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 JUNE 30, 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
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 AUGUST 8, 2003
----- --------------------
FirstEnergy Corp., $.10 par value 297,636,276
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
We are filing this Amendment No. 1 to our Quarterly Report on Form 10-Q for the
quarter ended June 30, 2003 (the "Report") to correct certain typographical and
minor computational errors in Item 1 - FINANCIAL STATEMENTS - Note 6 to the
Consolidated Financial Statements and Item 2 -- MANAGEMENT'S DISCUSSION AND
ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION of the Report. This
Amendment has no effect on previously reported results of operations or
financial position.
The complete amended and restated Item 1, which is included in its entirety
below, reflects corrections to the tables included in Note 6 "Segment
Information" as follows:
For the three months ended June 30, 2003 -
Income taxes for regulated services, competitive services and other,
respectively, of $89 million, $(32) million and $(32) million,
respectively, should have read $80 million, $(31) million and $(31)
million, respectively.
Income before discontinued operations and cumulative effect of
accounting change for regulated services and competitive services,
respectively, of $118 million and $(45) million, respectively, should
have read $107 million and $(44) million, respectively.
Net income (loss) for regulated services and competitive services,
respectively, of $118 million and $(45) million, respectively, should
have read $107 million and $(44) million, respectively.
For the three months ended June 30, 2002 -
External revenues for regulated services, competitive services and
other, respectively, of $2,161 million, $696 million and $36 million,
respectively, should have read $2,210 million, $590 million and $93
million, respectively.
Internal revenues for regulated services and competitive services,
respectively, of $177 million and $417 million, respectively, should
have read $237 million and $357 million, respectively.
Total revenues for regulated services, competitive services and other,
respectively, of $2,338 million, $1,113 million and $161 million,
respectively, should have read $2,447 million, $947 million and $218
million, respectively.
For the six months ended June 30, 2003 -
External revenues for regulated services and competitive services,
respectively, of $4,398 million and $1,606 million, respectively,
should have read $4,399 million and $1,605 million, respectively.
Total revenues for regulated services and competitive services,
respectively, of $4,896 million and $2,678 million, respectively,
should have read $4,897 million and $2,677 million, respectively.
Income taxes for regulated services, competitive services and other,
respectively, of $248 million, $(63) million and $(62) million,
respectively, should have read $234 million, $(61) million and $(61)
million, respectively.
Income before discontinued operations and cumulative effect of
accounting change for regulated services, competitive services and
other, respectively, of $345 million, $(89) million and $(105) million,
respectively, should have read $323 million, $(100) million and $(104)
million, respectively.
Net income (loss) for regulated services, competitive services and
other, respectively, of $446 million, $(88) million and $(165) million,
respectively, should have read $424 million, $(99) million and $(164)
million, respectively.
For the six months ended June 30, 2002 -
External revenues for regulated services and competitive services,
respectively, of $4,156 million and $1,283 million, respectively,
should have read $4,264 million and $1,175 million, respectively.
Total revenues for regulated services and competitive services,
respectively, of $4,688 million and $2,110 million, respectively,
should have read $4,796 million and $2,002 million, respectively.
The complete amended and restated Item 2, which is included in its entirety
below, reflects the following corrections:
Under the heading "RESULTS OF OPERATIONS":
Under the subheading "Expenses":
In the first sentence of the third paragraph, the decrease in
other operating expenses of $9.6 million in the second quarter
of 2003 should have read $7.1 million.
In the last sentence of the sixth paragraph, the lower charges
resulting from revised service life assumptions for generating
plants of $14.1 million should have read $12.7 million.
Under the heading "RESULTS OF OPERATIONS-BUSINESS SEGMENTS":
In the third paragraph under the subheading "Regulated Services":
In the third sentence, the increase in other operating
expenses of $15.9 million and in depreciation and amortization
expense of $10.6 million should have read $18.4 million and
$8.1 million, respectively, In the sixth sentence, the
increase in other operating expense of $29.9 million and in
depreciation and amortization expense of $27.2 million should
have read $32.4 million and $24.7 million, respectively.
Under the heading "CAPITAL RESOURCES AND LIQUIDITY":
Under the subheading "Cash Flows from Operating Activities":
In the table, cash earnings for the three months ended June
30, 2003 of $509 million should have read $515 million, and
for the three months ended June 30, 2002 of $530 million
should have read $495 million.
In the table, working capital and other for the three months
ended June 30, 2003 of ($487) million should have read ($493)
million, and for the three months ended June 30, 2002 of
($268) million should have read ($233) million.
In the second paragraph, the change in funds used for working
capital of $219 million should have read $260 million, and the
decrease in cash earnings of $21 million should have read an
increase in cash earnings of $20 million.
Under the heading "IMPLEMENTATION OF ACCOUNTING STANDARD":
The "Total as originally reported" for expenses in the chart entitled
Impact of Recording Energy Trading Net for the three months and six
months ended June 30, 2002 of $2,309 million and $4,701 million,
respectively, should have read $2,323 million and $4,725 million,
respectively.
The "Total as currently reported" for expenses in the same chart as
indicated above for the three months and six months ended June 30, 2002
of $2,259 million and $4,611 million, respectively, should have read
$2,273 million and $4,635 million, respectively.
TABLE OF CONTENTS
PAGES
PART I. FINANCIAL INFORMATION
Notes to Financial Statements............................................................. 1-20
FIRSTENERGY CORP.
Consolidated Statements of Income......................................................... 21
Consolidated Balance Sheets............................................................... 22-23
Consolidated Statements of Cash Flows..................................................... 24
Report of Independent Auditors............................................................ 25
Management's Discussion and Analysis of Results of Operations and
Financial Condition..................................................................... 26-49
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
PENNSYLVANIA POWER COMPANY
JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARIES
METROPOLITAN EDISON COMPANY AND SUBSIDIARIES
PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARIES
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.; MARBEL Energy Corporation; FirstEnergy Nuclear Operating Company
(FENOC); GPU Capital, Inc.; GPU Power, Inc.; and FirstEnergy Service Company
(FESC). FES provides energy-related products and services and, through its
FirstEnergy Generation Corp. (FGCO) subsidiary, operates FirstEnergy's
nonnuclear generation business. FENOC operates the Companies' nuclear generating
facilities. FSG is the parent company of several heating, ventilating, air
conditioning and energy management companies, and MYR is a utility
infrastructure construction service company. MARBEL holds FirstEnergy's interest
in Great Lakes Energy Partners, LLC. 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. FESC provides 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, as amended where applicable, 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
(GAAP) 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, as well as restated as discussed below.
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
1
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.
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 did not purchase and does not own any of the transition bonds,
which are included as long-term debt on each of 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 sold the bondable transition property to the Issuer and 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.
Pension and Other Postretirement Benefits
As a result of GPU Service Inc. merging with FESC in the second quarter
of 2003, operating company employees of GPU Service were transferred to JCP&L,
Met-Ed and Penelec. Accordingly, FirstEnergy requested an actuarial study to
update the pension and other post-employment benefit (OPEB) assets and
liabilities for each of its subsidiaries. Based on the actuary's report, the
accrued pension and OPEB costs for FirstEnergy and its subsidiaries as of June
30, 2003 increased (decreased) by the following amounts:
Pension OPEB
------- ----
(In thousands)
OE......................... $ 50,937 $ 48,775
CEI........................ (16,699) (49,526)
TE......................... (3,439) (24,476)
Penn....................... 15,851 9,751
JCP&L...................... 78,549 86,333
Met-Ed..................... 47,219 59,405
Penelec.................... 70,693 87,314
Other subsidiaries......... (243,111) (217,576)
---------- ----------
Total FirstEnergy.......... $ -- $ --
=============== ===============
The corresponding adjustment related to these changes increased
(decreased) other comprehensive income, deferred income taxes and receivables
from/to associated companies in the respective operating company's financial
statements.
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.
2
FirstEnergy entered into interest rate derivative transactions during 2001 to
hedge a portion of the anticipated interest 2nd QTR 10-Q 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 $110.8 million included in Accumulated Other
Comprehensive Loss (AOCL) as of June 30, 2003, for derivative hedging activity,
as compared to the March 31, 2003 balance of $105.8 million in net deferred
losses, resulted from a $7.7 million reduction related to current hedging
activity and a $12.7 million increase due to net hedge gains included in
earnings during the three months ended June 30, 2003. Approximately $25.3
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 and 2003 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 second quarter of 2003 are based on a
notional principal amount of $200 million. As of June 30, 2003, the notional
amount of FirstEnergy's fixed-for-floating rate interest rate swaps totaled $550
million.
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
June 30, 2003, FirstEnergy's AOCL was approximately $534.1 million as compared
to the December 31, 2002 balance of $656.1 million. A reconciliation of net
income to comprehensive income for the three months and six months ended June
30, 2003 and 2002, is shown below:
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
-------------------- ------------------
2003 2002 2003 2002
---- ---- ---- ----
RESTATED RESTATED
(SEE NOTE 1) (SEE NOTE 1)
(IN THOUSANDS) (IN THOUSANDS)
Net income (loss).................... $(57,888) $207,898 $160,514 $326,166
Other comprehensive income, net of tax:
Derivative hedge transactions...... (4,917) 535 (576) 36,379
Currency transactions (1).......... 89,790 -- 91,461 1
Available for sale securities...... 38,454 (2,140) 38,267 (1,411)
--------- ----------- ---------- ------------
Comprehensive income................. $65,439 $206,293 $289,666 $361,135
======= ======== ======== ========
(1) See Note 3 - International Operations (Emdersa Abandonment).
Stock-Based Compensation
FirstEnergy applies the recognition and measurement principles of
Accounting Principles Board Opinion No. 25 (APB 25), "Accounting for Stock
Issued to Employees" and related Interpretations in accounting for its
stock-based compensation plans. 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 reductions to net income and earnings per share. The following table
summarizes those effects.
3
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
----------------------- ----------------------
2003 2002 2003 2002
---- ---- ---- ----
RESTATED RESTATED
(SEE NOTE 1) (SEE NOTE 1)
(IN THOUSANDS) (IN THOUSANDS)
Net income (loss), as reported........... $(57,588) $207,898 $160,514 $326,166
Add back compensation expense
reported in net income, net of tax
(based on APB 25)...................... 49 44 91 87
Deduct compensation expense based
upon estimated fair value, net of tax.. (3,731) (2,556) (6,713) (3,956)
--------------------------------------------------------------------------------------------------
Adjusted net income (loss)............... $(61,270) $205,386 $153,892 $322,297
-------------------------------------------------------------------------------------------------
Earnings (Loss) Per Share of Common Stock -
Basic
As Reported......................... $(0.20) $0.74 $0.55 $1.10
Adjusted............................ $(0.21) $0.73 $0.52 $1.09
Diluted
As Reported......................... $(0.20) $0.73 $0.54 $1.09
Adjusted............................ $(0.21) $0.72 $0.52 $1.08
Changes in Previously Reported Income Statement Classifications
FirstEnergy recorded an increase to income during the first quarter of
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 six months ended June 30, 2002
are reflected in the restatements shown below.
As a result of FirstEnergy's divestiture of its ownership in GPU
Empresa Distribuidora Electrica Regional S.A. and affiliates (Emdersa) in April
2003 through the abandonment of its shares in the parent company of the
Argentina operation (as further described in Note 3), FirstEnergy recorded a
$67.4 million charge in the second quarter of 2003 on the Consolidated Statement
of Income as "Discontinued Operations". This divestiture caused Emdersa's first
quarter 2003 net income of approximately $6.9 million, which had been previously
classified in its respective revenues and expense captions on the Consolidated
Statement of Income, to be also reclassified as Discontinued Operations.
Accordingly, Emdersa's Discontinued Operations reflect a $60.5 million net loss
for the six months ended June 30, 2003 which included $6.9 million of after-tax
earnings from the Argentina operation from the first quarter of 2003 -
previously reported as $10.7 million of revenue, $0.1 million of expenses and
$3.7 million of income taxes.
