PENNSYLVANIA POWER COMPANY
SELECTED FINANCIAL DATA
1998 1997 1996 1995 1994
-------- --------- --------- --------- ---------
(Dollars in thousands)
Operating Revenues $323,756 $ 323,381 $ 322,625 $ 314,642 $ 301,965
======== ========== ========== ========== ==========
Operating Income $ 58,041 $ 50,736 $ 62,329 $ 67,317 $ 63,668
======== ========== ========== ========== ==========
Income Before Extraordinary Item $ 39,748 $ 31,472 $ 40,587 $ 38,930 $ 31,260
======== ========== ========== ========== ==========
Net Income $ 9,226 $ 31,472 $ 40,587 $ 38,930 $ 31,260
======== ========== ========== ========== ==========
Earnings on Common Stock $ 4,600 $ 26,846 $ 35,961 $ 34,155 $ 25,896
======== ========== ========== ========== ==========
Return on Average Common Equity 1.6% 9.3% 12.8% 12.9% 10.0%
=== === ==== ==== ====
Cash Dividends on Common Stock $ 21,386 $ 21,386 $ 21,386 $ 21,386 $ 21,386
======== ========== ========== ========== ==========
Total Assets $977,772 $1,034,457 $1,074,578 $1,151,990 $1,197,302
======== ========== ========== ========== ==========
CAPITALIZATION:
Common Stockholder's Equity $275,281 $ 291,977 $ 286,504 $ 271,920 $ 258,973
Preferred Stock-
Not Subject to Mandatory Redemption 50,905 50,905 50,905 50,905 50,905
Subject to Mandatory Redemption 15,000 15,000 15,000 15,000 15,000
Long-Term Debt 287,689 289,305 310,996 338,670 424,457
-------- ---------- ---------- ---------- ----------
Total Capitalization $628,875 $ 647,187 $ 663,405 $ 676,495 $ 749,335
======== ========== ========== ========== ==========
CAPITALIZATION RATIOS:
Common Stockholder's Equity 43.8% 45.1% 43.2% 40.2% 34.6%
Preferred Stock-
Not Subject to Mandatory Redemption 8.1 7.9 7.7 7.5 6.8
Subject to Mandatory Redemption 2.4 2.3 2.2 2.2 2.0
Long-Term Debt 45.7 44.7 46.9 50.1 56.6
----- ----- ----- ----- -----
Total Capitalization 100.0% 100.0% 100.0% 100.0% 100.0%
===== ===== ===== ===== =====
KILOWATT-HOUR SALES (Millions):
Residential 1,278 1,238 1,254 1,195 1,178
Commercial 1,090 1,013 996 938 891
Industrial 1,436 1,659 1,693 1,558 1,293
Other 6 6 6 6 6
----- ----- ----- ----- -----
Total Retail 3,810 3,916 3,949 3,697 3,368
Total Wholesale 964 901 1,106 1,080 1,076
----- ----- ----- ----- -----
Total 4,774 4,817 5,055 4,777 4,444
===== ===== ===== ===== =====
CUSTOMERS SERVED:
Residential 129,452 129,316 127,936 126,480 124,951
Commercial 17,296 16,738 16,531 16,317 15,966
Industrial 250 241 225 223 219
Other 107 97 99 97 98
-------- ---------- ---------- ---------- ----------
Total 147,105 146,392 144,791 143,117 141,234
======== ========== ========== ========== ==========
Average Annual Residential kWh Usage 9,913 9,634 9,866 9,505 9,501
Cost of Fuel per Million Btu $1.15 $1.10 $1.09 $1.12 $1.20
Peak Load - Megawatts 918 836 792 836 710
Generating Capability:
Coal 72.1% 72.1% 72.1% 72.1% 72.1%
Oil 3.0 3.0 3.0 3.0 3.0
Nuclear 24.9 24.9 24.9 24.9 24.9
----- ----- ----- ----- -----
Total 100.0% 100.0% 100.0% 100.0% 100.0%
===== ===== ===== ===== =====
SOURCES OF ELECTRIC GENERATION:
Coal 76.9% 73.8% 67.6% 65.6% 69.6%
Nuclear 23.1 26.2 32.4 34.4 30.4
----- ----- ----- ----- -----
Total 100.0% 100.0% 100.0% 100.0% 100.0%
===== ===== ===== ===== =====
NUMBER OF EMPLOYEES 888 997 1,015 1,220 1,255
=== === ===== ===== =====
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 are subject to
certain risks and uncertainties. These statements typically contain,
but are not limited to, the terms anticipate, potential, expect,
believe, estimate and similar words. Actual results may differ
materially due to the speed and nature of increased competition and
deregulation in the electric utility industry, economic or weather
conditions affecting future sales and margins, changes in markets for
energy services, changing energy market prices, legislative and
regulatory changes, and the availability and cost of capital and other
similar factors.
Results of Operations
We continued to take steps in 1998 to better position our
Company as competition continues to expand in the electric utility
industry. Investments were made in new information systems with
enhanced functionality which also address Year 2000 application
deficiencies. We also contributed to 1998 cash savings of FirstEnergy
Corp. (FirstEnergy) totaling $173 million which were captured from
initiatives implemented during the year in connection with the November
1997 merger of our parent company, Ohio Edison Company and Centerior
Energy Corporation to form FirstEnergy.
Earnings on common stock of $4.6 million in 1998 declined
from $26.8 million in 1997. Results for 1998 were adversely affected by
a one-time, extraordinary charge of $30.5 million after taxes, related
to our discontinued application of Statement of Financial Accounting
Standards No. 71 (SFAS 71), "Accounting for the Effects of Certain
Types of Regulation," to our generation business, as discussed later in
this report. Additionally, sharp increases in the spot market price for
electricity occasioned by a constrained power supply and heavy customer
demand in the latter part of June 1998, combined with an unscheduled
generating unit outage, resulted in spot market purchases of power at
prices which substantially exceeded amounts recovered from retail
customers. Earnings on common stock in 1997 were adversely affected by
nonrecurring charges resulting from merger-related staffing reductions,
charges for uncollectible customer accounts and an increase in
accelerated depreciation and amortization of nuclear and regulatory
assets under our rate plan.
Operating revenues were slightly higher in 1998 compared to
the prior year. This was the third consecutive year of record operating
revenues. The following table summarizes the sources of increases in
operating revenues for 1998 and 1997 as compared to the previous year:
1998 1997
---- ----
(In millions)
Decrease in retail kilowatt-hour sales $(7.6) $(1.7)
Change in average retail price (1.1) 3.7
Wholesale sales 1.3 (3.2)
Other 7.8 2.0
- -----------------------------------------------------------
Net Increase $ 0.4 $ 0.8
==========================================================
Our retail customer base continued to grow with over 700 new
customers added in 1998, after gaining approximately 1,600 customers
the previous year. Although residential and commercial kilowatt-hour
sales increased 3.3% and 7.5%, respectively from 1997, the increases
were more than offset by a 13.4% decrease in industrial sales. Closure
of an electric arc furnace at Caparo Steel Company (Caparo) in August
1997 and a general decline in electricity demand by steel manufacturers
due to intense foreign competition contributed to lower industrial
kilowatt-hour sales. Excluding sales to Caparo, industrial sales
declined 1.7% from 1997. Despite a 7.1% increase in kilowatt-hour sales
to wholesale customers, total kilowatt-hour sales decreased slightly
from 1997 due to the lower industrial sales. Without the closure of the
Caparo facility, total sales would have increased 3.4% from the
previous year. In 1997, residential and industrial kilowatt-hour sales
decreased 1.3% and 2.0%, respectively, compared to 1996. Kilowatt-hour
sales to commercial customers increased 1.8% from the prior year.
