PENNSYLVANIA POWER COMPANY
2002 ANNUAL REPORT TO STOCKHOLDERS
Pennsylvania Power Company (Penn), an electric utility operating
company of FirstEnergy Corp. and a wholly owned subsidiary of Ohio Edison
Company, provides electric service to approximately 155,000 customers in western
Pennsylvania.
Contents Page
- -------- ----
Selected Financial Data......................................... 1
Management's Discussion and Analysis............................ 2-10
Statements of Income............................................ 11
Balance Sheets.................................................. 12
Statements of Capitalization.................................... 13
Statements of Common Stockholder's Equity....................... 14
Statements of Preferred Stock................................... 14
Statements of Cash Flows........................................ 15
Statements of Taxes............................................. 16
Notes to Financial Statements................................... 17-27
Reports of Independent Accountants.............................. 28-29
PENNSYLVANIA POWER COMPANY
SELECTED FINANCIAL DATA
2002 2001 2000 1999 1998
- ---------------------------------------------------------------------------------------------------------------------
(Dollars in thousands)
Operating Revenues...................... $506,407 $498,401 $383,112 $ 329,234 $323,756
======== ======== ======== ========== ========
Operating Income........................ $ 60,922 $ 55,178 $ 39,979 $ 32,063 $ 58,041
======== ======== ======== ========== ========
Income Before Extraordinary Item........ $ 47,717 $ 41,041 $ 22,847 $ 12,648 $ 39,748
======== ======== ======== ========== ========
Net Income.............................. $ 47,717 $ 41,041 $ 22,847 $ 12,648 $ 9,226
======== ======== ======== ========== ========
Earnings on Common Stock................ $ 44,018 $ 37,338 $ 19,143 $ 8,278 $ 4,600
======== ======== ======== ========== ========
Total Assets............................ $907,748 $960,097 $988,909 $1,015,616 $977,772
======== ======== ======== ========== ========
CAPITALIZATION AT DECEMBER 31:
Common Stockholder's Equity............. $229,374 $223,788 $213,851 $ 199,608 $275,281
Preferred Stock-
Not Subject to Mandatory Redemption.. 39,105 39,105 39,105 39,105 50,905
Subject to Mandatory Redemption...... 13,500 14,250 15,000 15,000 15,000
Long-Term Debt.......................... 185,499 262,047 270,368 274,821 287,689
-------- -------- -------- ---------- --------
Total Capitalization.................... $467,478 $539,190 $538,324 $ 528,534 $628,875
======== ======== ======== ========== ========
CAPITALIZATION RATIOS:
Common Stockholder's Equity............. 49.1% 41.5% 39.7% 37.8% 43.8%
Preferred Stock-
Not Subject to Mandatory Redemption.. 8.3 7.3 7.3 7.4 8.1
Subject to Mandatory Redemption...... 2.9 2.6 2.8 2.8 2.4
Long-Term Debt.......................... 39.7 48.6 50.2 52.0 45.7
----- ----- ----- ----- -----
Total Capitalization.................... 100.0% 100.0% 100.0% 100.0% 100.0%
===== ===== ===== ===== =====
DISTRIBUTION KILOWATT-HOUR DELIVERIES
(Millions):
Residential............................. 1,533 1,391 1,387 1,325 1,278
Commercial.............................. 1,268 1,220 1,198 1,105 1,069
Industrial.............................. 1,505 1,540 1,665 1,495 1,439
Other................................... 6 6 6 6 6
----- ------ ----- ----- -----
Total................................... 4,312 4,157 4,256 3,931 3,792
===== ===== ===== ===== =====
CUSTOMERS SERVED:
Residential............................. 136,410 134,956 121,066 117,440 124,304
Commercial.............................. 18,397 18,153 16,634 16,307 16,924
Industrial.............................. 220 224 177 175 206
Other................................... 85 87 87 87 86
------- ------- ------- ------- -------
Total................................... 155,112 153,420 137,964 134,009 141,520
======= ======= ======= ======= =======
NUMBER OF EMPLOYEES..................... 201 256 275 895 888
1
PENNSYLVANIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
This discussion includes forward-looking statements based on
information currently available to management that is subject to certain risks
and uncertainties. Such statements typically contain, but are not limited to,
the terms anticipate, potential, expect, believe, estimate and similar words.
Actual results may differ materially due to the speed and nature of increased
competition and deregulation in the electric utility industry, economic or
weather conditions affecting future sales and margins, changes in markets for
energy services, changing energy and commodity market prices, legislative and
regulatory changes (including revised environmental requirements), and the
availability and cost of capital.
Corporate Separation
- --------------------
In connection with FirstEnergy's Ohio transition plan, FirstEnergy
separated its businesses into three distinct units - a competitive services
segment, a regulated services segment and a corporate support services segment.
Pennsylvania Power Company (Penn) is included in the regulated services segment
which continues to deliver power to homes and businesses through its existing
distribution system and maintains the "provider of last resort" (PLR) obligation
under its rate plan.
Beginning on January 1, 2001, FirstEnergy's electric utility operating
companies (EUOC) entered into power supply agreements whereby FirstEnergy
Solutions Corp. (FES) purchases all of the EUOC nuclear generation, as well as
generation from leased fossil generation facilities. FirstEnergy Generation
Corp. (FGCO), a wholly owned subsidiary of FES, leases fossil generating units
owned by the EUOC. We are a "full requirements" customer of FES to enable us to
meet our PLR responsibilities in our service area.
The effect on Penn's reported results of operations in 2001 from
FirstEnergy's corporate separation plan and our sale of transmission assets to
American Transmission Systems, Inc. (ATSI) in September 2000, are summarized in
the following table:
Corporate Restructuring - 2001 Income Statement Effects
-------------------------------------------------------
Increase (Decrease)
Corporate
Separation ATSI Total
---------- ---- -----
(In millions)
Operating Revenues:
Power supply agreement with FES........ $151.5 $ -- $151.5
Generating units rent.................. 20.2 -- 20.2
Ground lease with ATSI................. -- 0.6 0.6
--------------------------------------------------------------------------------------
Total Operating Revenues Effect........ $171.7 $ 0.6 $172.3
======================================================================================
Operating Expenses and Taxes:
Fossil fuel costs...................... $(32.6)(a) $ -- $(32.6)
Purchased power costs.................. 152.7(b) -- 152.7
Other operating costs.................. (21.1)(a) 4.9 (d) (16.2)
Provision for depreciation and
amortization ........................ -- (2.2)(e) (2.2)
General taxes.......................... (2.4)(c) (0.3)(e) (2.7)
Income Taxes........................... 31.1 -- 31.1
--------------------------------------------------------------------------------------
Total Operating Expenses Effect........ $127.7 $ 2.4 $130.1
======================================================================================
Other Income............................. $ -- $ 1.7 (f) $ 1.7
======================================================================================
<FN>
(a) Transfer of fossil operations to FGCO.
(b) Purchased power from power supply agreement (PSA).
(c) Payroll taxes related to employees transferred to FGCO.
(d) Transmission services received from ATSI.
(e) Depreciation and property taxes related to transmission assets sold to ATSI.
(f) Interest on note receivable from ATSI.
</FN>
Results of Operations
- ---------------------
Earnings on common stock in 2002 increased 17.9% to $44.0 million from
$37.3 million in 2001. The earnings increase in 2002 primarily resulted from
increased operating revenues and lower financing costs, which were partially
offset by higher operating expenses and taxes and reduced other income.
Excluding the effects shown in the table
2
above, earnings on common stock decreased to $6.6 million in 2001 from 2000,
being adversely affected by reduced operating revenues, which were partially
offset by lower operating expenses, taxes and net interest charges.
Operating revenues increased by $8.0 million or 1.6% in 2002 as
compared to 2001. The return of customers previously served by alternative
generation suppliers contributed to the revenue increase. Retail kilowatt-hour
sales increased by 7.8% in 2002 from the prior year, with increases in the
residential and commercial sectors contributing to a $15.8 million increase in
generation sales revenue. Sales of electric generation by alternative suppliers
as a percent of total sales delivered in our franchise area decreased to 0.4% in
2002 from 4.1% in 2001. Distribution deliveries increased 3.7% in 2002 as
compared to 2001, which increased revenues from electricity throughput by $3.9
million in 2002 from the prior year. The higher distribution deliveries resulted
from additional residential and commercial demand due to warmer summer weather
that was offset in part by the effect of continued sluggishness in the economy
on demand by industrial customers. Sales revenues from wholesale customers
decreased by $14.3 million in 2002 compared to 2001, due to a decline in market
prices.
Excluding the effects shown in the table above, operating revenues
decreased by $57.0 million or 14.9% in 2001 from 2000. The decrease primarily
resulted from a $56.7 million reduction in wholesale revenues (a 93.3% decrease
in wholesale kilowatt-hour sales) from the prior year due to the substitution of
PSA sales for kilowatt-hour sales to other wholesale customers. Distribution
deliveries declined 2.3% in 2001 from 2000 reflecting the influence of a
declining national economy on our regional business activity that contributed to
lower distribution deliveries to commercial and industrial customers. Partially
offsetting the impact of a weaker economy was an increase in retail electric
generation revenues reflecting a return of customers previously served by
alternative generation suppliers. Retail generation sales increased in all
customer categories resulting in an overall 4.8% increase in kilowatt-hour sales
in 2001 from the prior year. Electric generation services provided by other
suppliers in our service area decreased to 4.1% in 2001 from 10.6% in 2000.
Changes in KWH Sales 2002 2001
-------------------------------------------------------------------
Increase (Decrease)
Electric Generation:
Retail................................ 7.8% 4.8%
Wholesale............................. 12.0% (93.3)%
-------------------------------------------------------------------
Total Electric Generation Sales......... 10.3% (62.6)%
===================================================================
Distribution Deliveries:
Residential........................... 10.2% 0.3%
Commercial and industrial............. 0.5% (3.6)%
-------------------------------------------------------------------
Total Distribution Deliveries........... 3.7% (2.3)%
===================================================================
Operating Expenses and Taxes
Total operating expenses and taxes increased by $2.3 million in 2002
and by $100.1 million in 2001 from the prior year. Excluding the effects of
restructuring, total 2001 operating expenses and taxes were $30.0 million lower
than 2000. The following table presents changes from the prior year by expense
category excluding the impact of restructuring.
Operating Expenses and Taxes - Changes 2002 2001
-------------------------------------------------------------------
Increase (Decrease) (In millions)
Fuel and purchased power...................... $ 6.7 $(12.9)
Nuclear operating costs....................... (24.6) 1.9
Other operating costs......................... 5.4 1.9
--------------------------------------------------------------------
Total operation and maintenance expenses.... (12.5) (9.1)
Provision for depreciation and amortization... (0.3) 3.3
General taxes................................. 10.3 (5.2)
Income taxes.................................. 4.8 (19.0)
---------------------------------------------------------------------
Total operating expenses and taxes.......... $ 2.3 $(30.0)
=====================================================================
Higher fuel and purchased power costs in 2002 compared with 2001,
resulted from a $4.2 million increase in power purchased from FES, reflecting
higher kilowatt-hours purchased due to increased kilowatt-hour sales and lower
unit prices. Nuclear operating costs decreased $24.6 million, primarily due to
one less refueling outage in 2002 compared to 2001. The $5.4 million increase in
other operating costs resulted principally from higher employee benefit costs.