The following table summarizes Emdersa's major assets and liabilities
included in FirstEnergy's Consolidated Balance Sheet as of December 31, 2002:
(IN THOUSANDS)
------------------------------------------------
ASSETS ABANDONED:
Current Assets..................... $ 17,344
Property, plant and equipment...... 61,980
Other.............................. 8,737
------------------------------------------------
Total Assets......................... $ 88,061
================================================
LIABILITIES RELATED TO ASSETS ABANDONED:
Current Liabilities................ $ 12,777
Long-term debt..................... 100,202
Other.............................. 10,548
------------------------------------------------
Total Liabilities.................... $123,527
================================================
4
RESTATEMENTS OF PREVIOUSLY REPORTED RESULTS
FirstEnergy, OE, CEI and TE have restated their financial statements
for the year ended December 31, 2002; for the three months ended March 31, 2003
and 2002; the six months ended June 30, 2003 and the three and six months ended
June 30, 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 2002 are now reported in results for the
earlier periods. The net impact of these adjustments decreased net income by
$6.2 million in the first quarter of 2003. Included in the adjustments are the
impact in the first and second quarters of 2003 of recognizing revenue 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, 2002 by $12 million and decreased net
income in the second quarter 2002 by $8 million. See note 2(M) of the
FirstEnergy, OE, CEI and TE Form 10-K/A for further discussion of the
restatements. Since the results for the quarter ended March 31, 2003 have been
restated as discussed above and the results of operations for the six months
ended June 30, 2003 reflect these restated results, the June 30, 2003 amounts
are restated.
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 and six months ended June 30, 2002:
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, 2002 JUNE 30, 2002
------------------------- ----------------------------
AS PREVIOUSLY AS AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED
(IN THOUSANDS)
OE .................. $ 75,026 $ 82,326 $151,202 $150,502
CEI ................. 11,655 36,455 24,796 73,596
TE .................. 6,325 23,925 14,217 48,217
-------- -------- -------- --------
Total FirstEnergy $ 93,006 $142,706 $190,215 $272,315
======== ======== ======== ========
Above-Market Lease Costs
In 1997, FirstEnergy 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 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 $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
5
schedules for regulatory assets and amortized through the end of the recovery
period - approximately 2009 for CEI and 2007 for TE.
The effects of these changes on the Consolidated Statement of Income
previously reported for the three months ended March 31, 2003, were disclosed in
Amendment No. 1 on Form 10-Q/A for the quarter ended March 31, 2003. The effects
of these changes on the Consolidated Statements of Income previously reported
for the three months and six months ended June 30, 2002 are as follows:
FIRSTENERGY
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, 2002 JUNE 30, 2002
----------------------------- ------------------------------
AS PREVIOUSLY AS AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Revenues $2,898,573 $2,898,573 $5,751,851 $5,751,851
Expenses 2,230,409 2,272,659 4,594,043 4,635,001
----------- ----------- ----------- -----------
Income before interest and income taxes 668,164 625,914 1,157,808 1,116,850
Net interest charges 250,282 250,282 529,004 529,004
Income taxes 184,572 167,734 279,001 261,680
------------ ------------ ------------ ------------
Net income $ 233,310 $ 207,898 $ 349,803 $ 326,166
=========== =========== =========== ===========
Basic earnings per share of common stock $.80 $.71 $1.19 $1.11
Diluted earnings per share of common stock $.79 $.71 $1.19 $1.11
OE
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, 2002 JUNE 30, 2002
----------------------------- ------------------------------
AS PREVIOUSLY AS AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED
(IN THOUSANDS)
Operating revenues $744,550 $744,550 $1,452,349 $1,452,349
Operating expenses and taxes 605,946 611,069 1,216,681 1,211,518
--------- --------- ----------- -----------
Operating income 138,604 133,481 235,668 240,831
Other income 15,087 15,087 15,599 15,599
Net interest charges 35,856 35,856 77,081 77,081
---------- ---------- ------------- -------------
Net income 117,835 112,712 174,186 179,349
Preferred stock dividend requirements 2,597 2,597 5,193 5,193
----------- ----------- -------------- --------------
Earnings on common stock $115,238 $110,115 $ 168,993 $ 174,156
======== ======== =========== ===========
CEI
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, 2002 JUNE 30, 2002
----------------------------- ------------------------------
AS PREVIOUSLY AS AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED
(IN THOUSANDS)
Operating revenues $462,874 $462,874 $887,851 $896,151
Operating expenses and taxes 350,120 355,799 719,775 731,551
--------- --------- --------- ---------
Operating income 112,754 107,075 168,076 164,600
Other income 3,356 3,356 8,597 8,597
Net interest charges 46,750 46,750 94,617 94,617
---------- ---------- ----------- ----------
Net income 69,360 63,681 82,056 78,580
Preferred stock dividend requirements 3,054 3,054 11,310 9,610
----------- ----------- ----------- ---------
Earnings on common stock $ 66,306 $ 60,627 $ 70,746 $ 68,970
========= ========= ========== =========
TE
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, 2002 JUNE 30, 2002
----------------------------- ------------------------------
AS PREVIOUSLY AS AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED
(IN THOUSANDS)
Operating revenues $250,307 $250,307 $494,474 $502,874
Operating expenses and taxes 216,148 222,658 450,657 464,537
--------- --------- --------- ---------
Operating income 34,159 27,649 43,817 38,337
Other income 3,743 3,743 8,086 8,086
Net interest charges 14,859 14,859 29,568 29,568
---------- ---------- ---------- ----------
Net income 23,043 16,533 22,335 16,855
Preferred stock dividend requirements 2,210 2,210 6,934 6,934
----------- ----------- ----------- -----------
Earnings on common stock $ 20,833 $ 14,323 $ 15,401 $ 9,921
========= ========= ========= ==========
6
The effects of these changes on net cash provided from operating
activities on the Consolidated Statement of Cash Flows previously reported for
the three months ended March 31, 2003, were disclosed in Amendment No. 1 on Form
10-Q/A for the quarter ended March 31, 2003. The effects of these changes on the
Consolidated Statements of Cash Flows previously reported for the three months
and six months ended June 30, 2002 are as follows:
FE
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, 2002 JUNE 30, 2002
----------------------------- ------------------------------
AS PREVIOUSLY AS AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED
(IN THOUSANDS)
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income $233,310 $207,898 $349,803 $326,166
Adjustments to reconcile net income
to net cash from operating activities:
Provision for depreciation and
amortization 250,705 300,405 513,533 609,779
Nuclear fuel and lease amortization 19,598 19,598 40,563 40,563
Other amortization (4,386) (4,386) (7,923) (7,923)
Deferred costs recoverable as regulatory assets (68,936) (55,136) (139,070) (146,070)
Deferred income taxes 50,355 33,517 43,421 12,500
Investment tax credits (6,967) (6,967) (13,713) (13,713)
Cumulative effect of accounting change (Note 5) -- -- (45,300) --
Receivables (150,157) (150,157) (83,567) (90,062)
Materials and supplies (21,742) (21,742) (3,579) (3,579)
Accounts payable 47,766 47,766 37,774 44,762
Accrued taxes 4,422 4,422 86,719 86,719
Accrued interest (106,136) (106,136) (19,557) (19,557)
Deferred rents & sale/leaseback (121,642) (142,892) (50,204) (98,492)
Prepayments & other (128,937) (128,937) (19,386) (19,386)
Other 264,870 264,870 36,693 4,500
---------- ---------- ---------- -----------
Net cash provided from operating schedules $ 262,123 $ 262,123 $726,207 $726,207
--------- --------- -------- --------
OE
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, 2002 JUNE 30, 2002
----------------------------- ------------------------------
AS PREVIOUSLY AS AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED
(IN THOUSANDS)
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income $117,835 $112,712 $174,186 $179,349
Adjustments to reconcile net income
to net cash from operating activities:
Provision for depreciation and
amortization 91,521 98,821 183,651 174,551
Nuclear fuel and lease amortization 12,133 12,133 23,535 23,535
Deferred income taxes (8,886) (11,386) (22,056) (18,766)
Investment tax credits (3,762) (3,439) (7,535) (6,888)
Receivables (31,345) (31,345) 32,803 32,803
Materials and supplies (3,158) (3,158) (4,800) (4,800)
Accounts payable (1,166) (1,166) (19,461) (19,461)
Accrued taxes 149,376 149,376 206,260 206,260
Accrued interest (8,200) (8,200) (1,963) (1,963)
Deferred rents & sale/leaseback (31,865) (31,865) (182) (182)
Prepayments & other 15,178 15,178 31,273 31,273
Other (4,232) (4,232) (34,771) (34,771)
---------- ---------- ---------- ----------
Net cash provided from operating schedules $293,429 $293,429 $560,940 $560,940
-------- -------- -------- --------
7
CEI
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, 2002 JUNE 30, 2002
----------------------------- ------------------------------
AS PREVIOUSLY AS AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED
(IN THOUSANDS)
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income $69,360 $63,681 $82,056 $78,580
Adjustments to reconcile net income
to net cash from operating activities:
Provision for depreciation and
amortization 28,333 53,133 56,804 105,604
Nuclear fuel and lease amortization 4,794 4,794 10,784 10,784
Other amortization (4,275) (4,275) (8,167) (8,167)
Deferred income taxes 5,904 2,024 13,100 2,906
Investment tax credits (1,129) (1,270) (2,031) (2,313)
Receivables (38,473) (38,473) (31,657) (31,557)
Materials and supplies (1,840) (1,840) (3,206) (3,206)
Accounts payable 8,057 8,057 26,379 26,379
Other (27,779) (42,879) (13,588) (48,536)
--------- --------- ---------- ----------
Net cash provided from operating schedules $ 42,952 $ 42,952 $130,474 $130,474
-------- -------- -------- --------
TE
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, 2002 JUNE 30, 2002
----------------------------- ------------------------------
AS PREVIOUSLY AS AS PREVIOUSLY AS
REPORTED RESTATED REPORTED RESTATED
(IN THOUSANDS)
CASH FLOWS FROM OPERATING
ACTIVITIES
Net Income $ 23,043 $ 16,533 $ 22,335 $ 10,209
Adjustments to reconcile net income
to net cash from operating activities:
Provision for depreciation and
amortization 19,748 37,348 41,116 75,116
Nuclear fuel and lease amortization 2,671 2,671 6,244 6,244
Deferred income taxes 578 (4,322) 5,892 (2,963)
Investment tax credits (487) (527) (973) (1,053)
Receivables (18,762) (18,762) 1,260 1,260
Materials and supplies (1,169) (1,169) (1,820) (1,820)
Accounts payable (9,210) (9,210) (6,349) (7,049)
Other (40,885) (47,035) (26,413) (38,652)
--------- --------- --------- ----------
Net cash provided from operating activities $(24,473) $(24,473) $ 41,292 $ 41,292
--------- -------- -------- ---------
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 $733
million (OE-$85 million, CEI-$99 million, TE-$56 million, Penn-$53 million,
JCP&L-$112 million, Met-Ed-$51 million, Penelec-$49 million, ATSI-$25 million,
FES-$124 million and other subsidiaries-$79 million) is applicable to 2003.
Investments for additional nuclear fuel during the 2003-2007 period are
estimated to be approximately $481 million (OE-$59 million, CEI-$51 million,
TE-$31 million, Penn-$39 million and FES-$301 million), of which approximately
$76 million (OE-$28 million, CEI-$17 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 June 30, 2003,
outstanding guarantees and other assurances aggregated $1.050 billion.
8
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 $918.2 million as of June 30, 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 $24.5 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 June 30, 2003, rating-contingent
collateralization totaled $106.8 million. FirstEnergy monitors these
collateralization provisions and updates its total exposure monthly.
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 required
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. 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. On August 7, the United States District Court for the Southern
District of Ohio ruled that 11 projects undertaken at the Sammis Plant
9
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.
