UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 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 NOVEMBER 13, 2003
----- -----------------------
FirstEnergy Corp., $.10 par value 329,836,276
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 Corp.
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,
the ability to access the public securities markets, further investigation into
the causes of the August 14, 2003 power outage and the outcome, cost and other
effects of present and potential legal and administrative proceedings and claims
related to that outage, a denial of or material change to the Company's
Application related to its Rate Stabilization Plan, and other factors discussed
from time to time in FirstEnergy's Securities and Exchange Commission filings,
including its annual report on Form 10-K (as amended) for the year ended
December 31, 2002, and under "Risk Factors" in the Prospectus Supplement dated
September 12, 2003 to the Prospectus dated August 29, 2003 (which was part of
the Registration Statement-File No. 333-103865) and other similar factors.
TABLE OF CONTENTS
Pages
Part I. Financial Information
Notes to Financial Statements................................... 1-22
FirstEnergy Corp.
Consolidated Statements of Income............................... 23
Consolidated Balance Sheets..................................... 24-25
Consolidated Statements of Cash Flows........................... 26
Report of Independent Accountants............................... 27
Management's Discussion and Analysis of Results of
Operations and Financial Condition............................ 28-51
Ohio Edison Company
Consolidated Statements of Income............................... 52
Consolidated Balance Sheets..................................... 53-54
Consolidated Statements of Cash Flows........................... 55
Report of Independent Accountants............................... 56
Management's Discussion and Analysis of Results of
Operations and Financial Condition............................ 57-65
The Cleveland Electric Illuminating Company
Consolidated Statements of Income............................... 66
Consolidated Balance Sheets..................................... 67-68
Consolidated Statements of Cash Flows........................... 69
Report of Independent Accountants............................... 70
Management's Discussion and Analysis of Results of
Operations and Financial Condition............................ 71-80
The Toledo Edison Company
Consolidated Statements of Income............................... 81
Consolidated Balance Sheets..................................... 82-83
Consolidated Statements of Cash Flows........................... 84
Report of Independent Accountants............................... 85
Management's Discussion and Analysis of Results of
Operations and Financial Condition............................ 86-94
Pennsylvania Power Company
Statements of Income............................................ 95
Balance Sheets.................................................. 96-97
Statements of Cash Flows........................................ 98
Report of Independent Accountants............................... 99
Management's Discussion and Analysis of Results of
Operations and Financial Condition............................ 100-106
Jersey Central Power & Light Company
Consolidated Statements of Income............................... 107
Consolidated Balance Sheets..................................... 108-109
Consolidated Statements of Cash Flows........................... 110
Report of Independent Accountants............................... 111
Management's Discussion and Analysis of Results of
Operations and Financial Condition............................ 112-120
TABLE OF CONTENTS (Cont'd)
Pages
Metropolitan Edison Company
Consolidated Statements of Income............................... 121
Consolidated Balance Sheets..................................... 122-123
Consolidated Statements of Cash Flows........................... 124
Report of Independent Accountants............................... 125
Management's Discussion and Analysis of Results of
Operations and Financial Condition............................ 126-134
Pennsylvania Electric Company
Consolidated Statements of Income............................... 135
Consolidated Balance Sheets..................................... 136-137
Consolidated Statements of Cash Flows........................... 138
Report of Independent Accountants............................... 139
Management's Discussion and Analysis of Results of
Operations and Financial Condition............................ 140-148
Quantitative and Qualitative Disclosures About Market Risk........... 149
Controls and Procedures.............................................. 149
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, and restated as discussed below.
FirstEnergy's and the Companies' independent accountants have
performed reviews of, and issued reports on, these consolidated interim
financial statements in accordance with standards established by the American
Institute of Certified Public Accountants. Pursuant to Rule 436(c) under the
Securities Act of 1933, their reports of those reviews should not be considered
a report within the meaning of Section 7 and 11 of that Act, and the independent
accountant's liability under Section 11 does not extend to them.
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.
1
Met-Ed and Penelec each formed statutory business trusts for the
issuance of $100 million each of preferred securities due 2039 and are included
in FirstEnergy's, Met-Ed's and Penelec's respective capitalizations. Ownership
of the respective Met-Ed and Penelec trusts is through separate wholly owned
limited partnerships, of which a wholly owned subsidiary of each company is the
sole general partner. In these transactions, the sole assets and sources of
revenues of each trust are the preferred securities of the applicable limited
partnership, whose sole assets are the 7.35% and 7.34% subordinated debentures
(aggregate principal amount of $103.1 million each) of Met-Ed and Penelec,
respectively. In each case, the applicable parent company has effectively
provided a full and unconditional guarantee of the trust's obligations under the
preferred securities.
The continued consolidation of the issuer trusts and the appropriate
balance sheet classification of trust preferred securities is currently under
review pursuant to FIN 46, "Consolidation of Variable Interest Entities - an
interpretation of ARB 51." Upon the implementation of FIN 46 effective December
31, 2003, these trusts would be deconsolidated if CEI, Met-Ed and Penelec were
not the primary beneficiaries of the related trusts. Such a deconsolidation
would result in FirstEnergy, CEI, Met-Ed and Penelec reflecting liabilities for
the subordinated notes payable to the respective trusts, which are currently
eliminated in consolidation. We currently classify the trust preferred
securities as long-term debt in our consolidated balance sheets. The
deconsolidation of the issuer trusts would result in an increase to total assets
and liabilities of $9.3 million ($3.1 million for each of CEI, Met-Ed and
Penelec) for the investment in the trusts.
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 Sheets. 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 under
New Jersey law 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. Due to the significance of the transfers, FirstEnergy
engaged its actuary to evaluate how to allocate 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.
2
Derivative Accounting
FirstEnergy is exposed to financial risks resulting from the
fluctuation of interest rates and commodity prices, including electricity,
natural gas and coal. To manage the volatility relating to these exposures,
FirstEnergy uses a variety of non-derivative and derivative instruments,
including forward contracts, options, futures contracts and swaps. The
derivatives are used principally for hedging purposes, and to a lesser extent,
for trading purposes. FirstEnergy's Risk Policy Committee, comprised of
executive officers, exercises an independent risk oversight function to ensure
compliance with corporate risk management policies and prudent risk management
practices.
FirstEnergy uses derivatives to hedge the risk of price and interest
rate fluctuations. FirstEnergy's primary ongoing hedging activity involves cash
flow hedges of electricity and natural gas purchases. The maximum periods over
which the variability of electricity and natural gas cash flows are hedged are
two and three years, respectively. Gains and losses from hedges of commodity
price risks are included in net income when the underlying hedged commodities
are delivered. Also, gains and losses are included in net income when
ineffectiveness occurs on certain natural gas hedges. FirstEnergy entered into
interest rate derivative transactions during 2001 to hedge a portion of the
anticipated interest payments on debt related to the GPU acquisition. Gains and
losses from hedges of anticipated interest payments on acquisition debt are
included in net income over the periods that hedged interest payments are made -
5, 10 and 30 years. Gains and losses from derivative contracts are included in
other operating expenses. The net deferred loss of $115.1 million included in
Accumulated Other Comprehensive Loss (AOCL) as of September 30, 2003, for
derivative hedging activity, as compared to the June 30, 2003 balance of $110.8
million in net deferred losses, resulted from an $8.2 million reduction related
to current hedging activity and a $12.5 million increase due to net hedge gains
included in earnings during the three months ended September 30, 2003.
Approximately $22.1 million (after tax) of the net deferred loss on derivative
instruments in AOCL as of September 30, 2003, is expected to be reclassified to
earnings during the next twelve months as hedged transactions occur. The fair
value of these derivative instruments will fluctuate from period to period based
on various market factors.
FirstEnergy periodically enters into fixed-to-floating interest rate
swap agreements 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 agreement consummated in the
third quarter of 2003 is based on a notional principal amount of $50 million. As
of September 30, 2003, the notional amount of FirstEnergy's fixed-for-floating
rate interest rate swaps totaled $600 million.
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 Statement of Financial
Accounting Standards (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), the goodwill is tested for impairment. When impairment is
indicated, FirstEnergy recognizes a loss - calculated as the difference between
the implied fair value of a reporting unit's goodwill and the carrying value of
the goodwill. FirstEnergy's annual review was completed in the third quarter of
2003. As a result of that review, a non-cash goodwill impairment charge of
$121.5 million was recognized in the third quarter of 2003, reducing the
carrying value of FSG. That charge reflects the continued slow down in the
development of competitive retail markets and depressed economic conditions that
affect the value of FSG. The fair value of FSG was estimated using primarily the
expected discounted future cash flows.The forecasts used in FirstEnergy's
evaluations of goodwill reflect operations consistent with its general business
assumptions. Unanticipated changes in those assumptions could have a significant
effect on FirstEnergy's future evaluations of goodwill. As of September 30,
2003, FirstEnergy had $6.1 billion of goodwill that primarily relates to its
regulated services segment. A summary of the changes in FirstEnergy's goodwill
for the nine months ended September 30, 2003 (which affected only the
Competitive Services Segment) is shown below:
In millions)
Balance at December 31, 2003............ $6,278.1
Impairment charges...................... (121.5)
FSG divestitures........................ (40.8)
Other................................... 12.1
--------
Balance at September 30, 2003........... $6,127.9
========
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
3
of September 30, 2003, FirstEnergy's AOCL was approximately $532.6 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 nine months ended
September 30, 2003 and 2002, is shown below:
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------ ---------------------
2003 2002 2003 2002
---- ---- ---- ----
Restated Restated
(see Note 1) (see Note 1)
(In thousands) (In thousands)
Net income............................. $152,719 $284,845 $313,333 $611,011
Other comprehensive income, net of tax:
Derivative hedge transactions........ (4,346) 16,373 (4,922) 52,752
Currency translations (1)............ (11) -- 91,450 1
Available for sale securities........ 5,880 (1,068) 44,148 (2,479)
-------- -------- -------- --------
Comprehensive income................... $154,242 $300,150 $444,009 $661,285
======== ======== ======== ========
(1) See Note 3 - International Operations (Emdersa Abandonment).
Stock-Based Compensation
FirstEnergy applies the recognition and measurement principles of
Accounting Principles Board Opinion (APB) No. 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.
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------- ---------------------
2003 2002 2003 2002
---- ---- ---- ----
Restated Restated
(see Note 1) (see Note 1)
(In thousands) (In thousands)
Net income, as reported................... $152,719 $284,845 $313,333 $611,011
Add back compensation expense
reported in net income, net of tax
(based on APB 25)....................... 40 39 131 126
Deduct compensation expense based
upon estimated fair value, net of tax... (3,138) (2,491) (9,314) (6,432)
--------------------------------------------------------------------------------------------------
Adjusted net income....................... $149,621 $282,393 $304,150 $604,705
--------------------------------------------------------------------------------------------------
Earnings Per Share of Common Stock -
Basic
As Reported.......................... $0.51 $0.97 $1.06 $2.08
Adjusted............................. $0.50 $0.96 $1.03 $2.06
Diluted
As Reported.......................... $0.51 $0.97 $1.05 $2.08
Adjusted............................. $0.50 $0.96 $1.02 $2.05
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
4
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 nine months ended
September 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 nine months ended September 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
================================================
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, the three and six months ended
June 30, 2002 and the three and nine months ended September 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 2002 of ceasing deferral accounting for certain energy
costs incurred in Pennsylvania (see Note 4). The impact of this restatement
increased net income in the first quarter of 2002 by $12 million and decreased
net income in the second quarter of 2002 by $8 million.
Transition Cost Amortization
As discussed under 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 allowed transition costs not in the
financial statements prepared under GAAP. The Ohio electric utilities have
revised the amortization schedules to consider only revenues relating to
transition regulatory assets recognized on the GAAP balance sheet. This change
results in higher amortization of these regulatory assets in the first several
years of the transition cost recovery period, compared with the method
previously applied (see summary by years included after the Above-Market Lease
Costs discussion). The following table summarizes the previously reported
transition cost amortization and the restated amounts under the revised method
for the three months and nine months ended September 30, 2002:
Three Months Ended Nine Months Ended
September 30, 2002 September 30, 2002
---------------------------- ----------------------------
As Previously As As Previously As
Reported Restated Reported Restated
------------- -------- ------------- --------
(In thousands)
OE............................ $76,019 $ 85,419 $227,221 $237,911
CEI........................... 7,967 37,907 32,763 111,743
TE............................ 11,632 29,812 25,848 77,628
------- -------- -------- --------
Total FirstEnergy......... $95,618 $153,138 $285,832 $427,282
======= ======== ======== ========
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 APB 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 SFAS 71 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 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.
FirstEnergy reflected the net impact of the accounting for these
items for the period from the merger in 1997 through 2001 in the 2002 financial
statements. The cumulative impact to net income recorded in 2002 related to
these prior periods increased net income by $5.9 million in the restated 2002
financial statements and was reflected as a reduction in other operating
expenses. In addition, the impact changed the following balances in the
consolidated balance sheet as of January 1, 2002:
Increase (Decrease) (In Thousands)
Goodwill.............................. $ 381,780
Regulatory assets..................... 636,100
----------
Total assets.......................... $1,017,880
==========
Other current liabilities............. 84,600
Deferred income taxes................. (262,580)
Deferred investment tax credits....... (828)
Other deferred credits................ 1,190,800
----------
Total liabilities..................... $1,011,992
==========
Retained earnings..................... $ 5,888
==========
The adjustments described above are anticipated to result in a
decrease in reported net income through 2005 and an increase in net income for
the period 2006 through 2017, the end of the lease term for Beaver Valley Unit
2. The schedule below shows the estimated impact on pre-tax income of these
adjustments for 2001 through 2009.
Above-Market Leases
------------------------------------------
Transition Cost Amortization Effect on
---------------------------- Goodwill Pre-Tax
Year Original Revised Change Amortization (a) Reversal Amortization Income
---- -------- ------- ------ ------------ -------- ------------ ------
2001-2002 $ 792 $ 947 $(155) $(170) $287 $(44) $(82)
2003 514 582 (68) (103) 85 (86)
2004 628 668 (40) (118) 85 (73)
2005 813 777 36 (136) 85 (16)
2006 328 295 33 (83) 85 35
2007 200 136 64 (77) 85 72
2008 213 107 106 (56) 85 135
2009 55 31 24 (12) 85 97
-------- -------- ------
$3,543 $3,543 $ --
====== ====== =======
(a) This represents the additional amortization related to the regulatory
assets recognized in connection with the above-market lease for the Bruce
Mansfield Plant discussed above.
6
The effects of these changes on the Consolidated Statements of Income
previously reported for the three months ended March 31, 2003, were disclosed in
Amendment No. 1 to FirstEnergy's, OE's, CEI's and TE's Quarterly Report on Form
10-Q/A for the quarter ended March 31, 2003. The effects of these changes on the
respective Consolidated Statements of Income previously reported for the three
months and nine months ended September 30, 2002 are as follows:
FirstEnergy
-----------
Three Months Ended Nine Months Ended
September 30, 2002 September 30, 2002
----------------------------- ----------------------------
As Previously As As Previously As
Reported Restated Reported Restated
------------- ---------- ------------- ----------
(In thousands, except per share amounts)
Revenues................................. $3,451,184 $3,451,184 $9,203,035 $9,203,035
Expenses ................................ 2,681,668 2,724,018 7,275,711 7,359,019
---------- ---------- ---------- ----------
Income before interest and income taxes . 769,516 727,166 1,927,324 1,844,016
Net interest charges..................... 220,397 220,397 749,401 749,401
Income taxes............................. 238,864 221,924 517,865 483,604
---------- ---------- ---------- ----------
Net income............................... $ 310,255 $ 284,845 $ 660,058 $ 611,011
========== ========== ========== ==========
Basic earnings per share of common
stock. ................................. $1.06 $.97 $2.25 $2.08
Diluted earnings per share of common
stock .................................. $1.05 $.97 $2.24 $2.08
OE
--
Three Months Ended Nine Months Ended
September 30, 2002 September 30, 2002
----------------------------- ----------------------------
As Previously As As Previously As
Reported Restated Reported Restated
------------- ---------- ------------- ----------
(In thousands)
Operating revenues....................... $ 813,296 $ 813,296 $2,265,645 $2,265,645
Operating expenses and taxes............. 658,794 664,518 1,875,475 1,876,036
---------- ---------- ---------- ----------
Operating income ........................ 154,502 148,778 390,170 389,609
Other income............................. 14,212 14,212 29,811 29,811
Net interest charges..................... 33,695 33,695 110,776 110,776
---------- ---------- ---------- ----------
Net income............................... 135,019 129,295 309,205 308,644
Preferred stock dividend requirements.... 658 658 5,851 5,851
---------- ---------- ---------- ----------
Earnings on common stock................. $ 134,361 $ 128,637 $ 303,354 $ 302,793
========== ========== ========== ==========
CEI
---
Three Months Ended Nine Months Ended
September 30, 2002 September 30, 2002
----------------------------- ----------------------------
As Previously As As Previously As
Reported Restated Reported Restated
------------- ---------- ------------- ----------
(In thousands)
Operating revenues....................... $ 538,879 $ 538,879 $1,426,730 $1,435,030
Operating expenses and taxes............. 410,387 418,967 1,130,162 1,150,518
---------- ---------- ---------- ----------
Operating income ........................ 128,492 119,912 296,568 284,512
Other income............................. 5,562 5,562 14,159 14,159
Net interest charges..................... 47,263 47,263 141,880 141,880
---------- ---------- ---------- ----------
Net income............................... 86,791 78,211 168,847 156,791
Preferred stock dividend requirements.... 3,149 3,149 14,459 12,759
---------- ---------- ---------- ----------
Earnings on common stock................. $ 83,642 $ 75,062 $ 154,388 $ 144,032
========== ========== ========== ==========
TE
--
Three Months Ended Nine Months Ended
September 30, 2002 September 30, 2002
----------------------------- ----------------------------
As Previously As As Previously As
Reported Restated Reported Restated
------------- ---------- ------------- ----------
(In thousands)
Operating revenues....................... $ 269,857 $ 269,857 $ 764,331 $ 772,731
Operating expenses and taxes............. 244,815 251,670 695,472 716,207
---------- ---------- ---------- ----------
Operating income ........................ 25,042 18,187 68,859 56,524
Other income............................. 4,033 4,033 12,119 12,119
Net interest charges..................... 14,463 14,463 44,031 44,031
---------- ---------- ---------- ----------
Net income............................... 14,612 7,757 36,947 24,612
Preferred stock dividend requirements.... 2,211 2,211 9,145 9,145
---------- ---------- ---------- ----------
Earnings on common stock................. $ 12,401 $ 5,546 $ 27,802 $ 15,467
========== ========== ========== ==========
7
The effects of these changes on the respective Consolidated
Statements of Cash Flows previously reported for the three months and nine
months ended September 30, 2002 are as follows:
FE
--
Three Months Ended Nine Months Ended
September 30, 2002 September 30, 2002
----------------------------- ----------------------------
As Previously As As Previously As
Reported Restated (1) Reported Restated (1)
------------- ---------- ------------- --------
(In thousands)
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income............................... $ 310,255 $ 284,845 $ 660,058 $ 611,011
Adjustments to reconcile net income
to net cash from operating activities:
Provision for depreciation and
amortization.......................... 253,917 310,417 767,450 920,196
Nuclear fuel and lease amortization...... 20,191 20,191 60,754 60,754
Other amortization....................... (5,381) (5,381) (13,304) (13,304)
Deferred costs recoverable as
regulatory assets ...................... (152,336) (145,336) (291,406) (291,406)
Deferred income taxes.................... 37,831 20,891 81,252 33,391
Investment tax credits................... (6,767) (6,767) (20,480) (20,480)
Cumulative effect of accounting change
(Note 5) ............................... -- -- (45,300) --
..........................................
Receivables.............................. (67,608) (67,608) (151,175) (157,670)
Materials and supplies................... (18,388) (18,388) (21,967) (21,967)
Accounts payable......................... 47,888 47,888 85,662 92,650
Accrued taxes............................ 16,687 16,687 103,407 103,407
Accrued interest......................... 79,063 79,063 59,507 59,507
Other.................................... 153,065 131,915 120,166 18,535
---------- ---------- ---------- ----------
Net cash provided from operating
activities .......................... $ 668,417 $ 668,417 $1,394,624 $1,394,624
---------- ---------- ---------- ----------
OE
--
Three Months Ended Nine Months Ended
September 30, 2002 September 30, 2002
----------------------------- ----------------------------
As Previously As As Previously As
Reported Restated (1) Reported Restated (1)
------------- ---------- ------------- --------
(In thousands)
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income............................... $ 135,019 $ 129,295 $ 309,205 $ 308,644
Adjustments to reconcile net income
to net cash from operating activities:
Provision for depreciation and
amortization ......................... 82,691 90,991 266,342 273,932
Nuclear fuel and lease amortization...... 12,389 12,389 35,924 35,924
Deferred income taxes.................... (9,782) (12,682) (31,838) (39,838)
Investment tax credits................... (3,751) (3,427) (11,286) (10,315)
Receivables.............................. (18,352) (18,352) 14,451 14,451
Materials and supplies................... (3,699) (3,699) (8,499) (8,499)
Accounts payable......................... 18,690 18,690 (771) (771)
Accrued taxes............................ 16,302 16,302 222,562 222,562
Other.................................... 44,883 44,883 39,240 39,240
---------- ---------- ---------- ----------
Net cash provided from operating
activities .......................... $ 274,390 $ 274,390 $ 835,330 $ 835,330
---------- ---------- ---------- ----------
8
CEI
---
Three Months Ended Nine Months Ended
September 30, 2002 September 30, 2002
----------------------------- ----------------------------
As Previously As As Previously As
Reported Restated (1) Reported Restated (1)
------------- ---------- ------------- ----------
(In thousands)
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income............................... $ 86,791 $ 78,211 $ 168,847 $ 156,791
Adjustments to reconcile net income
to net cash from operating activities:
Provision for depreciation and
amortization ......................... 17,846 47,646 74,650 153,250
Nuclear fuel and lease amortization...... 5,037 5,037 15,821 15,821
Other amortization....................... (3,937) (3,937) (12,104) (12,104)
Deferred income taxes.................... 6,812 736 19,912 3,582
Investment tax credits................... (1,015) (1,159) (3,046) (3,472)
Receivables.............................. 3,274 3,274 (28,383) (36,683)
Materials and supplies................... (1,786) (1,786) (4,992) (4,992)
Accounts payable......................... (23,141) (23,141) 3,238 3,238
Other.................................... 23,518 8,518 9,930 (31,558)
---------- ---------- ---------- ----------
Net cash provided from operating
activities .......................... $ 113,399 $ 113,399 $ 243,873 $ 243,873
---------- ---------- ---------- ----------
TE
--
Three Months Ended Nine Months Ended
September 30, 2002 September 30, 2002
----------------------------- ----------------------------
As Previously As As Previously As
Reported Restated (1) Reported Restated (1)
------------- ---------- ------------- ----------
(In thousands)
CASH FLOWS FROM OPERATING
ACTIVITIES
Net Income............................... $ 14,612 $ 7,757 $ 36,947 $ 24,612
Adjustments to reconcile net income
to net cash from operating activities:
Provision for depreciation and
amortization ......................... 23,413 41,813 64,529 116,929
Nuclear fuel and lease amortization...... 2,765 2,765 9,009 9,009
Deferred income taxes.................... (5,911) (11,266) (19) (14,346)
Investment tax credits................... (414) (454) (1,387) (1,507)
Receivables.............................. 22,359 22,359 23,619 15,219
Materials and supplies................... (2,150) (2,150) (3,970) (3,970)
Accounts payable......................... 26,894 26,894 20,545 18,845
Accrued sale leaseback costs............. 8,905 2,755 (19,549) (37,999)
Other.................................... 7,556 7,556 9,597 12,529
---------- ---------- ---------- ----------
Net cash provided from operating
activities .......................... $ 98,029 $ 98,029 $ 139,321 $ 139,321
---------- ---------- ---------- ----------
(1) The restated cash flow amounts included above in the three-month and
nine-month periods of 2002 do not reflect the changes in the current year
presentation included in the Consolidated Statements of Cash Flows.
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 $732
million (OE-$80 million, CEI-$102 million, TE-$62 million, Penn-$43 million,
JCP&L-$103 million, Met-Ed-$37 million, Penelec-$40 million, ATSI-$17 million,
FES-$163 million and other subsidiaries-$85 million) is applicable to 2003.
Investments for additional nuclear fuel during the 2003-2007 period are
estimated to be approximately $481 million (OE-$57 million, CEI-$42 million,
TE-$21 million, Penn-$38 million and FES-$323 million), of which approximately
$65 million (OE-$25 million, CEI-$14 million, TE-$9 million and Penn-$17
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 September 30, 2003, outstanding guarantees and other assurances aggregated
$1.036 billion.
9
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 $956.0 million as of September 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 $15.6 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 September 30, 2003, rating-contingent
collateralization totaled $64.2 million. FirstEnergy monitors these
collateralization provisions and updates its total exposure monthly.
Environmental Matters
Various federal, state and local authorities regulate the Companies
with regard to air and water quality and other environmental matters.
FirstEnergy estimates additional capital expenditures for environmental
compliance of approximately $159 million, which is included in the construction
forecast provided under "Capital Expenditures" for 2003 through 2007.
The Companies are required to meet federally approved sulfur dioxide
(SO2) regulations. Violations of such regulations can result in shutdown of the
generating unit involved and/or civil or criminal penalties of up to $31,500 for
each day the unit is in violation. The Environmental Protection Agency (EPA) has
an interim enforcement policy for SO2 regulations in Ohio that allows for
compliance based on a 30-day averaging period. The Companies cannot predict what
action the EPA may take in the future with respect to the interim enforcement
policy.
The Companies believe they are in compliance with the current SO2 and
nitrogen oxides (NOx) reduction requirements under the Clean Air Act Amendments
of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel,
generating more electricity from lower-emitting plants, and/or using emission
allowances. NOx reductions are being achieved through combustion controls and
the generation of more electricity at lower-emitting plants. In September 1998,
the EPA finalized regulations requiring additional NOx reductions from the
Companies' Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule
imposes uniform reductions of NOx emissions (an approximate 85% reduction in
utility plant NOx emissions from projected 2007 emissions) across a region of
nineteen states and the District of Columbia, including New Jersey, Ohio and
Pennsylvania, based on a conclusion that such NOx emissions are contributing
significantly to ozone pollution in the eastern United States. State
Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx
budgets established by the EPA. Pennsylvania submitted a SIP that required
compliance with the NOx budgets at the Companies' Pennsylvania facilities by May
1, 2003 and Ohio submitted a SIP that requires compliance with the NOx budgets
at the Companies' Ohio facilities by May 31, 2004.
In July 1997, the EPA promulgated changes in the National Ambient Air
Quality Standard (NAAQS) for ozone emissions and proposed a new NAAQS for
previously unregulated ultra-fine particulate matter. In May 1999, the U.S.
Court of Appeals for the D.C. Circuit found constitutional and other defects in
the new NAAQS rules. In February 2001, the U.S. Supreme Court upheld the new
NAAQS rules regulating ultra-fine particulates but found defects in the new
NAAQS rules for ozone and decided that the EPA must revise those rules. The
future cost of compliance with these regulations may be substantial and will
depend if and how they are ultimately implemented by the states in which the
Companies operate affected facilities.
In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a
Compliance Order to nine utilities covering 44 power plants, including the W. H.
Sammis Plant. In addition, the U.S. Department of Justice filed eight civil
complaints against various investor-owned utilities, which included a complaint
against OE and Penn in the U.S. District Court for the Southern District of
Ohio. The NOV and complaint allege violations of the Clean Air Act based on
operation and maintenance of the Sammis Plant dating back to 1984. The complaint
requests permanent injunctive relief to require the installation of "best
available control technology" and civil penalties of up to $27,500 per day of
violation. On August 7, 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
10
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 April 19, 2004, will address
civil penalties and what, if any, actions should be taken to further reduce
emissions at the plant. In the ruling, the Court indicated that the remedies it
"may consider and impose involved a much broader, equitable analysis, requiring
the Court to consider air quality, public health, economic impact, and
employment consequences. The Court may also consider the less than consistent
efforts of the EPA to apply and further enforce the Clean Air Act." The
potential penalties that may be imposed, as well as the capital expenditures
necessary to comply with substantive remedial measures that may be required,
could have a material adverse impact on the Company's financial condition and
results of operations. Management is unable to predict the ultimate outcome of
this matter and no liability has been recorded as of September 30, 2003.
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, environmental liabilities that are considered probable have been
recognized on the Consolidated Balance Sheet as of September 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 $50.4 million
(JCP&L-$47.9 million, CEI-$2.5 million, TE-$0.2 million, Met-Ed-$0.2 million and
Penelec-$0.2 million) as of September 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
was 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 $215 million as of September 30, 2003. FirstEnergy believes it has
met the obligation and has requested release from lenders. The banks' decision
is pending. The lenders include the Overseas Private Investment Corporation, US
Export Import Bank and a commercial bank syndicate. FirstEnergy has also
guaranteed the obligations of the operators of the TEBSA project, up to a
maximum of $6.0 million (subject to escalation) under the project's operations
and maintenance agreement. FirstEnergy provided the TEBSA project lenders a $50
million letter of credit (LOC) (under FirstEnergy's existing $250 million LOC
capacity available as part of a $1.5 billion FirstEnergy credit facility) to
obtain TEBSA lender consent as substitute collateral for the release of the
assets for FirstEnergy to abandon its Argentina operations, Emdersa (see Note 3
below).
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
11
determined. FirstEnergy continues to accumulate data and evaluate the status of
its electrical system prior to and during the outage event. On September 12,
2003, the U.S./Canada Power Outage Task Force (Task Force) investigating the
August 14 outage released a timeline of events. The timeline presented the
sequence of events that occurred on major transmission lines (230 kilovolts or
greater) and at large power plants beginning at approximately noon through
approximately 4:00 PM, preceding the outage. This timeline did not attempt to
present or explain the linkages between the sequence of events. Determining the
specific causes of the events and their relation to the outage will require more
time to analyze by the Task Force. The Task Force is expected to release its
interim report on November 18, 2003.
Legal Matters
As of October 14, 2003, ten individual shareholder-plaintiffs have
filed separate complaints against FirstEnergy alleging various securities law
violations. The bases for these complaints vary but include alleged violations
arising out of the power outage, the extended outage at Davis-Besse, and the
restatement of earnings, all described herein. FirstEnergy is 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. In addition, four shareholder-plaintiffs have filed "shareholder
derivative" actions against the members of the Board of Directors, and
FirstEnergy as a nominal defendant, asserting rights of the corporation itself.
The complaints allege violations of fiduciary duties as a result of, generally,
the same events described in the securities lawsuits described herein.
Furthermore, five lawsuits - three in Ohio state courts, two in New York state
courts - have been filed seeking damages relating to the August 14, 2003 power
outage. The two New York actions name FirstEnergy as one of several defendants
and have been noticed but not served. Additionally, a complaint has been filed
with the PUCO by United States Congressman Dennis Kucinich, alleging that as a
result of several events, including the August 14, 2003 power outage and the
extended outage at Davis-Besse, both described herein, the Company has failed to
provide adequate and reasonable service to its customers. That complaint asks,
among other things, that another electric supplier be authorized to provide
service within the Ohio Utilities' certified territories. FirstEnergy believes
that in each instance, the legal actions are without merit. FirstEnergy intends
to defend these actions vigorously, but cannot predict the outcome of any of
these proceedings or whether any further regulatory proceedings or legal actions
may be instituted against it. In particular, if FirstEnergy were ultimately
determined to have legal liability in connection with the outage, it could have
a material adverse effect on FirstEnergy's financial condition and results of
operations.
Various lawsuits, claims and proceedings related to FirstEnergy's
normal business operations are pending against it, the most significant of which
are described herein.
3 - DIVESTITURES:
INTERNATIONAL OPERATIONS-
FirstEnergy had identified certain former GPU international
operations for divestiture within one year of the merger. These operations
constitute individual "lines of business" as defined in APB Opinion (APB) No.
30, "Reporting the Results of Operations - Reporting the Effects of Disposal of
a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions," with physically and operationally separable
activities. Application of Emerging Issues Task Force (EITF) Issue No. 87-11,
"Allocation of Purchase Price to Assets to Be Sold," required that expected,
pre-sale cash flows, including incremental interest costs on related acquisition
debt, of these operations be considered part of the purchase price allocation.
Accordingly, subsequent to the merger date, results of operations and
incremental interest costs related to these international subsidiaries were not
included in FirstEnergy's 2001 Consolidated Statement of Income. Additionally,
assets and liabilities of these international operations had been segregated
under separate captions on the Consolidated Balance Sheet as of December 31,
2001 as "Assets Pending Sale" and "Liabilities Related to Assets Pending Sale."
Upon completion of its merger with GPU, FirstEnergy accepted an
October 2001 offer from Aquila, Inc. (formerly UtiliCorp United) to purchase
Avon, FirstEnergy's wholly owned holding company for Midlands Electricity plc,
for $2.1 billion (including the assumption of $1.7 billion of debt). The
transaction closed on May 8, 2002 and reflected the March 2002 modification of
Aquila's initial offer such that Aquila acquired a 79.9 percent equity interest
in Avon for approximately $1.9 billion (including the assumption of $1.7 billion
of debt). Proceeds to FirstEnergy included $155 million in cash and a note
receivable for approximately $87 million (representing the present value of $19
million per year to be received over six years beginning in 2003) from Aquila
for its 79.9 percent interest. FirstEnergy and Aquila together own all of the
outstanding shares of Avon through a jointly owned subsidiary, with each company
having an ownership voting interest. Originally, in accordance with applicable
accounting guidance, the earnings of those foreign operations were not
recognized in current 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
12
for the nine months ended September 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 nine-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 to reduce the
carrying value of its remaining 20.1 percent interest.
In the second quarter of 2003, FirstEnergy recognized 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 the secondary market and received $63.2
million in proceeds on July 28, 2003.
In May 2003, FirstEnergy reached an agreement to sell its 20.1
percent interest in Avon to Scottish and Southern Energy plc; subsequently, the
agreement was terminated when the parties were unable to agree to terms with
representatives of certain bondholders. On October 21, 2003, FirstEnergy
announced it reached an agreement to sell its 20.1 percent interest in Avon to a
subsidiary of Powergen UK plc, as part of a transaction to include Aquila's 79.9
percent interest. Under terms of the agreement, FirstEnergy would receive
approximately $8 million. The sale is contingent upon regulatory approval and
reaching agreement with bondholders representing 95% of the aggregate principal
amount of the bonds. The holders of approximately half of the outstanding bonds
have given their approval.
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 of 2003. FirstEnergy anticipates tax benefits of approximately $129
million, of which $50 million would increase net income in the period that it
becomes probable those benefits will be realized. The remaining $79 million of
tax benefits would reduce goodwill recognized in connection with the acquisition
of GPU.
SALE OF GENERATING ASSETS-
In November 2001, FirstEnergy reached an agreement to sell four
coal-fired power plants totaling 2,535 megawatts (MW) to NRG Energy Inc. On
August 8, 2002, FirstEnergy notified NRG that it was canceling the agreement
because NRG stated that it could not complete the transaction under the original
terms of the agreement. FirstEnergy also notified NRG that FirstEnergy reserves
the right to pursue legal action against NRG, its affiliate and its parent, Xcel
Energy for damages, based on the anticipatory breach of the agreement. In May
2003, NRG filed voluntary bankruptcy petitions in U.S. Bankruptcy Court in the
Southern District of New York. On November 13, 2003, FirstEnergy announced it
had reached an agreement for settlement of its claim against NRG, subject to
U.S. Bankruptcy Court approval and required authorization from the FERC. Under
NRG's proposed Plan of Reorganization, FirstEnergy, as an unsecured
13
creditor, could receive an estimated settlement of approximately $198 million,
with payment in the form of cash (12%), notes (15.2%) and new NRG common stock
(72.8%).
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:
o allowing the Companies' electric customers to select their generation
suppliers;
o establishing provider of last resort (PLR) obligations to customers
in the Companies' service areas;
o allowing recovery of potentially stranded investment (sometimes
referred to as transition costs);
o itemizing (unbundling) the current price of electricity into its
component elements - including generation, transmission, distribution
and stranded costs recovery charges;
o deregulating the Companies' electric generation businesses; and
o continuing regulation of the Companies' transmission and distribution
systems.
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 SFAS 71, "Accounting for the
Effects of Certain Types of Regulation" to OE's generation business and the
nonnuclear generation businesses of CEI and TE was discontinued with the
issuance of the PUCO transition plan order, as described further below. Major
provisions of the settlement agreement consisted of approval of recovery of
generation-related transition costs as filed of $4.0 billion net of deferred
income taxes (OE-$1.6 billion, CEI-$1.6 billion and TE-$0.8 billion) and
transition costs related to regulatory assets as filed of $2.9 billion net of
deferred income taxes (OE-$1.0 billion, CEI-$1.4 billion and TE-$0.5 billion),
with recovery through no later than 2006 for OE, mid-2007 for TE and 2008 for
CEI, except where a longer period of recovery is provided for in the settlement
agreement. The generation-related transition costs include $1.4 billion, net of
deferred income taxes, (OE-$1.0 billion, CEI-$0.2 billion and TE-$0.2 billion)
of impaired generating assets recognized as regulatory assets as described
further below, $2.4 billion, net of deferred income taxes, (OE-$1.2 billion,
CEI-$0.4 billion and TE-$0.8 billion) of above market operating lease costs and
$0.8 billion, net of deferred income taxes, (CEI-$0.5 billion and TE-$0.3
billion) of additional plant costs that were reflected on CEI's and TE's
regulatory financial statements.
Also as part of the settlement agreement, FirstEnergy is giving
preferred access over its subsidiaries to nonaffiliated marketers, brokers and
aggregators to 1,120 MW of generation capacity through 2005 at established
prices for sales to the Ohio Companies' retail customers. Customer prices are
frozen through the five-year market development period, which runs through the
end of 2005, except for certain limited statutory exceptions, including the 5%
reduction referred to above. In February 2003, the Ohio Companies were
authorized increases in annual revenues aggregating approximately $50 million
(OE-$41 million, CEI-$4 million and TE-$5 million) to recover their higher tax
costs resulting from the Ohio deregulation legislation.
FirstEnergy's Ohio customers choosing alternative suppliers receive
an additional incentive applied to the shopping credit (generation component) of
45% for residential customers, 30% for commercial customers and 15% for
industrial customers. The amount of the incentive is deferred for future
recovery from customers - recovery will be
14
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.
On October 21, 2003, the Ohio Companies filed an application with the
PUCO to establish generation service rates beginning January 1, 2006, in
response to expressed concerns by the PUCO about price and supply uncertainty
following the end of the market development period. The filing included two
options:
o A competitive auction, which would establish a price for
generation that customers would be charged during the period
covered by the auction, or
o A Rate Stabilization Plan, which would extend current generation
prices through 2008, ensuring adequate supply and continuing
FirstEnergy's support of energy efficiency and economic
development efforts.
Under the first option, an auction would be conducted to secure
generation service, including PLR responsibility, for FirstEnergy's Ohio
customers. Beginning in 2006, customers would pay market prices for generation
as determined by the auction.
Under the Rate Stabilization Plan option, customers would have price
and supply stability through 2008 - three years beyond the end of the market
development period - as well as the benefits of a competitive market. Customer
benefits would include: customer savings by extending the current five percent
discount on generation costs and other customer credits; maintaining current
distribution base rates through 2007; market-based auctions that may be
conducted annually to ensure that customers pay the lowest available prices;
extension of FirstEnergy's support of energy-efficiency programs and the
potential for continuing the program to give preferred access to nonaffiliated
entities to generation capacity as discussed above. In order to facilitate
supply planning, FirstEnergy has requested that the PUCO rule on this proposal
by December 31, 2003. Under the proposed plan, FirstEnergy is requesting:
o Extension of the transition cost amortization period for OE from
2006 to 2007; for CEI from 2008 to 2009 and for TE from mid-2007
to 2008;
o Deferral of new regulatory assets and deferral of interest costs
on the shopping incentive and other new deferrals;
o Ability to initiate a request to increase generation rates only
under certain limited conditions.
As a result of the Ohio Companies' October 21 filing, the PUCO
entered an order on October 28, 2003 setting forth the discovery schedule
related to the application with hearings scheduled to begin December 3, 2003.
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 September 30,
15
2003, the accumulated deferred cost balance totaled approximately $440 million,
after the charge discussed below. The NJBPU also allowed securitization of
JCP&L's deferred balance to the extent permitted by law upon application by
JCP&L and a determination by the NJBPU that the conditions of the New Jersey
restructuring legislation are met. There can be no assurance as to the extent,
if any, that the NJBPU will permit such securitization.
Under New Jersey transition legislation, all electric distribution
companies were required to file rate cases to determine the level of unbundled
rate components to become effective August 1, 2003. JCP&L 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
reduced JCP&L's annual revenues by approximately $62 million effective August 1,
2003. The NJBPU decision also provided for an interim return on equity of 9.5
percent on JCP&L's rate base for 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 net revenue decrease from the NJBPU's
decision consists of a $223 million decrease in the electricity delivery charge,
a $111 million increase due to the August 1, 2003 expiration of annual customer
credits previously mandated by the New Jersey transition legislation, a $49
million increase in the MTC tariff component, and a net $1 million increase in
the SBC charge. The MTC allows for the recovery of $465 million in deferred
energy costs over the next ten years on an interim basis, thus disallowing $153
million of the $618 million provided for in a preliminary settlement agreement
between certain parties. As a result, JCP&L recorded charges to net income for
the nine months ended September 30, 2003, aggregating $172 million ($103 million
net of tax) consisting of the $153 million deferred energy costs and other
regulatory assets. JCP&L filed a motion for rehearing and reconsideration with
the NJBPU on August 15, 2003 with respect to the following issues: (1) the
disallowance of the $153 million deferred energy costs; (2) the reduced rate of
return on equity; and (3) $42.7 million of disallowed costs to achieve merger
savings. On October 10, 2003, the NJBPU held the motion in abeyance until the
final NJBPU decision and order which is expected to be issued in the fourth
quarter of 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. FirstEnergy
established reserves in 2002 for Met-Ed's and Penelec's PLR deferred energy
costs which aggregated $287.1 million, reflecting the potential adverse impact
of the then pending Pennsylvania Supreme Court decision whether to review the
Commonwealth Court decision.
On April 2, 2003, the PPUC remanded the issue relating to merger
savings to the Office of Administrative Law for hearings, directed Met-Ed and
Penelec to file a position paper on the effect of the Commonwealth Court order
on the Settlement Stipulation and allowed other parties to file responses to the
position paper. Met-Ed and Penelec filed a letter with the Administrative Law
Judge on June 11, 2003, voiding the Stipulation in its entirety and reinstating
Met-Ed's and Penelec's restructuring settlement previously approved by the PPUC.