3
The decrease in fuel and purchased power costs in 2001 compared to
2000, primarily reflects the transfer of fossil operations to FGCO with our
power requirements being provided under the PSA. Nuclear operating costs
increased slightly in 2001 from the previous year.
In 2001, depreciation and amortization increased $3.3 million compared
with 2000 primarily from the absence in 2001 of an adjustment in 2000 related to
decommissioning costs.
General taxes increased by $10.3 million in 2002 from 2001 as a result
of additional property taxes and gross receipt taxes. In 2001, general taxes
decreased by $5.2 million in 2001 from 2000 primarily due to a one-time benefit
of $3 million resulting from successfully resolving certain pending tax issues
and the effect of a reduction to the gross receipts tax rate.
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $2.2
million in 2002 and by $2.1 million in 2001, compared to the prior year. We
continue to redeem and refinance outstanding debt during 2002 - net redemptions
and refinancing activities totaled $1.7 million and $14.5 million, respectively,
and will result in annualized savings of $523,000.
Capital Resources and Liquidity
- -------------------------------
Through net debt and preferred stock redemptions, we continue to
reduce the cost of debt and preferred stock, and improve our financial position
in 2002. During 2002, we reduced our total debt by approximately $40.1 million.
At the end of 2002, our common equity as a percentage of capitalization stood at
49% compared to 42% at the end of 2001. The higher common equity percentage in
2002 compared to 2001 resulted from net redemptions of preferred stock and
long-term debt and the increase in retained earnings.
Changes in Cash Position
As of December 31, 2002, we had $1.2 million of cash and cash
equivalents, compared with $0.1 million as of December 31, 2001. The major
sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Our net cash from operating activities is provided by our regulated
energy services. Net cash provided from operating activities was $105.8 million
in 2002 and $93.3 million in 2001. Cash provided from 2002 and 2001 operating
activities are as follows:
Operating Cash Flows 2002 2001
-------------------------------------------------------------
(In millions)
Cash earnings (1).................. $115.8 $101.6
Working capital and other.......... (10.0) (8.3)
-------------------------------------------------------------
Total.............................. $105.8 $93.3
=============================================================
(1) Includes net income, depreciation and amortization, deferred income taxes,
investment tax credits and major noncash charges.
Cash Flows From Financing Activities
In 2002, the net cash used for financing activities of $75.3 million
primarily reflects the redemptions of debt and preferred stock shown below. The
following table provides details regarding new issues and redemptions during
2002:
Securities Issued or Redeemed in 2002
--------------------------------------------------------------
(In millions)
New Issues
----------
Pollution Control Notes..................... $ 14.5
Redemptions
-----------
First Mortgage Bonds........................ 1.0
Pollution Control Notes..................... 14.5
Capital Fuel Leases......................... 40.7
Preferred Stock............................. 0.8
Other, principally redemption premiums...... 0.6
-----------------------------------------------------------
$ 57.6
4
In 2001, net cash flow used for financing activities totaled $50.8
million, primarily due to $51 million of long-term debt redemptions and $31
million of dividend payments.
We had about $36.5 million of cash and temporary investments and no
short-term indebtedness as of December 31, 2002. At the end of 2002, we had the
capability to issue $323 million of additional first mortgage bonds on the basis
of property additions and retired bonds. Based upon applicable earnings in 2002
under the earnings coverage test contained in our charter, we could issue $251
million of preferred stock (assuming no additional debt was issued).
Cash Flows From Investing Activities
Net cash used in investing activities totaled $29.3 million in 2002.
The net cash used for investing resulted from loan payments from OE, which were
offset in part by an increase in property additions. Expenditures for property
additions primarily include expenditures supporting our distribution of
electricity.
In 2001, net cash used in investing activities totaled $45.9 million,
principally due to property additions and loans to associated companies, which
were offset in part by sales of assets to associated companies.
Our cash requirements in 2003 for operating expenses, construction
expenditures, scheduled debt maturities and preferred stock redemptions are
expected to be met without increasing our net debt and preferred stock
outstanding. Major contractual obligations for future cash payments are
summarized in the following table:
Less than 1-3 3-5 More than
Contractual Obligations Total 1 Year Years Years 5 Years
- ---------------------------------------------------------------------------------------------------------------
(in millions)
Long-term debt.................. $251 $41 $36 $ 2 $172
Preferred stock (1)............. 14 1 2 11 --
Purchases (2)................... 89 21 17 29 22
- -------------------------------------------------------------------------------------------------------------
Total........................ $354 $63 $55 $42 $194
=============================================================================================================
<FN>
(1) Subject to mandatory redemption.
(2) Fuel and power purchases under contracts with fixed or minimum quantities and approximate timing.
</FN>
Our capital spending for the period 2003-2007 is expected to be about
$123 million (excluding nuclear fuel) of which approximately $53 million applies
to 2003. Investments for additional nuclear fuel during the 2003-2007 period are
estimated to be approximately $42 million, of which about $19 million relates to
2003. During the same periods, our nuclear fuel investments are expected to be
reduced by approximately $34 million and $17 million, respectively, as the
nuclear fuel is consumed. We had no other material obligations as of December
31, 2002 that have not been recognized on our Balance Sheet.
On February 22, 2002, Moody's Investor Service changed its credit
rating outlook for FirstEnergy from stable to negative. The change was based
upon a decision by the Commonwealth Court of Pennsylvania to remand to the
Pennsylvania Public Utility Commission (PPUC) for reconsideration its decision
on the mechanism for sharing merger savings and reversed the PPUC's decisions
regarding rate relief and accounting deferrals rendered in connection with its
approval of the GPU merger. On April 4, 2002, Standard & Poor's (S&P) changed
its outlook for FirstEnergy's credit ratings from stable to negative citing
recent developments including: damage to the Davis-Besse reactor vessel head
(the Company has no ownership interest in Davis-Besse), the Pennsylvania
Commonwealth Court decision, and deteriorating market conditions for some sales
of its remaining non-core assets. On July 31, 2002, Fitch revised its rating
outlook for FirstEnergy, negative from stable. The revised outlook reflected the
adverse impact of the unplanned Davis-Besse outage, Fitch's judgment about NRG's
financial ability to consummate the purchase of four power plants (none owned by
the Company) from FirstEnergy and Fitch's expectation of subsequent delays in
debt reduction. On August 1, 2002, S&P concluded that while NRG's liquidity
position added uncertainty to FirstEnergy's sale of power plants to NRG, its
ratings would not be affected. S&P found FirstEnergy's cash flows sufficiently
stable to support a continued (although delayed) program of debt and preferred
stock redemption. S&P noted that they would continue to closely monitor
FirstEnergy's progress on various initiatives. On January 21, 2003, S&P
indicated its concern about FirstEnergy's disclosure of noncash charges related
to deferred costs in Pennsylvania, pension and other post-retirement benefits,
and Emdersa (FirstEnergy's Argentina operations), which were higher than
anticipated in the third quarter of 2002. S&P identified the restart of the
Davis-Besse nuclear plant "...without significant delay beyond April 2003..." as
key to maintaining its current debt ratings. S&P also identified other issues it
would continue to monitor including: its deleveraging efforts, free cash
generated during 2003, the Jersey Central Power & Light Company rate case,
successful hedging of its short power position, and continued capture of
projected merger savings. While FirstEnergy anticipates being prepared to
restart the Davis-Besse plant in the spring of 2003, the Nuclear Regulatory
Commission (NRC) must authorize the unit's restart following a formal inspection
process prior to its returning the unit to service. Significant delays in the
planned date of Davis-Besse's return to service or other factors (identified
above) affecting the speed with which FirstEnergy reduces debt could put
additional pressure on Penn's credit ratings.
5
Interest Rate Risk
- ------------------
Our exposure to fluctuations in market interest rates is reduced since
a significant portion of our debt has fixed interest rates, as noted in the
following table. We are subject to the inherent risks related to refinancing
maturing debt by issuing new debt securities. Changes in the market value of our
nuclear decommissioning trust funds had been recognized by making corresponding
changes to the decommissioning liability, as described in Note 1 - Utility Plant
and Depreciation. In conjunction with the adoption of SFAS 143, "Accounting for
Asset Retirement Obligations," on January 1, 2003, we reclassified unrealized
gains and losses to other comprehensive income (OCI) in accordance with SFAS
115, "Accounting for Certain Investments in Debt and Equity." While fluctuations
in the fair value of our Ohio EUOCs' trust balances will eventually affect
earnings (affecting OCI initially) based on the guidance provided by SFAS 115,
our non-Ohio EUOC have the opportunity to recover from customers the difference
between the investments held in trust and their decommissioning obligations.
Thus, in absence of disallowed costs, there should be no earnings effect from
fluctuations in their decommissioning trust balances. As of December 31, 2002,
decommissioning trust balances totaled $1.050 billion, with $698 million held by
our Ohio EUOC and the balance held by our non-Ohio EUOC. As of year end 2002,
trust balances included 51% of equity and 49% of debt instruments.
The table below presents principal amounts and related weighted
average interest rates by year of maturity for our investment portfolio, debt
obligations and preferred stock with mandatory redemption provisions.
Comparison of Carrying Value to Fair Value
- -------------------------------------------------------------------------------------------------------------------
There- Fair
2003 2004 2005 2006 2007 after Total Value
- --------------------------------------------------------------------------------------------------------------------
(Dollars in millions)
Assets
- --------------------------------------------------------------------------------------------------------------------
Investments other than Cash
and Cash Equivalents:
Fixed Income................. $ 6 $ 1 $ 1 $115 $123 $127
Average interest rate..... 7.8% 7.8% 7.8% 5.5% 5.7%
- --------------------------------------------------------------------------------------------------------------------
Liabilities
- --------------------------------------------------------------------------------------------------------------------
Long-term Debt:
Fixed rate................... $41 $ 35 $ 1 $ 1 $ 1 $110 $189 $198
Average interest rate .... 7.6% 6.6% 9.7% 9.7% 9.7% 7.0% 7.1%
Variable rate................ $ 62 $ 62 $ 62
Average interest rate..... 2.4% 2.4%
Preferred Stock.............. $ 1 $ 1 $ 1 $ 1 $10 $ 14 $ 14
Average dividend rate .... 7.6% 7.6% 7.6% 7.6% 7.6% 7.6%
- -------------------------------------------------------------------------------------------------------------------
Equity Price Risk
- -----------------
Included in our nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $38
million and $47 million as of December 31, 2002 and 2001, respectively. A
hypothetical 10% decrease in prices quoted by stock exchanges would result in a
$4 million reduction in fair value as of December 31, 2002 (see Note 1 -
Supplemental Cash Flows Information).
