergy's November 2001 merger with
the former GPU, Inc. FirstEnergy no longer has ownership interests in
international operating assets.
The divestiture in 2003 of international operations in Bolivia and
Argentina included the sale of FirstEnergy's wholly owned subsidiary, Guaracachi
America, Inc., a holding company with a 50.001 percent interest in EGSA, on
December 11, 2003, and its ownership in Emdersa through the abandonment of its
shares in Emdersa's parent company, GPU Argentina Holdings, Inc. on April 18,
2003 (see Note 2(I)). This resulted in a loss on sale of $33 million recognized
in Discontinued Operations in the Consolidated Statement of Income for the year
ended December 31, 2003.
FirstEnergy had sold a 79.9 percent equity interest in Avon on May 8,
2002 to Aquila, Inc. (formerly UtiliCorp United) 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.
After reaching agreement to sell its remaining 20.1 percent interest in the
fourth quarter of 2003, FirstEnergy recorded a $5 million after-tax charge to
reduce the carrying value. In the fourth quarter of 2002, FirstEnergy recorded a
$50 million after-tax charge to reduce the carrying value of its remaining 20.1
percent interest.
In the second quarter of 2003, FirstEnergy recognized an impairment
of $13 million ($8 million net of tax) related to the carrying value of the note
FirstEnergy had with Aquila from the 2002 sale of the 79.9 percent interest in
Avon. The charges in the fourth quarter of 2002 and second quarter of 2003 are
included in Other Operating Expenses on the Consolidated Statements of Income
for the years ended December 31, 2002 and 2003, respectively. After receiving
the first annual installment payment of $19 million in May 2003, FirstEnergy
sold the remaining balance of its note receivable in the secondary market and
received $63 million in proceeds on July 28, 2003.
Through 2002, FirstEnergy was unsuccessful in divesting of GPU's
former Argentina operations and made the decision to abandon its interest in
Emdersa in early 2003. A number of economic events occurred in Argentina that
hindered FirstEnergy's ability to realize Emdersa's estimated fair value. These
events included currency devaluation, restrictions on repatriation of cash, and
the anticipation of future asset sales in that region by competitors. 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 recognized a one-time, non-cash charge of $67 million,
or $0.23 per share of common stock in the second quarter of 2003. This charge is
the result of realizing the currency translation adjustment (CTA) losses through
current period
64
earnings ($90 million, or $0.30 per share), partially offset by the gain
recognized from abandoning FirstEnergy's investment in Emdersa ($23 million, or
$0.07 per share). Since FirstEnergy had previously recorded $90 million of CTA
adjustments in OCI, the net effect of the $67 million charge was an increase in
common stockholders' equity of $23 million. In addition, FirstEnergy reflected
Emdersa's 2002 results of an after-tax loss of $87 million (including $109
million in currency transaction losses arising principally from U.S. dollar
denominated debt) as discontinued operations in the Consolidated Statement of
Income for the year ended December 31, 2002. FirstEnergy also recognized a CTA
of $91 million in 2002 which reduced FirstEnergy's common stockholders' equity.
This adjustment represented the impact of translating Emdersa's financial
statements from its functional currency to the U.S. dollar for GAAP financial
reporting.
The $67 million after-tax charge in 2003 does not include the
expected income tax benefits related to the abandonment, which were fully
reserved during the second quarter of 2003. FirstEnergy expects 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 of tax benefits would reduce goodwill recognized in
connection with the acquisition of GPU.
GENERATION ASSETS-
In November 2001, FirstEnergy reached an agreement to sell four
coal-fired power plants totaling 2,535 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. NRG filed voluntary bankruptcy petitions in May 2003; subsequently
FirstEnergy reached an agreement for settlement of its claim against NRG. Under
NRG's proposed Plan of Reorganization, FirstEnergy, as an unsecured creditor,
could receive an estimated settlement of approximately $198 million, with
payment in the form of cash (12%), notes (15.2%) and new NRG common stock
(72.8%). FirstEnergy sold its entire claim (including $32 million of cash
proceeds received in December 2003) for $170 million in January 2004.
In December 2002, FirstEnergy decided to 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) of previously unrecognized depreciation and other
transaction costs in the fourth quarter of 2002 related to these plants from
November 2001 through December 2002 on its Consolidated Statements of Income.
OTHER DOMESTIC OPERATIONS-
Sales of domestic assets in 2003 included three FSG subsidiaries -
Ancoma, Inc., a mechanical contracting company based in Rochester, New York, and
Virginia-based Colonial Mechanical and Webb Technologies - and a MARBEL
subsidiary - Northeast Ohio Natural Gas (see Note 2(I)).
4. LEASES:
The Companies lease certain generating facilities, office space and
other property and equipment under cancelable and noncancelable leases.
OE sold portions of its ownership interests in Perry Unit 1 and
Beaver Valley Unit 2 and entered into operating leases on the portions sold for
basic lease terms of approximately 29 years. CEI and TE also sold portions of
their ownership interests in Beaver Valley Unit 2 and Bruce Mansfield Units 1, 2
and 3 and entered into similar operating leases for lease terms of approximately
30 years. During the terms of their respective leases, OE, CEI and TE continue
to be responsible, to the extent of their individual combined ownership and
leasehold interests, for costs associated with the units including construction
expenditures, operation and maintenance expenses, insurance, nuclear fuel,
property taxes and decommissioning. They have the right, at the expiration of
the respective basic lease terms, to renew their respective leases. They also
have the right to purchase the facilities at the expiration of the basic lease
term or any renewal term at a price equal to the fair market value of the
facilities. The basic rental payments are adjusted when applicable federal tax
law changes.
OES Finance, Incorporated, a wholly owned subsidiary of OE, maintains
deposits pledged as collateral to secure reimbursement obligations relating to
certain letters of credit supporting OE's obligations to lessors under the
Beaver Valley Unit 2 sale and leaseback arrangements. The deposits of
approximately $278 million pledged to the financial institution providing those
letters of credit are the sole property of OES Finance and are investments which
are classified as "Held to Maturity". In the event of liquidation, OES Finance,
as a separate corporate entity, would have to satisfy its obligations to
creditors before any of its assets could be made available to OE as sole owner
of OES Finance common stock.
65
Consistent with the regulatory treatment, the rentals for capital and
operating leases are charged to operating expenses on the Consolidated
Statements of Income. Such costs for the three years ended December 31, 2003 are
summarized as follows:
2003 2002 2001
- -------------------------------------------------------------------------------
(In millions)
Operating leases
Interest element...................... $181 $188 $194
Other................................. 150 136 120
Capital leases
Interest element...................... 2 2 8
Other................................. 2 3 36
- -----------------------------------------------------------------------------
Total rentals...................... $335 $329 $358
=============================================================================
OE invested in the PNBV Capital Trust, which was established to
purchase a portion of the lease obligation bonds issued on behalf of lessors in
OE's Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback transactions. CEI
and TE established the Shippingport Capital Trust to purchase the lease
obligation bonds issued on behalf of lessors in their Bruce Mansfield Units 1, 2
and 3 sale and leaseback transactions. The PNBV and Shippingport Capital Trust
arrangements effectively reduce lease costs related to those transactions (see
Note 9).
The future minimum lease payments as of December 31, 2003, are:
Operating Leases
-----------------------------------
Capital Lease Capital
Leases Payments Trusts Net
--------------------------------------------------------------------------------------------
(In millions)
2004.................................. $ 6 $ 294 $ 112 $ 182
2005.................................. 5 313 130 183
2006.................................. 5 322 142 180
2007.................................. 1 300 131 169
2008.................................. 1 294 105 189
Years thereafter...................... 6 2,514 872 1,642
--------------------------------------------------------------------------------------------
Total minimum lease payments.......... 24 $4,037 $1,492 $2,545
====== ====== ======
Executory costs....................... 5
---------------------------------------------
Net minimum lease payments............ 19
Interest portion...................... 6
---------------------------------------------
Present value of net minimum
lease payments...................... 13
Less current portion.................. 2
---------------------------------------------
Noncurrent portion.................... $11
---------------------------------------------
FirstEnergy has recorded above-market lease liabilities for Beaver
Valley Unit 2 and the Bruce Mansfield Plant associated with the 1997 merger
between OE and Centerior. The total above-market lease obligation of $722
million associated with Beaver Valley Unit 2 is being amortized on a
straight-line basis through the end of the lease term in 2017 (approximately $37
million per year). The total above-market lease obligation of $755 million
associated with the Bruce Mansfield Plant is being amortized on a straight-line
basis through the end of 2016 (approximately $48 million per year). As of
December 31, 2003 the above-market lease liabilities for Beaver Valley Unit 2
and the Bruce Mansfield Plant totaled $1.1 billion, of which $85 million is
current.
5. CAPITALIZATION:
(A) RETAINED EARNINGS-
There are no restrictions on retained earnings for payment of cash
dividends on FirstEnergy's common stock.
(B) EMPLOYEE STOCK OWNERSHIP PLAN (ESOP) -
An ESOP Trust funds most of the matching contribution for
FirstEnergy's 401(k) savings plan. All full-time employees eligible for
participation in the 401(k) savings plan are covered by the ESOP. The ESOP
borrowed $200 million from OE and acquired 10,654,114 shares of OE's common
stock (subsequently converted to FirstEnergy common stock) through market
purchases. Dividends on ESOP shares are used to service the debt. Shares are
released from the ESOP on a pro rata basis as debt service payments are made. In
2003, 2002 and 2001, 1,069,318 shares, 1,151,106 shares and 834,657 shares,
respectively, were allocated to employees with the corresponding expense
recognized based on the shares allocated method. The fair value of 2,896,951
shares unallocated as of December 31, 2003, was approximately $102.0 million.