On October 2, 2003, the PPUC issued an order concluding that the
Commonwealth Court reversed the PPUC's June 20, 2001 order in its entirety. The
PPUC directed Met-Ed and Penelec to file tariffs within thirty days of the order
to reflect the competitive transition charge (CTC) rates and shopping credits
that were in effect prior to the June 21, 2001 order to be effective upon one
day's notice. In response to that order, Met-Ed and Penelec filed these
supplements to their tariffs to become effective October 24, 2003.
16
On October 8, 2003, Met-Ed and Penelec filed a petition for
clarification relating to the October 2, 2003 order on two issues: to establish
June 30, 2004 as the date to fully refund the NUG trust fund and to clarify that
the ordered accounting treatment regarding the CTC rate/shopping credit swap
should follow the ratemaking, and that the PPUC's findings would not impair
their rights to recover all of their stranded costs. On October 9, 2003, ARIPPA
(an intervenor in the proceedings) petitioned the PPUC to direct Met-Ed and
Penelec to reinstate accounting for the CTC rate/shopping credit swap
retroactive to January 1, 2002. Several other parties also filed petitions. On
October 16, 2003, the PPUC issued a reconsideration order granting the date
requested by Met-Ed and Penelec for the NUG trust fund refund; and, denying
Met-Ed's and Penelec's other clarification requests and granting ARIPPA's
petition with respect to the accounting treatment of the changes to the CTC
rate/shopping credit swap. On October 22, 2003, Met-Ed and Penelec filed an
Objection with the Commonwealth Court asking that the Court reverse the PPUC's
finding that requires Met-Ed and Penelec to treat the stipulated CTC rates that
were in effect from January 1, 2002 on a retroactive basis. Met-Ed and Penelec
are considering filing an appeal to the Commonwealth Court on the PPUC orders as
well.
On October 27, 2003, one Commonwealth Court judge issued an Order
denying Met-Ed's and Penelec's objection without explanation. Due to the
vagueness of the Order, Met-Ed and Penelec, on October 31, 2003, filed an
Application for Clarification with the judge. Concurrent with this filing,
Met-Ed and Penelec, in order to preserve their rights, also filed with the
Commonwealth Court both a Petition for Review of the PPUC's October 16 and 22
Orders, and an application for reargument, if the judge, in his clarification
order, indicates that Met-Ed's and Penelec's objection was intended to be denied
on the merits. In addition to these findings, Met-Ed and Penelec, in compliance
with the PPUC's Orders, filed revised quarterly reports for the twelve months
ended December 31, 2001 and 2002, and for the first two quarters of 2003,
reflecting balances consistent with the PPUC's findings in their Orders.
Effective September 1, 2002, Met-Ed and Penelec assigned their PLR
responsibility to their FES affiliate through a wholesale power sale agreement.
The PLR sale 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 power contracts with
nonaffiliated third party suppliers. This arrangement reduces Met-Ed's and
Penelec's exposure to high wholesale power prices by providing power at a fixed
price for their uncommitted PLR energy costs during the term of the agreement
with FES. FES has hedged most of Met-Ed's and Penelec's unfilled PLR on-peak
obligation through 2004 and a portion of 2005, the period during which deferred
accounting was previously allowed under the PPUC's order. Met-Ed and Penelec are
authorized to continue deferring differences between NUG contract costs and
current market prices.
5 - NEW ACCOUNTING STANDARDS ADOPTED:
SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity"
In May 2003, the FASB issued SFAS 150, which establishes standards
for how an issuer classifies and measures certain financial instruments with
characteristics of both liabilities and equity. In accordance with the standard,
certain financial instruments that embody obligations for the issuer are
required to be classified as liabilities. SFAS 150 was effective immediately for
financial instruments entered into or modified after May 31, 2003 and effective
at the beginning of the first interim period beginning after June 15, 2003
(FirstEnergy's third quarter of 2003) for all other financial instruments.
Upon adoption of SFAS 150, effective July 1, 2003, FirstEnergy
reclassified as debt the preferred stock of consolidated subsidiaries subject to
mandatory redemptions with a carrying value of approximately $17.5 million ($4.0
million for CEI and $13.5 million for Penn) as of September 30, 2003.
Subsidiary-obligated mandatorily redeemable preferred securities of $285 million
($100 million for CEI, $93 million for Met-Ed and $92 million for Penelec) were
also reclassified and included in long-term debt as of September 30, 2003. As
required by SFAS 150, the preferred securities subject to mandatory redemption
were not restated as long-term debt on the December 31, 2002 balance sheet.
Adoption of SFAS 150 had no impact on FirstEnergy's Consolidated
Statements of Income because the preferred dividends were previously included in
net interest charges and required no reclassification. Dividends on preferred
stock subject to mandatory redemption on CEI and Penn's respective Consolidated
Statements of Income, which were not included in net interest charges prior to
the adoption of SFAS 150, were included in net interest charges for the three
months ended September 30, 2003.
CEI, Met-Ed and Penelec created statutory business trusts to issue
the preferred securities of $285 million discussed above. The continued
consolidation of the issuer trusts and the appropriate balance sheet
classification of the trust preferred securities is currently under review
pursuant to FIN 46 (see Note 6). Upon the implementation of FIN 46 effective
December 31, 2003, these trusts would be deconsolidated if CEI, Met-Ed and
Penelec were not the primary beneficiaries of the related trusts. Rather than
recording a liability for the trust preferred securities as discussed above,
FirstEnergy, CEI, Met-Ed and Penelec would reflect liabilities for the notes
payable to the respective trusts, which are
17
currently eliminated in consolidation. The deconsolidation of the trusts would
result in an increase to total assets and liabilities of $9.3 million ($3.1
million for each of CEI, Met-Ed and Penelec) for the investment in the trusts.
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, that continue to be applied
based on their original effective dates. Adoption of SFAS 149 did not have a
material impact on the Companies' financial statements.
SFAS 143, "Accounting for Asset Retirement Obligations"
In January 2003, FirstEnergy implemented SFAS 143 which provides
accounting standards for retirement obligations associated with tangible
long-lived assets. This statement 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
$1.107 billion, including accumulated accretion for the period from the date the
liability was incurred to the date of adoption. As of December 31, 2002,
FirstEnergy had recorded decommissioning liabilities of $1.244 billion.
FirstEnergy expects substantially all 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 generating facilities with the remaining ARO related to the Bruce
Mansfield Plant's sludge impoundment facilities and two coal ash disposal sites.
The Companies maintain nuclear decommissioning trust funds, which had balances
as of September 30, 2003 of $1.230 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 third quarter and the first nine months of 2003.
Periods Ended September 30, 2003
----------------------------------
ARO Reconciliation Three Months Nine Months
---------------------------------------------------------------------------------------
(In millions)
Balance at beginning of period .................... $1,143 $1,107
Liabilities incurred in the current period......... -- --
Liabilities settled in the current period.......... -- --
Accretion expense.................................. 18 54
Revisions in estimated cash flows.................. -- --
------------------------------------------------------------------------------------
Balance at end of period........................... $1,161 $1,161
------------------------------------------------------------------------------------
The following table provides the year-end balance of the ARO related
to nuclear decommissioning and sludge impoundment for 2002, as if SFAS 143 had
been adopted on January 1, 2002.
Adjusted ARO Reconciliation
---------------------------------------------------------------------------
(In millions)
Beginning balance as of January 1, 2002......................... $1,042
Accretion 2002.................................................. 65
---------------------------------------------------------------------------
Ending balance as of December 31, 2002.......................... $1,107
---------------------------------------------------------------------------
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. 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 cost of removal related to non-regulated
generation assets 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 depreciation as of September
30, 2003 was approximately $314 million.
The following table provides the effect on income as if the
accounting for SFAS 143 had been applied during the third quarter and first nine
months of 2002.
Period Ended September 30, 2002
Effect of the Change in Accounting -------------------------------
Principle Applied Retroactively to 2002 Three Nine
--------------------------------------- Months Months
------ ------
(Restated - see Note 1)
(In millions)
Reported net income............................. $ 285 $ 611
----------------------------------------------------------------------------
Increase(Decrease):
Elimination of decommissioning expense.......... 26 78
Depreciation of asset retirement cost........... (1) (2)
Accretion of ARO liability...................... (10) (28)
Income tax effect............................... (6) (20)
----------------------------------------------------------------------------
Net earnings increase........................... 9 28
----------------------------------------------------------------------------
Net income adjusted............................. $ 294 $ 639
============================================================================
Basic earnings per share of common stock:
Net income as previously reported............... $0.97 $2.08
Adjustment for effect of change in
accounting principle applied retroactively.... .03 0.10
----------------------------------------------------------------------------
Net income adjusted............................. $1.00 $2.18
============================================================================
Diluted earnings per share of common stock:
Net income as previously reported............... $0.97 $2.08
Adjustment for effect of change in
accounting principle applied retroactively.... 0.03 0.09
----------------------------------------------------------------------------
Net income adjusted............................. $1.00 $2.17
============================================================================
EITF Issue No. 01-8, "Determining Whether an Arrangement Contains a
Lease"
In May 2003, the EITF reached a consensus regarding when arrangements
contain a lease. Based on the EITF consensus, an arrangement contains a lease
if: (1) it identifies specific property, plant or equipment (explicitly or
implicitly); and (2) the arrangement transfers the right to the purchaser to
control the use of the property, plant or equipment. The consensus is to be
applied prospectively to arrangements committed to, modified or acquired through
a business combination. The adoption of this consensus as of July 1, 2003 did
not impact FirstEnergy's financial statements.
EITF Issue No. 02-3, "Issues Involved in Accounting for Derivative
Contracts Held for Trading Purposes and Contracts Involved in Energy
Trading and Risk Management Activities"
In October 2002, the EITF reached a consensus that 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.
19
Three Months Ended Nine Months Ended
September 30, 2002 September 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.............. $3,572 $2,845 $9,414 $7,570
Adjustment................................ (121) (121) (211) (211)
------------------------------------------------------------------------------------------------
Total as currently reported............... $3,451 $2,724 $9,203 $7,359
===============================================================================================
6 - NEW ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED:
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". This Interpretation requires the
consolidation of a variable interest entity (VIE) by an enterprise if that
enterprise either absorbs a majority of the VIE's expected losses or receives a
majority of the VIE's expected residual returns as a result of ownership,
contractual or other financial interests in the VIE. Currently, entities are
generally consolidated by an enterprise that has a controlling financial
interest through ownership of a majority voting interest in the entity.
FIN 46 defines a VIE as an entity in which equity investors do not
have the characteristics of a controlling financial interest nor have sufficient
equity at risk for the entity to finance its activities without additional
subordinated financial support. VIE's created after January 31, 2003, are
immediately subject to the provisions of FIN 46. The FASB recently deferred
implementation of FIN 46 for VIE's created before February 1, 2003, until the
first reporting period ending after December 15, 2003 (FirstEnergy's quarter
ending December 31, 2003.)
FirstEnergy currently has transactions with entities in connection
with sale and leaseback arrangements which fall within the scope of this
interpretation and which meet the definition of a VIE in accordance with FIN 46.
In addition to the two entities created to refinance debt discussed below, the
Company is evaluating its interest in the owner trusts that acquired certain
interests in the Perry Plant, Beaver Valley Unit 2 and the Bruce Mansfield
Plant. The leases are accounted for as operating leases in accordance with GAAP.
The combined purchase price of $3.1 billion for all of the interests acquired by
the owner trusts in 1987 was funded with debt of $2.5 billion and equity of $600
million.
FirstEnergy is exposed to losses under the sale-leaseback agreements
upon the occurrence of certain contingent events that we consider unlikely to
occur. The Company's maximum exposure to loss is currently estimated to be $2.0
billion, which represents the net amount of casualty value payments upon the
occurrence of specified casualty events that render the plants worthless. Under
the sale and leaseback agreements, FirstEnergy has minimum undiscounted net
lease payments of $2.6 billion that would not be payable if the casualty value
payments are made. In addition, the Company has recorded above market lease
obligations of $1.1 billion related to the Bruce Mansfield Plant and Beaver
Valley Unit 2 as of September 30, 2003 (see Note 1) related to the acquisition
by FirstEnergy of CEI and TE.
FirstEnergy currently believes that it will consolidate two VIE's
created in 1996 and 1997 to refinance debt in connection with the above sale and
leaseback transactions. In 1996, the PNBV Capital Trust issued equity and notes
to fund the acquisition of a portion of the collateralized lease bonds that had
been issued by certain owner trusts in connection with the sale and leaseback in
1987 of a portion of OE's interest in the Perry Plant and Beaver Valley Unit 2.
OE used debt and available funds to purchase the notes issued by the PNBV Trust.
Ownership of the trust includes a three-percent equity interest by a
nonaffiliated third party and a three-percent equity interest held by OES
Ventures, a wholly owned subsidiary of OE. Consolidation of the trust as of
December 31, 2002 would have changed the PNBV trust investment of $389 million
to an investment in collateralized lease bonds of $401 million. The increase in
$12 million would have represented the minority interest in the total assets of
the trust.
In 1997, CEI and TE established the Shippingport Capital Trust to
purchase all of the lease obligation bonds issued by the owner trusts in the
Bruce Mansfield Plant sale and leaseback transactions. CEI and TE acquired all
of the notes issued by Shippingport Capital Trust. The equity ownership of this
trust includes a 0.34% interest held by Toledo Edison Capital Corporation
(TECC), a wholly owned subsidiary of TE, and a 2.25% interest and a 2.60%
interest held by unaffiliated third parties. The assets and liabilities of the
trust are currently included on a proportionate basis in the financial
statements of CEI and TE. Adoption of FIN 46 will not impact FirstEnergy with
respect to this trust, but may result in reporting all of the trust assets and
liabilities on the books of CEI.
As described in Note 1, the consolidated financial statements of
FirstEnergy, CEI, Met-Ed and Penelec currently include several trusts that have
sold trust preferred securities in which FirstEnergy is not the primary
beneficiary. Pending further guidance from the FASB that would indicate
otherwise, these entities may not be consolidated in FirstEnergy's financial
statements as of December 31, 2003. The deconsolidation would result in an
20
increase to total assets and liabilities of $9.3 million ($3.1 million for each
of CEI, Met-Ed and Penelec) for the investment in the trusts.
The FASB continues to provide additional guidance on implementing FIN
46 and recently proposed modifications and clarifications with a comment period
ending December 1, 2003. As this guidance is finalized, the Company will
continue to assess the accounting and disclosure impact of FIN 46 with respect
to the VIE's discussed above as well as other potential VIE's.
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 of a general index, such as the Consumer
Price Index, in a contract would prevent that contract from qualifying for the
normal purchases and normal sales (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 but does not anticipate any material impact
on its financial statements.
7 - 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 holding company 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.
21
Segment Financial Information
-----------------------------
Regulated Competitive Reconciling
Services Services Other Adjustments Consolidated
-------- -------- ----- ----------- ------------
(In millions)
Three Months Ended:
-------------------
September 30, 2003
------------------
External revenues............................ $ 2,532 $ 889 $ 24 $ (2)(a) $ 3,443
Internal revenues............................ 296 578 135 (1,009)(b) --
Total revenues............................ 2,828 1,467 159 (1,011) 3,443
Depreciation and amortization................ 312 9 11 -- 332
Net interest charges......................... 117 12 54 18 (b) 201
Income taxes................................. 206 (38) (36) -- 132
Income before discontinued
operations and cumulative effect
of accounting change ..................... 284 (77) (54) -- 153
Net income (loss)............................ 284 (77) (54) -- 153
Total assets................................. 29,794 2,324 1,377 -- 33,495
Total goodwill............................... 5,993 135 -- -- 6,128
Property additions........................... 63 88 5 -- 156
September 30, 2002 (Restated - see Note 1)
------------------------------------------
External revenues............................ $ 2,718 $ 712 $ 19 $ 2 (a) $ 3,451
Internal revenues............................ 261 662 116 (1,039)(b) --
Total revenues............................ 2,979 1,374 135 (1,037) 3,451
Depreciation and amortization................ 294 8 8 -- 310
Net interest charges......................... 141 17 76 (14)(b) 220
Income taxes................................. 265 (10) (33) -- 222
Net income (loss)............................ 358 (15) (58) -- 285
Total assets................................. 30,776 2,174 2,077 -- 35,027
Total goodwill............................... 5,878 280 (4) -- 6,154
Property additions........................... 150 69 56 -- 275
Nine Months Ended:
------------------
September 30, 2003
------------------
External revenues............................ $ 6,931 $2,494 $ 86 $ 29 (a) $ 9,540
Internal revenues............................ 794 1,650 406 (2,850)(b) --
Total revenues............................ 7,725 4,144 492 (2,821) 9,540
Depreciation and amortization................ 909 25 32 -- 966
Net interest charges......................... 374 33 263 (57)(b) 613
Income taxes................................. 440 (99) (97) -- 244
Income before discontinued operations and
cumulative effect of accounting change ... 607 (177) (158) -- 272
Net income (loss)............................ 708 (176) (219) -- 313
Total assets................................. 29,794 2,324 1,377 -- 33,495
Total goodwill............................... 5,993 135 -- -- 6,128
Property additions........................... 218 302 60 -- 580
September 30, 2002 (Restated - see Note 1)
------------------------------------------
External revenues............................ $ 6,982 $1,887 $ 320 $ 14 (a) $ 9,203
Internal revenues............................ 793 1,489 358 (2,640)(b) --
Total revenues............................ 7,775 3,376 678 (2,626) 9,203
Depreciation and amortization................ 867 21 32 -- 920
Net interest charges......................... 458 34 300 (43)(b) 749
Income taxes................................. 623 (47) (92) -- 484
Net income (loss)............................ 805 (68) (126) -- 611
Total assets................................. 30,776 2,174 2,077 -- 35,027
Total goodwill............................... 5,878 280 (4) -- 6,154
Property additions........................... 414 179 102 -- 695
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.
22
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------ -----------------------
2003 2002 2003 2002
---------- ---------- ---------- ----------
Restated Restated
(See Note 1) (See Note 1)
(In thousands, except per share amounts)
REVENUES:
Electric utilities..................................... $2,531,639 $2,717,461 $6,930,662 $6,981,753
Unregulated businesses................................. 911,746 733,723 2,609,625 2,221,282
---------- ---------- ---------- ----------
Total revenues..................................... 3,443,385 3,451,184 9,540,287 9,203,035
---------- ---------- ---------- ----------
EXPENSES:
Fuel and purchased power............................... 1,324,297 1,274,679 3,642,936 2,705,007
Purchased gas.......................................... 103,000 95,799 456,823 447,980
Other operating expenses............................... 898,507 866,273 2,705,407 2,791,892
Provision for depreciation and amortization............ 332,125 310,417 966,009 920,196
Goodwill impairment (Note 1)........................... 121,523 -- 121,523 --
General taxes.......................................... 177,499 176,850 518,823 493,944
---------- ---------- ---------- ----------
Total expenses..................................... 2,956,951 2,724,018 8,411,521 7,359,019
---------- ---------- ---------- ----------
INCOME BEFORE INTEREST AND INCOME TAXES................... 486,434 727,166 1,128,766 1,844,016
---------- ---------- ---------- ----------
NET INTEREST CHARGES:
Interest expense....................................... 199,418 212,477 599,738 704,724
Capitalized interest................................... (6,513) (6,303) (23,287) (18,722)
Subsidiaries' preferred stock dividends................ 8,021 14,223 36,423 63,399
---------- ---------- ---------- ----------
Net interest charges............................... 200,926 220,397 612,874 749,401
---------- ---------- ---------- ----------
INCOME TAXES.............................................. 132,789 221,924 244,211 483,604
---------- ---------- ---------- ----------
INCOME BEFORE DISCONTINUED OPERATIONS AND
CUMULATIVE EFFECT OF ACCOUNTING CHANGE................. 152,719 284,845 271,681 611,011
Discontinued operations (net of income taxes of
$3,700,000) (Note 3)................................. -- -- (60,495) --
Cumulative effect of accounting change (net of income
taxes of $72,516,000) (Note 5)....................... -- -- 102,147 --
---------- ---------- ---------- ----------
NET INCOME................................................ $ 152,719 $ 284,845 $ 313,333 $ 611,011
========== ========== ========== ==========
BASIC EARNINGS PER SHARE OF COMMON STOCK:
Income before discontinued operations and cumulative
effect of accounting change.......................... $ .51 $ .97 $ .92 $ 2.08
Discontinued operations (net of income taxes) (Note 3). -- -- (.21) --
Cumulative effect of accounting change (net of income
taxes)(Note 5)....................................... -- -- .35 --
----- ----- ------ ------
Net income......................................... $ .51 $ .97 $ 1.06 $ 2.08
===== ===== ====== ======
WEIGHTED AVERAGE NUMBER OF BASIC SHARES
OUTSTANDING............................................ 299,422 293,328 295,825 293,066
======= ======= ======= =======
DILUTED EARNINGS PER SHARE OF COMMON STOCK:
Income before discontinued operations and cumulative
effect of accounting change.......................... $ .51 $ .97 $ .91 $ 2.08
Discontinued operations (net of income taxes) (Note 3). -- -- (.21) --
Cumulative effect of accounting change (net of income
taxes)(Note 5)....................................... -- -- .35 --
----- ----- ------ ------
Net income......................................... $ .51 $ .97 $ 1.05 $ 2.08
===== ===== ====== ======
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES
OUTSTANDING............................................ 300,751 294,277 297,153 294,385
======= ======= ======= =======
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK.............. $.375 $.375 $1.125 $1.125
===== ===== ====== ======
The preceding Notes to Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements.
23
FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2003 2002
------------- ------------
(See Note 1)
(In thousands)
ASSETS
------
CURRENT ASSETS:
Cash and cash equivalents................................................. $ 178,911 $ 196,301
Receivables-
Customers (less accumulated provisions of $57,509,000 and $52,514,000
respectively, for uncollectible accounts)............................. 1,126,111 1,153,486
Other (less accumulated provisions of $7,651,000 and $12,851,000,
respectively, for uncollectible accounts)............................. 406,995 469,606
Materials and supplies, at average cost-
Owned................................................................... 282,403 253,047
Under consignment....................................................... 158,506 174,028
Prepayments and other..................................................... 203,078 203,630
----------- -----------
2,356,004 2,450,098
----------- -----------
PROPERTY, PLANT AND EQUIPMENT:
In service................................................................ 21,497,981 20,372,224
Less--Accumulated provision for depreciation.............................. 9,286,506 8,552,927
----------- -----------
12,211,475 11,819,297
Construction work in progress............................................. 699,180 859,016
----------- -----------
12,910,655 12,678,313
----------- -----------
INVESTMENTS:
Capital trust investments................................................. 993,688 1,079,435
Nuclear plant decommissioning trusts...................................... 1,230,356 1,049,560
Letter of credit collateralization........................................ 277,763 277,763
Other..................................................................... 939,974 918,874
----------- -----------
3,441,781 3,325,632
----------- -----------
DEFERRED CHARGES:
Regulatory assets......................................................... 7,798,768 8,753,401
Goodwill.................................................................. 6,127,853 6,278,072
Other..................................................................... 859,930 900,837
----------- -----------
14,786,551 15,932,310
----------- -----------
$33,494,991 $34,386,353
=========== ===========
24
FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2003 2002
------------- ------------
(See Note 1)
(In thousands)
CAPITALIZATION AND LIABILITIES
------------------------------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock...................... $ 1,576,882 $ 1,702,822
Short-term borrowings..................................................... 246,084 1,092,817
Accounts payable.......................................................... 722,156 906,468
Accrued taxes............................................................. 667,938 455,121
Lease market valuation liability.......................................... 84,600 84,600
Other..................................................................... 834,454 1,009,215
----------- -----------
4,132,114 5,251,043
----------- -----------
CAPITALIZATION:
Common stockholders' equity-
Common stock, $.10 par value, authorized 375,000,000 shares -
329,836,276 and 297,636,276, shares outstanding, respectively......... 32,984 29,764
Other paid-in capital................................................... 7,055,651 6,120,341
Accumulated other comprehensive loss.................................... (532,560) (656,148)
Retained earnings....................................................... 1,617,499 1,634,981
Unallocated employee stock ownership plan common stock -
3,106,709 and 3,966,269 shares, respectively.......................... (62,142) (78,277)
----------- -----------
Total common stockholders' equity................................... 8,111,432 7,050,661
Preferred stock of consolidated subsidiaries-
Not subject to mandatory redemption..................................... 335,123 335,123
Subject to mandatory redemption (Note 5)................................ -- 18,521
Subsidiary-obligated mandatorily redeemable preferred securities
(Note 5)..... .......................................................... -- 409,867
Long-term debt and other long-term obligations-
Preferred stock of consolidated subsidiaries subject to mandatory
redemption (Note 5) .................................................. 17,516 --
Subsidiary-obligated mandatorily redeemable preferred securities
(Note 5)... .......................................................... 284,940 --
Other................................................................... 10,396,512 10,872,216
----------- -----------
19,145,523 18,686,388
----------- -----------
DEFERRED CREDITS:
Accumulated deferred income taxes......................................... 1,986,721 2,069,682
Accumulated deferred investment tax credits............................... 217,934 236,184
Asset retirement obligations.............................................. 1,161,145 --
Nuclear plant decommissioning costs....................................... -- 1,243,558
Power purchase contract loss liability.................................... 2,905,347 3,136,538
Retirement benefits....................................................... 1,806,632 1,564,930
Lease market valuation liability.......................................... 1,042,450 1,106,000
Other..................................................................... 1,097,125 1,092,030
----------- -----------
10,217,354 10,448,922
----------- -----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)...........................
----------- -----------
$33,494,991 $34,386,353
=========== ===========
The preceding Notes to Financial Statements as they relate to FirstEnergy Corp.
are an integral part of these balance sheets.
25
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------ -------------------------
2003 2002 2003 2002
---------- ---------- ----------- -----------
Restated Restated
(See Note 1) (See Note 1)
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................ $ 152,719 $ 284,845 $ 313,333 $ 611,011
Adjustments to reconcile net income to net cash from
operating activities-
Provision for depreciation and amortization........ 332,125 310,417 966,009 920,196
Nuclear fuel and capital lease amortization........ 16,902 20,191 47,398 60,754
Deferred costs recoverable as regulatory assets.... (32,650) (145,336) (142,340) (291,406)
Goodwill impairment................................ 121,523 -- 121,523 --
Deferred operating lease costs, net................ (6,401) 10,443 (86,363) (88,049)
Deferred income taxes, net......................... (42,433) 34,491 (63,987) 33,391
Amortization of investment tax credits............. (7,349) (6,767) (19,855) (20,480)
Accrued retirement benefit obligations............. 81,819 24,941 229,172 54,216
Accrued compensation, net.......................... (1,812) (14,070) (50,246) (87,943)
Revenue credits to customers....................... (19,583) (17,434) (71,984) (17,434)
Disallowed purchased power costs................... -- -- 152,500 --
Discontinued operations............................ -- -- 60,495 --
Cumulative effect of accounting change............. -- -- (174,663) --
Other amortization and accruals, net............... (9,540) (3,937) (6,244) (12,104)
Tax refund related to pre-merger period............ -- -- 51,073 --
Energy derivative transactions, net................ (34,939) (19,105) (31,137) (4,136)
Receivables........................................ 104,516 (61,113) 43,959 (157,670)
Materials and supplies............................. 19,708 (18,388) (14,276) (21,967)
Accounts payable................................... (136,271) 40,900 (171,314) 92,650
Accrued taxes...................................... 188,261 16,687 210,115 103,407
Accrued interest................................... 68,669 79,063 52,991 59,507
Prepayments and other current assets............... 109,687 113,841 (10,871) 94,455
Other.............................................. (9,224) 18,748 (25,568) 66,226
---------- ---------- ----------- -----------
Net cash provided from operating activities...... 895,727 668,417 1,379,720 1,394,624
---------- ---------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Common stock......................................... 934,605 -- 934,605 --
Long-term debt....................................... -- 317,890 981,637 684,620
Short-term borrowings, net........................... -- 508,720 -- 539,271
Redemptions and Repayments-
Preferred stock...................................... (1,000) (313,517) (126,337) (503,816)
Long-term debt....................................... (569,273) (871,608) (1,547,205) (1,250,251)
Short-term borrowings, net........................... (798,985) -- (846,734) --
Common stock dividend payments......................... (110,373) (109,963) (330,816) (329,565)
---------- ---------- ----------- -----------
Net cash used for financing activities........... (545,026) (468,478) (934,850) (859,741)
---------- ---------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions..................................... (155,908) (274,923) (580,069) (694,614)
Proceeds from sale of assets........................... 1,081 -- 67,530 155,034
Proceeds from note receivable.......................... -- -- 19,000 --
Avon cash and cash equivalents (Note 3)................ -- -- -- 31,326
Proceeds from nonutility generation trusts............. -- -- 106,327 34,208
Cash investments....................................... 31,696 (4,310) 46,761 59,712
Contributions to nuclear decommissioning trusts........ (47,622) (24,951) (75,873) (78,099)
Debt remarketing investments .......................... (73,231) -- (73,231) --
Other.................................................. 7,990 25,742 27,295 17,919
---------- ----------- ----------- -----------
Net cash used for investing activities........... (235,994) (278,442) (462,260) (474,514)
---------- ---------- ----------- -----------
Net increase (decrease) in cash and cash equivalents...... 114,707 (78,503) (17,390) 60,369
Cash and cash equivalents at beginning of period.......... 64,204 359,050 196,301 220,178
---------- ---------- ----------- -----------
Cash and cash equivalents at end of period................ $ 178,911 $ 280,547 $ 178,911 $ 280,547
========== ========== =========== ===========
The preceding Notes to Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements.
26
REPORT OF INDEPENDENT ACCOUNTANTS
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 September 30, 2003, and the related
consolidated statements of income and cash flows for each of the three-month and
nine-month periods ended September 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 each of the three-month and nine-month periods ended September
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
November 13, 2003
27
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 AND RECLASSIFICATIONS
As further discussed in Note 1 to the Consolidated Financial
Statements, FirstEnergy restated its consolidated financial statements for the
year ended December 31, 2002 and the three months ended March 31, 2003 to
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. These restatements were completed and reported in the
second quarter of 2003 together with reclassifications discussed in Note 3 to
the Consolidated Financial Statements. Financial comparisons described below for
the three-month and nine-month periods reflect the effect of these restatements
and reclassifications of 2002 financial results.
RESULTS OF OPERATIONS
FirstEnergy reported net income in the third quarter of 2003 of
$152.7 million, or $0.51 per share of common stock (basic and diluted), compared
to net income of $284.8 million, or $0.97 per share of common stock (basic and
diluted) in the third quarter of 2002. During the first nine months of 2003, net
income was $313.3 million, or basic earnings of $1.06 per share of common stock
($1.05 diluted), compared to net income of $611.0 million, or $2.08 per share of
common stock (basic and diluted) in the first nine months of 2002. Income before
discontinued operations and the cumulative effect of an accounting change was
$152.7 million, or $0.51 per share of common stock (basic and diluted) in the
third quarter of 2003 and $271.7 million, or basic earnings of $0.92 per share
of common stock ($0.91 diluted) in the first nine months of 2003.
Results for the third quarter and nine-month period in 2003 included
an after-tax goodwill impairment of $80.9 million, or $0.27 per share of common
stock (basic and diluted) for both periods. Net income for the first nine months
of 2003 also 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."
Results for the third quarter of 2003 compared to the third quarter
of 2002 were adversely affected by milder weather which reduced revenues.
Purchased power costs, storm damage, employee benefit expenses and nuclear
refueling costs all contributed to increased third quarter expenses, compared to
the same quarter last year. In addition, FirstEnergy recorded a non-cash charge
of $121.5 million ($80.9 million, net of tax) for goodwill impairment in the
third quarter of 2003. In the first nine months of 2003, expenses increased
compared to the same period of 2002 due to: purchased power costs, nuclear
expenses related to the extended outage at the Davis-Besse Nuclear Power Station
(see Outlook-Davis-Besse Restoration), additional unplanned work performed
during two scheduled nuclear refueling outages in the second quarter of 2003 and
increased employee benefit expenses. However, the absence in the first nine
months of 2003 of unusual charges incurred in the corresponding period of 2002
partially offset the cost increases in 2003. The 2003 year-to-date period
included $171.6 million of pre-tax charges for costs disallowed in the JCP&L
rate case decision (see State Regulatory Matters - New Jersey).
28
Revenues
Total revenues decreased $7.8 million in the third quarter of 2003,
compared to the same period last year, due to lower retail and wholesale
regulated electric sales. Increased revenues from competitive services,
primarily electric sales to wholesale customers, partially offset the decrease
in regulated electric retail revenues in the third quarter of 2003. In the first
nine months of 2003, revenues increased $337.3 million compared to the same
period of 2002 from increased competitive sales, offset in part by reduced
regulated revenues and lower international sales reflecting the partial sale of
Avon Energy Partners Holdings. Sources of changes in revenues during the third
quarter and first nine months of 2003 compared to the corresponding periods of
2002 are summarized in the following table:
Sources of Revenue Changes Three Months Nine Months
---------------------------------------------------------------------------
Increase (Decrease) (In millions)
Electric Utilities (Regulated Services):
Retail electric sales................. $(118.9) $(161.9)
Wholesale electric sales ............. (75.8) 105.1
All other revenues.................... 8.9 5.7
-----------------------------------------------------------------------
Total Electric Utilities................. (185.8) (51.1)
-----------------------------------------------------------------------
Unregulated Businesses (Competitive Services):
Retail electric sales................. 62.4 177.4
Wholesale electric sales.............. 184.5 612.0
Gas sales............................. 9.7 21.5
FSG................................... (57.4) (151.3)
MYR................................... (20.1) (73.3)
Other................................. (2.7) 21.1
-----------------------------------------------------------------------
Total Unregulated Businesses............. 176.4 607.4
-----------------------------------------------------------------------
International............................ 2.3 (241.1)
Other.................................... (0.7) 22.1
-----------------------------------------------------------------------
Net Change in Revenue.................... $ (7.8) $ 337.3
=======================================================================
Electric Sales
Retail sales by FirstEnergy's electric utility operating companies
(EUOC) decreased by $118.9 million in the third quarter of 2003 and by $161.9
million in the first nine months of 2003 from the corresponding periods of 2002.
Changes in electric generation kilowatt-hour sales and distribution
deliveries in the third quarter and first nine months of 2003 from the same
periods of 2002 are summarized in the following table:
Changes in Kilowatt-hour Sales Three Months Nine Months
-----------------------------------------------------------------------
Increase (Decrease)
Electric Generation Sales:
Retail -
Regulated services................. (11.4)% (6.9)%
Competitive services............... 37.6% 66.0%
Wholesale............................ 17.9% 71.2%
--------------------------------------------------------------------
Total Electric Generation Sales........ 0.5% 14.0%
====================================================================
EUOC Distribution Deliveries:
Residential.......................... (7.1)% 0.6%
Commercial........................... (4.1)% 1.9%
Industrial........................... (2.7)% (1.4)%
---------------------------------------------------------------------
Total Distribution Deliveries.......... (4.7)% 0.3%
====================================================================
Reduced air-conditioning load due to cooler summer temperatures in
2003 from the prior year, a sluggish but improving economy and increased sales
by alternative suppliers all combined to decrease regulated retail generation
sales revenue by $55.5 million in the third quarter of 2003 compared to the same
quarter of 2002. These factors also accounted for most of the $168.2 million
decrease in retail generation sales revenue in the first nine months of 2003
compared to the same period last year. Kilowatt-hour sales of electricity by
alternative suppliers in FirstEnergy's franchise areas increased by
approximately six percentage points in the three months and nine months ended
September 30, 2003, from the corresponding periods last year.
29
Revenues from distribution deliveries decreased by $56.5 million or
3.8% in the third quarter of 2003 compared to the third quarter of 2002 due in
part to mild weather in the third quarter of 2003 after unusually hot weather in
the same period last year which reduced the air-conditioning load of residential
and commercial customers. Weather also contributed to the $38.0 million, or 1.0%
increase in distribution deliveries to residential and commercial customers in
the first nine months of 2003 from the same period last year due to colder
temperatures in the first three months of 2003 from same period last year,
adding to heating-related loads. Sluggish economic conditions in the third
quarter and first nine months 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 - $6.9 million of additional credits in the
third quarter and $31.7 million of additional credits in the first nine months
of 2003 compared to the same periods in 2002. These additional credits 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 decreased by $75.8 million in the
third quarter of 2003 from the same period last year due to milder summer
weather in 2003. Sales to the wholesale market increased $105.1 million in the
first nine months of 2003 compared to the first nine months of 2002 primarily
due to 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 power under contracts existing as of August
2002, including energy provided by non-utility generation (NUG) contracts, into
the wholesale market.
Electric generation sales by FirstEnergy's competitive segment
increased $246.9 million in the third quarter and $789.4 million in the first
nine months of 2003 from the corresponding periods of 2002, primarily from
additional sales to the wholesale market ($184.5 million in the third quarter
and $612.0 million in the first nine months of 2003). The increases resulted in
part from sales in New Jersey as FES began supplying a portion of that state's
BGS in September 2002. Retail sales by FirstEnergy's competitive services
segment increased by $62.4 million in the third quarter and $177.4 million in
the first nine 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 and from growth
in competitive retail sales outside FirstEnergy's franchise areas.
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 nine months
ended September 30, 2003 and 2002 are summarized as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------------
2003 2002 2003 2002
-------------------------------------------------------------------
(In millions)
Sales.............. $465 $189 $1,009 $256
Purchases.......... 288 382 866 579
------------------------------------------------------------------
FirstEnergy's revenues on its 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 $70.5 million in the third quarter and $182.0 million in the first
nine 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 $9.7 million and $21.5 million higher in the third
quarter and year-to-date periods compared to the corresponding periods last
year. The increase in gas sales in the third quarter and first nine month of
2003 reflected increased prices which more than offset lower gas volumes
delivered as FES focused its operations in a narrower geographic area and on
higher-margin gas customers.
30
International Revenues
International revenues declined $241.1 million in the first nine
months of 2003 from the same period last year due to the sale of a 79.9%
interest in Avon during the second quarter of 2002 and abandonment of Emdersa in
the second quarter of 2003 (see Discontinued Operations below). As a result of
these transactions, FirstEnergy has substantially divested all of GPU Capital's
international operations acquired in the 2001 GPU merger.
Expenses
Total expenses increased $232.9 million in the third quarter and
$1,052.5 million in the first nine months of 2003 from the same periods of 2002.
Sources of changes in expenses in the third quarter and first nine months of
2003 compared to the corresponding periods of 2002 are summarized in the
following table:
Sources of Expense Changes Three Months Nine Months
----------------------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel and purchased power.............. $ 49.6 $ 937.9
Purchased gas......................... 7.2 8.9
Other operating expenses.............. 32.2 (86.5)
Depreciation and amortization......... 21.7 45.8
Goodwill Impairment................... 121.5 121.5
General taxes......................... 0.7 24.9
--------------------------------------------------------------------------
Net Increase in Expenses................ $232.9 $1,052.5
==========================================================================
Higher purchased power costs accounted for $58.2 of the increase in
expenses in the third quarter of 2003 and most of the increase ($968.6 million)
in the first nine months of 2003 compared to the same periods of 2002. Higher
unit costs contributed to increased purchased power costs in the third quarter
and first nine months of 2003 from the corresponding periods last year.
Additional quantities purchased also contributed significantly to the increased
purchase power costs in the first nine months of 2003 from the prior year.
Increased volumes were required to supply obligations assumed by FES for BGS
sales, as well as other wholesale commitments, and additional supplies required
to replace reduced nuclear generation. Results for the nine-month period include
$152.5 million of purchased power costs disallowed in the JCP&L rate case
decision (see State Regulatory Matters - New Jersey). The combined effect of one
additional refueling outage in 2003 compared to 2002, additional work performed
in 2003 during the refueling outages at the Perry Plant and Beaver Valley Unit 1
and the extended Davis-Besse outage, reduced nuclear generation by 5.7% in the
third quarter and 18.4% in the first nine months of 2003 from the corresponding
periods last year. Fuel expenses were $8.6 million and $30.7 million lower in
the third quarter and first nine months of 2003, respectively, from the same
periods of 2002, primarily reflecting reduced generation. Purchased gas costs
increased by $7.2 million in the third quarter and $8.9 million in the first
nine months of 2003 compared to the same periods of 2002 due to higher unit
costs, partially offset by lower volumes purchased to meet reduced gas
deliveries.
Other operating expenses increased $32.2 million in the third quarter
of 2003, compared to the same period of 2002, due to higher energy delivery
costs of $52.5 million (primarily due to storm restoration expenses and an
accelerated reliability plan within JCP&L's service territory), increased
pension and benefit costs (see Employee Benefit Plan Costs below) and additional
nuclear operating costs ($27.2 million) associated with a refueling outage at
Beaver Valley Unit 2 - completed on October 12, 2003. There were no nuclear
refueling outages in the third quarter of 2002. Partially offsetting these
increases were reduced costs from domestic energy-related businesses ($69.1
million) and reduced costs at the Davis-Besse nuclear plant related to its
extended outage as the plant approaches a return to operation (see
Outlook-Davis-Besse Restoration below). The reduced volume of energy-related
business reflects the sale in early 2003 of Colonial Mechanical and Webb
Technologies businesses and lower business volumes associated with weak economic
conditions.
In the first nine months of 2003, other operating expenses decreased
$86.5 million from the same period last year as a result of several factors.
Reduced business volumes and the sale of Colonial and Webb reduced expenses from
domestic energy-related businesses by $212.0 million, while the sale of Avon and
divestiture of Emdersa resulted in a $95.3 million reduction in expense from
international operations. The absence of unusual charges recognized in the first
nine months of 2002 resulted in a further net reduction of other operating
expenses ($70.7 million) from the corresponding period last year. Offsetting a
portion of these lower expenses in the first nine months of 2003 were increased
nuclear costs ($93.0 million) resulting from the extended Davis-Besse outage,
additional work performed during refueling outages in the second quarter of 2003
and three refueling outages in the first nine months of 2003 versus two in 2002.
Administrative and general costs increased $172.6 million principally reflecting
increased employee benefit costs. Energy delivery costs increased $51.5 million
primarily as a result of storm damage and an accelerated reliability plan within
JCP&L's service territory.
31
Charges for depreciation and amortization increased by $21.7 million
in the third quarter of 2003 compared to the corresponding three-month period of
2002. The higher charges primarily resulted from three factors - increased
amortization of the Ohio transition regulatory assets ($22.7 million),
recognition of depreciation on four power plants ($11.7 million) which had been
held pending sale in the third quarter of 2002, but were subsequently retained
by FirstEnergy in the fourth quarter of 2002, and reduced regulatory asset
deferrals in 2003 ($12.2 million). Partially offsetting these increases in
depreciation and amortization were higher shopping incentive deferrals in Ohio
($6.9 million), lower charges resulting from the implementation of SFAS 143
($12.7 million) and revised service life assumptions for generating plants ($7.4
million).