Expiration of a one-year contract with another utility to supply 33
megawatts of power contributed to a 18.6% decline in 1997 kilowatt-hour
sales to wholesale customers from the previous year and contributed to
a 4.7% decrease in total 1997 kilowatt-hour sales from 1996.
Total operation and maintenance expenses in 1998 decreased
from the prior year with higher fuel and purchased power costs more
than offset by lower nuclear operating costs and other operating costs.
Most of the increase in fuel and purchased power occurred in the second
quarter and resulted from a combination of factors. In late June 1998,
the midwestern and southern regions of the United States experienced
electricity shortages caused mainly by record temperatures and humidity
and unscheduled generating unit outages. Due in part to an unscheduled
outage at Beaver Valley Unit 1 at that time, our production
capabilities were reduced to the point that we purchased significant
amounts of power, at unusually high spot market prices, causing the
increase in purchased power costs. Because of the decrease in kilowatt-
hour sales in 1997, we spent less on fuel and purchased power during
1997, compared to 1996. Nuclear operating costs were lower in 1998,
compared to 1997, due primarily to lower refueling outage cost levels.
Increased operating costs at Beaver Valley Unit 1 resulted in higher
nuclear operating costs in 1997 compared to the previous year. Two
items in 1997, a $3 million charge for uncollectible customer accounts
and a fourth quarter charge of approximately $5.4 million for a
voluntary retirement program, contributed to the increase in other
operating costs in 1997 from the previous year and to the subsequent
reduction in other operating costs in 1998. In addition, continuing
improvements in operating efficiency, evidenced by a reduction in the
number of our employees over the last five years, contributed to the
reduction in other operating costs in 1998.
Depreciation and amortization decreased in 1998 compared to
the prior year due primarily to the effect of our rate restructuring
plan. The Pennsylvania Public Utility Commission's (PPUC) authorization
of our rate restructuring plan in the second quarter led to
discontinued application of certain regulatory accounting procedures
(i.e. SFAS 71) to our generation business, resulting in a write down of
our nuclear generating unit investment and the recognition of a portion
of such investment, recoverable through future customer rates, as a
regulatory asset. The decrease in nuclear depreciation resulting from
the write down was the primary cause of the total decrease. In 1997,
the increase in the provision for depreciation and amortization of net
regulatory assets from the previous year reflected accelerated
depreciation and amortization of nuclear and regulatory assets under
our rate plan. The decrease in general taxes in 1997 was due
principally to an adjustment, which reduced our liability for gross
receipts taxes.
The downward trend of net interest charges continued in 1998.
Interest on long-term debt decreased in both 1998 and 1997 from the
previous year due to our economic refinancings and redemption of
higher-cost debt totaling approximately $6.1 million in 1998 and $39.4
million in 1997.
Capital Resources and Liquidity
We have significantly improved our financial position over
the past five years as evidenced by our enhanced fixed charge coverage
ratios and percentage of common stockholder's equity to total
capitalization. Our SEC ratio of earnings to fixed charges improved to
4.14 at the end of 1998 from 2.16 at the end of 1993. Our indenture
ratio, which is used to determine our ability to issue first mortgage
bonds, increased from 2.99 at the end of 1993 to 4.92 at the end of
1998. Over the same period, the charter ratio, a measure of our ability
to issue preferred stock, improved from 1.61 to 2.33 and our common
stockholder's equity percentage of capitalization rose from
approximately 33% at the end of 1993 to almost 44% at the end of 1998.
Our improving financial position reflects ongoing efforts to increase
competitiveness. We continue to streamline our operations, as evidenced
by a 50% increase in FirstEnergy's customer/employee ratio, which has
increased from 165 at the end of 1993 to 247 as of December 31, 1998.
Merger-related savings through consolidation of activities have
contributed to these results. Also, net debt redemptions and
refinancings have lowered our average cost of long-term debt over the
last five years from 8.36% in 1993 to 7.70% at the end of 1998.
All cash requirements for the year, including debt
repayments, were met with internally generated funds. Our cash
requirements for 1999 for operating expenses, construction expenditures
and scheduled debt maturities are expected to be met without issuing
additional securities. Cash requirements of approximately $69 million
for the 1999-2003 period to meet scheduled maturities of long-term debt
and preferred stock are also expected to be funded internally.
We had about $57.5 million of cash and temporary investments
and no short-term indebtedness as of December 31, 1998. We also had a
$2 million bank facility that provides for borrowings on a short-term
basis at the bank's discretion.
During 1998, our capital spending (excluding nuclear fuel)
totaled approximately $16 million. Our capital spending for the period
1999-2003 is expected to be about $167 million (excluding nuclear
fuel), of which approximately $28 million applies to 1999. Investments
for additional nuclear fuel during the 1999-2003 period are estimated
to be approximately $28 million, of which about $3 million applies to
1999. During the same periods, our nuclear fuel investments are
expected to be reduced by approximately $29 million and $6 million,
respectively, as the nuclear fuel is consumed.
FirstEnergy signed an agreement in principle with Duquesne
Light Company (Duquesne) that would result in the transfer of 1,436
megawatts owned by Duquesne at five generating plants in exchange for
1,328 megawatts at three plants owned by FirstEnergy's electric utility
operating companies (see "Common Ownership of Generating Facilities" in
Note 1). A final agreement on the exchange of assets, which will be
structured as a tax-free transaction to the extent possible is being
negotiated. The transaction benefits FirstEnergy's utility operating
companies by providing exclusive ownership and operating control of all
generating assets that are now jointly owned and operated under the
Central Area Power Coordination Group agreement.
Interest Rate Risk
Our exposure to fluctuations in market interest rates is
mitigated since a significant portion of our debt has fixed interest
rates, as noted in the table below. We are subject to the inherent
interest rate risks related to refinancing maturing debt by issuing new
debt securities. Changes in the market value of our nuclear
decommissioning trust funds are recognized by making a corresponding
change to the decommissioning liability, as described in Note 1.
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.
- --------------------------------------------------------------------------------------------------
There- Fair
1999 2000 2001 2002 2003 after Total Value
(Dollars in Millions)
- --------------------------------------------------------------------------------------------------
Investments other than Cash and
Cash Equivalents:
Fixed Income $ 9 $ 9 $ 9
Average interest rate 5.1% 5.1%
- -------------------------------------------------------------------------------------------------
Liabilities
- -------------------------------------------------------------------------------------------------
Long-term Debt:
Fixed rate $ 1 $24 $ 1 $ 1 $41 $200 $268 $284
Average interest rate 9.7% 6.2% 9.7% 9.7% 7.6% 7.0% 7.0%
Variable rate $ 10 $ 10 $ 10
Average interest rate 4.2% 4.2%
- -------------------------------------------------------------------------------------------------
Preferred Stock $ 1 $ 1 $ 13 $ 15 $ 16
Average dividend rate 7.6% 7.6% 7.6% 7.6%
- -------------------------------------------------------------------------------------------------
Outlook
We face many competitive challenges in the years ahead as
the electric utility industry undergoes significant changes,
including changing regulation and the entrance of more energy
suppliers into the marketplace. Retail wheeling, which has begun in
our service area, allows retail customers to purchase electricity
from other energy producers. Our regulatory plan provided a solid
foundation to position us to meet the challenges we are now facing by
facilitating the reduction of fixed costs.