Total ESOP-related compensation expense was calculated as follows:
66
2003 2002 2001
- -------------------------------------------------------------------------------
(In millions)
Base compensation............................ $35.1 $34.2 $25.1
Dividends on common stock held by the ESOP
and used to service debt................... (9.1) (7.8) (6.1)
- --------------------------------------------------------------------------------
Net expense.............................. $26.0 $26.4 $19.0
================================================================================
(C) STOCK COMPENSATION PLANS-
In 2001, FirstEnergy assumed responsibility for two stock-based plans
as a result of its acquisition of GPU. No further stock-based compensation can
be awarded under the GPU, Inc. Stock Option and Restricted Stock Plan for MYR
Group Inc. Employees (MYR Plan) or the 1990 Stock Plan for Employees of GPU,
Inc. and Subsidiaries (GPU Plan). All options and restricted stock under both
plans have been converted into FirstEnergy options and restricted stock. Options
under the GPU Plan became fully vested on November 7, 2001, and will expire on
or before June 1, 2010. Under the MYR Plan, all options and restricted stock
maintained their original vesting periods, which range from one to four years,
and will expire on or before December 17, 2006.
Additional stock-based plans administered by FirstEnergy include the
Centerior Equity Plan (CE Plan) and the FirstEnergy Executive and Director
Incentive Compensation Plan (FE Plan). All options are fully vested under the CE
Plan, and no further awards are permitted. Outstanding options will expire on or
before February 25, 2007. Under the FE Plan, total awards cannot exceed 22.5
million shares of common stock or their equivalent. Only stock options and
restricted stock have been granted, with vesting periods ranging from six months
to seven years.
Collectively, the above plans are referred to as the FE Programs.
Restricted common stock grants under the FE Programs were as follows:
2003 2002 2001
- ----------------------------------------------------------------------------
Restricted common shares granted......... -- 36,922 133,162
Weighted average market price ........... n/a (1) $36.04 $35.68
Weighted average vesting period (years).. n/a (1) 3.2 3.7
Dividends restricted..................... n/a (1) Yes -- (2)
- ----------------------------------------------------------------------------
(1) Not applicable since no restricted stock was granted.
(2) FE Plan dividends are paid as restricted stock on 4,500
shares; MYR Plan dividends are paid as unrestricted cash
on 128,662 shares
Under the Executive Deferred Compensation Plan (EDCP), covered
employees can direct a portion of their Annual Incentive Award and/or Long-Term
Incentive Award into an unfunded FirstEnergy Stock Account to receive vested
stock units. An additional 20% premium is received in the form of stock units
based on the amount allocated to the FirstEnergy Stock Account. Dividends are
calculated quarterly on stock units outstanding and are paid in the form of
additional stock units. Upon withdrawal, stock units are converted to
FirstEnergy shares. Payout typically occurs three years from the date of
deferral; however, an election can be made in the year prior to payout to
further defer shares into a retirement stock account that will pay out in cash
upon retirement. As of December 31, 2003, there were 410,399 stock units
outstanding. See Note 10(D) for discussion of stock-based employee compensation
expense recognized for restricted stock and EDCP stock units.
67
Stock option activities under the FE Programs for the past three
years were as follows:
Number of Weighted Average
Stock Option Activities Options Exercise Price
- ------------------------------------------------------------------------------
Balance, January 1, 2001.............. 5,021,862 24.09
(473,314 options exercisable)......... 24.11
Options granted..................... 4,240,273 28.11
Options exercised................... 694,403 24.24
Options forfeited................... 120,044 28.07
Balance, December 31, 2001............ 8,447,688 26.04
(1,828,341 options exercisable)....... 24.83
Options granted..................... 3,399,579 34.48
Options exercised................... 1,018,852 23.56
Options forfeited................... 392,929 28.19
Balance, December 31, 2002............ 10,435,486 28.95
(1,400,206 options exercisable)....... 26.07
Options granted..................... 3,981,100 29.71
Options exercised................... 455,986 25.94
Options forfeited................... 311,731 29.09
Balance, December 31, 2003............ 13,648,869 29.27
(1,919,662 options exercisable)....... 29.67
As of December 31, 2003, the weighted average remaining contractual
life of outstanding stock options was 7.6 years.
Options outstanding by plan and range of exercise price as of
December 31, 2003 were as follows:
Range of Options
FirstEnergy Program Exercise Prices Outstanding
------------------------------------------------------------------------
FE plan $19.31 - $29.87 9,904,861
$30.17 - $35.15 3,214,601
Plans acquired through merger:
GPU plan $23.75 - $35.92 501,734
Other plans 27,673
----------------------------------------------------------------------
Total 13,648,869
======================================================================
No material stock-based employee compensation expense is reflected in
net income for stock options granted under the above plans since the exercise
price was equal to the market value of the underlying common stock on the grant
date. The effect of applying fair value accounting to FirstEnergy's stock
options is summarized in Note 2(G) - Stock-Based Compensation.
(D) PREFERRED AND PREFERENCE STOCK-
All preferred stock may be redeemed by the Companies in whole, or in
part, with 30-90 days' notice.
Met-Ed's and Penelec's preferred stock authorization consists of 10
million and 11.435 million shares, respectively, without par value. No preferred
shares are currently outstanding for the two companies.
The Companies' preference stock authorization consists of 8 million
shares without par value for OE; 3 million shares without par value for CEI; and
5 million shares, $25 par value for TE. No preference shares are currently
outstanding.
(E) LONG-TERM DEBT-
Each of the Companies has a first mortgage indenture under which it
issues first mortgage bonds secured by a direct first mortgage lien on
substantially all of its property and franchises, other than specifically
excepted property. FirstEnergy and its subsidiaries have various debt covenants
under their respective financing arrangements. The most restrictive of the debt
covenants relate to the nonpayment of interest and/or principal on debt and the
maintenance of certain financial ratios. The nonpayments debt covenant which
could trigger a default is applicable to financing arrangements of FirstEnergy
and all of the Companies. The maintenance of minimum fixed charge ratios and
debt to capitalization ratios covenants is applicable to financing arrangements
of FirstEnergy, the Ohio Companies and Penn. There also exist cross-default
provisions among financing arrangements of FirstEnergy and the Companies.
68
Based on the amount of bonds authenticated by the respective mortgage
bond trustees through December 31, 2003, the Companies' annual sinking fund
requirements for all bonds issued under the various mortgage indentures of the
Companies amounts to $61.9 million. OE and Penn expect to deposit funds with
their respective mortgage bond trustees in 2004 that will then be withdrawn upon
the surrender for cancellation of a like principal amount of bonds, specifically
authenticated for such purposes against unfunded property additions or against
previously retired bonds. This method can result in minor increases in the
amount of the annual sinking fund requirement. JCP&L, Met-Ed and Penelec expect
to fulfill their sinking fund obligations by providing bondable property
additions and/or retired bonds to the respective mortgage bond trustees.
Sinking fund requirements for first mortgage bonds and maturing
long-term debt (excluding capital leases) for the next five years are:
(In millions)
--------------------------------
2004.............. $1,750
2005.............. 683
2006.............. 1,377
2007.............. 237
2008.............. 385
--------------------------------
Included in the table above are amounts for various variable interest
rate long-term debt which have provisions by which individual debt holders have
the option to "put back" or require the respective debt issuer to redeem their
debt at those times when the interest rate may change prior to its maturity
date. These amounts are $494 million, $97 million and $50 million in 2004, 2005
and 2008, respectively, which represents the next date at which the debt holders
may exercise this provision.
The Companies' obligations to repay certain pollution control revenue
bonds are secured by several series of first mortgage bonds. Certain pollution
control revenue bonds are entitled to the benefit of irrevocable bank letters of
credit of $220 million and noncancelable municipal bond insurance policies of
$482 million to pay principal of, or interest on, the pollution control revenue
bonds. To the extent that drawings are made under the letters of credit or
policies, the Companies are entitled to a credit against their obligation to
repay those bonds. The Companies pay annual fees of 1.125% to 1.50% of the
amounts of the letters of credit to the issuing banks and are obligated to
reimburse the banks for any drawings thereunder.
FirstEnergy had unsecured borrowings of $270 million as of December
31, 2003, under its $500 million revolving credit facility agreement which
expires November 29, 2004. FirstEnergy currently pays an annual facility fee of
0.425% on the total credit facility amount. FirstEnergy had no borrowings as of
December 31, 2003 under a new $375 million long-term revolving credit facility
agreement which expires October 23, 2006. FirstEnergy currently pays an annual
facility fee of 0.50% on the total credit facility amount. The fees are subject
to change based on changes to FirstEnergy's credit ratings.
OE had unsecured borrowings of $40 million as of December 31, 2003
under a $250 million long-term revolving credit facility agreement which expires
May 12, 2005. OE currently pays an annual facility fee of 0.20% on the total
credit facility amount. OE had no unsecured borrowings as of December 31, 2003
under a $125 million long-term revolving credit facility which expires October
23, 2006. OE currently pays an annual facility fee of 0.25% on the total credit
facility amount. The fees are subject to change based on changes to OE's credit
ratings.
CEI and TE have unsecured letters of credit of approximately $216
million in connection with the sale and leaseback of Beaver Valley Unit 2 that
expire in April 2005. CEI and TE are jointly and severally liable for the
letters of credit. In connection with its Beaver Valley Unit 2 sale and
leaseback arrangements, OE has similar letters of credit secured by deposits
held by its subsidiary, OES Finance (see Note 4).
(F) LONG-TERM DEBT: PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION-
Effective July 1, 2003, upon adoption of SFAS 150 (see Note 9),
FirstEnergy reclassified as debt the preferred stock of consolidated
subsidiaries subject to mandatory redemption. Prior year amounts were not
reclassified.
