SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-Q/A
AMENDMENT NO. 1
(MARK ONE)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
----------------- -------------------
COMMISSION REGISTRANT; STATE OF INCORPORATION; I.R.S. EMPLOYER
FILE NUMBER ADDRESS; AND TELEPHONE NUMBER IDENTIFICATION NO.
----------- ----------------------------- ------------------
333-21011 FIRSTENERGY CORP. 34-1843785
(AN OHIO CORPORATION)
76 SOUTH MAIN STREET
AKRON, OH 44308
TELEPHONE (800)736-3402
1-2578 OHIO EDISON COMPANY 34-0437786
(AN OHIO CORPORATION)
76 SOUTH MAIN STREET
AKRON, OH 44308
TELEPHONE (800)736-3402
1-2323 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY 34-0150020
(AN OHIO CORPORATION)
C/O FIRSTENERGY CORP.
76 SOUTH MAIN STREET
AKRON, OH 44308
TELEPHONE (800)736-3402
1-3583 THE TOLEDO EDISON COMPANY 34-4375005
(AN OHIO CORPORATION)
C/O FIRSTENERGY CORP.
76 SOUTH MAIN STREET
AKRON, OH 44308
TELEPHONE (800)736-3402
TELEPHONE (800)736-3402
Indicate by check mark whether each of the registrants (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
----- -----
Indicate by check mark whether each registrant is an accelerated filer (
as defined in Rule 12b-2 of the Act):
Yes X No
----- -----
Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date:
OUTSTANDING
CLASS AS OF MAY 9, 2003
----- -----------------
FirstEnergy Corp., $.10 par value 297,636,276
Ohio Edison Company, no par value 100
The Cleveland Electric Illuminating Company, no par value 79,590,689
The Toledo Edison Company, $5 par value 39,133,887
FirstEnergy Corp. is the sole holder of Ohio Edison Company, The Cleveland
Electric Illuminating Company and The Toledo Edison Company.
This combined Form 10-Q/A is separately filed by FirstEnergy Corp., Ohio
Edison Company, The Cleveland Electric Illuminating Company and The Toledo
Edison Company. Information contained herein relating to any individual
registrant is filed by such registrant on its own behalf. No registrant makes
any representation as to information relating to any other registrant, except
that information relating to any of the FirstEnergy subsidiary registrants is
also attributed to FirstEnergy.
This Form 10-Q/A 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. This Form 10-Q 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), availability and cost of
capital, 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 the fall of 2003, inability to
accomplish or realize anticipated benefits from strategic goals, further
investigation into the causes of the August 14, 2003, power outage, and other
similar factors.
EXPLANATORY NOTE
This Amendment No. 1 for FirstEnergy Corp., Ohio Edison Company, The
Cleveland Electric Illuminating Company and The Toledo Edison Company is being
filed to restate certain amounts in the consolidated financial statements for
three months ended March 31, 2002 and 2003.
As described in Note 1 to the consolidated financial statements of
FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating
Company and The Toledo Edison Company, the Registrants have restated their
financial statements to reflect a change in the method of amortizing the costs
associated with the Ohio transition plan and recognition of above-market values
of certain leased generation facilities
These restatements have resulted in a decrease in net income of $22.5
million, $0.1 million, $5.0 million and $4.5 million reported for FirstEnergy
Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company and The
Toledo Edison Company, respectively, for the three months ended March 31, 2003.
Net income as reported for the three months ended March 31, 2002 increased $1.8
million, $10.3 million $2.2 million and $1.0 million for FirstEnergy Corp., Ohio
Edison Company, The Cleveland Electric Illuminating Company and The Toledo
Edison Company, respectively.
TABLE OF CONTENTS
PAGES
PART I. FINANCIAL INFORMATION
Notes to Financial Statements....................................... 1-21
FIRSTENERGY CORP.
Consolidated Statements of Income................................... 22
Consolidated Balance Sheets......................................... 23-24
Consolidated Statements of Cash Flows............................... 25
Report of Independent Auditors...................................... 26
Management's Discussion and Analysis of Results of Operations and
Financial Condition............................................... 27-47
OHIO EDISON COMPANY
Consolidated Statements of Income................................... 48
Consolidated Balance Sheets......................................... 49-50
Consolidated Statements of Cash Flows............................... 51
Report of Independent Auditors...................................... 52
Management's Discussion and Analysis of Results of Operations and
Financial Condition............................................... 53-60
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
Consolidated Statements of Income................................... 61
Consolidated Balance Sheets......................................... 62-63
Consolidated Statements of Cash Flows............................... 64
Report of Independent Auditors...................................... 65
Management's Discussion and Analysis of Results of Operations and
Financial Condition............................................... 66-73
THE TOLEDO EDISON COMPANY
Consolidated Statements of Income................................... 74
Consolidated Balance Sheets......................................... 75-76
Consolidated Statements of Cash Flows............................... 77
Report of Independent Auditors...................................... 78
Management's Discussion and Analysis of Results of Operations and
Financial Condition............................................... 79-87
CONTROLS AND PROCEDURES................................................ 88
PART II. OTHER INFORMATION
PART I. FINANCIAL INFORMATION
FIRSTENERGY CORP. AND SUBSIDIARIES
OHIO EDISON COMPANY AND SUBSIDIARIES
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
THE TOLEDO EDISON COMPANY AND SUBSIDIARY
NOTES TO FINANCIAL STATEMENTS
(UNAUDITED)
1 - FINANCIAL STATEMENTS:
The principal business of FirstEnergy Corp. (FirstEnergy) is the
holding, directly or indirectly, of all of the outstanding common stock of its
eight principal electric utility operating subsidiaries, Ohio Edison Company
(OE), The Cleveland Electric Illuminating Company (CEI), The Toledo Edison
Company (TE), Pennsylvania Power Company (Penn), American Transmission Systems,
Inc. (ATSI), Jersey Central Power & Light Company (JCP&L), Metropolitan Edison
Company (Met-Ed) and Pennsylvania Electric Company (Penelec). These utility
subsidiaries are referred to throughout as "Companies." Penn is a wholly owned
subsidiary of OE. JCP&L, Met-Ed and Penelec were acquired in a merger (which was
effective November 7, 2001) with GPU, Inc., the former parent company of JCP&L,
Met-Ed and Penelec. The merger was accounted for by the purchase method of
accounting and the applicable effects were reflected on the financial statements
of JCP&L, Met-Ed and Penelec as of the merger date. FirstEnergy's consolidated
financial statements also include its other principal subsidiaries: FirstEnergy
Solutions Corp. (FES); FirstEnergy Facilities Services Group, LLC (FSG); MYR
Group, Inc. (MYR); MARBEL Energy Corporation; FirstEnergy Nuclear Operating
Company (FENOC); GPU Capital, Inc.; GPU Power, Inc.; FirstEnergy Service Company
(FECO); and GPU Service, Inc. (GPUS). 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 is a fully
integrated natural gas company. GPU Capital owns and operates electric
distribution systems in foreign countries (see Note 3) and GPU Power owns and
operates generation facilities in foreign countries. FECO and GPUS provide
legal, financial and other corporate support services to affiliated FirstEnergy
companies. Significant intercompany transactions have been eliminated.
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 condensed unaudited financial statements of
FirstEnergy and each of the Companies reflect all normal recurring adjustments
that, in the opinion of management, are necessary to fairly present results of
operations for the interim periods. These statements should be read in
conjunction with the financial statements and notes included in the combined
Annual Report on Form 10-K and Amendments Nos. 1 and 2 on Forms 10-K/A for the
year ended December 31, 2002 for FirstEnergy and the Companies. The preparation
of financial statements in conformity with accounting principles generally
accepted in the United States requires management to make periodic estimates and
assumptions that affect the reported amounts of assets, liabilities, revenues
and expenses and disclosure of contingent assets and liabilities. Actual results
could differ from those estimates. The reported results of operations are not
indicative of results of operations for any future period. Certain prior year
amounts have been reclassified to conform with the current year presentation, as
discussed further in Note 5.
Preferred Securities
The sole assets of the CEI subsidiary trust that is the obligor on
the preferred securities included in FirstEnergy's and CEI's Capitalizations are
$103.1 million aggregate principal amount of 9% junior subordinated debentures
of CEI due December 31, 2006. CEI has effectively provided a full and
unconditional guarantee of the trust's obligations under the preferred
securities.
Met-Ed and Penelec each formed statutory business trusts for the
issuance of $100 million each of preferred securities due 2039 and included in
FirstEnergy's, Met-Ed's and Penelec's respective Capitalizations. Ownership of
the respective Met-Ed and Penelec trusts is through separate wholly-owned
limited partnerships, of which a wholly-owned subsidiary of each company is the
sole general partner. In these transactions, the sole assets and sources of
revenues of each trust are the preferred securities of the applicable limited
partnership, whose sole assets are the 7.35% and 7.34% subordinated debentures
(aggregate principal amount of $103.1 million each) of Met-Ed and Penelec,
respectively. In each case, the applicable parent company has effectively
provided a full and unconditional guarantee of the trust's obligations under the
preferred securities.
1
Securitized Transition Bonds
In June 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 or did not purchase any of the transition bonds,
which are included in long-term debt on FirstEnergy's and JCP&L'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 transition bond charge, 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 transition bond charge,
pursuant to a servicing agreement with the Issuer. JCP&L is entitled to a
quarterly servicing fee of $100,000 that is payable from transition bond charge
collections.
Derivative Accounting
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. 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 will be
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. The current net deferred loss of $105.8 million
included in Accumulated Other Comprehensive Loss (AOCL) as of March 31, 2003,
for derivative hedging activity, as compared to the December 31, 2002 balance of
$110.2 million in net deferred losses, resulted from a $8.8 million reduction
related to current hedging activity and a $4.4 million increase due to net hedge
gains included in earnings during the three months ended March 31, 2003.
Approximately $20.2 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 and will generally be more than offset by the margin on
related sales and revenues. FirstEnergy also entered into fixed-to-floating
interest rate swap agreements during 2002 to increase the variable-rate
component of its 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 and interest payment dates match those of
the underlying obligations resulting in no ineffectiveness in these hedge
positions. The swap agreements consummated in the first quarter of 2003 are
based on a notional principal amount of $200 million. As of March 31, 2003, the
notional amount of FirstEnergy's fixed-for-floating rate interest rate swaps
totaled $700 million.
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.
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
March 31, 2003, FirstEnergy's AOCL was approximately $657.4 million as compared
to the December 31, 2002 balance of $656.1 million. Comprehensive income for the
first quarter of 2003 and 2002 are shown in the following table:
2
THREE MONTHS ENDED MARCH 31,
-----------------------------
2003 2002
------------ ------------
RESTATED RESTATED
(SEE NOTE 1) (SEE NOTE 1)
------------ ------------
(IN THOUSANDS)
Net income ............................ $ 218,502 $ 118,268
Other comprehensive income, net of tax:
Derivative hedge transactions ....... 4,341 35,844
All other ........................... 1,484 730
------------ ------------
Comprehensive income .................. $ 224,327 $ 154,842
============ ============
Stock-Based Compensation
FirstEnergy applies the recognition and measurement principles of
Accounting Principles Board (APB) Opinion No. 25 (APB 25), "Accounting for Stock
Issued to Employees" and related Interpretations in accounting for its
stock-based compensation plans. No material stock-based employee compensation
expense is reflected in net income as all options granted under those plans have
exercise prices equal to the market value of the underlying common stock on the
respective grant dates, resulting in substantially no intrinsic value.
If FirstEnergy had accounted for employee stock options under the
fair value method, a higher value would have been assigned to the options
granted. The effects of applying fair value accounting to FirstEnergy's stock
options would be to reduce net income and earnings per share. The following
table summarizes this effect.
THREE MONTHS ENDED
MARCH 31,
---------------------------
2003 2002
----------- -----------
RESTATED RESTATED
(SEE NOTE 1) (SEE NOTE 1)
(IN THOUSANDS)
Net Income, as reported ........................ $ 218,502 $ 118,268
Add back compensation expense
reported in net income, net of tax
(based on APB 25) ............................ 43 43
Deduct compensation expense based
upon fair value, net of tax .................. (2,983) (1,402)
----------- -----------
Adjusted net income ............................ $ 215,562 $ 116,909
----------- -----------
Earnings Per Share of Common Stock -
Basic
As Reported ................................ $ 0.74 $ 0.40
Adjusted ................................... $ 0.73 $ 0.40
Diluted
As Reported ................................ $ 0.74 $ 0.40
Adjusted ................................... $ 0.73 $ 0.40
Change in Previously Reported Income Statement Classification -
FirstEnergy recorded an increase to income during the three months
ended March 31, 2002 of $31.7 million (net of income taxes of $13.6 million)
relative to a decision to retain an interest in the Avon Energy Partners
Holdings (Avon) business previously classified as held for sale - see Note 3.
This amount represents the aggregate results of operations of Avon for the
period this business was held for sale. It was previously reported on the
Consolidated Statement of Income as the cumulative effect of a change in
accounting. In April 2003, it was determined that this amount should instead
have been classified in operations. As further discussed in Note 3, the decision
to retain Avon was made in the first quarter of 2002 and Avon's results of
operations for that quarter have been classified in their respective revenue and
expense captions on the Consolidated Statement of Income. This change in
classification had no effect on previously reported net income. The effects of
this change on the Consolidated Statement of Income previously reported for the
three months ended March 31, 2002 are reflected in the restatements shown below.
3
RESTATEMENTS OF PREVIOUSLY REPORTED RESULTS
FirstEnergy, OE, CEI and TE have restated their financial statements
for the year ended December 31, 2002 and for the three months ended March 31,
2003 and 2002. The primary modifications include revisions to reflect a change
in the method of amortizing costs being recovered through the Ohio transition
plan and recognition of above-market values of certain leased generation
facilities. In addition, certain other immaterial adjustments recorded in the
first quarter of 2003 that related to prior periods are now reported in results
for the earlier periods. The net impact of these adjustments increases net
income by $6.2 million in the first quarter of 2003. Included in the adjustments
are the impact in the first quarter ended March 31, 2002 of recognizing a
reserve on the deferred costs incurred subsequent to the merger associated with
this Company's rate matter in Pennsylvania (see note 4). The impact of this
restatement increased net income in the first quarter ended March 31, 2002 by
$12 million. See Note 2(M) of the FirstEnergy, OE, CEI, and TE Form 10-K/A for
further discussion of the restatements.
Transition Cost Amortization
As discussed in Regulatory Matters in Note 4, FirstEnergy, OE, CEI
and TE amortize transition costs using the effective interest method. The
amortization schedules originally developed at the beginning of the transition
plan in 2001 in applying this method were based on total transition revenues,
including revenues designed to recover costs which have not yet been incurred or
that were recognized on the regulatory financial statements (fair value purchase
accounting adjustments) but not in the financial statements prepared under GAAP.
The Ohio electric utilities have revised the amortization schedules under the
effective interest method to consider only revenues relating to transition
regulatory assets recognized on the GAAP balance sheet. The impact of this
change will result in higher amortization of these regulatory assets in the
first several years of the transition cost recovery period, compared with the
method previously applied. The change in method results in no change in total
amortization of the regulatory assets recovered under the transition plan
through the end of 2009.
The following table summarizes the previously reported transition cost
amortization and the restated amounts under the revised method for the three
months ended March 31, 2002 and 2003:
Three Months Ended Three Months Ended
March 31, 2002 March 31, 2003
------------------------------- -------------------------------
AS PREVIOUSLY AS AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED
------------- -------- ------------- --------
OE $ 76,176 $ 68,176 $ 98,927 $101,927
CEI 13,141 37,141 16,802 41,602
TE 7,892 24,292 13,023 28,423
-------- -------- -------- --------
Total FirstEnergy $ 97,209 $129,609 $128,752 $171,952
======== ======== ======== ========
Above-Market Lease Costs
In 1997, FirstEnergy Corp. was formed through a merger between OE
and Centerior Energy Corp. The merger was accounted for as an acquisition of
Centerior, the parent company of CEI and TE, under the purchase accounting rules
of Accounting Principles Board (APB) Opinion No. 16. In connection with the
reassessment of the accounting for the transition plan, FirstEnergy reassessed
its accounting for the Centerior purchase and determined that above market lease
liabilities should have been recorded at the time of the merger. Accordingly, as
of 2002, FirstEnergy recorded additional adjustments associated with the 1997
merger between OE and Centerior to reflect certain above market lease
liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant, for which
CEI and TE had previously entered into sale-leaseback arrangements. CEI and TE
recorded an increase in goodwill related to the above market lease costs for
Beaver Valley Unit 2 since regulatory accounting for nuclear generating assets
had been discontinued prior to the merger date and it was determined that this
additional liability would have increased goodwill at the date of the merger.
The corresponding impact of the above market lease liabilities for the Bruce
Mansfield Plant was recorded as a regulatory asset because regulatory accounting
had not been discontinued at that time for the fossil generating assets and
recovery of these liabilities was provided for under the transition plan.
The total above market lease obligation of $722 million (CEI $ 611
million, TE $111 million) associated with Beaver Valley Unit 2 will be amortized
through the end of the lease term in 2017. The additional goodwill has been
recorded on a net basis, reflecting amortization that would have been recorded
through 2001 when goodwill amortization ceased with the adoption of Statement of
Financial Accounting Standard (SFAS) No. 142 (SFAS 142). The total above market
lease obligation of $755 million (CEI $457 million, TE $298 million) associated
with the Bruce Mansfield Plant is being amortized through the end of 2016.
Before the start of the transition plan in 2001, the regulatory asset would have
been amortized at the same rate as the lease obligation. Beginning in 2001, the
remaining unamortized regulatory asset would have been included in CEI's and
TE's amortization schedules for regulatory assets and amortized through the end
of the recovery period - approximately 2009 for CEI and 2007 for TE.
4
The effects of these changes and the change as described under
"Change in Previously Reported Income Statement Classification" on the
Consolidated Statements of Income previously reported for the three months ended
March 31, 2003 and 2002 are as follows:
FIRSTENERGY
THREE MONTHS ENDED THREE MONTHS ENDED
MARCH 31, 2003 MARCH 31, 2002
--------------------------- ---------------------------
AS PREVIOUSLY AS AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED
------------- ---------- ------------- ----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS))
Revenues $ 3,244,472 $3,233,756 $ 2,853,278 $2,853,278
Expenses 2,800,758 2,824,465 2,363,634 2,362,342
------------- ---------- ------------- ----------
Income before interest and income taxes 443,714 409,291 489,644 490,936
Net interest charges 202,740 206,040 278,722 278,722
Income taxes 102,136 93,773 94,429 93,946
------------- ---------- ------------- ----------
Income before discontinued operations and
cumulative effect of accounting change 138,838 109,478 116,493 118,268
Discontinued operations -- 6,877
Cumulative effect of accounting change 102,147 102,147 -- --
------------- ---------- ------------- ----------
Net income $ 240,985 $ 218,502 $ 116,493 $ 118,268
============= ========== ============= ==========
Basic earnings per share of common stock $ 0.82 $ 0.74 $ 0.40 $ 0.40
Diluted earnings per share of common stock $ 0.82 $ 0.74 $ 0.40 $ 0.40
OE
THREE MONTHS ENDED THREE MONTHS ENDED
MARCH 31, 2003 MARCH 31, 2002
--------------------------- ---------------------------
AS PREVIOUSLY AS AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED
------------- ---------- ------------- ----------
(IN THOUSANDS)
Revenues $ 742,743 $ 742,743 $ 707,799 $ 707,799
Expenses 673,054 672,661 610,735 600,449
------------- ---------- ------------- ----------
Operating income 69,689 70,082 97,064 107,350
Other income 14,031 13,501 512 512
------------- ---------- ------------- ----------
Income before net interest charges 83,720 83,583 97,576 107,862
Net interest charges 26,498 26,498 41,225 41,225
------------- ---------- ------------- ----------
Income before cumulative effect
of accounting change 57,222 57,085 56,351 66,637
Cumulative effect of accounting change 31,720 31,720 -- --
------------- ---------- ------------- ----------
Net income 88,942 88,805 56,351 66,637
Preferred stock dividend requirements 659 659 2,596 2,596
------------- ---------- ------------- ----------
Earnings on common stock $ 88,283 $ 88,146 $ 53,755 $ 64,041
============= ========== ============= ==========
CEI
THREE MONTHS ENDED THREE MONTHS ENDED
MARCH 31, 2003 MARCH 31, 2002
--------------------------- ---------------------------
AS PREVIOUSLY AS AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED
------------- ---------- ------------- ----------
(IN THOUSANDS)
Revenues $ 419,771 $ 419,771 $ 424,977 $ 433,277
Expenses 363,467 365,760 369,655 375,752
------------- ---------- ------------- ----------
Operating income 56,304 54,011 55,322 57,525
Other income 4,741 4,741 5,241 5,241
------------- ---------- ------------- ----------
Income before net interest charges 61,045 58,752 60,563 62,766
Net interest charges 40,754 43,454 47,867 47,867
------------- ---------- ------------- ----------
Income before cumulative effect
of accounting change 20,291 15,298 12,696 14,899
Cumulative effect of accounting change 42,378 42,378 -- --
------------- ---------- ------------- ----------
Net income 62,669 57,676 12,696 14,899
Preferred stock dividend requirements (759) (759) 8,256 6,556
------------- ---------- ------------- ----------
Earnings(loss) attributable to
common stock $ 63,428 $ 58,435 $ 4,440 $ 8,343
============= ========== ============= ==========
5
TE
THREE MONTHS ENDED THREE MONTHS ENDED
MARCH 31, 2003 MARCH 31, 2002
--------------------------- ---------------------------
AS PREVIOUSLY AS AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED
(IN THOUSANDS)
Revenues $ 231,822 $ 231,822 $ 244,167 $ 252,567
Expenses 221,195 226,345 234,509 241,879
------------- ---------- ------------- ----------
Operating income 10,627 5,477 9,658 10,688
Other income 3,100 3,100 4,343 4,343
------------- ---------- ------------- ----------
Income before net interest charges 13,727 8,577 14,001 15,031
Net interest charges 10,677 9,977 14,709 14,709
------------- ---------- ------------- ----------
Income (loss) before cumulative effect
of accounting change 3,050 (1,400) (708) 322
Cumulative effect of accounting change 25,550 25,550 -- --
------------- ---------- ------------- ----------
Net income (loss) 28,600 24,150 (708) 322
Preferred stock dividend requirements 1,605 2,205 4,724 4,724
------------- ---------- ------------- ----------
Earnings(loss) attributable to
common stock $ 26,995 $ 21,945 $ (5,432) $ (4,402)
============= ========== ============= ==========
The effects of these changes on the Consolidated Statements of Cash
Flows previously reported for the three months ended March 31, 2003 and 2002,
are as follows:
FE
THREE MONTHS ENDED THREE MONTHS ENDED
MARCH 31, 2003 MARCH 31, 2002
--------------------------- ---------------------------
AS PREVIOUSLY AS AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED
------------- ---------- ------------- ----------
(IN THOUSANDS)
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income $ 240,985 $ 218,502 $ 116,493 $ 118,268
Adjustments to reconcile net income
to net cash from operating activities:
Provision for depreciation and
amortization 281,662 324,862 262,828 309,374
Nuclear fuel and lease amortization 14,918 14,918 20,965 20,965
Other amortization (4,613) (4,613) (3,537) (3,537)
Deferred costs recoverable as regulatory
assets (38,748) (38,748) (70,134) (90,934)
Deferred income taxes 40,619 31,352 (20,534) (21,017)
Investment tax credits (6,259) (6,259) (6,746) (6,746)
Cumulative effect of accounting change
(Note 5) (174,663) (174,663) -- --
Receivables 1,602 (1,898) 60,095 60,095
Materials and supplies 11,413 11,413 18,163 18,163
Accounts payable (18,915) (7,115) (3,004) (3,004)
Accrued taxes 98,896 97,553 82,297 82,297
Accrued interest 89,599 89,599 86,579 86,579
Deferred rents & sale/leaseback 3,558 (17,592) 71,438 44,400
Prepayments & other (69,673) (69,673) 109,551 109,551
Other (8,119) (5,376) (260,370) (260,370)
------------- ---------- ------------- ----------
Net cash provided from operating
activities $ 462,262 $ 462,262 $ 464,084 $ 464,084
------------- ---------- ------------- ----------
6
OE
THREE MONTHS ENDED THREE MONTHS ENDED
MARCH 31, 2003 MARCH 31, 2002
--------------------------- ---------------------------
AS PREVIOUSLY AS AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED
------------- ---------- ------------- ----------
(IN THOUSANDS)
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income $ 88,942 $ 88,805 $ 56,351 $ 66,637
Adjustments to reconcile net income
to net cash from operating activities:
Provision for depreciation and
amortization 105,385 108,385 92,130 75,730
Nuclear fuel and lease amortization 7,106 7,106 11,402 11,402
Deferred income taxes 8,683 7,683 (13,170) (7,380)
Investment tax credits (3,580) (3,704) (3,773) (3,449)
Cumulative effect of accounting change (54,109) (54,109) -- --
Receivables (26,409) (29,909) 64,148 64,148
Materials and supplies (1,298) (1,298) (1,642) (1,642)
Accounts payable 14,470 14,470 (18,295) (18,295)
Accrued taxes 4,478 6,051 56,884 56,884
Accrued interest 2,437 2,437 6,237 6,237
Deferred rents & sale/leaseback 31,683 31,683 31,683 31,683
Prepayments & other (14,893) (14,893) 16,095 16,095
Other (9,378) (9,190) (30,539) (30,539)
------------- ---------- ------------- ----------
Net cash provided from operating
activities $ 153,517 $ 153,517 $ 267,511 $ 267,511
------------- ---------- ------------- ----------
CEI
THREE MONTHS ENDED THREE MONTHS ENDED
MARCH 31, 2003 MARCH 31, 2002
--------------------------- ---------------------------
AS PREVIOUSLY AS AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED
------------- ---------- ------------- ----------
(IN THOUSANDS)
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income $ 62,669 $ 57,676 $ 12,696 $ 14,899
Adjustments to reconcile net income
to net cash from operating activities:
Provision for depreciation and
amortization 26,557 51,357 28,471 52,471
Nuclear fuel and lease amortization 5,044 5,044 5,990 5,990
Other amortization (4,613) (4,613) (3,892) (3,892)
Deferred income taxes 35,474 33,804 7,196 822
Investment tax credits (965) (1,202) (902) (1,043)
Receivables 15,242 15,242 6,816 (1,484)
Materials and supplies (128) (128) (1,366) (1,366)
Accounts payable (44,129) (44,129) 18,322 18,322
Cumulative effect of accounting change (72,547) (72,547) -- --
Other (17,784) (35,684) 14,191 2,803
------------- ---------- ------------- ----------
Net cash provided from operating
activities $ 4,820 $ 4,820 $ 87,522 $ 87,522
------------- ---------- ------------- ---------
7
TE
THREE MONTHS ENDED THREE MONTHS ENDED
MARCH 31, 2003 MARCH 31, 2002
--------------------------- ---------------------------
AS PREVIOUSLY AS AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED
------------- ---------- ------------- ----------
(IN THOUSANDS)
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income $ 28,600 $ 24,150 $ (708) $ 322
Adjustments to reconcile net income
to net cash from operating activities:
Provision for depreciation and
amortization 20,240 35,640 21,368 37,768
Nuclear fuel and lease amortization 2,768 2,768 3,573 3,573
Deferred income taxes 22,675 19,130 5,314 1,242
Investment tax credits (498) (514) (486) (526)
Receivables 12,249 12,249 20,022 11,622
Materials and supplies (727) (727) (651) (651)
Accounts payable (53,917) (53,917) 2,861 1,161
Cumulative effect of accounting change (43,751) (43,751) -- --
Other (17,590) (24,979) 14,472 11,254
------------- ---------- ------------- ----------
Net cash provided from (used for)
operating activities $ (29,951) $ (29,951) $ 65,765 $ 65,765
------------- ---------- ------------- ----------
2 - COMMITMENTS, GUARANTEES AND CONTINGENCIES:
Capital Expenditures
FirstEnergy's current forecast reflects expenditures of
approximately $3.1 billion (OE-$268 million, CEI-$312 million, TE-$169 million,
Penn-$123 million, JCP&L-$462 million, Met-Ed-$288 million, Penelec-$328
million, ATSI-$131 million, FES-$823 million and other subsidiaries-$147
million) for property additions and improvements from 2003-2007, of which
approximately $727 million (OE-$86 million, CEI-$96 million, TE-$54 million,
Penn-$53 million, JCP&L-$102 million, Met-Ed-$53 million, Penelec-$54 million,
ATSI-$25 million, FES-$124 million and other subsidiaries-$80 million) is
applicable to 2003. Investments for additional nuclear fuel during the 2003-2007
period are estimated to be approximately $485 million (OE-$55 million, CEI-$53
million, TE-$34 million, Penn-$42 million and FES-$301 million), of which
approximately $69 million (OE-$23 million, CEI-$15 million, TE-$12 million and
Penn-$19 million) applies to 2003.
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 March 31, 2003, outstanding guarantees and other assurances aggregated $960.2
million.
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 $872.7 million as of March 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.
Most of FirstEnergy's surety bonds are backed by various indemnities
common within the insurance industry. Surety bonds and related FirstEnergy
guarantees of $25.8 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.
Various energy supply contracts contain credit enhancement
provisions in the form of cash collateral or letters of credit in the event of a
reduction in credit rating below investment grade. These provisions vary and
typically require more than one rating reduction to fall below investment grade
by Standard & Poor's or Moody's Investors Service to trigger additional
collateralization by FirstEnergy. As of March 31, 2003, rating-contingent
collateralization totaled $61.7 million. FirstEnergy monitors these
collateralization provisions and updates its total exposure monthly.
8
Environmental Matters
Various federal, state and local authorities regulate the Companies
with regard to air and water quality and other environmental matters.
FirstEnergy estimates additional capital expenditures for environmental
compliance of approximately $159 million, which is included in the construction
forecast provided under "Capital Expenditures" for 2003 through 2007.
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 believe they are in compliance with the current SO2
and nitrogen oxides (NOx) reduction requirements under the Clean Air Act
Amendments of 1990. SO2 reductions are being achieved by burning lower-sulfur
fuel, generating more electricity from lower-emitting plants, and/or using
emission allowances. NOx reductions are being achieved through combustion
controls and the generation of more electricity at lower-emitting plants. In
September 1998, the EPA finalized regulations requiring additional NOx
reductions from the Companies' Ohio and Pennsylvania facilities. The EPA's NOx
Transport Rule imposes uniform reductions of NOx emissions (an approximate 85%
reduction in utility plant NOx emissions from projected 2007 emissions) across a
region of nineteen states and the District of Columbia, including New Jersey,
Ohio and Pennsylvania, based on a conclusion that such NOx emissions are
contributing significantly to ozone pollution in the eastern United States.
State Implementation Plans (SIP) must comply by May 31, 2004 with individual
state NOx budgets established by the EPA. Pennsylvania submitted a SIP that
requires compliance with the NOx budgets at the Companies' Pennsylvania
facilities by May 1, 2003 and Ohio submitted a SIP that requires compliance with
the NOx budgets at the Companies' Ohio facilities by May 31, 2004.
In July 1997, the EPA promulgated changes in the National Ambient
Air Quality Standard (NAAQS) for ozone emissions and proposed a new NAAQS for
previously unregulated ultra-fine particulate matter. In May 1999, the U.S.
Court of Appeals for the D.C. Circuit found constitutional and other defects in
the new NAAQS rules. In February 2001, the U.S. Supreme Court upheld the new
NAAQS rules regulating ultra-fine particulates but found defects in the new
NAAQS rules for ozone and decided that the EPA must revise those rules. The
future cost of compliance with these regulations may be substantial and will
depend if and how they are ultimately implemented by the states in which the
Companies operate affected facilities.
In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a
Compliance Order to nine utilities covering 44 power plants, including the W. H.
Sammis Plant. In addition, the U.S. Department of Justice filed eight civil
complaints against various investor-owned utilities, which included a complaint
against OE and Penn in the U.S. District Court for the Southern District of Ohio
for which hearings began in February 2003. The NOV and complaint allege
violations of the Clean Air Act based on operation and maintenance of the Sammis
Plant dating back to 1984. The complaint requests permanent injunctive relief to
require the installation of "best available control technology" and civil
penalties of up to $27,500 per day of violation. Although unable to predict the
outcome of these proceedings, FirstEnergy believes the Sammis Plant is in full
compliance with the Clean Air Act and the NOV and complaint are without merit.
Penalties could be imposed if the Sammis Plant continues to operate without
correcting the alleged violations and a court determines that the allegations
are valid. The Sammis Plant continues to operate while these proceedings are
pending.
