EXHIBIT 13.6
METROPOLITAN EDISON COMPANY
2002 ANNUAL REPORT TO STOCKHOLDERS
Metropolitan Edison Company (Met-Ed) 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
eastern Pennsylvania. 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 1.3 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, Metropolitan Edison
Company was a wholly owned subsidiary of GPU, Inc.
Contents Page
- -------- ----
Selected Financial Data........................................... 1
Management's Discussion and Analysis.............................. 2-11
Consolidated Statements of Income................................. 12
Consolidated Balance Sheets....................................... 13
Consolidated Statements of Capitalization......................... 14
Consolidated Statements of Common Stockholder's Equity............ 15
Consolidated Statements of Preferred Stock........................ 15
Consolidated Statements of Cash Flows............................. 16
Consolidated Statements of Taxes.................................. 17
Notes to Consolidated Financial Statements........................ 18-30
Reports of Independent Accountants................................ 31-32
METROPOLITAN EDISON COMPANY
SELECTED FINANCIAL DATA
Nov. 7 - Jan. 1 - Year Ended December 31,
---------------------------------
2002 Dec. 31, 2001 Nov. 6, 2001 2000 1999 1998
- ---------------------------------------------------------------------------------------------------------------------
(Dollars in thousands)
Operating Revenues..................... $ 986,608 $ 143,760 | $ 824,556 $ 842,333 $ 902,827 $ 919,594
=========== ========== | ============ =========== ========== ==========
|
Operating Income....................... $ 91,271 $ 17,367 | $ 102,247 $ 135,211 $ 154,774 $ 124,447
=========== ========== | =========== =========== ========== ==========
|
Income Before Extraordinary Item....... $ 63,224 $ 14,617 | $ 62,381 $ 81,895 $ 95,123 $ 57,720
=========== ========== | ============ =========== ========== ==========
|
Net Income............................. $ 63,224 $ 14,617 | $ 62,381 $ 81,895 $ 95,123 $ 50,915
=========== ========== | ============ =========== ========== ==========
|
Earnings on Common Stock............... $ 63,224 $ 14,617 | $ 62,381 $ 81,895 $ 94,515 $ 50,432
=========== ========== | ============ =========== ============ ==========
|
Total Assets........................... $ 3,564,805 $3,607,187 | $ 2,708,062 $2,747,059 $3,347,822
=========== ========== | =========== ========== ==========
|
|
Capitalization: |
Common Stockholder's Equity......... $ 1,315,586 $1,288,953 | $ 537,013 $ 501,417 $ 687,059
Cumulative Preferred Stock.......... -- -- | -- -- 12,056
Company-Obligated Mandatorily |
Redeemable Preferred Securities... -- -- | -- -- 100,000
Company-Obligated Trust Preferred |
Securities........................ 92,409 92,200 | 100,000 100,000 --
Long-Term Debt...................... 538,790 583,077 | 496,860 496,883 546,904
----------- ---------- | ------------ ------------ ----------
Total Capitalization.............. $ 1,946,785 $1,964,230 | $1,133,873 $1,098,300 $1,346,019
=========== ========== | ========== ========== ==========
|
|
Capitalization Ratios: |
Common Stockholder's Equity......... 67.6% 65.6%| 47.4% 45.7% 51.1%
Cumulative Preferred Stock.......... -- -- | -- -- 0.9
Company-Obligated Mandatorily |
Redeemable Preferred Securities... -- -- | -- -- 7.4
Company-Obligated Trust Preferred |
Securities.......................... 4.7 4.7 | 8.8 9.1 --
Long-Term Debt...................... 27.7 29.7 | 43.8 45.2 40.6
----- ----- | ----- ----- -----
Total Capitalization.............. 100.0% 100.0%| 100.0% 100.0% 100.0%
===== ===== | ===== ===== =====
|
|
Transmission and Distribution |
Kilowatt-Hour Deliveries (Millions): |
Residential......................... 4,738 793 | 3,712 4,377 4,265 4,040
Commercial.......................... 3,991 652 | 3,203 3,699 3,488 3,321
Industrial.......................... 3,972 662 | 3,506 4,412 4,085 4,174
Other............................... 35 6 | 27 38 107 110
------- ------- | ------- ------ ------ ------
Total Retail........................ 12,736 2,113 | 10,448 12,526 11,945 11,645
Total Wholesale..................... 840 195 | 1,067 2,120 4,597 1,249
------ ------- | ------- ------ ------ ------
Total............................... 13,576 2,308 | 11,515 14,646 16,542 12,894
====== ======= | ======= ====== ====== ======
|
|
Customers Served: |
Residential......................... 448,334 442,763 | 436,573 430,746 425,431
Commercial.......................... 58,010 57,278 | 56,080 54,969 53,764
Industrial.......................... 1,936 1,961 | 1,967 2,073 2,090
Other............................... 728 819 | 810 1,057 1,063
------- ------- | ------- ------- -------
Total............................... 509,008 502,821 | 495,430 488,845 482,348
======= ======= | ======= ======= =======
1
METROPOLITAN EDISON 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 market prices, legislative and regulatory
changes (including revised environmental requirements), and the availability and
cost of capital.
Results of Operations
Net income decreased by 17.9% to $63.2 million in 2002, compared to
$77.0 million in 2001, due to the absence of deferral accounting for energy
costs in 2002 (see Regulatory Matters.), higher regulatory asset amortization
and general taxes. These increases were partially offset by an increase in
operating revenues and a decrease in other operating costs. In 2001, net income
decreased by 6.0% to $77.0 million, from $81.9 million in 2000. Results in 2001
were affected by higher purchased power and other operating costs, partially
offset by increased operating revenues.
Operating revenues increased $18.3 million in 2002, following a $126.0
million increase in 2001. The sources of changes in operating revenues during
2002 and 2001, as compared to the prior year, are summarized in the following
table.
Sources of Revenue Changes 2002 2001
-----------------------------------------------------------------------------
Increase (Decrease) (In millions)
Increase in kilowatt-hour sales due to level of
retail customers shopping for generation service...... $ 23.8 $142.6
Increase in other retail kilowatt-hour sales............ 31.1 8.2
Decrease in wholesale sales............................. (34.4) (9.4)
All other changes....................................... (2.2) (15.4)
-----------------------------------------------------------------------------
Net Increase in Operating Revenues...................... $ 18.3 $126.0
==============================================================================
Electric Sales
In 2002, further reductions in the number of residential and commercial
customers who received their power from alternate suppliers, and therefore
returned to us as full service customers, resulted in increased operating
revenues. During 2002, only 12.7% of total kilowatt-hours delivered were to
shopping customers, whereas that percentage was 16.2% in 2001 and 42.5% in 2000.
In addition to the higher revenues from returning shopping customers, warmer
summer weather in 2002 contributed to an increase in retail sales, as did a
slight increase in the number of residential and commercial customers. Partially
offsetting these 2002 increases were lower sales to industrial customers due to
a decline in economic conditions. Revenues from wholesale sales were lower in
2002 compared to 2001 due to a decrease in kilowatt-hours available for sale to
other parties, as well as lower average prices for energy in 2002. In 2001,
kilowatt-hour sales to wholesale customers also decreased; however, the decrease
was partially offset by an increase in the average price for energy sold,
compared to 2000. Changes in kilowatt-hour sales by customer class in 2002 and
2001 are summarized in the following table:
Changes in Kilowatt-hour Sales 2002 2001
Increase (Decrease)
Residential.................. 5.0% 2.9%
Commercial................... 3.4% 4.2%
Industrial................... (4.2)% (5.5)%
--------------------------------------------------
Total Retail................. 1.5% 0.3%
Wholesale.................... (33.4)% (40.5)%
--------------------------------------------------
Total Sales.................. (1.7)% (5.6)%
--------------------------------------------------
2
Operating Expenses and Taxes
Total operating expenses and taxes increased $46.6 million in 2002,
after increasing $141.6 million in 2001, compared to the preceding year. In
2002, the majority of the change was attributed to increases in purchased power
costs, regulatory asset amortization and general taxes, offset in part by a
decrease in other operating costs. An increase in purchased power and other
operating costs accounted for the majority of the increase in 2001.
Purchased power costs increased $42.1 million in 2002, compared to the
prior year. The increase was due primarily to energy costs of $40.2 million
incurred in 2002 that otherwise would have been deferred absent a Pennsylvania
Commonwealth Court decision (see Regulatory Matters). That increase was
partially offset by a reduction in power purchased during 2002. In 2001,
purchased power costs increased $91.2 million, compared to 2000. The higher
costs resulted from increased quantities of power purchased through two-party
agreements and the PJM Power Pool due to a large number of customers returning
to us in 2001 after receiving their power from alternate suppliers in 2000, as
well as higher average prices of power purchased under two-party agreements.
Partially offsetting the increase was the effect of the Pennsylvania Public
Utility Commission's (PPUC) June 2001 order that allowed us to defer, for future
recovery from customers, energy costs in excess of our fixed generation tariff
rates, retroactive to January 1, 2001, in connection with our provider of last
resort (PLR) obligation (see Regulatory Matters).
Other operating costs decreased $23.8 million in 2002, compared to the
previous year. The decrease resulted principally from reduced uncollectible
accounts expense, personnel reductions, the absence of employee severance costs
accrued in 2001 and the absence of costs related to the use of portable
generators at substations under a 2001 pilot program. Other operating costs
increased $47.8 million in 2001, compared to 2000, primarily due to the absence
of a pension curtailment gain associated with employees who were terminated when
we sold our generating assets. This gain was realized in 2000 as a result of the
PPUC's Phase II Order. Other operating costs also increased due to costs related
to Voluntary Enhanced Retirement Programs offered in 2001 to certain bargaining
unit employees.
In 2002, the provision for depreciation and amortization increased $20.6
million, compared to the prior year, primarily due to an increase in
amortization related to competitive transition charge (CTC) regulatory assets. A
$20.4 million increase in general taxes in 2002, compared to the prior year, was
the result of an increase in Pennsylvania gross receipts taxes.
Other Income
Other income increased $8.5 million in 2002, compared to the prior year,
primarily due to increased contract work performed during 2002, as well as the
absence of 2001 net losses on futures contracts and options, and the absence of
a 2001 payment for a sustainable energy fund, which was made in accordance with
the Stipulation of Settlement related to the FirstEnergy/GPU merger. In 2001,
other income increased $11.9 million, compared to 2000. The 2001 increase was
due primarily to higher CTC interest income and the absence of a 2000 write-down
of regulatory assets for decommissioning of Three Mile Island Unit 2 (TMI-2),
representing the net realized gain previously recorded on the accident-related
portion of the TMI-2 decommissioning trust. Partially offsetting the 2001
increases was the charge for the sustainable energy fund discussed above.
Net Interest Charges
Net interest charges decreased $6.1 million in 2002, compared to the
prior year, primarily due to reduced short-term borrowing levels and
amortization of purchase accounting fair market value adjustments recorded in
connection with the merger. An additional reduction was attributable to the
redemption of $30 million of notes in the first quarter of 2002; however, those
reductions were partially offset by increased interest on long-term debt due to
the issuance of $100 million of notes in September 2001 and $50 million of notes
in May 2002, which were used to refinance $30 million of notes in July 2002. In
2001, net interest charges increased $1.2 million, compared to 2000, due to the
September 2001 issuance of senior notes.