Annual sinking fund provisions for the Companies' preferred stock are
as follows:
Redemption
Price Per
Series Shares Share
------------------------------------------------------------------
CEI.......... $7.35C 10,000 $ 100
Penn......... 7.625% 7,500 100
------------------------------------------------------------------
69
Annual sinking fund requirements for the next five years are $1.8
million in each year 2004 through 2006, $12.3 million in 2007 and $1.0 million
in 2008.
(G) LONG-TERM DEBT: SUBORDINATED DEBENTURES TO AFFILIATED TRUSTS-
CEI formed a wholly owned statutory business trust to sell preferred
securities and invest the gross proceeds in the 9.00% subordinated debentures of
CEI. The sole assets of the trust are the applicable subordinated debentures.
Interest payment provisions of the subordinated debentures match the
distribution payment provisions of the trust's preferred securities. In
addition, upon redemption or payment at maturity of subordinated debentures, the
trust's preferred securities will be redeemed on a pro rata basis at their
liquidation value. Under certain circumstances, the applicable subordinated
debentures could be distributed to the holders of the outstanding preferred
securities of the trust in the event that the trust is liquidated. CEI has
effectively provided a full and unconditional guarantee of payments due on the
trust's preferred securities. The trust's preferred securities are redeemable at
100% of their principal amount at CEI's option beginning in December 2006.
Met-Ed and Penelec each formed statutory business trusts for
substantially similar transactions to those of CEI. However, ownership of the
respective Met-Ed and Penelec trusts is through separate wholly owned limited
partnerships. In these transactions, each trust invested the gross proceeds from
the sale of its preferred securities in the preferred securities of the
applicable limited partnership, which in turn invested those proceeds in the
7.35% and 7.34% subordinated debentures of Met-Ed and Penelec, respectively. In
each case, Met-Ed and Penelec has effectively provided a full and unconditional
guarantee of obligations under the trust's preferred securities. The trust's
preferred securities are redeemable at the option of Met-Ed and Penelec
beginning in May 2004 and September 2004, respectively, at 100% of their
principal amount.
In each of these transactions, interest on the subordinated
debentures (and therefore distributions on the trust's preferred securities) may
be deferred for up to 60 months, but CEI, Met-Ed and Penelec may not pay
dividends on, or redeem or acquire, any of its cumulative preferred or common
stock until deferred payments on its subordinated debentures are paid in full.
Upon adoption of FASB Interpretation No. 46 (revised December 2003),
"Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51"
(FIN 46R), the limited partnerships and statutory business trusts discussed
above are not consolidated on the financial statements of FirstEnergy, CEI,
Met-Ed and Penelec as of December 31, 2003 (see Note 9).
The following table displays information regarding preferred
securities of statutory business trusts outstanding as of December 31, 2003:
Stated Subordinated
Maturity Rate Value Debentures
- ------------------------------------------------------------------------------------------
(In millions)
Cleveland Electric Financing Trust (a) 2031 9.00% $100.0 $103.1
Met-Ed Capital Trust (b).............. 2039 7.35% $100.0 $103.1
Penelec Capital Trust (b)............. 2039 7.34% $100.0 $103.1
- ------------------------------------------------------------------------------------------
<FN>
(a) The sole assets of the trust are CEI's subordinated debentures with the
same rate and maturity date as the preferred securities.
(b) The sole assets of the trust are the preferred securities of Met-Ed
Capital II, L.P. and Penelec Capital II, L.P., respectively, whose sole
assets are the subordinated debentures of Met-Ed and Penelec,
respectively, with the same rate and maturity date as the preferred
securities.
</FN>
(H) SECURITIZED TRANSITION BONDS-
On June 11, 2002, JCP&L Transition Funding LLC (Issuer), a wholly
owned limited liability company of JCP&L, sold $320 million of transition bonds
to securitize the recovery of JCP&L's bondable stranded costs associated with
the previously divested Oyster Creek Nuclear Generating Station.
JCP&L does not own nor did it purchase any of the transition bonds,
which are included in long-term debt on FirstEnergy's Consolidated Balance
Sheet. The transition bonds represent obligations only of the Issuer and are
collateralized solely by the equity and assets of the Issuer, which consist
primarily of bondable transition property. The bondable transition property is
solely the property of the Issuer.
Bondable transition property represents the irrevocable right of a
utility company to charge, collect and receive from its customers, through a
non-bypassable TBC, the principal amount and interest on the transition bonds
and other fees and expenses associated with their issuance. JCP&L, as servicer,
manages and administers the bondable transition property, including the billing,
collection and remittance of the TBC, pursuant to a servicing agreement with the
Issuer. JCP&L is entitled to a quarterly servicing fee of $100,000 that is
payable from TBC collections.
70
(I) COMPREHENSIVE INCOME-
Comprehensive income includes net income as reported on the
Consolidated Statements of Income and all other changes in common stockholders'
equity except those resulting from transactions with common stockholders. As of
December 31, 2003, accumulated other comprehensive income (loss) consisted of a
minimum liability for unfunded retirement benefits of $306 million, unrealized
gains on investments in securities available for sale of $64 million, and
unrealized losses on derivative instrument hedges of $111 million. Other
comprehensive income (loss) reclassified to net income in 2003, 2002 and 2001
totaled $29 million, $(10) million and $31 million, respectively. These amounts
were net of income taxes in 2003, 2002 and 2001 of $20 million, $(7) million and
$22 million, respectively.
6. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT:
Short-term borrowings outstanding as of December 31, 2003, consisted
of $372 million of bank borrowings and $150 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 and is required to pay an annual fee of 0.50% on
the amount of the entire finance limit. The receivables financing agreement
expires in October 2004.
FirstEnergy and its subsidiaries have various credit facilities
(including a FirstEnergy $375 million short-term revolving credit facility) with
domestic and foreign banks that provide for borrowings of up to $604 million
under various interest rate options. To assure the availability of these lines,
FirstEnergy and its subsidiaries are required to pay annual commitment fees that
vary from 0.20% to 0.375%. These lines expire at various times during 2004. The
weighted average interest rates on short-term borrowings outstanding as of
December 31, 2003 and 2002 were 2.14% and 2.41%, respectively.
7. COMMITMENTS, GUARANTEES AND CONTINGENCIES:
(A) CAPITAL EXPENDITURES-
FirstEnergy's current forecast reflects expenditures of approximately
$2.3 billion for property additions and improvements from 2004-2006, of which
approximately $713 million is applicable to 2004. Investments for additional
nuclear fuel during the 2004-2006 period are estimated to be approximately $323
million, of which approximately $90 million applies to 2004. During the same
periods, the Companies' nuclear fuel investments are expected to be reduced by
approximately $285 million and $93 million, respectively, as the nuclear fuel is
consumed.
(B) NUCLEAR INSURANCE-
The Price-Anderson Act limits the public liability relative to a
single incident at a nuclear power plant to $10.9 billion. The amount is covered
by a combination of private insurance and an industry retrospective rating plan.
The Companies' maximum potential assessment under the industry retrospective
rating plan would be $402 million per incident but not more than $40 million in
any one year for each incident.
The Companies are also insured under policies for each nuclear plant.
Under these policies, up to $2.75 billion is provided for property damage and
decontamination costs. The Companies have also obtained approximately $1.2
billion of insurance coverage for replacement power costs. Under these policies,
the Companies can be assessed a maximum of approximately $64 million for
incidents at any covered nuclear facility occurring during a policy year which
are in excess of accumulated funds available to the insurer for paying losses.
The Companies intend to maintain insurance against nuclear risks as
described above as long as it is available. To the extent that replacement
power, property damage, decontamination, repair and replacement costs and other
such costs arising from a nuclear incident at any of the Companies' plants
exceed the policy limits of the insurance in effect with respect to that plant,
to the extent a nuclear incident is determined not to be covered by the
Companies' insurance policies, or to the extent such insurance becomes
unavailable in the future, the Companies would remain at risk for such costs.
(C) GUARANTEES AND OTHER ASSURANCES-
As part of normal business activities, FirstEnergy enters into
various agreements on behalf of its subsidiaries to provide financial or
performance assurances to third parties. Such agreements include contract
guarantees, surety bonds and ratings contingent collateralization provisions. As
of December 31, 2003, outstanding guarantees and other assurances aggregated
approximately $1.9 billion.
71
FirstEnergy guarantees energy and energy-related payments of its
subsidiaries involved in energy marketing activities - principally to facilitate
normal physical transactions involving electricity, gas, emission allowances and
coal. FirstEnergy also provides guarantees to various providers of subsidiary
financing principally for the acquisition of property, plant and equipment.
These agreements legally obligate FirstEnergy and its subsidiaries to fulfill
the obligations of those subsidiaries directly involved in energy and
energy-related transactions or financing where the law might otherwise limit the
counterparties' claims. If demands of a counterparty were to exceed the ability
of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables
the counterparty's legal claim to be satisfied by other FirstEnergy assets. The
likelihood that such parental guarantees of $1.0 billion (included in the $1.9
billion discussed above) as of December 31, 2003 will increase amounts otherwise
to be paid by FirstEnergy to meet its obligations incurred in connection with
financings and ongoing energy and energy-related activities is remote.
While guarantees are normally parental commitments for the future
payment of subsidiary obligations, subsequent to the occurrence of a credit
rating-downgrade or "material adverse event" the immediate payment of cash
collateral or provision of a letter of credit may be required. The following
table summarizes collateral provisions as of December 31, 2003:
Collateral Paid
---------------------------- Remaining
Collateral Provisions Exposure Cash Letters of Credit Exposure(1)
- ------------------------------------------------------------------------------------------
(In millions)
Rating downgrade.......... $187 $68 $ 5 $114
Adverse Event............. 235 -- 65 170
-------------------------------------------------------------------------------------
Total..................... $422 $68 $70 $284
=====================================================================================
<FN>
(1) As of February 11, 2004, we had a remaining exposure of $282
million with $106 million of cash and $87 million of letters of
credit provided as collateral.
