EXHIBIT 13.5
JERSEY CENTRAL POWER & LIGHT COMPANY
2001 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 is being
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.............................. 2-8
Consolidated Statements of Income................................. 9
Consolidated Balance Sheets....................................... 10
Consolidated Statements of Capitalization......................... 11
Consolidated Statements of Common Stockholder's Equity............ 12
Consolidated Statements of Preferred Stock........................ 12
Consolidated Statements of Cash Flows............................. 13
Consolidated Statements of Taxes.................................. 14
Notes to Consolidated Financial Statements........................ 15-23
Reports of Independent Public Accountants......................... 24-25
JERSEY CENTRAL POWER & LIGHT COMPANY
SELECTED FINANCIAL DATA
Years Ended December 31,
Nov. 7 - Jan. 1 - -----------------------------------------------
Dec. 31, 2001 Nov. 6, 2001 2000 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------------
(Dollars in thousands)
Operating Revenues..................... $ 282,902 | $ 1,838,638 $1,979,297 $2,018,209 $2,069,648 $2,093,972
========== | =========== ========== ========== ========== ==========
|
Operating Income....................... $ 43,666 | $ 292,847 $ 283,227 $ 277,420 $ 297,614 $ 324,850
========== | =========== ========== ========== ========== ==========
|
Income Before Extraordinary Item....... $ 30,041 | $ 34,467 $ 210,812 $ 172,380 $ 222,442 $ 212,014
========== | =========== ========== ========== ========== ==========
|
Net Income ............................ $ 30,041 | $ 34,467 $ 210,812 $ 172,380 $ 222,442 $ 212,014
========== | =========== ========== ========== ========== ==========
|
Earnings on Common Stock............... $ 29,343 | $ 29,920 $ 203,908 $ 162,862 $ 212,377 $ 200,638
========== | =========== ========== ========== ========== ==========
|
Total Assets........................... $8,039,998 | $6,009,054 $5,587,677 $4,382,073 $4,459,306
========== | ========== ========== ========== ==========
|
Capitalization: |
Common Stockholder's Equity............ $3,163,701 | $1,459,260 $1,385,367 $1,557,073 $1,540,121
Preferred Stock- |
Not Subject to Mandatory Redemption. 12,649 | 12,649 12,649 37,741 37,741
Subject to Mandatory Redemption..... 44,868 | 51,500 73,167 86,500 91,500
Company-Obligated Mandatorily |
Redeemable Preferred Securities..... 125,250 | 125,000 125,000 125,000 125,000
Long-Term Debt......................... 1,224,001 | 1,093,987 1,133,760 1,173,532 1,173,304
---------- | ---------- ---------- ---------- ----------
Total Capitalization................... $4,570,469 | $2,742,396 $2,729,943 $2,979,846 $2,967,666
========== | ========== ========== ========== ==========
|
Capitalization Ratios: |
Common Stockholder's Equity............ 69.2%| 53.2% 50.7% 52.2% 51.9%
Preferred Stock- |
Not Subject to Mandatory Redemption. 0.3 | 0.5 0.5 1.3 1.3
Subject to Mandatory Redemption..... 1.0 | 1.9 2.7 2.9 3.1
Company-Obligated Mandatorily |
Redeemable Preferred Securities..... 2.7 | 4.5 4.6 4.2 4.2
Long-Term Debt......................... 26.8 | 39.9 41.5 39.4 39.5
----- | ----- ----- ----- -----
Total Capitalization................... 100.0%| 100.0% 100.0% 100.0% 100.0%
===== | ===== ===== ===== =====
|
Transmission and Distribution |
Kilowatt-Hour Deliveries (Millions): |
Residential............................ 1,428 | 7,042 8,087 7,978 7,551 7,256
Commercial............................. 1,330 | 6,787 7,706 7,624 7,259 6,974
Industrial............................. 474 | 2,670 3,307 3,289 3,474 3,536
Other.................................. 17 | 66 82 81 81 79
----- | ------ ------ ------- ------ ------
Total Retail........................... 3,249 | 16,565 19,182 18,972 18,365 17,845
Total Wholesale........................ 295 | 1,780 2,161 1,622 1,690 1,063
----- | ------ ------ ------- ------ ------
Total.................................. 3,544 | 18,345 21,343 20,594 20,055 18,908
===== | ====== ====== ====== ====== ======
|
Transmission and Distribution Deliveries |
Customers Served: |
Residential............................ 909,494 | 896,629 883,930 872,134 859,747
Commercial............................. 109,985 | 107,479 107,210 105,611 104,183
Industrial............................. 2,785 | 2,835 2,965 3,014 3,054
Other.................................. 1,484 | 1,551 1,648 1,635 1,618
--------- | --------- --------- ------- -------
Total.................................. 1,023,748 | 1,008,494 995,753 982,394 968,602
========= | ========= ======= ======= =======
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 that is subject to certain risks and
uncertainties. Such 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, legislative and
regulatory changes (including revised environmental requirements), the
availability and cost of capital, ability to accomplish or realize anticipated
benefits from strategic initiatives and other similar factors.
Results of Operations
- ---------------------
Earnings on common stock decreased 70.9% to $59.3 million in 2001 from
$203.9 million in 2000. Results in 2001 were affected by an after-tax charge of
$177.5 million to reduce deferred costs in accordance with the Stipulation of
Settlement related to the merger of FirstEnergy and GPU, Inc. Also contributing
to lower earnings were higher purchased power costs. Partially offsetting these
were lower nuclear and other operating costs and greater revenues. In 2000,
earnings on common stock increased 25.2% to $203.9 million from $162.9 million
in 1999, primarily due to a gain for the reversal of certain deferred taxes and
realization of an investment tax credit related to the sale of the Oyster Creek
Nuclear Generating Station and the absence of a charge resulting from the
Summary Order issued by the New Jersey Board of Public Utilities (NJBPU) in
1999. Lower nuclear and other operating costs also positively affected results
for 2000.
Operating revenues increased by $142.2 million in 2001 following a $38.9
million decrease in 2000. The sources of the changes in operating revenues
during 2001 and 2000, as compared to the prior year, are summarized in the
following table.
Sources of Revenue Changes 2001 2000
-------------------------------------------------------------
Increase (Decrease) (In millions)
Change in kilowatt-hour sales due
to level of retail customers
shopping for generation service..........$ 67.3 $(108.7)
Change in other retail kilowatt-hour sales.. 38.4 (74.0)
Increase in wholesale sales................. 44.1 24.0
Provision for rate refunds.................. -- 112.2
All other changes........................... (7.6) 7.6
------------------------------------------------------------
Net Increase (Decrease) in Operating
Revenues................................. $142.2 $ (38.9)
==============================================================
Electric Sales
In 2001, a major source of the increase in operating revenues was the
increase in retail generation kilowatt-hour sales due to a large number of
customers returning to us in 2001 as full service customers, after receiving
their power from alternate suppliers in 2000. Residential and commercial sales
increased while industrial sales decreased. The majority of the increase in
residential sales was weather-related, whereas a greater number of commercial
customers and higher usage contributed almost evenly to the increase in
commercial sales. Industrial sales were lower than the previous year due to both
a decrease in the number of customers and lower usage.
A large decrease in operating revenues occurred in 2000, as compared to
1999, as customers took advantage of the first full year of customer choice in
New Jersey. In 2000, sales of electric generation provided by other suppliers
accounted for 11.7% of total energy delivered as compared to only 0.2% in 1999.
Partially offsetting the overall decrease in operating revenues was an increase
due to our obligation to refund revenues to customers in 1999 as a result of the
NJBPU's Restructuring Summary Order. The Order required us to refund customers
5% from rates in effect as of April 30, 1997. Changes in kilowatt-hour sales by
customer class in 2001 and 2000 are summarized in the following table:
2
Changes in Kilowatt-hour Sales 2001 2000
-------------------------------------------------
Increase (Decrease)
Residential.................. 4.7% 1.4%
Commercial................... 5.3% 1.1%
Industrial................... (4.9)% 0.5%
-------------------------------------------------
Total Retail................. 3.3% 1.1%
Wholesale.................... (4.0)% 33.2%
-------------------------------------------------
Total Sales.................. 2.6% 3.6%
-------------------------------------------------
Operating Expenses and Taxes
Total operating expenses and taxes increased $89.0 million in 2001 after
decreasing $44.7 million in 2000, compared to the preceding year. In both 2000
and 2001, greater purchased power costs accounted for the largest increases,
offset by lower nuclear and other operating costs. Depreciation and amortization
expenses also decreased in 2000 from 1999.