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants. The EPA identified mercury as the hazardous air pollutant of
greatest concern. The EPA established a schedule to propose regulations by
December 2003 and issue final regulations by December 2004. The future cost of
compliance with these regulations may be substantial.
As a result of the Resource Conservation and Recovery Act of 1976,
as amended, and the Toxic Substances Control Act of 1976, federal and state
hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous waste
disposal requirements pending the EPA's evaluation of the need for future
regulation. The EPA has issued its final regulatory determination that
regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the
EPA announced that it will develop national standards regulating disposal of
coal ash under its authority to regulate nonhazardous waste.
The Companies have been named as "potentially responsible parties"
(PRPs) at waste disposal sites which may require cleanup under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980. Allegations of
disposal of hazardous substances at historical sites and the liability involved
are often unsubstantiated and subject to dispute; however, federal law provides
that all PRPs for a particular site be held liable on a joint and several basis.
Therefore, potential environmental liabilities have been recognized on the
Consolidated Balance Sheet as of March 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
9
societal benefits charge. The Companies have total accrued liabilities
aggregating approximately $53.9 million (JCP&L-$47.1 million, CEI-$2.5 million,
TE-$0.2 million, Met-Ed-$0.2 million, Penelec-$0.3 million and other-$3.6
million) as of March 31, 2003.
The effects of compliance on the Companies with regard to
environmental matters could have a material adverse effect on FirstEnergy's
earnings and competitive position. These environmental regulations affect
FirstEnergy's earnings and competitive position to the extent it competes with
companies that are not subject to such regulations and therefore do not bear the
risk of costs associated with compliance, or failure to comply, with such
regulations. FirstEnergy believes it is in material compliance with existing
regulations but is unable to predict whether environmental regulations will
change and what, if any, the effects of such change would be.
Other Commitments and Contingencies
GPU made significant investments in foreign businesses and
facilities through its GPU Capital and GPU Power subsidiaries. Although
FirstEnergy attempts to mitigate its risks related to foreign investments, it
faces additional risks inherent in operating in such locations, including
foreign currency fluctuations.
EI Barranquilla, a wholly owned subsidiary of GPU Power, is a 28.67%
equity investor in Termobarranquilla S.A., Empresa de Servicios Publicos
(TEBSA), which owns a Colombian independent power generation project. GPU Power
is committed through September 30, 2003, under certain circumstances, to make
additional standby equity contributions to TEBSA of $21.3 million, which
FirstEnergy has guaranteed. The total outstanding senior debt of the TEBSA
project is $239 million as of March 31, 2003. The lenders include the Overseas
Private Investment Corporation, US Export Import Bank and a commercial bank
syndicate. FirstEnergy has also guaranteed the obligations of the operators of
the TEBSA project, up to a maximum of $5.9 million (subject to escalation) under
the project's operations and maintenance agreement. FirstEnergy provided the
TEBSA project lenders a $50 million letter of credit (LOC) issued by Bank One
under FirstEnergy's existing $250 million LOC capacity available as part of the
$1.5 billion FirstEnergy credit facility to obtain TEBSA lender consent to
abandon its Argentina operations, GPU Empresa Distribuidora Electrica Regional
S.A. and affiliates (Emdersa) (see Note 3 below).
Legal Matters
Various lawsuits, claims and proceedings related to the
FirstEnergy's normal business operations are pending against it and its
subsidiaries. The most significant applicable to the Company are described
above.
3 - DIVESTITURES:
INTERNATIONAL OPERATIONS-
FirstEnergy had identified certain former GPU international
operations for divestiture within one year of the merger. These operations
constitute individual "lines of business" as defined in APB Opinion (APB) No.
30, "Reporting the Results of Operations - Reporting the Effects of Disposal of
a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions," with physically and operationally separable
activities. Application of Emerging Issues Task Force ( EITF) Issue No. 87-11,
"Allocation of Purchase Price to Assets to Be Sold," required that expected,
pre-sale cash flows, including incremental interest costs on related acquisition
debt, of these operations be considered part of the purchase price allocation.
Accordingly, subsequent to the merger date, results of operations and
incremental interest costs related to these international subsidiaries were not
included in FirstEnergy's 2001 Consolidated Statement of Income. Additionally,
assets and liabilities of these international operations had been segregated
under separate captions on the Consolidated Balance Sheet as of December 31,
2001 as "Assets Pending Sale" and "Liabilities Related to Assets Pending Sale."
Upon completion of its merger with GPU, FirstEnergy accepted an
October 2001 offer from Aquila, Inc. (formerly UtiliCorp United) to purchase
Avon, FirstEnergy's wholly owned holding company for Midlands Electricity plc,
for $2.1 billion (including the assumption of $1.7 billion of debt). The
transaction closed on May 8, 2002 and reflected the March 2002 modification of
Aquila's initial offer such that Aquila acquired a 79.9 percent equity interest
in Avon for approximately $1.9 billion (including the assumption of $1.7 billion
of debt). Proceeds to FirstEnergy included $155 million in cash and a note
receivable for approximately $87 million (representing the present value of $19
million per year to be received over six years beginning in 2003) from Aquila
for its 79.9 percent interest. FirstEnergy and Aquila together own all of the
outstanding shares of Avon through a jointly owned subsidiary, with each company
having an ownership voting interest. Originally, in accordance with applicable
accounting guidance, the earnings of those foreign operations were not
recognized in current earnings from the date of the GPU acquisition. However, as
a result of the decision to retain an ownership interest in Avon in the quarter
ended March 31, 2002, EITF Issue No. 90-6, "Accounting for Certain Events Not
Addressed in Issue No. 87-11 relating to an Acquired Operating Unit to be Sold"
required FirstEnergy to reallocate the purchase price of GPU based on amounts as
of the purchase date as if Avon had never been held for sale, including reversal
of the effects of having applied EITF Issue No. 87-11, to the transaction. The
effect of reallocating the
10
purchase price and reversal of the effects of EITF Issue No. 87-11, including
the allocation of capitalized interest, has been reflected in the Consolidated
Statement of Income for the quarter ended March 31, 2002 by reclassifying
certain revenue and expense amounts related to activity during the quarter ended
March 31, 2002 to their respective income statement classifications. See Note 1
for the effects of the change in classification. In the fourth quarter of 2002,
FirstEnergy recorded a $50 million charge to reduce the carrying value of its
remaining 20.1 percent interest.
GPU's former Argentina operations were also identified by
FirstEnergy for divestiture within one year of the merger. FirstEnergy
determined the fair value of Emdersa, based on the best available information as
of the date of the merger. Subsequent to that date, a number of economic events
have occurred in Argentina which may have an impact on FirstEnergy's ability to
realize Emdersa's estimated fair value. These events included currency
devaluation, restrictions on repatriation of cash, and the anticipation of
future asset sales in that region by competitors. FirstEnergy did not reach a
definitive agreement to sell Emdersa as of December 31, 2002. Therefore, these
assets were no longer classified as "Assets Pending Sale" on the Consolidated
Balance Sheet as of December 31, 2002. Additionally, under EITF Issue No. 90-6,
FirstEnergy recorded in the fourth quarter of 2002 a one-time, non-cash charge
included as a "Cumulative Adjustment for Retained Businesses Previously Held for
Sale" on its 2002 Consolidated Statement of Income related to Emdersa's
cumulative results of operations from November 7, 2001 through September 30,
2002. The amount of this one-time, after-tax charge was $93.7 million, or $0.32
per share of common stock (comprised of $108.9 million in currency transaction
losses arising principally from U.S. dollar denominated debt, offset by $15.2
million of operating income).
In October 2002, FirstEnergy began consolidating the results of
Emdersa's operations in its financial statements. In addition to the currency
transaction losses of $108.9 million, FirstEnergy also recognized a currency
translation adjustment (CTA) in other comprehensive income (OCI) of $91.5
million as of December 31, 2002, which reduced FirstEnergy's common
stockholders' equity. This adjustment represents the impact of translating
Emdersa's financial statements from its functional currency to the U.S. dollar
for GAAP financial reporting.
On April 18, 2003, FirstEnergy divested its ownership in Emdersa.
The abandonment was accomplished by relinquishing FirstEnergy's shares of
Emdersa's parent company, GPU Argentina Holdings, to that company's independent
Board of Directors, relieving FirstEnergy of all rights and obligations relative
to this business. As a result of this action, FirstEnergy's gains and losses
related to discontinuing these operations have been presented as a separate item
on the Consolidated Statements of Income - "Discontinued operations" - in
accordance with SFAS 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets." Due to the abandonment, FirstEnergy recognized a one-time,
non-cash charge of $67.4 million in the second quarter of 2003. This charge
resulted from realizing $89.8 million of currency translation losses through
current period earnings, partially offset by a $22.4 million gain recognized
from eliminating FirstEnergy's investment in Emdersa. Discontinued operations
for the six-month period reflected a net after-tax charge of $60.5 million,
which included $6.9 million of earnings from Emdersa in the first quarter of
2003. As a result of the abandonment, FirstEnergy has substantially divested all
of GPU Capital's international operations.
The $67.4 million charge does not include the anticipated income tax
benefits related to the abandonment. These tax benefits will be fully reserved
during the second quarter. FirstEnergy anticipates tax benefits of approximately
$129 million, of which $50 million would increase net income in the period that
it becomes probable those benefits will be realized. The remaining $79 million
of tax benefits would reduce goodwill recognized in connection with the
acquisition of GPU.
SALE OF GENERATING ASSETS-
In November 2001, FirstEnergy reached an agreement to sell four
coal-fired power plants totaling 2,535 megawatts (MW) to NRG Energy Inc. On
August 8, 2002, FirstEnergy notified NRG that it was canceling the agreement
because NRG stated that it could not complete the transaction under the original
terms of the agreement. FirstEnergy also notified NRG that FirstEnergy reserves
the right to pursue legal action against NRG, its affiliate and its parent, Xcel
Energy for damages, based on the anticipatory breach of the agreement. On
February 25, 2003, the U.S. Bankruptcy Court in Minnesota approved FirstEnergy's
request for arbitration against NRG.
In December 2002, FirstEnergy 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 Statement of Income.
4 - REGULATORY MATTERS:
In Ohio, New Jersey and Pennsylvania, laws applicable to electric
industry deregulation included similar provisions which are reflected in the
Companies' respective state regulatory plans:
- allowing the Companies' electric customers to select their
generation suppliers;
11
- establishing provider of last resort (PLR) obligations to
customers in the Companies' service areas;
- allowing recovery of potentially stranded investment
(sometimes referred to as transition costs);
- itemizing (unbundling) the current price of electricity into
its component elements - including generation, transmission,
distribution and stranded costs recovery charges;
- deregulating the Companies' electric generation businesses;
and
- continuing regulation of the Companies' transmission and
distribution systems.
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 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 Statement of Financial
Accounting Standards (SFAS) No. 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 (see note 1) and $0.8 billion, net of
deferred income taxes, (CEI-$0.5 billion and TE-$0.3 billion) of additional
plant costs that were reflected on CEI's and TE's regulatory financial
statements.
Also as part of the settlement agreement, FirstEnergy is giving
preferred access over its subsidiaries to nonaffiliated marketers, brokers and
aggregators to 1,120 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 - recovery will be accomplished by extending the
respective transition cost recovery period. If the customer shopping goals
established in the agreement had not been achieved by the end of 2005, the
transition cost recovery periods could have been shortened for OE, CEI and TE to
reduce recovery by as much as $500 million (OE - $250 million, CEI - $170
million and TE - $80 million). The Ohio Companies achieved all of their required
20% customer shopping goals in 2002. Accordingly, FirstEnergy believes that
there will be no regulatory action reducing the recoverable transition costs.
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 remain in effect at
increasing levels through July 2003. The Final Order also confirmed the
establishment of a non-bypassable societal benefits charge (SBC) to recover
costs which include nuclear plant decommissioning and manufactured gas plant
remediation, as well as a non-bypassable market transition charge (MTC)
primarily to recover stranded costs. The NJBPU has deferred making a final
determination of the net proceeds and stranded costs related to prior generating
asset divestitures until JCP&L's request for an Internal Revenue Service (IRS)
ruling regarding the treatment of associated federal income tax benefits is
12
acted upon. Should the IRS ruling support the return of the tax benefits to
customers, there would be no effect to FirstEnergy's or JCP&L's net income since
the contingency existed prior to the merger.
In addition, the Final Order provided for the ability to securitize
stranded costs associated with the divested Oyster Creek Nuclear Generating
Station. In 2002, JCP&L received NJBPU authorization to issue $320 million of
transition bonds to securitize the recovery of these costs and which provided
for a usage-based non-bypassable transition bond charge and for the transfer of
the bondable transition property to another entity. JCP&L sold the transition
bonds through its wholly owned subsidiary, JCP&L Transition Funding LLC, in June
2002 - those bonds are recognized on the Consolidated Balance Sheet.
JCP&L's PLR obligation to provide basic generation service (BGS) to
non-shopping customers is supplied almost entirely from contracted and open
market purchases. JCP&L is permitted to defer for future collection from
customers the amounts by which its costs of supplying BGS to non-shopping
customers and costs incurred under nonutility generation (NUG) agreements exceed
amounts collected through BGS and MTC rates. As of March 31, 2003, the
accumulated deferred cost balance totaled approximately $530 million. The NJBPU
also allowed securitization of JCP&L's deferred balance to the extent permitted
by law upon application by JCP&L and a determination by the NJBPU that the
conditions of the New Jersey restructuring legislation are met. There can be no
assurance as to the extent, if any, that the NJBPU will permit such
securitization.
Under New Jersey transition legislation, all electric distribution
companies were required to file rate cases to determine the level of unbundled
rate components to become effective August 1, 2003. JCP&L submitted two rate
filings with the NJBPU in August 2002. The first filing requested increases in
base electric rates of approximately $98 million annually. The second filing was
a request to recover deferred costs that exceeded amounts being recovered under
the current MTC and SBC rates; one proposed method of recovery of these costs is
the securitization of the deferred balance. This securitization methodology is
similar to the Oyster Creek securitization discussed above. Hearings began in
February 2003. On March 18, 2003, a report prepared by independent auditors
addressing costs deferred by JCP&L from August 1, 1999 through July 31, 2002,
was transmitted to the Office of Administrative Law, where JCP&L's rate case is
being heard. While the auditors concluded that JCP&L's energy procurement
strategy and process was reasonable and prudent, they identified potential
disallowances approximating $17 million. The report subjected $436 million of
deferred costs to a retrospective prudence review during a period of extreme
price uncertainty and volatility in the energy markets. Although JCP&L disagrees
with the potential disallowances, it is pleased with the report's major
conclusions and overall tone. Hearings concluded on April 28, 2003, and initial
briefs were filed on May 7, 2003. The JCP&L brief supports its two rate filings
requesting an aggregate rate increase of approximately $122 million in base
electric rates and the recovery of deferred costs based on the securitization
methodology discussed above. If the securitization methodology is not allowed,
then JCP&L has requested deferred cost recovery over a four-year period with a
return on the unamortized deferred cost balance. This alternative would increase
the overall rate request to approximately $246 million. JCP&L strongly disagrees
with many of the positions taken by NJBPU Staff. The Staff's position would
result in a $119 million estimated annual earnings decrease related to the
electricity delivery charge. In addition, the Staff recommended disallowing
approximately $153 million of deferred energy costs which would result in a
one-time pre-tax charge against earnings of $153 million (or $0.31 per share of
common stock). JCP&L will respond to the Staff's position in its Reply Brief
which is due on May 21, 2003. The Administrative Law Judge's recommended
decision is due by the end of June 2003 and the NJBPU's subsequent decision is
due in July 2003.
In 1997, the NJBPU authorized JCP&L to recover from customers,
subject to possible refund, $135 million of costs incurred in connection with a
1996 buyout of a power purchase agreement. JCP&L has recovered the full $135
million; the NJBPU has established a procedural schedule to take further
evidence with respect to the buyout to enable it to make a final prudence
determination contemporaneously with the resolution of the pending rate case.
In December 2001, the NJBPU authorized the auctioning of BGS for the
period from August 1, 2002 through July 31, 2003 to meet the electricity demands
of all customers who have not selected an alternative supplier. The auction
results were approved by the NJBPU in February 2002, removing JCP&L's BGS
obligation of 5,100 MW for the period August 1, 2002 through July 31, 2003. In
February 2003, the NJBPU approved the BGS auction results for the period
beginning August 1, 2003. The auction covered a fixed price bid (applicable to
all residential and smaller commercial and industrial customers) and an hourly
price bid (applicable to all large industrial customers) process. JCP&L sells
all self-supplied energy (NUGs and owned generation) to the wholesale market
with offsetting credits to its deferred energy balances.
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
13
situation, if the IRS ruling ultimately supports returning these tax benefits to
customers, there would be no effect to FirstEnergy's, Met-Ed's or Penelec's net
income since the contingency existed prior to the merger.
As a result of their generating asset divestitures, Met-Ed and
Penelec obtained their supply of electricity to meet their PLR obligations
almost entirely from contracted and open market purchases. In 2000, Met-Ed and
Penelec filed a petition with the PPUC seeking permission to defer, for future
recovery, energy costs in excess of amounts reflected in their capped generation
rates; the PPUC subsequently consolidated this petition in January 2001 with the
FirstEnergy/GPU merger proceeding.
In June 2001, the PPUC entered orders approving the Settlement
Stipulation with all of the major parties in the combined merger and rate relief
proceedings which approved the merger and provided Met-Ed and Penelec PLR
deferred accounting treatment for energy costs. The PPUC permitted Met-Ed and
Penelec to defer for future recovery the difference between their actual energy
costs and those reflected in their capped generation rates, retroactive to
January 1, 2001. Correspondingly, in the event that energy costs incurred by
Met-Ed and Penelec would be below their respective capped generation rates, that
difference would have reduced costs that had been deferred for recovery in
future periods. This PLR deferral accounting procedure was denied in a court
decision discussed below. Met-Ed's and Penelec's PLR obligations extend through
December 31, 2010; during that period competitive transition charge (CTC)
revenues would have been applied to their stranded costs. Met-Ed and Penelec
would have been permitted to recover any remaining stranded costs through a
continuation of the CTC after December 31, 2010 through no later than December
31, 2015. Any amounts not expected to be recovered by December 31, 2015 would
have been written off at the time such nonrecovery became probable.
Several parties had filed Petitions for Review in June and July 2001
with the Commonwealth Court of Pennsylvania regarding the June 2001 PPUC orders.
On February 21, 2002, the Court affirmed the PPUC decision regarding the
FirstEnergy/GPU merger, remanding the decision to the PPUC only with respect to
the issue of merger savings. The Court reversed the PPUC's decision regarding
the PLR obligations of Met-Ed and Penelec, and rejected those parts of the
settlement that permitted the companies to defer for accounting purposes the
difference between their wholesale power costs and the amount that they collect
from retail customers. FirstEnergy and the PPUC each filed a Petition for
Allowance of Appeal with the Pennsylvania Supreme Court on March 25, 2002,
asking it to review the Commonwealth Court decision. Also on March 25, 2002,
Citizens Power filed a motion seeking an appeal of the Commonwealth Court's
decision to affirm the FirstEnergy and GPU merger with the Pennsylvania Supreme
Court. In September 2002, FirstEnergy established reserves for Met-Ed's and
Penelec's PLR deferred energy costs which aggregated $287.1 million. The
reserves reflected the potential adverse impact of a pending Pennsylvania
Supreme Court decision whether to review the Commonwealth Court ruling.
FirstEnergy recorded an aggregate non-cash charge to income of $55.8 million
($32.6 million net of tax), or $0.11 per share of common stock, for the deferred
costs incurred subsequent to the merger. The reserve for the remaining $231.3
million of deferred costs increased goodwill by an aggregate net of tax amount
of $135.3 million.
On January 17, 2003, the Pennsylvania Supreme Court denied further
appeals of the February 21, 2002 Pennsylvania Commonwealth Court decision, which
effectively affirmed the PPUC's order approving the merger between FirstEnergy
and GPU, let stand the Commonwealth Court's denial of PLR rate relief for Met-Ed
and Penelec and remanded the merger savings issue back to the PPUC. On April 2,
2003, the PPUC remanded the merger savings issue to the Office of Administrative
Law for hearings and directed Met-Ed and Penelec to file a position paper on the
effect of the Commonwealth Court's order on the Settlement Stipulation by May 2,
2003. Because FirstEnergy had already reserved for the deferred energy costs and
FES has largely hedged the anticipated PLR energy supply requirements for Met-Ed
and Penelec through 2005 as discussed further below, FirstEnergy, Met-Ed and
Penelec believe that the disallowance of continued CTC recovery of PLR costs
will not have a future adverse financial impact during that period.
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 currently runs through December 2003 and will be automatically
extended for each successive calendar year unless any party elects to cancel the
agreement by November 1 of the preceding year. Under the terms of the wholesale
agreement, FES 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 existing power contracts with
nonaffiliated third party suppliers. This arrangement reduces Met-Ed's and
Penelec's exposure to high wholesale power prices by providing power at or below
the shopping credit for their uncommitted PLR energy costs during the term of
the agreement with FES. FES has hedged most of Met-Ed's and Penelec's unfilled
PLR 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 amounts recovered through their capped generation rates.
5 - NEW ACCOUNTING STANDARDS:
In June 2001, the Financial Accounting Standards Board (FASB) issued
SFAS 143, "Accounting for Asset Retirement Obligations." The new statement
provides accounting standards for retirement obligations associated with
14
tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143
requires that the fair value of a liability for an asset retirement obligation
(ARO) be recorded 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 recorded 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. 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 at the date of adoption was
$1.109 billion, including accumulated accretion for the period from the date the
liability was incurred to the date of adoption. At December 31, 2002,
FirstEnergy had recorded decommissioning liabilities of $1.243 billion.
FirstEnergy expects substantially all nuclear decommissioning costs for Met-Ed,
Penelec, JCP&L and Penn would 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 these operating companies. The remaining cumulative effect
adjustment for unrecognized depreciation and accretion offset by the reduction
in the existing decommissioning liabilities and ceasing the accounting practice
of depreciating non-regulated generation assets using a cost of removal
component was a $174.7 million increase to income, or a $102.1 million increase
net of tax, or $0.35 per share of common stock (basic and diluted).
FirstEnergy recorded an ARO for nuclear decommissioning ($1.096
billion) of the Beaver Valley 1, Beaver Valley 2, Davis-Besse, Perry, and TMI-2
nuclear generation facilities with the remaining ARO related to Bruce
Mansfield's sludge impoundment facilities and two coal ash disposal sites. The
Company maintains nuclear decommissioning trust funds, which had balances at
March 31, 2003 of $1.061 billion. This number represents the fair value of the
assets that are legally restricted for purposes of settling the nuclear
decommissioning ARO. The following table provides the beginning and ending
aggregate carrying amount of the ARO and the changes to the balance for the
period of January 1, 2003 through March 31, 2003.
ARO RECONCILIATION
------------------
(MILLIONS)
Beginning balance as of January 1, 2003 ........................ $1,109
Liabilities incurred in the current period.................... --
Liabilities settled in the current period..................... --
Accretion expense............................................. 18
Revisions in estimated cash flows............................... --
------
ENDING BALANCE AS OF MARCH 31, 2003............................. $1,127
------
The following table provides on an adjusted basis the year-end
balance of the ARO related to nuclear decommissioning and sludge impoundment for
2002, as if SFAS 143 had been adopted on January 1, 2002.
ADJUSTED ARO RECONCILIATION
---------------------------
(MILLIONS)
Beginning balance as of January 1, 2002......................... $1,042
Accretion 2002.................................................. 67
------
ENDING BALANCE AS OF DECEMBER 31, 2002 ........................ $1,109
------
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 are applied to the generation assets.
This practice recognizes accumulated depreciation in excess of the historical
cost of an asset, because the removal cost exceeds the estimated salvage value.
The change in accounting resulted in a $60 million credit to income as part of
the SFAS 143 cumulative effect adjustment. Beginning in 2003 depreciation rates
applied to non-regulated generation assets will exclude the cost of removal
component and cost of removal will be charged to income rather than charged to
the accumulated provision for depreciation. In accordance with SFAS 71, the
regulated plant assets will continue the accounting practice of depreciating
assets using a cost of removal component in the depreciation rates. The net
removal cost credit balance included in the accumulated provision for regulated
assets at March 31, 2003 is $296.1 million.
The following table provides on an adjusted basis the effect on
income, as if the accounting for SFAS 143 had been applied in the first quarter
2002.
15
EFFECT OF THE CHANGE IN ACCOUNTING PRINCIPLE
APPLIED RETROACTIVELY TO THE FIRST QUARTER OF 2002
--------------------------------------------------
INCREASE(DECREASE)
(MILLIONS)
RESTATED
(SEE NOTE 1)
Reported net income...................... $ 118
-----
Replacement of decommissioning expense... 26
Depreciation of asset retirement cost.... (2)
Accretion of asset retirement cost....... (10)
Income tax effect........................ (6)
-----
Total earnings effect.................... 8
-----
Net income adjusted...................... $ 126
=====
Earnings per share of common stock
(basic and diluted):
Net income as previously reported $0.40
Adjustment for effect of change in
accounting principle applied
retroactively 0.02
-----
Net income adjusted $0.42
=====
In January 2003, the FASB issued an interpretation of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. This interpretation requires an enterprise to
disclose the nature of its involvement with a VIE if the enterprise has a
significant variable interest in the VIE and to consolidate a VIE if the
enterprise is the primary beneficiary. VIEs created after January 31, 2003 are
immediately subject to the provisions of FIN 46. VIEs created before February 1,
2003 are subject to this interpretation's provisions in the first interim or
annual reporting period after June 15, 2003 (FirstEnergy's third quarter of
2003). The FASB also identified transitional disclosure provisions for all
financial statements issued after January 31, 2003.
FirstEnergy currently has transactions with entities in connection
with sale and leaseback arrangements, the sale of preferred securities and debt
secured by bondable property, which may fall within the scope of this
interpretation and which are reasonably possible of meeting the definition of a
VIE in accordance with FIN 46.
FirstEnergy currently consolidates the majority of these entities
and believes it will continue to consolidate following the adoption of FIN 46.
In addition to the entities FirstEnergy is currently consolidating FirstEnergy
believes that the PNBV Capital Trust, which reacquired a portion of the
off-balance sheet debt issued in connection with the sale and leaseback of OE's
interest in the Perry Nuclear Plant and Beaver Valley Unit 2, would require
consolidation. Ownership of the trust includes a three-percent equity interest
by a nonaffiliated party and a three-percent equity interest by OES Ventures, a
wholly owned subsidiary of OE. Full consolidation of the trust under FIN 46
would change the characterization of the PNBV trust investment to a lease
obligation bond investment. Also, consolidation of the outside minority interest
would be required, which would increase assets and liabilities by $12.0 million.
Issued by the FASB in April 2003, SFAS 149 further clarifies and
amends accounting and reporting for derivative instruments. The statement amends
SFAS133 for decisions made by the Derivative Implementation Group, as well as
issues raised in connection with other FASB projects and implementation issues.
The statement is effective for contracts entered into or modified after June 30,
2003 except for implementation issues that have been effective for quarters
which began prior to June 15, 2003, which continue to be applied based on their
original effective dates. FirstEnergy is currently assessing the new standard
and has not yet determined the impact on its financial statements.
In June 2002, the EITF reached a partial consensus on Issue No.
02-03, "Issues Involved in Accounting for Derivative Contracts Held for Trading
Purposes and Contracts Involved in Energy Trading and Risk Management
Activities." Based on the EITF's partial consensus position, for periods after
July 15, 2002, mark-to-market revenues and expenses and their related
kilowatt-hour (KWH) sales and purchases on energy trading contracts must be
shown on a net basis in the Consolidated Statements of Income. Prior to its
adoption for 2002 year end reporting, FirstEnergy had previously reported such
contracts as gross revenues and purchased power costs. Comparative quarterly
disclosures and the Consolidated Statements of Income for revenues and expenses
have been reclassified for 2002 to conform with the revised presentation. In
addition, the related KWH sales and purchases statistics described under
Management's
16
Discussion and Analysis of Results of Operations and Financial Condition were
reclassified. The following table displays the impact of changing to a net
presentation for FirstEnergy's energy trading operations.
THREE MONTHS ENDED
MARCH 31, 2002
---------------------
2002 IMPACT OF RECORDING ENERGY TRADING NET REVENUES EXPENSES
---------------------
RESTATED RESTATED
(IN MILLIONS)
Total before adjustment............................. $2,893 $2,402
Adjustment.......................................... (40) (40)
------ ------
Total as reported................................... $2,853 $2,362
====== ======
6 - 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
2002 "Other" assets amount included assets in the United Kingdom identified for
divestiture (see Note 3 - Divestitures) which were sold in the second quarter of
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, which includes eight electric utility operating companies in
Ohio, Pennsylvania and New Jersey that provide electric transmission and
distribution services. Its other material business segment consists of the
subsidiaries that operate unregulated energy and energy-related businesses.
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 an alternative, competitive generation supplier. The regulated services
segment obtains a portion of its required generation through power supply
agreements with the competitive services segment.
SEGMENT FINANCIAL INFORMATION
REGULATED COMPETITIVE RECONCILING
SERVICES(D) SERVICES OTHER(C) ADJUSTMENTS CONSOLIDATED(C)(D)
----------- ----------- -------- ----------- ------------------
(IN MILLIONS)
THREE MONTHS ENDED:
MARCH 31, 2003
External revenues ........................... $ 2,315 $ 866 $ 51 $ 12(a) $ 3,244
Internal revenues ........................... 264 560 124 (948)(b) --
Total revenues ........................... 2,579 1,426 175 (936) 3,244
Depreciation and amortization ............... 307 7 11 -- 325
Net interest charges ........................ 125 11 105 (35)(b) 206
Income taxes ................................ 167 (43) (30) -- 94
Income before cumulative effect of accounting
change ................................... 216 (56) (51) -- 109
Net income .................................. 317 (55) (44) -- 218
Total assets ................................ 29,649 2,449 1,421 -- 34,287
Property additions .......................... 118 79 27 -- 224
MARCH 31, 2002
External revenues ........................... $ 1,995 $ 638 $ 214 $ 6(a) $ 2,853
Internal revenues ........................... 355 410 117 (882)(b) --
Total revenues ........................... 2,350 1,048 331 (876) 2,853
Depreciation and amortization ............... 292 7 12 -- 311
Net interest charges ........................ 161 10 122 (14)(b) 279
Income taxes ................................ 185 (41) (27) -- 117
Net income (loss) ........................... 188 (60) (22) -- 106
Total assets ................................ 29,552 2,706 6,288 (836)(b) 37,710
Property additions .......................... 144 37 14 -- 195
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.
(c) Amounts restated in 2002 - See Note 1.
(d) Amounts restated in 2002 and 2003 - see Note 1.
17
7. SUBSEQUENT EVENTS
ENVIRONMENTAL MATTERS-
On August 8, 2003, FirstEnergy, OE and Penn reported a development
regarding a complaint filed by the U.S. Department of Justice with respect to
the W.H. Sammis Plant. As reported, on August 7, 2003, the United States
District Court for the Southern District of Ohio ruled that 11 projects
undertaken at the 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 March 15, 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." Management is unable to predict the ultimate
outcome of this matter. The potential penalties that may be imposed, as well as
the capital expenditures necessary to comply with substantive remedial measures
that may be required, may have a material adverse impact on the Company's
financial condition.
REGULATORY MATTERS-
New Jersey
On July 25, 2003, FirstEnergy and JCP&L announced that review is
underway concerning a decision by the NJBPU on JCP&L's rate proceeding. Based on
that review, JCP&L will decide its appropriate course of action, which could
include filing a request for reconsideration with the NJBPU and possibly an
appeal to the Appellate Division of the Superior Court of New Jersey.
In its ruling, the NJBPU reduced JCP&L's annual revenues by
approximately $62 million, for an average rate decrease of 3 percent, 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 6 to 12 months. During that
period, JCP&L would initiate another proceeding to request recovery of
additional expenses incurred to enhance system reliability. In that proceeding,
the NJBPU could increase the return on equity to 9.75 percent or decrease it to
9.25 percent, depending on its assessment of the reliability of JCP&L's service.
Any reduction could be retroactive to August 1, 2003.
The NJBPU decision reflects elimination of $111 million in annual
customer credits mandated by the New Jersey Electric Discount and Energy
Competition Act (EDECA); a $223 million reduction in the energy delivery charge;
a net $1 million increase in the SBC; and a $49 million increase in the MTC. The
$1 million net SBC increase reflects approximately a $22 million increase
related to universal services' costs previously approved in a separate
proceeding, as well as reductions in other components of the SBC.
