JERSEY CENTRAL POWER & LIGHT COMPANY
2003 ANNUAL REPORT TO STOCKHOLDERS
Jersey Central Power & Light Company is a wholly owned electric
utility operating subsidiary of FirstEnergy Corp. It engages in the distribution
and sale of electric energy in an area of approximately 3,300 square miles in
New Jersey. It also engages in the sale, purchase and interchange of electric
energy with other electric companies. The area it serves has a population of
approximately 2.7 million.
In August 2000, FirstEnergy entered into an agreement to merge with
GPU, Inc., under which FirstEnergy would acquire all of the outstanding shares
of GPU, Inc.'s common stock for approximately $4.5 billion in cash and
FirstEnergy common stock. The merger became effective on November 7, 2001 and
was accounted for by the purchase method. Prior to that time, Jersey Central
Power & Light Company was a wholly owned subsidiary of GPU, Inc.
Contents Page
- -------- ----
Selected Financial Data............................................ 1
Management's Discussion and Analysis............................... 2-12
Consolidated Statements of Income.................................. 13
Consolidated Balance Sheets........................................ 14
Consolidated Statements of Capitalization.......................... 15
Consolidated Statements of Common Stockholder's Equity............. 16
Consolidated Statements of Preferred Stock......................... 16
Consolidated Statements of Cash Flows.............................. 17
Consolidated Statements of Taxes................................... 18
Notes to Consolidated Financial Statements......................... 19-33
Reports of Independent Auditors.................................... 34-35
JERSEY CENTRAL POWER & LIGHT COMPANY
SELECTED FINANCIAL DATA
Nov. 7 - Jan. 1 -
2003 2002 Dec. 31, 2001 Nov. 6, 2001 2000 1999
- ----------------------------------------------------------------------------------------------------------------------
(Dollars in thousands)
Operating Revenues...................... $2,364,203 $2,328,415 $ 282,902 | $1,838,638 $1,979,297 $2,018,209
========== ========== ========== | ========== ========== ==========
|
Operating Income........................ $ 146,271 $ 335,209 $ 43,666 | $ 292,847 $ 283,227 $ 277,420
========== ========== ============ | ========== ========== ==========
|
Net Income ............................. $ 68,017 $ 251,895 $ 30,041 | $ 34,467 $ 210,812 $ 172,380
========== ========== ========== | ========== ========== ==========
|
Earnings on Common Stock................ $ 68,129 $ 253,359 $ 29,343 | $ 29,920 $ 203,908 $ 162,862
========== ========== ========== | ========== ========== ==========
|
Total Assets............................ $7,579,044 $8,052,755 $8,039,998 | $6,009,054 $5,587,677
========== ========== ========== | ========== ==========
|
|
Capitalization as of December 31: |
Common Stockholder's Equity.......... $3,153,974 $3,274,069 $3,163,701 | $1,459,260 $1,385,367
Preferred Stock- |
Not Subject to Mandatory Redemption 12,649 12,649 12,649 | 12,649 12,649
Subject to Mandatory Redemption.... -- -- 44,868 | 51,500 73,167
Company-Obligated Mandatorily |
Redeemable Preferred Securities.... -- 125,244 125,250 | 125,000 125,000
Long-Term Debt....................... 1,095,991 1,210,446 1,224,001 | 1,093,987 1,133,760
---------- ---------- ---------- | ---------- ----------
Total Capitalization............... $4,262,614 $4,622,408 $4,570,469 | $2,742,396 $2,729,943
========== ========== ========== | ========== ==========
|
|
Capitalization Ratios: |
Common Stockholder's Equity.......... 74.0% 70.8% 69.2% | 53.2% 50.7%
Preferred Stock- |
Not Subject to Mandatory Redemption 0.3 0.3 0.3 | 0.5 0.5
Subject to Mandatory Redemption.... -- -- 1.0 | 1.9 2.7
Company-Obligated Mandatorily |
Redeemable Preferred Securities.... -- 2.7 2.7 | 4.5 4.6
Long-Term Debt....................... 25.7 26.2 26.8 | 39.9 41.5
----- ----- ----- | ----- -----
Total Capitalization............... 100.0% 100.0% 100.0% | 100.0% 100.0%
===== ===== ===== | ===== =====
|
|
Distribution Kilowatt-Hour Deliveries (Millions): |
Residential.......................... 9,104 8,976 1,428 | 7,042 8,087 7,978
Commercial........................... 8,620 8,509 1,330 | 6,787 7,706 7,624
Industrial........................... 3,046 3,171 474 | 2,670 3,307 3,289
Other................................ 89 81 17 | 66 82 81
------ ------ ------- | ------ ------ ------
Total Retail......................... 20,859 20,737 3,249 | 16,565 19,182 18,972
Total Wholesale...................... 6,203 5,039 295 | 1,780 2,161 1,622
------ ------ ------- | ------ ------ ------
Total................................ 27,062 25,776 3,544 | 18,345 21,343 20,594
====== ====== ======= | ====== ====== ======
|
|
Customers Served: |
Residential.......................... 931,227 921,716 909,494 | 896,629 883,930
Commercial........................... 114,270 112,385 109,985 | 107,479 107,210
Industrial........................... 2,705 2,759 2,785 | 2,835 2,965
Other................................ 1,345 1,393 1,484 | 1,551 1,648
--------- --------- --------- | --------- -------
Total................................ 1,049,547 1,038,253 1,023,748 | 1,008,494 995,753
========= ========= ========= | ========= =======
1
JERSEY CENTRAL POWER & LIGHT COMPANY
Management's Discussion and Analysis of
Results of Operations and Financial Condition
This discussion includes forward-looking statements based on
information currently available to management. Such statements are subject to
certain risks and uncertainties. These statements typically contain, but are not
limited to, the terms "anticipate," "potential," "expect," "believe," "estimate"
and similar words. Actual results may differ materially due to the speed and
nature of increased competition and deregulation in the electric utility
industry, economic or weather conditions affecting future sales and margins,
changes in markets for energy services, changing energy and commodity market
prices, replacement power costs being higher than anticipated or inadequately
hedged, maintenance costs being higher than anticipated, legislative and
regulatory changes (including revised environmental requirements), adverse
regulatory or legal decisions and the outcome of governmental investigations,
availability and cost of capital, the inability to accomplish or realize
anticipated benefits from strategic goals, the ability to improve electric
commodity margins and to experience growth in the distribution business, the
ability to access the public securities market, further investigation into the
causes of the August 14, 2003, regional power outage and the outcome, cost and
other effects of present and potential legal and administrative proceedings and
claims related to the outage and other similar factors.
Results of Operations
In 2003, earnings on common stock decreased to $68.1 million, from
$253.4 million in 2002, as a result of non-cash charges aggregating $185.2
million ($109.3 million after tax) due to a rate case decision disallowing
recovery of certain regulatory assets (see Regulatory Matters). In addition,
higher operating revenues were more than offset by increases in purchased power
and other operating costs causing a decline in earnings. In 2002, earnings on
common stock increased to $253.4 million, from $59.3 million in 2001, due to
higher operating revenues and the absence of a 2001 after-tax charge of $177.5
million, which reduced deferred costs in accordance with the Stipulation of
Settlement related to the merger of FirstEnergy and GPU, Inc. Partially
offsetting these favorable results were increased purchased power costs.
Electric Sales
Operating revenues increased $35.8 million or 1.5% in 2003 compared
with 2002. The increase in revenues was due to a $99.7 million increase in
wholesale revenues offset by lower revenues from our distribution deliveries.
Our basic generation service (BGS) obligation was transferred to external
parties through a February 2002 auction process authorized by the New Jersey
Board of Public Utilities (NJBPU) which terminated our BGS obligation for the
twelve-month period, August 1, 2002 through July 31, 2003. Subsequent BGS
auctions in February 2003 and 2004 continued this transfer and extended the
termination of the Company's BGS obligations through July 31, 2005. As result,
we have been selling all of our self-supplied energy (from non-utility
generation power contracts and owned generation) into the wholesale market and
anticipate continuing to do so through July 31, 2005.
Distribution deliveries increased slightly in 2003 from the previous
year. Lower unit prices in 2003 more than offset the impact of the increased
volume and reduced revenues by $64.1 million. In addition, revenues reflect the
impact of the distribution rate decrease effective August 1, 2003, from the
NJBPU's decision (see Regulatory Matters). 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.
Generation sales revenues in 2003 compared to 2002 were lower by
$23.9 million due to an 8.7% decrease in kilowatt-hour sales. The decrease
reflected a 9.1 percentage point increase in customers choosing an alternate
supplier in 2003 compared to 2002. This reversed the trend in 2002 where some
customers who were receiving their power from alternate suppliers returned to us
as full service customers. During 2002, only 0.7% of kilowatt-hours delivered
were to shopping customers, whereas that percentage was 4.5% in 2001. In
addition to the higher revenues from returning shopping customers, warmer summer
weather in both 2002 and 2001 contributed to significant increases in retail
sales. This was partially offset by a decrease in kilowatt-hour sales to
industrial customers, due to a decline in economic conditions during 2002.
Increases in kilowatt-hour sales to wholesale customers during 2002 were
partially offset by lower average prices for energy in 2002, compared to 2001.
2
Changes in kilowatt-hour sales by customer class in 2003 and 2002 are
summarized in the following table:
Changes in Kilowatt-hour Sales 2003 2002
--------------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail............................ (8.7)% 8.5%
Wholesale......................... 23.1 % 42.8%
--------------------------------------------------------
Total Electric Generation Sales..... (2.4)% 16.9%
========================================================
Distribution Deliveries:
Residential....................... 1.4 % 6.0%
Commercial........................ 1.3 % 4.9%
Industrial........................ (3.9)% 0.9%
--------------------------------------------------------
Total Distribution Deliveries....... 0.6 % 4.7%
========================================================
Operating Expenses and Taxes
Total operating expenses and taxes increased $224.7 million in 2003,
after increasing $208.2 million in 2002, compared to the prior year. These
increases include the non-cash charges in 2003 for amounts disallowed by the
NJBPU in its rate case decision (see Regulatory Matters), of which $152.5
million was charged to purchased power and $32.7 million was charged to
depreciation and amortization. The following table presents changes in 2003 and
2002 from the prior year by expense category.
Operating Expenses and Taxes - Changes 2003 2002
-----------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel and purchased power costs............ $256.5 $179.6
Other operating costs..................... 95.2 (5.3)
-----------------------------------------------------------------
Total operation and maintenance expenses.. 351.7 174.3
Provision for depreciation and amortization 5.3 3.7
General taxes............................. (2.6) (9.4)
Income taxes............................. (129.7) 39.6
----------------------------------------------------------------
Net increase in operating expenses and taxes $224.7 $208.2
================================================================
Excluding the disallowed deferred energy costs of $152.5 million,
fuel and purchased power increased $104.0 million in 2003 compared to 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 $95.2 million in 2003 compared to
2002, due to higher employee benefit costs, storm restoration expenses and costs
associated with an accelerated reliability plan within the Company's service
territory.
Depreciation and amortization charges, excluding the disallowed costs
discussed above, decreased $27.4 million due to the cessation of amortization of
regulatory assets related to the previously divested Oyster Creek Nuclear
Generation Station and the reduced depreciation rates effective August 1, 2003
in connection with the NJBPU rate case decision (see Regulatory Matters).
In 2002, fuel and purchased power costs increased $179.6 million,
compared to 2001. The increase was due primarily to more power being purchased
through two-party agreements and from associated companies during 2002. The
increase was partially offset by a decrease in power purchased through the PJM
Power Pool, and the absence of non-utility generation contract buyout costs
recognized in 2001.
Other Income
Other income was unchanged in 2003 and increased $183.3 million in
2002, compared to the prior year. The change in 2002 was due primarily to a 2001
charge of $300 million ($177.5 million net of tax) to reduce deferred costs in
accordance with the Stipulation of Settlement related to the merger between
FirstEnergy and GPU.
Net Interest Charges
Net interest charges decreased $5.2 million in 2003 and $5.3 million
in 2002, compared to the previous year, reflecting debt redemptions of $102
million and $192 million, respectively. Those decreases were partially offset by
interest on $320 million of transition bonds issued in June 2002 (see Note 4
(E)) 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.
3
Preferred Stock Dividend Requirements
Preferred stock dividend requirements decreased $1.6 million in 2003,
and $3.1 million in 2002, compared to the prior year, due to the reacquisition
and redemptions of cumulative preferred stock pursuant to mandatory and optional
sinking fund provisions. We realized non-cash gains of $0.6 million and $3.6
million in 2003 and 2002, respectively, on the reacquisition of preferred stock.
Capital Resources and Liquidity
Changes in Cash Position
As of December 31, 2003, we had $0.3 million of cash and cash
equivalents compared with $4.8 million as of December 31, 2002. The major
sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Cash flows provided from operating activities totaled $180 million in
2003, $309 million in 2002 and $290 million in 2001. The sources of these
changes are as follows:
Operating Cash Flows 2003 2002 2001
---------------------------------------------------------
(In millions)
Cash earnings (1)............. $ 369 $ 325 $219
Working capital and other..... (189) (16) 71
---------------------------------------------------------
Total................ $ 180 $ 309 $290
=========================================================
(1) Includes net income, depreciation and amortization,
disallowed purchase power costs, deferred costs recoverable
as regulatory assets, deferred income taxes, and investment
tax credits.
Net cash provided from operating activities decreased by $129 million
in 2003 and increased by $19 million in 2002, as compared to the previous year.
The decrease in 2003 was due to a $173 million increase in working capital and
other requirements (primarily from a $170 million reduction in payables) which
was partially offset by a $44 million increase in cash earnings. The increase in
2002 reflected a $106 million increase in cash earnings partially offset by an
$87 million increase in working capital and other.
Cash Flows From Financing Activities
Net cash used for financing activities was $139 million and $140
million in 2003 and 2002, respectively. These amounts reflect redemptions of
debt and preferred stock, in addition to payments of $138 million in 2003 and
$191 million in 2002 for common dividends to FirstEnergy. The following table
provides details regarding new issues and redemptions during 2003 and 2002:
Securities Issued or Redeemed in 2003 2002
-------------------------------------------------------------
(In millions)
New Issues
Secured Notes..........................$150 $ --
Transition Bonds (See Note 4 (E))...... -- 320
Redemptions
First Mortgage Bonds................... 150 192
Medium Term Notes...................... 102 --
Preferred Stock........................ 125 52
Other.................................. 4
-------------------------------------------------------------
Total Redemptions.................. 377 248
Short-term Borrowings, net ................. 231 (18)
-------------------------------------------------------------
We had $231.0 million of short-term indebtedness at the end of 2003,
compared to no short-term debt at the end of 2002. We may borrow from our
affiliates on a short-term basis. We will not issue first mortgage bonds (FMB)
other than as collateral for senior notes, since our senior note indentures
prohibit (subject to certain exceptions) us from issuing any debt which is
senior to the senior notes. As of December 31, 2003, we had the capability to
issue $126 million of additional senior notes based upon FMB collateral. At
year-end 2003, based upon applicable earnings coverage tests and our charter, we
could issue $189 million of preferred stock (assuming no additional debt was
issued).
