FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
(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
1-2578 OHIO EDISON COMPANY 34-0437786
(AN OHIO CORPORATION)
76 SOUTH MAIN STREET
AKRON, OH 44308
TELEPHONE (800)736-3402
1-2323 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY 34-0150020
(AN OHIO CORPORATION)
C/O FIRSTENERGY CORP.
76 SOUTH MAIN STREET
AKRON, OH 44308
TELEPHONE (800)736-3402
1-3583 THE TOLEDO EDISON COMPANY 34-4375005
(AN OHIO CORPORATION)
C/O FIRSTENERGY CORP.
76 SOUTH MAIN STREET
AKRON, OH 44308
TELEPHONE (800)736-3402
1-3491 PENNSYLVANIA POWER COMPANY 25-0718810
(A PENNSYLVANIA CORPORATION)
C/O FIRSTENERGY CORP.
76 SOUTH MAIN STREET
AKRON, OH 44308
TELEPHONE (800)736-3402
1-3141 JERSEY CENTRAL POWER & LIGHT COMPANY 21-0485010
(A NEW JERSEY CORPORATION)
C/O FIRSTENERGY CORP.
76 SOUTH MAIN STREET
AKRON, OH 44308
TELEPHONE (800)736-3402
1-446 METROPOLITAN EDISON COMPANY 23-0870160
(A PENNSYLVANIA CORPORATION)
C/O FIRSTENERGY CORP.
76 SOUTH MAIN STREET
AKRON, OH 44308
TELEPHONE (800)736-3402
1-3522 PENNSYLVANIA ELECTRIC COMPANY 25-0718085
(A PENNSYLVANIA CORPORATION)
C/O FIRSTENERGY CORP.
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
Ohio Edison Company, no par value 100
The Cleveland Electric Illuminating Company, no par value 79,590,689
The Toledo Edison Company, $5 par value 39,133,887
Pennsylvania Power Company, $30 par value 6,290,000
Jersey Central Power & Light Company, $10 par value 15,371,270
Metropolitan Edison Company, no par value 859,500
Pennsylvania Electric Company, $20 par value 5,290,596
FirstEnergy Corp. is the sole holder of Ohio Edison Company, The Cleveland
Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power &
Light Company, Metropolitan Edison Company and Pennsylvania Electric Company
common stock. Ohio Edison Company is the sole holder of Pennsylvania Power
Company common stock.
This combined Form 10-Q is separately filed by FirstEnergy
Corp., Ohio Edison Company, Pennsylvania Power Company, The Cleveland Electric
Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light
Company, Metropolitan Edison Company and Pennsylvania Electric Company.
Information contained herein relating to any individual registrant is filed by
such registrant on its own behalf. No registrant makes any representation as to
information relating to any other registrant, except that information relating
to any of the FirstEnergy subsidiary registrants is also attributed to
FirstEnergy.
This Form 10-Q 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.
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
OHIO EDISON COMPANY
Consolidated Statements of Income............................................................... 50
Consolidated Balance Sheets..................................................................... 51-52
Consolidated Statements of Cash Flows........................................................... 53
Report of Independent Auditors.................................................................. 54
Management's Discussion and Analysis of Results of Operations and
Financial Condition.......................................................................... 55-63
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
Consolidated Statements of Income............................................................... 64
Consolidated Balance Sheets..................................................................... 65-66
Consolidated Statements of Cash Flows........................................................... 67
Report of Independent Auditors.................................................................. 68
Management's Discussion and Analysis of Results of Operations and
Financial Condition.......................................................................... 69-78
THE TOLEDO EDISON COMPANY
Consolidated Statements of Income............................................................... 79
Consolidated Balance Sheets..................................................................... 80-81
Consolidated Statements of Cash Flows........................................................... 82
Report of Independent Auditors.................................................................. 83
Management's Discussion and Analysis of Results of Operations and
Financial Condition.......................................................................... 84-92
PENNSYLVANIA POWER COMPANY
Statements of Income............................................................................ 93
Balance Sheets.................................................................................. 94-95
Statements of Cash Flows........................................................................ 96
Report of Independent Auditors.................................................................. 97
Management's Discussion and Analysis of Results of Operations and
Financial Condition.......................................................................... 98-104
JERSEY CENTRAL POWER & LIGHT COMPANY
Consolidated Statements of Income............................................................... 105
Consolidated Balance Sheets..................................................................... 106-109
Consolidated Statements of Cash Flows........................................................... 108
Report of Independent Auditors.................................................................. 109
Management's Discussion and Analysis of Results of Operations and
Financial Condition.......................................................................... 110-118
TABLE OF CONTENTS (CONT'D)
PAGES
METROPOLITAN EDISON COMPANY
Consolidated Statements of Income............................................................... 119
Consolidated Balance Sheets..................................................................... 120-121
Consolidated Statements of Cash Flows........................................................... 122
Report of Independent Auditors.................................................................. 123
Management's Discussion and Analysis of Results of Operations and
Financial Condition.......................................................................... 124-132
PENNSYLVANIA ELECTRIC COMPANY
Consolidated Statements of Income............................................................... 133
Consolidated Balance Sheets..................................................................... 134-135
Consolidated Statements of Cash Flows........................................................... 136
Report of Independent Auditors.................................................................. 137
Management's Discussion and Analysis of Results of Operations and
Financial Condition.......................................................................... 138-146
CONTROLS AND PROCEDURES............................................................................... 146
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. FirstEnergy entered
into interest rate derivative transactions during 2001 to hedge a portion of the
anticipated interest
2
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 RESTATED
(SEE NOTE 1) (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 RESTATED
(SEE NOTE 1) (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 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:
5
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 2,084 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.
9
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 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
10
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).
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
11
own all of the outstanding shares of Avon through a jointly owned subsidiary,
with each company having an ownership voting interest. Originally, in accordance
with applicable accounting guidance, the earnings of those foreign operations
were not recognized in current earnings from the date of the GPU acquisition.
However, as a result of the decision to retain an ownership interest in Avon in
the quarter ended March 31, 2002, EITF Issue No. 90-6, "Accounting for Certain
Events Not Addressed in Issue No. 87-11 relating to an Acquired Operating Unit
to be Sold" required FirstEnergy to reallocate the purchase price of GPU based
on amounts as of the purchase date as if Avon had never been held for sale,
including reversal of the effects of having applied EITF Issue No. 87-11, to the
transaction. The effect of reallocating the 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
12
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.
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
13
industrial customers. The amount of the incentive is deferred for future
recovery from customers - recovery will be accomplished by extending the
respective transition cost recovery period. If the customer shopping goals
established in the agreement had not been achieved by the end of 2005, the
transition cost recovery periods could have been shortened for OE, CEI and TE to
reduce recovery by as much as $500 million (OE-$250 million, CEI-$170 million
and TE-$80 million). The Ohio Companies achieved all of their required 20%
customer shopping goals in 2002. Accordingly, FirstEnergy believes that there
will be no regulatory action reducing the recoverable transition costs.
New Jersey
JCP&L's 2001 Final Decision and Order (Final Order) with
respect to its rate unbundling, stranded cost and restructuring filings
confirmed rate reductions set forth in its 1999 Summary Order, which 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.
14
In December 2001, the NJBPU authorized the auctioning of BGS
for the period from August 1, 2002 through July 31, 2003 to meet the electricity
demands of all customers who have not selected an alternative supplier. The
auction results were approved by the NJBPU in February 2002, removing JCP&L's
BGS obligation of 5,100 MW for the period August 1, 2002 through July 31, 2003.
In February 2003, the NJBPU approved the BGS auction results for the period
beginning August 1, 2003. The auction covered a fixed price bid (applicable to
all residential and smaller commercial and industrial customers) and an hourly
price bid (applicable to all large industrial customers) process. JCP&L sells
all self-supplied energy (NUGs and owned generation) to the wholesale market
with offsetting credits to its deferred energy balances.
Pennsylvania
The PPUC authorized 1998 rate restructuring plans for Penn,
Met-Ed and Penelec. In 2000, the PPUC disallowed a portion of the requested
additional stranded costs above those amounts granted in Met-Ed's and Penelec's
1998 rate restructuring plan orders. The PPUC required Met-Ed and Penelec to
seek an IRS ruling regarding the return of certain unamortized investment tax
credits and excess deferred income tax benefits to customers. Similar to JCP&L's
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
15
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.
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
--------------------------
THREE SIX
EFFECT OF THE CHANGE IN ACCOUNTING MONTHS MONTHS
PRINCIPLE APPLIED RETROACTIVELY TO 2002 (RESTATED - SEE NOTE 1)
INCREASE(DECREASE) (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-percent equity interest by
OES Ventures, a wholly owned
17
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 ................................ 89 (32) (32) -- 18
Income before discontinued operations and
cumulative effect of accounting change ... 118 (45) (54) -- 9
Net income (loss) ........................... 118 (45) (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 ........................... $ 2,161 $ 696 $ 36 $ 6 (a) $ 2,899
Internal revenues ........................... 177 417 125 (719)(b) --
Total revenues ........................... 2,338 1,113 161 (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 (RESTATED - SEE NOTE 1)
External revenues ........................... $ 4,398 $ 1,606 $ 62 $ 31 (a) $ 6,097
Internal revenues ........................... 498 1,072 271 (1,841)(b) --
Total revenues ........................... 4,896 2,678 333 (1,810) 6,097
Depreciation and amortization ............... 597 16 21 -- 634
Net interest charges ........................ 257 21 209 (75)(b) 412
Income taxes ................................ 248 (63) (62) -- 112
Income before discontinued operations and
cumulative effect of accounting change ... 345 (89) (105) -- 119
Net income (loss) ........................... 446 (88) (165) -- 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 ........................... $ 4,156 $ 1,283 $ 301 $ 12 (a) $ 5,752
Internal revenues ........................... 532 827 242 (1,601)(b) --
Total revenues ........................... 4,688 2,110 543 (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 RESTATED
(SEE NOTE 1) (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 RESTATED
(SEE NOTE 1) (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.
26
Above-Market Lease Costs
In 1997, FirstEnergy Corp. was formed through a merger between OE
and Centerior Energy Corp. The merger was accounted for as an acquisition of
Centerior, the parent company of CEI and TE, under the purchase accounting rules
of Accounting Principles Board (APB) Opinion No. 16. In connection with the
reassessment of the accounting for the transition plan, FirstEnergy reassessed
its accounting for the Centerior purchase and determined that above market lease
liabilities should have been recorded at the time of the merger. Accordingly, as
of 2002, FirstEnergy recorded additional adjustments associated with the 1997
merger between OE and Centerior to reflect certain above market lease
liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant, for which
CEI and TE had previously entered into sale-leaseback arrangements. CEI and TE
recorded an increase in goodwill related to the above market lease costs for
Beaver Valley Unit 2 since regulatory accounting for nuclear generating assets
had been discontinued prior to the merger date and it was determined that this
additional liability would have increased goodwill at the date of the merger.
The corresponding impact of the above market lease liabilities for the Bruce
Mansfield Plant 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
27
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).
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:
28
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%
====== =====
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
----- ---- ---- ----
29
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 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 $9.6 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
30
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.
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 ($14.1 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
31
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 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.
32
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.
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 MONTHS SIX 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 a $15.9 million increase in other
operating expenses, $10.6 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
$29.9 million
33
increase in other operating expense, $27.2 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.
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
34
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 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)........ $ 509 $ 530 $ 867 $ 856
Working capital and other (487) (268) (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 $219 million change in funds used for working capital and a $21 million
decrease 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)
------ ------
35
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. 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.
36
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:
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
37
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.
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
38
purposes and, to a much lesser extent, for trading purposes. Most of
FirstEnergy's non-hedge derivative contracts represent non-trading positions
that do not qualify for hedge treatment under SFAS 133.
The change in the fair value of commodity derivative contracts related
to energy production during the 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.
(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.
39
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
40
of 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.
41
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
42
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
(SO(2)) regulations. Violations of such regulations can result in shutdown of
the generating unit involved and/or civil or criminal penalties of up to $31,500
for each day the unit is in violation. The Environmental Protection Agency (EPA)
has an interim enforcement policy for 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.
43
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.
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
44
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 $ 2,309 $ 5,842 $ 4,701
Adjustment......................................... (50) (50) (90) (90)
----------------------------------------------------------------------------------------------------
Total as currently reported........................ $ 2,899 $ 2,259 $ 5,752 $ 4,611
====================================================================================================
45
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:
- Net energy generated or purchased for retail load
- Losses of energy over transmission and distribution lines
- Mix of kilowatt-hour usage by residential, commercial and industrial
customers
- Kilowatt-hour usage of customers receiving electricity from
alternative suppliers
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory defined
pension and OPEB benefits are dependent upon numerous factors resulting from
actual plan experience and certain assumptions.
46
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 a loss - calculated as the
difference between the carrying value and the estimated fair value of the asset
(discounted future net cash flows).
47
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.
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.
48
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.
49
OHIO EDISON COMPANY
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)
OPERATING REVENUES ........................................ $ 673,708 $ 744,550 $ 1,416,451 $ 1,452,349
----------- ----------- ----------- -----------
OPERATING EXPENSES AND TAXES:
Fuel .................................................... 10,290 15,129 23,140 29,419
Purchased power ......................................... 216,355 213,172 460,183 454,651
Nuclear operating costs ................................. 118,209 80,700 243,577 175,934
Other operating costs ................................... 80,327 78,497 170,600 158,108
----------- ----------- ----------- -----------
Total operation and maintenance expenses .............. 425,181 387,498 897,500 818,112
Provision for depreciation and amortization ............. 105,753 98,821 214,138 182,941
General taxes ........................................... 44,406 42,524 92,662 87,900
Income taxes ............................................ 34,379 82,226 78,080 122,565
----------- ----------- ----------- -----------
Total operating expenses and taxes .................... 609,719 611,069 1,282,380 1,211,518
----------- ----------- ----------- -----------
OPERATING INCOME .......................................... 63,989 133,481 134,071 240,831
OTHER INCOME .............................................. 15,411 15,087 28,912 15,599
----------- ----------- ----------- -----------
INCOME BEFORE NET INTEREST CHARGES ........................ 79,400 148,568 162,983 256,430
----------- ----------- ----------- -----------
NET INTEREST CHARGES:
Interest on long-term debt .............................. 24,957 30,312 49,445 63,385
Allowance for borrowed funds used during construction and
capitalized interest .................................. (1,124) (883) (2,504) (1,504)
Other interest expense .................................. 9,325 2,801 11,803 7,948
Subsidiaries' preferred stock dividend requirements ..... 912 3,626 1,824 7,252
----------- ----------- ----------- -----------
Net interest charges .................................. 34,070 35,856 60,568 77,081
----------- ----------- ----------- -----------
INCOME BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE ....................................... 45,330 112,712 102,415 179,349
Cumulative effect of accounting change (net of income
taxes of $22,389,000) (Note 5) .......................... -- -- 31,720 --
----------- ----------- ----------- -----------
NET INCOME ................................................ 45,330 112,712 134,135 179,349
PREFERRED STOCK DIVIDEND REQUIREMENTS ..................... 659 2,597 1,318 5,193
----------- ----------- ----------- -----------
EARNINGS ON COMMON STOCK .................................. $ 44,671 $ 110,115 $ 132,817 $ 174,156
=========== =========== =========== ===========
The preceding Notes to Financial Statements as they relate to Ohio Edison
Company are an integral part of these statements.
50
OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
JUNE 30, DECEMBER 31,
2003 2002
---------- ------------
RESTATED
(SEE NOTE 1)
(IN THOUSANDS)
ASSETS
UTILITY PLANT:
In service ......................................................... $5,212,254 $ 4,989,056
Less-Accumulated provision for depreciation ........................ 2,585,546 2,552,007
---------- ------------
2,626,708 2,437,049
---------- ------------
Construction work in progress-
Electric plant ................................................... 118,927 122,741
Nuclear fuel ..................................................... 5,674 23,481
---------- ------------
124,601 146,222
---------- ------------
2,751,309 2,583,271
---------- ------------
OTHER PROPERTY AND INVESTMENTS:
PNBV Capital Trust ................................................. 388,225 402,565
Letter of credit collateralization ................................. 277,763 277,763
Nuclear plant decommissioning trusts ............................... 325,073 293,190
Long-term notes receivable from associated companies ............... 503,192 503,827
Other .............................................................. 67,824 74,220
---------- ------------
1,562,077 1,551,565
---------- ------------
CURRENT ASSETS:
Cash and cash equivalents .......................................... 2,364 20,512
Receivables-
Customers (less accumulated provisions of $5,708,000 and
$5,240,000, respectively for uncollectible accounts) ........... 291,501 296,548
Associated companies ............................................. 989,299 592,218
Other (less accumulated provisions of $1,000,000 for uncollectible
accounts at both dates) ........................................ 28,295 30,057
Notes receivable from associated companies ......................... 387,025 437,669
Materials and supplies, at average cost-
Owned .......................................................... 58,989 58,022
Under consignment .............................................. 13,115 19,753
Prepayments and other .............................................. 21,603 11,804
---------- ------------
1,792,191 1,466,583
---------- ------------
DEFERRED CHARGES:
Regulatory assets ................................................. 1,750,174 2,005,554
Property taxes .................................................... 59,035 59,035
Unamortized sale and leaseback costs .............................. 68,325 72,294
Other ............................................................. 55,802 51,739
---------- ------------
1,933,336 2,188,622
---------- ------------
$8,038,913 $ 7,790,041
========== ============
51
OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
JUNE 30, DECEMBER 31,
2003 2002
----------- ------------
RESTATED
(SEE NOTE 1)
(IN THOUSANDS)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity
Common stock, without par value, authorized 175,000,000 shares-
100 shares outstanding ...................................... $ 2,098,729 $ 2,098,729
Accumulated other comprehensive loss .......................... (101,077) (59,495)
Retained earnings ............................................. 647,838 800,021
----------- ------------
Total common stockholder's equity ......................... 2,645,490 2,839,255
Preferred stock not subject to mandatory redemption ............. 60,965 60,965
Preferred stock of consolidated subsidiary-
Not subject to mandatory redemption ........................... 39,105 39,105
Subject to mandatory redemption ............................... 13,500 13,500
Long-term debt .................................................. 1,521,866 1,219,347
----------- ------------
4,280,926 4,172,172
----------- ------------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock ............ 585,553 563,267
Short-term borrowings-
Associated companies .......................................... 1,170 225,345
Other ......................................................... 187,902 182,317
Accounts payable-
Associated companies .......................................... 410,027 145,981
Other ......................................................... 3,634 18,015
Accrued taxes ................................................... 515,198 466,064
Accrued interest ................................................ 23,103 28,209
Other ........................................................... 72,562 74,562
----------- ------------
1,799,149 1,703,760
----------- ------------
DEFERRED CREDITS:
Accumulated deferred income taxes ............................... 909,937 1,017,629
Accumulated deferred investment tax credits ..................... 82,135 88,449
Asset retirement obligation ..................................... 307,501 --
Nuclear plant decommissioning costs ............................. -- 280,858
Retirement benefits ............................................. 384,618 247,531
Other ........................................................... 274,647 279,642
----------- ------------
1,958,838 1,914,109
----------- ------------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (NOTE 2) ................
----------- ------------
$ 8,038,913 $ 7,790,041
=========== ============
The preceding Notes to Financial Statements as they relate to Ohio Edison
Company are an integral part of these balance sheets.
52
OHIO EDISON COMPANY
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 ................................................... $ 45,330 $ 112,712 $ 134,135 $ 179,349
Adjustments to reconcile net income to net cash from
operating activities-
Provision for depreciation and amortization ............ 105,753 98,821 214,138 182,941
Nuclear fuel and lease amortization .................... 10,763 12,133 17,869 23,535
Deferred income taxes, net ............................. (28,387) (11,386) (20,704) (27,156)
Investment tax credits, net ............................ (3,692) (3,439) (7,396) (6,888)
Cumulative effect of accounting change (Note 5) ........ -- -- (54,109) --
Receivables ............................................ (350,873) (31,345) (380,782) 32,803
Materials and supplies ................................. 6,969 (3,158) 5,671 (4,800)
Accounts payable ....................................... 240,948 (1,166) 255,418 (19,461)
Accrued taxes .......................................... 43,083 149,376 49,134 206,260
Accrued interest ....................................... (7,543) (8,200) (5,106) (1,963)
Deferred lease costs ................................... (34,360) (31,865) (2,677) (182)
Prepayments and other .................................. 5,094 15,178 (9,799) 31,273
Other .................................................. 41,445 (4,232) 32,255 (34,771)
------------ --------- --------- ---------
Net cash provided from operating activities .......... 74,530 293,429 228,047 560,940
------------ --------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt ........................................... 575,000 -- 575,000 --
Short-term borrowings, net ............................... 13,688 -- -- --
Redemptions and Repayments-
Long-term debt ........................................... (238,963) (244,179) (258,456) (228,741)
Short-term borrowings, net ............................... -- (66,464) (218,590) (26,158)
Dividend Payments-
Common stock ............................................. (272,000) -- (285,000) (101,200)
Preferred stock .......................................... (659) (2,596) (1,318) (5,193)
------------ --------- --------- ---------
Net cash provided from (used for) financing activities 77,066 (313,239) (188,364) (361,292)
------------ --------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions ......................................... (33,327) (25,377) (101,694) (55,721)
Notes receivable from associated companies, net ............ (121,971) 3,402 51,279 (134,779)
Other ...................................................... (8,254) 8,431 (7,416) 10,403
------------ --------- --------- ---------
Net cash used for investing activities ............... (163,552) (13,544) (57,831) (180,097)
------------ --------- --------- ---------
Net increase (decrease) in cash and cash equivalents ......... (11,956) (33,354) (18,148) 19,551
Cash and cash equivalents at beginning of period ............. 14,320 57,493 20,512 4,588
------------ --------- --------- ---------
Cash and cash equivalents at end of period ................... $ 2,364 $ 24,139 $ 2,364 $ 24,139
============ ========= ========= =========
The preceding Notes to Financial Statements as they relate to Ohio Edison
Company are an integral part of these statements.
53
REPORT OF INDEPENDENT AUDITORS
To the Stockholders and Board of
Directors of Ohio Edison Company:
We have reviewed the accompanying consolidated balance sheet of Ohio Edison
Company and its subsidiaries as of 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 stockholder's equity,
preferred stock, cash flows and taxes for the year then ended (not presented
herein), and in our report (which contained a reference to the Company's
restatement of its previously issued consolidated financial statements for the
year ended December 31, 2002 as discussed in Note 1(M) to those consolidated
financial statements) dated February 28, 2003, except as to Note 1(M), which is
as of August 18, 2003, we expressed an unqualified opinion on those consolidated
financial statements. In our opinion, the information set forth in the
accompanying consolidated balance sheet as of December 31, 2002, is fairly
stated in all material respects in relation to the consolidated balance sheet
from which it has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
August 18, 2003
54
OHIO EDISON COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
OE is a wholly owned, electric utility subsidiary of
FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in
portions of Ohio and Pennsylvania, providing regulated electric distribution
services. OE and Penn (OE Companies) also provide generation services to those
customers electing to retain them as their power supplier. The OE Companies
provide power directly to wholesale customers under previously negotiated
contracts, as well as to alternative energy suppliers under OE's transition
plan. The OE Companies have unbundled the price of electricity into its
component elements - including generation, transmission, distribution and
transition charges. Power supply requirements of the OE Companies are provided
by FES - an affiliated company.
RESTATEMENTS
As further discussed in Note 1 to the Consolidated Financial
Statements, OE identified certain accounting matters that require restatement of
the 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 associated with the Ohio transition plan.
Transition Cost Amortization
As discussed in Note 4 - Regulatory Matters, OE recovers
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.
OE amortizes transition costs using the effective interest
method. The amortization schedules developed in applying this method were
previously based on total transition revenues, including revenues designed to
recover costs which have not yet been incurred. OE has subsequently revised the
amortization schedules under the effective interest method to consider only
revenues relating to transition regulatory assets recognized on the balance
sheet. The amortization expense under the revised method (see Note 1) increased
by $7.3 million for the three months and decreased by $0.7 million for the six
months ended June 30, 2002.
RESULTS OF OPERATIONS
Earnings on common stock in the second quarter of 2003
decreased to $44.7 million from $110.1 million in the second quarter of 2002.
During the first six months of 2003, earnings on common decreased to $132.8
million from $174.2 million in the same period of 2002. In the first six months
of 2003 earnings on common stock included an after tax credit of $31.7 million
from the cumulative effect of an accounting change due to the adoption of SFAS
143, "Accounting for Asset Retirement Obligations." Income before the cumulative
effect was $102.4 million in the first six months of 2003, compared to $179.3
million for the same period of 2002.
Results in the second quarter of 2003 were adversely affected
by lower revenues due to mild weather and higher operating expenses principally
from additional outage-related work at the nuclear generating plants and
increased amortization of the Ohio transition regulatory assets compared to the
same quarter of last year. The lower results in the second quarter of 2003 were
partially offset by reduced nuclear fuel expenses as a result of the additional
nuclear outages and reduced financing costs compared to the second quarter of
2002.
In the first six months of 2003, results were negatively
affected by lower revenues reflecting mild weather in the second quarter of
2003, which moderated the affect of unusually cold weather earlier in the year.
Additional outage-related work and increased amortization of the Ohio transition
regulatory asset were also primary factors contributing to an increase in
operating expenses in the first half of 2003 from the same period in 2002.
Partially offsetting these factors were reduced fuel expense resulting from
lower nuclear production and the absence in 2003 of an adjustment recorded in
the first quarter of 2002 for low income housing investments.
Operating revenues decreased by $70.8 million or 9.5% in the
second quarter and $35.9 million or 2.5% in the first six months of 2003
compared with the same periods in 2002 due to cooler-than-normal temperatures in
the second quarter, continued sluggishness in the economy and increased sales by
alternative suppliers. The lower revenues primarily resulted from reduced
generation sales revenues, which included all retail customer categories -
residential, commercial and industrial. Kilowatt-hour sales to retail customers
declined by 17.3% in the second quarter
55
and 9.2% in the first six months of 2003 from the same periods of 2002, which
reduced generation sales revenue by $47.0 million and $60.6 million,
respectively. Electric generation services provided to retail customers by
alternative suppliers as a percent of total sales delivered in OE's franchise
area increased 10.3 percentage points in the second quarter and 8.4 percentage
points in the first six months of 2003 from the corresponding periods last year.
Distribution deliveries decreased 5.3% in the second quarter
of 2003 but increased 1.2% in the first six months of 2003 compared with the
corresponding periods of 2002. The decreased distribution deliveries in the
second quarter of 2003 reflected the mild weather in that period compared to the
same period last year which reduced residential and commercial usage - the
customer groups accounting for most of the $13.5 million reduction in revenues
from electricity throughput. In the first half of 2003, unusually cold weather
in the first few months of 2003 benefited distribution deliveries to residential
and commercial customers which provided most of the increase in revenues from
distribution throughput compared to the same period in 2002. The second quarter
and first six months of 2003 were both adversely impacted by the continued
effects of a sluggish economy and the demand by industrial customers in OE's
franchise area.
Operating revenues also decreased in 2003 as a result of the
Ohio transition plan incentives provided to customers to promote customer
shopping for alternative suppliers - $4.6 million of additional credits in the
second quarter and $11.0 million of additional credits in the first six months
of 2003 from the corresponding periods of 2002. These reductions in revenues are
deferred for future recovery under OE's transition plan and do not materially
affect current period earnings.
Sales revenues from wholesale customers decreased by $4.9
million in the second quarter but increased by $10.1 million in the first six
months of 2003 compared to the same periods of 2002. The changes in
kilowatt-hour sales to the wholesale market reflected reduced nuclear generation
available for sale to FES and offsetting increases in unit prices.
Changes in electric generation sales and distribution
deliveries in the second quarter and first six months of 2003 from the
corresponding periods of 2002 are summarized in the following table:
CHANGES IN KILOWATT-HOUR SALES THREE MONTHS SIX MONTHS
--------------------------------------------------------------------
INCREASE (DECREASE)
Electric Generation:
Retail (17.3)% (9.2)%
Wholesale (27.6)% (17.4)%
-----------------------------------------------------------------
Total Electric Generation Sales (22.1)% (13.0)%
=================================================================
Distribution Deliveries:
Residential (10.8)% 1.7%
Commercial (4.4)% 2.0%
Industrial (1.7)% 0.1%
-----------------------------------------------------------------
Total Distribution Deliveries (5.3)% 1.2%
=================================================================
Operating Expenses and Taxes
Total operating expenses and taxes decreased $1.3 million in
the second quarter and increased $70.9 million in the first six months of 2003
from the same periods last year. The following table presents changes from the
prior year by expense category.
OPERATING EXPENSES AND TAXES - CHANGES THREE MONTHS SIX MONTHS
----------------------------------------------------------------------------
INCREASE (DECREASE) (IN MILLIONS)
Fuel.......................................... $ (4.8) $ (6.2)
Purchased power costs......................... 3.2 5.5
Nuclear operating costs....................... 37.5 67.6
Other operating costs......................... 1.8 12.5
------------------------------------------------------------------------
TOTAL OPERATION AND MAINTENANCE EXPENSES.... 37.7 79.4
========================================================================
Provision for depreciation and amortization... 6.9 31.2
General taxes................................. 1.9 4.8
Income taxes.................................. (47.8) (44.5)
------------------------------------------------------------------------
NET CHANGE IN OPERATING EXPENSES AND TAXES.. $ (1.3) $ 70.9
========================================================================
Lower fuel costs in the second quarter and first six months of
2003, compared with the same periods of 2002, resulted from reduced nuclear
generation - down 30.7% and 20.5%, respectively. Although the required
kilowatt-hour purchases were lower because of reduced electric generation sales,
in the second quarter and first six months of 2003, compared to the
corresponding periods of 2002, higher unit costs more than offset the lower
volume and resulted in
56
higher purchased power costs. Nuclear operating costs increased in the second
quarter and first six months of 2003, compared to the same periods of 2002
driven by two refueling outages in 2003 - Beaver Valley Unit 1 (100% ownership)
and the Perry nuclear plant (35.24% ownership) in 2003 compared with one
refueling outage at Beaver Valley Unit 2 (55.62% ownership) in 2002. The two
refueling outages in 2003 included additional unplanned work which extended the
length of the outages and increased their cost. The increase in other operating
costs in the second quarter and first six months of 2003, compared to the same
periods of 2002, primarily reflects higher employee benefit costs.
Charges for depreciation and amortization increased by $6.9
million in the second quarter of 2003 compared to the second quarter of 2002
primarily from three factors - increased amortization of the Ohio transition
regulatory assets ($10.8 million) and reduced regulatory asset deferrals in 2003
($5.9 million). Partially offsetting these increases were higher shopping
incentive deferrals ($4.6 million) and lower charges resulting from the
implementation of SFAS 143 ($4.6 million).
