METROPOLITAN EDISON COMPANY
2003 ANNUAL REPORT TO STOCKHOLDERS
Metropolitan Edison Company is a wholly owned electric utility
operating subsidiary of FirstEnergy Corp. It engages in the distribution and
sale of electric energy in an area of approximately 3,300 square miles in
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 was
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............................. 2-12
Consolidated Statements of Income................................ 13
Consolidated Balance Sheets...................................... 14
Consolidated Statements of Capitalization........................ 15
Consolidated Statements of Common Stockholder's Equity........... 16
Consolidated Statements of Preferred Stock....................... 16
Consolidated Statements of Cash Flows............................ 17
Consolidated Statements of Taxes................................. 18
Notes to Consolidated Financial Statements....................... 19-34
Reports of Independent Auditors.................................. 35-36
METROPOLITAN EDISON COMPANY
SELECTED FINANCIAL DATA
Nov. 7 - Jan. 1 -
2003 2002 Dec. 31, 2001 Nov. 6, 2001 2000 1999
- ----------------------------------------------------------------------------------------------------------------------
(Dollars in thousands)
Operating Revenues..................... $ 971,020 $ 986,608 $ 143,760 | $ 824,556 $ 842,333 $ 902,827
========== ========== ========== | ========= ========== ===========
|
Operating Income....................... $ 83,084 $ 91,271 $ 17,367 | $ 102,247 $ 135,211 $ 154,774
========== ========== ========== | ========= ========== ===========
|
Income Before Cumulative Effect |
of Accounting Change................ $ 60,953 $ 63,224 $ 14,617 | $ 62,381 $ 81,895 $ 95,123
========== ========== ========== | ========= ========== ============
|
Net Income............................. $ 61,170 $ 63,224 $ 14,617 | $ 62,381 $ 81,895 $ 95,123
========== ========== ========== | ========= ========== ============
|
Earnings on Common Stock............... $ 61,170 $ 63,224 $ 14,617 | $ 62,381 $ 81,895 $ 94,515
========== ========== ========== | ========= ========== ============
|
Total Assets........................... $3,473,987 $3,564,805 $3,607,187 | $2,708,062 $2,747,059
========== ========== ========== | ========== ==========
|
|
Capitalization as of December 31: |
Common Stockholder's Equity......... $1,292,667 $1,315,586 $1,288,953 | $ 537,013 $ 501,417
Company-Obligated Trust Preferred |
Securities........................ -- 92,409 92,200 | 100,000 100,000
Long-Term Debt...................... 636,301 538,790 583,077 | 496,860 496,883
---------- ---------- ---------- | ---------- ------------
Total Capitalization.............. $1,928,968 $1,946,785 $1,964,230 | $1,133,873 $1,098,300
========== ========== ========== | ========== ==========
|
|
Capitalization Ratios: |
Common Stockholder's Equity......... 67.0% 67.6% 65.6%| 47.4% 45.7%
Company-Obligated Trust Preferred |
Securities.......................... -- 4.7 4.7 | 8.8 9.1
Long-Term Debt...................... 33.0 27.7 29.7 | 43.8 45.2
----- ----- ----- | ----- -----
Total Capitalization.............. 100.0% 100.0% 100.0%| 100.0% 100.0%
===== ===== ===== | ===== =====
|
|
Distribution Kilowatt-Hour Deliveries (Millions): |
Residential......................... 4,900 4,738 793 | 3,712 4,377 4,265
Commercial.......................... 4,034 3,991 652 | 3,203 3,699 3,488
Industrial.......................... 4,047 3,972 662 | 3,506 4,412 4,085
Other............................... 36 35 6 | 27 38 107
------ ------ ----- | ------ ------ ------
Total Retail........................ 13,017 12,736 2,113 | 10,448 12,526 11,945
Total Wholesale..................... -- 840 195 | 1,067 2,120 4,597
------ ------ ----- | ------ ------ ------
Total............................... 13,017 13,576 2,308 | 11,515 14,646 16,542
====== ====== ===== | ====== ====== ======
|
|
Customers Served: |
Residential......................... 455,073 448,334 442,763 | 436,573 430,746
Commercial.......................... 58,825 58,010 57,278 | 56,080 54,969
Industrial.......................... 1,906 1,936 1,961 | 1,967 2,073
Other............................... 732 728 819 | 810 1,057
------- ------- ------- | ------- -------
Total............................... 516,536 509,008 502,821 | 495,430 488,845
======= ======= ======= | ======= =======
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. Such statements are subject to
certain risks and uncertainties. These statements typically contain, but are not
limited to, the terms "anticipate," "potential," "expect," "believe," "estimate"
and similar words. Actual results may differ materially due to the speed and
nature of increased competition and deregulation in the electric utility
industry, economic or weather conditions affecting future sales and margins,
changes in markets for energy services, changing energy and commodity market
prices, replacement power costs being higher than anticipated or inadequately
hedged, maintenance costs being higher than anticipated, legislative and
regulatory changes (including revised environmental requirements), adverse
regulatory or legal decisions and the outcome of governmental investigations,
availability and cost of capital, the inability to accomplish or realize
anticipated benefits from strategic goals, the ability to improve electric
commodity margins and to experience growth in the distribution business, the
ability to access the public securities market, further investigation into the
causes of the August 14, 2003, regional power outage and the outcome, cost and
other effects of present and potential legal and administrative proceedings and
claims related to the outage, a denial of or material change to the Company's
Application related to its Rate Stabilization Plan, and other similar factors.
Results of Operations
Net income decreased 3.3% to $61.2 million in 2003, compared to $63.2
million in 2002, due to lower operating revenues and increased operating
expenses, including higher employee benefit costs and storm restoration
expenses. These reductions to operating income were partially offset by lower
purchased power costs, principally due to reduced quantities of power purchased
through two-party agreements. Net interest charges were lower in 2003 due to
debt redemptions and the refinancing of higher-rate debt.
Operating revenues decreased by $15.6 million in 2003, following an
$18.3 million increase in 2002. The decrease in 2003 was the result of wholesale
sales revenues decreasing $25.4 million principally due to a reduction in
kilowatt-hour sales to affiliate companies and other wholesale customers. An
increase in the number of commercial and industrial customers receiving their
power from alternate suppliers also contributed to the decrease in operating
revenues. Distribution deliveries benefited from higher demand by residential
(3.4%), commercial (1.0%), and industrial (1.9%) customers due in large part to
colder temperatures in early 2003, which were partially offset by milder summer
weather.
In 2002, reductions in the number of residential and commercial
customers who received their power from alternate suppliers, and therefore
returned to us as full service retail customers, resulted in increased operating
revenues. During 2002, 13.7% of total kilowatt-hours delivered were to shopping
customers, compared with 16.2% in 2001. 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. Changes in kilowatt-hour sales by customer class are
summarized in the following table:
Changes in Kilowatt-Hour Sales 2003 2002
------------------------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail.................................. 1.2% 4.8%
Wholesale............................... (100.0)% (33.4)%
------------------------------------------------------------------
Total Electric Generation Sales........... (6.1)% 0.7%
==================================================================
Distribution Deliveries:
Residential............................. 3.4% 5.2%
Commercial.............................. 1.0% 3.5%
Industrial.............................. 1.9% (4.7)%
------------------------------------------------------------------
Total Distribution Deliveries............. 2.2% 1.4%
------------------------------------------------------------------
Operating Expenses and Taxes
Total operating expenses and taxes decreased $7.4 million in 2003,
after increasing $46.6 million in 2002, compared to the preceding year. In 2003,
the majority of the decrease was attributed to decreases in purchase power,
2
offset in part by higher other operating costs and regulatory asset
amortization. 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.
Purchased power costs decreased by $44.2 million in 2003, compared
with 2002, because of fewer kilowatt-hours required for customer needs during
2003, partially offset by slightly higher unit costs. The increase in
depreciation and amortization charges in 2003, compared to 2002, reflected
higher amortization of regulatory assets being recovered through the competitive
transition charge (CTC), partially offset by lower depreciation expense on a
reduced asset base. Other operating costs increased by $31.4 million in 2003,
compared with 2002, primarily due to increased costs to restore customer service
resulting from significant storm activity and higher employee benefit costs.
Higher purchased power costs of $42.1 million in 2002, compared to
the prior year, were primarily due to increased energy costs of $40.2 million
incurred in 2002 that otherwise would have been deferred absent a Pennsylvania
Commonwealth Court decision (see Regulatory Matters). This increase was
partially offset by a reduction in power purchased during 2002. 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 recognized in 2001
and the absence of costs related to the use of portable generators at
substations under a 2001 pilot program. 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 the recovery of 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 $0.9 million in 2003, compared to 2002, due to
reduced losses on futures contracts in 2003 that occurred in 2002. The increase
in 2002 was primarily due to contract work performed during 2002, a reduction in
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 merger with GPU).
Net Interest Charges
Net interest charges decreased by $5.0 million in 2003, compared to
2002. The decrease reflects the refinancing of higher-cost debt in the first
quarter of 2003, through the issuance of $250 million of new senior notes in
March 2003. The refinancing of higher-cost debt included the redemption of $40
million and $20 million of notes in the first and second quarters of 2003,
respectively.
Net interest charges decreased $6.1 million in 2002, compared to the
prior year, primarily due to reduced short-term borrowing levels and the
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.
Cumulative Effect of Accounting Change
Results in 2003 include an after-tax credit to net income of
approximately $0.2 million upon the adoption of SFAS 143, "Accounting for Asset
Retirement Obligations," in January 2003. We identified applicable legal
obligations as defined under the new accounting standard for nuclear power plant
decommissioning. As a result of adopting SFAS 143 in January 2003, asset
retirement costs of $186 million were recorded as part of the carrying amount of
the related long-lived asset, offset by accumulated depreciation of $186
million. ARO liability at the date of adoption was $198 million, including
accumulated accretion for the period from the date the liability was incurred to
the date of adoption. As of December 31, 2002, we recorded decommissioning
liabilities of $260 million. We expect substantially all of our nuclear
decommissioning costs to be recoverable in rates over time. Therefore, we
recognized a regulatory liability of $61 million upon adoption of SFAS 143 for
the transition amounts related to establishing the ARO for nuclear
decommissioning. The remaining cumulative effect adjustment for unrecognized
depreciation and accretion offset by the reduction in the liabilities was a $0.4
million increase to income, or $0.2 million net of income taxes.
Capital Resources and Liquidity
Changes in Cash Position
As of December 31, 2003, we had $0.1 million of cash and cash
equivalents compared with $15.7 million as of December 31, 2002. The major
sources for changes in these balances are summarized below.
3
Cash Flows From Operating Activities
Cash flows provided from operating activities totaled $132 million in
2003 and $102 million in 2002. The sources of these changes are as follows:
Operating Cash Flows 2003 2002 2001
-----------------------------------------------------------------
(In millions)
Cash earnings (1).......... $180 $146 $102
Working capital............ (48) (44) (72)
-----------------------------------------------------------------
Total.............. $132 $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.
Net cash provided from operating activities increased $30 million
during 2003, compared with 2002. The increase consisted of $34 million in higher
cash earnings, partially offset by a $4 million decrease from changes in working
capital.
Cash Flows From Financing Activities
In 2003, net cash used for financing activities of $87.7 million
reflects redemptions of long-term debt of $260 million, and $52.0 million in
common stock dividend payments to FirstEnergy, partially offset by $248 million
in proceeds from the issuance of secured notes. In 2002, net cash used for
financing activities of $54.0 million reflects redemption of debt of $60 million
and $60.0 million in common stock dividend payments to FirstEnergy, partially
offset by $50 million in proceeds from the issuance of secured notes.
The following table provides details regarding new issues and
redemptions during 2003 and 2002:
Securities Issued or Redeemed 2003 2002
---------------------------------------------------------------
(In millions)
New Issues
Secured notes........................... $248 $50
---------------------------------------------------------------
Redemptions
First Mortgage Bonds.................... 260 60
---------------------------------------------------------------
Short-term Borrowings, net (use)/source of cash.. (23) 16
---------------------------------------------------------------
We had $65.3 million of short-term indebtedness at the end of 2003,
compared to $88.3 million at the end of 2002. We will not issue first mortgage
bonds (FMB) other than as collateral for senior notes, since our senior note
indentures prohibit (subject to certain exceptions) us from issuing any debt
which is senior to the senior notes. As of December 31, 2003, we had the
capability to issue $189 million of additional senior notes based upon FMB
collateral. We have no restrictions on the issuance of preferred stock.
We have the ability to borrow from our regulated affiliates and
FirstEnergy to meet our short-term working capital requirements. FirstEnergy
Service Company administers this money pool and tracks surplus funds of
FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the
money pool agreements must repay the principal, together with accrued interest,
within 364 days of borrowing the funds. The rate of interest is the same for
each company receiving a loan from the pool and is based on the average cost of
funds available through the pool. The average interest rate for borrowings in
2003 was 1.47%.
Our access to capital markets and costs of financing are dependent on
the ratings of our securities and that of our holding company, FirstEnergy. The
following table shows our securities' ratings following the downgrade by Moody's
Investors Service in February 2004. The ratings outlook on all securities is
stable.