Application of SFAS 71 was discontinued for the generation
portion of our business in June 1998 following PPUC approval of the
rate restructuring plan. Customer choice will be phased in over two
years with 66% of each customer class able to choose alternative
suppliers of generation on January 2, 1999, and all remaining
customers having choice as of January 2, 2000. Under the plan, we
continue to deliver power to homes and businesses through our
transmission and distribution system, which remains regulated.
However, our rates have been restructured to establish separate
charges for transmission and distribution; generation, which is
subject to competition; and stranded cost recovery. In the event
customers obtain power from an alternative source, the generation
portion of our rates will be excluded from their bill and our
customers will 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. We are
entitled to recover $234 million of stranded costs through a
competitive transition charge that starts in 1999 and ends in 2005.
The Clean Air Act Amendments of 1990, discussed in Note 5,
require additional emission reductions by 2000. We are pursuing cost-
effective compliance strategies for meeting these reduction
requirements.
On September 24, 1998, the Federal Environmental Protection
Agency issued a final rule establishing tighter nitrogen oxide
emission requirements for fossil fuel-fired utility boilers in
Pennsylvania, Ohio and twenty other eastern states, including the
District of Columbia (see "Environmental Matters" in Note 5).
Controls must be in place by May 2003, with required reductions
achieved during the five-month summer ozone season (May through
September). The new rule is expected to increase the cost of
producing electricity; however, we believe that we are in a better
position than a number of other utilities to achieve compliance due
to our nuclear generation capacity.
In connection with FirstEnergy's regulatory plan to reduce
fixed costs and lower rates, we continue to take steps to restructure
our operations. FirstEnergy announced plans to transfer our
transmission assets into a new subsidiary, American Transmission
Systems, Inc., with the transfer expected to be finalized in 1999.
The new subsidiary represents a first step toward the goal of
establishing or becoming part of a larger independent transmission
company (TransCo). We believe that a TransCo better addresses the
Federal Energy Regulatory Commission's (FERC) stated transmission
objectives of providing non-discriminatory service, while providing
for streamlined and cost-efficient operation. In working toward the
goal of forming a larger regional transmission entity, FirstEnergy,
American Electric Power, Virginia Power and Consumers Energy
announced in November 1998 that they would prepare a FERC filing
during 1999 for such a regional transmission entity. The entity would
be designed to meet the goals of reducing transmission costs that
result when transferring power over several transmission systems,
ensuring transmission reliability and providing non-discriminatory
access to the transmission grid.
Year 2000 Readiness
The Year 2000 issue is the result of computer programs
being written using two digits rather than four to identify the
applicable year. Any of our programs that have date-sensitive
software may recognize a date using "00" as the year 1900 rather than
the year 2000. Because so many of our computer functions are date
sensitive, this could cause far-reaching problems, such as system-
wide computer failures and miscalculations, if no remedial action is
taken.
We have developed a multi-phase program for Year 2000
compliance that consists of an assessment of our systems and
operations that could be affected by the Year 2000 problem;
remediation or replacement of noncompliant systems and components;
and testing of systems and components following such remediation or
replacement. We have focused our Year 2000 review on three areas:
centralized system applications, noncentralized systems and
relationships with third parties (including suppliers as well as end-
use customers). Our review of system readiness extends to systems
involving customer service, safety, shareholder needs and regulatory
obligations.
We are committed to taking appropriate actions to eliminate
or lessen negative effects of the Year 2000 issue on our operations.
We have completed an inventory of all computer systems and hardware
including equipment with embedded computer chips and have determined
which systems need to be converted or replaced to become Year 2000-
ready and are in the process of remediating them. Based on our
timetable, we expect to have all identified repairs, replacements and
upgrades completed to achieve Year 2000 readiness by September 1999.
Most of our Year 2000 issues will be resolved through
system replacement. Of our major centralized systems, the general
ledger system and inventory management, procurement and accounts
payable systems were replaced at the end of 1998. Our payroll system
was enhanced to be Year 2000 compliant in July 1998. The customer
service system is due to be replaced in mid-1999.
We have completed formal communications with most of our key
suppliers to determine the extent to which we are vulnerable to those
third parties' failure to resolve their own Year 2000 problems. For
suppliers having potential compliance problems, we are developing
alternate sources and services in the event such noncompliance occurs.
We are also identifying areas requiring higher inventory levels based
on compliance uncertainties. There can be no guarantee that the
failure of companies to resolve their own Year 2000 issue will not
have a material adverse effect on our business, financial condition
and results of operations.
We are using both internal and external resources to
reprogram and/or replace and test our software for Year 2000
modifications. Of the $6 million total project cost, approximately $5
million will be capitalized since those costs are attributable to the
purchase of new software for total system replacements because the
Year 2000 solution comprises only a portion of the benefits resulting
from the system replacements. The remaining $1 million will be
expensed as incurred. As of December 31, 1998, we have spent $3
million for Year 2000 capital projects and had expensed approximately
$600,000 for Year 2000-related maintenance activities. Our total Year
2000 project cost, as well as our estimates of the time needed to
complete remedial efforts, are based on currently available
information and do not include the estimated costs and time
associated with the impact of third party Year 2000 issues.
We believe we are managing the Year 2000 issue in such a
way that our customers will not experience any interruption of
service. We believe the most likely worst-case scenario from the Year
2000 issue will be disruption in power plant monitoring systems,
thereby producing inaccurate data and potential failures in
electronic switching mechanisms at transmission junctions. This would
prolong localized outages, as technicians would have to manually
activate switches. Such an event could have a material, but currently
undeterminable, effect on our financial results. We are developing
contingency plans to address the effects of any delay in becoming
Year 2000 compliant and expect to have contingency plans completed by
June 1999.
The costs of the project and the dates on which we plan to
complete the Year 2000 modifications are based on management's best
estimates, which were derived from numerous assumptions of future
events including the continued availability of certain resources, and
other factors. However, there can be no guarantee that this project
will be completed as planned and actual results could differ
materially from the estimates. Specific factors that might cause
material differences include but are not limited to, the availability
and cost of trained personnel, the ability to locate and correct all
relevant computer code, and similar uncertainties.
