10-Q 1 main10-q.htm FORM 10-Q DATED NOVEMBER 2, 2005 Form 10-Q dated November 1, 2005

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549

FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2005

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the transition period from
 
to
 

Commission
Registrant; State of Incorporation;
I.R.S. Employer
File Number
Address; and Telephone Number
Identification No.
     
333-21011
FIRSTENERGY CORP.
34-1843785
 
(An Ohio Corporation)
 
 
76 South Main Street
 
 
Akron, OH 44308
 
 
Telephone (800)736-3402
 
     
1-2578
OHIO EDISON COMPANY
34-0437786
 
(An Ohio Corporation)
 
 
c/o FirstEnergy Corp.
 
 
76 South Main Street
 
 
Akron, OH 44308
 
 
Telephone (800)736-3402
 
     
1-2323
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
34-0150020
 
(An Ohio Corporation)
 
 
c/o FirstEnergy Corp.
 
 
76 South Main Street
 
 
Akron, OH 44308
 
 
Telephone (800)736-3402
 
     
1-3583
THE TOLEDO EDISON COMPANY
34-4375005
 
(An Ohio Corporation)
 
 
c/o FirstEnergy Corp.
 
 
76 South Main Street
 
 
Akron, OH 44308
 
 
Telephone (800)736-3402
 
     
1-3491
PENNSYLVANIA POWER COMPANY
25-0718810
 
(A Pennsylvania Corporation)
 
 
c/o FirstEnergy Corp.
 
 
76 South Main Street
 
 
Akron, OH 44308
 
 
Telephone (800)736-3402
 
     
1-3141
JERSEY CENTRAL POWER & LIGHT COMPANY
21-0485010
 
(A New Jersey Corporation)
 
 
c/o FirstEnergy Corp.
 
 
76 South Main Street
 
 
Akron, OH 44308
 
 
Telephone (800)736-3402
 
     
1-446
METROPOLITAN EDISON COMPANY
23-0870160
 
(A Pennsylvania Corporation)
 
 
c/o FirstEnergy Corp.
 
 
76 South Main Street
 
 
Akron, OH 44308
 
 
Telephone (800)736-3402
 
     
1-3522
PENNSYLVANIA ELECTRIC COMPANY
25-0718085
 
(A Pennsylvania Corporation)
 
 
c/o FirstEnergy Corp.
 
 
76 South Main Street
 
 
Akron, OH 44308
 
 
Telephone (800)736-3402
 

 
 


Indicate by check mark whether each of the registrants (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes X   No   

Indicate by check mark whether each registrant is an accelerated filer (as defined in Rule 12b-2 of the Act):

YesX  
No    
FirstEnergy Corp.
Yes    
No
Ohio Edison Company, Pennsylvania Power Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company, and Pennsylvania Electric Company

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:
 
 
 
OUTSTANDING
CLASS
AS OF NOVEMBER 2, 2005
FirstEnergy Corp., $.10 par value
329,836,276
Ohio Edison Company, no par value
100
The Cleveland Electric Illuminating Company, no par value
79,590,689
The Toledo Edison Company, $5 par value
39,133,887
Pennsylvania Power Company, $30 par value
6,290,000
Jersey Central Power & Light Company, $10 par value
15,371,270
Metropolitan Edison Company, no par value
859,500
Pennsylvania Electric Company, $20 par value
5,290,596
 

FirstEnergy Corp. is the sole holder of Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company common stock. Ohio Edison Company is the sole holder of Pennsylvania Power Company common stock.

This combined Form 10-Q is separately filed by FirstEnergy Corp., Ohio Edison Company, Pennsylvania Power Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. No registrant makes any representation as to information relating to any other registrant, except that information relating to any of the FirstEnergy subsidiary registrants is also attributed to FirstEnergy Corp.

This Form 10-Q includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements typically contain, but are not limited to, the terms "anticipate", "potential", "expect", "believe", "estimate" and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, replacement power costs being higher than anticipated or inadequately hedged, the continued ability of our regulated utilities to collect transition and other charges, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), the uncertainty of the timing and amounts of the capital expenditures (including that such amounts could be higher than anticipated) or levels of emission reductions related to the settlement agreement resolving the New Source Review litigation, adverse regulatory or legal decisions and outcomes (including, but not limited to, the revocation of necessary licenses or operating permits, fines or other enforcement actions and remedies) of government investigations and oversight, including by the Securities and Exchange Commission, the United States Attorney’s Office and the Nuclear Regulatory Commission as disclosed in the registrants’ Securities and Exchange Commission filings, generally, and with respect to the Davis-Besse Nuclear Power Station outage and heightened scrutiny at the Perry Nuclear Power Plant in particular, the availability and cost of capital, rising interest rates and other inflationary trends, the continuing availability and operation of generating units, the ability of generating units to continue to operate at, or near full capacity, the inability to accomplish or realize anticipated benefits of strategic goals (including the proposed transfer of nuclear generation assets), the ability to improve electric commodity margins and to experience growth in the distribution business, any decision of the Pennsylvania Public Utility Commission regarding the plan filed by Penn on October 11, 2005 to secure electricity supply for its customers at a set rate, the ability to access the public securities and other capital markets, the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to the August 14, 2003 regional power outage, the final outcome in the proceeding related to FirstEnergy's Application for a Rate Stabilization Plan (RSP) in Ohio, specifically, the PUCO's acceptance of the September 9, 2005 proposed supplement to the RSP, the risks and other factors discussed from time to time in the registrants' Securities and Exchange Commission filings, including their annual report on Form 10-K for the year ended December 31, 2004, and other similar factors. A security rating is not a recommendation to buy, sell or hold securities and it may be subject to revision or withdrawal. Dividends declared from time to time on FirstEnergy's common stock during any annual period may in aggregate vary from the indicated amounts due to circumstances considered by FirstEnergy's Board of Directors at the time of the actual declarations. The registrants expressly disclaim any current intention to update any forward-looking statements contained in this document as a result of new information, future events, or otherwise.




 

TABLE OF CONTENTS


   
Pages
Glossary of Terms
iii-v
     
Part I. Financial Information
 
     
Items 1. and 2. - Financial Statements and Management’s Discussion and Analysis of
            Results of Operation and Financial Condition
 
     
 
Notes to Consolidated Financial Statements
1-25
     
FirstEnergy Corp.
 
     
 
Consolidated Statements of Income
26
 
Consolidated Statements of Comprehensive Income
27
 
Consolidated Balance Sheets
28
 
Consolidated Statements of Cash Flows
29
 
Report of Independent Registered Public Accounting Firm
30
 
Management's Discussion and Analysis of Results of Operations and
31-65
 
Financial Condition
 
     
Ohio Edison Company
 
     
 
Consolidated Statements of Income and Comprehensive Income
66
 
Consolidated Balance Sheets
67
 
Consolidated Statements of Cash Flows
68
 
Report of Independent Registered Public Accounting Firm
69
 
Management's Discussion and Analysis of Results of Operations and
70-82
 
Financial Condition
 
     
The Cleveland Electric Illuminating Company
 
     
 
Consolidated Statements of Income and Comprehensive Income
83
 
Consolidated Balance Sheets
84
 
Consolidated Statements of Cash Flows
85
 
Report of Independent Registered Public Accounting Firm
86
 
Management's Discussion and Analysis of Results of Operations and
87-98
 
Financial Condition
 
     
The Toledo Edison Company
 
     
 
Consolidated Statements of Income and Comprehensive Income
99
 
Consolidated Balance Sheets
100
 
Consolidated Statements of Cash Flows
101
 
Report of Independent Registered Public Accounting Firm
102
 
Management's Discussion and Analysis of Results of Operations and
103-114
 
Financial Condition
 
     
Pennsylvania Power Company
 
     
 
Consolidated Statements of Income and Comprehensive Income
115
 
Consolidated Balance Sheets
116
 
Consolidated Statements of Cash Flows
117
 
Report of Independent Registered Public Accounting Firm
118
 
Management's Discussion and Analysis of Results of Operations and
119-127
 
Financial Condition
 



i



TABLE OF CONTENTS (Cont'd)


   
Pages
     
     
Jersey Central Power & Light Company
 
     
 
Consolidated Statements of Income and Comprehensive Income
128
 
Consolidated Balance Sheets
129
 
Consolidated Statements of Cash Flows
130
 
Report of Independent Registered Public Accounting Firm
131
 
Management's Discussion and Analysis of Results of Operations and
132-140
 
Financial Condition
 
     
Metropolitan Edison Company
 
     
 
Consolidated Statements of Income and Comprehensive Income
141
 
Consolidated Balance Sheets
142
 
Consolidated Statements of Cash Flows
143
 
Report of Independent Registered Public Accounting Firm
144
 
Management's Discussion and Analysis of Results of Operations and
145-153
 
Financial Condition
 
     
Pennsylvania Electric Company
 
     
 
Consolidated Statements of Income and Comprehensive Income
154
 
Consolidated Balance Sheets
155
 
Consolidated Statements of Cash Flows
156
 
Report of Independent Registered Public Accounting Firm
157
 
Management's Discussion and Analysis of Results of Operations and
158-166
 
Financial Condition
 
     
Item 3. Quantitative and Qualitative Disclosures About Market Risk
167
     
Item 4. Controls and Procedures
167
     
Part II. Other Information
 
     
Item 1. Legal Proceedings
168
   
168
Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities
 
     
      Item 5.  Other Information        
 168
   
      Item 6. Exhibits
169-184
   
   



ii


GLOSSARY OF TERMS

The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries:

ATSI
American Transmission Systems, Incorporated, owns and operates transmission facilities
CEI
The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
CFC
Centerior Funding Corporation, a wholly owned finance subsidiary of CEI
Companies
OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec
EUOC
Electric Utility Operating Companies (OE, CEI, TE, Penn, JCP&L, Met-Ed, Penelec, and ATSI)
FENOC
FirstEnergy Nuclear Operating Company, operates nuclear generating facilities
FES
FirstEnergy Solutions Corp., provides energy-related products and services
FESC
FirstEnergy Service Company, provides legal, financial, and other corporate support services
FGCO
FirstEnergy Generation Corp., owns and operates non-nuclear generating facilities
FirstCom
First Communications, LLC, provides local and long-distance telephone service
FirstEnergy
FirstEnergy Corp., a registered public utility holding company
FSG
FirstEnergy Facilities Services Group, LLC, the parent company of several heating, ventilation,
 
air conditioning and energy management companies
GPU
GPU, Inc., former parent of JCP&L, Met-Ed and Penelec, which merged with FirstEnergy on
 
November 7, 2001
JCP&L
Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
JCP&L Transition
JCP&L Transition Funding LLC, a Delaware limited liability company and issuer of transition  bonds
Met-Ed
Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
MYR
MYR Group, Inc., a utility infrastructure construction service company
NGC
FirstEnergy Nuclear Generation Corp. established to acquire FirstEnergy's nuclear generating  facilities
OE
Ohio Edison Company, an Ohio electric utility operating subsidiary
OE Companies
OE and Penn
Ohio Companies
CEI, OE and TE
Penelec
Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
Penn
Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
PNBV
PNBV Capital Trust, a special purpose entity created by OE in 1996
Shippingport
Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
TE
The Toledo Edison Company, an Ohio electric utility operating subsidiary
TEBSA
Termobarranquilla S. A., Empresa de Servicios Publicos

 

The following abbreviations and acronyms are used to identify frequently used terms in this report:


AOCL
Accumulated Other Comprehensive Loss
APB
Accounting Principles Board
APB 25
APB Opinion No. 25, "Accounting for Stock Issued to Employees"
APB 29
APB Opinion No. 29, “Accounting for Nonmonetary Transactions”
ARO
Asset Retirement Obligation
BGS
Basic Generation Service
CAIR
Clean Air Interstate Rule
CAL
Confirmatory Action Letter
CAT
Commercial Activity Tax
CO2
Carbon Dioxide
CTC
Competitive Transition Charge
DOJ
United States Department of Justice
ECAR
East Central Area Reliability Coordination Agreement
EITF
Emerging Issues Task Force
EITF 03-1
EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and Its Application to Certain
 
Investments”
EITF 04-13
EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same  Counterparty”
EITF 99-19
EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent”
EPA
Environmental Protection Agency
ERO
Electric Reliability Organization
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
FIN
FASB Interpretation
FIN 46R
FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities"

 
iii

 

FIN 47
FASB Interpretation 47, “Accounting for Conditional Asset Retirement Obligations - an  interpretation of FASB Statement No. 143”
FMBs
First Mortgage Bonds
FSP
FASB Staff Position
FSP EITF 03-1-1
FASB Staff Position No. EITF Issue 03-1-1, "Effective Date of Paragraphs 10-20 of EITF Issue
 