Outlook
- -------
In 2002, a number of our customers previously electing to be served by
alternative energy providers returned to our system for their energy needs. 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. Adopting new approaches to regulation and experiencing new forms of
competition have created new uncertainties. We continue to deliver power to
homes and businesses through our existing distribution system, which remains
regulated.
As part of our transition plan we are obligated to supply electricity
to customers who do not choose an alternative supplier. Our competitive retail
sales affiliate, FES, acts as an alternate supplier for a portion of the load in
our franchise area. In 2003, the total peak load forecasted for customers
electing to stay with us, including the load served by our affiliate is 955
megawatts (MW).
6
Environmental Matters
We believe we are in compliance with the current sulfur dioxide (SO2)
and nitrogen oxide (NOx) reduction requirements under the Clean Air Act
Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized
regulations requiring additional NOx reductions in the future from our Ohio and
Pennsylvania facilities. Various regulatory and judicial actions have since
sought to further define NOx reduction requirements (see Note 5 - Environmental
Matters). We continue to evaluate our compliance plans and other compliance
options.
Violations of federally approved SO2 regulations can result in
shutdown of the generating unit involved and/or civil or criminal penalties of
up to $31,500 for each day a unit is in violation. The EPA has an interim
enforcement policy for SO2 regulations in Ohio that allows for compliance based
on a 30-day averaging period. We cannot predict what action the EPA may take in
the future with respect to the interim enforcement policy.
In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a
Compliance Order to nine utilities covering 44 power plants, including the W.H.
Sammis Plant. In addition, the U.S. Department of Justice filed eight civil
complaints against various investor-owned utilities, which included a complaint
against OE and Penn in the U.S. District Court for the Southern District of
Ohio, for which hearings began on February 3, 2003. The NOV and complaint allege
violations of the Clean Air Act (CAA). The civil complaint against OE and Penn
requests installation of "best available control technology" as well as civil
penalties of up to $27,500 per day. Although unable to predict the outcome of
these proceedings, we believe the Sammis Plant is in full compliance with the
CAA and that the NOV and complaint are without merit. Penalties could be imposed
if the Sammis Plant continues to operate without correcting the alleged
violations and a court determines that the allegations are valid. The Sammis
Plant continues to operate while these proceedings are pending.
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants. The EPA identified mercury as the hazardous air pollutant of
greatest concern. The EPA established a schedule to propose regulations by
December 2003 and issue final regulations by December 2004. The future cost of
compliance with these regulations may be substantial.
As a result of the Resource Conservation and Recovery Act of 1976, as
amended, and the Toxic Substances Control Act of 1976, federal and state
hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous waste
disposal requirements pending the EPA's evaluation of the need for future
regulation. The EPA has issued its final regulatory determination that
regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the
EPA announced that it will develop national standards regulating disposal of
coal ash under its authority to regulate nonhazardous waste.
The effects of compliance on the Company with regard to environmental
matters could have a material adverse effect on our earnings and competitive
position. These environmental regulations affect our earnings and competitive
position to the extent we compete with companies that are not subject to such
regulations and therefore do not bear the risk of costs associated with
compliance, or failure to comply, with such regulations. We believe we are in
material compliance with existing regulations, but are unable to predict how and
when applicable environmental regulations may change and what, if any, the
effects of any such change would be.
Significant Accounting Policies
- -------------------------------
We prepare our 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 our 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 those
specific factors. Our more significant accounting policies are described below.
Regulatory Accounting
We are subject to regulation that sets the prices (rates) we are
permitted to charge our customers based on our 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 -- $157 million as of December
31, 2002. We continually review these assets to assess their ultimate
recoverability within the approved regulatory guidelines. Impairment risk
associated with these assets relates to potentially adverse legislative,
judicial or regulatory actions in the future.
7
Revenue Recognition
We follow the accrual method of accounting for revenues, recognizing
revenue for kilowatt-hours that have been delivered but not yet been billed
through the end of the year. 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
Our reported costs of providing non-contributory defined pension
benefits and postemployment benefits other than pensions (OPEB) are dependent
upon numerous factors resulting from actual plan experience and certain
assumptions.
Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions we make to the plans, and earnings on plan assets. Pension and
OPEB costs may also be affected by changes to key assumptions, including
anticipated rates of return on plan assets, the discount rates and health care
trend rates used in determining the projected benefit obligations and pension
and OPEB costs.
In accordance with SFAS 87, "Employers' Accounting for Pensions" and
SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions," changes in pension and OPEB obligations associated with these factors
may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
In selecting an assumed discount rate, we consider currently available
rates of return on high-quality fixed income investments expected to be
available during the period to maturity of the pension and other postretirement
benefit obligations. Due to the significant decline in corporate bond yields and
interest rates in general during 2002, we reduced the assumed discount rate as
of December 31, 2002 to 6.75% from 7.25% used in 2001 and 7.75% used in 2000.
Our assumed rate of return on pension plan assets considers historical
market returns and economic forecasts for the types of investments held by our
pension trusts. The market values of our pension assets have been affected by
sharp declines in the equity markets since mid-2000. In 2002, 2001 and 2000,
plan assets have earned (11.3)%, (5.5)% and (0.3)%, respectively. Our pension
costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As
of December 31, 2002 the assumed return on plan assets was reduced to 9.00%
based upon our projection of future returns and pension trust investment
allocation of approximately 60% large cap equities, 10% small cap equities and
30% bonds.
Based on pension assumptions and pension plan assets as of December
31, 2002, we will not be required to fund our pension plans in 2003. While OPEB
plan assets have also been affected by sharp declines in the equity market, the
impact is not as significant due to the relative size of the plan assets.
However, health care cost trends have significantly increased and will affect
future OPEB costs. The 2003 composite health care trend rate assumption is
approximately 10%-12% gradually decreasing to 5% in later years, compared to our
2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in
later years. In determining our trend rate assumptions, we included the specific
provisions of our health care plans, the demographics and utilization rates of
plan participants, actual cost increases experienced in our health care plans,
and projections of future medical trend rates.
8
The effect on our SFAS 87 and 106 costs and liabilities from changes
in key assumptions are as follows:
Increase in Costs from Adverse Changes in Key Assumptions
- -------------------------------------------------------------------------------
Assumption Adverse Change Pension OPEB Total
- -------------------------------------------------------------------------------
(In millions)
Discount rate Decrease by 0.25% $0.1 $0.1 $0.2
Long-term return on assets Decrease by 0.25% 0.1 -- 0.1
Health care trend rate Increase by 1% na 0.2 0.2
Increase in Minimum Pension Liability
- -------------------------------------
Discount rate Decrease by 0.25% 2.0 na 2.0
- -------------------------------------------------------------------------------
As a result of the reduced market value of our pension plan assets, we
were required to recognize an additional minimum liability as prescribed by SFAS
87 and SFAS 132, "Employers' Disclosures about Pension and Postretirement
Benefits," as of December 31, 2002. We eliminated our prepaid pension asset of
$8.8 million and established a minimum liability of $11.7 million, recording an
intangible asset of $3.6 million and reducing OCI by $9.9 million (recording a
related deferred tax benefit of $7.0 million). The charge to OCI will reverse in
future periods to the extent the fair value of trust assets exceed the
accumulated benefit obligation. The amount of pension liability recorded as of
December 31, 2002 increased due to the lower discount rate assumed and reduced
market value of plan assets as of December 31, 2002. Our non-cash, pre-tax
pension and OPEB expense under SFAS 87 and SFAS 106 is expected to increase by
$1.1 million and $0.4 million, respectively - a total of $1.5 million in 2003 as
compared to 2002.
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 may not be fully recoverable. The accounting standard requires
that if the sum of future cash flows (undiscounted) expected to result from an
asset, is less than the carrying value of the asset, an asset impairment must be
recognized in the financial statements. If impairment, other than of a temporary
nature, has occurred, 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).
Recently Issued Accounting Standards Not Yet Implemented
- --------------------------------------------------------
SFAS 143, "Accounting for Asset Retirement Obligations"
In June 2001, the FASB issued SFAS 143. The new statement provides
accounting standards for retirement obligations associated with tangible
long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires
that the fair value of a liability for an asset retirement obligation be
recorded in the period in which it is incurred. The associated asset retirement
costs are capitalized as part of the carrying amount of the long-lived asset.
Over time the capitalized costs are depreciated and the present value of the
asset retirement liability increases, resulting in a period expense. However,
rate-regulated entities may recognize regulatory assets or liabilities if the
criteria for such treatment are met. Upon retirement, a gain or loss would be
recorded if the cost to settle the retirement obligation differs from the
carrying amount.
We have identified applicable legal obligations as defined under the
new standard, principally for nuclear power plant decommissioning. Upon adoption
of SFAS 143 in January 2003, asset retirement costs of $78 million were recorded
as part of the carrying amount of the related long-lived asset, offset by
accumulated depreciation of $9 million. Due to the increased carrying amount,
the related long-lived assets were tested for impairment in accordance with SFAS
144. No impairment was indicated. The asset retirement liability at the date of
adoption was $121 million. As of December 31, 2002, Penn had recorded
decommissioning liabilities of $120 million. The change in the estimated
liabilities resulted from changes in methodology and various assumptions,
including changes in the projected dates for decommissioning.
Management expects that substantially all nuclear decommissioning
costs for Penn will be recoverable through its regulated rates. Therefore, we
recognized a regulatory liability of $69 million upon adoption of SFAS 143 for
the transition amounts related to establishing the asset retirement obligations
for nuclear decommissioning. The remaining cumulative effect adjustment to
recognize the undepreciated asset retirement cost and the asset retirement
liability offset by the reversal of the previously recorded decommissioning
liabilities for Penn was a $1.1 million decrease to income ($0.6 million net of
tax).
9
SFAS 146, "Accounting for Costs Associated with Exit or Disposal
Activities"
This statement, which was issued by the FASB in July 2002, requires
the recognition of costs associated with exit or disposal activities at the time
they are incurred rather than when management commits to a plan of exit or
disposal. It also requires the use of fair value for the measurement of such
liabilities. The new standard supersedes guidance provided by EITF Issue No.
94-3, "Liability Recognition for Certain Employee Termination Benefits and Other
Costs to Exit an Activity (including Certain Costs Incurred in a
Restructuring)." This new standard was effective for exit and disposal
activities initiated after December 31, 2002. Since it is applied prospectively,
there will be no impact upon adoption. However, SFAS 146 could change the timing
and amount of costs recognized in connection with future exit or disposal
activities.
FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness
of Others - an interpretation of FASB Statements No. 5, 57, and 107 and
rescission of FASB Interpretation No. 34"
The FASB issued FIN 45 in January 2003. This interpretation identifies
minimum guarantee disclosures required for annual periods ending after December
15, 2002. It also clarifies that providers of guarantees must record the fair
value of those guarantees at their inception. This accounting guidance is
applicable on a prospective basis to guarantees issued or modified after
December 31, 2002. We do not believe that implementation of FIN 45 will be
material but we will continue to evaluate anticipated guarantees.