PENNSYLVANIA POWER COMPANY
STATEMENTS OF INCOME
For the Years Ended December 31, 1998 1997 1996
- ------------------------------------------------------------------------------------------------
(In thousands)
OPERATING REVENUES $323,756 $323,381 $322,625
-------- -------- --------
OPERATING EXPENSES AND TAXES:
Fuel and purchased power 76,801 67,345 67,443
Nuclear operating costs 22,968 26,220 22,064
Other operating costs 52,348 66,518 59,753
-------- -------- --------
Total operation and maintenance expenses 152,117 160,083 149,260
Provision for depreciation and amortization 59,264 64,628 57,114
General taxes 22,540 22,379 24,015
Income taxes 31,794 25,555 29,907
-------- -------- --------
Total operating expenses and taxes 265,715 272,645 260,296
-------- -------- --------
OPERATING INCOME 58,041 50,736 62,329
OTHER INCOME 2,485 2,760 5,760
-------- -------- --------
INCOME BEFORE NET INTEREST CHARGES 60,526 53,496 68,089
-------- -------- --------
NET INTEREST CHARGES:
Interest on long-term debt 19,255 20,458 25,715
Interest on nuclear fuel obligations 28 276 219
Allowance for borrowed funds used during construction (294) (414) (387)
Other interest expense 1,789 1,704 1,955
-------- -------- --------
Net interest charges 20,778 22,024 27,502
-------- -------- --------
INCOME BEFORE EXTRAORDINARY ITEM 39,748 31,472 40,587
EXTRAORDINARY ITEM (NET OF INCOME TAXES) (Note 1) (30,522) -- --
-------- -------- --------
NET INCOME 9,226 31,472 40,587
PREFERRED STOCK DIVIDEND REQUIREMENTS 4,626 4,626 4,626
-------- -------- --------
EARNINGS ON COMMON STOCK $ 4,600 $ 26,846 $ 35,961
======== ======== ========
PENNSYLVANIA POWER COMPANY
BALANCE SHEETS
At December 31, 1998 1997
- ----------------------------------------------------------------------------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service $686,771 $1,237,562
Less-Accumulated provision for depreciation 291,188 508,981
-------- ----------
395,583 728,581
-------- ----------
Construction work in progress-
Electric plant 17,187 7,427
Nuclear fuel 508 6,788
-------- ----------
17,695 14,215
-------- ----------
413,278 742,796
-------- ----------
OTHER PROPERTY AND INVESTMENTS 29,177 26,157
-------- ----------
CURRENT ASSETS:
Cash and cash equivalents 7,485 660
Notes receivable from parent company (Note 4) 50,000 17,500
Receivables-
Customers (less accumulated provisions of $3,599,000 and $3,609,000,
respectively, for uncollectible accounts) 34,737 33,934
Associated companies 34,430 12,599
Other 12,472 14,426
Materials and supplies, at average cost 15,515 14,973
Prepayments 2,657 1,707
-------- ----------
157,296 95,799
-------- ----------
DEFERRED CHARGES:
Regulatory assets 371,027 162,966
Other 6,994 6,739
-------- ----------
378,021 169,705
-------- ----------
$977,772 $1,034,457
======== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Statements of Capitalization):
Common stockholder's equity $275,281 $ 291,977
Preferred stock-
Not to subject to mandatory redemption 50,905 50,905
Subject mandatory redemption 15,000 15,000
Long-term debt-
Associated companies 6,617 9,231
Other 281,072 280,074
-------- ----------
628,875 647,187
-------- ----------
CURRENT LIABILITIES:
Currently payable long-term debt-
Associated companies 5,557 6,958
Other 984 1,443
Accounts payable-
Associated companies 9,676 6,788
Other 23,156 22,751
Accrued taxes 12,849 12,332
Accrued interest 6,519 6,588
Other 17,046 14,746
-------- ----------
75,787 71,606
-------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes 212,427 239,952
Accumulated deferred investment tax credits 7,787 26,052
Other 52,896 49,660
-------- ----------
273,110 315,664
-------- ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Notes 2 and 5) -------- ----------
$977,772 $1,034,457
======== ==========
<FN>
The accompanying Notes to Financial Statements are an integral
part of these balance sheets.
PENNSYLVANIA POWER COMPANY
STATEMENTS OF CAPITALIZATION
At December 31, 1998 1997
- ----------------------------------------------------------------------------------------------------------------------------
(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 income (Note 3B) -- (90)
Retained earnings (Note 3A) 86,891 103,677
-------- --------
Total common stockholder's equity 275,281 291,977
-------- --------
Number of Shares Optional
Outstanding Redemption Price
----------------- -----------------------
1998 1997 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
7.64% 60,000 60,000 101.42 6,085 6,000 6,000
7.75% 250,000 250,000 -- -- 25,000 25,000
8.00% 58,000 58,000 102.07 5,920 5,800 5,800
------- ------- ------- -------- --------
Total not subject to mandatory redemption 509,049 509,049 $26,619 50,905 50,905
======= ======= ======= -------- --------
Subject to Mandatory Redemption (Note 3D):
7.625% 150,000 150,000 106.86 $16,029 15,000 15,000
======= ======= ======= -------- --------
LONG-TERM DEBT (Note 3E):
First mortgage bonds-
9.740% due 1999-2019 20,000 20,000
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 128,250 128,250
-------- --------
Secured notes-
4.750% due 1998 -- 850
6.080% due 2000 23,000 23,000
5.400% due 2013 1,000 1,000
5.400% due 2017 10,600 10,600
7.150% due 2017 17,925 17,925
5.900% due 2018 16,800 16,800
8.100% due 2020 5,200 5,200
7.150% due 2021 14,482 14,482
6.150% due 2023 12,700 12,700
*4.150% due 2027 10,300 10,300
6.450% due 2027 14,500 14,500
5.375% due 2028 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 149,679 148,795
-------- --------
Other obligations-
Nuclear fuel 12,174 16,189
Capital leases (Note 2) 4,635 5,022
-------- --------
Total other obligations 16,809 21,211
-------- --------
Net unamortized discount on debt (508) (550)
-------- --------
Long-term debt due within one year (6,541) (8,401)
-------- --------
Total long-term debt 287,689 289,305
-------- --------
TOTAL CAPITALIZATION $628,875 $647,187
======== ========
<FN>
* Denotes variable rate issue with December 31, 1998 interest rate shown.
The accompanying Notes to Financial Statements are an integral
part of these statements.
PENNSYLVANIA POWER COMPANY
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
Accumulated
Other
Comprehensive Other Comprehensive
Income Number Par Paid-In Income Retained
(Note 3B) of Shares Value Capital (Note 3B) Earnings
------------- ---------- ------- ------- -------------- ---------
(Dollars in thousands)
Balance, January 1, 1996 6,290,000 $188,700 $(310) $(112) $ 83,642
Net income $40,587 40,587
Minimum liability for
unfunded retirement
benefits, net of $7,000
of income taxes 9 9
-------
Comprehensive income $40,596
=======
Cash dividends on common
stock (21,386)
Cash dividends on preferred
stock (4,626)
- -----------------------------------------------------------------------------------------------------
Balance, December 31, 1996 6,290,000 188,700 (310) (103) 98,217
Net income $31,472 31,472
Minimum liability for
unfunded retirement
benefits, net of $9,000
of income taxes 13 13
-------
Comprehensive income $31,485
=======
Cash dividends on common
stock (21,386)
Cash dividends on preferred
stock (4,626)
- ------------------------------------------------------------------------------------------------------
Balance, December 31, 1997 6,290,000 188,700 (310) (90) 103,677
Net income $ 9,226 9,226
Transfer of minimum liability
for unfunded retirement
benefits to FirstEnergy 90 90
-------
Comprehensive income $ 9,316
=======
Cash dividends on common
stock (21,386)
Cash dividends on preferred
stock (4,626)
- ------------------------------------------------------------------------------------------------------
Balance, December 31, 1998 6,290,000 $188,700 $(310) $ -- $ 86,891
======================================================================================================
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, 1996 509,049 $50,905 150,000 $15,000
- -----------------------------------------------------------------------------
Balance, December 31, 1996 509,049 50,905 150,000 15,000
- -----------------------------------------------------------------------------
Balance, December 31, 1997 509,049 50,905 150,000 15,000
- -----------------------------------------------------------------------------
Balance, December 31, 1998 509,049 $50,905 150,000 $15,000
=============================================================================
<FN>
The accompanying Notes to Financial Statements are an integral
part of these statements.