Capital Resources and Liquidity
Changes in Cash Position
As of December 31, 2002, we had $15.7 million of cash and cash
equivalents compared with $25.3 million as of December 31, 2001. The major
sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Cash flows provided from operating activities totaled $101.9 million in
2002 and $30.1 million in 2001. The sources of these changes are as follows:
3
Operating Cash Flows 2002 2001
----------------------------------------------------------
(in millions)
Cash earnings (1)............... $186 $102
Working capital................. (84) (72)
-----------------------------------------------------------
Total................... $102 $30
===========================================================
(1) Includes net income, depreciation and amortization, deferred costs
recoverable as regulatory assets, deferred income taxes, investment
tax credits and major noncash charges.
Cash Flows From Financing Activities
In 2002, net cash used for financing activities of $54.0 million
reflects redemptions of debt and $60.0 million in common stock dividend payments
to FirstEnergy, as well as the issuance of unsecured notes. The following table
provides details regarding new issues and redemptions during 2002:
Securities Issued or Redeemed in 2002
--------------------------------------------------------
(in millions)
New Issues
Unsecured notes........................ $50
--------------------------------------------------------
Redemptions
First Mortgage Bonds................... 60
--------------------------------------------------------
Short-term Borrowings, net source of cash... 16
--------------------------------------------------------
We had $88.3 million of short-term indebtedness on December 31, 2002,
compared to $72.0 million on December 31, 2001. We may borrow from our
affiliates on a short-term basis. We will not issue first mortgage bonds (FMBs)
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, 2002, we had the capability to
issue $74 million of additional senior notes based upon FMB collateral. We have
no restrictions on the issuance of preferred stock.
At the end of 2002, our common equity as a percentage of capitalization
stood at 68% compared to 66% and 47% at the end of 2001 and 2000, respectively.
In 2001 we experienced a significant increase in this ratio due to the
allocation of the purchase price when we were acquired by FirstEnergy.
Cash Flows From Investing Activities
Cash used for investing activities totaled $57.5 million in 2002 and
$68.2 million in 2001, and was used primarily for property additions to support
the distribution of electricity in both periods.
Our cash requirements in 2003 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. Over the next three years, we expect to meet our contractual
obligations with cash from operations. Thereafter, we expect to use a
combination of cash from operations and funds from the capital markets.
Less than 1-3 3-5 More than
Contractual Obligations Total 1 Year Years Years 5 Years
- ------------------------------------------------------------------------------
(in millions)
Long-term debt....... $ 587 $ 60 $ 90 $202 $ 235
Short-term borrowings 88 88 -- -- --
Preferred stock (1).. 92 -- -- -- 92
Operating leases (2). 53 2 3 3 45
Purchases (3)........ 2,158 264 318 337 1,239
- ---------------------------------------------------------------------------
Total............. $2,978 $414 $411 $542 $1,611
- ---------------------------------------------------------------------------
(1) Subject to mandatory redemption
(2) Operating lease payments are net of reimbursements from sublessees (see
Note 3)
(3) Fuel and power purchases under contracts with fixed or minimum quantities
and approximate timing
Our capital spending for the period 2003 through 2007 is expected to be
about $288 million, of which approximately $53 million applies to 2003.
4
Following approval of the merger of FirstEnergy and GPU by the New
Jersey Board of Public Utilities on September 26, 2001, Standard and Poor's
adjusted our corporate credit rating from A/A-1 to BBB/A-2, and our senior
secured debt rating from A+ to BBB+. The credit rating outlook of Standard &
Poor's is stable. On February 22, 2002, Moody's changed its credit rating
outlook from stable to negative based upon a decision by the Commonwealth Court
of Pennsylvania to remand to the PPUC for reconsideration its decisions
regarding rate relief, accounting deferrals and the mechanism for sharing merger
savings rendered in connection with its approval of the FirstEnergy/GPU merger
(see Regulatory Matters).
On February 22, 2002, Moody's Investor Service changed its credit rating
outlook for FirstEnergy from stable to negative. The change was based upon a
decision by the Commonwealth Court of Pennsylvania to remand to the Pennsylvania
Public Utility Commission (PPUC) for reconsideration its decision on the
mechanism for sharing merger savings and reversed the PPUC decisions regarding
rate relief and accounting deferrals rendered in connection with its approval of
the GPU merger. On April 4, 2002, Standard & Poor's (S&P) changed its outlook
for FirstEnergy's credit ratings from stable to negative citing recent
developments including: damage to the Davis-Besse reactor vessel head, the
Pennsylvania Commonwealth Court decision, and deteriorating market conditions
for some sales of FirstEnergy's remaining non-core assets. On July 31, 2002,
Fitch revised its rating outlook for FirstEnergy to negative from stable. The
revised outlook reflected the adverse impact of the unplanned Davis-Besse
outage, Fitch's judgment about NRG's financial ability to consummate the
purchase of four power plants from FirstEnergy and Fitch's expectation of
subsequent delays in debt reduction. On August 1, 2002, S&P concluded that while
NRG's liquidity position added uncertainty to FirstEnergy's sale of power plants
to NRG, its ratings would not be affected. S&P found FirstEnergy's cash flows
sufficiently stable to support a continued (although delayed) program of debt
and preferred stock redemption. S&P noted that it would continue to closely
monitor FirstEnergy's progress on various initiatives. On January 21, 2003, S&P
indicated its concern about FirstEnergy's disclosure of non-cash charges related
to deferred costs in Pennsylvania, pension and other post-retirement benefits,
and Emdersa (FirstEnergy's Argentina operations), which were higher than
anticipated in the third quarter of 2002. S&P identified the restart of the
Davis-Besse nuclear plant "...without significant delay beyond April 2003..." as
key to maintaining its current debt ratings. S&P also identified other issues it
would continue to monitor including: FirstEnergy's deleveraging efforts, free
cash generated during 2003, the Jersey Central Power & Light Company rate case,
successful hedging of its short power position, and continued capture of
projected merger savings. While FirstEnergy anticipates being prepared to
restart the Davis-Besse plant in the spring of 2003 the Nuclear Regulatory
Commission (NRC) must authorize the unit's restart following a formal inspection
process prior to its returning the unit to service. Significant delays in the
planned date of Davis-Besse's return to service or other factors (identified
above) affecting the speed with which FirstEnergy reduces debt could put
additional pressure on Met-Ed's credit ratings.
Market Risk Information
We use various market risk sensitive instruments, including derivative
contracts, primarily to manage the risk of price fluctuations. Our Risk Policy
Committee, comprised of FirstEnergy executive officers, exercises an independent
risk oversight function to ensure compliance with corporate risk management
policies and prudent risk management practices.
Commodity Price Risk
We are exposed to market risk primarily due to fluctuations in
electricity and natural gas prices. To manage the volatility relating to these
exposures, we use a variety of non-derivative and derivative instruments,
including options and futures contracts. The derivatives are used for hedging
purposes. Most of our non-hedge derivative contracts represent non-trading
positions that do not qualify for hedge treatment under Statement of Financial
Accounting Standards (SFAS) 133. The change in the fair value of commodity
derivative contracts related to energy production during 2002 is summarized in
the following table:
Increase (Decrease) in the Fair Value
of Commodity Derivative Contracts
Non-Hedge Hedge Total
--------- ----- -----
(In millions)
Change in the Fair Value of Commodity Derivative Contracts
Outstanding net asset as of January 1, 2002................. $ 2.2 $ 0.1 $ 2.3
New contract value when entered............................. -- -- --
Additions/Increase in value of existing contracts........... 15.2 1.6 16.8
Settled contracts........................................... -- (1.6) (1.6)
-------------------------------
Net Assets - Derivatives Contracts as of December 31, 2002 (1) $17.4 $ 0.1 $ 17.5
===============================
Impact of Changes in Commodity Derivative Contracts (2)
Balance Sheet Effects:
Regulatory Liability..................................... $ 15.2 $ -- $ 15.2
(1) Includes $17.0 million in non-hedge commodity derivative contracts which are
offset by a regulatory liability.
(2) Represents the increase in value of existing contracts and settled contracts
5
Derivatives included on the Consolidated Balance Sheet as of December 31, 2002:
Non-Hedge Hedge Total
--------- ----- -----
(In millions)
Current-
Other Assets................... $ -- $0.1 $ 0.1
Non-Current-
Other Deferred Charges......... 17.4 -- 17.4
------ ---- ------
Net assets................... $17.4 $0.1 $17.5
===== ==== =====
The valuation of derivative contracts is based on observable market
information to the extent that such information is available. In cases where
such information is not available, we rely on model-based information. The model
provides estimates of future regional prices for electricity and an estimate of
related price volatility. We use these results in developing estimates of fair
value for financial reporting purposes and for internal management decision
making. Sources of information for the valuation of derivative contracts by year
are summarized in the following table:
Source of Information - Fair Value by Contract Year
2003 2004 2005 2006 Thereafter Total
---- ---- ---- ---- ---------- -----
(In millions)
Prices based on external sources...... $0.5 $0.6 $1.5 $ -- $ -- $ 2.6
Prices based on models(1)............. -- -- -- 2.2 12.7 14.9
-------------------------------------------------------------------
Total(2).......................... $0.5 $0.6 $1.5 $2.2 $12.7 $17.5
===================================================================
(1) Broker quote sheets.
(2) Includes $17.0 million from an embedded option that is offset by a
regulatory liability and does not affect earnings.
We perform sensitivity analyses to estimate our exposure to the market
risk of our commodity position. A hypothetical 10% adverse shift in quoted
market prices in the near term on derivative instruments would not have had a
material effect on our consolidated financial position or cash flows as of
December 31, 2002.
Interest Rate Risk
Our exposure to fluctuations in market interest rates is reduced since
our debt has fixed interest rates, as noted in the following table.
Comparison of Carrying Value to Fair Value
There- Fair
2003 2004 2005 2006 2007 after Total Value
- ------------------------------------------------------------------------------------------------------------------
(Dollars in millions)
Assets
Investments other than Cash and Cash
Equivalents-Fixed Income.. -- -- -- -- -- $ 54 $ 54 $54
Average interest rate..... 4.6% 4.6%
- ------------------------------------------------------------------------------------------------------------------
Liabilities
- ------------------------------------------------------------------------------------------------------------------
Long-term Debt:
Fixed rate................... $60 $40 $50 $151 $51 $235 $587 $598
Average interest rate .... 7.0% 6.3% 7.0% 5.9% 5.9% 7.6% 6.8%
- ------------------------------------------------------------------------------------------------------------------
Preferred Stock.............. -- -- -- -- -- $ 92 $ 92 $100
Average dividend rate .... 7.4% 7.4%
- ------------------------------------------------------------------------------------------------------------------
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.
Equity Price Risk
Included in nuclear decommissioning trusts are marketable equity
securities carried at their market value of approximately $81 million and $91
million at December 31, 2002 and 2001, respectively. A hypothetical 10% decrease
in
6
prices quoted by stock exchanges would result in an $8 million reduction in fair
value at December 31, 2002. (See Note 1 - "Supplemental Cash Flows
Information.")
Outlook
Our industry continues to transition to a more competitive environment.
As of January 1, 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. The PPUC authorized our
rate restructuring plan, establishing separate charges for transmission,
distribution, generation and stranded cost recovery, which is recovered through
a CTC. Customers electing to obtain power from an alternative supplier have
their bills reduced based on the regulated generation component, and the
customers receive a generation charge from the alternative supplier. 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,
which is referred to as our PLR obligation.
Regulatory assets are costs which regulatory agencies have authorized
for recovery from customers in future periods and, without such authorization,
would have been charged to income when incurred. All of our regulatory assets
are expected to continue to be recovered under the provisions of the regulatory
plans as discussed below. Our regulatory assets totaled $1.2 billion and $1.3
billion as of December 31, 2002 and 2001, respectively.