10
PENNSYLVANIA POWER COMPANY
STATEMENTS OF INCOME
For the Years Ended December 31, 2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
(In thousands)
OPERATING REVENUES (Note 1)............................................... $506,407 $498,401 $383,112
-------- -------- --------
OPERATING EXPENSES AND TAXES:
Fuel and purchased power (Note 1)...................................... 181,968 175,257 68,099
Nuclear operating costs (Note 1)....................................... 90,024 114,623 112,731
Other operating costs (Note 1)......................................... 50,523 45,133 59,389
-------- -------- --------
Total operation and maintenance expenses............................. 322,515 335,013 240,219
Provision for depreciation and amortization............................ 56,763 57,087 55,964
General taxes.......................................................... 24,474 14,214 22,076
Income taxes........................................................... 41,733 36,909 24,874
-------- -------- --------
Total operating expenses and taxes................................... 445,485 443,223 343,133
-------- -------- --------
OPERATING INCOME.......................................................... 60,922 55,178 39,979
OTHER INCOME (Note 1)..................................................... 1,960 3,185 2,300
-------- -------- --------
INCOME BEFORE NET INTEREST CHARGES........................................ 62,882 58,363 42,279
-------- -------- --------
NET INTEREST CHARGES:
Interest on long-term debt............................................. 15,521 16,971 18,651
Interest on nuclear fuel obligations................................... 8 141 364
Allowance for borrowed funds used during construction.................. (1,509) (850) (1,005)
Other interest expense................................................. 1,145 1,060 1,422
-------- -------- --------
Net interest charges................................................. 15,165 17,322 19,432
-------- -------- --------
NET INCOME................................................................ 47,717 41,041 22,847
PREFERRED STOCK DIVIDEND REQUIREMENTS..................................... 3,699 3,703 3,704
-------- -------- --------
EARNINGS ON COMMON STOCK.................................................. $ 44,018 $ 37,338 $ 19,143
======== ======== ========
<FN>
The accompanying Notes to Financial Statements are an integral part of these statements.
</FN>
11
PENNSYLVANIA POWER COMPANY
BALANCE SHEETS
As of December 31, 2002 2001
- ------------------------------------------------------------------------------------------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service........................................................................ $680,729 $664,432
Less-Accumulated provision for depreciation....................................... 316,424 290,216
-------- --------
364,305 374,216
-------- --------
Construction work in progress-
Electric plant................................................................. 44,696 24,141
Nuclear fuel................................................................... 8,812 2,921
-------- --------
53,508 27,062
-------- --------
417,813 401,278
-------- --------
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts (Note 1)..................................... 119,401 116,634
Long-term notes receivable from associated companies.............................. 38,921 39,290
Other (Note 1H)................................................................... 2,569 21,597
-------- --------
160,891 177,521
-------- --------
CURRENT ASSETS:
Cash and cash equivalents......................................................... 1,222 67
Notes receivable from associated companies........................................ 35,317 54,411
Receivables-
Customers (less accumulated provisions of $702,000 and $619,000,
respectively, for uncollectible accounts).................................... 44,341 40,890
Associated companies........................................................... 42,652 36,491
Other.......................................................................... 5,262 4,787
Materials and supplies, at average cost........................................... 30,309 25,598
Prepayments....................................................................... 5,346 5,682
-------- --------
164,449 167,926
-------- --------
DEFERRED CHARGES:
Regulatory assets................................................................. 156,903 208,838
Other............................................................................. 7,692 4,534
-------- --------
164,595 213,372
-------- --------
$907,748 $960,097
======== ========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Statements of Capitalization):
Common stockholder's equity....................................................... $229,374 $223,788
Preferred stock-
Not subject to mandatory redemption............................................ 39,105 39,105
Subject to mandatory redemption................................................ 13,500 14,250
Long-term debt-
Associated companies........................................................... -- 21,064
Other.......................................................................... 185,499 240,983
-------- --------
467,478 539,190
-------- --------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock-
Associated companies........................................................... -- 18,090
Other.......................................................................... 66,556 12,075
Accounts payable-
Associated companies........................................................... 52,653 50,604
Other.......................................................................... 5,730 1,441
Accrued taxes..................................................................... 12,507 18,853
Accrued interest.................................................................. 5,558 5,264
Other............................................................................. 10,479 9,675
-------- --------
153,483 116,002
-------- --------
DEFERRED CREDITS:
Accumulated deferred income taxes................................................. 117,385 136,808
Accumulated deferred investment tax credits....................................... 3,810 4,108
Nuclear plant decommissioning costs............................................... 119,863 117,096
Other............................................................................. 45,729 46,893
-------- --------
286,787 304,905
-------- --------
COMMITMENTS AND CONTINGENCIES (Notes 2 and 5).....................................
-------- --------
$907,748 $960,097
======== ========
<FN>
The accompanying Notes to Financial Statements are an integral part of these balance sheets.
</FN>
12
PENNSYLVANIA POWER COMPANY
STATEMENTS OF CAPITALIZATION
As of December 31, 2002 2001
- ------------------------------------------------------------------------------------------------------------------
(Dollars in thousands, except per share amounts)
COMMON STOCKHOLDER'S EQUITY:
Common stock, $30 par value, 6,500,000 shares authorized, 6,290,000 shares outstanding $188,700 $188,700
Other paid-in capital................................................................ (310) (310)
Accumulated other comprehensive loss (Note 3F)....................................... (9,932) --
Retained earnings (Note 3A).......................................................... 50,916 35,398
-------- --------
Total common stockholder's equity.................................................. 229,374 223,788
-------- --------
Number of Shares Optional
Outstanding Redemption Price
---------------- -------------------
2002 2001 Per Share Aggregate
---- ---- --------- ---------
PREFERRED STOCK (Note 3C):
Cumulative, $100 par value-
Authorized 1,200,000 shares
Not Subject to Mandatory Redemption:
4.24%................................ 40,000 40,000 $103.13 $ 4,125 4,000 4,000
4.25%................................ 41,049 41,049 105.00 4,310 4,105 4,105
4.64%................................ 60,000 60,000 102.98 6,179 6,000 6,000
7.75%................................ 250,000 250,000 -- -- 25,000 25,000
------- ------- ------- ------- --------
Total not subject to mandatory
redemption....................... 391,049 391,049 $14,614 39,105 39,105
======= ======= ======= ------- --------
Subject to Mandatory Redemption (Note 3D):
7.625%............................... 142,500 150,000 103.81 $14,793 14,250 15,000
Redemption Within One Year............. (750) (750)
------- ------- ------- ------- --------
Total subject to mandatory
redemption 142,500 150,000 $14,793 13,500 14,250
======= ======= ======= ------- --------
LONG-TERM DEBT (Note 3E):
First mortgage bonds-
9.740% due 2003-2019............................................................... 16,591 17,565
7.500% due 2003.................................................................... 40,000 40,000
6.375% due 2004.................................................................... 20,500 20,500
6.625% due 2004.................................................................... 14,000 14,000
8.500% due 2022.................................................................... 27,250 27,250
7.625% due 2023.................................................................... 6,500 6,500
-------- --------
Total first mortgage bonds....................................................... 124,841 125,815
-------- --------
Secured notes-
5.400% due 2013.................................................................... 1,000 1,000
5.400% due 2017.................................................................... 10,600 10,600
*1.350% due 2017.................................................................... 17,925 17,925
5.900% due 2018.................................................................... 16,800 16,800
*1.350% due 2021.................................................................... 14,482 14,482
6.150% due 2023.................................................................... 12,700 12,700
*1.600% due 2027.................................................................... 10,300 10,300
6.450% due 2027.................................................................... -- 14,500
5.375% due 2028.................................................................... 1,734 1,734
5.450% due 2028.................................................................... 6,950 6,950
6.000% due 2028.................................................................... 14,250 14,250
5.950% due 2029.................................................................... 238 238
-------- ---------
Total secured notes.............................................................. 106,979 121,479
-------- --------
Unsecured notes-
*5.900% due 2033.................................................................... 5,200 5,200
*3.850% due 2029.................................................................... 14,500 --
-------- --------
Total unsecured notes............................................................ 19,700 5,200
-------- --------
Other obligations-
Nuclear fuel....................................................................... -- 39,154
Capital leases (Note 2)............................................................ 32 95
-------- --------
Total other obligations.......................................................... 32 39,249
-------- --------
Net unamortized discount on debt..................................................... (247) (281)
-------- --------
Long-term debt due within one year................................................... (65,806) (29,415)
-------- --------
Total long-term debt............................................................. 185,499 262,047
-------- --------
TOTAL CAPITALIZATION.................................................................... $467,478 $539,190
======== ========
<FN>
* Denotes variable rate issue with December 31, 2002 interest rate shown.
The accompanying Notes to Financial Statements are an integral part of these statements.
</FN>
13
PENNSYLVANIA POWER COMPANY
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
Accumulated
Other Other
Comprehensive Number Par Paid-In Comprehensive Retained
Income of Shares Value Capital Income (Loss) Earnings
------------- --------- ------- ------- ------------- --------
(Dollars in thousands)
Balance, January 1, 2000............. 6,290,000 $188,700 $(310) $ -- $ 11,218
Net income........................ $22,847 22,847
=======
Cash dividends on common stock.... (4,900)
Cash dividends on preferred stock. (3,704)
- --------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2000........... 6,290,000 188,700 (310) -- 25,461
Net income........................ $41,041 41,041
=======
Cash dividends on common stock.... (27,400)
Cash dividends on preferred stock. (3,704)
- --------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2001........... 6,290,000 188,700 (310) -- 35,398
Net income........................ $ 47,717 47,717
Minimum liability for unfunded retirement
benefits, net of $(7,045,000) of
income taxes.................... (9,932) (9,932)
--------
Comprehensive income.............. $ 37,785
========
Cash dividends on preferred stock. (3,699)
Cash dividends on common stock.... (28,500)
- --------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2002........... 6,290,000 $188,700 $(310) $(9,932) $ 50,916
====================================================================================================================
STATEMENTS OF PREFERRED STOCK
Not Subject to Subject to
Mandatory Redemption Mandatory Redemption
-------------------- --------------------
Number Par Number Par
of Shares Value of Shares Value
(Dollars in thousands)
Balance, January 1, 2000.......... 391,049 $39,105 150,000 $15,000
---------------------------------------------------------------------------------------------
Balance, December 31, 2000........ 391,049 39,105 150,000 15,000
---------------------------------------------------------------------------------------------
Balance, December 31, 2001........ 391,049 39,105 150,000 15,000
Redemptions-
7.625% Series.................. (7,500) (750)
---------------------------------------------------------------------------------------------
Balance, December 31, 2002........ 391,049 $39,105 142,500 $14,250
=============================================================================================
<FN>
The accompanying Notes to Financial Statements are an integral part of these statements.