The MTC would allow for the recovery of $465 million of deferred
energy costs over the next 10 years on an interim basis, thus disallowing $153
million of the $618 million provided for in the settlement agreement. This
decision reflects the NJBPU's belief that a hindsight review comparing JCP&L's
power purchases to spot market prices provides the appropriate benchmark for
recovery. JCP&L's deferred energy costs primarily reflect mandated purchase
power contracts with NUG's that are above wholesale market prices, and costs of
providing basic generation service to customers in excess of the company's
capped basic generation service charges during the transition period under
EDECA, which ends August 1, 2003. At that time, the generation portion of most
customer bills will increase by an average of 7.5 percent as a result of the
outcome of the basic generation service auction conducted earlier this year by
the BPU.
In the second quarter of 2003, JCP&L recorded charges to net income
aggregating $158 million ($94 million net of tax) consisting of the $153 million
deferred energy costs and other regulatory assets.
On July 25, 2003, the NJBPU approved a Stipulation of Settlement
between the parties and authorized the recovery of the total $135 million of the
Freehold buyout costs, eliminating the interim nature of the recovery.
Pennsylvania
On April 2, 2003, the PPUC remanded the merger savings issue to the
Office of Administrative Law for hearings and directed Met-Ed and Penelec to
file a position paper on the effect of the Commonwealth Court's order on the
Settlement Stipulation by May 2, 2003 and for the other parties to file their
responses to the Met-Ed and Penelec position paper by June 2, 2003. In summary,
the Met-Ed and Penelec position paper essentially stated the following:
18
- Because no stay of the PPUC's June 2001 order approving the Settlement
Stipulation was issued or sought, the Stipulation remained in effect until
the Pennsylvania Supreme Court denied all appeal applications in January
2003,
- As of January 16, 2003, the Supreme Court's Order became final and
the portions of the PPUC's June 2001 Order that were inconsistent
with the Supreme Court's findings were reversed,
- The Supreme Court's finding effectively amended the Stipulation to
remove the PLR cost recovery and deferral provisions and reinstated
the GENCO Code of Conduct as a merger condition, and
- All other provisions included in the Stipulation unrelated to these
three issues remain in effect.
The other parties' responses included significant disagreement with
the position paper and disagreement among the other parties themselves,
including the Stipulation's original signatory parties. Some parties believe
that no portion of the Stipulation has survived the Commonwealth Court's Order.
Because of these disagreements, Met-Ed and Penelec filed a letter on June 11,
2003 with the Administrative Law Judge assigned to the remanded case voiding the
Stipulation in its entirety pursuant to the termination provisions. They believe
this will significantly simplify the issues in the pending action by reinstating
Met-Ed's and Penelec's Restructuring Settlement previously approved by the PPUC.
In addition, they have agreed to voluntarily continue certain Stipulation
provisions including funding for energy and demand side response programs and to
cap distribution rates at current levels through 2007. This voluntary
distribution rate cap is contingent upon a finding that Met-Ed and Penelec have
satisfied the "public interest" test applicable to mergers and that any rate
impacts of merger savings will be dealt with in a subsequent rate case. Based
upon this letter, Met-Ed and Penelec believe that the remaining issues before
the Administrative Law Judge are the appropriate treatment of merger savings
issues and whether their accounting and related tariff modifications are
consistent with the Court Order.
INTERNATIONAL OPERATIONS-
Pending Sale of Remaining Investment in Avon and Sale of Note from Aquila
On May 22, 2003, FirstEnergy announced it reached an agreement to
sell its 20.1 percent interest in Avon to Scottish and Southern Energy plc; that
agreement also includes Aquila's 79.9 percent interest (See Note 3). Under terms
of the agreement, Scottish and Southern will pay FirstEnergy and Aquila an
aggregate $70 million (FirstEnergy's share would be approximately $14 million).
Avon's debt will remain with that company. FirstEnergy also recognized in the
second quarter of 2003 an impairment of $12.6 million ($8.2 million after tax)
related to the carrying value of the note receivable from the initial sale
of a 79.9 percent interest in Avon that occurred in May 2002. After receiving
the first annual installment payment of $19 million in May 2003, FirstEnergy
sold the remaining balance of the note in the secondary market and received
$63.2 million in proceeds on July 28, 2003.
RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET IMPLEMENTED-
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 is effective for financial
instruments entered into or modified after May 31, 2003 and is effective at the
beginning of the first interim period beginning after June 15, 2003
(FirstEnergy's third quarter of 2003) for all other financial instruments.
FirstEnergy did not enter into or modify any financial instruments
within the scope of SFAS 150 during June 2003. Upon adoption of SFAS 150,
effective July 1, 2003, FirstEnergy expects to classify as debt the preferred
stock of consolidated subsidiaries subject to mandatory redemptions with a
carrying value of approximately $19 million as of June 30, 2003. Subsidiary
preferred dividends on FirstEnergy's Consolidated Statements of Income are
currently included in net interest charges. Therefore, the application of SFAS
150 will not require the reclassification of such preferred dividends to net
interest charges.
19
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 which would correspond to
FirstEnergy's fourth quarter of 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 in a contract of a general index, such as
the Consumer Price Index, would prevent that contract from qualifying for the
normal purchases and normal sales (NPNS) exception under SFAS 133, as amended,
and therefore exempt from the mark-to-market treatment of certain contracts. DIG
Issue C20 is to be applied prospectively to all existing contracts as of its
effective date and for all future transactions. If it is determined under DIG
Issue C20 guidance that the NPNS exception was claimed for an existing contract
that was not eligible for this exception, the contract will be recorded at fair
value, with a corresponding adjustment of net income as the cumulative effect of
a change in accounting principle in the fourth quarter of 2003. FirstEnergy is
currently assessing the new guidance and has not yet determined the impact on
its financial statements.
EITF Issue No. 01-08, "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
will be applied prospectively to arrangements committed to, modified or acquired
through a business combination, beginning in the third quarter of 2003.
FirstEnergy is currently assessing the new EITF consensus and has not yet
determined the impact on its financial position or results of operations
following adoption.
20
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
------------------------------
2003 2002
----------- -----------
RESTATED RESTATED
(SEE NOTE 1) (SEE NOTE 1)
----------- -----------
(In thousands, except
per share amounts)
REVENUES:
Electric utilities ................................................................. $ 2,315,064 $ 2,053,976
Unregulated businesses ............................................................. 918,692 799,302
----------- -----------
Total revenues ................................................................. 3,233,756 2,853,278
----------- -----------
EXPENSES:
Fuel and purchased power ........................................................... 1,192,810 664,040
Purchased gas ...................................................................... 229,465 206,227
Other operating expenses ........................................................... 899,046 1,010,713
Provision for depreciation and amortization ........................................ 324,862 309,374
General taxes ...................................................................... 178,282 171,988
----------- -----------
Total expenses ................................................................. 2,824,465 2,362,342
----------- -----------
INCOME BEFORE INTEREST AND INCOME TAXES ............................................... 409,291 490,936
----------- -----------
NET INTEREST CHARGES:
Interest expense ................................................................... 200,650 260,465
Capitalized interest ............................................................... (9,152) (5,814)
Subsidiaries' preferred stock dividends ............................................ 14,542 24,071
----------- -----------
Net interest charges ........................................................... 206,040 278,722
----------- -----------
INCOME TAXES .......................................................................... 93,773 93,946
----------- -----------
INCOME BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE
EFFECT OF ACCOUNTING CHANGE ........................................................ 109,478 118,268
Discontinued operations ............................................................... 6,877 --
Cumulative effect of accounting change (net of income taxes of
$72,516,000) (Note 5) .............................................................. 102,147 --
----------- -----------
NET INCOME ............................................................................ $ 218,502 $ 118,268
=========== ===========
BASIC EARNINGS PER SHARE OF COMMON STOCK:
Income before discontinued operations and cumulative effect of accounting change ... $ 0.37 $ 0.40
Discontinued operations (net of income taxes) ...................................... 0.02 --
Cumulative effect of accounting change (net of income taxes) (Note 5) .............. 0.35 --
----------- -----------
Net income ......................................................................... $ 0.74 $ 0.40
=========== ===========
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING ................................... 293,886 292,791
=========== ===========
DILUTED EARNINGS PER SHARE OF COMMON STOCK:
Income before discontinued operations and cumulative effect of accounting change ... $ 0.37 $ 0.40
Discontinued operations (net of taxes).............................................. 0.02 --
Cumulative effect of accounting change (net of income taxes) (Note 5) .............. 0.35 --
----------- -----------
Net income ......................................................................... $ 0.74 $ 0.40
=========== ===========
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING ................................. 294,877 294,344
=========== ===========
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK .......................................... $ 0.375 $ 0.375
=========== ===========
The preceding Notes to Financial Statements as they relate to FirstEnergy Corp.
are an integral part of these statements.
21
FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
MARCH 31, DECEMBER 31,
2003 2002
----------- -----------
RESTATED RESTATED
(SEE NOTE 1) (SEE NOTE 1)
----------- -----------
(IN THOUSANDS)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents ................................................. $ 290,036 $ 196,301
Receivables-
Customers (less accumulated provisions of $55,945,000 and $52,514,000
respectively, for uncollectible accounts) ............................. 1,149,390 1,153,486
Other (less accumulated provisions of $12,596,000 and $12,851,000,
respectively, for uncollectible accounts) ............................. 439,605 469,606
Materials and supplies, at average cost-
Owned ................................................................... 255,950 253,047
Under consignment ....................................................... 159,268 174,028
Other ..................................................................... 289,588 203,630
----------- -----------
2,583,837 2,450,098
----------- -----------
PROPERTY, PLANT AND EQUIPMENT:
In service ................................................................ 21,061,059 20,372,224
Less--Accumulated provision for depreciation .............................. 9,047,427 8,552,927
----------- -----------
12,013,632 11,819,297
Construction work in progress ............................................. 963,422 859,016
----------- -----------
12,977,054 12,678,313
----------- -----------
INVESTMENTS:
Capital trust investments ................................................. 1,042,143 1,079,435
Nuclear plant decommissioning trusts ...................................... 1,060,994 1,049,560
Letter of credit collateralization ........................................ 277,763 277,763
Other ..................................................................... 899,551 918,874
----------- -----------
3,280,451 3,325,632
----------- -----------
DEFERRED CHARGES:
Regulatory assets ......................................................... 8,336,176 8,753,401
Goodwill .................................................................. 6,237,274 6,278,072
Other ..................................................................... 872,625 900,837
----------- -----------
15,446,075 15,932,310
----------- -----------
$34,287,417 $34,386,353
=========== ===========
22
FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
MARCH 31, DECEMBER 31,
2003 2002
------------ ------------
RESTATED RESTATED
(SEE NOTE 1) (SEE NOTE 1)
------------ ------------
(IN THOUSANDS)
CAPITALIZATION AND LIABILITIES
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock ............... $ 1,630,227 $ 1,702,822
Short-term borrowings .............................................. 855,327 1,092,817
Accounts payable ................................................... 885,651 906,468
Accrued taxes ...................................................... 550,453 455,121
Other .............................................................. 1,077,504 1,093,815
------------ ------------
4,999,162 5,251,043
------------ ------------
CAPITALIZATION:
Common stockholders' equity-
Common stock, $.10 par value, authorized 375,000,000 shares -
297,636,276 shares outstanding ................................. 29,764 29,764
Other paid-in capital ............................................ 6,119,286 6,120,341
Accumulated other comprehensive loss ............................. (657,411) (656,148)
Retained earnings ................................................ 1,743,324 1,634,981
Unallocated employee stock ownership plan common stock -
3,613,860 and 3,966,269 shares, respectively ................... (71,662) (78,277)
------------ ------------
Total common stockholders' equity ............................ 7,163,301 7,050,661
Preferred stock of consolidated subsidiaries-
Not subject to mandatory redemption .............................. 335,123 335,123
Subject to mandatory redemption .................................. 18,519 18,521
Subsidiary-obligated mandatorily redeemable preferred securities ... 409,971 409,867
Long-term debt ..................................................... 11,038,490 10,872,216
------------ ------------
18,965,404 18,686,388
------------ ------------
DEFERRED CREDITS:
Accumulated deferred income taxes .................................. 2,099,427 2,069,682
Accumulated deferred investment tax credits ........................ 230,472 236,184
Asset retirement obligation ........................................ 1,126,786 --
Nuclear plant decommissioning costs ................................ -- 1,243,558
Power purchase contract loss liability ............................. 3,015,816 3,136,538
Retirement benefits ................................................ 1,643,501 1,564,930
Lease market valuation liability ................................... 1,084,850 1,106,000
Other .............................................................. 1,121,999 1,092,030
------------ ------------
10,322,851 10,448,922
------------ ------------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (NOTE 2) ....................
------------ ------------
$ 34,287,417 $ 34,386,353
============ ============
The preceding Notes to Financial Statements as they relate to FirstEnergy Corp.
are an integral part of these balance sheets.
23
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
--------------------------
2003 2002
--------- ---------
RESTATED RESTATED
(SEE NOTE 1) (SEE NOTE 1)
--------- ---------
(IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ...................................................................... $ 218,502 $ 118,268
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation and amortization ................................ 324,862 309,374
Nuclear fuel and lease amortization ........................................ 14,918 20,965
Other amortization, net .................................................... (4,613) (3,537)
Deferred costs recoverable as regulatory assets ............................ (38,748) (90,934)
Deferred income taxes, net ................................................. 31,352 (21,017)
Investment tax credits, net ................................................ (6,259) (6,746)
Cumulative effect of accounting change (Note 5) ............................ (174,663) --
Receivables ................................................................ (1,898) 60,095
Materials and supplies ..................................................... 11,413 18,163
Accounts payable ........................................................... (7,115) (3,004)
Accrued taxes .............................................................. 97,553 82,297
Accrued interest ........................................................... 89,599 86,579
Deferred rents and sale/leaseback .......................................... (17,592) 44,400
Prepayments & other ........................................................ (69,673) 109,551
Other ...................................................................... (5,376) (260,370)
--------- ---------
Net cash provided from operating activities .............................. 462,262 464,084
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt ............................................................. 297,696 105,031
Short-term borrowings, net ................................................. -- 115,556
Redemptions and Repayments-
Preferred stock ............................................................ -- (185,299)
Long-term debt ............................................................. (200,866) (183,905)
Short-term borrowings, net ................................................. (237,490) --
Common stock dividend payments ............................................... (110,159) (109,726)
--------- ---------
Net cash provided from (used for) financing activities ................... (250,819) (258,343)
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions ........................................................... (224,419) (195,292)
Avon cash and cash equivalents previously held for sale (Note 3) ............. -- 411,822
Net assets held for sale ..................................................... -- (61,565)
Proceeds from nonutility generation trusts ................................... 106,327 34,208
Proceeds from assets sale .................................................... 60,572 --
Cash investments ............................................................. 24,715 (4,343)
Other ........................................................................ (84,903) 36,968
--------- ---------
Net cash provided from (used for) investing activities ................... (117,708) 221,798
--------- ---------
Net increase in cash and cash equivalents ....................................... 93,735 427,539
Cash and cash equivalents at beginning of period ................................ 196,301 220,178
--------- ---------
Cash and cash equivalents at end of period ...................................... $ 290,036 $ 647,717
========= =========
The preceding Notes to Financial Statements as they relate to FirstEnergy Corp.
are an integral part of these statements.
24
REPORT OF INDEPENDENT AUDITORS
To the Stockholders and Board of
Directors of FirstEnergy Corp.:
We have reviewed the accompanying consolidated balance sheet of FirstEnergy
Corp. and its subsidiaries as of March 31, 2003, and the related consolidated
statements of income and cash flows for each of the three-month periods ended
March 31, 2003 and 2002. These interim financial statements are the
responsibility of the Company's management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures and making
inquiries of persons responsible for financial and accounting matters. It is
substantially less in scope than an audit conducted in accordance with generally
accepted auditing standards, the objective of which is the expression of an
opinion regarding the financial statements taken as a whole. Accordingly, we do
not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to the accompanying consolidated interim financial statements for them
to be in conformity with accounting principles generally accepted in the United
States of America.
As discussed in Note 1 to the consolidated interim financial statements, the
Company has restated its previously issued consolidated interim financial
statements for the quarters ended March 31, 2003 and 2002.
We previously audited in accordance with auditing standards generally accepted
in the United States of America, the consolidated balance sheet and the
consolidated statement of capitalization as of December 31, 2002, and the
related consolidated statements of income, common stockholders' equity,
preferred stock, cash flows and taxes for the year then ended (not presented
herein), and in our report (which contained references to the Company's change
in its method of accounting for goodwill in 2002 as discussed in Note 2(E) to
those consolidated financial statements and the Company's restatement of its
previously issued consolidated financial statements for the year ended December
31, 2002 as discussed in Note 2(L) and Note 2(M) to those consolidated financial
statements) dated February 28, 2003, except as to Note 2(L), which is as of May
9, 2003, and Note 2(M), which is as of August 18, 2003, we expressed an
unqualified opinion on those consolidated financial statements. In our opinion,
the information set forth in the accompanying consolidated balance sheet as of
December 31, 2002, is fairly stated in all material respects in relation to the
consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
May 9, 2003, except as to Note 1, which is as of August 18, 2003
25
FIRSTENERGY CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
FirstEnergy Corp. is a registered public utility holding company that
provides regulated and competitive energy services (see Results of Operations -
Business Segments) domestically and internationally. The international
operations were acquired as part of FirstEnergy's acquisition of GPU, Inc. in
November 2001. GPU Capital, Inc. and its subsidiaries provide electric
distribution services in foreign countries. GPU Power, Inc. and its subsidiaries
develop, own and operate generation facilities in foreign countries. Sales are
planned but not pending for the remaining international operations (see Capital
Resources and Liquidity). Regulated electric distribution services are provided
in Ohio by wholly owned subsidiaries (Ohio electric utilities) - Ohio Edison
Company (OE), The Cleveland Electric Illuminating Company (CEI), and The Toledo
Edison Company (TE). Regulated services are provided in Pennsylvania through
wholly owned subsidiaries (Pennsylvania electric utilities) - Metropolitan
Edison Company (Met-Ed), Pennsylvania Electric Company (Penelec) and
Pennsylvania Power Company (Penn) - a wholly owned subsidiary of OE. Jersey
Central Power & Light Company (JCP&L) provides electric distribution services in
New Jersey. Transmission services are provided in the franchise areas of the
Ohio electric utilities and Penn by wholly owned subsidiary American
Transmission Systems, Inc. (ATSI). Transmission services are provided by Met-Ed,
Penelec and JCP&L in their respective franchise areas. The coordinated delivery
of energy and energy-related products, including electricity, natural gas and
energy management services, to customers in competitive markets is provided
through a number of subsidiaries. Subsidiaries providing competitive services
include FirstEnergy Solutions Corp. (FES), FirstEnergy Facilities Services
Group, LLC (FSG), MARBEL Energy Corporation and MYR Group, Inc.
RESTATEMENTS
As further discussed in Note 1 to the Consolidated Financial
Statements, FirstEnergy is restating its consolidated financial statements for
the year ended December 31, 2002 and the three months ended March 31, 2003 and
2002. The restatements reflect a change in the method of amortizing the costs
being recovered under the Ohio transition plan and recognition of above-market
values of certain leased generation facilities.
Transition Cost Amortization
As discussed in Note 4 - Regulatory Matters, FirstEnergy's Ohio
electric utilities recover transition costs, including regulatory assets,
through an approved transition plan filed under Ohio's electric utility
restructuring legislation. The plan, which was approved in July 2000, provides
for the recovery of costs from January 1, 2001 through a fixed number of
kilowatt-hour sales to all customers that continue to receive regulated
transmission and distribution service, which is expected to end in 2006 for OE,
2007 for TE and in 2009 for CEI.
FirstEnergy and the Ohio utilities amortize transition costs using
the effective interest method. The amortization schedules originally developed
at the beginning of the transition plan in 2001 in applying this method were
based on total transition revenues, including revenues designed to recover costs
which have not yet been incurred or that were recognized on the regulatory
financial statements (fair value purchase accounting adjustments) but not in the
financial statements prepared under GAAP. The Ohio electric utilities have
revised their amortization schedules under the effective interest method to
consider only revenues relating to transition regulatory assets recognized on
the GAAP balance sheet. The impact of this change will result in higher
amortization of these regulatory assets in the first several years of the
transition cost recovery period, versus the method previously applied. The
change in method results in no change in total amortization of the regulatory
assets recovered under the transition period through the end of 2009. The
amortization expense under the revised method (see Note 1) increased by $32.4
million and $43.2 million for the three months ended March 31, 2002 and 2003,
respectively.
Above-Market Lease Costs
In 1997, FirstEnergy Corp. was formed through a merger between OE and
Centerior Energy Corp. The merger was accounted for as an acquisition of
Centerior, the parent company of CEI and TE, under the purchase accounting rules
of Accounting Principles Board (APB) Opinion No. 16. In connection with the
reassessment of the accounting for the transition plan, FirstEnergy reassessed
its accounting for the Centerior purchase and determined that above market lease
liabilities should have been recorded at the time of the merger. Accordingly, as
of 2002, FirstEnergy recorded additional adjustments associated with the 1997
merger between OE and Centerior to reflect certain above market lease
liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant, for which
CEI and TE had previously entered into sale-leaseback arrangements. CEI and TE
recorded an increase in goodwill related to the above market lease costs for
Beaver Valley Unit 2 since regulatory accounting for nuclear generating assets
had been discontinued prior to the merger date and it was determined that this
additional liability would have increased goodwill at the date of the merger.
The corresponding impact of the above market lease liabilities for the Bruce
Mansfield Plant was recorded as
26
a regulatory asset because regulatory accounting had not been discontinued at
that time for the fossil generating assets and recovery of these liabilities was
provided for under the transition plan.
The total above market lease obligation of $722 million (CEI $611
million, TE $111 million) associated with Beaver Valley Unit 2 will be amortized
through the end of the lease term in 2017. The additional goodwill has been
recorded on a net basis, reflecting amortization that would have been recorded
through 2001 when goodwill amortization ceased with the adoption of SFAS No.
142. The total above market lease obligation of $755 million (CEI $457 million,
TE $298 million) associated with the Bruce Mansfield Plant is being amortized
through the end of 2016. Before the start of the transition plan in 2001, the
regulatory asset would have been amortized at the same rate as the lease
obligation. Beginning in 2001, the remaining unamortized regulatory asset would
have been included in CEI's and TE's amortization schedules for regulatory
assets and amortized through the end of the recovery period - approximately 2009
for CEI and 2007 for TE.
RESULTS OF OPERATIONS
Net income in the first quarter of 2003 was $218.5 million or $0.74
per share of common stock (basic and diluted), compared to $118.3 million or
$0.40 per share of common stock (basic and diluted) in the first quarter of
2002. Results in the first quarter of 2003 included an after tax charge of $6.9
or $0.02 per share of common stock (basic and diluted) resulting from the
abandonment of Emdersa's parent company, GPU Argentina Holdings, Inc on April
18, 2003. Results in the first quarter of 2003 included an after-tax charge of
$6.9 million or $0.02 per share of common stock (basic and diluted) resulting
from the abandonment of Emdersa's Parent Company, GPU Argentina Holdings, Inc.
on April 18, 2003. Net income in the first quarter of 2003 included an after-tax
credit of $102.1 million resulting from the cumulative effect of an accounting
change due to the adoption of Statement of Financial Accounting Standards (SFAS)
No. 143, "Accounting for Asset Retirement Obligations." Income before
discontinued operations and the cumulative effect of an accounting change was
$109.5 million in the first three months of 2003, or $0.37 per share of common
stock (basic and diluted). Results in the first quarter of 2003, benefited from
increased revenues due to cold weather, increased gas margins, and reduced
financing costs. Partially offsetting these favorable factors were higher
employee benefit expenses and incremental costs (which reduced basic and diluted
earnings per share by $0.18) related to the extended outage at the Davis-Besse
nuclear plant (see Davis-Besse Restoration).
Reclassifications of Previously Reported Income Statement
FirstEnergy recorded an increase to income during the three months
ended March 31, 2002 of $31.7 million (net of income taxes of $13.6 million)
relative to its decision to retain an interest in the Avon Energy Partners
Holdings (Avon) business previously classified as held for sale - see Note 3.
This amount represents the aggregate results of operations of Avon for the
period this business was held for sale. It was previously reported on the
Consolidated Statement of Income as the cumulative effect of a change in
accounting. In April 2003, it was determined that this amount should instead
have been classified in operations. As further discussed in Note 3, the decision
to retain Avon was made in the first quarter of 2002 and Avon's results of
operations for that quarter have been classified in their respective revenue and
expense captions on the Consolidated Statement of Income. This change in
classification had no effect on previously reported net income. The effects of
this change on the Consolidated Statement of Income previously reported for the
three months ended March 31, 2002 are shown in Note 1.
In June 2002, the Emerging Issues Task Force (EITF) reached a partial
consensus on Issue No. 02-03, "Issues Involved in Accounting for Derivative
Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and
Risk Management Activities." Based on the EITF's partial consensus position, for
periods after July 15, 2002, mark-to-market revenues and expenses and their
related kilowatt-hour sales and purchases on energy trading contracts must be
shown on a net basis in the Consolidated Statements of Income. FirstEnergy had
previously reported such contracts as gross revenues and purchased power costs.
Therefore, revenues and expenses for the first quarter of 2002 have been
reclassified (see Implementation of Recent Accounting Standard).
Revenues
Total revenues increased $380.5 million in the first quarter of 2003,
compared to the same period last year as a result of additional sales in
FirstEnergy's regulated and competitive service segments. Electric and gas sales
revenue increased due to colder than normal weather in the first quarter of 2003
compared to milder than normal weather in the first three months of 2002.
Sources of changes in revenues during the first quarter of 2003 compared to the
first quarter of 2002 are summarized in the following table:
27
SOURCES OF REVENUE CHANGES
--------------------------
INCREASE (DECREASE) (IN MILLIONS)
Electric Utilities (Regulated Services):
Retail electric sales .......................... $ 108.2
Wholesale electric sales ....................... 139.5
All other revenues ............................. 13.4
--------
Total Electric Utilities ......................... 261.1
--------
Unregulated Businesses (Competitive Services):
Retail electric sales .......................... 66.7
Wholesale electric sales ....................... 233.8
Gas sales ...................................... 43.9
FSG ............................................ (42.4)
Other .......................................... (8.9)
--------
Total Unregulated Businesses ..................... 293.1
--------
International .................................... (173.1)
Other ............................................ (0.6)
--------
Net Revenue Increase ............................. $ 380.5
========
Electric Sales
Retail sales by FirstEnergy's electric utility operating companies
(EUOC) increased by $108.2 million in the first quarter of 2003 compared to the
first quarter of 2002. Temperatures in the EUOC service areas ranged from 20% to
30% colder in the first quarter of 2003, compared to the same period last year,
increasing residential and commercial heating loads.
Changes in electric generation sales and distribution deliveries in
the first quarter of 2003 from the same quarter of 2002 are summarized in the
following table:
CHANGES IN KILOWATT-HOUR SALES
------------------------------
INCREASE (DECREASE)
Electric Generation Sales:
Retail
Regulated services ............ 2.1%
Competitive services .......... 130.2%
Wholesale ..................... 141.3%
-----
Total Electric Generation Sales ... 30.6%
=====
EUOC Distribution Deliveries:
Residential ..................... 15.4%
Commercial ...................... 11.7%
Industrial ...................... 1.3%
-----
Total Distribution Deliveries ..... 9.4%
=====
Shopping by customers for alternative energy suppliers and the effect
of a sluggish national economy in FirstEnergy's service areas combined to reduce
regulated retail generation sales revenue by $4.7 million in the first quarter
of 2003 from the same period in 2002, despite the colder weather in 2003. Sales
of electric generation by alternative suppliers in Ohio, Pennsylvania and New
Jersey in the first quarter of 2003 increased by 8.8, 4.4 and 0.8 percentage
points, respectively, or 5.8 percentage points on a consolidated basis from the
first quarter of 2002.
Revenues from distribution deliveries increased by $127.2 million or
11.2% in the first quarter of 2003 compared to the first quarter of 2002 largely
due to the colder temperatures. Increased kilowatt-hour deliveries resulted from
additional demand from all three customer segments: residential, commercial and
industrial. The slower industrial growth continued to reflect sluggish economic
conditions.
Partially offsetting the increase in revenues from distribution
deliveries were Ohio transition plan incentives provided to customers to promote
customer shopping for alternative suppliers - $14.4 million of additional
credits in the first quarter of 2003 compared to the same period in 2002. These
reductions in revenue are deferred for future recovery under the Ohio transition
plan and do not materially affect current period earnings.
EUOC sales to wholesale customers increased by $139.5 million in the
first quarter of 2003 from the same quarter last year. The increase occurred
almost entirely at JCP&L and resulted from the auction of its entire basic
28
generation service (BGS) responsibility to alternative suppliers. At the
direction of the New Jersey Board of Public Utilities (NJBPU), JCP&L is selling
its pre-existing sources of power supply, including energy provided by
non-utility generation (NUG) contracts, into the wholesale market.
Electric generation sales by FirstEnergy's competitive segment
increased $300.5 million in the first quarter of 2003 from the first quarter of
2002, primarily from additional sales to the wholesale market ($233.8 million)
as FES began supplying a portion of New Jersey's BGS requirements in September
2002. Retail sales by FirstEnergy's competitive services segment increased by
$66.7 million from kilowatt-hour sales that were more than double the prior
year's level. That increase resulted in part from retail customers switching to
FES, 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.
FirstEnergy's regulated and unregulated subsidiaries record purchase
and sales transactions with PJM Interconnection ISO, an independent system
operator, on a gross basis in accordance with EITF 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 months ended March
31, 2003 and 2002 are summarized as follows:
THREE MONTHS ENDED
MARCH 31,
--------------------
2003 2002
---- ----
(IN MILLIONS)
Sales.............. $336 $46
Purchases.......... 361 80
---- ----
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 it had 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 it required additional power to meet FirstEnergy's retail load
requirements and, secondarily, to sell to the wholesale market.
International revenues declined $162.3 million due to the sale of a
79.9% interest in Avon during the second quarter of 2002 and the subsequent
application of equity accounting to FirstEnergy's remaining 20.1% interest. As a
result, no revenues were recorded for FirstEnergy's equity interest in Avon in
the first quarter of 2003.
Nonelectric Sales
Nonelectric sales revenues of the competitive services segment
declined by $7.4 million in the first quarter of 2003 from the same period in
2002. Reduced revenues from FSG were substantially offset by higher natural gas
sales revenues resulting from a weather-stimulated increase in prices in the
first three months of 2003. The reduced revenues from FSG also reflected the
sales in early 2003 of Colonial Mechanical and Webb Technologies, as well as
continued declines associated with weak economic conditions.
Expenses
Total expenses increased $462.1 million in the first quarter of 2003
from the same quarter of 2002. Sources of changes in expenses in the first
quarter of 2003 from the first quarter of 2002 are summarized in the following
table:
AS PREVIOUSLY AS
REPORTED RESTATED
-------- --------
SOURCES OF EXPENSE CHANGES
--------------------------
INCREASE (DECREASE) (IN MILLIONS)
Fuel and purchased power ............. $ 497.3 $ 528.8
Purchased gas ........................ 23.2 23.2
Other operating expenses ............. (108.5) (111.7)
Depreciation and amortization ........ 18.8 15.5
General taxes ........................ 6.3 6.3
-------- --------
Net Expense Increase ................... $ 437.1 462.1
======== ========
The net increase in expenses in the first quarter of 2003 compared to
the first quarter of 2002 was primarily due to a $528.8 million increase in
purchased power costs. The increase resulted from additional volumes to cover
supply obligations assumed by FES for sales to the New Jersey market to provide
BGS, and additional supplies required to replace Davis-Besse power during its
extended outage (see Davis-Besse Restoration). The extended outage at the
Davis-Besse nuclear plant produced a decline in nuclear generation of 16.7% in
the first quarter of 2003, compared to the first quarter of 2002. Purchased gas
costs increased by $23.2 million in the first quarter of 2003 compared to the
29
same period of 2002 due to higher unit costs, partially offset by lower volumes
purchased to meet reduced sales levels. Despite reduced quantities of gas sold,
gross profit margins improved by $18.5 million during the first quarter of 2003,
compared to the same period last year.
Other operating expenses decreased $111.7 million in the first
quarter of 2003 from the first quarter of 2002. The decrease primarily resulted
from reduced business volume from domestic energy-related businesses which
lowered other operating expenses by $66.1 million, reduced international
expenses of $72.5 million (due to the sale of Avon) and the absence of one-time
charges recorded in the first quarter of 2002 of $78.2 million. The reduced
volume of energy-related business reflected the sale in early 2003 of the
Colonial Mechanical and Webb Technologies businesses, as well as continued
declines associated with weak economic conditions. Partially offsetting these
lower expenses were $36.3 million of additional nuclear costs resulting from the
Davis-Besse extended outage, $50.4 million in higher employee benefit costs and
the absence of a $38.5 million credit cumulative restatement adjustment (see
Restatements).