</FN>
Most of FirstEnergy's surety bonds are backed by various indemnities
common within the insurance industry. Surety bonds and related FirstEnergy
guarantees of $161 million provide additional assurance to outside parties that
contractual and statutory obligations will be met in a number of areas including
construction jobs, environmental commitments and various retail transactions.
FirstEnergy has also guaranteed the obligations of the operators of
the TEBSA project, up to a maximum of $6 million (subject to escalation) under
the project's operations and maintenance agreement. In connection with the sale
of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss
under this guarantee. FirstEnergy had provided the TEBSA project lenders a $50
million letter of credit (LOC) (under FirstEnergy's existing $250 million LOC
capacity available as part of a $1.25 billion FirstEnergy credit facility) to
obtain TEBSA lender consent as substitute collateral for the release of the
assets for FirstEnergy to abandon its Argentina operations, Emdersa (see Note
3). In December 2003, a replacement LOC was issued in the amount of $60 million,
which is renewable and declines yearly based upon the senior outstanding debt of
TEBSA. This LOC granted FirstEnergy the ability to sell its remaining 20.1%
interest in Avon, as well as abandon the Argentina assets in April 2003.
(D) ENVIRONMENTAL MATTERS-
Various federal, state and local authorities regulate the Companies
with regard to air and water quality and other environmental matters. 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 that 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.
Overall, FirstEnergy believes it is in material compliance with existing
regulations but is unable to predict future change in regulatory policies and
what, if any, the effects of such change would be. FirstEnergy estimates
additional capital expenditures for environmental compliance of approximately
$91 million for 2004 through 2006, which is included in the $2.3 billion of
forecasted capital expenditures for 2004 through 2006 (see Note 7(A)).
Additional estimated capital expenditures of $481 million relating to proposed
environmental laws could be required after 2006.
Clean Air Act Compliance
The Companies are required to meet federally approved sulfur dioxide
(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 Environmental Protection Agency (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 are complying with SO2 reduction requirements under the
Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more
electricity from lower-emitting plants, and/or using emission
72
allowances. NOx reductions required by the 1990 Amendments 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 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 (including
Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia 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.
New Jersey and Pennsylvania submitted a SIP that required compliance with the
NOx budgets at the Companies' New Jersey and Pennsylvania facilities by May 1,
2003. Michigan and Ohio submitted a SIP that requires compliance with the NOx
budgets at the Companies' Michigan and Ohio facilities by May 31, 2004.
National Ambient Air Quality Standards
In July 1997, the EPA promulgated changes in the National Ambient Air
Quality Standard (NAAQS) for ozone and proposed a new NAAQS for fine particulate
matter. On December 17, 2003, the EPA proposed the "Interstate Air Quality Rule"
covering a total of 29 states (including New Jersey, Ohio and Pennsylvania) and
the District of Columbia based on proposed findings that air pollution emissions
from 29 eastern states and the District of Columbia significantly contribute to
nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in
other states. The EPA has proposed the Interstate Air Quality Rule to
"cap-and-trade" NOx and SO2 emissions in two phases (Phase I in 2010 and Phase
II in 2015). According to the EPA, SO2 emissions would be reduced by
approximately 3.6 million tons in 2010, across states covered by the rule, with
reductions ultimately reaching more than 5.5 million tons annually. NOx emission
reductions would measure about 1.5 million tons in 2010 and 1.8 million tons in
2015. The future cost of compliance with these proposed regulations may be
substantial and will depend on whether and how they are ultimately implemented
by the states in which the Companies operate affected facilities.
Mercury Emissions
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants, identifying mercury as the hazardous air pollutant of greatest
concern. On December 15, 2003, the EPA proposed two different approaches to
reduce mercury emissions from coal-fired power plants. The first approach would
require plants to install controls known as "maximum achievable control
technologies" (MACT) based on the type of coal burned. According to the EPA, if
implemented, the MACT proposal would reduce nationwide mercury emissions from
coal-fired power plants by fourteen tons to approximately thirty-four tons per
year. The second approach proposes a cap-and-trade program that would reduce
mercury emissions in two distinct phases. Initially, mercury emissions would be
reduced by 2010 as a "co-benefits" from implementation of SO2 and NOx emission
caps under the EPA's proposed Interstate Air Quality Rule. Phase II of the
mercury cap-and-trade program would be implemented in 2018 to cap nationwide
mercury emissions from coal-fired power plants at fifteen tons per year. The EPA
has agreed to choose between these two options and issue a final rule by
December 15, 2004. The future cost of compliance with these regulations may be
substantial.
W. H. Sammis Plant
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. The NOV and complaint allege violations of the Clean Air Act based on
operation and maintenance of the W. H. Sammis Plant dating back to 1984. The
complaint requests permanent injunctive relief to require the installation of
"best available control technology" and civil penalties of up to $27,500 per day
of violation. On August 7, 2003, the United States District Court for the
Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis
Plant between 1984 and 1998 required pre-construction permits under the Clean
Air Act. The ruling concludes the liability phase of the case, which deals with
applicability of Prevention of Significant Deterioration provisions of the Clean
Air Act. The remedy phase, which is currently scheduled to be ready for trial
beginning July 19, 2004, will address civil penalties and what, if any, actions
should be taken to further reduce emissions at the plant. In the ruling, the
Court indicated that the remedies it "may consider and impose involved a much
broader, equitable analysis, requiring the Court to consider air quality, public
health, economic impact, and employment consequences. The Court may also
consider the less than consistent efforts of the EPA to apply and further
enforce the Clean Air Act." The potential penalties that may be imposed, as well
as the capital expenditures necessary to comply with substantive remedial
measures that may be required, could have a material adverse impact on
FirstEnergy's financial condition and results of operations. Management is
unable to predict the ultimate outcome of this matter and no liability has been
accrued as of December 31, 2003.
73
Regulation of Hazardous Waste
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 subsequently determined 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, environmental liabilities that are considered probable have been
recognized on the Consolidated Balance Sheet as of December 31, 2003, 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 a non-bypassable societal benefits charge.
Included in Current Liabilities and Other Noncurrent Liabilities are accrued
liabilities aggregating approximately $65 million as of December 31, 2003. The
Companies accrue environmental liabilities only when they can conclude that it
is probable that they have an obligation for such costs and can reasonably
determine the amount of such costs. Unasserted claims are reflected in the
Companies' determination of environmental liabilities and are accrued in the
period that they are both probable and reasonably estimable.
Climate Change
In December 1997, delegates to the United Nations' climate summit in
Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global
warming by reducing the amount of man-made greenhouse gases emitted by developed
countries by 5.2% from 1990 levels between 2008 and 2012. The United States
signed the Protocol in 1998 but it failed to receive the two-thirds vote of the
U.S. Senate required for ratification. However, the Bush administration has
committed the United States to a voluntary climate change strategy to reduce
domestic greenhouse gas intensity - the ratio of emissions to economic output -
by 18% through 2012.
The Companies cannot currently estimate the financial impact of
climate change policies although the potential restrictions on carbon dioxide
(CO2) emissions could require significant capital and other expenditures.
However, the CO2 emissions per kilowatt-hour of electricity generated by the
Companies is lower than many regional competitors due to the Companies'
diversified generation sources which includes low or non-CO2 emitting gas-fired
and nuclear generators.
Clean Water Act
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.
(E) OTHER LEGAL PROCEEDINGS-
Various lawsuits, claims for personal injury, asbestos and property
damage and proceedings related to FirstEnergy's normal business operations are
pending against FirstEnergy and its subsidiaries. The most significant not
otherwise discussed above are described below.
Power Outages
In July 1999, the Mid-Atlantic states experienced a severe heat storm
which resulted in power outages throughout the service territories of many
electric utilities, including JCP&L's territory. In an investigation into the
causes of the outages and the reliability of the transmission and distribution
systems of all four New Jersey electric utilities, the NJBPU concluded that
there was not a prima facie case demonstrating that, overall, JCP&L provided
unsafe, inadequate or improper service to its customers. Two class action
lawsuits (subsequently consolidated into a single proceeding) were filed in New
Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies,
seeking compensatory and punitive damages arising from the July 1999 service
interruptions in the JCP&L territory.
74
Since July 1999, this litigation has involved a substantial amount of
legal discovery including interrogatories, request for production of documents,
preservation and inspection of evidence, and depositions of the named plaintiffs
and many JCP&L employees. In addition, there have been many motions filed and
argued by the parties involving issues such as the primary jurisdiction and
findings of the NJBPU, consumer fraud by JCP&L, strict product liability, class
decertification, and the damages claimed by the plaintiffs. In January 2000, the
NJ Appellate Division determined that the trial court has proper jurisdiction
over this litigation. In August 2002, the trial court granted partial summary
judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud,
common law fraud, negligent misrepresentation, and strict products liability. In
November 2003, the trial court granted JCP&L's motion to decertify the class and
denied plaintiffs' motion to permit into evidence their class-wide damage model
indicating damages in excess of $50 million. These class decertification and
damage rulings have been appealed to the Appellation Division and oral argument
is scheduled for May 2004. FirstEnergy is unable to predict the outcome of these
matters and no liability has been accrued as of December 31, 2003.