Fuel and purchased power costs increased $177.6 million in 2001,
compared to 2000. The increase was primarily attributed to greater amounts of
power purchased through both two-party agreements and through the PJM Power Pool
as a result of the sale of Oyster Creek and higher customer demand. Also
contributing to the increase was a higher average cost of two-party power
purchases in 2001 than in 2000. These increases were partially offset by lower
fuel costs due to the sale of Oyster Creek.
In 2000, fuel and purchased power costs increased $39.9 million from the
preceding year due to the need to purchase more power through two-party
agreements and the PJM Power Pool after the sale of our fossil fuel generating
facilities and Unit 1 of the Three Mile Island Nuclear Plant in 1999. The
average cost of these two-party purchases was also higher in 2000 than in 1999.
Additionally, the amortization of non-utility generation (NUG) buyout costs was
greater in 2000 than in 1999. Partially offsetting these increases were lower
fuel costs since Oyster Creek was owned for only part of 2000.
With the sale of Oyster Creek in August 2000, we no longer have any
nuclear operating costs, which were $78.5 million in 2000. The sale of Oyster
Creek was also responsible for the $71.3 million decrease in nuclear operating
costs in 2000, compared to 1999.
In 2001, other operating expenses decreased $25.2 million from the
previous year due to lower bad debt expense and pension costs. The sale of our
generating stations in 1999 was primarily responsible for the $29.8 million
decrease in 2000 other operating costs from the preceding year. Also
contributing to the reduction in costs was the receipt of additional cash
distributions in 2000, compared to 1999, related to Oyster Creek property
insurance.
Other Income
Other income decreased $199.8 million in 2001 from the prior year
primarily due to a 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. In 2000, other income increased $26.1
million from 1999. The increase was primarily due to higher interest income and
the reversal of an estimated 1999 tax penalty.
Net Interest Charges
Net interest charges decreased by $0.2 million in 2001 following a
decrease of $6.5 million in 2000 as compared to the prior year. In 2001, the
slight decrease was attributed to greater deferred interest income offset by
interest expense on $150 million of senior notes issued in May, and higher
average short-term debt levels. The decrease in 2000 was primarily due to
greater deferred interest income and lower interest expense as a result of the
redemption of $40 million of first mortgage bonds (FMB).
Preferred Stock Dividend Requirements
Preferred stock dividend requirements decreased $1.7 million and $1.8
million in 2001 and 2000, respectively, due to the redemption of cumulative
preferred stock pursuant to mandatory and optional sinking fund provisions.
Capital Resources and Liquidity
- -------------------------------
We had approximately $31.4 million of cash and temporary investments and
$18.1 million of short-term indebtedness on December 31, 2001. We may borrow
from our affiliates on a short-term basis. We will not issue FMBs
3
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, 2001, we had the capability to
issue $257 million of additional senior notes based upon FMB collateral. At year
end 2001, based upon applicable earnings coverage tests and our charter, we
could issue $4.6 billion of preferred stock (assuming no additional debt was
issued).
At the end of 2001, our common equity as a percentage of capitalization
stood at 69%, as compared to 53% at the end of 2000. This increase resulted from
the allocation of the purchase price in the merger between FirstEnergy and GPU.
Following approval of the merger of FirstEnergy and GPU by the NJBPU on
September 26, 2001, Standard and Poor's adjusted our corporate credit rating
from A/A1 to BBB/A-2, our senior secured debt rating from A+ to BBB+ and our
preferred stock rating from BBB+ to BB+. The lower credit ratings reflect
Standard & Poor's consolidated rating methodology, which resulted in essentially
the same corporate credit rating for all of FirstEnergy's electric utility
operating companies. The credit rating outlook of both Standard & Poor's and
Moody's is stable.
Our cash requirements in 2002 for operating expenses, construction
expenditures, scheduled debt maturities and preferred stock redemptions are
expected to be met without increasing our net debt and preferred stock
outstanding. Major contractual obligations for future cash payments are
summarized in the following table:
Contractual Obligations 2002 2003 2004 2005 2006 Thereafter Total
- ---------------------------------------------------------------------------
(In millions)
Long-term debt..........$ 50 $150 $160 $ 50 $240 $ 596 $1,246
Mandatory preferred
stock................. 11 11 11 2 2 139 176
Operating leases ....... 2 4 2 2 2 74 86
Unconditional fuel and
power purchases....... 861 535 468 458 455 2,202 4,979
- ---------------------------------------------------------------------------
$924 $700 $641 $512 $699 $3,011 $6,487
===========================================================================
Our capital spending for the period 2002-2006 is expected to be about
$572 million, of which approximately $144 million applies to 2002.
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 derivative instruments, including forward
contracts, options and futures contracts. These derivatives are used principally
for hedging purposes. The change in the fair value of commodity derivative
contracts related to energy production during 2001 is summarized in the table
below:
Increase (Decrease)in the Fair Value of Commodity Derivative Contracts
----------------------------------------------------------------------
Nov. 7-Dec. 31 Jan. 1-Nov. 6
2001 2001
----------------------------------------------------------------------
(In millions)
Outstanding as of beginning of
period with SFAS 133
cumulative adjustment............ $4.7 $23.4
Contract value when entered......... 0.1 4.9
Decrease in value of existing
contracts........................ (3.2) (12.9)
Change in techniques/assumptions.... -- (10.6)
Settled contracts................... (0.1) (0.1)
---------------------------------------------------------------------
Outstanding as of end of period..... $1.5 $4.7
=====================================================================
While the valuation of derivative contracts is always based on active
market prices when they are available, longer-term contracts can require the use
of model-based estimates of prices in later years due to the absence of
published market prices. Currently, substantially all of our derivatives are
valued based on active market prices.
4
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 our derivative instruments would not have had
a material effect on our consolidated financial position or cash flows as of
December 31, 2001.
Interest Rate Risk
Our exposure to fluctuations in market interest rates is reduced since a
significant portion of our debt has fixed interest rates, as noted in the table
below. We are subject to the inherent interest rate risks related to refinancing
maturing debt by issuing new debt securities. Changes in the market value of our
nuclear decommissioning trust funds are recognized by making corresponding
changes to the decommissioning liability, as described in Note 1 to the
consolidated financial statements.
Comparison of Carrying Value to Fair Value
- --------------------------------------------------------------------------------
There- Fair
2002 2003 2004 2005 2006 after Total Value
- --------------------------------------------------------------------------------
(Dollars in millions)
Investments other
than Cash and
Cash Equivalents:
Fixed Income.......... -- -- -- -- -- $187 $ 187 $ 185
Average interest
rate.............. 5.4% 5.4%
- --------------------------------------------------------------------------------
________________________________________________________________________________
Liabilities
- --------------------------------------------------------------------------------
Long-term Debt:
Fixed rate............ $ 50 $150 $160 $ 50 $240 $596 $1,246 $1,250
Average interest
rate.............. 9.0% 6.4% 7.1% 6.8% 6.9% 7.8% 7.4%
Variable rate.........
Average interest
rate..............
Short-term
Borrowings.......... $ 18 -- -- -- -- -- $ 18 $ 18
Average interest
rate.............. 4.9% 4.9%
- --------------------------------------------------------------------------------
Preferred Stock..... $ 11 $ 11 $ 11 $ 2 $ 2 $139 $ 176 $ 180
Average dividend
rate.............. 8.4% 8.4% 8.4% 7.5% 7.5% 8.5% 8.4%
- --------------------------------------------------------------------------------
Outlook
- -------
Our industry continues to transition to a more competitive environment.
Beginning in late 1999, all of our customers could 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 (confirmed by a NJBPU Final
Decision and Order issued in March 2001). We have a continuing responsibility to
provide power to those customers not choosing to receive power from an
alternative energy supplier, subject to certain limits, referred to as Basic
Generation Service (BGS), until July 31, 2002.
Regulatory Matters
For the period from August 1, 2002 to July 31, 2003, the NJBPU has
authorized the auctioning of BGS to meet the electric demands of customers who
have not selected an alternative supplier. The auction was successfully
concluded on February 13, 2002, thereby eliminating our obligation to provide
for the energy requirements of BGS during that period. Beginning August 1, 2003,
the approach to be taken in procuring the energy needs for BGS has not been
determined. The NJBPU recently initiated a formal proceeding to decide how BGS
will be handled after the transition period.