No. 03-1, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain
 
Investments"
FSP 109-1
FASB Staff Position No. 109-1, “Application of FASB Statement No. 109, Accounting for Income
  Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs
  Creation Act of 2004”
GCAF
Generation Charge Adjustment Factor
GAAP
Accounting Principles Generally Accepted in the United States
GHG
Greenhouse Gases
HVAC
Heating, Ventilation and Air-conditioning
IBEW
International Brotherhood of Electrical Workers
KWH
Kilowatt-hours
LOC
Letter of Credit
MEIUG
Met-Ed Industrial Users Group
MISO
Midwest Independent Transmission System Operator, Inc.
MOU
Memorandum of Understanding
MSG
Market Support Generation
MTC
Market Transition Charge
MW
Megawatts
NAAQS
National Ambient Air Quality Standards
NERC
North American Electric Reliability Council
NJBPU
New Jersey Board of Public Utilities
NOAC
Northwest Ohio Aggregation Coalition
NOV
Notices of Violation
NOx
Nitrogen Oxide
NRC
Nuclear Regulatory Commission
NUG
Non-Utility Generation
OCA
Office of Consumer Advocate
OCC
Ohio Consumers' Counsel
OCI
Other Comprehensive Income
OPAE
Ohio Partners for Affordable Energy
OPEB
Other Post-Employment Benefits
OSBA
Office of Small Business Advocate
OTS
Office of Trial Staff
PCAOB
Public Company Accounting Oversight Board (United States)
PCRBs
Pollution Control Revenue Bonds
PICA
Penelec Industrial Customer Association
PJM
PJM Interconnection, L.L.C.
PLR
Provider of Last Resort
PPUC
Pennsylvania Public Utility Commission
PRP
Potentially Responsible Party
PSA
Purchase and Sale Agreement
PUCO
Public Utilities Commission of Ohio
PUHCA
Public Utility Holding Company Act of 1935
RCP
Rate Certainty Plan
RSP
Rate Stabilization Plan
RTC
Regulatory Transition Charge
S&P
Standard & Poor’s Ratings Service
SBC
Societal Benefits Charge
SEC
United States Securities and Exchange Commission
SFAS
Statement of Financial Accounting Standards
SFAS 71
SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
SFAS 123
SFAS No. 123, "Accounting for Stock-Based Compensation"
SFAS 123(R)
SFAS No. 123 (revised 2004), “Share-Based Payment”
SFAS 131
SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information”
SFAS 133
SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 140
SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and
 
Extinguishment of Liabilities”
SFAS 144
SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets"
SFAS 153
SFAS No. 153, “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29”

 
iv

 

   
SFAS 154
SFAS No. 154, “Accounting Changes and Error Corrections - a replacement of APB Opinion No.
  20 and FASB Statement No. 3”
SO2
Sulfur Dioxide
TBC
Transition Bond Charge
TMI-2
Three Mile Island Unit 2
UWUA
Utility Workers Union of America
VIE
Variable Interest Entity

v


PART I. FINANCIAL INFORMATION

FIRSTENERGY CORP. AND SUBSIDIARIES
OHIO EDISON COMPANY AND SUBSIDIARIES
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
THE TOLEDO EDISON COMPANY AND SUBSIDIARY
PENNSYLVANIA POWER COMPANY AND SUBSIDIARY
JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARIES
METROPOLITAN EDISON COMPANY AND SUBSIDIARIES
PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


1 - ORGANIZATION AND BASIS OF PRESENTATION:
 
FirstEnergy’s principal business is the holding, directly or indirectly, of all of the outstanding common stock of its eight principal electric utility operating subsidiaries: OE, CEI, TE, Penn, ATSI, JCP&L, Met-Ed and Penelec. Penn is a wholly owned subsidiary of OE. FirstEnergy's consolidated financial statements also include its other principal subsidiaries: FENOC, FES and its subsidiary FGCO, FESC, FSG and MYR.

FirstEnergy and its subsidiaries follow GAAP and comply with the regulations, orders, policies and practices prescribed by the SEC, FERC and, as applicable, PUCO, PPUC and NJBPU. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not indicative of results of operations for any future period.

These statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, 2004 for FirstEnergy and the Companies. The consolidated unaudited financial statements of FirstEnergy and each of the Companies reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain businesses divested in the nine months ended September 30, 2005 have been classified as discontinued operations on the Consolidated Statements of Income (see Note 6). As discussed in Note 16, interim period segment reporting in 2004 was reclassified to conform with the current year business segment organizations and operations.

FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. FirstEnergy consolidates a VIE (see Note 11) when it is determined to be the VIE's primary beneficiary. Investments in nonconsolidated affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but not control, (20-50 percent owned companies, joint ventures and partnerships) are accounted for under the equity method. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheet and the percentage share of the entity’s earnings is reported in the Consolidated Statement of Income. Certain prior year amounts have been reclassified to conform to the current presentation.
 
FirstEnergy's and the Companies' independent registered public accounting firm has performed reviews of, and issued reports on, these consolidated interim financial statements in accordance with standards established by the PCAOB. Pursuant to Rule 436(c) under the Securities Act of 1933, their reports of those reviews should not be considered a report within the meaning of Section 7 and 11 of that Act, and the independent registered public accounting firm’s liability under Section 11 does not extend to them.

2 - ACCOUNTING FOR CERTAIN WHOLESALE ENERGY TRANSACTIONS

FES engages in purchase and sale transactions in the PJM Market to support the supply of end-use customers, including PLR requirements in Pennsylvania. In conjunction with FirstEnergy's dedication of its Beaver Valley Plant to PJM on January 1, 2005, FES began accounting for purchase and sale transactions in the PJM Market based on its net hourly position -- recording each hour as either an energy purchase in Fuel and purchased power expense or an energy sale, respectively, in the Consolidated Statements of Income relating to the Power Supply Management Services segment. Hourly energy positions are aggregated to recognize gross purchases and sales for the month.
 
 
1

 
This revised method of accounting, which has no impact on net income, is consistent with the practice of other energy companies that have dedicated generating capacity to PJM and correlates with PJM's scheduling and reporting of hourly energy transactions. FES also applies the net hourly methodology to purchase and sale transactions in MISO's energy market, which became active on April 1, 2005.

For periods prior to January 1, 2005, FirstEnergy did not have substantial generating capacity in PJM and as such, FES recognized purchases and sales in the PJM Market by recording each discrete transaction. Under these transactions, FES would often buy a specific quantity of energy at a certain location in PJM and simultaneously sell a specific quantity of energy at a different location. Physical delivery occurred and the risks and rewards of ownership transferred with each transaction. FES accounted for those transactions on a gross basis in accordance with EITF 99-19.

At its September 2005 meeting, the FASB's EITF reached a final consensus on EITF 04-13, which relates to the accounting for purchases and sales of inventory with the same counterparty. The Task Force concluded that two or more transactions with the same counterparty should be viewed as a single nonmonetary transaction within the scope of APB 29, when the transactions are entered into "in contemplation" of one another. The consensus will be effective for new arrangements entered into, or modifications of existing arrangements, in interim or annual periods beginning after March 15, 2006. Retrospective application to prior transactions and/or restatement of prior period financial statements is not permitted. Accordingly, EITF 04-13 is not applicable to FES' purchases and sales in the PJM Market made prior to January 1, 2005. The recognition of these transactions on a net basis in 2004 would have no impact on net income, but would have reduced both wholesale revenue and purchased power expense by $264 million and $828 million for the three months and nine months ended September 30, 2004, respectively.

3 - DEPRECIATION

During the second half of 2004, FirstEnergy engaged an independent third party to assist in reviewing the service lives of its fossil generation units. This study was completed in the first quarter of 2005. As a result of the analysis, FirstEnergy extended the estimated service lives of its fossil generation units for periods ranging from 11 to 33 years during the first quarter of 2005. Extension of the service lives will provide improved matching of depreciation expense with the expected economic lives of those generation units.

4 - EARNINGS PER SHARE

Basic earnings per share are computed using the weighted average of actual common shares outstanding during the respective period as the denominator. The denominator for diluted earnings per share reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. Stock-based awards during the nine months ended September 30, 2004, to purchase 3.4 million shares of common stock were excluded from the calculation of diluted earnings per share of common stock because their exercise prices were greater than the average market price of common shares during the period. No stock-based awards were excluded from the calculation in the three months ended September 30, 2005 and 2004, and the nine months ended September 30, 2005. The following table reconciles the denominators for basic and diluted earnings per share from Income Before Discontinued Operations:

 
 
 
Three Months Ended
 
Nine Months Ended
 
   
September 30,
 
September 30,
 
Reconciliation of Basic and Diluted Earnings per Share
 
2005
 
2004
 
2005
 
2004
 
 
 
(In thousands, except per share amounts)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Before Discontinued Operations
 
$
331,832
 
$
296,125
 
$
651,627
 
$
670,334
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average Shares of Common Stock Outstanding:
 
 
 
 
 
 
 
 
 
 
 
 
 
Denominator for basic earnings per share
 
 
 
 
 
 
 
 
 
 
 
 
 
(weighted average shares outstanding) 
 
 
328,119
 
 
327,499
 
 
328,030
 
 
327,280
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assumed exercise of dilutive stock options and awards
 
 
2,074
 
 
1,600
 
 
1,896
 
 
1,570
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Denominator for diluted earnings per share
 
 
330,193
 
 
329,099
 
 
329,926
 
 
328,850
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Before Discontinued Operations per Common Share:
 
 
 
 
 
 
 
 
 
 
 
 
 
Basic
 
 
$1.01
 
 
$0.90
 
 
$1.99
 
 
$2.05
 
Diluted
 
 
$1.01
 
 
$0.90
 
 
$1.98
 
 
$2.04
 


2

 
5 - GOODWILL

In a business combination, the excess of the purchase price over the estimated fair values of assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, FirstEnergy evaluates its goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If impairment is indicated, FirstEnergy recognizes a loss - calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill. FirstEnergy's 2005 annual review was completed in the third quarter of 2005 with no impairment indicated.

FirstEnergy's goodwill primarily relates to its regulated services segment. In the nine months ended September 30, 2005, FirstEnergy adjusted goodwill related to the divestiture of non-core operations (FES' retail natural gas business, MYR's Power Piping Company subsidiary, and a portion of its interest in FirstCom) as further discussed in Note 6. In addition, adjustments to the former GPU and Centerior companies' goodwill were recorded to reverse pre-merger tax accruals due to final resolution of these tax contingencies. FirstEnergy estimates that completion of transition cost recovery (see Note 14) will not result in an impairment of goodwill relating to its regulated business segment. A summary of the changes in goodwill for the three months and nine months ended September 30, 2005 is shown below.

Three Months Ended
 
FirstEnergy
 
CEI
 
TE
 
JCP&L
 
Met-Ed
 
Penelec
 
 
 
(In millions)
 
Balance as of July 1, 2005
 
$
6,033
 
$
1,694
 
$
505
 
$
1,984
 
$
868
 
$
887
 
Pre-merger tax adjustments related to Centerior acquisition
 
 
(9
)
 
(5
)
 
(4
)
 
-
 
 
-
 
 
-
 
Balance as of September 30, 2005
 
$
6,024
 
$
1,689
 
$
501
 
$
1,984
 
$
868
 
$
887
 

 
Nine Months Ended
 
FirstEnergy
 
CEI
 
TE
 
JCP&L
 
Met-Ed
 
Penelec
 
 
 
(In millions)
 
Balance as of January 1, 2005
 
$
6,050
 
$
1,694
 
$
505
 
$
1,985
 
$
870
 
$
888
 
Non-core asset sales
 
 
(13
)
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
Pre-merger tax adjustments related to Centerior acquisition
 
 
(9
)
 
(5
)
 
(4
)
 
-
 
 
-
 
 
-
 
Pre-merger tax adjustments related to GPU acquisition
 
 
(4
)
 
-
 
 
-
 
 
(1
)
 
(2
)
 
(1
)
Balance as of September 30, 2005
 
$
6,024
 
$
1,689
 
$
501
 
$
1,984
 
$
868
 
$
887
 

6 - DIVESTITURES AND DISCONTINUED OPERATIONS

In December 2004, FES' retail natural gas business qualified as assets held for sale in accordance with SFAS 144. On March 31, 2005, FES completed the sale for an after-tax gain of $5 million. In March 2005, FirstEnergy sold 51% of its interest in FirstCom, resulting in an after-tax gain of $4 million. FirstEnergy accounts for its remaining 31.85% interest in FirstCom on the equity basis.

During the nine months ended September 30, 2005, FirstEnergy sold certain of its FSG subsidiaries (Elliott-Lewis, Spectrum and Cranston), and MYR’s Power Piping Company subsidiary, resulting in an after-tax gain of $12 million. FSG's remaining subsidiaries qualify as assets held for sale in accordance with SFAS 144 and are expected to be recognized as completed sales within one year. The assets and liabilities of these remaining FSG subsidiaries are not material to FirstEnergy’s Consolidated Balance Sheet as of September 30, 2005, and therefore have not been separately classified as assets held for sale.

As of September 30, 2005, the remaining FSG businesses do not meet the criteria for discontinued operations; therefore, the net results from these subsidiaries have been included in continuing operations. See Note 16 for FSG's segment financial information.

Operating results from discontinued operations (including the gains on sales of assets discussed above) for Elliott-Lewis, Cranston, Power Piping and FES' retail natural gas business are summarized as follows:
 

 
 
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
 
 
2005
 
2004
 
2005
 
2004
 
 
 
(In millions)
 
Revenues
 
$
1
 
$
151
 
$
214
 
$
508
 
Income before income taxes
 
$
1
 
$
4
 
$
10
 
$
10
 
Income from discontinued operations, net of tax
 
$
1
 
$
3
 
$
19
 
$
6
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3

 
The following table summarizes the sources of income from discontinued operations.

 
 
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
 
 
2005
 
2004
 
2005
 
2004
 
 
 
(In millions)
Discontinued operations (net of tax)
 
 
 
 
 
 
 
 
 
 
 
 
 
Gain on sale:
 
 
 
 
 
 
 
 
 
 
 
 
 
Retail gas business
 
$
-
 
$
-
 
$
5
 
$
-
 
FSG and MYR subsidiaries
 
 
-
 
 
-
 
 
12
 
 
-
 
Reclassification of operating income, net of tax
 
 
1
 
 
3
 
 
2
 
 
6
 
Total
 
$
1
 
$
3
 
$
19
 
$
6
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


7 - DERIVATIVE INSTRUMENTS

FirstEnergy is exposed to financial risks resulting from the fluctuation of interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. To manage the volatility relating to these exposures, FirstEnergy uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes, and to a lesser extent, for trading purposes. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk management activities throughout the Company.

FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheet at their fair value unless they meet the normal purchase and normal sales criteria. Derivatives that meet that criteria are accounted for on the accrual basis. The changes in the fair value of a derivative instrument are recorded in current earnings, in other comprehensive income, or as part of the value of the hedged item depending on whether or not it is designated as part of a hedge transaction, the nature of the hedge transaction and hedge effectiveness.

FirstEnergy has entered into fair value hedges of fixed-rate, long-term debt issues to protect against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates received, and interest payment dates match those of the underlying debt obligations. During the third quarter of 2005, FirstEnergy unwound swaps with a total notional amount of $350 million from which it received immaterial net cash gains. The gains will be recognized in earnings over the remaining maturity of each respective hedged security as reduced interest expense. As of September 30, 2005, the aggregate notional value of interest rate swap agreements outstanding was $1.05 billion.

FirstEnergy hedges anticipated transactions using cash flow hedges. Such transactions include hedges of anticipated electricity and natural gas purchases and anticipated interest payments associated with future debt issues. The effective portion of such hedges are initially recorded in equity as other comprehensive income or loss and are subsequently included in net income as the underlying hedged commodities are delivered or interest payments are made. Gains and losses from any ineffective portion of cash flow hedges are included directly in earnings. The impact of ineffectiveness on earnings during the three months and nine months ended September 30, 2005 was not material.

During the third quarter of 2005, FirstEnergy entered into several forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with the possible issuances of fixed-rate, long-term debt securities for one or more of its consolidated entities in the second half of 2006 as outstanding debt matures. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. As of September 30, 2005, FirstEnergy had entered into forward swaps with an aggregate notional amount of $500 million. As of September 30, 2005 the forward swaps had a fair value of $2 million.

The net deferred losses of $79 million included in AOCL as of September 30, 2005, for derivative hedging activity, as compared to the December 31, 2004 balance of $92 million of net deferred losses, resulted from a $6 million decrease related to current hedging activity, a $4 million increase due to the sale of gas business contracts and an $11 million decrease due to net hedge losses included in earnings during the nine months ended September 30, 2005. Approximately $14 million of the net deferred losses on derivative instruments in AOCL as of September 30, 2005 is expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments will fluctuate from period to period based on various market factors.

FirstEnergy trades commodity derivatives and periodically experiences net open positions. FirstEnergy’s risk management policies limit the exposure to market risk from open positions and require daily reporting to management of potential financial exposures. During the three months and nine months ended September 30, 2005, the effect of trading on earnings was not material.
 
4

 
8 - STOCK BASED COMPENSATION
 
FirstEnergy applies the recognition and measurement principles of APB 25 and related interpretations in accounting for its stock-based compensation plans. No material stock-based employee compensation expense is reflected in net income for options as all options granted under those plans have exercise prices equal to the market value of the underlying common stock on the respective grant dates, resulting in substantially no intrinsic value.

In December 2004, the FASB issued SFAS 123(R), a revision to SFAS 123 which requires expensing the fair value of stock options (see Note 15). In April 2005, the SEC delayed the effective date of SFAS 123(R) to annual, rather than interim, periods that begin after June 15, 2005. FirstEnergy will be required to adopt this standard beginning January 1, 2006. The table below summarizes the effects on FirstEnergy’s net income and earnings per share had FirstEnergy applied the fair value recognition provisions of SFAS 123(R) to stock-based employee compensation in the current reporting periods.

 
 
 
Three Months Ended
 
Nine Months Ended
 
 
 
 
September 30,
 
September 30,
 
 
 
 
2005
 
2004
 
2005
 
2004
 
 
 
 
(In thousands, except per share amounts)
 
 
 
 
 
 
 
 
 
 
 
 
Net income, as reported
 
 
 
$
332,360
 
$
298,622
 
$
670,078
 
$
676,666
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Add back compensation expense
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
reported in net income, net of tax
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(based on APB 25)(1)
 
 
 
 
17,404
 
 
13,549
 
 
39,785
 
 
29,355
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deduct compensation expense based
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
upon estimated fair value, net of tax(2)
 
 
 
 
(18,378
 
(16,981
)
 
(44,825
 
(40,380
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net income, as adjusted
 
 
 
$
331,386
 
$
295,190
 
$
665,038
 
$
665,641
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Earnings Per Share of Common Stock -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Basic
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
As reported 
 
 
 
 
$1.01
 
 
$0.91
 
 
$2.04
 
 
$2.07
 
As adjusted
 
 
 
 
$1.01
 
 
$0.90
 
 
$2.03
 
 
$2.03
 
Diluted
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
As reported 
 
 
 
 
$1.01
 
 
$0.91
 
 
$2.03
 
 
$2.06
 
As adjusted
 
 
 
 
$1.00
 
 
$0.90
 
 
$2.02
 
 
$2.02
 
   
(1) Includes restricted stock, restricted stock units, stock options, performance shares, Employee Stock
  Ownership Plan, Executive Deferred Compensation Plan and Deferred Compensation Plan for outside Directors.
 
(2) Assumes vesting at age 65.
 

FirstEnergy reduced the use of stock options in 2005 and increased the use of performance-based, restricted stock units. Therefore, the pro forma effects of applying SFAS 123(R) may not be representative of its future effect. FirstEnergy does not expect to accelerate out-of-the-money options in anticipation of implementing SFAS 123(R) on January 1, 2006.

9 - ASSET RETIREMENT OBLIGATIONS
 
FirstEnergy has identified applicable legal obligations for nuclear power plant decommissioning, reclamation of a sludge disposal pond related to the Bruce Mansfield Plant and closure of two coal ash disposal sites. The ARO liability of $1.130 billion as of September 30, 2005 included $1.115 billion for nuclear decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating facilities. The Companies' share of the obligation to decommission these units was developed based on site specific studies performed by an independent engineer. FirstEnergy utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.

In the third quarter of 2005, FirstEnergy revised the ARO associated with Beaver Valley Units 1 and 2 as a result of an updated decommissioning study. The present value of revisions in the estimated cash flows associated with projected decommissioning costs increased the ARO for Beaver Valley Unit 1 by $21 million and decreased the ARO for Beaver Valley Unit 2 by $22 million, resulting in a net decrease in the ARO liability and corresponding plant asset of $1 million (OE - ($2) million, CEI - ($5) million, TE - ($5) million and Penn - $11 million).

The Companies maintain trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of September 30, 2005, the fair value of the decommissioning trust assets was $1.7 billion.
 
 
5

 
The following tables analyze changes to the ARO balance during the three months and nine months ended September 30, 2005 and 2004, respectively.

Three Months Ended
 
FirstEnergy
 
OE
 
CEI
 
TE
 
Penn
 
JCP&L
 
Met-Ed
 
Penelec
 
 
 
(In millions)
 
Balance, July 1, 2005
 
$
1,113
 
$
208
 
$
281
 
$
201
 
$
143
 
$
75
 
$
137
 
$
68
 
Liabilities incurred
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
Liabilities settled
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
Accretion
 
 
18
 
 
3
 
 
5
 
 
4
 
 
2
 
 
1
 
 
2
 
 
1
 
Revisions in estimated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
cash flows
 
 
(1
)
 
(2
)
 
(5
)
 
(5
)
 
11
 
 
-
 
 
-
 
 
-
 
Balance, September 30, 2005
 
$
1,130
 
$
209
 
$
281
 
$
200
 
$
156
 
$
76
 
$
139
 
$
69
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance, July 1, 2004
 
$
1,217
 
$
194
 
$
263
 
$
188
 
$
134
 
$
113
 
$
216
 
$
108
 
Liabilities incurred
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
Liabilities settled
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
Accretion
 
 
19
 
 
4
 
 
5
 
 
3
 
 
2
 
 
2
 
 
3
 
 
1
 
Revisions in estimated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
cash flows
 
 
(176
 
-
 
 
-
 
 
-
 
 
-
 
 
(43
)
 
(89
)
 
(44
)
Balance, September 30, 2004
 
$
1,060
 
$
198
 
$
268
 
$
191
 
$
136
 
$
72
 
$
130
 
$
65
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


Nine Months Ended
 
FirstEnergy
 
OE
 
CEI
 
TE
 
Penn
 
JCP&L
 
Met-Ed
 
Penelec
 
 
 
(In millions)
 
Balance, January 1, 2005
 
$
1,078
 
$
201
 
$
272
 
$
195
 
$
138
 
$
72
 
$
133
 
$
67
 
Liabilities incurred
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
Liabilities settled
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
Accretion
 
 
53
 
 
10
 
 
14
 
 
10
 
 
7
 
 
4
 
 
6
 
 
2
 
Revisions in estimated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
cash flows
 
 
(1
 
(2
 
(5
 
(5
 
11
 
 
-
 
 
-
 
 
-
 
Balance, September 30, 2005
 
$
1,130
 
$
209
 
$
281
 
$
200
 
$
156
 
$
76
 
$
139
 
$
69
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance, January 1, 2004
 
$
1,179
 
$
188
 
$
255
 
$
182
 
$
130
 
$
110
 
$
210
 
$
105
 
Liabilities incurred
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
Liabilities settled
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
Accretion
 
 
57
 
 
10
 
 
13
 
 
9
 
 
6
 
 
5
 
 
9
 
 
4
 
Revisions in estimated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
cash flows
 
 
(176
 
-
 
 
-
 
 
-
 
 
-
 
 
(43
)
 
(89
)
 
(44
)
Balance, September 30, 2004
 
$
1,060
 
$
198
 
$
268
 
$
191
 
$
136
 
$
72
 
$
130
 
$
65
 

10 - PENSION AND OTHER POSTRETIREMENT BENEFITS:
 
The components of FirstEnergy's net periodic pension cost and other postretirement benefits cost (including amounts capitalized) for the three months and nine months ended September 30, 2005 and 2004, consisted of the following:

 
 
Three Months Ended
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
Pension Benefits
 
2005
 
2004
 
2005
 
2004
 
 
 
(In millions)
 
 
 
 
 
 
 
 
 
 
 
Service cost
 
$
19
 
$
19
 
$
58
 
$
58
 
Interest cost
 
 
64
 
 
63
 
 
191
 
 
189
 
Expected return on plan assets
 
 
(86
)
 
(71
)
 
(259
)
 
(215
)
Amortization of prior service cost
 
 
2
 
 
2
 
 
6
 
 
7
 
Recognized net actuarial loss
 
 
9
 
 
10
 
 
27
 
 
29
 
Net periodic cost
 
$
8
 
$
23
 
$
23
 
$
68
 



 
6



 
 
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
Other Postretirement Benefits
 
2005
 
2004
 
2005
 
2004
 
 
 
(In millions)
 
Service cost
 
$
10
 
$
9
 
$
30
 
$
27
 
Interest cost
 
 
27
 
 
26
 
 
83
 
 
83
 
Expected return on plan assets
 
 
(11
)
 
(10
)
 
(34
)
 
(32
)
Amortization of prior service cost
 
 
(11
)
 
(9
)
 
(33
)
 
(28
)
Recognized net actuarial loss
 
 
10
 
 
9
 
 
30
 
 
29
 
Net periodic cost
 
$
25
 
$
25
 
$
76
 
$
79
 

Pension and postretirement benefit obligations are allocated to the FirstEnergy subsidiaries employing the plan participants. The Companies capitalize employee benefits related to construction projects. The net periodic pension benefits (credit) and net periodic postretirement benefits (including amounts capitalized) recognized by each of the Companies in the three months and nine months ended September 30, 2005 and 2004 were as follows:

 
 
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
Pension Benefits (Credit)
 
2005
 
2004
 
2005
 
2004
 
 
 
(In millions)
 
 
 
 
 
 
 
 
 
 
 
OE
 
$
0.2
 
$
1.7
 
$
0.7
 
$
5.2
 
Penn
 
 
(0.2
)
 
0.1
 
 
(0.7
)
 
0.4
 
CEI
 
 
0.3
 
 
1.6
 
 
1.0
 
 
4.8
 
TE
 
 
0.3
 
 
0.8
 
 
1.0
 
 
2.3
 
JCP&L
 
 
(0.3
)
 
1.9
 
 
(0.8
)
 
5.6
 
Met-Ed
 
 
(1.1
)
 
0.1
 
 
(3.2
)
 
0.2
 
Penelec
 
 
(1.3
)
 
0.1
 
 
(4.0
)
 
0.4
 


 
 
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
Other Postretirement Benefits
 
2005
 
2004
 
2005
 
2004
 
 
 
(In millions)
 
 
 
 
 
 
 
 
 
 
 
OE
 
$
5.8
 
$
5.7
 
$
17.3
 
$
17.7
 
Penn
 
 
1.2
 
 
1.2
 
 
3.5
 
 
3.7
 
CEI
 
 
3.8
 
 
4.4
 
 
11.4
 
 
13.7
 
TE
 
 
2.2
 
 
1.7
 
 
6.5
 
 
5.0
 
JCP&L
 
 
1.5
 
 
1.0
 
 
5.7
 
 
3.5
 
Met-Ed
 
 
0.4
 
 
0.7
 
 
1.2
 
 
2.5
 
Penelec
 
 
2.0
 
 
0.7
 
 
5.9
 
 
2.5
 

11 - VARIABLE INTEREST ENTITIES

Leases
 
FirstEnergy’s consolidated financial statements include PNBV and Shippingport, VIEs created in 1996 and 1997, respectively, to refinance debt originally issued in connection with sale and leaseback transactions. PNBV and Shippingport financial data are included in the consolidated financial statements of OE and CEI, respectively.

PNBV was established to purchase a portion of the lease obligation bonds issued in connection with OE’s 1987 sale and leaseback of its interests in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by PNBV. Ownership of PNBV includes a three-percent equity interest by a nonaffiliated third party and a three-percent equity interest held by OES Ventures, a wholly owned subsidiary of OE. Shippingport was established to purchase all of the lease obligation bonds issued in connection with CEI’s and TE’s Bruce Mansfield Plant sale and leaseback transaction in 1987. CEI and TE used debt and available funds to purchase the notes issued by Shippingport.