Charges for depreciation and amortization increased by $15.5 million
in the first quarter of 2003 compared to the first quarter of 2002. The higher
charges primarily resulted from three factors - increased amortization of the
Ohio transition regulatory assets ($17.1 million), recognition of depreciation
on four fossil plants ($9.6 million) which had been held pending sale in the
first quarter of 2002, but were subsequently retained by FirstEnergy in the
fourth quarter of 2002, reduced tax related deferrals in 2003 ($7.9 million) and
a $2.1 million increase in the amortization of the above-market lease costs
regulatory assets discussed above. Partially offsetting these increases in
depreciation and amortization were higher shopping incentive deferrals in Ohio
($14.4 million) and lower charges resulting from the implementation of SFAS 143
($11.6 million), including revised service life assumptions for generating
plants ($8.0 million).
Net Interest Charges
Net interest charges decreased $72.7 million in the first quarter of
2003 compared to the same period of 2002. FirstEnergy's redemption and
refinancing of its outstanding debt and preferred stock over the last twelve
months, resulted in a $57.1 million reduction of financing costs. In addition,
the sale of FirstEnergy's 79.9% interest in Avon eliminated $18.9 million of
financing costs. Redemption and refinancing activities during the first quarter
of 2003 totaled $122 million (excluding net reductions to various revolving bank
facilities) and $563 million, respectively, and are expected to result in
annualized savings of approximately $20 million. Partially offsetting these
savings were $2.4 million of incremental interest costs associated with the
issuance of $250 million of new senior notes. FirstEnergy also exchanged
existing fixed-rate payments on outstanding debt (principal amount of $700
million as of March 31, 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 $6.9 million in the
first quarter of 2003, compared to the first quarter of 2002 as a result of
these swaps.
Discontinued Operations
In April 2003, FirstEnergy divested its ownership in GPU Emperssa
Distribuidora Electrica Regional S.A. and affiliates (Emdersa) through the
abandonment of its shares in the parent company of the Argentina operation.
FirstEngery has reclassified the results of Emdersa for the quarter ended March
31, 2003, $6.9 million of net income as discontinued operations. There was no
impact in 2002 as the assets was held for sale.
Cumulative Effect of Accounting Change
Upon adoption of SFAS 143 (see discussion further below) in the first
quarter of 2003, FirstEnergy recorded an after-tax credit to net income of
$102.1 million. FirstEnergy identified applicable legal obligations as defined
under the new standard for nuclear power plant decommissioning and reclamation
of a sludge disposal pond at the Bruce Mansfield Plant. 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 asset retirement obligation (ARO)
liability at the date of adoption was $1.109 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 $1.232 billion, including unrealized gains on decommissioning
trust funds of $12 million. 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 liabilities was a $174.6 million
increase to income, or $102.1 million net of income taxes.
Earnings Effect of SFAS 143
In June 2001, the FASB issued SFAS 143. The new statement provides
accounting standards for retirement obligations associated with tangible
long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires
that the fair value of a liability for an asset retirement obligation be
recorded 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 recorded if the cost to settle the retirement obligation differs from
the carrying amount.
30
In the first quarter of 2003, application of SFAS 143 (excluding the
cumulative adjustment recorded upon adoption -- See Note 5 ) resulted in the
following changes to income and expense categories:
EFFECT OF SFAS 143 -- FIRST QUARTER 2003
-----------------------------------------------------------------------------
INCREASE (DECREASE) (MILLIONS)
Other operating expense
Cost of removal (previously included in depreciation).... $ 4.2
Depreciation
Replacement of decommissioning expense................... (22.4)
Depreciation of asset retirement cost.................... 1.9
Accretion of asset retirement liability.................. 9.9
Reclassification of cost of removal to expense .......... (3.9)
------
Net impact to depreciation............................... (14.5)
------
Other Income
Earnings on trust balances............................... 2.5
-----
Income taxes............................................. 5.3
-----
Net income effect........................................ $7.5
=====
Postretirement Plans
Sharp declines in equity markets since the second quarter of 2000 and
a reduction in FirstEnergy's assumed discount rate for pensions and other
postretirement obligations have combined to produce a significant increase in
those costs. Also, increases in health care payments and a related increase in
projected trend rates have led to higher health care costs. Combined, these
employee benefit expenses increased $49.2 million in the first quarter of 2003
compared to the same period in 2002. The following table summarizes the net
pension and other post-employment benefits (OPEB) expense (excluding amounts
capitalized) for the three months ended March 31, 2003 and 2002.
THREE MONTHS ENDED
POSTRETIREMENT EXPENSE (INCOME) MARCH 31,
-------------------------------------------------------
2003 2002
------------------
(IN MILLIONS)
Pension...................... $31.3 $(3.8)
OPEB......................... 40.5 26.4
------------------
Total...................... $71.8 $22.6
==================
The pension and OPEB expense increases are included in various cost
categories and have contributed to other cost increases discussed above. See
"Significant Accounting Policies - Pension and Other Postretirement Benefits
Accounting" for a discussion of the impact of underlying assumptions on
postretirement expenses.
RESULTS OF OPERATIONS - BUSINESS SEGMENTS
FirstEnergy manages its business as two separate major business
segments - regulated services and competitive services. The regulated services
segment designs, constructs, operates and maintains FirstEnergy's regulated
domestic transmission and distribution systems. It also provides generation
services to franchise customers who have not chosen an alternative generation
supplier. The Ohio electric utilities and Penn obtain generation through a power
supply agreement with the competitive services segment (see Outlook - Business
Organization). The competitive services segment also supplies a substantial
portion of the "provider of last resort" (PLR) requirements for Met-Ed and
Penelec under 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 services such as heating, ventilating and air-conditioning.
Financial results discussed below include intersegment revenues. A
reconciliation of segment financial results to consolidated financial results is
provided in Note 6 to the consolidated financial statements.
31
Regulated Services
Net income increased to $317 million in the first quarter of 2003,
compared to $188 million in the first quarter of 2002. The factors contributing
to the changes in net income are summarized in the following table:
REGULATED SERVICES
--------------------------------------------------------------
INCREASE (DECREASE) (IN MILLIONS)
Revenues .................................. $ 229.0
Expenses .................................. 242.7
--------
Income Before Interest and Income Taxes ... (13.7)
Net interest charges ...................... (39.2)
Income taxes .............................. (2.5)
--------
Income Before Cumulative Effect of a
Change in Accounting ...................... 28.0
Cumulative effect of a change in accounting 101.0
--------
Net Income ................................ $ 129.0
=======
Higher generation sales and distribution deliveries combined to
increase external revenues by $247.7 million in the first quarter of 2003
compared to the same quarter of 2002. This increase was partially offset by a
$31.1 million decline in revenues from lower sales to FES, resulting from the
extended outage of the Davis-Besse nuclear plant, which decreased generation
available for sale. The remaining change in sales resulted from an increase in
energy-related revenues. The increase in expenses resulted principally from a
$205.8 million increase in purchased power costs due to higher generation sales.
Other operating expenses increased $14.9 million and depreciation and
amortization expense was $19.9 million higher in the first quarter of 2003
compared to the same quarter last year. The increase in other operating expenses
reflected additional employee benefit costs offset in part by the absence in the
first quarter of 2003 of adjustments related to OE's low income housing
investment and lower energy delivery costs. The increase in depreciation and
amortization expense primarily resulted from three factors - increased
amortization of the Ohio transition regulatory assets ($17.1 million),
recognition of depreciation on four fossil plants ($9.6 million) which had been
pending sale in the first quarter of 2002, but were subsequently retained by
FirstEnergy in the fourth quarter of 2002 and the termination of tax related
deferrals in February 2003 ($7.9 million). Partially offsetting these increases
in depreciation and amortization were higher incentive deferrals in Ohio ($14.4
million) and lower charges resulting from the implementation of SFAS 143 ($11.6
million), including revised service life assumptions for generating plants ($8.0
million).
Competitive Services
Net losses decreased to $55 million in the first quarter of 2003,
compared to $59.6 million in the first quarter of 2002. The factors contributing
to the reduced loss are summarized in the following table:
COMPETITIVE SERVICES
-------------------------------------------------------------------------
INCREASE (DECREASE) (IN MILLIONS)
Revenues .................................. $377.8
Expenses .................................. 351.4
------
Income Before Interest and Income Taxes ... 26.4
------
Net interest charges ...................... 1.0
Income taxes .............................. 10.1
------
Income Before Cumulative Effect of a
Change in Accounting .................... 15.3
Cumulative effect of a change in accounting 1.2
------
Net Income ................................ $ 16.5
======
The increase in revenues in the first quarter of 2003, compared to
the first quarter of 2002, includes the net effect of several factors. Revenues
from the electric wholesale market increased $233.8 million in the first quarter
of 2003 from the same period last year as kilowatt-hour sales more than doubled
resulting principally from sales as an alternative supplier for a portion of New
Jersey's BGS requirements. Retail kilowatt-hour sales revenues increased $66.7
million as a result of expanding the FES business in Ohio under Ohio's
electricity choice program and higher weather stimulated sales to existing
customers. Natural gas sales were $43.9 million higher due to higher prices
resulting from colder weather in the first quarter of 2003, compared to the same
period last year. Internal sales to the regulated services segment increased
$90.3 million primarily reflecting sales to Met-Ed and Penelec in supplying a
substantial portion of
32
their PLR requirements in Pennsylvania. Energy-related services such as heating,
ventilating and air-conditioning work reflected the divestiture in early 2003 of
Colonial Mechanical and Webb Technologies, as well as continued declines
associated with weak economic conditions. Revenues from energy-related services
decreased $69.9 million in the first quarter of 2003 from the first quarter of
2002.
Expenses increased $351.4 million in the first quarter of 2003 from
the same period of 2002 primarily attributable to purchased power costs, which
increased $405.8 million to source the higher kilowatt-hour sales to wholesale
and retail customers. Gas costs also increased in the first quarter of 2003 by
$23.2 million, reflecting higher unit costs during the colder than normal
weather compared to the first quarter of 2002. Partially offsetting these
factors were lower costs due to reduced business volume for domestic
energy-related businesses of $61.1 million and other operating expenses which
decreased $17.5 million. The decrease in other operating costs reflected the
absence of $65.6 million of one-time charges in the first quarter of 2002,
partially offset by higher nuclear production costs from the extended
Davis-Besse outage and increased employee benefit costs (principally pension and
health care).
CAPITAL RESOURCES AND LIQUIDITY
FirstEnergy's cash requirements in 2003 for operating expenses,
construction expenditures, scheduled debt maturities and preferred stock
redemptions are expected to be met without increasing FirstEnergy's net debt and
preferred stock outstanding. Available borrowing capacity under short-term
credit facilities will be used to manage working capital requirements. Over the
next three years, FirstEnergy expects to meet its contractual obligations with
cash from operations. Thereafter, FirstEnergy expects to use a combination of
cash from operations and funds from the capital markets.
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 $1.5 billion of revolving credit facilities. In the first quarter of
2003, FirstEnergy received $137.0 million of cash dividends from its
subsidiaries and paid $110.2 million in cash common stock dividends to its
shareholders. There are no material restrictions on the issuance of cash
dividends by FirstEnergy's subsidiaries.
As of March 31, 2003, FirstEnergy had $290.0 million of cash and cash
equivalents, compared with $196.3 million as of December 31, 2002. The major
sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Cash flows provided from operating activities during the first
quarter of 2003, compared with the first quarter of 2002 were as follows:
OPERATING CASH FLOWS 2003 2002
-----------------------------------------------
(IN MILLIONS)
Cash earnings (1) ....... $365 $326
Working capital and other 97 138
---- ----
Total ................... $462 $464
==== ====
(1) Includes net income, depreciation and amortization, deferred income
taxes, investment tax credits and major noncash charges.
Net cash provided from operating activities decreased $2 million due
to a $41 million decrease in funds used for working capital that was offset in
part by a $39 million increase in cash earnings. The change in funds used for
working capital represents offsetting changes for receivables, sale and
leaseback rent payments, prepayments and other.
Cash Flows From Financing Activities
The following table provides details regarding security issuances and
redemptions during the first quarter of 2003:
33
SECURITIES ISSUED OR REDEEMED IN THE FIRST QUARTER 2003
--------------------------------------------------------------------------
(IN MILLIONS)
New Issues
Senior Notes .................................... 250
Long-term revolver .............................. 50
Other, primarily debt discount .................. (2)
----
298
Redemptions
First mortgage bonds ............................ 40
Pollution control notes ......................... 50
Secured notes ................................... 108
Other, primarily redemption premiums ............ 3
----
201
Short-term Borrowings, Net Use of Cash ............... 237
----
Net cash flows used for financing activities declined by $8 million
in the first quarter of 2003 from the first quarter of 2002. The decrease in
funds used for financing activities resulted from increased financing of $77
million that exceeded $69 million of additional redemptions and repayments
during the first quarter of 2003 compared to the same period of 2002.
FirstEnergy had approximately $855.3 million of short-term
indebtedness as of March 31, 2003 compared to $1.093 billion at the end of 2002.
Available borrowing capability included $356 million under the $1.5 billion
revolving lines of credit and $76 million under bilateral bank facilities. As of
March 31, 2003, OE, CEI, TE and Penn had the aggregate capability to issue $2.2
billion of additional first mortgage bonds (FMB) on the basis of property
additions and retired bonds. 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 March 31, 2003, JCP&L, Met-Ed and Penelec had the
aggregate capability to issue $443 million of additional senior notes based upon
FMB collateral. Based upon applicable earnings coverage tests and their
respective charters, OE, Penn, TE and JCP&L could issue a total of $4.5 billion
of preferred stock. CEI, Met-Ed and Penelec have no restrictions on the issuance
of preferred stock.
On March 17, 2003, FirstEnergy filed a registration statement with
the U.S. Securities and Exchange Commission covering securities in the aggregate
amount of up to $2 billion. Although the Company does not have any current plans
to issue securities, the shelf registration provides the flexibility to issue
and sell various types of securities, including common stock, debt securities,
or share purchase contracts and related share purchase units.
On April 21, 2003, OE completed a $325 million refinancing
transaction that included two tranches -- $175 million of 4.00% five year notes
and $150 million of 5.45% twelve year notes. The net proceeds will be used to
redeem approximately $220 million of outstanding OE first mortgage bonds having
a weighted average cost of 7.99%, with the remainder to be used to pay down
short-term debt.
On May 1 and May 2, 2003, FirstEnergy executed two fixed-for-floating
interest rate swap agreements with notional values of $50 million each on
underlying senior notes with an average fixed interest rate of 4.73%.
Cash Flows From Investing Activities
Net cash flows used for investing activities totaled $118 million in
the first quarter of 2003, compared to net cash flows of $222 million provided
from investing activities for the same period of 2002. The $340 million change
resulted from the absence of the Avon cash amount recognized in the first
quarter of 2002 resulting from the reclassification from the "Assets Pending
Sale" presentation to normal operations presentation (see Note 3), increased
capital expenditures and other, offset in part by an increase in cash
investments and proceeds from NUG trusts.
The following table summarizes first quarter of 2003 investments by
FirstEnergy's regulated services and competitive services segments:
34
SUMMARY OF FIRST QUARTER 2003 PROPERTY
CASH USED FOR INVESTING ACTIVITIES ADDITIONS INVESTMENTS OTHER TOTAL
-------------------------------------------------------------------------------------------
SOURCES (USES) (IN MILLIONS)
Regulated Services . $(118) $ 136(1) $ (8) $ 10
Competitive Services (79) 63(2) (71) (87)
Other .............. (27) (77) 3 (101)
Eliminations ....... -- -- 60 60
----- ----- ----- -----
Total ......... $(224) $ 122 $ (16) $(118)
===== ===== ===== =====
(1) Includes $106 million proceeds from NUG trusts.
(2) Includes $61 million proceeds from sale of assets.
During the remaining three quarters of 2003, capital requirements for
property additions and capital leases are expected to be approximately $578
million, including $36 million for nuclear fuel. FirstEnergy has additional
requirements of approximately $378 million to meet sinking fund requirements for
preferred stock and maturing long-term debt during the remainder of 2003. These
cash requirements are expected to be satisfied from internal cash and short-term
credit arrangements.
On January 21, 2003, Standard & Poor's (S&P) indicated its concern
about FirstEnergy's disclosure of non-cash charges related to deferred costs in
Pennsylvania, pension and other post-retirement benefits, and Emdersa, which
were higher than anticipated in the third quarter of 2002. S&P identified the
restart of the Davis-Besse nuclear plant "...without significant delay beyond
April 2003..." as key to maintaining FirstEnergy's current debt ratings. S&P
also identified other issues it would continue to monitor including:
FirstEnergy's deleveraging efforts, free cash generated during 2003, the JCP&L
rate case, successful hedging of its short power position, and continued capture
of projected merger savings.
On April 14, 2003, S&P again affirmed its "BBB" corporate credit
rating for FirstEnergy. The S&P outlook remained negative, but S&P improved
FirstEnergy's business position from a "6" to a "5" (on a scale of 1 to 10 with
1 considered the least risky). S&P also reiterated that the key issues being
monitored by the agency included the timely restart of Davis-Besse, the JCP&L
rate case, capture of merger synergies, and controlling capital expenditures at
estimated levels. Significant delays in the planned date of Davis-Besse's return
to service or other factors (identified above) affecting the speed with which
FirstEnergy reduces debt, could put additional pressure on its credit ratings.
On August 14, 2003, Moody's Investors Service placed the debt ratings
of FirstEnergy and all of its subsidiaries under review for possible downgrade.
Moody's stated that the review was prompted by: (1) weaker than expected
operating performance and cash flow generation; (2) less progress than expected
in reducing debt; (3) continuing high leverage relative to its peer group; and
(4) negative impact on cash flow and earnings from the continuing nuclear plant
outage at Davis-Besse. Moody's further stated that, in anticipation of
Davis-Besse returning to service in the near future and FirstEnergy's continuing
to significantly reduce debt and improve its financial profile, "Moody's does
not expect that the outcome of the review will result in FirstEnergy's senior
unsecured debt rating falling below investment-grade."
OTHER OBLIGATIONS
Obligations not included on FirstEnergy's Consolidated Balance Sheet
primarily consist of sale and leaseback arrangements involving Perry Unit 1,
Beaver Valley Unit 2 and the Bruce Mansfield Plant. As of March 31, 2003, the
present value of these sale and leaseback operating lease commitments, net of
trust investments, total $1.5 billion. Also, CEI and TE continue to sell
substantially all of their retail customer receivables, which provided $145
million of financing not included in the Consolidated Balance Sheet as of March
31, 2003.
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 March 31, 2003, the maximum potential future payments under
outstanding guarantees and other assurances totaled $960.2 million as summarized
below:
35
MAXIMUM
GUARANTEES AND OTHER ASSURANCES EXPOSURE
--------------------------------------------------------
(IN MILLIONS)
FirstEnergy Guarantees of Subsidiaries:
Energy and Energy-Related Contracts(1) $774.4
Financings (2)(3) .................... 98.3
------
872.7
Surety Bonds ........................... 25.8
Rating-Contingent Collateralization (4) 61.7
------
Total Guarantees and Other Assurances $960.2
======
(1) Issued for a one-year term, with a 10-day termination right by
FirstEnergy.
(2) Includes parental guarantees of subsidiary debt and lease financing
including FirstEnergy's letters of credit supporting subsidiary debt.
(3) Issued for various terms.
(4) Estimated net liability under contracts subject to rating-contingent
collateralization provisions.
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 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 FirstEnergy's other assets. The likelihood that such
parental guarantees will increase amounts otherwise paid by FirstEnergy to meet
its obligations incurred in connection with energy-related activities is remote.
Most of FirstEnergy's 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.
Various contracts include credit enhancements in the form of cash
collateral, letters of credit or other security in the event of a reduction in
credit rating. Requirements of these provisions vary and typically require more
than one rating reduction to below investment grade by S&P or Moody's to trigger
additional collateralization.
EMDERSA ABANDONMENT
On April 18, 2003, FirstEnergy divested its ownership of 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.
Prior to the abandonment, FirstEnergy had recorded a foreign currency
translation adjustment (CTA) loss of $90 million through its other comprehensive
income (OCI) - a component of common stockholders' equity. The CTA reduced
FirstEnergy's common stockholders' equity and did not affect its net income. As
a result of the abandonment, FirstEnergy will recognize a one-time, non-cash
charge of $63 million, or $0.21 per share of common stock in the second quarter
of 2003. This charge is the result of realizing the CTA losses through its
current period earnings ($90 million, or $0.30 per share), partially offset by
the gain recognized from eliminating its investment in Emdersa ($27 million, or
$0.09 per share). Since FirstEnergy had previously recorded $90 million of CTA
adjustments in OCI, the net effect of the $63 million charge will be an increase
in common stockholders' equity of $27 million. The $63 million charge does not
include the anticipated income tax benefits related to the abandonment, which
will be fully reserved during the second quarter. FirstEnergy anticipates tax
benefits of approximately $129 million, of which $50 million would increase net
income in the period that it becomes probable those benefits will be realized.
The remaining $79 million of tax benefits would reduce goodwill recognized in
connection with the acquisition of GPU. When realized, the $129 million of tax
benefits will represent positive cash flows for FirstEnergy and increase its
common stockholders' equity by $50 million.
MARKET RISK INFORMATION
FirstEnergy uses various market risk sensitive instruments, including
derivative contracts, primarily to manage the risk of price and interest rate
fluctuations. 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.
36
Commodity Price Risk
FirstEnergy is exposed to market risk primarily due to fluctuations
in electricity, natural gas and coal prices. To manage the volatility relating
to these exposures, it 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 much lesser
extent, for trading purposes. Most of FirstEnergy's 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 the first quarter of 2003 is
summarized in the following table:
INCREASE (DECREASE) IN THE FAIR VALUE
OF COMMODITY 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 ............... $ 53.8 $ 24.1 $ 77.9
New contract value when entered ........................... -- -- --
Additions/Increase in value of existing contracts ......... 17.2 29.1 46.3
Change in techniques/assumptions .......................... -- -- --
Settled contracts ......................................... (4.6) (10.3) (14.9)
------ ------ ------
Outstanding net asset as of March 31, 2003 (1) ............ 66.4 42.9 109.3
------ ------ ------
NON-COMMODITY NET ASSETS AS OF MARCH 31, 2003:
Interest Rate Swaps (2) ................................... -- 24.0 24.0
------ ------ ------
Net Assets - Derivatives Contracts as of March 31, 2003 (3) $ 66.4 $ 66.9 $133.3
====== ====== ======
Impact of Changes in Commodity Derivative Contracts (4)
Income Statement Effects (Pre-Tax) ........................ $ (3.5) $ -- $ (3.5)
Balance Sheet Effects:
Other Comprehensive Income (Pre-Tax) ...................... $ -- $ 18.8 $ 18.8
Regulatory Liability ...................................... $ 16.1 $ -- $ 16.1
(1) Includes $50.3 million in non-hedge commodity derivative contracts which
are offset by a regulatory liability.
(2) Interest rate swaps are treated as fair value hedges. Changes in
derivative values are offset by changes in the hedged debts' premium or
discount.
(3) Excludes $26.7 million of derivative contract fair value decrease, as of
March 31, 2003, representing FirstEnergy's 50% share of Great Lakes Energy
Partners, LLC.
(4) Represents the increase in value of existing contracts, settled contracts
and changes in techniques/assumptions.
Derivatives included on the Consolidated Balance Sheet as of March 31, 2003:
NON-HEDGE HEDGE TOTAL
(IN MILLIONS)
------------------------------------------------------------------------
CURRENT-
Other Assets ......... $ 30.1 $ 31.1 $ 61.2
Other Liabilities .... (32.4) (2.3) (34.7)
NON-CURRENT-
Other Deferred Charges 70.4 38.9 109.3
Other Deferred Credits (1.7) (0.8) (2.5)
------ ------ ------
Net assets ........... $ 66.4 $ 66.9 $133.3
====== ====== ======
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, FirstEnergy relies on model-based
information. The model provides estimates of future regional prices for
electricity and an estimate of related price volatility. FirstEnergy uses 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 derivative contracts by year are summarized in the following table:
37
SOURCE OF INFORMATION
- FAIR VALUE BY CONTRACT YEAR 2003(1) 2004 2005 2006 THEREAFTER TOTAL
-------------------------------------------------------------------------------------------------------
(IN MILLIONS)
Prices actively quoted(2) $ 12.6 $ 2.6 $ -- $ -- $ -- $ 15.2
Other external sources(3) 26.7 15.8 9.3 -- -- 51.8
Prices based on models .. -- -- -- 6.3 36.0 42.3
------ ------ ------ ------ ------ ------
TOTAL(4) ............. $ 39.3 $ 18.4 $ 9.3 $ 6.3 $ 36.0 $109.3
====== ====== ====== ====== ====== ======
(1) For the last three quarters of 2003.
(2) Exchange traded.
(3) Broker quote sheets.
(4) Includes $50.3 million from an embedded option that is offset by a
regulatory liability and does not affect earnings.
FirstEnergy performs sensitivity analyses to estimate its exposure to
the market risk of its commodity positions. A hypothetical 10% adverse shift (an
increase or decrease depending on the derivative position) in quoted market
prices in the near term on both FirstEnergy's trading and nontrading derivative
instruments would not have had a material effect on its consolidated financial
position (assets, liabilities and equity) or cash flows as of March 31, 2003.
Based on derivative contracts held as of March 31, 2003, an adverse 10% change
in commodity prices would decrease net income by approximately $4.7 million for
the next twelve months.
Interest Rate Swap Agreements
During the first quarter of 2003, FirstEnergy entered into
fixed-to-floating interest rate swap agreements, as part of its ongoing efforts
to manage the interest rate risk of its liability 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, fixed interest rates
and interest payment dates match those of the underlying obligations. The swap
agreements consummated in the first quarter of 2003 are based on a notional
principal amount of $200 million.
Throughout the second half of 2002 and the first quarter of 2003,
FirstEnergy utilized fixed-to-floating interest rate swap agreements to increase
the variable-rate component of its debt portfolio. As of March 31, 2003, the
debt underlying FirstEnergy's $700 million notional amount of outstanding
fixed-for-floating interest rate swaps had a weighted average fixed interest
rate of 7.10%, which the swaps have effectively converted to a current weighted
average variable interest rate of 3.09%. GPU Power (through a subsidiary) used
existing dollar-denominated interest rate swap agreements in the first quarter
of 2003. The GPU Power agreements 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% as of March 31, 2003 and
December 31, 2002. The following summarizes the principal characteristics of the
swap agreements:
Interest Rate Swaps
MARCH 31, 2003 DECEMBER 31, 2002
---------------------------- ---------------------------------
NOTIONAL MATURITY FAIR NOTIONAL MATURITY FAIR
DENOMINATION AMOUNT DATE VALUE AMOUNT DATE VALUE
------------------------------------------------------------------
(DOLLARS IN MILLIONS)
Fixed to Floating Rate
(Fair value hedges) $ 200 2006 $ 2.4
350 2023 14.5 $ 444 2023 $ 15.5
150 2025 7.9 150 2025 5.9
Floating to Fixed Rate
(Cash flow hedges) . $ 13 2005 $ (0.8) $ 16 2005 $ (0.9)
------- ------- ------- ------- ------- -------
Equity Price Risk
Included in nuclear decommissioning trusts are marketable equity
securities carried at their market value of approximately $528 million and $532
million as of March 31, 2003 and December 31, 2002, respectively. A hypothetical
10% decrease in prices quoted by stock exchanges would result in a $53 million
reduction in fair value as of March 31, 2003.
OUTLOOK
FirstEnergy continues to pursue its goal of being the leading
regional supplier of energy and related services in the northeastern quadrant of
the United States, where it sees the best opportunities for growth. Its
fundamental business strategy remains stable and unchanged. While FirstEnergy
continues to build toward a strong regional
38
presence, key elements for its strategy are in place and management's focus
continues to be on execution. FirstEnergy intends to provide competitively
priced, high-quality products and value-added services - energy sales and
services, energy delivery, power supply and supplemental services related to its
core business. As FirstEnergy's industry changes to a more competitive
environment, FirstEnergy has taken and expects to take actions designed to
create a larger, stronger regional enterprise that will be positioned to compete
in the changing energy marketplace.
FirstEnergy's current focus includes: 1) returning Davis-Besse to
safe and reliable operation; 2) optimizing FirstEnergy's generation portfolio;
3) effectively managing commodity supplies and risks; 4) reducing FirstEnergy's
cost structure; and 5) enhancing its credit profile and financial flexibility.
Business Organization
FirstEnergy's business is managed as two distinct operating segments
- a competitive services segment and a regulated services segment. FES provides
competitive retail energy services while the EUOC provide regulated transmission
and distribution services. FirstEnergy Generation Corp. (FGCO), a wholly owned
subsidiary of FES, leases fossil and hydroelectric plants from the EUOC and
operates those plants. FirstEnergy expects the transfer of ownership of EUOC
non-nuclear generating assets to FGCO will be substantially completed by the end
of the market development period in 2005. All of the EUOC power supply
requirements for the Ohio Companies and Penn are provided by FES to satisfy
their PLR obligations, as well as grandfathered wholesale contracts.
State Regulatory Matters
In Ohio, New Jersey and Pennsylvania, laws applicable to electric
industry deregulation included similar provisions which are reflected in the
EUOC's respective state regulatory plans. However, despite these similarities,
the specific approach taken by each state and for each of the EUOCs varies.
Those provisions include:
- allowing the EUOC's electric customers to select their
generation suppliers;
- establishing PLR obligations to non-shopping customers in the
EUOC's service areas;
- allowing recovery of potentially stranded investment (or
transition costs) not otherwise recoverable in a competitive
generation market;
- itemizing (unbundling) the price of electricity into its
component elements - including generation, transmission,
distribution and stranded costs recovery charges;
- deregulating the EUOC's electric generation businesses; and
- continuing regulation of the EUOC's transmission and
distribution systems.
Regulatory assets are costs that 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. Regulatory
assets declined $417.2 million to $8.3 billion as of March 31, 2003 from the
balance as of December 31, 2002, with approximately one-half of the decrease
related to the adoption of SFAS 143 by JCP&L, Met-Ed, Penelec and Penn. The
regulatory assets of the individual companies are as follows:
REGULATORY ASSETS AS OF MARCH 31, DECEMBER 31,
COMPANY 2003 2002
---------------------------------------------------------------
RESTATED (SEE NOTE 1)
(IN MILLIONS)
OE .... $1,765.2 $1,848.7
CEI ... 1,170.4 1,191.8
TE .... 557.4 578.2
Penn .. 77.8 156.9
JCP&L . 3,094.8 3199.0
Met-Ed 1,126.9 1,179.1
Penelec 543.7 599.7
-------- --------
Total . $8,336.2 $8,753.4
======== ========
39
Ohio
FirstEnergy's transition plan (which FirstEnergy filed on behalf of
its Ohio electric utilities) included approval for recovery of transition costs,
including regulatory assets, as filed in the transition plan 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 approved plan also
granted preferred access over FirstEnergy's subsidiaries to nonaffiliated
marketers, brokers and aggregators to 1,120 MW of generation capacity through
2005 at established prices for sales to the Ohio Companies' retail customers.
Customer prices are frozen 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 electric utilities 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. FirstEnergy's Ohio customers choosing alternative
suppliers receive an additional incentive applied to the shopping credit
(generation component) of 45% for residential customers, 30% for commercial
customers and 15% for industrial customers. The amount of the incentive is
deferred for future recovery from customers - recovery will be accomplished by
extending the respective transition cost recovery periods.
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 submitted two rate
filings with the New Jersey Board of Public Utilities (NJBPU) in August 2002.
The first filing requested increases in base electric rates of approximately $98
million annually. The second filing was a request to recover deferred costs that
exceeded amounts being recovered under the current market transition charge and
societal benefits charge (SBC) rates; one proposed method of recovery of these
costs is the securitization of the deferred balance. Hearings began in February
2003. On March 18, 2003, a report prepared by independent auditors addressing
costs deferred by JCP&L from August 1, 1999 through July 31, 2002, was
transmitted to the Office of Administrative Law, where JCP&L's rate case is
being heard. While the auditors concluded that JCP&L's energy procurement
strategy and process was reasonable and prudent, they identified potential
disallowances approximating $17 million. The report subjected $436 million of
deferred costs to a retrospective prudence review during a period of extreme
price uncertainty and volatility in the energy markets. Although JCP&L disagrees
with the potential disallowances, it is pleased with the report's major
conclusions and overall tone. Hearings concluded on April 28, 2003, and initial
briefs were filed on May 7, 2003. The JCP&L brief supports its two rate filings
requesting an aggregate rate increase of approximately $122 million in base
electric rates and the recovery of deferred costs based on the securitization
methodology discussed above. If the securitization methodology is not allowed,
then JCP&L has requested deferred cost recovery over a four-year period with a
return on the unamortized deferred cost balance. This alternative would increase
the overall rate request to approximately $246 million. JCP&L strongly disagrees
with many of the positions taken by NJBPU Staff. The Staff's position would
result in a $119 million estimated annual earnings decrease related to the
electricity delivery charge. In addition, the Staff recommended disallowing
approximately $153 million of deferred energy costs which would result in a
one-time pre-tax charge against earnings of $153 million (or $0.31 per share of
common stock). JCP&L will respond to the Staff's position in its Reply Brief
which is due on May 21, 2003. The Administrative Law Judge's recommended
decision is due by the end of June 2003 and the NJBPU's subsequent decision is
due in July 2003.