Ratings of Securities
- ---------------------------------------------------------------------------
Securities S&P Moody's Fitch
- ---------------------------------------------------------------------------
FirstEnergy Senior unsecured BB+ Baa3 BBB-
Met-Ed Senior secured BBB Baa1 BBB+
- ---------------------------------------------------------------------------
4
On September 30, 2003, Fitch Ratings lowered the senior unsecured
ratings of FirstEnergy to "BBB-" from "BBB." Fitch also lowered the senior
secured rating of Met-Ed. Fitch announced that the Rating Outlook is Stable for
the securities of FirstEnergy, and all of the securities of its electric utility
operating companies. Fitch stated that the changes to the long-term ratings were
"driven by the high debt leverage of the parent, FirstEnergy. Despite
management's commitment to reduce debt related to the GPU merger, subsequent
cash flows have been vulnerable to unfavorable events, slowing the pace of
FirstEnergy's debt reduction efforts. The Stable Outlook reflects the success of
FirstEnergy's recent common equity offering and management's focus on a
relatively conservative integrated utility strategy."
On December 23, 2003, Standard & Poor's (S&P) lowered its corporate
credit ratings on FirstEnergy and its regulated utility subsidiaries to "BBB-"
from "BBB" and lowered FirstEnergy's senior unsecured debt rating to "BB+" from
"BBB-". Met-Ed's rating was lowered one notch as well (see table above). The
ratings were removed from CreditWatch with negative implications, where they had
been placed by S&P on August 18, 2003, and the Ratings Outlook returned to
Stable. The rating action followed a revision in S&P's assessment of our
consolidated business risk profile to `6' from `5' (`1' equals low risk, `10'
equals high risk), with S&P citing operational and management challenges as well
as heightened regulatory uncertainty for its revision of our business risk
assessment score. S&P's rationale for its revisions of the ratings included
uncertainty regarding the timing of the Ohio Rate Plan filing, the pending final
report on the August 14 blackout (see Power Outage), the outcome of the remedial
phase of litigation relating to the Sammis plant, and the extended Davis-Besse
outage and the related pending subpoena. S&P further stated that the restart of
Davis-Besse and a supportive Ohio Rate Plan extension will be vital positive
developments that would aid an upgrade of FirstEnergy's ratings. S&P's reduction
of the credit ratings in December 2003 triggered cash and letter-of-credit
collateral calls of FirstEnergy in addition to higher interest rates for some
outstanding borrowings.
On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured
debt to Baa3 from Baa2 and downgraded the senior secured debt of Met-Ed to Baa1
from A2. Moody's said that the lower ratings were prompted by: "1) high
consolidated leverage with significant holding company debt, 2) a degree of
regulatory uncertainty in the service territories in which the company operates,
3) risks associated with investigations of the causes of the August 2003
blackout, and related securities litigation, and 4) a narrowing of the ratings
range for the FirstEnergy operating utilities, given the degree to which
FirstEnergy increasingly manages the utilities as a single system and the
significant financial interrelationship among the subsidiaries."
Cash Flows From Investing Activities
Cash used for investing activities totaled $60.3 million in 2003 and
$57.5 million in 2002. The net cash flows used for investing activities during
2003 resulted from property additions, decommissioning trust investments, and
loans to associated companies. Cash used for investing activities during 2002
were for property additions primarily to support our energy delivery operations
and decommissioning trust investments.
Our cash requirements in 2004 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.
Our capital spending for the period 2004 through 2006 is expected to
be about $168 million, of which approximately $55 million applies to 2004.
Contractual Obligations
Our cash contractual obligations as of December 31, 2003 that we
consider firm obligations are as follows:
2005- 2007-
Contractual Obligations Total 2004 2006 2008 Thereafter
- ----------------------------------------------------------------------------
(In millions)
Long-term debt............. $ 672 $ 40 $181 $ 57 $ 394
Short-term borrowings...... 65 65 -- -- --
Operating leases (1)....... 51 1 3 3 44
Purchases (2).............. 3,075 181 691 811 1,392
- ----------------------------------------------------------------------------
Total................. $3,863 $287 $875 $871 $1,830
- ----------------------------------------------------------------------------
(1) Operating lease payments are net of reimbursements from sublessees
(see Note 3)
(2) Fuel and power purchases under contracts with fixed or minimum quantities
and approximate timing
5
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 SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities." The change in the fair value of
commodity derivative contracts related to energy production during 2003 is
summarized in the following table:
Increase (Decrease) in the Fair Value
of Commodity Derivative Contracts
Non-Hedge Hedge Total
--------- ----- -----
(In millions)
Change in the Fair Value of Commodity Derivative Contracts
Outstanding net asset as of January 1, 2003................. $ 17.4 $ 0.1 $ 17.5
New contract value when entered............................. -- -- --
Additions/Increase in value of existing contracts........... 8.9 -- 8.9
Change in techniques/assumptions............................ 4.6 -- 4.6
Settled contracts........................................... -- (0.1) (0.1)
-----------------------------
Net Assets - Derivatives Contracts as of December 31, 2003 (1) $30.9 $ -- $ 30.9
=============================
Impact of Changes in Commodity Derivative Contracts (2)
Income Statement Effects (Pre-Tax).......................... $ 0.8 $ -- $ 0.8
Balance Sheet Effects:
Other Comprehensive Income (Pre-Tax)..................... $ -- $(0.1) $ (0.1)
Regulatory Liability..................................... $ 12.7 $ -- $ 12.7
(1) Includes $30.7 million in non-hedge commodity derivative contracts which are
offset by a regulatory liability.
(2) Represents the increase in value of existing contracts, settled contracts
and changes in techniques/assumptions.
Derivatives included on the Consolidated Balance Sheet as of December 31, 2003:
Non-Hedge Hedge Total
--------- ----- -----
(In millions)
Current-
Other Assets................... $ -- $ -- $ --
Non-Current-
Other Deferred Charges......... 30.9 -- 30.9
----- ---- -----
Net assets................... $30.9 $ -- $30.9
===== ==== =====
The valuation of derivative contracts is based on observable market
information to the extent that such information is available. In cases where
such information is not available, 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
- ---------------------------------------------------
2004 2005 2006 2007 Thereafter Total
---- ---- ---- ---- ---------- -----
(In millions)
Prices based on external sources(1)... $4.7 $5.1 $-- $-- $-- $ 9.8
Prices based on models................ -- -- 4.9 4.7 11.5 21.1
-----------------------------------------------------------
Total(2).......................... $4.7 $5.1 $4.9 $4.7 $11.5 $30.9
===========================================================
(1) Broker quote sheets.
(2) Includes $30.7 million from an embedded option that is offset by a
regulatory liability and does not affect earnings.
6
We perform sensitivity analyses to estimate our exposure to the
market risk of our commodity position. A hypothetical 10% adverse shift in
quoted market prices in the near term on derivative instruments would not have
had a material effect on our consolidated financial position or cash flows as
of December 31, 2003.
Interest Rate Risk
Our exposure to fluctuations in market interest rates is reduced
since our debt has fixed interest rates, as noted in the following table.
Comparison of Carrying Value to Fair Value
- -------------------------------------------------------------------------------------------------------------------
There- Fair
Year of Maturity 2004 2005 2006 2007 2008 after Total Value
- -------------------------------------------------------------------------------------------------------------------
(Dollars in millions)
Assets
- -------------------------------------------------------------------------------------------------------------------
Investments Other Than Cash
and Cash Equivalents-
Fixed Income............... $ 78 $ 78 $ 78
Average interest rate...... 4.7% 4.7%
- -------------------------------------------------------------------------------------------------------------------
Liabilities
- -------------------------------------------------------------------------------------------------------------------
Long-term Debt and Other
Long-Term Obligations:
Fixed rate.................... $ 40 $ 30 $151 $50 $ 7 $394 $672 $697
Average interest rate ..... 6.3% 6.8% 5.9% 5.9% 6.0% 5.7% 5.9%
Short-term Borrowings......... $ 65 $ 65 $ 65
Average interest rate...... 1.7% 1.7%
- -------------------------------------------------------------------------------------------------------------------
We are subject to the inherent interest rate risks related to
refinancing maturing debt by issuing new debt securities.
Equity Price Risk
Included in nuclear decommissioning trusts are marketable equity
securities carried at their market value of approximately $114 million and $81
million as of December 31, 2003 and 2002, respectively. A hypothetical 10%
decrease in prices quoted by stock exchanges would result in an $11 million
reduction in fair value as of December 31, 2003 (see Note 1 (L) - "Cash and
Financial Instruments").
Outlook
Beginning in 1999, all of our customers were able to select
alternative energy suppliers. We continue to deliver power to homes and
businesses through our existing distribution system, which remains regulated.
The Pennsylvania Public Utility Commission (PPUC) authorized our rate
restructuring plan, establishing separate charges for transmission,
distribution, generation and stranded cost recovery, which is recovered through
a competitive transition charge (CTC). Customers electing to obtain power from
an alternative supplier have their bills reduced based on the regulated
generation component, and the customers receive a generation charge from the
alternative supplier. 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 have been authorized by the PPUC
and the Federal Energy Regulatory Commission (FERC) for recovery from customers
in future periods and, without such authorization, would have been charged to
income when incurred. All of our regulatory assets are expected to continue to
be recovered under the provisions of the regulatory plan as discussed below. Our
regulatory assets totaled $1.0 billion and $1.2 billion as of December 31, 2003
and December 31, 2002, respectively.
Regulatory Matters
In June 2001, the PPUC approved the Settlement Stipulation with all
of the major parties in the combined merger and rate proceedings which approved
the FirstEnergy/GPU merger and provided PLR deferred accounting treatment for
energy costs, permitting us to defer, for future recovery, energy costs in
excess of amounts reflected in our capped generation rates retroactive to
January 1, 2001. This PLR deferral accounting procedure was later reversed in a
February 2002 Commonwealth Court of Pennsylvania decision. The court decision
affirmed the PPUC decision regarding approval of the merger, remanding the
decision to the PPUC only with respect to the issue of merger savings. In 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 then 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.
7
On April 2, 2003, the PPUC remanded the issue relating to merger
savings to the Office of Administrative Law Judge (ALJ) for hearings, directed
us to file a position paper on the effect of the Commonwealth Court order on the
Settlement Stipulation and allowed other parties to file responses to the
position paper. We filed a letter with the ALJ on June 11, 2003, voiding the
Stipulation in its entirety and reinstating our restructuring settlement
previously approved by the PPUC.
On October 2, 2003, the PPUC issued an order concluding that the
Commonwealth Court reversed the PPUC's June 20, 2001 order in its entirety. The
PPUC directed us to file tariffs within thirty days of the order to reflect the
CTC rates and shopping credits that were in effect prior to the June 21, 2001
order to be effective upon one day's notice. In response to that order, we filed
these supplements to our tariffs to become effective October 24, 2003.
On October 8, 2003, we filed a petition for clarification relating to
the October 2, 2003 order on two issues: to establish June 30, 2004 as the date
to fully refund the NUG trust fund and to clarify that the ordered accounting
treatment regarding the CTC rate/shopping credit swap should follow the
ratemaking, and that the PPUC's findings would not impair our rights to recover
all of our stranded costs. On October 9, 2003, ARIPPA (an intervenor in the
proceedings) petitioned the PPUC to direct us to reinstate accounting for the
CTC rate/shopping credit swap retroactive to January 1, 2002. Several other
parties also filed petitions. On October 16, 2003, the PPUC issued a
reconsideration order granting the date requested by us for the NUG trust fund
refund and, denying our other clarification requests and granting ARIPPA's
petition with respect to the retroactive accounting treatment of the changes to
the CTC rate/shopping credit swap. On October 22, 2003, we filed an Objection
with the Commonwealth Court asking that the Court reverse the PPUC's finding
that requires us to treat the stipulated CTC rates that were in effect from
January 1, 2002 on a retroactive basis. We are considering filing an appeal to
the Commonwealth Court on the PPUC orders as well.
On October 27, 2003, one Commonwealth Court judge issued an Order
denying our objection without explanation. Due to the vagueness of the Order, on
October 31, 2003, we filed an Application for Clarification with the judge.
Concurrent with this filing, in order to preserve our rights, we also filed with
the Commonwealth Court both a Petition for Review of the PPUC's October 16 and
October 22 Orders, and an application for reargument, if the judge, in his
clarification order, indicates that our objection was intended to be denied on
the merits. In addition to these findings, in compliance with the PPUC's Orders,
we filed revised PPUC quarterly reports for the twelve months ended December 31,
2001 and 2002, and for the first two quarters of 2003, reflecting balances
consistent with the PPUC's findings in their Orders.
Effective September 1, 2002, we assigned our PLR responsibility to
our FirstEnergy Solutions Corp. (FES) affiliate through a wholesale power sale
agreement. The PLR sale will be automatically extended for each successive
calendar year unless any party elects to cancel the agreement by November 1 of
the preceding year. Under the terms of the wholesale agreement, FES assumed the
supply obligation and the supply profit and loss risk, for the portion of power
supply requirements not self-supplied by us under our NUG contracts and other
power contracts with nonaffiliated third party suppliers. This arrangement
reduces our exposure to high wholesale power prices by providing power at a
fixed price for our uncommitted PLR energy costs during the term of the
agreement with FES. FES has hedged most of our unfilled PLR on-peak obligation
through 2004 and a portion of 2005, the period during which deferred accounting
was previously allowed under the PPUC's order. We are authorized to continue
deferring differences between NUG contract costs and current market prices.