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 June 30, 2003, based on estimates of the total
costs of cleanup, the Companies' proportionate responsibility for such costs and
the financial ability of other nonaffiliated entities to pay. In addition, JCP&L
has accrued liabilities for environmental remediation of former manufactured gas
plants in New Jersey; those costs are being recovered by JCP&L through a
non-bypassable societal benefits charge. The Companies have total accrued
liabilities aggregating approximately $53.8 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-$3.5 million) as of June 30, 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 $226 million as of June 30, 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 $6.0 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) (under FirstEnergy's
existing $250 million LOC capacity available as part of a $1.5 billion
FirstEnergy credit facility) to obtain TEBSA lender consent as substitute
collateral for the release of the assets for FirstEnergy to abandon its
Argentina operations, Emdersa (see Note 3 below).
10
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.
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.
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
11
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 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 six months ended June 30, 2002 by
reclassifying certain revenue and expense amounts related to activity during the
quarter ended March 31, 2002 to their respective income statement
classifications for the six-month 2002 period. See Note 1 for the effects of the
change in classification. In the fourth quarter of 2002, FirstEnergy recorded a
$50 million charge ($32.5 million net of tax) to reduce the carrying value of
its remaining 20.1 percent interest.
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. Under terms of the
agreement, which is contingent upon bondholder approval, Scottish and Southern
will pay FirstEnergy and Aquila an aggregate $70 million (FirstEnergy's share
would be approximately $14 million). Midland'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 net of tax) related to the carrying value of the
note FirstEnergy had with Aquila 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 its note receivable in a secondary market and received $63.2 million
in proceeds on July 28, 2003.
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 occurred in
Argentina which affected 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 represented 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
through the abandonment of its shares in Emdersa's parent company, GPU Argentina
Holdings, Inc. The abandonment was accomplished by relinquishing FirstEnergy's
shares to the independent Board of Directors of GPU Argentina Holdings,
relieving FirstEnergy of all rights and obligations relative to this business.
As a result of the abandonment, FirstEnergy recognized a one-time, non-cash
charge of $67.4 million, or $0.23 per share of common stock in the second
quarter of 2003. This charge is the result of realizing the CTA losses through
current period earnings ($89.8 million, or $0.30 per share), partially offset by
the gain recognized from abandoning FirstEnergy's investment in Emdersa ($22.4
million, or $0.07 per share). Since FirstEnergy had previously recorded $89.8
million of CTA adjustments in OCI, the net effect of the $67.4 million charge
was an increase in common stockholders' equity of $22.4 million.
The $67.4 million charge does not include the anticipated income tax
benefits related to the abandonment, which were 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. The arbitration hearing is scheduled for
the week of February 23, 2004.
12
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;
- 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 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
13
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 had been in effect at
increasing levels through July 2003. The Final Order also confirmed the
establishment of a non-bypassable societal benefits charge (SBC) to recover
costs which include nuclear plant decommissioning and manufactured gas plant
remediation, as well as a non-bypassable market transition charge (MTC)
primarily to recover stranded costs. The NJBPU has deferred making a final
determination of the net proceeds and stranded costs related to prior generating
asset divestitures until JCP&L's request for an Internal Revenue Service (IRS)
ruling regarding the treatment of associated federal income tax benefits is
acted upon. Should the IRS ruling support the return of the tax benefits to
customers, there would be no effect to FirstEnergy's or JCP&L's net income since
the contingency existed prior to the merger.
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 (TBC) 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 June 30, 2003, the
accumulated deferred cost balance totaled approximately $450 million, after the
charge discussed below. The NJBPU also allowed securitization of JCP&L's
deferred balance to the extent permitted by law upon application by JCP&L and a
determination by the NJBPU that the conditions of the New Jersey restructuring
legislation are met. There can be no assurance as to the extent, if any, that
the NJBPU will permit such securitization.
Under New Jersey transition legislation, all electric distribution
companies were required to file rate cases to determine the level of unbundled
rate components to become effective August 1, 2003. JCP&L 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. On July 25, 2003,
the NJBPU announced its JCP&L base electric rate proceeding decision which would
reduce JCP&L's annual revenues by approximately $62 million effective August 1,
2003. The NJBPU decision also provided for an interim return on equity of 9.5
percent on JCP&L's rate base for the next 6 to 12 months. During that period,
JCP&L will initiate another proceeding to request recovery of additional costs
incurred to enhance system reliability. In that proceeding, the NJBPU could
increase the return on equity to 9.75 percent or decrease it to 9.25 percent,
depending on its assessment of the reliability of JCP&L's service. Any reduction
would be retroactive to August 1, 2003. The revenue decrease in the decision
consists of a $223 million decrease in the electricity delivery charge, a $111
million increase due to the August 1, 2003 expiration of annual customer credits
previously mandated by the New Jersey transition legislation, a $49 million
increase in the MTC tariff component, and a net $1 million increase in the SBC
charge. The MTC would allow for the recovery of $465 million in deferred energy
costs over the next ten years on an interim basis, thus disallowing $153 million
of the $618 million provided for in a preliminary settlement agreement between
certain parties. 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.
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. On July 25,
2003, the NJBPU approved a Stipulation Settlement between the parties and
authorized the recovery of the total $135 million of buyout costs.
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
14
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 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.
In June 2001, the PPUC approved the Settlement Stipulation with all of
the major parties in the combined merger and rate relief proceedings which
approved the merger and provided PLR deferred accounting treatment for energy
costs, permitting Met-Ed and Penelec to defer, for future recovery, energy costs
in excess of amounts reflected in their capped generation rates retroactive to
January 1, 2001. This PLR deferral accounting procedure was later denied in a
February 2002 Commonwealth Court of Pennsylvania decision. The court decision
also affirmed the PPUC decision regarding the merger, remanding the decision to
the PPUC only with respect to the issue of merger savings. In September 2002,
FirstEnergy established reserves for Met-Ed's and Penelec's PLR deferred energy
costs which aggregated $287.1 million, reflecting the potential adverse impact
of the then pending Pennsylvania Supreme Court decision whether to review the
Commonwealth Court decision.
On January 17, 2003, the Pennsylvania Supreme Court denied further
appeals of the Commonwealth Court decision which effectively affirmed the PPUC's
order approving the 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. 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.
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:
- 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.
15
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." That 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 (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. As of 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, $102.1 million 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 as of
June 30, 2003 of $1.161 billion. This amount 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 total ARO and the changes to the balance during
the second quarter and the first six months of 2003.
PERIODS ENDED JUNE 30, 2003
-----------------------------------
ARO RECONCILIATION THREE MONTHS SIX MONTHS
--------------------------------------------------------------------------------------
(IN MILLIONS)
Balance at beginning of period .................. $1,127 $1,109
Liabilities incurred in the current period....... -- --
Liabilities settled in the current period........ -- --
Accretion expense................................ 18 36
Revisions in estimated cash flows................ -- --
--------------------------------------------------------------------------------------
ENDING BALANCE AS OF JUNE 30, 2003............... $1,145 $1,145
--------------------------------------------------------------------------------------
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.
16
ADJUSTED ARO RECONCILIATION
---------------------------------------------------------------------------
(IN 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 exclude the cost of removal component
and cost of removal is charged to expense 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 as of June
30, 2003 was approximately $312.5 million.
The following table provides, on an adjusted basis, the effect on
income as if the accounting for SFAS 143 had been applied during the second
quarter and first six months of 2002.
PERIOD ENDED JUNE 30, 2002
EFFECT OF THE CHANGE IN ACCOUNTING --------------------------
PRINCIPLE APPLIED RETROACTIVELY TO 2002 THREE SIX
INCREASE(DECREASE) MONTHS MONTHS
------ ------
(RESTATED - SEE NOTE 1)
(IN MILLIONS)
Reported net income........................... $208 $326
------------------------------------------------------------------------------
Elimination of decommissioning expense........ 26 52
Depreciation of asset retirement cost......... (1) (2)
Accretion of ARO liability.................... (9) (18)
Income tax effect............................. (7) (13)
-----------------------------------------------------------------------------
Net earnings effect........................... 9 19
-----------------------------------------------------------------------------
Net income adjusted........................... $217 $345
============================================================================
Basic earnings per share of common stock:
Net income as previously reported............. $0.71 $1.11
Adjustment for effect of change in
accounting principle applied retroactively.. .03 0.06
-----------------------------------------------------------------------------
Net income adjusted........................... $0.74 $1.17
============================================================================
Diluted earnings per share of common stock:
Net income as previously reported............. $0.70 $1.10
Adjustment for effect of change in
accounting principle applied retroactively.. 0.03 0.06
----------------------------------------------------------------------------
Net income adjusted........................... $0.73 $1.16
============================================================================
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.
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 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-
17
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, increasing assets and
liabilities by $11.6 million.
Issued by the FASB in April 2003, SFAS 149 further clarifies and amends
accounting and reporting for derivative instruments. The statement amends SFAS
133 for decisions made by the Derivative Implementation Group (DIG), as well as
issues raised in connection with other FASB projects and implementation issues.
The statement is effective for contracts entered into or modified after June 30,
2003 except for implementation issues that have been effective for reporting
periods beginning before 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 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 immediately 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.
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.
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.
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 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.
18
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, 2002 JUNE 30, 2002
---------------------- ----------------------
2002 IMPACT OF RECORDING ENERGY TRADING NET REVENUES EXPENSES REVENUES EXPENSES
------------------------------------------------------------------------------------------------
RESTATED RESTATED
(SEE NOTE 1) (SEE NOTE 1)
(IN MILLIONS) (IN MILLIONS)
Total as originally reported............ $2,949 $2,323 $5,842 $4,725
Adjustment.............................. (50) (50) (90) (90)
------------------------------------------------------------------------------------------------
Total as currently reported............. $2,899 $2,273 $5,752 $4,635
===============================================================================================
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; corporate support
services and the international businesses acquired in the 2001 merger.
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.
19
SEGMENT FINANCIAL INFORMATION
REGULATED COMPETITIVE RECONCILING
SERVICES SERVICES OTHER ADJUSTMENTS CONSOLIDATED
--------- ----------- ----- ------------ ------------
(IN MILLIONS)
THREE MONTHS ENDED:
JUNE 30, 2003
External revenues..................... $ 2,083 $ 740 $ 22 $ 18(a) $ 2,863
Internal revenues..................... 233 512 147 (892)(b) --
Total revenues..................... 2,316 1,252 169 (874) 2,863
Depreciation and amortization......... 291 8 10 -- 309
Net interest charges.................. 132 11 104 (41)(b) 206
Income taxes.......................... 80 (31) (31) -- 18
Income before discontinued operations and
cumulative effect of accounting change 107 (44) (54) -- 9
Net income (loss)..................... 107 (44) (121) -- (58)
Total assets.......................... 30,123 2,499 1,403 -- 34,025
Property additions.................... 92 79 29 -- 200
JUNE 30, 2002 (RESTATED - SEE NOTE 1)
External revenues..................... $ 2,210 $ 590 $ 93 $ 6(a) $ 2,899
Internal revenues..................... 237 357 125 (719)(b) --
Total revenues..................... 2,447 947 218 (713) 2,899
Depreciation and amortization......... 282 6 12 -- 300
Net interest charges.................. 156 7 102 (15)(b) 250
Income taxes.......................... 196 5 (33) -- 168
Net income (loss)..................... 248 7 (47) -- 208
Total assets.......................... 30,261 2,010 2,009 -- 34,280
Property additions.................... 120 72 32 -- 224
SIX MONTHS ENDED:
JUNE 30, 2003
External revenues..................... $ 4,399 $1,605 $ 62 $ 31(a) $ 6,097
Internal revenues..................... 498 1,072 271 (1,841)(b) --
Total revenues..................... 4,897 2,677 333 (1,810) 6,097
Depreciation and amortization......... 597 16 21 -- 634
Net interest charges.................. 257 21 209 (75)(b) 412
Income taxes.......................... 234 (61) (61) -- 112
Income before discontinued operations and
cumulative effect of accounting change 323 (100) (104) -- 119
Net income (loss)..................... 424 (99) (164) -- 161
Total assets.......................... 30,123 2,499 1,403 -- 34,025
Property additions.................... 210 158 56 -- 424
JUNE 30, 2002 (RESTATED - SEE NOTE 1)
External revenues..................... $ 4,264 $1,175 $ 301 $ 12(a) $ 5,752
Internal revenues..................... 532 827 242 (1,601)(b) --
Total revenues..................... 4,796 2,002 543 (1,589) 5,752
Depreciation and amortization......... 573 13 24 -- 610
Net interest charges.................. 317 17 224 (29)(b) 529
Income taxes.......................... 358 (37) (59) -- 262
Net income (loss)..................... 447 (53) (68) -- 326
Total assets.......................... 30,261 2,010 2,009 -- 34,280
Property additions.................... 264 110 46 -- 420
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.