In the first six months of 2003, depreciation and amortization
increased by $31.2 million compared to the corresponding period of 2002 as a
result of the same factors which impacted the second quarter comparison -
increased amortization of the Ohio transition regulatory asset ($41.7 million
which reflects a cumulative adjustment credit in the first quarter of 2002 - see
Restatements section) and reduced transition plan regulatory asset deferrals
($12.2 million) in 2003. Partially offsetting these increases in depreciation
and amortization were higher shopping incentive deferrals ($11.0 million) and
lower charges resulting from the implementation of SFAS 143 ($10.9 million).
General taxes increased in the second quarter and first six
months of 2003 from the same periods of 2002 principally due to higher
kilowatt-hour taxes in Ohio.
Other Income
Other income increased by $13.3 million in the first six
months of 2003 from the same period last year, primarily due to the absence in
2003 of adjustments recorded in the first half of 2002 related to OE's low
income housing investments.
Net Interest Charges
Net interest charges continued to trend lower, decreasing by
$1.8 million in the second quarter and $16.5 million in the first six months of
2003 from the same periods last year, reflecting redemptions and refinancings
since the second quarter of last year. OE's net debt redemptions totaled $21.2
million during the first six months of 2003, which will result in annualized
savings of $6.3 million.
Cumulative Effect of Accounting Change
Results for the first six months of 2003 include an after-tax
credit to net income of $31.7 million recorded upon the adoption of SFAS 143 in
January 2003. OE identified applicable legal obligations as defined under the
new standard for nuclear power plant decommissioning and reclamation of a sludge
disposal pond at the Bruce Mansfield Plant. As a result of adopting SFAS 143 in
January 2003, asset retirement costs of $133.7 million were recorded as part of
the carrying amount of the related long-lived asset, offset by accumulated
depreciation of $25.2 million. The asset retirement obligation (ARO) liability
at the date of adoption was $297.6 million, including accumulated accretion for
the period from the date the liability was incurred to the date of adoption. As
of December 31, 2002, OE had recorded decommissioning liabilities of $292.4
million, including unrealized gains on the decommissioning trust funds of $10.6
million. Penn expects substantially all of its nuclear decommissioning costs to
be recoverable in rates over time. Therefore, OE recognized a regulatory
liability of $10.6 million upon adoption of SFAS 143 for the transition amounts
related to establishing the ARO for nuclear decommissioning for Penn. The
remaining cumulative effect adjustment for unrecognized depreciation, accretion
offset by the reduction in the existing decommissioning liabilities and ceasing
the accounting practice of depreciating non-regulated generation assets using a
cost of removal component was a $54.1 million increase to income, or $31.7
million net of income taxes.
CAPITAL RESOURCES AND LIQUIDITY
OE's cash requirements in 2003 for operating expenses,
construction expenditures, scheduled debt maturities and preferred stock
redemptions are expected to be met without significantly increasing its net debt
and preferred stock outstanding. Available borrowing capacity under short-term
credit facilities will be used to manage working capital requirements. Over the
next three years, OE expects to meet its contractual obligations with cash from
operations. Thereafter, OE expects to use a combination of cash from operations
and funds from the capital markets.
57
Changes in Cash Position
As of June 30, 2003, OE had $2.4 million of cash and cash
equivalents, compared with $20.5 million as of December 31, 2002. The major
sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Cash provided by operating activities during the second
quarter and first six months of 2003, compared with the corresponding periods in
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)............ $130 $209 $284 $352
Working capital and other.... (55) 84 (56) 209
-------------------------------------------------------------------------------
Total........................ $ 75 $293 $228 $561
-------------------------------------------------------------------------------
(1) Includes net income, depreciation and amortization, deferred income taxes,
investment tax credits and major noncash charges.
Net cash from operating activities decreased $218 million in
the second quarter of 2003 due to a $139 million decrease in funds from working
capital and a $79 million decrease in cash earnings. The change in working
capital and other primarily reflects higher accounts receivable in the second
quarter of 2003 compared with corresponding amounts in the second quarter of
2002 ($320 million). A change in accrued tax liabilities also contributed $106
million to the decrease in working capital primarily due to an increase in tax
payments in the second quarter of 2003 compared with the second quarter of 2002.
Cash Flows From Financing Activities
In the second quarter of 2003, net cash provided from
financing activities increased to $77 million from $313 million used in the same
period last year. The increase resulted from new financing partially offset by
dividends to FirstEnergy.
OE had approximately $389.4 million of cash and temporary
investments and approximately $189.1 million of short-term indebtedness as of
June 30, 2003. Available borrowing capability under bilateral bank facilities
totaled $20.0 million as of June 30, 2003. OE had the capability to issue $1.6
billion of additional first mortgage bonds on the basis of property additions
and retired bonds. Based upon applicable earnings coverage tests OE could issue
up to $2.2 billion of preferred stock (assuming no additional debt was issued)
as of June 30, 2003.
On April 21, 2003, OE completed a $325 million debt
refinancing transaction that included two tranches - $175 million of 4.00%
five-year notes and $150 million of 5.45% twelve year notes. The net proceeds
will be used to redeem approximately $220 million of outstanding OE first
mortgage bonds having a weighted average cost of 7.99%, with the remainder to be
used to pay down short-term debt. On May 12, 2003, OE completed a new two-year
$250 million revolving credit facility.
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%.
Cash Flows From Investing Activities
Net cash used for investing activities totaled $164 million in
the second quarter of 2003, compared to $14 million for the same period of 2002.
The $150 million increase in funds used for investing activities resulted from
payments on notes to associated companies.
During the second half of 2003, capital requirements for
property additions and capital leases are expected to be about $92 million,
including $17 million for nuclear fuel. OE has additional requirements of
approximately $220 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.
58
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."
Pension and Other Postretirement Benefits
As a result of GPU Service Inc. merging with FirstEnergy
Service Company 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, OE's accrued pension and OPEB costs
as of June 30, 2003 increased by $66.8 million and $58.5 million, respectively.
Other Obligations
Obligations not included on OE's Consolidated Balance Sheet
primarily consist of sale and leaseback arrangements involving Perry Unit 1 and
Beaver Valley Unit 2. As of June 30, 2003, the present value of these sale and
leaseback operating lease commitments, net of trust investments, total $693
million.
EQUITY PRICE RISK
Included in OE's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $177
million and $148 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 $18 million reduction in fair value as of June 30, 2003.
OUTLOOK
Beginning in 2001, OE's customers were able to select
alternative energy suppliers. OE continues to deliver power to residential homes
and businesses through its existing distribution system, which remains
regulated. Customer rates have been restructured into separate components to
support customer choice. In Ohio and Pennsylvania, the OE Companies have a
continuing responsibility to provide power to those customers not choosing to
receive power from an alternative energy supplier subject to certain limits.
Adopting new approaches to regulation and experiencing new forms of competition
have created new uncertainties.
Regulatory Matters
In 2001, Ohio customer rates were restructured to establish
separate charges for transmission, distribution, transition cost recovery and a
generation-related component. When one of OE's Ohio customers elects to obtain
power from an alternative supplier, OE reduces the customer's bill with a
"generation shopping credit," based on the regulated generation component (plus
an incentive), and the customer receives a generation charge from the
alternative supplier. OE has continuing PLR responsibility to its franchise
customers through December 31, 2005.
59
Regulatory assets are costs which have been authorized by the
Public Utilities Commission of Ohio (PUCO), Pennsylvania Public Utility
Commission and the Federal Energy Regulatory Commission, for recovery from
customers in future periods and, without such authorization, would have been
charged to income when incurred. Regulatory assets declined $255.4 million to
$1.8 billion on June 30, 2003 from the balance as of December 31, 2002, with
$10.6 million of the decrease related to the cumulative entry adopting SFAS 143
at Penn and the balance of the reduction resulting from recovery of transition
plan regulatory assets. All of the OE Companies' regulatory assets are expected
to continue to be recovered under the provisions of their respective transition
plan and rate restructuring plan. The OE Companies' regulatory assets are as
follows:
JUNE 30, DECEMBER 31,
REGULATORY ASSETS 2003 2002
----------------------------------------------------------
(IN MILLIONS)
OE......................... $1,689.9 $1,848.7
Penn....................... 60.3 156.9
----------------------------------------------------------
Consolidated Total...... $1,750.2 $2,005.6
==========================================================
As part of OE's Ohio transition plan it is obligated to supply
electricity to customers who do not choose an alternative supplier. OE is also
required to provide 560 megawatts (MW) of low cost supply to unaffiliated
alternative suppliers that serve customers within its service area. OE's
competitive retail sales affiliate, FES, acts as an alternate supplier for a
portion of the load in its franchise area. In 2003, the total peak load
forecasted for customers electing to stay with OE, including the 560 MW of low
cost supply and the load served by OE's affiliate is 5,820 MW.
Environmental Matters
OE believes it is in compliance with the current sulfur
dioxide (SO)(2) and nitrogen oxide (NO)(x) reduction requirements under the
Clean Air Act Amendments of 1990. In 1998, the Environmental Protection Agency
(EPA) finalized regulations requiring additional NO(x) reductions in the future
from OE's Ohio and Pennsylvania facilities. Various regulatory and judicial
actions have since sought to further define NO(x) reduction requirements
(see Note 2 - Environmental Matters). OE continues to evaluate its compliance
plans and other compliance options.
Violations of federally approved SO(2) regulations can result
in shutdown of the generating unit involved and/or civil or criminal penalties
of up to $31,500 for each day a unit is in violation. The EPA has an interim
enforcement policy for SO(2) regulations in Ohio that allows for compliance
based on a 30-day averaging period. OE cannot predict what action the EPA may
take in the future with respect to the interim enforcement policy.
In 1999 and 2000, the EPA issued Notices of Violation (NOV) or
a Compliance Order to nine utilities covering 44 power plants, including the W.
H. Sammis Plant. In addition, the U. S. Department of Justice filed eight civil
complaints against various investor-owned utilities, which included a complaint
against OE and Penn in the U.S. District Court for the Southern District of
Ohio. The NOV and complaint allege violations of the Clean Air Act (CAA). The
civil complaint against OE and Penn requests installation of "best available
control technology" as well as 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 W. H. Sammis Plant
between 1984 and 1998 required pre-construction permits under the Clean Air Act.
The ruling concludes the liability phase of the case, which deals with
applicability of Prevention of Significant Deterioration provisions of the Clean
Air Act. The remedy phase, which is currently scheduled to be ready for trial
beginning 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.
60
OE believes it is in compliance with the current SO(2) and
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 requires
compliance with the NOx budgets at the Companies' Pennsylvania facilities by May
1, 2003 and Ohio submitted a SIP that requires compliance with the NO(x) budgets
at the Companies' Ohio facilities by May 31, 2004.
The effects of compliance on OE with regard to environmental
matters could have a material adverse effect on its earnings and competitive
position. These environmental regulations affect our earnings and competitive
position to the extent OE competes with companies that are not subject to such
regulations and therefore do not bear the risk of costs associated with
compliance, or failure to comply, with such regulations. OE believes it is in
material compliance with existing regulations, but is unable to predict how and
when applicable environmental regulations may change and what, if any, the
effects of any such change would be.
Legal Matters
Various lawsuits, claims and proceedings related to OE's
normal business operations are pending against it, the most significant of which
are described above.
SIGNIFICANT ACCOUNTING POLICIES
OE prepares its consolidated financial statements in
accordance with accounting principles that are generally accepted in the United
States. Application of these principles often requires a high degree of
judgment, estimates and assumptions that affect OE's financial results. All of
the OE Companies' assets are subject to their own specific risks and
uncertainties and are regularly reviewed for impairment. Assets related to the
application of the policies discussed below are similarly reviewed with their
risks and uncertainties reflecting those specific factors. The OE Companies'
more significant accounting policies are described below.
Regulatory Accounting
The OE Companies are subject to regulation that sets the
prices (rates) they are permitted to charge their customers based on the costs
that the regulatory agencies determine the OE Companies are permitted to
recover. At times, regulators permit the future recovery through rates of costs
that would be currently charged to expense by an unregulated company. This
rate-making process results in the recording of regulatory assets based on
anticipated future cash inflows. As a result of the changing regulatory
framework in Ohio and Pennsylvania, a significant amount of regulatory assets
have been recorded. As of June 30, 2003, the OE Companies' regulatory assets
totaled approximately $1.8 billion. OE regularly reviews these assets to assess
their ultimate recoverability within the approved regulatory guidelines.
Impairment risk associated with these assets relates to potentially adverse
legislative, judicial or regulatory actions in the future.
Revenue Recognition
The OE Companies follow the accrual method of accounting for
revenues, recognizing revenue for kilowatt-hours that have been delivered but
not yet been billed through the end of the accounting period. The determination
of unbilled revenues requires management to make various estimates including:
- Net energy generated or purchased for retail load
- Losses of energy over distribution lines
- Allocations to distribution companies within the FirstEnergy
system
- Mix of kilowatt-hour usage by residential, commercial and
industrial customers
- Kilowatt-hour usage of customers receiving electricity from
alternative suppliers
61
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory
defined pension benefits and OPEB are dependent upon numerous factors resulting
from actual plan experience and certain assumptions.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions FirstEnergy makes to the plans, and earnings on plan assets.
Pension and OPEB costs may also be affected by changes to key assumptions,
including anticipated rates of return on plan assets, the discount rates and
health care trend rates used in determining the projected benefit obligations
for pension and OPEB costs.
In accordance with SFAS 87, "Employers' Accounting for
Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other
Than Pensions," changes in pension and OPEB obligations associated with these
factors may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
In selecting an assumed discount rate, FirstEnergy considers
currently available rates of return on high-quality fixed income investments
expected to be available during the period to maturity of the pension and other
postretirement benefit obligations. Due to the significant decline in corporate
bond yields and interest rates in general during 2002, FirstEnergy reduced the
assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001.
FirstEnergy's assumed rate of return on pension plan assets
considers historical market returns and economic forecasts for the types of
investments held by its pension trusts. The market values of FirstEnergy's
pension assets have been affected by sharp declines in the equity markets since
mid-2000. In 2002 and 2001 plan assets earned (11.3)% and (5.5)%, respectively.
FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of
return on plan assets. As of December 31, 2002 the assumed return on plan assets
was reduced to 9.00% based upon FirstEnergy's projection of future returns and
pension trust investment allocation of approximately 60% large cap equities, 10%
small cap equities and 30% bonds.
Based on pension assumptions and pension plan assets as of
December 31, 2002, FirstEnergy will not be required to fund its pension plans in
2003. While OPEB plan assets have also been affected by sharp declines in the
equity market, the impact is not as significant due to the relative size of the
plan assets. However, health care cost trends have significantly increased and
will affect future OPEB costs. The 2003 composite health care trend rate
assumption is approximately 10%-12% gradually decreasing to 5% in later years,
compared to 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," the OE Companies periodically evaluate their
long-lived assets to determine whether conditions exist that would indicate that
the carrying value of an asset may not be fully recoverable. The accounting
standard requires that if the sum of future cash flows (undiscounted) expected
to result from an asset is less than the carrying value of the asset, an asset
impairment must be recognized in the financial statements. If impairment other
than of a temporary nature has occurred, the OE Companies recognize a loss -
calculated as the difference between the carrying value and the estimated fair
value of the asset (discounted future net cash flows).
62
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 (OE's third quarter of
2003). The FASB also identified transitional disclosure provisions for all
financial statements issued after January 31, 2003.
OE currently has transactions which may fall within the scope
of this interpretation and which are reasonably possible of meeting the
definition of a VIE in accordance with FIN 46. OE currently consolidates the
majority of these entities and believes it will continue to consolidate
following the adoption of FIN 46. In addition to the entities OE is currently
consolidating OE 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 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 (OE's third quarter of 2003) for all other financial
instruments.
OE 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, OE expects to classify as debt the preferred stock of
consolidated subsidiaries subject to mandatory redemptions with a carrying value
of approximately $13.5 million as of June 30, 2003. Subsidiary preferred
dividends on OE'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.
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. OE is
currently assessing the new EITF consensus and has not yet determined the impact
on its financial position or results of operations following adoption.
63
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
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)
OPERATING REVENUES........................................ $412,133 $462,874 $ 831,904 $896,151
-------- -------- --------- --------
OPERATING EXPENSES AND TAXES:
Fuel................................................... 13,385 15,088 26,044 32,358
Purchased power........................................ 131,255 118,458 267,600 257,894
Nuclear operating costs................................ 67,218 30,985 122,579 94,602
Other operating costs.................................. 63,286 61,053 126,295 119,100
-------- -------- --------- --------
Total operation and maintenance expenses........... 275,144 225,584 542,518 503,954
Provision for depreciation and amortization............ 53,311 53,133 104,668 105,604
General taxes.......................................... 37,339 36,493 77,052 75,239
Income taxes........................................... 1,792 40,589 9,108 46,754
-------- -------- --------- --------
Total operating expenses and taxes................. 367,586 355,799 733,346 731,551
-------- -------- --------- --------
OPERATING INCOME.......................................... 44,547 107,075 98,558 164,600
OTHER INCOME.............................................. 4,684 3,356 9,425 8,597
-------- -------- --------- --------
INCOME BEFORE NET INTEREST CHARGES........................ 49,231 110,431 107,983 173,197
-------- -------- --------- --------
NET INTEREST CHARGES:
Interest on long-term debt............................. 39,299 45,372 79,939 92,367
Allowance for borrowed funds used during construction.. (1,637) (747) (3,804) (1,496)
Other interest expense (credit)........................ 5 (125) 36 (654)
Subsidiaries' preferred stock dividend requirements.... 2,250 2,250 7,200 4,400
-------- -------- --------- --------
Net interest charges............................... 39,917 46,750 83,371 94,617
-------- -------- --------- --------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE...... 9,314 63,681 24,612 78,580
Cumulative effect of accounting change (net of income
taxes of $30,168,000) (Note 5)......................... -- -- 42,378 --
-------- -------- --------- --------
NET INCOME................................................ 9,314 63,681 66,990 78,580
PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 1,864 3,054 1,105 9,610
-------- -------- --------- --------
EARNINGS ON COMMON STOCK.................................. $ 7,450 $ 60,627 $ 65,885 $ 68,970
======== ======== ========= ========
The preceding Notes to Financial Statements as they relate to The Cleveland
Electric Illuminating Company are an integral part of these statements.
64
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
JUNE 30, DECEMBER 31,
2003 2002
----------- ------------
RESTATED
(SEE NOTE 1)
(IN THOUSANDS)
ASSETS
UTILITY PLANT:
In service................................................................ $ 4,194,157 $ 4,045,465
Less - Accumulated provision for depreciation............................. 1,860,624 1,824,884
----------- -----------
2,333,533 2,220,581
----------- -----------
Construction work in progress-
Electric plant.......................................................... 127,827 153,104
Nuclear fuel............................................................ 24,309 45,354
----------- -----------
152,136 198,458
----------- -----------
2,485,669 2,419,039
----------- -----------
OTHER PROPERTY AND INVESTMENTS:
Shippingport Capital Trust................................................ 416,836 435,907
Nuclear plant decommissioning trusts...................................... 257,635 230,527
Long-term notes receivable from associated companies...................... 102,741 102,978
Other..................................................................... 20,822 21,004
----------- -----------
798,034 790,416
----------- -----------
CURRENT ASSETS:
Cash and cash equivalents................................................. 159 30,382
Receivables -
Customers............................................................... -- 11,317
Associated companies.................................................... 158,545 74,002
Other (less accumulated provisions of $1,000,000 and $1,015,000,
respectively, for uncollectible accounts)............................. 209,361 134,375
Notes receivable from associated companies................................ 464 447
Materials and supplies, at average cost -
Owned................................................................... 16,913 18,293
Under consignment....................................................... 28,663 38,094
Prepayments and other..................................................... 3,024 4,217
----------- -----------
417,129 311,127
----------- -----------
DEFERRED CHARGES:
Regulatory assets......................................................... 1,148,324 1,191,804
Goodwill.................................................................. 1,693,629 1,693,629
Property taxes............................................................ 79,430 79,430
Other..................................................................... 24,044 24,798
----------- -----------
2,945,427 2,989,661
----------- -----------
$ 6,646,259 $ 6,510,243
=========== ===========
65
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
JUNE 30, DECEMBER 31,
2003 2002
----------- ------------
RESTATED
(SEE NOTE 1)
(IN THOUSANDS)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 105,000,000 shares -
79,590,689 shares outstanding......................................... $ 981,962 $ 981,962
Accumulated other comprehensive loss.................................... (19,323) (44,284)
Retained earnings....................................................... 328,208 262,323
----------- -----------
Total common stockholder's equity................................... 1,290,847 1,200,001
Preferred stock -
Not subject to mandatory redemption..................................... 96,404 96,404
Subject to mandatory redemption......................................... 5,017 5,021
Company obligated mandatorily redeemable preferred securities of
subsidiary trust holding solely Company subordinated debentures......... 100,000 100,000
Long-term debt............................................................ 2,055,568 1,975,001
----------- -----------
3,547,836 3,376,427
----------- -----------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock...................... 158,279 388,190
Accounts payable-
Associated companies.................................................... 455,589 267,664
Other................................................................... 5,904 14,583
Notes payable to associated companies..................................... 338,804 288,583
Accrued taxes............................................................. 113,699 126,261
Accrued interest.......................................................... 48,199 51,767
Other..................................................................... 138,351 124,624
----------- -----------
1,258,825 1,261,672
----------- -----------
DEFERRED CREDITS:
Accumulated deferred income taxes......................................... 478,669 407,297
Accumulated deferred investment tax credits............................... 68,400 70,803
Nuclear plant decommissioning costs....................................... -- 242,511
Asset retirement obligation............................................... 246,610 --
Retirement benefits....................................................... 111,604 171,968
Lease market valuation liability.......................................... 758,700 788,800
Other..................................................................... 175,615 190,765
----------- -----------
1,839,598 1,872,144
----------- -----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (NOTE 2)........................... ----------- -----------
$ 6,646,259 $ 6,510,243
=========== ===========
The preceding Notes to Financial Statements as they relate to The Cleveland
Electric Illuminating Company are an integral part of these balance sheets.
66
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
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................................................ $ 9,314 $ 63,681 $ 66,990 $ 78,580
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization........ 53,311 53,133 104,668 105,604
Nuclear fuel and lease amortization................ 2,995 4,794 8,039 10,784
Other amortization................................. (409) (4,275) (5,022) (8,167)
Deferred income taxes, net......................... 133 2,084 33,937 2,906
Investment tax credits, net........................ (1,201) (1,270) (2,403) (2,313)
Receivables........................................ (163,454) (38,473) (148,212) (39,957)
Materials and supplies............................. 10,939 (1,840) 10,811 (3,206)
Accounts payable................................... 223,375 8,057 179,246 26,379
Cumulative effect of accounting charge (Note 5).... - - (72,547) -
Accrued taxes...................................... (15,458) 12,591 (12,562) 12,675
Accrued interest................................... (12,412) (5,907) (3,568) (338)
Prepayments and other.............................. (579) 7,103 1,193 29,611
Deferred lease costs............................... (222) (51,545) (41,825) (51,668)
Other.............................................. 18,122 (5,181) 10,529 (30,416)
--------- --------- --------- ---------
Net cash provided from operating activities...... 124,454 42,952 129,274 130,474
--------- --------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing -
Short-term borrowings, net........................... 16,976 - 50,221 26,663
Redemptions and Repayments-
Preferred stock...................................... (93) - (93) (100,000)
Long-term debt....................................... (100,962) (96) (146,065) (190)
Short-term borrowings, net........................... - (48,821) - -
Dividend Payments-
Preferred stock...................................... (1,865) (3,133) (3,730) (8,385)
--------- --------- --------- ---------
Net cash used for financing activities........... (85,944) (52,050) ( 99,667) (81,912)
--------- --------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions..................................... (30,805) (25,452) (62,023) (61,922)
Notes receivable from associated companies............. 220 205 220 205
Capital trust investments.............................. - 27,394 19,071 27,394
Other.................................................. (8,592) (8,021) (17,098) (14,245)
--------- --------- --------- ---------
Net cash used for investing activities........... (39,177) (5,874) (59,830) (48,568)
--------- --------- --------- ---------
Net decrease in cash and cash equivalents................. (667) (14,972) (30,223) (6)
Cash and cash equivalents at beginning of period.......... 826 15,262 30,382 296
--------- --------- --------- ---------
Cash and cash equivalents at end of period................ $ 159 $ 290 $ 159 $ 290
========= ========= ========= =========
The preceding Notes to Financial Statements as they relate to The Cleveland
Electric Illuminating Company are an integral part of these statements.
67
REPORT OF INDEPENDENT AUDITORS
To the Stockholders and Board of
Directors of The Cleveland
Electric Illuminating Company
We have reviewed the accompanying consolidated balance sheet of The Cleveland
Electric Illuminating Company and its subsidiaries as of 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 stockholder's equity,
preferred stock, cash flows and taxes for the year then ended (not presented
herein), and in our report (which contained references to the Company's change
in its method of accounting for goodwill in 2002 as discussed in Note 1(D) to
those consolidated financial statements and the Company's restatement of its
previously issued consolidated financial statements as of December 31, 2002 and
2001 and for each of the three years in the period ended December 31, 2002 as
discussed in Note 1(M) to those consolidated financial statements) dated August
18, 2003 we expressed an unqualified opinion on those consolidated financial
statements. In our opinion, the information set forth in the accompanying
consolidated balance sheet as of December 31, 2002, is fairly stated in all
material respects in relation to the consolidated balance sheet from which it
has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
August 18, 2003
68
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
CEI is a wholly owned, electric utility subsidiary of
FirstEnergy. CEI conducts business in portions of Ohio, providing regulated
electric distribution services. CEI also provides generation services to those
customers electing to retain them as their power supplier. CEI provides power
directly to alternative energy suppliers under CEI's transition plan. CEI has
unbundled the price of electricity into its component elements - including
generation, transmission, distribution and transition charges. Power supply
requirements of CEI are provided by FES - an affiliated company.
RESTATEMENTS
As further discussed in Note 1 to the Consolidated Financial
Statements, CEI identified certain accounting matters that require restatement
of the 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 associated with 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, CEI recovers
transition costs, including regulatory assets, through an approved transition
plan filed under Ohio's electric utility restructuring legislation. The plan,
which was approved in July 2000, provides for the recovery of costs from January
1, 2001 through a fixed number of kilowatt-hour sales to all customers that
continue to receive regulated transmission and distribution service, which is
expected to end in 2009 for CEI.
CEI amortizes transition costs using the effective interest
method. The amortization schedules developed in applying this method were
previously 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).
CEI has subsequently revised the amortization schedules under the effective
interest method to consider only revenues relating to transition regulatory
assets recognized on the balance sheet. The amortization expense under the
revised method (see Note 1) increased by $24.8 million for the three months and
$48.8 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, under the purchase accounting rules of
Accounting Principles Board (APB) Opinion No. 16. In connection with the
reassessment of the accounting for the transition plan, FirstEnergy reassessed
its accounting for the Centerior purchase and determined that above market lease
liabilities should have been recorded at the time of the merger. Accordingly, as
of 2002, FirstEnergy recorded additional adjustments associated with the 1997
merger between OE and Centerior to reflect certain above market lease
liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant, for which
CEI had previously entered into sale-leaseback arrangements. CEI recorded an
increase in goodwill related to the above market lease costs for Beaver Valley
Unit 2 since regulatory accounting for nuclear generating assets had been
discontinued prior to the merger date and it was determined that this additional
liability would have increased goodwill at the date of the merger. The
corresponding impact of the above market lease liabilities for the Bruce
Mansfield Plant were recorded as regulatory assets because regulatory accounting
had not been discontinued at that time for the fossil generating assets and
recovery of these liabilities was provided for under the transition plan.
The total above market lease obligation of $611 million
associated with Beaver Valley Unit 2 will be amortized through the end of the
lease term in 2017. The additional goodwill has been recorded on a net basis,
reflecting amortization that would have been recorded through 2001 when goodwill
amortization ceased with the adoption of SFAS No. 142. The total above market
lease obligation of $457 million associated with the Bruce Mansfield Plant is
being amortized through the end of 2016. Before the start of the transition plan
in fiscal 2001, the regulatory asset would have been amortized at the same rate
as the lease obligation. Beginning in 2001, the remaining unamortized regulatory
asset would have been included in CEI's amortization schedule for regulatory
assets and amortized through the end of the recovery period - approximately 2009
for CEI.
69
RESULTS OF OPERATIONS
Earnings on common stock in the second quarter of 2003
decreased to $7.5 million from $60.6 million in the second quarter of 2002.
Earnings on common stock in the first six months of 2003 included an after-tax
credit of $42.4 million from the cumulative effect of an accounting change due
to the adoption of SFAS 143, "Accounting for Asset Retirement Obligations."
Income before the cumulative effect was $24.6 million in the first six months of
2003, compared to $78.6 million for the same period of 2002. Lower earnings in
both periods resulted principally from lower revenues and higher operation and
maintenance expenses in 2003 compared to 2002. Revenues were affected by mild
weather in the second quarter after benefiting from unusually cold weather
earlier in 2003. Higher nuclear costs as a result of the extended outage at
Davis-Besse and additional unplanned work performed during the Perry Plant's
nuclear refueling outage in the second quarter of 2003 was the largest factor
contributing to the increased operation and maintenance expenses. Higher
employee benefit costs and purchased power costs also contributed to the
increased expenses.
Operating revenues decreased by $50.7 million or 11.0% in the
second quarter and $64.2 million or 7.2% in the first six months of 2003 from
the same periods of 2002 due to cooler-than-normal temperatures and increased
sales by alternative suppliers. Kilowatt-hour sales to retail customers declined
16.5% in the second quarter and 10.5% in the first six months of 2003 from the
corresponding periods of 2002, which reduced generation sales revenue by $22.0
million and $28.6 million, respectively. Mild temperatures in the second quarter
of 2003 reduced sales to residential and commercial customers. Kilowatt-hour
sales of electricity by alternative suppliers in CEI's franchise area increased
by 12.2 percentage points in the second quarter and 10.8 percentage points in
the first six months of 2003 from the corresponding periods last year.
Distribution deliveries were nearly unchanged in the second
quarter and increased 5.4% in the first six months of 2003 compared to the
corresponding periods of 2002. Lower unit prices and the change in distribution
deliveries in the second quarter and first six months of 2003 contributed to an
$11.3 million reduction in revenues in the second quarter and $4.2 million
increase in revenues from electricity throughput in the first six months of 2003
compared to the same periods last year. Cooler-than-normal temperatures in the
second quarter of 2003 reduced air-conditioning loads of residential and
commercial customers while residential and commercial loads benefited from
colder temperatures earlier in the year which increased demand in the first six
months of 2003 compared to the corresponding periods from last year. As a
result, deliveries to residential and commercial customers decreased by a
combined 2.6% in the second quarter and increased 4.0% in the first six months
of 2003 compared to the same periods of 2002. Distribution deliveries to
industrial customers increased in the second quarter and first six months of
2003 despite the continued effect of a sluggish economy due in part to the
expansion of steel production in the franchise area.