In the first nine months of 2003, depreciation and amortization
increased $45.8 million primarily as a result of the same factors which
influenced the third quarter comparison - increased amortization of the Ohio
transition regulatory assets ($64.8 million), recognition of depreciation on
four power plants ($31.2 million) previously held pending sale in the first nine
months of 2002, reduced regulatory asset deferrals in 2003 ($27.2 million) and
costs of $19.1 million disallowed in the JCP&L rate case decision. Partially
offsetting these increases in depreciation and amortization were higher shopping
incentive deferrals in Ohio ($31.7 million), lower charges resulting from the
implementation of SFAS 143 ($41.1 million) and revised service life assumptions
for generating plants ($20.0 million).
A non-cash goodwill impairment charge of $121.5 million ($80.9
million, net of tax) was recognized in the third quarter of 2003 reducing the
carrying value of FSG. This charge reflects the continued slow down in the
development of competitive retail markets and depressed economic conditions that
affect the value of FSG.
General taxes increased $24.9 million in the first nine months of
2003 compared to the same period last year. Higher payroll and kilowatt-hour
taxes in 2003 and a $9 million energy assessment credit adjustment that reduced
general taxes in the first nine months of 2002 were the principal factors
contributing to the increase.
Net Interest Charges
Net interest charges decreased $19.5 million in the third quarter and
$136.5 million in the first nine 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 nine months of 2003 totaled $656 million
and $850 million (including $227 million of pollution control note repricings),
respectively, and are expected to result in annualized interest charge savings
of approximately $68 million. Partially offsetting these savings are interest
charges on additional borrowings under revolving bank credit facilities.
FirstEnergy also exchanged existing fixed-rate interest payments on
outstanding debt (principal amount of $600 million as of September 30, 2003) for
short-term variable rate interest payments through interest rate swap
transactions (see Market Risk Information - Interest Rate Swap Agreements
below). Net interest charges were reduced by $5.2 million in the third quarter
and $19.8 million in the first nine months of 2003, compared to the
corresponding periods of 2002 as a result of the lower variable rates paid under
these agreements.
Discontinued Operations
On April 18, 2003, FirstEnergy divested its ownership in Emdersa. The
abandonment was accomplished by relinquishing FirstEnergy's shares of Emdersa's
parent company, GPU Argentina Holdings, to that company's independent Board of
Directors, relieving FirstEnergy of all rights and obligations relative to this
business. As a result of this action, FirstEnergy's gains and losses related to
discontinuing these operations have been presented as a separate item on the
Consolidated Statements of Income - "Discontinued operations" - in accordance
with SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets."
Due to the abandonment, FirstEnergy recognized a one-time, non-cash charge of
$67.4 million in the second quarter of 2003. This charge resulted from realizing
$89.8 million of currency translation losses through current period earnings,
partially offset by a $22.4 million gain recognized from eliminating
FirstEnergy's investment in Emdersa. Discontinued operations for the nine-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 acquired in the 2001 GPU merger.
Cumulative Effect of Accounting Change
Results for the first nine 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 $1.107 billion, including accumulated accretion for the
period from the date the liability was incurred to the date of
32
adoption. As of December 31, 2002, FirstEnergy had recorded decommissioning
liabilities of $1.244 billion. FirstEnergy expects substantially all of its
nuclear decommissioning costs for Met-Ed, Penelec, JCP&L and Penn to be
recoverable in rates over time. Therefore, FirstEnergy recognized a regulatory
liability of $185 million upon adoption of SFAS 143 for the transition amounts
related to establishing the ARO for nuclear decommissioning for those companies.
The remaining cumulative effect adjustment for unrecognized depreciation and
accretion offset by the reduction in the liabilities was a $174.7 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 third quarter and first nine 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 September 30, 2003
-------------------------------------------------------------------------------------
Effect of SFAS 143 Three Months Nine Months
-------------------------------------------------------------------------------------
Increase (Decrease) (In millions)
Other operating expense
-----------------------
Cost of removal (previously included in depreciation)... $ 0.1 $ 4.4
Depreciation
------------
Elimination of decommissioning expense.................. (22.3) (67.0)
Depreciation of asset retirement cost................... 0.4 1.5
Accretion of asset retirement liability................. 10.5 30.9
Reclassification of cost of removal to expense ......... (1.3) (6.5)
-----------------------------------------------------------------------------------
Net decrease to depreciation............................ (12.7) (41.1)
-----------------------------------------------------------------------------------
Other Income
------------
Earnings on decommissioning trust balances.............. 7.3 10.5
----------------------------------------------------------------------------------
Income taxes............................................ 8.2 19.4
----------------------------------------------------------------------------------
Net income effect....................................... $ 11.7 $ 27.8
==================================================================================
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 $45.4 million in
the third quarter and $139.1 million in the first nine 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 nine
months ended September 30, 2003 and 2002.
Three Months Ended Nine Months Ended
Pension and OPEB Expense (Income) September 30, September 30,
--------------------------------------------------------------------------------------
2003 2002 2003 2002
----------------------------------------------
(In millions)
Pension............................ $32.7 $ (6.0) $ 91.3 $(10.5)
OPEB............................... 39.3 32.6 118.3 81.0
--------------------------------------------------------------------------------------
Total........................ $72.0 $26.6 $209.6 $ 70.5
======================================================================================
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.
33
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 7 to the consolidated financial
statements.
Regulated Services
Net income decreased to $283.5 million in the third quarter of 2003,
compared to $357.5 million in the third quarter of 2002. In the first nine
months of 2003, net income decreased to $707.7 million from $804.7 million in
the first nine months of 2002. The factors contributing to the changes in net
income are summarized in the following table:
Regulated Services Three Months Nine Months
--------------------------------------------------------------------------------
Increase (Decrease) (In millions)
Revenues........................................ $(151.1) $ (50.1)
Expenses........................................ 6.9 415.2
------------------------------------------------------------------------------
Income Before Interest and Income Taxes......... (158.0) (465.3)
Net interest charges............................ (24.0) (83.5)
Income taxes.................................... (60.0) (183.8)
-------------------------------------------------------------------------------
Decrease in Income Before Cumulative Effect
of a Change in Accounting....................... (74.0) (198.0)
Cumulative effect of a change in accounting..... -- 101.0
------------------------------------------------------------------------------
Net Income Decrease............................. $ (74.0) $ (97.0)
==============================================================================
Lower generation sales and distribution deliveries combined to
decrease external electric revenues by $192.7 million in the third quarter of
2003 compared to the same quarter of 2002. Cooler summer temperatures than the
prior year and a continued sluggish economy contributed to reduced sales in the
third quarter. Retail generation sales were also adversely affected by
additional kilowatt-hour sales by alternative suppliers in the FirstEnergy
franchise area. This decrease was partially offset by a $34.7 million increase
in revenues from sales to FES. The remaining offset to lower revenues resulted
from an increase in energy-related revenues. Revenues in the first nine months
of 2003 decreased $50.1 million from the same period last year due to lower
retail sales revenue partially offset by increased sales to wholesale customers.
The decrease in retail revenues resulted from additional kilowatt-hour sales by
alternative suppliers, the cooler summer temperatures and sluggish economy noted
above but offset in part by colder-than-normal first quarter weather.
Expenses increased in the third quarter and first nine months of 2003
from the corresponding periods of 2002. The increase in expenses in the third
quarter of 2003 resulted principally from a $58.5 million increase in other
operating costs primarily due to increased energy delivery costs and employee
benefit costs and a $17.2 million increase in depreciation and amortization
expenses. Offsetting factors included reduced purchased power costs of $57.2
million and lower general taxes of $9.7 million. In the first nine months of
2003, expenses increased $415.2 million from the same period of 2002. The
increase in expenses resulted principally from a $287.2 million increase in
purchased power costs due in large part to higher sales to wholesale customers.
Purchased power costs in 2003 were further increased by a $152.5 million charge
in the second quarter resulting from the JCP&L rate case. The other expense
factors in the first nine months of 2003 compared to the first nine months of
2002 include a $90.8 million increase in other operating expense and a $41.9
million increase in depreciation and amortization expense. Other operating
expenses increased in part due to storm damage and additional employee benefit
costs from the corresponding period of 2002. Depreciation and amortization
expenses increased from the same periods last year due principally to three
factors - increased amortization of the Ohio transition regulatory assets,
recognition of depreciation on four power plants which had been pending sale in
the third quarter of 2002, but were subsequently retained by FirstEnergy in the
fourth quarter of 2002, and the termination of regulatory asset deferrals in
February 2003. A write-off of disallowed costs in the JCP&L rate case also
contributed to the increase in the year-to-date period. Partially offsetting
these increases in depreciation and
34
amortization were higher shopping 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 $77.0 million in the third quarter of 2003
from a net loss of $14.1 million in the third quarter of 2002. Net losses
increased to $175.7 million in the first nine months of 2003 from a net loss of
$67.3 million in the first nine months of last year. A non-cash impairment
charge in the third quarter of 2003, discussed below, accounted for all of the
net loss in that period and a majority of the loss in the first nine months of
2003. Factors contributing to the changes in earnings are summarized in the
following table:
Competitive Services Three Months Nine Months
---------------------------------------------------------------------------
Increase (Decrease) (In millions)
Revenues.................................... $ 93.6 $ 768.3
Expenses.................................... 188.9 930.4
-----------------------------------------------------------------------
Income Before Interest and Income Taxes..... (95.3) (162.1)
------------------------------------------------------------------------
Net interest charges........................ (5.2) (1.2)
Income taxes................................ (27.2) (51.3)
------------------------------------------------------------------------
Decrease in Income Before Cumulative Effect
of a Change in Accounting.................. (62.9) (109.6)
Cumulative effect of a change in accounting. -- 1.2
-----------------------------------------------------------------------
Net income change........................... $(62.9) $(108.4)
========================================================================
The increase in revenues in the third quarter and first nine months
of 2003, compared to the corresponding periods of 2002, includes the net effect
of several factors. Revenues from the electric wholesale market increased $184.5
million in the third quarter and $612.0 million in the first nine months of 2003
from the same periods last year. The large increase in year-to-date sales to the
wholesale market reflects in large part sales as an alternative supplier for a
portion of New Jersey's BGS requirements and sales to Met-Ed and Penelec in
supplying a substantial portion of their PLR requirements in Pennsylvania.
Retail kilowatt-hour sales revenues increased $62.4 million in the third quarter
and $177.4 million in the first nine months of 2003 from the same periods last
year. The increases primarily resulted from expanding the FES business in Ohio
under Ohio's electricity choice program. Internal sales to the regulated
services segment decreased $84.0 million in the third quarter but increased
$161.0 million in the first nine months of 2003 compared to the same periods of
2002.
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 $77.5 million in the third
quarter and $224.6 million in the first nine months of 2003 from the
corresponding periods of 2002.
Natural gas sales increased $9.7 million in the third quarter and
$21.5 million in the first nine months of 2003 from the corresponding periods
last year. The increase in gas sales in the third quarter and first nine month
of 2003 reflected increased prices which more than offset lower gas volumes
delivered as FES focused its operations in a narrower geographic area and on
higher-margin gas customers.
Expenses increased $188.9 million in the third quarter and $930.4
million in the first nine months of 2003 from the same periods of 2002. Higher
other operating expenses ($95.8 million) and purchased power costs ($31.5
million) accounted for the increase in third quarter expenses in 2003 compared
to the prior year. Higher pension and benefit costs and additional nuclear
operating costs associated with a refueling outage at Beaver Valley Unit 2 -
there were no refueling outages in the third quarter of 2002 - contributed to
the increase in other operating expenses. The increased purchased power costs
reflect higher unit costs. Partially offsetting the increase in third quarter
expenses were reduced expenses (excluding an impairment charge) from
energy-related businesses which declined $70.1 million in the third quarter of
2003 from the same period last year as a result of the divestiture of Colonial
and Webb, and declines associated with weak economic conditions. For the first
nine months of 2003, expenses increased $930.4 million from the first nine
months of 2002 due to increased purchased power costs ($842.4 million) and
additional other operating costs ($169.3 million). Higher unit costs and
additional quantities purchased resulted in the large increase in purchase power
costs in the first nine months of 2003 from the prior year. Increased volumes
resulted from supply obligations assumed by FES for BGS sales, sales to Met-Ed
and Penelec in supplying a substantial portion of their PLR requirements, as
well as other wholesale commitments, and additional supplies required to replace
reduced nuclear generation. Additional costs resulting from the Davis-Besse
extended outage, unplanned work performed during two nuclear refueling outages
in the second quarter of 2003 and higher employee benefit costs contributed to
the increase in other operating expenses. The absence of unusual charges
recorded in 2002 moderated the increase in operating expenses by $64.9 million
35
in the 2003 year-to-date period compared to the corresponding period of 2002.
Partially offsetting the increase in year-to-date expenses were reduced expenses
from energy-related businesses, which declined $212.0 million in the first nine
months of 2003 from the same period last year due to the same factors
experienced in the third quarter of 2003.
A non-cash goodwill impairment charge of $121.5 million ($80.9
million, net of tax) was recognized in the third quarter of 2003 reducing the
carrying value of FSG. This charge reflects the continued slow down in the
development of competitive retail markets and depressed economic conditions that
affect the value of FSG.
CAPITAL RESOURCES AND LIQUIDITY
FirstEnergy's cash requirements in the fourth quarter of 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 bank 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 $1.25 billion of revolving credit facilities. In the first nine months
of 2003, FirstEnergy received $597.0 million of cash dividends from its
subsidiaries and paid $330.8 million in cash common stock dividends to its
shareholders. There are currently no material restrictions on the payment of
cash dividends by FirstEnergy's subsidiaries.
As of September 30, 2003, FirstEnergy had $178.9 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 third quarter and
first nine months of 2003, compared with the corresponding periods of 2002 were
as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------------------------
Operating Cash Flows 2003 2002 2003 2002
------------------------------------------------------------------------
(In millions)
Cash earnings (1)........ $551 $478 $1,295 $1,158
Working capital and
other .................. 345 190 85 237
------------------------------------------------------------------------
Total.................... $896 $668 $1,380 $1,395
(1) Includes net income, depreciation and amortization,
deferred income taxes, investment tax credits and major
noncash charges.
Net cash provided from operating activities increased $228 million
due to a $155 million change in funds used for working capital and a $73 million
increase in cash earnings. The change in funds used for working capital
primarily represents offsetting changes for receivables, payables and accrued
taxes.
Cash Flows From Financing Activities
The following table provides details regarding security issuances and
redemptions during the third quarter and first nine months of 2003:
Securities Issued or Redeemed Three Months Nine Months
-------------------------------------------------------------------
(In millions)
New Issues
Common Stock.......................... $ 935 $ 935
Secured Debt.......................... -- 650
Unsecured Notes....................... -- 331
------------------------------------------------------------------
$ 935 $1,916
Redemptions
First Mortgage Bonds.................. $ 302 $1,002
Pollution Control Notes............... 4 54
Secured Notes......................... 263 491
------------------------------------------------------------------
$ 569 $1,547
Short-term Borrowings, Net.............. $(799) $ (847)
-------------------------------------------------------------------
36
Net cash used for financing activities increased by $76 million in
the third quarter of 2003 from the third quarter of 2002. The increase in funds
used for financing activities resulted from increased financing of $108 million
that was exceeded by $184 million of additional redemptions and repayments
during the third quarter of 2003 compared to the same period of 2002.
FirstEnergy had approximately $246.1 million of short-term
indebtedness as of September 30, 2003 compared to $1.093 billion at the end of
2002. Available borrowing capability included $1.173 billion under its then
existing $1.5 billion revolving lines of credit and $73 million under bilateral
bank facilities. As of September 30, 2003, OE, CEI, TE and Penn had the
aggregate capability to issue $2.4 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 September 30, 2003,
JCP&L, Met-Ed and Penelec had the aggregate capability to issue $833 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 $2.4 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 September 17, 2003, FirstEnergy completed issuance of 32.2 million
shares of common stock at $30 per share, receiving net proceeds of approximately
$935 million which were used to reduce bank debt. The issuance used
approximately half of the aggregate $2 billion available under the prior shelf
registration.
In July of 2003, FirstEnergy executed a fixed-for-floating interest
rate swap agreement with a notional value of $50 million (see Interest Rate Swap
Agreements below) on an underlying JCP&L Senior Note with a fixed interest rate
of 4.80%. In October of 2003, FirstEnergy executed two fixed-for-floating
interest rate swap agreements with notional values of $50 million each on
underlying JCP&L and FE senior notes with an average fixed interest rate of
5.6%.
In October 2003, FirstEnergy renewed $1 billion of credit facilities.
Combined with an existing $500 million three-year facility for FirstEnergy and
an existing $250 million two-year facility for OE, the renewal brings
FirstEnergy's primary credit facilities to $1.75 billion. The $1 billion renewal
of credit facilities is comprised of components with varying maturities - a
364-day, $375 million facility and three-year, $375 million facility for
FirstEnergy; and a 364-day, $125 million facility and three-year $125 million
facility for OE.
Cash Flows From Investing Activities
Net cash used for investing activities totaled $236 million in the
third quarter and $462 million in the first nine months of 2003, compared to net
cash of $278 million and $475 million, respectively, used for investing
activities for the same periods of 2002. The $42 million change in the third
quarter of 2003 resulted from the cash investments proceeds in the third quarter
of 2003 and decreased capital expenditures.
In May 2003, FirstEnergy had reached an agreement to sell its 20.1
percent interest in Avon to Scottish and Southern Energy plc.; subsequently, the
agreement was terminated when the parties were unable to agree to terms with
representatives of certain bondholders. On October 21, 2003, FirstEnergy
announced it reached an agreement to sell its 20.1 percent interest in Avon to a
subsidiary of Powergen UK plc, as part of a transaction to include Aquila's 79.9
percent interest. Under terms of the agreement, FirstEnergy would receive
approximately $8 million. The sale is contingent upon regulatory approval and
reaching agreement with bondholders representing 95% of the aggregate principal
amount of the bonds. The holders of approximately half of the outstanding bonds
have given their approval.
On November 13, 2003, FirstEnergy announced that it had reached an
agreement with NRG covering the settlement of its claims resulting from the
uncompleted sale of four FirstEnergy power plants to NRG (see Note 3 -
Divestitures: Sale of Generating Assets). Under the agreement FirstEnergy would
receive an estimated settlement of approximately $198 million in the form of
cash (12%), notes (15.2%) and common stock (72.8%). The agreement is subject to
FERC authorization and U.S. Bankruptcy Court approval since NRG and certain of
its subsidiaries filed for voluntary bankruptcy in May 2003.
The following table summarizes investments made in the third quarter
and first nine months of 2003 by FirstEnergy's regulated services and
competitive services segments:
37
Property
Summary of Cash Used for Investing Activities Additions Investments Other Total
---------------------------------------------------------------------------------------------
Sources (Uses) (In millions)
Three Months Ended September 30, 2003
Regulated Services........................... $ (63)(1) $ (84) $ 2 $(145)
Competitive Services......................... (88)(2) (37) 16 (109)
Other........................................ (5) 30 (7) 18
Eliminations................................. -- -- -- --
---------------------------------------------------------------------------------------------
Total............................... $(156) $ (91) $ 11 $(236)
=============================================================================================
Nine Months Ended September 30, 2003
Regulated Services........................... $(218)(1) $ (17)(3) $ 26 $(209)
Competitive Services......................... (302 (2) 27 (4) (77) (352)
Other........................................ (60) -- 99 (5) 39
Eliminations................................. -- -- 60 60
--------------------------------------------------------------------------------------------
Total............................... $(580) $ 10 $108 $(462)
============================================================================================
(1) Property additions primarily for transmission and 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 fourth quarter of 2003, capital requirements for property
additions and capital leases are expected to be approximately $209 million.
FirstEnergy has additional requirements of approximately $21 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 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."
On September 30, 2003, Fitch Ratings lowered the senior unsecured
ratings of FirstEnergy to "BBB-" from "BBB." Fitch also lowered the senior
secured, senior unsecured, and preferred stock ratings of Met-Ed, Penelec, CEI,
and TE. In addition, Fitch affirmed the ratings of OE, Penn and JCP&L. Fitch
announced that the Rating Outlook is Stable for the securities of FirstEnergy,
and all of the securities of its electric utility operating companies. Fitch
stated that the changes to the long-term ratings were "driven by the high debt
leverage of the parent FE. Despite management's commitment to reduce debt
related to the GPU merger, subsequent cash flows have been vulnerable to
unfavorable events, slowing the pace of FE's debt reduction efforts. The Stable
Outlook reflects the success of FE's recent common equity offering and
management's focus on a relatively conservative integrated utility strategy."
On October 27, 2003, Standard & Poors (S&P) stated that the `BBB'
corporate credit and the `BBB-` senior unsecured ratings for FirstEnergy and its
utility subsidiaries remain on CreditWatch with negative implications. The
ratings were placed on CreditWatch on August 18, 2003, and reflect S&P's
concerns regarding the potential impact of the August 14, 2003 blackout
investigation on FirstEnergy's deleveraging strategy and its overall efforts to
improve its credit profile.
At that time, S&P also noted other challenges facing FirstEnergy,
including the extended Davis-Besse outage; the recent U.S. District Court ruling
regarding the Sammis Plant (see Outlook-Environmental Matters below);
reliability concerns in subsidiary JCP&L's service territory; and FirstEnergy's
credibility with regulators and federal officials.
S&P further noted several factors that could aid FirstEnergy in
resolution of the CreditWatch, including strengthening its balance sheet.
FirstEnergy directly addressed this concern through its recently completed
common equity offering that raised approximately $935 million in net proceeds,
which was used to reduce bank debt. See Cash Flows from Financing Activities
above. S&P described the equity offering as a "positive credit development" and
also noted the recent renewal of FirstEnergy's $1 billion revolver facilities as
a "favorable development, as it mitigates liquidity
38
concerns." S&P also indicated that should various ongoing investigations into
the causal factors of the August 14, 2003 blackout establish that the blackout
resulted from no negligence or breach of compliance standards on FirstEnergy's
part, the CreditWatch could be removed and the outlook returned to negative. S&P
deemed a "stable" credit outlook unlikely until issues such as the restart of
Davis-Besse are resolved and the potential effect of the litigation relating to
the Sammis plant (the second trial is scheduled for April 2004) are known.
Extension of the Ohio transition plan will be viewed as a positive development
and will support an outlook revision to stable.
On October 27, 2003, S&P also noted that the ratings on FirstEnergy
and its subsidiaries incorporate such strengths as the ability to generate free
cash flow, power generation contracted to its transmission and distribution
subsidiaries through 2005, and the hedging of its short power position arising
from its PLR obligation in Pennsylvania. S&P said that these strengths are
offset by slower than anticipated reduction of FirstEnergy debt, remaining
volume risks of PLR obligations, the extended outage at Davis-Besse, the
unfavorable outcome of the New Jersey rate proceeding and regulatory uncertainty
in Ohio. S&P also said that it now views FirstEnergy's liquidity position as
average, following FirstEnergy's renewal of its $1 billion credit facilities.
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 September 30, 2003,
the present value of these sale and leaseback operating lease commitments, net
of trust investments, total $1.4 billion. Also, CEI and TE continue to sell
substantially all of their retail customer receivables, which provided $200
million of financing not included on the Consolidated Balance Sheet as of
September 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 September 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(1)
Energy and Energy-Related Contracts(2)...... $ 793.3
Other (3)................................... 162.7
----------------------------------------------------------
956.0
Surety Bonds.................................. 15.6
Rating-Contingent Collateralization (3)....... 64.2
----------------------------------------------------------
Total Guarantees and Other Assurances....... $1,035.8
==========================================================
(1) Estimated net liabilities under contracts subject to
rating-contingent collateralization provisions that
total $185.7 million.
(2) Issued for a one-year term, with a 10-day
termination right by FirstEnergy.
(3) Issued for various terms.
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.
39
Various contracts include credit enhancements in the form of cash
collateral, letters of credit or other security in the event of a reduction in
credit rating. Requirements of these provisions vary and typically require more
than one rating reduction to below investment grade by S&P or Moody's to trigger
additional collateralization.
MARKET RISK INFORMATION
FirstEnergy uses various market risk sensitive instruments, including
derivative contracts, primarily to manage the risk of price and interest rate
fluctuations. FirstEnergy's Risk Policy Committee, comprised of executive
officers, exercises an independent risk oversight function to ensure compliance
with corporate risk management policies and prudent risk management practices.
Commodity Price Risk
FirstEnergy is exposed to market risk primarily due to fluctuations
in electricity, natural gas and coal prices. To manage the volatility relating
to these exposures, it uses a variety of non-derivative and derivative
instruments, including forward contracts, options, futures contracts and swaps.
The derivatives are used principally for hedging purposes and, to a much lesser
extent, for trading purposes. Most of FirstEnergy's non-hedge derivative
contracts represent non-trading positions that do not qualify for hedge
treatment under SFAS 133.
The change in the fair value of commodity derivative contracts
related to energy production during the third quarter and first nine months of
2003 is summarized in the following table:
INCREASE (DECREASE) IN THE FAIR VALUE
OF COMMODITY DERIVATIVE CONTRACTS
-------------------------------------
Three Months Ended Nine Months Ended
September 30, 2003 September 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....................... $66.0 $ 35.5 $101.5 $53.8 $ 24.1 $ 77.9
New contract value when entered........................ -- -- -- -- -- --
Change in value of existing contracts.................. (4.7) (9.7) (14.4) 11.2 27.7 38.9
Change in techniques/assumptions....................... 9.4 -- 9.4 9.4 -- 9.4
Settled contracts...................................... 16.0 (19.3) (3.3) 12.3 (45.3) (33.0)
------------------------- -------------------------
Net asset at end of period (1)......................... 86.7 6.5 93.2 86.7 6.5 93.2
------------------------- -------------------------
Non-commodity net assets at end of period:
Interest Rate Swaps (2)............................. -- 5.9 5.9 -- 5.9 5.9...
------------------------- -------------------------
Net Assets - Derivative Contracts at end of period (3). $86.7 $ 12.4 $ 99.1 $86.7 $ 12.4 $ 99.1
========================= =========================
Impact of Changes in Commodity Derivative Contracts (4)
Income Statement Effects (Pre-Tax)..................... $20.2 $ -- $ 20.2 $ 7.8 $ -- $ 7.8
Balance Sheet Effects:
Other Comprehensive Income (Pre-Tax)................ $ -- $(29.0) $(29.0) $ -- $(17.6) $(17.6)
Regulatory Liability................................ $ 0.5 $ -- $ 0.5 $25.1 $ -- $ 25.1
(1) Includes $59.2 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 $14.1 million of derivative contract fair value decrease, as of
September 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
September 30, 2003 as follows:
Non-Hedge Hedge Total
---------------------------------------------------------------------
(In millions)
Current-
Other Assets...................... $ 6.8 $ 3.4 $ 10.2
Other Liabilities................. (8.2) (1.1) (9.3)
Non-Current-
Other Deferred Charges............ 88.8 15.2 104.0
Other Deferred Credits............ (0.7) (5.1) (5.8)
---------------------------------------------------------------------
Net assets........................ $86.7 $12.4 $ 99.1
=====================================================================
40
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)............. $0.8 $ 4.4 $(0.4) $-- $-- $ 4.8
Other external sources(3)............. 0.7 20.6 10.5 -- -- 31.8
Prices based on models................ -- -- -- 13.1 43.5 56.6
-----------------------------------------------------------------------------------------------------------
Total(4)........................... $1.5 $25.0 $10.1 $13.1 $43.5 $93.2
===========================================================================================================
(1) For the last quarter of 2003.
(2) Exchange traded.
(3) Broker quote sheets.
(4) Includes $59.2 million from an embedded option that is offset by a regulatory liability and does not affect earnings.
FirstEnergy performs sensitivity analyses to estimate its exposure to
the market risk of its commodity positions. A hypothetical 10% adverse shift (an
increase or decrease depending on the derivative position) in quoted market
prices in the near term on both FirstEnergy's trading and nontrading derivative
instruments would not have had a material effect on its consolidated financial
position (assets, liabilities and equity) or cash flows as of September 30,
2003. Based on derivative contracts held as of September 30, 2003, an adverse
10% change in commodity prices would decrease net income by approximately $4.7
million during the next twelve months.
Interest Rate Swap Agreements
During the third quarter of 2003, FirstEnergy entered into a
fixed-to-floating interest rate swap agreement, 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 agreement
consummated in the third quarter of 2003 is based on a notional principal amount
of $50 million.
As of September 30, 2003, the debt underlying FirstEnergy's $600
million notional amount of outstanding fixed-for-floating interest rate swaps
had a weighted average fixed interest rate of 5.62%, which the swaps have
effectively converted to a current weighted average variable interest rate of
2.24%. GPU Power (through a subsidiary) used existing dollar-denominated
interest rate swap agreements in the first nine 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 September 30, 2003 and December 31, 2002. The
following summarizes the principal characteristics of the swap agreements:
September 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 $ 4.7
50 2008 0.5
150 2015 (5.8) $444 2023 $15.5
50 2018 0.7 -- -- --
150 2025 6.3 150 2025 5.9
Floating to Fixed Rate
(Cash flow hedges) $ 8 2005 $(0.5) $ 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
$669 million and $532 million as of September 30, 2003 and December 31, 2002,
respectively. A hypothetical 10% decrease in prices quoted by stock exchanges
would result in a $67 million reduction in fair value as of September 30, 2003.
41
OUTLOOK
FirstEnergy continues to pursue its goal of being the leading
regional supplier of energy and related services in the northeastern quadrant of
the United States, where it sees the best opportunities for growth. Its
fundamental business strategy remains stable and unchanged. While FirstEnergy
continues to build toward a strong regional presence, key elements for its
strategy are in place and management's focus continues to be on execution.
FirstEnergy intends to provide competitively priced, high-quality products and
value-added services - energy sales and services, energy delivery, power supply
and supplemental services related to its core business. As FirstEnergy's
industry changes to a more competitive environment, FirstEnergy has taken and
expects to take actions designed to create a larger, stronger regional
enterprise that will be positioned to compete in the changing energy
marketplace.
FirstEnergy's current focus includes: 1) returning Davis-Besse to
safe and reliable operation; 2) optimizing FirstEnergy's generation portfolio;
3) effectively managing commodity supplies and risks; 4) reducing FirstEnergy's
cost structure; and 5) enhancing its credit profile and financial flexibility.
Business Organization
FirstEnergy's business is managed as two distinct operating segments
- a competitive services segment and a regulated services segment. FES provides
competitive retail energy services while the EUOC provide regulated transmission
and distribution services. FirstEnergy Generation Corp. (FGCO), a wholly owned
subsidiary of FES, leases fossil and hydroelectric plants from the EUOC and
operates those plants. FirstEnergy expects the transfer of ownership of EUOC
non-nuclear generating assets to FGCO will be substantially completed by the end
of the Ohio market development period. 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:
o allowing the EUOCs' electric customers to select their generation
suppliers;
o establishing PLR obligations to non-shopping customers in the EUOCs'
service areas;
o allowing recovery of potentially stranded investment (or
transition costs) not otherwise recoverable in a competitive
generation market;
o itemizing (unbundling) the price of electricity into its component
elements - including generation, transmission, distribution and
stranded costs recovery charges;
o deregulating the EUOCs' electric generation businesses; and
o continuing regulation of the EUOCs' 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 discussed below. Regulatory
assets declined by $954.6 million for the first nine months of 2003, to $7.8
billion as of September 30, 2003. 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:
42
Regulatory Assets
------------------------------------------------
September 30, December 31,
Company 2003 2002
------------------------------------------------
(In millions)
OE............... $1,594.0 $1,848.7
CEI.............. 1,138.2 1,191.8
TE............... 516.3 578.2
Penn............. 50.1 156.9
JCP&L............ 2,926.7 3,199.0
Met-Ed........... 1,059.8 1,179.1
Penelec.......... 513.7 599.7
----------------------------------------------
Total............ $7,798.8 $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.
On October 21, 2003, the Ohio Companies filed an application with the
PUCO to establish generation service rates beginning January 1, 2006, in
response to expressed concerns by the PUCO about price and supply uncertainty
following the end of the market development period. The filing included two
options:
o A competitive auction, which would establish a price for
generation that customers would be charged during the period
covered by the auction, or
o A Rate Stabilization Plan, which would extend current generation
prices through 2008, ensuring adequate supply and continuing
FirstEnergy's support of energy efficiency and economic
development efforts.
Under the first option, an auction would be conducted to secure
generation service, including PLR responsibility, for FirstEnergy's Ohio
customers. Beginning in 2006, customers would pay market prices for generation
as determined by the auction.
Under the Rate Stabilization Plan option, customers would have price
and supply stability through 2008 - three years beyond the end of the market
development period - as well as the benefits of a competitive market. Customer
benefits would include: customer savings by extending the current five percent
discount on generation costs and other customer credits; maintaining current
distribution base rates through 2007; market-based auctions that may be
conducted annually to ensure that customers pay the lowest available prices;
extension of FirstEnergy's support of energy-efficiency programs and the
potential for continuing the program to give preferred access to nonaffiliated
entities to generation capacity as discussed above. In order to facilitate
supply planning, FirstEnergy has requested that the PUCO rule on this proposal
by December 31, 2003. Under the proposed plan, FirstEnergy is requesting:
o Extension of the transition cost amortization period for OE from
2006 to 2007; for CEI from 2008 to 2009 and for TE from mid-2007
to 2008;
o Deferral of new regulatory assets and deferral of interest costs
on the shopping incentive and other new deferrals;
o Ability to initiate a request to increase generation rates only
under certain limited conditions.
As a result of the Ohio Companies' October 21 filing, the PUCO
entered an order on October 28, 2003 setting forth the discovery schedule
related to the application with hearings scheduled to begin December 3, 2003.
43
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 discussed above. On July 25, 2003,
the NJBPU announced its JCP&L base electric rate proceeding decision, which
reduced JCP&L's annual revenues by approximately $62 million effective August 1,
2003. The NJBPU decision also provided for an interim return on equity of 9.5
percent on JCP&L's rate base for 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 net revenue decrease from the NJBPU's
decision consists of a $223 million decrease in the electricity delivery charge,
a $111 million increase due to the August 1, 2003 expiration of annual customer
credits previously mandated by the New Jersey transition legislation, a $49
million increase in the MTC tariff component, and a net $1 million increase in
the SBC charge. The MTC allows for the recovery of $465 million in deferred
energy costs over the next ten years on an interim basis, thus disallowing $153
million of the $618 million provided for in a preliminary settlement agreement
between certain parties. As a result, JCP&L recorded charges to net income for
the nine months ended September 30, 2003, aggregating $172 million ($103 million
net of tax) consisting of the $153 million deferred energy costs and other
regulatory assets. JCP&L filed a motion for rehearing and reconsideration with
the NJBPU on August 15, 2003 with respect to the following issues: (1) the
disallowance of the $153 million deferred energy costs; (2) the reduced rate of
return on equity; and (3) $42.7 million of disallowed costs to achieve merger
savings. On October 10, 2003, the NJBPU held the motion in abeyance until the
final NJBPU decision and order which is expected to be issued in the fourth
quarter of 2003.
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 power contracts with
nonaffiliated third party suppliers. This arrangement reduces Met-Ed's and
Penelec's exposure to high wholesale power prices by providing power at a fixed
price for their uncommitted PLR energy costs during the term of the agreement 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 are authorized
to continue deferring differences between NUG contract costs and current market
prices.
On April 2, 2003, the PPUC remanded the issue relating to merger
savings to the Office of Administrative Law for hearings, directed Met-Ed and
Penelec to file a position paper on the effect of the Commonwealth Court order
on the Settlement Stipulation and allowed other parties to file responses to the
position paper. Met-Ed and Penelec filed a letter with the Administrative Law
Judge on June 11, 2003, voiding the Stipulation in its entirety and reinstating
Met-Ed's and Penelec's restructuring settlement previously approved by the PPUC.
On October 2, 2003, the PPUC issued an order concluding that the
Commonwealth Court reversed the PPUC's June 20, 2001 order in its entirety. The
PPUC directed Met-Ed and Penelec to file tariffs within thirty days of the order
to reflect the competitive transition charge (CTC) rates and shopping credits
that were in effect prior to the June 21, 2001 order to be effective upon one
day's notice. In response to that order, Met-Ed and Penelec filed these
supplements to their tariffs to become effective October 24, 2003.
On October 8, 2003, Met-Ed and Penelec filed a petition for
clarification relating to the October 2 order on two issues: to establish the
end of June 2004 as the date to fully refund the NUG trust fund and to clarify
that the ordered accounting treatment regarding the CTC rate/shopping credit
swap should follow the ratemaking, and that the PPUC's findings would not impair
their rights to recover all of their stranded costs. On October 9, 2003, ARIPPA
(an intervenor in the proceedings) petitioned the PPUC to direct Met-Ed and
Penelec to reinstate accounting for the CTC rate/shopping credit swap
retroactive to January 1, 2002. Several other parties also filed petitions. On
October 16, 2003, the PPUC issued a reconsideration order granting the date
requested by Met-Ed and Penelec for the NUG trust fund refund; and, denying
Met-Ed's and Penelec's other clarification requests and granting ARIPPA's
petition with respect to the accounting treatment of the changes to the CTC
rate/shopping credit swap. On October 22, 2003, Met-Ed and Penelec filed an
Objection with the Commonwealth Court asking that the Court reverse the PPUC's
finding that requires Met-Ed and Penelec to treat the stipulated CTC rates that
were in effect from January 1, 2002 on a retroactive basis. Met-Ed and Penelec
are considering filing an appeal to the Commonwealth Court on the PPUC orders as
well.
44
On October 27, 2003, one Commonwealth Court judge issued an order
denying Met-Ed's and Penelec's objections without explanation. Due to the
vagueness of the Order, Met-Ed and Penelec, on October 31, 2003, filed an
Application for Clarification with the Judge. Concurrent with this filing,
Met-Ed and Penelec, in order to preserve their rights, also filed with the
Commonwealth Court both a Petition for Review of the PPUC's October 16 and 22
Orders, and an application for reargument, if the Judge, in his clarification
order, indicates that Met-Ed's and Penelec's objection was intended to be denied
on the merits. In addition to these findings, Met-Ed and Penelec, in compliance
with the PPUC's Orders, filed revised quarterly reports for the twelve months
ended December 31, 2001 and 2002, and for the first two quarters of 2003,
reflecting balances consistent with the PPUC's findings in their Orders.
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. Testing of the bottom of the reactor for leaks was
completed in October 2003 and no indication of leakage was discovered.
FirstEnergy is installing 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 third quarter and first nine months of 2003 and 2002 were as follows:
Three Months Ended Nine Months Ended
------------------ -----------------
Costs of Davis-Besse Extended Outage September 30, September 30
--------------------------------------------------------------------------------
2003 2002 2003 2002
---- ---- ---- ----
(In millions)
Incremental Pre-Tax Expense
Replacement power................. $54.9 $50.9 $148.4 $ 84.5
Maintenance....................... 17.5 39.8 75.7 54.1
--------------------------------------------------------------------------------
Total......................... $72.4 $90.7 $224.1 $138.6
================================================================================
Capital Expenditures................ $10.9 $27.4 $ 13.3 $ 39.4
================================================================================
It is anticipated that an additional $14 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 during the remaining period of
the outage. FirstEnergy has hedged the on-peak replacement energy supply for
Davis-Besse for the expected length of the outage. If there are significant
delays in the NRC approval process, substantial replacement power costs will
continue to be incurred, which will continue to have an adverse effect on
FirstEnergy's, CEI's and TE's respective cash flows and results of operations.
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.
45
The Companies believe they are in compliance with the current SO2 and
nitrogen oxides (NOx) reduction requirements under the Clean Air Act Amendments
of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel,
generating more electricity from lower-emitting plants, and/or using emission
allowances. NOx reductions are being achieved through combustion controls and
the generation of more electricity at lower-emitting plants. In September 1998,
the EPA finalized regulations requiring additional NOx reductions from the
Companies' Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule
imposes uniform reductions of NOx emissions (an approximate 85% reduction in
utility plant NOx emissions from projected 2007 emissions) across a region of
nineteen states and the District of Columbia, including New Jersey, Ohio and
Pennsylvania, based on a conclusion that such NOx emissions are contributing
significantly to ozone pollution in the eastern United States. State
Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx
budgets established by the EPA. Pennsylvania submitted a SIP that required
compliance with the NOx budgets at the Companies' Pennsylvania facilities by May
1, 2003 and Ohio submitted a SIP that requires compliance with the NOx budgets
at the Companies' Ohio facilities by May 31, 2004.
In July 1997, the EPA promulgated changes in the National Ambient Air
Quality Standard (NAAQS) for ozone emissions and proposed a new NAAQS for
previously unregulated ultra-fine particulate matter. In May 1999, the U.S.
Court of Appeals for the D.C. Circuit found constitutional and other defects in
the new NAAQS rules. In February 2001, the U.S. Supreme Court upheld the new
NAAQS rules regulating ultra-fine particulates but found defects in the new
NAAQS rules for ozone and decided that the EPA must revise those rules. The
future cost of compliance with these regulations may be substantial and will
depend if and how they are ultimately implemented by the states in which the
Companies operate affected facilities.
In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a
Compliance Order to nine utilities covering 44 power plants, including the W. H.
Sammis Plant. In addition, the U.S. Department of Justice filed eight civil
complaints against various investor-owned utilities, which included a complaint
against OE and Penn in the U.S. District Court for the Southern District of
Ohio. The NOV and complaint allege violations of the Clean Air Act based on
operation and maintenance of the Sammis Plant dating back to 1984. The 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 April 19, 2004, will address civil penalties and what, if any, actions
should be taken to further reduce emissions at the plant. In the ruling, the
Court indicated that the remedies it "may consider and impose involved a much
broader, equitable analysis, requiring the Court to consider air quality, public
health, economic impact, and employment consequences. The Court may also
consider the less than consistent efforts of the EPA to apply and further
enforce the Clean Air Act." The potential penalties that may be imposed, as well
as the capital expenditures necessary to comply with substantive remedial
measures that may be required, could have a material adverse impact on the
Company's financial condition and results of operations. Management is unable to
predict the ultimate outcome of this matter and no liability has been recorded
as of September 30, 2003.
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, environmental liabilities that are considered probable have been
recognized on the Consolidated Balance Sheet as of September 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 $50.4 million as of September 30, 2003.
The effects of compliance on the EUOCs with regard to environmental
matters could have a material adverse effect on FirstEnergy's earnings
46
and competitive position. These environmental regulations affect FirstEnergy's
earnings and competitive position to the extent it competes with companies that
are not subject to such regulations and therefore do not bear the risk of costs
associated with compliance, or failure to comply, with such regulations.