OE, CEI and TE are exposed to losses under the applicable sale-leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. OE, CEI and TE each have a maximum exposure to loss under these provisions of approximately $1 billion, which represents the net amount of casualty value payments upon the occurrence of specified casualty events that render the applicable plant worthless. Under the applicable sale and leaseback agreements, OE, CEI and TE have net minimum discounted lease payments of $678 million, $103 million and $541 million, respectively, that would not be payable if the casualty value payments are made.


 
7

 
Power Purchase Agreements

In accordance with FIN 46R, FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the extent they own a plant that sells substantially all of its output to the Companies and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and Penelec, maintains approximately 30 long-term power purchase agreements with NUG entities. The agreements were structured pursuant to the Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, these entities.

FirstEnergy has determined that for all but eight of these entities, neither JCP&L, Met-Ed nor Penelec have variable interests in the entities or the entities are governmental or not-for-profit organizations not within the scope of FIN 46R. JCP&L, Met-Ed or Penelec may hold variable interests in the remaining eight entities, which sell their output at variable prices that correlate to some extent with the operating costs of the plants.

As required by FIN 46R, FirstEnergy periodically requests from these eight entities the information necessary to determine whether they are VIEs or whether JCP&L, Met-Ed or Penelec is the primary beneficiary. FirstEnergy has been unable to obtain the requested information, which in most cases was deemed by the requested entity to be proprietary. As such, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities under FIN 46R. The maximum exposure to loss from these entities results from increases in the variable pricing component under the contract terms and cannot be determined without the requested data. Purchased power costs from these entities during the three months and nine months ended September 30, 2005 and 2004 are shown in the table below:
 
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2005
 
2004
 
2005
 
2004
 
 
        (In millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
JCP&L
$
33
 
$
26
 
$
74
 
$
71
 
Met-Ed
 
10
 
 
13
 
 
40
 
 
38
 
Penelec
 
7
 
 
7
 
 
21
 
 
20
 
Total
$
50
 
$
46
 
$
135
 
$
129
 
 

Securitized Transition Bonds

The consolidated financial statements of FirstEnergy and JCP&L include the results of JCP&L Transition, a wholly owned limited liability company of JCP&L. In June 2002, JCP&L Transition sold $320 million of transition bonds to securitize the recovery of JCP&L's bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station.

JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. The transition bonds are obligations of JCP&L Transition only and are collateralized solely by the equity and assets of JCP&L Transition, which consist primarily of bondable transition property. The bondable transition property is solely the property of JCP&L Transition.

Bondable transition property represents the irrevocable right under New Jersey law of a utility company to charge, collect and receive from its customers, through a non-bypassable TBC, the principal amount and interest on the transition bonds and other fees and expenses associated with their issuance. JCP&L sold the bondable transition property to JCP&L Transition and, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the TBC, pursuant to a servicing agreement with JCP&L Transition. JCP&L is entitled to a quarterly servicing fee of $0.1 million that is payable from TBC collections.

12 - OHIO TAX LEGISLATION
 
On June 30, 2005, the State of Ohio enacted tax legislation that creates a new CAT tax, which is based on qualifying “taxable gross receipts” and will not consider any expenses or costs incurred to generate such receipts, except for items such as cash discounts, returns and allowances, and bad debts. The CAT tax was effective July 1, 2005, and replaces the Ohio income-based franchise tax and the Ohio personal property tax. The CAT tax is phased-in while the current income-based franchise tax is phased-out over a five-year period at a rate of 20% annually, beginning with the year ended 2005, and the personal property tax is phased-out over a four-year period at a rate of approximately 25% annually, beginning with the year ended 2005. For example, during the phase-out period the Ohio income-based franchise tax will be computed consistently with the prior tax law, except that the tax liability as computed will be multiplied by 4/5 in 2005; 3/5 in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current income-based franchise tax over a five-year period. As a result of the new tax structure, all net deferred tax benefits that were not expected to reverse during the five-year phase-in period were written-off as of June 30, 2005.
 
 
8


 
The increase (in millions) to income taxes associated with the adjustment to net deferred taxes for the nine months ended September 30, 2005 is summarized below:

OE
 
$
36.0
CEI
 
 
7.5
TE
 
 
17.5
Other FirstEnergy subsidiaries
 
 
10.7
Total FirstEnergy
 
$
71.7

Income tax expenses were (increased) reduced during the three months and nine months ended September 30, 2005 by the initial phase-out of the Ohio income-based franchise tax and phase-in of the CAT tax as summarized below:
 

   
Three Months Ended
   
Nine Months Ended
 
   
September 30, 2005
 
September 30, 2005
   
   
(In millions)
               
OE
 
$
1.6
 
$
6.5
 
CEI
 
 
(3.1
)
 
(1.7
)
TE
 
 
0.7
   
1.2
 
Other FirstEnergy subsidiaries
 
 
0.7
   
1.5
 
Total FirstEnergy
 
$
(0.1
)
$
7.5
 
 
 
13 - COMMITMENTS, GUARANTEES AND CONTINGENCIES:

(A)  GUARANTEES AND OTHER ASSURANCES
 
As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. Such agreements include contract guarantees, surety bonds and ratings contingent collateralization provisions. As of September 30, 2005, outstanding guarantees and other assurances aggregated approximately $2.7 billion and included contract guarantees ($1.3 billion), surety bonds ($0.3 billion) and LOCs ($1.1 billion).

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities - principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of subsidiary financing principally for the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. Such parental guarantees amount to $0.8 billion (included in the $1.3 billion discussed above) as of September 30, 2005 and the likelihood is remote that such guarantees will increase amounts otherwise to be paid by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related contracts.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating-downgrade or “material adverse event” the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. The following table summarizes collateral provisions in effect as of September 30, 2005:

 
 
 
Total
 
Collateral Paid
 
Remaining
 
Collateral Provisions
 
 
Exposure 
 
Cash
 
LOC
 
Exposure
 
 
 
 
(In millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Credit rating downgrade
 
 
 
$
445
 
$
213
 
$
18
 
$
214
 
Adverse event
 
 
 
 
77
 
 
-
 
 
5
 
 
72
 
Total
 
 
 
$
522
 
$
213
 
$
23
 
$
286
 
                               

On October 3, 2005, S&P raised the senior unsecured ratings of FirstEnergy's holding company to 'BBB-' from 'BB+'. As a result of the rating upgrade, $109 million of cash collateral was subsequently returned to FirstEnergy.


 
9


 
Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of $307 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction jobs, environmental commitments and various retail transactions.

The Companies, with the exception of TE and JCP&L, each have a wholly owned subsidiary whose borrowings are secured by customer accounts receivable purchased from its respective parent company. The CEI subsidiary's borrowings are also secured by customer accounts receivable purchased from TE. Each subsidiary company has its own receivables financing arrangement and, as a separate legal entity with separate creditors, would have to satisfy its obligations to creditors before any of its remaining assets could be available to its parent company.
   
Subsidiary Company
 
Parent Company
 
Capacity
 
 
 
 
 
(In millions)
 
OES Capital, Incorporated
 
 
OE
 
$
170
 
Centerior Funding Corp.
 
 
CEI
 
 
200
 
Penn Power Funding LLC
 
 
Penn
 
 
25
 
Met-Ed Funding LLC
 
 
Met-Ed
 
 
80
 
Penelec Funding LLC
 
 
Penelec
 
 
75
 
 
 
 
 
 
$
550
 


FirstEnergy has guaranteed the obligations of the operators of the TEBSA project, up to a maximum of $6 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has also provided an LOC ($47 million as of September 30, 2005) which is renewable and declines yearly based upon the senior outstanding debt of TEBSA. The LOC was reduced to $36 million on October 15, 2005.

(B) ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. The effects of compliance on the Companies with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position. These environmental regulations affect FirstEnergy's earnings and competitive position to the extent that 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. Overall, FirstEnergy believes it is in compliance with existing regulations but is unable to predict future changes in regulatory policies and what, if any, the effects of such changes would be. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately $670 million for 2005 through 2007.
 
The Companies accrue environmental liabilities only when they conclude that it is probable that they have an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in the Companies’ determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.
 
FirstEnergy plans to issue a report regarding its response to air emission requirements. FirstEnergy expects to complete the report by December 1, 2005.

Clean Air Act Compliance
 
FirstEnergy 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 $32,500 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 Companies cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

FirstEnergy believes it is complying with SO2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions required by the 1990 Amendments 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 FirstEnergy's facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85 percent reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOx emissions are contributing significantly to ozone levels in the eastern United States. FirstEnergy believes its facilities are also complying with the NOx budgets established under State Implementation Plans through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances.
 
10

 
National Ambient Air Quality Standards
 
In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR provides each affected state until 2006 to develop implementing regulations to achieve additional reductions of NOx and SO2 emissions in two phases (Phase I in 2009 for NOx, 2010 for SO2 and Phase II in 2015 for both NOx and SO2) in all cases from the 2003 levels. FirstEnergy's Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be subject to the caps on SO2 and NOx emissions, whereas their New Jersey fossil-fired generation facilities will be subject to a cap on NOx emissions only. According to the EPA, SO2 emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO2 emissions in affected states to just 2.5 million tons annually. NOx emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NOx cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which FirstEnergy operates affected facilities.

Mercury Emissions
 
In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On March 14, 2005, the EPA finalized the "Clean Air Mercury Rule," which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases. Initially, mercury emissions will be capped nationally at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOx emission caps under the EPA's CAIR program). Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. However, the final rules give states substantial discretion in developing rules to implement these programs. In addition, both the CAIR and the Clean Air Mercury Rule have been challenged in the United States Court of Appeals for the District of Columbia. FirstEnergy's future cost of compliance with these regulations may be substantial.

W. H. Sammis Plant
 
In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which was owned at that time by OE and Penn. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the W. H. Sammis Plant New Source Review litigation. This settlement agreement, which is in the form of a Consent Decree, was approved by the Court on July 11, 2005, requires OE and Penn to reduce Nox and SO2 emissions at the W. H. Sammis Plant and other coal fired plants through the installation of pollution control devices. Capital expenditures necessary to meet those requirements are currently estimated to be $1.5 billion (the primary portion of which is expected to be spent in the 2008 to 2011 time period). As disclosed in FirstEnergy's Form 8-K dated August 26, 2005, FGCO entered into an agreement with Bechtel Power Corporation (Bechtel), under which Bechtel will engineer, procure, and construct air quality control systems for the reduction of sulfur dioxide emissions. The settlement agreement also requires OE and Penn to spend up to $25 million toward environmentally beneficial projects, which include wind energy purchased power agreements over a 20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million. Results for the first quarter of 2005 included the penalties payable by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also recognized liabilities of $9.2 million and $0.8 million, respectively, during the first quarter of 2005, for probable future cash contributions toward environmentally beneficial projects.

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global warming by reducing the amount of man-made GHG emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Protocol in 1998 but it failed to receive the two-thirds vote of the United States Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity - the ratio of emissions to economic output - by 18 percent through 2012. The Energy Policy Act of 2005 established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.
 

 
11


FirstEnergy cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO2 emissions could require significant capital and other expenditures. However, the CO2 emissions per kilowatt-hour of electricity generated by FirstEnergy is lower than many regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.

Clean Water Act
 
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy's plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FirstEnergy's operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.

On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality, when aquatic organisms are pinned against screens or other parts of a cooling water intake system and entrainment, which occurs when aquatic species are drawn into a facility's cooling water system. FirstEnergy is conducting comprehensive demonstration studies, due in 2008, to determine the operational measures, equipment or restoration activities, if any, necessary for compliance by its facilities with the performance standards. FirstEnergy is unable to predict the outcome of such studies. Depending on the outcome of such studies, the future cost of compliance with these standards may require material capital expenditures.

Regulation of Hazardous Waste
 
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 subsequently determined 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 Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of September 30, 2005, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable SBC. Total liabilities of approximately $64 million (JCP&L - $46.8 million, CEI - $2.3 million, TE - $0.2 million, Met-Ed - $0.1 million and other - $14.6 million) have been accrued through September 30, 2005.

(C) OTHER LEGAL PROCEEDINGS

Power Outages and Related Litigation
 
In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four of New Jersey’s electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the JCP&L territory.

In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision on July 8, 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, New Jersey. On September 8, 2004, the New Jersey Supreme Court denied the motions filed by plaintiffs and JCP&L for leave to appeal the decision of the Appellate Division. JCP&L has filed a motion for summary judgment. FirstEnergy is unable to predict the outcome of these matters and no liability has been accrued as of September 30, 2005.



 
12

 
On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of September 30, 2005 for any expenditures in excess of those actually incurred through that date. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

FirstEnergy companies also are defending six separate complaint cases before the PUCO relating to the August 14, 2003 power outage. Two cases were originally filed in Ohio State courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In these cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Of the four other pending PUCO complaint cases, three were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of the four cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and American Electric Power Co. as well) for claims paid to insureds for claims allegedly arising as a result of the loss of power on August 14, 2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy company. The fourth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. In addition to these six cases, the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages. No estimate of potential liability has been undertaken for any of these cases.

One complaint was filed on August 25, 2004 against FirstEnergy in the New York State Supreme Court. In this case, several plaintiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. FirstEnergy's motion to dismiss the case was granted on September 26, 2005. Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter is not due until on or about December 1, 2005. No estimate of potential liability has been undertaken in this matter.