On August 14, 2003, various states and parts of southern Canada
experienced a widespread power outage. That outage affected approximately 1.4
million customers in FirstEnergy's service area. FirstEnergy continues to
accumulate data and evaluate the status of its electrical system prior to and
during the outage event, and continues to cooperate with the U.S.-Canada Power
System Outage Task Force (Task Force) investigating the August 14th outage. The
interim report issued by the Task Force on November 18, 2003 concluded that the
problems leading to the outage began in FirstEnergy's service area.
Specifically, the interim report concludes, among other things, that the
initiation of the August 14th outage resulted from the coincidence on that
afternoon of the following events: (1) inadequate situational awareness at
FirstEnergy; (2) FirstEnergy's failure to adequately manage tree growth in its
transmission rights of way; and (3) failure of the interconnected grid's
reliability organizations (Midwest Independent System Operator and PJM
Interconnection) to provide effective diagnostic support. FirstEnergy believes
that the interim report does not provide a complete and comprehensive picture of
the conditions that contributed to the August 14th outage and that it does not
adequately address the underlying causes of the outage. FirstEnergy remains
convinced that the outage cannot be explained by events on any one utility's
system. On November 25, 2003, the PUCO ordered FirstEnergy to file a plan with
the PUCO no later than March 1, 2004, illustrating how FirstEnergy will correct
problems identified by the Task Force as events contributing to the August 14th
outage and addressing how FirstEnergy proposes to upgrade its control room
computer hardware and software and improve the training of control room
operators to ensure that similar problems do not occur in the future. The PUCO,
in consultation with the North American Electric Reliability Council, will
review the plan before determining the next steps in the proceeding. On December
24, 2003, the FERC ordered FirstEnergy to pay for an independent study of part
of Ohio's power grid. The study is to examine the stability of the grid in
critical points in the Cleveland and Akron areas; the status of projected power
reserves during summer 2004 through 2008; and the need for new transmission
lines or other grid projects. The FERC ordered the study to be completed within
120 days. At this time, it is unknown what the cost of such study will be, or
the impact of the results.
Davis-Besse
FENOC recently received a subpoena from a grand jury sitting in the
United States District Court for the Northern District of Ohio, Eastern Division
requesting the production of certain documents and records relating to the
inspection and maintenance of the reactor vessel head at the Davis-Besse plant.
We are unable to predict the outcome of this investigation. In addition, FENOC
remains subject to possible civil enforcement action by the NRC in connection
with the events leading to the Davis Besse outage. If it were ultimately
determined that FirstEnergy has legal liability or is otherwise made subject to
regulatory or civil enforcement action with respect to the Davis-Besse outage,
it could have a material adverse effect on FirstEnergy's financial condition and
results of operations.
Other Legal Matters
Various legal proceedings have been filed against FirstEnergy in
connection with, among other things, the restatements in August 2003, by
FirstEnergy and its Ohio utility subsidiaries of previously reported results,
the August 14th power outage described above, and the extended outage at the
Davis-Besse Nuclear Power Station. Depending upon the particular proceeding, the
issues raised include alleged violations of federal securities laws, breaches of
fiduciary duties under state law by FirstEnergy directors and officers, and
damages as a result of one or more of the noted events. The securities cases
have been consolidated into one action pending in federal court in Akron. The
derivative actions filed in federal court likewise have been consolidated as a
separate matter, also in federal court in Akron. There also are pending
derivative actions in state court. FirstEnergy's Ohio utility subsidiaries also
were named as respondents in two regulatory proceedings initiated at the PUCO in
response to complaints alleging failure to provide reasonable and adequate
service stemming primarily from the August 14th power outage. FirstEnergy is
vigorously defending these actions, but cannot predict the outcome of any of
these proceedings or whether any further regulatory proceedings or legal actions
may be instituted against them. In particular, if FirstEnergy were ultimately
determined to have legal liability in connection with these proceedings, it
could have a material adverse effect on its financial condition and results of
operations.
75
8. SEGMENT INFORMATION:
FirstEnergy operates under two reportable segments: regulated
services and competitive services. The aggregate "Other" segments do not
individually meet the criteria to be considered a reportable segment. "Other"
consists of interest expense related to the 2001 merger acquisition debt; the
corporate support services operating segment and the international businesses
acquired in the 2001 merger. The international business assets reflected in the
2001 "Other" assets amount included assets in the United Kingdom identified for
divestiture (see Note 3 - Divestitures) which were sold in 2002. As those assets
were in the process of being sold, their performance was not being reviewed by a
chief operating decision maker and in accordance with SFAS 131, "Disclosures
about Segments of an Enterprise and Related Information," did not qualify as an
operating segment. The remaining assets and revenues for the corporate support
services and the remaining international businesses were below the quantifiable
threshold for operating segments for separate disclosure as "reportable
segments." FirstEnergy's primary segment is its regulated services segment,
whose operations include the regulated sale of electricity and distribution and
transmission services by its eight electric utility operating companies in Ohio,
Pennsylvania and New Jersey (OE, CEI, TE, Penn, JCP&L, Met-Ed, Penelec and
ATSI). The competitive services business segment consists of the subsidiaries
(FES, FSG, MYR, MARBEL and First Communications) that operate unregulated energy
and energy-related businesses, including the operation of generation facilities
of OE, CEI, TE and Penn resulting from the deregulation of the Companies'
electric generation business (see Note 2(D) - Regulatory Matters).
The regulated services segment designs, constructs, operates and
maintains FirstEnergy's regulated transmission and distribution systems. It also
provides generation services to regulated franchise customers who have not
chosen a competing generation supplier. The regulated services segment obtains a
portion of its required generation through power supply agreements with the
competitive services segment.
The competitive services segment includes all domestic unregulated
energy and energy-related services including commodity sales (both electricity
and natural gas) in the retail and wholesale markets, marketing, generation and
sourcing of commodity requirements, as well as other competitive
energy-application services. Competitive products are increasingly marketed to
customers as bundled services.
Segment financial data in 2002 has been adjusted to reflect the
reclassification of revenue, expense, interest expense and tax amounts of
divested businesses reflected as discontinued operations (see Note 2(I)).
76
Segment Financial Information
- -----------------------------
Regulated Competitive Reconciling
Services Services Other Adjustments Consolidated
--------- ----------- ----- ------------ ------------
(In millions)
2003
----
External revenues....................... $ 8,978 $3,234 $ 71 $ 24 (a) $12,307
Internal revenues....................... 1,092 2,168 547 (3,807)(b) --
Total revenues....................... 10,070 5,402 618 (3,783) 12,307
Depreciation and amortization........... 1,209 33 40 -- 1,282
Goodwill impairment..................... -- 117 -- -- 117
Net interest charges.................... 499 44 344 (75)(b) 812
Income taxes............................ 650 (126) (118) -- 406
Income before discontinued operations and
cumulative effect of accounting change 885 (205) (258) -- 422
Discontinued operations................. -- (6) (95) -- (101)
Cumulative effect of accounting change.. 101 1 -- -- 102
Net income.............................. 986 (210) (353) -- 423
Total assets............................ 29,789 2,335 786 -- 32,910
Total goodwill.......................... 5,993 135 -- -- 6,128
Property additions...................... 434 345 77 -- 856
2002
----
External revenues....................... $ 9,166 $2,482 $ 386 $ 13 (a) $12,047
Internal revenues....................... 1,052 2,044 478 (3,574)(b) --
Total revenues....................... 10,218 4,526 864 (3,561) 12,047
Depreciation and amortization........... 1,235 28 35 -- 1,298
Net interest charges.................... 588 44 384 (58)(b) 958
Income taxes............................ 698 (87) (87) -- 524
Income before discontinued operations... 928 (111) (184) -- 633
Discontinued operations................. -- 2 (82) -- (80)
Net income.............................. 928 (109) (266) -- 553
Total assets............................ 30,494 2,281 1,611 -- 34,386
Total goodwill.......................... 5,993 285 -- -- 6,278
Property additions...................... 490 403 105 -- 998
2001
----
External revenues....................... $ 5,729 $2,165 $ 11 $ 94 (a) $ 7,999
Internal revenues....................... 1,645 1,846 350 (3,841)(b) --
Total revenues....................... 7,374 4,011 361 (3,747) 7,999
Depreciation and amortization........... 841 21 28 -- 890
Net interest charges.................... 571 25 74 (114)(b) 556
Income taxes............................ 537 (23) (40) -- 474
Income before cumulative effect of
accounting change.................... 729 (23) (51) -- 655
Net income.............................. 729 (32) (51) -- 646
Total assets............................ 28,054 2,981 6,317 -- 37,352
Total goodwill.......................... 5,325 276 -- -- 5,601
Property additions...................... 447 375 30 -- 852
<FN>
Reconciling adjustments to segment operating results from internal management reporting to
consolidated external financial reporting:
(a) Principally fuel marketing revenues which are reflected as reductions to
expenses for internal management reporting purposes.
(b) Elimination of intersegment transactions.
</FN>
Products and Services*
----------------------
Energy Related
Electricity Oil & Gas Sales and
Year Sales Sales Services
---- ----------- --------- --------------
(In millions)
2003......... $10,267 $624 $766
2002......... 9,697 613 904
2001......... 6,078 792 693
2003 2002
-------------------------- --------------------------
Geographic Information* Revenues Assets Revenues Assets
---------------------- -------- ------ -------- ------
(In millions)
United States............. $12,282 $32,826 $11,753 $33,628
Foreign countries*........ 25 84 294 758
------- ------- ------- -------
Total................... $12,307 $32,910 $12,047 $34,386
======= ======= ======= =======
<FN>
* See Note 3 for discussion of divestitures of business operations and Note 2(I) for discussion
of discontinued operations.