PENNSYLVANIA POWER COMPANY
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1998 1997 1996
- ------------------------------------------------------------------------------------------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 9,226 $31,472 $ 40,587
Adjustments to reconcile net income to net cash from
operating activities:
Provision for depreciation and amortization 59,264 64,628 57,114
Nuclear fuel and lease amortization 5,418 7,172 8,693
Other amortization, net (330) (1,187) (1,700)
Deferred income taxes, net (20,007) (6,631) 396
Investment tax credits, net (2,289) (2,331) (2,138)
Deferred fuel costs, net -- -- 3,220
Extraordinary item 51,730 -- --
Receivables (20,680) 6,515 (1,193)
Materials and supplies (542) (704) 1,319
Accounts payable 3,293 (4,476) (2,472)
Other 3,148 (5,707) (12,087)
-------- ------- --------
Net cash provided from operating activities 88,231 88,751 91,739
-------- ------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt 1,563 9,942 --
Redemptions and Repayments-
Long-term debt 6,088 39,464 84,347
Dividend Payments-
Common stock 21,386 21,386 21,386
Preferred stock 4,626 4,626 4,626
-------- ------- --------
Net cash used for financing activities 30,537 55,534 110,359
-------- ------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions 16,495 14,513 20,361
Loan to parent 32,500 15,000 --
Loan payment from parent -- -- (19,500)
Other 1,874 4,431 116
-------- ------- --------
Net cash used for investing activities 50,869 33,944 977
-------- ------- --------
Net increase (decrease) in cash and cash equivalents 6,825 (727) (19,597)
Cash and cash equivalents at beginning of year 660 1,387 20,984
-------- ------- --------
Cash and cash equivalents at end of year $ 7,485 $ 660 $ 1,387
======== ======= ========
SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash paid during the year-
Interest (net of amounts capitalized) $ 19,057 $21,137 $ 26,653
======== ======= ========
Income taxes $ 32,290 $38,324 $ 36,815
======== ======= ========
<FN>
The accompanying Notes to Financial Statements are an integral part
of these statements.
PENNSYLVANIA POWER COMPANY
STATEMENT OF TAXES
For the Years Ended December 31, 1998 1997 1996
- ----------------------------------------------------------------------------------------------
(In thousands)
GENERAL TAXES:
State gross receipts $ 10,830 $ 11,267 $ 12,305
Real and personal property 6,893 6,060 6,178
State capital stock 2,774 2,566 2,820
Social security and unemployment 1,894 2,224 2,064
Other 149 262 648
-------- -------- --------
Total general taxes $ 22,540 $ 22,379 $ 24,015
======== ======== ========
PROVISION FOR INCOME TAXES:
Currently payable-
Federal $ 25,938 $ 27,560 $ 27,282
State 7,654 8,061 7,881
-------- -------- --------
33,592 35,621 35,163
-------- -------- --------
Deferred, net-
Federal (15,454) (5,096) 272
State (4,553) (1,535) 124
-------- -------- --------
(20,007) (6,631) 396
-------- -------- --------
Investment tax credit amortization (2,289) (2,331) (2,138)
-------- -------- --------
Total provision for income taxes $ 11,296 $ 26,659 $ 33,421
======== ======== ========
INCOME STATEMENT CLASSIFICATION OF
PROVISION FOR INCOME TAXES:
Operating expenses $ 31,794 $ 25,555 $ 29,907
Other income 710 1,104 3,514
Extraordinary item (21,208) -- --
-------- -------- --------
Total provision for income taxes $ 11,296 $ 26,659 $ 33,421
======== ======== ========
RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT
STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES:
Book income before provision for income taxes $ 20,522 $ 58,131 $ 74,008
======== ======== ========
Federal income tax expense at statutory rate $ 7,183 $ 20,346 $ 25,903
Increases (reductions) in taxes resulting from:
State income taxes, net of federal income tax benefit 2,016 4,242 5,203
Amortization of investment tax credits (2,289) (2,331) (2,138)
Amortization of tax regulatory assets 4,745 4,554 4,423
Other, net (359) (152) 30
-------- -------- --------
Total provision for income taxes $ 11,296 $ 26,659 $ 33,421
======== ======== ========
ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31:
Competitive transition charge $135,730 $ -- $ --
Property basis differences 69,867 172,094 178,886
Allowance for equity funds used during construction 7,219 29,875 33,677
Deferred nuclear expense -- 7,163 8,031
Customer receivables for future income taxes 9,690 37,954 40,901
Unamortized investment tax credits (3,193) (10,681) (11,635)
Other (6,886) 3,547 3,916
-------- -------- --------
Net deferred income tax liability $212,427 $239,952 $253,776
======== ======== ========
<FN>
The accompanying Notes to Financial Statements are an integral
part of these statements.
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
The Company, a wholly owned subsidiary of Ohio Edison Company
(Edison), follows the accounting policies and practices prescribed by
the Pennsylvania Public Utility Commission (PPUC) and the Federal Energy
Regulatory Commission (FERC). The preparation of financial statements in
conformity with generally accepted accounting principles requires
management to make periodic estimates and assumptions that affect the
reported amounts of assets, liabilities, revenues and expenses. Certain
prior year amounts have been reclassified to conform with the current
year presentation.
REVENUES-
The Company's principal business is providing electric
service to customers in 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, 1998 or 1997, with respect
to any particular segment of the Company's customers.
REGULATORY PLAN-
In June 1998, the PPUC authorized a rate restructuring plan
for the Company, which superseded the regulatory plan which had been in
place for the Company since 1996, and essentially resulted in the
deregulation of the Company's generation business as of June 30, 1998.
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 Securities and Exchange
Commission (SEC) issued interpretive guidance regarding asset
impairment measurement which concluded 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 a CTC over a
seven-year transition period; the remaining net amount of $78 million
was written off. The charge of $51.7 million ($30.5 million after
income taxes) for discontinuing the application of Statement of
Financial Accounting Standards (SFAS) No. 71, "Accounting for the
Effects of Certain Types of Regulation" (SFAS 71), to the Company's
generation business was recorded as an extraordinary item on the
Statement of Income. The Company's net assets included in utility plant
relating to the operations for which the application of SFAS 71 was
discontinued were $146 million as of December 31, 1998.
All of the Company's regulatory assets are being recovered
under provisions of the regulatory plan. In addition, the PPUC had
authorized the Company to accelerate at least $358 million, more than
the amounts that would have been recognized if the regulatory plan was
not in effect. These additional amounts are being recovered through
current rates. As of December 31, 1998, the Company's cumulative
additional capital recovery and regulatory asset amortization amounted
to $184 million (including the impairment discussed above).
In December 1996, Pennsylvania enacted "The Electricity
Generation Customer Choice and Competition Act," which permitted
customers, including the Company's customers, to choose their electric
generation supplier, while transmission and distribution services will
continue to be supplied by their current providers. Customer choice will
be phased in over two years with 66% of each customer class able to
choose alternative suppliers of generation on January 2, 1999, and all
remaining customers having choice as of January 2, 2000. Under the rate
restructuring plan, the Company continues to deliver power to homes and
businesses through its transmission and distribution system, which
remains regulated by the PPUC. The Company's rates have been
restructured to establish separate charges for transmission and
distribution; generation, which is subject to competition; and stranded
cost recovery. In the event customers obtain power from an alternative
source, the generation portion of the Company's rates will be excluded
from their bill and the customers will 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. The Company is entitled to recover $234 million of stranded
costs through a CTC that starts in 1999 and ends in 2005.
UTILITY PLANT AND DEPRECIATION-
Utility plant reflects the original cost of construction
(except for nuclear generating units which were adjusted to fair value
as discussed above), including payroll and related costs such as taxes,
employee benefits, administrative and general costs, and interest costs.