In late 2003, the PPUC issued a Tentative Order implementing new
reliability benchmarks and standards. In connection therewith, the PPUC
commenced a rulemaking procedure to amend the Electric Service Reliability
Regulations to implement these new benchmarks, and create additional reporting
on reliability. Although neither the Tentative Order nor the Reliability
Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to
begin filing quarterly reliability reports on November 1, 2003. The comment
period for both the Tentative Order and the Proposed Rulemaking Order has
closed. We are currently awaiting the PPUC to issue a final order in both
matters. The order will determine (1) the standards and benchmarks to be
utilized, and (2) the details required in the quarterly and annual reports. It
is expected that these Orders will be finalized in March 2004.
On January 16, 2004, the PPUC initiated a formal investigation of our
level of compliance with the Public Utility Code and the PPUC's regulations and
orders with regard to reliable electric service. Hearings will be held in August
in this investigation and the ALJ has been directed to issue a Recommended
Decision by September 30, 2004, in order to allow the PPUC time to issue a Final
Order before December 16, 2004. We are unable to predict the outcome of the
investigation or the impact of the PPUC Order.
8
FERC Regulatory Matters
On December 19, 2002, the FERC granted unconditional Regional
Transmission Organization status to PJM Interconnection, LLC which includes us
as transmission owners. PJM and the Midwest Independent System Operator, Inc.
(MISO) were ordered by the FERC to develop a common market between the regions
by October 31, 2004. The FERC also initiated a Section 206 investigation into
the reasonableness of the "through-and-out" transmission rates charged by PJM
and MISO. By order issued November 17, 2003, MISO, PJM and certain unaffiliated
transmission owners in the Midwest were directed to eliminate rates for
point-to-point service between the two RTOs effective April 1, 2004. A
settlement judge has been appointed by the FERC to resolve compliance filings by
the affected transmission providers. AEP, Commonwealth Edison and other
utilities have appealed the FERC's November 17, 2003 order to the federal court
of appeals for the District of Columbia.
Environmental Matters
We have been named as a "potentially responsible party" (PRP) at
waste disposal sites which may require cleanup under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980. Allegations of
disposal of hazardous substances at historical sites and the liability involved
are often unsubstantiated and subject to dispute; however, federal law provides
that all PRPs for a particular site be held liable on a joint and several basis.
Therefore, environmental liabilities that are considered probable have been
recognized on the Consolidated Balance Sheet as of December 31, 2003, based on
estimates of the total costs of cleanup, our proportionate responsibility for
such costs and the financial ability of other nonaffiliated entities to pay. We
have accrued liabilities aggregating approximately $59,000 as of December 31,
2003. We do not believe environmental remediation costs will have a material
adverse effect on our financial condition, cash flows or results of operations.
Power Outage
On August 14, 2003, various states in the northeast United States and
parts of southern Canada experienced a widespread power outage. That outage
affected approximately 1.4 million customers in FirstEnergy's service area.
FirstEnergy continues to accumulate data and evaluate the status of its
electrical system prior to and during the outage event, and continues to
cooperate with the U.S.-Canada Power System Outage Task Force (Task Force)
investigating the August 14th outage. The interim report issued by the Task
Force on November 18, 2003 concluded that the problems leading up to the outage
began in FirstEnergy's service area. Specifically, the interim report concludes,
among other things, that the initiation of the August 14th outage resulted from
the coincidence on that afternoon of the following events: (1) inadequate
situational awareness at FirstEnergy; (2) FirstEnergy's failure to adequately
manage tree growth in its transmission rights of way; and (3) failure of the
interconnected grid's reliability organizations (Midwest ISO and PJM
Interconnection) to provide effective diagnostic support. We believe that the
interim report does not provide a complete and comprehensive picture of the
conditions that contributed to the August 14th outage and that it does not
adequately address the underlying causes of the outage. On November 25, 2003,
the Public Utilities Commission of Ohio (PUCO) ordered FirstEnergy to file a
plan with the PUCO no later than March 1, 2004, illustrating how FirstEnergy
will correct problems identified by the Task Force as events contributing to the
August 14th outage and addressing how FirstEnergy proposes to upgrade its
control room computer hardware and software and improve the training of control
room operators to ensure that similar problems do not occur in the future. The
PUCO, in consultation with the North American Electric Reliability Council, will
review the plan before determining the next steps in the proceeding. On December
24, 2003, the FERC ordered FirstEnergy to pay for an independent study of part
of Ohio's power grid. The study has commenced and will examine the stability of
the grid in critical points in the Cleveland and Akron areas; the status of
projected power reserves during summer 2004 through 2008; and the need for new
transmission lines or other grid projects. The FERC ordered the study to be
completed within 120 days. At this time, we do not know how the results of the
study will impact FirstEnergy.
Legal Matters
Various lawsuits, claims and proceedings related to our normal
business operations are pending against us, the most significant of which are
described above.
Critical 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.
9
Purchase Accounting
The merger between FirstEnergy and GPU was accounted for by the
purchase method of accounting, which requires judgment regarding the allocation
of the purchase price based on the fair values of the assets acquired (including
intangible assets) and the liabilities assumed. The fair values of the acquired
assets and assumed liabilities were based primarily on estimates. The
adjustments reflected in our records, 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 goodwill for impairment at least
annually and would make such an evaluation more frequently if indicators of
impairment should arise. In accordance with the accounting standard, if the fair
value of a reporting unit is less than its carrying value (including goodwill),
the goodwill is tested for impairment. If impairment were indicated, we would
recognize a loss - calculated as the difference between the implied fair value
of its goodwill and the carrying value of the goodwill. Our annual review was
completed in the third quarter of 2003, with no impairment of goodwill
indicated. The forecasts used in our evaluation of goodwill reflect operations
consistent with our general business assumptions. Unanticipated changes in those
assumptions could have a significant effect on our future evaluations of
goodwill. As of December 31, 2003, we had recorded goodwill of approximately
$884 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 the costs that the regulatory
agencies determine we are permitted to recover. At times, regulators permit the
future recovery through rates of costs that would be currently charged to
expense by an unregulated company. This rate-making process results in the
recording of regulatory assets based on anticipated future cash inflows. As a
result of the changing regulatory framework in Pennsylvania, a significant
amount of regulatory assets have been recorded - $1.0 billion as of December 31,
2003. We regularly review these assets to assess their ultimate recoverability
within the approved regulatory guidelines. Impairment risk associated with these
assets relates to potentially adverse legislative, judicial or regulatory
actions in the future.
Derivative Accounting
Determination of appropriate accounting for derivative transactions
requires the involvement of management representing operations, finance and risk
assessment. In order to determine the appropriate accounting for derivative
transactions, the provisions of the contract need to be carefully assessed in
accordance with the authoritative accounting literature and management's
intended use of the derivative. New authoritative guidance continues to shape
the application of derivative accounting. Management's expectations and
intentions are key factors in determining the appropriate accounting for a
derivative transaction and, as a result, such expectations and intentions are
documented. Derivative contracts that are determined to fall within the scope of
SFAS 133, as amended, must be recorded at their fair value. Active market prices
are not always available to determine the fair value of the later years of a
contract, requiring that various assumptions and estimates be used in their
valuation. We continually monitor our derivative contracts to determine if our
activities, expectations, intentions, assumptions and estimates remain valid. As
part of our normal operations, we enter into commodity contracts which increase
the impact of derivative accounting judgments.
Revenue Recognition
We follow the accrual method of accounting for revenues, recognizing
revenue for kilowatt-hours that have been delivered but not yet billed through
the end of the accounting period. The determination of unbilled revenues
requires management to make various estimates including:
o Net energy generated or purchased for retail load
o Losses of energy over distribution lines
o Allocations to distribution companies within
the FirstEnergy system
o Mix of kilowatt-hour usage by residential, commercial and industrial
customers
o Kilowatt-hour usage of customers receiving electricity from
alternative suppliers
Pension and Other Postretirement Benefits Accounting
FirstEnergy's reported costs of providing non-contributory defined
pension benefits and postemployment benefits other than pensions (OPEB) are
dependent upon numerous factors resulting from actual plan experience and
certain assumptions.
10
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions FirstEnergy makes to the plans, and earnings on plan assets. Such
factors may be further affected by business combinations (such as FirstEnergy's
merger with GPU, Inc. in November 2001), which impacts employee demographics,
plan experience and other factors. Pension and OPEB costs are also affected by
changes to key assumptions, including anticipated rates of return on plan
assets, the discount rates and health care trend rates used in determining the
projected benefit obligations for pension and OPEB costs.
Plan amendments to retirement health care benefits in 2003 and 2002,
related to changes in benefits provided and cost-sharing provisions, which
reduced FirstEnergy's obligation by $123 and $121 million, respectively. In
early 2004, FirstEnergy announced that it would amend the benefit provisions of
its health care benefits plan and both employees and retirees would share in
more of the benefit costs.
In accordance with SFAS 87, "Employers' Accounting for Pensions" and
SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions," changes in pension and OPEB obligations associated with these factors
may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
In selecting an assumed discount rate, FirstEnergy considers
currently available rates of return on high-quality fixed income investments
expected to be available during the period to maturity of the pension and other
postretirement benefit obligations. Due to recent declines in corporate bond
yields and interest rates in general, FirstEnergy reduced the assumed discount
rate as of December 31, 2003 to 6.25% from 6.75% and 7.25% used as of December
31, 2002 and 2001, respectively.
FirstEnergy's assumed rate of return on pension plan assets considers
historical market returns and economic forecasts for the types of investments
held by their pension trusts. In 2003, 2002 and 2001, plan assets actually
earned 24.0%, (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in
2003 were computed assuming a 9.0% rate of return on plan assets based upon
projections of future returns and their pension trust investment allocation of
approximately 70% equities, 27% bonds, 2% real estate and 1% cash.
As a result of GPU Service Inc. merging with FirstEnergy Service
Company in the second quarter of 2003, operating company employees of GPU
Service were transferred to the former GPU operating companies. Accordingly,
FirstEnergy requested an actuarial study to update the pension liabilities for
each of its subsidiaries. Based on the actuary's report, our accrued pension
costs as of June 30, 2003 increased by $47 million. The corresponding adjustment
related to this change decreased other comprehensive income and deferred income
taxes and increased the payable to associated companies.
Due to the increased market value of our pension plan assets, we
reduced our minimum liability as prescribed by SFAS 87 as of December 31, 2003
by $7 million, recording an increase of $13,000 in an intangible asset and
crediting OCI by $4 million (offsetting previously recorded deferred tax
benefits by $3 million). The remaining balance in OCI of $33 million will
reverse in future periods to the extent the fair value of trust assets exceeds
the accumulated benefit obligation. The accrued pension cost was reduced to $45
million as of December 31, 2003.
Based on pension assumptions and pension plan assets as of December
31, 2003, FirstEnergy will not be required to fund their pension plans in 2004.
However, health care cost trends have significantly increased and will affect
future OPEB costs. FirstEnergy's pension and OPEB expenses in 2004 are expected
to decrease by $38 million and $34 million, respectively. These reductions
reflect the actual performance of pension plan assets and amendments to the
health care benefits plan announced in early 2004 which result in employees and
retirees sharing more of the benefit costs. The reduction in OPEB costs for 2004
does not reflect the impact of the new Medicare law signed by President Bush in
December 2003 due to uncertainties regarding some of its new provisions (see
Note 1(I)). The 2003 and 2002 composite health care trend rate assumptions are
approximately 10%-12% gradually decreasing to 5% in later years. In determining
their trend rate assumptions, FirstEnergy included the specific provisions of
their health care plans, the demographics and utilization rates of plan
participants, actual cost increases experienced in their health care plans, and
projections of future medical trend rates. The effect on FirstEnergy's pension
and OPEB costs and liabilities from changes in key assumptions are as follows:
11
Increase in Costs from Adverse Changes in Key Assumption
- --------------------------------------------------------------------------------
Assumption Adverse Change Pension OPEB Total
(In millions)
Discount rate................ Decrease by 0.25% $ 10 $ 5 $ 15
Long-term return on assets... Decrease by 0.25% $ 8 $ 1 $ 9
Health care trend rate....... Increase by 1% na $26 $ 26
Increase in Minimum Liability
Discount rate................ Decrease by 0.25% $104 na $104
- --------------------------------------------------------------------------------
Long-Lived Assets
In accordance with SFAS No. 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 might not be fully recoverable. The accounting standard
requires that if the sum of future cash flows (undiscounted) expected to result
from an asset is less than the carrying value of the asset, an asset impairment
must be recognized in the financial statements. If impairment has occurred, we
recognize a loss - calculated as the difference between the carrying value and
the estimated fair value of the asset (discounted future net cash flows).
The calculation of future cash flows is based on assumptions,
estimates and judgement about future events. The aggregate amount of cash flows
determines whether an impairment is indicated. The timing of the cash flows is
critical in determining the amount of the impairment.
Nuclear Decommissioning
In accordance with SFAS 143, we recognize an ARO for the future
decommissioning of TMI-2. The ARO liability represents an estimate of the fair
value of our current obligation related to nuclear decommissioning and the
retirement of other assets. A fair value measurement inherently involves
uncertainty in the amount and timing of settlement of the liability. We used an
expected cash flow approach (as discussed in FASB Concepts Statement No. 7,
"Using Cash Flow Information and Present Value in Accounting Measurements") to
measure the fair value of the nuclear decommissioning ARO. This approach applies
probability weighting to discounted future cash flow scenarios that reflect a
range of possible outcomes.