We are permitted to defer for future recovery the amount by which our
reasonable and prudently incurred costs for providing BGS to non-shopping
customers and costs incurred under NUG agreements exceed amounts currently
reflected in our BGS rate and market transition charge rate (for the recovery of
stranded costs). On September 26, 2001, the NJBPU approved the merger of
FirstEnergy and GPU subject to the terms and conditions set forth in a
settlement agreement with major intervenors. As part of the settlement, we
agreed to reduce our costs deferred for future recovery by $300 million, in
order to ensure that customers receive the benefit of future merger savings. We
wrote off $300 million of deferred costs in October 2001 upon receipt of the
final regulatory approval for the merger, which occurred on October 29, 2001.
On February 6, 2002, we received a Financing Order from the NJBPU with
authorization to issue $320 million of transition bonds to securitize the
recovery of bondable stranded costs associated with the previously divested
Oyster Creek. The Order grants us the right to charge a usage-based,
non-bypassable transition bond charge (TBC) and provided for the transfer of the
bondable transition property relating to the TBC to JCP&L Transition Funding LLC
(Transition Funding), a
5
wholly owned limited liability corporation. Transition Funding is expected to
issue and sell up to $320 million of transition bonds that will be recognized on
our Consolidated Balance Sheet in the second quarter of 2002, with the TBC
providing recovery of principal, interest and related fees on the transition
bonds.
Supply Plan
As part of our Restructuring Orders, we are obligated, through July 31,
2002, to supply electricity to customers who do not choose an alternate
supplier. The total forecasted peak of this obligation is 5,400 megawatts (MW).
The successful BGS auction in New Jersey removed our BGS obligation for 5,100 MW
for the period from August 1, 2002 to July 31, 2003. In that auction FirstEnergy
Solutions Corp., an affiliated company, was a successful bidder to provide 1,700
MW during the same period to us and two other electric utilities in New Jersey.
Our current supply portfolio contains approximately 900 MW of long-term
purchases from NUGs and 266 MW of owned generation. Our remaining obligation is
expected to be met through a mix of short-term forward (less than one year)
purchases and spot market purchases.
Environmental Matters
Various environmental liabilities have been recognized on the
Consolidated Balance Sheet as of December 31, 2001, 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 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. Federal law provides that all PRPs for a particular site be
held liable on a joint and several basis. In addition, we have accrued
liabilities for environmental remediation of former manufactured gas plants in
New Jersey; these costs are being recovered through a non-bypassable societal
benefits charge. We have total accrued liabilities aggregating approximately $52
million as of December 31, 2001. We do not believe environmental remediation
costs will have a material adverse effect on our financial condition, cash flows
or results of operations.
Legal Matters
Various lawsuits, claims and proceedings related to our normal business
operations are pending against us, the most significant of which are described
below.
We have a 25% ownership interest in Unit 2 of the Three Mile Island
Nuclear Plant (TMI-2), which was damaged during a 1979 accident. As a result of
the accident, claims for alleged personal injury were filed against us,
Metropolitan Edison Company, Pennsylvania Electric Company and GPU in the U.S.
District Court for the Middle District of Pennsylvania. In 1996, the District
Court granted a motion for summary judgment filed by the defendants and
dismissed the ten initial "test cases" which had been selected for a test case
trial, as well as all of the remaining 2,100 pending claims. In November 1999,
the U.S. Court of Appeals for the Third Circuit affirmed the District Court's
dismissal of the ten test cases, but set aside the dismissal of the additional
pending claims, remanding them to the District Court for further proceedings.
Following the resolution of judicial proceedings dealing with admissible
evidence, we have again requested summary judgment of the remaining 2,100 claims
in the District Court. On January 15, 2002, the District Court granted our
motion. On February 14, 2002, the plaintiffs filed a notice of appeal of this
decision (see Note 6 - Other Legal Proceedings). Although unable to predict the
outcome of this litigation, we believe that any liability to which we might be
subject by reason of the TMI-2 accident will not exceed our financial protection
under the Price-Anderson Act.
In July 1999, the Mid-Atlantic states experienced a severe heat storm
which resulted in power outages throughout the service areas of many electric
utilities, including ours. 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, we provided unsafe, inadequate or improper
service to our customers. In July 1999, two class action lawsuits (subsequently
consolidated into a single proceeding) were filed against us and other GPU
companies in New Jersey Superior Court, seeking compensatory and punitive
damages arising from the July 1999 service interruptions in our service
territory. In May 2001, the court denied without prejudice our motion seeking
decertification of the class. Discovery continues in the class action, but no
trial date has been set. The judge has set a schedule under which factual legal
discovery would conclude in March 2002, and expert reports would be exchanged by
June 2002. In October 2001, the court held argument on the plaintiffs' motion
for partial summary judgment, which contends that we are bound to several
findings of the NJBPU investigation. The plaintiffs' motion was denied by the
Court in November 2001 and plaintiffs' motion seeking permission to file an
appeal on this denial of their motion was rejected by the New Jersey Appellate
Division. We have also filed a motion for partial summary judgment that is
currently pending before the Superior Court. We are unable to predict the
outcome of these matters.
6
Significant Accounting Policies
- -------------------------------
We prepare our consolidated financial statements in accordance with
accounting principles generally accepted in the United States. Application of
these principles often requires a high degree of judgment, estimates and
assumptions that affect our financial results. All of our assets are subject to
their own specific risks and uncertainties and are continually 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
On November 7, 2001, the merger between FirstEnergy and GPU became
effective, and we became a wholly owned subsidiary of FirstEnergy. The merger
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, which are subject to
adjustment in 2002 when finalized, primarily consist of: (1) revaluation of
certain property, plant and equipment; (2) adjusting preferred stock subject to
mandatory redemption and long-term debt to estimated fair value; (3) recognizing
additional obligations related to retirement benefits; and (4) recognizing
estimated severance and other compensation liabilities. The excess of the
purchase price over the estimated fair values of the assets acquired and
liabilities assumed was recognized as goodwill, which will be reviewed for
impairment at least annually. As of December 31, 2001, we had recorded goodwill
of approximately $1.9 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 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. As of December 31, 2001, we had regulatory assets of
$3.3 billion. We continually review these assets to assess their ultimate
recoverability within the approved regulatory guidelines. Impairment risk
associated with these assets relates to potentially adverse legislation,
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 must
be documented. Derivative contracts that are determined to fall within the scope
of Statement of Financial Accounting Standards (SFAS) No. 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 commodities contracts, 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 year. The determination of unbilled revenues requires management
to make various estimates including:
- Net energy purchased or generated for retail load
- Losses of energy over distribution lines
- Mix of kilowatt-hour usage by residential, commercial and industrial
customers
- Kilowatt-hour usage of customers receiving electricity from
alternative suppliers
Recently Issued Accounting Standards
- ------------------------------------
The Financial Accounting Standards Board (FASB) approved SFAS 141,
"Business Combinations," and SFAS 142, "Goodwill and Other Intangible Assets,"
on June 29, 2001. SFAS 141 requires that all business combinations
7
initiated after June 30, 2001 be accounted for using purchase accounting. The
provisions of the new standard relating to the determination of goodwill and
other intangible assets have been applied to our 2001 merger, which was
accounted for as a purchase transaction. Under SFAS 142, amortization of
existing goodwill will cease January 1, 2002. Instead, goodwill will be tested
for impairment at least on an annual basis, and no impairment of goodwill is
anticipated as a result of a preliminary analysis. We did not have any goodwill
prior to our 2001 merger, and we did not amortize goodwill associated with the
merger under the provisions of the new standard.
In July 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement
Obligations." The new statement provides accounting standards for retirement
obligations associated with tangible long-lived assets, with adoption required
by January 1, 2003. SFAS 143 requires that the fair value of a liability for an
asset retirement obligation be recorded in the period in which it is incurred.
The associated asset retirement costs are capitalized as part of the carrying
amount of the long-lived asset. Over time the capitalized costs are depreciated
and the present value of the asset retirement liability increases, resulting in
a period expense. Upon retirement, a gain or loss will be recorded if the cost
to settle the retirement obligation differs from the carrying amount. We are
currently assessing the new standard and have not yet determined the impact on
our financial statements.
In September 2001, the FASB issued SFAS 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS 144 supersedes SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of." The Statement also supersedes the accounting and reporting
provisions of APB 30. Our adoption of this Statement, effective January 1, 2002,
will result in our accounting for any future impairments or disposals of
long-lived assets under the provisions of SFAS 144, but will not change the
accounting principles used in previous asset impairments or disposals.
Application of SFAS 144 is not anticipated to have a major impact on accounting
for impairments or disposal transactions compared to the prior application of
SFAS 121 or APB 30.