</FN>
77
9. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
FASB Staff Position (FSP) 106-1, "Accounting and Disclosure Requirements
Related to the Medicare Prescription Drug, Improvement and Modernization
Act of 2003"
Issued January 12, 2004, FSP 106-1 permits a sponsor of a
postretirement health care plan that provides a prescription drug benefit to
make a one-time election to defer accounting for the effects of the Medicare
Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The
Company has elected to defer the effects of the Act due to the lack of specific
guidance. Any measure of the accumulated postretirement benefit obligation or
net periodic postretirement benefit cost in the financial statements or the
accompanying notes do not reflect the impact of the Act on the plans. At this
time, specific authoritative guidance on the accounting for the federal subsidy
provided by the Act is pending and that guidance could require the Company to
change previously reported information.
FIN 46 (revised December 2003), "Consolidation of Variable Interest
Entities"
In December 2003, the FASB issued this revised interpretation of
Accounting Research Bulletin No. 51, "Consolidated Financial Statements". This
Interpretation, referred to below as "FIN 46R", requires the consolidation of a
VIE by an enterprise if that enterprise either absorbs a majority of the VIE's
expected losses or receives a majority of the VIE's expected residual returns as
a result of ownership, contractual or other financial interests in the VIE.
Prior to FIN 46R, entities were generally consolidated by an enterprise that had
a controlling financial interest through ownership of a majority voting interest
in the entity.
FIN 46R defines a VIE as an entity in which equity investors do not
have the characteristics of a controlling financial interest nor have sufficient
equity at risk for the entity to finance its activities without additional
subordinated financial support. Adoption of FIN 46R is required of public
entities that have interests in VIEs or potential VIEs commonly referred to as
special-purpose entities for periods ending after December 15, 2003. Adoption by
public entities for all other types of entities is required for periods ending
after March 15, 2004 (FirstEnergy's first quarter of 2004).
FirstEnergy currently has transactions with entities in connection
with sale and leaseback arrangements which fall within the scope of this
interpretation and which meet the definition of a VIE in accordance with FIN
46R. Upon adoption of FIN 46R effective December 31, 2003, FirstEnergy
consolidated two VIEs; the PNBV Capital Trust (PNBV) and the Shippingport
Capital Trust were created in 1996 and 1997, respectively, to refinance debt in
connection with these sale and leaseback transactions.
PNBV issued equity and notes to fund the acquisition of a portion of
the collateralized lease bonds that had been issued by certain owner trusts in
connection with the sale and leaseback in 1987 of a portion of OE's interest in
the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to
purchase the notes issued by the PNBV Capital Trust. Ownership of the trust
includes a three-percent equity interest by a nonaffiliated third party and a
three-percent equity interest held by OES Ventures, a wholly owned subsidiary of
OE. Consolidation of the trust as of December 31, 2003 changed the PNBV trust
investment of $361 million to an investment in collateralized lease bonds of
$372 million. The increase in $11 million represents the minority interest in
the total assets of the trust.
Shippingport was established to purchase all of the lease obligation
bonds issued by the owner trusts in the Bruce Mansfield Plant sale and leaseback
transactions in 1987. CEI and TE acquired all of the notes issued by
Shippingport Capital Trust. Upon adoption of FIN 46R, this entity was
consolidated on the books of CEI; the investment in the trusts was previously
recorded on the books of both CEI and TE. Consolidation of this entity therefore
had no impact on the financial statements of FirstEnergy.
In addition to the two entities created to refinance debt discussed
above, the Company evaluated its interest in the owner trusts that acquired the
interests in the Perry Plant, Beaver Valley Unit 2 and the Bruce Mansfield
Plant. FirstEnergy concluded that the operating companies (OE, CEI and TE) were
not the primary beneficiaries of these owner trusts and were therefore not
required to consolidate these entities. The leases are accounted for as
operating leases in accordance with GAAP and their related obligations are
disclosed in Note 4. The combined purchase price of $3.1 billion for all of the
interests acquired by the owner trusts in 1987 was funded with debt of $2.5
billion and equity of $600 million.
FirstEnergy is exposed to losses under the sale-leaseback agreements
upon the occurrence of certain contingent events that the Company considers
unlikely to occur. The Company's maximum exposure to loss is currently estimated
to be $2.0 billion, which represents the net amount of casualty value payments
upon the occurrence of specified casualty events that render the plants
worthless. Under the sale and leaseback agreements, FirstEnergy has minimum
undiscounted net lease payments of $2.6 billion that would not be payable if the
casualty value payments are made. In addition, the Company has recorded above
market lease obligations of $1.1 billion, of which $85 million is current,
related to the Bruce Mansfield Plant and Beaver Valley Unit 2 as of December 31,
2003 related to the acquisition by FirstEnergy of CEI and TE.
78
As described in Note 5(G), CEI, Met-Ed and Penelec created statutory
business trusts to issue trust preferred securities in the aggregate of $285
million. Prior to the adoption of FIN 46R, these trusts had been consolidated by
FirstEnergy and the respective operating company. Application of the guidance in
FIN 46R resulted in the holders of the preferred securities being considered the
primary beneficiaries of these trusts. Therefore, FirstEnergy, CEI, Met-Ed and
Penelec have deconsolidated the trusts. As of December 31, 2003, FirstEnergy
reported subordinated debentures to the respective trusts of $294 million ($103
million for CEI, $96 million for Met-Ed and $95 million for Penelec) within the
balance sheet liability caption "Subordinated debentures to affiliated trusts"
and the equity investment in the trusts of $9 million ($3 million each for CEI,
Met-Ed and Penelec) within the balance sheet asset caption "Investments -
Other."
In August 1995, Los Amigos Leasing Company, Ltd. (Los Amigos) was
formed as a consolidated subsidiary of GPU Power to own and lease to TEBSA
equipment comprised of an 895 megawatt plant constructed and operated by TEBSA.
Upon application of FIN 46R, Los Amigos met the criteria of a VIE and
FirstEnergy was determined not to be its primary beneficiary. Therefore,
effective December 31, 2003, Los Amigos was deconsolidated, resulting in the
removal of approximately $243 million of total assets (primarily unbilled lease
receivable) and liabilities (primarily senior and subordinated debt) from
FirstEnergy's Consolidated Balance Sheets. Los Amigos was sold as part of the
TEBSA divestiture on January 30, 2004.
FirstEnergy is evaluating other entities that meet the deferral
criteria and may be subject to consolidation under FIN 46R as of March 31, 2004.
Included in this analysis are non-utility generators in which we have neither
debt nor equity investments but are generally the sole purchaser of their power.
SFAS 132 (revised December 2003), "Employers' Disclosures about Pensions
and Other Postretirement Benefits - An amendment of FASB Statements No. 87,
88, and 106"
Issued by the FASB in December 2003 and effective for financial
statements with fiscal years ending after December 15, 2003, this revision to
SFAS 132 revises employers' disclosures about pension plans and other
postretirement benefits plans. SFAS 132 (as revised) does not change the
measurement or recognition of those plans as required by FASB Statements No. 87,
88, and 106, but requires additional disclosures about the assets, obligations,
cash flows, and net periodic benefit cost of defined benefit pension plans and
other defined benefit postretirement plans. FirstEnergy has included the
additional disclosure requirements in Note 2(K) - Pension and Other
Postretirement Benefit Plans.
EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and
its Application to Certain Investments"
In November 2003, the EITF reached consensus that certain
quantitative and qualitative disclosures are required for debt and equity
securities classified as available-for-sale or held-to-maturity. The guidance
requires the disclosure of the aggregate amount of unrealized losses and the
aggregate related fair value for investments with unrealized losses that have
not been recognized as other-than-temporary impairments. FirstEnergy has adopted
the disclosure requirements of EITF Issue No. 03-1 as of December 31, 2003 (See
Note 10(E)).
EITF Issue No. 03-11, "Reporting Realized Gains and Losses on Derivative
Instruments That Are Subject to SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities, and Not "Held for Trading Purposes" as
Defined in EITF Issue 02-03, "Issues Involved in Accounting for Derivative
Contracts Held for Trading Purposes and Contracts Involved in Energy
Trading and Risk Management Activities."
In July 2003, the EITF reached a consensus that determining whether
realized gains and losses on physically settled derivative contracts not "held
for trading purposes" should be reported in the income statement on a gross or
net basis is a matter of judgment that depends on the relevant facts and
circumstances. The consideration of the facts and circumstances, including
economic substance, should be made in the context of the various activities of
the entity rather than based solely on the terms of the individual contracts.
The Company adopted this consensus effective January 1, 2004. The impact on
operating revenues and operating expenses has not been determined but is not
expected to be material. The adoption of EITF C3-11 will have no impact on net
income.
DIG Implementation Issue No. C20 for SFAS 133, "Scope Exceptions:
Interpretation of the Meaning of Not Clearly and Closely
Related in Paragraph 10(b) Regarding Contracts with a Price Adjustment
Feature"
In June 2003, the FASB cleared DIG Issue C20 for implementation in
fiscal quarters beginning after July 10, 2003. The issue supersedes earlier DIG
Issue C11, "Interpretation of Clearly and Closely Related in Contracts That
Qualify for the Normal Purchases and Normal Sales Exception." DIG Issue C20
provides guidance regarding when the presence of a general index, such as the
Consumer Price Index, in a contract would prevent that contract from qualifying
for the normal purchases and normal sales exception under SFAS 133, as amended,
and therefore exempt from the mark-to-market treatment of certain contracts.
Adoption of DIG Issue C20 did not have a material impact on the Companies'
financial statements.