20
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------ ------------------------
2003 2002 2003 2002
---------- ---------- ---------- ----------
RESTATED RESTATED
(SEE NOTE 1) (SEE NOTE 1)
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
REVENUES:
Electric utilities..................................... $2,082,659 $2,210,316 $4,399,023 $4,264,292
Unregulated businesses................................. 780,487 688,257 1,697,879 1,487,559
------------ ------------ ----------- -----------
Total revenues..................................... 2,863,146 2,898,573 6,096,902 5,751,851
----------- ----------- ----------- -----------
EXPENSES:
Fuel and purchased power............................... 1,121,553 766,288 2,314,363 1,430,328
Purchased gas.......................................... 128,634 145,954 358,099 352,181
Other operating expenses............................... 907,854 914,906 1,806,900 1,925,619
Provision for depreciation and amortization............ 309,022 300,405 633,884 609,779
General taxes.......................................... 163,042 145,106 341,324 317,094
------------ ------------ ------------ ------------
Total expenses..................................... 2,630,105 2,272,659 5,454,570 4,635,001
----------- ----------- ----------- -----------
INCOME BEFORE INTEREST AND INCOME TAXES................... 233,041 625,914 642,332 1,116,850
------------ ------------ ------------ -----------
NET INTEREST CHARGES:
Interest expense....................................... 199,670 231,782 400,320 492,247
Capitalized interest................................... (7,622) (6,605) (16,774) (12,419)
Subsidiaries' preferred stock dividends................ 13,860 25,105 28,402 49,176
------------- ------------- --------------------------
Net interest charges............................... 205,908 250,282 411,948 529,004
------------ ------------ ------------ ------------
INCOME TAXES.............................................. 17,649 167,734 111,422 261,680
------------- ------------ ------------ ------------
INCOME BEFORE DISCONTINUED OPERATIONS AND
CUMULATIVE EFFECT OF ACCOUNTING CHANGE................. 9,484 207,898 118,962 326,166
Discontinued operations (net of income taxes of $3,700,000
in the six months period) (Note 3)..................... (67,372) -- (60,495) --
Cumulative effect of accounting change (net of income taxes
of $72,516,000) (Note 5)............................... -- -- 102,147 --
------------------------------------------------------------
NET INCOME (LOSS)......................................... $ (57,888) $ 207,898 $ 160,614 $ 326,166
============= =========== =========== ===========
BASIC EARNINGS (LOSS) PER SHARE OF COMMON STOCK:
Income before discontinued operations and cumulative
effect of accounting change.......................... $ .03 $ .71 $ .41 $1.11
Discontinued operations (net of income taxes) (Note 3). (.23) -- (.21) --
Cumulative effect of accounting change (net of income taxes)
(Note 5)............................................. -- -- .35 --
------- ------ ------ -----
Net income (loss)...................................... $ (.20) $ .71 $ .55 $1.11
====== ====== ====== =====
WEIGHTED AVERAGE NUMBER OF BASIC SHARES
OUTSTANDING............................................ 294,166 293,080 294,026 292,935
======= ======= ======= =======
DILUTED EARNINGS (LOSS) PER SHARE OF COMMON STOCK:
Income before discontinued operations and cumulative
effect of accounting change.......................... $ .03 $ .71 $ .40 $1.11
Discontinued operations (net of income taxes) (Note 3). (.23) -- (.21) --
Cumulative effect of accounting change (net of income taxes)
(Note 5).............................................. -- -- .35 --
------ ------ ------ -----
Net income (loss)...................................... $ (.20) $ .71 $ .54 $1.11
====== ====== ====== =====
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES
OUTSTANDING............................................ 295,888 294,589 295,355 294,472
======= ======= ======= =======
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK.............. $.375 $.375 $ .75 $ .75
===== ===== ====== ======
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)
JUNE 30, DECEMBER 31,
2003 2002
---------- -------------
RESTATED
(SEE NOTE 1)
(IN THOUSANDS)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents................................................. $ 64,204 $ 196,301
Receivables-
Customers (less accumulated provisions of $51,644,000 and $52,514,000
respectively, for uncollectible accounts)............................. 1,133,619 1,153,486
Other (less accumulated provisions of $8,003,000 and $12,851,000,
respectively, for uncollectible accounts)............................. 507,635 469,606
Materials and supplies, at average cost-
Owned................................................................... 292,728 253,047
Under consignment....................................................... 167,889 174,028
Other..................................................................... 327,847 203,630
------------- -------------
2,493,922 2,450,098
PROPERTY, PLANT AND EQUIPMENT:
In service................................................................ 21,460,203 20,372,224
Less--Accumulated provision for depreciation.............................. 9,152,201 8,552,927
------------- -------------
12,308,002 11,819,297
Construction work in progress............................................. 606,234 859,016
-------------- --------------
12,914,236 12,678,313
INVESTMENTS:
Capital trust investments................................................. 1,028,433 1,079,435
Nuclear plant decommissioning trusts...................................... 1,161,259 1,049,560
Letter of credit collateralization........................................ 277,763 277,763
Other..................................................................... 917,251 918,874
------------- -------------
3,384,706 3,325,632
DEFERRED CHARGES:
Regulatory assets......................................................... 8,088,548 8,753,401
Goodwill.................................................................. 6,249,363 6,278,072
Other..................................................................... 893,765 900,837
-------------- --------------
15,231,676 15,932,310
-------------- --------------
$34,024,540 $34,386,353
============== ==============
22
FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
JUNE 30, DECEMBER 31,
2003 2002
----------- -------------
RESTATED
(SEE NOTE 1)
(IN THOUSANDS)
CAPITALIZATION AND LIABILITIES
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock...................... $ 1,328,415 $ 1,702,822
Short-term borrowings..................................................... 1,045,067 1,092,817
Accounts payable.......................................................... 857,724 906,468
Accrued taxes............................................................. 474,754 455,121
Other..................................................................... 982,520 1,093,815
----------- -----------
4,688,480 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................................................... 6,121,164 6,120,341
Accumulated other comprehensive loss.................................... (534,084) (656,148)
Retained earnings....................................................... 1,575,153 1,634,981
Unallocated employee stock ownership plan common stock -
3,378,651 and 3,966,269 shares, respectively (67,246) (78,277)
----------- -----------
Total common stockholders' equity................................... 7,124,751 7,050,661
Preferred stock of consolidated subsidiaries-
Not subject to mandatory redemption..................................... 335,123 335,123
Subject to mandatory redemption......................................... 18,517 18,521
Subsidiary-obligated mandatorily redeemable preferred securities.......... 284,834 409,867
Long-term debt............................................................ 11,239,278 10,872,216
----------- -----------
19,002,503 18,686,388
DEFERRED CREDITS:
Accumulated deferred income taxes......................................... 2,066,541 2,069,682
Accumulated deferred investment tax credits............................... 224,759 236,184
Asset retirement obligations.............................................. 1,144,564 --
Nuclear plant decommissioning costs....................................... -- 1,243,558
Power purchase contract loss liability.................................... 3,022,798 3,136,538
Retirement benefits....................................................... 1,723,069 1,564,930
Lease market valuation liability.......................................... 1,063,600 1,106,000
Other..................................................................... 1,088,226 1,092,030
----------- -----------
10,333,557 10,448,922
COMMITMENTS, GUARANTEES AND CONTINGENCIES (NOTE 2)...........................
----------- -----------
$34,024,540 $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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
----------------------- -----------------------
2003 2002 2003 2002
--------- --------- --------- -----------
RESTATED RESTATED
(SEE NOTE 1) (SEE NOTE 1)
(IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)......................................... $ (57,888) $ 207,898 $ 160,614 $ 326,166
Adjustments to reconcile net income (loss) to net cash from
operating activities-
Provision for depreciation and amortization........ 309,022 300,405 633,884 609,779
Nuclear fuel and lease amortization................ 15,578 19,598 30,496 40,563
Other amortization, net............................ (409) (4,386) (5,022) (7,923)
Deferred costs recoverable as regulatory assets.... 81,558 (55,136) 42,810 (146,070)
Deferred income taxes, net......................... (52,906) 33,517 (21,554) 12,500
Investment tax credits, net........................ (6,247) (6,967) (12,506) (13,713)
Disallowed regulatory assets (Note 4).............. 158,500 -- 152,500 --
Discontinued operations (Note 3)................... 67,372 -- 60,495 --
Cumulative effect of accounting change (Note 5).... -- -- (174,663) --
Receivables........................................ (58,659) (150,157) (60,557) (90,062)
Materials and supplies............................. (45,397) (21,742) (33,984) (3,579)
Accounts payable................................... (27,928) 47,766 (35,043) 44,762
Accrued taxes...................................... (75,699) 4,422 21,854 86,719
Accrued interest................................... (105,277) (106,136) (15,678) (19,557)
Deferred lease costs............................... (62,370) (142,892) (79,962) (98,492)
Prepayments........................................ (50,885) (128,937) (120,558) (19,386)
Other.............................................. (66,634) 264,870 (59,133) 4,500
----------- ----------- ----------- -----------
Net cash provided from operating activities...... 21,731 262,123 483,993 726,207
----------- ---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt....................................... 722,041 261,699 1,019,737 366,730
Short-term borrowings, net........................... 189,741 -- -- 30,551
Redemptions and Repayments-
Preferred stock...................................... (125,337) (5,000) (125,337) (190,299)
Long-term debt....................................... (815,166) (194,738) (1,016,032) (378,643)
Short-term borrowings, net........................... -- (85,005) (47,749) --
Common stock dividend payments......................... (110,284) (109,876) (220,443) (219,602)
---------- ----------- ----------- ----------
Net cash used for financing activities........... (139,005) (132,920) (389,824) (391,263)
---------- ----------- ----------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions..................................... (199,742) (224,399) (424,161) (419,691)
Proceeds from sale of assets........................... 5,877 155,034 66,449 155,034
Proceeds from note receivable.......................... 19,000 -- 19,000 --
Avon cash and cash equivalents (Note 3)................ -- (380,496) -- 31,326
Proceeds from nonutility generation trusts............. -- -- 106,327 --
Cash investments....................................... (9,650) 68,365 15,065 64,022
Other.................................................. 75,957 (36,374) (8,946) (26,763)
----------- ----------- ------------ -----------
Net cash used for investing activities........... (108,558) (417,870) (226,266) (196,072)
---------- ---------- ---------- ----------
Net increase (decrease) in cash and cash equivalents...... (225,832) (288,667) (132,097) 138,872
Cash and cash equivalents at beginning of period.......... 290,036 647,717 196,301 220,178
---------- ---------- ---------- ----------
Cash and cash equivalents at end of period................ $ 64,204 $ 359,050 $ 64,204 $ 359,050
========== ========= ========== =========
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 June 30, 2003, and the related consolidated
statements of income and cash flows for each of the three-month and six-month
periods ended June 30, 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 quarter ended June 30, 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 Notes 2(M) and 8, which are 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
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). International assets were acquired as part of FirstEnergy's
acquisition of GPU, Inc. in November 2001. GPU Capital, Inc. and its
subsidiaries provided electric distribution services in foreign countries (see
Results of Operations - Discontinued Operations). 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
assets (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. 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 (MYR).