New Accounting Standards and Interpretations Adopted
FIN 46 (revised December 2003), "Consolidation of Variable
Interest Entities"
In December 2003, the FASB issued a revised interpretation of
Accounting Research Bulletin No. 51, "Consolidated Financial Statements." FASB
Interpretation No. 46, "Consolidation of Variable Interest Entities", referred
to as "FIN 46R", requires the consolidation of a VIE by an enterprise if that
enterprise is determined to be the primary beneficiary of the VIE. As required,
we adopted FIN 46R for interests in VIEs or potential VIEs commonly referred to
as special-purpose entities effective December 31, 2003. We will adopt FIN 46R
for all other types of entities effective March 31, 2004.
As described in Note 4(E), we created a statutory business trust to
issue trust preferred securities in the amount of $93 million. Application of
the guidance in FIN 46R resulted in the holders of the preferred securities
being considered the primary beneficiaries of these trusts. Therefore, we have
deconsolidated the trust and recognized an equity investment in the trust of $3
million and subordinated debentures to the trust of $96 million as of December
31, 2003.
We are evaluating entities that meet the deferral criteria and may be
subject to consolidation under FIN 46R as of March 31, 2004. These entities are
non-utility generators in which we have neither debt nor equity investments but
are generally the sole purchaser of their power.
SFAS 143, "Accounting for Asset Retirement Obligations"
In January 2003, we implemented SFAS 143 which provides accounting
standards for retirement obligations associated with tangible long-lived assets.
This statement requires recognition of the fair value of a liability for an
asset retirement obligation in the period in which it is incurred. See Notes
1(E) and 1(H) for further discussions of SFAS 143.
DIG Implementation Issue No. C20 for SFAS 133, "Scope Exceptions:
Interpretation of the Meaning of Not Clearly and Closely Related in
Paragraph 10(b) Regarding Contracts with a Price Adjustment Feature"
In June 2003, the FASB cleared DIG Issue C20 for implementation in
fiscal quarters beginning after July 10, 2003. The issue supersedes earlier DIG
Issue C11, "Interpretation of Clearly and Closely Related in Contracts That
Qualify for the Normal Purchases and Normal Sales Exception." DIG Issue C20
provides guidance regarding when the presence of a general index, such as the
Consumer Price Index, in a contract would prevent that contract from qualifying
for the normal purchases and normal sales exception under SFAS 133, as amended,
and therefore exempt from the mark-to-market treatment of certain contracts.
Adoption of DIG Issue C20 did not impact our financial statements.
12
METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
Nov 7 - Jan.1 -
2003 2002 Dec. 31, 2001 Nov. 6, 2001
- -------------------------------------------------------------------------------------------------------------------------
(In thousands)
OPERATING REVENUES (Note 1(K))............................ $971,020 $986,608 $143,760 | $824,556
-------- -------- -------- | --------
|
OPERATING EXPENSES AND TAXES: |
Fuel and purchased power (Note 1(K))................... 560,083 604,305 83,275 | 478,954
Other operating costs (Note 1(K))...................... 146,765 115,371 16,122 | 123,094
-------- -------- -------- | --------
Total operation and maintenance expenses............. 706,848 719,676 99,397 | 602,048
Provision for depreciation and amortization............ 86,514 81,419 8,903 | 51,867
General taxes.......................................... 67,207 66,795 6,509 | 39,845
Income taxes........................................... 27,367 27,447 11,584 | 28,549
-------- -------- -------- | --------
Total operating expenses and taxes................... 887,936 895,337 126,393 | 722,309
-------- -------- -------- | --------
|
OPERATING INCOME.......................................... 83,084 91,271 17,367 | 102,247
|
OTHER INCOME.............................................. 22,640 21,742 5,465 | 7,807
-------- -------- -------- | --------
|
INCOME BEFORE NET INTEREST CHARGES........................ 105,724 113,013 22,832 | 110,054
-------- -------- -------- | --------
|
NET INTEREST CHARGES: |
Interest on long-term debt............................. 36,661 40,774 5,615 | 33,101
Allowance for borrowed funds used during |
construction......................................... (323) (470) 30 | (574)
Deferred interest...................................... (1,187) (710) (276) | (321)
Other interest expense ................................ 5,841 2,636 1,744 | 9,219
Subsidiary's preferred stock dividend requirements..... 3,779 7,559 1,102 | 6,248
-------- -------- -------- | --------
Net interest charges................................. 44,771 49,789 8,215 | 47,673
-------- -------- -------- | --------
|
INCOME BEFORE CUMULATIVE EFFECT OF |
ACCOUNTING CHANGE...................................... 60,953 63,224 14,617 | 62,381
|
Cumulative effect of accounting change (net of income |
taxes of $154,000) (Note 1(H))......................... 217 -- -- | --
-------- -------- -------- | --------
|
NET INCOME................................................ $ 61,170 $ 63,224 $ 14,617 | $ 62,381
======== ======== ======== | ========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
13
METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31, 2003 2002
- ------------------------------------------------------------------------------------------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service..................................................................... $1,838,567 $1,620,613
Less-Accumulated provision for depreciation.................................... 772,123 547,925
---------- ----------
1,066,444 1,072,688
Construction work in progress.................................................. 21,980 16,078
---------- ----------
1,088,424 1,088,766
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts........................................... 192,409 155,690
Long-term notes receivable from associated companies........................... 9,892 12,418
Other.......................................................................... 34,922 19,206
---------- ----------
237,223 187,314
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents...................................................... 121 15,685
Receivables-
Customers (less accumulated provisions of $4,943,000 and $4,810,000
respectively, for uncollectible accounts)................................. 118,933 120,868
Associated companies......................................................... 45,934 23,219
Notes receivable from associated companies................................... 10,467 --
Other (less accumulated provisions of $68,000 and $0 respectively,
for uncollectible accounts)................................................ 22,750 18,235
Prepayments and other.......................................................... 6,600 9,731
---------- ----------
204,805 187,738
---------- ----------
DEFERRED CHARGES:
Regulatory assets.............................................................. 1,028,432 1,179,125
Goodwill....................................................................... 884,279 885,832
Other.......................................................................... 30,824 36,030
---------- ----------
1,943,535 2,100,987
---------- ----------
$3,473,987 $3,564,805
========== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity.................................................... $1,292,667 $1,315,586
Company-obligated mandatorily redeemable preferred securities.................. -- 92,409
Long-term debt and other long-term obligations-
Subordinated debentures to affiliated trusts................................. 95,711 --
Other........................................................................ 540,590 538,790
---------- ----------
1,928,968 1,946,785
---------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt............................................... 40,469 60,467
Short-term borrowings (Note 5)-
Associated companies......................................................... 65,335 88,299
Accounts payable-
Associated companies......................................................... 45,459 56,861
Other........................................................................ 33,878 28,583
Accrued taxes................................................................. 8,762 16,096
Accrued interest............................................................... 11,848 16,448
Other.......................................................................... 22,162 11,690
---------- ----------
227,913 278,444
---------- ----------
NONCURRENT LIABILITIES:
Accumulated deferred income taxes.............................................. 297,140 316,757
Accumulated deferred investment tax credits.................................... 11,696 12,518
Power purchase contract loss liability......................................... 584,340 660,507
Nuclear fuel disposal costs.................................................... 37,936 37,541
Nuclear plant decommissioning costs............................................ -- 270,611
Asset retirement obligation.................................................... 210,178 --
Pensions and other postretirement benefits..................................... 105,552 1,354
Other.......................................................................... 70,264 40,288
---------- ----------
1,317,106 1,339,576
---------- ----------
COMMITMENTS AND CONTINGENCIES
(Notes 3 and 6)................................................................
---------- ----------
$3,473,987 $3,564,805
========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.
</FN>
14
METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31, 2003 2002
- ------------------------------------------------------------------------------------------------------------------
(Dollars in thousands, except per share amounts)
COMMON STOCKHOLDER'S EQUITY:
Common stock, without par value, authorized 900,000 shares
859,500 shares outstanding........................................................ $1,298,130 $1,297,784
Accumulated other comprehensive loss (Note 4(F)).................................... (32,474) (39)
Retained earnings (Note 4(A))....................................................... 27,011 17,841
---------- ----------
Total common stockholder's equity................................................. 1,292,667 1,315,586
---------- ----------
Company obligated TRUST
Preferred securities
of subsidiary trust
(NOTE 4(E)):
7.35% due 2039.................................................................... -- 92,409
---------- ----------
LONG-TERM DEBT (Note 4(D)):
First mortgage bonds:
6.60% due 2003.................................................................... -- 20,000
7.22% due 2003.................................................................... -- 40,000
6.34% due 2004.................................................................... 40,000 40,000
6.77% due 2005.................................................................... 30,000 30,000
7.35% due 2005.................................................................... -- 20,000
6.36% due 2006.................................................................... 17,000 17,000
6.40% due 2006.................................................................... 33,000 33,000
6.00% due 2008.................................................................... 8,265 8,700
6.10% due 2021.................................................................... 28,500 28,500
8.60% due 2022.................................................................... -- 30,000
8.80% due 2022.................................................................... -- 30,000
6.97% due 2023.................................................................... -- 30,000
7.65% due 2023.................................................................... -- 30,000
8.15% due 2023.................................................................... -- 60,000
5.95% due 2027.................................................................... 13,690 13,690
---------- ----------
Total first mortgage bonds...................................................... 170,455 430,890
Secured notes:
5.72% due 2006.................................................................... 100,000 100,000
5.93% due 2007.................................................................... 50,000 50,000
4.45% due 2010.................................................................... 100,000 --
4.95% due 2013.................................................................... 150,000 --
---------- ----------
Total secured notes............................................................. 400,000 150,000
Unsecured notes:
7.69% due 2039.................................................................... 5,936 5,968
7.35% due 2039.................................................................... 95,711 --
---------- ----------
Total unsecured notes........................................................... 101,647 5,968
Net unamortized premium on debt..................................................... 4,668 12,399
Long-term debt due within one year.................................................. (40,469) (60,467)
---------- ----------
Total long-term debt ........................................................... 636,301 538,790
---------- ----------
TOTAL CAPITALIZATION................................................................... $1,928,968 $1,946,785
========== ==========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
15
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, 2001....................... 859,500 $ 66,273 $ 400,200 64 $ 70,476
Net income.................................. $ 62,381 62,381
Net unrealized gain on investments.......... 5 5
Net unrealized 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 on investments.......... 22 22
Net unrealized 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 on investment........... 17 17
Net unrealized 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
- ----------------------------------------------------------------------------------------------------------------------------
Net income.................................. $ 61,170 61,170
Net unrealized gain on investments.......... 2 2
Net unrealized gain on derivative
instruments. ............................. 78 78
Minimum liability for unfunded retirement
benefits, net of $(23,062,000) of
income taxes ............................. (32,515) (32,515)
--------
Comprehensive income........................ $ 28,735
--------
Cash dividends on common stock.............. (52,000)
Purchase accounting fair value adjustment... 346
- ----------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2003..................... 859,500 $1,298,130 $ -- $(32,474) $ 27,011
============================================================================================================================
CONSOLIDATED STATEMENTS OF PREFERRED STOCK
Subject to
Mandatory Redemption
--------------------
Number Carrying
of Shares Value
--------- --------
(Dollars in thousands)
Balance, January 1, 2001............ 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
=============================================================
FIN 46 Deconsolidation
7.35% Series.................... (4,000,000) (92,618)
Amortization of fair market
value adjustment................ 209
-------------------------------------------------------------
Balance, December 31, 2003.......... -- $ --
=============================================================
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
16
METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Nov. 7 - Jan. 1 -
2003 2002 Dec. 31, 2001 Nov. 6, 2001
- -------------------------------------------------------------------------------------------------------------------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income $ 61,170 $ 63,224 $ 14,617 | $ 62,381
Adjustments to reconcile net income to net |
cash from operating activities: |
Provision for depreciation and amortization.............. 86,514 81,419 8,903 | 51,867
Other amortization....................................... -- (2,528) 154 | 1,147
Deferred costs recoverable as regulatory assets.......... (15,321) (18,938) 1,045 | (91,182)
Deferred income taxes, net............................... 46,654 23,356 906 | 53,464
Investment tax credits, net.............................. (822) (792) (128) | (721)
Cumulative effect of accounting change (Note 1(H))....... (371) -- -- | --
Receivables.............................................. 10,380 (24,672) 10,213 | 33,714
Accounts payable......................................... (20,988) (18,657) (4,339) | (60,868)
Other (Note 7)........................................... (34,728) (538) 8,286 | (59,313)
--------- -------- -------- | --------
Net cash provided from (used for) operating |
activities. ......................................... 132,488 101,874 39,657 | (9,511)
--------- -------- -------- | --------
|
CASH FLOWS FROM FINANCING ACTIVITIES: |
New Financing- |
Long-term debt........................................... 247,696 49,750 -- | 99,500
Short-term borrowings, net............................... -- 16,288 -- | 51,400