8
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME
Nov 7 - Jan. 1 - For the Years Ended Dec. 31,
Dec. 31, 2001 Nov. 6, 2001 2000 1999
- -----------------------------------------------------------------------------------------------------------------------
(In thousands)
OPERATING REVENUES........................................ $ 282,902 | $1,838,638 $1,979,297 $2,018,209
---------- | ---------- ---------- ----------
|
OPERATING EXPENSES AND TAXES: |
Fuel and purchased power............................... 136,123 | 932,300 890,812 850,880
Nuclear operating costs................................ - | - 78,487 149,739
Other operating costs.................................. 40,670 | 237,513 303,353 333,134
---------- | ---------- ---------- ----------
Total operation and maintenance expenses............. 176,793 | 1,169,813 1,272,652 1,333,753
Provision for depreciation and amortization............ 35,124 | 205,918 235,001 241,842
General taxes.......................................... 8,919 | 56,582 64,398 76,824
Income taxes........................................... 18,400 | 113,478 124,019 88,370
---------- | ---------- ---------- ----------
Total operating expenses and taxes................... 239,236 | 1,545,791 1,696,070 1,740,789
---------- | ---------- ---------- ----------
|
OPERATING INCOME.......................................... 43,666 | 292,847 283,227 277,420
|
OTHER INCOME (EXPENSE).................................... 1,186 | (176,875) 24,146 (1,957)
---------- | ---------- ---------- ----------
|
INCOME BEFORE NET INTEREST CHARGES........................ 44,852 | 115,972 307,373 275,463
---------- | ---------- ---------- ----------
|
NET INTEREST CHARGES: |
Subsidiaries' preferred stock dividend requirements.... 1,605 | 9,095 10,700 10,700
Interest on long-term debt............................. 14,234 | 77,205 85,220 87,196
Allowance for borrowed funds used during |
construction......................................... 135 | (1,665) (1,287) (1,775)
Deferred interest income............................... (2,243) | (12,557) (7,951) (1,817)
Other interest expense................................. 1,080 | 9,427 9,879 8,779
----------- | ---------- ----------- -----------
Net interest charges................................. 14,811 | 81,505 96,561 103,083
---------- | ---------- ---------- ----------
|
NET INCOME................................................ 30,041 | 34,467 210,812 172,380
|
PREFERRED STOCK DIVIDEND |
REQUIREMENTS........................................... 698 | 4,547 6,904 8,670
|
LOSS ON PREFERRED STOCK |
REACQUISITION.......................................... - | - - 848
---------- | ---------- ---------- ---------
|
EARNINGS ON COMMON STOCK.................................. $ 29,343 | $ 29,920 $ 203,908 $ 162,862
=========== | =========== ========== ==========
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
9
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31, 2001 2000
- ------------------------------------------------------------------------------------------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service................................................................... $3,431,823 | $3,282,987
Less-Accumulated provision for depreciation.................................. 1,313,259 | 1,212,784
---------- | ----------
2,118,564 | 2,070,203
---------- | ----------
Construction work in progress- |
Electric plant............................................................. 60,482 | 75,201
---------- | ----------
2,179,046 | 2,145,404
---------- | ----------
OTHER PROPERTY AND INVESTMENTS: |
Nuclear plant decommissioning trusts......................................... 114,899 | 115,311
Nuclear fuel disposal trust.................................................. 137,098 | 126,336
Long-term notes receivable from associated companies......................... 20,333 | 20,333
Other........................................................................ 6,643 | 6,343
---------- | ----------
278,973 | 268,323
---------- | ----------
CURRENT ASSETS: |
Cash and cash equivalents.................................................... 31,424 | 2,021
Receivables- |
Customers (less accumulated provisions of $12,923,000 and $21,479,000 |
respectively, for uncollectible accounts)................................ 226,392 | 237,222
Associated companies....................................................... 6,412 | 8,520
Other...................................................................... 20,729 | 38,107
Materials and supplies, at average cost...................................... 1,348 | 508
Prepayments and other........................................................ 16,569 | 96,914
---------- | ----------
302,874 | 383,292
---------- | ----------
DEFERRED CHARGES: |
Regulatory assets............................................................ 3,324,804 | 3,185,072
Goodwill..................................................................... 1,926,526 | -
Other........................................................................ 27,775 | 26,963
---------- | ----------
5,279,105 | 3,212,035
---------- | ----------
$8,039,998 | $6,009,054
========== | ==========
CAPITALIZATION AND LIABILITIES |
|
CAPITALIZATION (See Consolidated Statements of Capitalization): |
Common stockholder's equity.................................................. $3,163,701 | $1,459,260
Preferred stock- |
Not subject to mandatory redemption........................................ 12,649 | 12,649
Subject to mandatory redemption............................................ 44,868 | 51,500
Company-obligated mandatorily redeemable preferred securities................ 125,250 | 125,000
Long-term debt............................................................... 1,224,001 | 1,093,987
---------- | ----------
4,570,469 | 2,742,396
---------- | ----------
CURRENT LIABILITIES: |
Currently payable long-term debt and preferred stock......................... 60,848 | 50,847
Short-term borrowings (Note 5)- |
Associated companies....................................................... 18,149 | -
Other...................................................................... - | 29,200
Accounts payable- |
Associated companies....................................................... 171,168 | 98,526
Other...................................................................... 89,739 | 87,261
Accrued taxes............................................................... 35,783 | 8,836
Accrued interest............................................................. 25,536 | 23,625
Other........................................................................ 79,589 | 38,168
---------- | ----------
480,812 | 336,463
---------- | ----------
DEFERRED CREDITS: |
Accumulated deferred income taxes............................................ 514,216 | 666,047
Accumulated deferred investment tax credits.................................. 13,490 | 17,087
Power purchase contract loss liability ...................................... 1,968,823 | 1,699,473
Nuclear fuel disposal costs.................................................. 163,377 | 156,959
Nuclear plant decommissioning costs.......................................... 137,424 | 135,835
Other........................................................................ 191,387 | 254,794
---------- | ----------
2,988,717 | 2,930,195
---------- | ----------
COMMITMENTS AND CONTINGENCIES |
(Notes 3 and 6)..............................................................
---------- | ----------
$8,039,998 | $6,009,054
========== | ==========
The accompanying Notes to Consolidated Financial Statements are an integral part
of these balance sheets.