RESTATEMENTS
As further discussed in Note 1 to the Consolidated Financial
Statements, FirstEnergy determined that it was appropriate to restate its
consolidated financial statements for the year ended December 31, 2002 and the
three months ended March 31, 2003. The revisions 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 $49.7 million for the three months and
$82.1 million for the six months ended June 30, 2002.
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
26
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 $722 million (CEI - $611; 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 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
FirstEnergy experienced a net loss in the second quarter of 2003 of
$57.9 million, or loss of $(0.20) per share of common stock (basic and diluted),
compared to net income of $207.9 million, or earnings of $0.71 per share of
common stock (basic and diluted) in the second quarter of 2002. Results in the
second quarter of 2003 included an after-tax charge of $67.4 million or $0.23
per share of common stock (basic and diluted) resulting from the abandonment of
FirstEnergy's shares in Emdersa's parent company, GPU Argentina Holdings, Inc.
on April 18, 2003. During the first six months of 2003, net income was $160.6
million, or basic earnings of $0.55 per share of common stock ($0.54 diluted),
compared to $326.2 million, or earnings of $1.11 per share of common stock
(basic and diluted) in the first half of 2002. Net income in the first half of
2003 included a $60.5 million after-tax charge for discontinued operations in
Argentina and an after-tax credit of $102.1 million resulting from the
cumulative effect of an accounting change due to the adoption of SFAS No. 143,
"Accounting for Asset Retirement Obligations." Income before discontinued
operations and the cumulative effect of an accounting change was $9.5 million,
or $0.03 per share of common stock (basic and diluted) in the second quarter and
$119.0 million, or basic earnings of $0.41 per share of common stock ($0.40
diluted) in the first six months of 2003.
Results in the second quarter of 2003 were adversely affected by mild
weather which reduced revenues after benefiting from unusually cold weather
earlier in the year. Expenses in both periods were higher due to a $158.5
million charge for costs disallowed in the JCP&L rate case decision (see State
Regulatory Matters - New Jersey), replacement power and additional nuclear
expenses related to the extended outage at the Davis-Besse Nuclear Power Station
(see Davis-Besse Restoration) and additional unplanned work performed during two
nuclear refueling outages in the second quarter of 2003. Incremental costs of
the extended outage at Davis-Besse reduced basic and diluted earnings per share
of common stock by $0.13 in the second quarter and $0.30 in the first six months
of 2003, compared to $.09 for both corresponding periods of 2002. Higher
employee benefit expenses also contributed to increased costs in the second
quarter and first six months of 2003 compared to the corresponding periods last
year. However, the absence in the first six months of 2003 of the unusual
charges incurred in the corresponding period of 2002 partially offset the higher
costs in 2003.
Reclassifications of Previously Reported Income Statement
FirstEnergy recorded an increase to income during the six months ended
June 30, 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 as
part of normal 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 to the Consolidated Statement of Income previously reported for the
six months ended June 30, 2002 are reflected in the restatements 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 on the Consolidated Statements of Income. FirstEnergy had
previously reported such contracts as gross revenues and purchased power costs.
Therefore, revenues and expenses for the second quarter and first six months of
2002 have been reclassified (see Implementation of Accounting Standard).
27
In April 2003, FirstEnergy divested its ownership of Emdersa -- see
Note 3. As part of the abandonment, FirstEnergy recognized a one-time, non-cash
charge of $67.4 million. The charge does not include the anticipated 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. Discontinued operations for the
six-month period of 2003 totaled $60.5 million and included $6.9 million of
after-tax earnings from the Argentina operation from the first quarter of 2003 -
previously reported as $10.7 million of revenue, $0.1 million of expenses and
$3.7 million of income taxes.
Revenues
Total revenues decreased $35.4 million in the second quarter of 2003,
compared to the same period last year, primarily due to lower retail regulated
electric sales and reduced international sales reflecting the May 2002 sale of a
79.9% interest in Avon. Increased revenues from competitive services, primarily
electric sales to wholesale customers, partially offset the decrease in
regulated electric retail and international revenues in the second quarter of
2003. In the first six months of 2003, revenues increased $345.1 million
compared to the same period of 2002 from increased regulated and competitive
sales, offset in part by reduced international sales from the partial sale of
Avon. Sources of changes in revenues during the second quarter and first six
months of 2003 compared to the corresponding periods of 2002 are summarized in
the following table:
SOURCES OF REVENUE CHANGES THREE MONTHS SIX MONTHS
-------------------------------------------------------------------
INCREASE (DECREASE) (IN MILLIONS)
Electric Utilities (Regulated Services):
Retail electric sales................. $ (151.2) $ (43.0)
Wholesale electric sales ............. 39.2 178.8
All other revenues.................... (15.8) (2.4)
-------------------------------------------------------------------
Total Electric Utilities................. (127.8) 133.4
------------------------------------------------------------------
Unregulated Businesses (Competitive Services):
Retail electric sales................. 48.3 115.0
Wholesale electric sales.............. 195.8 429.5
Gas sales............................. (32.1) 11.8
FSG................................... (51.5) (93.9)
MYR................................... (25.7) (53.2)
Other................................. 15.3 21.8
------------------------------------------------------------------
Total Unregulated Businesses............. 150.1 431.0
------------------------------------------------------------------
International............................ (70.3) (243.3)
Other.................................... 12.6 24.0
------------------------------------------------------------------
Net Change in Revenue.................... $ (35.4) $ 345.1
==================================================================
Electric Sales
Retail sales by FirstEnergy's electric utility operating companies
(EUOC) decreased by $151.2 million in the second quarter of 2003 and by $43.0
million in the first six months of 2003 from the corresponding periods of 2002.
Changes in electric generation kilowatt-hour sales and distribution
deliveries in the second quarter and first six months of 2003 from the same
periods of 2002 are summarized in the following table:
CHANGES IN KILOWATT-HOUR SALES THREE MONTHS SIX MONTHS
---------------------------------------------------------------------------------
INCREASE (DECREASE)
Electric Generation Sales:
Retail -
Regulated services....................... (10.8)% (4.4)%
Competitive services..................... 62.8% 90.2%
Wholesale.................................. 130.1% 135.8%
---------------------------------------------------------------------------------
Total Electric Generation Sales.............. 15.9% 23.2%
=================================================================================
EUOC Distribution Deliveries:
Residential................................ (5.6)% 5.6%
Commercial................................. (0.3)% 5.5%
Industrial................................. (2.6)% (0.8)%
----------------------------------------------------------------------------------
Total Distribution Deliveries................ (2.8)% 3.3%
=================================================================================
28
Reduced air-conditioning load due to cooler-than-normal temperatures,
continued sluggishness in the economy and increased sales by alternative
suppliers all combined to decrease regulated retail generation sales revenue by
$107.9 million in the second quarter of 2003 compared to the same quarter of
2002. These factors also accounted for most of the $112.6 million decrease in
retail generation sales revenue in the first half of 2003 compared to the same
period last year. Kilowatt-hour sales of electricity by alternative suppliers in
FirstEnergy's franchise areas increased by 7.1 percentage points in the second
quarter and 6.4 percentage points in the first half of 2003 from the
corresponding periods last year.
Revenues from distribution deliveries decreased by $32.8 million or
2.7% in the second quarter of 2003 compared to the second quarter of 2002 due in
part to cooler-than-normal temperatures which reduced the air-conditioning load
of residential and commercial customers. Weather also contributed to the $99.4
million (5.6%) increase in distribution deliveries to residential and commercial
customers in the first half of 2003 from the same period last year. Temperatures
ranged from 20% to 30% colder in the first three months of 2003 than the same
period last year adding to heating-related loads. Sluggish economic conditions
in both the second quarter and first half of 2003 contributed to reduced
distribution deliveries to industrial customers from the corresponding periods
last year.
Further contributing to the decrease in retail electric revenues were
Ohio transition plan incentives provided to customers to promote customer
shopping for alternative suppliers - $10.4 million of additional credits in the
second quarter and $24.8 million of credits in the first half of 2003 compared
to the same periods 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 $39.2 million in the
second quarter and $178.8 million in the first six months of 2003, from the same
periods last year. Substantially all of those increases resulted from the
auction of JCP&L's basic 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 $244.1 million in the second quarter and $544.5 million in the first
six months of 2003 from the corresponding periods of 2002, primarily from
additional sales to the wholesale market ($195.8 million in the second quarter
and $429.5 million in the first half of 2003). The increases resulted
principally from sales into the New Jersey market as FES began supplying a
portion of that state's BGS in September 2002. Retail sales by FirstEnergy's
competitive services segment increased by $48.3 million in the second quarter
and $115.0 million in the first six months of 2003 from the same periods of
2002. The increases primarily resulted from retail customers within
FirstEnergy's Ohio franchise areas switching to FES under Ohio's electricity
choice program.
FirstEnergy's regulated and unregulated subsidiaries record purchase
and sale 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 and six months ended
June 30, 2003 and 2002 are summarized as follows:
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
2003 2002 2003 2002
-------------------------------------------------------------------
(IN MILLIONS)
Sales................ $206 $ 35 $544 $67
Purchases............ 225 117 579 197
-------------------------------------------------------------------
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 in the wholesale market.
Nonelectric Sales
Nonelectric sales revenues of the competitive services segment declined
by $94.0 million in the second quarter and $113.4 million in the first six
months of 2003 from the corresponding periods of 2002. The reduced revenues from
FSG reflected the divestiture in early 2003 of its Colonial Mechanical and Webb
Technologies subsidiaries (accounting for the majority of the decreases), as
well as declines associated with weak economic conditions. MYR also experienced
revenue reductions resulting from the sluggish economic environment. Natural gas
sales were $32.1 million lower in the second quarter of 2003, but increased
$11.8 million in the year-to-date period from the corresponding periods last
year. Trends from
29
the first quarter of 2003 continued into the second quarter with higher unit
prices and reduced volumes. However, the reduction in gas sales volumes
accelerated in the second quarter of 2003 as FES focused its operations in a
narrower geographic area and on higher margin gas customers which resulted in a
decline in sales volume that more than offset the effect of higher gas costs.
International Revenues
International revenues declined $70.3 million in the second quarter and
$243.3 million in the first six months of 2003 from the corresponding periods
last year 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 second quarter and first six months
of 2003.
Expenses
Total expenses increased $357.4 million in the second quarter and
$819.6 million in the first six months of 2003 from the same periods of 2002.
Sources of changes in expenses in the second quarter and first six months of
2003 compared to the corresponding periods of 2002 are summarized in the
following table:
SOURCES OF EXPENSE CHANGES THREE MONTHS SIX MONTHS
--------------------------------------------------------------------------
INCREASE (DECREASE) (IN MILLIONS)
Fuel and purchased power.............. $355.3 $ 884.1
Purchased gas......................... (17.3) 5.9
Other operating expenses.............. (7.1) (118.7)
Depreciation and amortization......... 8.6 24.1
General taxes......................... 17.9 24.2
--------------------------------------------------------------------------
NET INCREASE IN EXPENSES................ $357.4 $ 819.6
==========================================================================
The increases in expenses in the second quarter and first six months of
2003 compared to the same periods of 2002 resulted from increased purchased
power costs - $375.2 million higher in the second quarter and $910.4 million
higher in the first six months of 2003. The higher costs resulted from $152.5
million of purchased power costs disallowed in the JCP&L rate case decision (see
State Regulatory Matters - New Jersey), additional volumes to cover supply
obligations assumed by FES for BGS sales to the New Jersey market, as well as
other wholesale commitments, and additional supplies required to replace reduced
nuclear generation. The combined effect of the extended Davis-Besse outage and
additional unplanned work performed during the refueling outages at the Perry
Plant and Beaver Valley Unit 1 reduced nuclear generation by 33.5% in the second
quarter and 24.6% in the first six months of 2003 from the corresponding periods
last year. Fuel expenses were $19.9 million and $26.4 million lower in the
second quarter and first half of 2003, respectively, from the same periods of
2002, primarily reflecting reduced generation. Purchased gas costs decreased by
$17.3 million in the second quarter of 2003 compared to the same period of 2002
due to lower volumes purchased to meet reduced sales levels, partially offset by
higher unit costs.