FirstEnergy believes it is in material compliance with existing regulations, but
is unable to predict how and when applicable environmental regulations may
change and what, if any, the effects of any such change would be.
Power Outage
On August 14, 2003, eight states and southern Canada experienced a
widespread power outage. That outage affected approximately 1.4 million
customers in FirstEnergy's service area. The cause of the outage has not been
determined. FirstEnergy continues to accumulate data and evaluate the status of
its electrical system prior to and during the outage event. On September 12,
2003, the U.S./Canada Power Outage Task Force (Task Force) investigating the
August 14 outage released a timeline of events. The timeline presented the
sequence of events that occurred on major transmission lines (230 kilovolts or
greater) and at large power plants beginning at approximately noon through
approximately 4:00 PM, preceding the outage. This timeline did not attempt to
present or explain the linkages between the sequence of events. Determining the
specific causes of the events and their relation to the outage will require more
time to analyze by the Task Force. The Task Force is expected to release its
interim report on November 18, 2003.
Legal Matters
As of October 14, 2003, ten individual shareholder-plaintiffs have
filed separate complaints against FirstEnergy alleging various securities law
violations. The bases for these complaints vary but include alleged violations
arising out of the power outage, described herein, the extended outage at
Davis-Besse, and the restatement of earnings, described herein. FirstEnergy is
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. In addition, four shareholder-plaintiffs have filed "shareholder
derivative" actions against the members of the Board of Directors, and the
Company as a nominal defendant, asserting rights of the corporation itself. The
complaints allege violations of fiduciary duties as a result of, generally, the
same events described in the securities lawsuits described herein. Furthermore,
five lawsuits - three in Ohio state courts, two in New York state courts - have
been filed seeking damages relating to the August 14, 2003 power outage. The two
New York actions name FirstEnergy as one of several defendants and have been
noticed but not served. Additionally, a complaint has been filed with the PUCO
by United States Congressman Dennis Kucinich, alleging that as a result of
several events, including the August 14, 2003 power outage and the extended
outage at Davis-Besse, both described herein, the Company has failed to provide
adequate and reasonable service to its customers. That complaint asks, among
other things, that another electric supplier be authorized to provide service
within the Ohio Utilities' certified territories. FirstEnergy believes that in
each instance, the legal actions are without merit. FirstEnergy intends to
defend these actions vigorously, but cannot predict the outcome of any of these
proceedings or whether any further regulatory proceedings or legal actions may
be instituted against it. In particular, if FirstEnergy were ultimately
determined to have legal liability in connection with the outage, it could have
a material adverse effect on FirstEnergy's financial condition and results of
operations.
Various lawsuits, claims and proceedings related to FirstEnergy's
normal business operations are pending against it, the most significant of which
are described herein.
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.
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 - $7.8 billion as of September 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.
47
Derivative Accounting
Determination of appropriate accounting for derivative transactions
requires the involvement of management representing operations, finance and risk
assessment. In order to determine the appropriate accounting for derivative
transactions, the provisions of the contract need to be carefully assessed in
accordance with the authoritative accounting literature and management's
intended use of the derivative. New authoritative guidance continues to shape
the application of derivative accounting. Management's expectations and
intentions are key factors in determining the appropriate accounting for a
derivative transaction and, as a result, such expectations and intentions are
documented. Derivative contracts that are determined to fall within the scope of
SFAS 133, as amended, must be recorded at their fair value. Active market prices
are not always available to determine the fair value of the later years of a
contract, requiring that various assumptions and estimates be used in their
valuation. FirstEnergy continually monitors its derivative contracts to
determine if its activities, expectations, intentions, assumptions and estimates
remain valid. As part of its normal operations, FirstEnergy enters into
significant commodity contracts, as well as interest rate and currency swaps,
which increase the impact of derivative accounting judgments.
Revenue Recognition
FirstEnergy follows the accrual method of accounting for revenues,
recognizing revenue for kilowatt-hours that have been delivered but not yet
billed through the end of the accounting period. The determination of unbilled
revenues requires management to make various estimates including:
o Net energy generated or purchased for retail load
o Losses of energy over transmission and distribution lines
o Mix of kilowatt-hour usage by residential, commercial and industrial
customers
o Kilowatt-hour usage of customers receiving electricity from
alternative suppliers
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory defined
pension and OPEB benefits are dependent upon numerous factors resulting from
actual plan experience and certain assumptions.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions FirstEnergy makes to the plans, and earnings on plan assets. Such
factors may be further affected by business combinations (such as FirstEnergy's
merger with GPU, Inc. in November 2001), which impacts employee demographics,
plan experience and other factors. Pension and OPEB costs may also be affected
by changes to key assumptions, including anticipated rates of return on plan
assets, the discount rates and health care trend rates used in determining the
projected benefit obligations for pension and OPEB costs.
In accordance with SFAS 87, "Employers' Accounting for Pensions" and
SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions," changes in pension and OPEB obligations associated with these factors
may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
In selecting an assumed discount rate, FirstEnergy considers
currently available rates of return on high-quality fixed income investments
expected to be available during the period to maturity of the pension and other
postretirement benefit obligations. Due to the significant decline in corporate
bond yields and interest rates in general during 2002, FirstEnergy reduced the
assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used at the
end of 2001.
FirstEnergy's assumed rate of return on pension plan assets considers
historical market returns and economic forecasts for the types of investments
held by its pension trusts. The market values of FirstEnergy's pension assets
have been affected by sharp declines in the equity markets since mid-2000. In
2002 and 2001 plan assets earned (11.3)% and (5.5)%, respectively. FirstEnergy's
pension costs in 2002 were computed assuming a 10.25% rate of return on plan
assets. Beginning in 2003, the assumed return on plan assets was reduced to
9.00% based upon FirstEnergy's projection of future returns and pension trust
investment allocation of approximately 60% large cap equities, 10% small cap
equities and 30% bonds.
Based on pension assumptions and pension plan assets as of December
31, 2002, FirstEnergy is not 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
48
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 connection with FirstEnergy's restructuring plan, the PUCO
determined allowable transition costs based on amounts recorded on the
regulatory books of the Ohio electric utilities. These costs exceeded those
deferred or capitalized on FirstEnergy's balance sheet prepared under GAAP since
they included certain costs which have not yet been incurred or that were
recognized on the regulatory financial statements (fair value purchase
accounting adjustments). FirstEnergy uses an effective interest method for
amortizing its transition costs, often referred to as a "mortgage-style"
amortization. The interest rate under this method is equal to the rate of return
authorized by the PUCO in the transition plan for each respective company. In
computing the transition cost amortization, FirstEnergy includes only the
portion of the transition revenues associated with transition costs included on
the balance sheet prepared under GAAP. Revenues collected for the off balance
sheet costs and the return associated with these costs are recognized as income
when received.
Long-Lived Assets
In accordance with SFAS 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," FirstEnergy periodically evaluates its
long-lived assets to determine whether conditions exist that would indicate that
the carrying value of an asset may not be fully recoverable. The accounting
standard requires that if the sum of future cash flows (undiscounted) expected
to result from an asset is less than the carrying value of the asset, an asset
impairment must be recognized in the financial statements. If impairment other
than of a temporary nature has occurred, FirstEnergy recognizes a loss -
calculated as the difference between the carrying value and the estimated fair
value of the asset (discounted future net cash flows).
Goodwill
In a business combination, the excess of the purchase price over the
estimated fair values of the assets acquired and liabilities assumed is
recognized as goodwill. Based on the guidance provided by SFAS 142, FirstEnergy
evaluates its goodwill for impairment at least annually and would make such an
evaluation more frequently if indicators of impairment should arise. In
accordance with the accounting standard, if the fair value of a reporting unit
is less than its carrying value (including goodwill), the goodwill is tested for
impairment. When impairment is indicated FirstEnergy recognizes a loss -
calculated as the difference between the implied fair value of a reporting
unit's goodwill and the carrying value of the goodwill. FirstEnergy's annual
review was completed in the third quarter of 2003. As a result of that review, a
non-cash goodwill impairment charge of $121.5 million was recognized in the
third quarter of 2003, reducing the carrying value of FSG. That charge reflects
the continued slow down in the development of competitive retail markets and
depressed economic conditions that affect the value of FSG. The forecasts used
in 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
September 30, 2003, FirstEnergy had $6.1 billion of goodwill that primarily
relates to its regulated services segment. A summary of the changes in
FirstEnergy's goodwill for the nine months ended September 30, 2003 (which
affected only the Competitive Services Segment) is shown below:
(In millions)
Balance at December 31, 2003............ $6,278.1
Impairment charges...................... (121.5)
FSG divestitures........................ (40.8)
Other................................... 12.1
--------
Balance at September 30, 2003........... $6,127.9
========
NEW ACCOUNTING STANDARDS ADOPTED
SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity"
In May 2003, the FASB issued SFAS 150, which establishes standards
for how an issuer classifies and measures certain financial instruments with
characteristics of both liabilities and equity. In accordance with the standard,
certain financial instruments that embody obligations for the issuer are
required to be classified as liabilities. SFAS 150 was effective immediately for
financial instruments entered into or modified after May 31, 2003 and effective
at the
49
beginning of the first interim period beginning after June 15, 2003
(FirstEnergy's third quarter of 2003) for all other financial instruments.
Upon adoption of SFAS 150, effective July 1, 2003, FirstEnergy
reclassified as debt the preferred stock of consolidated subsidiaries subject to
mandatory redemptions with a carrying value of approximately $17.5 million ($4.0
million for CEI and $13.5 million for Penn) as of September 30, 2003.
Subsidiary-obligated mandatorily redeemable preferred securities of $285 million
($100 million for CEI, $93 million for Met-Ed and $92 for Penelec) were also
reclassified and included in long-term debt as of September 30, 2003. As
required by SFAS 150, the preferred securities subject to mandatory redemption
were not restated as long-term debt on the December 31, 2002 balance sheet.
Adoption of SFAS 150 had no impact on FirstEnergy's Consolidated
Statements of Income because the preferred dividends were previously included in
net interest charges and required no reclassification. Dividends on preferred
stock subject to mandatory redemption on CEI and Penn's respective Consolidated
Statements of Income, which were not included in net interest charges prior to
the adoption of SFAS 150, were included in net interest charges for the three
months ended September 30, 2003.
CEI, Met-Ed and Penelec created statutory business trusts to issue
the preferred securities of $285 million discussed above. The continued
consolidation of the issuer trusts and the appropriate balance sheet
classification of the trust preferred securities is currently under review
pursuant to FIN 46 (see Note 6). Upon the implementation of FIN 46 effective
December 31, 2003, these trusts would be deconsolidated if CEI, Met-Ed and
Penelec were not the primary beneficiaries of the related trusts. Rather than
recording a liability for the trust preferred securities as discussed above,
FirstEnergy, CEI, Met-Ed and Penelec would reflect liabilities for the notes
payable to the respective trusts, which are currently eliminated in
consolidation. The deconsolidation of the trusts would result in an increase to
total assets and liabilities of $9.3 million ($3.1 million for each of CEI,
Met-Ed and Penelec) for the investment in the trusts.
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, that continue to be applied
based on their original effective dates. Adoption of SFAS 149 did not have a
material impact on the Company's financial statements.
SFAS 143, "Accounting for Asset-Retirement Obligations"
The Company adopted SFAS 143 effective January 1, 2003. The impact of
this new accounting standard is discussed above under Results of Operations.
EITF Issue No. 01-8, "Determining whether an Arrangement Contains a
Lease"
In May 2003, the EITF reached a consensus on Issue No. 01-8,
regarding when arrangements contain a lease. Based on the EITF consensus, an
arrangement contains a lease if (1) it identifies specific property, plant or
equipment (explicitly or implicitly), and (2) the arrangement transfers the
right to the purchaser to control the use of the property, plant or equipment.
The consensus is to be applied prospectively to arrangements committed to,
modified or acquired through a business combination, beginning in the third
quarter of 2003. The adoption of this consensus as of July 1, 2003 did not
impact FirstEnergy's financial statements.
EITF Issue No. 02-3, "Issues Involved in Accounting for Derivative
Contracts Held for Trading Purposes and Contracts Involved in Energy
Trading and Risk Management Activities"
In October 2002, the EITF reached a consensus that 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. In addition, the related kilowatt-hour sales and purchases
statistics described above under Results of Operations were reclassified (2.7
billion kilowatt-hours in the third quarter and 5.3 billion kilowatt-hours in
the first nine months of 2002). The following table displays the impact of
changing to a net presentation for FirstEnergy's energy trading operations.
50
Three Months Ended Nine Months Ended
September 30, 2002 September 30, 2002
------------------------ ------------------------
Impact of Recording Energy Trading Net Revenues Expenses Revenues Expenses
---------------------------------------------------------------------------------------------------
(In millions)
Total as originally reported................. $3,572 $2,845 $9,414 $7,570
Adjustment................................... (121) (121) (211) (211)
----------------------------------------------------------------------------------------------------
Total as currently reported.................. $3,451 $2,724 $9,203 $7,359
===================================================================================================
NEW ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED
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". This Interpretation requires the
consolidation of a variable interest entity (VIE) by an enterprise if that
enterprise either absorbs a majority of the VIE's expected losses or receives a
majority of the VIE's expected residual returns as a result of ownership,
contractual or other financial interests in the VIE. Currently, entities are
generally consolidated by an enterprise that has a controlling financial
interest through ownership of a majority voting interest in the entity.
FIN 46 defines a VIE as an entity in which equity investors do not
have the characteristics of a controlling financial interest nor have sufficient
equity at risk for the entity to finance its activities without additional
subordinated financial support. VIE's created after January 31, 2003, are
immediately subject to the provisions of FIN 46. The FASB recently deferred
implementation of FIN 46 for VIE's created before February 1, 2003, until the
first reporting period ending after December 15, 2003 (FirstEnergy's quarter
ending December 31, 2003.)
FirstEnergy currently has transactions with entities in connection
with sale and leaseback arrangements which fall within the scope of this
interpretation and which meet the definition of a VIE in accordance with FIN 46.
In addition to the two entities created to refinance debt discussed below, the
Company is evaluating its interest in the owner trusts that acquired certain
interests in the Perry Plant, Beaver Valley Unit 2 and the Bruce Mansfield
Plant. The leases are accounted for as operating leases in accordance with GAAP.
The combined purchase price of $3.1 billion for all of the interests acquired by
the owner trusts in 1987 was funded with debt of $2.5 billion and equity of $600
million.
FirstEnergy is exposed to losses under the sale-leaseback agreements
upon the occurrence of certain contingent events that we consider unlikely to
occur. The Company's maximum exposure to loss is currently estimated to be $2.0
billion, which represents the net amount of casualty value payments upon the
occurrence of specified casualty events that render the plants worthless. Under
the sale and leaseback agreements, FirstEnergy has minimum undiscounted net
lease payments of $2.6 billion that would not be payable if the casualty value
payments are made. In addition, the Company has recorded above market lease
obligations of $1.1 billion related to the Bruce Mansfield Plant and Beaver
Valley Unit 2 as of September 30, 2003 (see Note 1) related to the acquisition
by FirstEnergy of CEI and TE.
FirstEnergy currently believes that it will consolidate two VIE's
created in 1996 and 1997 to refinance debt in connection with the above sale and
leaseback transactions. In 1996, the PNBV Capital Trust issued equity and notes
to fund the acquisition of a portion of the collateralized lease bonds that had
been issued by certain owner trusts in connection with the sale and leaseback in
1987 of a portion of OE's interest in the Perry Plant and Beaver Valley Unit 2.
OE used debt and available funds to purchase the notes issued by the PNBV Trust.
Ownership of the trust includes a three-percent equity interest by a
nonaffiliated third party and a three-percent equity interest held by OES
Ventures, a wholly owned subsidiary of OE. Consolidation of the trust as of
December 31, 2002 would have changed the PNBV trust investment of $389 million
to an investment in collateralized lease bonds of $401 million. The increase in
$12 million would have represented the minority interest in the total assets of
the trust.
In 1997, CEI and TE established the Shippingport Capital Trust to
purchase all of the lease obligation bonds issued by the owner trusts in the
Bruce Mansfield Plant sale and leaseback transactions. CEI and TE acquired all
of the notes issued by Shippingport Capital Trust. The equity ownership of this
trust includes a 0.34% interest held by Toledo Edison Capital Corporation
(TECC), a wholly owned subsidiary of TE, and a 2.25% interest and a 2.60%
interest held by unaffiliated third parties. The assets and liabilities of the
trust are currently included on a proportionate basis in the financial
statements of CEI and TE. Adoption of FIN 46 will not impact FirstEnergy with
respect to this trust, but may result in reporting all of the trust assets and
liabilities on the books of CEI.
As described in Note 1, the consolidated financial statements of
FirstEnergy, CEI, Met-Ed and Penelec currently include several trusts that have
sold trust preferred securities in which FirstEnergy is not the primary
beneficiary. Pending further guidance from the FASB that would indicate
otherwise, these entities may not be consolidated in FirstEnergy's financial
statements as of December 31, 2003. The deconsolidation would result in an
increase to total assets and liabilities of $9.3 million ($3.1 million for each
of CEI, Met-Ed and Penelec) for the investment in the trusts.
51
The FASB continues to provide additional guidance on implementing FIN
46 and recently proposed modifications and clarifications with a comment period
ending December 1, 2003. As this guidance is finalized, the Company will
continue to assess the accounting and disclosure impact of FIN 46 with respect
to the VIE's discussed above as well as other potential VIE's.
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 of a general index, such as the Consumer
Price Index, in a contract would prevent that contract from qualifying for the
normal purchases and normal sales (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 but does not anticipate any material impact
on its financial statements.
52
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------- -----------------------
2003 2002 2003 2002
-------- -------- ---------- ----------
Restated Restated
(See Note 1) (See Note 1)
(In thousands)
OPERATING REVENUES........................................ $774,859 $813,296 $2,191,310 $2,265,645
-------- -------- ---------- ----------
OPERATING EXPENSES AND TAXES:
Fuel................................................... 13,978 15,649 37,118 45,068
Purchased power........................................ 231,619 243,475 691,802 698,126
Nuclear operating costs................................ 98,742 79,388 342,319 255,322
Other operating costs.................................. 107,509 94,820 278,109 252,928
-------- -------- ---------- ----------
Total operation and maintenance expenses........... 451,848 433,332 1,349,348 1,251,444
Provision for depreciation and amortization............ 121,734 90,991 335,872 273,932
General taxes.......................................... 46,863 47,254 139,525 135,154
Income taxes........................................... 66,453 92,941 144,533 215,506
-------- -------- ---------- ----------
Total operating expenses and taxes................. 686,898 664,518 1,969,278 1,876,036
-------- -------- ---------- ----------
OPERATING INCOME.......................................... 87,961 148,778 222,032 389,609
OTHER INCOME.............................................. 16,439 14,212 45,351 29,811
-------- -------- ---------- ----------
INCOME BEFORE NET INTEREST CHARGES........................ 104,400 162,990 267,383 419,420
-------- -------- ---------- ----------
NET INTEREST CHARGES:
Interest on long-term debt............................. 21,241 29,548 70,686 92,933
Allowance for borrowed funds used during construction
and capitalized interest............................. (1,668) (1,018) (4,172) (2,522)
Other interest expense................................. 3,144 2,889 14,947 10,837
Subsidiaries' preferred stock dividend requirements.... 911 2,276 2,735 9,528
-------- -------- ---------- ----------
Net interest charges............................... 23,628 33,695 84,196 110,776
-------- -------- ---------- ----------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING
CHANGE.................................................... 80,772 129,295 183,187 308,644
Cumulative effect of accounting change (net of income
taxes of $22,389,000) (Note 5)......................... -- -- 31,720 --
-------- -------- ---------- ----------
NET INCOME................................................ 80,772 129,295 214,907 308,644
PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 659 658 1,977 5,851
-------- -------- ---------- ----------
EARNINGS ON COMMON STOCK.................................. $ 80,113 $128,637 $ 212,930 $ 302,793
======== ======== ========== ==========
The preceding Notes to Financial Statements as they relate to Ohio Edison Company are an integral part of these statements.
53
OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2003 2002
------------- -------------
(See Note 1)
(In thousands)
ASSETS
------
UTILITY PLANT:
In service................................................................. $5,220,708 $4,989,056
Less-Accumulated provision for depreciation................................ 2,620,419 2,552,007
---------- ----------
2,600,289 2,437,049
---------- ----------
Construction work in progress-
Electric plant........................................................... 136,075 122,741
Nuclear fuel............................................................. 16,390 23,481
---------- ----------
152,465 146,222
---------- ----------
2,752,754 2,583,271
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
PNBV Capital Trust......................................................... 387,770 402,565
Letter of credit collateralization......................................... 277,763 277,763
Nuclear plant decommissioning trusts....................................... 346,378 293,190
Long-term notes receivable from associated companies....................... 509,684 503,827
Other...................................................................... 65,678 74,220
---------- ----------
1,587,273 1,551,565
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents.................................................. 1,792 20,512
Receivables-
Customers (less accumulated provisions of $8,635,000 and
$5,240,000, respectively for uncollectible accounts)................... 281,801 296,548
Associated companies..................................................... 668,273 592,218
Other (less accumulated provisions of $1,000,000 for uncollectible
accounts at both dates)................................................ 29,169 30,057
Notes receivable from associated companies................................. 577,822 437,669
Materials and supplies, at average cost-
Owned.................................................................... 58,799 58,022
Under consignment........................................................ 14,261 19,753
Prepayments and other...................................................... 18,089 11,804
---------- ----------
1,650,006 1,466,583
---------- ----------
DEFERRED CHARGES:
Regulatory assets.......................................................... 1,644,158 2,005,554
Property taxes............................................................. 59,035 59,035
Unamortized sale and leaseback costs....................................... 66,978 72,294
Other...................................................................... 59,223 51,739
---------- ----------
1,829,394 2,188,622
---------- ----------
$7,819,427 $7,790,041
========== ==========
54
OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2003 2002
------------- -------------
(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..................................... (98,638) (59,495)
Retained earnings........................................................ 633,951 800,021
---------- ----------
Total common stockholder's equity.................................... 2,634,042 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 (Note 5)................................. -- 13,500
Long-term debt and other long-term obligations-
Preferred stock of consolidated subsidiary subject to mandatory
redemption (Note 5) ................................................... 13,500 --
Other.................................................................... 1,477,530 1,219,347
---------- ----------
4,225,142 4,172,172
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock....................... 417,216 563,267
Short-term borrowings-
Associated companies..................................................... 9,947 225,345
Other.................................................................... 174,578 182,317
Accounts payable-
Associated companies..................................................... 268,214 145,981
Other.................................................................... 3,537 18,015
Accrued taxes.............................................................. 646,668 466,064
Accrued interest........................................................... 22,686 28,209
Other...................................................................... 107,596 74,562
---------- ----------
1,650,442 1,703,760
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes.......................................... 864,355 1,017,629
Accumulated deferred investment tax credits................................ 78,977 88,449
Asset retirement obligation................................................ 312,560 --
Nuclear plant decommissioning costs........................................ -- 280,858
Retirement benefits........................................................ 405,088 247,531
Other...................................................................... 282,863 279,642
---------- ----------
1,943,843 1,914,109
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)............................
---------- ----------
$7,819,427 $7,790,041
========== ==========
The preceding Notes to Financial Statements as they relate to Ohio Edison Company are an integral part of these balance sheets.
55
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------- -----------------------
2003 2002 2003 2002
-------- -------- ---------- ----------
Restated Restated
(See Note 1) (See Note 1)
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................ $ 80,772 $ 129,295 $ 214,907 $ 308,644
Adjustments to reconcile net income to net cash from
operating activities-
Provision for depreciation and amortization........ 121,734 90,991 335,872 273,932
Nuclear fuel and capital lease amortization........ 10,542 12,389 28,411 35,924
Deferred operating lease costs, net................ 33,977 32,908 31,300 32,726
Deferred income taxes, net......................... (30,010) (12,682) (50,714) (39,838)
Amortization of investment tax credits............. (3,681) (3,427) (11,077) (10,315)
Accrued retirement benefit obligations............. 20,471 6,325 31,652 6,143
Accrued compensation, net.......................... 366 5,651 (8,111) 3,757
Cumulative effect of accounting change (Note 5).... -- -- (54,109) --
Receivables........................................ 329,852 (18,352) (50,930) 14,451
Materials and supplies............................. (956) (3,699) 4,715 (8,499)
Accounts payable................................... (141,910) 18,690 113,508 (771)
Accrued taxes...................................... 131,470 16,302 180,604 222,562
Accrued interest................................... (417) 1,926 (5,523) (37)
Prepayments and other current assets............... 3,514 1,791 (6,285) 33,064
Other.............................................. (1,238) (3,718) 28,313 (36,413)
--------- --------- ---------- ----------
Net cash provided from operating activities...... 554,486 274,390 782,533 835,330
--------- --------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt....................................... -- 14,500 575,000 14,500
Short-term borrowings, net........................... -- 348,132 -- 321,974
Redemptions and Repayments-
Preferred stock...................................... -- (220,000) -- (220,000)
Long-term debt....................................... (209,111) (182,595) (467,567) (411,336)
Short-term borrowings, net........................... (4,547) -- (223,137) --
Dividend Payments-
Common stock......................................... (94,000) (20,700) (379,000) (121,900)
Preferred stock...................................... (659) (658) (1,977) (5,851)
--------- --------- ---------- -----------
Net cash used for financing activities .......... (308,317) (61,321) (496,681) (422,613)
--------- --------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions..................................... (39,432) (32,130) (141,126) (87,851)
Notes receivable from associated companies, net........ (197,289) (165,340) (146,010) (300,119)
Other.................................................. (10,020) 6,047 (17,436) 16,450
--------- --------- ---------- ----------
Net cash used for investing activities........... (246,741) (191,423) (304,572) (371,520)
--------- --------- ---------- ----------
Net increase (decrease) in cash and cash equivalents...... (572) 21,646 (18,720) 41,197
Cash and cash equivalents at beginning of period.......... 2,364 24,139 20,512 4,588
--------- --------- ---------- ----------
Cash and cash equivalents at end of period................ $ 1,792 $ 45,785 $ 1,792 $ 45,785
========= ========= ========== ==========
The preceding Notes to Financial Statements as they relate to Ohio Edison Company are an integral part of these statements.
56
REPORT OF INDEPENDENT ACCOUNTANTS
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 September 30, 2003, and the related
consolidated statements of income and cash flows for each of the three-month and
nine-month periods ended September 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 each of the three-month and nine-month periods ended
September 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
November 13, 2003
57
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 restated 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. These restatements were completed and reported in the
second quarter of 2003. Financial comparisons described below for the
three-month and nine month-periods reflect the effect of these restatements.
RESULTS OF OPERATIONS
Earnings on common stock in the third quarter of 2003 decreased to
$80.1 million from $128.6 million in the third quarter of 2002. During the first
nine months of 2003, earnings on common stock decreased to $212.9 million from
$302.8 million in the same period of 2002. In the first nine 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 $183.2 million in the first nine months of 2003, compared to $308.6
million for the same period of 2002.
Results in the third quarter of 2003 were adversely affected by lower
revenues due to milder 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. These adverse effects were partially offset by reduced
nuclear fuel expenses as a result of the additional nuclear outage in 2003 and
reduced financing costs compared to the third quarter of 2002.
In the first nine months of 2003, results were negatively affected by
lower revenues from mild weather in the second and third quarters of 2003, which
moderated the effect of unusually cold weather earlier in the year. Additional
nuclear outage-related work and increased amortization of the Ohio transition
regulatory assets were also primary factors contributing to an increase in
operating expenses in the first nine months 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 $38.4 million or 4.7% in the third
quarter and $74.3 million or 3.3% in the first nine months of 2003 compared with
the same periods in 2002 due to cooler-than-normal temperatures in the second
and third quarters, continued sluggishness in the regional 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 12.9% in the third quarter and 10.5% in the first nine
months of 2003 from the same periods of 2002, reducing generation sales revenue
by $36.4 million and $97.1 million, respectively. Electric generation services
provided to retail customers by alternative suppliers as a percent of total
kilowatt-hours delivered in OE's franchise area increased 6.0 percentage points
in the third quarter and 7.5 percentage points in the first nine months of 2003
from the corresponding periods last year.
Distribution deliveries decreased 5.6% and 1.2% in the third quarter
and the first nine months of 2003, respectively, compared with the corresponding
periods of 2002. The lower distribution deliveries in the third quarter of 2003
reflected the milder weather in that period compared to the same period last
year which reduced residential and commercial usage - the customer groups
accounting for most of a $23.1 million reduction in revenues from electricity
throughput. In the nine months of 2003, unusually cold weather in early 2003
increased distribution deliveries to commercial customers, providing most of the
increase in revenues from distribution throughput compared to the same period in
2002. The third quarter and first nine months of 2003 were both adversely
impacted by the continued effects of a sluggish regional economy reducing demand
by industrial customers in OE's franchise area.
58
Operating revenues were further reduced in 2003 as a result of the
Ohio transition plan incentives provided to customers to promote customer
shopping for alternative suppliers - $1.9 million of additional credits in the
first nine months of 2003 from the corresponding period 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 increased by $12.0 million
and $24.5 million in the third quarter and the first nine months of 2003,
respectively, compared to the same periods of 2002. These results reflect the
effect of higher unit prices, partially offset by lower kilowatt-hour sales to
the wholesale market due to reduced nuclear generation available for sale to
FES.
Changes in electric generation sales and distribution deliveries in
the third quarter and first nine months of 2003 from the corresponding periods
of 2002 are summarized in the following table:
Changes in Kilowatt-Hour Sales Three Months Nine Months
---------------------------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail............................... (12.9)% (10.5)%
Wholesale............................ (9.2)% (14.6)%
-------------------------------------------------------------------
Total Electric Generation Sales........ (11.1)% (12.4)%
===================================================================
Distribution Deliveries:
Residential.......................... (11.2)% (3.2)%
Commercial........................... (1.4)% 0.8%
Industrial........................... (3.1)% (1.0)%
-------------------------------------------------------------------
Total Distribution Deliveries.......... (5.6)% (1.2)%
===================================================================
Operating Expenses and Taxes
Total operating expenses and taxes increased $22.4 million and $93.2
million in the third quarter and the first nine months of 2003, respectively,
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 Nine Months
-----------------------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel............................................ $ (1.7) $ (7.9)
Purchased power costs........................... (11.8) (6.3)
Nuclear operating costs......................... 19.3 87.0
Other operating costs........................... 12.7 25.1
------------------------------------------------------------------------
Total operation and maintenance expenses...... 18.5 97.9
Provision for depreciation and amortization..... 30.8 61.9
General taxes................................... (0.4) 4.4
Income taxes.................................... (26.5) (71.0)
------------------------------------------------------------------------
Net increase in operating expenses and taxes.. $ 22.4 $ 93.2
========================================================================
Lower fuel costs in the third quarter and first nine months of 2003,
compared with the same periods of 2002, resulted from reduced nuclear generation
- down 4.7% and 15.1%, respectively. In the third quarter and first nine months
of 2003, the kilowatt-hour purchase requirements were lower than the same
periods in 2002 because of reduced electric generation sales - those cost
reductions were partially offset by the effect of higher unit costs. Higher
nuclear operating costs in the 2003 periods were driven by three nuclear
refueling outages in 2003 - Beaver Valley Unit 1 (100% ownership), Beaver Valley
Unit 2 (55.62% interest) and the Perry Plant (35.24% ownership) in 2003 compared
with one refueling outage at Beaver Valley Unit 2 in 2002. The Beaver Valley
Unit 1 and Perry refueling outages earlier 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 third quarter and first nine months of
2003, compared to the same periods of 2002, primarily reflects higher employee
benefit costs and energy delivery costs as a result of storm damage.
Charges for depreciation and amortization increased by $30.8 million
in the third quarter of 2003 compared to the third quarter of 2002 primarily
from three factors - increased amortization of the Ohio transition regulatory
assets ($16.6 million), reduced shopping incentive deferrals ($9.0 million) and
reduced transition plan regulatory asset deferrals in 2003 ($10.3 million).
Partially offsetting these increases were lower charges resulting from the
implementation of SFAS 143 ($4.6 million).
In the first nine months of 2003, depreciation and amortization
increased by $61.9 million compared to the corresponding period of 2002 as a
result of the same factors which impacted the third quarter comparison -
increased
59
amortization of the Ohio transition regulatory assets ($58.3 million) and
reduced transition plan regulatory asset deferrals ($22.5 million) in 2003.
Partially offsetting these increases in depreciation and amortization were
higher shopping incentive deferrals ($1.9 million) and lower charges resulting
from the implementation of SFAS 143 ($15.5 million).
General taxes increased in the first nine months of 2003 from the
same periods of 2002 principally due to higher kilowatt-hour excise taxes in
Ohio.
Other Income
Other income increased by $15.5 million in the first nine months of
2003 from the same period last year, primarily due to the absence in 2003 of
adjustments recorded in the first nine months of 2002 related to OE's low income
housing investments.
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $10.1
million in the third quarter and $26.6 million in the first nine months of 2003
from the same periods last year, reflecting redemptions and refinancings since
the third quarter of last year. OE's mandatory debt redemptions totaled $230.2
million during the first nine months of 2003, are expected to result in
annualized savings of $19.0 million.
Cumulative Effect of Accounting Change
Results for the first nine 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 $281
million. Penn expects substantially all of its nuclear decommissioning costs to
be recoverable in rates over time. Therefore, Penn 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. 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.
Changes in Cash Position
As of September 30, 2003, OE had $1.8 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 third quarter and
first nine months of 2003, compared with the corresponding periods in 2002 were
as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------------------------
Operating Cash Flows 2003 2002 2003 2002
-------------------------------------------------------------------------------
(In millions)
Cash earnings (1).............. $234 $261 $519 $611
Working capital and other...... 320 13 264 224
-------------------------------------------------------------------------------
Total.......................... $554 $274 $783 $835
-------------------------------------------------------------------------------
(1) Includes net income, depreciation and amortization,
deferred income taxes, investment tax credits and major
noncash charges.
60
Net cash from operating activities increased $280 million in the
third quarter of 2003 due to a $307 million increase in funds from working
capital, partially offset by a $27 million decrease in cash earnings. The change
in working capital and other primarily reflects lower accounts receivable in the
third quarter of 2003 compared with the corresponding change in the third
quarter of 2002 ($348 million). A higher tax accrual in the third quarter of
2003, compared to 2002, also contributed $115 million to the increase in working
capital.
Cash Flows From Financing Activities
In the third quarter of 2003, net cash used for financing activities
increased to $308 million from $61 million used in the same period last year.
The increase resulted from the absence of new financing in 2003 and increased
dividends to FirstEnergy.
OE had approximately $579.6 million of cash and temporary investments
and approximately $184.5 million of short-term indebtedness as of September 30,
2003. Available borrowing capability under bilateral bank facilities totaled
$34.0 million as of September 30, 2003. OE had the capability to issue $1.8
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 $1.6 billion of preferred stock (assuming no additional debt was issued)
as of September 30, 2003. In October 2003, FirstEnergy renewed $1 billion of
credit facilities (including OE's 364-day $125 million facility and 3-year $125
million facility).
Cash Flows From Investing Activities
Net cash used for investing activities totaled $247 million in the
third quarter of 2003, compared to $191 million for the same period of 2002. The
$56 million increase in funds used for investing activities resulted from
increases in short-term loans to associated companies.
During the fourth quarter of 2003, capital requirements for property
additions and capital leases are expected to be about $32 million, including $1
million for nuclear fuel. OE has additional requirements of approximately $17
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 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 (OE has no ownership interest in this facility). 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."
On September 30, 2003, Fitch Ratings lowered the senior unsecured
ratings of FirstEnergy to "BBB-" from "BBB." Fitch also lowered the senior
secured, senior unsecured, and preferred stock ratings of Met-Ed, Penelec, CEI,
and TE. In addition, Fitch affirmed the ratings of OE, Penn and JCP&L. Fitch
announced that the Rating Outlook is Stable for the securities of FirstEnergy,
and all of the securities of its electric utility operating companies. Fitch
stated that the changes to the long-term ratings were "driven by the high debt
leverage of the parent FE. Despite management's commitment to reduce debt
related to the GPU merger, subsequent cash flows have been vulnerable to
unfavorable events, slowing the pace of FE's debt reduction efforts. The Stable
Outlook reflects the success of FE's recent common equity offering and
management's focus on a relatively conservative integrated utility strategy."
On October 27, 2003, Standard & Poors (S&P) stated that the `BBB'
corporate credit and the `BBB-` senior unsecured ratings for FirstEnergy and its
utility subsidiaries remain on CreditWatch with negative implications. The
ratings were placed on CreditWatch on August 18, 2003, and reflect S&P's
concerns regarding the potential impact of the August 14, 2003 blackout
investigation on FirstEnergy's deleveraging strategy and its overall efforts to
improve its credit profile.
At that time, S&P also noted other challenges facing FirstEnergy,
including the extended Davis-Besse outage; the recent U.S. District Court ruling
regarding the Sammis Plant (see Environmental Matters below); reliability
concerns in subsidiary JCP&L's service territory; and FirstEnergy's credibility
with regulators and federal officials.
S&P further noted several factors that could aid FirstEnergy in
resolution of the CreditWatch, including strengthening its balance sheet.
FirstEnergy directly addressed this concern through its recently completed
common equity offering that raised approximately $935 million in net proceeds,
which was used to reduce bank debt. S&P described the equity offering as a
"positive credit development" and also noted the recent renewal of FirstEnergy's
$1 billion revolver facilities as a "favorable development, as it mitigates
liquidity concerns." S&P also indicated that should various ongoing
investigations into the causal factors of the August 14, 2003 blackout establish
that the blackout resulted
61
from no negligence or breach of compliance standards on FirstEnergy's part, the
CreditWatch could be removed and the outlook returned to negative. S&P deemed a
"stable" credit outlook unlikely until issues such as the restart of Davis-Besse
are resolved and the potential effect of the litigation relating to the Sammis
plant (the second trial is scheduled for April 2004) are known. Extension of the
Ohio transition plan will be viewed as a positive development and will support
an outlook revision to stable.
On October 27, 2003, S&P also noted that the ratings on FirstEnergy
and its subsidiaries incorporate such strengths as the ability to generate free
cash flow, power generation contracted to its transmission and distribution
subsidiaries through 2005, and the hedging of its short power position arising
from its PLR obligation in Pennsylvania. S&P said that these strengths are
offset by slower than anticipated reduction of FirstEnergy debt, remaining
volume risks of PLR obligations, the extended outage at Davis-Besse, the
unfavorable outcome of the New Jersey rate proceeding and regulatory uncertainty
in Ohio. S&P also said that it now views FirstEnergy's liquidity position as
average, following FirstEnergy's renewal of its $1 billion credit facilities.
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 September 30, 2003, the present value of these sale and
leaseback operating lease commitments, net of trust investments, total $709
million.
EQUITY PRICE RISK
Included in OE's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $180
million and $148 million as of September 30, 2003 and December 31, 2002,
respectively. A hypothetical 10% decrease in prices quoted by stock exchanges
would result in an $18 million reduction in fair value as of September 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.
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 by $361.4 million during the first nine
months of 2003, to $1.6 billion as of September 30, 2003; $10.6 million of the
decrease related to the cumulative adjustment related to the adoption of 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:
September 30, December 31,
Regulatory Assets 2003 2002
---------------------------------------------------------
(In millions)
OE......................... $1,594.0 $1,848.7
Penn....................... 50.2 156.9
---------------------------------------------------------
Consolidated Total...... $1,644.2 $2,005.6
=========================================================
As part of OE's Ohio transition plan, OE 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 who 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.
62
On October 21, 2003, the Ohio Companies filed an application with the
PUCO to establish generation service rates beginning January 1, 2006, in
response to expressed concerns by the PUCO about price and supply uncertainty
following the end of the market development period. The filing included two
options:
o A competitive auction, which would establish a price for
generation that customers would be charged during the period
covered by the auction, or
o A Rate Stabilization Plan, which would extend current generation
prices through 2008, ensuring adequate supply and continuing
FirstEnergy's support of energy efficiency and economic
development efforts.
Under the first option, an auction would be conducted to secure
generation service, including PLR responsibility, for FirstEnergy's Ohio
customers. Beginning in 2006, customers would pay market prices for generation
as determined by the auction.
Under the Rate Stabilization Plan option, customers would have price
and supply stability through 2008 - three years beyond the end of the market
development period - as well as the benefits of a competitive market. Customer
benefits would include: customer savings by extending the current five percent
discount on generation costs and other customer credits; maintaining current
distribution base rates through 2007; market-based auctions that may be
conducted annually to ensure that customers pay the lowest available prices;
extension of FirstEnergy's support of energy-efficiency programs and the
potential for continuing the program to give preferred access to nonaffiliated
entities to generation capacity as discussed above. In order to facilitate
supply planning, FirstEnergy has requested that the PUCO rule on this proposal
by December 31, 2003. Under the proposed plan, OE is requesting:
o Extension of the transition cost amortization period for OE from
2006 to 2007;
o Deferral of new regulatory assets and deferral of interest costs on
the shopping incentive and other new deferrals;
o Ability to initiate a request to increase generation rates only
under certain limited conditions.
As a result of the Ohio Companies' October 21 filing, the PUCO
entered an order on October 28, 2003 setting forth the discovery schedule
related to the application with hearings scheduled to begin December 3, 2003.
Environmental Matters
OE believes it is in compliance with the current sulfur dioxide (SO2)
and nitrogen oxide (NOx) reduction requirements under the Clean Air Act
Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized
regulations requiring additional NOx reductions in the future from OE's Ohio and
Pennsylvania facilities. Various regulatory and judicial actions have since
sought to further define NOx reduction requirements (see Note 2 - Environmental
Matters). OE continues to evaluate its compliance plans and other compliance
options.
Violations of federally approved SO2 regulations can result in
shutdown of the generating unit involved and/or civil or criminal penalties of
up to $31,500 for each day a unit is in violation. The EPA has an interim
enforcement policy for SO2 regulations in Ohio that allows for compliance based
on a 30-day averaging period. 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, 2003, the United States District Court for the Southern
District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant
between 1984 and 1998 required pre-construction permits under the Clean Air Act.
The ruling concludes the liability phase of the case, which deals with
applicability of Prevention of Significant Deterioration provisions of the Clean
Air Act. The remedy phase, which is currently scheduled to be ready for trial
beginning April 19, 2004, will address civil penalties and what, if any, actions
should be taken to further reduce emissions at the plant. In the ruling, the
Court indicated that the remedies it "may consider and impose involved a much
broader, equitable analysis, requiring the Court to consider air quality, public
health, economic impact and employment consequences. The Court may also consider
the less than consistent efforts of the EPA to apply and further enforce the
Clean Air Act." The potential penalties that may be imposed, as well as the
capital expenditures necessary to comply with substantive remedial measures that
may be required, could have a material adverse impact on the Company's financial
condition and results of operations. Management is unable to predict the
ultimate outcome of this matter and no liability has been recorded as of
September 30, 2003.