 
13



FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. In particular, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

Nuclear Plant Matters
 
FENOC received a subpoena in late 2003 from a grand jury sitting in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at the Davis-Besse Nuclear Power Station. On December 10, 2004, FirstEnergy received a letter from the United States Attorney's Office stating that FENOC is a target of the federal grand jury investigation into alleged false statements made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01. The letter also said that the designation of FENOC as a target indicates that, in the view of the prosecutors assigned to the matter, it is likely that federal charges will be returned against FENOC by the grand jury. On February 10, 2005, FENOC received an additional subpoena for documents related to root cause reports regarding reactor head degradation and the assessment of reactor head management issues at Davis-Besse. On May 11, 2005, FENOC received a subpoena for documents related to outside meetings attended by Davis-Besse personnel on corrosion and cracking of control rod drive mechanisms and additional root cause evaluations.

On April 21, 2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to the degradation of the Davis-Besse reactor vessel head issue described above. FirstEnergy accrued $2.0 million for a potential fine prior to 2005 and accrued the remaining liability for the proposed fine during the first quarter of 2005. On September 14, 2005, FENOC filed its response to the NOV with the NRC. FENOC accepted full responsibility for the past failure to properly implement its boric acid corrosion control and corrective action programs. The NRC NOV indicated that the violations do not represent current licensee performance. FirstEnergy paid the penalty in the third quarter of 2005.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability based on the events surrounding Davis-Besse, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

Effective July 1, 2005, the NRC oversight panel for Davis-Besse was terminated and Davis-Besse returned to the standard NRC reactor oversight process. At that time, NRC inspections were augmented to include inspections to support the NRC's Confirmatory Order dated March 8, 2004 that was issued at the time of startup and to address an NRC White Finding related to the performance of the emergency sirens.

On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the preceding two years and the licensee's failure to take prompt and corrective action. FENOC operates the Perry Nuclear Power Plant, which is currently owned and/or leased by OE, CEI, TE and Penn (however, see Note 17 regarding FirstEnergy’s pending intra-system generation asset transfers, which will include owned portions of the plant).

On April 4, 2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Plant operated "in a manner that preserved public health and safety" even though it remained under heightened NRC oversight. During the public meeting and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix.

On May 26, 2005, the NRC held a public meeting to discuss its oversight of the Perry Plant. While the NRC stated that the plant continued to operate safely, the NRC also stated that the overall performance had not substantially improved since the heightened inspection was initiated. The NRC reiterated this conclusion in its mid-year assessment letter dated August 30, 2005. On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance of Perry and stated that the CAL would remain open until substantial improvement was demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight Process. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process, from increased oversight to possible impact to the plant’s operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

 
14

 
Other Legal Matters
 
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.

On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, have become the subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. On August 24, 2005 additional information was requested regarding Davis-Besse. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.

On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from the W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members.

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties’ collective bargaining agreement. At the conclusion of the June 1, 2005, hearing, the Arbitrator decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the Arbitrator issued an opinion to award approximately $16.1 million to the bargaining unit employees. JCP&L initiated an appeal of this award by filing a motion to vacate in Federal Court in New Jersey on October 18, 2005. JCP&L recognized a liability for the potential $16.1 million award during the three months ended September 30, 2005.

The City of Huron filed a complaint against OE with the PUCO challenging the ability of electric distribution utilities to collect transition charges from a customer of a newly-formed municipal electric utility. The complaint was filed on May 28, 2003, and OE timely filed its response on June 30, 2003. In a related filing, the Ohio Companies filed for approval with the PUCO of a tariff that would specifically allow the collection of transition charges from customers of municipal electric utilities formed after 1998. An adverse ruling could negatively affect full recovery of transition charges by the utility. Hearings on the matter were held in August 2005. Initial briefs from all parties were filed on September 22, 2005 and reply briefs were filed on October 14, 2005. It is unknown when the PUCO will rule on this case.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

14 - REGULATORY MATTERS:

Reliability Initiatives
 
In late 2003 and early 2004, a series of letters, reports and recommendations were issued from various entities, including governmental, industry and ad hoc reliability entities (PUCO, FERC, NERC and the U.S. - Canada Power System Outage Task Force) regarding enhancements to regional reliability. In 2004, FirstEnergy completed implementation of all actions and initiatives related to enhancing area reliability, improving voltage and reactive management, operator readiness and training and emergency response preparedness recommended for completion in 2004. On July 14, 2004, NERC independently verified that FirstEnergy had implemented the various initiatives to be completed by June 30 or summer 2004, with minor exceptions noted by FirstEnergy, which exceptions are now essentially complete. FirstEnergy is proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future as the result of adoption of mandatory reliability standards pursuant to the Energy Policy Act of 2005 that could require additional, material expenditures. Finally, the PUCO is continuing to review the FirstEnergy filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.


 
15

 
As a result of outages experienced in JCP&L's service area in 2002 and 2003, the NJBPU had implemented reviews into JCP&L's service reliability. On March 29, 2004, the NJBPU adopted an MOU that set out specific tasks related to service reliability to be performed by JCP&L and a timetable for completion and endorsed JCP&L's ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a Stipulation that incorporates the final report of a Special Reliability Master who made recommendations on appropriate courses of action necessary to ensure system-wide reliability. The Stipulation also incorporates the Executive Summary and Recommendation portions of the final report of a focused audit of JCP&L's Planning and Operations and Maintenance programs and practices (Focused Audit). A final order in the Focused Audit docket was issued by the NJBPU on July 23, 2004. On February 11, 2005, JCP&L met with the Ratepayer Advocate to discuss reliability improvements. JCP&L continues to file compliance reports reflecting activities associated with the MOU and Stipulation.

In May 2004, the PPUC issued an order approving revised reliability benchmarks and standards, including revised benchmarks and standards for Met-Ed, Penelec and Penn. Met-Ed, Penelec and Penn filed a Petition for Amendment of Benchmarks with the PPUC on May 26, 2004, due to their implementation of automated outage management systems following restructuring. Evidentiary hearings have been scheduled for November 2005. FirstEnergy is unable to predict the outcome of this proceeding.

The Energy Policy Act of 2005 provides for the creation of an ERO to establish and enforce reliability standards for the bulk power system, subject to FERC review. On September 1, 2005, the FERC issued a Notice of Proposed Rulemaking to establish certification requirements for the ERO, as well as regional entities envisioned to assume monitoring and compliance responsibility for the new reliability standards. The FERC expects to adopt a final rule on or before February 2006 regarding certification requirements for the ERO and regional entities.

The NERC is expected to reorganize its structure to meet the FERC’s certification requirements for the ERO. Following adoption of the final rule, the NERC will be required to make a filing with the FERC to obtain certification as the ERO. The proposed rule also provides for regional reliability organizations designed to replace the current regional councils. The “regional entity” may be delegated authority by the ERO, subject to FERC approval, for enforcing reliability standards adopted by the ERO and approved by the FERC. The ECAR, Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability councils have signed an MOU designed to consolidate their regions into a new regional reliability organization known as ReliabilityFirst Corporation. Their intent is to file and obtain certification under the final rule as a “regional entity”. All of FirstEnergy’s facilities would be located within the ReliabilityFirst region.

On a parallel path, the NERC is establishing working groups to develop reliability standards to be filed for approval with the FERC following the NERC’s certification as an ERO. These reliability standards are expected to build on the current NERC Version 0 reliability standards. It is expected that the proposed reliability standards will be filed with the FERC in early 2006.

The impact of this effort on FirstEnergy is unclear. FirstEnergy believes that it is in compliance with all current NERC reliability standards. However, it is expected that the FERC will adopt stricter reliability standards than those contained in the current NERC Version 0 standards. The financial impact of complying with the new standards cannot be determined at this time. However, the Energy Policy Act of 2005 requires that all prudent costs incurred to comply with the new reliability standards be recovered in rates.

Ohio

On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a competitive bid process. The RSP was filed by the Ohio Companies to establish generation service rates beginning January 1, 2006, in response to PUCO concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. In October 2004, the OCC and NOAC filed appeals with the Supreme Court of Ohio to overturn the original June 9, 2004 PUCO order in this proceeding as well as the associated entries on rehearing. On September 28, 2005, the Ohio Supreme Court heard oral argument on the appeals.

On May 27, 2005, the Ohio Companies filed an application with the PUCO to establish a GCAF rider under the RSP. The application seeks to implement recovery of increased fuel costs from 2006 through 2008 applicable to the Ohio Companies' retail customers through a tariff rider to be implemented January 1, 2006. The application reflects projected increases in fuel costs in 2006 compared to 2002 baseline costs. The new rider, after adjustments made in testimony, is seeking to recover all costs above the baseline (approximately $88 million in 2006). Various parties including the OCC have intervened in this case and the case has been consolidated with the RCP application discussed below.


 
 
16


On September 9, 2005, the Ohio Companies filed an application with the PUCO that, if approved, would supplement their existing RSP with an RCP. On September 27, 2005, the PUCO granted FirstEnergy's motion to consolidate the GCAF rider application with the RCP proceedings and set hearings for the consolidated cases to begin November 29, 2005. The RCP is designed to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. Major provisions of the RCP include:

·    Maintain the existing level of base distribution rates through December 31, 2008 for OE and TE, and
    April 30, 2009 for CEI;

·    Defer and capitalize certain distribution costs to be incurred during the period January 1, 2006
    through December 31, 2008, not to exceed $150 million in each of the three years;

·    Adjust the RTC and extended RTC recovery periods and rate levels so that full recovery of authorized
    costs will occur as of December 31, 2008 for OE and TE, and as of December 31, 2010 for CEI;

·    Reduce the deferred shopping incentive balances as of January 1, 2006 by up to $75 million for OE,
    $45 million for TE, and $85 million for CEI by accelerating the application of each respective
    company's accumulated cost of removal regulatory liability; and

·    Recover increased fuel costs of up to $75 million, $77 million, and $79 million, in 2006, 2007, and
    2008, respectively, from all OE and TE distribution and transmission customers through a fuel
    recovery mechanism and OE, TE, and CEI may defer and capitalize increased fuel costs above the
    amount collected through the fuel recovery mechanism.

The following table provides a comparison of the estimated net amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) under the proposed RCP and the current RSP for the period 2006 through 2010:

 
 
Estimated Net Amortization
 
 
 
RCP
 
RSP
 
Amortization
 
 
 
 
 
 
 
Total
 
 
 
 
 
 
 
Total
 
Period
 
OE
 
CEI
 
TE
 
Ohio
 
OE
 
CEI
 
TE
 
Ohio
 
 
 
(In millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2006
 
$
169
 
$
100
 
$
80
 
$
349
 
$
175
 
$
94
 
$
73
 
$
342
 
2007
 
 
176
 
 
111
 
 
89
 
 
376
 
 
237
 
 
104
 
 
82
 
 
423
 
2008
 
 
198
 
 
129
 
 
100
 
 
427
 
 
206
 
 
122
 
 
159
 
 
487
 
2009
 
 
-
 
 
216
 
 
-
 
 
216
 
 
-
 
 
318
 
 
-
 
 
318
 
2010
 
 
-
 
 
268
 
 
-
 
 
268
 
 
-
 
 
271
 
 
-
 
 
271
 
Net Amortization*
 
$
543
 
$
824
 
$
269
 
$
1,636
 
$
618
 
$
909
 
$
314
 
$
1,841
 
 
* RCP aggregate amortization is less than amortization under the RSP due to the accelerated application of regulatory  liabilities to reduce deferred shopping incentives.

Under provisions of the RSP, the PUCO may require the Ohio Companies to undertake, no more often than annually, a competitive bid process to secure generation for the years 2007 and 2008. On July 22, 2005, FirstEnergy filed a competitive bid process for the period beginning in 2007 that is similar to the competitive bid process approved by the PUCO for the Ohio Companies in 2004, which resulted in the PUCO accepting no bids. Any acceptance of future competitive bid results would terminate the RSP pricing, with no accounting impacts to the RSP, and not until twelve months after the PUCO authorizes such termination. On September 28, 2005, the PUCO issued an Entry that essentially approved the Ohio Companies' filing but delayed the proposed timing of the competitive bid process by four months, calling for the auction to be held on March 21, 2006.

Pennsylvania

A February 2002 Commonwealth Court of Pennsylvania decision affirmed the June 2001 PPUC decision regarding approval of the FirstEnergy/GPU merger, remanded the issues of quantification and allocation of merger savings to the PPUC and denied Met-Ed and Penelec the rate relief initially approved in the PPUC decision. On October 2, 2003, the PPUC issued an order concluding that the Commonwealth Court reversed the PPUC’s June 2001 order in its entirety. In accordance with the PPUC's direction, Met-Ed and Penelec filed supplements to their tariffs that became effective in October 2003 and that reflected the CTC rates and shopping credits in effect prior to the June 2001 order.
 
17

 
In accordance with PPUC directives, Met-Ed and Penelec have been negotiating with interested parties in an attempt to resolve the merger savings issues that are the subject of remand from the Commonwealth Court. Met-Ed’s and Penelec’s combined portion of total merger savings is estimated to be approximately $31.5 million. On April 13, 2005, the Commonwealth Court issued an interim order in the remand proceeding that the parties should report the status of the negotiations to the PPUC with a copy to the ALJ. The parties exchanged settlement proposals in May and June 2005 and continue to have settlement discussions.

In an October 16, 2003 order, the PPUC approved September 30, 2004 as the date for Met-Ed's and Penelec's NUG trust fund refunds. The PPUC order also denied their accounting treatment request regarding the CTC rate/shopping credit swap by requiring Met-Ed and Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. On October 22, 2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court asking that the Court reverse this PPUC finding; a Commonwealth Court judge subsequently denied their Objection on October 27, 2003 without explanation. On October 31, 2003, Met-Ed and Penelec filed an Application for Clarification of the Court order with the judge, a Petition for Review of the PPUC's October 2 and October 16, 2003 Orders, and an application for reargument, if the judge, in his clarification order, indicates that Met-Ed's and Penelec's Objection was intended to be denied on the merits. The Reargument Brief before the Commonwealth Court was filed on January 28, 2005.
 