In 1997, the NJBPU authorized JCP&L to recover from customers,
subject to possible refund, $135 million of costs incurred in connection with a
1996 buyout of a power purchase agreement. JCP&L has recovered the full $135
million; the NJBPU has established a procedural schedule to take further
evidence with respect to the buyout to enable it to make a final prudence
determination contemporaneously with the resolution of the pending rate case.
In December 2001, the NJBPU authorized the auctioning of BGS for the
period from August 1, 2002 through July 31, 2003 to meet the electricity demands
of all customers who have not selected an alternative supplier. The results of
the February 2002 auction, with the NJBPU's approval, removed JCP&L's BGS
obligation of 5,100 megawatts for the period August 1, 2002 through July 31,
2003. In February 2003, the auctioning of BGS for the period beginning August 1,
2003 took place. 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
offsets to its deferred energy cost balances.
Pennsylvania
Effective September 1, 2002, Met-Ed and Penelec assigned their PLR
responsibility to FES through a wholesale power sale which expires in December
2003 and may be extended for each successive calendar 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 existing power contracts
with nonaffiliated third party suppliers. This arrangement reduces Met-Ed's and
Penelec's exposure to high wholesale power prices by providing power at or below
the shopping credit for their uncommitted PLR energy costs during the term of
the agreement to FES. FES has hedged most of Met-Ed's and Penelec's unfilled
on-peak
40
PLR obligation through 2004 and a portion of 2005. Met-Ed and Penelec will
continue to defer those cost differences between NUG contract rates and the
rates reflected in their capped generation rates.
On January 17, 2003, the Pennsylvania Supreme Court denied further
appeals of the Commonwealth Court's decision which effectively affirmed the
PPUC's order approving the merger between FirstEnergy and GPU, let stand the
Commonwealth Court's denial of PLR rate relief for Met-Ed and Penelec and
remanded the merger savings issue back to the PPUC. On April 2, 2003, the PPUC
remanded the merger savings issue to the Office of Administrative Law for
hearings and directed Met-Ed and Penelec to file a position paper on the effect
of the Commonwealth Court's order on the Settlement Stipulation by May 2, 2003.
Because FirstEnergy had already reserved for the deferred energy costs and FES
has largely hedged the anticipated PLR energy supply requirements for Met-Ed and
Penelec through 2005, FirstEnergy, Met-Ed and Penelec believe that the
disallowance of competitive transition charge recovery of PLR costs above
Met-Ed's and Penelec's capped generation rates will not have a future adverse
financial impact during that period.
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 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, FirstEnergy has
made significant management and human performance changes with the intent of
establishing the proper safety culture throughout the workforce. Work was
completed on the reactor head during 2002 and is continuing on efforts designed
to enhance the unit's reliability and performance. FirstEnergy is also
accelerating maintenance work that had been planned for future refueling and
maintenance outages. At a meeting with the NRC in November 2002, FirstEnergy
discussed plans to test the bottom of the reactor for leaks and to install a
state-of-the-art leak-detection system around the reactor. The additional
maintenance work being performed has expanded the previous estimates of
restoration work. FirstEnergy anticipates that the unit will be ready for
restart in the first half of the summer of 2003. The NRC must authorize restart
of the plant following its formal inspection process before the unit can be
returned to service. While the additional maintenance work has delayed
FirstEnergy's plans to reduce post-merger debt levels FirstEnergy believes such
investments in the unit's future safety, reliability and performance to be
essential. Significant delays in Davis-Besse's return to service, which depends
on the successful resolution of the management and technical issues as well as
NRC approval, could trigger an evaluation for impairment of the nuclear plant
(see Significant Accounting Policies below).
Total incremental expenses associated with the extended Davis-Besse
outage in the first quarter of 2003 totaled $88.6 million, including $36.3
million for maintenance work and $52.3 million for fuel and purchased power. It
is anticipated that an additional $13.7 million in maintenance costs will be
expended over the remainder of the Davis-Besse outage. Replacement power costs
are expected to be $15 million per month in the non-summer months and $20-25
million per month during the summer.
FirstEnergy has hedged the on-peak replacement energy supply for
Davis-Besse through the summer of 2003 and has completed some hedging for the
balance of 2003 as well based on a probabilistic assessment of the unit's
expected start-up date.
Environmental Matters
Various federal, state and local authorities regulate the Companies
with regard to air and water quality and other environmental matters.
FirstEnergy estimates additional capital expenditures for environmental
compliance of approximately $159 million, which is included in the construction
forecast provided under "Capital Expenditures" for 2003 through 2007.
The Companies are required to meet federally approved sulfur dioxide
(SO(2)) 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 SO(2) regulations in Ohio that allows for
compliance based on a 30-day averaging period. The Companies cannot predict what
action the EPA may take in the future with respect to the interim enforcement
policy.
The Companies believe they are in compliance with the current SO(2)
and nitrogen oxides (NO(x)) reduction requirements under the Clean Air Act
Amendments of 1990. SO(2) reductions are being achieved by burning lower-sulfur
fuel, generating more electricity from lower-emitting plants, and/or using
emission allowances. NO(x) reductions are being achieved through combustion
controls and the generation of more electricity at lower-emitting plants. In
September 1998, the EPA finalized regulations requiring additional NO(x)
reductions from the Companies' Ohio and Pennsylvania facilities. The
41
EPA's NO(x) Transport Rule imposes uniform reductions of NO(x) emissions (an
approximate 85% reduction in utility plant NO(x) emissions from projected 2007
emissions) across a region of nineteen states and the District of Columbia,
including New Jersey, Ohio and Pennsylvania, based on a conclusion that such
NO(x) 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 NO(x) budgets established by the EPA. Pennsylvania submitted a
SIP that requires compliance with the NO(x) budgets at the Companies'
Pennsylvania facilities by May 1, 2003 and Ohio submitted a SIP that requires
compliance with the NO(x) budgets at the Companies' Ohio facilities by May 31,
2004.
In July 1997, the EPA promulgated changes in the National Ambient Air
Quality Standard (NAAQS) for ozone emissions and proposed a new NAAQS for
previously unregulated ultra-fine particulate matter. In May 1999, the U.S.
Court of Appeals for the D.C. Circuit found constitutional and other defects in
the new NAAQS rules. In February 2001, the U.S. Supreme Court upheld the new
NAAQS rules regulating ultra-fine particulates but found defects in the new
NAAQS rules for ozone and decided that the EPA must revise those rules. The
future cost of compliance with these regulations may be substantial and will
depend if and how they are ultimately implemented by the states in which the
Companies operate affected facilities.
In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a
Compliance Order to nine utilities covering 44 power plants, including the W. H.
Sammis Plant. In addition, the U.S. Department of Justice filed eight civil
complaints against various investor-owned utilities, which included a complaint
against OE and Penn in the U.S. District Court for the Southern District of
Ohio. The NOV and complaint allege violations of the Clean Air Act based on
operation and maintenance of the Sammis Plant dating back to 1984. The civil
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 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 March 15, 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, may 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.
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants. The EPA identified mercury as the hazardous air pollutant of
greatest concern. The EPA established a schedule to propose regulations by
December 2003 and issue final regulations by December 2004. The future cost of
compliance with these regulations may be substantial.
As a result of the Resource Conservation and Recovery Act of 1976, as
amended, and the Toxic Substances Control Act of 1976, federal and state
hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous waste
disposal requirements pending the EPA's evaluation of the need for future
regulation. The EPA has issued its final regulatory determination that
regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the
EPA announced that it will develop national standards regulating disposal of
coal ash under its authority to regulate nonhazardous waste.
Several 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, potential environmental liabilities have been recognized on the
Consolidated Balance Sheet as of March 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 the SBC.
The Companies have total accrued liabilities aggregating approximately $53.9
million as of March 31, 2003.
The effects of compliance on the EUOC with regard to environmental
matters could have a material adverse effect on FirstEnergy's earnings and
competitive position. These environmental regulations affect FirstEnergy's
earnings and competitive position to the extent it competes with companies that
are not subject to such regulations and therefore do not bear the risk of costs
associated with compliance, or failure to comply, with such regulations.
FirstEnergy believes it is in material compliance with existing regulations, but
is unable to predict how and when applicable environmental regulations may
change and what, if any, the effects of any such change would be.
42
Legal Matters
It is FirstEnergy's understanding that, as of August 18, 2003,
five individual shareholder-plaintiffs have filed separate complaints against
FirstEnergy alleging various securities law violations in connection with the
restatement of earnings described herein. Most of these complaints have not yet
been officially served on the Company. Moreover, FirstEnergy is still reviewing
the suits that have been served in preparation for a responsive pleading.
FirstEnergy is, however, aware that in each case, the plaintiffs are seeking
certification from the court to represent a class of similarly situated
shareholders.
Various lawsuits, claims and proceedings related to FirstEnergy's
normal business operations are pending against it, the most significant of which
are described herein.
Power Outage
On August 14, 2003, eight states and southern Canada experienced a
widespread power outage. That outage affected approximately 1.4 million
customers in FirstEnergy's service area. The cause of the outage has not been
determined. Having restored service to its customers, FirstEnergy is now in the
process of accumulating data and evaluating the status of its electrical system
prior to and during the outage event and would expect that the same effort Is
under way at utilities and regional transmission operators across the region.
As of August 18, 2003, the following facts about FirstEnergy's system
were known. Early in the afternoon of August 14, hours before the event, Unit 5
of the Eastlake Plant in Eastlake, Ohio tripped off. Later in the afternoon,
three FirstEnergy transmission lines and one owned by American Electric Power
and FirstEnergy tripped out of service. The Midwest Independent System Operator
(MISO), which oversees the regional transmission grid, indicated that there were
a number of other transmission line trips in the region outside of FirstEnergy's
system. FirstEnergy customers experienced no service interruptions resulting
from these conditions. Indications to FirstEnergy were that the Company's system
was stable. Therefore, no isolation of FirstEnergy's system was called for. In
addition, FirstEnergy determined that its computerized system for monitoring and
controlling its transmission and generation system was operating, but the alarm
screen function was not. However, MISO's monitoring system was operating
properly. FirstEnergy believes that extensive data needs to be gathered and
analyzed in order to determine with any degree of certainty the circumstances
that led to the outage. This is a very complex situation, far broader than the
power line outages FirstEnergy experienced on its system. From the preliminary
data that has been gathered, FirstEnergy believes that the transmission grid in
the Eastern Interconnection, not just within FirstEnergy's system, was
experiencing unusual electrical conditions at various times prior to the event.
These included unusual voltage and frequency fluctuations and load swings on the
grid. FirstEnergy is committed to working with the North American Electric
Reliability Council and others involved to determine exactly what events in the
entire affected region led to the outage. There is no timetable as to when this
entire process will be completed. It is, however, expected to last several
weeks, at a minimum.
IMPLEMENTATION OF RECENT ACCOUNTING STANDARD
In June 2002, the EITF reached a partial consensus on Issue No.
02-03. Based on the EITF's partial consensus position, for periods after July
15, 2002, mark-to-market revenues and expenses and their related kilowatt-hour
sales and purchases on energy trading contracts must be shown on a net basis in
the Consolidated Statements of Income. FirstEnergy had previously reported such
contracts as gross revenues and purchased power costs. Comparative quarterly
disclosures and the Consolidated Statements of Income for revenues and expenses
have been reclassified for 2002 to conform with the revised presentation (see
Note 5). In addition, the related kilowatt-hour sales and purchases statistics
described above under Results of Operations were reclassified (1.3 billion
kilowatt-hour in the first quarter of 2002). The following table displays the
impact of changing to a net presentation for FirstEnergy's energy trading
operations.
IMPACT OF RECORDING ENERGY TRADING NET
ON THE PREVIOUSLY REPORTED FIRST QUARTER OF 2002 REVENUES EXPENSES
------------------------------------------------------------------------------
(IN MILLIONS)
Total before adjustment $ 2,893 $ 2,402
Adjustment ............ (40) (40)
------- -------
Total as reported ..... $ 2,853 $ 2,362
======= =======
SIGNIFICANT ACCOUNTING POLICIES
FirstEnergy prepares its 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
FirstEnergy's 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
43
below are similarly reviewed with their risks and uncertainties reflecting these
specific factors. FirstEnergy's more significant accounting policies are
described below.
Purchase Accounting - Acquisition of GPU
Purchase accounting requires judgment regarding the allocation of the
purchase price based on the fair values of the assets acquired (including
intangible assets) and the liabilities assumed. The fair values of the acquired
assets and assumed liabilities for GPU were based primarily on estimates. The
more significant of these included the estimation of the fair value of the
international operations, certain domestic operations and the fair value of the
pension and other post-retirement benefit assets and liabilities. The purchase
price allocations for the GPU acquisition were finalized in the fourth quarter
of 2002.
Regulatory Accounting
FirstEnergy's 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 FirstEnergy is 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 FirstEnergy operates, a significant amount of
regulatory assets have been recorded - $8.3 billion as of March 31, 2003.
FirstEnergy regularly reviews 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. FirstEnergy continually monitors its derivative contracts to
determine if its activities, expectations, intentions, assumptions and estimates
remain valid. As part of its normal operations, FirstEnergy enters into
significant commodity contracts, as well as interest rate and currency swaps,
which increase the impact of derivative accounting judgments.
Revenue Recognition
FirstEnergy follows the accrual method of accounting for revenues,
recognizing revenue for kilowatt-hours that have been delivered but not yet
billed through the end of the accounting period. The determination of unbilled
revenues requires management to make various estimates including:
- Net energy generated or purchased for retail load
- Losses of energy over transmission and distribution lines
- Mix of kilowatt-hour usage by residential, commercial and
industrial customers
- Kilowatt-hour usage of customers receiving electricity from
alternative suppliers
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory defined
pension benefits and postemployment benefits other than pensions (OPEB) 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 FirstEnergy makes to the plans, and earnings on plan assets. Such
factors may be further affected by business combinations (such as FirstEnergy's
merger with GPU, Inc. in November 2001), which impacts employee demographics,
plan experience and other factors. Pension and OPEB costs may also be
44
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.
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.
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. Due to the significant decline in corporate
bond yields and interest rates in general during 2002, FirstEnergy reduced the
assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used at the
end of 2001.
FirstEnergy's assumed rate of return on pension plan assets considers
historical market returns and economic forecasts for the types of investments
held by its pension trusts. The market values of FirstEnergy's pension assets
have been affected by sharp declines in the equity markets since mid-2000. In
2002 and 2001 plan assets earned (11.3)% and (5.5)%, respectively. FirstEnergy's
pension costs in the first quarter of 2002 were computed assuming a 10.25% rate
of return on plan assets. Beginning in the first quarter of 2003, the assumed
return on plan assets was reduced to 9.00% based upon FirstEnergy's projection
of future returns and pension trust investment allocation of approximately 60%
large cap equities, 10% small cap equities and 30% bonds.
Based on pension assumptions and pension plan assets as of December
31, 2002, FirstEnergy will not be required to fund its pension plans in 2003.
While OPEB plan assets have also been affected by sharp declines in the equity
market, the impact is not as significant due to the relative size of the plan
assets. However, health care cost trends have significantly increased and will
affect future OPEB costs. The 2003 composite health care trend rate assumption
is approximately 10%-12% gradually decreasing to 5% in later years, compared to
the 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6%
in later years. In determining its trend rate assumptions, FirstEnergy included
the specific provisions of its health care plans, the demographics and
utilization rates of plan participants, actual cost increases experienced in its
health care plans, and projections of future medical trend rates.
Ohio Transition Cost Amortization
In developing FirstEnergy's restructuring plan, the PUCO determined
allowable transition costs based on amounts recorded on the EUOC's regulatory
books. 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 No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," FirstEnergy periodically evaluates its
long-lived assets to determine whether conditions exist that would indicate that
the carrying value of an asset may 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 other
than of a temporary nature has occurred, FirstEnergy recognizes a loss -
calculated as the difference between the carrying value and the estimated fair
value of the asset (discounted future net cash flows).
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, FirstEnergy
evaluates its 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
45
carrying value including goodwill, an impairment for goodwill must be recognized
in the financial statements. If impairment were to occur FirstEnergy would
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.
FirstEnergy's annual review was completed in the third quarter of 2002. The
results of that review indicated no impairment of goodwill -- fair value was
higher than carrying value for each of its reporting units. 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
March 31, 2003, FirstEnergy had $6.2 billion of goodwill that primarily relates
to its regulated services segment.
RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET IMPLEMENTED
FIN 46, "Consolidation of Variable Interest Entities - an interpretation
of ARB 51"
In January 2003, the FASB issued this interpretation of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. This Interpretation requires an enterprise to
disclose the nature of its involvement with a VIE if the enterprise has a
significant variable interest in the VIE and to consolidate a VIE if the
enterprise is the primary beneficiary. VIEs created after January 31, 2003 are
immediately subject to the provisions of FIN 46. VIEs created before February 1,
2003 are subject to this interpretation's provisions in the first interim or
annual reporting period after June 15, 2003 (FirstEnergy's third quarter of
2003). The FASB also identified transitional disclosure provisions for all
financial statements issued after January 31, 2003.
FirstEnergy currently has transactions with entities in connection
with sale and leaseback arrangements, the sale of preferred securities and debt
secured by bondable property, which may fall within the scope of this
interpretation and which are reasonably possible of meeting the definition of a
VIE in accordance with FIN 46.
FirstEnergy currently consolidates the majority of these entities and
believe it will continue to consolidate following the adoption of FIN 46. In
addition to the entities FirstEnergy is currently consolidating FirstEnergy
believes that the PNBV Capital Trust, which reacquired a portion of the
off-balance sheet debt issued in connection with the sale and leaseback of OE's
interest in the Perry Nuclear Plant and Beaver Valley Unit 2, would require
consolidation. Ownership of the trust includes a three-percent equity interest
by a nonaffiliated party and a three-percent equity interest by OES Ventures, a
wholly owned subsidiary of OE. Full consolidation of the trust under FIN 46
would change the characterization of the PNBV trust investment to a lease
obligation bond investment. Also, consolidation of the outside minority interest
would be required, which would increase assets and liabilities by $12.0 million.
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
SFAS133 for decisions made by the Derivative Implementation Group, as well as
issues raised in connection with other FASB projects and implementation issues.
The statement is effective for contracts entered into or modified after June 30,
2003 except for implementation issues that have been effective for quarters
which began prior to June 15, 2003, which continue to be applied based on their
original effective dates. FirstEnergy is currently assessing the new standard
and has not yet determined the impact on its financial statements.
46
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
-------------------------------
2003 2002
------------ ------------
RESTATED RESTATED
(SEE NOTE 1) (SEE NOTE 1)
------------ ------------
(IN THOUSANDS)
OPERATING REVENUES ................................................................. $ 742,743 $ 707,799
--------- ---------
OPERATING EXPENSES AND TAXES:
Fuel ............................................................................ 12,850 14,290
Purchased power ................................................................. 243,828 241,479
Nuclear operating costs ......................................................... 125,368 95,234
Other operating costs ........................................................... 90,273 79,611
--------- ---------
Total operation and maintenance expenses ...................................... 472,319 430,614
Provision for depreciation and amortization ..................................... 108,385 75,730
General taxes ................................................................... 48,256 45,376
Income taxes .................................................................... 43,701 48,729
--------- ---------
Total operating expenses and taxes ............................................ 672,661 600,449
--------- ---------
OPERATING INCOME ................................................................... 70,082 107,350
OTHER INCOME ....................................................................... 13,501 512
--------- ---------
INCOME BEFORE NET INTEREST CHARGES ................................................. 83,583 107,862
--------- ---------
NET INTEREST CHARGES:
Interest on long-term debt ...................................................... 24,488 33,073
Allowance for borrowed funds used during construction and capitalized interest .. (1,380) (621)
Other interest expense .......................................................... 2,478 5,147
Subsidiaries' preferred stock dividend requirements ............................. 912 3,626
--------- ---------
Net interest charges .......................................................... 26,498 41,225
--------- ---------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE ............................... 57,085 66,637
Cumulative effect of accounting change (net of income taxes of $22,389,000) (Note 5) 31,720 --
--------- ---------
NET INCOME ......................................................................... 88,805 66,637
PREFERRED STOCK DIVIDEND REQUIREMENTS .............................................. 659 2,596
--------- ---------
EARNINGS ON COMMON STOCK ........................................................... $ 88,146 $ 64,041
========= =========
The preceding Notes to Financial Statements as they relate to Ohio Edison
Company are an integral part of these statements.
47
OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
MARCH 31, DECEMBER 31,
2003 2002
---------- ----------
RESTATED RESTATED
(SEE NOTE 1) (SEE NOTE 1)
---------- ----------
(IN THOUSANDS)
ASSETS
UTILITY PLANT:
In service ......................................................... $5,139,199 $4,989,056
Less--Accumulated provision for depreciation ....................... 2,573,462 2,552,007
---------- ----------
2,565,737 2,437,049
---------- ----------
Construction work in progress-
Electric plant ................................................... 145,785 122,741
Nuclear fuel ..................................................... 47,974 23,481
---------- ----------
193,759 146,222
---------- ----------
2,759,496 2,583,271
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
PNBV Capital Trust ................................................. 401,972 402,565
Letter of credit collateralization ................................. 277,763 277,763
Nuclear plant decommissioning trusts ............................... 296,298 293,190
Long-term notes receivable from associated companies ............... 503,510 503,827
Other .............................................................. 70,708 74,220
---------- ----------
1,550,251 1,551,565
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents .......................................... 14,320 20,512
Receivables-
Customers (less accumulated provisions of $5,708,000 and
$5,240,000, respectively for uncollectible accounts) ........... 296,218 296,548
Associated companies ............................................. 619,084 592,218
Other (less accumulated provisions of $1,000,000 for uncollectible
accounts at both dates) ........................................ 33,430 30,057
Notes receivable from associated companies ......................... 264,736 437,669
Materials and supplies, at average cost-
Owned ............................................................ 58,564 58,022
Under consignment ................................................ 20,509 19,753
Prepayments and other .............................................. 26,697 11,804
---------- ----------
1,333,558 1,466,583
---------- ----------
DEFERRED CHARGES:
Regulatory assets .................................................. 1,842,939 2,005,554
Property taxes ..................................................... 59,035 59,035
Unamortized sale and leaseback costs ............................... 69,672 72,294
Other .............................................................. 54,422 51,739
---------- ----------
2,026,068 2,188,622
---------- ----------
$7,669,373 $7,790,041
========== ==========
48
OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
-----------
MARCH 31, DECEMBER 31,
2003 2002
----------- -----------
RESTATED RESTATED
(SEE NOTE 1) (SEE NOTE 1)
----------- -----------
(IN THOUSANDS)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 175,000,000 shares -
100 shares outstanding ....................................... $ 2,098,729 $ 2,098,729
Accumulated other comprehensive loss ........................... (62,548) (59,495)
Retained earnings .............................................. 875,167 800,021
----------- -----------
Total common stockholder's equity .......................... 2,911,348 2,839,255
Preferred stock not subject to mandatory redemption .............. 60,965 60,965
Preferred stock of consolidated subsidiary-
Not subject to mandatory redemption ............................ 39,105 39,105
Subject to mandatory redemption ................................ 13,500 13,500
Long-term debt ................................................... 1,238,877 1,219,347
----------- -----------
4,263,795 4,172,172
----------- -----------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock ............. 526,475 563,267
Short-term borrowings-
Associated companies ........................................... 187 225,345
Other .......................................................... 175,197 182,317
Accounts payable-
Associated companies ........................................... 173,086 145,981
Other .......................................................... 5,380 18,015
Accrued taxes .................................................... 472,115 466,064
Accrued interest ................................................. 30,646 28,209
Other ............................................................ 101,023 74,562
----------- -----------
1,484,109 1,703,760
----------- -----------
DEFERRED CREDITS:
Accumulated deferred income taxes ................................ 1,005,763 1,017,629
Accumulated deferred investment tax credits ...................... 85,292 88,449
Asset retirement obligation ...................................... 302,524 --
Nuclear plant decommissioning costs .............................. -- 280,858
Retirement benefits .............................................. 250,211 247,531
Other ............................................................ 277,679 279,642
----------- -----------
1,921,469 1,914,109
----------- -----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (NOTE 2)
$ 7,669,373 $ 7,790,041
=========== ===========
The preceding Notes to Financial Statements as they relate to Ohio Edison
Company are an integral part of these balance sheets.
49
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
----------------------------------
2003 2002
------------- -------------
RESTATED RESTATED
(SEE NOTE 1) (SEE NOTE 1)
------------- -------------
(IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income .................................................................. $ 88,805 $ 66,637
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation and amortization ............................ 108,385 75,730
Nuclear fuel and lease amortization .................................... 7,106 11,402
Deferred income taxes, net ............................................. 7,683 (7,380)
Investment tax credits, net ............................................ (3,704) (3,449)
Cumulative effect of accounting change (Note 5) ........................ (54,109) --
Receivables ............................................................ (29,909) 64,148
Materials and supplies ................................................. (1,298) (1,642)
Accounts payable ....................................................... 14,470 (18,295)
Accrued taxes .......................................................... 6,051 56,884
Accrued interest ....................................................... 2,437 6,237
Deferred lease costs ................................................... 31,683 31,683
Prepayments and other .................................................. (14,893) 16,095
Other .................................................................. (9,190) (30,539)
--------- ---------
Net cash provided from operating activities .......................... 153,517 267,511
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt ......................................................... -- 104,985
Short-term borrowings, net ............................................. -- 40,306
Redemptions and Repayments-
Long-term debt ......................................................... (19,493) (89,547)
Short-term borrowings, net ............................................. (232,278) --
Dividend Payments
Common stock ........................................................... (13,000) (101,200)
Preferred stock ........................................................ (659) (2,597)
--------- ---------
Net cash used for financing activities ............................... (265,430) (48,053)
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions ....................................................... (68,367) (30,344)
Notes receivable from associated companies, net .......................... 173,250 (138,181)
Other .................................................................... 838 1,972
--------- ---------
Net cash provided from (used for) investing activities ............... 105,721 (166,553)
--------- ---------
Net Increase (decrease) in cash and cash equivalents ........................ (6,192) 52,905
Cash and cash equivalents at beginning of period ............................ 20,512 4,588
--------- ---------
Cash and cash equivalents at end of period .................................. $ 14,320 $ 57,493
========= =========
The preceding Notes to Financial Statements as they relate to Ohio Edison
Company are an integral part of these statements.
50
REPORT OF INDEPENDENT AUDITORS
To the Stockholders and Board of
Directors of Ohio Edison Company:
We have reviewed the accompanying consolidated balance sheet of Ohio Edison
Company and its subsidiaries as of March 31, 2003, and the related consolidated
statements of income and cash flows for each of the three-month periods ended
March 31, 2003 and 2002. These interim financial statements are the
responsibility of the Company's management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures and making
inquiries of persons responsible for financial and accounting matters. It is
substantially less in scope than an audit conducted in accordance with generally
accepted auditing standards, the objective of which is the expression of an
opinion regarding the financial statements taken as a whole. Accordingly, we do
not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to the accompanying consolidated interim financial statements for them
to be in conformity with accounting principles generally accepted in the United
States of America.
As discussed in Note 1 to the consolidated interim financial statements, the
Company has restated its previously issued consolidated interim financial
statements for the quarters ended March 31, 2003 and 2002.
We previously audited in accordance with auditing standards generally accepted
in the United States of America, the consolidated balance sheet and the
consolidated statement of capitalization as of December 31, 2002, and the
related consolidated statements of income, common stockholder's equity,
preferred stock, cash flows and taxes for the year then ended (not presented
herein), and in our report (which contained a reference to the Company's
restatement of its previously issued consolidated financial statements for the
year ended December 31, 2002 as discussed in Note 1(M) to those consolidated
financial statements) dated February 28, 2003, except as to Note 1(M), which is
as of August 18, 2003, we expressed an unqualified opinion on those consolidated
financial statements. In our opinion, the information set forth in the
accompanying consolidated balance sheet as of December 31, 2002, is fairly
stated in all material respects in relation to the consolidated balance sheet
from which it has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
May 9, 2003, except as to Note 1, which is as of August 18, 2003
51
OHIO EDISON COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
OE is a wholly owned, electric utility subsidiary of FirstEnergy. OE
and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and
Pennsylvania, providing regulated electric distribution services. OE and Penn
(OE Companies) also provide generation services to those customers electing to
retain them as their power supplier. The OE Companies provide power directly to
wholesale customers under previously negotiated contracts, as well as to
alternative energy suppliers under OE's transition plan. The OE Companies have
unbundled the price of electricity into its component elements -- including
generation, transmission, distribution and transition charges. Power supply
requirements of the OE Companies are provided by FES -- an affiliated company.
RESTATEMENTS
As further discussed in Note 1 to the Consolidated Financial
Statements, FirstEnergy is restating its consolidated financial statements for
the year ended December 31, 2002 and the three months ended March 31, 2003 and
2002. The restatements reflect a change in the method of amortizing the costs
being recovered under the Ohio transition plan and recognition of above-market
values of certain leased generation facilities.
Transition Cost Amortization
As discussed in Note 4 - Regulatory Matters, FirstEnergy's Ohio
electric utilities recover transition costs, including regulatory assets,
through an approved transition plan filed under Ohio's electric utility
restructuring legislation. The plan, which was approved in July 2000, provides
for the recovery of costs from January 1, 2001 through a fixed number of
kilowatt-hour sales to all customers that continue to receive regulated
transmission and distribution service, which is expected to end in 2006 for OE.
FirstEnergy and the Ohio utilities amortize transition costs using
the effective interest method. The amortization schedules originally developed
at the beginning of the transition plan in 2001 in applying this method were
based on total transition revenues, including revenues designed to recover costs
which have not yet been incurred or that were recognized on the regulatory
financial statements (fair value purchase accounting adjustments) but not in the
financial statements prepared under GAAP. The Ohio electric utilities have
revised their amortization schedules under the effective interest method to
consider only revenues relating to transition regulatory assets recognized on
the GAAP balance sheet. The impact of this change will result in higher
amortization of these regulatory assets in the first several years of the
transition cost recovery period, versus the method previously applied. The
change in method results in no change in total amortization of the regulatory
assets recovered under the transition period through the end of 2009. The
amortization expense under the revised method (see Note 1) decreased by $8
million for the three months ended June 30, 2002 and increased by $3 million
for the three months ended June 30, 2003.
RESULTS OF OPERATIONS
Earnings on common stock in the first quarter of 2003 increased to
$88.1 million from $64.0 million in the first quarter of 2002. Earnings on
common stock in the first quarter of 2003 included an after-tax credit of $31.7
million from the cumulative effect of an accounting change due to the adoption
of SFAS 143, "Accounting for Asset Retirement Obligations." Income before the
cumulative effect was $57.1 million in the first three months of 2003, compared
to $66.6 million for the same period of 2002. Lower results in the first quarter
of 2003 reflect higher operating expenses -- primarily nuclear operating costs,
employee benefit costs and depreciation and amortization. Partially offsetting
these effects were higher revenues due to colder weather, increased sales to FES
and reduced financing costs, compared with the first quarter of 2002, as well as
the absence of adjustments reflected in the first quarter of 2002 for OE's low
income housing investments.
Operating revenues increased by $34.9 million or 4.9% in the first
quarter of 2003 compared with the same period in 2002. The higher revenues
resulted from increased distribution deliveries to residential and commercial
customers due to colder temperatures and additional sales revenues to FES, which
were partially offset by lower generation kilowatt-hour sales to retail
customers. Kilowatt-hour sales to retail customers declined by 1.4% in the first
quarter of 2003 from the same quarter of 2002, which reduced generation sales
revenue by $13.6 million. Electric generation services provided by alternative
suppliers as a percent of total sales delivered in OE's franchise area increased
to 24.0% in the first quarter of 2003 from 17.1% in the first quarter of 2002.
Distribution deliveries increased 7.6% in the first quarter of 2003
compared with the corresponding quarter of 2002, with increases in all customer
sectors (residential, commercial and industrial). This increased revenues from
electricity throughput by $37.6 million in the first quarter of 2003 from the
same quarter of the prior year. Approximately
52
70% of the increase reflected higher volumes with the remainder due to higher
unit prices. Distribution deliveries benefited from substantially higher
residential and commercial demand, due in large part to colder temperatures,
that was moderated by the continued effect of a sluggish economy and its impact
on demand by industrial customers in OE's franchise area.