63
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants. The EPA identified mercury as the hazardous air pollutant of
greatest concern. The EPA established a schedule to propose regulations by
December 2003 and issue final regulations by December 2004. The future cost of
compliance with these regulations may be substantial.
As a result of the Resource Conservation and Recovery Act of 1976, as
amended, and the Toxic Substances Control Act of 1976, federal and state
hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous waste
disposal requirements pending the EPA's evaluation of the need for future
regulation. The EPA has issued its final regulatory determination that
regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the
EPA announced that it will develop national standards regulating disposal of
coal ash under its authority to regulate nonhazardous waste.
OE believes it is in compliance with the current SO2 and 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.
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 -
$1.6 billion as of September 30, 2003. 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 billed through the end of the accounting period. The determination of
unbilled revenues requires management to make various estimates including:
64
o Net energy generated or purchased for retail load
o Losses of energy
over distribution lines
o 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 is not 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 connection with FirstEnergy's restructuring plan, the PUCO
determined allowable transition costs based on amounts recorded on OE's
regulatory books. These costs exceeded those deferred or capitalized on OE's
balance sheet prepared under GAAP since they included certain costs which have
not yet been incurred. OE uses an effective interest method for amortizing its
transition costs, often referred to as a "mortgage-style" amortization. The
interest rate under this method is equal to the rate of return authorized by the
PUCO in the transition plan for OE. In computing the transition cost
amortization, OE includes only the portion of the transition revenues associated
with transition costs included on the balance sheet prepared under GAAP.
Revenues collected for the off balance sheet costs and the return associated
with these costs are recognized as income when received.
Long-Lived Assets
In accordance with SFAS 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
65
be recognized in the financial statements. If impairment other than of a
temporary nature has occurred, the OE Companies recognize a loss - calculated as
the difference between the carrying value and the estimated fair value of the
asset (discounted future net cash flows).
RECENTLY ISSUED ACCOUNTING STANDARDS
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". This Interpretation requires the
consolidation of a variable interest entity (VIE) by an enterprise if that
enterprise either absorbs a majority of the VIE's expected losses or receives a
majority of the VIE's expected residual returns as a result of ownership,
contractual or other financial interests in the VIE. Currently, entities are
generally consolidated by an enterprise that has a controlling financial
interest through ownership of a majority voting interest in the entity.
FIN 46 defines a VIE as an entity in which equity investors do not
have the characteristics of a controlling financial interest nor have sufficient
equity at risk for the entity to finance its activities without additional
subordinated financial support. VIE's created after January 31, 2003, are
immediately subject to the provisions of FIN 46. The FASB recently deferred
implementation of FIN 46 for VIE's created before February 1, 2003, until the
first reporting period ending after December 15, 2003 (OE's quarter ending
December 31, 2003.)
OE currently has transactions with entities in connection with sale
and leaseback arrangements which may fall within the scope of this
interpretation and which meet the definition of a VIE in accordance with FIN 46.
The Company currently believes that it will consolidate the PNBV Capital Trust,
which issued equity and notes to fund the acquisition of a portion of the
collateralized lease bonds that had been issued in connection with the sale and
leaseback in 1987 of a portion of OE's interest in the Perry Plant and Beaver
Valley Unit 2. OE used debt and available funds to purchase the notes issued by
the PNBV Trust. Ownership of the trust includes a three-percent equity interest
by a nonaffiliated third party and a three-percent equity interest by OES
Ventures, a wholly owned subsidiary of OE. Consolidation of the trust as of
December 31, 2002 would have changed the PNBV trust investment of $389 million
to an investment in collateralized lease bonds of $401 million. The increase in
$12 million would have represented the minority interest in the total assets of
the trust.
In addition to the PNBV Capital Trust discussed above, the Company is
evaluating its interest in the owner trusts that acquired certain interests in
the Perry Plant and Beaver Valley Unit 2. OE has not completed its evaluation to
determine if it would be the primary beneficiary and therefore required to
consolidate these trusts.
The FASB continues to provide additional guidance on implementing FIN
46 and recently proposed modifications and clarifications with a comment period
ending December 1, 2003. As this guidance is finalized, OE will continue to
assess the accounting and disclosure impact of FIN 46 with respect to the VIE's
discussed above as well as other potential VIE's.
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.
Upon adoption of SFAS 150, on July 1, 2003, OE reclassified as debt
the preferred stock of consolidated subsidiaries subject to mandatory redemption
having carrying values of approximately $13.5 million as of September 30, 2003.
Prior to the adoption of SFAS 150, subsidiary preferred dividends on OE's
Consolidated Statements of Income were included in net interest charges.
Therefore, the application of SFAS 150 did 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 on Issue No. 01-08,
regarding when arrangements contain a lease. Based on the EITF consensus, an
arrangement contains a lease if: (1) it identifies specific property, plant or
equipment (explicitly or implicitly); and (2) the arrangement transfers the
right to the purchaser to control the use of the property, plant or equipment.
The consensus is to be applied prospectively to arrangements committed to,
modified or acquired through a business combination. The adoption of this
consensus as of July 1, 2003 did not impact OE's financial statements.
66
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- -------------------------
2003 2002 2003 2002
-------- -------- ---------- ----------
Restated Restated
(See Note 1) (See Note 1)
(In thousands)
OPERATING REVENUES........................................ $496,699 $538,879 $1,328,603 $1,435,030
-------- -------- ---------- ----------
OPERATING EXPENSES AND TAXES:
Fuel................................................... 5,536 15,809 31,580 48,167
Purchased power........................................ 139,661 140,357 407,261 398,251
Nuclear operating costs................................ 67,449 49,093 190,028 143,695
Other operating costs.................................. 65,230 73,586 191,525 192,686
-------- -------- ---------- ----------
Total operation and maintenance expenses........... 277,876 278,845 820,394 782,799
Provision for depreciation and amortization............ 42,443 47,646 147,111 153,250
General taxes.......................................... 37,689 40,771 114,741 116,010
Income taxes........................................... 38,719 51,705 47,827 98,459
-------- -------- ---------- ----------
Total operating expenses and taxes................. 396,727 418,967 1,130,073 1,150,518
-------- -------- ---------- ----------
OPERATING INCOME.......................................... 99,972 119,912 198,530 284,512
OTHER INCOME.............................................. 6,467 5,562 15,892 14,159
-------- -------- ---------- ----------
INCOME BEFORE NET INTEREST CHARGES........................ 106,439 125,474 214,422 298,671
-------- -------- ---------- ----------
NET INTEREST CHARGES:
Interest on long-term debt............................. 38,130 44,441 118,069 136,808
Allowance for borrowed funds used during construction.. (1,920) (1,155) (5,724) (2,651)
Other interest expense................................. 163 1,727 199 1,073
Subsidiaries' preferred stock dividend requirements.... 2,250 2,250 9,450 6,650
-------- -------- ---------- ----------
Net interest charges............................... 38,623 47,263 121,994 141,880
-------- -------- ---------- ----------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING
CHANGE ................................................... 67,816 78,211 92,428 156,791
Cumulative effect of accounting change (net of income
taxes of $30,168,000) (Note 5)......................... -- -- 42,378 --
-------- -------- ---------- ----------
NET INCOME................................................ 67,816 78,211 134,806 156,791
PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 1,865 3,149 2,970 12,759
-------- -------- ---------- ----------
EARNINGS ON COMMON STOCK.................................. $ 65,951 $ 75,062 $ 131,836 $ 144,032
======== ======== ========== ==========
The preceding Notes to Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of
these statements.
67
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2003 2002
------------- ------------
(See Note 1)
(In thousands)
ASSETS
------
UTILITY PLANT:
In service................................................................ $4,208,873 $4,045,465
Less-Accumulated provision for depreciation............................... 1,892,945 1,824,884
---------- ----------
2,315,928 2,220,581
---------- ----------
Construction work in progress-
Electric plant.......................................................... 137,096 153,104
Nuclear fuel............................................................ 28,554 45,354
---------- ----------
165,650 198,458
---------- ----------
2,481,578 2,419,039
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Shippingport Capital Trust................................................ 385,945 435,907
Nuclear plant decommissioning trusts...................................... 279,074 230,527
Long-term notes receivable from associated companies...................... 108,192 102,978
Other..................................................................... 20,805 21,004
---------- ----------
794,016 790,416
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents................................................. 159 30,382
Receivables-
Customers............................................................... 9,977 11,317
Associated companies.................................................... 39,680 74,002
Other (less accumulated provisions of $1,000,000 and $1,015,000,
respectively, for uncollectible accounts)............................. 83,577 134,375
Notes receivable from associated companies................................ 587 447
Materials and supplies, at average cost-
Owned................................................................... 16,724 18,293
Under consignment....................................................... 31,016 38,094
Prepayments and other..................................................... 3,503 4,217
---------- ----------
185,223 311,127
---------- ----------
DEFERRED CHARGES:
Regulatory assets......................................................... 1,138,236 1,191,804
Goodwill.................................................................. 1,693,629 1,693,629
Property taxes............................................................ 79,430 79,430
Other..................................................................... 23,980 24,798
---------- ----------
2,935,275 2,989,661
---------- ----------
$6,396,092 $6,510,243
========== ==========
68
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2003 2002
------------- ------------
(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.................................... (17,061) (44,284)
Retained earnings....................................................... 394,162 262,323
---------- ----------
Total common stockholder's equity................................... 1,359,063 1,200,001
Preferred stock-
Not subject to mandatory redemption..................................... 96,404 96,404
Subject to mandatory redemption (Note 5)................................ -- 5,021
Company obligated mandatorily redeemable preferred securities of
subsidiary trust holding solely Company subordinated debentures
(Note 5) ............................................................... -- 100,000
Long-term debt and other long-term obligations-
Preferred stock subject to mandatory redemption (Note 5)................ 4,016 --
Company-obligated mandatorily redeemable preferred securities of
subsidiary trust holding solely Company subordinated debentures
(Note 5)......... .................................................... 100,000 --
Other................................................................... 1,773,797 1,975,001
---------- ----------
3,333,280 3,376,427
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock...................... 438,289 388,190
Accounts payable-
Associated companies.................................................... 242,433 267,664
Other................................................................... 5,762 14,583
Notes payable to associated companies..................................... 215,093 288,583
Accrued taxes............................................................. 160,026 126,261
Accrued interest.......................................................... 56,195 51,767
Lease market valuation liability.......................................... 60,000 60,000
Other..................................................................... 46,865 64,624
---------- ----------
1,224,663 1,261,672
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes......................................... 494,638 407,297
Accumulated deferred investment tax credits............................... 67,198 70,803
Nuclear plant decommissioning costs....................................... -- 242,511
Asset retirement obligation............................................... 250,687 --
Retirement benefits....................................................... 116,308 171,968
Lease market valuation liability.......................................... 743,700 788,800
Other..................................................................... 165,618 190,765
---------- ----------
1,838,149 1,872,144
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)...........................
---------- ----------
$6,396,092 $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.
69
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------- -------------------------
2003 2002 2003 2002
--------- --------- ---------- ----------
Restated Restated
(See Note 1) (See Note 1)
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................ $ 67,816 $ 78,211 $ 134,806 $ 156,791
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization........ 42,443 47,646 147,111 153,250
Nuclear fuel and capital lease amortization........ 4,178 5,037 12,217 15,821
Other amortization................................. (7,911) (3,937) (12,933) (12,104)
Deferred operating lease costs, net................ (36,167) (25,220) (77,992) (76,888)
Deferred income taxes, net......................... 14,847 676 48,784 3,582
Amortization of investment tax credits............. (1,202) (1,159) (3,605) (3,472)
Accrued retirement benefit obligations............. 26,453 2,437 10,566 5,151
Accrued compensation, net.......................... 257 3,386 (4,056) 2,422
Cumulative effect of accounting charge (Note 5).... -- -- (72,546) --
Receivables........................................ 234,672 3,274 86,460 (36,683)
Materials and supplies............................. (2,164) (1,786) 8,647 (4,992)
Accounts payable................................... (235,048) (23,141) (55,802) 3,238
Accrued taxes...................................... 46,327 30,546 33,765 43,221
Accrued interest................................... 7,996 2,726 4,428 2,388
Prepayments and other current assets............... (479) (1,466) 714 28,145
Other.............................................. (9,831) (3,831) 20,897 (35,997)
--------- --------- ---------- ----------
Net cash provided from operating activities...... 152,187 113,399 281,461 243,873
--------- --------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt....................................... -- 77,505 -- 77,505
Short-term borrowings, net........................... -- 162,858 -- 189,521
Equity contributions from parent..................... -- 50,000 -- 50,000
Redemptions and Repayments-
Preferred stock...................................... (1,000) (47,017) (1,093) (147,017)
Long-term debt....................................... (256) (309,189) (146,321) (309,379)
Short-term borrowings, net........................... (123,711) -- (73,490) --
Dividend Payments-
Preferred stock...................................... (1,864) (2,283) (5,594) (10,668)
--------- --------- ---------- ----------
Net cash used for financing activities........... (126,831) (68,126) (226,498) (150,038)
--------- --------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions..................................... (29,620) (40,545) (91,643) (102,467)
Notes receivable from associated companies, net........ (5,574) -- (5,354) 205
Capital trust investments.............................. 30,891 10,325 49,962 37,719
Contributions to nuclear decommissioning trusts ....... (14,512) (7,256) (21,768) (21,768)
Other.................................................. (6,541) 119 (16,383) 386
--------- --------- ---------- ----------
Net cash used for investing activities........... (25,356) (37,357) (85,186) (85,925)
--------- --------- ---------- ----------
Net increase (decrease) in cash and cash equivalents...... -- 7,916 (30,223) 7,910
Cash and cash equivalents at beginning of period.......... 159 290 30,382 296
--------- --------- ---------- ----------
Cash and cash equivalents at end of period................ $ 159 $ 8,206 $ 159 $ 8,206
========= ========= ========== ==========
The preceding Notes to Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral
part of these statements.
70
REPORT OF INDEPENDENT ACCOUNTANTS
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 September 30, 2003, and
the related consolidated statements of income and cash flows for each of the
three-month and nine-month periods ended September 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 each of the three-month and nine-month periods ended September
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
November 13, 2003
71
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 restated its consolidated financial statements for the three
years ended December 31, 2002 and the three months ended March 31, 2003 to
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. These restatements were completed and reported in the
second quarter of 2003. Financial comparisons described below for the
three-month and nine month-periods reflect the effect of these restatements.
RESULTS OF OPERATIONS
Earnings on common stock in the third quarter of 2003 decreased to
$66.0 million from $75.1 million in the third quarter of 2002. Earnings on
common stock in the first nine 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 $92.4 million in the first nine months of 2003,
compared to $156.8 million for the same period of 2002. Reduced earnings in both
periods resulted principally from lower revenues in 2003 compared to 2002 due to
milder weather.
Operating revenues decreased by $42.2 million or 7.8% in the third
quarter and $106.4 million or 7.4% in the first nine months of 2003 from the
same periods of 2002 reflecting milder weather in the third quarter and
increased sales by alternative suppliers. Kilowatt-hour sales to retail
customers declined 28.8% in the third quarter and 17.2% in the first nine months
of 2003 from the corresponding periods of 2002, reducing generation sales
revenue by $21.5 million and $50.1 million, respectively. Milder weather in the
third 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 12.5 percentage points in the third quarter and 11.2
percentage points in the first nine months of 2003 from the corresponding
periods last year.
Distribution deliveries were lower by 12.6% in the third quarter and
1.4% in the first nine months of 2003 compared to the corresponding periods of
2002. The reduction in distribution deliveries, partially offset by the effect
of higher unit prices, resulted in a $7.4 million and $3.2 million reduction in
revenues from electricity throughput in the third quarter and first nine months
of 2003, respectively, compared to the same periods last year. Lower
temperatures in the third quarter of 2003 reduced air-conditioning loads of
residential and commercial customers for that period while residential and
commercial loads benefited from cooler temperatures in the first quarter of 2003
which moderated the distribution delivery reductions in the first nine months of
2003 as compared to 2002.
Further decreasing operating revenues were Ohio transition plan
incentives, provided to customers to encourage switching to alternative energy
providers - $13.7 million of additional credits in the third quarter and $24.2
million of additional credits in the first nine 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
$1.1 million in the third quarter and $22.6 million in the first nine months of
2003 compared with the same periods of 2002. The lower sales resulted from
reductions in available nuclear generation of 6.6% in the third quarter and
22.3% in the first nine months of 2003 compared to the corresponding periods of
2002. Available generation decreased due to the extended outage of Davis-Besse
and generating capacity removed from service due to additional nuclear refueling
activities in 2003 compared to 2002.
Changes in electric generation sales and distribution deliveries in
the third quarter and first nine months of 2003 from the corresponding periods
of 2002 are summarized in the following table:
72
Changes in Kilowatt-hour Sales Three Months Nine Months
---------------------------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail................................ (28.8)% (17.2)%
Wholesale............................. (4.4)% (13.7)%
-------------------------------------------------------------------
Total Electric Generation Sales......... (17.8)% (15.5)%
===================================================================
Distribution Deliveries:
Residential........................... (10.4)% (1.1)%
Commercial............................ (1.5)% 1.2%
Industrial............................ (19.9)% (3.1)%
-------------------------------------------------------------------
Total Distribution Deliveries (12.6)% (1.4)%
===================================================================
Operating Expenses and Taxes
Total operating expenses and taxes decreased by $22.2 million in the
third quarter and $20.4 million in the first nine 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 Nine Months
-----------------------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel............................................ $(10.3) $(16.6)
Purchased power costs........................... (0.7) 9.0
Nuclear operating costs......................... 18.4 46.3
Other operating costs........................... (8.4) (1.1)
--------------------------------------------------------------------------
Total operation and maintenance expenses...... (1.0) 37.6
Provision for depreciation and amortization..... (5.2) (6.1)
General taxes................................... (3.0) (1.3)
Income taxes.................................... (13.0) (50.6)
--------------------------------------------------------------------------
Net decrease in operating expenses and taxes.. $(22.2) $(20.4)
==========================================================================
Lower fuel costs in the third quarter and first nine 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 first
nine months of 2003 compared to the corresponding period of 2002. Increased
nuclear costs resulted from incremental costs associated with the extended
Davis-Besse outage, unplanned work performed during the Perry Plant 56-day
nuclear refueling outage (44.85% ownership) in the second quarter of 2003, and
the Beaver Valley Unit 2 28-day refueling outage (24.47% ownership) in the third
quarter of 2003, compared with the 24-day refueling outage at Beaver Valley Unit
2 in the first quarter of 2002.
The decrease in depreciation and amortization charges in the third
quarter of 2003, compared with the third quarter of 2002 was primarily
attributable to several factors - increased amortization of regulatory assets
being recovered under CEI's transition plan ($5.5 million) and recognition of
depreciation on three fossil plants ($7.2 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 factors were
higher shopping incentive deferrals ($13.7 million) and lower charges resulting
from the implementation of SFAS 143 ($2.9 million).
The decrease of $6.1 million in depreciation and amortization charges
in the first nine months of 2003, compared with the same period of 2002
reflected the same factors affecting the third quarter of 2003 - decreases due
to higher shopping incentive deferrals ($24.2 million) and lower charges from
the SFAS 143 implementation ($10.7 million) being partially offset by increases
in CEI's transition plan amortization ($13.6 million) and recognition of
depreciation on the fossil plants ($21 million).
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $8.6
million in the third quarter and $19.9 million in the first nine months of 2003
from the same periods last year, reflecting redemption and refinancing
activities. CEI's redemption and repricing activities during the first nine
months of 2003 totaled $116 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 nine 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
73
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. 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 $9.8 million in the
first nine months of 2003, compared to the same period last year, principally
due to optional redemptions of preferred stock in 2002.
CAPITAL RESOURCES AND LIQUIDITY
CEI's cash requirements in the fourth quarter of 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 September 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 third quarter and
first nine months of 2003, compared with the corresponding periods in 2002 were
as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------------------------
Operating Cash Flows 2003 2002 2003 2002
------------------------------------------------------------------------
(In millions)
Cash earnings (1).......... $111 $107 $182 $245
Working capital and other.. 41 6 99 (1)
------------------------------------------------------------------------
Total...................... $152 $113 $281 $244
========================================================================
(1)Includes net income, depreciation and amortization,
deferred income taxes, investment tax credits and major
noncash charges.
The increase in working capital and other reflected increases of $231
million and $16 million in changes in accounts receivable and accrued tax
liabilities, respectively, for the third quarter 2003 as compared to the third
quarter of 2002 changes which were partially offset by a $212 million decrease
in accounts payable for those periods. Net cash from operating activities
increased $37 million in the first nine months of 2003 compared to the same
period in 2002 as a result of a $100 million working capital and other increase
partially offset by a $63 million reduction in cash earnings. The largest factor
contributing to the working capital and other increase was a $123 million change
in accounts receivable while the cash earnings decrease was primarily
attributable to higher nuclear operating costs.
Cash Flows From Financing Activities
In the third quarter and first nine months of 2003, net cash used for
financing activities increased $59 million and $76 million, respectively from
the corresponding periods of 2002. The increase in funds used for financing
activities primarily reflected higher repayments of short-term borrowings with
no new financings in 2003 compared to lower net repayments on long-term debt in
2002.
CEI had about $0.7 million of cash and temporary investments and
approximately $215.1 million of short-term indebtedness as of September 30,
2003. CEI had the capability to issue $588.0 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.
74
Cash Flows From Investing Activities
Net cash used for investing activities decreased $12 million in the
third quarter of 2003 from the same quarter of 2002 due to a change in the
Shippingport Capital Trust investment and lower capital expenditures in 2003.
During the fourth quarter of 2003, capital requirements for property
additions and capital leases are expected to be about $26 million. CEI has no
sinking fund requirements for preferred stock and maturing long-term debt during
the remainder of 2003.
On November 13, 2003, FirstEnergy announced that it had reached an
agreement with NRG covering the settlement of its claims resulting from the
uncompleted sale of four power plants to NRG, three of which were CEI generating
plants (Ashtabula, Eastlake and Lakeshore). Under the agreement FirstEnergy
would receive an estimated settlement for the four plants of approximately $198
million in the form of cash (12%), notes (15.2%) and common stock (72.8%). The
agreement is subject to FERC authorization and U.S. Bankruptcy Court approval
since NRG and certain of its subsidiaries filed for voluntary bankruptcy in May
2003.
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."
On September 30, 2003, Fitch Ratings lowered the senior unsecured
ratings of FirstEnergy to "BBB-" from "BBB." Fitch also lowered the senior
secured, senior unsecured, and preferred stock ratings of Met-Ed, Penelec, CEI,
and TE. In addition, Fitch affirmed the ratings of OE, Penn and JCP&L. Fitch
announced that the Rating Outlook is Stable for the securities of FirstEnergy,
and all of the securities of its electric utility operating companies. Fitch
stated that the changes to the long-term debt ratings were "driven by the high
debt leverage of the parent FE. Despite management's commitment to reduce debt
related to the GPU merger, subsequent cash flows have been vulnerable to
unfavorable events, slowing the pace of FE's debt reduction efforts. The Stable
Outlook reflects the success of FE's recent common equity offering and
management's focus on a relatively conservative integrated utility strategy."
On October 27, 2003, Standard & Poors (S&P) stated that the `BBB'
corporate credit and the `BBB-` senior unsecured ratings for FirstEnergy and its
utility subsidiaries remain on CreditWatch with negative implications. The
ratings were placed on CreditWatch on August 18, 2003, and reflect the S&P's
concerns regarding the potential impact of the August 14, 2003 blackout
investigation on FirstEnergy's deleveraging strategy and its overall efforts to
improve its credit profile.
At that time, S&P also noted other challenges facing FirstEnergy,
including the extended Davis-Besse outage; the recent U.S. District Court ruling
regarding the Sammis Plant; reliability concerns in subsidiary JCP&L's service
territory; and FirstEnergy's credibility with regulators and federal officials.
S&P further noted several factors that could aid FirstEnergy in
resolution of the CreditWatch, including strengthening its balance sheet.
FirstEnergy directly addressed this concern through its recently completed
common equity offering that raised approximately $935 million in net proceeds,
which was used to reduce bank debt. S&P described the equity offering as a
"positive credit development" and also noted the recent renewal of FirstEnergy's
$1 billion revolver facilities as a "favorable development, as it mitigates
liquidity concerns." S&P also indicated that should various ongoing
investigations into the causal factors of the August 14, 2003 blackout establish
that the blackout resulted from no negligence or breach of compliance standards
on FirstEnergy's part, the CreditWatch could be removed and the outlook returned
to negative. S&P deemed a "stable" credit outlook unlikely until issues such as
the restart of Davis-Besse are resolved and the potential effect of the
litigation relating to the Sammis plant (the second trial is scheduled for April
2004) are known. Extension of the Ohio transition plan will be viewed as a
positive development and will support an outlook revision to stable.
On October 27, 2003, S&P also noted that the ratings on FirstEnergy
and its subsidiaries incorporate such strengths as the ability to generate free
cash flow, power generation contracted to its transmission and distribution
subsidiaries through 2005, and the hedging of its short power position arising
from its PLR obligation in Pennsylvania. S&P said that these strengths are
offset by slower than anticipated reduction of FirstEnergy debt, remaining
volume risks of PLR obligations, the extended outage at Davis-Besse, the
unfavorable outcome of the New Jersey rate proceeding and regulatory uncertainty
in Ohio. S&P also said that it now views FirstEnergy's liquidity position as
average, following FirstEnergy's renewal of its $1 billion credit facilities.
75
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 September 30, 2003, the present value of these sale and
leaseback operating lease commitments, net of trust investments, total $131
million. CEI sells substantially all of its retail customer receivables, which
provided $133 million of off-balance sheet financing as of September 30, 2003.
EQUITY PRICE RISK
Included in CEI's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $158
million and $119 million as of September 30, 2003 and December 31, 2002,
respectively. A hypothetical 10% decrease in prices quoted by stock exchanges
would result in a $16 million reduction in fair value as of September 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 by $53.6 million for the first
nine months of 2003, to $1,138.2 million as of September 30, 2003. All of CEI's
regulatory assets are expected to continue to be recovered under the provisions
of its transition plan.
As part of CEI's Ohio transition plan CEI 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 who 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.
On October 21, 2003, the Ohio Companies filed an application with the
PUCO to establish generation service rates beginning January 1, 2006, in
response to expressed concerns by the PUCO about price and supply uncertainty
following the end of the market development period. The filing included two
options:
o A competitive auction, which would establish a price for
generation that customers would be charged during the period
covered by the auction, or
o A Rate Stabilization Plan, which would extend current generation
prices through 2008, ensuring adequate supply and continuing
FirstEnergy's support of energy efficiency and economic
development efforts.
Under the first option, an auction would be conducted to secure
generation service, including PLR responsibility, for FirstEnergy's Ohio
customers. Beginning in 2006, customers would pay market prices for generation
as determined by the auction.
Under the Rate Stabilization Plan option, customers would have price
and supply stability through 2008 - three years beyond the end of the market
development period - as well as the benefits of a competitive market. Customer
benefits would include: customer savings by extending the current five percent
discount on generation costs and other customer credits; maintaining current
distribution base rates through 2007; market-based auctions that may be
conducted annually to ensure that customers pay the lowest available prices;
extension of FirstEnergy's support of energy-efficiency programs and the
potential for continuing the program to give preferred access to nonaffiliated
entities to generation capacity as discussed above. In order to facilitate
supply planning, FirstEnergy has requested that the PUCO rule on this proposal
by December 31, 2003. Under the proposed plan, CEI is requesting:
76
o Extension of the transition cost amortization period for CEI from
2008 to 2009;
o Deferral of new regulatory assets and deferral of interest costs on
the shopping incentive and other new deferrals;
o Ability to initiate a request to increase generation rates only
under certain limited conditions.
As a result of the Ohio Companies' October 21 filing, the PUCO
entered an order on October 28, 2003 setting forth the discovery schedule
related to the application with hearings scheduled to begin December 3, 2003.
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. Testing of the bottom of the reactor for leaks was
completed in October 2003 and no indication of leakage was discovered.
FirstEnergy is installing 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 third quarter and first nine months of 2003 and
2002 were as follows:
Three Months Ended Nine Months Ended
Costs of Davis-Besse Extended Outage September 30, September 30
--------------------------------------------------------------------------------
2003 2002 2003 2002
---- ---- ---- ----
(In millions)
Incremental Pre-Tax Expense
Replacement power................ $54.9 $50.9 $148.4 $ 84.5
Maintenance...................... 17.5 39.8 75.7 54.1
-------------------------------------------------------------------------------
Total........................ $72.4 $90.7 $224.1 $138.6
===============================================================================
Capital Expenditures............... $10.9 $27.4 $ 13.3 $ 39.4
===============================================================================
It is anticipated that an additional $14 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 during the remaining period of
the outage. FirstEnergy has hedged the on-peak replacement energy supply for
Davis-Besse for the expected length of the outage. If there are significant
delays in the NRC approval process, substantial replacement power costs will
continue to be incurred, which will continue to have an adverse effect on CEI's
cash flows and results of operations.
Environmental Matters
CEI believes it is in compliance with the current sulfur dioxide
(SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act
Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized
regulations requiring additional NOx reductions in the future from its
generating facilities. Various regulatory and judicial actions have since sought
to further define NOx reduction requirements (see Note 2 - Environmental
Matters). CEI continues to evaluate its compliance plans and other compliance
options.
77
Violations of federally approved SO2 regulations can result in
shutdown of the generating unit involved and/or civil or criminal penalties of
up to $31,500 for each day a unit is in violation. The EPA has an interim
enforcement policy for SO2 regulations in Ohio that allows for compliance based
on a 30-day averaging period. CEI cannot predict what action the EPA may take in
the future with respect to the interim enforcement policy.
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants. The EPA identified mercury as the hazardous air pollutant of
greatest concern. The EPA established a schedule to propose regulations by
December 2003 and issue final regulations by December 2004. The future cost of
compliance with these regulations may be substantial.
As a result of the Resource Conservation and Recovery Act of 1976, as
amended, and the Toxic Substances Control Act of 1976, federal and state
hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous waste
disposal requirements pending the EPA's evaluation of the need for future
regulation. The EPA has issued its final regulatory determination that
regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the
EPA announced that it will develop national standards regulating disposal of
coal ash under its authority to regulate nonhazardous waste.
CEI believes it is in compliance with the current SO2 and 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 CEI's 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, environmental liabilities that are considered probable have been
recognized on the Consolidated Balance Sheet as of September 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 September
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
78
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 -
$1,138.2 million as of September 30, 2003. CEI regularly reviews these assets to
assess their ultimate recoverability within the approved regulatory guidelines.
Impairment risk associated with these assets relates to potentially adverse
legislative, judicial or regulatory actions in the future.
Revenue Recognition
CEI follows the accrual method of accounting for revenues,
recognizing revenue for kilowatt-hours that have been delivered but not yet
billed through the end of the accounting period. The determination of unbilled
revenues requires management to make various estimates including:
o Net energy generated or purchased for retail load
o Losses of energy over distribution lines
o 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 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 is not 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 connection with FirstEnergy's restructuring plan, the PUCO
determined allowable transition costs based on amounts recorded on CEI's
regulatory books. These costs exceeded those deferred or capitalized on CEI's
balance sheet prepared under GAAP since they included certain costs which have
not yet been incurred or that were recognized on the regulatory financial
statements (fair value purchase accounting adjustments). CEI uses an effective
interest method for amortizing its transition costs, often referred to as a
"mortgage-style" amortization.
79
The interest rate under this method is equal to the rate of return
authorized by the PUCO in the transition plan for CEI. In computing the
transition cost amortization, CEI includes only the portion of the transition
revenues associated with transition costs included on the balance sheet prepared
under GAAP. Revenues collected for the off balance sheet costs and the return
associated with these costs are recognized as income when received.
Long-Lived Assets
In accordance with SFAS 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), the goodwill is tested for
impairment. If impairment were indicated, CEI would recognize a loss -
calculated as the difference between the implied fair value of its goodwill and
the carrying value of the goodwill. CEI's annual review was completed in the
third quarter of 2003, with no impairment of goodwill indicated. The forecasts
used in CEI's evaluation 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 September
30, 2003, CEI had approximately $1.7 billion of goodwill.
RECENTLY ISSUED ACCOUNTING STANDARDS
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". This Interpretation requires the
consolidation of a variable interest entity (VIE) by an enterprise if that
enterprise either absorbs a majority of the VIE's expected losses or receives a
majority of the VIE's expected residual returns as a result of ownership,
contractual or other financial interests in the VIE. Currently, entities are
generally consolidated by an enterprise that has a controlling financial
interest through ownership of a majority voting interest in the entity.
FIN 46 defines a VIE as an entity in which equity investors do not
have the characteristics of a controlling financial interest nor have sufficient
equity at risk for the entity to finance its activities without additional
subordinated financial support. VIE's created after January 31, 2003, are
immediately subject to the provisions of FIN 46. The FASB recently deferred
implementation of FIN 46 for VIE's created before February 1, 2003, until the
first reporting period ending after December 15, 2003 (CEI's quarter ending
December 31, 2003.)
CEI currently has transactions with entities in connection with sale
and leaseback arrangements which may fall within the scope of this
interpretation and which meet the definition of a VIE in accordance with FIN 46.
One such entity is the Shippingport Capital Trust which acquired all of the
lease obligation bonds issued in connection with the sale and leaseback in 1987
of interests in the Bruce Mansfield Plant held by CEI and TE, an affiliated
company. The equity ownership of this trust includes a 0.34% interest held by
Toledo Edison Capital Corporation, an affiliated company, and a 4.85% interest
held by unaffiliated third parties. The assets and liabilities of the trust are
currently included on a proportionate basis in the financial statements of CEI
and TE. Adoption of FIN 46 may result in reporting all of the trust assets and
liabilities on the books of CEI. CEI is also evaluating its interests in the
owner trusts that acquired the interests in the Bruce Mansfield Plant and Beaver
Valley Unit 2. CEI has not completed its evaluation to determine if it would be
the primary beneficiary and therefore required to consolidate these trusts.
As described in Note 1, CEI's consolidated financial statements
include a subsidiary trust that sold trust-preferred securities in which CEI is
not the primary beneficiary. Pending further guidance from the FASB that would
indicate otherwise, this entity may not be consolidated in CEI's financial
statements as of December 31, 2003. The deconsolidation would result in an
increase in total assets and liabilities of approximately $3.1 million for the
investment in the trust.
The FASB continues to provide additional guidance on implementing FIN
46 and recently proposed modifications and clarifications with a comment period
ending December 1, 2003. As this guidance is finalized, CEI will
80
continue to assess the accounting and disclosure impact of FIN 46 with respect
to the VIE's discussed above as well as other potential VIE's.
SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity"
In May 2003, the FASB issued SFAS 150, which establishes standards
for how an issuer classifies and measures certain financial instruments with
characteristics of both liabilities and equity. In accordance with the standard,
certain financial instruments that embody obligations for the issuer are
required to be classified as liabilities. SFAS 150 was effective immediately for
financial instruments entered into or modified after May 31, 2003 and effective
at the beginning of the first interim period beginning after June 15, 2003
(CEI's third quarter of 2003) for all other financial instruments.
Upon adoption of SFAS 150, effective July 1, 2003, CEI reclassified
as debt the preferred stock subject to mandatory redemption with a carrying
value of approximately $4.0 million as of September 30, 2003. Company-obligated
mandatorily redeemable preferred securities of $100 million were also
reclassified and included in long-term debt as of September 30, 2003. As
required by SFAS 150, the preferred securities subject to mandatory redemption
were not restated as long-term debt on the December 31, 2002 balance sheet.
Dividends on preferred stock subject to mandatory redemption on CEI's
Consolidated Statements of Income, which were not included in net interest
charges prior to the adoption of SFAS 150, are now included in net interest
charges for the three months ended September 30, 2003.
EITF Issue No. 01-08, "Determining whether an Arrangement Contains a
Lease"
In May 2003, the EITF reached a consensus on Issue No. 01-08,
regarding when arrangements contain a lease. Based on the EITF consensus, an
arrangement contains a lease if (1) it identifies specific property, plant or
equipment (explicitly or implicitly), and (2) the arrangement transfers the
right to the purchaser to control the use of the property, plant or equipment.
The consensus is to be applied prospectively to arrangements committed to,
modified or acquired through a business combination, beginning in the third
quarter of 2003. The adoption of this consensus as of July 1, 2003 did not
impact CEI's financial statements.
81
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2003 2002 2003 2002
-------- -------- -------- --------
Restated Restated
(See Note 1) (See Note 1)
(In thousands)
OPERATING REVENUES........................................ $260,190 $269,857 $708,000 $772,731
-------- -------- -------- --------
OPERATING EXPENSES AND TAXES:
Fuel................................................... 2,940 9,524 18,364 30,342
Purchased power........................................ 81,795 85,329 230,271 247,085
Nuclear operating costs................................ 64,681 61,149 195,877 178,939
Other operating costs.................................. 39,692 38,902 106,026 97,281
-------- -------- -------- --------
Total operation and maintenance expenses........... 189,108 194,904 550,538 553,647
Provision for depreciation and amortization............ 36,142 41,813 106,460 116,929
General taxes.......................................... 14,305 14,061 43,279 41,258
Income taxes (benefit)................................. 2,432 892 (13,877) 4,373
-------- -------- -------- --------
Total operating expenses and taxes................. 241,987 251,670 686,400 716,207
-------- -------- -------- --------
OPERATING INCOME.......................................... 18,203 18,187 21,600 56,524
OTHER INCOME.............................................. 5,768 4,033 12,644 12,119
-------- -------- -------- --------
INCOME BEFORE NET INTEREST CHARGES........................ 23,971 22,220 34,244 68,643
-------- -------- -------- --------
NET INTEREST CHARGES:
Interest on long-term debt............................. 9,039 14,611 32,485 46,084
Allowance for borrowed funds used during construction.. (1,458) (611) (3,948) (1,421)
Other interest expense (credit)........................ 639 463 1,068 (632)
-------- -------- -------- --------
Net interest charges............................... 8,220 14,463 29,605 44,031
-------- -------- -------- --------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING
CHANGE ................................................... 15,751 7,757 4,639 24,612
Cumulative effect of accounting change (net of income
taxes of $18,201,000) (Note 5)......................... -- -- 25,550 --
-------- -------- -------- --------
NET INCOME................................................ 15,751 7,757 30,189 24,612
PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 2,211 2,211 6,627 9,145
-------- -------- -------- --------
EARNINGS ON COMMON STOCK.................................. $ 13,540 $ 5,546 $ 23,562 $ 15,467
======== ======== ======== ========
The preceding Notes to Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements.
82
THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2003 2002
------------- ------------
(See Note 1)
(In thousands)
ASSETS
------
UTILITY PLANT:
In service................................................................ $1,697,909 $1,600,860
Less--Accumulated provision for depreciation.............................. 747,456 706,772
---------- ----------
950,453 894,088
---------- ----------
Construction work in progress-
Electric plant.......................................................... 106,471 104,091
Nuclear fuel............................................................ 26,057 33,650
---------- ----------
132,528 137,741
---------- ----------
1,082,981 1,031,829
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Shippingport Capital Trust................................................ 219,973 240,963
Nuclear plant decommissioning trusts...................................... 214,395 174,514
Long-term notes receivable from associated companies...................... 163,638 162,159
Other..................................................................... 75,281 2,236
---------- ----------
673,287 579,872
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents................................................. 11,275 20,688
Receivables-
Customers............................................................... 4,339 4,711
Associated companies.................................................... 33,496 55,245
Other................................................................... 20,842 6,778
Notes receivable from associated companies................................ 9,079 1,957
Materials and supplies, at average cost-
Owned................................................................... 12,563 13,631
Under consignment....................................................... 20,232 22,997
Prepayments and other..................................................... 9,172 3,455
---------- ----------
120,998 129,462
---------- ----------
DEFERRED CHARGES:
Regulatory assets......................................................... 516,284 578,243
Goodwill.................................................................. 504,522 504,522
Property taxes............................................................ 23,429 23,429
Other..................................................................... 16,106 14,257
---------- ----------
1,060,341 1,120,451
---------- ----------
$2,937,607 $2,861,614
========== ==========
83
THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2003 2002
----------- ------------
(See Note 1)
(In thousands)
CAPITALIZATION AND LIABILITIES
------------------------------
CAPITALIZATION:
Common stockholder's equity-
Common stock, $5 par value, authorized 60,000,000 shares -
39,133,887 shares outstanding......................................... $ 195,670 $ 195,670
Other paid-in capital................................................... 428,559 428,559
Accumulated other comprehensive loss.................................... (4,453) (20,012)
Retained earnings....................................................... 100,539 76,978
---------- ----------
Total common stockholder's equity................................... 720,315 681,195
Preferred stock not subject to mandatory redemption....................... 126,000 126,000
Long-term debt............................................................ 285,565 557,265
---------- ----------
1,131,880 1,364,460
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt.......................................... 341,650 189,355
Accounts payable-
Associated companies.................................................... 120,256 171,862
Other................................................................... 3,212 9,338
Notes payable-
Associated companies.................................................... 333,695 149,653
Banks................................................................... 70,000 --
Accrued taxes............................................................. 50,958 34,676
Accrued interest.......................................................... 14,012 16,377
Lease market valuation liability.......................................... 24,600 24,600
Other..................................................................... 26,543 57,462
---------- ----------
984,926 653,323
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes......................................... 188,651 158,279
Accumulated deferred investment tax credits............................... 27,714 29,255
Nuclear plant decommissioning costs....................................... -- 179,587
Asset retirement obligation............................................... 178,847 --
Retirement benefits....................................................... 60,105 82,553
Lease market valuation liability.......................................... 298,750 317,200
Other..................................................................... 66,734 76,957
---------- ----------
820,801 843,831
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)...........................
---------- ----------
$2,937,607 $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.