10
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31, 2001 2000
- -------------------------------------------------------------------------------------------------------------------
(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........................................................ 2,981,117 | 510,769
Accumulated other comprehensive loss (Note 4F)............................. (472)| (8)
Retained earnings (Note 4A).................................................. 29,343 | 794,786
----------- | -----------
Total common stockholder's equity.......................................... 3,163,701 | 1,459,260
----------- | -----------
Number of Shares Optional
Outstanding Redemption Price
---------------- --------------------
2001 2000 Per Share Aggregate
---- ---- --------- ---------
PREFERRED STOCK (Note 4B):
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
|
Subject to Mandatory Redemption (Note 4C): |
8.65% Series J..................... 250,001 333,334 101.30 $ 25,325 26,750 | 33,333
7.52% Series K..................... 265,000 290,000 103.76 27,496 28,951 | 29,000
Redemption Within One Year......... (10,833)| (10,833)
-------- -------- --------- ----------- | -----------
Total Subject to Mandatory |
Redemption..................... 515,001 623,334 $ 52,821 44,868 | 51,500
======== ======== ========= ----------- | -----------
COMPANY OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF SUBSIDIARY LIMITED
PARTNERSHIP HOLDING SOLELY COMPANY
SUBORDINATED DEBENTURES (NOTE 4D):
Cumulative, $25 par value -
Authorized 5,000,000 shares
Subject to Mandatory Redemption:
8.56% due 2044........................................................... 125,250 | 125,000
|
LONG-TERM DEBT (Note 4E): |
First mortgage bonds: |
6.450% due 2001............................................................ - | 40,000
9.000% due 2002............................................................ 50,000 | 50,000
6.375% due 2003............................................................ 150,000 | 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............................................................ 50,000 | 50,000
7.900% due 2007............................................................ 40,000 | 40,000
7.125% due 2009............................................................ 6,300 | 6,300
7.100% due 2015............................................................ 12,200 | 12,200
9.200% due 2021............................................................ 50,000 | 50,000
8.320% due 2022............................................................ 40,000 | 40,000
8.550% due 2022............................................................ 30,000 | 30,000
8.820% due 2022............................................................ 12,000 | 12,000
8.850% due 2022............................................................ 38,000 | 38,000
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............................................... 1,093,500 | 1,133,500
----------- | -----------
|
Secured notes: |
6.450% due 2006............................................................ 150,000 | -
----------- | -----------
Unsecured notes: |
7.69% due 2039............................................................. 2,998 | 3,012
----------- | -----------
Net unamortized premium / (discount) on debt..................................... 27,518 | (2,511)
----------- | -----------
Long-term debt due within one year............................................... (50,015)| (40,014)
----------- | -----------
Total long-term debt......................................................... 1,224,001 | 1,093,987
----------- | -----------
|
TOTAL CAPITALIZATION................................................................ $ 4,570,469 | $ 2,742,396
=========== | ===========
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
11
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, 1999....................... 15,371,270 $153,713 $ 510,769 $ (425) $ 893,016
Net income.................................. $172,380 172,380
Net unrealized gains on investments......... 7 7
Minimum pension liability................... 425 425
--------
Comprehensive income........................ 172,812
--------
Loss on preferred stock reacquisition...... (848)
Cash dividends on preferred stock........... (8,670)
Cash dividends on common stock.............. (335,000)
- --------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1999..................... 15,371,270 153,713 510,769 7 720,878
Net income.................................. 210,812 210,812
Minimum pension liability................... (15) (15)
--------
Comprehensive income........................ 210,797
--------
Cash dividends on preferred stock........... (6,904)
Cash dividends on common stock.............. (130,000)
- --------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2000..................... 15,371,270 153,713 510,769 (8) 794,786
Net income.................................. 34,467 34,467
Net unrealized gains 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 gain (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
====================================================================================================================
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, 1999............ 375,000 $ 37,741 5,890,000 $214,000
Redemptions-
7.88% Series .................. (250,000) (25,092)
7.52% Series .................. (50,000) (5,000)
---------------------------------------------------------------------------------------
Balance, December 31, 1999.......... 125,000 12,649 5,840,000 209,000
Redemptions-
7.52% Series .................. (50,000) (5,000)
8.65% Series .................. (166,666) (16,667)
---------------------------------------------------------------------------------------
Balance, December 31, 2000.......... 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 $180,951
=======================================================================================
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
12
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Nov. 7 - Jan. 1 - For the Years Ended Dec. 31,
Dec. 31, 2001 Nov. 6, 2001 2000 1999
- ------------------------------------------------------------------------------------------------------------------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income...........................................................$ 30,041 | $ 34,467 $ 210,812 $ 172,380
Adjustments to reconcile net income to net |
cash from operating activities: |
Provision for depreciation and amortization..................... 35,124 | 205,918 235,001 241,842
Nuclear fuel and lease amortization............................. - | - 11,472 29,507
Other amortization.............................................. 1,360 | 23,025 34,563 30,441
NJBPU restructuring rate order.................................. - | - - 115,000
Deferred costs, net............................................. (25,471)| (29,312) (229,321) (37,841)
Deferred income taxes, net...................................... 5,609 | (58,132) 270,479 (78,072)
Investment tax credits, net..................................... (540)| (3,057) (15,027) (18,111)
Receivables..................................................... 7,050 | 27,177 11,766 (84,364)
Materials and supplies.......................................... 2 | (842) (268) 46,023
Accounts payable................................................ (5,060)| (44,498) 51,633 21,788
Other........................................................... 20,563 | 66,328 (230,100) (65,161)
-------- | --------- --------- ---------
Net cash provided from operating activities................... 68,678 | 221,074 351,010 373,432
-------- | --------- --------- ---------
|
CASH FLOWS FROM FINANCING ACTIVITIES: |
New Financing- |
Long-term debt.................................................. - | 148,796 - -
Short-term borrowings, net...................................... - | - 29,200 -
Redemptions and Repayments- |
Preferred stock................................................. - | 10,833 21,667 30,940
Long-term debt.................................................. 40,000 | - 40,000 12
Short-term borrowings, net...................................... 1,851 | 9,200 - 122,344
Capital lease payments.......................................... - | - 48,516 27,347
Dividend Payments- |
Common stock.................................................... - | 175,000 130,000 335,000
Preferred stock................................................. 698 | 4,547 7,065 7,468
-------- | --------- --------- ---------
Net cash used for financing activities........................ 42,549 | 50,784 218,048 523,111
-------- | --------- --------- ---------
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
Property additions................................................... 21,487 | 141,030 144,389 140,915
Contributions to decommissioning trusts.............................. 202 | 1,004 130,444 59,175
Sale of investments.................................................. - | - (74,797) (413,753)
Other................................................................ 1,078 | 2,215 624 2,162
-------- | --------- --------- ---------
Net cash used for (provided from) investing activities........ 22,767 | 144,249 200,660 (211,501)
-------- | --------- --------- ---------
Net increase (decrease) in cash and cash equivalents................. 3,362 | 26,041 (67,698) 61,822
Cash and cash equivalents at beginning of period..................... 28,062 | 2,021 69,719 7,897
-------- | --------- --------- ---------
Cash and cash equivalents at end of period...........................$ 31,424 | $ 28,062 $ 2,021 $ 69,719
======== | ========= ========= =========
|
SUPPLEMENTAL CASH FLOWS INFORMATION: |
Cash Paid During the Year- |
Interest (net of amounts capitalized)...........................$ 4,787 | $ 95,509 $ 99,961 $ 104,924
======== | ========= ========= =========
Income taxes (refund)...........................................$ 20,586 | $ 19,365 $ (50,105) $ 189,304
======== | ========= ========= =========
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
13
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF TAXES
Nov. 7 - Jan. 1 - For the Years Ended Dec.31,
Dec. 31, 2001 Nov. 6, 2001 2000 1999
- -----------------------------------------------------------------------------------------------------------------------
(In thousands)
GENERAL TAXES:
Real and personal property......................................... $ 283 | $ 3,589 $ 4,093 $ 4,668
State gross receipts............................................... 1,269 | - - -
Social security and unemployment................................... (1) | 7 - 95
NJ TEFA............................................................ 6,765 | 42,418 47,521 58,831
Other.............................................................. 603 | 10,568 12,784 13,230
---------- | ---------- ---------- ----------
Total general taxes......................................... $ 8,919 | $ 56,582 $ 64,398 $ 76,824
========= | ========== ========== ==========
|
PROVISION FOR INCOME TAXES: |
Currently payable- |
Federal......................................................... $ 11,827 | $ 41,826 $ (109,572) $ 147,586
State........................................................... 3,205 | 19,415 (26,005) 49,567
--------- | --------- ---------- ----------
15,032 | 61,241 (135,577) 197,153
--------- | --------- ----------- ----------
Deferred, net- |
Federal......................................................... 4,268 | (36,210) 209,127 (54,760)
State........................................................... 1,341 | (21,922) 61,352 (23,312)
--------- | --------- ---------- ----------
5,609 | (58,132) 270,479 (78,072)
--------- | ---------- ---------- -----------
Investment tax credit amortization................................. (540) | (3,057) (15,027) (18,111)
--------- | ---------- ---------- ----------
Total provision for income taxes............................ $ 20,101 | $ 52 $ 119,875 $ 100,970
========= | ========== ========== ==========
|
INCOME STATEMENT CLASSIFICATION |
OF PROVISION FOR INCOME TAXES: |
Operating income................................................... $ 18,400 | $ 113,478 $ 124,019 $ 88,370
Other income....................................................... 1,701 | (113,426) (4,144) 12,600
--------- | ---------- ---------- ----------
Total provision for income taxes............................ $ 20,101 | $ 52 $ 119,875 $ 100,970
========= | ========== ========== ==========
|
RECONCILIATION OF FEDERAL INCOME TAX |
EXPENSE AT STATUTORY RATE TO TOTAL |
PROVISION FOR INCOME TAXES: |
Book income before provision for income taxes...................... $ 50,142 | $ 34,519 $ 330,688 $ 273,349
========= | ========== ========== --========
Federal income tax expense at statutory rate....................... $ 17,550 | $ 12,082 $ 115,741 $ 95,672
Increases (reductions) in taxes resulting from- |
Amortization of investment tax credits.......................... (540) | (3,057) (15,027) (12,481)
Depreciation.................................................... 226 | 3,563 3,230 2,684
State income tax, net of federal tax............................ 3,077 | 4,355 21,987 16,232
Allocated share of consolidated tax savings..................... -- | (8,509) -- (2,421)
Sale of generation assets....................................... -- | -- (6,239) --
Other, net...................................................... (212) | (8,382) 183 1,284
---------- | ---------- ---------- -----------
Total provision for income taxes............................ $ 20,101 | $ 52 $ 119,875 $ 100,970
========= | ========== ========== ==========
|
ACCUMULATED DEFERRED INCOME TAXES AT |
DECEMBER 31: |
Property basis differences......................................... $ 288,255 | $ 302,476 $ 403,250
Nuclear decommissioning............................................ 59,716 | 97,817 2,264
Deferred sale and leaseback costs.................................. (16,240) | (15,605) (15,429)
Purchase accounting basis difference............................... (71,900) | -- --
Sale of generation assets.......................................... 202,485 | 235,923 --
Regulatory transition charge....................................... 123,042 | 99,930 --
Provision for rate refund.......................................... (46,942) | (46,942) (46,942)
Customer receivables for future income taxes....................... 16,749 | 33,234 29,073
Other.............................................................. (40,949) | (40,786) (17,232)
--------- | ---------- ----------
Net deferred income tax liability........................... $ 514,216 | $ 666,047 $ 354,984
========= | ========== ==========
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
14
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. All significant
intercompany transactions have been eliminated. The Company is a wholly owned
subsidiary of FirstEnergy Corp. FirstEnergy also holds directly all of the
issued and outstanding common shares of 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 period and post-merger period financial results
are separated by a heavy black line.