79
EITF Issue No. 01-8, "Determining Whether an Arrangement Contains a Lease"
In May 2003, the EITF reached a consensus regarding when arrangements
contain a lease. Based on the EITF consensus, an arrangement contains a lease
if: (1) it identifies specific property, plant or equipment (explicitly or
implicitly); and (2) the arrangement transfers the right to the purchaser to
control the use of the property, plant or equipment. The consensus is to be
applied prospectively to arrangements committed to, modified or acquired through
a business combination after the effective date of the consensus. The adoption
of this consensus as of July 1, 2003 did not affect FirstEnergy's financial
statements.
SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity"
In May 2003, the FASB issued SFAS 150, which establishes standards
for how an issuer classifies and measures certain financial instruments with
characteristics of both liabilities and equity. In accordance with the standard,
certain financial instruments that embody obligations for the issuer are
required to be classified as liabilities. SFAS 150 was effective immediately for
financial instruments entered into or modified after May 31, 2003 and effective
at the beginning of the first interim period beginning after June 15, 2003 for
all other financial instruments.
Upon adoption of SFAS 150, effective July 1, 2003, FirstEnergy
reclassified as debt the preferred stock of consolidated subsidiaries subject to
mandatory redemption with a carrying value of approximately $19 million ($5
million for CEI and $14 million for Penn) as of December 31, 2003. Adoption of
SFAS 150 had no impact on FirstEnergy's Consolidated Statements of Income
because the preferred dividends were previously included in net interest charges
and required no reclassification.
SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging
Activities"
Issued by the FASB in April 2003, SFAS 149 further clarifies and
amends accounting and reporting for derivative instruments. The statement amends
SFAS 133 for decisions made by the Derivative Implementation Group (DIG), as
well as issues raised in connection with other FASB projects and implementation
issues. The statement was effective for contracts entered into or modified after
June 30, 2003 except for implementation issues that were effective for reporting
periods beginning before June 15, 2003, that continue to be applied based on
their original effective dates. Adoption of SFAS 149 did not have a material
impact on the Companies' financial statements.
SFAS 143, "Accounting for Asset Retirement Obligations"
The Company adopted SFAS 143 effective January 1, 2003. The impact of
this new accounting standard is discussed above under Notes 2(F) and 2(J).
FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, including Indirect
Guarantees of Indebtedness of Others - an interpretation of FASB
Statements No. 5, 57 and 107 and rescission of FASB Interpretation
No. 34"
The FASB issued FIN 45 in January 2003. This interpretation
identifies minimum guarantee disclosures required for annual periods ending
after December 15, 2002. It also clarifies that providers of guarantees must
record the fair value of those guarantees at their inception. This accounting
guidance was applicable on a prospective basis to guarantees issued or modified
after December 31, 2002. Adoption of FIN 45 for guarantees issued during 2003
did not have a material impact on FirstEnergy's financial statements.
80
10. OTHER INFORMATION:
The following provides supplemental unaudited information to the
consolidated financial statements and notes previously reported in 2001:
(A) Consolidated Statements of Cash Flows
(Unaudited)
2003 2002 2001
---- ---- ----
(In thousands)
Other Cash Flows From Operating Activities:
Accrued taxes........................... $ 219,936 $ 35,108 $ 8,915
Accrued interest........................ (57,509) (27,420) 117,520
Retail rate refund obligation payments.. (71,984) (43,016) --
Interest rate hedge..................... -- -- (132,376)
Prepayments and other................... (31,155) 133,677 (146,741)
Accrued retirement benefit obligations.. 282,804 124,678 19,797
Accrued compensation, net............... (74,401) (92,197) (118,325)
Tax refund related to pre-merger period. 51,073 -- --
Energy derivative transactions.......... (70,498) (8,682) --
Asset retirement obligation............. 97,820 -- --
All other............................... (7,349) 3,538 646
----------------------------------------------------------------------------
Total-Other........................... $ 338,737 $ 125,686 $(250,564)
=============================================================================
Other Cash Flows from Investing Activities:
Retirements and transfers............... $ 37,580 $ 29,619 $ 40,106
Nonutility generation trusts
withdrawals........................... 66,327 49,044 --
Contributions to nuclear decommissioning
trusts................................ (101,218) (103,143) (90,995)
Nuclear decommissioning trust
investments........................... (143,493) 16,922 17,614
Long-term notes receivable.............. 82,250 (91,335) --
Other investments....................... 29,137 (7,944) (165,938)
All other............................... 42,273 52,482 (34,313)
----------------------------------------------------------------------------
Total-Other........................... $ 12,856 $ (54,355) $(233,526)
=============================================================================
(B) Consolidated Statements of Taxes
(Unaudited)
2003 2002 2001
---- ---- ----
(In thousands)
Other Accumulated Deferred Income
Taxes as of December 31:
Retirement Benefits..................... $(359,038) $(223,065) $(133,282)
Oyster Creek securitization (Note 5(H)). 193,558 202,447 --
Loss carryforwards...................... (495,254) (507,690) (486,495)
Loss carryforward valuation reserve..... 470,813 482,061 459,170
Purchase accounting basis differences... (2,657) (2,657) (147,450)
Sale of generating assets............... (11,785) (11,786) 207,787
Provision for rate refund............... -- (29,370) (46,942)
All other............................... (49,569) (149,226) (176,484)
--------- --------- ---------
Total-Other........................... $(253,932) $(239,286) $(323,696)
========= ========= =========
(C) Revenues - Independent System Operator (ISO) Transactions
FirstEnergy's regulated and competitive subsidiaries record purchase
and sales transactions with PJM Interconnection ISO, an independent system
operator, on a gross basis in accordance with EITF Issue No. 99-19, "Reporting
Revenue Gross as a Principal versus Net as an Agent." The aggregate purchase and
sales transactions for the three years ended December 31, 2003, are summarized
as follows:
(Unaudited)
2003 2002 2001
- -----------------------------------------------------------------------
(In millions)
Sales................. $ 990 $453 $142
Purchases............. 1,019 687 204
----------------------------------------------------------------------
FirstEnergy's revenues on the Consolidated Statements of Income
include wholesale electricity sales revenues from the PJM ISO from power sales
(as reflected in the table above) during periods when FirstEnergy had
81
additional available power capacity. Revenues also include sales by FirstEnergy
of power sourced from the PJM ISO (reflected as purchases in the table above)
during periods when FirstEnergy required additional power to meet its retail
load requirements and, secondarily, to make sales to the wholesale market.
(D) Stock Based Compensation (2001 Unaudited)
Stock-based employee compensation expense recognized for the
FirstEnergy Programs' restricted stock during 2003, 2002 and 2001 totaled
$1,747,000, $2,259,000 and $1,342,000, respectively. In addition, stock-based
employee compensation expense of $2,312,000, $206,000 and $1,637,000 during
2003, 2002 and 2001, respectively, was recognized for EDCP stock units (see Note
5(C) for further discussion).
(E) SFAS 115 Activity
Investments other than cash and cash equivalents in the table in Note
2(M) - Cash and Financial Instruments include available-for-sale securities, at
fair value, with the following net results:
(Unaudited)
2003* 2002* 2001
- -------------------------------------------------------------------------------
(In millions)
Unrealized gains (losses)........... $116 $ (48) $2
Proceeds from sales................. 516 421 --
Realized gains (losses)............. 3 (15) --
------------------------------------------------------------------------------
* Includes the available-for-sale securities of FirstEnergy's Ohio
Companies' decommissioning trusts.
As of December 31, 2003 accumulated other comprehensive income (loss)
for available-for-sale securities consisted of investments with net unrealized
gains of $153 million and net unrealized losses of $45 million. The following
table provides details for the available-for-sale securities with net unrealized
losses as of December 31, 2003.
Less Than 12 Months 12 Months or More Total
-------------------- -------------------- ---------------------
Fair Unrealized Fair Unrealized Fair Unrealized
Security Type Value Losses Value Losses Value Losses
- -------------------------------------------------------------------------------------------------------
(In millions)
Equity Securities....... 17 5 43 40 60 45
Debt Securities......... 33 -- -- -- 33 --
- -------------------------------------------------------------------------------------------------------
Total............... 50 5 43 40 93 45
- -------------------------------------------------------------------------------------------------------
All of the aggregate unrealized losses related to available-for-sale
securities in the table above are considered to be temporary in nature. These
securities are primarily held by the nuclear decommissioning trusts of
FirstEnergy's Ohio Companies. FirstEnergy has the ability and intent to hold
these securities for the period necessary to fund their cost.
82
11. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
The following summarizes certain consolidated operating results by quarter for
2003 and 2002.