</FN>
14
PENNSYLVANIA POWER COMPANY
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income............................................................ $ 47,717 $ 41,041 $ 22,847
Adjustments to reconcile net income to net cash from operating activities:
Provision for depreciation and amortization........................ 56,763 57,087 55,964
Nuclear fuel and lease amortization................................ 19,204 17,323 18,248
Deferred income taxes, net......................................... (5,337) (11,055) (8,620)
Investment tax credits, net........................................ (2,595) (2,775) (3,051)
Receivables........................................................ (8,434) 8,345 (8,484)
Materials and supplies............................................. (4,711) 3,997 2,888
Accounts payable................................................... 6,338 (11,413) 8,335
Other ............................................................. (3,183) (9,265) (9,651)
---------- --------- ---------
Net cash provided from operating activities...................... 105,762 93,285 78,476
---------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt..................................................... 14,500 31,626 --
Redemptions and Repayments-
Preferred stock.................................................... (750) -- --
Long-term debt..................................................... (56,837) (51,351) (47,796)
Dividend Payments-
Common stock....................................................... (28,500) (27,400) (4,900)
Preferred stock.................................................... (3,699) (3,704) (3,704)
---------- --------- ---------
Net cash provided from (used for) financing activities........... (75,286) (50,829) (56,400)
---------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions.................................................... (46,060) (40,529) (29,856)
Loans to associated companies......................................... -- (19,175) (59,421)
Loan payment from parent.............................................. 19,120 -- --
Sale of assets to associated companies................................ -- 6,053 67,472
Other ................................................................ (2,381) 7,787 (2,466)
---------- --------- ---------
Net cash provided from (used for) investing activities........... (29,321) (45,864) (24,271)
---------- --------- ---------
Net increase (decrease) in cash and cash equivalents.................. 1,155 (3,408) (2,195)
Cash and cash equivalents at beginning of year........................ 67 3,475 5,670
---------- --------- ---------
Cash and cash equivalents at end of year.............................. $ 1,222 $ 67 $ 3,475
========== ========= =========
SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash paid during the year-
Interest (net of amounts capitalized).............................. $ 13,771 $ 19,286 $ 18,804
========== ========= =========
Income taxes....................................................... $ 60,078 $ 53,527 $ 39,704
========== ========= =========
<FN>
The accompanying Notes to Financial Statements are an integral part of these statements.
</FN>
15
PENNSYLVANIA POWER COMPANY
STATEMENTS OF TAXES
For the Years Ended December 31, 2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
(In thousands)
GENERAL TAXES:
State gross receipts*................................................ $ 18,516 $ 12,776 $ 14,264
Real and personal property........................................... 3,729 59 4,012
State capital stock.................................................. 1,357 1,081 1,598
Social security and unemployment..................................... 750 201 2,137
Other................................................................ 122 97 65
--------- --------- ---------
Total general taxes............................................. $ 24,474 $ 14,214 $ 22,076
========= ========= =========
PROVISION FOR INCOME TAXES:
Currently payable-
Federal........................................................... $ 38,972 $ 40,948 $ 26,712
State............................................................. 12,004 12,803 11,080
--------- --------- ----------
50,976 53,751 37,792
--------- --------- ----------
Deferred, net-
Federal........................................................... (4,144) (8,304) (4,273)
State............................................................. (1,193) (2,751) (4,347)
--------- --------- ---------
(5,337) (11,055) (8,620)
--------- --------- ---------
Investment tax credit amortization................................... (2,595) (2,775) (3,051)
--------- --------- ---------
Total provision for income taxes................................ $ 43,044 $ 39,921 $ 26,121
========= ========= =========
INCOME STATEMENT CLASSIFICATION OF PROVISION FOR
INCOME TAXES:
Operating expenses................................................... $ 41,733 $ 36,909 $ 24,874
Other income......................................................... 1,311 3,012 1,247
--------- --------- ---------
Total provision for income taxes................................ $ 43,044 $ 39,921 $ 26,121
========= ========= =========
RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT
STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES:
Book income before provision for income taxes........................ $ 90,761 $ 80,962 $ 48,968
========= ========= =========
Federal income tax expense at statutory rate......................... $ 31,766 $ 28,337 $ 17,139
Increases (reductions) in taxes resulting from:
State income taxes, net of federal income tax benefit............. 7,027 6,534 4,376
Amortization of investment tax credits............................ (2,595) (2,775) (3,051)
Amortization of tax regulatory assets............................. 5,967 6,315 6,899
Other, net........................................................ 879 1,510 758
--------- --------- ---------
Total provision for income taxes................................ $ 43,044 $ 39,921 $ 26,121
========= ========= =========
ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31:
Competitive transition charge........................................ $ 56,172 $ 75,686 $ 95,497
Property basis differences........................................... 72,488 65,534 64,348
Allowance for equity funds used during construction.................. 1,045 2,608 4,163
Customer receivables for future income taxes......................... 4,249 5,640 7,016
Unamortized investment tax credits................................... (1,578) (1,702) (1,823)
Deferred gain for asset sale to affiliated company................... 8,810 9,943 8,925
Other comprehensive income........................................... (7,045) -- --
Other ............................................................... (16,756) (20,901) (17,494)
--------- --------- ---------
Net deferred income tax liability............................... $ 117,385 $ 136,808 $ 160,632
========= ========= =========
<FN>
* Collected from customers through regulated rates and included in revenue on the Statements of Income.
The accompanying Notes to Financial Statements are an integral part of these statements.
</FN>
16
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Pennsylvania Power Company (Company), a wholly owned subsidiary of
Ohio Edison Company (OE), 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) REVENUES-
The Company's principal business is providing electric service to
customers in western Pennsylvania. The Company's retail customers are metered on
a cycle basis. Revenue is recognized for unbilled electric service through the
end of the year.
Receivables from customers include sales to residential, commercial
and industrial customers located in the Company's service area and sales to
wholesale customers. There was no material concentration of receivables at
December 31, 2002 or 2001, with respect to any particular segment of the
Company's customers.
(B) REGULATORY PLAN-
Pennsylvania enacted its electric utility competition law in 1996 with
the phase in of customer choice for electric generation suppliers completed on
January 1, 2001. The Company continues to deliver power to homes and businesses
through its distribution system, which remains regulated by the PPUC. The
Company's rates have been restructured to itemize (unbundle) the current price
of electricity into its component elements - including generation, transmission,
distribution and stranded cost recovery. In the event customers obtain power
from an alternative source, the generation portion of the Company's rates is
excluded from their bill and the customers receive a generation charge from the
alternative supplier. The stranded cost recovery portion of rates provides for
recovery of certain amounts not otherwise considered recoverable in a
competitive generation market, including regulatory assets.
In 1998, the PPUC authorized the Company's rate restructuring plan,
which essentially resulted in the deregulation of the Company's generation
business. The Company was required to remove from its balance sheet all
regulatory assets and liabilities related to its generation business and assess
all other assets for impairment. The SEC issued interpretive guidance regarding
asset impairment measurement concluding that any supplemental regulated cash
flows such as a competitive transition charge (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.
Consistent with the SEC guidance, the Company reduced its nuclear generating
unit investments by approximately $305 million, of which approximately $227
million was recognized as a regulatory asset to be recovered through the CTC
over a seven-year transition period; the remaining net amount of $78 million was
written off. The Company is entitled to recover $236 million of stranded costs
through the CTC that began in 1999 and ends in 2006. The Company's net assets
included in utility plant relating to the operations for which the application
of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
(SFAS 71) was discontinued were $82 million as of December 31, 2002.
(C) UTILITY PLANT AND DEPRECIATION-
Utility plant reflects the original cost of construction (except for
nuclear generating units which were adjusted to fair value), including payroll
and related costs such as taxes, employee benefits, administrative and general
costs, and interest costs. 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 annual composite rate for electric plant was approximately 2.9% in 2002 and
2001 and 2.6% in 2000.
Annual depreciation expense includes approximately $1.6 million for
future decommissioning costs applicable to the Company's ownership interest in
three nuclear generating units (Beaver Valley Units 1 and 2 and Perry Unit 1).
The Company's share of the future obligation to decommission these units is
approximately $354 million in current dollars and (using a 4.0% escalation rate)
approximately $695 million in future dollars. The estimated obligation and the
escalation rate were developed based on site specific studies. Payments for
decommissioning are expected to begin in 2016, when actual decommissioning work
begins. The Company has recovered approximately $17 million for decommissioning
through its electric rates from customers through December 31, 2002. The Company
has also
17
recognized an estimated liability of approximately $5.3 million related to
decontamination and decommissioning of nuclear enrichment facilities operated by
the United States Department of Energy, as required by the Energy Policy Act of
1992.
In June 2001, the Financial Accounting Standards Board issued SFAS
143, "Accounting for Asset Retirement Obligations". The new statement provides
accounting standards for retirement obligations associated with tangible
long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires
that the fair value of a liability for an asset retirement obligation be
recorded in the period in which it is incurred. The associated asset retirement
costs are capitalized as part of the carrying amount of the long-lived asset.
Over time the capitalized costs are depreciated and the present value of the
asset retirement liability increases, resulting in a period expense. However,
rate-regulated entities may recognize a regulatory asset or liability if the
criteria for such treatment are met. Upon retirement, a gain or loss would be
recorded if the cost to settle the retirement obligation differs from the
carrying amount.
The Company has identified applicable legal obligations as defined
under the new standard, principally for nuclear power plant decommissioning.
Upon adoption of SFAS 143 in January 2003, asset retirement costs of $78 million
were recorded as part of the carrying amount of the related long-lived asset,
offset by accumulated depreciation of $9 million. Due to the increased carrying
amount, the related long-lived assets were tested for impairment in accordance
with SFAS 144, "Accounting for Impairment or Disposal of Long-Lived Assets". No
impairment was indicated. The asset retirement liability at the date of adoption
will be $121 million. As of December 31, 2002, the Company had recorded
decommissioning liabilities of $120 million. The change in the estimated
liabilities resulted from changes in methodology and various assumptions,
including changes in the projected dates for decommissioning.
Management expects that the ultimate nuclear decommissioning costs for
the Company will be recovered through its regulated rates. Therefore, the
Company recognized a regulatory liability of $69 million upon adoption of SFAS
143 for the transition amounts related to establishing the asset retirement
obligations for nuclear decommissioning for the Company. The remaining
cumulative effect adjustment to recognize the undepreciated asset retirement
cost and the asset retirement liability offset by the reversal of the previously
recorded decommissioning liabilities was a $1.1 million decrease to income ($0.6
million net of tax).
(D) COMMON OWNERSHIP OF GENERATING FACILITIES-
The Company, together with OE and other affiliated companies, The
Cleveland Electric Illuminating Company (CEI) and The Toledo Edison Company
(TE), own, as tenants in common, various power generating facilities. Each of
the companies is obligated to pay a share of the costs associated with any
jointly owned facility in the same proportion as its interest. The Company's
portion of operating expenses associated with jointly owned facilities is
included in the corresponding operating expenses on the Statements of Income.