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 3.0% in 1998 and 2.7% in 1997 and 1996. In addition to the
straight-line depreciation recognized in 1998, 1997 and 1996, the
Company also recognized additional capital recovery of $15 million,
$27 million and $20 million, respectively, as additional depreciation
expense in accordance with the regulatory plan.
Annual depreciation expense includes approximately
$3.1 million for future decommissioning costs applicable to the
Company's ownership interest in two nuclear generating units. The
Company's share of the future obligation to decommission these units is
approximately $88 million in current dollars and (using a 4.0%
escalation rate) approximately $205 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 $12 million for decommissioning through its
electric rates from customers through December 31, 1998. If the actual
costs of decommissioning the units exceed the funds accumulated from
investing amounts recovered from customers, the Company expects that
additional amount to be recoverable from its customers. The Company has
approximately $13.7 million invested in external decommissioning trust
funds as of December 31, 1998. Earnings on these funds are reinvested
with a corresponding increase to the decommissioning liability. The
Company has also recognized an estimated liability of approximately
$3.0 million at December 31, 1998 related to decontamination and
decommissioning of nuclear enrichment facilities operated by the United
States Department of Energy (DOE), as required by the Energy Policy Act
of 1992.
The Financial Accounting Standards Board (FASB) issued a
proposed accounting standard for nuclear decommissioning costs in 1996.
If the standard is adopted as proposed: (1) annual provisions for
decommissioning could increase; (2) the net present value of estimated
decommissioning costs could be recorded as a liability; and (3) income
from the external decommissioning trusts could be reported as investment
income. The FASB subsequently expanded the scope of the proposed
standard to include other closure and removal obligations related to
long-lived assets. A revised proposal may be issued by the FASB in 1999.
COMMON OWNERSHIP OF GENERATING FACILITIES-
The Company and other Central Area Power Coordination Group
(CAPCO) companies 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, 1998, include
the following:
Utility Accumulated Construction Company's
Generating Plant Provision for Work in Ownership
Units in Service Depreciation Progress Interest
- ---------------------------------------------------------------------------
(In millions)
W. H. Sammis #7 $ 57.8 $21.8 $0.3 20.80%
Bruce Mansfield
#1, #2 and #3 98.9 47.3 0.6 5.76%
Beaver Valley #1 18.6 1.2 2.2 17.50%
Perry #1 1.5 0.6 1.1 5.24%
- --------------------------------------------------------------------------
Total $176.8 $70.9 $4.2
==========================================================================
On October 15, 1998, FirstEnergy Corp. (FirstEnergy) the
parent company of Edison, announced that it signed an agreement in
principle with Duquesne Light Company (Duquesne) that would result in
the transfer of 1,436 megawatts owned by Duquesne at eight CAPCO
generating units in exchange for 1,328 megawatts at three non-CAPCO
power plants owned by the Company, Edison and The Cleveland Electric
Illuminating Company, an affiliate. As part of this exchange, the
Company will transfer its 339-megawatt New Castle Plant and its 4-
megawatt interest in the Niles Plant to Duquesne. A definitive
agreement on the exchange of assets, which will be structured as a
tax-free transaction to the extent possible, will provide
FirstEnergy's utility operating companies with exclusive ownership
and operating control of all CAPCO generating units. Duquesne will
fund decommissioning costs equal to its percentage interest in the
three nuclear generating units to be transferred. The asset transfer
is expected to take twelve to eighteen months to close.
NUCLEAR FUEL-
OES Fuel, Incorporated (OES Fuel), a wholly owned subsidiary
of Edison, is the sole lessor for the Company's nuclear fuel
requirements.
Minimum lease payments during the next five years are
estimated to be as follows:
(In millions)
- -------------------------------
1999 $6.3
2000 3.6
2001 2.2
2002 1.2
2003 0.2
- ------------------------------
The Company amortizes the cost of nuclear fuel based on the
rate of consumption. The Company's electric rates include amounts for
the future disposal of spent nuclear fuel based upon the formula used
to compute payments to the DOE.
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. Since Edison
became a wholly owned subsidiary of FirstEnergy on November 8, 1997,
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.
RETIREMENT BENEFITS-
The Company's trusteed, noncontributory defined benefit
pension plan covers almost all full-time employees. Upon retirement,
employees receive a monthly pension based on length of service and
compensation. In 1998, the Company's, Edison's and Centerior Energy
Corporation pension plans were merged into the FirstEnergy pension
plans. 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, 1998. The assets of the pension
plans 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 deductibles and copayments, are also available to retired
employees, their dependents and, under certain circumstances, their
survivors. The Company pays insurance premiums to cover a portion of
these benefits in excess of set limits; all amounts up to the limits
are paid by the Company. The Company recognizes the expected cost of
providing other postretirement benefits to employees and their
beneficiaries and covered dependents from the time employees are
hired until they become eligible to receive those benefits.
The following sets forth the funded status of the
FirstEnergy plans in 1998 and the Company's plans in 1997 and amounts
recognized on the Balance Sheets as of December 31 (which includes
the Company's share of the FirstEnergy 1998 plans' net prepaid
pension cost and accrued other postretirement benefits costs of $9.0
million and $28.4 million, respectively):
Other
Pension Benefits Postretirement Benefits
---------------- -----------------------
1998 1997 1998 1997
- --------------------------------------------------------------------------------------------------
(In millions)
Change in benefit obligation:
Benefit obligation as of January 1* $1,327.5 $122.8 $ 534.1 $ 43.7
Service cost 25.0 2.7 7.5 0.9
Interest cost 92.5 8.9 37.6 3.2
Plan amendments 44.3 0.5 40.1 --
Early retirement program expense -- 5.8 -- 0.3
Actuarial loss 101.6 10.1 10.7 1.5
Benefits paid (90.8) (8.4) (28.7) (2.3)
- ---------------------------------------------------------------------------------------------
Benefit obligation as of December 31 1,500.1 142.4 601.3 47.3
- ---------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets as of January 1* 1,542.5 150.5 2.8 0.2
Actual return on plan assets 231.3 30.0 0.7 0.1
Company contribution -- -- 0.4 --
Benefits paid (90.8) (8.4) -- --
- ---------------------------------------------------------------------------------------------
Fair value of plan assets as of December 31 1,683.0 172.1 3.9 0.3
- ---------------------------------------------------------------------------------------------
Funded status of plan* 182.9 29.7 (597.4) (47.0)
Unrecognized actuarial loss (gain) (110.8) (25.7) 30.6 4.3
Unrecognized prior service cost 63.0 4.2 27.4 (4.0)
Unrecognized net transition obligation (asset) (18.0) (5.3) 129.3 21.4
- ---------------------------------------------------------------------------------------------
Prepaid (accrued) benefit cost $ 117.1 $ 2.9 $(410.1) $(25.3)
=============================================================================================
Assumptions used as of December 31:
Discount rate 7.00% 7.25% 7.00% 7.25%
Expected long-term return on plan assets 10.25% 10.00% 10.25% 10.00%
Rate of compensation increase 4.00% 4.00% 4.00% 4.00%
<FN>
* 1998 beginning balances reflect 1998 merger of the Company's,
Edison's and Centerior plans into FirstEnergy plans.