84
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2003 2002 2003 2002
-------- -------- -------- --------
Restated Restated
(See Note 1) (See Note 1)
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................ $ 15,751 $ 7,757 $ 30,189 $ 24,612
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization........ 36,142 41,813 106,460 116,929
Nuclear fuel and capital lease amortization........ 2,182 2,765 6,770 9,009
Deferred operating lease costs, net................ (4,212) 2,755 (39,671) (37,999)
Deferred income taxes, net......................... (11,570) (11,266) 5,421 (14,346)
Amortization of investment tax credits............. (514) (454) (1,542) (1,507)
Accrued retirement benefit obligation.............. 7,800 928 5,467 1,710
Accrued compensation, net.......................... (608) 912 (2,754) 912
Cumulative effect of accounting change............. -- -- (43,751) --
Receivables........................................ 25,437 22,359 8,058 15,219
Materials and supplies............................. (1,317) (2,150) 3,833 (3,970)
Accounts payable................................... (54,140) 26,894 (65,990) 18,845
Accrued taxes...................................... 15,801 3,313 16,283 12,694
Accrued interest................................... (3,514) (3,988) (2,365) (4,046)
Prepayment and other current assets................ 3,263 1,740 (5,716) 12,671
Other.............................................. (6,039) 4,651 (11,576) (11,412)
-------- -------- -------- --------
Net cash provided from operating activities...... 24,462 98,029 9,440 139,321
-------- -------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net........................... 122,451 13,279 254,041 130,234
Equity contributions from parent..................... -- 100,000 -- 100,000
Redemptions and Repayments-
Preferred stock...................................... -- -- -- (85,299)
Long-term debt....................................... (34,981) (167,705) (117,743) (179,968)
Dividend Payments-
Common stock......................................... -- -- -- (5,600)
Preferred stock...................................... (2,205) (2,211) (6,626) (7,846)
-------- -------- -------- --------
Net cash provided from (used for) financing
activities ..................................... 85,265 (56,637) 129,672 (48,479)
-------- -------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions..................................... (20,043) (26,636) (54,825) (66,897)
Notes receivable from associated companies, net........ 138 (10,798) (8,602) (19,005)
Capital trust investments.............................. 3,399 3,207 20,989 20,033
Contributions to nuclear decommissioning trust ........ (14,271) (7,135) (21,406) (21,406)
Debt remarketing investments .......................... (73,231) -- (73,231) --
Other.................................................. (4,752) 36 (11,450) (3,350)
-------- -------- -------- --------
Net cash used for investing activities........... (108,760) (41,326) (148,525) (90,625)
-------- -------- -------- --------
Net increase (decrease) in cash and cash equivalents...... 967 66 (9,413) 217
Cash and cash equivalents at beginning of period.......... 10,308 453 20,688 302
-------- -------- -------- --------
Cash and cash equivalents at end of period................ $ 11,275 $ 519 $ 11,275 $ 519
======== ======== ======== ========
The preceding Notes to Financial Statements as they relate to The Toledo Edison Company are an integral part of these
statements.
85
REPORT OF INDEPENDENT ACCOUNTANTS
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 September 30, 2003, and the related
consolidated statements of income and cash flows for each of the three-month and
nine-month periods ended September 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 each of the three-month and nine-month periods ended September
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
November 13, 2003
86
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 restated its consolidated financial statements for the three
years ended December 31, 2002 and the three months ended March 31, 2003 to
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. These restatements were completed and reported in the
second quarter of 2003. Financial comparisons described below for the
three-month and nine month-periods reflect the effect of these restatements.
RESULTS OF OPERATIONS
Earnings on common stock in the third quarter of 2003 increased to
$13.5 million from earnings of $5.5 million in the third quarter of 2002.
Earnings on common stock in the first nine months of 2003 included an after-tax
credit of $25.6 million from the cumulative effect of an accounting change due
to the adoption of SFAS 143, "Accounting for Asset Retirement Obligations."
Income before the cumulative effect was $4.6 million in the first nine months of
2003, compared to $24.6 million for the same period of 2002. The increase in the
third quarter 2003 reflected lower fuel and purchased power costs, depreciation
and amortization and financing costs partially offset by lower operating
revenues and higher nuclear operating costs. In the first nine months of 2003,
results were adversely affected by lower operating revenues and higher nuclear
operating costs partially offset by lower fuel and purchased power costs and
reduced financing costs.
Operating revenues decreased by $9.7 million or 3.6% in the third
quarter and $64.7 million or 8.4% in the first nine months of 2003 from the same
periods in 2002. Reduced revenues resulted from lower kilowatt-hour sales due to
milder weather in the second and third quarters, continued sluggishness in the
regional economy and increased sales by alternative suppliers. The decline in
revenues primarily resulted from lower generation sales revenues from all retail
customer sectors. Kilowatt-hour sales to retail customers declined by 9.9% in
the third quarter and 10.1% in the first nine months of 2003 from the same
periods of 2002, which reduced generation retail sales revenues by $16.4 million
and $43.5 million, respectively. Electric generation services provided to retail
customers by alternative suppliers as a percent of total sales delivered in TE's
service area increased 6.0 percentage points in the third quarter and 7.0
percentage points during the first nine months of 2003 from the corresponding
periods last year.
Distribution deliveries decreased 2.7% in the third quarter and 1.9%
in the first nine months of 2003 compared to the corresponding periods of 2002.
However, higher unit prices resulted in overall revenue increases from
electricity throughput of $2.7 million and $12.5 million in the third quarter
and first nine months of 2003, respectively, compared to 2002.
Transition plan incentives, provided to customers to encourage
switching to alternative energy providers, reduced revenues by $2.2 million in
the third quarter and $5.6 million in the first nine months of 2003 compared to
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 increased by $4.9 million in
the third quarter and decreased by $22.3 million in the first nine months of
2003 compared with the same periods of 2002. Both periods reflected lower
kilowatt-hour sales to the wholesale market due to reduced nuclear generation
available for sale to FES. The third quarter increase in revenues reflected the
effect of higher unit prices partially offset by lower sales volume.
Changes in electric generation sales and distribution deliveries in
the third quarter and the first nine months of 2003 from the third quarter and
first nine months of 2002 are summarized in the following table:
87
Changes in Kilowatt-Hour Sales Three Months Nine Months
---------------------------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail (9.9)% (10.1)%
Wholesale............................. (4.1)% (17.2)%
-------------------------------------------------------------------
Total Electric Generation Sales......... (7.5)% (13.2)%
===================================================================
Distribution Deliveries:
Residential (13.0)% (4.3)%
Commercial 9.3% 2.5%
Industrial............................ (3.9)% (3.4)%
-------------------------------------------------------------------
Total Distribution Deliveries........... (2.7)% (1.9)%
===================================================================
Operating Expenses and Taxes
Total operating expenses and taxes decreased by $9.7 million in the
third quarter and $29.8 million in the first nine months of 2003 from the same
periods in 2002. The following table presents changes from the prior year by
expense category.
Operating Expenses and Taxes - Changes Three Months Nine Months
---------------------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel......................................... $(6.6) $ (12.0)
Purchased power costs........................ (3.5) (16.8)
Nuclear operating costs...................... 3.5 16.9
Other operating costs........................ 0.8 8.8
------------------------------------------------------------------------
Total operation and maintenance expenses... (5.8) (3.1)
Provision for depreciation and amortization.. (5.7) (10.5)
General taxes................................ 0.3 2.0
Income taxes................................. 1.5 (18.2)
-------------------------------------------------------------------------
Net decrease in operating expenses and taxes $(9.7) $ (29.8)
==========================================================================
Lower fuel costs in the third quarter and first nine months of 2003,
compared with the same quarter and nine months of 2002, resulted from reduced
nuclear generation (down 9.7% and 24.6%, respectively). The lower purchased
power costs reflect reduced kilowatt-hours required for customer needs which
more than offset an increase in unit costs. Increased nuclear costs resulted
from incremental costs associated with the extended Davis-Besse outage,
unplanned work performed during the Perry Plant's 56-day nuclear refueling
outage (19.91% ownership) in the second quarter of 2003, and the 28-day
refueling outage at Beaver Valley Unit 2 (19.91% interest) in the third quarter
of 2003 compared with a 24-day refueling outage at Beaver Valley Unit 2, in the
first quarter of 2002. The increase in other operating costs resulted in part
from higher employee benefit costs and energy delivery costs as a result of
storm damage.
Charges for depreciation and amortization decreased by $5.7 million in
the third quarter of 2003, compared with the third quarter of 2002 primarily
from four factors - higher shopping incentive deferrals ($2.2 million), lower
charges resulting from the implementation of SFAS 143 ($3.9 million), revised
service life assumptions for generating plants ($3.0 million) and a slight
decline in amortization of regulatory assets being recovered under TE's
transition plan ($0.4 million). Partially offsetting these decreases were the
recognition of depreciation on the Bay Shore generating plant ($1.4 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 ($0.9 million).
In the first nine months of 2003, depreciation and amortization
decreased by $10.5 million compared to the corresponding period of 2002 as a
result of the same factors which impacted the third quarter comparison - higher
shopping incentive deferrals ($5.6 million), lower charges resulting from
implementation of SFAS 143 ($12.1 million) and revised service life assumptions
($8.0 million). Partially offsetting these decreases were increased amortization
of regulatory assets being recovered under TE's transition plan ($5.0 million),
recognition of depreciation on the Bay Shore generating plant ($4.1 million) and
reduced regulatory asset deferrals ($2.5 million).
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $6.2
million in the third quarter and $14.4 million in the first nine months of 2003
from the same periods last year, reflecting security redemptions and
refinancings since the beginning of the third 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 $25.6 million. TE identified applicable legal
88
obligations as defined under the new accounting standard for nuclear power plant
decommissioning and reclamation of a sludge disposal pond at the Bruce Mansfield
Plant. As a result of adopting SFAS 143 in January 2003, asset retirement costs
of $41.1 million were recorded as part of the carrying amount of the related
long-lived asset, offset by accumulated depreciation of $5.5 million. The asset
retirement obligation liability at the date of adoption was $172 million,
including accumulated accretion for the period from the date the liability was
incurred to the date of adoption. As of December 31, 2002, TE had recorded
decommissioning liabilities of $179.6 million. The cumulative effect adjustment
for unrecognized depreciation, accretion offset by the reduction in the existing
decommissioning liabilities and ceasing the accounting practice of depreciating
non-regulated generation assets using a cost of removal component was a $43.8
million increase to income, or $25.6 million net of income taxes.
CAPITAL RESOURCES AND LIQUIDITY
TE's cash requirements in 2003 for operating expenses, construction
expenditures, scheduled debt maturities and preferred stock redemptions are
expected to be met without 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.
Changes in Cash Position
As of September 30, 2003, TE had $11.3 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 operating activities during the third quarter and
first nine months of 2003, compared with the corresponding periods in 2002 were
as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ ------------------
Operating Cash Flows 2003 2002 2003 2002
------------------------------------------------------------------------
(In millions)
Cash earnings (1)........ $ 45 $45 $ 66 $ 99
Working capital and other (21) 53 (57) 40
------------------------------------------------------------------------
Total.................... $ 24 $98 $ 9 $139
========================================================================
(1) Includes net income, depreciation and amortization,
deferred income taxes, investment tax credits and major
noncash charges.
Net cash provided from operating activities decreased by $74 million
in the third quarter and $130 million in the first nine months of 2003 compared
to the same periods of 2002. The third quarter decrease in funds from operating
activities resulted from the decrease in cash provided from working capital. The
change in working capital and other primarily reflected an $81 million decrease
from accounts payable changes in the third quarter of 2003 compared to the third
quarter of 2002. The decrease in the first nine months of 2003 consisted of a
$97 million decrease in working capital and other, and a $33 million decrease in
cash earnings. The largest factor contributing to the working capital and other
decrease was an $85 million change in accounts payable while the cash earnings
decrease was attributable to lower electric sales revenues and higher nuclear
operating costs.
Cash Flows From Financing Activities
In the third quarter of 2003, net cash provided from financing
activities increased to $85 million from $57 million of net cash used in the
third quarter of 2002. This increase in cash provided from financing activities
primarily resulted from lower security redemptions and repayments. In the first
nine months of 2003, net cash provided from financing activities increased to
$130 million from $48 million of net cash used in financing activities in the
same period of 2002. This change was due to a $147 million decrease in
redemptions in 2003 compared to 2002.
TE had approximately $20.4 million of cash and temporary investments
and approximately $403.7 million of short-term indebtedness as of September 30,
2003. TE is currently precluded from issuing first mortgage bonds or preferred
stock based upon applicable earnings coverage tests as of September 30, 2003.
Cash Flows From Investing Activities
Net cash used for investing activities increased $67 million between
the third quarter of 2003 and the same quarter of 2002 due to changes in nuclear
decommissioning trust investments.
89
During the fourth quarter of 2003, capital requirements for property
additions and capital leases are expected to be about $18 million. TE has no
requirements to meet sinking fund requirements for preferred stock and maturing
long-term debt during the remainder of 2003.
On November 13, 2003, FirstEnergy announced that it had reached an
agreement with NRG covering the settlement of its claims resulting from the
uncompleted sale of four power plants to NRG, one of which was a TE generating
plant (Bay Shore). Under the agreement FirstEnergy would receive an estimated
settlement for the four plants of approximately $198 million in the form of cash
(12%), notes (15.2%) and common stock (72.8%). The agreement is subject to FERC
authorization and U.S. Bankruptcy Court approval since NRG and certain of its
subsidiaries filed for voluntary bankruptcy in May 2003.
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."
On September 30, 2003, Fitch Ratings lowered the senior unsecured
ratings of FirstEnergy to "BBB-" from "BBB." Fitch also lowered the senior
secured, senior unsecured, and preferred stock ratings of Met-Ed, Penelec, CEI,
and TE. In addition, Fitch affirmed the ratings of OE, Penn and JCP&L. Fitch
announced that the Rating Outlook is Stable for the securities of FirstEnergy,
and all of the securities of its electric utility operating companies. Fitch
stated that the changes to the long-term ratings were "driven by the high debt
leverage of the parent FE. Despite management's commitment to reduce debt
related to the GPU merger, subsequent cash flows have been vulnerable to
unfavorable events, slowing the pace of FE's debt reduction efforts. The Stable
Outlook reflects the success of FE's recent common equity offering and
management's focus on a relatively conservative integrated utility strategy."
On October 27, 2003, Standard & Poors (S&P) stated that the `BBB'
corporate credit and the `BBB-` senior unsecured ratings for FirstEnergy and its
utility subsidiaries remain on CreditWatch with negative implications. The
ratings were placed on CreditWatch on August 18, 2003, and reflect S&P's
concerns regarding the potential impact of the August 14, 2003 blackout
investigation on FirstEnergy's deleveraging strategy and its overall efforts to
improve its credit profile.
At that time, S&P also noted other challenges facing FirstEnergy,
including the extended Davis-Besse outage; the recent U.S. District Court ruling
regarding the Sammis Plant; reliability concerns in subsidiary JCP&L's service
territory; and FirstEnergy's credibility with regulators and federal officials.
S&P further noted several factors that could aid FirstEnergy in
resolution of the CreditWatch, including strengthening its balance sheet.
FirstEnergy directly addressed this concern through its recently completed
common equity offering that raised approximately $935 million in net proceeds,
which was used to reduce bank debt. S&P described the equity offering as a
"positive credit development" and also noted the recent renewal of FirstEnergy's
$1 billion revolver facilities as a "favorable development, as it mitigates
liquidity concerns." S&P also indicated that should various ongoing
investigations into the causal factors of the August 14, 2003 blackout establish
that the blackout resulted from no negligence or breach of compliance standards
on FirstEnergy's part, the CreditWatch could be removed and the outlook returned
to negative. S&P deemed a "stable" credit outlook unlikely until issues such as
the restart of Davis-Besse are resolved and the potential effect of the
litigation relating to the Sammis plant (the second trial is scheduled for April
2004) are known. Extension of the Ohio transition plan will be viewed as a
positive development and will support an outlook revision to stable.
On October 27, 2003, S&P also noted that the ratings on FirstEnergy
and its subsidiaries incorporate such strengths as the ability to generate free
cash flow, power generation contracted to its transmission and distribution
subsidiaries through 2005, and the hedging of its short power position arising
from its PLR obligation in Pennsylvania. S&P said that these strengths are
offset by slower than anticipated reduction of FirstEnergy debt, remaining
volume risks of PLR obligations, the extended outage at Davis-Besse, the
unfavorable outcome of the New Jersey rate proceeding and regulatory uncertainty
in Ohio. S&P also said that it now views FirstEnergy's liquidity position as
average, following FirstEnergy's renewal of its $1 billion credit facilities.
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 September 30, 2003, the present value of these
90
sale and leaseback operating lease commitments, net of trust investments,
totaled $595 million. TE also sells substantially all of its retail customer
receivables, which provided $67 million of off-balance sheet financing as of
September 30, 2003.
EQUITY PRICE RISK
Included in TE's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $122
million and $90 million as of September 30, 2003 and December 31, 2002,
respectively. A hypothetical 10% decrease in prices quoted by stock exchanges
would result in a $12 million reduction in fair value as of September 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 by
$62.0 million for the first nine months of 2003, to $516.3 million as of
September 30, 2003 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.
On October 21, 2003, the Ohio Companies filed an application with the
PUCO to establish generation service rates beginning January 1, 2006, in
response to expressed concerns by the PUCO about price and supply uncertainty
following the end of the market development period. The filing included two
options:
o A competitive auction, which would establish a price for
generation that customers would be charged during the period
covered by the auction, or
o A Rate Stabilization Plan, which would extend current generation
prices through 2008, ensuring adequate supply and continuing
FirstEnergy's support of energy efficiency and economic
development efforts.
Under the first option, an auction would be conducted to secure
generation service, including PLR responsibility, for FirstEnergy's Ohio
customers. Beginning in 2006, customers would pay market prices for generation
as determined by the auction.
Under the Rate Stabilization Plan option, customers would have price
and supply stability through 2008 - three years beyond the end of the market
development period - as well as the benefits of a competitive market. Customer
benefits would include: customer savings by extending the current five percent
discount on generation costs and other customer credits; maintaining current
distribution base rates through 2007; market-based auctions that may be
conducted annually to ensure that customers pay the lowest available prices;
extension of FirstEnergy's support of energy-efficiency programs and the
potential for continuing the program to give preferred access to nonaffiliated
entities to generation capacity as discussed above. In order to facilitate
supply planning, FirstEnergy has requested that the PUCO rule on this proposal
by December 31, 2003. Under the proposed plan, TE is requesting:
o Extension of the transition cost amortization period for TE from
mid-2007 to 2008;
o Deferral of new regulatory assets and deferral of interest costs
on the shopping incentive and other new deferrals;
91
o Ability to initiate a request to increase generation rates only
under certain limited conditions.
As a result of the Ohio Companies' October 21 filing, the PUCO entered
an order on October 28, 2003 setting forth the discovery schedule related to the
application with hearings scheduled to begin December 3, 2003.
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. Testing of the bottom of the reactor for leaks was
completed in October 2003 and no indication of leakage was discovered.
FirstEnergy is installing 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 third quarter and first nine months of 2003 and
2002 were as follows:
Three Months Ended Nine Months Ended
Costs of Davis-Besse Extended Outage September 30 September 30
----------------------------------------------------------------------------
2003 2002 2003 2002
---- ---- ---- ----
(In millions)
Incremental Pre-Tax Expense
Replacement power $54.9 $50.9 $148.4 $ 84.5
Maintenance 17.5 39.8 75.7 54.1
----------------------------------------------------------------------------
Total $72.4 $90.7 $224.1 $138.6
============================================================================
Capital Expenditures $10.9 $27.4 $ 13.3 $ 39.4
============================================================================
It is anticipated that an additional $14 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 during the remaining period of
the outage. FirstEnergy has hedged the on-peak replacement energy supply for
Davis-Besse for the expected length of the outage. If there are significant
delays in the NRC approval process, substantial replacement power costs will
continue to be incurred, which will continue to have an adverse effect on TE's
cash flows and results of operations.
Environmental Matters
TE believes it is in compliance with the current sulfur dioxide (SO2)
and nitrogen oxide (NOx) reduction requirements under the Clean Air Act
Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized
regulations requiring additional NOx reductions in the future from our Ohio and
Pennsylvania facilities. Various regulatory and judicial actions have since
sought to further define NOx reduction requirements (see Note 2C - Environmental
Matters). TE continues to evaluate its compliance plans and other compliance
options.
Violations of federally approved SO2 regulations can result in
shutdown of the generating unit involved and/or civil or criminal penalties of
up to $31,500 for each day a unit is in violation. The EPA has an interim
enforcement policy for SO2 regulations in Ohio that allows for compliance based
on a 30-day averaging period. We cannot predict what action the EPA may take in
the future with respect to the interim enforcement policy.
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
92
power plants. The EPA identified mercury as the hazardous air pollutant of
greatest concern. The EPA established a schedule to propose regulations by
December 2003 and issue final regulations by December 2004. The future cost of
compliance with these regulations may be substantial.
As a result of the Resource Conservation and Recovery Act of 1976, as
amended, and the Toxic Substances Control Act of 1976, federal and state
hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous waste
disposal requirements pending the EPA's evaluation of the need for future
regulation. The EPA has issued its final regulatory determination that
regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the
EPA announced that it will develop national standards regulating disposal of
coal ash under its authority to regulate nonhazardous waste.
TE believes it is in compliance with the current SO2 and 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 TE's 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, environmental liabilities that are considered probable have been
recognized on the Consolidated Balance Sheet as of September 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 September 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 related 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 - $516.3 million as of September 30, 2003.
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.
93
Revenue Recognition
TE follows the accrual method of accounting for revenues, recognizing
revenue for kilowatt-hours that have been delivered but not yet billed through
the end of the accounting period. The determination of unbilled revenues
requires management to make various estimates including:
o Net energy generated or purchased for retail load
o Losses of energy over distribution lines
o 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 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 is not 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 connection with FirstEnergy's restructuring plan, the PUCO
determined allowable transition costs based on amounts recorded on TE's
regulatory books. These costs exceeded those deferred or capitalized on TE's
balance sheet prepared under GAAP since they included certain costs which have
not yet been incurred or that were recognized on the regulatory financial
statements (fair value purchase accounting adjustments). TE uses an effective
interest method for amortizing its transition costs, often referred to as a
"mortgage-style" amortization. The interest rate under this method is equal to
the rate of return authorized by the PUCO in the transition plan for TE. In
computing the transition cost amortization, TE includes only the portion of the
transition revenues associated with transition costs included on the balance
sheet prepared under GAAP. Revenues collected for the off balance sheet costs
and the return associated with these costs are recognized as income when
received.
94
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), the goodwill is tested for impairment. If
impairment were indicated, TE would recognize a loss - calculated as the
difference between the implied fair value of its goodwill and the carrying value
of the goodwill. TE's annual review was completed in the third quarter of 2003,
with no impairment of goodwill indicated. The forecasts used in TE's evaluation
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 September 30, 2003, TE had
approximately $505 million of goodwill.
RECENTLY ISSUED ACCOUNTING STANDARDS
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". This Interpretation requires the
consolidation of a variable interest entity (VIE) by an enterprise if that
enterprise either absorbs a majority of the VIE's expected losses or receives a
majority of the VIE's expected residual returns as a result of ownership,
contractual or other financial interests in the VIE. Currently, entities are
generally consolidated by an enterprise that has a controlling financial
interest through ownership of a majority voting interest in the entity.
FIN 46 defines a VIE as an entity in which equity investors do not
have the characteristics of a controlling financial interest nor have sufficient
equity at risk for the entity to finance its activities without additional
subordinated financial support. VIE's created after January 31, 2003, are
immediately subject to the provisions of FIN 46. The FASB recently deferred
implementation of FIN 46 for VIE's created before February 1, 2003, until the
first reporting period ending after December 15, 2003 (TE's quarter ending
December 31, 2003.)
TE currently has transactions with entities in connection with sale
and leaseback arrangements which may fall within the scope of this
interpretation and which meet the definition of a VIE in accordance with FIN 46.
One such entity is the Shippingport Capital Trust which acquired all of the
lease obligation bonds issued in connection with the sale and leaseback in 1987
of interests in the Bruce Mansfield Plant held by TE and CEI, an affiliated
company. The equity ownership of this trust includes a 0.34% interest held by
Toledo Edison Capital Corporation, a majority owned subsidiary, and 4.85%
interests held by unaffiliated third parties. The assets and liabilities of the
trust are currently included on a proportionate basis in the financial
statements of TE and CEI. Adoption of FIN 46 may result in reporting all of the
trust assets and liabilities on the books of CEI. TE is also evaluating its
interests in the owner trusts that acquired the interests in the Bruce Mansfield
Plant and Beaver Valley Unit 2. TE has not completed its evaluation to determine
if it would be the primary beneficiary and therefore required to consolidate
these trusts.
The FASB continues to provide additional guidance on implementing FIN
46 and recently proposed modifications and clarifications with a comment period
ending December 1, 2003. As this guidance is finalized, TE will continue to
assess the accounting and disclosure impact of FIN 46 with respect to the VIE's
discussed above as well as other potential VIE's.
EITF Issue No. 01-08, "Determining whether an Arrangement
Contains a Lease"
In May 2003, the EITF reached a consensus on Issue No. 01-08,
regarding when arrangements contain a lease. Based on the EITF consensus, an
arrangement contains a lease if (1) it identifies specific property, plant or
equipment (explicitly or implicitly), and (2) the arrangement transfers the
right to the purchaser to control the use of the property, plant or equipment.
The consensus is to be applied prospectively to arrangements committed to,
modified or acquired through a business combination, beginning in the third
quarter of 2003. The adoption of this consensus as of July 1, 2003 did not
impact TE's financial statements.
95
PENNSYLVANIA POWER COMPANY
STATEMENTS OF INCOME
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------ ------------------------
2003 2002 2003 2002
---------- ---------- ---------- ----------
(In thousands)
OPERATING REVENUES........................................ $145,904 $131,917 $390,806 $383,989
-------- -------- -------- --------
OPERATING EXPENSES AND TAXES:
Fuel................................................... 6,142 6,568 15,073 19,280
Purchased power........................................ 44,761 40,057 125,781 115,683
Nuclear operating costs................................ 25,448 19,155 107,806 60,960
Other operating costs.................................. 15,141 13,365 41,750 33,034
-------- -------- -------- --------
Total operation and maintenance expenses........... 91,492 79,145 290,410 228,957
Provision for depreciation and amortization............ 13,461 14,203 40,206 42,615
General taxes.......................................... 6,093 6,720 18,151 18,730
Income taxes........................................... 14,990 13,044 17,779 38,295
-------- -------- -------- --------
Total operating expenses and taxes................. 126,036 113,112 366,546 328,597
-------- -------- -------- --------
OPERATING INCOME.......................................... 19,868 18,805 24,260 55,392
OTHER INCOME.............................................. 465 739 1,589 1,880
-------- -------- -------- --------
INCOME BEFORE NET INTEREST CHARGES........................ 20,333 19,544 25,849 57,272
-------- -------- -------- --------
NET INTEREST CHARGES:
Interest expense....................................... 3,788 4,188 11,964 12,554
Allowance for borrowed funds used during construction.. (844) (447) (2,172) (1,044)
-------- -------- -------- --------
Net interest charges............................... 2,944 3,741 9,792 11,510
-------- -------- -------- --------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING
CHANGE ................................................... 17,389 15,803 16,057 45,762
Cumulative effect of accounting change (net of income
taxes of $7,532,000) (Note 5).......................... -- -- 10,618 --
-------- -------- -------- --------
NET INCOME................................................ 17,389 15,803 26,675 45,762
PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 639 926 2,462 2,778
-------- -------- -------- --------
EARNINGS ON COMMON STOCK.................................. $ 16,750 $ 14,877 $ 24,213 $ 42,984
======== ======== ======== ========
The preceding Notes to Financial Statements as they relate to Pennsylvania Power Company are an integral part of these
statements.
96
PENNSYLVANIA POWER COMPANY
BALANCE SHEETS
(Unaudited)
September 30, December 31,
2003 2002
------------- ------------
(In thousands)
ASSETS
------
UTILITY PLANT:
In service................................................................ $793,153 $680,729
Less--Accumulated provision for depreciation.............................. 323,714 316,424
-------- --------
469,439 364,305
-------- --------
Construction work in progress-
Electric plant.......................................................... 63,054 44,696
Nuclear fuel............................................................ 4,050 8,812
-------- --------
67,104 53,508
-------- --------
536,543 417,813
-------- --------
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts...................................... 127,212 119,401
Long-term notes receivable from associated companies...................... 39,493 38,921
Other..................................................................... 2,131 2,569
-------- --------
168,836 160,891
-------- --------
CURRENT ASSETS:
Cash and cash equivalents................................................. 41 1,222
Receivables-
Customers (less accumulated provisions of $747,000 and $702,000,
respectively, for uncollectible accounts)............................. 45,511 44,341
Associated companies.................................................... 27,540 42,652
Other................................................................... 1,681 5,262
Notes receivable from associated companies................................ 486 35,317
Materials and supplies, at average cost................................... 30,874 30,309
Prepayments............................................................... 12,321 5,346
-------- --------
118,454 164,449
-------- --------
DEFERRED CHARGES:
Regulatory assets......................................................... 50,157 156,903
Other..................................................................... 7,447 7,692
-------- --------
57,604 164,595
-------- --------
$881,437 $907,748
======== ========
97
PENNSYLVANIA POWER COMPANY
BALANCE SHEETS
(Unaudited)
September 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....................................................... 38,129 50,916
-------- --------
Total common stockholder's equity................................... 204,260 229,374
Preferred stock-
Not subject to mandatory redemption..................................... 39,105 39,105
Subject to mandatory redemption (Note 5)................................ -- 13,500
Long-term debt and other long-term obligations-
Preferred stock subject to mandatory redemption (Note 5)................ 13,500 --
Other................................................................... 150,538 185,499
-------- --------
407,403 467,478
-------- --------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock (Note 5)............. 61,024 66,556
Accounts payable-
Associated companies.................................................... 51,352 52,653
Other................................................................... 360 5,730
Notes payable to associated companies..................................... 8,290 --
Accrued taxes............................................................. 35,332 12,507
Accrued interest.......................................................... 3,086 5,558
Other..................................................................... 9,091 10,479
-------- --------
168,535 153,483
-------- --------
DEFERRED CREDITS:
Accumulated deferred income taxes......................................... 97,513 117,385
Accumulated deferred investment tax credits............................... 3,590 3,810
Asset retirement obligation............................................... 127,450 --
Nuclear plant decommissioning costs....................................... -- 119,863
Other..................................................................... 76,946 45,729
-------- --------
305,499 286,787
-------- --------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)...........................
-------- --------
$881,437 $907,748
======== ========
The preceding Notes to Financial Statements as they relate to Pennsylvania Power Company are an integral part of these balance
sheets.
98
PENNSYLVANIA POWER COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2003 2002 2003 2002
-------- -------- -------- --------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................ $ 17,389 $ 15,803 $ 26,675 $ 45,762
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization........ 13,461 14,203 40,206 42,615
Nuclear fuel and lease amortization................ 4,607 5,054 11,396 14,622
Deferred income taxes, net......................... (2,378) (1,731) 1,376 (5,606)
Amortization of investment tax credits............. (598) (643) (1,826) (1,963)
Cumulative effect of accounting change (Note 5).... -- -- (18,150) --
Receivables........................................ (9,122) 376 12,418 (3,644)
Materials and supplies............................. (45) (1,766) (565) (4,049)
Accounts payable................................... 1,244 161 (917) (18,745)
Accrued taxes...................................... 14,024 (18,063) 22,825 5,026
Accrued interest................................... (2,496) (1,849) (2,472) (1,780)
Prepayments and other current assets............... 5,503 4,886 (6,975) (3,897)
Other.............................................. 4,026 1,461 11,222 2,013
-------- -------- -------- --------
Net cash provided from operating activities...... 45,615 17,892 95,213 70,354
-------- -------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt....................................... -- 14,500 -- 14,500
Short-term borrowings, net........................... 8,290 -- 8,290 --
Redemptions and Repayments-
Long-term debt....................................... (40,052) (15,031) (40,669) (56,321)
Dividend Payments-
Common stock......................................... (11,000) (20,700) (37,000) (28,500)
Preferred stock...................................... (911) (926) (2,734) (2,778)
-------- -------- -------- --------
Net cash used for financing activities........... (43,673) (22,157) (72,113) (73,099)
-------- -------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions..................................... (12,017) (8,210) (52,751) (24,636)
Contributions to nuclear decommissioning trusts........ (797) (399) (1,196) (1,196)
Notes receivable from associated companies, net........ 9,646 14,982 34,259 31,856
Other.................................................. 1,226 (1,244) (4,593) (1,892)
-------- -------- -------- --------
Net cash provided from (used for) investing
activities ..................................... (1,942) 5,129 (24,281) 4,132
-------- -------- -------- --------
Net increase (decrease) in cash and cash equivalents...... -- 864 (1,181) 1,387
Cash and cash equivalents at beginning of period.......... 41 590 1,222 67
-------- -------- -------- --------
Cash and cash equivalents at end of period................ $ 41 $ 1,454 $ 41 $ 1,454
======== ======== ======== ========
The preceding Notes to Financial Statements as they relate to Pennsylvania Power Company are an integral part of these
statements.
99
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board
of Directors of Pennsylvania
Power Company:
We have reviewed the accompanying balance sheet of Pennsylvania Power Company as
of September 30, 2003, and the related statements of income and cash flows for
each of the three-month and nine-month periods ended September 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
November 13, 2003
100
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 third quarter of 2003 increased to
$16.8 million from $14.9 million in the third quarter of 2002. In the first nine
months of 2003, earnings on common stock decreased to $24.2 million from $43.0
million in the first nine months of 2002. Earnings in the first nine months 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." Income before the cumulative effect was $16.1 million
in the first nine months of 2003 compared to income of $45.8 million for the
same period of 2002. The increased earnings in the third quarter of 2003
reflected higher operating revenues, but were partially offset by higher
operating costs - primarily nuclear operating costs, purchased power and
employee benefit costs. The lower results for the first nine months of 2003 were
primarily due to higher nuclear operating costs, purchased power costs and
employee benefit costs. These increased costs were partially offset by higher
operating revenues, lower fuel costs and reduced financing costs.
Operating revenues increased by $14.0 million, or 10.6%, in the third
quarter and $6.8 million, or 1.8%, in the first nine months of 2003 compared
with the same periods of 2002. The higher revenues primarily resulted from
increased wholesale revenues of $10.1 million and $10.5 million in the third
quarter and first nine months of 2003, respectively, as compared to the same
periods of 2002. In addition, higher retail generation sales revenues
contributed $3.5 million and $0.9 million in the third quarter and first nine
months, respectively.
Distribution deliveries increased 2.9% in the third quarter of 2003
compared with the same quarter in 2002. This increase reflected increases in
commercial and industrial sales of 6.9% and 6.0%, respectively, partially offset
by a residential customer sales decrease of 3.1% caused by the milder weather in
the third quarter of 2003 which reduced air conditioning demands. This
weather-related effect resulted in a nearly flat change in distribution delivery
revenues in the third quarter of 2003 from the same quarter of 2002. In the
first nine months of 2003, distribution deliveries decreased 1.2% compared with
the corresponding period of 2002, principally reflecting decreases in the
residential and industrial customer sectors. The residential customer sales
decreases were caused by the milder weather in the second and third quarters of
2003 which also reduced air conditioning demands and was the primary cause of
lower electricity throughput revenues of $4.6 million in the first nine months
of 2003 from the same period of the prior year.
Wholesale revenues from sales to FES increased by $11.0 million in the
third quarter and $9.2 million in the first nine months of 2003. These increases
reflected higher unit prices, which were partially offset by lower kilowatt-hour
sales due to reduced nuclear generation available for sale to FES.
Changes in electric generation sales and distribution deliveries in
the third quarter and first nine months of 2003 from the same periods of 2002
are summarized in the following table:
Changes in Kilowatt-Hour Sales Three Months Nine Months
------------------------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail............................. 3.0% (0.9)%
Wholesale.......................... (2.3)% (17.3)%
-----------------------------------------------------------------
Total Electric Generation Sales....... (0.2)% (10.8)%
=================================================================
Distribution Deliveries:
Residential........................ (3.1)% (1.9)%
Commercial......................... 6.9% 2.0%
Industrial......................... 6.0% (3.1)%
-----------------------------------------------------------------
Total Distribution Deliveries......... 2.9% (1.2)%
=================================================================
101
Operating Expenses and Taxes
Total operating expenses and taxes increased by $12.9 million in the
third quarter and $38.0 million in the first nine months of 2003 from the third
quarter and first nine months of 2002. The following table presents changes from
the prior year by expense category.
Operating Expenses and Taxes - Changes Three Months Nine Months
-------------------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel......................................... $(0.4) $ (4.2)
Purchased power costs........................ 4.7 10.1
Nuclear operating costs...................... 6.3 46.9
Other operating costs........................ 1.7 8.7
-------------------------------------------------------------------------
Total operation and maintenance expenses.. 12.3 61.5
Provision for depreciation and amortization.. (0.7) (2.4)
General taxes................................ (0.6) (0.6)
Income taxes................................. 1.9 (20.5)
-------------------------------------------------------------------------
Total increase in operating expenses and taxes $12.9 $ 38.0
=========================================================================
Lower fuel costs in the third quarter and first nine months 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 and increased kilowatt-hour purchases. 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; at Perry
(5.24% ownership) in the second quarter of 2003; and at Beaver Valley Unit 2
(13.74% ownership) in the third quarter of 2003, compared with one refueling
outage at Beaver Valley Unit 2 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 third quarter and $2.4 million in the first nine months of 2003 compared to
the third quarter and first nine months of 2002 primarily from lower charges
resulting from the implementation of SFAS 143 ($0.3 million for the third
quarter and $1.2 million for the first nine months of 2003) and revised service
life assumptions for generating plants ($0.3 million for the third quarter and
$0.9 million for the first nine months of 2003).
Net Interest Charges
Net interest charges continued to trend lower, decreasing by
approximately $0.8 million in the third quarter and $1.7 million in the first
nine months of 2003 from the same periods last year, reflecting redemptions and
refinancings since the beginning of the third 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.
102
Changes in Cash Position
As of September 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 provided from operating activities during the third quarter and
first nine months of 2003, compared with the corresponding periods in 2002 were
as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------------------
Operating Cash Flows 2003 2002 2003 2002
------------------------------------------------------------------------
(In millions)
Cash earnings (1)........ $36 $ 34 $63 $ 96
Working capital and other 10 (16) 32 (26)
------------------------------------------------------------------------
Total ............ $46 $ 18 $95 $ 70
========================================================================
(1) Includes net income, depreciation and amortization,
deferred income taxes, investment tax credits and major
noncash charges.
Net cash from operating activities increased to $46 million in the
third quarter and $95 million in the first nine months of 2003 compared with $18
million and $70 million, respectively, in the same periods of 2002. The increase
in working capital and other primarily was due to an increase of $32 million in
accrued tax liabilities partially offset by a decrease in accounts receivable of
$9 million in the third quarter of 2003 compared with corresponding changes in
the third quarter of 2002.
Cash Flows From Financing Activities
In the third quarter of 2003, net cash used for financing activities
increased to $44 million from $22 million in the same period last year. The
increase resulted from an increase in redemptions in 2003 compared to 2002.
Penn had approximately $0.5 million of cash and temporary investments,
primarily composed of notes receivable from associated companies and
approximately $8.3 million of short-term indebtedness as of September 30, 2003.
Penn may borrow from its affiliates on a short-term basis. Penn had the
capability to issue $230 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 September 30, 2003.
Cash Flows From Investing Activities
Net cash used for investing activities totaled $2 million in the third
quarter and $24 million in the first nine months of 2003, compared to net cash
provided from investing activities of $5 million and $4 million for the same
periods of 2002, respectively. The $7 million change in funds for the third
quarter resulted from lower payments received on notes from associated companies
and higher property additions as compared to 2002.
During the fourth quarter of 2003, capital requirements for property
additions and capital leases are expected to be about $13 million. Penn has
additional requirements of approximately $1.2 million to meet sinking fund
requirements for preferred stock and maturing long-term debt during the fourth
quarter of 2003. These requirements are expected to be satisfied from internal
cash and short-term credit arrangements.
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 (Penn has no ownership interest in this facility). 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."
On September 30, 2003, Fitch Ratings lowered the senior unsecured
ratings of FirstEnergy to "BBB-" from "BBB." Fitch also lowered the senior
secured, senior unsecured, and preferred stock ratings of Met-Ed, Penelec, CEI,
and TE. In addition, Fitch affirmed the ratings of OE, Penn and JCP&L. Fitch
announced that the Rating Outlook is Stable for the securities of FirstEnergy,
and all of the securities of its electric utility operating companies. Fitch
stated that the changes to the long-term debt ratings were "driven by the high
debt leverage of the parent FirstEnergy. Despite management's commitment to
reduce debt related to the GPU merger, subsequent cash flows have been
103
vulnerable to unfavorable events, slowing the pace of FirstEnergy's debt
reduction efforts. The Stable Outlook reflects the success of FirstEnergy's
recent common equity offering and management's focus on a relatively
conservative integrated utility strategy."
On October 27, 2003, Standard & Poors (S&P) stated that the `BBB'
corporate credit and the `BBB-` senior unsecured ratings for FirstEnergy and its
utility subsidiaries remain on CreditWatch with negative implications. The
ratings were placed on CreditWatch on August 18, 2003, and reflect S&P's
concerns regarding the potential impact of the August 14, 2003 blackout
investigation on FirstEnergy's deleveraging strategy and its overall efforts to
improve its credit profile.
At that time, S&P also noted other challenges facing FirstEnergy,
including the extended Davis-Besse outage; the recent U.S. District Court ruling
regarding the Sammis Plant (see Environmental Matters below); reliability
concerns in subsidiary JCP&L's service territory; and FirstEnergy's credibility
with regulators and federal officials.
S&P further noted several factors that could aid FirstEnergy in
resolution of the CreditWatch, including strengthening its balance sheet.
FirstEnergy directly addressed this concern through its recently completed
common equity offering that raised approximately $935 million in net proceeds,
which was used to reduce bank debt. S&P described the equity offering as a
"positive credit development" and also noted the recent renewal of FirstEnergy's
$1 billion revolver facilities as a "favorable development, as it mitigates
liquidity concerns." S&P also indicated that should various ongoing
investigations into the causal factors of the August 14, 2003 blackout establish
that the blackout resulted from no negligence or breach of compliance standards
on FirstEnergy's part, the CreditWatch could be removed and the outlook returned
to negative. S&P deemed a "stable" credit outlook unlikely until issues such as
the restart of Davis-Besse are resolved and the potential effect of the
litigation relating to the Sammis plant (the second trial is scheduled for April
2004) are known. Extension of the Ohio transition plan will be viewed as a
positive development and will support an outlook revision to stable.
On October 27, 2003, S&P also noted that the ratings on FirstEnergy
and its subsidiaries incorporate such strengths as the ability to generate free
cash flow, power generation contracted to its transmission and distribution
subsidiaries through 2005, and the hedging of its short power position arising
from its PLR obligation in Pennsylvania. S&P said that these strengths are
offset by slower than anticipated reduction of FirstEnergy debt, remaining
volume risks of PLR obligations, the extended outage at Davis-Besse, the
unfavorable outcome of the New Jersey rate proceeding and regulatory uncertainty
in Ohio. S&P also said that it now views FirstEnergy's liquidity position as
average, following FirstEnergy's renewal of its $1 billion credit facilities.