4
We have the ability to borrow from our regulated affiliates and
FirstEnergy to meet our short-term working capital requirements. FirstEnergy
Service Company administers this money pool and tracks surplus funds of
FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the
money pool agreements must repay the principal, together with accrued interest,
within 364 days of borrowing the funds. The rate of interest is the same for
each company receiving a loan from the pool and is based on the average cost of
funds available through the pool. The average interest rate for borrowings in
2003 was 1.47%.
At the end of 2003, our common equity as a percentage of
capitalization stood at 74%, as compared to 71% and 69% at the end of 2002 and
2001, respectively. In 2001, we experienced a significant increase in this ratio
due to the allocation of the purchase price when we were acquired by
FirstEnergy.
Our access to capital markets and costs of financing are dependent on
the ratings of our securities and that of our holding company, FirstEnergy. The
following table shows our securities' ratings following the downgrade by Moody's
Investors Service in February 2004. The ratings outlook on all securities is
stable.
Ratings of Securities
- ----------------------------------------------------------------------------
Securities S&P Moody's Fitch
- ----------------------------------------------------------------------------
FirstEnergy Senior unsecured BB+ Baa3 BBB-
JCP&L Senior secured BBB Baa1 BBB+
Preferred stock BB Ba1 BBB
- ----------------------------------------------------------------------------
On September 30, 2003, Fitch Ratings lowered the senior unsecured
ratings of FirstEnergy to "BBB-" from "BBB." Fitch affirmed the ratings of
JCP&L. Fitch announced that the Rating Outlook is Stable for the securities of
FirstEnergy, and all of the securities of its electric utility operating
companies. Fitch stated that the changes to the long-term ratings were "driven
by the high debt leverage of the parent, FirstEnergy. Despite management's
commitment to reduce debt related to the GPU merger, subsequent cash flows have
been vulnerable to unfavorable events, slowing the pace of FirstEnergy's debt
reduction efforts. The Stable Outlook reflects the success of FirstEnergy's
recent common equity offering and management's focus on a relatively
conservative integrated utility strategy."
On December 23, 2003, Standard & Poor's (S&P) lowered its corporate
credit ratings on FirstEnergy and its regulated utility subsidiaries to "BBB-"
from "BBB" and lowered FirstEnergy's senior unsecured debt rating to "BB+" from
"BBB-". Except for Ohio Edison's senior secured issue rating, which was left
unchanged, all other subsidiary ratings were lowered one notch as well. The
ratings were removed from CreditWatch with negative implications, where they had
been placed by S&P on August 18, 2003, and the Ratings Outlook returned to
Stable. The rating action followed a revision in S&P's assessment of our
consolidated business risk profile to `6' from `5' (`1' equals low risk, `10'
equals high risk), with S&P citing operational and management challenges as well
as heightened regulatory uncertainty for its revision of our business risk
assessment score. S&P's rationale for its revisions of the ratings included
uncertainty regarding the timing of the Ohio Rate Plan filing, the pending final
report on the August 14 blackout (see Power Outages), the outcome of the
remedial phase of litigation relating to the Sammis plant, and the extended
Davis-Besse outage (JCP&L has no ownership interest in Davis-Besse) and the
related pending subpoena. S&P further stated that the restart of Davis-Besse and
a supportive Ohio Rate Plan extension will be vital positive developments that
would aid an upgrade of FirstEnergy's ratings. S&P's reduction of the credit
ratings in December 2003 triggered cash and letter-of-credit collateral calls of
FirstEnergy in addition to higher interest rates for some outstanding
borrowings.
On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured
debt to Baa3 from Baa2 and downgraded the senior secured debt of JCP&L to Baa1
from A2. Moody's also downgraded the preferred stock rating of JCP&L to Ba1 from
Baa2. Moody's said that the lower ratings were prompted by: "1) high
consolidated leverage with significant holding company debt, 2) a degree of
regulatory uncertainty in the service territories in which the company operates,
3) risks associated with investigations of the causes of the August 2003
blackout, and related securities litigation, and 4) a narrowing of the ratings
range for the FirstEnergy operating utilities, given the degree to which
FirstEnergy increasingly manages the utilities as a single system and the
significant financial interrelationship among the subsidiaries."
Cash Flows From Investing Activities
Cash used in investing activities totaled $45.2 million in 2003 and
$195.2 million in 2002, principally for property additions to support the
distribution of electricity. Payments on loans from and (to) associated
companies were $78 million and $(77) million in 2003 and 2002, respectively.
Our capital spending for the period 2004-2006 is expected to be about
$446 million, of which approximately $146 million applies to 2004.
5
Contractual Obligations
Our cash contractual obligations as of December 31, 2003 that we
consider firm obligations are as follows:
2005- 2007-
Contractual Obligations Total 2004 2006 2008 Thereafter
- ------------------------------------------------------------------------------
(In millions)
Long-term debt.............. $1,273 $176 $ 275 $ 37 $ 785
Short-term borrowings....... 231 231 -- -- --
Operating leases............ 63 1 4 3 55
Purchases (1)............... 3,487 445 965 912 1,165
- ------------------------------------------------------------------------------
Total.................. $5,054 $853 $1,244 $952 $2,005
- ------------------------------------------------------------------------------
(1) Fuel and power purchases under contracts with fixed or minimum quantities
and approximate timing.
Market Risk Information
We use various market risk sensitive instruments, including
derivative contracts, primarily to manage the risk of price fluctuations. Our
Risk Policy Committee, comprised of FirstEnergy executive officers, exercises an
independent risk oversight function to ensure compliance with corporate risk
management policies and prudent risk management practices.
Commodity Price Risk
We are exposed to market risk primarily due to fluctuations in
electricity and natural gas prices. To manage the volatility relating to these
exposures, we use a variety of non-derivative and derivative instruments,
including forward contracts, options and futures contracts. The derivatives are
used for hedging purposes. Most of our non-hedge derivative contracts represent
non-trading positions that do not qualify for hedge treatment under SFAS 133,
"Accounting for Derivative Instruments and Hedging Activities." The change in
the fair value of commodity derivative contracts related to energy production
during 2003 is summarized in the following table:
Increase (Decrease) in the Fair Value of Commodity Derivative Contracts
Non-Hedge Hedge Total
--------- ----- -----
(In millions)
Change in the Fair Value of Commodity Derivative Contracts
Outstanding net asset as of January 1, 2003.................. $ 8.7 $ (0.1) $ 8.6
New contract value when entered.............................. -- -- --
Additions/Change in value of existing contracts.............. 4.5 -- 4.5
Change in techniques/assumptions............................. 2.3 -- 2.3
Settled contracts............................................ 0.1 0.1 0.2
------------------------------
Net Assets - Derivatives Contracts as of December 31, 2003 (1) $15.6 $ -- $15.6
==============================
Impact of Changes in Commodity Derivative Contracts (2)
Income Statement Effects:.................................... $ 0.5 $ -- $ 0.5
Balance Sheet Effects:
Other Comprehensive Income (Pre-Tax)...................... $ -- $ 0.1 $ 0.1
Regulatory Liability...................................... $ 6.4 $ -- $ 6.4
(1) Includes $15.5 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 December 31, 2003:
Non-Hedge Hedge Total
--------- ----- -----
(In millions)
Current-
Other Assets.................... $ 0.2 $ -- $ 0.2
Non-Current-
Other Deferred Charges.......... 15.4 -- 15.4
------ ------ ------
Net assets.................... $15.6 $ -- $ 15.6
===== ====== ======
The valuation of derivative contracts is based on observable market
information to the extent that such information is available. In cases where
such information is not available, we rely on model-based information. The model
provides estimates of future regional prices for electricity and an estimate of
6
related price volatility. We use these results to develop estimates of fair
value for financial reporting purposes and for internal management decision
making. Sources of information for the valuation of derivative contracts by year
are summarized in the following table:
Source of Information - Fair Value by Contract Year
- ---------------------------------------------------
2004 2005 2006 2007 Thereafter Total
---- ---- ---- ---- ---------- -----
(In millions)
Prices actively quoted(1)... $0.2 $-- $ -- $ -- $ -- $ 0.2
Other external sources(2)... 2.3 2.6 -- -- -- 4.9
Prices based on models...... -- -- 2.5 2.4 5.6 10.5
--------------------------------------------------
Total(3)................ $2.5 $2.6 $2.5 $2.4 $5.6 $15.6
=================================================
(1) Exchange traded. (2) Broker quote sheets.
(3) Includes $15.5 million from an embedded option that is offset by a
regulatory liability and does not affect earnings.
We perform sensitivity analyses to estimate our exposure to the
market risk of our commodity position. A hypothetical 10% adverse shift in
quoted market prices in the near term on derivative instruments would not have
had a material effect on our consolidated financial position or cash flows as of
December 31, 2003.
Interest Rate Risk
Our exposure to fluctuations in market interest rates is reduced
since our debt has fixed interest rates, as noted in the following table.
Comparison of Carrying Value to Fair Value
- -------------------------------------------------------------------------------------------------------------------
There- Fair
Year of Maturity 2004 2005 2006 2007 2008 after Total Value
- -------------------------------------------------------------------------------------------------------------------
(Dollars in millions)
Assets
- -------------------------------------------------------------------------------------------------------------------
Investments Other Than Cash
and Cash Equivalents-
Fixed Income............... $212 $ 212 $ 212
Average interest rate...... 5.0% 5.0%
- -------------------------------------------------------------------------------------------------------------------
Liabilities
- -------------------------------------------------------------------------------------------------------------------
Long-term Debt and Other
Long-Term Obligations:
Fixed rate.................... $176 $67 $208 $18 $19 $785 $1,273 $1,190
Average interest rate ..... 6.9% 6.1% 6.3% 4.2% 5.4% 6.5% 6.5%
Short-term Borrowings......... $231 $ 231 $ 231
Average interest rate...... 1.7% 1.7%
- -------------------------------------------------------------------------------------------------------------------
Equity Price Risk
Included in nuclear decommissioning trusts are marketable equity
securities carried at their market value of approximately $69 million and $52
million at December 31, 2003 and 2002, respectively. A hypothetical 10% decrease
in prices quoted by stock exchanges would result in a $7 million reduction in
fair value as of December 31, 2003. (See Note 1 (K) - "Cash and Financial
Instruaments")
Outlook
Beginning in 1999, all of our customers were able to select
alternative energy suppliers. We continue to deliver power to homes and
businesses through our 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 (FERC) for recovery from customers
in future periods and, without such authorization, would have been charged to
income when incurred. All of our regulatory assets are expected to continue to
be recovered under the provisions of the regulatory proceedings discussed below.
Our regulatory assets totaled $2.6 billion and $3.1 billion as of December 31,
2003 and December 31, 2002, respectively.
7
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. Our two August 2002 rate
filings requested increases in base electric rates of approximately $98 million
annually and requested the recovery of deferred energy costs that exceeded
amounts being recovered under the current market transition charge (MTC) and
societal benefits charge (SBC) rates; one proposed method of recovery of these
costs is the securitization of the deferred balance. This securitization
methodology is similar to the Oyster Creek securitization. On July 25, 2003, the
NJBPU announced its JCP&L base electric rate proceeding decision which reduced
our 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
our rate base for the next six to twelve months. During that period, we will
initiate another proceeding to request recovery of additional costs incurred to
enhance system reliability. In that proceeding, the NJBPU could increase the
return on equity to 9.75% or decrease it to 9.25%, depending on its assessment
of the reliability of our service. Any reduction would be retroactive to August
1, 2003. The revenue decrease in the decision consists of a $223 million
decrease in the electricity delivery charge, a $111 million increase due to the
August 1, 2003 expiration of annual customer credits previously mandated by the
New Jersey transition legislation, a $49 million increase in the MTC tariff
component, and a net $1 million increase in the SBC charge. The MTC allows for
the recovery of $465 million in deferred energy costs over the next ten years on
an interim basis, disallowing $153 million of the $618 million provided for in a
preliminary settlement agreement between certain parties. As a result, we
recorded charges to net income for the year ended December 31, 2003, aggregating
$185 million ($109 million net of tax) consisting of the $153 million deferred
energy costs and other regulatory assets. We filed a motion for rehearing and
reconsideration with the NJBPU on August 15, 2003 with respect to the following
issues: (1) the disallowance of the $153 million deferred energy costs; (2) the
reduced rate of return on equity; and (3) $42.7 million of disallowed costs to
achieve merger savings. On October 10, 2003, the NJBPU held the motion in
abeyance until the final NJBPU decision and order is issued, which is expected
in the first quarter of 2004.
On July 5, 2003, we experienced a series of 34.5 kilo-volt
sub-transmission line faults that resulted in outages on the New Jersey shore.
The NJBPU instituted an investigation into these outages, and directed that a
Special Reliability Master be hired to oversee the investigation. On December 8,
2003, the Special Reliability Master issued his Interim Report recommending that
we implement a series of actions to improve reliability in the area affected by
the outages. The NJBPU adopted the findings and recommendations of the Interim
Report on December 17, 2003, and ordered us to implement the recommended actions
on a staggered basis, with initial actions to be completed by March 31, 2004. We
expect to spend approximately $12.5 million implementing these actions during
2004.
FERC Regulatory Matters
On December 19, 2002, the FERC granted unconditional Regional
Transmission Organization status to PJM Interconnection, LLC which includes us
as transmission owners. PJM and the Midwest Independent System Operator, Inc.
(MISO) were ordered by the FERC to develop a common market between the regions
by October 31, 2004. The FERC also initiated a Section 206 investigation into
the reasonableness of the "through-and-out" transmission rates charged by PJM
and MISO. By order issued November 17, 2003, MISO, PJM and certain unaffiliated
transmission owners in the Midwest were directed to eliminate rates for
point-to-point service between the two RTOs effective April 1, 2004. A
settlement judge has been appointed by the FERC to resolve compliance filings by
the affected transmission providers. AEP, Commonwealth Edison and other
utilities have appealed the FERC's November 17, 2003 order to the federal court
of appeals for the District of Columbia.
Environmental Matters
We have 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 December 31, 2003, based on
estimates of the total costs of cleanup, our proportionate responsibility for
such costs and the financial ability of other nonaffiliated entities to pay. We
have accrued liabilities aggregating approximately $45 million as of December
31, 2003. We do not believe environmental remediation costs will have a material
adverse effect on our financial condition, cash flows or results of operations.
Power Outages
In July 1999, the Mid-Atlantic states experienced a severe heat storm
which resulted in power outages throughout the service territories of many
electric utilities, including JCP&L's territory. In an investigation into the
causes of the outages and the reliability of the transmission and distribution
systems of all four New Jersey electric utilities, the NJBPU concluded that
there was not a prima facie case demonstrating that, overall, JCP&L provided
unsafe, inadequate or improper service to its customers. Two class action
lawsuits (subsequently consolidated into a single proceeding)
8
were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and
other GPU companies, seeking compensatory and punitive damages arising from the
July 1999 service interruptions in the JCP&L territory.