Further decreasing operating revenues were Ohio transition
plan incentives, provided to customers to encourage switching to alternative
energy providers - $4.7 million of additional credits in the second quarter and
$10.5 million of additional credits in the first six months of 2003 compared
with the corresponding periods of 2002. These revenue reductions are deferred
for future recovery under CEI's transition plan and do not materially affect
current period earnings.
Sales revenues from wholesale customers (primarily FES)
decreased by $10.8 million in the second quarter and $21.5 million in the first
six months of 2003 compared with the same periods of 2002. The lower sales
resulted from reductions in available nuclear generation of 41.1% in the second
quarter and 29.3% in the first half of 2003 compared to the corresponding
periods of 2002. Available generation decreased due to the extended outage at
Davis-Besse and generating capacity removed from service due to refueling
activities in 2003 compared to 2002.
Changes in electric generation sales and distribution
deliveries in the second quarter and first six months of 2003 from the
corresponding periods of 2002 are summarized in the following table:
CHANGES IN KILOWATT-HOUR SALES THREE MONTHS SIX MONTHS
--------------------------------------------------------------------
INCREASE (DECREASE)
Electric Generation:
Retail................................ (16.5)% (10.5)%
Wholesale............................. (18.7)% (18.2)%
----- -----
TOTAL ELECTRIC GENERATION SALES......... (17.5)% (14.3)%
===== =====
Distribution Deliveries:
Residential........................... (3.7)% 5.1%
Commercial............................ (1.5)% 2.7%
Industrial............................ 3.6% 7.0%
----- -----
TOTAL DISTRIBUTION DELIVERIES 0.4% 5.4%
===== =====
70
Operating Expenses and Taxes
Total operating expenses and taxes increased by $11.8 million
in the second quarter and $4.2 million in the first six months of 2003 from the
same periods of 2002. The following table presents changes from the prior year
by expense category.
OPERATING EXPENSES AND TAXES - CHANGES THREE MONTHS SIX MONTHS
----------------------------------------------------------------------------
INCREASE (DECREASE) (IN MILLIONS)
Fuel.......................................... $ (1.7) $ (6.3)
Purchased power costs......................... 12.8 9.7
Nuclear operating costs....................... 36.2 28.0
Other operating costs......................... 2.2 7.2
------- ------
TOTAL OPERATION AND MAINTENANCE EXPENSES.... 49.5 38.6
Provision for depreciation and amortization... 0.2 (0.9)
General taxes................................. 0.9 1.8
Income taxes.................................. (38.8) (37.7)
------- ------
NET INCREASE IN OPERATING EXPENSES AND TAXES $ 11.8 $ 1.8
======= ======
Lower fuel costs in the second quarter and first six months of
2003, compared with the same periods of 2002 resulted from reduced nuclear
generation. Higher purchased power costs primarily reflect increased unit costs
in the second quarter and first six months of 2003 compared to the corresponding
periods of 2002. Increased nuclear costs resulted from additional incremental
costs associated with the extended Davis-Besse outage and unplanned work
performed during the Perry nuclear plant's 56-day refueling outage (44.85%
ownership) in the second quarter of 2003, compared with the 24-day refueling
outage at Beaver Valley Unit 2 (24.47% ownership) in the first quarter of 2002.
The increase in other operating costs in the second quarter and first six months
of 2003, compared to the same periods of 2002 primarily resulted from higher
employee benefit costs.
The small increase in depreciation and amortization charges in
the second quarter of 2003, compared with the second quarter of 2002 was
primarily attributable to three factors - increased amortization of regulatory
assets being recovered under CEI's transition plan ($3.6 million) and
recognition of depreciation on three fossil plants ($5.8 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. Substantially offsetting these
three factors were higher shopping incentive deferrals ($4.7 million) and lower
charges resulting from the implementation of SFAS 143 ($3.6 million). During the
first six months of 2003 depreciation and amortization charges decreased
slightly from the same period of 2002 primarily as the result of the same
offsetting factors affecting the second quarter of 2003.
Net Interest Charges
Net interest charges continued to trend lower, decreasing by
$6.8 million in the second quarter and $11.2 million in the first six months of
2003 from the same periods last year, reflecting redemption and refinancing
activities. CEI's redemption and repricing activities during the first six
months of 2003 totaled $115 million and $113 million, respectively, and are
expected to result in annualized savings of approximately $9 million.
Cumulative Effect of Accounting Changes
Results for the first six months of 2003 include an after-tax
credit to net income of $42.4 million recorded by CEI upon adoption of SFAS 143
in January of 2003. CEI identified applicable legal obligations as defined under
the new accounting standard for nuclear power plant decommissioning, reclamation
of a sludge disposal pond at the Bruce Mansfield Plant, and closure of two coal
ash disposal sites. As a result of adopting SFAS 143 in January 2003, asset
retirement costs of $49.9 million were recorded as part of the carrying amount
of the related long-lived asset, offset by accumulated depreciation of $6.8
million. The asset retirement obligation liability at the date of adoption was
$238.3 million, including accumulated accretion for the period from the date the
liability was incurred to the date of adoption. As of December 31, 2002, CEI had
recorded decommissioning liabilities of $239.7 million, including unrealized
gains on the decommissioning trust funds of $0.4 million. The cumulative effect
adjustment for unrecognized depreciation, accretion offset by the reduction in
the existing decommissioning liabilities and ceasing the accounting practice of
depreciating non-regulated generation assets using a cost of removal component
was a $72.5 million increase to income, or $42.4 million net of income taxes.
Preferred Stock Dividend Requirements
Preferred stock dividend requirements decreased $8.5 million
in the first six months of 2003, compared to the same period last year,
principally due to optional redemptions of preferred stock in 2002.
71
CAPITAL RESOURCES AND LIQUIDITY
CEI's cash requirements in 2003 for operating expenses,
construction expenditures, scheduled debt maturities and preferred stock
redemptions are expected to be met without significantly increasing its net debt
and preferred stock outstanding. Available borrowing capacity under short-term
credit facilities will be used to manage working capital requirements. Over the
next three years, CEI expects to meet its contractual obligations with cash from
operations. Thereafter, CEI expects to use a combination of cash from operations
and funds from the capital markets.
Changes in Cash Position
As of June 30, 2003, CEI had $0.2 million of cash and cash
equivalents, compared with $30.4 million as of December 31, 2002. The major
sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Cash provided by operating activities during the second
quarter and first six months of 2003, compared with the corresponding periods in
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)........... $ 64 $118 $133 $187
Working capital and other... 60 (75) (4) (57)
----- ---- ---- ----
Total....................... $ 124 $ 43 $129 $130
===== ==== ==== ====
(1) Includes net income, depreciation and amortization, deferred income taxes,
investment tax credits and major noncash charges.
Net cash provided from operating activities increased $81
million in the second quarter of 2003 compared to the same period in 2002 due to
a $135 million increase in working capital partially offset by a $54 million
decrease in cash earnings. The largest factor contributing to the increase in
working capital and other was primarily higher accounts payable.
Cash Flows From Financing Activities
In the second quarter and first six months of 2003, net cash
used for financing activities increased $34 million and $18 million,
respectively from the corresponding periods of 2002. The increase in funds used
for financing activities primarily reflected higher security redemptions and
repayments, which were partially offset by changes in short-term borrowings.
CEI had about $0.6 million of cash and temporary investments
and approximately $338.8 million of short-term indebtedness as of June 30, 2003.
CEI had the capability to issue $573.3 million of additional first mortgage
bonds on the basis of property additions and retired bonds. CEI has no
restrictions on the issuance of preferred stock.
Cash Flows From Investing Activities
Net cash used for investing activities increased $33 million
in the second quarter of 2003 from the same quarter of 2002 due to a reduction
in 2002 in the Shippingport Capital Trust investment and higher capital
expenditures in 2003.
During the second half of 2003, capital requirements for
property additions and capital leases are expected to be about $54 million,
including $8 million for nuclear fuel. CEI has additional requirements of
approximately $1 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.
72
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."
Pension and Other Postretirement Benefits
As a result of GPU Service Inc. merging with FirstEnergy
Service Company 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, CEI's accrued pension and OPEB
costs as of June 30, 2003 decreased by $16.7 million and $49.5 million,
respectively.
Other Obligations
Obligations not included on CEI's Consolidated Balance Sheet
primarily consist of sale and leaseback arrangements involving the Bruce
Mansfield Plant. As of June 30, 2003, the present value of these sale and
leaseback operating lease commitments, net of trust investments, total $160
million. CEI sells substantially all of its retail customer receivables, which
provided $96 million of off-balance sheet financing as of June 30, 2003.
EQUITY PRICE RISK
Included in CEI's nuclear decommissioning trust investments
are marketable equity securities carried at their market value of approximately
$141 million and $119 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 $14 million reduction in fair value as of June 30, 2003.
OUTLOOK
Beginning in 2001, CEI's customers were able to select
alternative energy suppliers. CEI continues to deliver power to residential
homes and businesses through its existing distribution systems, which remain
regulated. Customer rates have been restructured into separate components to
support customer choice. In Ohio CEI has a continuing responsibility to provide
power to those customers not choosing to receive power from an alternative
energy supplier subject to certain limits. Adopting new approaches to regulation
and experiencing new forms of competition have created new uncertainties.
Regulatory Matters
In 2001, Ohio customer rates were restructured to establish
separate charges for transmission, distribution, transition cost recovery and a
generation-related component. When one of CEI's customers elects to obtain power
from an alternative supplier, CEI reduces the customer's bill with a "generation
shopping credit," based on the regulated generation component (plus an
incentive), and the customer receives a generation charge from the alternative
supplier. CEI has continuing PLR responsibility to its franchise customers
through December 31, 2005.
Regulatory assets are costs which have been authorized by the
PUCO and the Federal Energy Regulatory Commission for recovery from customers in
future periods and, without such authorization, would have been charged to
income when incurred. Regulatory assets decreased $43.5 million to $1,148.3
million as of June 30, 2003 from the balance as of December 31, 2002. All of
CEI's regulatory assets are expected to continue to be recovered under the
provisions of its transition plan.
73
As part of CEI's Ohio transition plan it is obligated to
supply electricity to customers who do not choose an alternative supplier. CEI
is also required to provide 400 megawatts (MW) of low cost supply to
unaffiliated alternative suppliers that serve customers within its service area.
CEI's competitive retail sales affiliate, FES, acts as an alternate supplier for
a portion of the load in its franchise area.
Davis-Besse Restoration
On April 30, 2002, the Nuclear Regulatory Commission (NRC)
initiated a formal inspection process at the Davis-Besse nuclear plant. This
action was taken in response to corrosion found by FENOC in the reactor vessel
head near the nozzle penetration hole during a refueling outage in the first
quarter of 2002. The purpose of the formal inspection process is to establish
criteria for NRC oversight of the licensee's performance and to provide a record
of the major regulatory and licensee actions taken, and technical issues
resolved, leading to the NRC's approval of restart of the plant.
Restart activities include both hardware and management
issues. In addition to refurbishment and installation work at the plant,
FirstEnergy has made significant management and human performance changes with
the intent of establishing the proper safety culture throughout the workforce.
Work was completed on the reactor head during 2002 and is continuing on efforts
designed to enhance the unit's reliability and performance. FirstEnergy is also
accelerating maintenance work that had been planned for future refueling and
maintenance outages. At a meeting with the NRC in November 2002, FirstEnergy
discussed plans to test the bottom of the reactor for leaks and to install a
state-of-the-art leak-detection system around the reactor. The additional
maintenance work being performed has expanded the previous estimates of
restoration work. FirstEnergy anticipates that the unit will be ready for
restart in the 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 (CEI's share - 51.38%) 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
CEI believes it is in compliance with the current sulfur
dioxide (SO(2)) and nitrogen oxide (NO)(x) reduction requirements under the
Clean Air Act Amendments of 1990. In 1998, the Environmental Protection Agency
(EPA) finalized regulations requiring additional NO(x) reductions in the future
from its generating facilities. Various regulatory and judicial actions have
since sought to further define NO(x) reduction requirements (see Note 2 -
Environmental Matters). CEI continues to evaluate its compliance plans and other
compliance options.
Violations of federally approved SO(2) regulations can result
in shutdown of the generating unit involved and/or civil or criminal penalties
of up to $31,500 for each day a unit is in violation. The EPA has an interim
enforcement policy for SO(2) regulations in Ohio that allows for compliance
based on a 30-day averaging period. CEI cannot predict what action the EPA may
take in the future with respect to the interim enforcement policy.
74
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants. The EPA identified mercury as the hazardous air pollutant of
greatest concern. The EPA established a schedule to propose regulations by
December 2003 and issue final regulations by December 2004. The future cost of
compliance with these regulations may be substantial.
As a result of the Resource Conservation and Recovery Act of
1976, as amended, and the Toxic Substances Control Act of 1976, federal and
state hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous waste
disposal requirements pending the EPA's evaluation of the need for future
regulation. The EPA has issued its final regulatory determination that
regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the
EPA announced that it will develop national standards regulating disposal of
coal ash under its authority to regulate nonhazardous waste.
CEI believes it is in compliance with the current SO(2) and
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 requires
compliance with the NO(x) budgets at the Companies' Pennsylvania facilities by
May 1, 2003 and Ohio submitted a SIP that requires compliance with the NO(x)
budgets at the Companies' Ohio facilities by May 31, 2004.
CEI has been named as a "potentially responsible party" (PRP)
at waste disposal sites which may require cleanup under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980. Allegations of
disposal of hazardous substances at historical sites and the liability involved
are often unsubstantiated and subject to dispute; however, federal law provides
that all PRPs for a particular site be held liable on a joint and several basis.
Therefore, potential environmental liabilities have been recognized on the
Consolidated Balance Sheet as of June 30, 2003, based on estimates of the total
costs of cleanup, CEI's proportionate responsibility for such costs and the
financial ability of other nonaffiliated entities to pay. CEI's total accrued
liabilities were approximately $2.5 million as of June 30, 2003.
The effects of compliance on CEI with regard to environmental
matters could have a material adverse effect on its earnings and competitive
position. These environmental regulations affect its earnings and competitive
position to the extent CEI competes with companies that are not subject to such
regulations and therefore do not bear the risk of costs associated with
compliance, or failure to comply, with such regulations. CEI believes it is in
material compliance with existing regulations, but is unable to predict how and
when applicable environmental regulations may change and what, if any, the
effects of any such change would be.
Legal Matters
Various lawsuits, claims and proceedings related to CEI's
normal business operations are pending against CEI, the most significant of
which are described above.
SIGNIFICANT ACCOUNTING POLICIES
CEI prepares its consolidated financial statements in
accordance with accounting principles that are generally accepted in the United
States. Application of these principles often requires a high degree of
judgment, estimates and assumptions that affect CEI's financial results. All of
CEI's assets are subject to their own specific risks and uncertainties and are
regularly reviewed for impairment. Assets related to the application of the
policies discussed below are similarly reviewed with their risks and
uncertainties reflecting those specific factors. CEI's more significant
accounting policies are described below.
Regulatory Accounting
CEI is subject to regulation that sets the prices (rates) it
is permitted to charge its customers based on the costs that the regulatory
agencies determine CEI is permitted to recover. At times, regulators permit the
future recovery through rates of costs that would be currently charged to
expense by an unregulated company. This rate-making process results in the
recording of regulatory assets based on anticipated future cash inflows. As a
result of the changing regulatory framework in Ohio a significant amount of
regulatory assets have been recorded. As of June 30, 2003, CEI's regulatory
assets totaled $1,148.3 million. CEI regularly reviews these assets to assess
their ultimate recoverability within
75
the approved regulatory guidelines. Impairment risk associated with these assets
relates to potentially adverse legislative, judicial or regulatory actions in
the future.
Revenue Recognition
CEI follows the accrual method of accounting for revenues,
recognizing revenue for kilowatt-hours that have been delivered but not yet been
billed through the end of the accounting period. The determination of unbilled
revenues requires management to make various estimates including:
- Net energy generated or purchased for retail load
- Losses of energy over distribution lines
- Allocations to distribution companies within the FirstEnergy
system
- Mix of kilowatt-hour usage by residential, commercial and
industrial customers
- Kilowatt-hour usage of customers receiving electricity from
alternative suppliers
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory
defined pension 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.
Pension and OPEB costs may also be affected by changes to key assumptions,
including anticipated rates of return on plan assets, the discount rates and
health care trend rates used in determining the projected benefit obligations
for pension and OPEB costs.
In accordance with SFAS 87, "Employers' Accounting for
Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other
Than Pensions," changes in pension and OPEB obligations associated with these
factors may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
In selecting an assumed discount rate, FirstEnergy considers
currently available rates of return on high-quality fixed income investments
expected to be available during the period to maturity of the pension and other
postretirement benefit obligations. Due to the significant decline in corporate
bond yields and interest rates in general during 2002, FirstEnergy reduced the
assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001.
FirstEnergy's assumed rate of return on pension plan assets considers historical
market returns and economic forecasts for the types of investments held by its
pension trusts. The market values of FirstEnergy's pension assets have been
affected by sharp declines in the equity markets since mid-2000. In 2002 and
2001, plan assets earned (11.3)% and (5.5)%, respectively. FirstEnergy's pension
costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As
of December 31, 2002 the assumed return on plan assets was reduced to 9.00%
based upon FirstEnergy's projection of future returns and pension trust
investment allocation of approximately 60% large cap equities, 10% small cap
equities and 30% bonds.
Based on pension assumptions and pension plan assets as of
December 31, 2002, FirstEnergy will not be required to fund its pension plans in
2003. While OPEB plan assets have also been affected by sharp declines in the
equity market, the impact is not as significant due to the relative size of the
plan assets. However, health care cost trends have significantly increased and
will affect future OPEB costs. The 2003 composite health care trend rate
assumption is approximately 10%-12% gradually decreasing to 5% in later years,
compared to FirstEnergy's 2002 assumption of approximately 10% in 2002,
gradually decreasing to 4%-6% in later years. In determining its trend rate
assumptions, 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.
76
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," CEI periodically evaluates its long-lived assets
to determine whether conditions exist that would indicate that the carrying
value of an asset may not be fully recoverable. The accounting standard requires
that if the sum of future cash flows (undiscounted) expected to result from an
asset, is less than the carrying value of the asset, an asset impairment must be
recognized in the financial statements. If impairment, other than of a temporary
nature, has occurred, CEI recognizes a loss - calculated as the difference
between the carrying value and the estimated fair value of the asset (discounted
future net cash flows).
Goodwill
In a business combination, the excess of the purchase price
over the estimated fair values of the assets acquired and liabilities assumed is
recognized as goodwill. Based on the guidance provided by SFAS 142, CEI
evaluates its goodwill for impairment at least annually and would make such an
evaluation more frequently if indicators of impairment should arise. In
accordance with the accounting standard, if the fair value of a reporting unit
is less than its carrying value including goodwill, an impairment for goodwill
must be recognized in the financial statements. If impairment were to occur, CEI
would recognize a loss - calculated as the difference between the implied fair
value of a reporting unit's goodwill and the carrying value of the goodwill.
CEI's annual review was completed in the third quarter of 2002. The results of
that review indicated no impairment of goodwill. The forecasts used in CEI's
evaluations of goodwill reflect operations consistent with its general business
assumptions. Unanticipated changes in those assumptions could have a significant
effect on its future evaluations of goodwill. As of June 30, 2003, CEI had
approximately $1.7 billion of goodwill.
RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET IMPLEMENTED
FIN 46, "Consolidation of Variable Interest Entities - an
interpretation of ARB 51"
In January 2003, the FASB issued this interpretation of ARB
No. 51, "Consolidated Financial Statements". The new interpretation provides
guidance on consolidation of variable interest entities (VIEs), generally
defined as certain entities in which equity investors do not have the
characteristics of a controlling financial interest or do not have sufficient
equity at risk for the entity to finance its activities without additional
subordinated financial support from other parties. This Interpretation requires
an enterprise to disclose the nature of its involvement with a VIE if the
enterprise has a significant variable interest in the VIE and to consolidate a
VIE if the enterprise is the primary beneficiary. VIEs created after January 31,
2003 are immediately subject to the provisions of FIN 46. VIEs created before
February 1, 2003 are subject to this interpretation's provisions in the first
interim or annual reporting period beginning after June 15, 2003 (CEI's third
quarter of 2003). The FASB also identified transitional disclosure provisions
for all financial statements issued after January 31, 2003.
CEI currently has transactions which may fall within the scope
of this interpretation and which are reasonably possible of meeting the
definition of a VIE in accordance with FIN 46. One of these entities CEI is
currently consolidating is the Shippingport Capital Trust which reacquired a
portion of the off-balance sheet debt issued in connection with the sale and
leaseback of its interest in the Bruce Mansfield Plant. Ownership of the trust
includes a 4.85 percent interest by nonaffiliated parties and a 0.34 percent
equity interest by Toledo Edison Capital Corp., an affiliated company.
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 (CEI's third quarter of 2003) for all other financial
instruments.
CEI 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, CEI classified as debt the preferred stock subject to
mandatory redemptions with a carrying value of approximately $5.0 million as of
June 30, 2003. Dividends on preferred stock subject to mandatory redemption in
CEI's Consolidated Statements of Income are currently not included in net
interest
77
charges. Therefore, the application of SFAS 150 will require the
reclassification of such preferred dividends to net interest charges.
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. CEI is
currently assessing the new EITF consensus and has not yet determined the impact
on its financial position or results of operations following adoption.
78
THE TOLEDO EDISON COMPANY
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)
OPERATING REVENUES........................................ $ 215,988 $ 250,307 $ 447,810 $ 502,874
--------- ---------- ---------- ----------
OPERATING EXPENSES AND TAXES:
Fuel................................................... 7,743 9,427 15,424 20,818
Purchased power........................................ 74,225 79,352 148,476 161,756
Nuclear operating costs................................ 66,641 44,117 131,196 117,790
Other operating costs.................................. 32,297 31,195 66,334 58,379
--------- ---------- ---------- ----------
Total operation and maintenance expenses............. 180,906 164,091 361,430 358,743
Provision for depreciation and amortization............ 34,678 37,348 70,318 75,116
General taxes.......................................... 13,966 13,449 28,974 27,197
Income taxes (benefit)................................. (11,482) 7,770 (16,309) 3,481
--------- ---------- ---------- ----------
Total operating expenses and taxes................. 218,068 222,658 444,413 464,537
--------- ---------- ---------- ----------
OPERATING INCOME (LOSS)................................... (2,080) 27,649 3,397 38,337
OTHER INCOME.............................................. 3,776 3,743 6,876 8,086
--------- ---------- ---------- ----------
INCOME BEFORE NET INTEREST CHARGES........................ 1,696 31,392 10,273 46,423
--------- ---------- ---------- ----------
NET INTEREST CHARGES:
Interest on long-term debt............................. 11,631 15,601 23,446 31,473
Allowance for borrowed funds used during construction.. (1,184) (382) (2,490) (810)
Other interest expense (credit)........................ 961 (360) 429 (1,095)
--------- ---------- ---------- ----------
Net interest charges............................... 11,408 14,859 21,385 29,568
--------- ---------- ---------- ----------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE...................................... (9,712) 16,533 (11,112) 16,855
Cumulative effect of accounting change (net of income taxes
of $18,201,000) (Note 5)............................... -- -- 25,550 --
--------- ---------- ---------- ----------
NET INCOME (LOSS)......................................... (9,712) 16,533 14,438 16,855
PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 2,211 2,210 4,416 6,934
--------- ---------- ---------- ----------
EARNINGS (LOSS) ON COMMON STOCK........................... $ (11,923) $ 14,323 $ 10,022 $ 9,921
========= ========== ========== ==========
The preceding Notes to Financial Statements as they relate to The Toledo Edison
Company are an integral part of these statements.
79
THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
JUNE 30, DECEMBER 31,
2003 2002
----------- ------------
RESTATED
(SEE NOTE 1)
(IN THOUSANDS)
ASSETS
UTILITY PLANT:
In service................................................................ $ 1,696,989 $ 1,600,860
Less--Accumulated provision for depreciation.............................. 734,675 706,772
----------- -----------
962,314 894,088
----------- -----------
Construction work in progress-
Electric plant.......................................................... 91,258 104,091
Nuclear fuel............................................................ 22,414 33,650
----------- -----------
113,672 137,741
----------- -----------
1,075,986 1,031,829
----------- -----------
OTHER PROPERTY AND INVESTMENTS:
Shippingport Capital Trust................................................ 223,373 240,963
Nuclear plant decommissioning trusts...................................... 195,470 174,514
Long-term notes receivable from associated companies...................... 162,059 162,159
Other..................................................................... 2,102 2,236
----------- -----------
583,004 579,872
----------- -----------
CURRENT ASSETS:
Cash and cash equivalents................................................. 10,309 20,688
Receivables-
Customers............................................................... 10,445 4,711
Associated companies.................................................... 110,518 55,245
Other................................................................... 8,233 6,778
Notes receivable from associated companies................................ 10,796 1,957
Materials and supplies, at average cost-
Owned................................................................... 12,740 13,631
Under consignment....................................................... 18,738 22,997
Prepayments and other..................................................... 12,435 3,455
----------- -----------
194,214 129,462
----------- -----------
DEFERRED CHARGES:
Regulatory assets......................................................... 537,251 578,243
Goodwill.................................................................. 504,522 504,522
Property taxes............................................................ 23,429 23,429
Other..................................................................... 14,916 14,257
----------- -----------
1,081,118 1,120,451
----------- -----------
$ 2,933,322 $ 2,861,614
=========== ===========
80
THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
JUNE 30, DECEMBER 31,
2003 2002
----------- ------------
RESTATED
(SEE NOTE 1)
(IN THOUSANDS)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity-
Common stock, $5 par value, authorized 60,000,000 shares -
39,133,887 shares outstanding......................................... $ 195,669 $ 195,670
Other paid-in capital................................................... 428,559 428,559
Accumulated other comprehensive loss.................................... (5,564) (20,012)
Retained earnings....................................................... 88,801 76,978
----------- -----------
Total common stockholder's equity................................... 707,465 681,195
Preferred stock not subject to mandatory redemption....................... 126,000 126,000
Long-term debt............................................................ 501,938 557,265
----------- -----------
1,335,403 1,364,460
----------- -----------
CURRENT LIABILITIES:
Currently payable long-term debt.......................................... 160,405 189,355
Accounts payable-
Associated companies.................................................... 173,255 171,862
Other................................................................... 3,653 9,338
Notes payable to associated companies..................................... 281,245 149,653
Accrued taxes............................................................. 35,448 34,676
Accrued interest.......................................................... 17,526 16,377
Other..................................................................... 103,998 82,062
----------- -----------
775,530 653,323
----------- -----------
DEFERRED CREDITS:
Accumulated deferred income taxes......................................... 198,151 158,279
Accumulated deferred investment tax credits............................... 26,428 29,255
Nuclear plant decommissioning costs....................................... -- 179,587
Asset retirement obligation............................................... 163,603 --
Retirement benefits....................................................... 57,849 82,553
Lease market valuation liability.......................................... 304,900 317,200
Other..................................................................... 71,458 76,957
----------- -----------
822,389 843,831
----------- -----------
----------- -----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... $ 2,933,322 $ 2,861,614
=========== ===========
The preceding Notes to Financial Statements as they relate to The Toledo Edison
Company are an integral part of these balance sheets.
81
THE TOLEDO EDISON COMPANY
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)............................................... $ (9,712) $ 16,533 $ 14,438 $ 10,209
Adjustments to reconcile net income (loss) to net
cash from operating activities-
Provision for depreciation and amortization.............. 34,678 37,348 70,318 75,116
Nuclear fuel and lease amortization...................... 1,820 2,671 4,588 6,244
Deferred income taxes, net............................... (2,138) (4,322) 16,992 (2,963)
Investment tax credits, net.............................. (514) (527) (1,028) (1,053)
Receivables.............................................. (74,711) (18,762) (62,462) 1,260
Materials and supplies................................... 5,877 (1,169) 5,150 (1,820)
Accounts payable......................................... 42,068 (9,210) (11,849) (7,049)
Cumulative effect of accounting change (Note 5).......... -- -- (43,751) --
Accrued taxes............................................ (5,263) 15,091 482 9,381
Accrued interest......................................... 2,548 1,972 1,149 (58)
Prepayments and other.................................... (3,858) 944 (8,979) 10,931
Deferred lease costs..................................... (27,788) (59,482) (35,460) (40,693)
Other.................................................... 51,923 (5,560) 35,391 (18,213)
--------- --------- --------- ---------
Net cash provided from (used for) operating activities. 14,930 (24,473) (35,021) 41,292
--------- --------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net................................. 33,199 47,957 131,591 116,955
Redemptions and Repayments-
Preferred stock............................................ -- -- -- (85,299)
Long-term debt............................................. (9,162) (12,169) (82,762) (12,263)
Dividend Payments-
Common stock............................................... -- -- -- (5,600)
Preferred stock............................................ (2,211) (2,210) (4,422) (5,635)
--------- --------- --------- ---------
Net cash provided from financing activities............ 21,826 33,578 44,407 8,158
--------- --------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions........................................... (17,540) (14,702) (34,782) (40,261)
Loans to associated companies................................ (4,294) (1,906) (8,739) (8,207)
Capital trust investments.................................... (38) 16,883 17,590 16,826
Other........................................................ (6,020) (11,536) (13,834) (17,657)
--------- --------- --------- ---------
Net cash used for investing activities................. (27,892) (11,261) (39,765) (49,299)
--------- --------- --------- ---------
Net increase (decrease) in cash and cash equivalents............ 8,864 (2,156) (10,379) 151
Cash and cash equivalents at beginning of period................ 1,445 2,609 20,688 302
--------- --------- --------- ---------
Cash and cash equivalents at end of period...................... $ 10,309 $ 453 $ 10,309 $ 453
========= ========= ========= =========
The preceding Notes to Financial Statements as they relate to The Toledo Edison
Company are an integral part of these statements.
82
REPORT OF INDEPENDENT AUDITORS
To the Stockholders and Board
of Directors of The Toledo
Edison Company:
We have reviewed the accompanying consolidated balance sheet of The Toledo
Edison Company and its subsidiary as of 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 stockholder's equity,
preferred stock, cash flows and taxes for the year then ended (not presented
herein), and in our report (which contained references to the Company's change
in its method of accounting for goodwill in 2002 as discussed in Note 1(D) to
those consolidated financial statements and the Company's restatement of its
previously issued consolidated financial statements as of December 31, 2002 and
2001 and for each of the three years in the period ended December 31, 2002 as
discussed in Note 1(M) to those consolidated financial statements) dated August
18, 2003 we expressed an unqualified opinion on those consolidated financial
statements. In our opinion, the information set forth in the accompanying
consolidated balance sheet as of December 31, 2002, is fairly stated in all
material respects in relation to the consolidated balance sheet from which it
has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
August 18, 2003
83
THE TOLEDO EDISON COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
TE is a wholly owned, electric utility subsidiary of
FirstEnergy. TE conducts business in portions of Ohio, providing regulated
electric distribution services. TE also provides generation services to those
customers electing to retain them as their power supplier. TE provides power
directly to wholesale customers under previously negotiated contracts, as well
as to alternative energy suppliers under TE's transition plan. TE has unbundled
the price of electricity into its component elements - including generation,
transmission, distribution and transition charges. Power supply requirements of
TE are provided by FES - an affiliated company.