Other operating expenses decreased $7.1 million in the second quarter
of 2003 compared to the same period of 2002, primarily due to reduced business
volume from domestic energy-related businesses ($75.7 million) and decreased
international expenses as a result of the sale of Avon ($31.1 million). The
reduced volume of energy-related business reflects the sale in early 2003 of
Colonial Mechanical and Webb Technologies businesses ($30.3 million), as well as
continued declines associated with weak economic conditions. Partially
offsetting these lower expenses were increased costs resulting from the
Davis-Besse extended outage, unplanned work performed during the refueling
outages at the Perry Plant and Beaver Valley Unit 1 in the second quarter of
2003, higher administration and general costs of $43.8 million (principally
employee benefit costs - see Employee Benefit Plan Costs) and a $12.6 million
impairment of a note receivable related to the sale of 79.9% of Avon. Nuclear
nonfuel operating costs in the second quarter of 2003 were $61.7 million higher,
including $10.3 million of additional incremental expense from the Davis-Besse
extended outage.
In the first six months of 2003, other operating expenses decreased
$118.7 million as a result of the same factors which influenced the second
quarter comparison: reduced business volume from domestic energy-related
businesses ($141.8 million) and decreased international expenses as a result of
the sale of Avon ($103.8 million). The sale of Colonial and Webb reduced
expenses by $57.8 million in the first six months of 2003 compared to the same
period of 2002. The absence of unusual charges recorded in the first six months
of 2002 resulted in a further net reduction of other operating expenses ($59.4
million) from the corresponding period last year. Offsetting a portion of these
lower expenses in the first half of 2003 were increased nuclear costs resulting
from the extended Davis-Besse outage, unplanned work performed during the
refueling outages in the second quarter of 2003 and higher administrative and
general costs of $133.4 million (principally employee benefit costs). Nuclear
nonfuel operating costs increased $88.1 million in the first six months of 2003
from the same period of 2002, including $46.5 million of additional incremental
expense related to the Davis-Besse extended outage.
30
Charges for depreciation and amortization increased by $8.6 million in
the second quarter of 2003 compared to the corresponding three-month period of
2002. The higher charges primarily resulted from five factors - increased
amortization of the Ohio transition regulatory assets ($17.9 million),
recognition of depreciation on four power plants ($10.0 million) which had been
held pending sale in the second quarter of 2002, but were subsequently retained
by FirstEnergy in the fourth quarter of 2002, costs of $6.0 million disallowed
in the JCP&L rate case decisions (see State Regulatory Matters - New Jersey) and
reduced regulatory asset deferrals in 2003 ($7.1 million). Partially offsetting
these increases in depreciation and amortization were higher shopping incentive
deferrals in Ohio ($10.4 million), lower charges resulting from the
implementation of SFAS 143 ($11.5 million) and revised service life assumptions
for generating plants ($6.5 million).
In the first six months of 2003, depreciation and amortization
increased $24.1 million as a result of the same factors which influenced the
second quarter comparison - increased amortization of the Ohio transition
regulatory assets ($42.1 million), recognition of depreciation on four power
plants ($19.6 million) which had been held pending sale in the first half of
2002, costs of $6.0 million disallowed in the JCP&L rate case decision and
reduced regulatory asset deferrals in 2003 ($15.0 million). Partially offsetting
these increases in depreciation and amortization were higher shopping incentive
deferrals in Ohio ($24.8 million), lower charges resulting from the
implementation of SFAS 143 ($26.0 million) and revised service life assumptions
for generating plants ($12.7 million).
General taxes increased $17.9 million in the second quarter and $24.2
million in the first six months of 2003 compared to the same periods last year.
Higher payroll and kilowatt-hour taxes in 2003 and a $9 million energy
assessment credit adjustment that reduced general taxes in the second quarter of
2002 were the principal factors contributing to the increases.
Net Interest Charges
Net interest charges decreased $44.4 million in the second quarter and
$117.1 million in the first six months of 2003 compared to the same periods of
2002, due to previous debt and preferred stock redemptions and refinancing
activities and the sale of a 79.9% interest in Avon in 2002. Redemption and
refinancing activities during the first six months of 2003 totaled $415 million
and $835 million (including $213 million of pollution control note repricings),
respectively, and are expected to result in annualized savings of approximately
$47 million. Partially offsetting these savings are interest charges on
additional borrowings under revolving bank credit facilities.
FirstEnergy also exchanged existing fixed-rate payments on outstanding
debt (principal amount of $550 million as of June 30, 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 $7.8 million in the second quarter and $14.6 million in the first six
months of 2003, compared to the corresponding periods of 2002 as a result of the
lower variable rates paid under these agreements. FirstEnergy also closed out
$168.5 million (notional amount) of interest rate swap transactions in the
second quarter of 2003 and recognized gains of $5.7 million.
Discontinued Operations
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.
Cumulative Effect of Accounting Change
Results for the first six months of 2003 include an after-tax credit to
net income of $102.1 million recorded upon the adoption of SFAS 143 in January
2003 (see discussion below). FirstEnergy identified applicable legal obligations
as defined under the new standard for nuclear power plant decommissioning,
reclamation of a sludge disposal pond at the Bruce Mansfield Plant and two coal
ash disposal sites. As a result of adopting SFAS 143 in January 2003, asset
retirement costs of $602 million were recorded as part of the carrying amount of
the related long-lived asset, offset by accumulated depreciation of $415
million. The 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
31
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. That 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.
In the second quarter and first six months 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:
ENDED JUNE 30, 2003
-------------------------------------------------------------------------------------
EFFECT OF SFAS 143 THREE MONTHS SIX MONTHS
-------------------------------------------------------------------------------------
INCREASE (DECREASE) (IN MILLIONS)
Other operating expense
Cost of removal (previously included in depreciation) $ 0.1 $ 4.3
Depreciation
Elimination of decommissioning expense............... (22.3) (44.7)
Depreciation of asset retirement cost................ 0.3 2.2
Accretion of asset retirement liability.............. 10.5 20.4
Reclassification of cost of removal to expense ...... -- (3.9)
-----------------------------------------------------------------------------------
Net decrease to depreciation......................... (11.5) (26.0)
-----------------------------------------------------------------------------------
Other Income
Earnings on decommissioning trust balances........... 0.7 3.2
----------------------------------------------------------------------------------
Income taxes......................................... 4.9 10.2
----------------------------------------------------------------------------------
Net income effect.................................... $ 7.2 $ 14.7
==================================================================================
Employee Benefit Plan Costs
Sharp declines in equity markets since the second quarter of 2000 and a
reduction in FirstEnergy's assumed discount rate for pensions and other
post-employment benefit (OPEB) 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 by $44.6 million in
the second quarter and $93.8 million in the first six months of 2003 compared to
the same periods in 2002. The following table summarizes the net pension and
OPEB expense (excluding amounts capitalized) for the three months and six months
ended June 30, 2003 and 2002.
THREE MONTHS ENDED SIX MONTHS ENDED
PENSION AND OPEB EXPENSE (INCOME) JUNE 30, JUNE 30,
--------------------------------------------------------------------------------------
2003 2002 2003 2002
---------------------------------------------
(IN MILLIONS)
Pension............................ $27.4 $(0.7) $ 58.7 $ (4.5)
OPEB............................... 38.5 22.0 79.0 48.4
--------------------------------------------------------------------------------------
Total..............................$65.9 $21.3 $137.7 $43.9
======================================================================================
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.
32
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 through a wholesale contract. The competitive services segment includes
all competitive energy and energy-related services including commodity sales
(both electricity and natural gas) in the retail and wholesale markets,
marketing, generation, trading and sourcing of commodity requirements, as well
as other competitive energy services such as heating, ventilation 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.
Regulated Services
Net income decreased to $107.0 million in the second quarter of 2003,
compared to $247.5 million in the second quarter of 2002. In the first six
months of 2003, net income decreased to $424.1 from $447.2 million in the first
six months of 2002. The factors contributing to the changes in net income are
summarized in the following table:
REGULATED SERVICES THREE MONTHSSIX MONTHS
------------------------------------------------------------------------------
INCREASE (DECREASE) (IN MILLIONS)
Revenues...................................... $(130.5) $ 101.0
Expenses...................................... 149.6 408.4
------------------------------------------------------------------------------
Income Before Interest and Income Taxes....... (280.1) (307.4)
Net interest charges.......................... (23.6) (59.5)
Income taxes.................................. (116.0) (123.8)
-------------------------------------------------------------------------------
Decrease in Income Before Cumulative Effect of a
Change in Accounting.......................... (140.5) (124.1)
Cumulative effect of a change in accounting... -- 101.0
------------------------------------------------------------------------------
Net Income Decrease........................... $(140.5) $ (23.1)
==============================================================================
Lower generation sales and distribution deliveries combined to decrease
external electric revenues by $112.0 million in the second quarter of 2003
compared to the same quarter of 2002. Cooler than normal temperatures and a
continued sluggish economy reduced sales in the second quarter. Retail
generation sales were also adversely affected by additional kilowatt-hour sales
by alternative suppliers in the FirstEnergy franchise area. The remaining change
in sales primarily resulted from a decrease in energy-related revenues. Revenues
in the first six months of 2003 increased $101.0 million from the same period
last year due to a stronger first quarter performance in 2003 due in part to
colder than normal weather compared to the same period in 2002.
Expenses increased in the second quarter and first six months of 2003
from the corresponding periods of 2002. The increase in expenses in the second
quarter of 2003 resulted principally from a $117.8 million increase in purchased
power costs resulting from a $152.5 million charge related to the JCP&L rate
case. Additional factors included an $18.4 million increase in other operating
expenses, $8.1 million increase in depreciation and amortization expense and
$6.5 million increase in general taxes. In the first six months of 2003,
expenses increased $408.4 million from the same period of 2002. The increase in
expenses resulted principally from a $344.4 million increase in purchased power
costs due to higher sales to wholesale generation customers and the charge
resulting from the JCP&L rate case. The other expense factors in the first six
months of 2003 compared to the first six months of 2002 include a $32.4 million
increase in other operating expense, $24.7 million increase in depreciation and
amortization expense and $9.4 million increase in general taxes. Other operating
expenses in both the second quarter and first six months of 2003 increased in
part due to additional employee benefit costs from the corresponding periods of
2002. Depreciation and amortization expenses increased in the second quarter and
first six months of 2003 from the same periods last year due principally to four
factors - increased amortization of the Ohio transition regulatory assets,
recognition of depreciation on four power plants which had been pending sale in
the second quarter of 2002, but were subsequently retained by FirstEnergy in the
fourth quarter of 2002, the write-off of disallowed costs in the JCP&L rate case
and the termination of regulatory asset deferrals in February 2003. Partially
offsetting these increases in depreciation and amortization were higher shopping
tax incentive deferrals in Ohio and lower charges resulting from the
implementation of SFAS 143, including revised service life assumptions for
generating plants.