Since July 1999, this litigation has involved a substantial amount of
legal discovery including interrogatories, request for production of documents,
preservation and inspection of evidence, and depositions of the named plaintiffs
and many JCP&L employees. In addition, there have been many motions filed and
argued by the parties involving issues such as the primary jurisdiction and
findings of the NJBPU, consumer fraud by JCP&L, strict product liability, class
decertification, and the damages claimed by the plaintiffs. In January 2000, the
NJ Appellate Division determined that the trial court has proper jurisdiction
over this litigation. In August 2002, the trial court granted partial summary
judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud,
common law fraud, negligent misrepresentation, and strict products liability. In
November 2003, the trial court granted JCP&L's motion to decertify the class and
denied plaintiffs' motion to permit into evidence their class-wide damage model
indicating damages in excess of $50 million. These class decertification and
damage rulings have been appealed to the Appellation Division and oral argument
is scheduled for May 2004. FirstEnergy is unable to predict the outcome of these
matters and no liability has been accrued as of December 31, 2003.
On August 14, 2003, various states and parts of southern Canada
experienced a widespread power outage. That outage affected approximately 1.4
million customers in FirstEnergy's service area. FirstEnergy continues to
accumulate data and evaluate the status of its electrical system prior to and
during the outage event, and continues to cooperate with the U.S.-Canada Power
System Outage Task Force (Task Force) investigating the August 14th outage. The
interim report issued by the Task Force on November 18, 2003 concluded that the
problems leading to the outage began in FirstEnergy's service area.
Specifically, the interim report concludes, among other things, that the
initiation of the August 14th outage resulted from the coincidence on that
afternoon of the following events: (1) inadequate situational awareness at
FirstEnergy; (2) FirstEnergy's failure to adequately manage tree growth in its
transmission rights of way; and (3) failure of the interconnected grid's
reliability organizations (Midwest Independent System Operator and PJM
Interconnection) to provide effective diagnostic support. FirstEnergy believes
that the interim report does not provide a complete and comprehensive picture of
the conditions that contributed to the August 14th outage and that it does not
adequately address the underlying causes of the outage. FirstEnergy remains
convinced that the outage cannot be explained by events on any one utility's
system. On November 25, 2003, the PUCO ordered FirstEnergy to file a plan with
the PUCO no later than March 1, 2004, illustrating how FirstEnergy will correct
problems identified by the Task Force as events contributing to the August 14th
outage and addressing how FirstEnergy proposes to upgrade its control room
computer hardware and software and improve the training of control room
operators to ensure that similar problems do not occur in the future. The PUCO,
in consultation with the North American Electric Reliability Council, will
review the plan before determining the next steps in the proceeding. On December
24, 2003, the FERC ordered FirstEnergy to pay for an independent study of part
of Ohio's power grid. The study is to examine the stability of the grid in
critical points in the Cleveland and Akron areas; the status of projected power
reserves during summer 2004 through 2008; and the need for new transmission
lines or other grid projects. The FERC ordered the study to be completed within
120 days. At this time, it is unknown what the cost of such study will be, or
the impact of the results.
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.
Management Changes
On December 11, 2003, we named a new president, to whom the Central
and Northern regional presidents will report. The new organizational structure
creates clearer lines of responsibility and accountability for our operations.
Critical Accounting Policies
We prepare our consolidated financial statements in accordance with
accounting principles that are generally accepted in the United States (GAAP).
Application of these principles often requires a high degree of judgment,
estimates and assumptions that affect financial results. All of our assets are
subject to their own specific risks and uncertainties and are regularly reviewed
for impairment. Assets related to the application of the policies discussed
below are similarly reviewed with their risks and uncertainties reflecting these
specific factors. Our more significant accounting policies are described below.
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 our records primarily consist of: (1) revaluation of
certain property, plant and equipment; (2) adjusting preferred stock subject to
mandatory redemption and long-term debt to
9
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," we evaluate goodwill for impairment at least annually and
would make such an evaluation more frequently if indicators of impairment should
arise. In accordance with the accounting standard, if the fair value of a
reporting unit is less than its carrying value (including goodwill), the
goodwill is tested for impairment. If impairment were indicated, we would
recognize a loss - calculated as the difference between the implied fair value
of its goodwill and the carrying value of the goodwill. Our annual review was
completed in the third quarter of 2003, with no impairment of goodwill
indicated. The forecasts used in our evaluation of goodwill reflect operations
consistent with our general business assumptions. Unanticipated changes in those
assumptions could have a significant effect on our future evaluations of
goodwill. As of December 31, 2003, we had recorded goodwill of approximately
$2.0 billion related to the merger.
Regulatory Accounting
We are subject to regulation that sets the prices (rates) we are
permitted to charge our customers based on the costs that the regulatory
agencies determine we are permitted to recover. At times, regulators permit the
future recovery through rates of costs that would be currently charged to
expense by an unregulated company. This rate-making process results in the
recording of regulatory assets based on anticipated future cash inflows. As a
result of the changing regulatory framework in New Jersey, a significant amount
of regulatory assets have been recorded - $2.6 billion as of December 31, 2003.
We regularly review these assets to assess their ultimate recoverability within
the approved regulatory guidelines. Impairment risk associated with these assets
relates to potentially adverse legislative, judicial or regulatory actions in
the future.
Derivative Accounting
Determination of appropriate accounting for derivative transactions
requires the involvement of management representing operations, finance and risk
assessment. In order to determine the appropriate accounting for derivative
transactions, the provisions of the contract need to be carefully assessed in
accordance with the authoritative accounting literature and management's
intended use of the derivative. New authoritative guidance continues to shape
the application of derivative accounting. Management's expectations and
intentions are key factors in determining the appropriate accounting for a
derivative transaction and, as a result, such expectations and intentions are
documented. Derivative contracts that are determined to fall within the scope of
SFAS 133, as amended, must be recorded at their fair value. Active market prices
are not always available to determine the fair value of the later years of a
contract, requiring that various assumptions and estimates be used in their
valuation. We continually monitor our derivative contracts to determine if our
activities, expectations, intentions, assumptions and estimates remain valid. As
part of our normal operations, we enter into commodity contracts, as well as
interest rate swaps, which increase the impact of derivative accounting
judgments.
Revenue Recognition
We follow the accrual method of accounting for revenues, recognizing
revenue for 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 postemployment benefits other than pensions (OPEB) are
dependent upon numerous factors resulting from actual plan experience and
certain assumptions.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions FirstEnergy makes to the plans, and earnings on plan assets. Such
factors may be further affected by business combinations (such as FirstEnergy's
merger with GPU, Inc. in November 2001), which impacts employee demographics,
plan experience and other factors. Pension and OPEB costs are also affected by
changes to key assumptions, including anticipated rates of return on plan
assets, the discount rates and health care trend rates used in determining the
projected benefit obligations for pension and OPEB costs.
Plan amendments to retirement health care benefits in 2003 and 2002,
related to changes in benefits provided and cost-sharing provisions, which
10
reduced FirstEnergy's obligation by $123 and $121 million, respectively. In
early 2004, FirstEnergy announced that it would amend the benefit provisions of
its health care benefits plan and both employees and retirees would share in
more of the benefit costs.
In accordance with SFAS 87, "Employers' Accounting for Pensions" and
SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions," changes in pension and OPEB obligations associated with these factors
may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
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 recent declines in corporate bond
yields and interest rates in general, FirstEnergy reduced the assumed discount
rate as of December 31, 2003 to 6.25% from 6.75% and 7.25% used as of December
31, 2002 and 2001, respectively.
FirstEnergy's assumed rate of return on pension plan assets considers
historical market returns and economic forecasts for the types of investments
held by their pension trusts. In 2003, 2002 and 2001, plan assets actually
earned 24.0%, (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in
2003 were computed assuming a 9.0% rate of return on plan assets based upon
projections of future returns and their pension trust investment allocation of
approximately 70% equities, 27% bonds, 2% real estate and 1% cash.
As a result of GPU Service Inc. merging with FirstEnergy Service
Company in the second quarter of 2003, operating company employees of GPU
Service were transferred to the former GPU operating companies. Accordingly,
FirstEnergy requested an actuarial study to update the pension liabilities for
each of its subsidiaries. Based on the actuary's report, our accrued pension
costs as of June 30, 2003 increased by $79 million. The corresponding adjustment
related to this change decreased other comprehensive income and deferred income
taxes and increased the payable to associated companies.
Due to the increased market value of our pension plan assets, we
reduced our minimum liability as prescribed by SFAS 87 as of December 31, 2003
by $22 million, recording an increase of $59,000 in an intangible asset and
crediting OCI by $13 million (offsetting previously recorded deferred tax
benefits by $9 million). The remaining balance in OCI of $48 million will
reverse in future periods to the extent the fair value of trust assets exceeds
the accumulated benefit obligation. The accrued pension cost was reduced to $68
million as of December 31, 2003.
Based on pension assumptions and pension plan assets as of December
31, 2003, FirstEnergy will not be required to fund their pension plans in 2004.
However, health care cost trends have significantly increased and will affect
future OPEB costs. FirstEnergy's pension and OPEB expenses in 2004 are expected
to decrease by $38 million and $34 million, respectively. These reductions
reflect the actual performance of pension plan assets and amendments to the
health care benefits plan announced in early 2004 which result in employees and
retirees sharing more of the benefit costs. The reduction in OPEB costs for 2004
does not reflect the impact of the new Medicare law signed by President Bush in
December 2003 due to uncertainties regarding some of its new provisions (see
Note 1(H)). The 2003 and 2002 composite health care trend rate assumptions are
approximately 10%-12% gradually decreasing to 5% in later years. In determining
their trend rate assumptions, FirstEnergy included the specific provisions of
their health care plans, the demographics and utilization rates of plan
participants, actual cost increases experienced in their health care plans, and
projections of future medical trend rates. The effect on FirstEnergy's pension
and OPEB costs and liabilities from changes in key assumptions are as follows:
Increase in Costs from Adverse Changes in Key Assumptions
- -------------------------------------------------------------------------------
Assumption Adverse Change Pension OPEB Total
- -------------------------------------------------------------------------------
(In millions)
Discount rate................ Decrease by 0.25% $ 10 $ 5 $ 15
Long-term return on assets... Decrease by 0.25% $ 8 $ 1 $ 9
Health care trend rate....... Increase by 1% n/a $26 $ 26
Increase in Minimum Liability
Discount rate................ Decrease by 0.25% $104 n/a $104
- -------------------------------------------------------------------------------
Long-Lived Assets
In accordance with SFAS 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," we periodically evaluate our long-lived assets
to determine whether conditions exist that would indicate that the carrying
11
value of an asset might not be fully recoverable. The accounting standard
requires that if the sum of future cash flows (undiscounted) expected to result
from an asset is less than the carrying value of the asset, an asset impairment
must be recognized in the financial statements. If impairment has occurred, we
recognize a loss - calculated as the difference between the carrying value and
the estimated fair value of the asset (discounted future net cash flows).
The calculation of future cash flows is based on assumptions,
estimates and judgement about future events. The aggregate amount of cash flows
determines whether an impairment is indicated. The timing of the cash flows is
critical in determining the amount of the impairment.
Nuclear Decommissioning
In accordance with SFAS 143, we recognize an ARO for the future
decommissioning of TMI-2. The ARO liability represents an estimate of the fair
value of our current obligation related to nuclear decommissioning and the
retirement of other assets. A fair value measurement inherently involves
uncertainty in the amount and timing of settlement of the liability. We used an
expected cash flow approach (as discussed in FASB Concepts Statement No. 7,
"Using Cash Flow Information and Present Value in Accounting Measurements") to
measure the fair value of the nuclear decommissioning ARO. This approach applies
probability weighting to discounted future cash flow scenarios that reflect a
range of possible outcomes. The scenarios consider settlement of the ARO at the
expiration of the nuclear power plants' current license and settlement based on
an extended license term
New Accounting Standards And Interpretations Adopted
FIN 46 (revised December 2003), "Consolidation of Variable
Interest Entities"
In December 2003, the FASB issued a revised interpretation of
Accounting Research Bulletin No. 51, "Consolidated Financial Statements." FASB
Interpretation No. 46, "Consolidation of Variable Interest Entities", referred
to as "FIN 46R", requires the consolidation of a VIE by an enterprise if that
enterprise is determined to be the primary beneficiary of the VIE. FIN 46R
requires adoption for interests in VIEs or potential VIEs commonly referred to
as special-purpose entities effective December 31, 2003. Adoption of FIN 46R for
all other types of entities is effective March 31, 2004.
We are evaluating entities that meet the deferral criteria and may be
subject to consolidation under FIN 46R as of March 31, 2004. These entities are
non-utility generators in which we have neither debt nor equity investments but
are generally the sole purchaser of their power.
SFAS 143, "Accounting for Asset Retirement Obligations"
In January 2003, we implemented SFAS 143 which provides accounting
standards for retirement obligations associated with tangible long-lived assets.
This statement requires recognition of the fair value of a liability for an
asset retirement obligation in the period in which it is incurred. See Note 1(E)
for further discussion of SFAS 143.
DIG Implementation Issue No. C20 for SFAS 133, "Scope Exceptions:
Interpretation of the Meaning of Not Clearly and Closely Related in
Paragraph 10(b) Regarding Contracts with a Price Adjustment Feature"
In June 2003, the FASB cleared DIG Issue C20 for implementation in
fiscal quarters beginning after July 10, 2003. The issue supersedes earlier DIG
Issue C11, "Interpretation of Clearly and Closely Related in Contracts That
Qualify for the Normal Purchases and Normal Sales Exception." DIG Issue C20
provides guidance regarding when the presence of a general index, such as the
Consumer Price Index, in a contract would prevent that contract from qualifying
for the normal purchases and normal sales exception under SFAS 133, as amended,
and therefore exempt from the mark-to-market treatment of certain contracts.
Adoption of DIG Issue C20 did not impact our financial statements.