RESTATEMENTS
As further discussed in Note 1 to the Consolidated Financial
Statements, TE identified certain accounting matters that require restatement of
the 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 associated with 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, TE recovers
transition costs, including regulatory assets, through an approved transition
plan filed under Ohio's electric utility restructuring legislation. The plan,
which was approved in July 2000, provides for the recovery of costs from January
1, 2001 through a fixed number of kilowatt-hour sales to all customers that
continue to receive regulated transmission and distribution service, which is
expected to end in 2007 for TE.
TE amortizes transition costs using the effective interest
method. The amortization schedules developed in applying this method were
previously 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). TE
has subsequently revised the amortization schedules under the effective interest
method to consider only revenues relating to transition regulatory assets
recognized on the balance sheet. The amortization expense under the revised
method (see Note 1) increased by $17.6 million for the three months and $34
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 TE, under the purchase accounting rules of
Accounting Principles Board (APB) Opinion No. 16. In connection with the
reassessment of the accounting for the transition plan, FirstEnergy reassessed
its accounting for the Centerior purchase and determined that above market lease
liabilities should have been recorded at the time of the merger. Accordingly, as
of 2002, FirstEnergy recorded additional adjustments associated with the 1997
merger between OE and Centerior to reflect certain above market lease
liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant, for which TE
had previously entered into sale-leaseback arrangements. TE recorded an increase
in goodwill related to the above market lease costs for Beaver Valley Unit 2
since regulatory accounting for nuclear generating assets had been discontinued
prior to the merger date and it was determined that this additional liability
would have increased goodwill at the date of the merger. The corresponding
impact of the above market lease liabilities for the Bruce Mansfield Plant were
recorded as regulatory assets because regulatory accounting had not been
discontinued at that time for the fossil generating assets and recovery of these
liabilities was provided for under the transition plan.
The total above market lease obligation of $111 million
associated with Beaver Valley Unit 2 will be amortized through the end of the
lease term in 2017. The additional goodwill has been recorded on a net basis,
reflecting amortization that would have been recorded through 2001 when goodwill
amortization ceased with the adoption of SFAS 142. The total above market lease
obligation of $298 million associated with the Bruce Mansfield Plant is being
amortized through the end of 2016. Before the start of the transition plan in
fiscal 2001, the regulatory asset would have been amortized at the same rate as
the lease obligation. Beginning in 2001, the remaining unamortized regulatory
asset would have been included in TE's amortization schedule for regulatory
assets and amortized through the end of the recovery period - approximately 2007
for TE.
84
RESULTS OF OPERATIONS
TE experienced a loss of $11.9 million on common stock in the
second quarter of 2003 or a decrease of $26.2 million from earnings of $14.3
million in the second quarter of 2002. Earnings on common stock in the first six
months of 2003 increased to $10.0 million from $9.9 million in the first half of
2002. Results in the first six months of 2003 included an after-tax credit of
$25.60 million from the cumulative effect of an accounting change due to the
adoption of SFAS 143, "Accounting for Asset Retirement Obligations." The loss
before the cumulative effect was $11.1 million in the first half of 2003,
compared to income of $16.9 million for the same period of 2002. The lower
results in the second quarter and the first six months of 2003 before the
cumulative effect reflected higher nuclear operating costs and lower operating
revenues which were partially offset by lower fuel, purchased power,
depreciation and amortization, and financing costs.
Operating revenues decreased by $34.3 million or 13.7% in the
second quarter and $55.1 million or 10.9% in the first six months of 2003 from
the same periods in 2002. The lower revenues resulted from reduced kilowatt-hour
sales due, in large part, to the cooler-than-normal temperatures in the second
quarter of 2003. These results were moderated in the first half of 2003 as
compared to the corresponding period of 2002 by the effects of colder weather in
the first quarter of 2003 which increased heating demands. Kilowatt-hour sales
to retail customers declined by 16.4% in the second quarter of 2003 and 10.2% in
the first half of 2003 from the same periods of 2002, which reduced generation
sales revenue by $15.5 million and $27.1 million, respectively. Electric
generation services provided to retail customers by alternative suppliers as a
percent of total sales delivered in TE's franchise area increased 7.5 percentage
points in the second quarter and first six months of 2003 from the corresponding
periods last year.
Distribution deliveries decreased 8.3% in the second quarter
and 1.5% in the first six months of 2003 compared to the corresponding periods
of 2002. Decreases occurred in all customer sectors (residential, commercial and
industrial) in the second quarter of 2003 and only residential sales increased
in the first half of 2003. As a result, revenues from electricity throughput
decreased by $10.8 million in the second quarter of 2003 from the second quarter
of 2002. Revenues from electricity throughput increased by $9.8 million in the
first six months of 2003 due to an increase in industrial sales revenues of
$10.6 million which reflected the effect of higher unit prices partially offset
by a 3.1% kilowatt-hour sales decrease as compared to the same period of 2002.
Transition plan incentives, provided to customers to encourage
switching to alternative energy providers, reduced operating revenues by $1.2
million in the second quarter and $3.4 million in the first six months of 2003
compared with the same periods last year. These revenue reductions are deferred
for future recovery under TE's transition plan and do not materially affect
current period earnings.
Sales revenues from wholesale customers decreased by $6.3
million and $27.4 million (primarily to FES) in the second quarter and the first
six months of 2003 compared with the same periods in 2002, due to reduced
nuclear generation from the extended outage of the Davis-Besse Plant and a
longer than planned refueling outage at Perry Plant. Available nuclear
generation declined 32.4% in the second quarter and 30.8% in the first half of
2003 compared to the corresponding periods of 2002.
Changes in electric generation sales and distribution
deliveries in the second quarter and the first half of 2003 from the second
quarter and first half of 2002 are summarized in the following table:
CHANGES IN KILOWATT-HOUR SALES THREE MONTHS SIX MONTHS
------------------------------ ------------ ----------
INCREASE (DECREASE)
Electric Generation:
Retail.............................. (16.4)% (10.2)%
Wholesale........................... (17.1)% (23.2)%
-----------------------------------------------------------------
TOTAL ELECTRIC GENERATION SALES....... (16.7)% (15.9)%
=================================================================
Distribution Deliveries:
Residential......................... (10.2)% 1.3%
Commercial.......................... (12.4)% (1.0)%
Industrial.......................... (6.0)% (3.1)%
-----------------------------------------------------------------
TOTAL DISTRIBUTION DELIVERIES......... (8.3)% (1.5)%
=================================================================
Operating Expenses and Taxes
Total operating expenses and taxes decreased by $4.6 million
in the second quarter and $20.1 million in the first six months of 2003 from the
same periods in 2002. The following table presents changes from the prior year
by expense category.
85
OPERATING EXPENSES AND TAXES - CHANGES THREE MONTHS SIX MONTHS
-------------------------------------------------------------------------
(IN MILLIONS)
INCREASE (DECREASE)
Fuel......................................... $ (1.7) $ (5.4)
Purchased power costs........................ (5.1) (13.3)
Nuclear operating costs...................... 22.5 13.4
Other operating costs........................ 1.1 8.0
------------------------------------------------------------------------
TOTAL OPERATION AND MAINTENANCE EXPENSES... 16.8 2.7
Provision for depreciation and amortization.. (2.7) (4.8)
General taxes................................ 0.5 1.8
Income taxes................................. (19.2) (19.8)
------------------------------------------------------------------------
NET DECREASE IN OPERATING EXPENSES AND TAXES $ (4.6) $ (20.1)
========================================================================
Lower fuel costs in the second quarter and first half of 2003,
compared with the same quarter and six months of 2002, resulted from reduced
nuclear generation (down 32.4% and 30.8%, respectively). The lower purchased
power costs reflected fewer kilowatt-hours required for customer needs which
more than offset an increase in unit costs. Increased nuclear costs resulted
from additional incremental costs associated with the extended Davis-Besse
outage and unplanned work performed during the Perry nuclear plant's 56-day
refueling outage (19.91% ownership) in the second quarter of 2003, compared with
the 24-day refueling outage at Beaver Valley Unit 2 (19.91% ownership) in the
first quarter of 2002. The increase in other operating costs resulted in part
from higher employee benefit costs.
Charges for depreciation and amortization decreased by $2.7
million in the second quarter of 2003, compared with the second quarter of 2002
primarily from three factors - higher shopping incentive deferrals ($1.2
million), lower charges resulting from the implementation of SFAS 143 ($4.5
million) and revised service life assumptions for generating plants ($2.6
million). Partially offsetting these decreases were increased amortization of
regulatory assets being recovered under TE's transition plan ($3.4 million),
recognition of depreciation on the Bay Shore generating plant ($1.2 million)
which had been held pending sale in the second quarter of 2002 but was
subsequently retained by FirstEnergy in the fourth quarter of 2002 and reduced
regulatory asset deferrals ($0.7 million).
In the first six months of 2003, depreciation and amortization
decreased by $4.8 million compared to the corresponding period of 2002 as a
result of the same factors which impacted the second quarter comparison - higher
shopping incentive deferrals ($3.4 million), lower charges resulting from
implementation of SFAS 143 ($8.2 million) and revised service life assumptions
($5.0 million). Partially offsetting these decreases were increased amortization
of regulatory assets being recovered under TE's transition plan ($7.7 million),
recognition of depreciation on the Bay Shore generating plant ($2.4 million) and
reduced regulatory asset deferrals ($1.6 million).
Net Interest Charges
Net interest charges continued to trend lower, decreasing by
$3.5 million in the second quarter and $7.5 million in the first half of 2003
from the same periods last year, reflecting security redemptions and
refinancings since the beginning of the second quarter of 2002.
Cumulative Effect of Accounting Change
Upon adoption of SFAS 143 in the first quarter of 2003, TE
recorded an after-tax credit to net income of $25.5 million. TE identified
applicable legal obligations as defined under the new accounting standard for
nuclear power plant decommissioning and reclamation of a sludge disposal pond at
the Bruce Mansfield Plant. As a result of adopting SFAS 143 in January 2003,
asset retirement costs of $41.1 million were recorded as part of the carrying
amount of the related long-lived asset, offset by accumulated depreciation of
$5.5 million. The asset retirement obligation liability at the date of adoption
was $172 million, including accumulated accretion for the period from the date
the liability was incurred to the date of adoption. As of December 31, 2002, TE
had recorded decommissioning liabilities of $180.8 million, including unrealized
gains on the decommissioning trust funds of $1.9 million. The cumulative effect
adjustment for unrecognized depreciation, accretion offset by the reduction in
the existing decommissioning liabilities and ceasing the accounting practice of
depreciating non-regulated generation assets using a cost of removal component
was a $43.8 million increase to income, or $25.6 million net of income taxes.
CAPITAL RESOURCES AND LIQUIDITY
TE's cash requirements in 2003 for operating expenses,
construction expenditures, scheduled debt maturities and preferred stock
redemptions are expected to be met without significantly increasing its net debt
and preferred stock outstanding. Available borrowing capacity under short-term
credit facilities will be used to manage working capital requirements. Over the
next three years, TE expects to meet its contractual obligations with cash from
operations. Thereafter, TE expects to use a combination of cash from operations
and funds from the capital markets.
86
Changes in Cash Position
As of June 30, 2003, TE had $10.3 million of cash and cash
equivalents, compared with $20.7 million as of December 31, 2002. The major
sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Cash provided by (used for) operating activities during the
second quarter and first six months of 2003, compared with the corresponding
periods in 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)........ $24 $ 52 $ 62 $ 87
Working capital and other (9) (76) (77) (46)
----------------------------------------------------------------------
TOTAL.................... $15 $(24) $(15) $ 41
======================================================================
(1) Includes net income, depreciation and amortization, deferred income taxes,
investment tax credits and major noncash charges.
Net cash provided from operating activities was $15 million in
the second quarter and $15 million of net cash used in the first half of 2003
compared with $24 million and $41 million, respectively, in the corresponding
periods of 2002. The second quarter increase in funds from operating activities
resulted from a $67 million decrease in cash used for working capital.
Cash Flows From Financing Activities
In the second quarter of 2003, net cash provided from
financing activities decreased to $22 million from $34 million in the second
quarter of 2002. This decrease in cash provided from financing activities
primarily resulted from lower short-term borrowings from associated companies
and a slight reduction in security redemptions and repayments.
TE had approximately $21.1 million of cash and temporary
investments and approximately $281.2 million of short-term indebtedness as of
June 30, 2003. TE is currently precluded from issuing first mortgage bonds or
preferred stock based upon applicable earnings coverage tests as of June 30,
2003.
Cash Flows From Investing Activities
Net cash used for investing activities increased $17 million
between the second quarter of 2003 and the same quarter of 2002 due to a
reduction in 2002 in the Shippingport Capital Trust investment.
During the second half of 2003, capital requirements for
property additions and capital leases are expected to be about $34 million,
including $6 million for nuclear fuel. TE has additional requirements of
approximately $34 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
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.
87
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."
Pension and Other Postretirement Benefits
As a result of GPU Service Inc. merging with FirstEnergy
Service Company 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, TE's accrued pension and OPEB costs
as of June 30, 2003 decreased by $3.4 million and $24.5 million, respectively.
Other Obligations
Obligations not included on TE's Consolidated Balance Sheet
primarily consist of sale and leaseback arrangements involving the Bruce
Mansfield Plant and Beaver Valley Unit 2. As of June 30, 2003, the present value
of these sale and leaseback operating lease commitments, net of trust
investments, totaled $474 million. TE sells substantially all of its retail
customer receivables, which provided $49 million of off-balance sheet financing
as of June 30, 2003.
EQUITY PRICE RISK
Included in TE's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $107
million and $90 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 $11 million reduction in fair value as of June 30, 2003.
OUTLOOK
Beginning in 2001, TE's customers were able to select
alternative energy suppliers. TE continues to deliver power to residential homes
and businesses through its existing distribution system, which remains
regulated. Customer rates have been restructured into separate components to
support customer choice. TE has a continuing responsibility to provide power to
those customers not choosing to receive power from an alternative energy
supplier subject to certain limits. Adopting new approaches to regulation and
experiencing new forms of competition have created new uncertainties.
Regulatory Matters
In 2001, Ohio customer rates were restructured to establish
separate charges for transmission, distribution, transition cost recovery and a
generation-related component. When one of TE's Ohio customers elects to obtain
power from an alternative supplier, TE reduces the customer's bill with a
"generation shopping credit," based on the regulated generation component (plus
an incentive), and the customer receives a generation charge from the
alternative supplier. TE has continuing PLR responsibility to its franchise
customers through December 31, 2005.
Regulatory assets are costs which have been authorized by The
Public Utilities Commission of Ohio (PUCO) and the Federal Energy Regulatory
Commission for recovery from customers in future periods and, without such
authorization, would have been charged to income when incurred. Regulatory
assets declined $41.0 million to $537.3 million as of June 30, 2003 from the
balance as of December 31, 2002, resulting from recovery of transition plan
regulatory assets.
As part of TE's transition plan it is obligated to supply
electricity to customers who do not choose an alternative supplier. TE is also
required to provide 160 megawatts (MW) of low cost supply to unaffiliated
alternative suppliers that serve customers within its service area. TE's
competitive retail sales affiliate, FES, acts as an alternate supplier for a
portion of the load in its franchise area.
88
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 (TE's share - 48.62%) 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
TE believes it is in compliance with the current sulfur
dioxide (SO(2)) and nitrogen oxide (NO(x)) reduction requirements under the
Clean Air Act Amendments of 1990. In 1998, the Environmental Protection Agency
(EPA) finalized regulations requiring additional NO(x) reductions in the future
from our Ohio and Pennsylvania facilities. Various regulatory and judicial
actions have since sought to further define NO(x) reduction requirements (see
Note 2C - Environmental Matters). TE continues to evaluate its compliance plans
and other compliance options.
Violations of federally approved SO(2) regulations can result
in shutdown of the generating unit involved and/or civil or criminal penalties
of up to $31,500 for each day a unit is in violation. The EPA has an interim
enforcement policy for SO(2) regulations in Ohio that allows for compliance
based on a 30-day averaging period. We cannot predict what action the EPA may
take in the future with respect to the interim enforcement policy.
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants. The EPA identified mercury as the hazardous air pollutant of
greatest concern. The EPA established a schedule to propose regulations by
December 2003 and issue final regulations by December 2004. The future cost of
compliance with these regulations may be substantial.
89
As a result of the Resource Conservation and Recovery Act of
1976, as amended, and the Toxic Substances Control Act of 1976, federal and
state hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous waste
disposal requirements pending the EPA's evaluation of the need for future
regulation. The EPA has issued its final regulatory determination that
regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the
EPA announced that it will develop national standards regulating disposal of
coal ash under its authority to regulate nonhazardous waste.
TE believes it is in compliance with the current SO(2) and
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 requires
compliance with the NO(x) budgets at the Companies' Pennsylvania facilities by
May 1, 2003 and Ohio submitted a SIP that requires compliance with the NO(x)
budgets at the Companies' Ohio facilities by May 31, 2004.
TE has been named as a "potentially responsible party" (PRP)
at waste disposal sites which may require cleanup under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980. Allegations of
disposal of hazardous substances at historical sites and the liability involved,
are often unsubstantiated and subject to dispute; however, federal law provides
that all PRPs for a particular site be held liable on a joint and several basis.
Therefore, potential environmental liabilities have been recognized on the
Consolidated Balance Sheet as of June 30, 2003, based on estimates of the total
costs of cleanup, TE's proportionate responsibility for such costs and the
financial ability of other nonaffiliated entities to pay. TE has total accrued
liabilities of approximately $0.2 million as of June 30, 2003.
The effects of compliance on TE with regard to environmental
matters could have a material adverse effect on its earnings and competitive
position. These environmental regulations affect its earnings and competitive
position to the extent TE competes with companies that are not subject to such
regulations and therefore do not bear the risk of costs associated with
compliance, or failure to comply, with such regulations. TE believes it is in
material compliance with existing regulations, but is unable to predict how and
when applicable environmental regulations may change and what, if any, the
effects of any such change would be.
Legal Matters
Various lawsuits, claims and proceedings relayed to TE's
normal business operations are pending against TE, the most significant of which
are described above.
SIGNIFICANT ACCOUNTING POLICIES
TE prepares its consolidated financial statements in
accordance with accounting principles that are generally accepted in the United
States. Application of these principles often requires a high degree of
judgment, estimates and assumptions that affect TE's financial results. All of
TE's assets are subject to their own specific risks and uncertainties and are
regularly reviewed for impairment. Assets related to the application of the
policies discussed below are similarly reviewed with their risks and
uncertainties reflecting those specific factors. TE's more significant
accounting policies are described below.
Regulatory Accounting
TE is subject to regulation that sets the prices (rates) it is
permitted to charge its customers based on the costs that the regulatory
agencies determine TE is permitted to recover. At times, regulators permit the
future recovery through rates of costs that would be currently charged to
expense by an unregulated company. This rate-making process results in the
recording of regulatory assets based on anticipated future cash inflows. As a
result of the changing regulatory framework in Ohio, a significant amount of
regulatory assets have been recorded. As of June 30, 2003, TE's regulatory
assets totaled $548.5 million. TE regularly reviews these assets to assess their
ultimate recoverability within the approved regulatory guidelines. Impairment
risk associated with these assets relates to potentially adverse legislative,
judicial or regulatory actions in the future.
90
Revenue Recognition
TE follows the accrual method of accounting for revenues,
recognizing revenue for kilowatt-hours that have been delivered but not yet been
billed through the end of the accounting period. The determination of unbilled
revenues requires management to make various estimates including:
- Net energy generated or purchased for retail load
- Losses of energy over distribution lines
- Allocations to distribution companies within the FirstEnergy
system
- Mix of kilowatt-hour usage by residential, commercial and
industrial customers
- Kilowatt-hour usage of customers receiving electricity from
alternative suppliers
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory
defined pension 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.
Pension and OPEB costs may also be affected by changes to key assumptions,
including anticipated rates of return on plan assets, the discount rates and
health care trend rates used in determining the projected benefit obligations
for pension and OPEB costs.
In accordance with SFAS 87, "Employers' Accounting for
Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other
Than Pensions," changes in pension and OPEB obligations associated with these
factors may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
In selecting an assumed discount rate, FirstEnergy considers
currently available rates of return on high-quality fixed income investments
expected to be available during the period to maturity of the pension and other
postretirement benefit obligations. Due to the significant decline in corporate
bond yields and interest rates in general during 2002, FirstEnergy reduced the
assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001.
FirstEnergy's assumed rate of return on pension plan assets
considers historical market returns and economic forecasts for the types of
investments held by its pension trusts. The market values of FirstEnergy's
pension assets have been affected by sharp declines in the equity markets since
mid-2000. In 2002 and 2001, plan assets earned (11.3)% and (5.5)%, respectively.
FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of
return on plan assets. As of December 31, 2002 the assumed return on plan assets
was reduced to 9.00% based upon FirstEnergy's projection of future returns and
pension trust investment allocation of approximately 60% large cap equities, 10%
small cap equities and 30% bonds.
Based on pension assumptions and pension plan assets as of
December 31, 2002, FirstEnergy will not be required to fund its pension plans in
2003. While OPEB plan assets have also been affected by sharp declines in the
equity market, the impact is not as significant due to the relative size of the
plan assets. However, health care cost trends have significantly increased and
will affect future OPEB costs. The 2003 composite health care trend rate
assumption is approximately 10%-12% gradually decreasing to 5% in later years,
compared to 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
91
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," TE periodically evaluates its long-lived assets
to determine whether conditions exist that would indicate that the carrying
value of an asset may not be fully recoverable. The accounting standard requires
that if the sum of future cash flows (undiscounted) expected to result from an
asset is less than the carrying value of the asset, an asset impairment must be
recognized in the financial statements. If impairment other than of a temporary
nature has occurred, TE recognizes a loss - calculated as the difference between
the carrying value and the estimated fair value of the asset (discounted future
net cash flows).
Goodwill
In a business combination, the excess of the purchase price
over the estimated fair values of the assets acquired and liabilities assumed is
recognized as goodwill. Based on the guidance provided by SFAS 142, TE evaluates
its goodwill for impairment at least annually and would make such an evaluation
more frequently if indicators of impairment should arise. In accordance with the
accounting standard, if the fair value of a reporting unit is less than its
carrying value including goodwill, an impairment for goodwill must be recognized
in the financial statements. If impairment were to occur, TE would recognize a
loss - calculated as the difference between the implied fair value of a
reporting unit's goodwill and the carrying value of the goodwill. TE's annual
review was completed in the third quarter of 2002. The results of that review
indicated no impairment of goodwill. The forecasts used in TE's evaluations of
goodwill reflect operations consistent with its general business assumptions.
Unanticipated changes in those assumptions could have a significant effect on
its future evaluations of goodwill. As of June 30, 2003, TE had approximately
$505 million of goodwill.
RECENTLY ISSUED ACCOUNTING STANDARD NOT YET IMPLEMENTED
FIN 46, "Consolidation of Variable Interest Entities - an
interpretation of ARB 51"
In January 2003, the FASB issued this interpretation of ARB
No. 51, "Consolidated Financial Statements". The new interpretation provides
guidance on consolidation of variable interest entities (VIEs), generally
defined as certain entities in which equity investors do not have the
characteristics of a controlling financial interest or do not have sufficient
equity at risk for the entity to finance its activities without additional
subordinated financial support from other parties. This Interpretation requires
an enterprise to disclose the nature of its involvement with a VIE if the
enterprise has a significant variable interest in the VIE and to consolidate a
VIE if the enterprise is the primary beneficiary. VIEs created after January 31,
2003 are immediately subject to the provisions of FIN 46. VIEs created before
February 1, 2003 are subject to this interpretation's provisions in the first
interim or annual reporting period beginning after June 15, 2003 (TE's third
quarter of 2003). The FASB also identified transitional disclosure provisions
for all financial statements issued after January 31, 2003.
TE currently has transactions which may fall within the scope
of this interpretation and which are reasonably possible of meeting the
definition of a VIE in accordance with FIN 46. TE currently consolidates the
majority of these entities and believes it will continue to consolidate
following the adoption of FIN 46. One of these entities TE is currently
consolidating is the Shippingport Capital Trust, which reacquired a portion of
the off-balance sheet debt issued in connection with the sale and leaseback of
its interest in the Bruce Mansfield Plant. Ownership of the trust includes a
4.85 percent interest by nonaffiliated parties and a 0.34 percent equity
interest by Toledo Edison Capital Corp., a majority owned subsidiary.
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. TE is
currently assessing the new EITF consensus and has not yet determined the impact
on its financial position or results of operations following adoption.
92
PENNSYLVANIA POWER COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------- ----------------------
2003 2002 2003 2002
-------- -------- -------- --------
(IN THOUSANDS)
OPERATING REVENUES......................................... $116,559 $127,737 $244,902 $252,072
-------- -------- -------- --------
OPERATING EXPENSES AND TAXES:
Fuel.................................................... 4,218 6,379 8,931 12,712
Purchased power......................................... 36,954 35,663 81,020 75,626
Nuclear operating costs................................. 35,428 19,473 82,357 41,805
Other operating costs................................... 10,060 9,717 26,610 19,669
-------- -------- -------- --------
Total operation and maintenance expenses............ 86,660 71,232 198,918 149,812
Provision for depreciation and amortization............. 13,480 14,208 26,745 28,412
General taxes........................................... 5,879 6,006 12,058 12,010
Income taxes............................................ 4,268 14,835 2,789 25,251
-------- -------- -------- --------
Total operating expenses and taxes.................. 110,287 106,281 240,510 215,485
-------- -------- -------- --------
OPERATING INCOME........................................... 6,272 21,456 4,392 36,587
OTHER INCOME............................................... 563 476 1,124 1,141
-------- -------- -------- --------
INCOME BEFORE NET INTEREST CHARGES......................... 6,835 21,932 5,516 37,728
-------- -------- -------- --------
NET INTEREST CHARGES:
Interest expense........................................ 4,112 4,268 8,176 8,366
Allowance for borrowed funds used during construction... (699) (345) (1,328) (597)
-------- -------- -------- --------
Net interest charges................................ 3,413 3,923 6,848 7,769
-------- -------- -------- --------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF ACCOUNTING
CHANGE.................................................. 3,422 18,009 (1,332) 29,959
Cumulative effect of accounting change (net of income taxes
of $7,532,000) (Note 5)................................. -- -- 10,618 --
-------- -------- -------- --------
NET INCOME................................................. 3,422 18,009 9,286 29,959
PREFERRED STOCK DIVIDEND REQUIREMENTS...................... 911 926 1,823 1,852
-------- -------- -------- --------
EARNINGS ON COMMON STOCK................................... $ 2,511 $ 17,083 $ 7,463 $ 28,107
======== ======== ======== ========
The preceding Notes to Financial Statements as they relate to Pennsylvania Power
Company are an integral part of these statements.
93
PENNSYLVANIA POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
JUNE 30, DECEMBER 31,
2003 2002
-------- --------
(IN THOUSANDS)
ASSETS
UTILITY PLANT:
In service................................................................ $791,429 $680,729
Less-Accumulated provision for depreciation............................... 315,835 316,424
-------- --------
475,594 364,305
-------- --------
Construction work in progress-
Electric plant.......................................................... 55,785 44,696
Nuclear fuel............................................................ 1,402 8,812
-------- --------
57,187 53,508
-------- --------
532,781 417,813
-------- --------
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts...................................... 126,425 119,401
Long-term notes receivable from associated companies...................... 38,724 38,921
Other..................................................................... 2,459 2,569
-------- --------
167,608 160,891
-------- --------
CURRENT ASSETS:
Cash and cash equivalents................................................. 41 1,222
Receivables-
Customers (less accumulated provisions of $775,000 and $702,000,
respectively, for uncollectible accounts)............................. 42,672 44,341
Associated companies.................................................... 22,233 42,652
Other................................................................... 706 5,262
Notes receivable from associated companies................................ 10,901 35,317
Materials and supplies, at average cost................................... 30,829 30,309
Prepayments............................................................... 17,824 5,346
-------- --------
125,206 164,449
-------- --------
DEFERRED CHARGES:
Regulatory assets......................................................... 60,306 156,903
Other..................................................................... 7,502 7,692
-------- --------
67,808 164,595
-------- --------
$893,403 $907,748
======== ========
94
PENNSYLVANIA POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
JUNE 30, DECEMBER 31,
2003 2002
-------- --------
(IN THOUSANDS)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity-
Common stock, $30 par value, authorized 6,500,000 shares -
6,290,000 shares outstanding.......................................... $188,700 $188,700
Other paid-in capital................................................... (310) (310)
Accumulated other comprehensive loss.................................... (22,259) (9,932)
Retained earnings....................................................... 32,379 50,916
-------- --------
Total common stockholder's equity................................... 198,510 229,374
Preferred stock-
Not subject to mandatory redemption..................................... 39,105 39,105
Subject to mandatory redemption......................................... 13,500 13,500
Long-term debt............................................................ 171,030 185,499
-------- --------
422,145 467,478
-------- --------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock...................... 80,524 66,556
Accounts payable-
Associated companies.................................................... 50,111 52,653
Other................................................................... 357 5,730
Accrued taxes............................................................. 21,308 12,507
Accrued interest.......................................................... 5,582 5,558
Other..................................................................... 8,607 10,479
-------- --------
166,489 153,483
-------- --------
DEFERRED CREDITS:
Accumulated deferred income taxes......................................... 102,722 117,385
Accumulated deferred investment tax credits............................... 3,663 3,810
Asset retirement obligation............................................... 125,387 --
Nuclear plant decommissioning costs....................................... -- 119,863
Other..................................................................... 72,997 45,729
-------- --------
304,769 286,787
-------- --------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)...........................
-------- --------
$893,403 $907,748
======== ========
The preceding Notes to Financial Statements as they relate to Pennsylvania Power
Company are an integral part of these balance sheets.