EQUITY PRICE RISK
Included in Penn's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $45
million and $38 million as of September 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 September 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. A number of customers previously served
by alternative energy providers have 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 by $106.7 million during the first nine
months of 2003, to $50.2 million as of September 30, 2003; $69.2 million of the
decrease related to the cumulative adjustment related to the adoption of 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.
104
Environmental Matters
Penn believes it is in compliance with the current sulfur dioxide
(SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act
Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized
regulations requiring additional NOx reductions in the future from Penn's Ohio
and Pennsylvania facilities. Various regulatory and judicial actions have since
sought to further define NOx reduction requirements (see Note 2 - Environmental
Matters). Penn continues to evaluate its compliance plans and other compliance
options.
Violations of federally approved SO2 regulations can result in
shutdown of the generating unit involved and/or civil or criminal penalties of
up to $31,500 for each day a unit is in violation. The EPA has an interim
enforcement policy for SO2 regulations in Ohio that allows for compliance based
on a 30-day averaging period. Penn 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 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 April
19, 2004, will address civil penalties and what, if any, actions should be taken
to further reduce emissions at the plant. In the ruling, the Court indicated
that the remedies it "may consider and impose involved a much broader, equitable
analysis, requiring the Court to consider air quality, public health, economic
impact and employment consequences. The Court may also consider the less than
consistent efforts of the EPA to apply and further enforce the Clean Air Act."
The potential penalties that may be imposed, as well as the capital expenditures
necessary to comply with substantive remedial measures that may be required,
could have a material adverse impact on the Company's financial condition and
results of operations. Management is unable to predict the ultimate outcome of
this matter and no liability has been recorded as of September 30, 2003.
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 SO2 and 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 its 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 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.
105
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 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 - $50 million as of September 30,
2003. 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:
o Net energy generated or purchased for retail load
o Losses of energy over distribution lines
o 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.
106
Based on pension assumptions and pension plan assets as of December
31, 2002, FirstEnergy is not 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.
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 STANDARDS
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". This Interpretation requires the
consolidation of a variable interest entity (VIE) by an enterprise if that
enterprise either absorbs a majority of the VIE's expected losses or receives a
majority of the VIE's expected residual returns as a result of ownership,
contractual or other financial interests in the VIE. Currently, entities are
generally consolidated by an enterprise that has a controlling financial
interest through ownership of a majority voting interest in the entity.
FIN 46 defines a VIE as an entity in which equity investors do not
have the characteristics of a controlling financial interest nor have sufficient
equity at risk for the entity to finance its activities without additional
subordinated financial support. VIE's created after January 31, 2003, are
immediately subject to the provisions of FIN 46. The FASB recently deferred
implementation of FIN 46 for VIE's created before February 1, 2003, until the
first reporting period ending after December 15, 2003 (Penn's quarter ending
December 31, 2003.)
The adoption of FIN 46 for variable interests created after January
31, 2003 did not have an impact on Penn's financial statements. We are
continuing to review the provisions of FIN 46 to determine its impact, if any,
on future reporting periods with respect to interests in VIE's created prior to
February 1, 2003, and do not currently anticipate that adoption will result in
any material accounting or disclosure requirements.
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
Upon adoption of SFAS 150, on July 1, 2003, Penn reclassified as debt
its preferred stock subject to mandatory redemption having carrying values of
approximately $13.5 million as of September 30, 2003. Prior to the adoption of
SFAS 150, dividends on preferred stock subject to mandatory redemption in Penn's
Statements of Income were not included in net interest charges. Therefore, the
application of SFAS 150 required 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 on Issue No. 01-08,
regarding when arrangements contain a lease. Based on the EITF consensus, an
arrangement contains a lease if (1) it identifies specific property, plant or
equipment (explicitly or implicitly), and (2) the arrangement transfers the
right to the purchaser to control the use of the property, plant or equipment.
The consensus is to be applied prospectively to arrangements committed to,
modified or acquired through a business combination, beginning in the third
quarter of 2003. The adoption of this consensus as of July 1, 2003 did not
impact Penn's financial statements.
107
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ---------------------------
2003 2002 2003 2002
-------- -------- ---------- ----------
(In thousands)
OPERATING REVENUES........................................ $743,145 $779,955 $1,942,868 $1,731,900
-------- -------- ---------- ----------
OPERATING EXPENSES AND TAXES:
Fuel................................................... 524 1,873 3,290 4,347
Purchased power........................................ 416,308 453,081 1,260,352 913,532
Other operating costs.................................. 111,204 50,587 263,229 193,204
-------- -------- ---------- ----------
Total operation and maintenance expenses........... 528,036 505,541 1,526,871 1,111,083
Provision for depreciation and amortization............ 68,523 67,645 181,673 186,919
General taxes.......................................... 18,506 17,740 47,282 39,037
Income taxes........................................... 44,461 67,689 51,713 134,093
-------- -------- ---------- ----------
Total operating expenses and taxes................. 659,526 658,615 1,807,539 1,471,132
-------- -------- ---------- ----------
OPERATING INCOME.......................................... 83,619 121,340 135,329 260,768
OTHER INCOME.............................................. 1,061 1,269 4,501 6,291
-------- -------- ---------- ----------
INCOME BEFORE NET INTEREST CHARGES........................ 84,680 122,609 139,830 267,059
-------- -------- ---------- ----------
NET INTEREST CHARGES:
Interest on long-term debt............................. 20,888 23,721 66,867 69,206
Allowance for borrowed funds used during construction.. 39 (301) (195) (880)
Deferred interest...................................... (1,541) (3,722) (7,667) (5,107)
Other interest expense................................. 1,131 (538) 1,076 (2,315)
Subsidiary's preferred stock dividend requirements..... -- 2,674 5,348 8,021
-------- -------- ---------- ----------
Net interest charges............................... 20,517 21,834 65,429 68,925
-------- -------- ---------- ----------
NET INCOME................................................ 64,163 100,775 74,401 198,134
PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 125 (2,773) (238) (1,589)
-------- -------- ---------- ----------
EARNINGS ON COMMON STOCK.................................. $ 64,038 $103,548 $ 74,639 $ 199,723
======== ======== ========== ==========
The preceding Notes to Financial Statements as they relate to Jersey Central Power & Light Company are an integral part
of these statements.
108
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2003 2002
------------- ------------
(In thousands)
ASSETS
------
UTILITY PLANT:
In service................................................................ $3,603,705 $3,478,803
Less--Accumulated provision for depreciation.............................. 1,500,171 1,343,846
---------- ----------
2,103,534 2,134,957
Construction work in progress - electric plant............................ 41,320 20,687
---------- ----------
2,144,854 2,155,644
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts...................................... 117,768 106,820
Nuclear fuel disposal trust............................................... 152,341 149,738
Long-term notes receivable from associated companies...................... 21,317 20,333
Other..................................................................... 24,206 18,202
---------- ----------
315,632 295,093
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents................................................. 1,270 4,823
Receivables-
Customers (less accumulated provisions of $4,998,000 and $4,216,000
respectively, for uncollectible accounts).............................. 287,062 247,624
Associated companies.................................................... 88,807 318
Other .................................................................. 41,716 20,134
Notes receivable from associated companies................................ -- 77,358
Materials and supplies, at average cost................................... 2,076 1,341
Prepayments and other..................................................... 58,278 37,719
---------- ----------
479,209 389,317
---------- ----------
DEFERRED CHARGES:
Regulatory assets......................................................... 2,926,669 3,199,012
Goodwill.................................................................. 2,000,875 2,000,875
Other..................................................................... 12,558 12,814
---------- ----------
4,940,102 5,212,701
---------- ----------
$7,879,797 $8,052,755
========== ==========
109
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 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.................................... (64,740) (865)
Retained earnings....................................................... 38,641 92,003
---------- ----------
Total common stockholder's equity................................... 3,156,832 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............................................................ 1,261,690 1,210,446
---------- ----------
4,431,171 4,622,408
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt.......................................... 15,600 173,815
Accounts payable-
Associated companies.................................................... 87,553 170,803
Other................................................................... 121,833 106,504
Notes payable to associated companies..................................... 287,867 --
Accrued taxes............................................................. 29,932 13,844
Accrued interest.......................................................... 26,124 27,161
Other..................................................................... 64,736 112,408
---------- ----------
633,645 604,535
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes......................................... 619,506 691,721
Accumulated deferred investment tax credits............................... 8,232 9,939
Power purchase contract loss liability.................................... 1,599,904 1,710,968
Nuclear fuel disposal costs............................................... 167,537 166,191
Asset retirement obligation............................................... 108,343 --
Retirement benefits...................................................... 192,492 --
Nuclear decommissioning costs............................................. -- 135,355
Other..................................................................... 118,967 111,638
---------- ----------
2,814,981 2,825,812
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)...........................
---------- ----------
$7,879,797 $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.
110
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ---------------------------
2003 2002 2003 2002
-------- -------- ---------- ----------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................ $ 64,163 $ 100,775 $ 74,401 $ 198,134
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization........ 68,523 67,645 181,673 186,919
Deferred costs, net................................ (34,004) (122,338) (118,337) (231,286)
Deferred income taxes, net......................... 7,362 48,583 (9,642) 85,123
Amortization of investment tax credits............. (557) (899) (1,707) (2,698)
Accrued retirement benefit obligation.............. 22,739 -- 28,905 --
Accrued compensation, net.......................... (829) -- 20,730 --
Revenue credits to customers....................... (19,583) (17,434) (71,984) (17,434)
Disallowed purchased power costs (see Note 4)...... -- -- 152,500 --
Receivables........................................ (30,971) (14,584) (98,573) (4,647)
Materials and supplies............................. 37 (1) (735) 44
Accounts payable................................... (105,130) (21,250) (92,791) 11,694
Prepayments and other current assets............... 49,888 41,706 (20,559) (28,944)
Accrued taxes...................................... 11,279 7,761 16,088 (20,699)
Accrued interest................................... 7,391 8,570 (1,037) 7,060
Other.............................................. (32,954) (2,096) (1,456) 2,356
--------- --------- ---------- ----------
Net cash provided from operating
activities ..................................... 7,354 96,438 57,476 185,622
--------- --------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt....................................... -- -- 150,000 318,106
Short-term borrowings, net........................... 91,741 -- 287,867 --
Redemptions and Repayments-
Preferred stock...................................... -- (46,500) (125,244) (51,500)
Long-term debt....................................... (82,388) (146,033) (247,414) (196,033)
Short-term borrowings, net........................... -- -- -- (18,149)
Dividend Payments-
Common stock......................................... -- (57,700) (128,000) (123,700)
Preferred stock...................................... -- (256) -- (2,000)
--------- --------- ---------- ----------
Net cash provided from (used for) financing
activities ..................................... 9,353 (250,489) (62,791) (73,276)
--------- --------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions..................................... (19,891) (23,567) (74,742) (70,401)
Decommissioning trust investments...................... (742) (304) (1,931) (1,013)
Associated companies loans, net........................ (984) -- 76,374 --
Other.................................................. 153 (7,782) 2,061 (10,764)
--------- --------- ---------- ----------
Net cash provided from (used for) investing
activities ..................................... (21,464) (31,653) 1,762 (82,178)
--------- --------- ---------- ----------
Net increase (decrease) in cash and cash equivalents...... (4,757) (185,704) (3,553) 30,168
Cash and cash equivalents at beginning of period.......... 6,027 247,296 4,823 31,424
--------- --------- ---------- ----------
Cash and cash equivalents at end of period................ $ 1,270 $ 61,592 $ 1,270 $ 61,592
========= ========= ========== ==========
The preceding Notes to Financial Statements as they relate to Jersey Power & Light Company are an integral part of these
statements.
111
REPORT OF INDEPENDENT ACCOUNTANTS
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 September 30, 2003, and the
related consolidated statements of income and cash flows for each of the
three-month and nine-month periods ended September 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
November 13, 2003
112
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. The "provider of last resort" (PLR) obligation
known as Basic Generation Services (BGS) for customers who have not selected an
alternative supplier had been removed from JCP&L as the result of the NJBPU
approved auctions of those obligations.
RESULTS OF OPERATIONS
Earnings on common stock in the third quarter of 2003 decreased to
$64.0 million from $103.5 million in the third quarter of 2002. For the first
nine months of 2003, earnings on common stock were $74.6 million as compared to
$199.7 million for the same period of 2002, as a result of non-cash charges
aggregating $171.6 million ($103 million after tax) due to a rate case decision
disallowing recovery of certain regulatory assets (see Regulatory Matters).
Excluding the impact of those non-cash charges earnings on common stock were
$167.2 million for the first nine months of 2003.
Operating revenues decreased $36.8 million or 4.7% in the third
quarter but increased $211.0 million or 12.2% in the first nine months of 2003,
respectively, compared with the same periods in 2002. The lower revenues in the
third quarter of 2003 compared to the previous year resulted from decreased
wholesale revenues of $54.5 million. The milder summer weather adversely
impacted the opportunities to sell in the wholesale market. The increase in
revenues for the first nine months of the year was due to a $124.4 million
increase in wholesale revenues and higher distribution deliveries. 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 August 1, 2002 through
July 31, 2003, and as a result, JCP&L 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. The operating revenue
changes also included increased retail generation sales revenue of $28.1 million
and $39.4 million in the third quarter and first nine months of 2003,
respectively, as compared to those periods in 2002. These revenue increases
reflected higher unit prices which were partially offset by the effect of lower
retail sales of 9.2% and 0.3%, respectively, in the third quarter and first nine
months of 2003.
Distribution deliveries increased by 1.6% in the third quarter of 2003
from the corresponding quarter of 2002. Lower unit prices in 2003 more than
offset the impact of the increased volume and reduced revenues by $14.2 million.
In addition, revenues reflect the impact of the net revenue decrease effective
August 1, 2003, from the NJBPU's decision (see Regulatory Matters). Weather
contributed to the $26.5 million (3.2%) increase in revenue from higher
distribution deliveries to retail customers in the first nine months of 2003
compared to the same period last year. Colder temperatures early in the year
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 third quarter and the first nine months of 2003 compared with
the same periods of 2002 are summarized in the following table:
Changes in Kilowatt-Hour Deliveries Three Months Nine Months
-----------------------------------------------------------------------
Increase (Decrease)
Residential........................... 4.1% 5.5%
Commercial............................ (2.6)% 5.2%
Industrial............................ 3.7% (2.0)%
------------------------------------------------------------------------
Total Distribution Deliveries........... 1.6% 4.3%
========================================================================
Operating Expenses and Taxes
Total operating expenses and taxes increased by $0.9 million in the
third quarter and $336.4 million in the first nine months of 2003 compared to
the same periods of 2002. These increases include the non-cash charges in the
first nine months of 2003 for amounts disallowed in the JCP&L rate case decision
(see Regulatory Matters), ($152.5 million charged to purchased power and $19.1
million charged to depreciation and amortization). The following table presents
changes from the prior year by expense category.
113
Operating Expenses and Taxes - Changes Three Months Nine Months
----------------------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel............................................. $ (1.3) $ (1.0)
Purchased power costs............................ (36.8) 346.8
Other operating costs............................ 60.6 70.0
----------------------------------------------------------------------------
Total operation and maintenance expenses....... 22.5 415.8
Provision for depreciation and amortization...... 0.8 (5.2)
General taxes.................................... 0.8 8.2
Income taxes..................................... (23.2) (82.4)
-----------------------------------------------------------------------------
Net increase in operating expenses and taxes... $ 0.9 $336.4
===========================================================================--
Purchased power costs decreased by $36.8 million in the third quarter
compared to the prior year due to reduced energy requirements. Excluding the
disallowed deferred energy costs of $152.5 million, purchased power increased
$194.3 million in the first nine months of 2003 compared to the corresponding
period of 2002. Increased kilowatt-hours purchased through two-party agreements
and changes in the deferred energy and capacity costs were the primary
contributors to the increase. Other operating expenses increased $60.6 million
in the third quarter of 2003 and $70.0 million for the first nine months of
2003, compared to the same periods in 2002, due to higher pension and benefits
costs, storm restoration expense and costs associated with an accelerated
reliability plan within JCP&L's service territory.
Excluding the disallowed costs discussed above, depreciation and
amortization charges decreased by $12.2 million in the third quarter and $24.4
million in the first nine months of 2003, due to the cessation of amortization
of regulatory assets related to the previously divested Oyster Creek Nuclear
Generating Station, demand side management program deferrals and the reduction
of depreciation rates on August 1, 2003 resulting from the NJBPU decision (see
Regulatory Matters). General taxes increased $8.2 million in the first nine
months of 2003, compared to the corresponding period 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 $1.3 million in the third quarter of
2003 and $3.5 million in the first nine months compared with the same periods of
2002, reflecting debt redemptions since the beginning of the fourth quarter 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 which were used for redeeming outstanding securities in
the second and third quarters of 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 September 30, 2003, JCP&L had $1.3 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 third quarter and
first nine months of 2003 compared to the corresponding periods of 2002 were as
follows:
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------------
Operating Cash Flows 2003 2002 2003 2002
-------------------------------------------------------------------------
(In millions)
Cash earnings (1)........ $ 108 $75 $ 256 $219
Working capital and other (101) 21 (199) (33)
-------------------------------------------------------------------------
Total ............ $ 7 $96 $ 57 $186
=========================================================================
(1) Includes net income, depreciation and amortization,
deferred income taxes, investment tax credits and major
noncash charges.
114
Net cash provided from operating activities decreased by $89 million
in the third quarter of 2003 and $129 million in the first nine months of 2003
compared to the same periods of 2002. The third quarter decrease was due to a
$122 million increase in funds used for working capital and other, partially
offset by a $33 million increase in cash earnings. The change in working capital
primarily reflects an $84 million change in accounts payable.
Cash Flows From Financing Activities
In the third quarter of 2003, net cash provided from financing
activities of $9 million primarily reflected the issuance of $92 million of
short-term debt and an $83 million repayment of long-term debt. In the third
quarter of 2002, net cash used for financing activities totaled $250 million,
due to redemptions ($192.5 million) and dividend payments of $57.7 million to
FirstEnergy.
As of September 30, 2003, JCP&L had approximately $1.3 million of cash
and temporary investments and $287.9 million of 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 September 30, 2003. JCP&L had
the capability to issue $666 million of additional senior notes based upon FMB
collateral. Based upon applicable earnings coverage tests, JCP&L could issue a
total of $783 million of preferred stock (assuming no additional debt was
issued) as of September 30, 2003.
Cash Flows From Investing Activities
Net cash used for investing activities totaled $22 million in the
third quarter and $2 million provided from investing activities in the first
nine months of 2003, compared with net cash used of $32 million and $82 million
in the third quarter and first nine months of 2002. Net cash used for 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 fourth quarter of 2003, capital requirements for property
additions are expected to be about $25 million. JCP&L has additional
requirements of approximately $4 million for maturing long-term debt during the
fourth quarter of 2003. These cash requirements are expected to be satisfied
from internal cash and short-term credit arrangements.
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."
On September 30, 2003, Fitch Ratings lowered the senior unsecured
ratings of FirstEnergy to "BBB-" from "BBB." Fitch also lowered the senior
secured, senior unsecured, and preferred stock ratings of Met-Ed, Penelec, CEI,
and TE. In addition, Fitch affirmed the ratings of OE, Penn and JCP&L. Fitch
announced that the Rating Outlook is Stable for the securities of FirstEnergy,
and all of the securities of its electric utility operating companies. Fitch
stated that the changes to the long-term ratings were "driven by the high debt
leverage of the parent FE. Despite management's commitment to reduce debt
related to the GPU merger, subsequent cash flows have been vulnerable to
unfavorable events, slowing the pace of FE's debt reduction efforts. The Stable
Outlook reflects the success of FE's recent common equity offering and
management's focus on a relatively conservative integrated utility strategy."
On October 27, 2003, Standard & Poors (S&P) stated that the `BBB'
corporate credit and the `BBB-` senior unsecured ratings for FirstEnergy and its
utility subsidiaries remain on CreditWatch with negative implications. The
ratings were placed on CreditWatch on August 18, 2003, and reflect S&P's
concerns regarding the potential impact of the August 14, 2003 blackout
investigation on FirstEnergy's deleveraging strategy and its overall efforts to
improve its credit profile.
At that time, S&P also noted other challenges facing FirstEnergy,
including the extended Davis-Besse outage; the recent U.S. District Court ruling
regarding the Sammis Plant; reliability concerns in subsidiary JCP&L's service
territory; and FirstEnergy's credibility with regulators and federal officials.
S&P further noted several factors that could aid FirstEnergy in
resolution of the CreditWatch, including strengthening its balance sheet.
FirstEnergy directly addressed this concern through its recently completed
common equity offering that raised approximately $935 million in net proceeds,
115
which was used to reduce bank debt. S&P described the equity offering as a
"positive credit development" and also noted the recent renewal of FirstEnergy's
$1 billion revolver facilities as a "favorable development, as it mitigates
liquidity concerns." S&P also indicated that should various ongoing
investigations into the causal factors of the August 14, 2003 blackout establish
that the blackout resulted from no negligence or breach of compliance standards
on FirstEnergy's part, the CreditWatch could be removed and the outlook returned
to negative. S&P deemed a "stable" credit outlook unlikely until issues such as
the restart of Davis-Besse are resolved and the potential effect of the
litigation relating to the Sammis plant (the second trial is scheduled for April
2004) are known. Extension of the Ohio transition plan will be viewed as a
positive development and will support an outlook revision to stable.
On October 27, 2003, S&P also noted that the ratings on FirstEnergy
and its subsidiaries incorporate such strengths as the ability to generate free
cash flow, power generation contracted to its transmission and distribution
subsidiaries through 2005, and the hedging of its short power position arising
from its PLR obligation in Pennsylvania. S&P said that these strengths are
offset by slower than anticipated reduction of FirstEnergy debt, remaining
volume risks of PLR obligations, the extended outage at Davis-Besse, the
unfavorable outcome of the New Jersey rate proceeding and regulatory uncertainty
in Ohio. S&P also said that it now views FirstEnergy's liquidity position as
average, following FirstEnergy's renewal of its $1 billion credit facilities.
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 third quarter and first nine months of 2003 is
summarized in the following table:
Three Months Ended Nine Months Ended
Increase (Decrease) in the Fair Value September 30, 2003 September 30, 2003
-------------------------- --------------------------
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....................... $12.9 $ (0.1) $12.8 $ 8.7 $(0.1) $ 8.6
New contract value when entered........................ -- -- -- -- -- --
Changes in value of existing contracts................. (0.1) -- (0.1) 4.0 -- 4.0
Change in techniques/assumptions....................... 2.3 -- 2.3 2.3 -- 2.3
Settled contracts...................................... -- 0.1 0.1 0.1 0.1 0.2
------------------------------------------------------- ------------------------- ------------------------
Net Assets - Derivative Contracts at end of period (1). $15.1 $ -- $15.1 $15.1 $-- $15.1
======================================================= ========================= ========================
Impact of Changes in Commodity Derivative Contracts (2)
Income Statement Effects (Pre-Tax)..................... $-- $ -- $ -- $ -- $-- $--
Balance Sheet Effects:
Other Comprehensive Income (Pre-Tax)................ $-- $ 0.1 $ 0.1 $ -- $ 0.1 $ 0.1
Regulatory Liability................................ $ 2.2 $ -- $ 2.2 $ 6.4 $-- $ 6.4
(1) Represents 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
September 30, 2003:
Non-Hedge Hedge Total
----------------------------------------------------------------------
(In millions)
Current-
Other Assets.................. $-- $ -- $--
Other Liabilities............. -- -- --
Non-Current-
Other Deferred Charges........ 15.1 -- 15.1
Other Deferred Credits........ -- -- --
-------------------------------------------------------------------
Net Assets.................... $15.1 $ -- $15.1
======================================================================
116
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)... $0.3 $2.1 $2.3 $-- $-- $ 4.7
Prices based on models................ -- -- -- 2.4 8.0 10.4
-----------------------------------------------------------------------------------------------------------
Total(3).......................... $0.3 $2.1 $2.3 $2.4 $8.0 $15.1
===========================================================================================================
(1) For the last quarter of 2003. (2) Broker quote sheets.
(3) Represents an embedded option that is offset by a regulatory liability and does not affect earnings.
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
September 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 $61
million and $52 million as of September 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 September 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 $2.9 billion and $3.2 billion as of
September 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 reduced JCP&L's annual
revenues by approximately $62 million effective August 1, 2003. The NJBPU
decision also provided for an interim return on equity of 9.5 percent on JCP&L's
rate base for 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 net revenue decrease from the NJBPU's decision consists of a $223
million decrease in the electricity delivery charge, a $111 million increase due
to the August 1, 2003 expiration of annual customer credits previously mandated
by the New Jersey transition legislation, a $49 million increase in the MTC
tariff component, and a net $1 million increase in the SBC charge. The MTC
allows for the recovery of $465 million in deferred energy costs over the next
ten years on an interim basis, thus disallowing $153 million of the $618 million
provided for in a preliminary settlement agreement between certain parties. As a
result, JCP&L recorded charges to net income for the nine months ended September
30, 2003, aggregating $172 million ($103 million net of tax) consisting of the
$153 million deferred energy costs and other regulatory assets. JCP&L filed a
117
motion for rehearing and reconsideration with the NJBPU on August 15, 2003 with
respect to the following issues: (1) the disallowance of the $153 million
deferred energy costs; (2) the reduced rate of return on equity; and (3) $42.7
million of disallowed costs to achieve merger savings. On October 10, 2003, the
NJBPU held the motion in abeyance until the final NJBPU decision and order is
issued, which is expected in the fourth quarter of 2003.
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, environmental liabilities that are considered probable have been
recognized on the Consolidated Balance Sheet as of September 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 $47.9
million as of September 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.
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
118
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. In accordance with the
accounting standard, if the fair value of a reporting unit is less than its
carrying value (including goodwill), the goodwill is tested for impairment. If
impairment were indicated, JCP&L would recognize a loss - calculated as the
difference between the implied fair value of its goodwill and the carrying value
of the goodwill indicated. JCP&L's annual review was completed in the third
quarter of 2003, with no impairment of goodwill indicated. The forecasts used in
JCP&L's evaluation 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 September
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 - $2.9 billion as of September 30, 2003.
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.
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
billed through the end of the accounting period. The determination of unbilled
revenues requires management to make various estimates including:
o Net energy generated or purchased for retail load
o Losses of energy over distribution lines
o 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
119
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 is not 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.
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
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". This Interpretation requires the
consolidation of a variable interest entity (VIE) by an enterprise if that
enterprise either absorbs a majority of the VIE's expected losses or receives a
majority of the VIE's expected residual returns as a result of ownership,
contractual or other financial interests in the VIE. Currently, entities are
generally consolidated by an enterprise that has a controlling financial
interest through ownership of a majority voting interest in the entity.
FIN 46 defines a VIE as an entity in which equity investors do not
have the characteristics of a controlling financial interest nor have sufficient
equity at risk for the entity to finance its activities without additional
subordinated financial support. VIE's created after January 31, 2003, are
immediately subject to the provisions of FIN 46. The FASB recently deferred
implementation of FIN 46 for VIE's created before February 1, 2003, until the
first reporting period ending after December 15, 2003 (JCP&L's quarter ending
December 31, 2003.)
The adoption of FIN 46 for variable interests created after January
31, 2003 did not have an impact on JCP&L's financial statements. We are
continuing to review the provisions of FIN 46 to determine its impact, if any,
on future reporting periods with respect to interests in VIE's created prior to
February 1, 2003, and do not currently anticipate that adoption will result in
any material accounting or disclosure requirements.
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, 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, that continue to be applied based on their
original effective dates. Adoption of SFAS 149 did not have a material impact on
JCP&L's financial statements.
120
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 JCP&L'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 of a general index, such as the Consumer Price
Index, in a contract would prevent that contract from qualifying for the normal
purchases and normal sales (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 but does not anticipate any material 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 on Issue No. 01-08 regarding
when arrangements contain a lease. Based on the EITF consensus, an arrangement
contains a lease if (1) it identifies specific property, plant or equipment
(explicitly or implicitly), and (2) the arrangement transfers the right to the
purchaser to control the use of the property, plant or equipment. The consensus
is to be applied prospectively to arrangements committed to, modified or
acquired through a business combination, beginning in the third quarter of 2003.
The adoption of this consensus as of July 1, 2003 did not impact JCP&L's
financial statements.
121
METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ---------------------
2003 2002 2003 2002
-------- -------- -------- --------
(In thousands)
OPERATING REVENUES........................................ $261,756 $281,540 $730,671 $767,333
-------- -------- -------- --------
OPERATING EXPENSES AND TAXES:
Purchased power........................................ 159,968 201,320 425,116 483,756
Other operating costs.................................. 41,660 24,372 109,240 86,947
-------- -------- -------- --------
Total operation and maintenance expenses........... 201,628 225,692 534,356 570,703
Provision for depreciation and amortization............ 18,508 22,022 67,745 52,360
General taxes.......................................... 18,406 19,237 50,804 50,964
Income taxes........................................... 4,153 988 16,136 22,886
-------- -------- -------- --------
Total operating expenses and taxes................. 242,695 267,939 669,041 696,913
-------- -------- -------- --------
OPERATING INCOME.......................................... 19,061 13,601 61,630 70,420
OTHER INCOME.............................................. 5,357 5,884 15,832 16,471
-------- -------- -------- --------
INCOME BEFORE NET INTEREST CHARGES........................ 24,418 19,485 77,462 86,891
-------- -------- -------- --------
NET INTEREST CHARGES:
Interest on long-term debt............................. 8,501 10,054 28,382 30,736
Allowance for borrowed funds used during construction.. (94) (234) (252) (798)
Deferred interest...................................... (192) (167) (1,187) (402)
Other interest expense................................. 2,521 854 3,386 2,025
Subsidiary's preferred stock dividend requirements..... -- 1,890 3,779 5,669
-------- -------- -------- --------
Net interest charges............................... 10,736 12,397 34,108 37,230
-------- -------- -------- --------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING
CHANGE ................................................... 13,682 7,088 43,354 49,661
Cumulative effect of accounting change (net of income
taxes of $154,000) (Note 5)............................ -- -- 217 --
-------- -------- -------- --------
NET INCOME................................................ $ 13,682 $ 7,088 $ 43,571 $ 49,661
======== ======== ======== ========
The preceding Notes to Financial Statements as they relate to Metropolitan Edison Company are an integral part of these
statements.
122
METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2003 2002
------------- ------------
(In thousands)
ASSETS
------
UTILITY PLANT:
In service................................................................ $1,825,650 $1,620,613
Less--Accumulated provision for depreciation.............................. 762,454 547,925
---------- ----------
1,063,196 1,072,688
Construction work in progress.............................................. 20,068 16,078
---------- ----------
1,083,264 1,088,766
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts...................................... 176,848 155,690
Long-term notes receivable from associated companies...................... 9,974 12,418
Other..................................................................... 31,538 19,206
---------- ----------
218,360 187,314
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents................................................. 142 15,685
Receivables-
Customers (less accumulated provisions of $5,061,000 and $4,810,000
respectively, for uncollectible accounts)............................. 117,722 120,868
Associated companies.................................................... 57,839 23,219
Other................................................................... 19,802 18,235
Notes receivable from associated companies................................ 10,010 --
Material and supplies, at average cost.................................... 145 --
Prepayments and other..................................................... 12,231 9,731
---------- ----------
217,891 187,738
---------- ----------
DEFERRED CHARGES:
Regulatory assets......................................................... 1,059,756 1,179,125
Goodwill.................................................................. 885,832 885,832
Other..................................................................... 38,222 36,030
---------- ----------
1,983,810 2,100,987
---------- ----------
$3,503,325 $3,564,805
========== ==========
123
METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 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............................................ $1,297,784 $1,297,784
Accumulated other comprehensive loss.................................... (36,414) (39)
Retained earnings....................................................... 34,411 17,841
---------- ----------
Total common stockholder's equity................................... 1,295,781 1,315,586
Company-obligated mandatorily redeemable preferred securities (Note 5).... -- 92,409
Long-term debt and other long-term obligations-
Company-obligated mandatorily redeemable preferred securities (Note 5).. 92,566 --
Other................................................................... 569,105 538,790
---------- ----------
1,957,452 1,946,785
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt.......................................... 40,469 60,467
Accounts payable-
Associated companies.................................................... 60,222 56,861
Other................................................................... 34,457 28,583
Notes payable to associated companies..................................... 56,256 88,299
Accrued taxes............................................................. 3,636 16,096
Accrued interest.......................................................... 8,497 16,448
Other..................................................................... 20,063 11,690
---------- ----------
223,600 278,444
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes......................................... 260,123 316,757
Accumulated deferred investment tax credits............................... 11,903 12,518
Power purchase contract loss liability.................................... 614,608 660,507
Nuclear fuel disposal costs............................................... 37,845 37,541
Asset retirement obligation............................................... 207,139 --
Nuclear decommissioning costs............................................. -- 270,611
Retirement benefits....................................................... 119,738 1,354
Other..................................................................... 70,917 40,288
---------- ----------
1,322,273 1,339,576
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)...........................
---------- ----------
$3,503,325 $3,564,805
========== ==========
The preceding Notes to Financial Statements as they relate to Metropolitan Edison Company are an integral part of these
balance sheets.
124
METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ---------------------
2003 2002 2003 2002
-------- -------- -------- --------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................ $ 13,682 $ 7,088 $ 43,571 $ 49,661
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization........ 18,508 22,022 67,745 52,360
Deferred costs, net................................ 5,621 7,678 (7,857) (1,733)
Deferred income taxes, net......................... (315) 2,111 9,349 14,301
Amortization of investment tax credits............. (205) (212) (615) (636)
Accrued retirement benefit obligation.............. 3,620 25 7,144 38
Accrued compensation, net.......................... (120) (352) 6,207 (2,389)
Cumulative effect of accounting change (Note 5).... -- -- (371) --
Receivables........................................ 11,953 (3,494) 2,007 (17,302)
Materials and supplies............................. (6) -- (145) --
Accounts payable................................... (89,944) (26,567) (5,647) (29,492)
Accrued taxes...................................... 214 5 (12,460) (5,084)
Accrued interest................................... (4,161) (7,063) (7,951) (6,627)
Prepayments and other current assets............... 16,136 16,088 (2,500) 4,662
Other.............................................. (11,300) (18,365) (30,201) (38,592)
-------- -------- -------- --------
Net cash provided from (used for) operating
activities ..................................... (36,317) (1,036) 68,276 19,167
-------- -------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt....................................... -- -- 247,696 49,750
Short-term borrowings, net........................... 35,591 60,628 -- 59,769
Redemptions and Repayments-
Long-term debt....................................... (32) (30,000) (230,467) (60,000)
Short-term borrowings, net........................... -- -- (32,043) --
Dividend Payments-
Common stock......................................... (7,000) -- (27,000) (30,000)
-------- -------- -------- --------
Net cash provided from (used for) financing
activities ..................................... 28,559 30,628 (41,814) 19,519
-------- -------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions..................................... (8,382) (11,209) (28,284) (31,996)
Contributions to nuclear decommissioning trusts........ (2,371) (2,371) (7,112) (10,358)
Associated companies loans, net........................ 17,144 -- (7,566) --
Other.................................................. 1,179 (20) 957 (279)
-------- -------- -------- --------
Net cash provided from (used for) investing
activities ..................................... 7,570 (13,600) (42,005) (42,633)
-------- -------- -------- --------
Net increase (decrease) in cash and cash equivalents...... (188) 15,992 (15,543) (3,947)
Cash and cash equivalents at beginning of period.......... 330 5,335 15,685 25,274
-------- -------- -------- --------
Cash and cash equivalents at end of period................ $ 142 $ 21,327 $ 142 $ 21,327
======== ======== ======== ========
The preceding Notes to Financial Statements as they relate to Metropolitan Edison Company are an integral part of these
statements.
125
REPORT OF INDEPENDENT ACCOUNTANTS
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 September 30, 2003, and the related
consolidated statements of income and cash flows for each of the three-month and
nine-month periods ended September 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
November 13, 2003
126
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 third quarter of 2003 increased to $13.7 million
from $7.1 million in the third quarter of 2002. During the first nine months of
2003, net income decreased to $43.6 million from $49.7 million in the first nine
months of 2002. Net income in the first nine months of 2003 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 cumulative effect was $43.4 million in the first
nine months of 2003 compared with $49.7 million in the corresponding period of
2002. The higher earnings in the third quarter of 2003 reflected lower
depreciation and amortization charges and reduced purchased power costs that
were partially offset by lower operating revenues and higher other operating
costs. Comparing the first nine month periods, the effect of higher depreciation
and amortization charges and lower operating revenues, were partially offset by
lower purchased power costs in the first nine months of 2003.
Operating revenues decreased by $19.8 million or 7.0% in the third
quarter of 2003 compared with the same period of 2002 due to decreased
distribution deliveries, as well as reduced sales to the wholesale market.
Retail distribution deliveries decreased by 4.0% and reduced revenues by $6.4
million, as a result of cooler temperatures in the third quarter of 2003
compared to the same period last year. Wholesale revenue decreased by $10.3
million, which reflected lower sales to affiliated companies and to the
wholesale market.
Operating revenues decreased by $36.7 million or 4.8% in the first
nine months of 2003 compared with the first nine months of 2002. Retail
generation kilowatt-hour sales decreased by 2.2%, which consisted of lower
commercial (4.0%) and industrial (10.0%) sales, and higher residential sales
(3.3%) - producing decreased revenues of $9.0 million. Wholesale sales revenues
decreased $25.7 million principally due to a reduction in kilowatt-hour sales to
affiliated companies and to the wholesale market. Distribution deliveries were
nearly flat in the first nine months of 2003 compared with the same period of
2002. Distribution deliveries benefited from higher residential demand (3.2%),
due in large part to colder temperatures in the first quarter of 2003, which
were partially offset by decreases in commercial (1.3%) and industrial (0.3%)
demand from the continued effect of a sluggish, but improving, economy.
Changes in electric generation sales and distribution deliveries in
the third quarter and first nine months of 2003 from the same periods of 2002
are summarized in the following table:
Changes in Kilowatt-Hour Sales Three Months Nine Months
----------------------------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail.................................. 0.6% (2.2)%
Wholesale............................... (100.0)% (100.9)%
----------------------------------------------------------------------
Total Electric Generation Sales........... (7.6)% (11.1)%
======================================================================
Distribution Deliveries:
Residential............................. (8.0)% 3.2%
Commercial.............................. (12.1)% (1.3)%
Industrial.............................. 14.0% (0.3)%
----------------------------------------------------------------------
Total Distribution Deliveries............. (4.0)% 0.7%
----------------------------------------------------------------------
Operating Expenses and Taxes
Total operating expenses and taxes decreased $25.2 million in the
third quarter and $27.9 million in the first nine months of 2003 compared to the
same periods of 2002, primarily due to lower purchased power costs for both
periods. Lower depreciation and amortization charges that were partially offset
by higher other operating costs also contributed to the decrease in operating
expenses in the third quarter of 2003. The lower purchased power costs during
the first nine months of 2003 were partially offset by higher depreciation and
amortization costs, as well as higher other operating costs. The following table
presents changes from the prior year by expense category.
127
Operating Expenses and Taxes - Changes Three Months Nine Months
Increase (Decrease) (In millions)
Purchased power costs........................ $(41.4) $(58.6)
Other operating costs........................ 17.3 22.3
-------------------------------------------------------------------------
Total operation and maintenance expenses.. (24.1) (36.3)
Provision for depreciation and amortization.. (3.5) 15.4
General taxes................................ (0.8) (0.2)
Income taxes................................. 3.2 (6.8)
-------------------------------------------------------------------------
Net decrease in operating expenses and taxes $(25.2) $(27.9)
=========================================================================
Lower purchased power costs in the third quarter and first nine months
of 2003, compared with the same periods of 2002, were primarily attributed to
lower unit costs in the third quarter of 2003 and fewer kilowatt-hours required
for customer needs during the first nine months of 2003. Lower depreciation and
amortization charges in the third quarter of 2003 compared to the same period in
2002, reflected lower depreciation expense on a reduced asset base and lower
amortization of regulatory assets being recovered through the competitive
transition charge (CTC). The increase in depreciation and amortization charges
for the first nine months of 2003 compared to the same period in 2002, reflected
increases in amortization of regulatory assets being recovered through the
competitive transition charge (CTC). Other operating costs increased by $17.3
million in the three months and $22.3 million in the nine months ended September
30, 2003, compared with the same periods of 2002, primarily due to higher
employee benefit costs and costs to restore customer service resulting from
significant storm activity.
Net Interest Charges
Net interest charges decreased by $1.7 million in the third quarter of
2003 and $3.1 million in the first nine months of 2003 from the same periods
last year. The decreases reflect the refinancing of higher rate debt in the
second quarter of 2003 through the issuance of $250 million of new senior notes
in March 2003 and the redemption of $40 million and $20 million of notes in the
first and second quarters of 2003, respectively.
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 September 30, 2003, Met-Ed had $0.1 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 (used for) operating activities during the third
quarter and first nine months of 2003, compared with corresponding periods of
2002 were as follows:
128
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ ------------------
Operating Cash Flows 2003 2002 2003 2002
-----------------------------------------------------------------------
(In millions)
Cash earnings (1)....... $ 41 $ 38 $ 125 $111
Working capital and other (77) (39) (57) (92)
-----------------------------------------------------------------------
Total................... $(36) $ (1) $ 68 $ 19
=======================================================================
(1) Includes net income, depreciation and amortization,
deferred income taxes, investment tax credits and major
noncash charges.
Net cash used for operating activities decreased $35 million in the
third quarter of 2003 compared to the same period in 2002 due to a $38 million
increase in working capital and other requirements (primarily from changes in
accounts payable) which was partially offset by an increase in cash earnings.
Net cash provided from operating activities increased $49 million in the first
nine months of 2003 compared with the same period in 2002. The increase
consisted of a $14 million increase in cash earnings and a $35 million decrease
in working capital and other requirements (primarily due to accounts payable
change).
Cash Flows From Financing Activities
In the third quarter of 2003, net cash provided from financing
activities of $29 million reflected the increase of $36 million of short-term
debt, partially offset by a $7 million dividend payment to FirstEnergy. In the
third quarter of 2002, net cash provided from financing activities totaled $31
million, due to the increase of $61 million of short-term debt, partially offset
by the redemption of $30 million of medium term notes.
As of September 30, 2003, Met-Ed had approximately $10.2 million of
cash and temporary investments, including $10 million of notes receivable from
associated companies and approximately $56.3 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 September 30,
2003, Met-Ed had the capability to issue $152 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 provided from investing activities totaled $8 million in the
third quarter, and net cash used for investing activities totaled $42 in the
first nine months of 2003. The net cash flows provided from investing activities
in the third quarter of 2003 resulted from the repayment of borrowings by
associated companies, partially offset by property additions and decommissioning
trust investments. The net cash flows used for investing activities during the
first nine months of 2003 resulted from property additions, decommissioning
trust investments, and loans to associated companies. Expenditures for property
additions primarily support Met-Ed's energy delivery operations. In the third
quarter and first nine months of 2002, net cash flows used for investing
activities totaled $14 million and $43 million, respectively, principally due to
property additions.