12
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME
Nov 7 - Jan. 1 -
2003 2002 Dec. 31, 2001 Nov. 6, 2001
- ----------------------------------------------------------------------------------------------------------------------
(In thousands)
|
OPERATING REVENUES (Note 1(J))............................ $2,364,203 $2,328,415 $282,902 | $1,838,638
---------- ---------- -------- | ----------
|
OPERATING EXPENSES AND TAXES: |
Fuel and purchased power (Note 1(J))................... 1,504,558 1,248,012 136,123 | 932,300
Other operating costs (Note 1(J))...................... 368,041 272,890 40,670 | 237,513
---------- ---------- -------- | -----------
Total operation and maintenance expenses............. 1,872,599 1,520,902 176,793 | 1,169,813
Provision for depreciation and amortization............ 250,013 244,759 35,124 | 205,918
General taxes.......................................... 53,481 56,049 8,919 | 56,582
Income taxes........................................... 41,839 171,496 18,400 | 113,478
---------- ---------- -------- | -----------
Total operating expenses and taxes................... 2,217,932 1,993,206 239,236 | 1,545,791
---------- ---------- -------- | -----------
|
OPERATING INCOME.......................................... 146,271 335,209 43,666 | 292,847
|
OTHER INCOME (EXPENSE).................................... 7,530 7,653 1,186 | (176,875)
---------- ---------- -------- | -----------
|
INCOME BEFORE NET INTEREST CHARGES........................ 153,801 342,862 44,852 | 115,972
---------- ---------- -------- | -----------
|
NET INTEREST CHARGES: |
Interest on long-term debt............................. 87,681 92,314 14,234 | 77,205
Allowance for borrowed funds used during |
construction......................................... (296) (583) 135 | (1,665)
Deferred interest ..................................... (8,639) (8,815) (2,243) | (12,557)
Other interest expense................................. 1,691 (2,643) 1,080 | 9,427
Subsidiary's preferred stock dividend requirements..... 5,347 10,694 1,605 | 9,095
---------- ---------- -------- | -----------
Net interest charges................................. 85,784 90,967 14,811 | 81,505
---------- ---------- -------- | -----------
|
NET INCOME................................................ 68,017 251,895 30,041 | 34,467
|
PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 500 2,125 698 | 4,547
|
GAIN ON PREFERRED STOCK REACQUISITION..................... (612) (3,589) -- | --
---------- ---------- -------- | -----------
|
EARNINGS ON COMMON STOCK.................................. $ 68,129 $ 253,359 $ 29,343 | $ 29,920
========== ========== ======== | ===========
|
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
13
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31, 2003 2002
- ------------------------------------------------------------------------------------------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service..................................................................... $3,642,467 $3,478,803
Less-Accumulated provision for depreciation.................................... 1,367,042 1,203,043
---------- ----------
2,275,425 2,275,760
---------- ----------
Construction work in progress.................................................. 48,985 20,687
---------- ----------
2,324,410 2,296,447
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts........................................... 125,945 106,820
Nuclear fuel disposal trust.................................................... 155,774 149,738
Long-term notes receivable from associated companies........................... 19,579 20,333
Other.......................................................................... 18,744 18,202
---------- ----------
320,042 295,093
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents...................................................... 271 4,823
Receivables-
Customers (less accumulated provisions of $4,296,000 and $4,509,000
respectively, for uncollectible accounts).................................. 198,061 247,624
Associated companies......................................................... 70,012 318
Other (less accumulated provisions of $1,183,000 in 2003).................... 46,411 20,134
Notes receivable from associated companies..................................... -- 77,358
Materials and supplies, at average cost........................................ 2,480 1,341
Prepayments and other.......................................................... 49,360 37,719
---------- ----------
366,595 389,317
---------- ----------
NONCURRENT LIABILITIES:
Regulatory assets.............................................................. 2,558,214 3,058,209
Goodwill....................................................................... 2,001,302 2,000,875
Other.......................................................................... 8,481 12,814
---------- ----------
4,567,997 5,071,898
---------- ----------
$7,579,044 $8,052,755
========== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity.................................................... $3,153,974 $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................................................................. 1,095,991 1,210,446
---------- ----------
4,262,614 4,622,408
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt............................................... 175,921 173,815
Short-term borrowings (Note 5)-
Associated companies......................................................... 230,985 --
Accounts payable-
Associated companies......................................................... 42,410 170,803
Other........................................................................ 105,815 106,504
Accrued taxes................................................................. 919 13,844
Accrued interest............................................................... 14,843 27,161
Other.......................................................................... 58,094 112,408
---------- ----------
628,987 604,535
---------- ----------
NONCURRENT LIABILITIES:
Accumulated deferred income taxes.............................................. 640,208 691,721
Accumulated deferred investment tax credits.................................... 7,711 9,939
Power purchase contract loss liability ........................................ 1,473,070 1,710,968
Nuclear fuel disposal costs.................................................... 167,936 166,191
Asset retirement obligation.................................................... 109,851 --
Retirement benefits............................................................ 159,219 --
Nuclear plant decommissioning costs............................................ -- 135,355
Other.......................................................................... 129,448 111,638
---------- ----------
2,687,443 2,825,812
---------- ----------
COMMITMENTS AND CONTINGENCIES
(Notes 3 and 6)...............................................................
---------- ----------
$7,579,044 $8,052,755
========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.
</FN>
14
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31, 2003 2002
- -----------------------------------------------------------------------------------------------------------------
(Dollars in thousands, except per share amounts)
COMMON STOCKHOLDER'S EQUITY:
Common stock, par value $10 per share, authorized 16,000,000 shares
15,371,270 shares outstanding.................................................... $ 153,713 $ 153,713
Other paid-in capital.............................................................. 3,029,894 3,029,218
Accumulated other comprehensive loss (Note 4(F))................................... (51,765) (865)
Retained earnings (Note 4(A))...................................................... 22,132 92,003
---------- -----------
Total common stockholder's equity................................................ 3,153,974 3,274,069
---------- -----------
Number of Shares Optional
Outstanding Redemption Price
---------------- --------------------
2003 2002 Per Share Aggregate
---- ---- --------- ---------
PREFERRED STOCK (Note 4(C)):
Cumulative, without par value-
Authorized 125,000 shares
Not Subject to Mandatory Redemption:
4% Series...................... 125,000 125,000 $106.50 $13,313 12,649 12,649
======= ======= ======= ======= ---------- -----------
Company obligated mandatorily redeemablE
Preferred securities of subsidiary LIMITED
PARTNERSHIP Holding solely company
subordinated Debentures
Cumulative, $25 par value -
Authorized 5,000,000 shares
Subject to Mandatory Redemption:
8.56% due 2044.................................................................. -- 125,244
---------- -----------
LONG-TERM DEBT (Note 4(D)):
First mortgage bonds:
6.375% due 2003................................................................... -- 150,000
7.125% due 2004................................................................... 160,000 160,000
6.780% due 2005................................................................... 50,000 50,000
6.850% due 2006................................................................... 40,000 40,000
8.250% due 2006................................................................... -- 23,053
7.900% due 2007................................................................... -- 18,361
7.125% due 2009................................................................... 6,300 6,300
7.100% due 2015................................................................... 12,200 12,200
9.200% due 2021................................................................... -- 22,963
8.320% due 2022................................................................... 40,000 40,000
8.550% due 2022................................................................... -- 13,623
7.980% due 2023................................................................... 40,000 40,000
7.500% due 2023................................................................... 125,000 125,000
8.450% due 2025................................................................... 50,000 50,000
6.750% due 2025................................................................... 150,000 150,000
---------- -----------
Total first mortgage bonds...................................................... 673,500 901,500
---------- -----------
Secured notes:
6.450% due 2006................................................................... 150,000 150,000
4.190% due 2007................................................................... 67,312 91,111
5.390% due 2010................................................................... 52,297 52,297
5.810% due 2013................................................................... 77,075 77,075
6.160% due 2017................................................................... 99,517 99,517
4.800% due 2018................................................................... 150,000 --
---------- -----------
Total secured notes............................................................. 596,201 470,000
---------- -----------
Unsecured notes:
7.69% due 2039.................................................................... 2,968 2,984
---------- -----------
Net unamortized premium (discount) on debt.......................................... (757) 9,777
---------- -----------
Long-term debt due within one year.................................................. (175,921) (173,815)
---------- -----------
Total long-term debt............................................................ 1,095,991 1,210,446
---------- -----------
TOTAL CAPITALIZATION................................................................... $4,262,614 $4,622,408
========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
15
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
Common Stock Accumulated
------------------- Other Other
Comprehensive Number Par Paid-In Comprehensive Retained
Income of Shares Value Capital Income (Loss) Earnings
------------- ---------- -------- ---------- ------------- --------
(Dollars in thousands)
Balance, January 1, 2001........................... 15,371,270 $153,713 $ 510,769 $ (8) $ 794,786
Net income...................................... $ 34,467 34,467
Net unrealized gain on investments.............. 2 2
Net unrealized gain on derivative instruments... 768 768
--------
Comprehensive income............................ $ 35,237
--------
Cash dividends on preferred stock............... (4,547)
Cash dividends on common stock ................ (175,000)
- -------------------------------------------------------------------------------------------------------------------------------
Balance, November 6, 2001.......................... 15,371,270 153,713 510,769 762 649,706
Purchase accounting fair value adjustment....... 2,470,348 (762) (649,706)
_______________________________________________________________________________________________________________________________
Balance, November 7, 2001.......................... 15,371,270 153,713 2,981,117 -- --
Net income...................................... $ 30,041 30,041
Net unrealized loss on derivative instruments... (472) (472)
--------
Comprehensive income............................ $ 29,569
--------
Cash dividends on preferred stock............... (698)
- -------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2001......................... 15,371,270 153,713 2,981,117 (472) 29,343
Net income...................................... $251,895 251,895
Net unrealized loss on derivative instruments... (393) (393)
--------
Comprehensive income............................ $251,502
--------
Cash dividends on preferred stock............... 1,465
Cash dividends on common stock.................. (190,700)
Purchase accounting fair value adjustment....... 48,101
- -------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2002......................... 15,371,270 153,713 3,029,218 (865) 92,003
Net income...................................... $ 68,017 68,017
Net unrealized loss on derivative instruments... (3,020) (3,020)
Minimum liability for unfunded retirement
benefits, net of $(32,998,000) of
income taxes.................................. (47,880) (47,880)
--------
Comprehensive income............................ $ 17,117
--------
Cash dividends on preferred stock............... (500)
Cash dividends on common stock.................. (138,000)
Gain on preferred stock reacquisition...........
Purchase accounting fair value adjustment ...... 676 612
- -------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2003......................... 15,371,270 $153,713 $3,029,894 $(51,765) $ 22,132
===============================================================================================================================
CONSOLIDATED STATEMENTS OF PREFERRED STOCK
Not Subject to Subject to
Mandatory Redemption Mandatory Redemption
-------------------- --------------------
Number Carrying Number Carrying
of Shares Value of Shares Value
--------- -------- --------- --------
(Dollars in thousands)
Balance, January 1, 2001............ 125,000 $12,649 5,623,334 $ 187,333
Redemptions-
7.52% Series.................... (25,000) (2,500)
8.65% Series.................... (83,333) (8,333)
Purchase accounting fair
value adjustment.............. 4,451
-----------------------------------------------------------------------------------------
Balance, December 31, 2001.......... 125,000 12,649 5,515,001 $ 180,951
Redemptions-
7.52% Series.................... (265,000) (28,951)
8.65% Series.................... (250,001) (26,750)
Amortization of fair market
value adjustment.............. (6)
-----------------------------------------------------------------------------------------
Balance, December 31, 2002.......... 125,000 12,649 5,000,000 $ 125,244
Redemptions-
8.56% Series.................... (5,000,000) (125,242)
Amortization of fair market
value adjustment.............. (2)
-----------------------------------------------------------------------------------------
Balance, December 31, 2003.......... 125,000 $12,649 -- $ --
=========================================================================================
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
16
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Nov. 7 - Jan. 1 -
2003 2002 Dec. 31, 2001 Nov. 6, 2001
- --------------------------------------------------------------------------------------------------------------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES: |
Net Income.................................................... $ 68,017 $ 251,895 $ 30,041 | $ 34,467
Adjustments to reconcile net income to net |
cash from operating activities: |
Provision for depreciation and amortization.............. 250,013 244,759 35,124 | 205,918
Other amortization....................................... 64 849 1,360 | 23,025
Deferred costs recoverable as regulatory assets.......... (164,290) (285,065) (25,471) | (29,312)
Deferred income taxes, net............................... 64,600 115,866 5,609 | (58,132)
Investment tax credits, net.............................. (2,228) (3,551) (540) | (3,057)
Receivables.............................................. 4,528 (14,542) 7,050 | 27,177
Materials and supplies................................... (1,139) 7 2 | (842)
Accounts payable......................................... (153,953) 16,399 (5,060) | (44,498)
Retail rate refunds obligation payments.................. (71,984) (43,016) -- | --
Disallowed purchased power costs......................... 152,500 -- -- | --
Accrued retirement benefit obligation.................... 8,381 -- -- | --
Accrued compensation, net................................ 19,864 (59) -- | --
Other (Note 7)........................................... 5,579 25,433 20,563 | 66,328
--------- --------- -------- | ---------
Net cash provided from operating activities............ 179,952 308,975 68,678 | 221,074
--------- --------- -------- | ---------
|
CASH FLOWS FROM FINANCING ACTIVITIES: |
New Financing- |
Long-term debt........................................... 150,000 318,106 -- | 148,796
Short-term borrowings, net............................... 230,985 -- -- | --
Redemptions and Repayments- |
Preferred stock.......................................... (125,244) (51,500) -- | (10,833)
Long-term debt........................................... (251,815) (196,033) (40,000) | --
Short-term borrowings, net............................... -- (18,149) (1,851) | (9,200)
Dividend Payments- |
Common stock............................................. (138,000) (190,700) -- | (175,000)
Preferred stock.......................................... (5,235) (2,125) (698) | (4,547)
--------- --------- -------- | ---------
Net cash used for financing activities................. (139,309) (140,401) (42,549) | (50,784)
--------- --------- -------- | ---------
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
Property additions......................................... (122,930) (97,346) (21,487) | (141,030)
Contributions to decommissioning trusts.................... (2,630) -- (202) | (1,004)
Loan payments from (to) associated companies, net.......... 78,112 (77,358) -- | --
Other...................................................... 2,253 (20,471) (1,078) | (2,215)
--------- --------- -------- | ---------
Net cash used for investing activities................. (45,196) (195,175) (22,767) | (144,249)
--------- --------- -------- | ---------
|
|
Net increase (decrease) in cash and cash equivalents.......... (4,552) (26,601) 3,362 | 26,041
Cash and cash equivalents at beginning of period.............. 4,823 31,424 28,062 | 2,021
--------- --------- -------- | ---------
Cash and cash equivalents at end of period.................... $ 271 $ 4,823 $ 31,424 | $ 28,062
========= ========= ======== | =========
|
SUPPLEMENTAL CASH FLOWS INFORMATION: |
Cash Paid During the Year- |
Interest (net of amounts capitalized).................... $ 101,432 $ 92,152 $ 4,787 | $ 95,509
========= ========= ======== | =========
Income taxes............................................. $ 16,883 $ 83,776 $ 20,586 | $ 19,365
========= ========= ======== | =========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
17
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF TAXES
Nov. 7 - Jan. 1 -
2003 2002 Dec. 31, 2001 Nov. 6, 2001
- --------------------------------------------------------------------------------------------------------------------
(In thousands)
GENERAL TAXES: |
New Jersey Transitional Energy Facilities Assessment*......... $ 38,668 $ 39,387 $ 6,765 | $ 42,418
Real and personal property.................................... 3,889 4,362 283 | 3,589
State gross receipts.......................................... -- -- 1,269 | --
Social security and unemployment.............................. 4,826 -- (1) | 7
Other ....................................................... 6,098 12,300 603 | 10,568
-------- -------- -------- | ---------
Total general taxes.................................... $ 53,481 $ 56,049 $ 8,919 | $ 56,582
======== ======== ======== | =========
|
PROVISION FOR INCOME TAXES: |
Currently payable (receivable)- |
Federal.................................................... $(15,687) $ 55,731 $ 11,827 | $ 41,826
State...................................................... (245) 13,809 3,205 | 19,415
-------- -------- -------- | ---------
(15,932) `69,540 15,032 | 61,241
-------- -------- -------- | ---------
Deferred, net- |
Federal.................................................... 54,252 88,758 4,268 | (36,210)
State...................................................... 10,348 27,108 1,341 | (21,922)
-------- -------- -------- | ---------
64,600 115,866 5,609 | (58,132)
-------- -------- -------- | ---------
Investment tax credit amortization............................ (2,228) (3,551) (540) | (3,057)
-------- -------- -------- | ---------
Total provision for income taxes....................... $ 46,440 $181,855 $ 20,101 | $ 52
======== ======== ======== | =========
|
INCOME STATEMENT CLASSIFICATION |
OF PROVISION FOR INCOME TAXES: |
Operating income.............................................. $ 41,839 $171,496 $ 18,400 | $ 113,478
Other income.................................................. 4,601 10,359 1,701 | (113,426)
-------- -------- -------- | ---------
Total provision for income taxes....................... $ 46,440 $181,855 $ 20,101 | $ 52
======== ======== ======== | =========
|
RECONCILIATION OF FEDERAL INCOME TAX |
EXPENSE AT STATUTORY RATE TO TOTAL |
PROVISION FOR INCOME TAXES: |
Book income before provision for income taxes................. $114,457 $433,749 $ 50,142 | $ 34,519
======== ======== ======== | =========
Federal income tax expense at statutory rate.................. $ 40,060 $151,812 $ 17,550 | $ 12,082
Increases (reductions) in taxes resulting from- |
Amortization of investment tax credits..................... (2,228) (3,551) (540) | (3,057)
Depreciation............................................... 3,315 7,154 226 | 3,563
State income tax, net of federal benefit................... 7,178 27,111 3,077 | 4,355
Allocated share of consolidated tax savings................ -- -- -- | (8,509)
Other, net................................................. (1,885) (671) (212) | (8,382)
-------- -------- -------- | ---------
Total provision for income taxes....................... $ 46,440 $181,855 $ 20,101 | $ 52
======== ======== ======== | =========
|
ACCUMULATED DEFERRED INCOME TAXES AT |
DECEMBER 31: |
Property basis differences.................................... $371,811 $297,983 $288,255 |
Nuclear decommissioning....................................... 34,663 44,775 59,716 |
Deferred sale and leaseback costs............................. (16,651) (16,451) (16,240) |
Purchase accounting basis difference.......................... (1,253) (1,253) (71,900) |
Sale of generation assets..................................... (17,861) (17,861) 184,625 |
Regulatory transition charge.................................. 197,729 224,117 123,042 |
Provision for rate refund..................................... -- (29,370) (46,942) |
Customer receivables for future income taxes.................. (4,519) (5,336) 16,749 |
Oyster Creek securitization................................... 193,558 202,448 -- |
Other comprehensive income.................................... (32,998) -- -- |
Employee benefits............................................. (29,129) -- -- |
Other......................................................... (55,142) (7,331) (23,089) |
-------- -------- -------- |
Net deferred income tax liability...................... $640,208 $691,721 $514,216 |
======== ======== ======== |
<FN>
* Collected from customers through regulated rates and included in revenue on the Consolidated Statements of Income.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
18
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
The consolidated financial statements include Jersey Central Power &
Light Company (Company) and its wholly owned subsidiaries. The Company is a
wholly owned subsidiary of FirstEnergy Corp. FirstEnergy also holds directly all
of the issued and outstanding common shares of its other principal electric
utility operating subsidiaries, including Ohio Edison Company (OE), The
Cleveland Electric Illuminating Company (CEI), The Toledo Edison Company (TE),
American Transmission Systems, Inc. (ATSI), Metropolitan Edison Company (Met-Ed)
and Pennsylvania Electric Company (Penelec). The Company, Met-Ed and Penelec
were formerly wholly owned subsidiaries of GPU, Inc., which merged with
FirstEnergy on November 7, 2001. Pre-merger and post-merger period financial
results are separated by a heavy black line.