Regulatory Matters
Effective September 1, 2002, we assigned our provider of last resort
(PLR) responsibility to our unregulated supply affiliate, FirstEnergy Solutions
Corp. (FES), through a wholesale power sale agreement which expires in December
2003 and may be extended for each successive calendar year. Under the terms of
the wholesale agreement, FES assumed the supply obligation, and the energy
supply profit and loss risk, for the portion of power supply requirements that
we do not self-supply under our non-utility generation (NUG) contracts and other
existing power contracts with nonaffiliated third party suppliers. This
arrangement reduces our exposure to high wholesale power prices by providing
power at or below the shopping credit for our uncommitted PLR energy costs
during the term of the agreement to FES. We will continue to defer the cost
differences between NUG contract rates and the rates reflected in our capped
generation rates.
In its February 21, 2002 decision on Petitions for Review regarding the
June 2001 PPUC orders which approved the FirstEnergy/GPU merger and provided us
deferral accounting treatment for energy costs, the Commonwealth Court of
Pennsylvania affirmed the PPUC merger decision, remanding the decision to the
PPUC only with respect to the issue of merger savings. The Court reversed the
PPUC's decision regarding our PLR obligations, and denied us authority to defer
for future recovery the difference between our wholesale power costs and the
amount we collect from retail customers. We and the PPUC each filed a Petition
for Allowance of Appeal with the Pennsylvania Supreme Court in March 2002,
asking it to review the Commonwealth Court decision. In the first quarter of
2002, we established a $103.0 million reserve against our PLR deferred energy
costs incurred prior to our acquisition by FirstEnergy. The reserve reflected
the potential adverse impact of a pending Pennsylvania Supreme Court decision
whether to review the Commonwealth Court ruling. The reserve increased goodwill
by an aggregate net of tax amount of $60.3 million. On January 17, 2003, the
Pennsylvania Supreme Court denied further appeals of the Commonwealth Court's
decision, which effectively affirmed the PPUC's order approving the merger
between FirstEnergy and GPU, let stand the Commonwealth Court's denial of our
request for PLR rate relief and remanded the merger savings issue back to the
PPUC.
FERC Regulatory Matters
On December 19, 2002 the Federal Energy Regulatory Commission (FERC)
granted unconditional Regional Transmission Organization status to PJM
Interconnection, LLC (PJM). We are a transmission owner in PJM.
Environmental Matters
We have been named as a "potentially responsible party" (PRP) at waste
disposal sites which may require cleanup under the Comprehensive Environmental
Response, Compensation and Liability Act of 1980. Allegations of disposal of
hazardous substances at historical sites and the liability involved are often
unsubstantiated and subject to dispute; however, federal law provides that all
PRPs for a particular site be held liable on a joint and several basis.
Therefore, potential environmental liabilities have been recognized on the
Consolidated Balance Sheet as of December 31, 2002, based on estimates of the
total costs of cleanup, our proportionate responsibility for such costs and the
financial ability of other nonaffiliated entities to pay. We have accrued
liabilities aggregating approximately $0.2 million as of December 31, 2002. We
do not believe environmental remediation costs will have a material adverse
effect on our financial condition, cash flows or results of operations.
7
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 50% ownership interest in TMI-2, which was damaged during a
1979 accident. As a result of the accident, claims for alleged personal injury
against Met-Ed, Jersey Central Power & Light Company, Pennsylvania Electric
Company and GPU (the defendants) had been 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. In January
2002, the District Court granted our motion for summary judgment on the
remaining 2,100 pending claims. In February 2002, the plaintiffs filed a notice
of appeal of this decision (see Note 6 - Other Legal Proceedings). In December
2002, the Court of Appeals for the Third Circuit refused to hear the appeal,
which effectively ended further legal action for those claims.
Significant Accounting Policies
We prepare our consolidated financial statements in accordance with
accounting principles that are generally accepted in the United States.
Application of these principles often requires a high degree of judgment,
estimates and assumptions that affect financial results. All of our assets are
subject to their own specific risks and uncertainties and are regularly reviewed
for impairment. Assets related to the application of the policies discussed
below are similarly reviewed with their risks and uncertainties reflecting these
specific factors. Our more significant accounting policies are described below.
Purchase Accounting
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 were finalized in
the fourth quarter of 2002, primarily consist of: (1) revaluation of certain
property, plant and equipment; (2) adjusting preferred stock subject to
mandatory redemption and long-term debt to estimated fair value; (3) recognizing
additional obligations related to retirement benefits; and (4) recognizing
estimated severance and other compensation liabilities. The excess of the
purchase price over the estimated fair values of the assets acquired and
liabilities assumed was recognized as goodwill. Based on the guidance provided
by SFAS 142, "Goodwill and Other Intangible Assets," we evaluate our goodwill
for impairment at least annually and would make such an evaluation more
frequently if indicators of impairment should arise. The forecasts used in our
evaluations of goodwill reflect operations consistent with our general business
assumptions. Unanticipated changes in those assumptions could have a significant
effect on our future evaluations of goodwill. As of December 31, 2002, we had
recorded goodwill of approximately $885.8 million 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 Pennsylvania, a significant amount of
regulatory assets have been recorded - $1.2 billion as of December 31, 2002. We
regularly review these assets to assess their ultimate recoverability within the
approved regulatory guidelines. Impairment risk associated with these assets
relates to potentially adverse legislative, judicial or regulatory actions in
the future.
Derivative Accounting
Determination of appropriate accounting for derivative transactions
requires the involvement of management representing operations, finance and risk
assessment. In order to determine the appropriate accounting for derivative
transactions, the provisions of the contract need to be carefully assessed in
accordance with the authoritative accounting literature and management's
intended use of the derivative. New authoritative guidance continues to shape
the application of derivative accounting. Management's expectations and
intentions are key factors in determining the appropriate accounting for a
derivative transaction and, as a result, such expectations and intentions are
documented. Derivative contracts that are determined to fall within the scope of
SFAS 133, as amended, must be recorded at their fair value. Active market prices
are not always available to determine the fair value of the later years of a
contract, requiring that various assumptions and estimates be used in their
valuation. We continually monitor our derivative contracts to determine if our
activities, expectations, intentions, assumptions and estimates remain valid. As
part of our normal operations, we enter into commodity contracts which increase
the impact of derivative accounting judgments.
8
Revenue Recognition
We follow the accrual method of accounting for revenues, recognizing
revenue for kilowatt-hours that have been delivered but not yet billed through
the end of the accounting period. The determination of unbilled revenues
requires management to make various estimates including:
o Net energy generated or purchased for retail load
o Losses of energy over transmission and distribution lines
o Mix of kilowatt-hour usage by residential, commercial and industrial
customers
o Kilowatt-hour usage of customers receiving electricity from alternative
suppliers
Pension and Other Postretirement Benefits Accounting
Our reported costs of providing non-contributory defined pension
benefits and postemployment benefits other than pensions (OPEB) are dependent
upon numerous factors resulting from actual plan experience and certain
assumptions.
Pension and OPEB costs are affected by employee demographics (including
age, compensation levels, and employment periods), the level of contributions we
make to the plans, and earnings on plan assets. Pension and OPEB costs may also
be affected by changes to key assumptions, including anticipated rates of return
on plan assets, the discount rates and health care trend rates used in
determining the projected benefit obligations and pension and OPEB costs.
In accordance with SFAS 87, "Employers' Accounting for Pensions" and
SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions," changes in pension and OPEB obligations associated with these factors
may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
In selecting an assumed discount rate, we consider currently available
rates of return on high-quality fixed income investments expected to be
available during the period to maturity of the pension and other postretirement
benefit obligations. Due to the significant decline in corporate bond yields and
interest rates in general during 2002, we reduced the assumed discount rate as
of December 31, 2002 to 6.75% from 7.25% used in 2001 and 7.75% used in 2000.
Our assumed rate of return on pension plan assets considers historical
market returns and economic forecasts for the types of investments held by our
pension trusts. The market values of our pension assets have been affected by
sharp declines in the equity markets since mid-2000. In 2002, plan assets have
earned (11.3)%. Our pension costs in 2002 were computed assuming a 10.25% rate
of return on plan assets. As of December 31, 2002 the assumed return on plan
assets was reduced to 9.00% based upon our projection of future returns and
pension trust investment allocation of approximately 60% large cap equities, 10%
small cap equities and 30% bonds.
Based on pension assumptions and pension plan assets as of December 31,
2002, we will not be required to fund our pension plans in 2003. While OPEB plan
assets have also been affected by sharp declines in the equity market, the
impact is not as significant due to the relative size of the plan assets.
However, health care cost trends have significantly increased and will affect
future OPEB costs. The 2003 composite health care trend rate assumption is
approximately 10%-12% gradually decreasing to 5% in later years, compared to our
2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in
later years. In determining our trend rate assumptions, we included the specific
provisions of our health care plans, the demographics and utilization rates of
plan participants, actual cost increases experienced in our health care plans,
and projections of future medical trend rates. Our non-cash, pre-tax pension and
OPEB expense under SFAS 87 and SFAS 106 is expected to increase by $18 million
and $6 million, respectively - a total of $24 million in 2003 as compared to
2002.
9
Increase in Costs from Adverse Changes in Key Assumptions
-----------------------------------------------------------------------------
Assumption Adverse Change Pension OPEB Total
-----------------------------------------------------------------------------
(In millions)
Discount rate................ Decrease by 0.25% $1.3 $0.8 $2.1
Long-term return on assets... Decrease by 0.25% 0.9 0.2 1.1
Health care trend rate....... Increase by 1% na 2.3 2.3
Long-Lived Assets
In accordance with SFAS 144, "Accounting for the Impairment or Disposal
of Long-Lived Assets," we periodically evaluate our long-lived assets to
determine whether conditions exist that would indicate that the carrying value
of an asset may not be fully recoverable. The accounting standard requires that
if the sum of future cash flows (undiscounted) expected to result from an asset
is less than the carrying value of the asset, an asset impairment must be
recognized in the financial statements. If impairment were to occur, other than
of a temporary nature, we would recognize a loss - calculated as the difference
between the carrying value and the estimated fair value of the asset (discounted
future net cash flows).
Recently Issued Accounting Standards Not Yet Implemented
SFAS 143, "Accounting for Asset Retirement Obligations"
In June 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. However, rate-regulated entities may recognize regulatory
assets or liabilities if the criteria for such treatment are met. Upon
retirement, a gain or loss would be recorded if the cost to settle the
retirement obligation differs from the carrying amount.
We have identified applicable legal obligations as defined under the new
standard, principally for nuclear power plant decommissioning. Upon adoption of
SFAS 143, asset retirement costs of $186 million will be recorded as part of the
carrying amount of the related long-lived asset, offset by accumulated
depreciation of $186 million.
The asset retirement liability at the date of adoption will be $198
million. As of December 31, 2002, we had recorded decommissioning liabilities of
$260 million. The change in the estimated liabilities resulted from changes in
methodology and various assumptions, including changes in the projected dates
for decommissioning.
Management expects that substantially all of our nuclear decommissioning
costs will be recoverable through regulated rates. Therefore, we recognized a
regulatory liability of $61 million upon adoption of SFAS 143 for the transition
amounts related to establishing the asset retirement obligations for nuclear
decommissioning. The remaining cumulative effect adjustment to recognize the
undepreciated asset retirement cost and the asset retirement liability offset by
the reversal of the previously recorded decommissioning liabilities was a $0.4
million increase to income, or $0.2 million net of tax.