The Company follows the accounting policies and practices prescribed by
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
disclosure of contingent assets and liabilities. Actual results could differ
from these estimates. Certain prior year amounts have been reclassified to
conform with the current year presentation.
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 through the end of
the year.
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, 2001 or 2000, with respect to
any particular segment of the Company's customers.
REGULATORY PLAN-
New Jersey is evolving to a competitive electric utility marketplace.
In March 2001, the NJBPU issued a Final Decision and Order (Final Order) with
respect to the Company's rate unbundling, stranded cost and restructuring
filings, which superseded its 1999 Summary Order. The Final Order confirms rate
reductions set forth in the Summary Order, which remain in effect at increasing
levels through July 2003 with rates after July 31, 2003 to be determined in a
rate case commencing in 2002. The Final Order also confirms the right of
customers to select their generation suppliers effective August 1, 1999, and
includes the deregulation of electric generation service costs. The Final Order
confirms the establishment of a non-bypassable societal benefits charge 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; however, the NJBPU 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
ratepayers, the Company would need to record a corresponding charge to income of
approximately $25 million, plus interest.
The Company has an obligation to provide basic generation service
(BGS), that is, it must act as provider of last resort to non-shopping customers
as a result of the NJBPU's restructuring plans. The Company obtains its supply
of electricity to meet its BGS obligation to non-shopping customers 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 non-utility
generation agreements exceed amounts collected through BGS and MTC rates. As of
December 31, 2001, the accumulated deferred cost balance totaled approximately
$300 million, after giving effect to the reduction discussed below. The Final
Order provided for the ability to securitize stranded costs associated with the
divested Oyster Creek Nuclear Generation Station. In February 2002, the Company
received NJBPU authorization to issue $320 million of transition bonds to
securitize the recovery of these costs. The NJBPU order also provides for a
usage-based non-bypassable transition bond charge and for the transfer of the
bondable transition property to another entity. The Company plans to sell
transition bonds in the second quarter of 2002, which will be recognized on the
Consolidated Balance Sheet. The Final Order also allows for additional
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.
In June 2001, the four incumbent New Jersey electric distribution
companies, including the Company, filed a joint proposal seeking NJBPU approval
of a competitive bidding process to procure supply for the provision of BGS for
the period August 1, 2002 through July 31, 2003. In December 2001, the NJBPU
authorized the auctioning of BGS to meet
15
the electric demands of all customers who have not selected an alternative
supplier. BGS for all four companies, for the period August 1, 2002 to July 31,
2003, was simultaneously put out for bid. The auction, which ended on February
13, 2002 and was approved by the NJBPU on February 15, 2002, removed the
Company's BGS obligation of 5,100 megawatts for the period from August 1, 2002
to July 31, 2003. The auction represents a transitional mechanism and a
different model for the procurement of BGS commencing August 1, 2003 may be
adopted.
On September 26, 2001, the NJBPU approved the merger between FirstEnergy
and GPU, (see Note 2 - Merger) subject to the terms and conditions set forth in
a Stipulation of Settlement which had been signed by the major parties in the
merger discussions. Under this Stipulation of Settlement, FirstEnergy agreed to
reduce the Company's regulatory assets by $300 million, in order to ensure that
customers receive the benefit of future merger savings. The Company wrote off
$300 million of its deferred costs upon receipt of the final regulatory approval
for the merger, which occurred on October 29, 2001.
The application of Statement of Financial Accounting Standards (SFAS)
No. 71, "Accounting for the Effects of Certain Types of Regulation," was
discontinued in 1999 with respect to the Company's generation operations. The
Company subsequently divested substantially all of its generating assets. The
Securities and Exchange Commission issued interpretive guidance regarding asset
impairment measurement, concluding 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 the operations for which the
application of SFAS 71 was discontinued were $46 million as of December 31,
2001. All of the Company's regulatory assets are expected to continue to be
recovered under provisions of the Company's regulatory orders.
PROPERTY, PLANT AND EQUIPMENT-
As a result of the merger, certain of the Company's property, plant
and equipment have been 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 $21.5 million as of December 31, 2001.
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 3.4% in 2001, 3.3% in 2000 and
2.9% in 1999.
Annual depreciation expense in 2001 included approximately $27.1 million
for future decommissioning costs applicable to the Company's ownership in Unit 2
of the Three Mile Island Nuclear Plant (TMI-2), a demonstration nuclear reactor
owned by a wholly owned subsidiary of the Company (in conjunction with Met-Ed
and Penelec) and decommissioning liabilities for its previously divested nuclear
generating units. The Company's share of the future obligation to decommission
these units is approximately $130.1 million in current dollars and (using a 4.0%
escalation rate) approximately $214.1 million in future dollars. The estimated
obligation and the escalation rate were developed based on site specific
studies. Decommissioning of the demonstration nuclear reactor is expected to be
completed in 2003; payments for decommissioning of TMI-2 are expected to begin
in 2014, when actual decommissioning work is expected to begin. The Company has
recovered approximately $33 million for decommissioning through its electric
rates from customers through December 31, 2001. The Company has also recognized
an estimated liability of approximately $12.1 million related to decontamination
and decommissioning of nuclear enrichment facilities operated by the United
States Department of Energy, as required by the Energy Policy Act of 1992.
In July 2001, the Financial Accounting Standards Board (FASB) issued
SFAS 143, "Accounting for Asset Retirement Obligations." The new statement
provides accounting treatment for retirement obligations associated with
tangible long-lived assets with adoption required as of January 1, 2003. SFAS
143 requires that the fair value of a liability for an asset retirement
obligation be recorded in the period in which it is incurred. The associated
asset retirement costs are capitalized as part of the carrying amount of the
long-lived asset. Over time the capitalized costs are depreciated and the
present value of the asset retirement liability increases, resulting in a period
expense. Upon retirement, a gain or loss will be recorded if the costs to settle
the retirement obligation differs from the carrying amount. Under the new
standard, additional assets and liabilities relating principally to nuclear
decommissioning obligations will be recorded, the pattern of expense recognition
will change and income from the external decommissioning trusts will be recorded
as investment income. The Company is currently assessing the new standard and
has not yet quantified the impact on its financial statements.
INCOME TAXES-
Details of the total provision for income taxes are shown on the
Consolidated Statements of Taxes. Deferred income taxes result from timing
differences in the recognition of revenues and expenses for tax and accounting
purposes. Investment tax credits, which were deferred when utilized, are being
amortized over the recovery period of the related property. The liability method
is used to account for deferred income taxes. Deferred income tax liabilities
related
16
to tax and accounting basis differences 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 are included in the final
consolidated federal income tax return of GPU, and results for the period
November 7, 2001 through December 31, 2001 are included in FirstEnergy's 2001
consolidated federal income tax return. In both cases, 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 contributed to the
consolidated return.
RETIREMENT BENEFITS-
Effective December 31, 2001, the Company's defined benefit pension
plan was merged into FirstEnergy's defined benefit pension plan. FirstEnergy's
trusteed, noncontributory defined benefit pension plan covers almost all of the
Company's full-time employees. Upon retirement, employees receive a monthly
pension based on length of service and compensation. On December 31, 2001, the
GPU pension plans were merged with the FirstEnergy plan. FirstEnergy uses the
projected unit credit method for funding purposes. The assets of the pension
plan consist primarily of common stocks, United States government bonds and
corporate bonds. The FirstEnergy and GPU postretirement benefit plans are
currently separately maintained; the information shown below is aggregated as of
December 31, 2001. Costs for the year 2001 include the former GPU companies'
pension and other postretirement benefit costs for the period November 7, 2001
through December 31, 2001.