The Company follows the accounting policies and practices prescribed
by the Securities and Exchange Commission (SEC), the New Jersey Board of Public
Utilities (NJBPU) and the Federal Energy Regulatory Commission (FERC). The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States (GAAP) requires management to make
periodic estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses and the disclosure of contingent assets and
liabilities. Actual results could differ from these estimates.
(A) CONSOLIDATION-
The Company consolidates all majority-owned subsidiaries, over which
the Company exercises control and, when applicable, entities for which the
Company has a controlling financial interest. Intercompany transactions and
balances are eliminated in consolidation. Investments in nonconsolidated
affiliates (20-50 percent owned companies, joint ventures and partnerships) over
which the Company has the ability to exercise significant influence, but not
control, are accounted for on the equity basis.
(B) REVENUES-
The Company's principal business is providing electric service to
customers in New Jersey. The Company's retail customers are metered on a cycle
basis. Revenue is recognized for unbilled electric service provided through the
end of the year. See Note 7 - Other Information for discussion of reporting of
independent system operator transactions.
Receivables from customers include sales to residential, commercial
and industrial customers and sales to wholesale customers. There was no material
concentration of receivables as of December 31, 2003 or 2002, with respect to
any particular segment of the Company's customers. Total customer receivables
were $198 million (billed - $119 million and unbilled - $79 million) and $248
million (billed - $154 million and unbilled - $94 million) as of December 31,
2003 and 2002, respectively.
(C) REGULATORY MATTERS-
The Company'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 the Company'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 the Company's net income since the
contingency existed prior to the merger and there would be an adjustment to
goodwill.
In addition, the Final Order provided for the ability to securitize
stranded costs associated with the divested Oyster Creek Nuclear Generating
Station. Under NJBPU authorization in 2002, the Company issued through its
wholly owned subsidiary, JCP&L Transition Funding LLC, $320 million of
transition bonds (recognized on the Consolidated Balance Sheet) which
securitized the recovery of these costs and which provided for a usage-based
non-bypassable transition bond charge (TBC) and for the transfer of the bondable
transition property to another entity.
Prior to August 1, 2003, the Company's provider of last resort (PLR)
obligation to provide basic generation service (BGS) to non-shopping customers
was supplied almost entirely from contracted and open market purchases. The
Company 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
19
BGS and MTC rates. As of December 31, 2003, the accumulated deferred cost
balance totaled approximately $440 million, after the charge discussed below.
The NJBPU also allowed securitization of the Company's deferred balance to the
extent permitted by law upon application by the Company 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. The Company's two August
2002 rate filings requested increases in base electric rates of approximately
$98 million annually and requested the recovery of deferred costs that exceeded
amounts being recovered under the current MTC and SBC rates; one proposed method
of recovery of these costs is the securitization of the deferred balance. This
securitization methodology is similar to the Oyster Creek securitization
discussed above. On July 25, 2003, the NJBPU announced its decision in the
Company's base electric rate proceeding decision, which reduced the Company'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 the
Company's rate base for 6 to 12 months. During that period, the Company 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 the Company'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, the Company recorded charges to net income
for the year ended December 31, 2003, aggregating $185 million ($109 million net
of tax) consisting of the $153 million deferred energy costs and other
regulatory assets. the Company filed a motion for rehearing and reconsideration
with the NJBPU on August 15, 2003 with respect to the following issues: (1) the
disallowance of the $153 million deferred energy costs; (2) the reduced rate of
return on equity; and (3) $42.7 million of disallowed costs to achieve merger
savings. On October 10, 2003, the NJBPU held the motion in abeyance until the
final NJBPU decision and order which is expected to be issued in the first
quarter of 2004.
The Company's BGS obligation for the twelve month period beginning
August 1, 2003 was auctioned in February 2003. The auction covered a fixed price
bid (applicable to all residential and smaller commercial and industrial
customers) and an hourly price bid (applicable to all large industrial
customers) process. JCP&L sells all self-supplied energy (NUGs and owned
generation) to the wholesale market with offsetting credits to its deferred
energy balances. The BGS auction for the subsequent period was completed in
February 2004. The NJBPU adjusted the generation component of the Company's
retail rates on August 1, 2003 to reflect the result of the BGS auction.
On July 5, 2003, the Company experienced a series of 34.5 kilovolts
sub-transmission line faults that resulted in outages on the New Jersey shore.
The NJBPU instituted an investigation into these outages, and directed that a
Special Reliability Master be hired to oversee the investigation. On December 8,
2003, the Special Reliability Master issued his Interim Report recommending that
the Company implement a series of actions to improve reliability in the area
affected by the outages. The NJBPU adopted the findings and recommendations of
the Interim Report on December 17, 2003, and ordered the Company to implement
the recommended actions on a staggered basis, with initial actions to be
completed by March 31, 2004. The Company expects to spend $12.5 million
implementing these actions during 2004.
Regulatory Assets-
The Company recognizes, as regulatory assets, costs which the FERC
and the NJBPU have authorized for recovery from customers in future periods.
Without such authorization, the costs would have been charged to income as
incurred. All regulatory assets are expected to continue to be recovered from
customers under the Company's regulatory plan. The Company continues to bill and
collect cost-based rates for its transmission and distribution services, which
remain regulated; accordingly, it is appropriate that the Company continue the
application of Statement of Financial Accounting Standards No.(SFAS) 71 ,
"Accounting for the Effects of Certain Types of Regulation," to those
operations.
20
Net regulatory assets on the Consolidated Balance Sheets are
comprised of the following:
2003 2002
---------------------------------------------------------------------
(In millions)
Regulatory transition charge................... $2,457 $2,802
Societal benefits charge....................... 82 144
Property losses and unrecovered plant costs.... 70 88
Customer receivables for future income taxes... -- 34
Employee postretirement benefit costs.......... 30 33
Loss on reacquired debt........................ 15 17
Component fuel disposal costs.................. 3 9
Component removal costs........................ (150) (141)
Other.......................................... 51 72
--------------------------------------------------------------------
Total....................................... $2,558 $3,058
====================================================================
Regulatory Accounting for Generation Operations-
The application of SFAS 71 was discontinued in 1999 with respect to
the Company's generation operations. The Company subsequently divested
substantially all of its generating assets. The SEC issued interpretive guidance
regarding asset impairment measurement, providing that any supplemental
regulated cash flows such as a Competitive Transition Charge should be excluded
from the cash flows of assets in a portion of the business not subject to
regulatory accounting practices. If those assets are impaired, a regulatory
asset should be established if the costs are recoverable through regulatory cash
flows. Net assets included in utility plant relating to operations for which the
application of SFAS 71 was discontinued were $42 million as of December 31,
2003.
(D) PROPERTY, PLANT AND EQUIPMENT-
As a result of the merger, a portion of the Company's property, plant
and equipment was adjusted to reflect fair value. The majority of the Company's
property, plant and equipment is reflected at original cost since such assets
remain subject to rate regulation on a historical cost basis. In addition to its
wholly owned facilities, the Company holds a 50% ownership interest in Yards
Creek Pumped Storage Facility, and its net book value was approximately $20.7
million as of December 31, 2003. The Company's accounting policy for planned
major maintenance projects is to recognize liabilities as they are incurred.
The Company provides for depreciation on a straight-line basis at
various rates over the estimated lives of property included in plant in service.
The annualized composite rate was approximately 2.8% in 2003, 3.5% in 2002 and
3.4% in 2001. The 2003 rate reflects the rate depreciation reduction from the
NJBPU August 2003 rate decision.
(E) ASSET RETIREMENT OBLIGATION-
In January 2003, the Company implemented SFAS 143, "Accounting for
Asset Retirement Obligations", which provides accounting standards for
retirement obligations associated with tangible long-lived assets. This
statement requires recognition of the fair value of a liability for an asset
retirement obligation (ARO) in the period in which it is incurred. The
associated asset retirement costs are capitalized as part of the carrying amount
of the long-lived asset. Over time the capitalized costs are depreciated and the
present value of the asset retirement liability increases, resulting in a period
expense. However, rate-regulated entities may recognize a regulatory asset or
liability instead if the criteria for such treatment are met. Upon retirement, a
gain or loss would be recognized if the cost to settle the retirement obligation
differs from the carrying amount.
The Company identified applicable legal obligations as defined under
the new standard for nuclear power plant decommissioning. The ARO liability as
of the date of adoption of SFAS 143 was $103.9 million, including accumulated
accretion for the period from the date the liability was incurred to the date of
adoption. As of December 31, 2002, the Company recognized decommissioning
liabilities of $129.9 million. The Company expects substantially all nuclear
decommissioning costs to be recoverable through regulated rates. Therefore, a
regulatory liability of $26 million was recognized upon adoption of SFAS 143.
Accretion during 2003 was $5.9 million, bringing the ARO liability as of
December 31, 2003 to $109.8 million. The ARO includes the Company's obligation
for the nuclear decommissioning of Three Mile Island Unit 2 (TMI-2). The
Company's share of the obligation to decommission TMI-2 was developed based on a
site-specific study performed by an independent engineer. The Company utilized
an expected cash flow approach (as discussed in FASB Concepts Statement No. 7,
"Using Cash Flow Information and Present Value in Accounting Measurements") to
measure the fair value of the nuclear decommissioning ARO. The Company maintains
nuclear decommissioning trust funds that are legally restricted for purposes of
settling the nuclear decommissioning ARO. As of December 31, 2003, the fair
value of the decommissioning trust assets was $125.9 million.
In accordance with SFAS 143, the Company ceased the accounting
practice of depreciating non-regulated generation assets using a cost of removal
component in the depreciation rates. That practice recognized accumulated
depreciation in excess of the historical cost of an asset because the removal
21
cost would exceed the estimated salvage value. Beginning in 2003, the cost of
removal related to non-regulated generation assets is charged to expense rather
than to the accumulated provision for depreciation. In accordance with SFAS 71,
the cost of removal on regulated plant assets continues to be accounted for as a
component of depreciation rates and is recognized as a regulatory liability. If
SFAS 143 had been applied during 2002 and 2001, there would have been no impact
to the Company's Statements of Income.
The following table provides the year-end balance of the ARO related
to nuclear decommissioning for 2002, as if SFAS 143 had been adopted on January
1, 2002.