Met-Ed and Penelec purchase a portion of their PLR requirements from FES through a wholesale power sales agreement. The PLR sale is automatically extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. Under the terms of the wholesale agreement, FES retains the supply obligation, and the supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec under their NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR energy costs during the term of the agreement with FES. Met-Ed and Penelec are authorized to defer differences between NUG contract costs and current market prices. On November 1, 2005, FES and the other parties to the wholesale power agreement amended the agreement to provide FES the right over the next year to terminate the agreement at any time upon 60 days notice. If the wholesale power agreement were terminated, Met-Ed and Penelec would need to satisfy the applicable portion of their PLR obligations from other sources at prevailing prices, which are likely to be higher than the current price charged by FES under the agreement and, as a result, Met-Ed’s and Penelec’s purchased power costs could materially increase. 
 
In October 11, 2005, Penn filed a plan with the PPUC to secure electricity supply for its customers at set rates following the end of its transition period on December 31, 2006. Penn is recommending that the Request for Proposal process cover the period of January 1, 2007 through May 31, 2008. Under Pennsylvania's electric competition law, Penn is required to secure generation supply for customers who do not choose alternative suppliers for their electricity.

New Jersey

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and MTC rates. As of September 30, 2005, the accumulated deferred cost balance totaled approximately $508 million. New Jersey law allows for securitization of JCP&L's deferred balance upon application by JCP&L and a determination by the NJBPU that the conditions of the New Jersey restructuring legislation are met. On February 14, 2003, JCP&L filed for approval of the securitization of the July 31, 2003 deferred balance. JCP&L is in discussions with the NJBPU staff as a result of the stipulated settlement agreements (as further discussed below) which recommended that the NJBPU issue an order regarding JCP&L's application. On July 20, 2005, JCP&L requested the NJBPU to set a procedural schedule for this matter and is awaiting NJBPU action.

The 2003 NJBPU decision on JCP&L's base electric rate proceeding (the Phase I Order) disallowed certain regulatory assets and provided for an interim return on equity of 9.5% on JCP&L's rate base. The Phase I order also provided for a Phase II proceeding in which the NJBPU would review whether JCP&L is in compliance with current service reliability and quality standards and determine whether the expenditures and projects undertaken by JCP&L to increase its system's reliability are prudent and reasonable for rate recovery. Depending on its assessment of JCP&L's service reliability, the NJBPU could have increased JCP&L’s return on equity to 9.75% or decreased it to 9.25%. On August 15, 2003 and June 1, 2004, JCP&L filed with the NJBPU an interim motion and a supplemental and amended motion for rehearing and reconsideration of the Phase I Order, respectively. On July 7, 2004, the NJBPU granted limited reconsideration and rehearing on the following issues: (1) deferred cost disallowances; (2) the capital structure including the rate of return; (3) merger savings, including amortization of costs to achieve merger savings; and (4) decommissioning costs.

On July 16, 2004, JCP&L filed the Phase II petition and testimony with the NJBPU, requesting an increase in base rates of $36 million for the recovery of system reliability costs and a 9.75% return on equity. The filing also requested an increase to the MTC deferred balance recovery of approximately $20 million annually.
 
On May 25, 2005, the NJBPU approved two stipulated settlement agreements. The first stipulation between JCP&L and the NJBPU staff resolves all of the issues associated with JCP&L's motion for reconsideration of the Phase I Order. The second stipulation between JCP&L, the NJBPU staff and the Ratepayer Advocate resolves all of the issues associated with JCP&L's Phase II proceeding. The stipulated settlements provide for, among other things, the following:

 
 
18

 

 
·
An annual increase in distribution revenues of $23 million effective June 1, 2005, associated with the Phase I Order reconsideration;

 
·
An annual increase in distribution revenues of $36 million effective June 1, 2005, related to JCP&L's Phase II Petition;

 
·
An annual reduction in both rates and amortization expense of $8 million, effective June 1, 2005, in anticipation of an NJBPU order regarding JCP&L's request to securitize up to $277 million of its deferred cost balance;

 
·
An increase in JCP&L's authorized return on common equity from 9.5% to 9.75%; and

 
·
A commitment by JCP&L to maintain a target level of customer service reliability with a reduction in JCP&L's authorized return on common equity from 9.75% to 9.5% if the target is not met for two consecutive quarters. The authorized return on common equity would then be restored to 9.75% if the target is met for two consecutive quarters.

The Phase II stipulation included an agreement that the distribution revenue increase also reflects a three-year amortization of JCP&L's one-time service reliability improvement costs incurred in 2003-2005. This resulted in the creation of a regulatory asset associated with accelerated tree trimming and other reliability costs which were expensed in 2003 and 2004. The establishment of the new regulatory asset of approximately $28 million resulted in an increase to net income of approximately $16 million ($0.05 per share of common stock) in the second quarter of 2005.

JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits to its deferred energy balance with the exception of 300 MW from JCP&L's NUG committed supply currently being used to serve BGS customers pursuant to NJBPU order for the period June 1, 2005 through May 31, 2006. New BGS tariffs reflecting the results of a February 2005 auction for the BGS supply became effective June 1, 2005. On July 1, 2005, JCP&L filed its BGS procurement proposals for post transition year four. The auction is scheduled to take place in February 2006 for the annual supply period beginning June 1, 2006.

In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting a continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The Ratepayer Advocate filed comments on February 28, 2005. On March 18, 2005, JCP&L filed a response to those comments. A schedule for further proceedings has not yet been set.

Transmission

On November 1, 2004, ATSI requested authority from the FERC to defer approximately $54 million of vegetation management costs estimated to be incurred from 2004 through 2007. On March 4, 2005, the FERC approved ATSI's request to defer those costs ($21 million deferred as of September 30, 2005). ATSI expects to file an application with the FERC in the second quarter of 2006 that would include recovery of the deferred costs.

On December 30, 2004, the Ohio Companies filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application seeks recovery of these costs beginning January 1, 2006. The Ohio Companies requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted each July 1 thereafter. The Ohio Companies reached a settlement with OCC, PUCO staff, Industrial Energy Users - Ohio and OPAE. The only other party in this proceeding, Dominion Retail, Inc., agreed not to oppose the settlement. This settlement, which was filed with the PUCO on July 22, 2005, provides for the rider recovery requested by the Ohio Companies, with carrying charges applied in the subsequent year’s rider for any over or under collection while the then-current rider is in effect. The PUCO approved the settlement stipulation on August 31, 2005. The incremental Transmission and Ancillary service revenues expected to be recovered from January through June 2006 are approximately $61.2 million. This amount includes the recovery of the 2005 deferred MISO expenses as described below. In May 2006, the Companies will file a modification to the rider to determine revenues from July 2006 through June 2007.
 
19

 
The second application sought authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for the Ohio Companies to defer incremental transmission and ancillary service-related charges incurred as a participant in MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Permission to defer costs incurred prior to December 30, 2004 was denied. The PUCO also authorized the Ohio Companies to accrue carrying charges on the deferred balances. An application filed with the PUCO to recover these deferred charges over a five-year period through the rider, beginning in 2006, was approved in the PUCO order issued on August 31, 2005 approving the stipulation referred to above. The OCC, OPAE and the Ohio Companies each filed applications for rehearing. The Ohio Companies sought authority to defer the transmission and ancillary service-related costs incurred during the period October 1, 2003 through December 29, 2004, while both OCC and OPAE sought to have the PUCO deny deferral of all costs. On July 6, 2005, the PUCO denied the Ohio Companies' and OCC’s applications and, at the request of the Ohio Companies, struck as untimely OPAE’s application. The OCC filed a notice of appeal with the Ohio Supreme Court on August 31, 2005. On September 30, 2005, in accordance with appellate procedure, the PUCO filed with the Ohio Supreme Court the record in this case. The Companies' brief will be due thirty days after the OCC files its brief, which, absent any time extensions, must be filed no later than November 9, 2005.

On January 12, 2005, Met-Ed and Penelec filed a request with the PPUC for deferral of transmission-related costs beginning January 1, 2005, estimated to be approximately $8 million per month. The OCA, OSBA, OTS, MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric Association have all intervened in the case. To date no hearing schedule has been established, and neither company has yet implemented deferral accounting for these costs.

On January 31, 2005, certain PJM transmission owners made three filings pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to referral and hearing procedures. On June 30, 2005, the PJM transmission owners filed a request for rehearing of the May 31, 2005 order. The rate design and formula rate proceedings are currently being litigated before the FERC. The outcome of these cases cannot be predicted.

Regulatory Assets

The EUOC recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods. Without such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. All regulatory assets are expected to be recovered from customers under the Companies' respective transition and regulatory plans. Based on those plans, the Companies continue to bill and collect cost-based rates for their transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Companies continue the application of SFAS 71 to those operations.

The Ohio Companies are deferring customer shopping incentives and interest costs as new regulatory assets in accordance with the transition and rate stabilization plans. Under the RSP, recovery of these regulatory assets (OE - $302 million, CEI - $402 million, TE - $122 million, as of September 30, 2005) would have begun through a surcharge rate equal to the RTC rate in effect only after the transition costs have been fully recovered. Under the proposed RCP, OE's and TE's recovery of the new regulatory assets would begin January 1, 2006 and expected to be completed by December 31, 2008. CEI's new regulatory asset recovery would still begin after full recovery of its transition costs (estimated as of mid-2009) and expected to be completed by December 31, 2010. Amortization of the new regulatory assets for each accounting period would equal the amount of the surcharge revenue recognized during that period.

Regulatory transition costs as of September 30, 2005 for JCP&L and Met-Ed are approximately $2.4 billion and $0.6 billion, respectively. Deferral of above-market costs from power supplied by NUGs to JCP&L are approximately $1.4 billion and are being recovered through BGS and MTC revenues. Met-Ed has deferred above-market NUG costs totaling approximately $200 million. These costs are being recovered through CTC revenues. The regulatory asset for above-market NUG future obligations and the corresponding liability are adjusted to fair value at the end of each quarter. Recovery of the remaining regulatory transition costs is expected to continue under the provisions of the various regulatory proceedings in New Jersey and Pennsylvania.

 
 
20

 
15 - NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

FSP No. FAS 13-1, "Accounting for Rental Costs Incurred during the Construction Period"
 
       Issued in October 2005, FSP No. FAS 13-1 requires rental costs associated with ground or building operating leases that are incurred during a construction period to be recognized as rental expense. The effective date of the FSP guidance is the first reporting period beginning after December 15, 2005. FirstEnergy is currently evaluating this FSP and its impact on the financial statements.

EITF Issue 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty"
 
In September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus that an exchange of inventory should be accounted for at fair value. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and other storable inventory. Therefore, FirstEnergy will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006. See Note 2 for an example of FirstEnergy's application of this Issue.

 
EITF Issue No. 05-6, "Determining the Amortization Period for Leasehold Improvements Purchased after Lease Inception or Acquired in a Business Combination"
 
In June 2005, the EITF reached a consensus on the application guidance for Issue 05-6. EITF 05-6 addresses the amortization period for leasehold improvements that were either acquired in a business combination or placed in service significantly after and not contemplated at or near the beginning of the initial lease term. For leasehold improvements acquired in a business combination, the amortization period is the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date of acquisition. Leasehold improvements that are placed in service significantly after and not contemplated at or near the beginning of the lease term should be amortized over the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date the leasehold improvements are purchased. This EITF was effective July 1, 2005 and is consistent with FirstEnergy's current accounting.

FIN 47, “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective for FirstEnergy in the fourth quarter of 2005. FirstEnergy and the Companies are currently evaluating the effect this Interpretation will have on their financial statements.

 
SFAS 154 - “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3”

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in the Consolidated Statements of Income. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. FirstEnergy and the Companies will adopt this Statement effective January 1, 2006.
 
21

 

 
SFAS 153, “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29”

In December 2004, the FASB issued SFAS 153 amending APB 29, which was based on the principle that nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB 29 included certain exceptions to that principle. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement are effective January 1, 2006 for FirstEnergy. This FSP is not expected to have a material impact on FirstEnergy's financial statements.

SFAS 123(R), “Share-Based Payment”

In December 2004, the FASB issued SFAS 123(R), a revision to SFAS 123, which requires expensing stock options in the financial statements. Important to applying the new standard is understanding how to (1) measure the fair value of stock-based compensation awards and (2) recognize the related compensation cost for those awards. For an award to qualify for equity classification, it must meet certain criteria in SFAS 123(R). An award that does not meet those criteria will be classified as a liability and remeasured each period. SFAS 123(R) retains SFAS 123's requirements on accounting for income tax effects of stock-based compensation. In April 2005, the SEC delayed the effective date of SFAS 123(R) to annual, rather than interim, periods that begin after June 15, 2005. The SEC’s new rule results in a six-month deferral for companies with a fiscal year beginning January 1. Therefore, FirstEnergy will adopt this Statement effective January 1, 2006. FirstEnergy expects to adopt modified prospective application, without restatement of prior interim periods. Potential cumulative adjustments, if any, have not yet been determined. FirstEnergy uses the Black-Scholes option-pricing model to value options for disclosure purposes only and expects to apply this pricing model upon adoption of SFAS 123(R).

SFAS 151, “Inventory Costs - an amendment of ARB No. 43, Chapter 4”

In November 2004, the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Previous guidance stated that in some circumstances these costs may be “so abnormal” that they would require treatment as current period costs. SFAS 151 requires abnormal amounts for these items to always be recorded as current period costs. In addition, this Statement requires that allocation of fixed production overheads to the cost of conversion be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred by FirstEnergy beginning January 1, 2006. FirstEnergy is currently evaluating this Standard and does not expect it to have a material impact on the financial statements.