Partially offsetting the increase in revenues from distribution
deliveries were Ohio transition plan incentives provided to customers to promote
customer shopping for alternative suppliers -- $6.3 million of additional
credits in the first quarter of 2003 from the same period last year. These
reductions in revenues are deferred for future recovery under OE's transition
plan and do not materially affect current period earnings.
Sales revenues from wholesale customers increased by $17.3 million
(primarily to FES) in the first quarter of 2003 compared to the same quarter of
2002, due to higher market prices. Increased wholesale revenues occurred despite
a reduction in kilowatt-hour sales in the first quarter of 2003 from the same
quarter last year, due a 9.9% reduction in available nuclear generation from
Beaver Valley Unit 1 as a result of its refueling outage that began on March 8,
2003.
Changes in electric generation sales and distribution deliveries in
the first quarter of 2003 from the same quarter of 2002 are summarized in the
following table:
CHANGES IN KILOWATT-HOUR SALES
----------------------------------------------------
INCREASE (DECREASE)
Electric Generation:
Retail.................................. (1.4)%
Wholesale............................... (7.1)%
----------------------------------------------------
TOTAL ELECTRIC GENERATION SALES........... (4.0)%
====================================================
Distribution Deliveries:
Residential............................. 12.2%
Commercial.............................. 8.7%
Industrial.............................. 2.1%
---------------------------------------------------
TOTAL DISTRIBUTION DELIVERIES............. 7.6%
===================================================
Operating Expenses and Taxes
Total operating expenses and taxes increased by $72.2 million in the
first quarter of 2003 from the first quarter of 2002. The following table
presents changes from the prior year by expense category.
OPERATING EXPENSES AND TAXES - CHANGES
------------------------------------------------------------------
INCREASE (DECREASE) (IN MILLIONS)
(REVISED)
Fuel............................................. $ (1.4)
Purchased power costs............................ 2.3
Nuclear operating costs.......................... 30.1
Other operating costs............................ 10.7
--------------------------------------------------------------
TOTAL OPERATION AND MAINTENANCE EXPENSES....... 41.7
Provision for depreciation and amortization...... 32.6
General taxes.................................... 2.9
Income taxes..................................... (5.0)
---------------------------------------------------------------
TOTAL OPERATING EXPENSES AND TAXES............. $72.2
===============================================================
Lower fuel costs in the first quarter of 2003, compared with the
same quarter of 2002, resulted from reduced nuclear generation. The increased
purchased power costs reflected additional kilowatt-hour purchases offset in
part by lower unit costs. Higher nuclear operating costs occurred in large part
due to the refueling outage at Beaver Valley Unit 1 (100% ownership) in the
first quarter of 2003 compared with refueling outage costs at Beaver Valley Unit
2 (55.6% ownership) in the first quarter of 2002. The increase in other
operating costs reflects higher employee benefit costs and increased
uncollectible customer accounts.
Charges for depreciation and amortization increased by $32.6 million
in the first quarter of 2003 compared to the first quarter of 2002 primarily
from two factors - increased amortization of the Ohio transition regulatory
assets ($33.8 million) and reduced transition plan tax-related deferrals ($6.3
million) in 2003. Partially offsetting these increases were higher shopping
incentive deferrals ($6.6 million) and lower charges resulting from the
implementation of SFAS 143 ($4.7 million), including revised service life
assumptions for generating plants ($1.0 million).
53
General taxes increased in the first quarter of 2003 from the same
quarter of last year principally due to higher kilowatt-hour taxes in Ohio as
the result of increased kilowatt-hour deliveries.
Other Income
Other income increased by $13.0 million in the first quarter of 2003
from the same period last year, primarily due to the absence in the first
quarter of 2003 of adjustments recorded in the first quarter of 2002 related to
OE's low income housing investments.
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $14.7
million in the first quarter of 2003 from the same period last year, reflecting
redemptions and refinancings since the first quarter of 2002. OE's net debt
redemptions totaled $13.0 million during the first quarter of 2003, which will
result in annualized savings of $1.1 million.
Cumulative Effect of Accounting Change
Upon adoption of SFAS 143 in the first quarter of 2003, OE recorded
an after-tax credit to net income of $31.7 million. OE identified applicable
legal obligations as defined under the new standard for nuclear power plant
decommissioning and reclamation of a sludge disposal pond at the Bruce Mansfield
Plant. As a result of adopting SFAS 143 in January 2003, asset retirement costs
of $133.7 million were recorded as part of the carrying amount of the related
long-lived asset, offset by accumulated depreciation of $25.2 million. The asset
retirement obligation (ARO) liability at the date of adoption was $297.6
million, including accumulated accretion for the period from the date the
liability was incurred to the date of adoption. As of December 31, 2002, OE had
recorded decommissioning liabilities of $292.4 million, including unrealized
gains on the decommissioning trust funds of $10.6 million. Penn expects
substantially all of its nuclear decommissioning costs to be recoverable in
rates over time. Therefore, OE recognized a regulatory liability of $10.6
million upon adoption of SFAS 143 for the transition amounts related to
establishing the ARO for nuclear decommissioning for Penn. The remaining
cumulative effect adjustment for unrecognized depreciation, accretion offset by
the reduction in the existing decommissioning liabilities and ceasing the
accounting practice of depreciating non-regulated generation assets using a cost
of removal component was a $54.1 million increase to income, or $31.7 million
net of income taxes.
CAPITAL RESOURCES AND LIQUIDITY
OE's cash requirements in 2003 for operating expenses, construction
expenditures, scheduled debt maturities and preferred stock redemptions are
expected to be met without increasing its net debt and preferred stock
outstanding. Available borrowing capacity under short-term credit facilities
will be used to manage working capital requirements. Over the next three years,
OE expects to meet its contractual obligations with cash from operations.
Thereafter, OE expects to use a combination of cash from operations and funds
from the capital markets.
Changes in Cash Position
As of March 31, 2003, OE had $14.3 million of cash and cash
equivalents, compared with $20.5 million as of December 31, 2002. The major
sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Cash flows provided by operating activities during the first quarter
of 2003, compared with the corresponding period in 2002 were as follows:
OPERATING CASH FLOWS 2003 2002
------------------------------------------------------------
(IN MILLIONS)
Cash earnings (1).................... $154 $143
Working capital and other............ -- 125
------------------------------------------------------------
Total................................ $154 $268
============================================================
(1) Includes net income, depreciation and amortization, deferred
income taxes, investment tax credits and major noncash
charges.
54
Net cash from operating activities decreased $114 million due to a
$124 million increase in funds used for working capital -- that decrease was
offset in part by a $11 million increase in cash earnings. The increase in
working capital and other primarily reflects higher accounts receivable from
associated companies in the first quarter of 2003 compared with corresponding
amounts in the first quarter of 2002 ($81 million). A change in accrued tax
liabilities also contributed $52 million to the increase in working capital
primarily due to a $48 million increase in tax payments in the first quarter of
2003 compared with the first quarter of 2002.
Cash Flows From Financing Activities
In the first quarter of 2003, net cash used for financing activities
increased to $265 million from $48 million in the same period last year. The
increase resulted from the absence of new financing and a reduction of debt
(primarily short-term borrowings from associated companies) partially offset by
reduced dividends to FirstEnergy.
OE had approximately $279.1 million of cash and temporary
investments and approximately $175.4 million of short-term indebtedness as of
March 31, 2003. Available borrowing capability under bilateral bank facilities
totaled $34.0 million as of March 31, 2002. OE had the capability to issue $1.7
billion of additional first mortgage bonds on the basis of property additions
and retired bonds. Based upon applicable earnings coverage tests OE could issue
up to $3.0 billion of preferred stock (assuming no additional debt was issued)
as of March 31, 2003.
On April 21, 2003, OE completed a $325 million debt refinancing
transaction that included two tranches -- $175 million of 4.00% five year notes
and $150 million of 5.45% twelve year notes. The net proceeds will be used to
redeem approximately $220 million of outstanding OE first mortgage bonds having
a weighted average cost of 7.99%, with the remainder to be used to pay down
short-term debt.
Cash Flows From Investing Activities
Net cash flows received from investing activities totaled $106
million in the first quarter of 2003, compared to a net use of funds of $167
million for the same period of 2002. The $273 million increase in funds from
investing activities resulted from payments received on notes from associated
companies, offset in part by additional capital expenditures.
During the last three quarters of 2003, capital requirements for
property additions and capital leases are expected to be about $113 million,
including $17 million for nuclear fuel. OE has additional requirements of
approximately $234 million to meet sinking fund requirements for preferred stock
and maturing long-term debt during the remainder of 2003. These cash
requirements are expected to be satisfied from internal cash and short-term
credit arrangements.
On January 21, 2003, Standard and Poor's (S&P) indicated its concern
about FirstEnergy's disclosure of non-cash charges related to deferred costs in
Pennsylvania, pension and other post-retirement benefits, and Emdersa, which
were higher than anticipated in the third quarter of 2002. S&P identified the
restart of the Davis-Besse nuclear plant "...without significant delay beyond
April 2003..." as key to maintaining FirstEnergy's current debt ratings. S&P
also identified other issues it would continue to monitor including:
FirstEnergy's deleveraging efforts, free cash generated during 2003, the JCP&L
rate case, successful hedging of its short power position, and continued capture
of projected merger savings.
On April 14, 2003, S&P again affirmed its "BBB" corporate credit
rating for FirstEnergy. The S&P outlook remained negative, but S&P improved
FirstEnergy's business position from a "6" to a "5" (on a scale of 1 to 10 with
1 considered the least risky). S&P also reiterated that the key issues being
monitored by the agency included the timely restart of Davis-Besse, the JCP&L
rate case, capture of merger synergies, and controlling capital expenditures at
estimated levels. Significant delays in the planned date of Davis-Besse's return
to service or other factors (identified above) affecting the speed with which
FirstEnergy reduces debt, could put additional pressure on the credit ratings of
FirstEnergy and, correspondingly, its subsidiaries, including OE.
On August 14, 2003, Moody's Investors Service placed the debt
ratings of FirstEnergy and all of its subsidiaries under review for possible
downgrade. Moody's stated that the review was prompted by: (1) weaker than
expected operating performance and cash flow generation; (2) less progress than
expected in reducing debt; (3) continuing high leverage relative to its peer
group; and (4) negative impact on cash flow and earnings from the continuing
nuclear plant outage at Davis-Besse. Moody's further stated that, in
anticipation of Davis-Besse returning to service in the near future and
FirstEnergy's continuing to significantly reduce debt and improve its financial
profile, "Moody's does not expect that the outcome of the review will result in
FirstEnergy's senior unsecured debt rating falling below investment-grade."
55
Other Obligations
Obligations not included on OE's Consolidated Balance Sheet
primarily consist of sale and leaseback arrangements involving Perry Unit 1 and
Beaver Valley Unit 2. As of March 31, 2003, the present value of these sale and
leaseback operating lease commitments, net of trust investments, total $713
million.
EQUITY PRICE RISK
Included in OE's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $151
million and $148 million as of March 31, 2003 and December 31, 2002,
respectively. A hypothetical 10% decrease in prices quoted by stock exchanges
would result in a $15 million reduction in fair value as of March 31, 2003.
OUTLOOK
Beginning in 2001, OE's customers were able to select alternative
energy suppliers. OE continues to deliver power to residential homes and
businesses through its existing distribution system, which remains regulated.
Customer rates have been restructured into separate components to support
customer choice. In Ohio and Pennsylvania, the OE Companies have a continuing
responsibility to provide power to those customers not choosing to receive power
from an alternative energy supplier subject to certain limits. Adopting new
approaches to regulation and experiencing new forms of competition have created
new uncertainties.
Regulatory Matters
In 2001, Ohio customer rates were restructured to establish separate
charges for transmission, distribution, transition cost recovery and a
generation-related component. When one of OE's Ohio customers elects to obtain
power from an alternative supplier, OE reduces the customer's bill with a
"generation shopping credit," based on the regulated generation component (plus
an incentive), and the customer receives a generation charge from the
alternative supplier. OE has continuing PLR responsibility to its franchise
customers through December 31, 2005.
Regulatory assets are costs which have been authorized by the Public
Utilities Commission of Ohio (PUCO), Pennsylvania Public Utility Commission and
the Federal Energy Regulatory Commission, for recovery from customers in future
periods and, without such authorization, would have been charged to income when
incurred. Regulatory assets declined $162.7 million to $1.8 billion on March 31,
2003 from the balance as of December 31, 2002, with $10.6 million of the
decrease related to the cumulative entry adopting SFAS 143 at Penn and the
balance of the reduction resulting from recovery of transition plan regulatory
assets. All of the OE Companies' regulatory assets are expected to continue to
be recovered under the provisions of their respective transition plan and rate
restructuring plan. The OE Companies' regulatory assets are as follows:
REGULATORY ASSETS AS OF
---------------------------------------------------------
MARCH 31, DECEMBER 31,
Company 2003 2002
---------------------------------------------------------
(IN MILLIONS)
OE......................... $1,765.1 $1,848.7
Penn....................... 77.8 156.9
---------------------------------------------------------
Consolidated Total...... $1,842.9 $2,005.6
=========================================================
As part of OE's Ohio transition plan it is obligated to supply
electricity to customers who do not choose an alternative supplier. OE is also
required to provide 560 megawatts (MW) of low cost supply to unaffiliated
alternative suppliers that serve customers within its service area. OE's
competitive retail sales affiliate, FES, acts as an alternate supplier for a
portion of the load in its franchise area. In 2003, the total peak load
forecasted for customers electing to stay with OE, including the 560 MW of low
cost supply and the load served by OE's affiliate is 5,820 MW.
Environmental Matters
OE believes it is in compliance with the 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 in the future from OE's Ohio and
Pennsylvania facilities. Various regulatory and judicial actions have since
sought to further define NOx reduction requirements (see Note 2C - Environmental
Matters). OE continues to evaluate its compliance plans and other compliance
options.
56
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 a 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. OE cannot predict what action the EPA may take in
the future with respect to the interim enforcement policy.
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 Sammis Plant dating back to 1984. The civil
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 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 March 15, 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 they may be required, may 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.
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants. The EPA identified mercury as the hazardous air pollutant of
greatest concern. The EPA established a schedule to propose regulations by
December 2003 and issue final regulations by December 2004. The future cost of
compliance with these regulations may be substantial.
As a result of the Resource Conservation and Recovery Act of 1976,
as amended, and the Toxic Substances Control Act of 1976, federal and state
hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous waste
disposal requirements pending the EPA's evaluation of the need for future
regulation. The EPA has issued its final regulatory determination that
regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the
EPA announced that it will develop national standards regulating disposal of
coal ash under its authority to regulate nonhazardous waste.
OE believes it is in compliance with the current SO2 and nitrogen
oxides (NOx) reduction requirements under the Clean Air Act Amendments of 1990.
SO2 reductions are being achieved by burning lower-sulfur fuel, generating more
electricity from lower-emitting plants, and/or using emission allowances. NOx
reductions are being achieved through combustion controls and the generation of
more electricity at lower-emitting plants. In September 1998, the EPA finalized
regulations requiring additional NOx reductions from the Companies' Ohio and
Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions
of NOx emissions (an approximate 85% reduction in utility plant NOx emissions
from projected 2007 emissions) across a region of nineteen states and the
District of Columbia, including New Jersey, Ohio and Pennsylvania, based on a
conclusion that such NOx emissions are contributing significantly to ozone
pollution in the eastern United States. State Implementation Plans (SIP) must
comply by May 31, 2004 with individual state NOx budgets established by the EPA.
Pennsylvania submitted a SIP that requires compliance with the NOx budgets at
the Companies' Pennsylvania facilities by May 1, 2003 and Ohio submitted a SIP
that requires compliance with the NOx budgets at the Companies' Ohio facilities
by May 31, 2004. Management is unable to predict the ultimate outcome of this
matter. The potential penalties that may be imposed, as well as the capital
expenditures necessary to comply with substantive remedial measures that may be
required, may have a material adverse impact on the Company's financial
condition.
The effects of compliance on OE with regard to environmental matters
could have a material adverse effect on its earnings and competitive position.
These environmental regulations affect our earnings and competitive position to
the extent OE 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. OE believes it is in material
compliance with existing regulations, but is unable to predict how and when
applicable environmental regulations may change and what, if any, the effects of
any such change would be.
SIGNIFICANT ACCOUNTING POLICIES
OE prepares its 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 OE's financial results. All of the OE
Companies' 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
57
are similarly reviewed with their risks and uncertainties reflecting those
specific factors. The OE Companies' more significant accounting policies are
described below.
Regulatory Accounting
The OE Companies are subject to regulation that sets the prices
(rates) they are permitted to charge their customers based on the costs that the
regulatory agencies determine the OE Companies 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 Ohio
and Pennsylvania, a significant amount of regulatory assets have been recorded.
As of March 31, 2003, the OE Companies' regulatory assets totaled $1.8 billion.
OE regularly reviews 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.
Revenue Recognition
The OE Companies follow the accrual method of accounting for
revenues, recognizing revenue for kilowatt-hours that have been delivered but
not yet been billed through the end of the accounting period. The determination
of unbilled revenues requires management to make various estimates including:
- Net energy generated or purchased for retail load
- Losses of energy over distribution lines
- Allocations to distribution companies within the FirstEnergy system
- Mix of kilowatt-hour usage by residential, commercial and industrial
customers
- Kilowatt-hour usage of customers receiving electricity from
alternative suppliers
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory defined
pension benefits and postemployment benefits other than pensions (OPEB) 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 FirstEnergy makes to the plans, and earnings on plan assets.
Pension and OPEB costs may also be 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.
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.
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. Due to the significant decline in corporate
bond yields and interest rates in general during 2002, FirstEnergy reduced the
assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001.
FirstEnergy's assumed rate of return on pension plan assets
considers historical market returns and economic forecasts for the types of
investments held by its pension trusts. The market values of FirstEnergy's
pension assets have been affected by sharp declines in the equity markets since
mid-2000. In 2002 and 2001 plan assets earned (11.3)% and (5.5)%, respectively.
FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of
return on plan assets. As of December 31, 2002 the assumed return on plan assets
was reduced to 9.00% based upon FirstEnergy's projection of future returns and
pension trust investment allocation of approximately 60% large cap equities, 10%
small cap equities and 30% bonds.
Based on pension assumptions and pension plan assets as of December
31, 2002, FirstEnergy will not be required to fund its pension plans in 2003.
While OPEB plan assets have also been affected by sharp declines in the equity
market, the impact is not as significant due to the relative size of the plan
assets. However, health care cost trends
58
have significantly increased and will affect future OPEB costs. The 2003
composite health care trend rate assumption is approximately 10%-12% gradually
decreasing to 5% in later years, compared to the 2002 assumption of
approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In
determining its trend rate assumptions, FirstEnergy included the specific
provisions of its health care plans, the demographics and utilization rates of
plan participants, actual cost increases experienced in its health care plans,
and projections of future medical trend rates.
Ohio Transition Cost Amortization
In developing OE's restructuring plan, the PUCO determined allowable
transition costs based on amounts recorded on the EUOC's regulatory books. These
costs exceeded those deferred or capitalized on OE'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). OE 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, OE 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 No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," the OE Companies periodically evaluate their
long-lived assets to determine whether conditions exist that would indicate that
the carrying value of an asset may 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 other
than of a temporary nature has occurred, the OE Companies recognize a loss -
calculated as the difference between the carrying value and the estimated fair
value of the asset (discounted future net cash flows).
RECENTLY ISSUED ACCOUNTING STANDARD NOT YET IMPLEMENTED
FIN 46, "Consolidation of Variable Interest Entities - an interpretation
of ARB 51"
In January 2003, the FASB issued this interpretation of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. This Interpretation requires an enterprise to
disclose the nature of its involvement with a VIE if the enterprise has a
significant variable interest in the VIE and to consolidate a VIE if the
enterprise is the primary beneficiary. VIEs created after January 31, 2003 are
immediately subject to the provisions of FIN 46. VIEs created before February 1,
2003 are subject to this interpretation's provisions in the first interim or
annual reporting period beginning after June 15, 2003 (OE's third quarter of
2003). The FASB also identified transitional disclosure provisions for all
financial statements issued after January 31, 2003.
OE currently has transactions which may fall within the scope of
this interpretation and which are reasonably possible of meeting the definition
of a VIE in accordance with FIN 46. OE currently consolidates the majority of
these entities and believe it will continue to consolidate following the
adoption of FIN 46. In addition to the entities it is currently consolidating,
OE believes that the PNBV Capital Trust, which was used to acquire a portion of
the off-balance sheet debt issued in connection with the sale and leaseback of
its interest in the Perry Plant and Beaver Valley Unit 2, would require
consolidation as a VIE under FIN 46. Ownership of the trust includes a
three-percent equity interest by a nonaffiliated party and a three-percent
equity interest by OES Ventures, a wholly owned subsidiary of OE. Full
consolidation of the trust under FIN 46 would change the characterization of the
PNBV trust investment to a lease obligation bond investment. Also, consolidation
of the outside minority interest would be required, which would increase assets
and liabilities by $12.0 million.
59
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
-------------------------
2003 2002
---------- ----------
RESTATED RESTATED
(See Note 1) (See Note 1)
(IN THOUSANDS)
OPERATING REVENUES ................................................................. $ 419,771 $ 433,277
---------- ----------
OPERATING EXPENSES AND TAXES:
Fuel ............................................................................ 12,659 17,270
Purchased power ................................................................. 136,345 139,436
Nuclear operating costs ......................................................... 55,361 63,617
Other operating costs ........................................................... 63,009 58,047
---------- ----------
Total operation and maintenance expenses .................................... 267,374 278,370
Provision for depreciation and amortization ..................................... 51,357 52,471
General taxes ................................................................... 39,713 38,746
Income taxes .................................................................... 7,316 6,165
---------- ----------
Total operating expenses and taxes .......................................... 365,760 375,752
---------- ----------
OPERATING INCOME ................................................................... 54,011 57,525
OTHER INCOME ....................................................................... 4,741 5,241
---------- ----------
INCOME BEFORE NET INTEREST CHARGES ................................................. 58,752 62,766
---------- ----------
NET INTEREST CHARGES:
Interest on long-term debt ...................................................... 40,640 46,995
Allowance for borrowed funds used during construction ........................... (2,167) (749)
Other interest expense (credit) ................................................. 31 (529)
Subsidiary's preferred dividend requirements .................................... 4,950 2,150
---------- ----------
Net interest charges ........................................................ 43,454 47,867
---------- ----------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE ............................... 15,298 14,899
Cumulative effect of accounting change (Net of income taxes of $30,168,000) (Note 5) 42,378 --
---------- ----------
NET INCOME ......................................................................... 57,676 14,899
PREFERRED STOCK DIVIDEND REQUIREMENTS .............................................. (759) 6,556
---------- ----------
EARNINGS ATTRIBUTABLE TO COMMON STOCK .............................................. $ 58,435 $ 8,343
========== ==========
The preceding Notes to Financial Statements as they relate to The Cleveland
Electric Illuminating Company are an integral part of these statements.
60
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
MARCH 31, DECEMBER 31,
2003 2002
---------- ------------
RESTATED RESTATED
(See Note 1) (See Note 1)
(IN THOUSANDS)
ASSETS
UTILITY PLANT:
In service ............................................................ $4,114,337 $4,045,465
Less--Accumulated provision for depreciation .......................... 1,834,329 1,824,884
---------- ----------
2,280,008 2,220,581
Construction work in progress-
Electric plant ...................................................... 164,966 153,104
Nuclear fuel ........................................................ 44,406 45,354
---------- ----------
209,372 198,458
---------- ----------
2,489,380 2,419,039
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Shippingport Capital Trust ............................................ 416,836 435,907
Nuclear plant decommissioning trusts .................................. 234,855 230,527
Long-term notes receivable from associated companies .................. 102,860 102,978
Other ................................................................. 20,914 21,004
---------- ----------
775,465 790,416
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents ............................................. 826 30,382
Receivables-
Customers ........................................................... 14,184 11,317
Associated companies ................................................ 63,946 74,002
Other (less accumulated provisions of $1,015,000 for uncollectible...
accounts at both dates) ........................................... 126,322 134,375
Notes receivable from associated companies ............................ 565 447
Materials and supplies, at average cost-
Owned ............................................................... 18,356 18,293
Under consignment ................................................... 38,159 38,094
Prepayments and other ................................................. 2,445 4,217
---------- ----------
264,803 311,127
---------- ----------
DEFERRED CHARGES:
Regulatory assets ..................................................... 1,170,431 1,191,804
Goodwill .............................................................. 1,693,629 1,693,629
Property taxes ........................................................ 79,430 79,430
Other ................................................................. 25,065 24,798
---------- ----------
2,968,555 2,989,661
---------- ----------
$6,498,203 $6,510,243
========== ==========
61
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
MARCH 31, DECEMBER 31,
2003 2002
----------- ------------
RESTATED RESTATED
(See Note 1) (See Note 1)
(IN THOUSANDS)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 105,000,000 shares -
79,590,689 shares outstanding......................................... $ 981,962 $ 981,962
Accumulated other comprehensive loss.................................... (46,818) (44,284)
Retained earnings....................................................... 320,782 262,323
----------- -----------
Total common stockholder's equity................................... 1,255,926 1,200,001
Preferred stock-
Not subject to mandatory redemption..................................... 96,404 96,404
Subject to mandatory redemption......................................... 5,019 5,021
Company obligated mandatorily redeemable preferred securities of
subsidiary trust holding solely Company subordinated debentures......... 100,000 100,000
Long-term debt............................................................ 1,972,400 1,975,001
----------- -----------
3,429,749 3,376,427
----------- -----------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock...................... 343,199 388,190
Accounts payable-
Associated companies.................................................... 229,544 267,664
Other................................................................... 8,574 14,583
Notes payable to associated companies..................................... 321,828 288,583
Accrued taxes............................................................. 129,157 126,261
Accrued interest.......................................................... 60,611 51,767
Other..................................................................... 98,294 124,624
------------- ------------
1,191,207 1,261,672
----------- -----------
DEFERRED CREDITS:
Accumulated deferred income taxes......................................... 438,761 407,297
Accumulated deferred investment tax credits............................... 69,601 70,803
Nuclear plant decommissioning costs....................................... -- 242,511
Asset retirement obligation............................................... 242,599 --
Retirement benefits....................................................... 173,765 171,968
Lease market valuation liability.......................................... 773,800 788,800
Other..................................................................... 178,721 190,765
------------ ------------
1,877,247 1,872,144
----------- -----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (NOTE 2)...........................
----------- -----------
$6,498,203 $6,510,243
========== ==========
The preceding Notes to Financial Statements as they relate to The Cleveland
Electric Illuminating Company are an integral part of these balance sheets.
62
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
------------------------------
2003 2002
----------- ----------
RESTATED RESTATED
(See Note 1) (See Note 1)
(IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................................. $ 57,676 $ 14,899
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization......................... 51,357 52,471
Nuclear fuel and lease amortization................................. 5,044 5,990
Other amortization.................................................. (4,613) (3,892)
Deferred income taxes, net.......................................... 33,804 822
Investment tax credits, net......................................... (1,202) (1,043)
Receivables......................................................... 15,242 (1,484)
Materials and supplies.............................................. (128) (1,366)
Accounts payable.................................................... (44,129) 18,322
Cumulative effect of accounting change.............................. (72,547) --
Accrued taxes....................................................... 2,896 84
Accrued interest.................................................... 8,844 5,569
Prepayments and other............................................... 1,772 22,508
Deferred rents and sale/leaseback................................... (41,603) (123)
Other............................................................... (7,593) (25,235)
----------- ----------
Net cash provided from operating activities....................... 4,820 87,522
----------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net............................................ 33,245 75,484
Redemptions and Repayments-
Preferred Stock....................................................... -- (100,000)
Long-term debt........................................................ (45,103) (94)
Dividend Payments-
Preferred stock....................................................... (1,865) (5,252)
----------- ----------
Net cash used for financing activities............................ (13,723) (29,862)
----------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions...................................................... (31,218) (36,470)
Capital trust investments............................................... 19,071 --
Other................................................................... (8,506) (6,224)
----------- ----------
Net cash used for investing activities............................ (20,653) (42,694)
----------- ----------
Net increase (decrease) in cash and cash equivalents....................... (29,556) 14,966
Cash and cash equivalents at beginning of period .......................... 30,382 296
----------- ----------
Cash and cash equivalents at end of period................................. $ 826 $ 15,262
=========== ==========
The preceding Notes to Financial Statements as they relate to The Cleveland
Electric Illuminating Company are an integral part of these statements.
63
REPORT OF INDEPENDENT AUDITORS
To the Stockholders and Board of
Directors of The Cleveland
Electric Illuminating Company
We have reviewed the accompanying consolidated balance sheet of The Cleveland
Electric Illuminating Company and its subsidiaries as of March 31, 2003, and the
related consolidated statements of income and cash flows for each of the
three-month periods ended March 31, 2003 and 2002. These interim financial
statements are the responsibility of the Company's management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures and making
inquiries of persons responsible for financial and accounting matters. It is
substantially less in scope than an audit conducted in accordance with generally
accepted auditing standards, the objective of which is the expression of an
opinion regarding the financial statements taken as a whole. Accordingly, we do
not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to the accompanying consolidated interim financial statements for them
to be in conformity with accounting principles generally accepted in the United
States of America.
As discussed in Note 1 to the consolidated interim financial statements, the
Company has restated its previously issued consolidated interim financial
statements for the quarters ended March 31, 2003 and 2002.
We previously audited in accordance with auditing standards generally accepted
in the United States of America, the consolidated balance sheet and the
consolidated statement of capitalization as of December 31, 2002, and the
related consolidated statements of income, common stockholder's equity,
preferred stock, cash flows and taxes for the year then ended (not presented
herein), and in our report (which contained references to the Company's change
in its method of accounting for goodwill in 2002 as discussed in Note 1(D) to
those consolidated financial statements and the Company's restatement of its
previously issued consolidated financial statements as of December 31, 2002 and
2001 and for each of the three years in the period ended December 31, 2002 as
discussed in Note 1(M) to those consolidated financial statements) dated August
18, 2003 we expressed an unqualified opinion on those consolidated financial
statements. In our opinion, the information set forth in the accompanying
consolidated balance sheet as of December 31, 2002, is fairly stated in all
material respects in relation to the consolidated balance sheet from which it
has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
May 9, 2003, except as to Note 1, which is as of August 18, 2003
64
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
CEI is a wholly owned, electric utility subsidiary of FirstEnergy.
CEI conducts business in portions of Ohio, providing regulated electric
distribution services. CEI also provides generation services to those customers
electing to retain them as their power supplier. CEI provides power directly to
alternative energy suppliers under CEI's transition plan. CEI has unbundled the
price of electricity into its component elements -- including generation,
transmission, distribution and transition charges. Power supply requirements of
CEI are provided by FES -- an affiliated company.
RESTATEMENTS
As further discussed in Note 1 to the Consolidated Financial
Statements, FirstEnergy is restating its consolidated financial statements for
the year ended December 31, 2002 and the three months ended March 31, 2003 and
2002. The restatements reflect a change in the method of amortizing the costs
being recovered under the Ohio transition plan and recognition of above-market
values of certain leased generation facilities.
Transition Cost Amortization
As discussed in Note 4 - Regulatory Matters, FirstEnergy's Ohio
electric utilities recover transition costs, including regulatory assets,
through an approved transition plan filed under Ohio's electric utility
restructuring legislation. The plan, which was approved in July 2000, provides
for the recovery of costs from January 1, 2001 through a fixed number of
kilowatt-hour sales to all customers that continue to receive regulated
transmission and distribution service, which is expected to end in 2009 for CEI.
FirstEnergy and the Ohio utilities amortize transition costs using
the effective interest method. The amortization schedules originally developed
at the beginning of the transition plan in 2001 in applying this method were
based on total transition revenues, including revenues designed to recover costs
which have not yet been incurred or that were recognized on the regulatory
financial statements (fair value purchase accounting adjustments) but not in the
financial statements prepared under GAAP. The Ohio electric utilities have
revised their amortization schedules under the effective interest method to
consider only revenues relating to transition regulatory assets recognized on
the GAAP balance sheet. The impact of this change will result in higher
amortization of these regulatory assets in the first several years of the
transition cost recovery period, versus the method previously applied. The
change in method results in no change in total amortization of the regulatory
assets recovered under the transition period through the end of 2009. The
amortization expense under the revised method (see Note 1) increased by $24
million and $24.8 million for the three months ended June 30, 2002 and 2003,
respectively.