Adjusted ARO Reconciliation 2002
--------------------------------------------------------
(In millions)
Beginning balance as of January 1, 2002 $ 98.4
Accretion in 2002 5.5
--------------------------------------------------------
Ending balance as of December 31, 2002 $103.9
--------------------------------------------------------
In addition to the nuclear decommissioning ARO, FirstEnergy has also
recognized estimated liabilities for post defueling monitored storage at TMI-2
of $26 million and decontamination and decommissioning of nuclear enrichment
facilities of $28 million. Under terms of the NRC license, FirstEnergy is
required to monitor and maintain TMI-2 to ensure that there is no deterioration
of the facility. As required by the Energy Policy Act of 1992, FirstEnergy
participates in the decontamination and decommissioning of nuclear enrichment
facilities operated by the United States Department of Energy.
(F) STOCK-BASED COMPENSATION-
FirstEnergy applies the recognition and measurement principles of
Accounting Principles Board Opinion No. 25 (APB 25), "Accounting for Stock
Issued to Employees" and related Interpretations in accounting for its
stock-based compensation plans (see Note 4(B)). No material stock-based employee
compensation expense is reflected in net income as all options granted under
those plans had an exercise price equal to the market value of the underlying
common stock on the grant date, resulting in substantially no intrinsic value.
If FirstEnergy had accounted for employee stock options under the
fair value method of SFAS 123, "Accounting for Stock Compensation," a higher
value would have been assigned to the options granted. The weighted average
assumptions used in valuing the options and their resulting estimated fair
values would be as follows:
2003 2002 2001
-------------------------------------------------------------
Valuation assumptions:
Expected option term (years). 7.9 8.1 8.3
Expected volatility.......... 26.91% 23.31% 23.45%
Expected dividend yield...... 5.09% 4.36% 5.00%
Risk-free interest rate...... 3.67% 4.60% 4.67%
Fair value per option.......... $5.09 $6.45 $4.97
-------------------------------------------------------------
The effects of applying fair value accounting to the FirstEnergy's
stock options would not materially affect the Company's net income.
(G) INCOME TAXES-
Details of the total provision for income taxes are shown on the
Consolidated Statements of Taxes. The Company records income taxes in accordance
with the liability method of accounting. Deferred income taxes reflect the net
tax effect of temporary differences between the carrying amounts of assets and
liabilities for financial reporting purposes and the amounts used for tax
purposes. Investment tax credits, which were deferred when utilized, are being
amortized over the recovery period of the related property. Deferred income tax
liabilities related to tax and accounting basis differences and tax credit
carryforward items are recognized at the statutory income tax rates in effect
when the liabilities are expected to be paid. Results for the period January 1,
2001 through November 6, 2001 were included in the final consolidated federal
income tax return of GPU, and results for the period November 7, 2001 through
December 31, 2001 were included in FirstEnergy's 2001 consolidated federal
income tax return. The consolidated tax liability is allocated on a
"stand-alone" company basis, with the Company recognizing the tax benefit for
any tax losses or credits it contributes to the consolidated return.
22
(H) PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
FirstEnergy provides noncontributory defined benefit pension plans
that cover substantially all of the Company's employees. The trusteed plans
provide defined benefits based on years of service and compensation levels.
FirstEnergy's funding policy is based on actuarial computations using the
projected unit credit method. No pension contributions were required during the
three years ended December 31, 2003.
FirstEnergy provides a minimum amount of noncontributory life
insurance to retired employees in addition to optional contributory insurance.
Health care benefits, which include certain employee contributions, deductibles
and copayments, are also available to retired employees, their dependents and,
under certain circumstances, their survivors. The Company recognizes the
expected cost of providing other postretirement benefits to employees and their
beneficiaries and covered dependents from the time employees are hired until
they become eligible to receive those benefits.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions made to the plans, and earnings on plan assets. Such factors may
be further affected by business combinations (such as 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 and pension and OPEB costs. FirstEnergy uses a
December 31 measurement date for the majority of its plans.
Plan amendments to retirement health care benefits in 2003 and 2002,
relate to changes in benefits provided and cost-sharing provisions, which
reduced FirstEnergy's obligation by $123 and $121 million, respectively. In
early 2004, FirstEnergy announced that it would amend the benefit provisions of
its health care benefits plan and both employees and retirees would share in
more of the benefit costs.
On December 8, 2003, President Bush signed into law a bill that
expands Medicare, primarily adding a prescription drug benefit for
Medicare-eligible retirees starting in 2006. FirstEnergy anticipates that the
benefits it pays after 2006 will be lower as a result of the new Medicare
provisions. Due to uncertainties surrounding some of the new Medicare provisions
and a lack of authoritative accounting guidance about these issues, FirstEnergy
deferred the recognition of the impact of the new Medicare provisions as
provided by FASB Staff Position 106-1. The final accounting guidance could
require changes to previously reported information.
The following sets forth the funded status of the plans and amounts
recognized on FirstEnergy's Consolidated Balance Sheets as of December 31:
Obligations and Funded Status Pension Benefits Other Benefits
---------------- --------------
As of December 31 2003 2002 2003 2002
------------------------------------------------------------------------------------------
(In millions)
Change in benefit obligation
Benefit obligation at beginning of year.. $3,866 $3,548 $ 2,077 $ 1,582
Service cost............................. 66 59 43 28
Interest cost............................ 253 249 136 114
Plan participants' contributions......... -- -- 6 --
Plan amendments.......................... -- -- (123) (121)
Actuarial loss........................... 222 268 323 440
GPU acquisition (Note 2)................. -- (12) -- 110
Benefits paid............................ (245) (246) (94) (76)
------ ------ ------- -------
Benefit obligation at end of year........ $4,162 $3,866 $ 2,368 $ 2,077
====== ====== ======= =======
Change in fair value of plan assets
Fair value of plan assets at beginning
of year................................ $2,889 $3,484 $ 473 $ 535
Actual return on plan assets............. 671 (349) 88 (57)
Company contribution..................... -- -- 68 31
Plan participants' contribution.......... -- -- 2 --
Benefits paid............................ (245) (246) (94) (36)
------ ------ ------- -------
Fair value of plan assets at end of year. $3,315 $2,889 $ 537 $ 473
====== ====== ======= =======
Funded status............................ $ (847) $ (977) $(1,831) $(1,604)
Unrecognized net actuarial loss.......... 919 1,186 994 752
Unrecognized prior service cost (benefit) 72 78 (221) (107)
Unrecognized net transition obligation... -- -- 83 92
------ ------ ------- -------
Net asset (liability) recognized......... $ 144 $ 287 $ (975) $ (867)
====== ====== ======= =======
23
Amounts Recognized in the
Consolidated Balance Sheets
As of December 31
----------------------------------------
Accrued benefit cost..................... $(438) $(548) $(975) $(867)
Intangible assets........................ 72 78 -- --
Accumulated other comprehensive loss..... 510 757 -- --
----- ----- ------ -----
Net amount recognized.................... $ 144 $ 287 $(975) $(867)
===== ===== ===== =====
Company's share of net amount recognized. $ 13 $ -- $ (89) $ --
===== ===== ===== =====
Increase (decrease) in minimum liability
included in other comprehensive income
(net of tax)........................... $(145) $ 444 $ -- $ --
Weighted-Average Assumptions Used
to Determine Benefit Obligations
As of December 31
----------------------------------------
Discount rate........................... 6.25% 6.75% 6.25% 6.75%
Rate of compensation increase........... 3.50% 3.50%
Allocation of Plan Assets
As of December 31
----------------------------------------
Asset Category
Equity securities..................... 70% 61% 71% 58%
Debt securities....................... 27 35 22 29
Real estate........................... 2 2 -- --
Other................................. 1 2 7 13
--- ---- ----- ----
Total................................. 100% 100% 100% 100%
=== === === ===
Information for Pension Plans With an
Accumulated Benefit Obligation in
Excess of Plan Assets 2003 2002
----------------------------------------- ---- ----
(In millions)
Projected benefit obligation............. $4,162 $3,866
Accumulated benefit obligation........... 3,753 3,438
Fair value of plan assets................ 3,315 2,889
FirstEnergy's net pension and other postretirement benefit costs for
the three years ended December 31, 2003 were computed as follows:
Pension Benefits Other Benefits
---------------------- --------------------
Components of Net Periodic Benefit Costs 2003 2002 2001 2003 2002 2001
---------------------------------------------------------------------------------------------
(In millions)
Service cost............................ $ 66 $ 59 $ 35 $ 43 $ 29 $ 18
Interest cost........................... 253 249 133 137 114 65
Expected return on plan assets.......... (248) (346) (205) (43) (52) (10)
Amortization of prior service cost...... 9 9 9 (9) 3 3
Amortization of transition obligation (asset) -- -- (2) 9 9 9
Recognized net actuarial loss........... 62 -- -- 40 11 5
Voluntary early retirement program...... -- -- 6 -- -- 2
----- ------ ----- ----- ---- -----
Net periodic cost (income).............. $ 142 $ (29) $ (24) $ 177 $114 $ 92
===== ===== ===== ===== ==== =====
Company's share of net benefit costs (income)
(see Note 7)
Weighted-Average Assumptions Used
to Determine Net Periodic Benefit Cost
for Years Ended December 31
---------------------------------------
Discount rate.......................... 6.75% 7.25% 7.75% 6.75% 7.25% 7.75%
Expected long-term return on plan assets 9.00% 10.25% 10.25% 9.00% 10.25% 10.25%
Rate of compensation increase.......... 3.50% 4.00% 4.00%
In selecting an assumed discount rate, FirstEnergy considers
currently available rates of return on high-quality fixed income investments
expected to be available during the period to maturity of the pension and other
postretirement benefit obligations. The assumed rate of return on pension plan
assets considers historical market returns and economic forecasts for the types
of investments held by the Company's pension trusts. The long-term rate of
return is developed considering the portfolio's asset allocation strategy.
24
Assumed health care cost trend rates
As of December 31 2003 2002
- ------------------------------------------------------------------------------
Health care cost trend rate assumed for next
year (pre/post-Medicare).......................... 10%-12% 10%-12%
Rate to which the cost trend rate is assumed to
decline (the ultimate trend rate)................. 5% 5%
Year that the rate reaches the ultimate trend
rate (pre/post-Medicare).......................... 2009-2011 2008-2010
Assumed health care cost trend rates have a significant effect on the
amounts reported for the health care plans. A one-percentage-point change in
assumed health care cost trend rates would have the following effects:
1-Percentage- 1-Percentage-
Point Increase Point Decrease
- --------------------------------------------------------------------------------
(In millions)
Effect on total of service and interest cost.. $ 26 $ (19)
Effect on postretirement benefit obligation... $233 $(212)
FirstEnergy employs a total return investment approach whereby a mix
of equities and fixed income investments are used to maximize the long-term
return of plan assets for a prudent level of risk. Risk tolerance is established
through careful consideration of plan liabilities, plan funded status, and
corporate financial condition. The investment portfolio contains a diversified
blend of equity and fixed-income investments. Furthermore, equity investments
are diversified across U.S. and non-U.S. stocks, as well as growth, value, and
small and large capitalizations. Other assets such as real estate are used to
enhance long-term returns while improving portfolio diversification. Derivatives
may be used to gain market exposure in an efficient and timely manner; however,
derivatives are not used to leverage the portfolio beyond the market value of
the underlying investments. Investment risk is measured and monitored on a
continuing basis through periodic investment portfolio reviews, annual liability
measurements, and periodic asset/liability studies.
As a result of GPU Service Inc. (GPUS) merging with FirstEnergy
Service Company (FESC) in the second quarter of 2003, operating company
employees of GPU Service were transferred to the former GPU operating companies.
Accordingly, FirstEnergy requested an actuarial study to update the pension
liabilities for each of its subsidiaries. Based on the actuary's report, the
accrued pension costs for the Company as of June 30, 2003 increased by $79
million. The corresponding adjustment related to this change decreased other
comprehensive income and deferred income taxes and increased the payable to
associated companies.
Due to the increased market value of our pension plan assets, the
Company reduced its minimum liability as prescribed by SFAS 87 as of December
31, 2003 by $22 million, recording an increase of $59,000 in an intangible asset
and crediting OCI by $13 million (offsetting previously recorded deferred tax
benefits by $9 million). The remaining balance in OCI of $48 million will
reverse in future periods to the extent the fair value of trust assets exceeds
the accumulated benefit obligation. The accrued pension cost was reduced to $68
million as of December 31, 2003.
FirstEnergy does not expect to contribute to its pension plans in
2004 and expects to contribute $16 million to its other postretirement benefit
plans in 2004.
(I) GOODWILL-
In a business combination, excess of the purchase price over the
estimated fair values of the assets acquired and liabilities assumed is
recognized as goodwill. Under SFAS 142, "Goodwill and Other Intangible Assets,"
amortization of existing goodwill ceased January 1, 2002. Instead, the Company
evaluates its goodwill for impairment at least annually and makes such an
evaluation more frequently if indicators of impairment should arise. In
accordance with the accounting standard, if the fair value of a reporting unit
is less than its carrying value (including goodwill), the goodwill is tested for
impairment. When impairment is indicated, the Company would recognize a loss -
calculated as the difference between the implied fair value of its goodwill and
the carrying value of the goodwill indicated. The Company's annual review was
completed in the third quarter of 2003, with no impairment of goodwill
indicated. The forecasts used in the Company'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 December 31, 2003, the Company had recorded
goodwill of $2.0 billion related to the merger.
(J) TRANSACTIONS WITH AFFILIATED COMPANIES-
Operating revenues, operating expenses and other income included
transactions with affiliated companies, primarily FESC, GPUS and FirstEnergy
Solutions (FES). GPUS (until it ceased operations in mid-2003) and FESC have
provided legal, accounting, financial and other services to the Company. The
25
Company also entered into sale and purchase transactions with affiliates (Met-Ed
and Penelec) during the period. Through the BGS auction process, FES is a
supplier of power to the Company. See Note 7 for further discussion of
transactions with affiliated companies.
FirstEnergy does not bill directly or allocate any of its costs to
any subsidiary company. Costs are allocated to the Company from its affiliates,
GPUS and FESC, both subsidiaries of FirstEnergy Corp. and both "mutual service
companies" as defined in Rule 93 of the Public Utility Holding Company Act of
1935 (PUHCA). The majority of costs are directly billed or assigned at no more
than cost as determined by PUHCA Rule 91. The remaining costs are for services
that are provided on behalf of more than one company, or costs that cannot be
precisely identified and are allocated using formulas that are filed annually
with the SEC on Form U-13-60. The current allocation or assignment formulas used
and their bases include multiple factor formulas: each company's proportionate
amount of FirstEnergy's aggregate direct payroll, number of employees, asset
balances, revenues, number of customers, other factors and specific departmental
charge ratios. Management believes that these allocation methods are reasonable.
Intercompany transactions with FirstEnergy and its other subsidiaries are
generally settled under commercial terms within 30 day, except for a net $26
million receivable from affiliates for pension and OPEB obligations.
(K) CASH AND FINANCIAL INSTRUMENTS-
All temporary cash investments purchased with an initial maturity of
three months or less are reported as cash equivalents on the Consolidated
Balance Sheets at cost, which approximates their fair market value.