Redemptions and Repayments- |
Long-term debt........................................... (260,466) (60,000) -- | --
Short-term borrowings, net............................... (22,964) -- (25,989) | --
Dividend Payments- |
Common stock............................................. (52,000) (60,000) -- | (65,000)
--------- -------- -------- | --------
Net cash provided from (used for) financing |
activities. ......................................... (87,734) (53,962) (25,989) | 85,900
--------- -------- -------- | --------
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
Property additions......................................... (43,558) (44,533) (7,787) | (47,660)
Contributions to decommissioning trusts.................... (9,483) (12,644) -- | (7,113)
Loans to associated companies, net......................... (7,941) -- -- | --
Other...................................................... 664 (324) (453) | (5,209)
--------- -------- -------- | --------
Net cash used for investing activities................. (60,318) (57,501) (8,240) | (59,982)
--------- -------- -------- | --------
|
Net increase (decrease) in cash and cash equivalents.......... (15,564) (9,589) 5,428 | 16,407
Cash and cash equivalents at beginning of period.............. 15,685 25,274 19,846 | 3,439
--------- --------- -------- | --------
Cash and cash equivalents at end of period.................... $ 121 $ 15,685 $ 25,274 | $ 19,846
========= ======== ======== | ========
|
SUPPLEMENTAL CASH FLOWS INFORMATION: |
Cash Paid During the Year- |
Interest (net of amounts capitalized).................... $ 51,505 $ 46,266 $ -- | $ 41,473
========= ======== ======== | ========
Income taxes (refund).................................... $ (25,085) $ 34,385 $ (2,990) | $ 7,486
========= ======== ======== | ========
<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
17
METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF TAXES
Nov. 7 - Jan. 1 -
2003 2002 Dec. 31, 2001 Nov. 6, 2001
- -------------------------------------------------------------------------------------------------------------------------
(In thousands)
GENERAL TAXES:
State gross receipts *.......................................... $ 53,462 $ 56,043 $ 5,730 | $ 31,353
Real and personal property...................................... 2,510 1,384 5 | 1,236
Social security and unemployment................................ 2,448 1 (1) | 14
Other........................................................... 8,787 9,367 775 | 7,242
--------- -------- -------- | --------
Total general taxes...................................... $ 67,207 $ 66,795 $ 6,509 | $ 39,845
========= ======== ======== | ========
|
PROVISION FOR INCOME TAXES: |
Currently payable- |
Federal...................................................... $ (3,435) $ 15,371 $ 7,693 | $(11,534)
State........................................................ 1,763 6,437 2,433 | (1,760)
--------- -------- -------- | --------
(1,672) 21,808 10,126 | (13,294)
--------- -------- -------- | --------
Deferred, net- |
Federal...................................................... 38,863 19,615 934 | 41,297
State........................................................ 7,791 3,741 (28) | 12,167
--------- -------- -------- | --------
46,654 23,356 906 | 53,464
--------- -------- ------- | --------
Investment tax credit amortization.............................. (822) (792) (128) | (721)
--------- -------- -------- | --------
Total provision for income taxes......................... $ 44,160 $ 44,372 $ 10,904 | $ 39,449
========= ======== ======== | ========
|
INCOME STATEMENT CLASSIFICATION |
OF PROVISION FOR INCOME TAXES: |
Operating income................................................ $ 27,367 $ 27,447 $ 11,584 | $ 28,549
Other income.................................................... 16,639 16,925 (680) | 10,900
Cumulative effect of accounting change.......................... 154 -- -- | --
--------- -------- -------- | --------
Total provision for income taxes......................... $ 44,160 $ 44,372 $ 10,904 | $ 39,449
========= ======== ======== | ========
|
RECONCILIATION OF FEDERAL INCOME TAX |
EXPENSE AT STATUTORY RATE TO TOTAL |
PROVISION FOR INCOME TAXES: |
Book income before provision for income taxes................... $ 105,330 $107,596 $ 25,521 | $101,831
========= ======== ======== | ========
Federal income tax expense at statutory rate.................... $ 36,866 $ 37,659 $ 8,932 | $ 35,641
Increases (reductions) in taxes resulting from- |
Amortization of investment tax credits....................... (822) (792) (128) | (721)
Depreciation................................................. 1,736 1,362 304 | 926
State income tax, net of federal benefit..................... 6,289 6,107 938 | 7,388
Allocated share of consolidated tax savings.................. -- -- -- | (3,151)
Other, net................................................... 91 36 858 | (634)
--------- -------- -------- | --------
Total provision for income taxes......................... $ 44,160 $ 44,372 $ 10,904 | $ 39,449
========= ======== ======== | ========
|
ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31: |
Property basis differences...................................... $ 250,779 $217,351 $211,394 |
Nuclear decommissioning......................................... (6,405) (4,247) (5,623) |
Deferred sale and leaseback costs............................... (10,986) (11,366) (12,077) |
Non-utility generation costs.................................... 2,287 (4,832) 36,099 |
Purchase accounting basis difference............................ (642) (642) (37,143) |
Sale of generation assets....................................... (1,419) (1,419) (1,420) |
Regulatory transition charge.................................... 88,020 88,315 85,414 |
Customer receivables for future income taxes.................... 46,010 50,259 49,755 |
Other comprehensive income...................................... (23,062) -- -- |
Employee benefits............................................... (17,252) -- -- |
Other........................................................... (30,190) (16,662) (25,961) |
--------- -------- -------- |
Net deferred income tax liability........................ $ 297,140 $316,757 $300,438 |
========= ======== ======== |
<FN>
* Collected from customers through regulated rates and included in revenue on the Consolidated Statements of Income.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
</FN>
18
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
The consolidated financial statements include Metropolitan Edison
Company (Company) and its wholly owned subsidiaries. The Company is a wholly
owned subsidiary of FirstEnergy Corp. FirstEnergy also holds directly all of the
issued and outstanding common shares of its other principal electric utility
operating subsidiaries, including Ohio Edison Company (OE), The Cleveland
Electric Illuminating Company (CEI), The Toledo Edison Company (TE), American
Transmission Systems, Inc. (ATSI), 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.
(A) CONSOLIDATION-
The Company consolidates all majority-owned subsidiaries, over which
the Company exercises control and, when applicable, entities for which the
Company has a controlling financial interest. Intercompany transactions and
balances are eliminated in consolidation. Investments in nonconsolidated
affiliates (20-50 percent owned companies, joint ventures and partnerships) over
which the Company has the ability to exercise significant influence, but not
control, are accounted for on the equity basis.
(B) REVENUES-
The Company's principal business is providing electric service to
customers in 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, 2003 or 2002, with respect to
any particular segment of the Company's customers. Total customer receivables
were $119 million (billed - $70 million and unbilled - $49 million) and $121
million (billed - $76 million and unbilled - $45 million) as of December 31,
2003 and 2002, respectively.
(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. The PPUC authorized a 1998 rate restructuring plan for the
Company. 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 orders. The PPUC required the Company to seek an 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 merger and there
would be an adjustment to goodwill.
In June 2001, the PPUC approved the Settlement Stipulation with all
of the major parties in the combined merger and rate relief proceedings which
approved the FirstEnergy/GPU merger and provided provider of last resort (PLR)
deferred accounting treatment for energy costs, permitting the Company to defer,
for future recovery, energy costs in excess of amounts reflected in its capped
generation rates retroactive to January 1, 2001. This PLR deferral accounting
procedure was later denied in a February 2002 Commonwealth Court of Pennsylvania
decision. The court decision also affirmed the PPUC decision regarding approval
of the merger, remanding the decision to the PPUC only with respect to the issue
of merger savings. In 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 then 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 April 2, 2003, the PPUC remanded the issue relating to merger
savings to the Office of Administrative Law for hearings, directed the Company
to file a position paper on the effect of the Commonwealth Court order on the
19
Settlement Stipulation and allowed other parties to file responses to the
position paper. The Company filed a letter with the Administrative Law Judge
(ALJ) on June 11, 2003, voiding the Stipulation in its entirety and reinstating
its restructuring settlement previously approved by the PPUC.
On October 2, 2003, the PPUC issued an order concluding that the
Commonwealth Court reversed the PPUC's June 20, 2001 order in its entirety. The
PPUC directed the Company to file tariffs within thirty days of the order to
reflect the competitive transition charge (CTC) rates and shopping credits that
were in effect prior to the June 21, 2001 order to be effective upon one day's
notice. In response to that order, the Company filed the supplements to its
tariffs to become effective October 24, 2003.
On October 8, 2003, the Company filed a petition for clarification
relating to the October 2, 2003 order on two issues: to establish June 30, 2004
as the date to fully refund the nonutility generation (NUG) trust fund and to
clarify that the ordered accounting treatment regarding the CTC rate/shopping
credit swap should follow the ratemaking, and that the PPUC's findings would not
impair its rights to recover all of its stranded costs. On October 9, 2003,
ARIPPA (an intervenor in the proceedings) petitioned the PPUC to direct the
Company to reinstate accounting for the CTC rate/shopping credit swap
retroactive to January 1, 2002. Several other parties also filed petitions. On
October 16, 2003, the PPUC issued a reconsideration order granting the date
requested by the Company for the NUG trust fund refund; and, denying the
Company's other clarification requests and granting ARIPPA's petition with
respect to the accounting treatment of the changes to the CTC rate/shopping
credit swap. On October 22, 2003, the Company filed an Objection with the
Commonwealth Court asking that the Court reverse the PPUC's finding that
requires the Company to treat the stipulated CTC rates that were in effect from
January 1, 2002 on a retroactive basis. The Company is considering filing an
appeal to the Commonwealth Court on the PPUC orders as well.
On October 27, 2003, one Commonwealth Court judge issued an Order
denying the Company's objection without explanation. Due to the vagueness of the
Order, the Company, on October 31, 2003, filed an Application for Clarification
with the judge. Concurrent with this filing, the Company, in order to preserve
its rights, also filed with the Commonwealth Court both a Petition for Review of
the PPUC's October 16 and 22 Orders, and an application for reargument, if the
judge, in his clarification order, indicates that the Company's objection was
intended to be denied on the merits. In addition to these findings, the Company,
in compliance with the PPUC's Orders, filed revised PPUC quarterly reports for
the twelve months ended December 31, 2001 and 2002, and for the first two
quarters of 2003, reflecting balances consistent with the PPUC's findings in its
Orders.
Effective September 1, 2002, the Company assigned its PLR
responsibility to its FirstEnergy Solutions Corp. (FES) affiliate through a
wholesale power sale agreement. The PLR sale will be automatically extended for
each successive calendar year unless any party elects to cancel the agreement by
November 1 of the preceding year. Under the terms of the wholesale agreement,
FES assumed the supply obligation and the supply profit and loss risk, for the
portion of power supply requirements not self-supplied by the Company under its
NUG contracts and other power contracts with nonaffiliated third party
suppliers. This arrangement reduces the Company's exposure to high wholesale
power prices by providing power at a fixed price for their uncommitted PLR
energy costs during the term of the agreement with FES. FES has hedged most of
the Company's unfilled PLR on-peak obligation through 2004 and a portion of
2005, the period during which deferred accounting was previously allowed under
the PPUC's order. The Company' is authorized to continue deferring differences
between NUG contract costs and current market prices.
In late 2003, the PPUC issued a Tentative Order implementing new
reliability benchmarks and standards. In connection therewith, the PPUC
commenced a rulemaking procedure to amend the Electric Service Reliability
Regulations to implement these new benchmarks, and create additional reporting
on reliability. Although neither the Tentative Order nor the Reliability
Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to
begin filing quarterly reports on November 1, 2003. The comment period for both
the Tentative Order and the Proposed Rulemaking Order has closed. The Company is
currently awaiting the PPUC to issue a final order in both matters. The order
will determine (1) the standards and benchmarks to be utilized, and (2) the
details required in the quarterly and annual reports. It is expected that these
Orders will be finalized in March 2004.
On January 16, 2004, the PPUC initiated a formal investigation of the
Company's levels of compliance with the Public Utility Code and the PPUC's
regulations and orders with regard to reliable electric service. Hearings will
be held in August in this investigation and the ALJ has been directed to issue a
Recommended Decision by September 30, 2004, in order to allow the PPUC time to
issue a Final Order before December 16, 2004. The Company is unable to predict
the outcome of the investigation or the impact of the PPUC Order.
Regulatory Assets-
The Company recognizes, as regulatory assets, costs which the FERC
and the 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
20
remain regulated; accordingly, it is appropriate that the Company continue the
application of Statement of Financial Accounting Standards No. (SFAS) 71,
"Accounting for the Effects of Certain Types of Regulation," to those
operations.
Net regulatory assets on the Consolidated Balance Sheets are
comprised of the following:
2003 2002
------------------------------------------------------------------
(In millions)
Regulatory transition charge................... $ 926 $ 986
Customer receivables for future income taxes... 103 116
Nuclear decommissioning costs.................. (26) 54
Employee postretirement benefit costs.......... 18 20
Loss on reacquired debt........................ 8 4
Other.......................................... (1) (1)
------------------------------------------------------------------
Total....................................... $1,028 $1,179
=================================================================
Regulatory Accounting for Generation Operations-
The application of SFAS 71 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, providing 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 $15 million as of December 31,
2003.
(D) PROPERTY, PLANT AND EQUIPMENT-
As a result of the merger, a portion of the Company's property, plant
and equipment was adjusted to reflect fair value. The majority of the Company's
property, plant and equipment 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 2.7% in 2003 and 3.0% in 2002
and 2001.
(E) ASSET RETIREMENT OBLIGATION-
In January 2003, the Company implemented SFAS 143, "Accounting for
Asset Retirement Obligations," which provides accounting standards for
retirement obligations associated with tangible long-lived assets. This
statement requires recognition of the fair value of a liability for an asset
retirement obligation (ARO) in the period in which it is incurred. The
associated asset retirement costs are capitalized as part of the carrying amount
of the long-lived asset. Over time the capitalized costs are depreciated and the
present value of the asset retirement liability increases, resulting in a period
expense. However, rate-regulated entities may recognize a regulatory asset or
liability instead if the criteria for such treatment are met. Upon retirement, a
gain or loss would be recognized if the cost to settle the retirement obligation
differs from the carrying amount.