SFAS 146, "Accounting for costs Associated with Exit or Disposal
Activities"
This statement, which was issued by the FASB in July 2002, requires the
recognition of costs associated with exit or disposal activities at the time
they are incurred rather than when management commits to a plan of exit or
disposal. It also requires the use of fair value for the measurement of such
liabilities. The new standard supersedes guidance provided by Emerging Issues
Task Force Issue No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (including Certain
Costs Incurred in a Restructuring)." This new standard was effective for exit
and disposal activities initiated after December 31, 2002. Since it is applied
prospectively, there will be no impact upon adoption. However, SFAS 146 could
change the timing and amount of costs recognized in connection with future exit
or disposal activities.
FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others - an interpretation of FASB Statements No. 5, 57,
and 107 and rescission of FASB Interpretation No. 34"
10
The FASB issued FIN 45 in January 2003. This interpretation identifies
minimum guarantee disclosures required for annual periods ending after December
15, 2002. It also clarifies that providers of guarantees must record the fair
value of those guarantees at their inception. This accounting guidance is
applicable on a prospective basis to guarantees issued or modified after
December 31, 2002. We do not believe that implementation of FIN 45 will be
material but we will continue to evaluate anticipated guarantees.
FIN 46, "Consolidation of Variable Interest Entities - an interpretation
of ARB 51"
In January 2003, the FASB issued this interpretation of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. This Interpretation requires an enterprise to
disclose the nature of its involvement with a VIE if the enterprise has a
significant variable interest in the VIE and to consolidate a VIE if the
enterprise is the primary beneficiary. VIEs created after January 31, 2003 are
immediately subject to the provisions of FIN 46. VIEs created before February 1,
2003 are subject to this interpretation's provisions in the first interim or
annual reporting period beginning after June 15, 2003 (our third quarter of
2003). The FASB also identified transitional disclosure provisions for all
financial statements issued after January 31, 2003.
We currently have transactions with entities in connection with the sale
of preferred securities, which may fall within the scope of this interpretation,
and which are reasonably possible of meeting the definition of a VIE in
accordance with FIN 46. We currently consolidate these entities and believe we
will continue to consolidate following the adoption of FIN 46.
11
METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
Nov 7 - Jan. 1 -
2002 Dec. 31, 2001 Nov. 6, 2001 2000
- ---------------------------------------------------------------------------------------------------------------------
(In thousands)
OPERATING REVENUES (Note 1)............................... $ 986,608 $ 143,760 | $ 824,556 $ 842,333
--------- --------- | --------- ----------
|
OPERATING EXPENSES AND TAXES: |
Fuel and purchased power (Note 1)...................... 604,305 83,275 | 478,954 471,070
Other operating costs (Note 1)......................... 115,371 16,122 | 123,094 91,456
--------- --------- | --------- ----------
Total operation and maintenance expenses............. 719,676 99,397 | 602,048 562,526
Provision for depreciation and amortization............ 81,419 8,903 | 51,867 68,695
General taxes.......................................... 66,795 6,509 | 39,845 42,623
Income taxes........................................... 27,447 11,584 | 28,549 33,278
--------- --------- | --------- ----------
Total operating expenses and taxes................... 895,337 126,393 | 722,309 707,122
--------- --------- | --------- ----------
|
OPERATING INCOME.......................................... 91,271 17,367 | 102,247 135,211
|
OTHER INCOME.............................................. 21,742 5,465 | 7,807 1,387
--------- --------- | --------- ----------
|
INCOME BEFORE NET INTEREST CHARGES........................ 113,013 22,832 | 110,054 136,598
--------- --------- | --------- ----------
|
NET INTEREST CHARGES: |
Interest on long-term debt............................. 40,774 5,615 | 33,101 37,886
Allowance for borrowed funds used during |
construction......................................... (470) 30 | (574) (477)
Deferred interest...................................... (710) (276) | (321) --
Other interest expense ................................ 2,636 1,744 | 9,219 10,638
Subsidiary's preferred stock dividend requirements..... 7,559 1,102 | 6,248 6,656
--------- --------- | --------- ----------
Net interest charges................................. 49,789 8,215 | 47,673 54,703
--------- --------- | --------- ----------
|
NET INCOME................................................ $ 63,224 $ 14,617 | $ 62,381 $ 81,895
========= ========= | ========= ==========
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
12
METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31, 2002 2001
- ------------------------------------------------------------------------------------------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service..................................................................... $1,620,613 $1,609,974
Less-Accumulated provision for depreciation.................................... 547,925 530,006
---------- ----------
1,072,688 1,079,968
Construction work in progress-
Electric plant............................................................... 16,078 14,291
---------- -----------
1,088,766 1,094,259
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts........................................... 155,690 157,699
Long-term notes receivable from associated companies........................... 12,418 12,418
Other.......................................................................... 19,206 13,391
---------- ----------
187,314 183,508
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents...................................................... 15,685 25,274
Receivables-
Customers (less accumulated provisions of $4,810,000 and $12,271,000
respectively, for uncollectible accounts)................................. 120,868 112,257
Associated companies......................................................... 23,219 8,718
Other........................................................................ 18,235 16,675
Prepayments and other.......................................................... 9,731 12,239
---------- ----------
187,738 175,163
---------- ----------
DEFERRED CHARGES:
Regulatory assets.............................................................. 1,179,125 1,320,412
Goodwill....................................................................... 885,832 784,443
Other.......................................................................... 36,030 49,402
---------- ----------
2,100,987 2,154,257
---------- ----------
$3,564,805 $3,607,187
========== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity.................................................... $1,315,586 $1,288,953
Company - obligated trust preferred securities................................. 92,409 92,200
Long-term debt................................................................. 538,790 583,077
---------- ----------
1,946,785 1,964,230
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt............................................... 60,467 30,029
Short-term borrowings (Note 5)-
Associated companies......................................................... 88,299 72,011
Accounts payable-
Associated companies......................................................... 56,861 67,351
Other........................................................................ 28,583 36,750
Accrued taxes................................................................. 16,096 7,037
Accrued interest............................................................... 16,448 17,468
Other.......................................................................... 11,690 13,652
---------- ----------
278,444 244,298
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes.............................................. 316,757 300,438
Accumulated deferred investment tax credits.................................... 12,518 13,310
Power purchase contract loss liability......................................... 660,507 730,662
Nuclear fuel disposal costs.................................................... 37,541 36,906
Nuclear plant decommissioning costs............................................ 270,611 268,967
Other.......................................................................... 41,642 48,376
---------- ----------
1,339,576 1,398,659
---------- ----------
COMMITMENTS AND CONTINGENCIES
(Notes 3 and 6)................................................................. ---------- ----------
$3,564,805 $3,607,187
========== ==========
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.
13
METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31, 2002 2001
- ------------------------------------------------------------------------------------------------------------------
(Dollars in thousands, except per share amounts)
COMMON STOCKHOLDER'S EQUITY:
Common stock, without par value, authorized 900,000 shares
859,500 shares outstanding........................................................ $1,297,784 $1,274,325
Accumulated other comprehensive income (Note 4E).................................... (39) 11
Retained earnings (Note 4A)......................................................... 17,841 14,617
---------- ----------
Total common stockholder's equity................................................. 1,315,586 1,288,953
---------- ----------
COMPANY OBLIGATED TRUST
PREFERRED SECURITIES
OF SUBSIDIARY TRUST
(NOTE 4C):
7.35% due 2039.................................................................... 92,409 92,200
---------- ----------
LONG-TERM DEBT (Note 4D):
First mortgage bonds:
8.05% due 2002.................................................................... -- 30,000
6.60% due 2003.................................................................... 20,000 20,000
7.22% due 2003.................................................................... 40,000 40,000
9.10% due 2003.................................................................... -- 30,000
6.34% due 2004.................................................................... 40,000 40,000
6.77% due 2005.................................................................... 30,000 30,000
7.35% due 2005.................................................................... 20,000 20,000
6.36% due 2006.................................................................... 17,000 17,000
6.40% due 2006.................................................................... 33,000 33,000
6.00% due 2008.................................................................... 8,700 8,700
6.10% due 2021.................................................................... 28,500 28,500
8.60% due 2022.................................................................... 30,000 30,000
8.80% due 2022.................................................................... 30,000 30,000
6.97% due 2023.................................................................... 30,000 30,000
7.65% due 2023.................................................................... 30,000 30,000
8.15% due 2023.................................................................... 60,000 60,000
5.95% due 2027.................................................................... 13,690 13,690
---------- ----------
Total first mortgage bonds...................................................... 430,890 490,890
Secured note:
5.72% due 2006.................................................................... 100,000 100,000
5.93% due 2007.................................................................... 50,000 --
----------- ----------
Total Secured notes............................................................. 150,000 100,000
Unsecured note:
7.69% due 2039.................................................................... 5,968 5,997
Net unamortized premium on debt..................................................... 12,399 16,219
Long-term debt due within one year.................................................. (60,467) (30,029)
---------- ----------
Total long-term debt ........................................................... 538,790 583,077
---------- ----------
TOTAL CAPITALIZATION................................................................... $1,946,785 $1,964,230
========== ==========
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
14
METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
Common Stock Accumulated
----------------- Other Other
Comprehensive Number Carrying Paid-In Comprehensive Retained
Income of Shares Value Capital Income (Loss) Earnings
------------- --------- -------- ------- ------------- ---------
(Dollars in thousands)
Balance, January 1, 2000....................... 859,500 $ 66,273 $400,200 $21,363 $ 13,581
Net income.................................. $81,895 81,895
Net unrealized gain (loss) on investments... (21,295) (21,295)
Minimum pension liability................... (4) (4)
-------
Comprehensive income........................ 60,596
-------
Cash dividends on common stock.............. (25,000)
- ---------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2000..................... 859,500 66,273 400,200 64 70,476
Net income.................................. 62,381 62,381
Net unrealized gain (loss) on investments... 5 5
Net unrealized gain (loss) on derivative
instruments............................... (174) (174)
-------
Comprehensive income........................ 62,212
-------
Cash dividends on common stock.............. (65,000)
- ---------------------------------------------------------------------------------------------------------------------
Balance, November 6, 2001...................... 859,500 66,273 400,200 (105) 67,857
Purchase accounting fair value adjustment... 1,208,052 (400,200) 105 (67,857)
- ---------------------------------------------------------------------------------------------------------------------
Balance, November 7, 2001...................... 859,500 1,274,325 -- -- --
Net income.................................. 14,617 14,617
Net unrealized gain (loss) on investments... 22 22
Net unrealized gain (loss) on derivative
instruments.............................. (11) (11)
-------
Comprehensive income........................ 14,628
- ---------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2001..................... 859,500 1,274,325 -- 11 14,617
Net income.................................. 63,224 63,224
Net unrealized gain (loss) on investments... 17 17
Net unrealized gain (loss) on derivative
instruments............................... (67) (67)
-------
Comprehensive income........................ $63,174