FSP FAS 115-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

In September 2005, the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP FAS 115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition of Other Than Temporary Impairment upon the Planned Sale of a Security Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when the impairment is deemed other than temporary, even if a decision to sell has not been made, and (3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after September 15, 2005. The FASB expects to issue this FSP in the fourth quarter of 2005, which would require prospective application with an effective date for reporting periods beginning after December 15, 2005. FirstEnergy is currently evaluating this FSP Issue and any impact on its investments.

FSP 109-1, “Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction and Qualified Production Activities Provided by the American Jobs Creation Act of 2004”
 
Issued in December 2004, FSP 109-1 provides guidance related to the provision within the American Jobs Creation Act of 2004 (Act) that provides a tax deduction on qualified production activities. The Act includes a tax deduction of up to nine percent (when fully phased-in) of the lesser of (a) “qualified production activities income,” as defined in the Act, or (b) taxable income (after the deduction for the utilization of any net operating loss carryforwards). The FASB believes that the deduction should be accounted for as a special deduction in accordance with SFAS 109, “Accounting for Income Taxes", which is consistent with FirstEnergy's accounting.
 
 

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16 - SEGMENT INFORMATION:

FirstEnergy has three reportable segments: regulated services, power supply management services and FSG. The aggregate “Other” segments do not individually meet the criteria to be considered a reportable segment. FirstEnergy's primary segment is its regulated services segment, whose operations include the regulated sale of electricity and distribution and transmission services by its eight EUOCs in Ohio, Pennsylvania and New Jersey. The power supply management services segment primarily consists of the subsidiaries (FES, FGCO, NGC and FENOC) that sell electricity in deregulated markets and operate the generation facilities of OE, CEI, TE and Penn resulting from the deregulation of the Companies' electric generation business. “Other” consists of MYR (a construction service company), retail natural gas operations (recently sold - see Note 6) and telecommunications services. The assets and revenues for the other business operations are below the quantifiable threshold for operating segments for separate disclosure as “reportable segments.”

The regulated services segment designs, constructs, operates and maintains FirstEnergy's regulated transmission and distribution systems. Its revenues are primarily derived from electricity delivery and transition cost recovery. Assets of the regulated services segment as of September 30, 2005 and 2004, included generating units that were leased or whose output was sold to the power supply management services segment. The regulated services segment’s internal revenues represent the rental revenues for the generating unit leases.

The power supply management services segment has responsibility for FirstEnergy’s generation operations. Its net income is primarily derived from all electric generation sales revenues, which consist of generation services to regulated franchise customers who have not chosen an alternative generation supplier, retail sales in deregulated markets and all domestic unregulated electricity sales in the retail and wholesale markets, less the related costs of electricity generation and sourcing of commodity requirements. Its net income also reflects the expense of the intersegment generating unit leases and power sales agreements discussed above and property taxes related to those generating units.

Segment reporting for interim periods in 2004 have been reclassified to conform with the current year business segment organization and operations that were reported in the 2004 Form 10-K, emphasizing FirstEnergy's regulated electric businesses and power supply management operations and the reclassification of discontinued operations (see Note 6). FSG is being disclosed as a reporting segment due to its subsidiaries qualifying as held for sale (see Note 6 for discussion of the divestiture of three of those subsidiaries in 2005). Interest expense on holding company debt and corporate support services revenues and expenses are included in "Reconciling Items."
 


 
23



Segment Financial Information
                         
                           
       
Power
                 
       
Supply
                 
   
Regulated
 
Management
 
Facilities
     
Reconciling
     
   
Services
 
Services
 
Services
 
Other
 
Adjustments
 
Consolidated
 
   
(In millions)
 
Three Months Ended:
                         
                           
September 30, 2005
                         
External revenues
 
$
1,676
 
$
1,712
 
$
59
 
$
138
 
$
2
 
$
3,587
 
Internal revenues
   
79
   
-
   
-
   
-
   
(79
)
 
-
 
Total revenues
   
1,755
   
1,712
   
59
   
138
   
(77
)
 
3,587
 
Depreciation and amortization
   
377
   
9
   
-
   
1
   
6
   
393
 
Net interest charges
   
88
   
11
   
-
   
2
   
57
   
158
 
Income taxes
   
254
   
7
   
-
   
4
   
(28
)
 
237
 
Income before discontinued operations
   
366
   
10
   
(2
)
 
6
   
(49
)
 
331
 
Discontinued operations
   
-
   
-
   
-
   
1
   
-
   
1
 
Net income (loss)
   
366
   
10
   
(2
)
 
7
   
(49
)
 
332
 
Total assets
   
28,385
   
1,741
   
82
   
522
   
644
   
31,374
 
Total goodwill
   
5,938
   
24
   
-
   
62
   
-
   
6,024
 
Property additions
   
207
   
79
   
-
   
1
   
7
   
294
 
                                       
September 30, 2004
                                     
External revenues
 
$
1,481
 
$
1,756
 
$
61
 
$
90
 
$
(3
)
$
3,385
 
Internal revenues
   
80
   
-
   
-
   
-
   
(80
)
 
-
 
Total revenues
   
1,561
   
1,756
   
61
   
90
   
(83
)
 
3,385
 
Depreciation and amortization
   
374
   
9
   
-
   
-
   
9
   
392
 
Net interest charges
   
82
   
9
   
-
   
-
   
60
   
151
 
Income taxes
   
226
   
30
   
-
   
(1
)
 
(41
)
 
214
 
Income before discontinued operations
   
315
   
44
   
-
   
(2
)
 
(61
)
 
296
 
Discontinued operations
   
-
   
-
   
1
   
2
   
-
   
3
 
Net income (loss)
   
315
   
44
   
1
   
-
   
(61
)
 
299
 
Total assets
   
28,416
   
1,467
   
182
   
596
   
564
   
31,225
 
Total goodwill
   
5,965
   
24
   
37
   
75
   
-
   
6,101
 
Property additions
   
157
   
46
   
-
   
1
   
7
   
211
 
                                       
Nine Months Ended:
                         
                           
September 30, 2005
                         
External revenues
 
$
4,366
 
$
4,346
 
$
161
 
$
385
 
$
19
 
$
9,277
 
Internal revenues
   
237
   
-
   
-
   
-
   
(237
)
 
-
 
Total revenues
   
4,603
   
4,346
   
161
   
385
   
(218
)
 
9,277
 
Depreciation and amortization
   
1,076
   
26
   
-
   
2
   
19
   
1,123
 
Net interest charges
   
285
   
29
   
1
   
4
   
170
   
489
 
Income taxes
   
595
   
(10
)
 
3
   
13
   
(2
)
 
599
 
Income before discontinued operations
   
856
   
(15
)
 
(6
)
 
18
   
(201
)
 
652
 
Discontinued operations
   
-
   
-
   
13
   
5
   
-
   
18
 
Net income (loss)
   
856
   
(15
)
 
7
   
23
   
(201
)
 
670
 
Total assets
   
28,385
   
1,741
   
82
   
522
   
644
   
31,374
 
Total goodwill
   
5,938
   
24
   
-
   
62
   
-
   
6,024
 
Property additions
   
506
   
226
   
1
   
5
   
18
   
756
 
                                       
September 30, 2004
                                     
External revenues
 
$
4,049
 
$
4,828
 
$
156
 
$
324
 
$
4
 
$
9,361
 
Internal revenues
   
239
   
-
   
-
   
-
   
(239
)
 
-
 
Total revenues
   
4,288
   
4,828
   
156
   
324
   
(235
)
 
9,361
 
Depreciation and amortization
   
1,098
   
26
   
1
   
-
   
28
   
1,153
 
Net interest charges
   
301
   
30
   
-
   
2
   
169
   
502
 
Income taxes
   
541
   
55
   
(1
)
 
(19
)
 
(70
)
 
506
 
Income before discontinued operations
   
761
   
79
   
(1
)
 
39
   
(207
)
 
671
 
Discontinued operations
   
-
   
-
   
3
   
3
   
-
   
6
 
Net income (loss)
   
761
   
79
   
2
   
42
   
(207
)
 
677
 
Total assets
   
28,416
   
1,467
   
182
   
596
   
564
   
31,225
 
Total goodwill
   
5,965
   
24
   
37
   
75
   
-
   
6,101
 
Property additions
   
377
   
149
   
2
   
1
   
17
   
546
 
                                       
Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting primarily
 
consist of interest expense related to holding company debt, corporate support services revenues and expenses, fuel marketing revenues, which are
 
reflected as reductions to expenses for internal management reporting purposes, and elimination of intersegment transactions.
   
 
 
24


17 - FIRSTENERGY INTRA-SYSTEM GENERATION ASSET TRANSFERS
 
On May 13, 2005, Penn, and on May 18, 2005, the Ohio Companies entered into certain agreements implementing a series of intra-system generation asset transfers. When fully completed, the asset transfers will result in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear and non-nuclear plants being owned by NGC, and FGCO, respectively. The generating plant interests that are being transferred do not include leasehold interests of CEI, TE and OE in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates.

On October 24, 2005, the Ohio Companies and Penn completed the intra-system transfer of non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease with the Ohio Companies and Penn, leased, operated and maintained the non-nuclear generation assets that it now owns. The asset transfers were consummated pursuant to the May 13, and May 18, 2005 agreements and FGCO's purchase option under the Master Facility Lease.

As contemplated by the agreements entered into in May 2005, the Ohio Companies and Penn intend to transfer their respective interests in the nuclear generation assets to NGC through, in the case of OE and Penn, a spin-off by way of dividend and, in the case of CEI and TE, a sale at net book value. FENOC currently operates and maintains the nuclear generation assets to be transferred. FirstEnergy currently expects to complete the nuclear asset transfers in the fourth quarter of 2005, subject to the receipt of required regulatory approvals.

These transactions are pursuant to the Ohio Companies’ and Penn’s restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. The transactions will essentially complete the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO without impacting the operation of the plants.

The following table provides the value of assets pending sale along with the related liabilities as of September 30, 2005:

 
 
OE
 
Penn
 
CEI
 
TE
 
 
 
 
 
 
 
 
 
 
 
 
(In millions)
 
Assets Pending Sale
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Property, plant and equipment
 
$
1,598
 
$
440
 
$
1,305
 
$
687
 
Other property and investments
 
 
363
 
 
147
 
 
433
 
 
276
 
Current assets
 
 
93
 
 
38
 
 
73
 
 
42
 
Deferred charges
 
 
(60
)
 
2
 
 
-
 
 
-
 
Total
 
$
1,994
 
$
627
 
$
1,811
 
$
1,005
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities Related to Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
Pending Sale
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term debt
 
$
238
 
$
53
 
$
-
 
$
-
 
Current liabilities
 
 
40
 
 
31
 
 
434
 
 
253
 
Noncurrent liabilities
 
 
280
 
 
226
 
 
362
 
 
202
 
Total
 
$
558
 
$
310
 
$
796
 
$
455
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Assets Pending Sale
 
$
1,436
 
$
317
 
$
1,015
 
$
550
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 




 
25



FIRSTENERGY CORP.
 
                   
CONSOLIDATED STATEMENTS OF INCOME
 
(Unaudited)
 
                   
   
Three Months Ended
 
Nine Months Ended
 
   
September 30,
 
September 30,
 
   
2005
 
2004
 
2005
 
2004
 
   
(In thousands, except per share amounts)
 
REVENUES:
                 
Electric utilities 
 
$
2,935,547
 
$
2,526,971
 
$
7,573,858
 
$
6,874,574
 
Unregulated businesses (Note 2) 
   
651,240
   
858,497
   
1,703,281
   
2,485,959
 
 Total revenues
   
3,586,787
   
3,385,468
   
9,277,139
   
9,360,533
 
                           
EXPENSES:
                         
Fuel and purchased power (Note 2) 
   
1,287,225
   
1,285,355
   
3,115,153
   
3,514,816
 
Other operating expenses 
   
992,436
   
868,440
   
2,758,378
   
2,500,182
 
Provision for depreciation 
   
152,786
   
147,052
   
444,443
   
439,017
 
Amortization of regulatory assets 
   
364,337
   
324,300
   
981,750
   
905,488
 
Deferral of new regulatory assets 
   
(123,827
)
 
(78,767
)
 
(303,496
)
 
(191,487
)
General taxes 
   
187,562
   
177,452
   
540,606
   
514,174
 
 Total expenses
   
2,860,519
   
2,723,832
   
7,536,834
   
7,682,190
 
                           
INCOME BEFORE INTEREST AND INCOME TAXES
   
726,268
   
661,636
   
1,740,305
   
1,678,343
 
                           
NET INTEREST CHARGES:
                         
Interest expense 
   
162,104
   
152,348
   
488,462
   
504,396
 
Capitalized interest 
   
(7,005
)
 
(6,536
)
 
(11,957
)
 
(18,286
)
Subsidiaries’ preferred stock dividends 
   
2,626
   
5,354
   
12,912
   
16,024
 
 Net interest charges
   
157,725
   
151,166
   
489,417
   
502,134
 
                           
INCOME TAXES
   
236,711
   
214,345
   
599,261
   
505,875
 
                           
INCOME BEFORE DISCONTINUED OPERATIONS
   
331,832
   
296,125
   
651,627
   
670,334
 
                           
Discontinued operations (net of income taxes (benefit) of
                         
$367,000 and $1,625,000 in the three months ended 
                         
September 30, and ($8,684,000) and $3,762,000 in the nine  
                         
months ended September 30, of 2005 and 2004, respectively)  
                         
(Note 6) 
   
528
   
2,497
   
18,451
   
6,332
 
                           
NET INCOME
 
$
332,360
 
$
298,622
 
$
670,078
 
$
676,666
 
                           
BASIC EARNINGS PER SHARE OF COMMON STOCK:
                         
Earnings before discontinued operations  
 
$
1.01
 
$
0.90
 
$
1.99
 
$
2.05
 
Discontinued operations (Note 6) 
   
-
   
0.01
   
0.05
   
0.02
 
Net earnings per basic share 
 
$
1.01
 
$
0.91
 
$
2.04
 
$
2.07
 
                           
WEIGHTED AVERAGE NUMBER OF BASIC SHARES
                         
OUTSTANDING 
   
328,119
   
327,499
   
328,030
   
327,280
 
                           
DILUTED EARNINGS PER SHARE OF COMMON STOCK:
                         
Earnings before discontinued operations  
 
$
1.01
 
$
0.90
 
$
1.98
 
$
2.04
 
Discontinued operations (Note 6) 
   
-
   
0.01
   
0.05
   
0.02
 
Net earnings per diluted share 
 
$
1.01
 
$
0.91
 
$
2.03
 
$
2.06
 
                           
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES
                         
OUTSTANDING 
   
330,193
   
329,099
   
329,926
   
328,850
 
                           
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK
 
$
0.43
 
$
0.375
 
$
1.255
 
$
1.125
 
                           
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements.
   