95
PENNSYLVANIA POWER COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------- ----------------------
2003 2002 2003 2002
-------- -------- -------- --------
(IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income..................................................... $ 3,422 $ 18,009 $ 9,286 $ 29,959
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization............. 13,480 14,208 26,745 28,412
Nuclear fuel and lease amortization..................... 3,206 4,852 6,789 9,568
Deferred income taxes, net.............................. (2,368) (1,950) 3,754 (3,875)
Investment tax credits, net............................. (608) (655) (1,228) (1,320)
Cumulative effect of accounting change (Note 5)......... -- -- (18,150) --
Receivables............................................. 4,278 (3,338) 21,540 (4,020)
Materials and supplies.................................. (89) (1,711) (520) (2,283)
Accounts payable........................................ (30,005) (3,147) (2,161) (18,906)
Accrued taxes........................................... 4,530 12,439 8,801 23,089
Accrued interest........................................ 2,033 1,707 24 69
Prepayments and other................................... 3,810 4,687 (12,478) (8,783)
Other................................................... 7,576 826 7,196 552
-------- -------- -------- --------
Net cash provided from operating activities........... 9,265 45,927 49,598 52,462
-------- -------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and Repayments-
Long-term debt............................................ (601) (623) (617) (41,290)
Dividend Payments-
Common stock.............................................. (13,000) -- (26,000) (7,800)
Preferred stock........................................... (911) (926) (1,823) (1,852)
-------- -------- -------- --------
Net cash used for financing activities................ (14,512) (1,549) (28,440) (50,942)
-------- -------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions.......................................... (9,680) (8,343) (40,734) (16,426)
Capital trust investments................................... (7,155) (5,274) (7,024) (4,675)
Notes receivable from associated companies, net............. 19,692 (36,357) 24,613 16,706
Other....................................................... 604 5,185 806 3,398
-------- -------- -------- --------
Net cash provided from (used for) investing activities 3,461 (44,789) (22,339) (997)
-------- -------- -------- --------
Net increase (decrease) in cash and cash equivalents........... (1,786) (411) (1,181) 523
Cash and cash equivalents at beginning of period............... 1,827 1,001 1,222 67
-------- -------- -------- --------
Cash and cash equivalents at end of period..................... $ 41 $ 590 $ 41 $ 590
======== ======== ======== ========
The preceding Notes to Financial Statements as they relate to Pennsylvania Power
Company are an integral part of these statements.
96
REPORT OF INDEPENDENT AUDITORS
To the Stockholders and Board
of Directors of Pennsylvania
Power Company:
We have reviewed the accompanying balance sheet of Pennsylvania Power Company as
of June 30, 2003, and the related 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 interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.
We previously audited in accordance with auditing standards generally accepted
in the United States of America, the balance sheet and the statement of
capitalization as of December 31, 2002, and the related statements of income,
common stockholder's equity, preferred stock, cash flows and taxes for the year
then ended (not presented herein), and in our report dated February 28, 2003 we
expressed an unqualified opinion on those financial statements. In our opinion,
the information set forth in the accompanying balance sheet as of December 31,
2002, is fairly stated in all material respects in relation to the balance sheet
from which it has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
August 18, 2003
97
PENNSYLVANIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
Penn is a wholly owned, electric utility subsidiary of OE.
Penn conducts business in western Pennsylvania, providing regulated electric
distribution services. Penn also provides generation services to those customers
electing to retain it as their power supplier. Penn provides power directly to
wholesale customers under previously negotiated contracts. Penn has unbundled
the price of electricity into its component elements - including generation,
transmission, distribution and transition charges. Its power supply requirements
are provided by FES - an affiliated company.
RESULTS OF OPERATIONS
Earnings on common stock in the second quarter of 2003
decreased to $2.5 million from $17.1 million in the second quarter of 2002. In
the first six months of 2003, earnings on common stock decreased to $7.5 million
from $28.1 million in the first six months of 2002. Earnings in the first half
of 2003 included an after-tax credit of $10.6 million from the cumulative effect
of an accounting change due to the adoption of SFAS 143, "Accounting for Asset
Retirement Obligations." The loss before the cumulative effect was $1.3 million
in the first half of 2003 compared to income of $30.0 million for the same
period of 2002. The lower results in both periods of 2003 reflected lower
operating revenues and higher operating expenses - primarily nuclear operating
costs, purchased power costs and employee benefit costs. These increases were
partially offset by lower fuel costs and reduced financing costs, compared with
the second quarter and first six months of 2002.
Operating revenues decreased by $11.2 million, or 8.8% in the
second quarter and $7.2 million, or 2.8% in the first six months of 2003
compared with the same periods in 2002. The lower revenues resulted from
decreased retail sales revenues and lower sales to FES. Kilowatt-hour sales to
retail customers were lower by 13.8% in the second quarter and 2.8% in the first
half of 2003 from the same periods of 2002, which decreased generation sales
revenue by $4.5 million and $2.6 million, respectively. The second quarter 2003
decreases were caused by cooler-than-normal temperatures which reduced air
conditioning demands in all retail sectors. These decreases were moderated in
the first six months by colder temperatures in the first quarter of 2003 that
increased heating demands.
Distribution deliveries decreased 13.8% in the second quarter
of 2003 and 3.2% in the first half of 2003 compared with the corresponding
periods of 2002, with decreases in all customer sectors (residential, commercial
and industrial). The weather related effects discussed above resulted in the
lower distribution deliveries and decreased revenues from electricity throughput
by approximately $5.2 million in the second quarter and $4.3 million in the
first six months of 2003 from the respective quarter and first six months of the
prior year.
Wholesale revenues decreased by $1.5 million in the second
quarter and increased $0.5 million in the first half of 2003 compared to the
corresponding periods of 2002 due to lower sales to FES. The lower sales
resulted from reductions in available nuclear generation. Lower revenues
resulted from reductions in nuclear generation (down 31.8% for the second
quarter and 27.0% in the first half of 2003) which decreased sales to FES in
both periods of 2003, but was more than offset in the six-month period by
increased sales to non-associated companies.
Changes in electric generation 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:
Retail............................. (13.6)% (2.8)%
Wholesale.......................... (29.2)% (25.1)%
-----------------------------------------------------------------
TOTAL ELECTRIC GENERATION SALES....... (23.1)% (16.3)%
=================================================================
Distribution Deliveries:
Residential........................ (14.3)% (1.1)%
Commercial......................... (8.2)% (0.6)%
Industrial......................... (17.5)% (7.3)%
-----------------------------------------------------------------
TOTAL DISTRIBUTION DELIVERIES......... (13.8)% (3.2)%
=================================================================
98
Operating Expenses and Taxes
Total operating expenses and taxes increased by $4.0 million
in the second quarter and $25.0 million in the first half of 2003 from the
second quarter and first half of 2002. The following table presents changes from
the prior year by expense category.
OPERATING EXPENSES AND TAXES - CHANGES THREE MONTHS SIX MONTHS
----------------------------------------------------------------------------
(IN MILLIONS)
INCREASE (DECREASE)
Fuel............................................. $ (2.2) $ (3.8)
Purchased power costs............................ 1.3 5.4
Nuclear operating costs.......................... 16.0 40.6
Other operating costs............................ 0.3 6.9
---------------------------------------------------------------------------
TOTAL OPERATION AND MAINTENANCE EXPENSES...... 15.4 49.1
Provision for depreciation and amortization...... (0.7) (1.7)
General taxes.................................... (0.1) 0.1
Income taxes..................................... (10.6) (22.5)
---------------------------------------------------------------------------
TOTAL INCREASE IN OPERATING EXPENSES AND TAXES $ 4.0 $ 25.0
===========================================================================
Lower fuel costs in the second quarter and first half of 2003,
compared with the same periods of 2002, resulted from reduced nuclear
generation. The increased purchased power costs in both periods of 2003
reflected higher units costs partially offset by decreased kilowatt-hour
purchases due to lower demand by generation customers. Higher nuclear operating
costs occurred in large part due to the refueling outages at Beaver Valley Unit
1 (65.00% ownership) in the first quarter of 2003 and at Perry (5.24% ownership)
in the second quarter of 2003 compared with refueling outage costs at Beaver
Valley Unit 2 (13.74% ownership) in the first quarter of 2002. The increase in
other operating costs reflects higher employee benefit costs and increased
uncollectible customer accounts.
Charges for depreciation and amortization decreased by $0.7
million in the second quarter and $1.7 million in the first half of 2003
compared to the second quarter and first half of 2002 primarily from lower
charges resulting from the implementation of SFAS 143 ($0.3 million for the
second quarter and $0.9 million for the first half of 2003) and revised service
life assumptions for generating plants ($0.3 million for the second quarter and
$0.6 million for the first half of 2003).
Net Interest Charges
Net interest charges continued to trend lower, decreasing by
approximately $0.5 million in the second quarter and $0.9 million in the first
six months of 2003 from the same periods last year, reflecting redemptions and
refinancings since the beginning of the second quarter of 2002.
Cumulative Effect of Accounting Change
Upon adoption of SFAS 143 in the first quarter of 2003, Penn
recorded an after-tax credit to net income of $10.6 million. Penn identified
applicable legal obligations as defined under the new standard for nuclear power
plant decommissioning and reclamation of a sludge disposal pond at the Bruce
Mansfield Plant. As a result of adopting SFAS 143 in January 2003, asset
retirement costs of $78 million were recorded as part of the carrying amount of
the related long-lived asset, offset by accumulated depreciation of $9 million.
The asset retirement obligation (ARO) liability at the date of adoption was $121
million, including accumulated accretion for the period from the date the
liability was incurred to the date of adoption. As of December 31, 2002, Penn
had recorded decommissioning liabilities of $120 million. Penn expects
substantially all of its nuclear decommissioning costs to be recoverable in
rates over time. Therefore, it recognized a regulatory liability of $69 million
upon adoption of SFAS 143 for the transition amounts related to establishing the
ARO for nuclear decommissioning. The remaining cumulative effect adjustment for
unrecognized depreciation, offset by the reduction in the liabilities and
ceasing the accounting practice of depreciating non-regulated generation assets
using a cost of removal component, was an $18.2 million increase to income, or
$10.6 million net of income taxes (see Note 5).
CAPITAL RESOURCES AND LIQUIDITY
Penn'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 its net debt
and preferred stock outstanding. Available borrowing capacity under short-term
credit facilities will be used to manage working capital requirements. Over the
next three years, Penn expects to meet its contractual obligations with cash
from operations. Thereafter, Penn expects to use a combination of cash from
operations and funds from the capital markets.
99
Changes in Cash Position
As of June 30, 2003, Penn had $41,000 of cash and cash
equivalents, compared with $1.2 million as of December 31, 2002. The major
sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Cash flows provided from operating activities during the
second quarter and first six months of 2003, compared with the corresponding
periods in 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)........... $ 17 $ 34 $ 27 $ 62
Working capital and other... (8) 12 23 (10)
----------------------------------------------------------------------
Total....................... $ 9 $ 46 $ 50 $ 52
======================================================================
(1) Includes net income, depreciation and amortization, deferred income taxes,
investment tax credits and major noncash charges.
Net cash from operating activities decreased to $9 million in
the second quarter and $50 million in the first half of 2003 compared with $46
million and $52 million, respectively, in the same period of 2002. The decrease
in working capital and other primarily was due to a decrease of $27 million in
accounts payable from associated companies in the second quarter of 2003
compared with corresponding amounts in the second quarter of 2002. A decrease in
accounts receivable also contributed $8 million to the increase in cash provided
from working capital. The decrease in cash earnings in the second quarter of
2003 compared with the second quarter of 2002 primarily resulted from higher
nuclear operating costs.
Cash Flows From Financing Activities
In the second quarter of 2003, net cash used for financing
activities increased to $15 million from $2 million in the same period last
year. The increase resulted from dividends to OE.
Penn had approximately $10.9 million of cash and temporary
investments, primarily composed of notes receivable from associated companies
and no short-term indebtedness as of June 30, 2003. Penn may borrow from its
affiliates on a short-term basis. Penn had the capability to issue $193 million
of additional first mortgage bonds on the basis of property additions and
retired bonds. Based upon applicable earnings coverage tests, Penn could not
issue preferred stock as of June 30, 2003.
Cash Flows From Investing Activities
Net cash provided from investing activities totaled $3 million
in the second quarter and net cash used of $22 million in the first six months
of 2003, compared to a net cash flows used for investing activities of $45
million and $1 million for the same periods of 2002, respectively. The $48
million change in funds for the second quarter resulted from higher payments
received on notes from associated companies.
During the remaining half of 2003, capital requirements for
property additions and capital leases are expected to be about $36 million,
including $4 million for nuclear fuel. Penn has additional requirements of
approximately $41 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, 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
100
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."
Pension and Other Postretirement Benefits
As a result of GPU Service Inc. merging with FirstEnergy
Service Company 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, Penn's accrued pension and OPEB
costs as of June 30, 2003 increased by $15.9 million and $9.8 million,
respectively.
EQUITY PRICE RISK
Included in Penn's nuclear decommissioning trust investments
are marketable equity securities carried at their market value of approximately
$43 million and $38 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 $4 million reduction in fair value as of June 30, 2003.
OUTLOOK
Beginning in 1999, Penn's customers were able to select
alternative energy suppliers and customer rates have been restructured into
separate components to support customer choice. Currently, a number of customers
previously electing to be served by alternative energy providers returned to
Penn for their energy needs. Penn has a continuing responsibility to provide
power to those customers not choosing to receive power from an alternative
energy supplier subject to certain limits. Adopting new approaches to regulation
and experiencing new forms of competition have created new uncertainties. Penn
continues to deliver power to residential homes and businesses through its
existing distribution system, which remains regulated.
Regulatory Matters
Regulatory assets are costs which have been authorized by the
PPUC and the Federal Energy Regulatory Commission, for recovery from customers
in future periods and, without such authorization, would have been charged to
income when incurred. Regulatory assets declined $96.6 million to $60.3 million
on June 30, 2003 from the balance as of December 31, 2002, with $69.2 million of
the decrease related to the cumulative entry adopting SFAS 143. All of Penn's
regulatory assets are expected to continue to be recovered under the provisions
of its regulatory plan.
As part of Penn's transition plan it is obligated to supply
electricity to customers who do not choose an alternative supplier. Penn's
competitive retail sales affiliate, FES, acts as an alternate supplier for a
portion of the load in Penn's franchise area.
Environmental Matters
Penn believes it is in compliance with the current sulfur
dioxide (SO(2)) and nitrogen oxide (NO(x)) reduction requirements under the
Clean Air Act Amendments of 1990. In 1998, the Environmental Protection Agency
(EPA) finalized regulations requiring additional NO(x) reductions in the future
from Penn's Ohio and Pennsylvania facilities. Various regulatory and judicial
actions have since sought to further define NO(x) reduction requirements (see
Note 2 - Environmental Matters). Penn continues to evaluate its compliance
plans and other compliance options.
Violations of federally approved SO(2) regulations can result
in shutdown of the generating unit involved and/or civil or criminal penalties
of up to $31,500 for each day a unit is in violation. The EPA has an interim
enforcement policy for SO(2) regulations in Ohio that allows for compliance
based on a 30-day averaging period. Penn cannot predict what action the EPA may
take in the future with respect to the interim enforcement policy.
101
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 (CAA). The
civil complaint against OE and Penn requests installation of "best available
control technology" as well as 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 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.
Penn believes it is in compliance with the current SO(2) and
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 its 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
Penn's Pennsylvania facilities by May 1, 2003.
The effects of compliance on Penn with regard to environmental
matters could have a material adverse effect on its earnings and competitive
position. These environmental regulations affect Penn'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. Penn believes it is in
material compliance with existing regulations, but are unable to predict how and
when applicable environmental regulations may change and what, if any, the
effects of any such change would be.
Legal Matters
Various lawsuits, claims and proceedings relayed to Penn's
normal business operations are pending against Penn, the most significant of
which are described above.
SIGNIFICANT ACCOUNTING POLICIES
Penn 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 Penn's financial results. All of
Penn's assets are subject to their own specific risks and uncertainties and are
regularly reviewed for impairment. Penn's more significant accounting policies
are described below.
Regulatory Accounting
Penn is subject to regulation that sets the prices (rates) it
is permitted to charge its customers based on the costs that the regulatory
agencies determine Penn is permitted to recover. At times, regulators permit the
future recovery
102
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 Pennsylvania, a significant amount of
regulatory assets have been recorded. As of June 30, 2003, Penn's regulatory
assets totaled $60 million. Penn regularly reviews these assets to assess their
ultimate recoverability within the approved regulatory guidelines. Impairment
risk associated with these assets relates to potentially adverse legislative,
judicial or regulatory actions in the future.
Revenue Recognition
Penn follows the accrual method of accounting for revenues,
recognizing revenue for kilowatt-hours that have been delivered but not yet
billed through the end of the accounting period. The determination of unbilled
revenues requires management to make various estimates including:
- Net energy generated or purchased for retail load
- Losses of energy over distribution lines
- Allocations to distribution companies within the FirstEnergy
system o Mix of kilowatt-hour usage by residential, commercial
and industrial customers o Kilowatt-hour usage of customers
receiving electricity from alternative suppliers
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory
defined pension benefits and OPEB are dependent upon numerous factors resulting
from actual plan experience and certain assumptions.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions FirstEnergy makes to the plans, and earnings on plan assets.
Pension and OPEB costs may also be affected by changes to key assumptions,
including anticipated rates of return on plan assets, the discount rates and
health care trend rates used in determining the projected benefit obligations
for pension and OPEB costs.
In accordance with SFAS 87, "Employers' Accounting for
Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other
Than Pensions," changes in pension and OPEB obligations associated with these
factors may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
In selecting an assumed discount rate, FirstEnergy considers
currently available rates of return on high-quality fixed income investments
expected to be available during the period to maturity of the pension and other
postretirement benefit obligations. Due to the significant decline in corporate
bond yields and interest rates in general during 2002, FirstEnergy reduced the
assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001.
FirstEnergy's assumed rate of return on pension plan assets
considers historical market returns and economic forecasts for the types of
investments held by its pension trusts. The market values of FirstEnergy's
pension assets have been affected by sharp declines in the equity markets since
mid-2000. In 2002 and 2001, plan assets earned (11.3)% and (5.5)%, respectively.
FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of
return on plan assets. As of December 31, 2002 the assumed return on plan assets
was reduced to 9.00% based upon FirstEnergy's projection of future returns and
pension trust investment allocation of approximately 60% large cap equities, 10%
small cap equities and 30% bonds.
Based on pension assumptions and pension plan assets as of
December 31, 2002, FirstEnergy will not be required to fund its pension plans in
2003. While OPEB plan assets have also been affected by sharp declines in the
equity market, the impact is not as significant due to the relative size of the
plan assets. However, health care cost trends have significantly increased and
will affect future OPEB costs. The 2003 composite health care trend rate
assumption is approximately 10%-12% gradually decreasing to 5% in later years,
compared to 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.
103
Long-Lived Assets
In accordance with SFAS 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," Penn 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, Penn recognizes a loss - calculated as the
difference between the carrying value and the estimated fair value of the asset
(discounted future net cash flows).
RECENTLY ISSUED ACCOUNTING STANDARD NOT YET IMPLEMENTED
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 (Penn's third quarter of 2003) for all other financial
instruments.
Penn 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, Penn classified as debt its preferred stock subject to
mandatory redemptions with a carrying value of approximately $13.5 million as of
June 30, 2003. Therefore, the application of SFAS 150 will require the
reclassification of such preferred dividends to net interest charges.
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. Penn is
currently assessing the new EITF consensus and has not yet determined the impact
on its financial position or results of operations following adoption.
104
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
----------------------- ------------------------
2003 2002 2003 2002
--------- --------- ----------- ---------
(IN THOUSANDS)
OPERATING REVENUES........................................ $ 542,771 $ 501,232 $ 1,199,723 $ 951,945
--------- --------- ----------- ---------
OPERATING EXPENSES AND TAXES:
Fuel................................................... 1,432 1,298 2,766 2,474
Purchased power........................................ 444,978 249,466 844,044 460,451
Other operating costs.................................. 82,302 74,100 152,025 142,617
--------- --------- ----------- ---------
Total operation and maintenance expenses........... 528,712 324,864 998,835 605,542
Provision for depreciation and amortization............ 52,983 55,371 113,150 119,274
General taxes.......................................... 12,964 4,294 28,776 21,297
Income taxes........................................... (28,390) 38,543 7,252 66,404
--------- --------- ----------- ---------
Total operating expenses and taxes................. 566,269 423,072 1,148,013 812,517
--------- --------- ----------- ---------
OPERATING INCOME (LOSS)................................... (23,498) 78,160 51,710 139,428
OTHER INCOME.............................................. 2,264 2,196 3,440 5,022
--------- --------- ----------- ---------
INCOME (LOSS) BEFORE NET INTEREST CHARGES................. (21,234) 80,356 55,150 144,450
--------- --------- ----------- ---------
NET INTEREST CHARGES:
Interest on long-term debt............................. 22,667 22,768 45,979 45,485
Allowance for borrowed funds used during construction.. (111) (97) (234) (579)
Deferred interest...................................... (2,924) (1,834) (6,126) (1,385)
Other interest expense (credit)........................ 104 (533) (55) (1,777)
Subsidiary's preferred stock dividend requirements..... 2,674 2,672 5,348 5,347
--------- --------- ----------- ---------
Net interest charges............................... 22,410 22,976 44,912 47,091
--------- --------- ----------- ---------
NET INCOME (LOSS)......................................... (43,644) 57,380 10,238 97,359
PREFERRED STOCK DIVIDEND REQUIREMENTS..................... (488) 431 (363) 1,184
--------- --------- ----------- ---------
EARNINGS (LOSS) ATTRIBUTABLE TO COMMON STOCK.............. $ (43,156) $ 56,949 $ 10,601 $ 96,175
========= ========= =========== =========
The preceding Notes to Financial Statements as they relate to Jersey Central
Power & Light Company are an integral part of these statements.
105
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
JUNE 30, DECEMBER 31,
2003 2002
----------- ------------
(IN THOUSANDS)
ASSETS
UTILITY PLANT:
In service................................................................ $3,595,739 $3,478,803
Less--Accumulated provision for depreciation.............................. 1,481,357 1,343,846
---------- ----------
2,114,382 2,134,957
Construction work in progress - electric plant............................ 32,079 20,687
---------- ----------
2,146,461 2,155,644
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts...................................... 116,249 106,820
Nuclear fuel disposal trust............................................... 154,748 149,738
Long-term notes receivable from associated companies...................... 20,333 20,333
Other..................................................................... 22,173 18,202
---------- ----------
313,503 295,093
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents................................................. 6,027 4,823
Receivables-
Customers (less accumulated provisions of $4,215,680 and $4,509,000
respectively, for uncollectible accounts).............................. 243,740 247,624
Associated companies.................................................... 123,039 318
Other .................................................................. 19,835 20,134
Notes receivable from associated companies................................ -- 77,358
Materials and supplies, at average cost................................... 2,114 1,341
Prepayments and other..................................................... 108,165 37,719
---------- ----------
502,920 389,317
---------- ----------
DEFERRED CHARGES:
Regulatory assets......................................................... 3,004,421 3,199,012
Goodwill.................................................................. 2,000,875 2,000,875
Other..................................................................... 9,494 12,814
---------- ----------
5,014,790 5,212,701
---------- ----------
$7,977,674 $8,052,755
========== ==========
106
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
JUNE 30, DECEMBER 31,
2003 2002
---------- -----------
(IN THOUSANDS)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity-
Common stock, $10 par value, authorized 16,000,000 shares -
15,371,270 shares outstanding......................................... $ 153,713 $ 153,713
Other paid-in capital................................................... 3,029,218 3,029,218
Accumulated other comprehensive loss.................................... (64,858) (865)
Retained earnings (accumulated deficit)................................. (25,396) 92,003
---------- ----------
Total common stockholder's equity................................... 3,092,677 3,274,069
Preferred stock not subject to mandatory redemption....................... 12,649 12,649
Company-obligated mandatorily redeemable preferred securities............. -- 125,244
Long-term debt............................................................ 1,270,602 1,210,446
---------- ----------
4,375,928 4,622,408
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt.......................................... 93,857 173,815
Accounts payable-
Associated companies.................................................... 187,882 170,803
Other................................................................... 126,634 106,504
Notes payable to associated companies..................................... 196,126 --
Accrued taxes............................................................. 18,653 13,844
Accrued interest.......................................................... 18,733 27,161
Other..................................................................... 106,024 112,408
---------- ----------
747,909 604,535
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes......................................... 631,079 691,721
Accumulated deferred investment tax credits............................... 8,789 9,939
Power purchase contract loss liability.................................... 1,651,294 1,710,968
Nuclear fuel disposal costs............................................... 167,159 166,191
Asset retirement obligation............................................... 106,856 --
Retirement benefits....................................................... 169,753 --
Nuclear decommissioning costs............................................. 4,814 135,355
Other..................................................................... 114,093 111,638
---------- ----------
2,853,837 2,825,812
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (NOTE 2)...........................
---------- ----------
$7,977,674 $8,052,755
========== ==========
The preceding Notes to Financial Statements as they relate to Jersey Central
Power & Light Company are an integral part of these balance sheets.
107
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------- -----------------------
2003 2002 2003 2002
----------- ---------- --------- ----------
(IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)......................................... $ (43,644) $ 57,380 $ 10,238 $ 97,359
Adjustments to reconcile net income (loss) to net
cash from operating activities-
Provision for depreciation and amortization........ 52,983 55,371 113,150 119,274
Other amortization................................. (102) 940 83 1,451
Deferred costs, net................................ (49,251) (43,340) (84,333) (108,948)
Deferred income taxes, net......................... (31,981) 27,862 (17,004) 36,540
Investment tax credits, net........................ (575) (900) (1,150) (1,799)
Disallowed regulatory assets (see Note 4).......... 152,500 -- 152,500 --
Receivables........................................ (87,390) (34,185) (67,602) 9,937
Materials and supplies............................. (546) 39 (772) 45
Accounts payable................................... 102,517 37,910 12,339 32,944
Prepayments and other.............................. (86,491) (76,554) (70,447) (70,650)
Accrued taxes...................................... (40,255) (63,030) 4,809 (28,460)
Accrued interest................................... (14,200) (5,863) (8,429) (1,510)
Other.............................................. 9,730 1,164 15,764 3,001
----------- ---------- --------- ----------
Net cash provided from (used for) operating
activities...................................... (36,705) (43,206) 59,146 89,184
----------- ---------- --------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt....................................... 158,789 318,106 158,789 318,106
Short-term borrowings, net from associated
companies.......................................... 196,126 -- 196,126 --
Redemptions and Repayments-
Preferred stock...................................... (125,244) (5,000) (125,244) (5,000)
Long-term debt....................................... (163,725) -- (173,815) (50,000)
Short-term borrowings, net........................... -- -- -- (18,149)
Dividend Payments-
Common stock......................................... (39,000) (66,000) (128,000) (66,000)
Preferred stock...................................... 125 (991) -- (1,744)
----------- ---------- --------- ----------
Net cash provided from (used for) financing
activities...................................... 27,071 246,115 (72,144) 177,213
----------- ---------- --------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions..................................... (30,528) (20,932) (54,851) (46,834)
Decommissioning trust investments...................... (1,189) (608) (1,189) (709)
Loan repayments from associated companies.............. 52,608 -- 77,358 --
Other.................................................. (7,066) (1,690) (7,116) (2,982)
----------- ---------- --------- ----------
Net cash provided from (used for) investing
activities...................................... 13,825 (23,230) 14,202 (50,525)
----------- ---------- --------- ----------
Net increase in cash and cash equivalents................. 4,191 179,679 1,204 215,872
Cash and cash equivalents at beginning of period.......... 1,836 67,617 4,823 31,424
----------- ---------- --------- ----------
Cash and cash equivalents at end of period................ $ 6,027 $ 247,296 $ 6,027 $ 247,296
=========== ========== ========= ==========
The preceding Notes to Financial Statements as they relate to Jersey Power &
Light Company are an integral part of these statements.
108
REPORT OF INDEPENDENT AUDITORS
To the Stockholders and Board
of Directors of Jersey Central
Power & Light Company:
We have reviewed the accompanying consolidated balance sheet of Jersey Central
Power & Light Company 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.
We previously audited in accordance with auditing standards generally accepted
in the United States of America, the consolidated balance sheet and the
consolidated statement of capitalization as of December 31, 2002, and the
related consolidated statements of income, common stockholder's equity,
preferred stock, cash flows and taxes for the year then ended (not presented
herein), and in our report dated February 28, 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
109
JERSEY CENTRAL POWER & LIGHT COMPANY
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
JCP&L provides regulated transmission and distribution
services in northern, western and east central New Jersey. New Jersey customers
are able to choose their electricity suppliers as a result of legislation which
restructured the electric utility industry. JCP&L's regulatory plan required
unbundling the price for electricity into its component elements - including
generation, transmission, distribution and transition charges. Also under the
regulatory plan, JCP&L continues to deliver power to homes and businesses
through its existing distribution system and is required to maintain the
"provider of last resort" (PLR) obligation known as Basic Generation Services
(BGS) for customers who elect to retain JCP&L as their power supplier.
RESULTS OF OPERATIONS
In the second quarter of 2003, JCP&L incurred a loss
attributable to common stock of $43.2 million as compared to earnings on common
stock of $56.9 million in the second quarter of 2002, as a result of non-cash
charges aggregating $158.5 million ($94 million after tax) due to a rate case
decision disallowing such costs from recovery (see Regulatory Matters).
Excluding the impact of those non-cash charges, earnings on common stock were
$50.7 million. Earnings on common stock during the first six months of 2003 were
$10.6 million as compared to $96.2 million for the same period of 2002. Earnings
before the non-cash charges related to the rate case decision were $104.4
million for the first six months of 2003.
Operating revenues increased $41.5 million or 8.3% in the
second quarter and $247.8 million or 26.0% in the first six months of 2003,
respectively, compared with the same periods in 2002. The higher revenues
resulted from higher wholesale revenues that increased by $39.7 million and
$178.9 million, respectively, over the second quarter and first six months of
2002. JCP&L's BGS obligation was transferred to external parties through a
February 2002 auction process authorized by the New Jersey Board of Public
Utilities (NJBPU). The auction removed JCP&L's BGS obligation for the period
from August 1, 2002 through July 31, 2003, and as a result, it has been selling
all of its self-supplied energy (from non-utility generation power contracts and
owned generation) into the wholesale market. The NJBPU subsequently approved the
February 2003 BGS auction results for the period beginning August 1, 2003.
Distribution deliveries decreased by 2.0% in the second
quarter of 2003 from the corresponding quarter of 2002, which was caused by
cooler-than-normal temperatures in the second quarter 2003. The impact of the
reduced volume was more than offset by higher unit prices, which increased
electricity throughput revenues by $3.4 million. Weather also contributed to the
$40.7 million (8.1%) revenue increase from higher distribution deliveries to
retail customers in the first half of 2003 from the same period last year.