-------
Cash dividends on common stock.............. (60,000)
Purchase accounting fair value adjustment... 23,459
- ---------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2002..................... 859,500 $1,297,784 $ -- $ (39) $ 17,841
=====================================================================================================================
CONSOLIDATED STATEMENTS OF PREFERRED STOCK
Subject to
Mandatory Redemption
---------------------
Number Carrying
of Shares Value
--------- --------
(Dollars in thousands)
Balance, January 1, 2000............ 4,000,000 $100,000
==============================================================
Balance, December 31, 2000.......... 4,000,000 100,000
==============================================================
Purchase accounting fair
value adjustment.............. (7,800)
--------------------------------------------------------------
Balance, December 31, 2001.......... 4,000,000 92,200
Amortization of fair market
value adjustment.............. 209
--------------------------------------------------------------
Balance, December 31, 2002.......... 4,000,000 $ 92,409
==============================================================
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
15
METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Nov. 7 - Jan. 1 -
2002 Dec. 31, 2001 Nov. 6, 2001 2000
- -----------------------------------------------------------------------------------------------------------------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income $ 63,224 $ 14,617 | $ 62,381 $ 81,895
Adjustments to reconcile net income to net |
cash from operating activities: |
Provision for depreciation and amortization................ 81,419 8,903 | 51,867 68,695
Other amortization......................................... (2,528) 154 | 1,147 5,684
Impact of PPUC rate order, net............................. -- -- | -- (44,580)
Deferred costs recoverable as regulatory assets............ (18,938) 1,045 | (91,182) (7,941)
Deferred income taxes, net................................. 23,356 906 | 53,464 22,483
Investment tax credits, net................................ (792) (128) | (721) (851)
Receivables................................................ (24,672) 10,213 | 33,714 33,348
Accounts payable........................................... (18,657) (4,339) | (60,868) (48,395)
Other (Note 7)............................................. (538) 8,286 | (59,313) (25,896)
--------- -------- | -------- --------
Net cash provided from (used for) operating activities... 101,874 39,657 | (9,511) 84,442
--------- -------- | -------- --------
|
CASH FLOWS FROM FINANCING ACTIVITIES: |
New Financing- |
Long-term debt............................................. 49,750 -- | 99,500 --
Short-term borrowings, net................................. 16,288 -- | 51,400 46,600
Redemptions and Repayments- |
Long-term debt............................................. (60,000) -- | -- (50,000)
Short-term borrowings, net................................. -- (25,989) | -- --
Dividend Payments- |
Common stock............................................... (60,000) -- | (65,000) (25,000)
--------- --------- | -------- --------
Net cash provided from (used for) financing activities... (53,962) (25,989) | 85,900 (28,400)
--------- -------- | -------- --------
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
Property additions........................................... (44,533) (7,787) | (47,660) (58,481)
Contributions to decommissioning trusts...................... -- -- | (7,113) (8,700)
Sale of investments.......................................... -- -- | -- 3,519
Other........................................................ (12,968) (453) | (5,209) --
--------- -------- | -------- --------
Net cash provided from (used for) investing activities... (57,501) (8,240) | (59,982) (63,662)
--------- -------- | -------- --------
|
|
Net increase (decrease) in cash and cash equivalents............ (9,589) 5,428 | 16,407 (7,620)
Cash and cash equivalents at beginning of period................ 25,274 19,846 | 3,439 11,059
--------- ------- | -------- --------
Cash and cash equivalents at end of period...................... $ 15,685 $25,274 | $ 19,846 $ 3,439
========= ======= | ======== ========
|
SUPPLEMENTAL CASH FLOWS INFORMATION: |
Cash Paid During the Year- |
Interest (net of amounts capitalized)...................... $ 46,266 $ -- | $ 41,473 $ 47,451
========= ======= | ======== ========
Income taxes (refund)...................................... $ 34,385 $(2,990) | $ 7,486 $ 45,534
========= ======= | ======== ========
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
16
METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF TAXES
Nov. 7 - Jan. 1 -
2002 Dec. 31, 2001 Nov. 6, 2001 2000
- -----------------------------------------------------------------------------------------------------------------------
(In thousands)
GENERAL TAXES:
Real and personal property...................................... $ 1,384 $ 5 | $ 1,236 $ 1,826
State gross receipts *.......................................... 56,043 5,730 | 31,353 35,288
Social security and unemployment................................ 1 (1) | 14 --
Other........................................................... 9,367 775 | 7,242 5,509
--------- --------- | -------- --------
Total general taxes...................................... $ 66,795 $ 6,509 | $ 39,845 $ 42,623
========= ========= | ======== ========
|
PROVISION FOR INCOME TAXES: |
Currently payable- |
Federal...................................................... $ 15,371 $ 7,693 | $(11,534) $ 17,080
State........................................................ 6,437 2,433 | (1,760) 5,377
--------- --------- | -------- --------
21,808 10,126 | (13,294) 22,457
--------- --------- | -------- --------
Deferred, net- |
Federal...................................................... 19,615 934 | 41,297 19,476
State........................................................ 3,741 (28) | 12,167 3,007
--------- ---------- | --------- --------
23,356 906 | 53,464 22,483
--------- --------- | -------- --------
Investment tax credit amortization.............................. (792) (128) | (721) (851)
--------- --------- | -------- --------
Total provision for income taxes......................... $ 44,372 $ 10,904 | $ 39,449 $ 44,089
========= ========== | ======== ========
|
INCOME STATEMENT CLASSIFICATION |
OF PROVISION FOR INCOME TAXES: |
Operating income................................................ $ 27,447 $ 11,584 | $ 28,549 $ 33,278
Other income.................................................... 16,925 (680) | 10,900 10,811
---------- --------- | -------- --------
Total provision for income taxes......................... $ 44,372 $ 10,904 | $ 39,449 $ 44,089
========= ========= | ======== ========
|
RECONCILIATION OF FEDERAL INCOME TAX |
EXPENSE AT STATUTORY RATE TO TOTAL |
PROVISION FOR INCOME TAXES: |
Book income before provision for income taxes................... $107,596 $ 25,521 | $101,831 $125,983
========= ========= | ======== ========
Federal income tax expense at statutory rate.................... $ 37,659 $ 8,932 | $ 35,641 $ 44,094
Increases (reductions) in taxes resulting from- |
Amortization of investment tax credits....................... (792) (128) | (721) (851)
Depreciation................................................. 1,362 304 | 926 300
State income tax, net of federal benefit..................... 6,107 938 | 7,388 7,379
Allocated share of consolidated tax savings.................. -- -- | (3,151) --
Other, net................................................... 36 858 | (634) (6,833)
--------- --------- | -------- --------
Total provision for income taxes......................... $ 44,372 $ 10,904 | $ 39,449 $ 44,089
========= ========= | ======== ========
|
ACCUMULATED DEFERRED INCOME TAXES AT |
DECEMBER 31: |
Property basis differences...................................... $ 217,351 $ 211,394 | $203,352
Nuclear decommissioning......................................... (4,247) (5,623) | (9,797)
Deferred sale and leaseback costs............................... (11,366) (12,077) | (11,298)
Non-utility generation costs.................................... (4,832) 36,099 | 12,238
Purchase accounting basis difference............................ (642) (37,143) | --
Sale of generation assets....................................... (1,419) (1,420) | (1,397)
Regulatory transition charge.................................... 88,315 85,414 | 69,828
Customer receivables for future income taxes.................... 50,259 49,755 | 51,247
Other........................................................... (16,662) (25,961) | (35,164)
--------- --------- | --------
Net deferred income tax liability........................ $ 316,757 $ 300,438 | $279,009
========= ========= | ========
* Collected from customers through regulated rates and included in revenue on the Consolidated Statements of Income.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
17
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
The consolidated financial statements include Metropolitan Edison
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), Jersey Central Power & Light Company (JCP&L)
and Pennsylvania Electric Company (Penelec). The Company, JCP&L 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 Securities and Exchange Commission (SEC), the Pennsylvania Public Utility
Commission (PPUC) and the Federal Energy Regulatory Commission (FERC). The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States (GAAP) requires management to make
periodic estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses and the disclosure of contingent assets and
liabilities. Actual results could differ from these estimates. Certain prior
year amounts have been reclassified to conform with the current year
presentation.
(A) CONSOLIDATION-
The Company consolidates all majority-owned subsidiaries, after
eliminating the effects of intercompany transactions. Non-majority owned
investments, including investments in limited liability companies, partnerships
and joint ventures, are accounted for under the equity method when the Company
is able to influence their financial or operating policies. Investments in
corporations resulting in voting control of 20% or more are presumed to be
equity method investments. Limited partnerships are evaluated in accordance with
SEC Staff D-46, "Accounting for Limited Partnership Investments" and American
Institute of Certified Public Accountants (AICPA) Statement of Position (SOP)
78-9, "Accounting for Investments in Real Estate Ventures," which specify a 3 to
5 percent threshold for the presumption of influence. For all remaining
investments (excluding those within the scope of Statement of Financial
Accounting Standards (SFAS) 115, the Company applies the cost method.
(B) REVENUES-
The Company's principal business is providing electric service to
customers in Pennsylvania. The Company's retail customers are metered on a cycle
basis. Revenue is recognized for unbilled electric service provided through the
end of the year. See Note 7 - Other Information for discussion of reporting of
independent system operator transactions.
Receivables from customers include sales to residential, commercial and
industrial customers and sales to wholesale customers. There was no material
concentration of receivables as of December 31, 2002 or 2001, with respect to
any particular segment of the Company's customers.
(C) REGULATORY PLAN-
Pennsylvania enacted its electric utility competition law in 1996 with
the phase-in of customer choice for generation suppliers completed as of January
1, 2001. In 1998, the PPUC authorized a rate restructuring plan for the Company
which essentially resulted in the deregulation of the Company's generation
business. The Company has a continuing responsibility to provide power to those
customers not choosing to receive power from an alternative energy supplier,
subject to certain limits, which is referred to as the Company's provider of
last resort (PLR) obligation. In 2000, the PPUC disallowed a portion of the
requested additional stranded costs above those amounts granted in the Company's
1998 rate restructuring plan order. The PPUC required the Company to seek an
Internal Revenue Service (IRS) ruling regarding the return of certain
unamortized investment tax credits and excess deferred income tax benefits to
customers. If the IRS ruling ultimately supports returning these tax benefits to
customers, there would be no effect to the Company's net income since the
contingency existed prior to the Company being acquired by FirstEnergy.
As a result of its generating asset divestitures, the Company obtained
its supply of electricity to meet its PLR obligation almost entirely from
contracted and open market purchases. In 2000, the Company filed a petition with
the PPUC seeking permission to defer, for future recovery, energy costs in
excess of amounts reflected in its capped generation rates; the PPUC
subsequently consolidated this petition in January 2001 with the FirstEnergy/GPU
merger proceeding (see Note 2 - Merger).
In June 2001, the PPUC entered orders approving the Settlement
Stipulation with all of the major parties in the combined merger and rate relief
proceedings which approved the merger and provided the Company PLR rate relief.
18
The PPUC permitted the Company to defer, for future recovery, the difference
between its actual energy costs and those reflected in its capped generation
rates, retroactive to January 1, 2001. Correspondingly, in the event that energy
costs incurred by the Company were below its capped generation rates, that
difference would have reduced costs that had been deferred for recovery in
future periods. However, this PLR deferral accounting procedure was subsequently
denied in a court decision, as discussed below. The Company's PLR obligation
extends through December 31, 2010. Had the PLR accounting procedure been
allowed, competitive transition charge (CTC) revenues would have been applied to
the Company's PLR stranded costs during that period. The Company would have been
permitted to recover any remaining stranded costs through a continuation of the
CTC after December 31, 2010 through no later than December 31, 2015. Any amounts
not expected to be recovered by December 31, 2015 would have been written off at
the time such nonrecovery became probable.
Several parties had filed Petitions for Review in June and July 2001
with the Commonwealth Court of Pennsylvania regarding the June 2001 PPUC orders.
On February 21, 2002, the Court affirmed the PPUC decision regarding the
FirstEnergy/GPU merger, remanding the decision to the PPUC only with respect to
the issue of merger savings. The Court reversed the PPUC's decision regarding
the Company's PLR obligation, and rejected those parts of the settlement that
permitted the Company to defer for accounting purposes the difference between
its wholesale power costs and the amount that it collects from retail customers.