All borrowings with initial maturities of less than one year are
defined as financial instruments under GAAP and are reported on the Consolidated
Balance Sheets at cost, which approximates their fair market value. The
following sets forth the approximate fair value and related carrying amounts of
all other long-term debt, preferred stock subject to mandatory redemption and
investments other than cash and cash equivalents as of December 31:
2003 2002
- ----------------------------------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Value Value Value Value
(In millions)
Long-term debt.................................. $1,273 $1,190 $1,374 $1,415
Preferred stock................................. $ -- $ -- $ 125 $ 127
Investments other than cash and cash equivalents $ 283 $ 283 $ 258 $ 258
- ----------------------------------------------------------------------------------------------------------
The fair values of long-term debt and preferred stock reflect the
present value of the cash outflows relating to those securities based on the
current call price, the yield to maturity or the yield to call, as deemed
appropriate at the end of each respective year. The yields assumed were based on
securities with similar characteristics offered by corporations with credit
ratings similar to the Company's ratings. In 2001, long-term debt and preferred
stock subject to mandatory redemption were recognized at fair value in
connection with the merger.
The fair value of investments other than cash and cash equivalents
represents cost (which approximates fair value) or the present value of the cash
inflows based on the yield to maturity. The yields assumed were based on
financial instruments with similar characteristics and terms. Investments other
than cash and cash equivalents include decommissioning trust investments. The
Company has no securities held for trading purposes.
The investment policy for the nuclear decommissioning trust funds
restricts or limits the ability to hold certain types of assets including
private or direct placements, warrants, securities of FirstEnergy, investments
in companies owning nuclear power plants, financial derivatives, preferred
stocks, securities convertible into common stock and securities of the trust
fund's custodian or managers and their parents or subsidiaries. The investments
that are held in the decommissioning trusts (included as "Investments other than
cash and cash equivalents" in the table above) consist of equity securities ($69
million) and fixed income securities ($57 million) as of December 31, 2003.
Realized and unrealized gains and losses applicable to the decommissioning
trusts have been recognized in the trust investment with a corresponding change
to regulatory assets. For 2003 and 2002, net realized gains (losses) were
approximately $0.8 million and $(0.06) million and interest and dividend income
totaled approximately $3.8 million and $3.6 million, respectively.
On January 1, 2001, the Company adopted SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended by SFAS 138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities --
an amendment of FASB Statement No. 133." The adoption resulted in the
recognition of derivative assets on the Consolidated Balance Sheet as of January
1, 2001 in the amount of $21.8 million with offsetting amounts, net of tax,
recorded in Accumulated Other Comprehensive Income, of $5.1 million, and in
Regulatory Assets, of $13 million.
The Company is exposed to financial risks resulting from the
fluctuation of commodity prices, including electricity and natural gas. To
manage the volatility relating to these exposures, the Company uses a variety of
non-derivative and derivative instruments, including forward contracts, options
and futures contracts. These derivatives are used principally for hedging
26
purposes. The Company has a Risk Policy Committee, comprised of FirstEnergy
executive officers, which exercises an independent risk oversight function to
ensure compliance with corporate risk management policies and prudent risk
management practices.
The Company uses derivatives to hedge the risk of price fluctuations.
The Company's primary ongoing hedging activity involves cash flow hedges of
electricity and natural gas purchases. The majority of the Company's forward
commodity contracts are considered "normal purchases and sales," as defined by
SFAS 133, and are therefore excluded from the scope of SFAS 138. The forward
contracts, options and futures contracts determined to be within the scope of
SFAS 133 are accounted for as cash flow hedges and expire on various dates
through 2003. Gains and losses from hedges of commodity price risks are included
in net income when the underlying hedged commodities are delivered. The Company
may also use derivatives to hedge anticipated debt issuances or existing debt.
There was a net deferred loss of $3.9 million included in Accumulated Other
Comprehensive Loss as of December 31, 2003 which is primarily related to a cash
flow hedge of a 2003 debt issuance. This deferred loss is being amortized over
the fifteen year life of the related debt.
2. MERGER:
On November 7, 2001, the merger of FirstEnergy and GPU became
effective pursuant to the Agreement and Plan of Merger, dated August 8, 2000. As
a result of the merger, GPU's former wholly owned subsidiaries, including the
Company, became wholly owned subsidiaries of FirstEnergy.
The merger was accounted for by the purchase method of accounting.
The assets acquired and liabilities assumed were recorded at estimated fair
values as determined by FirstEnergy's management based on information currently
available and on current assumptions as to future operations. Merger purchase
accounting adjustments recorded in the records of the Company 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. Other assets and liabilities were not adjusted since they remain
subject to rate regulation on a historical cost basis. The excess of the
purchase price over the estimated fair values of the assets acquired and
liabilities assumed was recognized as goodwill.
During 2002 and 2003, certain pre-acquisition contingencies and other
final adjustments to the fair values of the assets acquired and liabilities
assumed were reflected in the final allocations of the purchase price. These
adjustments primarily related to: (1) final actuarial calculations related to
pension and postretirement benefit obligations and (2) return to accrual
adjustments for income taxes. As a result of these adjustments, goodwill
increased by approximately $74.3 million. As of December 31, 2003, the Company
had recorded goodwill of $2.0 billion related to the merger.
3. LEASES:
Consistent with regulatory treatment, the rentals for capital and
operating leases are charged to operating expenses on the Consolidated
Statements of Income. The Company's most significant operating lease relates to
the sale and leaseback of a portion of its ownership interest in the Merrill
Creek Reservoir project. The interest element related to this lease was $1.4
million, $1.2 million and $1.2 million for the years 2003, 2002 and 2001,
respectively.
As of December 31, 2003, the future minimum lease payments on the
Company's Merrill Creek operating lease, net of reimbursements from subleases,
are: $1.2 million, $1.7 million, $1.6 million, $1.6 million and $1.6 million for
the years 2004 through 2008, respectively, and $55.1 million for the years
thereafter. The Company is recovering its Merrill Creek lease payments, net of
reimbursements, through its distribution rates.
4. CAPITALIZATION:
(A) RETAINED EARNINGS-
The merger purchase accounting adjustments included resetting the
retained earnings balance to zero as of the November 7, 2001 merger date.
In general, the Company's first mortgage bond (FMB) indentures
restrict the payment of dividends or distributions on or with respect to the
Company's common stock to amounts credited to earned surplus since approximately
the date of its indenture. On that date, the Company had a $1.7 million balance
in its earned surplus account, which would not be available for dividends or
other distributions. As of December 31, 2003, the Company had retained earnings
available to pay common stock dividends of $20.4 million, net of amounts
restricted under the Company's FMB indentures.
27
(B) STOCK COMPENSATION PLANS-
FirstEnergy administers the FirstEnergy Executive and Director
Incentive Compensation Plan (FE Plan). Under the FE Plan, total awards cannot
exceed 22.5 million shares of common stock or their equivalent. Only stock
options and restricted stock have been granted, with vesting periods ranging
from six months to seven years. Several other stock compensation plans have been
acquired through the mergers with GPU and Centerior - GPU, Inc. Stock Option and
Restricted Stock Plan for MYR Group Inc. Employees (MYR Plan), 1990 Stock Plan
for Employees of GPU, Inc. and Subsidiaries (GPU Plan) and Centerior Equity
Plan. No further stock-based compensation can be awarded under these plans.
Collectively, the above plans are referred to as the FE Programs.
Restricted common stock grants under the FE Programs were as follows:
2003 2002 2001
--------------------------------------------------------------------------
Restricted common shares granted..... -- 36,922 133,162
Weighted average market price ........ n/a (1) $36.04 $35.68
Weighted average vesting period (years) n/a (1) 3.2 3.7
Dividends restricted.................. n/a (1) Yes -- (2)
--------------------------------------------------------------------------
(1) Not applicable since no restricted stock was granted.
(2) FE Plan dividends are paid as restricted stock on 4,500
shares
Under the Executive Deferred Compensation Plan (EDCP), covered
employees can direct a portion of their Annual Incentive Award and/or Long-Term
Incentive Award into an unfunded FirstEnergy Stock Account to receive vested
stock units. An additional 20% premium is received in the form of stock units
based on the amount allocated to the FirstEnergy Stock Account. Dividends are
calculated quarterly on stock units outstanding and are paid in the form of
additional stock units. Upon withdrawal, stock units are converted to
FirstEnergy shares. Payout typically occurs three years from the date of
deferral; however, an election can be made in the year prior to payout to
further defer shares into a retirement stock account that will pay out in cash
upon retirement. As of December 31, 2003, there were 410,399 stock units
outstanding.
Stock option activities under the FE Programs for the past three
years were as follows:
Number of Weighted Average
Stock Option Activities Options Exercise Price
--------------------------------------------------------------------------
Balance, January 1, 2001............... 5,021,862 $24.09
(473,314 options exercisable).......... 24.11
Options granted...................... 4,240,273 28.11
Options exercised.................... 694,403 24.24
Options forfeited.................... 120,044 28.07
Balance, December 31, 2001............. 8,447,688 26.04
(1,828,341 options exercisable)........ 24.83
Options granted...................... 3,399,579 34.48
Options exercised.................... 1,018,852 23.56
Options forfeited.................... 392,929 28.19
Balance, December 31, 2002............. 10,435,486 28.95
(1,400,206 options exercisable)........ 26.07
Options granted...................... 3,981,100 29.71
Options exercised.................... 455,986 25.94
Options forfeited.................... 311,731 29.09
Balance, December 31, 2003............. 13,648,869 29.27
(1,919,662 options exercisable)........ 29.67
As of December 31, 2003, the weighted average remaining contractual
life of outstanding stock options was 7.6 years.
Options outstanding by plan and range of exercise price as of
December 31, 2003 were as follows:
28
Range of Options
FirstEnergy Program Exercise Prices Outstanding
--------------------------------------------------------------------
FE plan $19.31 - $29.87 9,904,861
$30.17 - $35.15 3,214,601
Plans acquired through merger:
GPU plan $23.75 - $35.92 501,734
Other plans 27,673
-------------------------------------------------------------------
Total 13,648,869
===================================================================
No material stock-based employee compensation expense is reflected in
net income for stock options granted under the above plans since the exercise
price was equal to the market value of the underlying common stock on the grant
date. The effect of applying fair value accounting to FirstEnergy's stock
options is summarized in Note 1(F) - Stock-Based Compensation.
(C) PREFERRED AND PREFERENCE STOCK-
Preferred stock may be redeemed by the Company, in whole or in part,
with 30-90 days' notice.
(D) LONG-TERM DEBT-
The Company's FMB indenture, which secures all of the Company's FMBs,
serve as a direct first mortgage lien on substantially all of the Company's
property and franchises, other than specifically excepted property.
The Company has various debt covenants under its financing
arrangements. The most restrictive of these relate to the nonpayment of interest
and/or principal on debt, which could trigger a default. Cross-default
provisions also exist between FirstEnergy and the Company.
Based on the amount of bonds authenticated by the Trustee through
December 31, 2003 the Company's annual sinking fund requirements for all bonds
issued under the mortgage amount to $16 million. The Company expects to fulfill
its sinking fund obligation by providing refundable bonds to the Trustee.
Sinking fund requirements for FMBs and maturing long-term debt
(excluding capital leases) for the next five years are:
(In millions)
---------------------------------
2004................ $176
2005................ 67
2006................ 208
2007................ 18
2008................ 19
----------------------------------
(E) SECURITIZED TRANSITION BONDS-
On June 11, 2002, JCP&L Transition Funding LLC (Issuer), a wholly
owned limited liability company of the Company, sold $320 million of transition
bonds to securitize the recovery of the Company's bondable stranded costs
associated with the previously divested Oyster Creek Nuclear Generating Station.
The Company does not own nor did it purchase any of the transition
bonds, which are included in long-term debt on the Company'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 of a
utility company to charge, collect and receive from its customers, through a
non-bypassable TBC, the principal amount and interest on the transition bonds
and other fees and expenses associated with their issuance. The Company, as
servicer, manages and administers the bondable transition property, including
the billing, collection and remittance of the TBC, pursuant to a servicing
agreement with the Issuer. The Company is entitled to a quarterly servicing fee
of $100,000 that is payable from TBC collections.
(F) COMPREHENSIVE INCOME-
Comprehensive income includes net income as reported on the
Consolidated Statements of Income and all other changes in common stockholder's
equity except those resulting from transactions with the Company's parent. As of
29
December 31, 2003, accumulated other comprehensive loss consisted of unrealized
losses on derivative instrument hedges of $(3.9) million and a minimum liability
for unfunded retirement benefits of $(47.9) million.
5. SHORT-TERM BORROWINGS:
The Company may borrow from its affiliates on a short-term basis. As
of December 31, 2003, the Company had total short-term borrowings outstanding of
$231 million from its affiliates with an interest rate of 1.7%.
6. COMMITMENTS, GUARANTEES AND CONTINGENCIES:
(A) CAPITAL EXPENDITURES-
The Company's current forecast reflects expenditures of approximately
$446 million for property additions and improvements from 2004 through 2006, of
which approximately $146 million is applicable to 2004.
(B) NUCLEAR INSURANCE-
The Price-Anderson Act limits the public liability relative to a
single incident at a nuclear power plant to $10.9 billion. The amount is covered
by a combination of private insurance and an industry retrospective rating plan.
Based on its present ownership interest in TMI-2, the Company is exempt from any
potential assessment under the industry retrospective rating plan.
The Company is also insured as to its interest in TMI-2 under a
policy issued to the operating company for the plant. Under this policy, $150
million is provided for property damage and decontamination and decommissioning
costs. Under this policy, the Company can be assessed a maximum of approximately
$0.2 million for incidents at any covered nuclear facility occurring during a
policy year which are in excess of accumulated funds available to the insurer
for paying losses.
The Company intends to maintain insurance against nuclear risks as
described above as long as it is available. To the extent that property damage,
decontamination, decommissioning, repair and replacement costs and other such
costs arising from a nuclear incident at TMI-2 exceed the policy limits of the
insurance in effect with respect to that plant, to the extent a nuclear incident
is determined not to be covered by the Company's insurance policies, or to the
extent such insurance becomes unavailable in the future, the Company would
remain at risk for such costs.
(C) ENVIRONMENTAL MATTERS-
The Company has been named as a "potentially responsible party" (PRP)
at waste disposal sites which may require cleanup under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980. Allegations of
disposal of hazardous substances at historical sites and the liability involved
are often unsubstantiated and subject to dispute; however, federal law provides
that all PRPs for a particular site be held liable on a joint and several basis.
Therefore, potential environmental liabilities have been recognized on the
Consolidated Balance Sheet as of December 31, 2003, based on estimates of the
total costs of cleanup, the Company's proportionate responsibility for such
costs and the financial ability of other nonaffiliated entities to pay. In
addition, the Company has accrued liabilities for environmental remediation of
former manufactured gas plants in New Jersey; those costs are being recovered
through a non-bypassable societal benefits charge. The Company has total accrued
liabilities aggregating approximately $45.5 million as of December 31, 2003. The
Company accrues for environmental costs only when it can conclude that it is
probable that they have an obligation for such costs and can reasonably
determine the amount of such costs. Unasserted claims are reflected in the
Company's determination of environmental liabilities and are accrued in the
period that they are both probable and reasonably estimable. The Company does
not believe environmental remediation costs will have a material adverse effect
on its financial condition, cash flows or results of operations.