Net pension and other postretirement benefit costs for the
three years ended December 31, 1998 (including the Company's share of
FirstEnergy plans' 1998 pension benefits costs and other
postretirement benefit costs of $(6.1) million and $5.4 million,
respectively) were computed as follows:
Other
Pension Benefits Postretirement Benefits
-------------------- ----------------------
1998 1997 1996 1998 1997 1996
- ---------------------------------------------------------------------------------------------
(In millions)
Service cost $ 25.0 $ 2.7 $ 3.2 $ 7.5 $0.9 $ 1.1
Interest cost 92.5 8.9 9.5 37.6 3.2 3.2
Expected return on plan assets (152.7) (14.7) (12.3) (0.3) -- --
Amortization of transition obligation
(asset) (8.0) (1.0) (1.0) 9.2 1.2 1.7
Amortization of prior service cost 2.3 0.4 0.4 (0.8) -- (0.3)
Recognized net actuarial gain (2.6) (0.4) -- -- -- --
Voluntary early retirement program
expense -- 5.8 -- -- 0.3 --
Plan curtailment loss (gain) -- -- (4.3) -- -- 3.5
- -------------------------------------------------------------------------------------------
Net benefit cost $ (43.5) $ 1.7 $ (4.5) $53.2 $5.6 $ 9.2
============================================================================================
In accordance with SFAS 88 "Employers' Accounting for
Settlements and Curtailments of Defined Benefit Pension Plans and for
Termination Benefits," the 1996 net pension costs and postretirement
benefit costs shown above included curtailment effects (significant
changes in projected plan assumptions) relating to the pension and
postretirement benefit plans. The employee terminations reflected in
the Company's 1996 restructuring activities represented a plan
curtailment that significantly reduced the expected future employee
service years and the related accrual of defined pension and
postretirement benefits. In the pension plan, the reduction in the
benefit obligation increased the net pension asset and was shown as a
plan curtailment gain. In the postretirement benefit plan, the
unrecognized prior service cost associated with service years no
longer expected to be rendered as a result of the terminations, was
shown as a plan curtailment loss.
The FirstEnergy plans' health care trend rate assumption is
5.5% in the first year gradually decreasing to 4.0% for the year 2008
and later. Assumed health care cost trend rates have a significant
effect on the amounts reported for the health care plan. An increase
in the health care trend rate assumption by one percentage point would
increase the total service and interest cost components by $4.0
million and the postretirement benefit obligation by $68.1 million. A
decrease in the same assumption by one percentage point would decrease
the total service and interest cost components by $3.2 million and the
postretirement benefit obligation by $55.2 million.
TRANSACTIONS WITH AFFILIATED COMPANIES-
Transactions with affiliated companies are included on the
Statements of Income as follows:
1998 1997 1996
- -------------------------------------------------------------------
(In millions)
Operating revenues:
Electric sales $ 9.8 $ 6.1 $ 3.6
Bruce Mansfield Plant administrative
and general charges to affiliates 6.3 0.9 --
Other transactions 0.7 0.4 0.4
- -------------------------------------------------------------------
$16.8 $ 7.4 $ 4.0
===================================================================
Fuel and purchased power:
Purchased power $20.9 $12.7 $13.2
Nuclear fuel leased from OES Fuel 5.9 7.5 9.6
- -------------------------------------------------------------------
$26.8 $20.2 $22.8
===================================================================
Other operating costs:
Rental of transmission lines $ 1.3 $ 1.0 $ 1.0
Data processing services 2.8 2.9 2.5
Other transactions 5.4 4.4 3.9
- -------------------------------------------------------------------
$ 9.5 $ 8.3 $ 7.4
===================================================================
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. The Company reflects temporary cash investments
at cost, which approximates their market value. Noncash financing and
investing activities included capital lease transactions amounting to
$0.8 million, $8.5 million and $4.1 million for the years 1998, 1997
and 1996, respectively.
All borrowings with initial maturities of less than one year
are defined as financial instruments under generally accepted
accounting principles 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:
1998 1997
- --------------------------------------------------------------------
Carrying Fair Carrying Fair
Value Value Value Value
- --------------------------------------------------------------------
(In millions)
Long-term debt $278 $294 $277 $291
Preferred stock 15 16 15 15
Investments other than cash
and cash equivalents 17 21 14 15
- --------------------------------------------------------------------
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 a corporation 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.
Unrealized gains and losses applicable to the decommissioning trust
have been recognized in the trust investment with a corresponding
change to the decommissioning liability. The Company has no
securities held for trading purposes.
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 being
recovered from customers under the Company's regulatory plan. Based
on the regulatory plan, at this time, the Company believes it will
continue to be able to bill and collect cost-based rates relating to
the Company's nongeneration operations; accordingly, it is
appropriate that the Company continues the application of SFAS 71
relating to those operations. The Company recognized additional cost
recovery of $24 million, $11 million and $8 million in 1998, 1997 and
1996, respectively, as additional regulatory asset amortization in
accordance with its regulatory plan. Regulatory assets on the Balance
Sheets are comprised of the following:
1998 1997
- -------------------------------------------------------------------
(In millions)
Competitive transition charge $331.0 $ --
Customer receivables for future income taxes 23.6 92.6
Nuclear unit expenses -- 17.5
Perry Unit 2 termination -- 36.7
Loss on reacquired debt 8.2 9.2
DOE decommissioning and decontamination costs 0.3 3.6
Employee postretirement benefit costs 6.2 --
Other 1.7 3.4
- -------------------------------------------------------------------
Total $371.0 $163.0
===================================================================
2. LEASES
The Company leases certain transmission facilities, 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, 1998, are summarized as follows:
1998 1997 1996
- -----------------------------------------------------
(In millions)
Operating leases
Interest element $0.5 $0.5 $0.5
Other 1.3 1.5 1.3
Capital leases
Interest element 0.6 0.7 0.7
Other 0.7 0.8 0.9
- ---------------------------------------------------
Total rental payments $3.1 $3.5 $3.4
===================================================
The future minimum lease payments as of December 31, 1998,
are:
Capital Operating
Leases Leases
- ------------------------------------------------------------------
(In millions)
1999 $ 1.3 $0.2
2000 1.2 0.2
2001 1.0 0.2
2002 1.0 0.2
2003 0.9 0.2
Years thereafter 9.6 3.0
- --------------------------------------------------------------
Total minimum lease payments 15.0 $4.0
====
Executory costs 3.1
- -----------------------------------------------
Net minimum lease payments 11.9
Interest portion 7.3
- -----------------------------------------------
Present value of net minimum
lease payments 4.6
Less current portion 0.5
- -----------------------------------------------
Noncurrent portion $ 4.1
===============================================
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 $75.3 million at December 31, 1998.
(B) COMPREHENSIVE INCOME-
In 1998, the Company adopted SFAS 130, "Reporting
Comprehensive Income," and applied the standard to all periods
presented in the Statements of Common Stockholder's Equity.
Comprehensive income includes net income as reported on the
Statements of Income and all other changes in common stockholder's
equity except dividends to stockholders.
(C) PREFERRED STOCK-
The Company's 7.75% series of preferred stock has
restrictions which prevent 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 beginning on October 1, 2002.
(E) LONG-TERM DEBT-
The first mortgage indenture and its supplements, which
secure all of the Company's first mortgage bonds, serve as a direct
first mortgage lien on substantially all property and franchises,
other than specifically excepted property, owned by the Company.
Long-term debt maturities (excluding capital leases) during the next
five years are $0.5 million in 1999, $24.0 million in 2000,
$1.0 million in 2001, $1.0 million in 2002 and $41.0 million in
2003.