The Company identified applicable legal obligations as defined under
the new standard for nuclear power plant decommissioning. The ARO liability as
of the date of adoption of SFAS 143 was $198.3 million, including accumulated
accretion for the period from the date the liability was incurred to the date of
adoption. As of December 31, 2002, the Company recognized decommissioning
liabilities of $259.6 million. The Company expects substantially all nuclear
decommissioning costs to be recoverable through regulated rates. Therefore, a
regulatory liability of $61.3 million was recognized upon adoption of SFAS 143.
Accretion during 2003 was $11.9 million, bringing the ARO liability as of
December 31, 2003 to $210.2 million. The ARO includes the Company's obligation
for nuclear decommissioning of Three Mile Island Unit 2 (TMI-2). The Company's
share of the obligation to decommission TMI-2 was developed based on a
site-specific study performed by an independent engineer. The Company utilized
an expected cash flow approach (as discussed in FASB Concepts Statement No. 7,
"Using Cash Flow Information and Present Value in Accounting Measurements") to
measure the fair value of the nuclear decommissioning ARO. The Company maintains
nuclear decommissioning trust funds that are legally restricted for purposes of
settling the nuclear decommissioning ARO. As of December 31, 2003, the fair
value of the decommissioning trust assets was $192.4 million.
21
The following table provides the year-end balance of the ARO related
to nuclear decommissioning for 2002, as if SFAS 143 had been adopted on January
1, 2002.
Adjusted ARO Reconciliation 2002
-------------------------------------------------------
(In millions)
Beginning balance as of January 1, 2002 $187.1
Accretion in 2002 11.2
-------------------------------------------------------
Ending balance as of December 31, 2002 $198.3
-------------------------------------------------------
(F) STOCK-BASED COMPENSATION-
FirstEnergy applies the recognition and measurement principles of
Accounting Principles Board Opinion No. 25 (APB 25), "Accounting for Stock
Issued to Employees" and related Interpretations in accounting for its
stock-based compensation plans (see Note 4(B)). No material stock-based employee
compensation expense is reflected in net income as all options granted under
those plans had an exercise price equal to the market value of the underlying
common stock on the grant date, resulting in substantially no intrinsic value.
If FirstEnergy had accounted for employee stock options under the
fair value method of SFAS 123, "Accounting for Stock Compensation," a higher
value would have been assigned to the options granted. The weighted average
assumptions used in valuing the options and their resulting estimated fair
values would be as follows:
2003 2002 2001
---------------------------------------------------------------
Valuation assumptions:
Expected option term (years) 7.9 8.1 8.3
Expected volatility......... 26.91% 23.31% 23.45%
Expected dividend yield..... 5.09% 4.36% 5.00%
Risk-free interest rate..... 3.67% 4.60% 4.67%
Fair value per option......... $5.09 $6.45 $4.97
---------------------------------------------------------------
The effects of applying fair value accounting to the FirstEnergy's
stock options would not materially affect the Company's net income.
(G) INCOME TAXES-
Details of the total provision for income taxes are shown on the
Consolidated Statements of Taxes. The Company records income taxes in accordance
with the liability method of accounting. Deferred income taxes reflect the net
tax effect of temporary differences between the carrying amounts of assets and
liabilities for financial reporting purposes and the amounts used for tax
purposes. Investment tax credits, which were deferred when utilized, are being
amortized over the recovery period of the related property. Deferred income tax
liabilities related to tax and accounting basis differences and tax credit
carryforward items are recognized at the statutory income tax rates in effect
when the liabilities are expected to be paid. Results for the period January 1,
2001 through November 6, 2001 were included in the final consolidated federal
income tax return of GPU, and results for the period November 7, 2001 through
December 31, 2001 were included in FirstEnergy's 2001 consolidated federal
income tax return. The consolidated tax liability is allocated on a
"stand-alone" company basis, with the Company recognizing the tax benefit for
any tax losses or credits it contributes to the consolidated return.
(H) CUMULATIVE EFFECT OF ACCOUNTING CHANGE
As a result of adopting SFAS 143 in January 2003, asset retirement
costs were recorded in the amount of $186 million as part of the carrying amount
of the related long-lived asset, offset by accumulated depreciation of $186
million. The ARO liability on the date of adoption was $198 million, including
accumulated accretion for the period from the date the liability was incurred to
the date of adoption. The remaining cumulative effect adjustment for
unrecognized depreciation and accretion, offset by the reduction in the existing
decommissioning liabilities and the reversal of accumulated estimated removal
costs for non-regulated generation assets, was a $0.4 million increase to
income, $0.2 million net of tax in the year ended December 31, 2003. If SFAS 143
had been applied during 2002 and 2001, the impact would not have been material
to the Company's Consolidated Statements of Income.
22
(I) PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
FirstEnergy provides noncontributory defined benefit pension plans
that cover substantially all of the Company's employees. The trusteed plans
provide defined benefits based on years of service and compensation levels.
FirstEnergy's funding policy is based on actuarial computations using the
projected unit credit method. No pension contributions were required during the
three years ended December 31, 2003.
FirstEnergy provides a minimum amount of noncontributory life
insurance to retired employees in addition to optional contributory insurance.
Health care benefits, which include certain employee contributions, deductibles
and copayments, are also available to retired employees, their dependents and,
under certain circumstances, their survivors. The Company recognizes the
expected cost of providing other postretirement benefits to employees and their
beneficiaries and covered dependents from the time employees are hired until
they become eligible to receive those benefits.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions made to the plans, and earnings on plan assets. Such factors may
be further affected by business combinations (such as FirstEnergy's merger with
GPU, Inc. in November 2001), which impacts employee demographics, plan
experience and other factors. Pension and OPEB costs may also be affected by
changes to key assumptions, including anticipated rates of return on plan
assets, the discount rates and health care trend rates used in determining the
projected benefit obligations and pension and OPEB costs. FirstEnergy uses a
December 31 measurement date for the majority of its plans.
Plan amendments to retirement health care benefits in 2003 and 2002,
relate to changes in benefits provided and cost-sharing provisions, which
reduced FirstEnergy's obligation by $123 and $121 million, respectively. In
early 2004, FirstEnergy announced that it would amend the benefit provisions of
its health care benefits plan and both employees and retirees would share in
more of the benefit costs.
On December 8, 2003, President Bush signed into law a bill that
expands Medicare, primarily adding a prescription drug benefit for
Medicare-eligible retirees starting in 2006. FirstEnergy anticipates that the
benefits it pays after 2006 will be lower as a result of the new Medicare
provisions. Due to uncertainties surrounding some of the new Medicare provisions
and a lack of authoritative accounting guidance about these issues, FirstEnergy
deferred the recognition of the impact of the new Medicare provisions as
provided by FASB Staff Position 106-1. The final accounting guidance could
require changes to previously reported information.
The following sets forth the funded status of the plans and amounts
recognized on FirstEnergy's Consolidated Balance Sheets as of December 31:
23
Obligations and Funded Status Pension Benefits Other Benefits
---------------- --------------
As of December 31 2003 2002 2003 2002
------------------------------------------------------------------------------------------
(In millions)
Change in benefit obligation
Benefit obligation at beginning of year.. $3,866 $3,548 $ 2,077 $ 1,582
Service cost............................. 66 59 43 28
Interest cost............................ 253 249 136 114
Plan participants' contributions......... -- -- 6 --
Plan amendments.......................... -- -- (123) (121)
Actuarial loss........................... 222 268 323 440
GPU acquisition (Note 2)................. -- (12) -- 110
Benefits paid............................ (245) (246) (94) (76)
------ ------ ------- -------
Benefit obligation at end of year........ $4,162 $3,866 $ 2,368 $ 2,077
====== ====== ======= =======
Change in fair value of plan assets
Fair value of plan assets at
beginning of year...................... $2,889 $3,484 $ 473 $ 535
Actual return on plan assets............. 671 (349) 88 (57)
Company contribution..................... -- -- 68 31
Plan participants' contribution.......... -- -- 2 --
Benefits paid............................ (245) (246) (94) (36)
------ ------ ------- -------
Fair value of plan assets at end of year. $3,315 $2,889 $ 537 $ 473
====== ====== ======= =======
Funded status............................ $ (847) $ (977) $(1,831) (1,604)
Unrecognized net actuarial loss.......... 919 1,186 994 752
Unrecognized prior service cost (benefit) 72 78 (221) (107)
Unrecognized net transition obligation... -- -- 83 92
------ ------ ------- -------
Net asset (liability) recognized......... $ 144 $ 287 $ (975) $ (867)
====== ====== ======= =======
Amounts Recognized in the
Consolidated Balance Sheets
As of December 31
----------------------------------------
Accrued benefit cost..................... $ (438) $ (548) $ (975) $(867)
Intangible assets........................ 72 78 -- --
Accumulated other comprehensive loss..... 510 757 -- --
------ ------ ------- -----
Net amount recognized.................... $ 144 $ 287 $ (975) $(867)
====== ====== ======= =====
Company's share of net amount recognized. $ 10 $ -- $ (59) $ --
====== ====== ======= =====
Increase (decrease) in minimum liability
included in other comprehensive income
(net of tax)........................... $ (145) $ 444 -- $ --
Weighted-Average Assumptions Used
to Determine Benefit Obligations
As of December 31
----------------------------------------
Discount rate............................ 6.25% 6.75% 6.25% 6.75%
Rate of compensation increase............ 3.50% 3.50%
Allocation of Plan Assets
As of December 31
----------------------------------------
Asset Category
Equity securities........................ 70% 61% 71% 58%
Debt securities.......................... 27 35 22 29
Real estate.............................. 2 2 -- --
Other.................................... 1 2 7 13
---- ---- ---- ----
Total.................................... 100% 100% 100% 100%
==== ==== ==== ====
Information for Pension Plans With an
Accumulated Benefit Obligation in
Excess of Plan Assets 2003 2002
----------------------------------------- ---- ----
(In millions)
Projected benefit obligation............. $4,162 $3,866
Accumulated benefit obligation........... 3,753 3,438
Fair value of plan assets................ 3,315 2,889
FirstEnergy's net pension and other postretirement benefit costs for
the three years ended December 31, 2003 were computed as follows:
24
Pension Benefits Other Benefits
--------------------- --------------------
Components of Net Periodic Benefit Costs 2003 2002 2001 2003 2002 2001
-------------------------------------------------------------------------------------------
(In millions)
Service cost............................ $ 66 $ 59 $ 35 $ 43 $ 29 $ 18
Interest cost........................... 253 249 133 137 114 65
Expected return on plan assets.......... (248) (346) (205) (43) (52) (10)
Amortization of prior service cost...... 9 9 9 (9) 3 3
Amortization of transition
obligation (asset).................... -- -- (2) 9 9 9
Recognized net actuarial loss........... 62 -- -- 40 11 5
Voluntary early retirement program...... -- -- 6 -- -- 2
----- ----- ----- ----- ---- ----
Net periodic cost (income).............. $ 142 $ (29) $ (24) $ 177 $114 $ 92
===== ===== ===== ===== ==== ====
Company's share of net periodic cost (income)
(see Note 7)
Weighted-Average Assumptions Used
to Determine Net Periodic Benefit Cost
for Years Ended December 31
----------------------------------------
Discount rate........................... 6.75% 7.25% 7.75% 6.75% 7.25% 7.75%
Expected long-term return on
plan assets........................... 9.00% 10.25% 10.25% 9.00% 10.25% 10.25%
Rate of compensation increase........... 3.50% 4.00% 4.00%
In selecting an assumed discount rate, FirstEnergy considers
currently available rates of return on high-quality fixed income investments
expected to be available during the period to maturity of the pension and other
postretirement benefit obligations. The assumed rate of return on pension plan
assets considers historical market returns and economic forecasts for the types
of investments held by the Company's pension trusts. The long-term rate of
return is developed considering the portfolio's asset allocation strategy.
Assumed health care cost trend rates
As of December 31 2003 2002
--------------------------------------------------------------------------------
Health care cost trend rate assumed for next
year (pre/post-Medicare).......................... 10%-12% 10%-12%
Rate to which the cost trend rate is assumed to
decline (the ultimate trend rate)................. 5% 5%
Year that the rate reaches the ultimate trend
rate (pre/post-Medicare).......................... 2009-2011 2007-2009
Assumed health care cost trend rates have a significant effect on the
amounts reported for the health care plans. A one-percentage-point change in
assumed health care cost trend rates would have the following effects:
1-Percentage- -Percentage-
Point Increase Point Decrease
-------------------------------------------------------------------------
(In millions)
Effect on total of service and interest cost.. $ 26 $ (19)
Effect on postretirement benefit obligation... $233 $(212)
FirstEnergy employs a total return investment approach whereby a mix
of equities and fixed income investments are used to maximize the long-term
return of plan assets for a prudent level of risk. Risk tolerance is established
through careful consideration of plan liabilities, plan funded status, and
corporate financial condition. The investment portfolio contains a diversified
blend of equity and fixed-income investments. Furthermore, equity investments
are diversified across U.S. and non-U.S. stocks, as well as growth, value, and
small and large capitalizations. Other assets such as real estate are used to
enhance long-term returns while improving portfolio diversification. Derivatives
may be used to gain market exposure in an efficient and timely manner; however,
derivatives are not used to leverage the portfolio beyond the market value of
the underlying investments. Investment risk is measured and monitored on a
continuing basis through periodic investment portfolio reviews, annual liability
measurements, and periodic asset/liability studies.