The amounts reflected on the Balance Sheet under utility plant at December 31,
2002 include the following:
Utility Accumulated Construction Company's
Plant in Provision for Work in Ownership
Generating Units Service Depreciation Progress Interest
- -------------------------------------------------------------------------------------------------------------
(In millions)
W. H. Sammis #7....................... $ 64.1 $ 24.4 $ -- 20.80%
Bruce Mansfield
#1, #2 and #3....................... 185.9 114.8 2.7 16.38%
Beaver Valley #1 and #2............... 52.6 13.7 32.9 39.37%
Perry #1.............................. 3.7 0.9 1.0 5.24%
-------------------------------------------------------------------------------------------------------
Total............................. $306.3 $153.8 $36.6
=============================================================================================================
(E) NUCLEAR FUEL-
OES Fuel, Incorporated, a wholly owned subsidiary of OE, had been the
sole lessor for the Company's nuclear fuel requirements. The Company and OE
replaced that lease arrangement with direct ownership and nuclear fuel financing
by the Company and OE. The Company amortizes the cost of nuclear fuel based on
the rate of consumption.
(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 3B). 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.
18
If FirstEnergy had accounted for employee stock options under the fair
value method, a higher value would have been assigned to the options granted.
The weighted average assumptions used in valuing the options and their resulting
estimated fair values would be as follows:
2002 2001 2000
----------------------------------------------------------------------------
Valuation assumptions:
Expected option term (years)... 8.1 8.3 7.6
Expected volatility............ 23.31% 23.45% 21.77%
Expected dividend yield........ 4.36% 5.00% 6.68%
Risk-free interest rate........ 4.60% 4.67% 5.28%
Fair value per option............ $6.45 $4.97 $2.86
----------------------------------------------------------------------------
The effects of applying fair value accounting to FirstEnergy's stock
options would not be material to the Company's net income.
(G) INCOME TAXES-
Details of the total provision for income taxes are shown on the
Statements of Taxes. Deferred income taxes result from timing differences in the
recognition of revenues and expenses for tax and accounting purposes. Investment
tax credits, which were deferred when utilized, are being amortized over the
recovery period of the related property. The liability method is used to account
for deferred income taxes. Deferred income tax liabilities related to tax and
accounting basis differences are recognized at the statutory income tax rates in
effect when the liabilities are expected to be paid. The Company is included in
FirstEnergy's consolidated federal income tax return. The consolidated tax
liability is allocated on a "stand-alone" company basis, with the Company
recognizing any tax losses or credits it contributed to the consolidated return.
(H) RETIREMENT BENEFITS-
FirstEnergy's trusteed, noncontributory defined benefit pension plan
covers almost all of the Company's full-time employees. Upon retirement,
employees receive a monthly pension based on length of service and compensation.
On December 31, 2001, the FirstEnergy pension plan was merged with the pension
plans of GPU, Inc., which merged with FirstEnergy on November 7, 2001. The
Company uses the projected unit credit method for funding purposes and was not
required to make pension contributions during the three years ended December 31,
2002. The assets of the FirstEnergy pension plan consist primarily of common
stocks, United States government bonds and corporate bonds.
The Company provides a minimum amount of noncontributory life
insurance to retired employees in addition to optional contributory insurance.
Health care benefits, which include certain employee contributions, deductibles
and copayments, are also available to retired employees, their dependents and,
under certain circumstances, their survivors. The Company pays insurance
premiums to cover a portion of these benefits in excess of set limits; all
amounts up to the limits are paid by the Company. The Company recognizes the
expected cost of providing other postretirement benefits to employees and their
beneficiaries and covered dependents from the time employees are hired until
they become eligible to receive those benefits.
As a result of the reduced market value of FirstEnergy's pension plan
assets, it was required to recognize an additional minimum liability as
prescribed by SFAS 87 and SFAS 132, "Employers' Disclosures about Pension and
Postretirement Benefits," as of December 31, 2002. FirstEnergy's accumulated
benefit obligation of $3.438 billion exceeded the fair value of plan assets
($2.889 billion) resulting in a minimum pension liability of $548.6 million.
FirstEnergy eliminated its prepaid pension asset of $286.9 million (Company -
$8.8 million) and established a minimum liability of $548.6 million (Company -
$11.7 million), recording an intangible asset of $78.5 million (Company - $3.6
million) and reducing OCI by $444.2 million (Company - $9.9 million) (recording
a related deferred tax asset of $312.8 million (Company - $7.0 million)). The
charge to OCI will reverse in future periods to the extent the fair value of
trust assets exceed the accumulated benefit obligation. The amount of pension
liability recorded as of December 31, 2002, increased due to the lower discount
rate and asset returns assumed as of December 31, 2002.
19
The following sets forth the funded status of the plans and amounts
recognized on FirstEnergy's Consolidated Balance Sheets as of December 31:
Other
Pension Benefits Postretirement Benefits
---------------- -----------------------
2002 2001 2002 2001
--------------------------------------------------------------------------------------------
(In millions)
Change in benefit obligation:
Benefit obligation as of January 1........ $3,547.9 $1,506.1 $ 1,581.6 $ 752.0
Service cost.............................. 58.8 34.9 28.5 18.3
Interest cost ............................ 249.3 133.3 113.6 64.4
Plan amendments........................... -- 3.6 (121.1) --
Actuarial loss............................ 268.0 123.1 440.4 73.3
Voluntary early retirement program........ -- -- -- 2.3
GPU acquisition........................... (11.8) 1,878.3 110.0 716.9
Benefits paid............................. (245.8) (131.4) (83.0) (45.6)
---------------------------------------------------------------------------------------------
Benefit obligation as of December 31...... 3,866.4 3,547.9 2,070.0 1,581.6
---------------------------------------------------------------------------------------------
Change in fair value of plan assets:
Fair value of plan assets as of January 1. 3,483.7 1,706.0 535.0 23.0
Actual return on plan assets.............. . (348.9) 8.1 (57.1) 12.7
Company contribution ..................... -- -- 37.9 43.3
GPU acquisition........................... -- 1,901.0 -- 462.0
Benefits paid.............................. (245.8) (131.4) (42.5) (6.0)
---------------------------------------------------------------------------------------------
Fair value of plan assets as of December 31 2,889.0 3,483.7 473.3 535.0
---------------------------------------------------------------------------------------------
Funded status of plan..................... (977.4) (64.2) (1,596.7) (1,046.6)
Unrecognized actuarial loss............... 1,185.8 222.8 751.6 212.8
Unrecognized prior service cost........... 78.5 87.9 (106.8) 17.7
Unrecognized net transition obligation.... -- -- 92.4 101.6
--------------------------------------------------------------------------------------------
Net amount recognized..................... $ 286.9 $ 246.5 $ (859.5) $ (714.5)
=============================================================================================
Consolidated Balance Sheets classification:
Prepaid (accrued) benefit cost............ $ (548.6) $ 246.5 $ (859.5) $ (714.5)
Intangible asset.......................... 78.5 -- -- --
Accumulated other comprehensive loss...... 757.0 -- -- --
--------------------------------------------------------------------------------------------
Net amount recognized..................... $ 286.9 $ 246.5 $ (859.5) $ (714.5)
=============================================================================================
Company's share of net amount recognized.. $ 8.8 $ 18.1 $ (26.4) $ (37.4)
=============================================================================================
Assumptions used as of December 31:
Discount rate............................. 6.75% 7.25% 6.75% 7.25%
Expected long-term return on plan assets.. 9.00% 10.25% 9.00% 10.25%
Rate of compensation increase............. 3.50% 4.00% 3.50% 4.00%
<FN>
FirstEnergy's net pension and other postretirement benefit costs for the three
years ended December 31, 2002 were computed as follows:
</FN>
Other
Pension Benefits Postretirement Benefits
------------------------ -------------------------
2002 2001 2000 2002 2001 2000
------------------------------------------------------------------------------------------------------
(In millions)
Service cost $ 58.8 $ 34.9 $ 27.4 $ 28.5 $18.3 $11.3
Interest cost 249.3 133.3 104.8 113.6 64.4 45.7
Expected return on plan assets (346.1) (204.8) (181.0) (51.7) (9.9) (0.5)
Amortization of transition obligation (asset)-- (2.1) (7.9) 9.2 9.2 9.2
Amortization of prior service cost 9.3 8.8 5.7 3.2 3.2 3.2
Recognized net actuarial loss (gain) -- -- (9.1) 11.2 4.9 --
Voluntary early retirement program -- 6.1 17.2 -- 2.3 --
------------------------------------------------------------------------------------------------------
Net periodic benefit cost (income) $ (28.7) $ (23.8) $ (42.9) $114.0 $92.4 $68.9
======================================================================================================
Company's share of net benefit cost..... $ 0.4 $ (0.7) $ (3.6) $ 2.1 $ 4.0 $ 7.5
------------------------------------------------------------------------------------------------------
The composite health care cost trend rate assumption is approximately
10%-12% in 2003, 9% in 2004 and 8% in 2005, decreasing to 5% in later years.
Assumed health care cost trend rates have a significant effect on the amounts
reported for the health care plan. An increase in the health care cost trend
rate assumption by one percentage point would increase the total service and
interest cost components by $20.7 million and the postretirement benefit
obligation by $232.2 million. A decrease in the same assumption by one
percentage point would decrease the total service and interest cost components
by $16.7 million and the postretirement benefit obligation by $204.3 million.
20
(I) TRANSACTIONS WITH AFFILIATED COMPANIES-
Operating revenues, operating expenses and other income include
transactions with affiliated companies, primarily OE, CEI, TE, American
Transmission Systems, Inc. (ATSI), FirstEnergy Solutions Corp. (FES) and
FirstEnergy Service Company (FECO). The Ohio transition plan resulted in the
corporate separation of FirstEnergy's regulated and unregulated operations in
2001. Unregulated operations under FES now operate the generation businesses of
the Company, OE, CEI and TE. As a result, the Company entered into power supply
agreements (PSA) whereby FES purchases all of the Company's nuclear generation
and the Company purchases its power from FES to meet its "provider of last
resort" obligations. The reduction in revenues for Bruce Mansfield
administrative and general charges and costs for FirstEnergy support services in
2001 and 2002 from 2000 levels reflects the transfer of fossil generation
operations to FES. In 2002, the Company and OE terminated their nuclear fuel
leasing arrangement with OES Fuel and now own their nuclear fuel. The primary
affiliated companies transactions, including the effects of the PSA beginning in
2001, the sale and leaseback of the Company's transmission assets to ATSI in
September 2000 and FirstEnergy's providing support services at cost, are as
follows:
2002 2001 2000
- -------------------------------------------------------------------------------
(In millions)
Operating Revenues:
PSA revenues with FES..................... $138.0 $151.5 $ --
Generating units rent with FES............ 20.2 20.2 --
Electric sales to affiliated utilitie -- -- 57.6
Bruce Mansfield administrative and
general charges........................ -- -- 2.9
Ground lease with ATSI.................... 1.3 1.3 0.7
Operating Expenses:
Nuclear fuel leased from OES Fuel......... 4.8 18.7 20.3
Purchased power from affiliated utilities. -- -- 7.1
Purchased power under PSA................. 157.0 152.7 --
Transmission facilities rentals
(including ATSI rents)................. 13.3 9.9 5.7
Nuclear operations administrative and
generation charges..................... 20.2 18.6 15.0
FirstEnergy support services.............. 8.5 10.1 27.4
Other Income:
Interest income from ATSI.................. 2.6 2.6 0.9
Interest income from FES................... 0.5 0.5 --
- -------------------------------------------------------------------------------
FirstEnergy does not bill directly or allocate any of its costs to any
subsidiary company. Costs are allocated to the Company from its affiliates, GPU
Service, Inc. and FECO, both subsidiaries of FirstEnergy Corp. and both "mutual
service companies" as defined in Rule 93 of the 1935 Public Utility Holding
Company Act (PUHCA). The majority of costs are directly billed or assigned at no
more than cost as determined by PUHCA Rule 91. The remaining costs are for
services that are provided on behalf of more than one company, or costs that
cannot be precisely identified and are allocated using formulas that are filed
annually with the SEC on Form U-13-60. The current allocation or assignment
formulas used and their bases include multiple factor formulas; the ratio of
each company's amount of FirstEnergy's aggregate direct payroll, number of
employees, asset balances, revenues, number of customers and other factors; and
specific departmental charge ratios. Management believes that these allocation
methods are reasonable.