The Company provides a minimum amount of noncontributory life insurance
to retired employees in addition to optional contributory insurance. Health care
benefits, which include certain employee deductibles and copayments, are also
available to retired employees, their dependents and, under certain
circumstances, their survivors. The Company pays insurance premiums to cover a
portion of these benefits in excess of set limits; all amounts up to the limits
are paid by the Company. 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.
The following sets forth the funded status of the plans and amounts
recognized on FirstEnergy's Consolidated Balance Sheet as of December 31, 2001:
Other
Pension Benefits Postretirement Benefits
---------------- -----------------------
(In millions)
Change in benefit obligation:
Benefit obligation as
of January 1................. $1,506.1 $752.0
Service cost................... 34.9 18.3
Interest cost.................. 133.3 64.4
Plan amendments................ 3.6 --
Actuarial loss................. 123.1 73.3
Voluntary early retirement
program...................... -- 2.3
GPU acquisition................ 1,878.3 716.9
Benefits paid.................. (131.4) (45.6)
-----------------------------------------------------------------------
Benefit obligation as of
December 31.................. 3,547.9 1,581.6
-----------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets
as of January 1.............. 1,706.0 23.0
Actual return on plan assets... 8.1 12.7
Company contribution........... -- 43.3
GPU acquisition................ 1,901.0 462.0
Benefits paid.................. (131.4) (6.0)
-----------------------------------------------------------------------
Fair value of plan assets
as of December 31............ 3,483.7 535.0
-----------------------------------------------------------------------
Funded status of plan.......... (64.2) (1,046.6)
Unrecognized actuarial
loss (gain).................. 222.8 212.8
Unrecognized prior
service cost................. 87.9 17.7
Unrecognized net transition
obligation (asset)........... -- 101.6
-----------------------------------------------------------------------
Prepaid (accrued) benefit cost. $ 246.5 $ (714.5)
=======================================================================
Assumptions used as
of December 31, 2001:
Discount rate.................. 7.25% 7.25%
Expected long-term return
on plan assets............... 10.25% 10.25%
Rate of compensation
increase..................... 4.00% 4.00%
17
FirstEnergy's net pension and other postretirement benefit costs for the
year ended December 31, 2001 were computed as follows:
Other
Pension Benefits Postretirement Benefits
---------------- -----------------------
(In millions)
Service cost................... $ 34.9 $18.3
Interest cost.................. 133.3 64.4
Expected return on
plan assets.................. (204.8) (9.9)
Amortization of transition
obligation (asset)........... (2.1) 9.2
Amortization of prior
service cost................. 8.8 3.2
Recognized net actuarial
loss (gain).................. -- 4.9
Voluntary early retirement
program...................... 6.1 2.3
-----------------------------------------------------------------------
Net benefit cost............... $ (23.8) $92.4
=======================================================================
The composite health care trend rate assumption is approximately 10% in
2002, 9% in 2003 and 8% in 2004, trending to 4%-6% in later years. Assumed
health care cost trend rates have a significant effect on the amounts reported
for the health care plan. An increase in the health care trend rate assumption
by one percentage point would increase FirstEnergy's total service and interest
cost components by $14.6 million and the postretirement benefit obligation by
$151.2 million. A decrease in the same assumption by one percentage point would
decrease the total service and interest cost components by $12.7 million and the
postretirement benefit obligation by $131.3 million.
Pre-Merger
As of December 31, 2000, the Company's balance sheet included accrued
benefit costs of $1.8 million and $0.1 million, respectively, related to pension
and other postretirement benefit obligations. In addition, for the year ended
December 31, 2000, the Company recognized in income net benefit costs/(credits)
of $(0.5) million and $0.04 million, respectively, for pension and other
postretirement benefits, and for the year ended December 31, 1999, the Company
recognized net benefit costs/(credits) of $0.2 million and $0.05 million,
respectively.
TRANSACTIONS WITH AFFILIATED COMPANIES-
During the three years ended December 31, 2001, GPU Service, Inc., an
affiliated company, provided legal, accounting, financial and other services to
the Company. In addition, prior to the sales of the Company's generating assets
in 2000 and 1999, affiliated companies GPU Nuclear, Inc. and GPU Generation,
Inc. conducted generation operations for the company. The total cost of services
rendered by affiliates was $279 million, $464 million and $580 million for the
years 2001, 2000 and 1999, respectively. Of these amounts, $141 million, $259
million and $393 million were charged to income for the years 2001, 2000 and
1999, respectively.
SUPPLEMENTAL CASH FLOWS INFORMATION-
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:
2001 2000
-------------------------------------------------------------------
Carrying Fair Carrying Fair
Value Value Value Value
-------------------------------------------------------------------
(In millions)
Long-term debt.......... $1,246 $1,250 $1,134 $1,125
Preferred stock......... $ 176 $ 180 $ 187 $ 188
Investments other
than cash and
cash equivalents...... $ 253 $ 252 $ 243 $ 243
-------------------------------------------------------------------
$1,675 $1,682 $1,564 $1,556
===================================================================
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. 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
represent 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
18
financial instruments with similar characteristics and terms. Investments other
than cash and cash equivalents include decommissioning trust investments.
Unrealized gains and losses applicable to the decommissioning trusts have been
recognized in the trust investment with a corresponding change to the
decommissioning liability. The Company has no securities held for trading
purposes.
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 derivative
instruments, including forward contracts, options and futures contracts. These
derivatives are used principally for hedging purposes. FirstEnergy has a Risk
Policy Committee comprised of 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 138, 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 2002. Gains and losses from hedges of commodity price risks are included
in net income when the underlying hedged commodities are delivered. There is
currently a net deferred loss of $0.5 million included in Accumulated Other
Comprehensive Loss as of December 31, 2001 related to derivative hedging
activity, which will be reclassified to earnings during the next twelve months
as hedged transactions occur.
REGULATORY ASSETS-
The Company recognizes, as regulatory assets, costs which the FERC and
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 continues the
application of SFAS 71 to those operations.
Net regulatory assets on the Consolidated Balance Sheets are comprised
of the following:
2001 2000
-------------------------------------------------------------------
(In millions)
Regulatory transition charge......... $2,844.7 $2,592.7
Societal benefits charge............. 166.6 206.6
Property losses and unrecovered
plant costs........................ 104.1 119.2
Customer receivables for
future income taxes................ 52.4 87.6
Employee postretirement
benefit costs...................... 36.5 39.8
Loss on reacquired debt.............. 19.3 21.3
Spent fuel disposal costs............ 20.2 26.1
Other................................ 81.0 91.8
-------------------------------------------------------------------
Total $3,324.8 $3,185.1
===================================================================
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
19
basis. The excess of the purchase price over the estimated fair values of the
assets acquired and liabilities assumed was recognized as goodwill, which will
not be amortized but will be reviewed for impairment at least annually. As of
December 31, 2001, the Company had recorded goodwill of approximately $1.9
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. Prior to the sale of its nuclear generating facilities
(completed in 2000), the Company's capital lease obligations related primarily
to nuclear fuel lease agreements with nonaffiliated fuel trusts for the plants.
In 2000, total rentals related to these capital leases were $13.0 million,
comprised of an interest element of $1.5 million and other costs of $11.5
million. 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 $1.2 million and $0.4
million for the years 2001 and 2000, respectively.
As of December 31, 2001, the future minimum lease payments on the
Company's Merrill Creek operating lease, net of reimbursements from sublessees,
are: $2.3 million, $3.8 million, $1.8 million, $2.3 million and $2.2 million for
the years 2002 through 2006, and $73.4 million for the years thereafter. The
Company is recovering its Merrill Creek lease payments, net of reimbursements,
through 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. At such date, the Company had a balance of $1.7 million in its
earned surplus account, which would not be available for dividends or other
distributions. As of December 31, 2001, the Company had retained earnings
available to pay common stock dividends of $27.6 million, net of amounts
restricted under the Company's FMB indentures.
(B) PREFERRED AND PREFERENCE STOCK-
The Company's 7.52% Series K of preferred stock has a restriction which
prevents early redemption prior to June 2002. All other preferred stock may be
redeemed by the Company, in whole or in part, with 30-90 days' notice.
(C) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION-
Annual sinking fund provisions for the Company's preferred stock are as
follows:
Redemption
Price Per
Series Shares Share
-------------------------------------
8.65% J 83,333 100
7.52% K 25,000 100
-------------------------------------
Annual sinking fund requirements for the next five years are $10.8
million in each year 2002 through 2004, and $2.5 million in each year 2005 and
2006.