33
Competitive Services
Net losses increased to $44.0 million in the second quarter and $98.7
million in the first six months of 2003, compared to net income of $6.4 million
and a net loss of $53.3 million in the corresponding periods of 2002. The
factors contributing to the increased losses are summarized in the following
table:
COMPETITIVE SERVICES THREE MONTHS SIX MONTHS
-----------------------------------------------------------------------
INCREASE (DECREASE) (IN MILLIONS)
Revenues................................... $304.8 $674.7
Expenses................................... 387.5 741.4
-----------------------------------------------------------------------
Income Before Interest and Income Taxes.... (82.7) (66.7)
------------------------------------------------------------------------
Net interest charges....................... 3.1 4.1
Income taxes............................... (35.4) (24.2)
------------------------------------------------------------------------
Decrease in Income Before Cumulative Effect of
a Change in Accounting................... (50.4) (46.6)
Cumulative effect of a change in accounting -- 1.2
-------------------------------------------------------------------------
Net Income................................. $(50.4) $(45.4)
========================================================================
The increase in revenues in the second quarter and first six months of
2003, compared to the corresponding periods of 2002, includes the net effect of
several factors. Revenues from the electric wholesale market increased $195.8
million in the second quarter and $429.5 million in the first six months of 2003
from the same periods 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 $48.3
million in the second quarter and $115.0 million in the first six months of 2003
from the same periods last year as a result of expanding the FES business in
Ohio under Ohio's electricity choice program. Internal sales to the regulated
services segment increased $154.6 million in the second quarter and $244.9
million in the first six months of 2003 compared to the same periods of 2002
primarily reflecting sales to Met-Ed and Penelec in supplying a substantial
portion of their PLR requirements in Pennsylvania. Several factors partially
offset the increase in revenues.
Energy-related services such as heating, ventilation and
air-conditioning work reflected the divestiture in early 2003 of Colonial and
Webb, as well as continued declines associated with weak economic conditions.
Revenues from energy-related services decreased $77.2 million in the second
quarter and $147.1 million in the first six months of 2003 from the
corresponding periods of 2002.
Natural gas sales decreased $32.1 million in the second quarter, but
increased $11.8 million in the first six months of 2003 from the corresponding
periods last year. Gas revenue trends in the first quarter of 2003 continued
into the second quarter with higher unit prices and reduced volumes. However,
the reduction in gas sales volumes accelerated in the second quarter of 2003 as
FES focused its operations to a narrower geographic area and on higher-margin
gas customers with a resulting decline in volume that more than offset the
effect of higher prices.
Expenses increased $387.5 million in the second quarter and $741.4
million in the first six months of 2003 from the same periods of 2002 due to
purchased power costs, which increased $400.8 million in the second quarter and
$810.9 million in the first six months of 2003. The increases reflected the
higher sales combined with reduced internal generation. Expenses of
energy-related businesses declined $75.7 million in the second quarter and
$141.8 million in the first six months of 2003 from the corresponding periods
last year as a result of the divestiture of Colonial and Webb, as well as
continued declines associated with weak economic conditions. Other operating
expenses increased $99.0 million in the second quarter and $73.4 million in the
first six months of 2003 from the corresponding periods of 2002. Additional
costs resulting from the Davis-Besse extended outage, unplanned work performed
during two nuclear refueling outages in the second quarter of 2003 and higher
employee benefit costs all contributed to the increase in other operating
expenses. The absence of unusual charges recorded in 2002 moderated the increase
in operating expenses by $59.4 million in the year-to-date period of 2003
compared to the corresponding period of 2002. Purchased gas costs decreased
$17.3 million in the second quarter of 2003 compared to the second quarter of
last year as a result of reduced volumes required for gas sales.
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 materially 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
34
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 six months
of 2003, FirstEnergy received $485.0 million of cash dividends from its
subsidiaries and paid $220.4 million in cash common stock dividends to its
shareholders. There are no material restrictions on the payment of cash
dividends by FirstEnergy's subsidiaries.
As of June 30, 2003, FirstEnergy had $64.2 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 provided from operating activities during the second quarter and
first six months of 2003, compared with the corresponding periods of 2002 were
as follows:
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
----------------------------------------------
OPERATING CASH FLOWS 2003 2002 2003 2002
------------------------------------------------------------------------
(IN MILLIONS)
Cash earnings (1)........ $ 515 $ 495 $867 $856
Working capital and other (493) (233) (383) (130)
------------------------------------------------------------------------
Total.................... $ 22 $ 262 $484 $726
(1) Includes net income, depreciation and amortization,
deferred income taxes, investment tax credits and major
noncash charges.
Net cash provided from operating activities decreased $240 million due
to a $260 million change in funds used for working capital and a $20 million
increase in cash earnings. The change in funds used for working capital
primarily represents offsetting changes for receivables, sale and leaseback rent
payments, and prepayments.
Cash Flows From Financing Activities
The following table provides details regarding security issuances and
redemptions during the second quarter and first six months of 2003:
SECURITIES ISSUED OR REDEEMED THREE MONTHS SIX MONTHS
-------------------------------------------------------------------
(IN MILLIONS)
New Issues
Senior Notes........................ $159 $ 409
Long-Term Revolving Credit.......... 230 280
Unsecured Notes..................... 333 331
-------------------------------------------------------------------
$722 $1,020
Redemptions
First Mortgage Bonds................ $593 $ 633
Pollution Control Notes............. -- 50
Secured Notes....................... 222 333
------------------------------------------------------------------
$815 $1,016
Short-term Borrowings, Net............ $190 $ (48)
-------------------------------------------------------------------
Net cash used for financing activities increased by $6 million in the
second quarter of 2003 from the second quarter of 2002. The increase in funds
used for financing activities resulted from increased financing of $650 million
that was exceeded by $656 million of additional redemptions and repayments
during the second quarter of 2003 compared to the same period of 2002.
FirstEnergy had approximately $1.045 billion of short-term indebtedness
as of June 30, 2003 compared to $1.093 billion at the end of 2002. Available
borrowing capability included $151 million under $1.5 billion revolving lines of
credit and $59 million under bilateral bank facilities. As of June 30, 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.
35
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 June 30, 2003, JCP&L, Met-Ed and Penelec had the aggregate capability to
issue $737 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 $4.0 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 of
up to $2 billion. 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 were used to redeem
approximately $220 million of outstanding OE first mortgage bonds having a
weighted average cost of 7.99%, with the remainder used to pay down short-term
debt.
On May 22, 2003, JCP&L completed a $150 million refinancing transaction
that included one tranche - 4.8% Senior Notes due 2018. The proceeds of this
transaction were used in conjunction with short-term borrowing, to call and
redeem $78 million of medium term notes with a weighted average interest cost of
8.35% and $125 million of JCP&L Capital's Monthly Income Preferred Securities
(8.56%).
In May and June of 2003, OE executed four fixed-to-floating interest
rate swap agreements with notional values of $50 million each on underlying
senior notes with an average fixed rate of 5.09%. Counterparties closed $168.5
million of FirstEnergy fixed-to-floating interest rate swap agreements in the
second quarter of 2003 on which $5.7 million of gains were recognized. In July
2003, FirstEnergy executed a fixed-to-floating rate swap agreement with a fixed
rate of 4.80% on an underlying senior note.
Cash Flows From Investing Activities
Net cash used for investing activities totaled $109 million in the
second quarter and $226 million in the first six months of 2003, compared to net
cash of $418 million and $196 million, respectively, used for investing
activities for the same periods of 2002. The $309 million change in the second
quarter of 2003 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), and
decreased capital expenditures.
In May 2003, FirstEnergy received $19 million from Aquila as its first
annual installment payment on the note receivable FirstEnergy had as part of its
79.9 percent sale of Avon in May 2002. After receiving this payment, FirstEnergy
sold the remaining balance of its note receivable in the secondary market and
received $63.2 million in proceeds on July 28, 2003. On May 22, 2003,
FirstEnergy reached an agreement to sell its remaining 20.1% interest in Avon to
Scottish and Southern Energy. Under the terms of the agreement, FirstEnergy will
receive approximately $14 million, subject to bondholder approval.
The following table summarizes investments made in the second quarter
and first six months of 2003 by FirstEnergy's regulated services and competitive
services segments:
36
PROPERTY
SUMMARY OF CASH USED FOR INVESTING ACTIVITIES ADDITIONS INVESTMENTS OTHER TOTAL
SOURCES (USES) (IN MILLIONS)
THREE MONTHS ENDED JUNE 30, 2003
Regulated Services........................ $ (37) (1) $(69) $ 32 $ (74)
Competitive Services...................... (135) (2) 1 (22) (156)
Other..................................... (28) 47 102 (5) 121
Eliminations.............................. -- -- -- --
--------------------------------------------------------------------------------------------
Total............................ $(200) $(21) $112 $(109)
=============================================================================================
SIX MONTHS ENDED JUNE 30, 2003
Regulated Services........................ $(155) (1) $ 67 (3) $ 24 $(64)
Competitive Services...................... (214) (2) 64 (4) (93) (243)
Other..................................... (55) (30) 106 (5) 21
Eliminations.............................. -- -- 60 60
--------------------------------------------------------------------------------------------
Total............................ $(424) $ 101 $ 97 $(226)
=============================================================================================
(1) Property additions to distribution facilities.
(2) Property additions to generation facilities.
(3) Net of several items from cash investments and NUG trust offset in
part by investments in nuclear decommissioning trusts.
(4) Sale of assets - includes Colonial and Webb sale.
(5) Primarily a change in OCI from Emdersa abandonment (see Note 3).
During the second half of 2003, capital requirements for property
additions and capital leases are expected to be approximately $397 million,
including $31 million for nuclear fuel. FirstEnergy has additional requirements
of approximately $264 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 July 25, 2003, Standard & Poor's (S&P) issued comments on
FirstEnergy's debt ratings in light of the latest extension of the Davis-Besse
outage and the NJBPU decision on the JCP&L rate case. S&P noted that additional
costs from the Davis-Besse outage extension, the NJBPU ruling on recovery of
deferred energy costs and additional capital investments required to improve
reliability in the New Jersey shore communities will adversely affect
FirstEnergy's cash flow and deleveraging plans. S&P noted that it continues to
assess FirstEnergy's plans to determine if projected financial measures are
adequate to maintain its current rating.
On August 7, 2003, S&P affirmed its "BBB" corporate credit rating for
FirstEnergy. However, S&P stated that although FirstEnergy generates substantial
free cash, that its strategy for reducing debt had deviated substantially from
the one presented to S&P around the time of the GPU merger when the current
rating was assigned. S&P further noted that their affirmation of FirstEnergy's
corporate credit rating was based on the assumption that FirstEnergy would take
appropriate steps quickly to maintain its investment grade ratings including the
issuance of equity or possible sale of assets. Key issues being monitored by S&P
include the restart of Davis-Besse, FirstEnergy's liquidity position, its
ability to forecast provider-of-last-resort load and the performance of its
hedged portfolio, and continued capture of merger synergies. On August 11, 2003,
S&P stated that a recent U.S. District Court ruling (see Environmental Matters
below) with respect to the Sammis Plant is negative for FirstEnergy's credit
quality.
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 June 30, 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 on the Consolidated Balance Sheet as of June
30, 2003.
37
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 June 30, 2003, the maximum potential future payments under
outstanding guarantees and other assurances totaled approximately $1.0 billion
as summarized below:
MAXIMUM
GUARANTEES AND OTHER ASSURANCES EXPOSURE
(IN MILLIONS)
----------------------------------------------------------
FirstEnergy Guarantees of Subsidiaries:
Energy and Energy-Related Contracts(1)...... $ 855.0
Financings (2)(3)........................... 63.2
----------------------------------------------------------
918.2
Surety Bonds.................................. 24.5
Rating-Contingent Collateralization (4)....... 106.8
----------------------------------------------------------
Total Guarantees and Other Assurances....... $ 1,049.5
==========================================================
(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.
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.
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.