The Company and the PPUC each filed a Petition for Allowance of Appeal with the
Pennsylvania Supreme Court on March 25, 2002, asking it to review the
Commonwealth Court decision. Also on March 25, 2002, Citizens Power filed a
motion seeking an appeal of the Commonwealth Court's decision to affirm the
FirstEnergy/GPU merger with the Pennsylvania Supreme Court. In the first quarter
of 2002, the Company established a $103.0 million reserve for its PLR deferred
energy costs incurred prior to its acquisition by FirstEnergy. The reserve
reflected the potential adverse impact of a pending Pennsylvania Supreme Court
decision whether to review the Commonwealth Court ruling. The reserve increased
goodwill by an aggregate net of tax amount of $60.3 million. On January 17,
2003, the Pennsylvania Supreme Court denied further appeals of the February 21,
2002 Pennsylvania Commonwealth Court decision, which effectively affirmed the
PPUC's order approving the merger between FirstEnergy and GPU, let stand the
Commonwealth Court's denial of PLR rate relief for the Company and remanded the
merger savings issue back to the PPUC.
Effective September 1, 2002, the Company assigned its PLR responsibility
to FES through a wholesale power sale agreement. The PLR sale, which initially
ran through the end of 2002, was extended through December 2003 and will be
automatically extended for each successive calendar year unless any party elects
to cancel the agreement by November 1 of the preceding year. Under the terms of
the wholesale agreement, FES assumes the supply obligation and the energy supply
profit and loss risk for the portion of power supply requirements not
self-supplied by the Company under its non-utility generation (NUG) contracts
and other existing power contracts with nonaffiliated third party suppliers.
This arrangement reduces the Company's exposure to high wholesale power prices
by providing power at or below the shopping credit for its uncommitted PLR
energy costs during the term of the agreement with FES. The Company is
authorized to continue deferring differences between NUG contract costs and
amounts recovered through its capped generation rates.
The application of SFAS 71, "Accounting for the Effects of Certain Types
of Regulation," was discontinued in 1998 with respect to the Company's
generation operations. The Company subsequently divested substantially all of
its generating assets. The SEC issued interpretive guidance regarding asset
impairment measurement, concluding that any supplemental regulated cash flows
such as a CTC 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 $17
million as of December 31, 2002.
(D) PROPERTY, PLANT AND EQUIPMENT-
As a result of the merger, a portion of the Company's property, plant
and equipment was adjusted to reflect fair value. The majority of the Company's
property, plant and equipment continues to be reflected at original cost since
such assets remain subject to rate regulation on a historical cost basis. The
Company's accounting policy for planned major maintenance projects is to
recognize liabilities as they are incurred.
The Company provides for depreciation on a straight-line basis at
various rates over the estimated lives of property included in plant in service.
The annualized composite rate was approximately 3.0% in 2002, 3.0% in 2001 and
2.9% in 2000.
Annual depreciation expense in 2002 included approximately $9.5 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
(Saxton Nuclear Experimental Facility) owned by a wholly owned subsidiary of the
Company (in conjunction with JCP&L 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 $261.2 million in
current dollars and (using a 4.0% escalation rate) approximately $417.2 million
in future dollars. The estimated obligation and the escalation rate
19
were developed based on site specific studies. Decommissioning of the
demonstration nuclear reactor is expected to be completed in 2003; payments for
decommissioning of the nuclear generating units are expected to begin in 2014,
when actual decommissioning work is expected to begin. The Company has recovered
approximately $66.6 million for future decommissioning through its electric
rates from customers through December 31, 2002. The Company has also recognized
an estimated liability of approximately $3.7 million related to decontamination
and decommissioning of nuclear enrichment facilities operated by the United
States Department of Energy (DOE), as required by the Energy Policy Act of 1992.
In June 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. However, rate-regulated entities may recognize a regulatory
asset or liability instead, if the criteria for such treatment are met. Upon
retirement, a gain or loss would be recorded if the cost to settle the
retirement obligation differs from the carrying amount.
The Company has identified applicable legal obligations as defined under
the new standard, principally for nuclear power plant decommissioning. Upon
adoption of SFAS 143, asset retirement costs of $186 million will be recorded as
part of the carrying amount of the related long-lived asset, offset by
accumulated depreciation of $186 million.
The asset retirement liability at the date of adoption will be $198
million. As of December 31, 2002, the Company had recorded decommissioning
liabilities of $260 million. The change in the estimated liabilities resulted
from changes in methodology and various assumptions, including changes in the
projected dates for decommissioning.
Management expects that the Company's ultimate nuclear decommissioning
costs will be tracked and recovered through regulated rates. Therefore, the
Company recognized a regulatory liability of $61 million upon adoption of SFAS
143 for the transition amounts related to establishing the asset retirement
obligations for nuclear decommissioning. The remaining cumulative effect
adjustment to recognize the undepreciated asset retirement cost and the asset
retirement liability offset by the reversal of the previously recorded
decommissioning liabilities was a $0.4 million increase to income, or $0.2
million net of tax.
The FASB approved SFAS 141, "Business Combinations" and SFAS 142,
"Goodwill and Other Intangible Assets," on June 29, 2001. SFAS 141 requires all
business combinations initiated after June 30, 2001, to 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 the
FirstEnergy/GPU merger, which was accounted for as a purchase transaction, and
have not materially affected the accounting for this transaction. Under SFAS
142, amortization of existing goodwill ceased January 1, 2002. Instead, goodwill
is tested for impairment at least on an annual basis - based on the results of
the transition analysis and the 2002 annual analysis, no impairment of the
Company's goodwill is required.
(E) STOCK-BASED COMPENSATION-
FirstEnergy applies the recognition and measurement principles of
Accounting Principles Board Opinion No. 25 (APB 25), "Accounting for Stock
Issued to Employees" and related Interpretations in accounting for its
stock-based compensation plans (see Note 4B). No material stock-based employee
compensation expense is reflected in net income as all options granted under
those plans had an exercise price equal to the market value of the underlying
common stock on the grant date, resulting in substantially no intrinsic value.
If FirstEnergy had accounted for employee stock options under the fair
value method, a higher value would have been assigned to the options granted.
The weighted average assumptions used in valuing the options and their resulting
estimated fair values would be as follows:
2002 2001 2000
-----------------------------------------------------------------------------
Valuation assumptions:
Expected option term (years) 8.1 8.3 7.6
Expected volatility......... 23.31% 23.45% 21.77%
Expected dividend yield..... 4.36% 5.00% 6.68%
Risk-free interest rate..... 4.60% 4.67% 5.28%
Fair value per option......... $6.45 $4.97 $2.86
----------------------------------------------------------------------------
20
The effects of applying fair value accounting to the FirstEnergy's stock
options would not materially effect the Company's net income.
(F) 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 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 were included in the
final consolidated federal income tax return of GPU, and results for the period
November 7, 2001 through December 31, 2001 were included in FirstEnergy's 2001
consolidated federal income tax return. The consolidated tax liability is
allocated on a "stand-alone" company basis, with the Company recognizing the tax
benefit for any tax losses or credits it contributed to the consolidated return.
(G) 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. 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. 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 contributions, 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:
21
Other
Pension Benefits Postretirement Benefits
---------------- -----------------------
2002 2001 2002 2001
- -----------------------------------------------------------------------------------------------------------
(In millions)
Change in benefit obligation:
Benefit obligation as of January 1......... $3,547.9 $1,506.1 $ 1,581.6 $ 752.0
Service cost............................... 58.8 34.9 28.5 18.3
Interest cost.............................. 249.3 133.3 113.6 64.4
Plan amendments............................ -- 3.6 (121.1) --
Actuarial loss............................. 268.0 123.1 440.4 73.3
Voluntary early retirement program......... -- -- -- 2.3
GPU acquisition............................ (11.8) 1,878.3 110.0 716.9
Benefits paid.............................. (245.8) (131.4) (83.0) (45.6)
-------------------------------------------------------------------------------------------
Benefit obligation as of December 31....... 3,866.4 3,547.9 2,070.0 1,581.6
-------------------------------------------------------------------------------------------
Change in fair value of plan assets:
Fair value of plan assets as of January 1.. 3,483.7 1,706.0 535.0 23.0
Actual return on plan assets............... (348.9) 8.1 (57.1) 12.7
Company contribution....................... -- -- 37.9 43.3
GPU acquisition............................ -- 1,901.0 -- 462.0
Benefits paid.............................. (245.8) (131.4) (42.5) (6.0)
-------------------------------------------------------------------------------------------
Fair value of plan assets as of December 31 2,889.0 3,483.7 473.3 535.0
-------------------------------------------------------------------------------------------
Funded status of plan...................... (977.4) (64.2) (1,596.7) (1,046.6)
Unrecognized actuarial loss................ 1,185.8 222.8 751.6 212.8
Unrecognized prior service cost............ 78.5 87.9 (106.8) 17.7
Unrecognized net transition obligation..... -- -- 92.4 101.6
-------------------------------------------------------------------------------------------
Net amount recognized...................... $ 286.9 $ 246.5 $ (859.5) $ (714.5)
===========================================================================================
Consolidated Balance Sheets classification:
Prepaid (accrued) benefit cost............. $ (548.6) $ 246.5 $ (859.5) $ (714.5)
Intangible asset........................... 78.5 -- -- --
Accumulated other comprehensive loss....... 757.0 -- -- --
-------------------------------------------------------------------------------------------
Net amount recognized...................... $ 286.9 $ 246.5 $ (859.5) $ (714.5)
============================================================================================
Assumptions used as of December 31:
Discount rate.............................. 6.75% 7.25% 6.75% 7.25%
Expected long-term return on plan assets... 9.00% 10.25% 9.00% 10.25%
Rate of compensation increase.............. 3.50% 4.00% 3.50% 4.00%
Net pension and other postretirement benefit costs for the two years
ended December 31, 2002 were computed as follows:
Other
Pension Benefits Postretirement Benefits
-------------------- -----------------------
2002 2001 2002 2001
---------------------------------------------------------------------------------------------------
(In millions)
Service cost........................... $ 58.8 $ 34.9 $ 28.5 $18.3
Interest cost.......................... 249.3 133.3 113.6 64.4
Expected return on plan assets......... (346.1) (204.8) (51.7) (9.9)
Amortization of transition obligation (asset) -- (2.1) 9.2 9.2
Amortization of prior service cost..... 9.3 8.8 3.2 3.2
Recognized net actuarial loss (gain)... -- -- 11.2 4.9
Voluntary early retirement program..... -- 6.1 -- 2.3
---------------------------------------------------------------------------------------------------
Net periodic benefit cost (income)..... $ (28.7) $ (23.8) $114.0 $92.4
===================================================================================================
The composite health care cost trend rate assumption is approximately
10%-12% in 2003, 9% in 2004 and 8% in 2005, decreasing to 5% 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 cost trend
rate assumption by one percentage point would increase the total service and
interest cost components by $20.7 million and the postretirement benefit
obligation by $232.2 million. A decrease in the same assumption by one
percentage point would decrease the total service and interest cost components
by $16.7 million and the postretirement benefit obligation by $204.3 million.
A significant portion of the services provided to the Company are from
affiliates, GPU Service, Inc. (GPUS) and FirstEnergy Service Company (FECO) (see
Note 1H). Therefore, substantially all of the employees are with GPUS which
bills the Company for services rendered. See Note 7D for the Company's amount of
net pension and other postretirement benefit costs reflected in its Consolidated
Statements of Income.
22
(H) TRANSACTIONS WITH AFFILIATED COMPANIES-
Operating revenues, operating expenses and other income include
transactions with affiliated companies, primarily GPUS and FES. During the three
years ended December 31, 2002, GPUS provided legal, accounting, financial and
other services to the Company. The Company also entered into sale and purchase
transactions with affiliates (JCP&L and Penelec) during the period. Effective
September 1, 2002, the Company assigned its PLR responsibility to FES through a
wholesale power sale agreement. See Note 7 for affiliated companies'
transactions schedule.