March 31, June 30, September 30, December 31,
Three Months Ended (a) 2003 2003 2003 2003
- ------------------------------------------------------------------------------------------------------------------
(In millions, except per share amounts)
Revenues......................................... $3,221 $2,853 $3,434 $2,799
Expenses......................................... 2,806 2,619 2,947 2,463
Claim Settlement (Note 3)........................ -- -- -- 168
- ------------------------------------------------------------------------------------------------------------------
Income Before Interest and Income Taxes.......... 415 234 487 504
Net Interest Charges............................. 206 205 201 200
Income Taxes..................................... 94 19 135 158
- ------------------------------------------------------------------------------------------------------------------
Income Before Discontinued Operations and
Cumulative Effect of Accounting Change........ 115 10 151 146
- ------------------------------------------------------------------------------------------------------------------
Discontinued Operations (Net of Income Taxes).... 2 (68) 1 (36)
Cumulative Effect of Accounting Change
(Net of Income Taxes)......................... 102 -- -- --
- ------------------------------------------------------------------------------------------------------------------
Net Income (Loss)................................ $ 219 $ (58) $ 152 $ 110
==================================================================================================================
Basic Earnings (Loss) Per Share of Common Stock:
Before Discontinued Operations and Cumulative
Effect of Accounting Change................. $ 0.39 $ 0.03 $ 0.51 $ 0.44
Discontinued Operations....................... -- (0.23) -- (0.11)
Cumulative Effect of Accounting Change........ 0.35 -- -- --
- ------------------------------------------------------------------------------------------------------------------
Basic Earnings (Loss) Per Share of Common Stock.. $ 0.74 $(0.20) $ 0.51 $ 0.33
- ------------------------------------------------------------------------------------------------------------------
Diluted Earnings (Loss) Per Share of Common Stock:
Before Discontinued Operations and Cumulative
Effect of Accounting Change................. $ 0.39 $ 0.03 $ 0.50 $ 0.44
Discontinued Operations....................... -- (0.23) -- (0.11)
Cumulative Effect of Accounting Change........ 0.35 -- -- --
- ------------------------------------------------------------------------------------------------------------------
Diluted Earnings (Loss) Per Share of Common Stock $ 0.74 $(0.20) $ 0.50 $ 0.33
==================================================================================================================
March 31, June 30, September 30, December 31,
Three Months Ended (a) 2002 2002 2002 2002
- ------------------------------------------------------------------------------------------------------------------
(In millions, except per share amounts)
Revenues......................................... $2,810 $2,854 $3,407 $2,976
Expenses......................................... 2,322 2,232 2,684 2,694
- ------------------------------------------------------------------------------------------------------------------
Income Before Interest and Income Taxes.......... 488 622 723 282
Net Interest Charges............................. 278 249 220 211
Income Taxes..................................... 93 167 220 44
- ------------------------------------------------------------------------------------------------------------------
Income Before Discontinued Operations............ 117 206 283 27
- ------------------------------------------------------------------------------------------------------------------
Discontinued Operations (Net of Income Taxes).... 1 2 2 (85)
- ------------------------------------------------------------------------------------------------------------------
Net Income (Loss)................................ $ 118 $ 208 $ 285 $ (58)
==================================================================================================================
Basic Earnings (Loss) Per Share of Common Stock:
Before Discontinued Operations................ $ 0.40 $ 0.71 $ 0.96 $ 0.09
Discontinued Operations....................... -- -- 0.01 (0.29)
- ------------------------------------------------------------------------------------------------------------------
Basic Earnings (Loss) Per Share of Common Stock.. $ 0.40 $ 0.71 $ 0.97 $(0.20)
- ------------------------------------------------------------------------------------------------------------------
Diluted Earnings (Loss) Per Share of Common Stock:
Before Discontinued Operations................ $ 0.40 $ 0.70 $ 0.96 $ 0.09
Discontinued Operations....................... -- -- 0.01 (0.29)
- ------------------------------------------------------------------------------------------------------------------
Diluted Earnings (Loss) Per Share of Common Stock $ 0.40 $ 0.70 $ 0.97 $(0.20)
==================================================================================================================
<FN>
(a) Revenues, expenses, net interest charges and income taxes have been revised
to reflect reclassifications of the results of discontinued operations.
</FN>
Net income for the three months ended December 31, 2003, was increased
by $7.4 million due to adjustments relating to the first nine months of 2003.
After-tax income of $16.3 million resulted from adjustments for costs charged to
expense in prior quarters of 2003 that were subsequently capitalized to
regulated segment construction projects in the fourth quarter, partially offset
by after-tax charges of $8.9 million for adjustments relating to prior quarters
for the competitive segment. Management concluded that these adjustments were
not material to the reported consolidated results of operations for any quarter
of 2003 (after-tax amounts of $3.1 million, $0.6 million and $3.7 million for
the first three quarters of 2003, respectively). However, the adjustments
relating to the regulated segment were material to the separate reported results
of JCP&L, Penelec and TE; accordingly, the reported results of operations for
the first three quarters of 2003 for those subsidiaries will be restated in
their separate financial statements. The impact of these adjustments was not
material to FirstEnergy's consolidated balance sheets or consolidated statements
of cash flows for any quarter of 2003.
The net loss for the second quarter of 2003 included a charge
resulting from the NJBPU's decision to disallow recovery by JCP&L of $153
million in deferred energy costs and a $67 million non-cash charge (no tax
benefit recognized) from the abandonment of operations in Argentina.
Results for the fourth quarter of 2003 included a $33 million
after-tax loss from the divestiture of assets in Bolivia included in
discontinued operations and a $26 million impairment of the equity TEBSA
investment in Columbia included in continuing operations. The fourth quarter
results also include a $170 million gain ($168 million net of expenses) from the
NRG Energy Inc. settlement claim.
83
The operating results in 2002 related to assets sold in 2003 have
been reclassified as discontinued operations. The fourth quarter discontinued
operations include an $88 million loss from operations of the Argentina assets.
12. GPU MERGER (UNAUDITED);
On November 7, 2001, the merger of FirstEnergy and GPU became
effective pursuant to the Agreement and Plan of Merger, dated August 8, 2000
(Merger Agreement). As a result of the merger, GPU's former wholly owned
subsidiaries, including JCP&L, Met-Ed and Penelec, (collectively, the Former GPU
Companies), became wholly owned subsidiaries of FirstEnergy. Under the terms of
the Merger Agreement, GPU shareholders received the equivalent of $36.50 for
each share of GPU common stock they owned, payable in cash and/or FirstEnergy
common stock. GPU shareholders receiving FirstEnergy shares received 1.2318
shares of FirstEnergy common stock for each share of GPU common stock they
exchanged. The cash portion of the merger consideration was approximately $2.2
billion and nearly 73.7 million shares of FirstEnergy common stock were issued
to GPU shareholders for the share portion of the transaction consideration.
The merger was accounted for by the purchase method of accounting
and, accordingly, the Consolidated Statements of Income include the results of
the Former GPU Companies beginning November 7, 2001. The assets acquired and
liabilities assumed were recorded at estimated fair values as determined by
FirstEnergy's management based on information currently available and on current
assumptions as to future operations. The merger purchase accounting adjustments,
which were recorded in the records of GPU's direct subsidiaries, primarily
consist of: (1) revaluation of GPU's international operations to fair value; (2)
revaluation of property, plant and equipment; (3) adjusting preferred stock
subject to mandatory redemption and long-term debt to estimated fair value; (4)
recognizing additional obligations related to retirement benefits; and (5)
recognizing estimated severance and other compensation liabilities. Other assets
and liabilities were not adjusted since they remain subject to rate regulation
on a historical cost basis. The severance and compensation liabilities are based
on anticipated workforce reductions reflecting duplicate positions primarily
related to corporate support groups including finance, legal, communications,
human resources and information technology. The workforce reductions represented
the expected reduction of approximately 700 employees at a cost of approximately
$140 million. Merger related staffing reductions began in late 2001 and the
remaining reductions occurred in 2003 as merger-related transition assignments
were completed.
The merger greatly expanded the size and scope of FirstEnergy's
electric business and the goodwill recognized primarily relates to the regulated
services segment. The combination of FirstEnergy and GPU was a key strategic
step in FirstEnergy achieving its vision of being the leading energy and related
services provider in the region. The merger combined companies with the
management, employee experience and technical expertise, retail customer base,
energy and related services platform and financial resources to grow and succeed
in a rapidly changing energy marketplace. The merger also allowed for a natural
alliance of companies with adjoining service areas and interconnected
transmission systems to eliminate duplicative costs, maximize efficiencies and
increase management and operational flexibility in order to enhance operations
and become a more effective competitor.
Under the purchase method of accounting, tangible and identifiable
intangible assets acquired and liabilities assumed are recorded at their
estimated fair values. The excess of the purchase price, including estimated
fees and expenses related to the merger, over the net assets acquired, is
classified as goodwill and amounts to $3.8 billion as of December 31, 2003. The
following table summarizes the estimated fair values of the assets acquired and
liabilities assumed on the date of acquisition.
-------------------------------------------------------------
(In millions)
Current assets................... $ 1,027
Goodwill......................... 3,698
Regulatory assets................ 4,352
Other............................ 5,595
-------------------------------------------------------------
Total assets acquired........ 14,672
-------------------------------------------------------------
Current liabilities.............. (2,615)
Long-term debt................... (2,992)
Other............................ (4,785)
-------------------------------------------------------------
Total liabilities assumed.... (10,392)
Net assets acquired pending sale. 566
-------------------------------------------------------------
Net assets acquired.............. $ 4,846
-------------------------------------------------------------
During 2002, certain pre-acquisition contingencies and other final
adjustments to the fair values of the assets acquired and liabilities assumed
were reflected in the final allocation of the purchase price. These adjustments
primarily related to: (1) final actuarial calculations related to pension and
postretirement benefit obligations; (2) updated valuations
84
of GPU's international operations as of the date of the merger; (3)
establishment of a reserve for deferred energy costs recognized prior to the
merger; and (4) return to accrual adjustments for income taxes. As a result of
these and other minor adjustments, goodwill increased by approximately $286
million as of December 31, 2002. The increase was attributable to the regulated
services segment.
The following pro forma combined condensed statement of income of
FirstEnergy give effect to the FirstEnergy/GPU merger as if it had been
consummated on January 1, 2001, with the purchase accounting adjustments
actually recognized in the business combination. The pro forma adjustments
reflect a reduction in debt from application of the proceeds from certain
pending divestitures as well as the related reduction in interest costs.
Year Ended December 31, 2001
----------------------------
(In millions, except per share amounts)
Revenues.................................... $12,108
Expenses.................................... 9,768
-------------------------------------------------------
Income Before Interest and Income Taxes..... 2,340
Net Interest Charges........................ 941
Income Taxes................................ 561
-------------------------------------------------------
Net Income.................................. $ 838
-------------------------------------------------------
Earnings per Share of Common Stock.......... $ 2.87
-------------------------------------------------------
85