Above-Market Lease Costs
In 1997, FirstEnergy Corp. was formed through a merger between OE
and Centerior Energy Corp. The merger was accounted for as an acquisition of
Centerior, the parent company of CEI, under the purchase accounting rules of
Accounting Principles Board (APB) Opinion No. 16. In connection with the
reassessment of the accounting for the transition plan, FirstEnergy reassessed
its accounting for the Centerior purchase and determined that above market lease
liabilities should have been recorded at the time of the merger. Accordingly, as
of 2002, FirstEnergy recorded additional adjustments associated with the 1997
merger between OE and Centerior to reflect certain above market lease
liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant, for which
CEI had previously entered into sale-leaseback arrangements. CEI recorded an
increase in goodwill related to the above market lease costs for Beaver Valley
Unit 2 since regulatory accounting for nuclear generating assets had been
discontinued prior to the merger date and it was determined that this additional
liability would have increased goodwill at the date of the merger. The
corresponding impact of the above market lease liabilities for the Bruce
Mansfield Plant were recorded as regulatory assets because regulatory accounting
had not been discontinued at that time for the fossil generating assets and
recovery of these liabilities was provided for under the transition plan.
The total above market lease obligation of $611 million associated
with Beaver Valley Unit 2 will be amortized through the end of the lease term in
2017. The additional goodwill has been recorded on a net basis, reflecting
amortization that would have been recorded through 2001 when goodwill
amortization ceased with the adoption of SFAS 142. The total above market lease
obligation of $457 million associated with the Bruce Mansfield Plant is being
amortized through the end of 2016. Before the start of the transition plan in
2001, the regulatory asset would have been amortized at the same rate as the
lease obligation. Beginning in 2001, the remaining unamortized regulatory asset
would have been included in CEI's amortization schedule for regulatory assets
and amortized through the end of the recovery period - approximately 2009 for
CEI.
65
RESULTS OF OPERATIONS
Earnings on common stock in the first quarter of 2003 increased to
$58.4 million from income of $8.3 million in the first quarter of 2002. Earnings
on common stock in the first quarter of 2003 included an after-tax credit of
$42.4 million from the cumulative effect of an accounting change due to the
adoption of SFAS 143, "Accounting for Asset Retirement Obligations." Income
before the cumulative effect was $15.3 million in the first quarter of 2003,
compared to $14.9 million for the same period of 2002.
Operating revenues decreased by $13.5 million or 3.1% in the first
quarter of 2003 from the same period in 2002. The lower revenues resulted from
reduced kilowatt-hour sales, which were partially offset by the effects of
colder weather on distribution deliveries to residential and commercial
customers. Kilowatt-hour sales to retail customers declined by 4.3% in the first
quarter of 2003 from the same quarter of 2002, which reduced generation sales
revenue by $6.6 million. Electric generation services provided by alternative
suppliers as a percent of total sales deliveries in CEI's franchise area
increased to 37.6% in the first quarter of 2003 from 28.5% in the first quarter
of 2002.
Distribution deliveries increased 10.5% in the first quarter of 2003
compared to the corresponding quarter of 2002, with increases in all customer
sectors (residential, commercial and industrial). As a result, revenues from
electricity throughput increased by $15.5 million in the first quarter of 2003
from the same quarter of the prior year. The increase reflected higher volumes,
offset in part by lower unit prices. Distribution deliveries to residential and
commercial customers benefited from colder than normal weather, while a
substantial increase in distribution deliveries to industrial customers, despite
the continued effect of a sluggish economy, resulted from an expansion of steel
production in the franchise area.
Transition plan incentives, provided to customers to encourage
switching to alternative energy providers, reduced operating revenues -- $5.8
million in the first quarter of 2003 compared with the corresponding period of
2002. These revenue reductions are deferred for future recovery under CEI's
transition plan and do not materially affect current period earnings.
Sales revenues from wholesale customers decreased by $10.7 million
(primarily to FES) in the first quarter of 2003 compared with the first quarter
of 2002, due to reduced nuclear generation from the extended outage of the
Davis-Besse Plant (see Davis-Besse Restoration).
Changes in electric generation sales and distribution deliveries in
the first quarter of 2003 from the first quarter of 2002 are summarized in the
following table:
CHANGES IN KILOWATT-HOUR SALES
----------------------------------------------------
INCREASE (DECREASE)
Electric Generation:
Retail.................................. (4.3)%
Wholesale............................... (17.8)%
----------------------------------------------------
TOTAL ELECTRIC GENERATION SALES........... (11.3)%
====================================================
Distribution Deliveries:
Residential............................. 12.9%
Commercial.............................. 7.0%
Industrial.............................. 10.9%
----------------------------------------------------
TOTAL DISTRIBUTION DELIVERIES............. 10.5%
====================================================
Operating Expenses and Taxes
Total operating expenses and taxes decreased by $9.9 million in the
first quarter of 2003 from the first quarter of 2002. The following table
presents changes from the prior year by expense category.
OPERATING EXPENSES AND TAXES - CHANGES
---------------------------------------------------------------
INCREASE (DECREASE) (IN MILLIONS)
(REVISED)
Fuel............................................ $(4.6)
Purchased power costs........................... (3.1)
Nuclear operating costs......................... (8.3)
Other operating costs........................... 5.0
---------------------------------------------------------------
TOTAL OPERATION AND MAINTENANCE EXPENSES...... (11.0)
Provision for depreciation and amortization..... (1.1)
General taxes................................... 1.0
Income taxes.................................... 1.2
---------------------------------------------------------------
TOTAL OPERATING EXPENSES AND TAXES............ $(9.9)
===============================================================
66
Lower fuel costs in the first quarter of 2003, compared with the
first quarter of 2002 resulted from reduced nuclear generation (down 21%). The
lower purchased power costs reflected reduced unit costs offset in part by
additional kilowatt-hours purchased. Two scheduled refueling outages in the
first quarter of 2002 (Beaver Valley Unit 2 and Davis-Besse) and the absence of
refueling outages in the first quarter of 2003 more than offset incremental
costs associated with the extended outage of Davis-Besse, producing the lower
nuclear operating costs. The increase in other operating costs resulted in part
from higher employee benefit costs.
The decrease in depreciation and amortization charges in the first
quarter of 2003, compared with the first quarter of 2002 was attributable to
several factors - higher shopping incentive deferrals ($5.8 million) and lower
charges resulting from the implementation of SFAS 143 ($3.0 million), including
revised service life assumptions for generating plants ($4.0 million). Partially
offsetting these decreases were increased amortization of regulatory assets
being recovered under CEI's transition plan ($1.5 million) and recognition of
depreciation on three fossil plants ($8.1 million), which had been held pending
sale in the first quarter of 2002 but were subsequently retained by FirstEnergy
in the fourth quarter of 2002.
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $0.5
million in the first quarter of 2003 from the same quarter last year, reflecting
redemptions and refinancings since the end of the first quarter of 2002. CEI's
net debt redemptions totaled $15.0 million during the first quarter of 2003
which will result in annualized savings of $1.2 million.
Cumulative Effect of Accounting Changes
Upon adoption of SFAS 143 in the first quarter of 2003, CEI recorded
an after-tax credit to net income of $42.4 million. CEI identified applicable
legal obligations as defined under the new accounting standard for nuclear power
plant decommissioning, reclamation of a sludge disposal pond at the Bruce
Mansfield Plant, and closure of two coal ash disposal sites. As a result of
adopting SFAS 143 in January 2003, asset retirement costs of $49.9 million were
recorded as part of the carrying amount of the related long-lived asset, offset
by accumulated depreciation of $6.8 million. The asset retirement obligation
liability at the date of adoption was $238.3 million, including accumulated
accretion for the period from the date the liability was incurred to the date of
adoption. As of December 31, 2002, CEI had recorded decommissioning liabilities
of $242.5 million. The cumulative effect adjustment for unrecognized
depreciation, accretion offset by the reduction in the existing decommissioning
liabilities and ceasing the accounting practice of depreciating non-regulated
generation assets using a cost of removal component was a $72.5 million increase
to income, or $42.4 million net of income taxes.
Preferred Stock Dividend Requirements
Preferred stock dividend requirements decreased $7.3 million in the
first quarter of 2003, compared to the same period last year, principally due to
optional redemptions of preferred stock in 2002.
CAPITAL RESOURCES AND LIQUIDITY
CEI's cash requirements in 2003 for operating expenses, construction
expenditures, scheduled debt maturities and preferred stock redemptions are
expected to be met without increasing its net debt and preferred stock
outstanding. Available borrowing capacity under short-term credit facilities
will be used to manage working capital requirements. Over the next three years,
CEI expects to meet its contractual obligations with cash from operations.
Thereafter, CEI expects to use a combination of cash from operations and funds
from the capital markets.
Changes in Cash Position
As of March 31, 2003, CEI had $0.8 million of cash and cash
equivalents, compared with $30.4 million as of December 31, 2002. The major
sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Cash provided from operating activities during the first quarter of
2003, compared with the first quarter of 2002 were as follows:
67
OPERATING CASH FLOWS 2003 2002
-------------------------------------------------------------
(IN MILLIONS)
Cash earnings (1).................... $ 52 $ 50
Working capital and other............ (47) 38
-------------------------------------------------------------
Total................................ $ 5 $ 88
=============================================================
(1) Includes net income, depreciation and amortization, deferred
income taxes, investment tax credits and major noncash
charges.
Net cash provided from operating activities decreased $83 million
due to an $85 million decrease in working capital - that decrease was offset in
part by a $2 million increase in cash earnings. The largest factors contributing
to the increase in working capital and other were lower accounts payable from
associated companies in the first quarter of 2003 compared with corresponding
amounts in the first quarter of 2002 ($68 million).
Cash Flows From Financing Activities
Net cash used for financing activities declined $16 million in the
first quarter of 2003 from the first quarter of 2002. The decrease in funds used
for financing activities primarily reflected lower security redemptions and
repayments, which were partially offset by a net reduction in short-term
borrowings.
CEI had about $1.4 million of cash and temporary investments and
approximately $321.8 million of short-term indebtedness as of March 31, 2003.
CEI had the capability to issue $545.5 million of additional first mortgage
bonds on the basis of property additions and retired bonds. CEI has no
restrictions on the issuance of preferred stock.
Cash Flows From Investing Activities
Net cash used for investing activities decreased $22 million in the
first quarter of 2003 from the same quarter of 2002 due to a reduction in the
Shippingport Capital Trust investment and lower capital expenditures.
During the last three quarters of 2003, capital requirements for
property additions and capital leases are expected to be about $85 million,
including $9 million for nuclear fuel. CEI has additional requirements of
approximately $101 million to meet sinking fund requirements for preferred stock
and maturing long-term debt during the remainder of 2003. These cash
requirements are expected to be satisfied from internal cash and short-term
credit arrangements.
On January 21, 2003, Standard and Poor's (S&P) indicated its concern
about FirstEnergy's disclosure of non-cash charges related to deferred costs in
Pennsylvania, pension and other post-retirement benefits, and Emdersa, which
were higher than anticipated in the third quarter of 2002. S&P identified the
restart of the Davis-Besse nuclear plant "...without significant delay beyond
April 2003..." as key to maintaining FirstEnergy's current debt ratings. S&P
also identified other issues it would continue to monitor including:
FirstEnergy's deleveraging efforts, free cash generated during 2003, the JCP&L
rate case, successful hedging of its short power position, and continued capture
of projected merger savings.
On April 14, 2003, S&P again affirmed its "BBB" corporate credit
rating for FirstEnergy. The S&P outlook remained negative, but S&P improved
FirstEnergy's business position from a "6" to a "5" (on a scale of 1 to 10 with
1 considered the least risky). S&P also reiterated that the key issues being
monitored by the agency included the timely restart of Davis-Besse, the JCP&L
rate case, capture of merger synergies, and controlling capital expenditures at
estimated levels. Significant delays in the planned date of Davis-Besse's return
to service or other factors (identified above) affecting the speed with which
FirstEnergy reduces debt, could put additional pressure on the credit ratings of
FirstEnergy and, correspondingly, its subsidiaries, including CEI.
On August 14, 2003, Moody's Investors Service placed the debt
ratings of FirstEnergy and all of its subsidiaries under review for possible
downgrade. Moody's stated that the review was prompted by: (1) weaker than
expected operating performance and cash flow generation; (2) less progress than
expected in reducing debt; (3) continuing high leverage relative to its peer
group; and (4) negative impact on cash flow and earnings from the continuing
nuclear plant outage at Davis-Besse. Moody's further stated that, in
anticipation of Davis-Besse returning to service in the near future and
FirstEnergy's continuing to significantly reduce debt and improve its financial
profile, "Moody's does not expect that the outcome of the review will result in
FirstEnergy's senior unsecured debt rating falling below investment-grade."
68
Other Obligations
Obligations not included on CEI's Consolidated Balance Sheet
primarily consist of sale and leaseback arrangements involving the Bruce
Mansfield Plant. As of March 31, 2003, the present value of these sale and
leaseback operating lease commitments, net of trust investments, total $157
million. CEI sells substantially all of its retail customer receivables, which
provided $96 million of off-balance sheet financing as of March 31, 2003.
EQUITY PRICE RISK
Included in CEI's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $117
million and $119 million as of March 31, 2003 and December 31, 2002,
respectively. A hypothetical 10% decrease in prices quoted by stock exchanges
would result in a $12 million reduction in fair value as of March 31, 2003.
OUTLOOK
Beginning in 2001, CEI's customers were able to select alternative
energy suppliers. CEI continues to deliver power to residential homes and
businesses through its existing distribution systems, which remain regulated.
Customer rates have been restructured into separate components to support
customer choice. In Ohio CEI has a continuing responsibility to provide power to
those customers not choosing to receive power from an alternative energy
supplier subject to certain limits. Adopting new approaches to regulation and
experiencing new forms of competition have created new uncertainties.
Regulatory Matters
In 2001, Ohio customer rates were restructured to establish separate
charges for transmission, distribution, transition cost recovery and a
generation-related component. When one of CEI's customers elects to obtain power
from an alternative supplier, CEI reduces the customer's bill with a "generation
shopping credit," based on the regulated generation component (plus an
incentive), and the customer receives a generation charge from the alternative
supplier. CEI has continuing PLR responsibility to its franchise customers
through December 31, 2005.
Regulatory assets are costs which have been authorized by the PUCO
and the Federal Energy Regulatory Commission for recovery from customers in
future periods and, without such authorization, would have been charged to
income when incurred. Regulatory assets decreased $21.4 million to $1,170.4
million as of March 31, 2003 from the balance as of December 31, 2002. All of
CEI's regulatory assets are expected to continue to be recovered under the
provisions of its transition plan.
As part of CEI's Ohio transition plan it is obligated to supply
electricity to customers who do not choose an alternative supplier. CEI is also
required to provide 400 megawatts (MW) of low cost supply to unaffiliated
alternative suppliers that serve customers within its service area. CEI's
competitive retail sales affiliate, FES, acts as an alternate supplier for a
portion of the load in its franchise area.
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 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, FirstEnergy has
made significant management and human performance changes with the intent of
establishing the proper safety culture throughout the workforce. Work was
completed on the reactor head during 2002 and is continuing on efforts designed
to enhance the unit's reliability and performance. FirstEnergy is also
accelerating maintenance work that had been planned for future refueling and
maintenance outages. At a meeting with the NRC in November 2002, FirstEnergy
discussed plans to test the bottom of the reactor for leaks and to install a
state-of-the-art leak-detection system around the reactor. The additional
maintenance work being performed has expanded the previous estimates of
restoration work. FirstEnergy anticipates that the unit will be ready for
restart in the first half of the summer of 2003. The NRC must authorize restart
of the plant following its formal inspection process before the unit can be
returned to service. While the additional maintenance work has delayed
FirstEnergy's plans to reduce debt levels FirstEnergy believes such investments
in the unit's future safety, reliability and performance to be essential.
Significant delays in Davis-Besse's return to service, which depends on the
successful resolution of the management and technical
69
issues as well as NRC approval, could trigger an evaluation for impairment of
the nuclear plant (see Significant Accounting Policies below).
Incremental expenses associated with the extended Davis-Besse outage
in the first quarter of 2003 totaled $88.6 million, including $36.3 million for
maintenance work and $52.3 million for fuel and purchased power. CEI's ownership
share is 51.38% of those expenses. It is anticipated that an additional $13.7
million in maintenance costs will be spent during the remainder of the
Davis-Besse outage. Replacement power costs are expected to be $15 million per
month in the non-summer months and $20-25 million per month during the summer.
Environmental Matters
CEI believes it is in compliance with the 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 in the future from its
generating facilities. Various regulatory and judicial actions have since sought
to further define NOx reduction requirements (see Note 2 - Environmental
Matters). CEI continues to evaluate its compliance plans and other compliance
options.
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 a 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. CEI cannot predict what action the EPA may take in
the future with respect to the interim enforcement policy.
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants. The EPA identified mercury as the hazardous air pollutant of
greatest concern. The EPA established a schedule to propose regulations by
December 2003 and issue final regulations by December 2004. The future cost of
compliance with these regulations may be substantial.
As a result of the Resource Conservation and Recovery Act of 1976,
as amended, and the Toxic Substances Control Act of 1976, federal and state
hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous waste
disposal requirements pending the EPA's evaluation of the need for future
regulation. The EPA has issued its final regulatory determination that
regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the
EPA announced that it will develop national standards regulating disposal of
coal ash under its authority to regulate nonhazardous waste.
CEI has been named as a "potentially responsible party" (PRP) at
waste disposal sites which may require cleanup under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980. Allegations of
disposal of hazardous substances at historical sites and the liability involved
are often unsubstantiated and subject to dispute; however, federal law provides
that all PRPs for a particular site be held liable on a joint and several basis.
Therefore, potential environmental liabilities have been recognized on the
Consolidated Balance Sheet as of March 31, 2003, based on estimates of the total
costs of cleanup, CEI's proportionate responsibility for such costs and the
financial ability of other nonaffiliated entities to pay. CEI's total accrued
liabilities were approximately $2.5 million as of March 31, 2003.
The effects of compliance on CEI with regard to environmental
matters could have a material adverse effect on its earnings and competitive
position. These environmental regulations affect its earnings and competitive
position to the extent CEI 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. CEI believes it is in
material compliance with existing regulations, but is unable to predict how and
when applicable environmental regulations may change and what, if any, the
effects of any such change would be.
Legal Matters
Various lawsuits, claims and proceedings related to CEI's normal
business operations are pending against CEI, the most significant of which are
described above.
SIGNIFICANT ACCOUNTING POLICIES
CEI prepares its 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 CEI's financial results. All of CEI's
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 those specific factors. CEI's more significant
accounting policies are described below.
70
Regulatory Accounting
CEI is subject to regulation that sets the prices (rates) it is
permitted to charge its customers based on the costs that the regulatory
agencies determine CEI is 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 Ohio a significant amount of
regulatory assets have been recorded. As of March 31, 2003, CEI's regulatory
assets totaled $1,170.4 million. CEI regularly reviews 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.
Revenue Recognition
CEI follows the accrual method of accounting for revenues,
recognizing revenue for kilowatt-hours that have been delivered but not yet been
billed through the end of the accounting period. The determination of unbilled
revenues requires management to make various estimates including:
- Net energy generated or purchased for retail load
- Losses of energy over distribution lines
- Allocations to distribution companies within the FirstEnergy system
- Mix of kilowatt-hour usage by residential, commercial and industrial
customers
- Kilowatt-hour usage of customers receiving electricity from
alternative suppliers
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory defined
pension benefits and postemployment benefits other than pensions (OPEB) 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 FirstEnergy makes to the plans, and earnings on plan assets.
Pension and OPEB costs may also be 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.
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.
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. Due to the significant decline in corporate
bond yields and interest rates in general during 2002, FirstEnergy reduced the
assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001.
FirstEnergy's assumed rate of return on pension plan assets considers historical
market returns and economic forecasts for the types of investments held by its
pension trusts. The market values of FirstEnergy's pension assets have been
affected by sharp declines in the equity markets since mid-2000. In 2002 and
2001, plan assets earned (11.3)% and (5.5)%, respectively. FirstEnergy's pension
costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As
of December 31, 2002 the assumed return on plan assets was reduced to 9.00%
based upon FirstEnergy's projection of future returns and pension trust
investment allocation of approximately 60% large cap equities, 10% small cap
equities and 30% bonds.
Based on pension assumptions and pension plan assets as of December
31, 2002, FirstEnergy will not be required to fund its pension plans in 2003.
While OPEB plan assets have also been affected by sharp declines in the equity
market, the impact is not as significant due to the relative size of the plan
assets. However, health care cost trends have significantly increased and will
affect future OPEB costs. The 2003 composite health care trend rate assumption
is approximately 10%-12% gradually decreasing to 5% in later years, compared to
FirstEnergy's 2002 assumption of approximately 10% in 2002, gradually decreasing
to 4%-6% in later years. In determining its trend rate assumptions,
71
FirstEnergy included the specific provisions of its health care plans, the
demographics and utilization rates of plan participants, actual cost increases
experienced in its health care plans, and projections of future medical trend
rates.
Ohio Transition Cost Amortization
In developing CEI's restructuring plan, the PUCO determined
allowable transition costs based on amounts recorded on the EUOC's regulatory
books. These costs exceeded those deferred or capitalized on CEI'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). CEI 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, CEI 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 No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," CEI periodically evaluates its long-lived assets
to determine whether conditions exist that would indicate that the carrying
value of an asset may 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, other than of a temporary
nature, has occurred, CEI recognizes a loss - calculated as the difference
between the carrying value and the estimated fair value of the asset (discounted
future net cash flows).
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, CEI
evaluates its 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, an impairment for goodwill
must be recognized in the financial statements. If impairment were to occur, CEI
would 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.
CEI's annual review was completed in the third quarter of 2002. The results of
that review indicated no impairment of goodwill. The forecasts used in CEI's
evaluations of goodwill reflect operations consistent with its general business
assumptions. Unanticipated changes in those assumptions could have a significant
effect on its future evaluations of goodwill. As of March 31, 2003, CEI had
approximately $1.7 billion of goodwill.
RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET IMPLEMENTED
FIN 46, "Consolidation of Variable Interest Entities - an interpretation
of ARB 51"
In January 2003, the FASB issued this interpretation of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. This Interpretation requires an enterprise to
disclose the nature of its involvement with a VIE if the enterprise has a
significant variable interest in the VIE and to consolidate a VIE if the
enterprise is the primary beneficiary. VIEs created after January 31, 2003 are
immediately subject to the provisions of FIN 46. VIEs created before February 1,
2003 are subject to this interpretation's provisions in the first interim or
annual reporting period beginning after June 15, 2003 (CEI's third quarter of
2003). The FASB also identified transitional disclosure provisions for all
financial statements issued after January 31, 2003.
CEI currently has transactions which may fall within the scope of
this interpretation and which are reasonably possible of meeting the definition
of a VIE in accordance with FIN 46. CEI currently consolidates the majority of
these entities and believes it will continue to consolidate following the
adoption of FIN 46. One of these entities CEI is currently consolidating is the
Shippingport Capital Trust which reacquired a portion of the off-balance sheet
debt issued in connection with the sale and leaseback of its interest in the
Bruce Mansfield Plant. Ownership of the trust includes a 4.85 percent interest
by nonaffiliated parties and a 0.34 percent equity interest by Toledo Edison
Capital Corp., an affiliated company.
72
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
-------------------------
2003 2002
---------- ----------
RESTATED RESTATED
(SEE NOTE 1) (SEE NOTE 1)
---------- ----------
(IN THOUSANDS)
OPERATING REVENUES ................................................................. $ 231,822 $ 252,567
---------- ----------
OPERATING EXPENSES AND TAXES:
Fuel ............................................................................ 7,681 11,391
Purchased power ................................................................. 74,251 82,404
Nuclear operating costs ......................................................... 64,555 73,673
Other operating costs ........................................................... 34,037 27,184
---------- ----------
Total operation and maintenance expenses .................................... 180,524 194,652
Provision for depreciation and amortization ..................................... 35,640 37,768
General taxes ................................................................... 15,008 13,748
Income taxes (benefit) .......................................................... (4,827) (4,289)
---------- ----------
Total operating expenses and taxes .......................................... 226,345 241,879
---------- ----------
OPERATING INCOME ................................................................... 5,477 10,688
OTHER INCOME ....................................................................... 3,100 4,343
---------- ----------
INCOME BEFORE NET INTEREST CHARGES ................................................. 8,577 15,031
---------- ----------
NET INTEREST CHARGES:
Interest on long-term debt ...................................................... 11,815 15,872
Allowance for borrowed funds used during construction ........................... (1,306) (428)
Other interest expense (credit) ................................................. (532) (735)
---------- ----------
Net interest charges ........................................................ 9,977 14,709
---------- ----------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE ........................ (1,400) 322
Cumulative effect of accounting change (net of income taxes of $18,201,000) (Note 5) 25,550 --
---------- ----------
NET INCOME ......................................................................... 24,150 322
PREFERRED STOCK DIVIDEND REQUIREMENTS .............................................. 2,205 4,724
---------- ----------
EARNINGS (LOSS) ATTRIBUTABLE TO COMMON STOCK ....................................... $ 21,945 $ (4,402)
========== ==========
The preceding Notes to Financial Statements as they relate to The Toledo Edison
Company are an integral part of these statements.
73
THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
MARCH 31, DECEMBER 31,
2003 2002
------------- -------------
RESTATED RESTATED
(SEE NOTE 1) (SEE NOTE 1)
------------- -------------
(IN THOUSANDS)
ASSETS
UTILITY PLANT:
In service................................................................ $ 1,655,389 $ 1,600,860
Less--Accumulated provision for depreciation.............................. 723,821 706,772
------------- -------------
931,568 894,088
------------- -------------
Construction work in progress-
Electric plant.......................................................... 110,267 104,091
Nuclear fuel............................................................ 30,464 33,650
------------- -------------
140,731 137,741
------------- -------------
1,072,299 1,031,829
------------- -------------
OTHER PROPERTY AND INVESTMENTS:
Shippingport Capital Trust................................................ 223,335 240,963
Nuclear plant decommissioning trusts...................................... 179,511 174,514
Long-term notes receivable from associated companies...................... 162,109 162,159
Other..................................................................... 2,172 2,236
------------- -------------
567,127 579,872
------------- -------------
CURRENT ASSETS:
Cash and cash equivalents................................................. 1,445 20,688
Receivables-
Customers............................................................... 5,640 4,711
Associated companies.................................................... 44,275 55,245
Other................................................................... 4,570 6,778
Notes receivable from associated companies................................ 6,452 1,957
Materials and supplies, at average cost-
Owned................................................................... 13,768 13,631
Under consignment....................................................... 23,587 22,997
Prepayments and other..................................................... 8,576 3,455
------------- -------------
108,313 129,462
------------- -------------
DEFERRED CHARGES:
Regulatory assets......................................................... 557,420 578,243
Goodwill.................................................................. 504,522 504,522
Property taxes............................................................ 23,429 23,429
Other..................................................................... 14,641 14,257
------------- -------------
1,100,012 1,120,451
------------- -------------
$ 2,847,751 $ 2,861,614
============= =============
74
THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
MARCH 31, DECEMBER 31,
2003 2002
------------- ------------
RESTATED RESTATED
(SEE NOTE 1) (SEE NOTE 1)
------------- ------------
(IN THOUSANDS)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity-
Common stock, $5 par value, authorized 60,000,000 shares -
39,133,887 shares outstanding......................................... $ 195,670 $ 195,670
Other paid-in capital................................................... 428,559 428,559
Accumulated other comprehensive loss.................................... (20,535) (20,012)
Retained earnings....................................................... 100,723 78,778
------------- ------------
Total common stockholder's equity................................... 704,417 682,995
Preferred stock not subject to mandatory redemption....................... 126,000 126,000
Long-term debt............................................................ 556,080 557,265
------------- ------------
1,386,497 1,366,260
------------- ------------
CURRENT LIABILITIES:
Currently payable long-term debt.......................................... 115,755 189,355
Accounts payable-
Associated companies.................................................... 120,483 171,862
Other................................................................... 6,100 9,338
Notes payable to associated companies..................................... 248,045 149,653
Accrued taxes............................................................. 40,712 34,676
Accrued interest.......................................................... 14,978 16,377
Other..................................................................... 77,616 82,062
------------- ------------
623,689 653,323
------------- ------------
DEFERRED CREDITS:
Accumulated deferred income taxes......................................... 178,254 158,279
Accumulated deferred investment tax credits............................... 26,941 27,455
Nuclear plant decommissioning costs....................................... -- 179,587
Asset retirement obligation............................................... 166,858 --
Retirement benefits....................................................... 83,324 82,553
Lease market valuation liability.......................................... 311,050 317,200
Other..................................................................... 71,138 76,957
------------- ------------
837,565 842,031
------------- ------------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)...........................
------------- ------------
$ 2,847,751 $ 2,861,614
============= ============
The preceding Notes to Financial Statements as they relate to The Toledo Edison
Company are an integral part of these balance sheets.
75
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
------------------------------
2003 2002
------------ ------------
RESTATED RESTATED
(SEE NOTE 1) (SEE NOTE 1)
------------ ------------
(IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income...................................................................... $ 24,150 $ 322
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization.............................. 35,640 37,768
Nuclear fuel and lease amortization...................................... 2,768 3,573
Deferred income taxes, net............................................... 19,130 1,242
Investment tax credits, net.............................................. (514) (526)
Receivables.............................................................. 12,249 11,622
Materials and supplies................................................... (727) (651)
Accounts payable......................................................... (53,917) 1,161
Cumulative effect of accounting change................................... (43,751) --
Accrued taxes............................................................ 5,745 (5,710)
Accrued interest......................................................... (1,399) (2,030)
Prepayments and other.................................................... (5,121) 9,987
Deferred rents and sale/leaseback........................................ (7,672) 18,728
Other.................................................................... (16,532) (9,721)
--------- ---------
Net cash provided from (used for) operating activities................. (29,951) 65,765
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net................................................. 98,392 68,998
Redemptions and Repayments-
Preferred stock............................................................ -- (85,299)
Long-term debt............................................................. (73,600) (94)
Dividend Payments-
Common stock............................................................... -- (5,600)
Preferred stock............................................................ (2,211) (3,425)
--------- ---------
Net cash provided from (used for) financing activities................. 22,581 (25,420)
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions........................................................... (17,242) (25,559)
Loans to associated companies................................................ (4,445) (6,301)
Capital trust investments.................................................... 17,628 (57)
Other........................................................................ (7,814) (6,121)
--------- ---------
Net cash provided from (used for) investing activities................. (11,873) (38,038)
--------- ---------
Net increase (decrease) in cash and cash equivalents............................ (19,243) 2,307
Cash and cash equivalents at beginning of period................................ 20,688 302
--------- ---------
Cash and cash equivalents at end of period...................................... $ 1,445 $ 2,609
========= =========
The preceding Notes to Financial Statements as they relate to The Toledo Edison
Company are an integral part of these statements.
76
REPORT OF INDEPENDENT AUDITORS
To the Stockholders and Board
of Directors of The Toledo
Edison Company:
We have reviewed the accompanying consolidated balance sheet of The Toledo
Edison Company and its subsidiary as of March 31, 2003, and the related
consolidated statements of income and cash flows for each of the three-month
periods ended March 31, 2003 and 2002. These interim financial statements are
the responsibility of the Company's management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures and making
inquiries of persons responsible for financial and accounting matters. It is
substantially less in scope than an audit conducted in accordance with generally
accepted auditing standards, the objective of which is the expression of an
opinion regarding the financial statements taken as a whole. Accordingly, we do
not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to the accompanying consolidated interim financial statements for them
to be in conformity with accounting principles generally accepted in the United
States of America.
As discussed in Note 1 to the consolidated interim financial statements, the
Company has restated its previously issued consolidated interim financial
statements for the quarters ended March 31, 2003 and 2002.
We previously audited in accordance with auditing standards generally accepted
in the United States of America, the consolidated balance sheet and the
consolidated statement of capitalization as of December 31, 2002, and the
related consolidated statements of income, common stockholder's equity,
preferred stock, cash flows and taxes for the year then ended (not presented
herein), and in our report (which contained references to the Company's change
in its method of accounting for goodwill in 2002 as discussed in Note 1(D) to
those consolidated financial statements and the Company's restatement of its
previously issued consolidated financial statements as of December 31, 2002 and
2001 and for each of the three years in the period ended December 31, 2002 as
discussed in Note 1(M) to those consolidated financial statements) dated August
18, 2003 we expressed an unqualified opinion on those consolidated financial
statements. In our opinion, the information set forth in the accompanying
consolidated balance sheet as of December 31, 2002, is fairly stated in all
material respects in relation to the consolidated balance sheet from which it
has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
May 9, 2003, except as to Note 1, which is as of August 18, 2003
77
THE TOLEDO EDISON COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
TE is a wholly owned, electric utility subsidiary of FirstEnergy. TE
conducts business in portions of Ohio, providing regulated electric distribution
services. TE also provides generation services to those customers electing to
retain them as their power supplier. TE provides power directly to wholesale
customers under previously negotiated contracts, as well as to alternative
energy suppliers under TE's transition plan. TE has unbundled the price of
electricity into its component elements - including generation, transmission,
distribution and transition charges. Power supply requirements of TE are
provided by FES - an affiliated company.