Colder temperatures in the first quarter of 2003 resulted, in large part, in
higher residential and commercial demand, which was partially offset by a
decrease in industrial demand. Changes in distribution deliveries in the second
quarter and first half of 2003 compared with the same periods of 2002 are
summarized in the following table:
CHANGES IN KILOWATT-HOUR DELIVERIES THREE MONTHS SIX MONTHS
--------------------------------------------------------------------------
INCREASE (DECREASE)
Residential.................... (4.9)% 6.6%
Commercial..................... 3.0% 10.2%
Industrial..................... (7.1)% (5.0)%
-----------------------------------------------------------------------
TOTAL DISTRIBUTION DELIVERIES.... (2.0)% 6.0%
=======================================================================
Operating Expenses and Taxes
Total operating expenses and taxes increased by $143.2 million
in the second quarter and $335.5 million in the first six months of 2003
compared to the same periods of 2002. These increases include the non-cash
charges in the second quarter of 2003 for amounts disallowed in the JCP&L rate
case decision (see Regulatory Matters), consisting of $152.5 million of
deferred purchased power costs, $3.5 million relating to depreciation and
amortization and $2.5 million included in other operating costs. The following
table presents changes from the prior year by expense category.
110
OPERATING EXPENSES AND TAXES - CHANGES THREE MONTHS SIX MONTHS
---------------------------------------------------------------------------------
(IN MILLIONS)
INCREASE (DECREASE)
Fuel............................................. $ 0.1 $ 0.3
Purchased power costs............................ 195.5 383.6
Other operating costs............................ 8.2 9.4
-------------------------------------------------------------------------------
TOTAL OPERATION AND MAINTENANCE EXPENSES....... 203.8 393.3
Provision for depreciation and amortization...... (2.4) (6.1)
General taxes.................................... 8.7 7.5
Income taxes..................................... (66.9) (59.2)
-------------------------------------------------------------------------------
NET INCREASE IN OPERATING EXPENSES AND TAXES... $143.2 $335.5
===============================================================================
Excluding the disallowed deferred energy costs of $152.5
million, the higher purchased power costs of $43.0 million in the second quarter
and $231.1 million in the first half of 2003, compared to the corresponding
periods of 2002, were due primarily to increased kilowatt-hour purchases through
two-party agreements and changes in the deferred energy and capacity costs.
Excluding the disallowed costs discussed above, the decreases in depreciation
and amortization charges of $5.9 million in the second quarter and $9.6 million
in the first six months of 2003, compared to the corresponding 2002 periods were
due to the cessation of amortization of regulatory assets related to the
previously divested Oyster Creek Nuclear Generating Station and demand side
management program deferrals. General taxes increased $8.7 million in the second
quarter and $7.5 million in the first six months of 2003, compared to the
corresponding periods in 2002, principally due to the absence of a $9 million
energy assessment accrual reduction in the second quarter of 2002.
Net Interest Charges
Net interest charges decreased by $0.6 million in the second
quarter of 2003 and $2.2 million in the first six months compared with the same
periods of 2002, reflecting debt redemptions since the end of the first half of
2002. Those decreases were partially offset by interest on $320 million of
transition bonds issued in June 2002 (see Note 1) and $150 million of senior
notes issued in May 2003 to be used for redeeming currently outstanding
securities later in 2003.
CAPITAL RESOURCES AND LIQUIDITY
JCP&L's cash requirements in 2003 for operating expenses,
construction expenditures and scheduled debt maturities are expected to be met
without materially increasing its net debt and preferred stock outstanding.
Available borrowing capacity under short-term credit facilities with affiliates
will be used to manage working capital requirements. Over the next three years,
JCP&L expects to meet its contractual obligations with cash from operations.
Thereafter, JCP&L expects to use a combination of cash from operations and funds
from the capital markets.
Changes in Cash Position
As of June 30, 2003, JCP&L had $6.0 million of cash and cash
equivalents, compared with $4.8 million as of December 31, 2002. The major
sources of 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 to 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)........... $ 80 $ 97 $ 174 $144
Working capital and other... (117) (140) (115) (55)
-------------------------------------------------------------------------
TOTAL....................... $ (37) $ (43) $ 59 $ 89
=========================================================================
(1) Includes net income, depreciation and amortization, deferred income taxes,
investment tax credits and major noncash charges.
Net cash used for operating activities was $37 million in the
second quarter 2003 compared to $43 million in the same quarter of 2002 and net
cash from operating activities was $59 million in the first half of 2003 from
$89 million in the corresponding period of 2002. The second quarter increase was
due to a $23 million decrease in funds used for
111
working capital and other, partially offset by a $17 million decrease in cash
earnings. The change in working capital reflects a $65 million net increase in
accounts payable.
Cash Flows From Financing Activities
In the second quarter of 2003, net cash provided from
financing activities of $27 million primarily reflected the issuance of $196
million of short-term debt and a $27 million decrease in common stock dividend
payments to FirstEnergy. In the second quarter of 2002, net cash provided from
financing activities totaled $246 million, primarily due to the issuance of
transition bonds.
As of June 30, 2003, JCP&L had approximately $6.0 million of
cash and temporary investments and no short-term indebtedness. JCP&L may borrow
from its affiliates on a short-term basis. JCP&L will not issue first mortgage
bonds (FMB) other than as collateral for senior notes, since its senior note
indentures prohibit (subject to certain exceptions) it from issuing any debt
which is senior to the senior notes. As of June 30, 2003. JCP&L had the
capability to issue $578 million of additional senior notes based upon FMB
collateral. Based upon applicable earnings coverage tests JCP&L could issue a
total of $1.78 billion of preferred stock (assuming no additional debt was
issued) as of June 30, 2003.
Cash Flows From Investing Activities
Net cash provided from investing activities totaled $14
million in the second quarter and in the first six months of 2003, compared with
net cash used of $23 million and $51 million in the second quarter and first six
months of 2002. Net cash provided from investing in 2003 represented loan
repayments from associated companies offset by expenditures for property
additions. Net cash used in investing activities in 2002 were principally for
property additions.
During the remaining half of 2003, capital requirements for
property additions are expected to be about $62 million. JCP&L has additional
requirements of approximately $9 million for 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, 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."
Pension and Other Postretirement Benefits
As a result of GPU Service Inc. merging with FirstEnergy
Service Company 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, JCP&L's accrued pension and OPEB
costs as of June 30, 2003 increased by $78.5 million and $86.3 million,
respectively.
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MARKET RISK INFORMATION
JCP&L uses various market risk sensitive instruments,
including derivative contracts, primarily to manage the risk of price
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
JCP&L is exposed to market risk primarily due to fluctuations
in electricity and natural gas prices. To manage the volatility relating to
these exposures, it uses a variety of non-derivative and derivative instruments,
including forward contracts, options and future contracts. The derivatives are
used for hedging purposes. Most of JCP&L's non-hedge derivative contracts
represent non-trading positions that do not qualify for hedge treatment under
SFAS 133. The change in the fair value of commodity derivative contracts related
to energy production during the second quarter and first six months of 2003 is
summarized in the following table:
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, 2003 JUNE 30, 2003
INCREASE (DECREASE) IN THE FAIR VALUE ---------------------------- ----------------------------
OF COMMODITY DERIVATIVE CONTRACTS 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....................... $12.8 $ -- $12.8 $ 8.7 $(0.1) $ 8.6
New contract value when entered........................ -- -- -- -- -- --
Changes in value of existing contracts................. 0.1 (0.1) -- 4.2 (0.1) 4.1
Change in techniques/assumptions....................... -- -- -- -- -- --
Settled contracts...................................... -- -- -- -- 0.1 0.1
----------------------------------------------------------------------------------------------------------------------------
NET ASSETS - DERIVATIVE CONTRACTS AT END OF PERIOD (1). $12.9 $(0.1) $12.8 $12.9 $(0.1) $12.8
============================================================================================================================
IMPACT OF CHANGES IN COMMODITY DERIVATIVE CONTRACTS (2)
Income Statement Effects (Pre-Tax)..................... $ 0.2 $ -- $ 0.2 $ 8.4 $ -- $ 8.4
Balance Sheet Effects:
Other Comprehensive Income (Pre-Tax)................ $ -- $(0.1) $(0.1) $ -- $ -- $ --
Regulatory Liability................................ $(0.1) $ -- $(0.1) $(4.2) $ -- $(4.2)
(1) Includes $12.9 million in non-hedge commodity derivative contracts which are
offset by a regulatory liability.
(2) Represents the increase in value of existing contracts, settled contracts
and changes in techniques/assumptions.
Derivatives included on the Consolidated Balance Sheet as of June 30, 2003:
NON-HEDGE HEDGE TOTAL
---------------------------
(IN MILLIONS)
CURRENT-
Other Assets............................ $ -- $ -- $ --
Other Liabilities....................... -- (0.1) (0.1)
NON-CURRENT-
Other Deferred Charges.................. 12.9 -- 12.9
Other Deferred Credits.................. -- -- --
-----------------------------------------------------------------------------
NET ASSETS.............................. $12.9 $(0.1) $12.8
=============================================================================
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, JCP&L relies on model-based
information. The model provides estimates of future regional prices for
electricity and an estimate of related price volatility. JCP&L uses these
results to develop estimates of fair value for financial reporting purposes and
for internal management decision making. Sources of information for the
valuation of derivative contracts by year are summarized in the following table:
SOURCE OF INFORMATION
- FAIR VALUE BY CONTRACT YEAR 2003(1) 2004 2005 2006 THEREAFTER TOTAL
------------------------------------------------------------------------------------------------------------
(IN MILLIONS)
Prices based on external sources(2)... $0.2 $2.0 $2.5 $ -- $ -- $ 4.7
Prices based on models................ -- -- -- 1.2 6.9 8.1
------------------------------------------------------------------------------------------------------------
TOTAL(3).......................... $0.2 $2.0 $2.5 $ 1.2 $6.9 $12.8
============================================================================================================
(1) For the remaining quarters of 2003.
(2) Broker quote sheets.
(3) Includes $12.9 million from an embedded option that is offset by a
regulatory liability and does not affect earnings.
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JCP&L performs sensitivity analyses to estimate its exposure
to the market risk of its commodity positions. A hypothetical 10% adverse shift
in quoted market prices in the near term on derivative instruments would not
have had a material effect on its consolidated financial position or cash flows
as of June 30, 2003.
Equity Price Risk
Included in JCP&L's nuclear decommissioning trust investments
are marketable equity securities carried at their market value of approximately
$59 million and $52 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 $6 million reduction in fair value as of June 30, 2003.
OUTLOOK
Beginning in 1999, all of JCP&L's customers were able to
select alternative energy suppliers. JCP&L continues to deliver power to homes
and businesses through its existing distribution system, which remains
regulated. To support customer choice, rates were restructured into unbundled
service charges and additional non-bypassable charges to recover stranded costs.
Regulatory assets are costs which have been authorized by the
NJBPU and the Federal Energy Regulatory Commission for recovery from customers
in future periods and, without such authorization, would have been charged to
income when incurred. All of JCP&L's regulatory assets are expected to continue
to be recovered under the provisions of the regulatory proceedings discussed
below. JCP&L's regulatory assets totaled $3.0 billion and $3.2 billion as of
June 30, 2003 and December 31, 2002, respectively.
Regulatory Matters
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 Market Transition Charge (MTC) and Societal
Benefits Charge (SBC) rates; one proposed method of recovery of these costs is
the securitization of the deferred balance. This securitization methodology is
similar to the Oyster Creek securitization 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 up 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. In the second quarter of 2003, JCP&L recorded non-cash amounts
aggregating to $158.5 million ($94 million after tax) consisting of the $153
million deferred energy costs and other regulatory assets. On July 25, 2003, the
NJBPU approved a Stipulation of Settlement between the parties and authorized
the recovery of the total $135 million of the Freehold buyout costs, eliminating
the interim nature of the recovery.
Environmental Matters
JCP&L has been named as a "potentially responsible party"
(PRP) at waste disposal sites which may require cleanup under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980. Allegations of
disposal of hazardous substances at historical sites and the liability involved
are often unsubstantiated and subject to dispute; however, federal law provides
that all PRPs for a particular site be held liable on a joint and several basis.
Therefore, potential environmental liabilities have been recognized on the
Consolidated Balance Sheet as of June 30, 2003, based on estimates of the total
costs of cleanup, JCP&L's 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 through the SBC. JCP&L has
accrued liabilities aggregating approximately $47.1 million as of June 30, 2003.
JCP&L does not believe environmental remediation costs will have a material
adverse effect on its financial condition, cash flows or results of operations.
114
Legal Matters
Various lawsuits, claims and proceedings related to our normal
business operations are pending against us, the most significant of which are
described above and below.
In July 1999, the Mid-Atlantic states experienced a severe
heat storm which resulted in power outages throughout the service territories of
many electric utilities, including JCP&L. In an investigation into the causes of
the outages and the reliability of the transmission and distribution systems of
all four New Jersey electric utilities, the NJBPU concluded that there was not a
prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate
or improper service to its customers. In July 1999, two class action lawsuits
(subsequently consolidated into a single proceeding) were filed in New Jersey
Superior Court against JCP&L and other GPU companies, seeking compensatory and
punitive damages arising from the July 1999 service interruptions in its service
territory. In May 2001, the court denied without prejudice JCP&L's motion
seeking decertification of the class. Discovery continues in the class action,
but no trial date has been set. In October 2001, the court held argument on the
plaintiffs' motion for partial summary judgment, which contends that JCP&L is
bound to several findings of the NJBPU investigation. The plaintiffs' motion was
denied by the Court in November 2001 and the plaintiffs' motion to file an
appeal of this decision was denied by the New Jersey Appellate Division. JCP&L
has also filed a motion for partial summary judgment that is currently pending
before the Superior Court. JCP&L is unable to predict the outcome of these
matters.
A series of unexpected faults in the three transmission lines
triggered a series of outages for approximately 34,000 customers from July 5-8,
2003. The NJBPU has launched an investigation into the causes of the outages,
and JCP&L has filed an incident report with the NJBPU, detailing the timeline
and causes for the outages. JCP&L has committed to accelerate $60 million in
transmission system improvements. Additionally, JCP&L sited ten emergency
generators at strategic locations within a few days of the outage. Without
admitting liability, JCP&L has established a streamlined procedure to address
customers' damage claims.
SIGNIFICANT ACCOUNTING POLICIES
JCP&L 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
JCP&L's assets are subject to their own specific risks and uncertainties and are
regularly reviewed for impairment. Assets related to the application of the
policies discussed below are similarly reviewed with their risks and
uncertainties reflecting those specific factors. JCP&L's more significant
accounting policies are described below.
Purchase Accounting
The merger between FirstEnergy and GPU was accounted for by
the purchase method of accounting, which 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 were based primarily on estimates.
The adjustments reflected in JCP&L's records, which were finalized in the fourth
quarter of 2002, primarily consist of: (1) revaluation of certain property,
plant and equipment; (2) adjusting preferred stock subject to mandatory
redemption and long-term debt to estimated fair value; (3) recognizing
additional obligations related to retirement benefits; and (4) recognizing
estimated severance and other compensation liabilities. The excess of the
purchase price over the estimated fair values of the assets acquired and
liabilities assumed was recognized as goodwill. Based on the guidance provided
by SFAS 142, "Goodwill and Other Intangible Assets," JCP&L evaluates its
goodwill for impairment at least annually and would make such an evaluation more
frequently if indicators of impairment should arise. The forecasts used in
JCP&L's evaluations of goodwill reflect operations consistent with its general
business assumptions. Unanticipated changes in those assumptions could have a
significant effect on JCP&L's future evaluations of goodwill. As of June 30,
2003, JCP&L had recorded goodwill of approximately $2.0 billion related to the
merger.
Regulatory Accounting
JCP&L is subject to regulation that sets the prices (rates) it
is permitted to charge its customers based on the costs that the regulatory
agencies determine JCP&L 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 New Jersey, a significant amount
of regulatory assets have been recorded. As of June 30, 2003, JCP&L's regulatory
assets totaled $3.0 billion. JCP&L 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.
115
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. JCP&L continually monitors its derivative contracts to
determine if its activities, expectations, intentions, assumptions and estimates
remain valid. As part of JCP&L's normal operations, it enters into commodity
contracts which increase the impact of derivative accounting judgments.
Revenue Recognition
JCP&L follows the accrual method of accounting for revenues,
recognizing revenue for kilowatt-hours that have been delivered but not yet been
billed through the end of the accounting period. The determination of unbilled
revenues requires management to make various estimates including:
- Net energy generated or purchased for retail load
- Losses of energy over distribution lines
- Allocations to distribution companies within the FirstEnergy
system
- Mix of kilowatt-hour usage by residential, commercial and
industrial customers
- Kilowatt-hour usage of customers receiving electricity from
alternative suppliers
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory
defined pension benefits and OPEB are dependent upon numerous factors resulting
from actual plan experience and certain assumptions.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions FirstEnergy makes to the plans, and earnings on plan assets.
Pension and OPEB costs may also be affected by changes to key assumptions,
including anticipated rates of return on plan assets, the discount rates and
health care trend rates used in determining the projected benefit obligations
for pension and OPEB costs.
In accordance with SFAS 87, "Employers' Accounting for
Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other
Than Pensions," changes in pension and OPEB obligations associated with these
factors may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
In selecting an assumed discount rate, FirstEnergy considers
currently available rates of return on high-quality fixed income investments
expected to be available during the period to maturity of the pension and other
postretirement benefit obligations. Due to the significant decline in corporate
bond yields and interest rates in general during 2002, FirstEnergy reduced the
assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001.
FirstEnergy's assumed rate of return on pension plan assets
considers historical market returns and economic forecasts for the types of
investments held by its pension trusts. The market values of FirstEnergy's
pension assets have been affected by sharp declines in the equity markets since
mid-2000. In 2002 and 2001, plan assets earned (11.3)% and (5.5)%, respectively.
FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of
return on plan assets. As of December 31, 2002 the assumed return on plan assets
was reduced to 9.00% based upon FirstEnergy's projection of future returns and
pension trust investment allocation of approximately 60% large cap equities, 10%
small cap equities and 30% bonds.
Based on pension assumptions and pension plan assets as of
December 31, 2002, FirstEnergy will not be required to fund its pension plans in
2003. While OPEB plan assets have also been affected by sharp declines in the
equity market, the impact is not as significant due to the relative size of the
plan assets. However, health care cost trends
116
have significantly increased and will affect future OPEB costs. The 2003
composite health care trend rate assumption is approximately 10%-12% gradually
decreasing to 5% in later years, compared to the 2002 assumption of
approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In
determining its trend rate assumptions, FirstEnergy included the specific
provisions of its health care plans, the demographics and utilization rates of
plan participants, actual cost increases experienced in its health care plans,
and projections of future medical trend rates.
Ohio Transition Cost Amortization
In developing FirstEnergy's restructuring plan, the PUCO
determined allowable transition costs based on amounts recorded on the EUOC's
regulatory books. These costs exceeded those deferred or capitalized on
FirstEnergy's balance sheet prepared under GAAP since they included certain
costs which have not yet been incurred or that were recognized on the regulatory
financial statements (fair value purchase accounting adjustments). FirstEnergy
uses an effective interest method for amortizing its transition costs, often
referred to as a "mortgage-style" amortization. The interest rate under this
method is equal to the rate of return authorized by the PUCO in the transition
plan for each respective company. In computing the transition cost amortization,
FirstEnergy includes only the portion of the transition revenues associated with
transition costs included on the balance sheet prepared under GAAP. Revenues
collected for the off balance sheet costs and the return associated with these
costs are recognized as income when received.
Long-Lived Assets
In accordance with SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," JCP&L 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, JCP&L recognizes a loss - calculated as
the difference between the carrying value and the estimated fair value of the
asset (discounted future net cash flows).
RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET IMPLEMENTED
FIN 46, "Consolidation of Variable Interest Entities - an
interpretation of ARB 51"
In January 2003, the FASB issued this interpretation of ARB
No. 51, "Consolidated Financial Statements". The new interpretation provides
guidance on consolidation of variable interest entities (VIEs), generally
defined as certain entities in which equity investors do not have the
characteristics of a controlling financial interest or do not have sufficient
equity at risk for the entity to finance its activities without additional
subordinated financial support from other parties. This Interpretation requires
an enterprise to disclose the nature of its involvement with a VIE if the
enterprise has a significant variable interest in the VIE and to consolidate a
VIE if the enterprise is the primary beneficiary. VIEs created after January 31,
2003 are immediately subject to the provisions of FIN 46. VIEs created before
February 1, 2003 are subject to this interpretation's provisions in the first
interim or annual reporting period beginning after June 15, 2003 (JCP&L's third
quarter of 2003). The FASB also identified transitional disclosure provisions
for all financial statements issued after January 31, 2003.
JCP&L currently has transactions with entities in connection
with the sale of preferred securities and debt secured by bondable property, and
which are reasonably possible of meeting the definition of a VIE in accordance
with FIN 46.
SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities"
Issued by the FASB in April 2003, SFAS 149 further clarifies
and amends accounting and reporting for derivative instruments. The statement
amends SFAS133 for decisions made by the Derivative Implementation Group, as
well as issues raised in connection with other FASB projects and implementation
issues. The statement is effective for contracts entered into or modified after
June 30, 2003 except for implementation issues that have been effective for
quarters which began prior to June 15, 2003, which continue to be applied based
on their original effective dates. JCP&L is currently assessing the new standard
and has not yet determined the impact on its financial statements.
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
117
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. JCP&L 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. JCP&L is
currently assessing the new EITF consensus and has not yet determined the impact
on its financial position or results of operations following adoption.
118
METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
----------------------- -----------------------
2003 2002 2003 2002
---------- ---------- ---------- ----------
(IN THOUSANDS)
OPERATING REVENUES ......................................... $ 217,712 $ 240,003 $ 468,915 $ 485,793
---------- ---------- ---------- ----------
OPERATING EXPENSES AND TAXES:
Purchased power ......................................... 121,687 146,296 265,148 282,436
Other operating costs ................................... 35,068 33,570 67,580 62,575
---------- ---------- ---------- ----------
Total operation and maintenance expenses ............ 156,755 179,866 332,728 345,011
Provision for depreciation and amortization ............. 22,076 15,046 49,237 30,338
General taxes ........................................... 15,538 14,815 32,398 31,727
Income taxes ............................................ 4,785 7,027 11,983 21,898
---------- ---------- ---------- ----------
Total operating expenses and taxes .................. 199,154 216,754 426,346 428,974
---------- ---------- ---------- ----------
OPERATING INCOME ........................................... 18,558 23,249 42,569 56,819
OTHER INCOME ............................................... 5,307 5,456 10,475 10,587
---------- ---------- ---------- ----------
INCOME BEFORE NET INTEREST CHARGES ......................... 23,865 28,705 53,044 67,406
---------- ---------- ---------- ----------
NET INTEREST CHARGES:
Interest on long-term debt .............................. 9,342 10,227 19,881 20,682
Allowance for borrowed funds used during construction ... (85) (280) (158) (564)
Deferred interest ....................................... (555) (42) (995) (235)
Other interest expense .................................. 402 898 865 1,171
Subsidiary's preferred stock dividend requirements ...... 1,889 1,941 3,779 3,779
---------- ---------- ---------- ----------
Net interest charges ................................ 10,993 12,744 23,372 24,833
---------- ---------- ---------- ----------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING
CHANGE .................................................. 12,872 15,961 29,672 42,573
Cumulative effect of accounting change (net of income
taxes of $154,000) (Note 5) ............................. -- -- 217 --
---------- ---------- ---------- ----------
NET INCOME ................................................. $ 12,872 $ 15,961 $ 29,889 $ 42,573
========== ========== ========== ==========
The preceding Notes to Financial Statements as they relate to Metropolitan
Edison Company are an integral part of these statements.
119
METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
JUNE 30, DECEMBER 31,
2003 2002
------------ ------------
(IN THOUSANDS)
ASSETS
UTILITY PLANT:
In service .................................................................. $ 1,821,853 $ 1,620,613
Less--Accumulated provision for depreciation ................................ 754,696 547,925
------------ ------------
1,067,157 1,072,688
Construction work in progress ................................................ 18,835 16,078
------------ ------------
1,085,992 1,088,766
------------ ------------
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts ........................................ 171,965 155,690
Long-term notes receivable from associated companies ........................ 12,418 12,418
Other ....................................................................... 27,415 19,206
------------ ------------
211,798 187,314
------------ ------------
CURRENT ASSETS:
Cash and cash equivalents ................................................... 330 15,685
Receivables-
Customers (less accumulated provisions of $4,929,000 and $4,810,000
respectively, for uncollectible accounts) ............................... 117,440 120,868
Associated companies ...................................................... 70,490 23,219
Other ..................................................................... 19,387 18,235
Notes receivable from associated companies .................................. 24,710 --
Material and supplies, at average cost ...................................... 139 --
Prepayments and other ....................................................... 28,366 9,731
------------ ------------
260,862 187,738
------------ ------------
DEFERRED CHARGES:
Regulatory assets ........................................................... 1,090,957 1,179,125
Goodwill .................................................................... 885,832 885,832
Other ....................................................................... 35,951 36,030
------------ ------------
2,012,740 2,100,987
------------ ------------
$ 3,571,392 $ 3,564,805
============ ============
120
METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
JUNE 30, DECEMBER 31,
2003 2002
------------ ------------
(IN THOUSANDS)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 900,000 shares -
859,500 shares outstanding .............................................. $ 1,297,785 $ 1,297,784
Accumulated other comprehensive loss ...................................... (36,358) (39)
Retained earnings ......................................................... 27,729 17,841
------------ ------------
Total common stockholder's equity ..................................... 1,289,156 1,315,586
Company-obligated trust preferred securities ................................ 92,513 92,409
Long-term debt .............................................................. 609,551 538,790
------------ ------------
1,991,220 1,946,785
------------ ------------
CURRENT LIABILITIES:
Currently payable long-term debt ............................................ 467 60,467
Accounts payable-
Associated companies ...................................................... 154,368 56,861
Other ..................................................................... 30,255 28,583
Notes payable to associated companies ....................................... 20,665 88,299
Accrued taxes ............................................................... 3,422 16,096
Accrued interest ............................................................ 12,658 16,448
Other ....................................................................... 20,429 11,690
------------ ------------
242,264 278,444
------------ ------------
DEFERRED CREDITS:
Accumulated deferred income taxes ........................................... 270,764 316,757
Accumulated deferred investment tax credits ................................. 12,108 12,518
Purchase power contract loss liability ...................................... 632,342 660,507
Nuclear fuel disposal costs ................................................. 37,760 37,541
Asset retirement obligation ................................................. 215,114 270,611
Retirement benefits ......................................................... 109,064 1,354
Other ....................................................................... 60,756 40,288
------------ ------------
1,337,908 1,339,576
------------ ------------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (NOTE 2)
------------ ------------
$ 3,571,392 $ 3,564,805
============ ============
The preceding Notes to Financial Statements as they relate to Metropolitan
Edison Company are an integral part of these balance sheets.
121
METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
----------------------- -----------------------
2003 2002 2003 2002
---------- ---------- ---------- ----------
(IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ................................................. $ 12,872 $ 15,961 $ 29,889 $ 42,573
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization ......... 22,076 15,046 49,237 30,338
Deferred costs, net ................................. (9,658) (2,491) (13,478) (9,411)
Deferred income taxes, net .......................... 8,280 4,308 9,665 12,190
Investment tax credits, net ......................... (205) (212) (410) (424)
Receivables ......................................... (28,290) (26,722) (9,946) (13,808)
Materials and supplies .............................. -- -- (139) --
Accounts payable .................................... 52,329 17,887 84,297 (2,925)
Cumulative effect of accounting change (Note 5) ..... -- -- (371) --
Accrued taxes ....................................... (758) (3,738) (12,674) (5,089)
Accrued interest .................................... 1,008 7,269 (3,790) 436
Prepayments and other ............................... 11,504 15,471 (18,636) (11,426)
Other ............................................... 2,674 (5,083) (9,043) (22,271)
---------- ---------- ---------- ----------
Net cash provided from operating activities ....... 71,832 37,696 104,601 20,183
---------- ---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt ........................................ -- 49,750 247,696 49,750
Redemptions and Repayments-
Long-term debt ........................................ (190,435) -- (230,435) (30,000)
Short-term borrowings, net ............................ (44,547) (56,406) (67,634) (859)
Dividend Payments-
Common stock .......................................... (20,000) (30,000) (20,000) (30,000)
---------- ---------- ---------- ----------
Net cash used for financing activities ............ (254,982) (36,656) (70,373) (11,109)
---------- ---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions ...................................... (9,569) (11,691) (19,902) (20,787)
Decommissioning trust investments ....................... (2,432) (4,826) (4,803) (7,987)
Loans to associated companies ........................... (16,705) -- (24,710) --
Other ................................................... (385) -- (168) (239)
---------- ---------- ---------- ----------
Net cash used for investing activities ............ (29,091) (16,517) (49,583) (29,013)
---------- ---------- ---------- ----------
Net decrease in cash and cash equivalents .................. (212,241) (15,477) (15,355) (19,939)
Cash and cash equivalents at beginning of period ........... 212,571 20,812 15,685 25,274
---------- ---------- ---------- ----------
Cash and cash equivalents at end of period ................. $ 330 $ 5,335 $ 330 $ 5,335
========== ========== ========== ==========
The preceding Notes to Financial Statements as they relate to Metropolitan
Edison Company are an integral part of these statements.
122
REPORT OF INDEPENDENT AUDITORS
To the Stockholders and Board
of Directors of Metropolitan
Edison Company:
We have reviewed the accompanying consolidated balance sheet of Metropolitan
Edison Company 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.
We previously audited in accordance with auditing standards generally accepted
in the United States of America, the consolidated balance sheet and the
consolidated statement of capitalization as of December 31, 2002, and the
related consolidated statements of income, common stockholder's equity,
preferred stock, cash flows and taxes for the year then ended (not presented
herein), and in our report dated February 28, 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
123
METROPOLITAN EDISON COMPANY
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
Met-Ed provides regulated transmission and distribution
services in eastern and south central Pennsylvania. Pennsylvania customers are
able to choose their electricity suppliers as a result of legislation which
restructured the electric utility industry. Met-Ed's regulatory plan required
unbundling the price for electricity into its component elements - including
generation, transmission, distribution and transition charges. Met-Ed continues
to deliver power to homes and businesses through its existing distribution
system and maintains provider of last resort (PLR) obligations to customers who
elect to retain Met-Ed as their power supplier.
RESULTS OF OPERATIONS
Net income in the second quarter of 2003 decreased to $12.9
million from $16.0 million in the second quarter of 2002. During the first six
months of 2003, net income decreased to $29.9 million from $42.6 million in the
first six months of 2002. The first half of 2003 net income included an
after-tax credit of $0.2 million from the cumulative effect of an accounting
change due to the adoption of SFAS No. 143, "Accounting for Asset Retirement
Obligations." Income before the first quarter 2003 cumulative effect was $29.7
million in the first half of 2003 compared with $42.6 million in the
corresponding period of 2002.