(D) COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF
LIMITED PARTNERSHIP HOLDING SOLELY COMPANY SUBORDINATED DEBENTURES-
JCP&L Capital, L.P. is a special-purpose limited partnership in which a
subsidiary of the Company is the sole general partner. The limited partnership
invested the gross proceeds from the sale of $125.0 million at 8.56% of monthly
income preferred securities (MIPS) in $128.9 million of the Company's 8.56%
subordinated debentures. The sole assets of the limited partnership are these
subordinated debentures, which have the same rate and maturity date as the
preferred securities. The Company has effectively provided a full and
unconditional guarantee of its obligations under its limited partnership's MIPS,
to the extent that there is sufficient cash on hand to permit such payments and
funds legally available therefor, and payments on liquidation or redemption with
respect to the MIPS. Distributions on the limited partnership's MIPS (and
interest on the subordinated debentures) may be deferred for up to 60 months,
but the Company may not pay dividends on, or redeem or acquire, any of its
cumulative preferred or common stock until
20
deferred payments on its subordinated debentures are paid in full. The limited
partnership's MIPS, which mature in 2044 and have a liquidation value of $25.00
per security, are redeemable at the option of the Company at 100% of their
principal amount.
(E) LONG-TERM DEBT-
The first mortgage indentures and their supplements, which secure all of
the Company's FMBs, serve as direct first mortgage liens on substantially all
property and franchises, other than specifically excepted property, owned by the
Company.
Based on the amount of bonds authenticated by the Trustee through
December 31, 2001, the Company's annual sinking and improvement fund
requirements for all bonds issued under the mortgage amount to $16.1 million.
The Company expects to fulfill its sinking and improvement fund obligation by
providing retired 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)
-----------------------
2002........ $ 50.0
2003........ 150.0
2004........ 160.3
2005........ 50.3
2006........ 240.3
------------------------
(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 December 31,
2001, accumulated other comprehensive loss consisted of unrealized losses on
derivative instrument hedges of $0.5 million.
5. SHORT-TERM BORROWINGS:
The Company may borrow from its affiliates on a short-term basis. As of
December 31, 2001, the Company had total short-term borrowings of $18.1 million
from its affiliates with a weighted average interest rate of approximately 4.9%.
6. COMMITMENTS, GUARANTEES AND CONTINGENCIES:
CAPITAL EXPENDITURES-
The Company's current forecast reflects expenditures of approximately
$572 million for property additions and improvements from 2002-2006, of which
approximately $144 million is applicable to 2002.
NUCLEAR INSURANCE-
The Price-Anderson Act limits the public liability relative to a single
incident at a nuclear power plant to $9.5 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.
21
ENVIRONMENTAL MATTERS-
Various environmental liabilities have been recognized on the
Consolidated Balance Sheet as of December 31, 2001, 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. 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. Federal law provides that all PRPs for a
particular site be held liable on a joint and several basis. In addition, the
Company has accrued liabilities for environmental remediation of former
manufactured gas plants in New Jersey; these costs are being recovered through a
non-bypassable societal benefits charge. The Company has total accrued
liabilities aggregating approximately $52 million as of December 31, 2001. The
Company does not believe environmental remediation costs will have a material
adverse effect on its financial condition, cash flows or results of operations.
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.
TMI-2, which was damaged during a 1979 accident, is jointly owned by the
Company, Met-Ed and Penelec, with the Company having a 25% ownership percentage.
Claims for alleged personal injury against the Company, Met-Ed, Penelec and GPU
(the defendants) were filed in the U.S. District Court for the Middle District
of Pennsylvania. In 1996, the District Court granted a motion for summary
judgment filed by the defendants and dismissed the ten initial "test cases"
which had been selected for a test case trial, as well as all of the remaining
2,100 pending claims. In November 1999, the U.S. Court of Appeals for the Third
Circuit affirmed the District Court's dismissal of the ten "test cases," but set
aside the dismissal of the additional pending claims, remanding them to the
District Court for further proceedings. In September 2000, the defendants filed
for a summary judgment in the District Court. Meanwhile, the plaintiffs appealed
to the Third Circuit for a review of the District Court's decision placing
limitations on the remaining plaintiffs' suit. In April 2001, the Third Circuit
affirmed the District Court's decision. In July 2001, the defendants renewed
their motion for a summary judgment on the remaining 2,100 claims in the
District Court. On January 15, 2002, the District Court granted the defendants'
amended motion for summary judgment. On February 14, 2002, plaintiffs filed a
notice of appeal to the United States Court of Appeals for the Third Circuit. In
addition to the approximately 2,100 claims for which summary judgment has been
granted, there is other pending litigation arising out of the TMI-2 accident.
This litigation consists of the following: eight personal injury cases that were
not consolidated with the above-referenced approximately 2,100 claims; two class
actions brought on behalf of plaintiffs alleging additional injuries diagnosed
after the filing of the complaints in the above-referenced case; a case alleging
exposure during the post-accident cleanup of the TMI-2 plant; and claims by
individual businesses for economic loss resulting from the TMI-2 accident.
Although unable to predict the outcome of this litigation, the Company believes
that any liability to which it might be subject by reason of the TMI-2 accident
will not exceed its financial protection under the Price-Anderson Act.
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 the Company'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, the
Company provided unsafe, inadequate or improper service to its customers. In
July 1999, two class action lawsuits (subsequently consolidated into a single
proceeding) were filed against the Company and other GPU companies in New Jersey
Superior Court, seeking compensatory and punitive damages arising from the July
1999 service interruptions in the Company's service territory. In May 2001, the
court denied without prejudice the Company's motion seeking decertification of
the class. Discovery continues in the class action, but no trial date has been
set. The judge has set a schedule under which factual legal discovery would
conclude in March 2002, and expert reports would be exchanged by June 2002. In
October 2001, the court held argument on the plaintiffs' motion for partial
summary judgment, which contends that the Company is bound to several findings
of the NJBPU investigation. The plaintiffs' motion was denied by the Court in
November 2001 and plaintiffs' motion to file an appeal of this decision was
denied by the New Jersey Appellate Division. The Company has also filed a motion
for partial summary judgement that is currently pending before the Superior
Court. The Company is unable to predict the outcome of these matters.
22
7. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
The following summarizes certain consolidated operating results by
quarter for 2001 and 2000.
Three Months Ended
-----------------------------
March 31, June 30, Sept. 30, Oct.1-Nov. 6 Nov. 7-Dec. 31
2001 2001 2001 2001 2001
- -------------------------------------------------------------------------------------------
(In millions)
Operating Revenues............ $461.7 $521.0 $672.2 $ 183.7 | $282.9
Operating Expenses and Taxes.. 388.2 451.7 554.0 151.9 | 239.2
- ---------------------------------------------------------------------------|---------------
Operating Income.............. 73.5 69.3 118.2 31.8 | 43.7
Other Income (Expense)........ 1.2 2.3 (2.7) (177.7) | 1.2
Net Interest Charges.......... 23.3 25.6 24.3 8.3 | 14.8
- ---------------------------------------------------------------------------|---------------
Net Income (Loss)............. $ 51.4 $ 46.0 $ 91.2 $(154.2) | $ 30.1
===========================================================================|===============
Earnings on Common Stock...... $ 50.0 $ 44.7 $ 89.8 $(154.5) | $ 29.3
===========================================================================================
March 31, June 30, September 30,December 31,
Three Months Ended 2000 2000 2000 2000
- ------------------------------------------------------------------------------
(In millions)
Operating Revenues............ $452.7 $490.2 $605.0 $431.4
Operating Expenses and Taxes.. 384.8 420.0 509.3 382.0
- ------------------------------------------------------------------------------
Operating Income.............. 67.9 70.2 95.7 49.4
Other Income (Expense)........ 2.4 (2.6) 21.8 2.5
Net Interest Charges.......... 24.8 23.1 24.7 23.9
- ------------------------------------------------------------------------------
Net Income.................... $ 45.5 $ 44.5 $ 92.8 $ 28.0
==============================================================================
Earnings on Common Stock...... $ 43.1 $ 42.8 $ 91.4 $ 26.6
==============================================================================
23
Report of 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.
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Report of Independent Accountants
To the Board of Directors and Stockholder of
Jersey Central Power & Light Company:
In our opinion, the consolidated balance sheet as of December 31, 2000 and the
related consolidated statements of income, and cash flows for each of the two
years in the period ended December 31, 2000 (appearing on the accompanying index
of the Jersey Central Power & Light Company 2001 Annual Report to Stockholders
incorporated by reference in this Form 10-K) present fairly, in all material
respects, the financial position, results of operations and cash flows of Jersey
Central Power & Light Company and Subsidiary Company at December 31, 2000 and
for each of the two years in the period ended December 31, 2000, 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.
PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
January 31, 2001
25