RESTATEMENTS
As further discussed in Note 1 to the Consolidated Financial
Statements, FirstEnergy is restating its consolidated financial statements for
the year ended December 31, 2002 and the three months ended March 31, 2003 and
2002. The restatements reflect a change in the method of amortizing the costs
being recovered under the Ohio transition plan and recognition of above-market
values of certain leased generation facilities.
Transition Cost Amortization
As discussed in Note 4 - Regulatory Matters, FirstEnergy's Ohio
electric utilities recover transition costs, including regulatory assets,
through an approved transition plan filed under Ohio's electric utility
restructuring legislation. The plan, which was approved in July 2000, provides
for the recovery of costs from January 1, 2001 through a fixed number of
kilowatt-hour sales to all customers that continue to receive regulated
transmission and distribution service, which is expected to end in 2007 for TE.
FirstEnergy and the Ohio utilities amortize transition costs using
the effective interest method. The amortization schedules originally developed
at the beginning of the transition plan in 2001 in applying this method were
based on total transition revenues, including revenues designed to recover costs
which have not yet been incurred or that were recognized on the regulatory
financial statements (fair value purchase accounting adjustments) but not in the
financial statements prepared under GAAP. The Ohio electric utilities have
revised their amortization schedules under the effective interest method to
consider only revenues relating to transition regulatory assets recognized on
the GAAP balance sheet. The impact of this change will result in higher
amortization of these regulatory assets in the first several years of the
transition cost recovery period, versus the method previously applied. The
change in method results in no change in total amortization of the regulatory
assets recovered under the transition period through the end of 2009. The
amortization expense under the revised method (see Note 1) increased by $16.4
million and $15.4 million for the three months ended June 30, 2002 and 2003,
respectively.
Above-Market Lease Costs
In 1997, FirstEnergy Corp. was formed through a merger between OE
and Centerior Energy Corp. The merger was accounted for as an acquisition of
Centerior, the parent company of TE, under the purchase accounting rules of
Accounting Principles Board (APB) Opinion No. 16. In connection with the
reassessment of the accounting for the transition plan, FirstEnergy reassessed
its accounting for the Centerior purchase and determined that above market lease
liabilities should have been recorded at the time of the merger. Accordingly, as
of 2002, FirstEnergy recorded additional adjustments associated with the 1997
merger between OE and Centerior to reflect certain above market lease
liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant, for which TE
had previously entered into sale-leaseback arrangements. and TE recorded an
increase in goodwill related to the above market lease costs for Beaver Valley
Unit 2 since regulatory accounting for nuclear generating assets had been
discontinued prior to the merger date and it was determined that this additional
liability would have increased goodwill at the date of the merger. The
corresponding impact of the above market lease liabilities for the Bruce
Mansfield Plant were recorded as regulatory assets because regulatory accounting
had not been discontinued at that time for the fossil generating assets and
recovery of these liabilities was provided for under the transition plan.
The total above market lease obligation of $111 million associated
with Beaver Valley Unit 2 will be amortized through the end of the lease term in
2017. The additional goodwill has been recorded on a net basis, reflecting
amortization that would have been recorded through 2001 when goodwill
amortization ceased with the adoption of SFAS 142. The total above market lease
obligation of $298 million associated with the Bruce Mansfield Plant is being
amortized through the end of 2016. Before the start of the transition plan in
2001, the regulatory asset would have been amortized at the same rate as the
lease obligation. Beginning in 2001, the remaining unamortized regulatory asset
would have been included in TE's amortization schedule for regulatory assets and
amortized through the end of the recovery period - approximately 2007 for TE.
78
RESULTS OF OPERATIONS
Earnings on common stock in the first quarter of 2003 increased to
$21.9 million from a loss of $4.4 million in the first quarter of 2002. Earnings
on common stock in the first quarter of 2003 included an after-tax credit of
$25.6 million from the cumulative effect of an accounting change due to the
adoption of SFAS 143, "Accounting for Asset Retirement Obligations." Loss before
the cumulative effect was $1.4 million in the first quarter of 2003, compared to
net income of $0.3 million for the same period of 2002. Improved results in
the first quarter of 2003 reflected reduced financing costs and lower operating
expenses. Substantially offsetting these improvements were lower operating
revenues from reduced kilowatt-hour sales.
Operating revenues decreased by $20.7 million or 8.2% in the first
quarter of 2003 from the same period in 2002. The lower revenues resulted from
reduced kilowatt-hour sales which were partially offset by the effects of colder
weather on distribution deliveries to residential and commercial customers.
Kilowatt-hour sales to retail customers declined by 3.5% in the first quarter of
2003 from the same quarter of 2002, which reduced generation sales revenue by
$11.6 million. Electric generation services provided by alternative suppliers as
a percent of total sales deliveries in TE's franchise area increased to 21.8% in
the first quarter of 2003 from 14.4% in the first quarter of 2002.
Distribution deliveries increased 5.8% in the first quarter of 2003
compared to the corresponding quarter of 2002, with increases in all customer
sectors (residential, commercial and industrial). As a result, revenues from
electricity throughput increased by $20.7 million in the first quarter of 2003
from the first quarter of 2002. The increase reflected higher unit prices, which
accounted for two-thirds of the increase and higher volumes. Distribution
deliveries benefited from substantially higher residential and commercial
demand, due in larger part to colder than normal weather, that was moderated by
the continued effect of a sluggish economy and its impact on demand by
industrial customers in TE's franchise area.
Transition plan incentives, provided to customers to encourage
switching to alternative energy providers, reduced operating revenues by $2.2
million in the first quarter of 2003 compared with the same period last year.
These revenue reductions are deferred for future recovery under TE's transition
plan and do not materially affect current period earnings.
Sales revenues from wholesale customers decreased by $21.0 million
(primarily to FES) in the first quarter of 2003 compared with the first quarter
of 2002, due to reduced nuclear generation from the extended outage of the
Davis-Besse Plant (see Davis-Besse Restoration).
Changes in electric generation sales and distribution deliveries in
the first quarter of 2003 from the first quarter of 2002 are summarized in the
following table:
CHANGES IN KILOWATT-HOUR SALES
----------------------------------------------------
INCREASE (DECREASE)
Electric Generation:
Retail................................ (3.5)%
Wholesale............................. (28.1)%
----------------------------------------------------
TOTAL ELECTRIC GENERATION SALES........... (15.2)%
====================================================
Distribution Deliveries:
Residential........................... 10.9%
Commercial............................ 11.7%
Industrial............................ 0.3%
----------------------------------------------------
TOTAL DISTRIBUTION DELIVERIES............. 5.8%
====================================================
79
Operating Expenses and Taxes
Total operating expenses and taxes decreased by $15.5 million in the
first quarter of 2003 from the first quarter of 2002. The following table
presents changes from the prior year by expense category.
OPERATING EXPENSES AND TAXES - CHANGES
---------------------------------------------------------------
INCREASE (DECREASE ) (IN MILLIONS)
(REVISED)
Fuel............................................. $ (3.7)
Purchased power costs............................ (8.2)
Nuclear operating costs.......................... (9.1)
Other operating costs............................ 6.9
---------------------------------------------------------------
TOTAL OPERATION AND MAINTENANCE EXPENSES....... (14.1)
Provision for depreciation and amortization...... (2.2)
General taxes.................................... 1.3
Income taxes..................................... (0.5)
---------------------------------------------------------------
TOTAL OPERATING EXPENSES AND TAXES............. $(15.5)
===============================================================
Lower fuel costs in the first quarter of 2003, compared with the
same quarter of 2002, resulted from reduced nuclear generation (down 30%). The
lower purchased power costs reflected fewer kilowatt-hours required for customer
needs. Two scheduled refueling outages in the first quarter of 2002 (Beaver
Valley Unit 2 and Davis-Besse) and the absence of refueling outages in the first
quarter of 2003 more than offset incremental costs associated with the extended
outage of Davis-Besse, producing the lower nuclear operating costs. The increase
in other operating costs resulted in part from higher employee benefit costs.
Charges for depreciation and amortization decreased $2.2 million in
the first quarter of 2003 compared with the first quarter of 2002, attributable
to several factors - higher shopping incentive deferrals ($2.2 million) and
lower charges resulting from the implementation of SFAS 143 ($4.0 million),
including revised service life assumptions for generating plants ($3.0 million).
Nearly offsetting these decreases were increased amortization of regulatory
assets being recovered under TE's transition plan ($2.5 million) and recognition
of depreciation on the Bay Shore generating plant ($1.5 million), which had been
held pending sale in the first quarter of 2002 but was subsequently retained by
FirstEnergy in the fourth quarter of 2002.
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $4.7
million in the first quarter of 2003 from the same period last year, reflecting
security redemptions and refinancings since the end of the first quarter of
2002. TE's net debt redemptions totaled $53.4 million during the first quarter
of 2003, which will result in annualized savings of $4.2 million.
Cumulative Effect of Accounting Change
Upon adoption of SFAS 143 in the first quarter of 2003, TE recorded
an after-tax credit to net income of $25.6 million. TE identified applicable
legal obligations as defined under the new accounting standard for nuclear power
plant decommissioning and reclamation of a sludge disposal pond at the Bruce
Mansfield Plant. As a result of adopting SFAS 143 in January 2003, asset
retirement costs of $41.1 million were recorded as part of the carrying amount
of the related long-lived asset, offset by accumulated depreciation of $5.5
million. The asset retirement obligation liability at the date of adoption was
$172 million, including accumulated accretion for the period from the date the
liability was incurred to the date of adoption. As of December 31, 2002, TE had
recorded decommissioning liabilities of $179.6 million. The cumulative effect
adjustment for unrecognized depreciation, accretion offset by the reduction in
the existing decommissioning liabilities and ceasing the accounting practice of
depreciating non-regulated generation assets using a cost of removal component
was a $43.8 million increase to income, or $25.6 million net of income taxes.
CAPITAL RESOURCES AND LIQUIDITY
TE's cash requirements in 2003 for operating expenses, construction
expenditures, scheduled debt maturities and preferred stock redemptions are
expected to be met without increasing its net debt and preferred stock
outstanding. Available borrowing capacity under short-term credit facilities
will be used to manage working capital requirements. Over the next three years,
TE expects to meet its contractual obligations with cash from operations.
Thereafter, TE expects to use a combination of cash from operations and funds
from the capital markets.
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Changes in Cash Position
As of March 31, 2003, TE had $1.4 million of cash and cash
equivalents, compared with $20.7 million as of December 31, 2002. The major
sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Cash provided by (used for) operating activities during the first
quarter of 2003, compared with the corresponding period in 2002 were as follows:
OPERATING CASH FLOWS 2003 2002
-------------------------------------------------------------
(IN MILLIONS)
Cash earnings (1).................... $ 30 $ 29
Working capital and other............ (60) 37
-------------------------------------------------------------
Total................................ $(30) $ 66
=============================================================
(1) Includes net income, depreciation and amortization, deferred
income taxes, investment tax credits and major noncash
charges.
Net cash used for operating activities was $30 million in the first
quarter of 2003, a $96 million change from the $66 million provided by operating
activities in the first quarter of 2002. The decrease in funds from operating
activities resulted from a $97 million decrease in working capital - principally
reduced accounts payable (primarily to associated companies) which contributed
$56.8 million to the decrease in working capital requirements.
Cash Flows From Financing Activities
In the first quarter of 2003, net cash provided from financing
activities increased to $23 million from net cash used for financing of $25
million in the first quarter of 2002. The increase in cash provided from
financing activities primarily resulted from additional short-term borrowings
from associated companies and a slight reduction in security redemptions and
repayments.
TE had approximately $7.9 million of cash and temporary investments
and approximately $248 million of short-term indebtedness as of March 31, 2003.
TE is currently precluded from issuing first mortgage bonds or preferred stock
based upon applicable earnings coverage tests as of March 31, 2003.
Cash Flows From Investing Activities
Net cash used for investing activities decreased $26 million between
the first quarter of 2003 and the same quarter of 2002 due to reduced capital
expenditures and a reduction in the Shippingport Capital Trust investment.
During the last three quarters of 2003, capital requirements for
property additions and capital leases are expected to be about $52 million,
including $9 million for nuclear fuel. TE has additional requirements of
approximately $43 million to meet sinking fund requirements for preferred stock
and maturing long-term debt during the remainder of 2003. These cash
requirements are expected to be satisfied from internal cash and short-term
credit arrangements.
On January 21, 2003, Standard and Poor's (S&P) indicated its concern
about FirstEnergy's disclosure of non-cash charges related to deferred costs in
Pennsylvania, pension and other post-retirement benefits, and Emdersa, which
were higher than anticipated in the third quarter of 2002. S&P identified the
restart of the Davis-Besse nuclear plant "...without significant delay beyond
April 2003..." as key to maintaining FirstEnergy's current debt ratings. S&P
also identified other issues it would continue to monitor including:
FirstEnergy's deleveraging efforts, free cash generated during 2003, the JCP&L
rate case, successful hedging of its short power position, and continued capture
of projected merger savings.
On April 14, 2003, S&P again affirmed its "BBB" corporate credit
rating for FirstEnergy. The S&P outlook remained negative, but S&P improved
FirstEnergy's business position from a "6" to a "5" (on a scale of 1 to 10 with
1 considered the least risky). S&P also reiterated that the key issues being
monitored by the agency included the timely restart of Davis-Besse, the JCP&L
rate case, capture of merger synergies, and controlling capital expenditures at
estimated levels. Significant delays in the planned date of Davis-Besse's return
to service or other factors (identified above) affecting the speed with which
FirstEnergy reduces debt, could put additional pressure on the credit ratings of
FirstEnergy and, correspondingly, its subsidiaries, including TE.
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On August 14, 2003, Moody's Investors Service placed the debt
ratings of FirstEnergy and all of its subsidiaries under review for possible
downgrade. Moody's stated that the review was prompted by: (1) weaker than
expected operating performance and cash flow generation; (2) less progress than
expected in reducing debt; (3) continuing high leverage relative to its peer
group; and (4) negative impact on cash flow and earnings from the continuing
nuclear plant outage at Davis-Besse. Moody's further stated that, in
anticipation of Davis-Besse returning to service in the near future and
FirstEnergy's continuing to significantly reduce debt and improve its financial
profile, "Moody's does not expect that the outcome of the review will result in
FirstEnergy's senior unsecured debt rating falling below investment-grade."
Other Obligations
Obligations not included on TE's Consolidated Balance Sheet
primarily consist of sale and leaseback arrangements involving the Bruce
Mansfield Plant and Beaver Valley Unit 2. As of March 31, 2003, the present
value of these sale and leaseback operating lease commitments, net of trust
investments, totaled $509 million. TE sells substantially all of its retail
customer receivables, which provided $49 million of off-balance sheet financing
as of March 31, 2003.
EQUITY PRICE RISK
Included in TE's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $90
million as of March 31, 2003 and December 31, 2002. A hypothetical 10% decrease
in prices quoted by stock exchanges would result in a $9 million reduction in
fair value as of March 31, 2003.
OUTLOOK
Beginning in 2001, TE's customers were able to select alternative
energy suppliers. TE continues to deliver power to residential homes and
businesses through its existing distribution system, which remains regulated.
Customer rates have been restructured into separate components to support
customer choice. TE has a continuing responsibility to provide power to those
customers not choosing to receive power from an alternative energy supplier
subject to certain limits. Adopting new approaches to regulation and
experiencing new forms of competition have created new uncertainties.
Regulatory Matters
In 2001, Ohio customer rates were restructured to establish separate
charges for transmission, distribution, transition cost recovery and a
generation-related component. When one of TE's Ohio customers elects to obtain
power from an alternative supplier, TE reduces the customer's bill with a
"generation shopping credit," based on the regulated generation component (plus
an incentive), and the customer receives a generation charge from the
alternative supplier. TE has continuing PLR responsibility to its franchise
customers through December 31, 2005.
Regulatory assets are costs which have been authorized by The Public
Utilities Commission of Ohio (PUCO) and the Federal Energy Regulatory Commission
for recovery from customers in future periods and, without such authorization,
would have been charged to income when incurred. Regulatory assets declined
$20.8 million to $557.4 million as of March 31, 2003 from the balance as of
December 31, 2002, resulting from recovery of transition plan regulatory assets.
As part of TE's transition plan it is obligated to supply
electricity to customers who do not choose an alternative supplier. TE is also
required to provide 160 megawatts (MW) of low cost supply to unaffiliated
alternative suppliers that serve customers within its service area. TE's
competitive retail sales affiliate, FES, acts as an alternate supplier for a
portion of the load in its franchise area.
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 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, FirstEnergy has
made significant management and human performance changes with the intent of
establishing the proper safety culture throughout the workforce. Work was
completed on the reactor head during 2002 and is continuing on efforts designed
to enhance the unit's reliability and performance. FirstEnergy is also
accelerating
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maintenance work that had been planned for future refueling and maintenance
outages. At a meeting with the NRC in November 2002, FirstEnergy discussed plans
to test the bottom of the reactor for leaks and to install a state-of-the-art
leak-detection system around the reactor. The additional maintenance work being
performed has expanded the previous estimates of restoration work. FirstEnergy
anticipates that the unit will be ready for restart in the first half of the
summer of 2003 after completion of the additional maintenance work and
regulatory reviews. The NRC must authorize restart of the plant following its
formal inspection process before the unit can be returned to service. While the
additional maintenance work has delayed FirstEnergy's plans to reduce debt
levels FirstEnergy believes such investments in the unit's future safety,
reliability and performance to be essential. Significant delays in Davis-Besse's
return to service, which depends on the successful resolution of the management
and technical issues as well as NRC approval, could trigger an evaluation for
impairment of the nuclear plant (see Significant Accounting Policies below).
Incremental expenses associated with the extended Davis-Besse outage
in the first quarter of 2003 totaled $88.6 million, including $36.3 million for
maintenance work and $52.3 million for fuel and purchased power. TE's ownership
share is 48.62% of those expenses. It is anticipated that an additional $13.7
million in maintenance costs will be spent during the remainder of the
Davis-Besse outage. Replacement power costs are expected to be $15 million per
month in the non-summer months and $20-25 million per month during the summer.
Environmental Matters
TE believes it is in compliance with the 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 in the future from our Ohio and
Pennsylvania facilities. Various regulatory and judicial actions have since
sought to further define NOx reduction requirements (see Note 2C - Environmental
Matters). TE continues to evaluate its compliance plans and other compliance
options.
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 a 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.
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants. The EPA identified mercury as the hazardous air pollutant of
greatest concern. The EPA established a schedule to propose regulations by
December 2003 and issue final regulations by December 2004. The future cost of
compliance with these regulations may be substantial.
As a result of the Resource Conservation and Recovery Act of 1976,
as amended, and the Toxic Substances Control Act of 1976, federal and state
hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous waste
disposal requirements pending the EPA's evaluation of the need for future
regulation. The EPA has issued its final regulatory determination that
regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the
EPA announced that it will develop national standards regulating disposal of
coal ash under its authority to regulate nonhazardous waste.
TE believes it is in compliance with the current SO2 and nitrogen
oxides (NOx) reduction requirements under the Clean Air Act Amendments of 1990.
SO2 reductions are being achieved by burning lower-sulfur fuel, generating more
electricity from lower-emitting plants, and/or using emission allowances. NOx
reductions are being achieved through combustion controls and the generation of
more electricity at lower-emitting plants. In September 1998, the EPA finalized
regulations requiring additional NOx reductions from the Companies' Ohio and
Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions
of NOx emissions (an approximate 85% reduction in utility plant NOx emissions
from projected 2007 emissions) across a region of nineteen states and the
District of Columbia, including New Jersey, Ohio and Pennsylvania, based on a
conclusion that such NOx emissions are contributing significantly to ozone
pollution in the eastern United States. State Implementation Plans (SIP) must
comply by May 31, 2004 with individual state NOx budgets established by the EPA.
Pennsylvania submitted a SIP that requires compliance with the NOx budgets at
the Companies' Pennsylvania facilities by May 1, 2003 and Ohio submitted a SIP
that requires compliance with the NOx budgets at the Companies' Ohio facilities
by May 31, 2004.
TE has been named as a "potentially responsible party" (PRP) at
waste disposal sites which may require cleanup under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980. Allegations of
disposal of hazardous substances at historical sites and the liability involved,
are often unsubstantiated and subject to dispute; however, federal law provides
that all PRPs for a particular site be held liable on a joint and several basis.
Therefore, potential environmental liabilities have been recognized on the
Consolidated Balance Sheet as of March 31, 2003, based on estimates of the total
costs of cleanup, TE's proportionate responsibility for such costs and the
financial ability of other nonaffiliated entities to pay. TE has total accrued
liabilities of approximately $0.2 million as of March 31, 2003.
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The effects of compliance on TE with regard to environmental matters
could have a material adverse effect on its earnings and competitive position.
These environmental regulations affect its earnings and competitive position to
the extent TE 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. TE believes it is in material
compliance with existing regulations, but is unable to predict how and when
applicable environmental regulations may change and what, if any, the effects of
any such change would be.
Legal Matters
Various lawsuits, claims and proceedings relayed to TE's normal
business operations are pending against TE, the most significant of which are
described above.
SIGNIFICANT ACCOUNTING POLICIES
TE prepares its 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 TE's financial results. All of TE's 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 those specific factors. TE's more significant accounting policies are
described below.
Regulatory Accounting
TE is subject to regulation that sets the prices (rates) it is
permitted to charge its customers based on the costs that the regulatory
agencies determine TE is 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 Ohio, a significant amount of
regulatory assets have been recorded. As of March 31, 2003, TE's regulatory
assets totaled $557.4 million. TE regularly reviews 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.
Revenue Recognition
TE follows the accrual method of accounting for revenues,
recognizing revenue for kilowatt-hours that have been delivered but not yet been
billed through the end of the accounting period. The determination of unbilled
revenues requires management to make various estimates including:
- Net energy generated or purchased for retail load
- Losses of energy over distribution lines
- Allocations to distribution companies within the FirstEnergy system
- Mix of kilowatt-hour usage by residential, commercial and industrial
customers
- Kilowatt-hour usage of customers receiving electricity from
alternative suppliers
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory defined
pension benefits and postemployment benefits other than pensions (OPEB) 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 FirstEnergy makes to the plans, and earnings on plan assets.
Pension and OPEB costs may also be 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.
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
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the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
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. Due to the significant decline in corporate
bond yields and interest rates in general during 2002, FirstEnergy reduced the
assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001.
FirstEnergy's assumed rate of return on pension plan assets
considers historical market returns and economic forecasts for the types of
investments held by its pension trusts. The market values of FirstEnergy's
pension assets have been affected by sharp declines in the equity markets since
mid-2000. In 2002 and 2001, plan assets earned (11.3)% and (5.5)%, respectively.
FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of
return on plan assets. As of December 31, 2002 the assumed return on plan assets
was reduced to 9.00% based upon FirstEnergy's projection of future returns and
pension trust investment allocation of approximately 60% large cap equities, 10%
small cap equities and 30% bonds.
Based on pension assumptions and pension plan assets as of December
31, 2002, FirstEnergy will not be required to fund its pension plans in 2003.
While OPEB plan assets have also been affected by sharp declines in the equity
market, the impact is not as significant due to the relative size of the plan
assets. However, health care cost trends have significantly increased and will
affect future OPEB costs. The 2003 composite health care trend rate assumption
is approximately 10%-12% gradually decreasing to 5% in later years, compared to
the 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6%
in later years. In determining its trend rate assumptions, FirstEnergy included
the specific provisions of its health care plans, the demographics and
utilization rates of plan participants, actual cost increases experienced in its
health care plans, and projections of future medical trend rates.
Ohio Transition Cost Amortization
In developing TE's restructuring plan, the PUCO determined allowable
transition costs based on amounts recorded on the EUOC's regulatory books. These
costs exceeded those deferred or capitalized on TE'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). TE 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, TE 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 No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," TE periodically evaluates its long-lived assets
to determine whether conditions exist that would indicate that the carrying
value of an asset may 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 other than of a temporary
nature has occurred, TE recognizes a loss - calculated as the difference between
the carrying value and the estimated fair value of the asset (discounted future
net cash flows).
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, TE evaluates
its 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, an impairment for goodwill must be recognized
in the financial statements. If impairment were to occur, TE would 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. TE's annual
review was completed in the third quarter of 2002. The results of that review
indicated no impairment of goodwill. The forecasts used in TE's evaluations of
goodwill reflect operations consistent with its general business assumptions.
Unanticipated changes in those assumptions could have a significant effect on
its future evaluations of goodwill. As of March 31, 2003, TE had approximately
$505 million of goodwill.
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RECENTLY ISSUED ACCOUNTING STANDARD NOT YET IMPLEMENTED
FIN 46, "Consolidation of Variable Interest Entities - an interpretation
of ARB 51"
In January 2003, the FASB issued this interpretation of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. This Interpretation requires an enterprise to
disclose the nature of its involvement with a VIE if the enterprise has a
significant variable interest in the VIE and to consolidate a VIE if the
enterprise is the primary beneficiary. VIEs created after January 31, 2003 are
immediately subject to the provisions of FIN 46. VIEs created before February 1,
2003 are subject to this interpretation's provisions in the first interim or
annual reporting period beginning after June 15, 2003 (TE's third quarter of
2003). The FASB also identified transitional disclosure provisions for all
financial statements issued after January 31, 2003.
TE currently has transactions which may fall within the scope of
this interpretation and which are reasonably possible of meeting the definition
of a VIE in accordance with FIN 46. TE currently consolidates the majority of
these entities and believes it will continue to consolidate following the
adoption of FIN 46. One of these entities TE is currently consolidating is the
Shippingport Capital Trust, which reacquired a portion of the off-balance sheet
debt issued in connection with the sale and leaseback of its interest in the
Bruce Mansfield Plant. Ownership of the trust includes a 4.85 percent interest
by nonaffiliated parties and a 0.34 percent equity interest by Toledo Edison
Capital Corp., a majority owned subsidiary.
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CONTROLS AND PROCEDURES
(A) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
The respective registrant's chief executive officer and chief
financial officer have reviewed and evaluated the registrant's disclosure
controls and procedures, as defined in the Securities Exchange Act of 1934 Rules
13a-14(c) and 15d-14(c), as of a date within 90 days prior to the filing date of
this report (Evaluation Date). Based on that evaluation those officers have
concluded that the registrant's disclosure controls and procedures are effective
and were designed to bring to their attention, during the period in which this
quarterly report was being prepared, material information relating to the
registrant and its consolidated subsidiaries by others within those entities.
(B) CHANGES IN INTERNAL CONTROLS
Effective June 1, 2003, the registrants implemented a new Enterprise
Resource Planning (ERP) system. While the associated business process changes
transform the internal control structure, management believes adequate controls
have been properly integrated into the reengineering ERP-enabled processes and
that internal controls will be enhanced.
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PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(A) EXHIBITS
EXHIBIT
NUMBER
FIRSTENERGY AND OE
15 Letter from independent public auditors
31.1 Certification letter from chief executive officer, as adopted
pursuant to Section 302 of the Sarbanes-Oxley Act.
31.2 Certification letter from chief financial officer, as adopted
pursuant to Section 302 of the Sarbanes-Oxley Act.
32.1 Certification letter from chief executive officer and chief
financial officer, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act.
CEI AND TE
31.1 Certification letter from chief executive officer, as adopted
pursuant to Section 302 of the Sarbanes-Oxley Act.
31.2 Certification letter from chief financial officer, as adopted
pursuant to Section 302 of the Sarbanes-Oxley Act.
32.1 Certification letter from chief executive officer and chief
financial officer, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act.
Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K,
neither FirstEnergy, OE, CEI nor TE have filed as an exhibit to this Form
10-Q/A any instrument with respect to long-term debt if the respective
total amount of securities authorized thereunder does not exceed 10% of
their respective total assets of FirstEnergy and its subsidiaries on a
consolidated basis, or respectively, OE, CEI or TE, , but hereby agree to
furnish to the Commission on request any such documents.
(B) REPORTS ON FORM 8-K
FIRSTENERGY-
FirstEnergy filed ten reports on Form 8-K since December 31, 2002. A
report dated January 17, 2003 reported updated information related with efforts
to prepare Davis-Besse for a safe and reliable return to service and the updated
schedule for JCP&L rate proceedings. A report dated January 21, 2003 reported
that the Pennsylvania Supreme Court denied further appeals of the February 21,
2002 Pennsylvania Commonwealth Court decision, which effectively affirmed the
Pennsylvania Public Utility Commission's order approving the FirstEnergy and GPU
merger, let stand the Commonwealth Court's denial of PLR relief for Met-Ed and
Penelec and remanded the merger savings issue back to the PPUC. A report dated
March 11, 2003 reported updated Davis-Besse information including the
installation of the new reactor head on the reactor vessel. A report dated March
17, 2003 reported updated Davis-Besse information, the filing of a $2 billion
shelf registration with the SEC and the status of the JCP&L rate proceedings. A
report dated March 18, 2003 reported NJBPU audit results of JCP&L
restructuring-related deferrals. A report dated April 16, 2003 reported updated
Davis-Besse information. A report dated April 18, 2003 reported FirstEnergy's
divestiture of its Argentina operations through the abandonment of its
investment resulting in a second quarter 2003 charge to net income of $63
million. A report dated May 1, 2003 reported FirstEnergy's first quarter 2003
results and other updated information including Davis-Besse updated ready for
restart schedule. A report dated May 9, 2003 reported updated Davis-Besse
information and a JCP&L rate proceedings update. A report dated May 9, 2003
reported that FirstEnergy had amended its Form 10-K for the year ended December
31, 2002 for a change in classification of a $57.1 net of tax charge with no
effect on previously reported net income. A report dated May 22, 2003, reported
an agreement to sell its remaining 10.1% interest in United Kingdom-based Aquila
Sterling Limited, the owner of Midlands Electricity. A report dated June 5, 2003
reported updated Davis Besse information. A report dated June 11, 2003, reported
a letter filed with the Pennsylvania Public Utility Commission Administrative
Law Judge which voids a prior stipulation. A report dated June 27, 2003,
reported signing a settlement agreement with certain the parties in its base
rate case proceeding. A report dated July 24, 2003, reported updates to the
schedule and cost estimates for Davis Besse.
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OE
OE filed two reports on Form 8-K since March 31, 2003. A report
dated August 5, 2003 reported the pending restatement of 2002 FE, OE, CEI and TE
financial statements. A report dated August 8, 2003 reported a U.S. District
Court ruling with respect to the W. H. Sammis Plant under the Clean Air Act.
CEI
CEI filed six reports on Form 8-K since December 31, 2002. A report
dated January 17, 2003 reported updated information related with efforts to
prepare Davis-Besse for a safe and reliable return to service. A report dated
March 11, 2003 reported updated Davis-Besse information including the
installation of the new reactor head on the reactor vessel. A report dated March
17, 2003 reported updated Davis-Besse information. A report dated April 16, 2003
reported Davis-Besse information. A report dated May 1, 2003 reported an updated
Davis-Besse ready for restart schedules. A report dated May 9, 2003 reported
updated Davis-Besse information. A report dated June 5, 2003 reported updated
Davis Besse information. A report dated July 24, 2003, reported updates to the
schedule and cost estimates for Davis-Besse.
TE
TE filed six reports on Form 8-K since December 31, 2002. A report
dated January 17, 2003 reported updated information related with efforts to
prepare Davis-Besse for a safe and reliable return to service. A report dated
March 11, 2003 reported updated Davis-Besse information including the
installation of the new reactor head on the reactor vessel. A report dated March
17, 2003 reported updated Davis-Besse information. A report dated April 16, 2003
reported Davis-Besse information. A report dated May 1, 2003 reported an updated
Davis-Besse ready for restart schedules. A report dated May 9, 2003 reported
updated Davis-Besse information. A report dated June 5, 2003 reported updated
Davis Besse information. A report dated July 24, 2003, reported updates to the
schedule and cost estimates for Davis-Besse.
89
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, each
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
August 18, 2003
FIRSTENERGY CORP.
Registrant
OHIO EDISON COMPANY
Registrant
THE CLEVELAND ELECTRIC
ILLUMINATING COMPANY
Registrant
THE TOLEDO EDISON COMPANY
Registrant
/s/ Harvey L. Wagner
----------------------------------------
Harvey L. Wagner
Vice President, Controller
and Chief Accounting Officer
90