The Company's obligations to repay certain pollution
control revenue bonds are secured by series of first mortgage bonds
and, in some cases, by subordinate liens on the related pollution
control facilities.
4. SHORT-TERM BORROWINGS:
The Company has a credit agreement with Edison whereby
either company can borrow funds from the other by issuing unsecured
notes at the prevailing prime or similar interest rate. Under the
terms of this agreement, the maximum borrowing is limited only by the
availability of funds; however, the Company's borrowing under this
agreement is currently limited by the PPUC to a total of $50 million.
Either company can terminate the agreement with six months' notice.
5. COMMITMENTS, GUARANTEES AND CONTINGENCIES:
CAPITAL EXPENDITURES-
The Company's current forecast reflects expenditures of
approximately $167 million for property additions and improvements
from 1999 through 2003, of which approximately $28 million is
applicable to 1999. Investments for additional nuclear fuel during
the 1999-2003 period are estimated to be approximately $28 million,
of which approximately $3 million applies to 1999. During the same
periods, the Company's nuclear fuel investments are expected to be
reduced by approximately $29 million and $6 million, respectively, as
the nuclear fuel is consumed.
NUCLEAR INSURANCE-
The Price-Anderson Act limits the public liability relative
to a single incident at a nuclear power plant to $9.7 billion. The
amount is covered by a combination of private insurance and an
industry retrospective rating plan. Based on its present ownership
interests in Beaver Valley Unit 1 and the Perry Plant, the Company's
maximum potential assessment under the industry retrospective rating
plan (assuming the other co-owners contribute their proportionate
shares of any assessments under the retrospective rating plan) would
be $20 million per incident but not more than $2.3 million in any one
year for each incident.
The Company is also insured as to its interest in Beaver
Valley Unit 1 and the Perry Plant 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
$69.5 million of insurance coverage for replacement power costs for
its interests in Perry and Beaver Valley Unit 1. Under these
policies, the Company can be assessed a maximum of approximately
$2.8 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.
GUARANTEE-
The Company, together with the other CAPCO companies, has
severally guaranteed certain debt and lease obligations in connection
with a coal supply contract for the Bruce Mansfield Plant. As of
December 31, 1998, the Company's share of the guarantee (which
approximates fair market value) was $3.6 million. The price under the
coal supply contract, which includes certain minimum payments, has
been determined to be sufficient to satisfy the debt and lease
obligations. The Company's total payments under the coal supply
contract were $15.0 million, $13.3 million and $11.1 million during
1998, 1997, and 1996, respectively. The Company's minimum payment for
1999 is approximately $4 million. The contract expires December 31,
1999.
ENVIRONMENTAL MATTERS-
Various federal, state and local authorities regulate the
Company with regard to air and water quality and other environmental
matters. The Company has estimated additional capital expenditures
for environmental compliance of approximately $47 million, which is
included in the construction forecast provided under "Capital
Expenditures" for 1999 through 2003.
The Company is in compliance with the current sulfur dioxide
(SO2) and nitrogen oxides (NOx) reduction requirements under the Clean
Air Act Amendments of 1990. SO2 reductions in 1999 will be achieved by
burning lower-sulfur fuel, generating more electricity from lower-
emitting plants, and/or purchasing emission allowances. Plans for
complying with reductions required for the year 2000 and thereafter
have not been finalized. In September 1998, the Environmental
Protection Agency (EPA) finalized regulations requiring additional NOx
reductions from the Company's Pennsylvania facilities by May 2003. The
EPA's NOx Transport Rule imposes uniform reductions of NOx emissions
across a region of twenty-two 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. By September 1999, each of the twenty-two
states are required to submit revised State Implementation Plans (SIP)
which comply with individual state NOx budgets established by the EPA.
These state NOx budgets contemplate an 85% reduction in utility plant
NOx emissions from 1990 emissions. A proposed Federal Implementation
Plan accompanied the NOx Transport Rule and may be implemented by the
EPA in states which fail to revise their SIP. In another separate but
related action, eight states filed petitions with the EPA under
Section 126 of the Clean Air Act seeking reductions of NOx emissions
which are alleged to contribute to ozone pollution in the eight
petitioning states. The EPA suggests that the Section 126 petitions
will be adequately addressed by the NOx Transport Program, but a
September 1998 proposed rulemaking established an alternative program
which would require nearly identical 85% NOx reductions at the
Company's Ohio and Pennsylvania plants by May 2003 in the event
implementation of the NOx Transport Rule is delayed. FirstEnergy
continues to evaluate its compliance plans and other compliance
options and currently estimates its additional capital expenditures
for NOx reductions may reach $500 million.
The Company is required to meet federally approved SO2
regulations. Violations of such regulations can result in shutdown of
the generating unit involved and/or civil or criminal penalties of up
to $25,000 for each day the 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. The Company cannot
predict what action the EPA may take in the future with respect to
the interim enforcement policy.
In July 1997, the EPA promulgated changes in the National
Ambient Air Quality Standard (NAAQS) for ozone and proposed a new
NAAQS for previously unregulated ultra-fine particulate matter. The
cost of compliance with these regulations may be substantial and
depends on the manner in which they are implemented by the states in
which the Company operates affected facilities.
Legislative, administrative and judicial actions will
continue to change the way that the Company must operate in order to
comply with environmental laws and regulations. With respect to any
such changes and to the environmental matters described above, the
Company expects that any resulting additional capital costs which may
be required, as well as any required increase in operating costs,
would ultimately be reflected in its generation supply prices.
6. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
The following summarizes certain operating results by
quarter for 1998 and 1997.
March 31, June 30, September 30, December 31,
Three Months Ended 1998 1998 1998 1998
- -------------------------------------------------------------------------------------------
(In millions)
Operating Revenues $78.5 $ 80.3 $87.9 $77.0
Operating Expenses and Taxes 65.9 70.3 71.5 58.0
- ----------------------------------------------------------------------------------------
Operating Income 12.6 10.0 16.4 19.0
Other Income 0.7 0.6 0.6 0.6
Net Interest Charges 5.4 5.2 5.2 5.1
- ----------------------------------------------------------------------------------------
Income Before Extraordinary Item 7.9 5.4 11.8 14.5
Extraordinary Item (Net of Income Taxes)
(Note 1) -- (30.5) -- --
Net Income (Loss) $ 7.9 $(25.1) $11.8 $14.5
========================================================================================
Earnings (Loss) on Common Stock $ 6.8 $(26.2) $10.7 $13.3
========================================================================================
March 31, June 30, September 30, December 31,
Three Months Ended 1997 1997 1997 1997
- --------------------------------------------------------------------------------------------
(In millions)
Operating Revenues $79.0 $79.2 $85.2 $79.9
Operating Expenses and Taxes 65.4 66.2 69.6 71.4
- ----------------------------------------------------------------------------------------
Operating Income 13.6 13.0 15.6 8.5
Other Income 0.7 0.3 0.8 0.9
Net Interest Charges 5.7 5.5 5.5 5.2
- ----------------------------------------------------------------------------------------
Net Income $ 8.6 $ 7.8 $10.9 $ 4.2
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Earnings on Common Stock $ 7.4 $ 6.6 $ 9.7 $ 3.1
=========================================================================================
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, 1998
and 1997, 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, 1998. 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 generally accepted auditing
standards. 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, 1998 and 1997, and the results of its operations
and its cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting
principles.
ARTHUR ANDERSEN LLP
Cleveland, Ohio
February 12, 1999