FirstEnergy does not bill directly or allocate any of its costs to any
subsidiary company. Costs are allocated to the Company from its affiliates, GPUS
and FECO, both subsidiaries of FirstEnergy Corp. and both "mutual service
companies" as defined in Rule 93 of the 1935 Public Utility Holding Company Act
(PUHCA). The vast majority of costs are directly billed or assigned at no more
than cost as determined by PUHCA Rule 91. The remaining costs are for services
that are provided on behalf of more than one company, or costs that cannot be
precisely identified and are allocated using formulas that are filed annually
with the SEC on Form U-13-60. The current allocation or assignment formulas used
and their bases include multiple factor formulas: the ratio of each company's
amount of FirstEnergy's aggregate direct payroll, number of employees, asset
balances, revenues, number of customers and other factors; and specific
departmental charge ratios. Management believes that these allocation methods
are reasonable.
(I) 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:
2002 2001
- -----------------------------------------------------------------------------
Carrying Fair Carrying Fair
Value Value Value Value
- -----------------------------------------------------------------------------
(In millions)
Long-term debt.................... $587 $598 $597 $601
Preferred stock................... $ 92 $100 $100 $ 93
Investments other than cash
and cash equivalents........... $156 $156 $159 $160
- -----------------------------------------------------------------------------
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
financial instruments with similar characteristics and terms. Investments other
than cash and cash equivalents include decommissioning trust investments. The
Company has no securities held for trading purposes.
The investment policy for the nuclear decommissioning trust funds
restricts or limits the ability to hold certain types of assets including
private or direct placements, warrants, securities of FirstEnergy, investments
in companies owning nuclear power plants, financial derivatives, preferred
stocks, securities convertible into common stock and securities of the trust
fund's custodian or managers and their parents or subsidiaries. The investments
that are held in the decommissioning trusts (included as "Investments other than
cash and cash equivalents" in the table above) consist of equity securities,
government bonds and corporate bonds. Unrealized gains and losses applicable to
the decommissioning trusts have been recognized in the trust investment with a
corresponding change to the decommissioning liability. Realized gains (losses)
are recognized as additions (reductions) to trust asset balances. For the year
2002, net realized losses were approximately $0.4 million and interest and
dividend income totaled approximately $4.7 million.
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 at January 1,
2001 in the amount of $13.0 million, with a substantially offsetting amount
23
recorded in Regulatory Assets of $12.2 million. As of January 1, 2001, a
cumulative effect of accounting change was recognized as an expense in Other
Income (Deductions), Net on the Consolidated Statement of Income in the amount
of $0.1 million.
The Company is exposed to financial risks resulting from the fluctuation
of commodity prices, including electricity and natural gas. To manage the
volatility relating to these exposures, the Company uses a variety of
non-derivative and derivative instruments, including options and futures
contracts. These derivatives are used principally for hedging purposes. The
Company has a Risk Policy Committee, comprised of FirstEnergy executive
officers, which exercises an independent risk oversight function to ensure
compliance with corporate risk management policies and prudent risk management
practices.
The Company uses derivatives to hedge the risk of price fluctuations.
The Company's primary ongoing hedging activity involves cash flow hedges of
electricity and natural gas purchases. The majority of the Company's forward
commodity contracts are considered "normal purchases and sales," as defined by
SFAS 133, and are therefore excluded from the scope of SFAS 138. The options and
futures contracts determined to be within the scope of SFAS 133 are accounted
for as cash flow hedges and expire on various dates through 2003. Gains and
losses from hedges of commodity price risks are included in net income when the
underlying hedged commodities are delivered. There is currently a net deferred
loss of $67 thousand included in Accumulated Other Comprehensive Loss as of
December 31, 2002 related to derivative hedging activity, which will be
reclassified to earnings during the next twelve months as hedged transactions
occur.
(J) REGULATORY ASSETS-
The Company recognizes, as regulatory assets, costs which the FERC and
PPUC 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:
2002 2001
-----------------------------------------------------------------------
(In millions)
Regulatory transition charge................... $ 986.2 $1,115.9
Customer receivables for future income taxes... 116.0 110.9
Nuclear decommissioning costs.................. 53.7 34.7
Provider of last resort deferrals.............. -- 32.7
Employee postretirement benefit costs.......... 19.5 21.4
Loss on reacquired debt........................ 4.4 4.8
Other.......................................... (0.7) --
-----------------------------------------------------------------------
Total....................................... $1,179.1 $1,320.4
=======================================================================
2. MERGER:
On November 7, 2001, the merger of FirstEnergy and GPU became effective
pursuant to the Agreement and Plan of Merger, dated August 8, 2000. As a result
of the merger, GPU's former wholly owned subsidiaries, including the Company,
became wholly owned subsidiaries of FirstEnergy.
The merger was accounted for by the purchase method of accounting. The
assets acquired and liabilities assumed were recorded at estimated fair values
as determined by FirstEnergy's management based on information currently
available and on current assumptions as to future operations. Merger purchase
accounting adjustments recorded in the records of the Company primarily consist
of: (1) revaluation of certain property, plant and equipment; (2) adjusting
preferred stock subject to mandatory redemption and long-term debt to estimated
fair value; (3) recognizing additional obligations related to retirement
benefits; and (4) recognizing estimated severance and other compensation
liabilities. Other assets and liabilities were not adjusted since they remain
subject to rate regulation on a historical cost basis. The excess of the
purchase price over the estimated fair values of the assets acquired and
liabilities assumed was recognized as goodwill.
During 2002, certain pre-acquisition contingencies and other final
adjustments to the fair values of the assets acquired and liabilities assumed
were reflected in the final allocation of the purchase price. These adjustments
primarily related to: (1) final actuarial calculations related to pension and
postretirement benefit obligations; (2) establishment of a reserve for deferred
energy costs recognized prior to the merger, and (3) return to accrual
adjustments for income taxes. As a result of these adjustments, goodwill
increased by approximately $101.4 million. As of December 31, 2002, the Company
had recorded goodwill of approximately $885.8 million related to the merger.
24
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 facility in
December 1999, the Company's capital lease obligations related primarily to
nuclear fuel lease agreements with nonaffiliated fuel trusts for the plant. 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 $0.2 million, $1.9 million and $1.9
million for the years 2002, 2001 and 2000.
As of December 31, 2002, the future minimum lease payments on the
Company's Merrill Creek operating lease, net of reimbursements from sublessees,
are: $2.5 million, $1.2 million, $1.5 million, $1.5 million and $1.5 million for
the years 2003 through 2007, respectively, and $45.2 million for the years
thereafter. The Company's Merrill Creek lease payments were offset against the
actual net divestiture proceeds received from the 1999 sales of its generating
assets.
4. CAPITALIZATION:
(A) RETAINED EARNINGS-
The merger purchase accounting adjustments included resetting the
retained earnings balance to zero at 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 $3.4 million in its
earned surplus account, which would not be available for dividends or other
distributions. As of December 31, 2002, the Company had retained earnings
available to pay common stock dividends of $14.5 million, net of amounts
restricted under the Company's FMB indentures.
(B) STOCK COMPENSATION PLANS-
In 2001, FirstEnergy assumed responsibility for two new stock-based
plans as a result of its acquisition of GPU. No further stock-based compensation
can be awarded under the GPU, Inc. Stock Option and Restricted Stock Plan for
MYR Group Inc. Employees (MYR Plan) or the 1990 Stock Plan for Employees of GPU,
Inc. and Subsidiaries (GPU Plan). All options and restricted stock under both
Plans have been converted into FirstEnergy options and restricted stock. Options
under the GPU Plan became fully vested on November 7, 2001, and will expire on
or before June 1, 2010. Under the MYR Plan, all options and restricted stock
maintained their original vesting periods, which range from one to four years,
and will expire on or before December 17, 2006.
Additional stock based plans administered by FirstEnergy include the
Centerior Equity Plan (CE Plan) and the FirstEnergy Executive and Director
Incentive Compensation Plan (FE Plan). All options are fully vested under the CE
Plan, and no further awards are permitted. Outstanding options will expire on or
before February 25, 2007. Under the FE Plan, total awards cannot exceed 22.5
million shares of common stock or their equivalent. Only stock options and
restricted stock have been granted, with vesting periods ranging from six months
to seven years.
Collectively, the above plans are referred to as the FE Programs.
Restricted common stock grants under the FE Programs were as follows:
2002 2001 2000
---------------------------------------------------------------------
Restricted common shares granted...... 36,922 133,162 208,400
Weighted average market price ........ $36.04 $35.68 $26.63
Weighted average vesting period
(years)............................. 3.2 3.7 3.8
Dividends restricted.................. Yes * Yes
---------------------------------------------------------------------
* FE Plan dividends are paid as restricted stock on 4,500 shares; MYR Plan
dividends are paid as unrestricted cash on 128,662 shares
25
Under the Executive Deferred Compensation Plan (EDCP), covered employees
can direct a portion of their Annual Incentive Award and/or Long-Term Incentive
Award into an unfunded FirstEnergy Stock Account to receive vested stock units.
An additional 20% premium is received in the form of stock units based on the
amount allocated to the FirstEnergy Stock Account. Dividends are calculated
quarterly on stock units outstanding and are paid in the form of additional
stock units. Upon withdrawal, stock units are converted to FirstEnergy shares.
Payout typically occurs three years from the date of deferral; however, an
election can be made in the year prior to payout to further defer shares into a
retirement stock account that will pay out in cash upon retirement. As of
December 31, 2002, there were 296,008 stock units outstanding.
Stock option activities under the FE Programs for the past three years
were as follows:
Number of Weighted Average
Stock Option Activities Options Exercise Price
-------------------------------------------------------------------------
Balance, January 1, 2000......... 2,153,369 $25.32
(159,755 options exercisable).... 24.87
Options granted................ 3,011,584 23.24
Options exercised.............. 90,491 26.00
Options forfeited.............. 52,600 22.20
Balance, December 31, 2000...... 5,021,862 24.09
(473,314 options exercisable).... 24.11
Options granted................ 4,240,273 28.11
Options exercised.............. 694,403 24.24
Options forfeited.............. 120,044 28.07
Balance, December 31, 2001....... 8,447,688 26.04
(1,828,341 options exercisable).. 24.83
Options granted................ 3,399,579 34.48
Options exercised.............. 1,018,852 23.56
Options forfeited.............. 392,929 28.19
Balance, December 31, 2002...... 10,435,486 28.95
(1,400,206 options exercisable).. 26.07
As of December 31, 2002, the weighted average remaining contractual life
of outstanding stock options was 7.6 years.
No material stock-based employee compensation expense is reflected in
net income for stock options granted under the above plans since the exercise
price was equal to the market value of the underlying common stock on the grant
date. The effect of applying fair value accounting to FirstEnergy's stock
options is summarized in Note 1E - Stock-Based Compensation.
(C) PREFERRED AND PREFERENCE STOCK-
The Company's preferred stock authorization consists of 10 million
shares without par value. No preferred shares are currently outstanding.