(J) SUPPLEMENTAL CASH FLOWS INFORMATION-
All temporary cash investments purchased with an initial maturity of
three months or less are reported as cash equivalents on the Balance Sheets at
cost, which approximates their fair market value. Noncash financing and
investing activities included capital lease transactions amounting to $1.5
million, $21.6 million and $21.2 million for the years 2002, 2001 and 2000,
respectively.
All borrowings with initial maturities of less than one year are
defined as financial instruments under GAAP and are reported on the 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:
21
2002 2001
- --------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Value Value Value Value
-------- ----- -------- -----
(In millions)
Long-term debt.............................. $252 $260 $252 $262
Preferred stock............................. 14 14 15 15
Investments other than cash and
cash equivalents.......................... 161 165 160 162
- --------------------------------------------------------------------------------
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.
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 consist primarily of 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 the Company, investments
in companies owning nuclear power plants, financial derivatives, preferred
stocks, securities convertible into common stock and securities of the trust
fund's custodian or managers and their parents or subsidiaries. The investments
that are held in the decommissioning trusts (included as "Investments other than
cash and cash equivalents" in the table above) consist of equity securities,
government bonds and corporate bonds. Unrealized gains and losses applicable to
the decommissioning trusts have been recognized in the trust investment with a
corresponding change to the decommissioning liability. In conjunction with the
adoption of SFAS 143 on January 1, 2003, unrealized gains or losses were
reclassified to OCI in accordance with SFAS 115. Realized gains (losses) are
recognized as additions (reductions) to trust asset balances. For the year 2002,
net realized gains (losses) were approximately $(0.3) million and interest and
dividend income totaled approximately $5.2 million.
(K) REGULATORY ASSETS-
The Company recognizes, as regulatory assets, costs which the FERC and
PPUC have authorized for recovery from customers in future periods. Without such
authorization, the costs would have been charged to income as incurred. All
regulatory assets are expected to continue to be recovered from customers under
the Company's rate restructuring plan. Based on the rate restructuring plan, the
Company continues to bill and collect cost-based rates relating to the Company's
nongeneration operations and continues the application of SFAS 71 to these
operations.
Net regulatory assets on the Balance Sheets are comprised of the
following:
2002 2001
- -----------------------------------------------------------------------------
(In millions)
Competitive transition charge.................. $135.7 $182.7
Customer receivables for future income taxes... 10.3 13.6
Loss on reacquired debt........................ 6.9 6.9
Employee postretirement benefit costs.......... 2.8 3.6
Other.......................................... 1.2 2.0
- -----------------------------------------------------------------------------
Total..................................... $156.9 $208.8
=============================================================================
2. LEASES
The Company leases office space and other property and equipment under
cancelable and noncancelable leases. Consistent with the regulatory treatment,
the rentals for capital and operating leases are charged to operating expenses
on the Statements of Income. Such costs for the three years ended December 31,
2002, are summarized as follows:
2002 2001 2000
----------------------------------------------------------------------------
(In millions)
Operating leases
Interest element................... $0.1 $-- $0.3
Other.............................. 0.2 0.1 0.8
Capital leases
Interest element................... -- -- 0.4
Other.............................. 0.1 0.1 0.3
----------------------------------------------------------------------------
Total rentals......................... $ 0.4 $ 0.2 $1.8
============================================================================
22
The future minimum lease payments as of December 31, 2002, are:
Capital Operating
Leases Leases
----------------------------------------------------------------------
(In millions)
2003................................... $0.1 $0.1
2004................................... -- 0.1
2005................................... -- 0.1
2006................................... -- 0.1
2007................................... -- 0.1
Years thereafter....................... -- 0.7
------------------------------------------------------------------
Total minimum lease payments........... 0.1 $1.2
====
Executory costs........................ 0.1
------------------------------------------------
Net minimum lease payments............. --
Interest portion....................... --
------------------------------------------------
Present value of net minimum
lease payments....................... --
Less current portion................... --
------------------------------------------------
Noncurrent portion..................... $--
================================================
3. CAPITALIZATION
(A) RETAINED EARNINGS-
Under the Company's Charter, the Company's retained earnings
unrestricted for payment of cash dividends on the Company's common stock were
$41.0 million as of December 31, 2002.
(B) STOCK COMPENSATION PLANS-
In 2001, FirstEnergy assumed responsibility for two new stock-based
plans as a result of its acquisition of GPU. No further stock-based compensation
can be awarded under the GPU, Inc. Stock Option and Restricted Stock Plan for
MYR Group Inc. Employees (MYR Plan) or the 1990 Stock Plan for Employees of GPU,
Inc. and Subsidiaries (GPU Plan). All options and restricted stock under both
Plans have been converted into FirstEnergy options and restricted stock. Options
under the GPU Plan became fully vested on November 7, 2001, and will expire on
or before June 1, 2010. Under the MYR Plan, all options and restricted stock
maintained their original vesting periods, which range from one to four years,
and will expire on or before December 17, 2006.
Additional stock based plans administered by FirstEnergy include the
Centerior Equity Plan (CE Plan) and the FirstEnergy Executive and Director
Incentive Compensation Plan (FE Plan). All options are fully vested under the CE
Plan, and no further awards are permitted. Outstanding options will expire on or
before February 25, 2007. Under the FE Plan, total awards cannot exceed 22.5
million shares of common stock or their equivalent. Only stock options and
restricted stock have been granted, with vesting periods ranging from six months
to seven years.
Collectively, the above plans are referred to as the FE Programs.
Restricted common stock grants under the FE Programs were as follows:
2002 2001 2000
-----------------------------------------------------------------------
Restricted common shares granted 36,922 133,162 208,400
Weighted average market price $36.04 $35.68 $26.63
Weighted average vesting period (years) 3.2 3.7 3.8
Dividends restricted Yes * Yes
* FE Plan dividends are paid as restricted stock on 4,500
shares; MYR Plan dividends are paid as unrestricted cash
on 128,662 shares
Under the Executive Deferred Compensation Plan (EDCP), covered
employees can direct a portion of their Annual Incentive Award and/or Long-Term
Incentive Award into an unfunded FirstEnergy Stock Account to receive vested
stock units. An additional 20% premium is received in the form of stock units
based on the amount allocated to the FirstEnergy Stock Account. Dividends are
calculated quarterly on stock units outstanding and are paid in the form of
additional stock units. Upon withdrawal, stock units are converted to
FirstEnergy shares. Payout typically occurs three years from the date of
deferral; however, an election can be made in the year prior to payout to
further defer shares into a retirement stock account that will pay out in cash
upon retirement. As of December 31, 2002, there were 296,008 stock units
outstanding.
23
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, 2002 2,153,369 $25.32
(159,755 options exercisable) 24.87
Options granted 3,011,584 23.24
Options exercised 90,491 26.00
Options forfeited 52,600 22.20
Balance, December 31, 2000 5,021,862 24.09
(473,314 options exercisable) 24.11
Options granted 4,240,273 28.11
Options exercised 694,403 24.24
Options forfeited 120,044 28.07
Balance, December 31, 2001 8,447,688 26.04
(1,828,341 options exercisable) 24.83
Options granted 3,399,579 34.48
Options exercised 1,018,852 23.56
Options forfeited 392,929 28.19
Balance, December 31, 2002 10,435,486 28.95
(1,400,206 options exercisable) 26.07
As of December 31, 2002, the weighted average remaining contractual
life of outstanding stock options was 7.6 years.
No material stock-based employee compensation expense is reflected in
net income for stock options granted under the above plans since the exercise
price was equal to the market value of the underlying common stock on the grant
date. The effect of applying fair value accounting to FirstEnergy's stock
options is summarized in Note 1F - "Stock-Based Compensation."
(C) PREFERRED STOCK-
The Company's 7.75% series of preferred stock has a restriction which
prevents early redemption prior to July 2003. All other preferred stock may be
redeemed by the Company in whole, or in part, with 30-60 days' notice.
(D) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION-
The Company's 7.625% series has an annual sinking fund requirement for
7,500 shares.
(E) LONG-TERM DEBT-
The Company has a first mortgage indenture under which it issues from
time to time first mortgage bonds secured by a direct first mortgage lien on
substantially all of its property and franchises, other than specifically
excepted property. The Company has various debt covenants under its financing
arrangements. The most restrictive of the debt covenants relate to the
nonpayment of interest and/or principal on debt which could trigger a default
and the maintenance of minimum fixed charge ratios and debt to capitalization
ratios. There also exists cross-default provisions among financing arrangements
of FirstEnergy and the Company.
Based on the amount of bonds authenticated by the mortgage bond
trustee through December 31, 2002, the Company's annual improvement fund
requirements for all bonds issued under its first mortgage indenture amounts to
$9.2 million. The Company expects to deposit funds with its mortgage bond
trustee in 2003 that will then be withdrawn upon the surrender for cancellation
of a like principal amount of bonds, which are specifically authenticated for
such purposes against unfunded property additions or against previously retired
bonds. This method can result in minor increases in the amount of the annual
sinking fund requirement.
Sinking fund requirements for first mortgage bonds and maturing
long-term debt (excluding capital leases) during the next five years are $65.8
million in 2003, $40.7 million in 2004 and $1.0 million in each year 2005
through 2007. Included in these amounts are various variable interest rate
long-term debt which have provisions by which individual debt holders have the
option to "put back" or require the respective debt issuer to redeem their debt
at those times when the interest rate may change prior to its maturity date.
Those amounts are $25 million and $5 million in 2003 and 2004, respectively,
which is the next time debt holders may exercise this provision.