Electric Sales
Operating revenues decreased by $22.3 million, or 9.3% in the
second quarter of 2003 compared with the same period of 2002. The lower revenues
resulted from decreased generation sales and distribution deliveries to all
retail sectors, as well as sales to the wholesale market. Lower retail
generation sales (9.2%) and distribution deliveries (3.2%) decreased revenues by
$11.4 million and $2.4 million, respectively, as a result of cooler-than-normal
temperatures in the second quarter of 2003. Wholesale revenue decreased by $8.5
million, which reflected lower sales to affiliated companies. Operating revenues
were lower by $16.9 million, or 3.5% in the first half of 2003 compared with the
first half of 2002. Retail generation kilowatt-hour sales increased overall by
3.8%, which consisted of lower industrial sales (29.4%), higher residential
(10.6%) and nearly flat commercial sales -- producing decreased revenues of $9.1
million. The lower generation sales reflected more commercial and industrial
customers choosing an alternate power supplier compared with the same period of
2002. Wholesale sales revenues decreased $15.5 million principally due to a
reduction in kilowatt-hour sales to affiliated companies. Distribution
deliveries increased 3.3% in the first six months of 2003 from the same period
of the prior year, increasing revenues from electricity throughput by $6.6
million. Distribution deliveries benefited from higher residential and
commercial demand, due in large part to colder temperatures in the first quarter
of 2003, which was partially offset by a decrease in industrial demand from the
continued effect of a sluggish economy.
Changes in electric generation 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:
Retail ............................ (9.2)% (3.8)%
Wholesale ......................... (100.0)% (101.3)%
--------------------------------------------------------------------
TOTAL ELECTRIC GENERATION SALES ..... (18.4)% (12.9)%
====================================================================
Distribution Deliveries:
Residential ....................... (4.0)% 10.4%
Commercial ........................ 0.8% 5.9%
Industrial ........................ (6.1)% (6.2)%
--------------------------------------------------------------------
TOTAL DISTRIBUTION DELIVERIES ....... (3.2)% 3.3%
--------------------------------------------------------------------
Operating Expenses and Taxes
Total operating expenses and taxes decreased $17.6 million in
the second quarter of 2003 and $2.6 million in the first half of 2003 compared
to the same periods of 2002, primarily due to lower purchased power costs that
were partially offset by higher depreciation and amortization charges. The
following table presents changes from the prior year by expense category.
124
OPERATING EXPENSES AND TAXES - CHANGES THREE MONTHS SIX MONTHS
--------------------------------------------------------------------------------
INCREASE (DECREASE) (IN MILLIONS)
Purchased power costs............................. $ (24.6) $ (17.3)
Other operating costs............................. 1.5 5.0
--------------------------------------------------------------------------------
TOTAL OPERATION AND MAINTENANCE EXPENSES........ (23.1) (12.3)
Provision for depreciation and amortization....... 7.0 18.9
General taxes..................................... 0.7 0.7
Income taxes...................................... (2.2) (9.9)
--------------------------------------------------------------------------------
NET DECREASE IN OPERATING EXPENSES AND TAXES.... $ (17.6) $ (2.6)
================================================================================
Lower purchased power costs in the second quarter and first
half of 2003, compared with the second quarter and first half of 2002, were
primarily attributed to lower required kilowatt-hour purchases driven by lower
generation sales. The increase in depreciation and amortization charges
reflected increases in amortization of regulatory assets being recovered through
the competitive transition charge (CTC). Other operating costs increased by $1.5
million and $5.0 million in the three months and six months ended June 30, 2003,
compared with the same periods of 2002, as a result of higher pension and other
employee benefit costs.
Net Interest Charges
Net interest charges decreased by $1.8 million in the second
quarter of 2003 and $1.5 million in the first six months of 2003 compared with
2002. The decrease reflects the refinancing of higher rate debt in the second
quarter of 2003 with the issuance of $250 million of new senior notes issued in
March 2003 and the redemption of $40 million of notes in the first quarter of
2003.
Cumulative Effect of Accounting Change
Upon adoption of SFAS 143 in the first quarter of 2003, Met-Ed
recorded an after-tax credit to net income of approximately $0.2 million. Met-Ed
identified applicable legal obligations as defined under the new accounting
standard for nuclear power plant decommissioning. As a result of adopting SFAS
143 in January 2003, asset retirement costs of $186 million were recorded as
part of the carrying amount of the related long-lived asset, offset by
accumulated depreciation of $186 million. The asset retirement obligation (ARO)
liability at the date of adoption was $198 million, including accumulated
accretion for the period from the date the liability was incurred to the date of
adoption. As of December 31, 2002, Met-Ed had recorded decommissioning
liabilities of $260 million. Met-Ed expects substantially all of its nuclear
decommissioning costs to be recoverable in rates over time. Therefore, Met-Ed
recognized a regulatory liability of $61 million upon adoption of SFAS 143 for
the transition amounts related to establishing the ARO for nuclear
decommissioning. The remaining cumulative effect adjustment for unrecognized
depreciation and accretion offset by the reduction in the liabilities was a $0.4
million increase to income, or $0.2 million net of income taxes.
CAPITAL RESOURCES AND LIQUIDITY
Met-Ed's cash requirements in 2003 for operating expenses,
construction expenditures, scheduled debt maturities and optional debt
redemptions are expected to be met without materially increasing its net debt
and preferred stock outstanding. Over the next three years, Met-Ed expects to
meet its contractual obligations with cash from operations. Thereafter, Met-Ed
expects to use a combination of cash from operations and funds from the capital
markets.
Changes in Cash Position
As of June 30, 2003, Met-Ed had $0.3 million of cash and cash
equivalents compared with $15.7 million as of December 31, 2002. The major
sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Cash provided from operating activities during the second
quarter and first six months of 2003, compared with corresponding periods of
2002 were as follows:
125
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
----------------------------------------
OPERATING CASH FLOWS 2003 2002 2003 2002
---------------------------------------------------------------------
(IN MILLIONS)
Cash earnings (1)....... $ 33 $ 32 $ 75 $ 74
Working capital and other 39 6 30 (54)
---------------------------------------------------------------------
TOTAL................... $ 72 $ 38 $ 105 $ 20
=====================================================================
(1) Includes net income, depreciation and amortization, deferred income
taxes, investment tax credits and major noncash charges.
Net cash from operating activities increased to $72 million in
the second quarter and $105 in the first half of 2003 compared with the
corresponding periods in 2002 of $38 million and $20, respectively. The second
quarter increase was due to a $39 million increase in funds from working capital
and other, primarily from changes in accounts payable.
Cash Flows From Financing Activities
In the second quarter of 2003, net cash used for financing
activities of $255 million reflected the redemption of $190 million of senior
notes and $45 million of short-term debt. In the second quarter of 2002, net
cash used for financing activities totaled $37 million, due to dividends to
FirstEnergy.
As of June 30, 2003, Met-Ed had approximately $25.0 million of
cash and temporary investments, including $24.7 million of notes receivable from
associated companies and approximately $20.7 million of short-term indebtedness.
Met-Ed may borrow from its affiliates on a short-term basis. Met-Ed will not
issue first mortgage bonds (FMB) other than as collateral for senior notes,
since its senior note indentures prohibit (subject to certain exceptions) it
from issuing any debt which is senior to the senior notes. As of June 30, 2003,
Met-Ed had the capability to issue $149 million of additional senior notes based
upon FMB collateral. Met-Ed had no restrictions on the issuance of preferred
stock.
Cash Flows From Investing Activities
Net cash used for investing activities totaled $29 million in
the second quarter and $50 in the first six months of 2003,. The net cash flows
used for investing resulted from property additions and loans to associated
companies. Expenditures for property additions primarily support Met-Ed's energy
delivery operations. In the second quarter and first six months of 2002, net
cash flows used for investing activities totaled $17 million and $29 million,
respectively, principally due to property additions
During the second half of 2003, capital requirements for
property additions are expected to be about $33 million. Met-Ed has additional
requirements of approximately $0.1 million for 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, 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 continued 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
126
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."
Pension and Other Postretirement Benefits
As a result of GPU Service Inc. merging with FirstEnergy
Service Company 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, Met-Ed's accrued pension and OPEB
costs as of June 30, 2003 increased by $47.2 million and $59.4 million,
respectively.
MARKET RISK INFORMATION
Met-Ed uses various market risk sensitive instruments,
including derivative contracts, primarily to manage the risk of price
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
Met-Ed is exposed to market risk primarily due to fluctuations
in electricity and natural gas prices. To manage the volatility relating to
these exposures, it uses a variety of non-derivative and derivative instruments,
including options and future contracts. The derivatives are used for hedging
purposes. Most of Met-Ed's non-hedge derivative contracts represent non-trading
positions that do not qualify for hedge treatment under SFAS 133. The change in
the fair value of commodity derivative contracts related to energy production
during the second quarter and the first six months of 2003 is summarized in the
following table:
INCREASE (DECREASE) IN THE FAIR VALUE THREE MONTHS ENDED SIX MONTHS ENDED
OF COMMODITY DERIVATIVE CONTRACTS 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
Outstanding net asset at beginning of period .................. $ 25.6 $ -- $ 25.6 $ 17.4 $ 0.1 $ 17.5
New contract value when entered ............................... -- -- -- -- -- --
Additions/Increase in value of existing contracts ............. 0.3 -- 0.3 8.5 (0.1) 8.4
Change in techniques/assumptions .............................. -- -- -- -- -- --
Settled contracts ............................................. -- -- -- -- -- --
------------------------------------------------------------------------------------------------ -------------------------------
NET ASSETS - DERIVATIVE CONTRACTS AS OF JUNE 30, 2003 (1) ..... $ 25.9 $ -- $ 25.9 $ 25.9 $ -- $ 25.9
================================================================================================ ===============================
IMPACT OF CHANGES IN COMMODITY DERIVATIVE CONTRACTS (2)
Income Statement Effects (Pre-Tax) ............................ $ 0.5 $ -- $ 0.5 $ 17.0 $ -- $ 17.0
Balance Sheet Effects:
Other Comprehensive Income (Pre-Tax) ....................... $ -- $ -- $ -- $ -- $ (0.1) $ (0.1)
Regulatory Liability ....................................... $ (0.2) $ -- $ (0.2) $ (8.5) $ -- $ (8.5)
(1) Includes $25.7 million in non-hedge commodity derivative contracts
which are offset by a regulatory liability.
(2) Represents the increase in value of existing contracts, settled
contracts and changes in techniques/assumptions.
DERIVATIVES INCLUDED ON THE CONSOLIDATED BALANCE SHEET AS OF JUNE 30, 2003:
NON-HEDGE HEDGE TOTAL
------------------------------------------------------------------------------
(IN MILLIONS)
CURRENT-
Other Assets............................ $ -- $ -- $ --
Other Liabilities....................... -- -- --
NON-CURRENT-
Other Deferred Charges.................. 25.9 -- 25.9
Other Deferred Credits.................. -- -- --
-----------------------------------------------------------------------------
NET ASSETS.............................. $ 25.9 $ -- $ 25.9
=============================================================================
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, Met-Ed relies on model-based
information. The model provides estimates of future regional prices for
electricity and an estimate of related price volatility. Met-Ed uses
127
these results to develop estimates of fair value for financial reporting
purposes and for internal management decision making. Sources of information for
the valuation of derivative contracts by year are summarized in the following
table:
SOURCE OF INFORMATION
- FAIR VALUE BY CONTRACT YEAR 2003(1) 2004 2005 2006 THEREAFTER TOTAL
--------------------------------------------------------------------------------------------------------
(IN MILLIONS)
Prices based on external sources(2) $ 0.5 $ 4.1 $ 5.1 $ -- $ -- $ 9.7
Prices based on models -- -- -- 2.3 13.9 16.2
--------------------------------------------------------------------------------------------------------
TOTAL(3) $ 0.5 $ 4.1 $ 5.1 $ 2.3 $ 13.9 $ 25.9
========================================================================================================
(1) For the last two quarters of 2003.
(2) Broker quote sheets.
(3) Includes $25.7 million from an embedded option that is offset by a
regulatory liability and does not affect earnings.
Met-Ed performs sensitivity analyses to estimate its exposure
to the market risk of its commodity positions. A hypothetical 10% adverse shift
in quoted market prices in the near term on derivative instruments would not
have had a material effect on its consolidated financial position or cash flows
as of June 30, 2003.
Equity Price Risk
Included in Met-Ed's nuclear decommissioning trust investments
are marketable equity securities carried at their market value of approximately
$93 million and $81 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 $9 million reduction in fair value as of June 30, 2003.
OUTLOOK
Beginning in 1999, all of Met-Ed's customers were able to
select alternative energy suppliers. Met-Ed continues to deliver power to homes
and businesses through its existing distribution system, which remains
regulated. The Pennsylvania Public Utility Commission (PPUC) authorized Met-Ed's
rate restructuring plan, establishing separate charges for transmission,
distribution, generation and stranded cost recovery, which is recovered through
a CTC. Customers electing to obtain power from an alternative supplier have
their bills reduced based on the regulated generation component, and the
customers receive a generation charge from the alternative supplier. Met-Ed has
a continuing responsibility to provide power to those customers not choosing to
receive power from an alternative energy supplier, subject to certain limits,
which is referred to as its PLR obligation.
Regulatory assets are costs which have been authorized by the
PPUC and the Federal Energy Regulatory Commission for recovery from customers in
future periods and, without such authorization, would have been charged to
income when incurred. All of Met-Ed's regulatory assets are expected to continue
to be recovered under the provisions of the regulatory plan as discussed below.
Met-Ed's regulatory assets totaled $1.1 billion and $1.2 billion as of June 30,
2003 and December 31, 2002, respectively.
Regulatory Matters
Effective September 1, 2002, Met-Ed assigned its PLR
responsibility to its unregulated supply affiliate, FirstEnergy Solutions Corp.
(FES), through a wholesale power sale agreement 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 energy supply
profit and loss risk, for the portion of power supply requirements that Met-Ed
does not self-supply under its non-utility generation (NUG) contracts and other
existing power contracts with nonaffiliated third party suppliers. This
arrangement reduces its exposure to high wholesale power prices by providing
power at or below the shopping credit for its uncommitted PLR energy costs
during the term of the agreement to FES. Met-Ed will continue to defer the cost
differences between NUG contract rates and the rates reflected in its 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 Met-Ed's PLR rate relief and remanded the merger
savings issue back to the PPUC. Because Met-Ed had already reserved for the
deferred energy costs and FES has largely hedged Met-Ed's anticipated PLR energy
supply requirements through 2005, Met-Ed believes that the disallowance of CTC
recovery of PLR costs above its capped generation rates will not have a future
adverse financial impact during that period.
128
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.
Environmental Matters
Met-Ed has been named as a "potentially responsible party"
(PRP) at waste disposal sites which may require cleanup under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980. Allegations of
disposal of hazardous substances at historical sites and the liability involved
are often unsubstantiated and subject to dispute; however, federal law provides
that all PRPs for a particular site be held liable on a joint and several basis.
Therefore, potential environmental liabilities have been recognized on the
Consolidated Balance Sheet as of June 30, 2003, based on estimates of the total
costs of cleanup, Met-Ed's proportionate responsibility for such costs and the
financial ability of other nonaffiliated entities to pay. Met-Ed has accrued
liabilities aggregating approximately $0.2 million as of June 30, 2003. Met-Ed
does not believe environmental remediation costs will have a material adverse
effect on its financial condition, cash flows or results of operations.
Legal Matters
Various lawsuits, claims and proceedings related to our normal
business operations are pending against Met-Ed, the most significant of which
are described above.
SIGNIFICANT ACCOUNTING POLICIES
Met-Ed 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 its financial results. All of
its assets are subject to their own specific risks and uncertainties and are
regularly reviewed for impairment. Assets related to the application of the
policies discussed below are similarly reviewed with their risks and
uncertainties reflecting those specific factors. Met-Ed's more significant
accounting policies are described below.
Purchase Accounting
The merger between FirstEnergy and GPU was accounted for by
the purchase method of accounting, which 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 were based primarily on estimates.
The adjustments reflected in Met-Ed's records, which were finalized in the
fourth quarter of 2002, primarily consist of: (1) revaluation of certain
property, plant and equipment; (2) adjusting preferred stock
129
subject to mandatory redemption and long-term debt to estimated fair value; (3)
recognizing additional obligations related to retirement benefits; and (4)
recognizing estimated severance and other compensation liabilities. The excess
of the purchase price over the estimated fair values of the assets acquired and
liabilities assumed was recognized as goodwill. Based on the guidance provided
by SFAS 142, "Goodwill and Other Intangible Assets," Met-Ed evaluates its
goodwill for impairment at least annually and would make such an evaluation more
frequently if indicators of impairment should arise. The forecasts used in
Met-Ed's evaluations of goodwill reflect operations consistent with its general
business assumptions. Unanticipated changes in those assumptions could have a
significant effect on its future evaluations of goodwill. As of June 30, 2003,
Met-Ed had recorded goodwill of approximately $885.8 million related to the
merger.
Regulatory Accounting
Met-Ed is subject to regulation that sets the prices (rates)
it is permitted to charge its customers based on the costs that the regulatory
agencies determine it 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 Pennsylvania, a significant
amount of regulatory assets have been recorded. As of June 30, 2003, Met-Ed's
regulatory assets totaled $1.1 billion. Met-Ed 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. Met-Ed continually monitors its derivative contracts to
determine if its activities, expectations, intentions, assumptions and estimates
remain valid. As part of Met-Ed's normal operations, it enters into commodity
contracts which increase the impact of derivative accounting judgments.
Revenue Recognition
Met-Ed follows the accrual method of accounting for revenues,
recognizing revenue for kilowatt-hours that have been delivered but not yet been
billed through the end of the accounting period. The determination of unbilled
revenues requires management to make various estimates including:
- Net energy generated or purchased for retail load
- Losses of energy over distribution lines
- Allocations to distribution companies within the FirstEnergy
system
- Mix of kilowatt-hour usage by residential, commercial and
industrial customers
- Kilowatt-hour usage of customers receiving electricity from
alternative suppliers
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory
defined pension benefits and OPEB are dependent upon numerous factors resulting
from actual plan experience and certain assumptions.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions FirstEnergy makes to the plans, and earnings on plan assets.
Pension and OPEB costs may also be affected by changes to key assumptions,
including anticipated rates of return on plan assets, the discount rates and
health care trend rates used in determining the projected benefit obligations
for pension and OPEB costs.
In accordance with SFAS 87, "Employers' Accounting for
Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other
Than Pensions," changes in pension and OPEB obligations associated with these
factors may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect
130
the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
In selecting an assumed discount rate, FirstEnergy considers
currently available rates of return on high-quality fixed income investments
expected to be available during the period to maturity of the pension and other
postretirement benefit obligations. Due to the significant decline in corporate
bond yields and interest rates in general during 2002, FirstEnergy reduced the
assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001.
FirstEnergy's assumed rate of return on pension plan assets
considers historical market returns and economic forecasts for the types of
investments held by its pension trusts. The market values of FirstEnergy's
pension assets have been affected by sharp declines in the equity markets since
mid-2000. In 2002 and 2001, plan assets earned (11.3)% and (5.5)%, respectively.
FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of
return on plan assets. As of December 31, 2002 the assumed return on plan assets
was reduced to 9.00% based upon FirstEnergy's projection of future returns and
pension trust investment allocation of approximately 60% large cap equities, 10%
small cap equities and 30% bonds.
Based on pension assumptions and pension plan assets as of
December 31, 2002, FirstEnergy will not be required to fund its pension plans in
2003. While OPEB plan assets have also been affected by sharp declines in the
equity market, the impact is not as significant due to the relative size of the
plan assets. However, health care cost trends have significantly increased and
will affect future OPEB costs. The 2003 composite health care trend rate
assumption is approximately 10%-12% gradually decreasing to 5% in later years,
compared to FirstEnergy's 2002 assumption of approximately 10% in 2002,
gradually decreasing to 4%-6% in later years. In determining its trend rate
assumptions, 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.
Long-Lived Assets
In accordance with SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," Met-Ed 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, Met-Ed would recognize a loss -
calculated as the difference between the carrying value and the estimated fair
value of the asset (discounted future net cash flows).
RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET IMPLEMENTED
FIN 46, "Consolidation of Variable Interest Entities - an
interpretation of ARB 51"
In January 2003, the FASB issued this interpretation of ARB
No. 51, "Consolidated Financial Statements". The new interpretation provides
guidance on consolidation of variable interest entities (VIEs), generally
defined as certain entities in which equity investors do not have the
characteristics of a controlling financial interest or do not have sufficient
equity at risk for the entity to finance its activities without additional
subordinated financial support from other parties. This Interpretation requires
an enterprise to disclose the nature of its involvement with a VIE if the
enterprise has a significant variable interest in the VIE and to consolidate a
VIE if the enterprise is the primary beneficiary. VIEs created after January 31,
2003 are immediately subject to the provisions of FIN 46. VIEs created before
February 1, 2003 are subject to this interpretation's provisions in the first
interim or annual reporting period beginning after June 15, 2003 (Met-Ed's third
quarter of 2003). The FASB also identified transitional disclosure provisions
for all financial statements issued after January 31, 2003.
Met-Ed currently has transactions with entities in connection
with the sale of preferred securities, 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.
SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities"
Issued by the FASB in April 2003, SFAS 149 further clarifies
and amends accounting and reporting for derivative instruments. The statement
amends SFAS 133 for decisions made by the Derivative Implementation Group (DIG),
as well as issues raised in connection with other FASB projects and
implementation issues. The statement 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. Met-Ed is currently
assessing the new standard and has not yet determined the impact on its
financial statements.
131
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 (Met-Ed's third quarter of 2003) for all other financial
instruments.
Met-Ed did not enter into or modify any financial instruments
within the scope of SFAS 150 during June 2003. Adoption of SFAS 150, effective
July 1, 2003, did not change the accounting treatment of company-obligated trust
preferred securities ($92.5 million) which continue to be treated as an
obligation and their dividends as interest charges on Met-Ed's Consolidated
Statements of Income. 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. Met-Ed 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 Emerging Issues Task Force (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. Met-Ed is currently assessing the new EITF consensus
and has not yet determined the impact on its financial position or results of
operations following adoption.
132
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
----------------------- -----------------------
2003 2002 2003 2002
--------- --------- --------- ---------
(IN THOUSANDS)
OPERATING REVENUES........................................ $ 231,926 $ 237,576 $ 486,802 $ 480,396
--------- --------- --------- ---------
OPERATING EXPENSES AND TAXES:
Purchased power........................................ 140,549 150,723 313,785 288,852
Other operating costs.................................. 40,477 38,418 77,028 72,218
--------- --------- --------- ---------
Total operation and maintenance expenses........... 181,026 189,141 390,813 361,070
Provision for depreciation and amortization............ 13,603 14,814 27,376 29,645
General taxes.......................................... 15,854 14,426 31,598 29,456
Income taxes........................................... 5,561 3,300 8,454 15,799
--------- --------- --------- ---------
Total operating expenses and taxes................. 216,044 221,681 458,241 435,970
--------- --------- --------- ---------
OPERATING INCOME.......................................... 15,882 15,895 28,561 44,426
OTHER INCOME.............................................. 534 789 342 1,087
--------- --------- --------- ---------
INCOME BEFORE NET INTEREST CHARGES........................ 16,416 16,684 28,903 45,513
--------- --------- --------- ---------
NET INTEREST CHARGES:
Interest on long-term debt............................. 7,352 7,907 14,691 16,328
Allowance for borrowed funds used during construction.. (99) (163) (180) (283)
Deferred interest...................................... (1,149) (691) (2,145) (1,442)
Other interest expense................................. 119 834 262 1,439
Subsidiary's preferred stock dividend requirements..... 1,889 1,942 3,777 3,777
--------- --------- --------- ---------
Net interest charges............................... 8,112 9,829 16,405 19,819
--------- --------- --------- ---------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING
CHANGE................................................. 8,304 6,855 12,498 25,694
Cumulative effect of accounting change (net of income taxes
of $777,000) (Note 5).................................. -- -- 1,096 --
--------- --------- --------- ---------
NET INCOME................................................ $ 8,304 $ 6,855 $ 13,594 $ 25,694
========= ========= ========= =========
The preceding Notes to Financial Statements as they relate to Pennsylvania
Electric Company are an integral part of these statements.
133
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
JUNE 30, DECEMBER 31,
2003 2002
---------- ----------
(IN THOUSANDS)
ASSETS
UTILITY PLANT:
In service................................................................ $1,952,605 $1,844,999
Less--Accumulated provision for depreciation.............................. 764,984 647,581
---------- ----------
1,187,621 1,197,418
Construction work in progress-
Electric plant.......................................................... 20,787 19,200
---------- ----------
1,208,408 1,216,618
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Non-utility generation trusts............................................. 3,984 109,881
Nuclear plant decommissioning trusts...................................... 94,867 88,818
Long-term notes receivable from associated companies...................... 15,515 15,515
Other..................................................................... 13,416 9,425
---------- ----------
127,782 223,639
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents................................................. 366 10,310
Receivables-
Customers (less accumulated provisions of $6,153,000 and $6,216,000
respectively, for uncollectible accounts)............................ 120,675 128,303
Associated companies.................................................... 94,139 45,236
Other................................................................... 17,633 16,184
Notes receivable from associated companies................................ 61,987 --
Prepayments and other..................................................... 8,364 2,551
---------- ----------
303,164 202,584
---------- ----------
DEFERRED CHARGES:
Regulatory assets......................................................... 557,420 599,663
Goodwill.................................................................. 898,086 898,086
Accumulated deferred income tax benefits.................................. 90,250 1,517
Other..................................................................... 19,407 21,147
---------- ----------
1,565,163 1,520,413
---------- ----------
$3,204,517 $3,163,254
========== ==========
134
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
JUNE 30, DECEMBER 31,
2003 2002
----------- -----------
(IN THOUSANDS)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity-
Common stock, par value $20 per share, authorized 5,400,000
shares, 5,290,596 shares outstanding.................................. $ 105,812 $ 105,812
Other paid-in capital................................................... 1,215,256 1,215,256
Accumulated other comprehensive loss.................................... (53,861) (69)
Retained earnings....................................................... 30,299 32,705
----------- -----------
Total common stockholder's equity................................... 1,297,506 1,353,704
Company-obligated trust preferred securities ............................. 92,321 92,214
Long-term debt............................................................ 344,321 470,274
----------- -----------
1,734,148 1,916,192
----------- -----------
CURRENT LIABILITIES:
Currently payable long-term debt.......................................... 125,843 813
Accounts payable-
Associated companies.................................................... 168,052 129,906
Other................................................................... 34,643 29,690
Notes payable to associated companies..................................... 27,569 90,427
Accrued taxes............................................................. 20,863 21,271
Accrued interest.......................................................... 12,809 12,695
Other..................................................................... 19,265 8,409
----------- -----------
409,044 293,211
----------- -----------
DEFERRED CREDITS:
Accumulated deferred investment tax credits............................... 10,430 10,924
Nuclear fuel disposal costs............................................... 18,880 18,771
Power purchase contract loss liability.................................... 739,162 765,063
Asset retirement obligation............................................... 107,366 135,450
Retirement benefits....................................................... 160,645 --
Other..................................................................... 24,842 23,643
----------- -----------
1,061,325 953,851
----------- -----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (NOTE 2)........................... ----------- -----------
$ 3,204,517 $ 3,163,254
=========== ===========
The preceding Notes to Financial Statements as they relate to the Pennsylvania
Electric Company are an integral part of these balance sheets.
135
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------ ------------------------
2003 2002 2003 2002
--------- --------- --------- ---------
(IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 8,304 $ 6,855 $ 13,594 $ 25,694
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization 13,603 14,814 27,376 29,645
Other amortization 14 (595) -- 187
Deferred costs, net (11,787) (9,266) (11,879) (27,700)
Deferred income taxes, net 4,131 4,866 (37,509) (1,438)
Investment tax credits, net (247) (286) (494) (571)
Receivables 3,352 (21,455) 8,792 (9,652)
Accounts payable 13,306 12,915 21,972 1,093
Cumulative effect of accounting change (Note 5) -- -- (1,873) --
Accrued taxes (27,692) (35,087) (408) (19,825)
Accrued interest (5,565) (5,725) 114 364
Prepayments and other 28,965 16,147 (5,813) (12,697)
Pension and retirement obligation 11,964 -- 11,964 --
Other 24,756 4,826 17,680 (1,866)
--------- --------- --------- ---------
Net cash provided from (used for) operating activities 63,104 (11,991) 43,516 (16,766)
--------- --------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net 27,569 65,438 -- 25,865
Redemptions and Repayments-
Long-term debt (289) (24,973) (289) (24,973)
Short-term borrowings, net -- -- (62,858) --
Dividend Payments-
Common stock (16,000) (14,000) (16,000) (14,000)
--------- --------- --------- ---------
Net cash provided from (used for) financing activities 11,280 26,465 (79,147) (13,108)
--------- --------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (12,465) (12,623) (18,777) (22,817)
Decommissioning trust investments (78) -- (78) --
Proceeds from non-utility generation trusts -- -- 106,327 34,208
Loans to associated companies (61,987) -- (61,987) --
Other 202 -- 202 (239)
--------- --------- --------- ---------
Net cash provided from (used for) investing activities (74,328) (12,623) 25,687 11,152
--------- --------- --------- ---------
Net increase (decrease) in cash and cash equivalents 56 1,851 (9,944) (18,722)
Cash and cash equivalents at beginning of period 310 18,460 10,310 39,033
--------- --------- --------- ---------
Cash and cash equivalents at end of period $ 366 $ 20,311 $ 366 $ 20,311
========= ========= ========= =========
The preceding Notes to Financial Statements as they relate to Pennsylvania
Electric Company are an integral part of these statements.
136
REPORT OF INDEPENDENT AUDITORS
To the Stockholders and Board
of Directors of Pennsylvania
Electric Company:
We have reviewed the accompanying consolidated balance sheet of Pennsylvania
Electric Company 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.
We previously audited in accordance with auditing standards generally accepted
in the United States of America, the consolidated balance sheet and the
consolidated statement of capitalization as of December 31, 2002, and the
related consolidated statements of income, common stockholder's equity,
preferred stock, cash flows and taxes for the year then ended (not presented
herein), and in our report dated February 28, 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
137
PENNSYLVANIA ELECTRIC COMPANY
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
Penelec provides regulated transmission and distribution
services in northern, western and south central Pennsylvania. Pennsylvania
customers are able to choose their electricity suppliers as a result of
legislation which restructured the electric utility industry. Penelec's
regulatory plan required unbundling the price for electricity into its component
elements - including generation, transmission, distribution and transition
charges. Penelec continues to deliver power to homes and businesses through its
existing distribution system and maintains provider of last resort (PLR)
obligations to customers who elect to retain Penelec as their power supplier.