During the fourth quarter of 2003, capital requirements for property
additions are expected to be about $9 million. Met-Ed has no additional
requirements for maturing long-term debt during the remainder of 2003. The
capital requirements are expected to be satisfied from internal cash and
short-term credit arrangements.
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."
On September 30, 2003, Fitch Ratings lowered the senior unsecured
ratings of FirstEnergy to "BBB-" from "BBB." Fitch also lowered the senior
secured, senior unsecured, and preferred stock ratings of Met-Ed. Fitch
announced that the Rating Outlook is Stable for the securities of FirstEnergy,
and all of the securities of its electric utility operating companies. Fitch
stated that the changes to the long-term ratings were "driven by the high debt
leverage of the parent FE. Despite management's commitment to reduce debt
related to the GPU merger, subsequent cash flows have been vulnerable to
unfavorable events, slowing the pace of FE's debt reduction efforts. The Stable
Outlook reflects the success of FE's recent common equity offering and
management's focus on a relatively conservative integrated utility strategy."
129
On October 27, 2003, Standard & Poors (S&P) stated that the `BBB'
corporate credit and the `BBB-` senior unsecured ratings for FirstEnergy's and
its utility subsidiaries remain on CreditWatch with negative implications. The
ratings were placed on CreditWatch on August 18, 2003, and reflect S&P's
concerns regarding the potential impact of August 14, 2003 blackout
investigation on FirstEnergy's deleveraging strategy and its overall efforts to
improve its credit profile.
At that time, S&P also noted other challenges facing FirstEnergy,
including the extended Davis-Besse outage; the recent U.S. District Court ruling
regarding the Sammis Plant; reliability concerns in subsidiary JCP&L's service
territory; and FirstEnergy's credibility with regulators and federal officials.
S&P further noted several factors that could aid FirstEnergy in
resolution of the CreditWatch, including strengthening its balance sheet.
FirstEnergy directly addressed this concern through its recently completed
common equity offering that raised approximately $935 million in net proceeds,
which was used to reduce bank debt. S&P described the equity offering as a
"positive credit development" and also noted the recent renewal of FirstEnergy's
$1 billion revolver facilities as a "favorable development, as it mitigates
liquidity concerns." S&P also indicated that should various ongoing
investigations into the causal factors of the August 14, 2003 blackout establish
that the blackout resulted from no negligence or breach of compliance standards
on FirstEnergy's part, the CreditWatch could be removed and the outlook returned
to negative. S&P deemed a "stable" credit outlook unlikely until issues such as
the restart of Davis-Besse are resolved and the potential effect of the
litigation relating to the Sammis plant (the second trial is scheduled for April
2004) are known. Extension of the Ohio transition plan will be viewed as a
positive development and will support an outlook revision to stable.
In its October 27, 2003, comments, S&P also noted that the ratings on
FirstEnergy and its subsidiaries incorporate such strengths as the ability to
generate free cash flow, power generation contracted to its transmission and
distribution subsidiaries through 2005, and the hedging of its short power
position arising from its PLR obligation in Pennsylvania. S&P said that these
strengths are offset by slower than anticipated reduction of FirstEnergy debt,
remaining volume risks of PLR obligations, the extended outage at Davis-Besse,
the unfavorable outcome of the New Jersey rate proceeding and regulatory
uncertainty in Ohio. S&P also said that it now views FirstEnergy's liquidity
position as average, following FirstEnergy's renewal of its $1 billion credit
facilities.
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 third quarter and the first nine months of 2003 is summarized in the
following table:
Increase (Decrease) in the Fair Value Three Months Ended Nine Months Ended
of Commodity Derivative Contracts September 30, 2003 September 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........... $ 25.9 $ -- $25.9 $17.4 $ 0.1 $17.5
New contract value when entered........................ -- -- -- -- -- --
Additions/Increase in value of existing contracts...... (0.4) -- (0.4) 8.1 -- 8.1
Change in techniques/assumptions....................... 4.6 -- 4.6 4.6 -- 4.6
Settled contracts...................................... -- -- -- -- (0.1) (0.1)
-------------------------------------------------------------- ------------------------- -----------------------------
Net Assets - Derivative Contracts as of September 30, 2003 (1) $ 30.1 $ -- $30.1 $30.1 $ -- $30.1
============================================================== ========================= =============================
Impact of Changes in Commodity Derivative Contracts (2)
Income Statement Effects (Pre-Tax)..................... $ (0.1) $ -- $(0.1) $ -- $ -- $ --
Balance Sheet Effects:
Other Comprehensive Income (Pre-Tax)................ $ -- $ -- $ -- $ -- $(0.1) $(0.1)
Regulatory Liability................................ $ 4.3 $ -- $ 4.3 $12.7 $ -- $12.7
(1) Includes $29.9 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.
130
Derivatives included on the Consolidated Balance Sheet as of
September 30, 2003:
Non-Hedge Hedge Total
-------------------------------------------------------------------
(In millions)
Current-
Other Assets.................. $-- $ -- $ --
Other Liabilities............. -- -- --
Non-Current-
Other Deferred Charges........ 30.1 -- 30.1
Other Deferred Credits........ -- -- --
-------------------------------------------------------------------
Net Assets.................... $30.1 $ -- $30.1
===================================================================
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 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)... $0.6 $4.1 $4.5 $-- $ -- $ 9.2
Prices based on models................ -- -- -- 4.9 16.0 20.9
-----------------------------------------------------------------------------------------------------------
Total(3).......................... $0.6 $4.1 $4.5 $4.9 $16.0 $30.1
===========================================================================================================
(1) For the last quarter of 2003.
(2) Broker quote sheets.
(3) Includes $29.9 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
September 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 $101
million and $81 million as of September 30, 2003 and December 31, 2002,
respectively. A hypothetical 10% decrease in prices quoted by stock exchanges
would result in a $10 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 September
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
131
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 power
contracts with nonaffiliated third party suppliers. This arrangement reduces its
exposure to high wholesale power prices by providing power at a fixed price for
its uncommitted PLR energy costs during the term of the agreement to FES. Met-Ed
is authorized to continue deferring differences between NUG contract costs and
current market prices.
On April 2, 2003, the PPUC remanded the issue relating to merger
savings to the Office of Administrative Law for hearings, directed Met-Ed to
file a position paper on the effect of the Commonwealth Court order on the
Settlement Stipulation and allowed other parties to file responses to the
position paper. Met-Ed filed a letter with the Administrative Law Judge on June
11, 2003, voiding the Stipulation in its entirety and reinstating Met-Ed's
restructuring settlement previously approved by the PPUC.
On October 2, 2003, the PPUC issued an order concluding that the
Commonwealth Court reversed the PPUC's June 20, 2001 order in its entirety. The
PPUC directed Met-Ed to file tariffs within thirty days of the order to reflect
the CTC rates and shopping credits that were in effect prior to the June 21,
2001 order to be effective upon one day's notice. In response to that order,
Met-Ed filed these supplements to their tariffs to become effective October 24,
2003.
On October 8, 2003, Met-Ed filed a petition for clarification relating
to the October 2 order on two issues: to establish the end of June 2004 as the
date to fully refund the NUG trust fund and to clarify that the ordered
accounting treatment regarding the CTC rate/shopping credit swap should follow
the ratemaking, and that the PPUC findings would not impair Met-Ed's rights to
recover all of its stranded costs. On October 9, 2003, ARIPPA (an intervenor in
the proceeding) petitioned the PPUC to direct Met-Ed to reinstate accounting for
the CTC rate/shopping credit swap retroactive to January 1, 2002. Several other
parties also filed petitions. On October 16, 2003, the PPUC issued a
reconsideration order granting the date requested by Met-Ed for the NUG trust
fund refund; and, denying Met-Ed's other clarification request and granting
ARIPPA's petition with respect to the accounting treatment of the changes to the
CTC rate/shopping credit swap. On October 22, 2003, Met-Ed filed an Objection
with the Commonwealth Court asking that the Court reverse the PPUC's finding
that requires Met-Ed to treat the stipulated CTC rates that were in effect from
January 1, 2002 on a retroactive basis. Met-Ed is considering filing an appeal
to the Commonwealth Court on the PPUC orders as well.
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, environmental liabilities that are considered probable have been
recognized on the Consolidated Balance Sheet as of September 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
September 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
132
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 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. In accordance with the
accounting standard, if the fair value of a reporting unit is less than its
carrying value (including goodwill), the goodwill is tested for impairment. If
impairment were indicated, Met-Ed would recognize a loss - calculated as the
difference between the implied fair value of its goodwill and the carrying value
of the goodwill. Met-Ed's annual review was completed in the third quarter of
2003, with no impairment of goodwill indicated. The forecasts used in Met-Ed's
evaluation 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 of September 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 - $1.1 billion as of September
30, 2003. 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
billed through the end of the accounting period. The determination of unbilled
revenues requires management to make various estimates including:
o Net energy generated or purchased for retail load
o Losses of energy over distribution lines
o 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
133
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 is not 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
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". This Interpretation requires the
consolidation of a variable interest entity (VIE) by an enterprise if that
enterprise either absorbs a majority of the VIE's expected losses or receives a
majority of the VIE's expected residual returns as a result of ownership,
contractual or other financial interests in the VIE. Currently, entities are
generally consolidated by an enterprise that has a controlling financial
interest through ownership of a majority voting interest in the entity.
FIN 46 defines a VIE as an entity in which equity investors do not
have the characteristics of a controlling financial interest nor have sufficient
equity at risk for the entity to finance its activities without additional
subordinated financial support. VIE's created after January 31, 2003, are
immediately subject to the provisions of FIN 46. The FASB recently deferred
implementation of FIN 46 for VIE's created before February 1, 2003, until the
first reporting period ending after December 15, 2003 (Met-Ed's quarter ending
December 31, 2003.)
As described in Note 1, the consolidated financial statements of
Met-Ed include a statutory business trust that sold trust-preferred securities
in which Met-Ed is not the primary beneficiary. Pending further guidance from
the FASB that would indicate otherwise, this entity may not be consolidated in
Met-Ed's financial statements as of December 31, 2003. The deconsolidation would
result in an increase in total assets and liabilities of approximately $3.1
million for the investment in the trust.
The FASB continues to provide additional guidance on implementing FIN
46 and recently proposed modifications and clarifications with a comment period
ending December 1, 2003. As this guidance is finalized, Met-Ed will continue to
assess the accounting and disclosure impact of FIN 46 with respect to potential
VIE's.
134
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, that continue to be applied
based on their original effective dates. Adoption of SFAS 149 did not have a
material impact on Met-Ed's financial statements.
SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity"
In May 2003, the FASB issued SFAS 150, which establishes standards for
how an issuer classifies and measures certain financial instruments with
characteristics of both liabilities and equity. In accordance with the standard,
certain financial instruments that embody obligations for the issuer are
required to be classified as liabilities. SFAS 150 was effective immediately for
financial instruments entered into or modified after May 31, 2003 and effective
at the beginning of the first interim period beginning after June 15, 2003
(Met-Ed's third quarter of 2003) for all other financial instruments.
Upon adoption of SFAS 150, effective July 1, 2003, company-obligated
mandatorily redeemable preferred securities of $92.6 million were reclassified
and included in long-term debt as of September 30, 2003. As required by SFAS
150, the preferred securities subject to mandatory redemption were not restated
as long-term debt on the December 31, 2002 balance sheet.
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 Met-Ed'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 of a general index, such as the Consumer Price
Index, in a contract would prevent that contract from qualifying for the normal
purchases and normal sales (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 but does not anticipate any material 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 on Issue No. 01-08,
regarding when arrangements contain a lease. Based on the EITF consensus, an
arrangement contains a lease if (1) it identifies specific property, plant or
equipment (explicitly or implicitly), and (2) the arrangement transfers the
right to the purchaser to control the use of the property, plant or equipment.
The consensus is to be applied prospectively to arrangements committed to,
modified or acquired through a business combination, beginning in the third
quarter of 2003. The adoption of this consensus as of July 1, 2003 did not
impact Met-Ed's financial statements.
135
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2003 2002 2003 2002
(In thousands)
OPERATING REVENUES........................................ $242,960 $269,359 $729,762 $749,755
-------- -------- -------- --------
OPERATING EXPENSES AND TAXES:
Purchased power........................................ 153,440 191,756 467,225 480,608
Other operating costs.................................. 48,168 27,759 125,196 99,977
-------- -------- -------- --------
Total operation and maintenance expenses........... 201,608 219,515 592,421 580,585
Provision for depreciation and amortization............ 10,982 16,098 38,358 45,743
General taxes.......................................... 17,032 17,744 48,630 47,200
Income taxes........................................... 862 3,040 9,316 18,839
-------- -------- -------- --------
Total operating expenses and taxes................. 230,484 256,397 688,725 692,367
-------- -------- -------- --------
OPERATING INCOME.......................................... 12,476 12,962 41,037 57,388
OTHER INCOME.............................................. 545 1,067 887 2,154
-------- -------- -------- --------
INCOME BEFORE NET INTEREST CHARGES........................ 13,021 14,029 41,924 59,542
-------- -------- -------- --------
NET INTEREST CHARGES:
Interest on long-term debt............................. 7,432 7,796 22,123 24,124
Allowance for borrowed funds used during construction.. (77) 84 (257) (199)
Deferred interest...................................... (380) (869) (2,525) (2,311)
Other interest expense................................. 2,071 684 2,333 2,123
Subsidiary's preferred stock dividend requirements..... -- 1,888 3,777 5,665
-------- -------- -------- --------
Net interest charges............................... 9,046 9,583 25,451 29,402
-------- -------- -------- --------
Income before cumulative effect of accounting change...... 3,975 4,446 16,473 30,140
Cumulative effect of accounting change (net of income
taxes of $777,000) (Note 5)............................. -- -- 1,096 --
-------- -------- -------- --------
NET INCOME................................................ $ 3,975 $ 4,446 $ 17,569 $ 30,140
======== ======== ======== ========
The preceding Notes to Financial Statements as they relate to Pennsylvania Electric Company
are an integral part of these statements.
136
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2003 2002
----------- ------------
(In thousands)
ASSETS
------
UTILITY PLANT:
In service................................................................ $1,956,623 $1,844,999
Less--Accumulated provision for depreciation.............................. 773,485 647,581
---------- ----------
1,183,138 1,197,418
Construction work in progress-
Electric plant.......................................................... 24,448 19,200
---------- ----------
1,207,586 1,216,618
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Non-utility generation trusts............................................. 3,840 109,881
Nuclear plant decommissioning trusts...................................... 95,894 88,818
Long-term notes receivable from associated companies...................... 14,905 15,515
Other..................................................................... 15,497 9,425
---------- ----------
130,136 223,639
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents................................................. 84 10,310
Receivables-
Customers (less accumulated provisions of $5,949,000 and $6,153,000
respectively, for uncollectible accounts)............................. 114,009 128,303
Associated companies.................................................... 100,128 45,236
Other................................................................... 17,026 16,184
Prepayments and other..................................................... 12,287 2,551
---------- ----------
243,534 202,584
---------- ----------
DEFERRED CHARGES:
Regulatory assets......................................................... 513,664 599,663
Goodwill.................................................................. 898,086 898,086
Accumulated deferred income tax benefits.................................. 98,694 1,517
Other..................................................................... 22,765 21,147
---------- ----------
1,533,209 1,520,413
---------- ----------
$3,114,465 $3,163,254
========== ==========
137
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 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.................................... (53,881) (69)
Retained earnings....................................................... 24,274 32,705
---------- ----------
Total common stockholder's equity................................... 1,291,461 1,353,704
Company-obligated mandatorily redeemable preferred securities (Note 5).... -- 92,214
Long-term debt and other long-term obligations-
Company-obligated mandatorily redeemable preferred securities (Note 5).. 92,374 --
Other................................................................... 343,821 470,274
---------- ----------
1,727,656 1,916,192
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt.......................................... 125,860 813
Accounts payable-
Associated companies.................................................... 72,537 129,906
Other................................................................... 36,340 29,690
Notes payable to associated companies..................................... 65,720 90,427
Accrued taxes............................................................. 20,537 21,271
Accrued interest.......................................................... 18,259 12,695
Other..................................................................... 21,023 8,409
---------- ----------
360,276 293,211
---------- ----------
DEFERRED CREDITS:
Accumulated deferred investment tax credits............................... 10,183 10,924
Nuclear fuel disposal costs............................................... 18,923 18,771
Power purchase contract loss liability.................................... 690,836 765,063
Asset retirement obligation............................................... 103,569 --
Nuclear plant decommissioning costs....................................... -- 135,450
Retirement benefits....................................................... 177,076 --
Other..................................................................... 25,946 23,643
---------- ----------
1,026,533 953,851
---------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)...........................
---------- ----------
$3,114,465 $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.
138
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2003 2002 2003 2002
-------- -------- -------- --------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................ $ 3,975 $ 4,446 $ 17,569 $ 30,140
Adjustments to reconcile net income to net
cash from operating activities-
Provision for depreciation and amortization........ 10,982 16,098 38,358 45,743
Deferred costs recoverable as regulatory assets.... (4,267) (13,468) (16,146) (41,168)
Deferred income taxes, net......................... 6,356 4,525 (31,153) 3,087
Amortization of investment tax credits............. (247) (285) (741) (856)
Accrued retirement benefit obligations............. 6,867 -- 18,831 --
Accrued compensation, net.......................... (234) (183) 8,618 (1,206)
Cumulative effect of accounting change (Note 5).... -- -- (1,873) --
Receivables........................................ 1,283 9,186 10,075 (466)
Accounts payable................................... (93,818) (16,663) (71,846) (15,570)
Accrued taxes...................................... (327) (3,144) (735) (22,969)
Accrued interest................................... 5,450 6,014 5,564 6,378
Prepayments and other current assets............... (3,923) 14,793 (9,736) 2,096
Other.............................................. (13,005) 1,194 (4,177) 538
-------- -------- -------- --------
Net cash provided from (used for) operating
activities ..................................... (80,908) 22,513 (37,392) 5,747
-------- -------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net........................... 38,150 444 -- 26,309
Redemptions and Repayments-............................
Long-term debt....................................... (165) -- (454) (24,973)
Short-term borrowings, net........................... -- -- (24,708) --
Dividend Payments-
Common stock......................................... (10,000) -- (26,000) (14,000)
-------- -------- -------- --------
Net cash provided from (used for) financing
activities ..................................... 27,985 444 (51,162) (12,664)
-------- -------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions..................................... (10,346) (10,958) (29,123) (33,775)
Proceeds from non-utility generation trusts (Note 4)... -- -- 106,327 34,208
Associated companies loans, net........................ 62,597 -- 610 --
Other.................................................. 390 -- 514 (239)
-------- -------- -------- --------
Net cash provided from (used for) investing
activities ..................................... 52,641 (10,958) 78,328 194
-------- -------- -------- --------
Net increase (decrease) in cash and cash equivalents...... (282) 11,999 (10,226) (6,723)
Cash and cash equivalents at beginning of period.......... 366 20,311 10,310 39,033
-------- -------- -------- --------
Cash and cash equivalents at end of period................ $ 84 $ 32,310 $ 84 $ 32,310
======== ======== ======== ========
The preceding Notes to Financial Statements as they relate to Pennsylvania Electric Company are an
integral part of these statements.
139
REPORT OF INDEPENDENT ACCOUNTANTS
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 September 30, 2003, and the related
consolidated statements of income and cash flows for each of the three-month and
nine-month periods ended September 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
November 13, 2003
140
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 third quarter of 2003 decreased to $4.0 million from
$4.4 million in the third quarter of 2002. Lower operating revenues and higher
other operating costs were partially offset by reduced purchase power costs as
compared to the third quarter of 2002. During the first nine months of 2003, net
income decreased to $17.6 million compared to $30.1 million in the first nine
months of 2002. Net income in the first nine months 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 $16.5 million in the first
nine months of 2003 compared with $30.1 million for the corresponding period of
2002. In the first nine months of 2003, higher operating costs and lower
operating revenues were partially offset by reduced purchase power costs.
Electric Sales
Operating revenues decreased by $26.4 million, or 9.8% in the third
quarter of 2003 compared with the same period of 2002, primarily due to lower
wholesale, residential and commercial kilowatt-hour sales, partially offset by
increased industrial kilowatt-hour sales. Wholesale sales revenues decreased by
$9.6 million in the third quarter of 2003, which were primarily attributable to
lower sales to non-affiliated companies. Retail generation kilowatt-hour sales
decreased 5.0% ($9.4 million decrease in revenue) as a result of a 14.5%
decrease in residential sales and a 13.2% decrease in commercial sales offset in
part by higher industrial sales (31.9%). The significant decrease in residential
and commercial sales were primarily due to milder weather in the third quarter
of 2003 compared to 2002 and a sluggish, but improving economy. These factors
also contributed to the decrease in distribution deliveries of 3.4% in the third
quarter of 2003 from the same quarter of 2002, decreasing revenues from
electricity throughput by $8.1 million. Operating revenues decreased $20.0
million or 2.7% in the first nine months of 2003 compared to the same period in
2002, reflecting a wholesale sales revenue decrease of $14.8 million, primarily
due to lower affiliated company sales. Generation retail kilowatt-hour sales
were also lower by 1.6% with a corresponding decrease in revenues of $7.9
million. Lower kilowatt-hour sales to industrial customers were partially offset
by higher demand from residential and commercial customers.
Changes in electric generation sales and distribution deliveries in
the third quarter and the first nine months of 2003 from the corresponding
periods of 2002 are summarized in the following table:
Changes in Kilowatt-Hour Sales Three Months Nine Months
-------------------------------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail................................ (5.0)% (1.6)%
Wholesale............................. (99.9)% (99.5)%
-------------------------------------------------------------------------
Total Electric Generation Sales......... (10.7)% (6.4)%
=======================================================================
Distribution Deliveries:
Residential........................... (14.6)% 1.5%
Commercial............................ (13.1)% 1.0%
Industrial............................ 28.1% 2.9%
-------------------------------------------------------------------------
Total Distribution Deliveries........... (3.4)% 1.8%
=======================================================================
Operating Expenses and Taxes
Total operating expenses and taxes decreased $25.9 million or 10.1% in
the third quarter of 2003 and decreased $3.6 million or 0.5% in the first nine
months of 2003 from the same periods of 2002. The following table presents
changes from the prior year by expense category.
141
Operating Expenses and Taxes - Changes Three Months Nine Months
Increase (Decrease) (In millions)
Purchased power costs............................ $(38.3) $(13.4)
Other operating costs............................ 20.4 25.2
-------------------------------------------------------------------------------
Total operation and maintenance expenses....... (17.9) 11.8
Provision for depreciation and amortization...... (5.1) (7.3)
General taxes.................................... (0.7) 1.4
Income taxes..................................... (2.2) (9.5)
-------------------------------------------------------------------------------
Total decrease in operating expenses and taxes. $(25.9) $ (3.6)
===============================================================================
Reduced purchased power costs in the third quarter of 2003, compared
with the same quarter of 2002, were due to lower required kilowatt-hour
purchases driven by lower generation sales. In the first nine months, purchased
power costs were lower principally due to fewer kilowatt-hour purchases,
partially offset by higher average unit costs. The increase in other operating
costs in the third quarter and first nine months of 2003 compared to the same
periods of 2002 was primarily due to higher employee benefit costs and costs to
restore customer service resulting from significant storm activity.
Net Interest Charges
Net interest charges decreased by $0.5 million in the third quarter of
2003 and $4.0 million in the first nine months of 2003 compared with 2002,
reflecting debt redemptions since the beginning of the third 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 September 30, 2003, Penelec had $0.1 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
third quarter and first nine months of 2003 compared with the corresponding
periods of 2002 were as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
Operating Cash Flows 2003 2002 2003 2002
------------------------------------------------------------------------
(In millions)
Cash earnings (1)............ $ 23 $11 $ 34 $ 36
Working capital and other.... (104) 12 (71) (30)
-----------------------------------------------------------------------
Total........................ $ (81) $23 $(37) $ 6
======================================================================
(1) Includes net income, depreciation and amortization,
deferred income taxes, investment tax credits and major
noncash charges.
142
Net cash used for operating activities decreased $104 million in the
third quarter of 2003 compared to the same period of 2002, due to a $116 million
increase in working capital and other requirements (primarily from changes in
accounts payable). Net cash used for operating activities decreased $43 million
in the first nine months of 2003 compared to the same period of 2002. This
decrease resulted from a $41 million increase in working capital and other
requirements primarily attributable to a $56 million change in accounts payable.
Cash Flows From Financing Activities
In the third quarter of 2003, the increase in net cash provided from
financing activities of $28 million as compared to $0.4 million in the same
period of 2002 resulted from an increase in net short-term borrowings.
As of September 30, 2003, Penelec had about $0.1 million of cash and
temporary cash investments and approximately $65.7 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
September 30, 2003, Penelec had the capability to issue $15 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 provided from investing activities totaled $53 million in the
third quarter of 2003 compared to a use of $11 million in the third quarter of
2002. Net cash provided from investing activities was $78 million in the first
nine months of 2003, compared with $0.2 million in the same period of 2002. The
net cash in 2003 provided from investing activities resulted from proceeds from
loans to associated companies in the third quarter and proceeds from nonutility
generation (NUG) trusts in the first nine months, slightly offset by
expenditures for property additions in both periods. Refunds to the NUG trusts
are expected to be made in 2004 (see Regulatory Matters). Expenditures for
property additions primarily support Penelec's energy delivery operations.
During the last quarter of 2003, capital requirements for property
additions are expected to be about $10 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 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."
On September 30, 2003, Fitch Ratings lowered the senior unsecured
ratings of FirstEnergy to "BBB-" from "BBB." Fitch also lowered the senior
secured, senior unsecured, and preferred stock ratings of Met-Ed, Penelec, CEI,
and TE. In addition, Fitch affirmed the ratings of OE, Penn and JCP&L. Fitch
announced that the Rating Outlook is Stable for the securities of FirstEnergy,
and all of the securities of its electric utility operating companies. Fitch
stated that the changes to the long-term ratings were "driven by the high debt
leverage of the parent FE. Despite management's commitment to reduce debt
related to the GPU merger, subsequent cash flows have been vulnerable to
unfavorable events, slowing the pace of FE's debt reduction efforts. The Stable
Outlook reflects the success of FE's recent common equity offering and
management's focus on a relatively conservative integrated utility strategy."
On October 27, 2003, Standard & Poors (S&P) stated that the `BBB'
corporate credit and the `BBB-` senior unsecured ratings for FirstEnergy and its
utility subsidiaries remain on CreditWatch with negative implications. The
ratings were placed on CreditWatch on August 18, 2003, and reflect S&P's
concerns regarding the potential impact of the August 14, 2003 blackout
investigation on FirstEnergy's deleveraging strategy and its overall efforts to
improve its credit profile.
At that time, S&P also noted other challenges facing FirstEnergy,
including the extended Davis-Besse outage; the recent U.S. District Court ruling
regarding the Sammis Plant; reliability concerns in subsidiary JCP&L's service
territory; and FirstEnergy's credibility with regulators and federal officials.
S&P further noted several factors that could aid FirstEnergy in
resolution of the CreditWatch, including strengthening its balance sheet.
FirstEnergy directly addressed this concern through its recently completed
common equity offering that raised approximately $935 million in net proceeds,
which was used to reduce bank debt. S&P described the equity offering as a
"positive credit development" and also noted the recent renewal of FirstEnergy's
143
$1 billion revolver facilities as a "favorable development, as it mitigates
liquidity concerns." S&P also indicated that should various ongoing
investigations into the causal factors of the August 14, 2003 blackout establish
that the blackout resulted from no negligence or breach of compliance standards
on FirstEnergy's part, the CreditWatch could be removed and the outlook returned
to negative. S&P deemed a "stable" credit outlook unlikely until issues such as
the restart of Davis-Besse are resolved and the potential effect of the
litigation relating to the Sammis plant (the second trial is scheduled for April
2004) are known. Extension of the Ohio transition plan will be viewed as a
positive development and will support an outlook revision to stable.
On October 27, 2003, S&P also noted that the ratings on FirstEnergy
and its subsidiaries incorporate such strengths as the ability to generate free
cash flow, power generation contracted to its transmission and distribution
subsidiaries through 2005, and the hedging of its short power position arising
from its PLR obligation in Pennsylvania. S&P said that these strengths are
offset by slower than anticipated reduction of FirstEnergy debt, remaining
volume risks of PLR obligations, the extended outage at Davis-Besse, the
unfavorable outcome of the New Jersey rate proceeding, and regulatory
uncertainty in Ohio. S&P also said that it now views FirstEnergy's liquidity
position as average, following FirstEnergy's renewal of its $1 billion credit
facilities.
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 third quarter and first nine months of 2003 is summarized in the
following table:
Increase (Decrease) in the Fair Value Three Months Ended Nine Months Ended
of Commodity Derivative Contracts September 30, 2003 September 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....................... $12.9 $ -- $12.9 $ 8.7 $ 0.1 $ 8.8
New contract value when entered........................ -- -- -- -- -- --
Additions/Increase in value of existing contracts...... (0.1) -- (0.1) 4.1 -- 4.1
Change in techniques/assumptions....................... 2.3 -- 2.3 2.3 -- 2.3
Settled contracts...................................... -- -- -- -- (0.1) (0.1)
-------------------------------------------------------- ------------------------- -----------------------------
Net Assets - Derivative Contracts at end of period (1). $15.1 $ -- $15.1 $15.1 $ -- $15.1
======================================================== ========================= =============================
Impact of Changes in Commodity Derivative Contracts (2)
Income Statement Effects (Pre-Tax)..................... $ 0.2 $ -- $ 0.2 $ 0.4 $ -- $ 0.4
Balance Sheet Effects:
Other Comprehensive Income (Pre-Tax)................ $ -- $ -- $ -- $ -- $(0.1) $(0.1)
Regulatory Liability................................ $ 2.0 $ -- $ 2.0 $ 6.0 $ -- $ 6.0
(1) Includes $14.2 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 September 30, 2003:
Non-Hedge Hedge Total
--------- ----- -----
(In millions)
Current-
Other Assets............................ $ -- $ -- $ --
Other Liabilities....................... -- -- --
Non-Current-
Other Deferred Charges.................. 15.1 -- 15.1
Other Deferred Credits.................. -- -- --
----------------------------------------------------------------------------
Net Assets.............................. $15.1 $ -- $15.1
============================================================================
144
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 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 $2.1 $2.3 $-- $-- $ 4.7
Prices based on models -- -- -- 2.4 8.0 10.4
---------------------------------------------------------------------------------------------------------
Total3 $0.3 $2.1 $2.3 $2.4 $8.0 $15.1
=========================================================================================================
(1) For the last quarter of 2003. (2) Broker quote sheets.
(3) Includes $14.2 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
September 30, 2003.
Equity Price Risk
Included in Penelec's nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $48
million and $42 million as of September 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 September 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 $514 million and $600 million as of
September 30, 2003 and December 31, 2002, respectively.
Regulatory Matters
Effective September 1, 2002, Penelec assigned its provider of last
resort (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 Penelec does not self-supply under its NUG contracts and other power
contracts with nonaffiliated third party suppliers. This arrangement reduces its
exposure to high wholesale power prices by providing power at a fixed price for
its uncommitted PLR energy costs during the term of the agreement to FES.
Penelec is authorized to continue deferring differences between NUG contract
costs and current market prices.
On April 2, 2003, the PPUC remanded the issue relating to merger
savings to the Office of Administrative Law for hearings, directed Met-Ed and
Penelec to file a position paper on the effect of the Commonwealth Court order
on the Settlement Stipulation and allowed other parties to file responses to the
position paper. Met-Ed and Penelec filed a letter with the Administrative Law
Judge on June 11, 2003, voiding the Stipulation in its entirety and reinstating
Met-Ed's and Penelec's restructuring settlement previously approved by the PPUC.
145
On October 2, 2003, the PPUC issued an order concluding that the
Commonwealth Court reversed the PPUC's June 20, 2001 order in its entirety. The
PPUC directed Met-Ed and Penelec to file tariffs within thirty days of the order
to reflect the CTC rates and shopping credits that were in effect prior to the
June 21, 2001 order to be effective upon one day's notice. In response to that
order, Met-Ed and Penelec filed these supplements to their tariffs to become
effective October 24, 2003.
On October 8, 2003, Met-Ed and Penelec filed a petition for
clarification relating to the October 2 order on two issues: to establish the
end of June 2004 as the date to fully refund the NUG trust fund and to clarify
that the ordered accounting treatment regarding the CTC rate/shopping credit
swap should follow the ratemaking, and that the PPUC findings would not impair
Penelec's rights to recover all of its stranded costs. On October 9, 2003,
ARIPPA (an intervenor in the proceedings) petitioned the PPUC to direct Met-Ed
and Penelec to reinstate accounting for the CTC rate/shopping credit swap
retroactive to January 1, 2002. Several other parties also filed petitions. On
October 16, 2003, the PPUC issued a reconsideration order granting the date
requested by Met-Ed and Penelec for the NUG trust fund refunds; and, denying
Met-Ed's and Penelec's other clarification requests and granting ARIPPA's
petition with respect to the accounting treatment of the changes to the CTC
rate/shopping credit swap. On October 22, 2003, Met-Ed and Penelec filed an
Objection with the Commonwealth Court asking that the Court reverse the PPUC's
finding that requires Met-Ed and Penelec to treat the stipulated CTC rates that
were in effect from January 1, 2002 on a retroactive basis. Met-Ed and Penelec
are considering filing an appeal to the Commonwealth Court on the PPUC orders as
well.
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, environmental liabilities that are considered probable have been
recognized on the Consolidated Balance Sheet as of September 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 September 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
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. In accordance with the
accounting standard, if the fair value of a reporting unit is less than its
carrying value (including goodwill), the goodwill is tested for impairment. If
impairment were indicated, Penelec would recognize a loss - calculated as the
difference between the implied fair value of its goodwill and the carrying value
of the goodwill. Penelec's annual review was completed in the third quarter of
2003, with no impairment of goodwill indicated. The forecasts used in its
evaluation of goodwill reflect operations consistent with its general business
assumptions. Unanticipated changes in those assumptions could have a significant
effect on Penelec's future evaluation of goodwill. As of September 30, 2003,
Penelec had recorded goodwill of approximately $898.1 million related to the
merger.
146
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 - $514 million as of September
30, 2003. 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:
o Net energy generated or purchased for retail load
o Losses of energy over distribution lines
o 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
147
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 is not 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
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". This Interpretation requires the
consolidation of a variable interest entity (VIE) by an enterprise if that
enterprise either absorbs a majority of the VIE's expected losses or receives a
majority of the VIE's expected residual returns as a result of ownership,
contractual or other financial interests in the VIE. Currently, entities are
generally consolidated by an enterprise that has a controlling financial
interest through ownership of a majority voting interest in the entity.
FIN 46 defines a VIE as an entity in which equity investors do not
have the characteristics of a controlling financial interest nor have sufficient
equity at risk for the entity to finance its activities without additional
subordinated financial support. VIE's created after January 31, 2003, are
immediately subject to the provisions of FIN 46. The FASB recently deferred
implementation of FIN 46 for VIE's created before February 1, 2003, until the
first reporting period ending after December 15, 2003 (Penelec's quarter ending
December 31, 2003.)
As described in Note 1, the consolidated financial statements of
Penelec include a statutory business trust that sold trust-preferred securities
in which Penelec is not the primary beneficiary. Pending further guidance from
the FASB that would indicate otherwise, this entity may not be consolidated in
Penelec's financial statements as of December 31, 2003. The deconsolidation
would result in an increase in total assets and liabilities of approximately
$3.1 million for the investment in the trust.
The FASB continues to provide additional guidance on implementing FIN
46 and recently proposed modifications and clarifications with a comment period
ending December 1, 2003. As this guidance is finalized, Penelec will continue to
assess the accounting and disclosure impact of FIN 46 with respect to potential
VIE's.
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, that continue to be
applied based on their original effect dates. Adoption of SFAS 149 did not have
a material impact on Penelec's financial statements.
SFAS 150, "Accounting for Certain Financial Instruments
with Characteristics of both Liabilities and Equity"
In May 2003, the FASB issued SFAS 150, which establishes standards for
how an issuer classifies and measures certain financial instruments with
characteristics of both liabilities and equity. In accordance with the standard,
148
certain financial instruments that embody obligations for the issuer are
required to be classified as liabilities. SFAS 150 was effective immediately for
financial instruments entered into or modified after May 31, 2003 and effective
at the beginning of the first interim period beginning after June 15, 2003
(Penelec's third quarter of 2003) for all other financial instruments.
Upon adoption of SFAS 150, effective July 1, 2003, company-obligated
mandatorily redeemable preferred securities of $92.4 million were reclassified
and included in long-term debt as of September 30, 2003. As required by SFAS
150, the preferred securities subject to mandatory redemption were not restated
as long-term debt on the December 31, 2002 balance sheet.
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
Penelec'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 of a general index, such as the Consumer Price
Index, in a contract would prevent that contract from qualifying for the normal
purchases and normal sales (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 but does not anticipate any material 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 on Issue No. 01-08,
regarding when arrangements contain a lease. Based on the EITF consensus, an
arrangement contains a lease if (1) it identifies specific property, plant or
equipment (explicitly or implicitly), and (2) the arrangement transfers the
right to the purchaser to control the use of the property, plant or equipment.
The consensus is to be applied prospectively to arrangements committed to,
modified or acquired through a business combination, beginning in the third
quarter of 2003. The adoption of this consensus as of July 1, 2003 did not
impact Penelec's financial statements.
149
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See "Management's Discussion and Analysis of Results of Operation and
Financial Condition - Market Risk Information" in Item 2 above.
ITEM 4. 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-15(e) and 15d-15(e), as of the end of the date covered by this report. 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 material information relating to the registrant and its
consolidated subsidiaries by others within those entities.
(b) CHANGES IN INTERNAL CONTROLS
During the quarter ended September 30, 2003, there were no changes in
the registrants' internal control over financial reporting that have materially
affected, or are reasonably likely to materially affect, the registrants'
internal control over financial reporting.
150
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
Exhibit
Number
-------
Met-Ed
------
12 Fixed charge ratios
31.1 Certification of chief executive officer, as adopted
pursuant to Rule 13a-15(e)/15d-(e).
31.2 Certification of chief financial officer, as adopted
pursuant to Rule 13a-15(e)/15d-(e).
32.1 Certification of chief executive officer and chief financial
officer, pursuant to 18 U.S.C. Section 1350.
Penelec
-------
12 Fixed charge ratios
15 Letter from independent auditors
31.1 Certification of chief executive officer, as adopted
pursuant to Rule 13a-15(e)/15d-(e).
31.2 Certification of chief financial officer, as adopted
pursuant to Rule 13a-15(e)/15d-(e).
32.1 Certification of chief executive officer and chief financial
officer, pursuant to 18 U.S.C. Section 1350.
JCP&L
-----
12 Fixed charge ratios
15 Letter from independent auditors
31.2 Certification of chief financial officer, as adopted
pursuant to Rule 13a-15(e)/15d-(e).
31.3 Certification of chief executive officer, as adopted
pursuant to Rule 13a-15(e)/15d-(e).
32.2 Certification of chief executive officer and chief
financial officer, pursuant to 18 U.S.C. Section 1350.
FirstEnergy, OE and Penn
------------------------
15 Letter from independent public auditors
31.1 Certification of chief executive officer, as adopted
pursuant to Rule 13a-15(e)/15d-(e).
31.2 Certification of chief financial officer, as adopted
pursuant to Rule 13a-15(e)/15d-(e).
32.1 Certification of chief executive officer and chief
financial officer, pursuant to 18 U.S.C. Section 1350.
CEI and TE
----------
31.1 Certification of chief executive officer, as adopted
pursuant to Rule 13a-15(e)/15d-(e).
31.2 Certification of chief financial officer, as adopted
pursuant to Rule 13a-15(e)/15d-(e).
32.1 Certification of chief executive officer and chief
financial officer, pursuant to 18 U.S.C. Section 1350.
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 thirteen reports on Form 8-K since June 30, 2003. 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
151
with respect to the W. H. Sammis Plant under the Clean Air Act. A report dated
August 28, 2003 reported FirstEnergy's cash and liquidity position. A report
dated September 8, 2003 reported the announcement of a public offering of
additional common stock and a Regulation G reconciliation of a non-GAAP
financial measure, free cash flow, presented in connection with the offering. A
report dated September 12, 2003 reported that FirstEnergy, OE, CEI and TE had
received an informal data request from the Securities and Exchange Commission to
provide information related to their recent financial statement restatements. A
report dated September 24, 2003 reported an underwriting agreement related to
its public offering of additional common stock. A report dated October 21, 2003
reported the filing of a proposed rate stabilization plan with the PUCO. A
report dated October 23, 2003, reported FirstEnergy's third quarter 2003 results
and other information. A report dated November 13, 2003 reported the
announcement of a settlement agreement of FirstEnergy's claim against NRG Energy
for the cancellation of a generating plants sale.
OE
--
OE filed four reports on Form 8-K since June 30, 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. A
report dated September 12, 2003 reported that FirstEnergy, OE, CEI and TE had
received an informal data request from the Securities and Exchange Commission to
provide information related to their recent financial statement restatements. A
report dated October 21, 2003 reported the filing of a proposed rate
stabilization plan with the PUCO.
Penn
----
None
CEI
---
CEI filed six reports on Form 8-K since June 30, 2003. 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. A
report dated September 12, 2003 reported that FirstEnergy, OE, CEI and TE had
received an informal data request from the Securities and Exchange Commission to
provide information related to their recent financial statement restatements. A
report dated October 21, 2003 reported the filing of a proposed rate
stabilization plan with the PUCO. A report dated November 13, 2003 reported the
announcement of a settlement agreement of FirstEnergy's claim against NRG Energy
for the cancellation of a generating plants sale.
TE
--
TE filed six reports on Form 8-K since June 30, 2003. 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. A
report dated September 12, 2003 reported that FirstEnergy, OE, CEI and TE had
received an informal data request from the Securities and Exchange Commission to
provide information related to their recent financial statement restatements. A
report dated October 21, 2003 reported the filing of a proposed rate
stabilization plan with the PUCO. A report dated November 13, 2003 reported the
announcement of a settlement agreement of FirstEnergy's claim against NRG Energy
for the cancellation of a generating plants sale.
Met-Ed and Penelec
------------------
None
JCP&L
-----
JCP&L filed one report on Form 8-K since June 30, 2003. A report dated
July 25, 2003 reported the New Jersey Board of Public Utilities decision on
JCP&L's rate proceedings.
152
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.
November 14, 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
153