24
The Company's obligations to repay certain pollution control revenue
bonds are secured by several series of first mortgage bonds. Certain pollution
control revenue bonds are entitled to the benefit of irrevocable bank letters of
credit of $10.4 million and noncancelable municipal bond insurance policies of
$32.9 million to pay principal of, or interest on, the pollution control revenue
bonds. To the extent that drawings are made under the letters of credit or
policies, the Company is entitled to a credit against its obligation to repay
the related bond. The Company pays an annual fee of 1.375% of the amount of the
letters of credit to the issuing bank and is obligated to reimburse the bank for
any drawings thereunder.
(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 OE. As of December 31,
2002, accumulated other comprehensive loss consisted of a minimum liability for
unfunded retirement benefits of $9.9 million.
4. SHORT-TERM BORROWINGS:
The Company may borrow from affiliates on a short-term basis. As of
December 31, 2002, the Company had no short-term borrowings.
5. COMMITMENTS AND CONTINGENCIES:
(A) CAPITAL EXPENDITURES-
The Company's current forecast reflects expenditures of approximately
$123 million for property additions and improvements from 2003-2007, of which
approximately $53 million is applicable to 2003. Investments for additional
nuclear fuel during the 2003-2007 period are estimated to be approximately $42
million, of which approximately $19 million applies to 2003. During the same
periods, the Company's nuclear fuel investments are expected to be reduced by
approximately $34 million and $17 million, respectively, as the nuclear fuel is
consumed.
(B) NUCLEAR INSURANCE-
The Price-Anderson Act limits the public liability relative to a
single incident at a nuclear power plant to $9.5 billion. The amount is covered
by a combination of private insurance and an industry retrospective rating plan.
Based on its ownership interests in the Beaver Valley Station and the Perry
Plant, the Company's maximum potential assessment under the industry
retrospective rating plan (assuming the other affiliate co-owners contribute
their proportionate shares of any assessments under the retrospective rating
plan) would be $74.0 million per incident but not more than $8.4 million in any
one year for each incident.
The Company is also insured as to its interest in Beaver Valley and
Perry under policies issued to the operating company for each plant. Under these
policies, up to $2.75 billion is provided for property damage and
decontamination and decommissioning costs. The Company has also obtained
approximately $222.1 million of insurance coverage for replacement power costs
for its interests in Beaver Valley and Perry. Under these policies, the Company
can be assessed a maximum of approximately $13.1 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 replacement
power, property damage, decontamination, decommissioning, repair and replacement
costs and other such costs arising from a nuclear incident at any of the
Company's plants exceed the policy limits of the insurance in effect with
respect to that plant, to the extent a nuclear incident is determined not to be
covered by the Company's insurance policies, or to the extent such insurance
becomes unavailable in the future, the Company would remain at risk for such
costs.
(C) ENVIRONMENTAL MATTERS-
Various federal, state and local authorities regulate the Company with
regard to air and water quality and other environmental matters. Generation
operations and any related additional capital expenditures for environmental
compliance are the responsibility of FirstEnergy's competitive services business
unit.
The Company is required to meet federally approved sulfur dioxide
(SO2) regulations. Violations of such regulations can result in shutdown of the
generating unit involved and/or civil or criminal penalties of up to $31,500 for
each day the unit is in violation. The Environmental Protection Agency (EPA) has
an interim enforcement policy for SO2 regulations in Ohio that allows for
compliance based on a 30-day averaging period. The Company cannot predict what
action the EPA may take in the future with respect to the interim enforcement
policy.
25
The Company believes it is in compliance with the current SO2 and
nitrogen oxides (NOx) reduction requirements under the Clean Air Act Amendments
of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel,
generating more electricity from lower-emitting plants, and/or using emission
allowances. NOx reductions are being achieved through combustion controls and
the generation of more electricity at lower-emitting plants. In September 1998,
the EPA finalized regulations requiring additional NOx reductions from the
Company's Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform
reductions of NOx emissions (an approximate 85% reduction in utility plant NOx
emissions from projected 2007 emissions) across a region of nineteen states and
the District of Columbia, including Ohio and Pennsylvania, based on a conclusion
that such NOx emissions are contributing significantly to ozone pollution in the
eastern United States. State Implementation Plans (SIP) must comply by May 31,
2004 with individual state NOx budgets established by the EPA. Pennsylvania
submitted a SIP that requires compliance with the NOx budgets at the Company's
Pennsylvania facilities by May 1, 2003.
In July 1997, the EPA promulgated changes in the National Ambient Air
Quality Standard (NAAQS) for ozone emissions and proposed a new NAAQS for
previously unregulated ultra-fine particulate matter. In May 1999, the U.S.
Court of Appeals found constitutional and other defects in the new NAAQS rules.
In February 2001, the U.S. Supreme Court upheld the new NAAQS rules regulating
ultra-fine particulates but found defects in the new NAAQS rules for ozone and
decided that the EPA must revise those rules. The future cost of compliance with
these regulations may be substantial and will depend if and how they are
ultimately implemented by the states in which the Company operates affected
facilities.
In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a
Compliance Order to nine utilities covering 44 power plants, including the W. H.
Sammis Plant. In addition, the U.S. Department of Justice filed eight civil
complaints against various investor-owned utilities, which included a complaint
against the Company and OE in the U.S. District Court for the Southern District
of Ohio, for which hearings began February 3, 2003. The NOV and complaint allege
violations of the Clean Air Act based on operation and maintenance of the Sammis
Plant dating back to 1984. The complaint requests permanent injunctive relief to
require the installation of "best available control technology" and civil
penalties of up to $27,500 per day of violation. Although unable to predict the
outcome of these proceedings, the Company and OE believe the Sammis Plant is in
full compliance with the Clean Air Act and the NOV and complaint are without
merit. Penalties could be imposed if the Sammis Plant continues to operate
without correcting the alleged violations and a court determines that the
allegations are valid. The Sammis Plant continues to operate while these
proceedings are pending.
In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants. The EPA identified mercury as the hazardous air pollutant of
greatest concern. The EPA established a schedule to propose regulations by
December 2003 and issue final regulations by December 2004. The future cost of
compliance with these regulations may be substantial.
As a result of the Resource Conservation and Recovery Act of 1976, as
amended, and the Toxic Substances Control Act of 1976, federal and state
hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous waste
disposal requirements pending the EPA's evaluation of the need for future
regulation. The EPA has issued its final regulatory determination that
regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the
EPA announced that it will develop national standards regulating disposal of
coal ash under its authority to regulate nonhazardous waste.
The effects of compliance on the Company with regard to environmental
matters could have a material adverse effect on the Company's earnings and
competitive position. These environmental regulations affect the Company's
earnings and competitive position to the extent it competes with companies that
are not subject to such regulations and therefore do not bear the risk of costs
associated with compliance, or failure to comply, with such regulations. The
Company believes it is in material compliance with existing regulations but is
unable to predict whether environmental regulations will change and what, if
any, the effects of such change would be.
(D) LEGAL MATTERS-
Various lawsuits, claims and proceedings related to the Company's
normal business operations are pending against FirstEnergy and its subsidiaries.
The most significant applicable to the Company are described above.
6. RECENTLY ISSUED ACCOUNTING STANDARDS
FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees
of Indebtedness of Others - an interpretation of FASB Statements No.
5, 57, and 107 and rescission of FASB Interpretation No. 34"
The FASB issued FIN 45 in January 2003. This interpretation identifies
minimum guarantee disclosures required for annual periods ending after December
15, 2002. It also clarifies that providers of guarantees must record the fair
26
value of those guarantees at their inception. This accounting guidance is
applicable on a prospective basis to guarantees issued or modified after
December 31, 2002. The Company does not believe that implementation of FIN 45
will be material but it will continue to evaluate anticipated guarantees.
7. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
The following summarizes certain operating results by quarter for 2002
and 2001.
March 31, June 30, September 30, December 31,
Three Months Ended 2002 2002 2002 2002
- ---------------------------------------------------------------------------------------------------------------
(In millions)
Operating Revenues........................ $ 124.3 $ 127.8 $ 131.9 $ 122.4
Operating Expenses and Taxes.............. 109.2 106.3 113.1 116.9
- ---------------------------------------------------------------------------------------------------------------
Operating Income.......................... 15.1 21.5 18.8 5.5
Other Income.............................. 0.7 0.5 0.7 0.1
Net Interest Charges...................... 3.8 4.0 3.7 3.6
- ---------------------------------------------------------------------------------------------------------------
Net Income................................ $ 12.0 $ 18.0 $ 15.8 $ 2.0
===============================================================================================================
Earnings on Common Stock.................. $ 11.0 $ 17.1 $ 14.9 $ 1.0
===============================================================================================================
March 31, June 30, September 30, December 31,
Three Months Ended 2001 2001 2001 2001
- ---------------------------------------------------------------------------------------------------------------
(In millions)
Operating Revenues........................ $ 128.4 $ 124.7 $ 121.3 $ 124.0
Operating Expenses and Taxes.............. 112.4 101.8 118.7 110.3
- ---------------------------------------------------------------------------------------------------------------
Operating Income.......................... 16.0 22.9 2.6 13.7
Other Income.............................. 0.9 0.7 1.0 0.6
Net Interest Charges...................... 4.5 4.6 4.3 4.0
- ---------------------------------------------------------------------------------------------------------------
Net Income (Loss)......................... $ 12.4 $ 19.0 $ (0.7) $ 10.3
===============================================================================================================
Earnings (Loss) Applicable to Common Stock $ 11.5 $ 18.1 $ (1.7) $ 9.4
===============================================================================================================
27
Report of Independent Accountants
To the Stockholders and Board of Directors of Pennsylvania Power Company:
In our opinion, the accompanying balance sheet and statement of capitalization
and the related statements of income, common stockholder's equity, preferred
stock, cash flows and taxes present fairly, in all material respects, the
financial position of Pennsylvania Power Company (a wholly owned subsidiary of
Ohio Edison Company) as of December 31, 2002, and the results of its operations
and its cash flows for the year 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 audit. We conducted our audit 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 audit provides a
reasonable basis for our opinion. The financial statements of Pennsylvania Power
Company as of December 31, 2001 and for each of the two years in the period
ended December 31, 2001 were audited by other independent accountants who have
ceased operations. Those independent accountants expressed an unqualified
opinion on those financials statements in their report dated March 18, 2002.
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 28, 2003
28
The following report is a copy of a report previously issued by Arthur Andersen
LLP and has not been reissued by Arthur Andersen LLP.
Report of Independent Public Accountants
To the Stockholders and Board of Directors of Pennsylvania Power Company:
We have audited the accompanying balance sheets and statements of capitalization
of Pennsylvania Power Company (a Pennsylvania corporation and wholly owned
subsidiary of Ohio Edison Company) as of December 31, 2001 and 2000, and the
related statements of income, common stockholder's equity, preferred stock, cash
flows and taxes for each of the three years in the period ended December 31,
2001. 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 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 audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Pennsylvania Power Company as
of December 31, 2001 and 2000, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 2001, in
conformity with accounting principles generally accepted in the United States.
29
ARTHUR ANDERSEN LLP
Cleveland, Ohio,
March 18, 2002.