As a result of GPU Service Inc. merging with FirstEnergy Service
Company (FESC) in the second quarter of 2003, operating company employees of GPU
Service (GPUS) were transferred to the former GPU operating companies.
Accordingly, FirstEnergy requested an actuarial study to update the pension
liabilities for each of its subsidiaries. Based on the actuary's report, the
accrued pension costs for the Company as of June 30, 2003 increased by $47
million. The corresponding adjustment related to this change decreased other
comprehensive income and deferred income taxes and increased the payable to
associated companies.
Due to the increased market value of its pension plan assets, the
Company reduced its minimum liability as prescribed by SFAS 87 as of December
31, 2003 by $7 million, recording an increase of $13,000 in an intangible asset
and crediting OCI by $4 million (offsetting previously recorded deferred tax
25
benefits by $3 million). The remaining balance in OCI of $33 million will
reverse in future periods to the extent the fair value of trust assets exceeds
the accumulated benefit obligation. The accrued pension cost was reduced to $45
million as of December 31, 2003.
FirstEnergy does not expect to contribute to its pension plans in
2004 and expects to contribute $16 million to its other postretirement benefit
plans in 2004.
(J) GOODWILL-
In a business combination, the excess of the purchase price over the
estimated fair values of the assets acquired and liabilities assumed is
recognized as goodwill. Under SFAS 142, "Goodwill and Other Intangible Assets,"
amortization of existing goodwill ceased January 1, 2002. Instead, the Company
evaluates goodwill for impairment at least annually and makes such an evaluation
more frequently if indicators of impairment should arise. In accordance with the
accounting standard, if the fair value of a reporting unit is less than its
carrying value (including goodwill), the goodwill is tested for impairment. When
impairment is indicated, the Company recognizes a loss - calculated as the
difference between the implied fair value of a reporting unit's goodwill and the
carrying value of the goodwill. The Company's annual review was completed in the
third quarter of 2003. The forecasts used in the Company's evaluations of
goodwill reflect operations consistent with its general business assumptions.
Unanticipated changes in those assumptions could have a significant effect on
the Company's future evaluations of goodwill. As of December 31, 2003, the
Company had $884 million of goodwill.
(K) TRANSACTIONS WITH AFFILIATED COMPANIES-
Operating revenues, operating expenses and other income included
transactions with affiliated companies, primarily FESC, GPUS and FES. GPUS
(until it ceased operations in mid-2003) and FESC have 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 FESC, both subsidiaries of FirstEnergy Corp. and both "mutual service
companies" as defined in Rule 93 of the Public Utility Holding Company Act of
1935 (PUHCA). The 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: each company's
proportionate amount of FirstEnergy's aggregate direct payroll, number of
employees, asset balances, revenues, number of customers, other factors and
specific departmental charge ratios. Management believes that these allocation
methods are reasonable. Intercompany transactions with FirstEnergy and its other
subsidiaries are generally settled under commercial terms within thirty days,
except for a net $20 million receivable from affiliates for pension and OPEB
obligations.
(L) CASH AND FINANCIAL INSTRUMENTS-
All temporary cash investments purchased with an initial maturity of
three months or less are reported as cash equivalents on the Consolidated
Balance Sheets at cost, which approximates their fair market value.
All borrowings with initial maturities of less than one year are
defined as financial instruments under GAAP and are reported on the Consolidated
Balance Sheets at cost, which approximates their fair market value. The
following sets forth the approximate fair value and related carrying amounts of
all other long-term debt, preferred stock subject to mandatory redemption and
investments other than cash and cash equivalents as of December 31:
2003 2002
---------------------------------------------------------------------------
Carrying Fair Carrying Fair
Value Value Value Value
---------------------------------------------------------------------------
(In millions)
Long-term debt..................... $672 $697 $587 $598
Preferred stock.................... $ -- $ -- $ 92 $100
Investments other than cash
and cash equivalents............. $195 $195 $156 $156
---------------------------------------------------------------------------
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.
26
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
($114 million) and fixed income securities ($78 million) as of December 31,
2003. Realized and unrealized gains and losses applicable to the decommissioning
trusts have been recognized in the trust investment with a corresponding change
to regulatory assets. For 2003 and 2002, net realized gains (losses) were
approximately $0.5 million and $(0.4) million and interest and dividend income
totaled approximately $5.1 million and $4.7 million, respectively.
On January 1, 2001, the Company adopted SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended by SFAS 138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities --
an amendment of FASB Statement No. 133." The adoption resulted in the
recognition of derivative assets on the Consolidated Balance Sheet at January 1,
2001 in the amount of $13.0 million, with a substantially offsetting amount
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 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 was no deferred gain or loss
in Accumulated Other Comprehensive Loss as of December 31, 2003 related to
derivative hedging activity.
2. MERGER:
On November 7, 2001, the merger of FirstEnergy and GPU became
effective pursuant to the Agreement and Plan of Merger, dated August 8, 2000. As
a result of the merger, GPU's former wholly owned subsidiaries, including the
Company, became wholly owned subsidiaries of FirstEnergy.
The merger was accounted for by the purchase method of accounting.
The assets acquired and liabilities assumed were recorded at estimated fair
values as determined by FirstEnergy's management based on information currently
available and on current assumptions as to future operations. Merger purchase
accounting adjustments recorded in the records of the Company primarily consist
of: (1) revaluation of certain property, plant and equipment; (2) adjusting
preferred stock subject to mandatory redemption and long-term debt to estimated
fair value; (3) recognizing additional obligations related to retirement
benefits; and (4) recognizing estimated severance and other compensation
liabilities. Other assets and liabilities were not adjusted since they remain
subject to rate regulation on a historical cost basis. The excess of the
purchase price over the estimated fair values of the assets acquired and
liabilities assumed was recognized as goodwill.
During 2002 and 2003, certain pre-acquisition contingencies and other
final adjustments to the fair values of the assets acquired and liabilities
assumed were reflected in the final allocations of the purchase price. These
adjustments primarily related to: (1) final actuarial calculations related to
pension and postretirement benefit obligations; (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, 2003, the Company
had recorded goodwill of approximately $884.3 million related to the merger.
27
3. LEASES:
Consistent with regulatory treatment, the rentals for capital and
operating leases are charged to operating expenses on the Consolidated
Statements of Income. The Company's most significant operating lease relates to
the sale and leaseback of a portion of its ownership interest in the Merrill
Creek Reservoir project. The interest element related to this lease was $1.6
million, $0.2 million and $1.9 million for the years 2003, 2002 and 2001.
As of December 31, 2003, the future minimum lease payments on the
Company's Merrill Creek operating lease, net of reimbursements from sublessees,
are: $1.2 million, $1.5 million, $1.5 million, $1.5 million and $1.5 million for
the years 2004 through 2008, respectively, and $43.7 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 as of the November 7, 2001 merger date.
In general, the Company's first mortgage bond (FMB) indentures
restrict the payment of dividends or distributions on or with respect to the
Company's common stock to amounts credited to earned surplus since approximately
the date of its indenture. At such date, the Company had a balance of $3.4
million in its earned surplus account, which would not be available for
dividends or other distributions. As of December 31, 2003, the Company had
retained earnings available to pay common stock dividends of $23.6 million, net
of amounts restricted under the Company's FMB indentures.
(B) STOCK COMPENSATION PLANS-
FirstEnergy administers the FirstEnergy Executive and Director
Incentive Compensation Plan (FE Plan). Under the FE Plan, total awards cannot
exceed 22.5 million shares of common stock or their equivalent. Only stock
options and restricted stock have been granted, with vesting periods ranging
from six months to seven years. Several other stock compensation plans have been
acquired through the mergers with GPU and Centerior - GPU, Inc. Stock Option and
Restricted Stock Plan for MYR Group Inc. Employees (MYR Plan), 1990 Stock Plan
for Employees of GPU, Inc. and Subsidiaries (GPU Plan) and Centerior Equity
Plan. No further stock-based compensation can be awarded under these plans.
Collectively, the above plans are referred to as the FE Programs.
Restricted common stock grants under the FE Programs were as follows:
2003 2002 2001
-----------------------------------------------------------------------
Restricted common shares granted..... -- 36,922 133,162
Weighted average market price ........ n/a (1) $36.04 $35.68
Weighted average vesting period (years) n/a (1) 3.2 3.7
Dividends restricted.................. n/a (1) Yes -- (2)
-----------------------------------------------------------------------
(1) Not applicable since no restricted stock was granted.
(2) FE Plan dividends are paid as restricted stock on 4,500
shares; MYR Plan dividends are paid as unrestricted cash
on 128,662 shares
Under the Executive Deferred Compensation Plan (EDCP), covered
employees can direct a portion of their Annual Incentive Award and/or Long-Term
Incentive Award into an unfunded FirstEnergy Stock Account to receive vested
stock units. An additional 20% premium is received in the form of stock units
based on the amount allocated to the FirstEnergy Stock Account. Dividends are
calculated quarterly on stock units outstanding and are paid in the form of
additional stock units. Upon withdrawal, stock units are converted to
FirstEnergy shares. Payout typically occurs three years from the date of
deferral; however, an election can be made in the year prior to payout to
further defer shares into a retirement stock account that will pay out in cash
upon retirement. As of December 31, 2003, there were 410,399 stock units
outstanding.
28
Stock option activities under the FE Programs for the past three
years were as follows:
Number of Weighted Average
Stock Option Activities Options Exercise Price
--------------------------------------------------------------------
Balance, January 1, 2001......... 5,021,862 $24.09
(473,314 options exercisable).... 24.11
Options granted................ 4,240,273 28.11
Options exercised.............. 694,403 24.24
Options forfeited.............. 120,044 28.07
Balance, December 31, 2001....... 8,447,688 26.04
(1,828,341 options exercisable).. 24.83
Options granted................ 3,399,579 34.48
Options exercised.............. 1,018,852 23.56
Options forfeited.............. 392,929 28.19
Balance, December 31, 2002...... 10,435,486 28.95
(1,400,206 options exercisable).. 26.07
Options granted................ 3,981,100 29.71
Options exercised.............. 455,986 25.94
Options forfeited.............. 311,731 29.09
Balance, December 31, 2003...... 13,648,869 29.27
(1,919,662 options exercisable).. 29.67
As of December 31, 2003, the weighted average remaining contractual
life of outstanding stock options was 7.6 years.
Options outstanding by plan and range of exercise price as of
December 31, 2003 were as follows:
Range of Options
FirstEnergy Program Exercise Prices Outstanding
-------------------------------------------------------------------
FE plan $19.31 - $29.87 9,904,861
$30.17 - $35.15 3,214,601
Plans acquired through merger:
GPU plan $23.75 - $35.92 501,734
Other plans 27,673
-------------------------------------------------------------------
Total 13,648,869
==================================================================-
No material stock-based employee compensation expense is reflected in
net income for stock options granted under the above plans since the exercise
price was equal to the market value of the underlying common stock on the grant
date. The effect of applying fair value accounting to FirstEnergy's stock
options is summarized in Note 1(F) - Stock-Based Compensation.
(C) PREFERRED AND PREFERENCE STOCK-
The Company's preferred stock authorization consists of 10 million
shares without par value. No preferred shares are currently outstanding.
(D) LONG-TERM DEBT-
The Company's FMB indenture, which secures all of the Company's FMBs,
serve as a direct first mortgage lien on substantially all of the Company's
property and franchises, other than specifically excepted property.
The Company has various debt covenants under its financing
arrangements. The most restrictive of these relate to the nonpayment of interest
and/or principal on debt, which could trigger a default. Cross-default
provisions also exist between FirstEnergy and the Company.
Based on the amount of bonds authenticated by the Trustee through
December 31, 2003 the Company's annual sinking fund requirements for all bonds
issued under the mortgage amount to $6 million. The Company expects to fulfill
its sinking fund obligation by providing refundable bonds to the Trustee.
Sinking fund requirements for FMBs and maturing long-term debt
(excluding capital leases) for the next five years are:
29
(In millions)
----------------------------------
2004................ $ 40
2005................ 30
2006................ 151
2007................ 50
2008................ 7
----------------------------------
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 million to pay principal of, or interest on, the pollution
control revenue bonds.
(E) LONG-TERM DEBT: SUBORDINATED DEBENTURES TO AFFILIATED TRUST-
The Company formed a statutory business trust to sell preferred
securities and invest the gross proceeds in subordinated debentures. Ownership
of the Company's trust is through a separate wholly owned limited partnership.
In this transaction, the trust invested the gross proceeds from the sale of its
preferred securities in the preferred securities of the limited partnership,
which in turn invested those proceeds in the 7.35% subordinated debentures of
the Company. The Company has effectively provided a full and unconditional
guarantee of obligations under the trust's preferred securities. The trust's
preferred securities are redeemable at the option of the Company beginning in
May 2004 at 100% of their principal amount.
Interest on the subordinated debentures (and therefore distributions
on the trust's 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.
Upon adoption of FIN 46R "Consolidation of Variable Interest
Entities", the limited partnership and statutory business trust discussed above
are not consolidated on the Company's financial statements as of December 31,
2003 (see Note 8).
(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, 2003, accumulated other comprehensive loss consisted of a minimum
liability for unfunded retirement benefits of $32.5 million.
5. SHORT-TERM BORROWINGS:
The Company may borrow from its affiliates on a short-term basis. As
of December 31, 2003, the Company had total short-term borrowings of $65.3
million from its affiliates. The weighted average interest rates on short-term
borrowings outstanding at December 31, 2003 and 2002 were 1.7% and 1.8%,
respectively.