(D) OTHER LEGAL PROCEEDINGS-
Various lawsuits, claims and proceedings related to the Company's
normal business operations are pending against the Company, the most significant
of which are described below.
Power Outages
In July 1999, the Mid-Atlantic states experienced a severe heat storm
which resulted in power outages throughout the service territories of many
electric utilities, including JCP&L's territory. In an investigation into the
causes of the outages and the reliability of the transmission and distribution
systems of all four New Jersey electric utilities, the NJBPU concluded that
there was not a prima facie case demonstrating that, overall, JCP&L provided
unsafe, inadequate or improper service to its customers. Two class action
lawsuits (subsequently consolidated into a single proceeding) were filed in New
Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies,
seeking compensatory and punitive damages arising from the July 1999 service
interruptions in the JCP&L territory.
30
Since July 1999, this litigation has involved a substantial amount of
legal discovery including interrogatories, request for production of documents,
preservation and inspection of evidence, and depositions of the named plaintiffs
and many JCP&L employees. In addition, there have been many motions filed and
argued by the parties involving issues such as the primary jurisdiction and
findings of the NJBPU, consumer fraud by JCP&L, strict product liability, class
decertification, and the damages claimed by the plaintiffs. In January 2000, the
NJ Appellate Division determined that the trial court has proper jurisdiction
over this litigation. In August 2002, the trial court granted partial summary
judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud,
common law fraud, negligent misrepresentation, and strict products liability. In
November 2003, the trial court granted JCP&L's motion to decertify the class and
denied plaintiffs' motion to permit into evidence their class-wide damage model
indicating damages in excess of $50 million. These class decertification and
damage rulings have been appealed to the Appellation Division and oral argument
is scheduled for May 2004. FirstEnergy is unable to predict the outcome of these
matters and no liability has been accrued as of December 31, 2003.
On August 14, 2003, various states and parts of southern Canada
experienced a widespread power outage. That outage affected approximately 1.4
million customers in FirstEnergy's service area. FirstEnergy continues to
accumulate data and evaluate the status of its electrical system prior to and
during the outage event, and continues to cooperate with the U.S.-Canada Power
System Outage Task Force (Task Force) investigating the August 14th outage. The
interim report issued by the Task Force on November 18, 2003 concluded that the
problems leading to the outage began in FirstEnergy's service area.
Specifically, the interim report concludes, among other things, that the
initiation of the August 14th outage resulted from the coincidence on that
afternoon of the following events: (1) inadequate situational awareness at
FirstEnergy; (2) FirstEnergy's failure to adequately manage tree growth in its
transmission rights of way; and (3) failure of the interconnected grid's
reliability organizations (Midwest Independent System Operator and PJM
Interconnection) to provide effective diagnostic support. FirstEnergy believes
that the interim report does not provide a complete and comprehensive picture of
the conditions that contributed to the August 14th outage and that it does not
adequately address the underlying causes of the outage. FirstEnergy remains
convinced that the outage cannot be explained by events on any one utility's
system. On November 25, 2003, the Public Utilities Commission of Ohio (PUCO)
ordered FirstEnergy to file a plan with the PUCO no later than March 1, 2004,
illustrating how FirstEnergy will correct problems identified by the Task Force
as events contributing to the August 14th outage and addressing how FirstEnergy
proposes to upgrade its control room computer hardware and software and improve
the training of control room operators to ensure that similar problems do not
occur in the future. The PUCO, in consultation with the North American Electric
Reliability Council, will review the plan before determining the next steps in
the proceeding. On December 24, 2003, the FERC ordered FirstEnergy to pay for an
independent study of part of Ohio's power grid. The study is to examine the
stability of the grid in critical points in the Cleveland and Akron areas; the
status of projected power reserves during summer 2004 through 2008; and the need
for new transmission lines or other grid projects. The FERC ordered the study to
be completed within 120 days. At this time, it is unknown what the cost of such
study will be, or the impact of the results.
7. OTHER INFORMATION:
The following represents the financial data which includes
supplemental unaudited prior years' information as compared to consolidated
financial statements and notes previously reported in 2001.
(A) CONSOLIDATED STATEMENTS OF CASH FLOWS
Nov. 7- Jan. 1-
Dec. 31, Nov. 6,
2003 2002 2001 2001
---- ---- ---- ----
(Unaudited) (Unaudited)
(In thousands)
Other Cash Flows from Operating Activities:
Accrued taxes............................. $(12,925) $(21,939) $ 2,675 | $ 24,272
Accrued interest.......................... (12,319) 1,625 9,501 | (7,590)
Prepayments and other..................... (11,640) (21,149) 16,436 | 63,909
All other................................. 42,463 66,896 (8,049) | (14,263)
--------- ---------- --------- | ----------
Other cash provided from |
operating activities................. $ 5,579 $ 25,433 $20,563 | $ 66,328
========= ========= ======= | ========
(B) REVENUES - INDEPENDENT SYSTEM OPERATOR (ISO) TRANSACTIONS
The Company records purchase and sales transactions with PJM
Interconnection ISO, an independent system operator, on a gross basis in
accordance with EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal
versus Net as an Agent." The aggregate purchase and sales transactions for the
three years ended December 31, 2003, are summarized as follows:
31
Nov. 7- Jan. 1-
Dec. 31, Nov. 6,
2003 2002 2001 2001
------------------------------------------------------------------------
(Unaudited) (Unaudited)
(In millions)
|
Sales.......... $270 $136 $ 2 | $ 28
Purchases...... -- 101 16 | 188
------------------------------------------------------------------------
The Company's revenues on the Consolidated Statements of Income
include wholesale electricity sales revenues from the PJM ISO from power sales
(as reflected in the table above) during periods when the Company had additional
available power capacity. Revenues also include sales by the Company of power
sourced from the PJM ISO (reflected as purchases in the table above) during
periods when the Company required additional power to meet its retail load
requirements.
(C) TRANSACTIONS WITH AFFILIATED COMPANIES-
The primary affiliated companies transactions are as follows:
Nov. 7- Jan. 1-
Dec. 31, Nov. 6,
2003 2002 2001 2001
- -------------------------------------------------------------------------------
(Unaudited) (Unaudited)
(In millions)
Operating Revenues:
Wholesale sales-affiliated companies. $ 36 $ 18 $ 2 | $ 17
|
Operating Expenses: |
Service Company support services..... 101 140 21 | 120
Power purchased from other affiliates -- 26 3 | 16
Power purchased from FES............. 55 18 8 | --
- -------------------------------------------------------------------------------
(D) RETIREMENTS BENEFITS (1)
Net pension and other postretirement benefit costs (income) for the
three years ended December 31, 2003 are approximately as follows:
Nov. 7- Jan. 1-
Dec. 31, Nov. 6,
2003 2002 2001 2001
- ------------------------------------------------------------------------------
(Unaudited) (Unaudited)
(In millions)
|
Pension Benefits.................... $12 $(20) $(7) | $(33)
Other Postretirement Benefits....... 12 5 2 | 8
- ----------------------------------------------------------------------------
(1) Includes estimated portion of benefit costs included in billings from GPUS.
8. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS:
FIN 46 (revised December 2003), "Consolidation of Variable
Interest Entities"
In December 2003, the FASB issued a revised interpretation of
Accounting Research Bulletin No. 51, "Consolidated Financial Statements." FASB
Interpretation No. 46, "Consolidation of Variable Interest Entities", referred
to as "FIN 46R", requires the consolidation of a VIE by an enterprise if that
enterprise is determined to be the primary beneficiary of the VIE. FIN 46R
requires adoption for interests in VIEs or potential VIEs commonly referred to
as special-purpose entities effective December 31, 2003. Adoption of FIN 46R for
all other types of entities is effective March 31, 2004.
The Company is evaluating entities that meet the deferral criteria
and may be subject to consolidation under FIN 46R as of March 31, 2004. These
entities are non-utility generators in which we have neither debt nor equity
investments but are generally the sole purchaser of their power.
32
SFAS 143, "Accounting for Asset Retirement Obligations"
In January 2003, the Company implemented SFAS 143 which provides
accounting standards for retirement obligations associated with tangible
long-lived assets. This statement requires recognition of the fair value of a
liability for an asset retirement obligation in the period in which it is
incurred. See Note 1(E) for further discussions of SFAS 143.
DIG Implementation Issue No. C20 for SFAS 133, "Scope Exceptions:
Interpretation of the Meaning of Not Clearly and Closely Related in
Paragraph 10(b) Regarding Contracts with a Price Adjustment Feature"
In June 2003, the FASB cleared DIG Issue C20 for implementation in
fiscal quarters beginning after July 10, 2003. The issue supersedes earlier DIG
Issue C11, "Interpretation of Clearly and Closely Related in Contracts That
Qualify for the Normal Purchases and Normal Sales Exception." DIG Issue C20
provides guidance regarding when the presence of a general index, such as the
Consumer Price Index, in a contract would prevent that contract from qualifying
for the normal purchases and normal sales exception under SFAS 133, as amended,
and therefore exempt from the mark-to-market treatment of certain contracts.
Adoption of DIG Issue C20 did not impact JCP&L's financial statements.
9. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
The quarterly financial information for the first three quarters of
2003 have been restated to correct costs that should have been capitalized to
construction projects but were improperly recorded as operating expenses. These
corrections have resulted in restated earnings increases of $0.1 million, $1.8
million and $3.4 million during the quarters ended March 31, 2003, June 30, 2003
and September 30, 2003, respectively.The impact of these adjustments was not
material to the Company's consolidated balance sheets or consolidated statements
of cash flows for any quarter of 2003. The following summarizes certain
consolidated operating results by quarter for 2003 and 2002.
Three Months Ended March 31, 2003 June 30, 2003(a) September 30, 2003 December 31, 2003
- ------------------------------------------------------------------------------------------------------------------
As Previously As As Previously As As Previously As
Reported Restated Reported Restated Reported Restated
-------- -------- -------- -------- -------- --------
(In millions)
Operating Revenues......... $656.9 $656.9 $542.8 $542.8 $743.1 $743.1 $421.4
Operating Expenses and
Taxes................... 581.7 581.6 566.3 564.5 659.5 656.1 415.7
- ------------------------------------------------------------------------------------------------------------
Operating Income (Loss).... 75.2 75.3 (23.5) (21.7) 83.6 87.0 5.7
Other Income .............. 1.2 1.2 2.3 2.3 1.1 1.1 2.9
Net Interest Charges....... 22.5 22.5 22.4 22.4 20.5 20.5 20.4
- ------------------------------------------------------------------------------------------------------------
Net Income (Loss).......... $ 53.9 $ 54.0 $(43.6) $(41.8) $ 64.2 $ 67.6 $(11.8)
=============================================================================================================
Earnings (Loss) Applicable
to Common Stock......... $ 53.8 $ 53.9 $(43.2) $(41.4) $ 64.0 $ 67.4 $(11.9)
=============================================================================================================
March 31, June 30, September 30, December 31,
Three Months Ended 2002 2002 2002 2002
- -------------------------------------------------------------------------------------------------------------
(In millions)
Operating Revenues.......................... $450.7 $501.3 $779.9 $596.5
Operating Expenses and Taxes................ 389.4 423.1 658.6 522.1
- -------------------------------------------------------------------------------------------------------------
Operating Income............................ 61.3 78.2 121.3 74.4
Other Income ............................... 2.8 2.2 1.2 1.5
Net Interest Charges........................ 24.1 23.0 21.8 22.1
- -------------------------------------------------------------------------------------------------------------
Net Income.................................. $ 40.0 $ 57.4 $100.7 $ 53.8
=============================================================================================================
Earnings on Common Stock.................... $ 39.2 $ 57.0 $103.5 $ 53.7
=============================================================================================================
(a) The net loss for the second quarter of 2003 included a charge resulting
from the NJBPU's decision to disallow recovery by the Company of $153
million in deferred energy costs.
33
Report of Independent Auditors
To the Stockholders and Board of Directors of
Jersey Central Power & Light Company:
In our opinion, the accompanying consolidated balance sheets and consolidated
statements of capitalization and the related consolidated statements of income,
common stockholder's equity, preferred stock, cash flows and taxes present
fairly, in all material respects, the financial position of Jersey Central Power
& Light Company (a wholly owned subsidiary of FirstEnergy Corp.) and
subsidiaries as of December 31, 2003 and 2002 and the results of their
operations and their cash flows for the years then ended in conformity with
accounting principles generally accepted in the United States of America. These
financial statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States of America, which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion. The consolidated financial statements of
Jersey Central Power & Light Company and subsidiaries for the period from
January 1, 2001 to November 6, 2001 (pre-merger) and the period from November 7,
2001 to December 31, 2001 (post-merger) were audited by other independent
auditors who have ceased operations. Those independent auditors expressed an
unqualified opinion on those financial statements in their report dated March
18, 2002.
As discussed in Note 1(E) to the consolidated financial statements, the Company
changed its method of accounting for asset retirement obligations as of January
1, 2003.
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 25, 2004
34
The following report is a copy of a report previously issued by Arthur Andersen
LLP (Andersen). This report has not been reissued by Andersen and Andersen did
not consent to the incorporation by reference of this report into any of the
Company's registration statements.
Report of Previous Independent Public Accountants
To the Stockholders and Board of Directors of
Jersey Central Power & Light Company:
We have audited the accompanying consolidated balance sheet and consolidated
statement of capitalization of Jersey Central Power & Light Company (a New
Jersey corporation and wholly owned subsidiary of FirstEnergy Corp.) and
subsidiaries as of December 31, 2001 (post-merger), and the related consolidated
statements of income, common stockholder's equity, preferred stock, cash flows
and taxes for the period from January 1, 2001 to November 6, 2001 (pre-merger)
and the period from November 7, 2001 to December 31, 2001 (post-merger). These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audit. The financial statements of Jersey Central Power & Light Company and
subsidiary as of December 31, 2000 and for each of the two years in the period
ended December 31, 2000 (pre-merger), were audited by other auditors whose
report dated January 31, 2001, expressed an unqualified opinion on those
statements.
We conducted our audit in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audit provides a reasonable basis for our
opinion.
In our opinion, the 2001 financial statements referred to above present fairly,
in all material respects, the financial position of Jersey Central Power & Light
Company and subsidiaries as of December 31, 2001 (post-merger), and the results
of their operations and their cash flows for the period from January 1, 2001 to
November 6, 2001 (pre-merger) and the period from November 7, 2001 to December
31, 2001 (post-merger), in conformity with accounting principles generally
accepted in the United States.
ARTHUR ANDERSEN LLP
Cleveland, Ohio,
March 18, 2002.
35