38
The change in the fair value of commodity derivative contracts
related to energy production during the second quarter and first six months of
2003 is summarized in the following table:
INCREASE (DECREASE) IN THE FAIR VALUE
OF COMMODITY DERIVATIVE CONTRACTS
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, 2003 JUNE 30, 2003
--------------------------- ----------------------------
NON-HEDGE HEDGE TOTAL NON-HEDGE HEDGE TOTAL
--------- ----- ----- --------- ----- -----
(IN MILLIONS)
CHANGE IN THE FAIR VALUE OF COMMODITY DERIVATIVE CONTRACTS
Net asset at beginning of period....................... $66.4 $42.9 $109.3 $ 53.8 $24.1 $ 77.9
New contract value when entered........................ -- -- -- -- -- --
Change in value of existing contracts.................. (1.4) 9.2 7.8 15.8 37.4 53.2
Change in techniques/assumptions....................... -- -- -- -- -- --
Settled contracts...................................... 1.0 (16.6) (15.6) (3.6) (26.0) (29.6)
---------------------------- -------------------------------
Net asset at end of period (1)......................... 66.0 35.5 101.5 66.0 35.5 101.5
--------------------------- -------------------------------
NON-COMMODITY NET ASSETS AT END OF PERIOD:
Interest Rate Swaps (2)............................. -- 13.2 13.2 -- 13.2 13.2
--------------------------- -------------------------------
NET ASSETS - DERIVATIVE CONTRACTS AT END OF PERIOD (3). $66.0 $ 48.7 $114.7 $ 66.0 $ 48.7 $114.7
=========================== ===============================
IMPACT OF CHANGES IN COMMODITY DERIVATIVE CONTRACTS (4)
Income Statement Effects (Pre-Tax)..................... $(0.9) $ -- $(0.9) $ (4.4) $ -- $ (4.4)
Balance Sheet Effects:
Other Comprehensive Income (Pre-Tax)................ $ -- $ (7.4) $(7.4) $ -- $ 11.4 $ 11.4
Regulatory Liability................................ $ 0.5 $ -- $ 0.5 $ 16.6$ -- $ 16.6
(1) Includes $50.8 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 $28.7 million of derivative contract fair value decrease, as of
June 30, 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 are included on the Consolidated Balance Sheet as of June
30, 2003 as follows:
NON-HEDGE HEDGE TOTAL
----------------------------------------------------------------------
(IN MILLIONS)
CURRENT-
Other Assets...................... $ 19.6 $18.5 $ 38.1
Other Liabilities................. (28.2) (1.6) (29.8)
NON-CURRENT-
Other Deferred Charges............ 75.8 32.4 108.2
Other Deferred Credits............ (1.2) (0.6) (1.8)
----------------------------------------------------------------------
Net assets........................ $ 66.0 $48.7 $ 114.7
======================================================================
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 commodity derivative contracts by year are summarized in the
following table:
SOURCE OF INFORMATION
- FAIR VALUE BY CONTRACT YEAR 2003(1) 2004 2005 2006 THEREAFTER TOTAL
-----------------------------------------------------------------------------------------------------------
(IN MILLIONS)
Prices actively quoted(2)............. $7.3 $7.9 $ (0.1) $ -- $ -- $15.1
Other external sources(3)............. 12.2 18.4 11.1 -- -- 41.7
Prices based on models................ -- -- -- 6.9 37.8 44.7
-----------------------------------------------------------------------------------------------------------
TOTAL(4)........................... $19.5 $26.3 $11.0 $6.9 $37.8 $101.5
===========================================================================================================
(1) For the last two quarters of 2003.
39
(2) Exchange traded.
(3) Broker quote sheets.
(4) Includes $50.8 million from an embedded option that is offset by a
regulatory liability and does not affect earnings.
40
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 June 30, 2003.
Based on derivative contracts held as of June 30, 2003, an adverse 10% change in
commodity prices would decrease net income by approximately $6.7 million during
the next twelve months.
Interest Rate Swap Agreements
During the second quarter of 2003, FirstEnergy entered into
fixed-to-floating interest rate swap agreements, as part of its ongoing effort
to manage the interest rate risk 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, fixed interest rates and interest
payment dates match those of the underlying obligations. The swap agreements
consummated in the second quarter of 2003 are based on a notional principal
amount of $200 million.
As of June 30, 2003, the debt underlying FirstEnergy's $550 million
notional amount of outstanding fixed-for-floating interest rate swaps had a
weighted average fixed interest rate of 5.69%, which the swaps have effectively
converted to a current weighted average variable interest rate of 2.32%. GPU
Power (through a subsidiary) used existing dollar-denominated interest rate swap
agreements in the first six months 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 June 30, 2003 and December 31, 2002. The following
summarizes the principal characteristics of the swap agreements:
JUNE 30, 2003 DECEMBER 31, 2002
---------------------------- -----------------------------
NOTIONAL MATURITY FAIR NOTIONAL MATURITY FAIR
INTEREST RATE SWAPS AMOUNT DATE VALUE AMOUNT DATE VALUE
--------------------------------------------------------------------
(DOLLARS IN MILLIONS)
Fixed to Floating Rate
(Fair value hedges) $200 2006 $ 6.5
50 2008 1.3
150 2015 (0.6) $444 2023 $15.5
150 2025 6.6 150 2025 5.9
Floating to Fixed Rate
(Cash flow hedges) $ 10 2005 $(0.6) $ 16 2005 $(0.9)
----------------------------------------------------------------------------------------------
Equity Price Risk
Included in FirstEnergy's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $623
million and $532 million as of June 30, 2003 and December 31, 2002,
respectively. A hypothetical 10% decrease in prices quoted by stock exchanges
would result in a $62 million reduction in fair value as of June 30, 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 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
41
EUOC non-nuclear generating assets to FGCO will be substantially completed by
the end of the Ohio 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
EUOCs' 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 by $664.9 million to $8.1 billion as of June 30, 2003 from the
balance as of December 31, 2002. Over one-half of the reduction in regulatory
assets resulted from the costs disallowed in the JCP&L rate case decision and
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
------------------------------------------------
JUNE 30, DECEMBER 31,
COMPANY 2003 2002
------------------------------------------------
(IN MILLIONS)
OE............... $1,689.9 $1,848.7
CEI.............. 1,148.3 1,191.8
TE............... 537.2 578.2
Penn............. 60.3 156.9
JCP&L............ 3,004.4 3,199.0
Met-Ed........... 1,091.0 1,179.1
Penelec.......... 557.4 599.7
----------------------------------------------
Total............ $8,088.5 $8,753.4
==============================================
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 megawatts 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.
42
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 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. On July 25, 2003, the NJBPU
announced its JCP&L base electric rate proceeding decision which reduces JCP&L's
annual revenues by approximately $62 million effective August 1, 2003. The NJBPU
decision also provided for an interim return on equity of 9.5 percent on JCP&L's
rate base for the next 6 to 12 months. During that period, JCP&L will initiate
another proceeding to request recovery of additional costs incurred to enhance
system reliability. In that proceeding, the NJBPU could increase the return on
equity to 9.75 percent or decrease it to 9.25 percent, depending on its
assessment of the reliability of JCP&L's service. Any reduction would be
retroactive to August 1, 2003. The revenue decrease in the decision consists of
a $223 million decrease in the electricity delivery charge, a $111 million
increase due to the August 1, 2003 expiration of annual customer credits
previously mandated by the New Jersey transition legislation, a $49 million
increase in the MTC tariff component, and a net $1 million increase in the SBC
charge. The MTC would allow for the recovery of $465 million in deferred energy
costs over the next ten years on an interim basis, thus disallowing $152.5
million. JCP&L also announced on July 25, 2003 that it is reviewing the NJBPU
decision and will decide on its appropriate course of action, which could
include filing an appeal for reconsideration with the NJBPU and possibly an
appeal to the Appellate Division of the Superior Court of New Jersey.
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 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. 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.
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:
- 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
43
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.
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 fall 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).
Incremental costs associated with the extended Davis-Besse outage for
the second quarter and first six months of 2003 and 2002 were as follows:
THREE MONTHS ENDED SIX MONTHS ENDED
COSTS OF DAVIS-BESSE EXTENDED OUTAGE JUNE 30, JUNE 30
---------------------------------------------------------------------------------
2003 2002 2003 2002
---- ---- ---- ----
(IN MILLIONS)
INCREMENTAL PRE-TAX EXPENSE
Replacement power $41.1 $33.6 $ 93.4 $33.6
Maintenance 22.4 12.1 58.6 12.1
----------------------------------------------------------------------------------
Total $63.5 $45.7 $152.0 $45.7
==================================================================================
CAPITAL EXPENDITURES $ 2.4 $12.0 $ 2.4 $12.0
==================================================================================
It is anticipated that an additional $22 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 months of July and August.
FirstEnergy has hedged the on-peak replacement energy supply for
Davis-Besse for the expected length of the outage.
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.
44
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 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
required 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 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.
Several EUOCs 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 June 30, 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 $53.8
million as of June 30, 2003.
45
The effects of compliance on the EUOCs 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.
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.
Legal Matters
It is FirstEnergy's understanding, 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 above.
IMPLEMENTATION OF 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 on 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 (1.4 billion
kilowatt-hours in the second quarter and 2.7 billion kilowatt-hours in the first
six months of 2002). The following table displays the impact of changing to a
net presentation for FirstEnergy's energy trading operations.
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, 2002 JUNE 30, 2002
------------------------ ----------------------
IMPACT OF RECORDING ENERGY TRADING NET REVENUES EXPENSES REVENUES EXPENSES
---------------------------------------------------------------------------------------------------------
(IN MILLIONS)
Total as originally reported....................... $2,949 $2,323 $5,842 $4,725
Adjustment......................................... (50) (50) (90) (90)
----------------------------------------------------------------------------------------------------------
Total as currently reported........................ $2,899 $2,273 $5,752 $4,635
=========================================================================================================
46
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 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 - $8.1 billion as of June 30, 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:
o Net energy generated or purchased for retail load
o Losses of energy over transmission and distribution lines
o Mix of kilowatt-hour usage by residential, commercial and industrial
customers
o Kilowatt-hour usage of customers receiving electricity from
alternative suppliers
47
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory defined
pension and OPEB benefits 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 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 2002 were computed assuming a 10.25% rate of return on plan
assets. Beginning in 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 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
48
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 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 June 30, 2003, FirstEnergy had $6.3 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.
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 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 $11.6 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 (DIG), 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
reporting periods beginning before 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.
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 immediately 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.
49
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. 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.
50
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) EXHIBITS
FIRSTENERGY
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.
Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K,
FirstEnergy has not 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 the
total assets of FirstEnergy and its subsidiaries on a consolidated
basis, but hereby agrees to furnish to the Commission on request any
such documents.
(b) REPORTS ON FORM 8-K
FIRSTENERGY-
FirstEnergy filed fifteen reports on Form 8-K since March 31, 2003. 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 ready for restart schedule. A report dated May 9, 2003
reported updated Davis-Besse information and a JCP&L rate proceeding 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
million net of tax charge with no effect on previously reported net income. A
report dated May 22, 2003 reported that FirstEnergy had reached an agreement to
sell its remaining 20.1 percent interest in Avon. A report dated June 5, 2003
reported updated Davis-Besse information. A report dated June 11, 2003 reported
that FirstEnergy subsidiaries, Met-Ed and Penelec, filed a letter with a
Pennsylvania Public Utility Commission Administrative Law Judge which voids the
2001 settlement stipulation previously entered into by Met-Ed and Penelec. A
report dated June 27, 2003 reported a JCP&L settlement agreement with all the
parties in its base rate case proceeding except for the Board of Public
Utilities Regulatory Staff and the Division of the Ratepayer Advocate. A report
dated July 24, 2003 reported an updated Davis-Besse ready for restart schedule
and cost estimates. A report dated July 25, 2003 reported the New Jersey Board
of Public Utilities decision on JCP&L's rate proceedings. A report dated August
5, 2003 reported FirstEnergy's second quarter 2003 earnings results and other
information. A report dated August 5, 2003 reported the pending restatement of
2002 FE, OE, CEI and TE financial statements and restatement and reaudit of 2001
CEI and TE financial statements. A report dated August 7, 2003 reported the
pending restatement and reaudit of 2000 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. A report dated August 28,
2003 reported FirstEnergy's financial status and liquidity. A report dated
September 8, 2003 reported the announcement of a public offering of additional
common stock and a Regulation G reconciliation of a non-GAAP financial measure,
free cash flow, presented in connection with the offering.
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
September 11, 2003
FIRSTENERGY CORP.
Registrant
/s/ Harvey L. Wagner
-----------------------------------
Harvey L. Wagner
Vice President, Controller
and Chief Accounting Officer
52