RESULTS FROM OPERATIONS
Net income in the second quarter of 2003 increased to $8.3
million from $6.9 million in the second quarter of 2002. Reduced purchased power
costs in the second quarter of 2003 were partially offset by lower operating
revenues and higher other operating costs as compared to the second quarter of
2002. During the first six months of 2003, net income decreased to $13.6 million
compared to $25.7 million in the first six months of 2002. Net income in the
first half of 2003 included an after-tax credit of $1.1 million from the
cumulative effect of an accounting change due to the adoption of SFAS No. 143,
"Accounting for Asset Retirement Obligations." Income before the cumulative
effect was $12.5 million in the first half of 2003 compared with $25.7 million
for the corresponding period of 2002. In the first six months of 2003, higher
operating expenses, primarily due to purchased power costs, were partially
offset by higher operating revenues.
Electric Sales
Operating revenues decreased by $5.7 million, or 2.4% in the
second quarter of 2003 compared with the same period in 2002, primarily as a
result of lower wholesale and industrial kilowatt-hour sales, partially offset
by increased residential and commercial kilowatt-hour sales. Wholesale sales
revenues decreased by $4.6 million, which was attributable to lower sales to
affiliated companies. Retail generation kilowatt-hour sales decreased by 2.6%
($2.7 million decrease in revenue) as a result of a 20.2% decrease in industrial
sales offset by higher residential and commercial sales (4.9% and 8.4%,
respectively). The substantial decrease in industrial sales was primarily due to
more industrial customers being served by alternative suppliers in the second
quarter of 2003 compared to 2002. Distribution deliveries increased 2.3% in the
second quarter of 2003 from the same quarter of the prior year, increasing
revenues from electricity throughput by $1.8 million. Distribution deliveries
benefited from higher residential and commercial demand, which was partially
offset by a decrease in industrial demand from the continued effect of a
sluggish economy. Operating revenues increased $6.4 million, or 1.3% in the
first six months of 2003 over the same period in 2002, reflecting a 4.6%
increase in distribution deliveries and a corresponding increase in revenues of
$8.9 million. Higher distribution deliveries to residential and commercial
customers were partially offset by lower industrial demands. The higher
distribution revenues were partially offset by lower wholesale sales revenues of
$5.2 million, due to lower sales to affiliated companies.
Changes in electric generation sales and distribution
deliveries in the second quarter and the first six months of 2003 from the
corresponding periods of 2002 are summarized in the following table:
CHANGES IN KILOWATT-HOUR SALES THREE MONTHS SIX MONTHS
-------------------------------------------------------------------------
INCREASE (DECREASE)
Electric Generation:
Retail................................ (2.6)% 0.1%
Wholesale............................. (92.1)% (99.2)%
---------------------------------------------------------------------
TOTAL ELECTRIC GENERATION SALES......... (7.2)% (4.1)%
=====================================================================
Distribution Deliveries:
Residential........................... 4.8% 11.5%
Commercial............................ 9.7% 10.3%
Industrial............................ (6.0)% (6.3)%
---------------------------------------------------------------------
TOTAL DISTRIBUTION DELIVERIES........... 2.3% 4.6%
=====================================================================
138
Operating Expenses and Taxes
Total operating expenses and taxes decreased $5.6 million or
2.5% in the second quarter of 2003 and increased $22.3 million, or 5.1% in the
first six months of 2003 from the same periods of 2002. The following table
presents changes from the prior year by expense category.
OPERATING EXPENSES AND TAXES - CHANGES THREE MONTHS SIX MONTHS
---------------------------------------------------------------------------------
INCREASE (DECREASE) (IN MILLIONS)
Purchased power costs............................ $ (10.2) $ 24.9
Other operating costs............................ 2.1 4.8
-------------------------------------------------------------------------------
TOTAL OPERATION AND MAINTENANCE EXPENSES....... (8.1) 29.7
Provision for depreciation and amortization...... (1.2) (2.3)
General taxes.................................... 1.4 2.2
Income taxes..................................... 2.3 (7.3)
-------------------------------------------------------------------------------
TOTAL CHANGE IN OPERATING EXPENSES AND TAXES... $ (5.6) $ 22.3
===============================================================================
Reduced purchased power costs in the second quarter of 2003,
compared with the same quarter of 2002, were due to lower required kilowatt-hour
purchases driven by lower generation sales. The higher purchased power costs in
the first half of 2003 were principally due to higher average unit costs. The
increase in other operating costs in the second quarter and first half of 2003
over 2002 was primarily due to higher pension and other employee benefit costs.
Net Interest Charges
Net interest charges decreased by $1.7 million in the second
quarter of 2003 and $3.4 million in the first half of 2003 compared with 2002,
reflecting debt redemptions since the beginning of the second quarter of 2002.
Cumulative Effect of Accounting Change
Upon adoption of SFAS 143 in the first quarter of 2003,
Penelec recorded an after-tax credit to net income of $1.1 million. Penelec
identified applicable legal obligations as defined under the new standard for
nuclear power plant decommissioning. As a result of adopting SFAS 143 in January
2003, asset retirement costs of $93 million were recorded as part of the
carrying amount of the related long-lived asset, offset by accumulated
depreciation of $93 million. The asset retirement obligation (ARO) liability at
the date of adoption was $99 million, including accumulated accretion for the
period from the date the liability was incurred to the date of adoption. As of
December 31, 2002, Penelec had recorded decommissioning liabilities of $130
million. Penelec expects substantially all of its nuclear decommissioning costs
to be recoverable in rates over time. Therefore, Penelec recognized a regulatory
liability of $29 million upon adoption of SFAS 143 for the transition amounts
related to establishing the ARO for nuclear decommissioning. The remaining
cumulative effect adjustment for unrecognized depreciation and accretion offset
by the reduction in the liabilities was a $1.9 million increase to income, or
$1.1 million net of income taxes.
CAPITAL RESOURCES AND LIQUIDITY
Penelec's cash requirements in 2003 for operating expenses,
construction expenditures and scheduled debt maturities are expected to be met
without materially increasing its net debt and preferred stock outstanding. Over
the next three years, Penelec expects to meet its contractual obligations with
cash from operations. Thereafter, Penelec expects to use a combination of cash
from operations and funds from the capital markets.
Changes in Cash Position
As of June 30, 2003, Penelec had $0.4 million of cash and cash
equivalents, compared with $10.3 million as of December 31, 2002. The major
sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Net cash provided from (used for) operating activities during
the second quarter and first six months of 2003 compared with the corresponding
periods of 2002 were as follows:
139
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------ ----------------
OPERATING CASH FLOWS 2003 2002 2003 2002
---------------------------------------------------------------------------
(IN MILLIONS)
Cash earnings (loss) (1)..... $14 $ 16 $(11) $ 26
Working capital and other.... 49 (28) 54 (43)
---------------------------------------------------------------------------
Total........................ $63 $(12) $ 43 $(17)
===========================================================================
(1) Includes net income, depreciation and amortization, deferred income taxes,
investment tax credits and major noncash charges.
Net cash provided from operating activities increased to $63
million in the second quarter and $43 million in the first half of 2003 compared
with net cash used for operating activities in the corresponding periods of 2002
of $12 million and $17 million, respectively. This increase was primarily due to
the increase of working capital and other.
Cash Flows From Financing Activities
In the second quarter of 2003, the decrease in net cash
provided from financing activities of $11 million as compared to $26 million in
the same period of 2002 resulted from a reduction in net short-term borrowings.
As of June 30, 2003, Penelec had about $62.4 million of cash
and temporary cash investments and approximately $27.6 million of short-term
indebtedness. Penelec may borrow from its affiliates on a short-term basis.
Penelec will not issue first mortgage bonds (FMB) other than as collateral for
senior notes, since its senior note indentures prohibit (subject to certain
exceptions) it from issuing any debt which is senior to the senior notes. As of
June 30, 2003, Penelec had the capability to issue $10 million of additional
senior notes based upon FMB collateral. Penelec had no restrictions on the
issuance of preferred stock.
Cash Flows From Investing Activities
Net cash used for investing activities totaled $74 million in
the second quarter of 2003 compared to $13 million in the second quarter of
2002. Net cash provided from investing activities was $26 million in the first
six months of 2003, compared with $11 million in the same period of 2002. The
net cash provided from investing activities resulted from proceeds from
nonutility generation trusts, slightly offset by expenditures for property
additions in both periods. Expenditures for property additions primarily support
Penelec's energy delivery operations.
During the second half of 2003, capital requirements for
property additions are expected to be about $30 million. Penelec has additional
requirements of approximately $0.2 million for 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, 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 continued 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 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
140
not expect that the outcome of the review will result in FirstEnergy's senior
unsecured debt rating falling below investment-grade."
Pension and Other Postretirement Benefits
As a result of GPU Service Inc. merging with FirstEnergy
Service Company 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, Penelec's accrued pension and OPEB
costs as of June 30, 2003 increased by $70.7 million and $87.3 million,
respectively.
MARKET RISK INFORMATION
Penelec uses various market risk sensitive instruments,
including derivative contracts, primarily to manage the risk of price
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
Penelec is exposed to market risk primarily due to
fluctuations in electricity and natural gas prices. To manage the volatility
relating to these exposures, it uses a variety of non-derivative and derivative
instruments, including options and future contracts. The derivatives are used
for hedging purposes. Most of Penelec's non-hedge derivative contracts represent
non-trading positions that do not qualify for hedge treatment under SFAS 133.
The change in the fair value of commodity derivative contracts related to energy
production during the second quarter and first six months of 2003 is summarized
in the following table:
INCREASE (DECREASE) IN THE FAIR VALUE THREE MONTHS ENDED SIX MONTHS ENDED
OF COMMODITY DERIVATIVE CONTRACTS 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............................ $12.8 $ -- $12.8 $ 8.7 $ 0.1 $ 8.8
New contract value when entered............................. -- -- -- -- -- --
Additions/Increase in value of existing contracts........... 0.1 -- 0.1 4.2 -- 4.2
Change in techniques/assumptions............................ -- -- -- -- -- --
Settled contracts........................................... -- -- -- -- (0.1) (0.1)
------------------------------------------------------------------------------------------- ---------------------------
NET ASSETS - DERIVATIVE CONTRACTS AS OF JUNE 30, 2003 (1)... $12.9 $ -- $12.9 $12.9 $ -- $12.9
=========================================================================================== ===========================
IMPACT OF CHANGES IN COMMODITY DERIVATIVE CONTRACTS (2)
Income Statement Effects (Pre-Tax).......................... $ 0.2 $ -- $ 0.2 $ 8.4 $ -- $ 8.4
Balance Sheet Effects:
Other Comprehensive Income (Pre-Tax)..................... $ -- $ -- $ -- $ -- $(0.1) $(0.1)
Regulatory Liability..................................... $(0.1) $ -- $(0.1) $(4.2) $ -- $(4.2)
(1) Includes $12.2 million in non-hedge commodity derivative contracts which
are offset by a regulatory liability.
(2) Represents the increase in value of existing contracts, settled contracts
and changes in techniques/assumptions.
Derivatives included on the Consolidated Balance Sheet as of June 30, 2003:
NON-HEDGE HEDGE TOTAL
---------------------------
(IN MILLIONS)
CURRENT-
Other Assets.................... $ -- $ -- $ --
Other Liabilities............... -- -- --
NON-CURRENT-
Other Deferred Charges.......... 12.9 -- 12.9
Other Deferred Credits.......... -- -- --
----------------------------------------------------------------------------
NET ASSETS...................... $12.9 $ -- $12.9
============================================================================
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, Penelec relies on model-based
information. The model provides estimates of future regional prices for
electricity and an estimate of related price volatility. Penelec uses these
results to develop estimates of fair value for financial reporting purposes and
for internal management
141
decision making. Sources of information for the valuation of 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 based on external sources(2) $0.3 $2.0 $2.5 $ -- $ -- $ 4.8
Prices based on models -- -- -- 1.2 6.9 8.1
-----------------------------------------------------------------------------------------------------------
TOTAL(3) $0.3 $2.0 $2.5 $1.2 $6.9 $12.9
===========================================================================================================
(1) For the remaining quarters of 2003.
(2) Broker quote sheets.
(3) Includes $12.2 million from an embedded option that is offset by a
regulatory liability and does not affect earnings.
Penelec performs sensitivity analyses to estimate its exposure
to the market risk of its commodity positions. A hypothetical 10% adverse shift
in quoted market prices in the near term on derivative instruments would not
have had a material effect on its consolidated financial position or cash flows
as of June 30, 2003.
Equity Price Risk
Included in Penelec's nuclear decommissioning trust
investments are marketable equity securities carried at their market value of
approximately $47 million and $42 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 $5 million reduction in fair value as of June 30,
2003.
OUTLOOK
Beginning in 1999, all of Penelec's customers were able to
select alternative energy suppliers. Penelec continues to deliver power to homes
and businesses through its existing distribution system, which remains
regulated. The Pennsylvania Public Utility Commission (PPUC) authorized
Penelec's rate restructuring plan, establishing separate charges for
transmission, distribution, generation and stranded cost recovery, which is
recovered through a competitive transition charge (CTC). Customers electing to
obtain power from an alternative supplier have their bills reduced based on the
regulated generation component, and the customers receive a generation charge
from the alternative supplier. Penelec has a continuing responsibility to
provide power to those customers not choosing to receive power from an
alternative energy supplier, subject to certain limits, which is referred to as
its PLR obligation.
Regulatory assets are costs which have been authorized by the
PPUC and the Federal Energy Regulatory Commission for recovery from customers in
future periods and, without such authorization, would have been charged to
income when incurred. All of Penelec's regulatory assets are expected to
continue to be recovered under the provisions of the regulatory plan as
discussed below. Penelec's regulatory assets totaled $557 million and $600
million as of June 30, 2003 and December 31, 2002, respectively.
Regulatory Matters
Effective September 1, 2002, Penelec assigned its provider of
last resort (PLR) responsibility obligation to its unregulated supply affiliate,
FirstEnergy Solutions Corp. (FES), through a wholesale power sale agreement
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 energy supply profit and loss risk, for the portion of power
supply requirements that Penelec does not self-supply under its non-utility
generation (NUG) contracts and other existing power contracts with nonaffiliated
third party suppliers. This arrangement reduces its exposure to high wholesale
power prices by providing power at or below the shopping credit for its
uncommitted PLR energy costs during the term of the agreement to FES. Penelec
will continue to defer those cost differences between NUG contract rates and the
rates reflected in its 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 Penelec's PLR rate relief and remanded the merger
savings issue back to the PPUC. Because Penelec had already reserved for the
deferred energy costs and FES has largely hedged Penelec's anticipated PLR
energy supply requirements through 2005, Penelec believes that the disallowance
of CTC recovery of PLR costs above its 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
142
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.
Environmental Matters
Penelec has been named as a "potentially responsible party"
(PRP) at waste disposal sites which may require cleanup under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980. Allegations of
disposal of hazardous substances at historical sites and the liability involved
are often unsubstantiated and subject to dispute; however, federal law provides
that all PRPs for a particular site be held liable on a joint and several basis.
Therefore, potential environmental liabilities have been recognized on the
Consolidated Balance Sheet as of June 30, 2003, based on estimates of the total
costs of cleanup, Penelec's proportionate responsibility for such costs and the
financial ability of other nonaffiliated entities to pay. Penelec has total
accrued liabilities aggregating approximately $0.2 million as of June 30, 2003.
Penelec does not believe environmental remediation costs will have a material
adverse effect on its financial condition, cash flows or results of operations.
Legal Matters
Various lawsuits, claims and proceedings related to Penelec's
normal business operations are pending against it, the most significant of which
are described above.
SIGNIFICANT ACCOUNTING POLICIES
Penelec 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 its financial results. All of
its assets are subject to their own specific risks and uncertainties and are
regularly reviewed for impairment. Assets related to the application of the
policies discussed below are similarly reviewed with their risks and
uncertainties reflecting those specific factors. Penelec's more significant
accounting policies are described below.
Purchase Accounting
The merger between FirstEnergy and GPU was accounted for by
the purchase method of accounting, which 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 were based primarily on estimates.
The adjustments reflected in Penelec's records, which were finalized in the
fourth quarter of 2002, primarily consist of: (1) revaluation of certain
property, plant and equipment; (2) adjusting preferred stock subject to
mandatory redemption and long-term debt to estimated fair value; (3) recognizing
additional obligations related to retirement benefits; and (4) recognizing
estimated severance and other compensation liabilities. The excess of the
143
purchase price over the estimated fair values of the assets acquired and
liabilities assumed was recognized as goodwill. Based on the guidance provided
by SFAS 142, "Goodwill and Other Intangible Assets," Penelec evaluates its
goodwill for impairment at least annually and would make such an evaluation more
frequently if indicators of impairment should arise. The forecasts used in its
evaluations of goodwill reflect operations consistent with its general business
assumptions. Unanticipated changes in those assumptions could have a significant
effect on Penelec's future evaluations of goodwill. As of June 30, 2003, Penelec
had recorded goodwill of approximately $898.1 million related to the merger.
Regulatory Accounting
Penelec is subject to regulation that sets the prices (rates)
it is permitted to charge its customers based on the costs that the regulatory
agencies determine it 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 Pennsylvania, a significant
amount of regulatory assets have been recorded. As of June 30, 2003, Penelec's
regulatory assets totaled $557 million. Penelec 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. Penelec continually monitors its derivative contracts
to determine if Penelec's activities, expectations, intentions, assumptions and
estimates remain valid. As part of Penelec's normal operations, it enters into
commodity contracts which increase the impact of derivative accounting
judgments.
Revenue Recognition
Penelec follows the accrual method of accounting for revenues,
recognizing revenue for kilowatt-hours that have been delivered but not yet been
billed through the end of the accounting period. The determination of unbilled
revenues requires management to make various estimates including:
- Net energy generated or purchased for retail load
- Losses of energy over distribution lines
- Allocations to distribution companies within the FirstEnergy
system
- Mix of kilowatt-hour usage by residential, commercial and
industrial customers
- Kilowatt-hour usage of customers receiving electricity from
alternative suppliers
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory
defined pension benefits and OPEB are dependent upon numerous factors resulting
from actual plan experience and certain assumptions.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions FirstEnergy makes to the plans, and earnings on plan assets.
Pension and OPEB costs may also be affected by changes to key assumptions,
including anticipated rates of return on plan assets, the discount rates and
health care trend rates used in determining the projected benefit obligations
for pension and OPEB costs.
In accordance with SFAS 87, "Employers' Accounting for
Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other
Than Pensions," changes in pension and OPEB obligations associated with these
factors may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
144
In selecting an assumed discount rate, FirstEnergy considers
currently available rates of return on high-quality fixed income investments
expected to be available during the period to maturity of the pension and other
postretirement benefit obligations. Due to the significant decline in corporate
bond yields and interest rates in general during 2002, FirstEnergy reduced the
assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001.
FirstEnergy's assumed rate of return on pension plan assets
considers historical market returns and economic forecasts for the types of
investments held by its pension trusts. The market values of FirstEnergy's
pension assets have been affected by sharp declines in the equity markets since
mid-2000. In 2002 and 2001, plan assets have earned (11.3)% and (5.5)%,
respectively. FirstEnergy's pension costs in 2002 were computed assuming a
10.25% rate of return on plan assets. As of December 31, 2002 the assumed return
on plan assets was reduced to 9.00% based upon FirstEnergy's projection of
future returns and pension trust investment allocation of approximately 60%
large cap equities, 10% small cap equities and 30% bonds.
Based on pension assumptions and pension plan assets as of
December 31, 2002, FirstEnergy will not be required to fund its pension plans in
2003. While OPEB plan assets have also been affected by sharp declines in the
equity market, the impact is not as significant due to the relative size of the
plan assets. However, health care cost trends significantly increased and will
affect future OPEB costs. The 2003 composite health care trend rate assumption
is approximately 10%-12% gradually decreasing to 5% in later years, compared to
FirstEnergy's 2002 assumption of approximately 10% in 2002, gradually decreasing
to 4%-6% in later years. In determining its trend rate assumptions, 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.
Long-Lived Assets
In accordance with SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," Penelec 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, Penelec would recognize a loss -
calculated as the difference between the carrying value and the estimated fair
value of the asset (discounted future net cash flows).
RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET IMPLEMENTED
FIN 46, "Consolidation of Variable Interest Entities - an
interpretation of ARB 51"
In January 2003, the FASB issued this interpretation of ARB
No. 51, "Consolidated Financial Statements". The new interpretation provides
guidance on consolidation of variable interest entities (VIEs), generally
defined as certain entities in which equity investors do not have the
characteristics of a controlling financial interest or do not have sufficient
equity at risk for the entity to finance its activities without additional
subordinated financial support from other parties. This Interpretation requires
an enterprise to disclose the nature of its involvement with a VIE if the
enterprise has a significant variable interest in the VIE and to consolidate a
VIE if the enterprise is the primary beneficiary. VIEs created after January 31,
2003 are immediately subject to the provisions of FIN 46. VIEs created before
February 1, 2003 are subject to this interpretation's provisions in the first
interim or annual reporting period beginning after June 15, 2003 (Penelec's
third quarter of 2003). The FASB also identified transitional disclosure
provisions for all financial statements issued after January 31, 2003.
Penelec currently has involvement with entities in connection
with the sale of preferred securities, 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.
SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities"
Issued by the FASB in April 2003, SFAS 149 further clarifies
and amends accounting and reporting for derivative instruments. The statement
amends SFAS 133 for decisions made by the Derivative Implementation Group (DIG),
as well as issues raised in connection with other FASB projects and
implementation issues. The statement is effective for contracts entered into or
modified after June 30, 2003 except for implementation issues that have been
effective for reporting periods which began prior to June 15, 2003, which
continue to be applied based on their original effect dates. Penelec is
currently assessing the new standard and has not yet determined the impact on
its financial statements.
145
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 (Penelec's third quarter of 2003) for all other financial
instruments.
Penelec did not enter into or modify any financial instruments
within the scope of SFAS 150 during June 2003. Adoption of SFAS 150, effective
July 1, 2003, did not change the accounting treatment of company-obligated trust
preferred securities ($92.3 million) which continue to be treated as obligations
and their dividends as interest charges on Penelec's Consolidated Statements of
Income. 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. Penelec 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 Emerging Issues Task Force (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. Penelec is currently assessing the new EITF consensus
and has not yet determined the impact on its financial position or results of
operations following adoption.
CONTROLS AND PROCEDURES
(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
The applicable registrant's chief executive officer and chief
financial officer have reviewed and evaluated the registrant's disclosure
controls and procedures, as defined in the Securities Exchange Act of 1934 Rules
13a-14(c) and 15d-14(c), as of a date within 90 days prior to the filing date of
this report (Evaluation Date). Based on that evaluation those officers have
concluded that the registrant's disclosure controls and procedures are effective
and were designed to bring to their attention, during the period in which this
quarterly report was being prepared, material information relating to the
registrant and its consolidated subsidiaries by others within those entities.
(b) CHANGES IN INTERNAL CONTROLS
Effective June 1, 2003, the registrants implemented a new
Enterprise Resource Planning (ERP) system. While the associated business process
changes transform the internal control structure, management believes adequate
controls have been properly integrated into the reengineered ERP enabled
processes and that internal controls will be enhanced.
146
PART II. OTHER INFORMATION
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
(a) The annual meeting of FirstEnergy shareholders was held on May 20,
2003.
(b) At this meeting, the following persons were elected to
FirstEnergy's Board of Directors:
NUMBER OF VOTES
--------------------------
FOR WITHHELD
----------- ----------
Paul T. Addison................... 249,474,343 9,379,634
Dr. Carol A. Cartwright........... 215,455,549 43,398,428
William T. Cottle................. 249,690,431 9,163,546
Paul J. Powers.................... 215,158,961 43,695,016
George M. Smart................... 213,788,961 45,065,016
Dr. Patricia K. Woolf............. 214,937,572 43,916,405
(c) At this meeting, the appointment of PricewaterhouseCoopers LLP,
independent public accountants, as auditor for the year 2003 was
ratified:
NUMBER OF VOTES
-----------------------------------------
FOR AGAINST ABSTENTIONS
----------- --------- -----------
248,044,248 7,804,863 3,004,866
(d) At this meeting, material terms of performance goals under the
Executive and Director Incentive Compensation Plan were reapproved
(reapproval required a majority of votes cast):
NUMBER OF VOTES
----------------------------------------
FOR AGAINST ABSTENTIONS
----------- ---------- -----------
235,422,226 18,576,274 4,855,477
(e) At this meeting, a shareholder proposal designed to result in the
election of the entire Board of Directors each year was rejected
(passage required 80% of the 297,636,276 common shares outstanding):
NUMBER OF VOTES
-------------------------------------------------------------
BROKER
FOR AGAINST ABSTENTIONS NON-VOTES
----------- ---------- ----------- ----------
138,780,623 79,888,135 8,793,222 31,391,997
(f) At this meeting, a shareholder proposal requesting that a policy be
adopted in which all future stock option grants to employees be
expensed in FirstEnergy's annual income statement was rejected:
NUMBER OF VOTES
------------------------------------------------------------
BROKER
FOR AGAINST ABSTENTIONS NON-VOTES
----------- ----------- ----------- ----------
101,621,396 116,226,152 9,610,633 31,395,796
147
(g) At this meeting, a shareholder proposal requesting that a policy be
adopted in which the exercise price of all future stock options
granted to senior executives be linked to a peer group index was
rejected:
NUMBER OF VOTES
-----------------------------------------------------------
BROKER
FOR AGAINST ABSTENTIONS NON-VOTES
---------- ----------- ----------- ---------
35,672,175 185,188,114 6,598,190 31,395,498
(h) At this meeting, a shareholder proposal recommending that
FirstEnergy's shareholder rights plan be redeemed and any future
plan to be approved by shareholders was passed (passage required a
majority of votes cast):
NUMBER OF VOTES
------------------------------------------------------------
BROKER
FOR AGAINST ABSTENTIONS NON-VOTES
----------- ---------- ----------- ----------
143,458,470 77,265,103 6,738,406 31,391,998
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) EXHIBITS
EXHIBIT
NUMBER
MET-ED
12 Fixed charge ratios
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.
PENELEC
12 Fixed charge ratios
15 Letter from independent 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.
JCP&L
12 Fixed charge ratios
15 Letter from independent auditors
31.2 Certification letter from chief financial officer, as
adopted pursuant to Section 302 of the Sarbanes-Oxley
Act.
31.3 Certification letter from chief executive officer, as
adopted pursuant to Section 302 of the Sarbances-Oxley
Act.
32.2 Certification letter from chief executive officer and
chief financial officer, as adopted pursuant to Section
906 of the Sarbanes-Oxley Act.
148
FIRSTENERGY, OE AND PENN
15 Letter from independent public auditors
31.1 Certification letter from chief executive officer, as
adopted pursuant to Section 302 of the Sarbanes-Oxley
Act.
31.2 Certification letter from chief financial officer, as
adopted pursuant to Section 302 of the Sarbanes-Oxley
Act.
32.1 Certification letter from chief executive officer and
chief financial officer, as adopted pursuant to Section
906 of the Sarbanes-Oxley Act.
CEI AND TE
31.1 Certification letter from chief executive officer, as
adopted pursuant to Section 302 of the Sarbanes-Oxley
Act.
31.2 Certification letter from chief financial officer, as
adopted pursuant to Section 302 of the Sarbanes-Oxley
Act.
32.1 Certification letter from chief executive officer and
chief financial officer, as adopted pursuant to Section
906 of the Sarbanes-Oxley Act.
Pursuant to reporting requirements of respective financings,
JCP&L, Met-Ed and Penelec are required to file fixed charge
ratios as an exhibit to this Form 10-Q. FirstEnergy, OE, CEI,
TE and Penn do not have similar financing reporting
requirements and have not filed their respective fixed charge
ratios.
Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation
S-K, neither FirstEnergy, OE, CEI, TE, Penn, JCP&L, Met-Ed nor
Penelec have filed as an exhibit to this Form 10-Q any
instrument with respect to long-term debt if the respective
total amount of securities authorized thereunder does not
exceed 10% of their respective total assets of FirstEnergy and
its subsidiaries on a consolidated basis, or respectively, OE,
CEI, TE, Penn, JCP&L, Met-Ed or Penelec but hereby agree 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.
OE
OE filed two reports on Form 8-K since March 31, 2003. A
report dated August 5, 2003 reported the pending restatement of 2002 FE, OE, CEI
and TE financial statements. A report dated August 8, 2003 reported a U.S.
District Court ruling with respect to the W. H. Sammis Plant under the Clean Air
Act.
PENN
Penn filed one report on Form 8-K since March 31, 2003. 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.
149
CEI
CEI filed seven reports on Form 8-K since March 31, 2003. A
report dated April 16, 2003 reported Davis-Besse information. A report dated May
1, 2003 reported an updated Davis-Besse ready for restart schedule. A report
dated May 9, 2003 reported updated Davis-Besse information. A report dated June
5, 2003, reported updated Davis-Besse information. A report dated July 24, 2003
reported an updated Davis-Besse ready for restart schedule and cost estimates. 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.
TE
TE filed seven reports on Form 8-K since March 31, 2003. A
report dated April 16, 2003 reported Davis-Besse information. A report dated May
1, 2003 reported an updated Davis-Besse ready for restart schedule. A report
dated May 9, 2003 reported updated Davis-Besse information. A report dated June
5, 2003, reported updated Davis-Besse information. A report dated July 24, 2003
reported an updated Davis-Besse ready for restart schedule and cost estimates. 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.
MET-ED
Met-Ed filed one report on Form 8-K since March 31, 2003. A
report dated June 11, 2003 reported that 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.
PENELEC
Penelec filed one report on Form 8-K since March 31, 2003. A
report dated June 11, 2003 reported that 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.
JCP&L
JCP&L filed three reports on Form 8-K since March 31, 2003. A
report dated May 9, 2003 reported a JCP&L rate proceeding update. 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 25, 2003
reported the New Jersey Board of Public Utilities decision on JCP&L's rate
proceedings.
150
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of
1934, each Registrant has duly caused this report to be signed on its behalf by
the undersigned thereunto duly authorized.
August 18, 2003
FIRSTENERGY CORP.
-----------------
Registrant
OHIO EDISON COMPANY
-------------------
Registrant
THE CLEVELAND ELECTRIC
----------------------
ILLUMINATING COMPANY
--------------------
Registrant
THE TOLEDO EDISON COMPANY
-------------------------
Registrant
PENNSYLVANIA POWER COMPANY
--------------------------
Registrant
JERSEY CENTRAL POWER & LIGHT COMPANY
------------------------------------
Registrant
METROPOLITAN EDISON COMPANY
---------------------------
Registrant
PENNSYLVANIA ELECTRIC COMPANY
-----------------------------
Registrant
/s/ Harvey L. Wagner
----------------------------------
Harvey L. Wagner
Vice President, Controller
and Chief Accounting Officer
151