(D) COMPANY-OBLIGATED MANDATORILY REDEEMABLE TRUST PREFERRED SECURITIES OF
SUBSIDIARY TRUST HOLDING SOLELY PARTNERSHIP PREFERRED SECURITIES-
The Company has formed a statutory business trust, Met-Ed Capital Trust,
which is owned through a wholly-owned limited partnership of the Company, Met-Ed
Capital II, L.P., of which a wholly-owned subsidiary of the Company is the sole
general partner. In this transaction, Met-Ed Capital Trust invested the gross
proceeds from the sale of $100.0 million of its 7.35% trust preferred securities
in the preferred securities of Met-Ed Capital II, L.P., which in turn invested
those proceeds in $103.1 million of 7.35% subordinated debentures of the
Company. The sole assets of Met-Ed Capital Trust are the preferred securities of
Met-Ed Capital II, L.P., whose sole assets are the Company's subordinated
debentures with 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 trust's preferred securities. The trust preferred
securities, which mature in 2039 and have a liquidation value of $25.00 per
security, are redeemable at the option of the Company beginning in May 2004 at
100% of their principal amount. The interest on the subordinated debentures (and
therefore the distributions on the preferred securities) 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 deferred payments on its
subordinated debentures are paid in full.
26
(E) LONG-TERM DEBT-
The Company's first mortgage bond indenture, which secures all of the
Company's FMBs, serve as a direct first mortgage lien on substantially all of
the Company's property and franchises, other than specifically excepted
property.
The Company has various debt covenants under its financing arrangements.
The most restrictive of these relate to the nonpayment of interest and/or
principal on debt, which could trigger a default. Cross-default provisions also
exist between FirstEnergy and the Company.
Based on the amount of bonds authenticated by the Trustee through
December 31, 2002 the Company's annual sinking and improvement fund requirements
for all bonds issued under the mortgage amount to $5.9 million. The Company
expects to fulfill its sinking and improvement fund obligation by providing
refundable bonds to the Trustee.
Sinking fund requirements for FMBs and maturing long-term debt
(excluding capital leases) for the next five years are:
(In millions)
-------------------------
2003..........$ 60.5
2004.......... 40.5
2005.......... 50.5
2006.......... 150.5
2007.......... 50.5
-------------------------
The Company's obligations to repay certain pollution control revenue
bonds are secured by several series of FMBs. Certain pollution control revenue
bonds are entitled to the benefit of noncancelable municipal bond insurance
policies of $42.2 million to pay principal of, or interest on, the pollution
control revenue bonds.
(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,
2002, accumulated other comprehensive income consisted of an unrealized loss on
derivative instruments of $39,000.
5. SHORT-TERM BORROWINGS:
The Company may borrow from its affiliates on a short-term basis. As of
December 31, 2002, the Company had total short-term borrowings of $88.3 million
from its affiliates with a weighted average interest rate of approximately 1.8%.
6. COMMITMENTS, GUARANTEES AND CONTINGENCIES:
(A) CAPITAL EXPENDITURES-
The Company's current forecast reflects expenditures of approximately
$288 million for property additions and improvements from 2003 through 2007, of
which approximately $53 million is applicable to 2003.
(B) 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 $0.4
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
27
that plant, to the extent a nuclear incident is determined not to be covered by
the Company's insurance policies, or to the extent such insurance becomes
unavailable in the future, the Company would remain at risk for such costs.
(C ) ENVIRONMENTAL MATTERS-
The Company has been named as a "potentially responsible party" (PRP) at
waste disposal sites which may require cleanup under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980. Allegations of
disposal of hazardous substances at historical sites and the liability involved
are often unsubstantiated and subject to dispute; however, federal law provides
that all PRPs for a particular site be held liable on a joint and several basis.
Therefore, potential environmental liabilities have been recognized on the
Consolidated Balance Sheet as of December 31, 2002, 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 accrued liabilities aggregating approximately $0.2 million as of
December 31, 2002. The Company does not believe environmental remediation costs
will have a material adverse effect on its financial condition, cash flows or
results of operations.
(D) OTHER LEGAL PROCEEDINGS-
Various lawsuits, claims and proceedings related to the Company's normal
business operations are pending against the Company, the most significant of
which is described below.
The Company has a 50% ownership interest in TMI-2, which was damaged
during a 1979 accident. As a result of the accident, claims for alleged personal
injury were filed against the Company, JCP&L, Penelec and GPU (the defendants)
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. In January 2002, the District Court granted the defendants' July 2001
motion for summary judgment on the remaining 2,100 pending claims. In February
2002, the plaintiffs filed a notice of appeal to the United States Court of
Appeals for the Third Circuit. In December 2002, the Court of Appeals refused to
hear the appeal, which effectively ended further legal action for those claims.
7. OTHER INFORMATION:
The following represents the financial data which includes
supplemental unaudited prior years' information as compared to consolidated
financial statements and notes previously reported in 2001 and 2000.
(A) CONSOLIDATED STATEMENTS OF CASH FLOWS
Nov. 7- Jan. 1-
Dec. 31, Nov. 6,
2002 2001 2001 2000
---- ---- ---- ----
(In thousands)
Other cash flows from operating activities:
Accrued taxes............................... $ 9,059 $5,229 | $(18,960) $(15,207)
All other................................... (9,597) 3,057 | (40,353) (10,689)
-------- ------- | -------- --------
Other cash provided from (used for)
operating activities.................... $ (538) $8,286 | $(59,313) $(25,896)
========= ====== | ======== =======
(B) REVENUES - INDEPENDENT SYSTEM OPERATOR (ISO) TRANSACTIONS-
The Company records purchase and sales transactions with PJM
Interconnection ISO, an independent system operator, on a gross basis in
accordance with EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal
versus Net as an Agent." The aggregate purchase and sales transactions for the
three years ended December 31, 2002, are summarized as follows:
28
Nov. 7-Dec. 31, Jan. 1-Nov. 6,
2002 2001 2001 2000
------------------------------------------------------------------------
(In millions)
Sales............. $ 9 $ 1 | $11 $49
Purchases......... 67 13 | 81 18
--------------------------------------------|---------------------------
The Company's revenues on the Consolidated Statements of Income include
wholesale electricity sales revenues from the PJM ISO from power sales (as
reflected in the table above) during periods when the Company had additional
available power capacity. Revenues also include sales by the Company of power
sourced from the PJM ISO (reflected as purchases in the table above) during
periods when the Company required additional power to meet its retail load
requirements.
(C) TRANSACTIONS WITH AFFILIATED COMPANIES-
The primary affiliated companies transactions are as follows:
Nov. 7- Jan. 1-
Dec. 31, Nov. 6,
2002 2001 2001 2000
- ------------------------------------------------------------------------------
(In millions)
Operating Revenues:
Wholesale sales-affiliated companies... $ 18.6 $ 3.2 | $ 8.4 $20.0
|
Operating Expenses: |
Power purchased from FES............... 171.9 10.6 | -- --
GPU Service, Inc. support services..... 68.1 14.0 | 81.0 77.0
Power purchased from other affiliates.. 9.5 1.9 | 9.2 2.3
- ----------------------------------------------------------|-------------------
(D) RETIREMENTS BENEFITS (1)
Net pension and other postretirement benefit costs (income) for the
three years ended December 31, 2002 are approximately as follows:
Nov. 7- Jan. 1-
Dec. 31, Nov. 6,
2002 2001 2001 2000
- ------------------------------------------------------------------------------
(In millions)
Pension Benefits.................... $(10.7) $(3.2) | $(8.3) $(5.9)
Other Postretirement Benefits....... 2.7 1.4 | 8.0 10.4
- -----------------------------------------------------------|------------------
(1) Includes estimated portion of benefit costs included in billings from GPUS.
8. RECENTLY ISSUED ACCOUNTING STANDARDS:
FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others - an interpretation of FASB Statements No. 5, 57,
and 107 and rescission of FASB Interpretation No. 34"
The FASB issued FIN 45 in January 2003. This interpretation identifies
minimum guarantee disclosures required for annual periods ending after December
15, 2002. It also clarifies that providers of guarantees must record the fair
value of those guarantees at their inception. This accounting guidance is
applicable on a prospective basis to guarantees issued or modified after
December 31, 2002. The Company does not believe that implementation of FIN 45
will be material but it will continue to evaluate anticipated guarantees.
FIN 46, "Consolidation of Variable Interest Entities - an interpretation
of ARB 51"
In January 2003, the FASB issued this interpretation of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. This Interpretation requires an enterprise to
disclose the nature of its involvement with a VIE if the enterprise has a
significant variable interest in the VIE and to consolidate a VIE if the
enterprise is the primary beneficiary. VIEs created after January 31, 2003 are
immediately subject to the provisions of FIN 46. VIEs created before February 1,
2003 are subject to this interpretation's provisions in the first interim or
annual reporting period beginning after June 15, 2003 (our third quarter of
2003). The FASB also identified transitional disclosure provisions for all
financial statements issued after January 31, 2003.
29
The Company currently has transactions with entities in connection with
the sale of preferred securities, which may fall within the scope of this
interpretation, and which are reasonably possible of meeting the definition of a
VIE in accordance with FIN 46. The Company currently consolidates these entities
and believes it will continue to consolidate following the adoption of FIN 46.
9. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
The following summarizes certain consolidated operating results by
quarter for 2002 and 2001.
Three Months Ended
-----------------------------------------
March 31, June 30, Sept. 30, Dec. 31,
2002 2002 2002 2002
- -------------------------------------------------------------------------------
(In millions)
Operating Revenues.................. $245.8 $240.0 $281.5 $219.3
Operating Expenses and Taxes........ 212.3 216.8 267.9 198.3
- -------------------------------------------------------------------------------
Operating Income.................... 33.5 23.2 13.6 21.0
Other Income........................ 5.2 5.5 5.9 5.1
Net Interest Charges................ 12.1 12.7 12.4 12.6
- -------------------------------------------------------------------------------
Net Income.......................... $ 26.6 $ 16.0 $ 7.1 $ 13.5
===============================================================================
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.......................... $221.0 $222.6 $283.5 $97.5 | $143.7
Operating Expenses and Taxes................ 196.6 197.9 248.3 79.5 | 126.4
- -------------------------------------------------------------------------------------------------------|----------------
Operating Income............................ 24.4 24.7 35.2 18.0 | 17.3
Other Income (Expense)...................... 4.7 5.3 2.6 (4.8) | 5.5
Net Interest Charges........................ 13.1 14.1 13.3 7.2 | 8.2
- -------------------------------------------------------------------------------------------------------|----------------
Net Income.................................. $ 16.0 $ 15.9 $ 24.5 $ 6.0 | $ 14.6
========================================================================================================================
30
Report of Independent Accountants
To the Stockholders and Board of Directors of
Metropolitan Edison Company:
In our opinion, the accompanying consolidated balance sheet and consolidated
statement of capitalization and the related consolidated statements of income,
common stockholder's equity, preferred stock, cash flows and taxes present
fairly, in all material respects, the financial position of Metropolitan Edison
Company (a wholly owned subsidiary of FirstEnergy Corp.) and subsidiaries as of
December 31, 2002, and the results of their operations and their cash flows for
the year then ended and the year ended December 31, 2000 (pre-merger) 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 audit. We conducted our audits of these statements in
accordance with auditing standards generally accepted in the United States of
America, which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion. The consolidated financial
statements of Metropolitan Edison Company and subsidiaries as of December 31,
2001 and for the period from January 1, 2001 to November 6, 2001 (pre-merger)
and the period from November 7, 2001 to December 31, 2001 (post-merger) were
audited by other independent accountants who have ceased operations. Those
independent accountants expressed an unqualified opinion on those financials
statements in their report dated March 18, 2002.
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 28, 2003
31
The following report is a copy of a report previously issued by Arthur Andersen
LLP and has not been reissued by Arthur Andersen LLP.
Report of Previous Independent Public Accountants
To the Stockholders and Board of Directors of
Metropolitan Edison Company:
We have audited the accompanying consolidated balance sheet and consolidated
statement of capitalization of Metropolitan Edison Company (a Pennsylvania
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 Metropolitan Edison Company and
subsidiaries 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 Metropolitan Edison 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.
32