6. COMMITMENTS, GUARANTEES AND CONTINGENCIES:
(A) CAPITAL EXPENDITURES-
The Company's current forecast reflects expenditures of approximately
$168 million for property additions and improvements from 2004 through 2006, of
which approximately $55 million is applicable to 2004.
(B) NUCLEAR INSURANCE-
The Price-Anderson Act limits the public liability relative to a
single incident at a nuclear power plant to $10.9 billion. The amount is covered
by a combination of private insurance and an industry retrospective rating plan.
Based on its present ownership interest in TMI-2, the Company is exempt from any
potential assessment under the industry retrospective rating plan.
The Company is also insured as to its interest in TMI-2 under a
policy issued to the operating company for the plant. Under this policy, $150
million is provided for property damage and decontamination and decommissioning
costs. Under this policy, the Company can be assessed a maximum of approximately
$0.3 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
30
insurance in effect with respect to that plant, to the extent a nuclear incident
is determined not to be covered by the Company's insurance policies, or to the
extent such insurance becomes unavailable in the future, the Company would
remain at risk for such costs.
(C) ENVIRONMENTAL MATTERS-
The Company has been named as a "potentially responsible party" (PRP)
at waste disposal sites which may require cleanup under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980. Allegations of
disposal of hazardous substances at historical sites and the liability involved
are often unsubstantiated and subject to dispute; however, federal law provides
that all PRPs for a particular site be held liable on a joint and several basis.
Therefore, potential environmental liabilities have been recognized on the
Consolidated Balance Sheet as of December 31, 2003, based on estimates of the
total costs of cleanup, the Company's proportionate responsibility for such
costs and the financial ability of other nonaffiliated entities to pay. The
Company has accrued liabilities aggregating approximately $59,000 as of December
31, 2003. The Company accrues for environmental costs only when it can conclude
that it is probable that they have an obligation for such costs and can
reasonably determine the amount of such costs. Unasserted claims are reflected
in the Company's determination of environmental liabilities and are accrued in
the period that they are both probable and reasonably estimable. The Company
does not believe environmental remediation costs will have a material adverse
effect on its financial condition, cash flows or results of operations.
(D) OTHER LEGAL PROCEEDINGS-
Various lawsuits, claims and proceedings related to the Company's
normal business operations are pending against the Company, the most significant
of which is described above.
On August 14, 2003, various states and parts of southern Canada
experienced a widespread power outage. That outage affected approximately 1.4
million customers in FirstEnergy's service area. FirstEnergy continues to
accumulate data and evaluate the status of its electrical system prior to and
during the outage event, and continues to cooperate with the U.S.-Canada Power
System Outage Task Force (Task Force) investigating the August 14th outage. The
interim report issued by the Task Force on November 18, 2003 concluded that the
problems leading to the outage began in FirstEnergy's service area.
Specifically, the interim report concludes, among other things, that the
initiation of the August 14th outage resulted from the coincidence on that
afternoon of the following events: (1) inadequate situational awareness at
FirstEnergy; (2) FirstEnergy's failure to adequately manage tree growth in its
transmission rights of way; and (3) failure of the interconnected grid's
reliability organizations (Midwest Independent System Operator and PJM
Interconnection) to provide effective diagnostic support. FirstEnergy believes
that the interim report falls far short of providing a complete and
comprehensive picture of the conditions that contributed to the August 14th
outage and that it does not adequately address the underlying causes of the
outage. FirstEnergy remains convinced that the outage cannot be explained by
events on any one utility's system. On November 25, 2003, The Public Utillity
Commission of Ohio (PUCO) ordered FirstEnergy to file a plan with the PUCO no
later than March 1, 2004, illustrating how FirstEnergy will correct problems
identified by the Task Force as events contributing to the August 14th outage
and addressing how FirstEnergy proposes to upgrade its control room computer
hardware and software and improve the training of control room operators to
ensure that similar problems do not occur in the future. The PUCO, in
consultation with the North American Electric Reliability Council, will review
the plan before determining the next steps in the proceeding. On December 24,
2003, the FERC ordered FirstEnergy to pay for an independent study of part of
Ohio's power grid. The study is to examine the stability of the grid in critical
points in the Cleveland and Akron areas; the status of projected power reserves
during summer 2004 through 2008; and the need for new transmission lines or
other grid projects. The FERC ordered the study to be completed within 120 days.
At this time, it is unknown what the cost of such study will be, or the impact
of the results.
7. OTHER INFORMATION :
The following represents the financial data which includes
supplemental unaudited prior years' information as compared to consolidated
financial statements and notes previously reported in 2001.
31
(A) CONSOLIDATED STATEMENTS OF CASH FLOWS
Nov. 7- Jan. 1-
Dec. 31, Nov. 6,
2003 2002 2001 2001
---- ---- ---- ----
(Unaudited) (Unaudited)
(In thousands)
Other cash flows from operating activities:
Accrued retirement benefit obligations.... $ (3,284) $ 63 $ 1 | $ (15)
Accrued compensation, net................. 5,531 (2,491) -- | (1,238)
Accrued taxes............................. (7,334) 9,059 5,229 | (18,960)
Accrued interest.......................... (4,600) (1,020) 5,629 | (2,536)
Prepayments and other..................... 3,131 2,508 10,456 | (15,140)
Other..................................... (28,172) (8,657) (13,029) | (21,424)
-------- ------- --------- | --------
Other cash provided from (used for)
operating activities.................. $(34,728) $ (538) $ 8,286 | $(59,313)
======== ======== ======== | =========
(B) REVENUES - INDEPENDENT SYSTEM OPERATOR (ISO) TRANSACTIONS-
The Company records purchase and sales transactions with PJM
Interconnection ISO, an independent system operator, on a gross basis in
accordance with EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal
versus Net as an Agent." The aggregate purchase and sales transactions for the
three years ended December 31, 2003, are summarized as follows:
Nov. 7-Dec. 31, Jan. 1-Nov. 6,
2003 2002 2001 2001
--------------------------------------------------------------------------
(Unaudited) (Unaudited)
(In millions)
|
Sales............. $ 3 $ 9 $ 1 | $11
Purchases......... 13 67 13 | 81
--------------------------------------------------------------------------
The Company's revenues on the Consolidated Statements of Income
include wholesale electricity sales revenues from the PJM ISO from power sales
(as reflected in the table above) during periods when the Company had additional
available power capacity. Revenues also include sales by the Company of power
sourced from the PJM ISO (reflected as purchases in the table above) during
periods when the Company required additional power to meet its retail load
requirements.
(C) TRANSACTIONS WITH AFFILIATED COMPANIES-
The primary affiliated companies transactions are as follows:
Nov. 7- Jan. 1-
Dec. 31, Nov. 6,
2003 2002 2001 2001
- --------------------------------------------------------------------------------
(Unaudited) (Unaudited)
(In millions)
Operating Revenues:
Wholesale sales-affiliated companies... $ -- $ 18.6 $3.2 | $8.4
|
Operating Expenses: |
Power purchased from FES............... 276.7 171.9 10.6 | --
Service Company support services....... 49.5 68.1 14.0 | 81.0
Power purchased from other affiliates.. 2.2 9.5 1.9 | 9.2
- --------------------------------------------------------------------------------
(D) RETIREMENTS BENEFITS (1)
Net pension and other postretirement benefit costs (income) for the
three years ended December 31, 2003 are approximately as follows:
Nov. 7- Jan. 1-
Dec. 31, Nov. 6,
2003 2002 2001 2001
- --------------------------------------------------------------------------------
(Unaudited) (Unaudited)
(In millions)
Pension Benefits....................... $5 $(11) $(3) $(8)
Other Postretirement Benefits.......... 7 3 1 8
- -------------------------------------------------------------------------------
(1) Includes estimated portion of benefit costs included in billings from GPUS.
8. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS:
32
FIN 46 (revised December 2003), "Consolidation of Variable
Interest Entities"
In December 2003, the FASB issued a revised interpretation of
Accounting Research Bulletin No. 51, "Consolidated Financial Statements." FASB
Interpretation No. 46, "Consolidation of Variable Interest Entities", referred
to as "FIN 46R", requires the consolidation of a VIE by an enterprise if that
enterprise is determined to be the primary beneficiary of the VIE. As required,
the Company adopted FIN 46R for interests in VIEs or potential VIEs commonly
referred to as special-purpose entities effective December 31, 2003. The Company
will adopt FIN 46R for all other types of entities effective March 31, 2004.
As described in Note 4(E), the Company created a statutory business
trust to issue trust preferred securities in the amount of $93 million.
Application of the guidance in FIN 46R resulted in the holders of the preferred
securities being considered the primary beneficiaries of these trusts.
Therefore, the Company has deconsolidated the trust and recognized an equity
investment in the trust of $3 million and subordinated debentures to the trust
of $96 million as of December 31, 2003.
The Company is evaluating entities that meet the deferral criteria
and may be subject to consolidation under FIN 46R as of March 31, 2004. These
entities are non-utility generators in which we have neither debt nor equity
investments but are generally the sole purchaser of their power.
SFAS 143, "Accounting for Asset Retirement Obligations"
In January 2003, the Company implemented SFAS 143 which provides
accounting standards for retirement obligations associated with tangible
long-lived assets. This statement requires recognition of the fair value of a
liability for an asset retirement obligation in the period in which it is
incurred. See Notes 1(E) and 1(H) for further discussions of SFAS 143.
DIG Implementation Issue No. C20 for SFAS 133, "Scope Exceptions:
Interpretation of the Meaning of Not Clearly and Closely Related in
Paragraph 10(b) Regarding Contracts with a Price Adjustment Feature"
In June 2003, the FASB cleared DIG Issue C20 for implementation in
fiscal quarters beginning after July 10, 2003. The issue supersedes earlier DIG
Issue C11, "Interpretation of Clearly and Closely Related in Contracts That
Qualify for the Normal Purchases and Normal Sales Exception." DIG Issue C20
provides guidance regarding when the presence of a general index, such as the
Consumer Price Index, in a contract would prevent that contract from qualifying
for the normal purchases and normal sales exception under SFAS 133, as amended,
and therefore exempt from the mark-to-market treatment of certain contracts.
Adoption of DIG Issue C20 did not impact the Company's financial statements.
33
9. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
The following summarizes certain consolidated operating results by
quarter for 2003 and 2002.
March 31, June 30, Sept. 30, Dec. 31,
Three Months Ended 2003 2003 2003 2003 (a)
- -------------------------------------------------------------------------------------------------------
(In millions)
Operating Revenues.......................... $251.2 $217.7 $261.7 $240.4
Operating Expenses and Taxes................ 227.2 199.1 242.7 218.9
- -------------------------------------------------------------------------------------------------------
Operating Income............................ 24.0 18.6 19.0 21.5
Other Income................................ 5.2 5.3 5.4 6.8
Net Interest Charges........................ 12.4 11.0 10.7 10.7
- -------------------------------------------------------------------------------------------------------
Income Before Cumulative Effect of
Accounting Change........................ 16.8 12.9 13.7 17.6
Cumulative Effect of Accounting Change
(Net of Income Taxes).................... 0.2 -- -- --
- -------------------------------------------------------------------------------------------------------
Net Income.................................. $ 17.0 $ 12.9 $ 13.7 $ 17.6
=====================================================================================================--
March 31, June 30, Sept. 30, Dec. 31,
Three Months Ended 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
=====================================================================================================
(a)......Net income for the three months ended December 31, 2003, was increased
by $1.6 million due to adjustments that were subsequently capitalized to
construction projects in the fourth quarter. The adjustments included $0.4
million and $1.2 million of costs charged to expense in the second and
third quarters, respectively. Management concluded that the adjustments
were not material to the consolidated financial statements for any quarter
of 2003.
34
Report of Independent Auditors
To the Stockholders and Board of Directors of
Metropolitan Edison Company:
In our opinion, the accompanying consolidated balance sheets and consolidated
statements of capitalization and the related consolidated statements of income,
common stockholder's equity, preferred stock, cash flows and taxes present
fairly, in all material respects, the financial position of Metropolitan Edison
Company (a wholly owned subsidiary of FirstEnergy Corp.) and subsidiaries as of
December 31, 2003 and 2002 and the results of their operations and their cash
flows for the years then ended in conformity with accounting principles
generally accepted in the United States of America. These financial statements
are the responsibility of the Company's management; our responsibility is to
express an opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with auditing standards
generally accepted in the United States of America, which require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion. The
consolidated financial statements of Metropolitan Edison Company and
subsidiaries for the period from January 1, 2001 to November 6, 2001
(pre-merger) and the period from November 7, 2001 to December 31, 2001
(post-merger), were audited by other independent auditors who have ceased
operations. Those independent auditors expressed an unqualified opinion on those
financial statements in their report dated March 18, 2002.
As discussed in Note 1(E) to the consolidated financial statements, the Company
changed its method of accounting for asset retirement obligations as of January
1, 2003. As discussed in Note 8 to the consolidated financial statements, the
Company changed its method of accounting for the consolidation of variable
interest entities as of December 31, 2003.
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 25, 2004
35
The following report is a copy of a report previously issued by Arthur Andersen
LLP (Andersen). This report has not been reissued by Andersen and Andersen did
not consent to the incorporation by reference of this report into any of the
Company's registration statements.
Report of Previous Independent Public Accountants
To the Stockholders and Board of Directors of
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.
36