                           
 
 
 
26

 
 

FIRSTENERGY CORP.
 
                   
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
(Unaudited)
 
                   
   
Three Months Ended
 
Nine Months Ended
 
   
September 30,
 
September 30,
 
   
2005
 
2004
 
2005
 
2004
 
   
(In thousands)
 
                   
NET INCOME
 
$
332,360
 
$
298,622
 
$
670,078
 
$
676,666
 
                           
OTHER COMPREHENSIVE INCOME (LOSS):
                         
Unrealized gain on derivative hedges 
   
17,723
   
5,927
   
19,023
   
26,536
 
Unrealized gain (loss) on available for sale securities 
   
(13,093
)
 
8,715
   
(37,216
)
 
5,265
 
 Other comprehensive income (loss)
   
4,630
   
14,642
   
(18,193
)
 
31,801
 
Income tax expense (benefit) related to other  
                         
 comprehensive income
   
(1,797
)
 
2,498
   
(7,704
)
 
11,026
 
 Other comprehensive income (loss), net of tax
   
6,427
   
12,144
   
(10,489
)
 
20,775
 
                           
COMPREHENSIVE INCOME
 
$
338,787
 
$
310,766
 
$
659,589
 
$
697,441
 
                           
                           
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these
 
statements.
                         
 
 
 
27

 

FIRSTENERGY CORP.
 
           
CONSOLIDATED BALANCE SHEETS
 
(Unaudited)
 
   
September 30,
 
December 31,
 
   
2005
 
2004
 
   
(In thousands)
 
ASSETS
         
CURRENT ASSETS:
         
Cash and cash equivalents
 
$
139,812
 
$
52,941
 
Receivables -
           
Customers (less accumulated provisions of $37,429,000 and
             
$34,476,000, respectively, for uncollectible accounts) 
   
1,336,969
   
979,242
 
Other (less accumulated provisions of $26,416,000 and
             
$26,070,000, respectively, for uncollectible accounts) 
   
198,256
   
377,195
 
Materials and supplies, at average cost -
             
Owned
   
378,937
   
363,547
 
Under consignment
   
117,265
   
94,226
 
Prepayments and other
   
235,496
   
145,196
 
     
2,406,735
   
2,012,347
 
PROPERTY, PLANT AND EQUIPMENT:
             
In service
   
22,777,299
   
22,213,218
 
Less - Accumulated provision for depreciation
   
9,688,122
   
9,413,730
 
     
13,089,177
   
12,799,488
 
Construction work in progress
   
684,042
   
678,868
 
     
13,773,219
   
13,478,356
 
INVESTMENTS:
             
Nuclear plant decommissioning trusts
   
1,711,112
   
1,582,588
 
Investments in lease obligation bonds
   
905,504
   
951,352
 
Other
   
773,994
   
740,026
 
     
3,390,610
   
3,273,966
 
DEFERRED CHARGES:
             
Goodwill
   
6,024,376
   
6,050,277
 
Regulatory assets
   
5,045,838
   
5,532,087
 
Other
   
733,164
   
720,911
 
     
11,803,378
   
12,303,275
 
   
$
31,373,942
 
$
31,067,944
 
LIABILITIES AND CAPITALIZATION
             
CURRENT LIABILITIES:
             
Currently payable long-term debt
 
$
983,412
 
$
940,944
 
Short-term borrowings
   
246,505
   
170,489
 
Accounts payable
   
651,941
   
610,589
 
Accrued taxes
   
852,477
   
657,219
 
Other
   
1,110,511
   
929,194
 
     
3,844,846
   
3,308,435
 
CAPITALIZATION:
             
Common stockholders’ equity -
             
Common stock, $0.10 par value, authorized 375,000,000 shares -
             
329,836,276 shares outstanding 
   
32,984
   
32,984
 
Other paid-in capital
   
7,033,726
   
7,055,676
 
Accumulated other comprehensive loss
   
(323,601
)
 
(313,112
)
Retained earnings
   
2,115,434
   
1,856,863
 
Unallocated employee stock ownership plan common stock -
           
1,642,223 and 2,032,800 shares, respectively 
   
(30,584
)
 
(43,117
)
 Total common stockholders' equity
   
8,827,959
   
8,589,294
 
Preferred stock of consolidated subsidiaries
   
183,719
   
335,123
 
Long-term debt and other long-term obligations
   
9,418,734
   
10,013,349
 
     
18,430,412
   
18,937,766
 
NONCURRENT LIABILITIES:
             
Accumulated deferred income taxes
   
2,345,281
   
2,324,097
 
Asset retirement obligations
   
1,130,194
   
1,077,557
 
Power purchase contract loss liability
   
1,920,358
   
2,001,006
 
Retirement benefits
   
1,343,461
   
1,238,973
 
Lease market valuation liability
   
872,650
   
936,200
 
Other
   
1,486,740
   
1,243,910
 
     
9,098,684
   
8,821,743
 
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 13)
              
   
$
31,373,942
 
$
31,067,944
 
               
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these    
       
balance sheets.
             
 
 
 
28

 

FIRSTENERGY CORP.
 
                   
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(Unaudited)
 
                   
   
Three Months Ended
 
Nine Months Ended
 
   
September 30,
 
September 30,
 
   
2005
 
2004
 
2005
 
2004
 
   
(In thousands)
 
                   
CASH FLOWS FROM OPERATING ACTIVITIES:
                 
Net income
 
$
332,360
 
$
298,622
 
$
670,078
 
$
676,666
 
Adjustments to reconcile net income to net cash from
                         
operating activities -
                         
Provision for depreciation
   
152,786
   
147,052
   
444,443
   
439,017
 
Amortization of regulatory assets
   
364,337
   
324,300
   
981,750
   
905,488
 
Deferral of new regulatory assets
   
(123,827
)
 
(78,767
)
 
(303,496
)
 
(191,487
)
Nuclear fuel and lease amortization
   
25,785
   
26,776
   
63,363
   
71,782
 
Amortization of electric service obligation
   
(8,630
)
 
(3,336
)
 
(24,135
)
 
(12,877
)
Deferred purchased power and other costs
   
(39,215
)
 
(118,409
)
 
(231,438
)
 
(263,290
)
Deferred income taxes and investment tax credits, net
   
(37,851
)
 
37,138
   
24,034
   
(56,995
)
Deferred rents and lease market valuation liability
   
29,834
   
28,402
   
(71,275
)
 
(52,182
)
Accrued retirement benefit obligations
   
56,116
   
42,397
   
104,488
   
106,897
 
Accrued compensation, net
   
4,380
   
25,864
   
(32,895
)
 
48,186
 
Commodity derivative transactions, net
   
(55,101
)
 
17,336
   
(40,993
)
 
(37,443
)
Cash collateral from suppliers
   
76,978
   
-
   
76,978
   
-
 
Income from discontinued operations (Note 6)
   
(528
)
 
(2,497
)
 
(18,451
)
 
(6,332
)
Pension trust contribution
   
-
   
(500,000
)
 
-
   
(500,000
)
Decrease (increase) in operating assets -
                         
Receivables
   
(90,673
)
 
16,288
   
(225,982
)
 
187,730
 
Materials and supplies
   
11,976
   
6,210
   
(39,876
)
 
7,173
 
Prepayments and other current assets
   
102,025
   
46,969
   
(57,192
)
 
(42,625
)
Increase (decrease) in operating liabilities -
                         
Accounts payable
   
(44,369
)
 
(37,049
)
 
59,662
   
(145,691
)
Accrued taxes
   
167,851
   
152,009
   
207,006
   
296,668
 
Accrued interest
   
95,721
   
82,221
   
91,934
   
75,158
 
Prepayment for electric service - education programs
   
-
   
-
   
241,685
   
-
 
Other
   
(38,799
)
 
15,979
   
(7,416
)
 
32,370
 
Net cash provided from operating activities
   
981,156
   
527,505
   
1,912,272
   
1,538,213
 
                           
CASH FLOWS FROM FINANCING ACTIVITIES:
                         
New Financing -
                         
Long-term debt
   
88,950
   
86,754
   
334,300
   
961,474
 
Short-term borrowings, net
   
-
   
228,072
   
77,295
   
-
 
Redemptions and Repayments -
                         
Preferred stock
   
(30,000
)
 
(1,000
)
 
(169,650
)
 
(1,000
)
Long-term debt
   
(162,939
)
 
(772,451
)
 
(851,687
)
 
(1,752,394
)
Short-term borrowings, net
   
(308,319
)
 
-
   
-
   
(219,032
)
Net controlled disbursement activity
   
(27,118
)
 
(19,129
)
 
(27,594
)
 
(36,400
)
Common stock dividend payments
   
(141,023
)
 
(123,965
)
 
(411,507
)
 
(367,751
)
Net cash used for financing activities
   
(580,449
)
 
(601,719
)
 
(1,048,843
)
 
(1,415,103
)
                           
CASH FLOWS FROM INVESTING ACTIVITIES:
                         
Property additions
   
(294,443
)
 
(211,243
)
 
(756,118
)
 
(545,743
)
Proceeds from asset sales
   
-
   
1,662
   
61,207
   
213,109
 
Proceeds from certificates of deposit
   
-
   
277,763
   
-
   
277,763
 
Nonutility generation trust contributions
   
-
   
-
   
-
   
(50,614
)
Contributions to nuclear decommissioning trusts
   
(25,370
)
 
(25,370
)
 
(76,112
)
 
(76,112
)
Cash investments
   
(13,950
)
 
(7,316
)
 
21,171
   
19,640
 
Other
   
23,120
   
7,072
   
(26,706
)
 
(7,236
)
Net cash provided from (used for) investing activities
   
(310,643
)
 
42,568
   
(776,558
)
 
(169,193
)
                           
Net change in cash and cash equivalents
   
90,064
   
(31,646
)
 
86,871
   
(46,083
)
Cash and cash equivalents at beginning of period
   
49,748
   
99,538
   
52,941
   
113,975
 
Cash and cash equivalents at end of period
 
$
139,812
 
$
67,892
 
$
139,812
 
$
67,892
 
                           
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these
   
statements.
                         
                           
 
 
29



Report of Independent Registered Public Accounting Firm









To the Stockholders and Board of
Directors of FirstEnergy Corp.:

We have reviewed the accompanying consolidated balance sheet of FirstEnergy Corp. and its subsidiaries as of September 30, 2005, and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month and nine-month periods ended September 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2004, and the related consolidated statements of income, capitalization, common stockholders’ equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 2(K) to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 7 to those consolidated financial statements) dated March 7, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.




PricewaterhouseCoopers LLP
Cleveland, Ohio
November 1, 2005


 
 
30



FIRSTENERGY CORP.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION


EXECUTIVE SUMMARY


Net income in the third quarter of 2005 was $332 million, or basic and diluted earnings of $1.01 per share of common stock, compared to net income of $299 million, or basic and diluted earnings of $0.91 per share of common stock for the third quarter of 2004. Net income in the first nine months of 2005 was $670 million, or basic earnings of $2.04 per share of common stock ($2.03 diluted) compared to $677 million in the first nine months of 2004, or basic earnings of $2.07 per share of common stock ($2.06 diluted). The following Non-GAAP Reconciliation displays the unusual items resulting in the difference between GAAP and non-GAAP earnings.

Reconciliation of non-GAAP to GAAP
 
2005
 
2004
 
 
 
After-tax
 
Basic
 
After-tax
 
Basic
 
 
 
Amount
 
Earnings
 
Amount
 
Earnings
 
Three Months Ended September 30,
 
(Millions)
 
Per Share
 
(Millions)
 
Per Share
 
Earnings Before Unusual Items (Non-GAAP)
 
$
342
 
$
1.04
 
$
319
 
$
0.97
 
Unusual Items:
 
 
 
 
 
 
 
 
 
 
 
 
 
Non-core asset sales gains/losses, net
 
 
-
 
 
-
 
 
(16
)
 
(0.05
)
JCP&L arbitration decision
 
 
(10
)
 
(0.03
)
 
-
 
 
-
 
Other
 
 
-
 
 
-
 
 
(4
)
 
(0.01
)
Net Income (GAAP)
 
$
332
 
$
1.01
 
$
299
 
$
0.91
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30,
 
 
 
 
 
 
 
 
 
 
 
 
 
Earnings Before Unusual Items (Non-GAAP)
 
$
730
 
$
2.22
 
$
753
 
$
2.30
 
Unusual Items:
 
 
 
 
 
 
 
 
 
 
 
 
 
Non-core asset sales gains/losses, net
 
 
22
 
 
0.07
 
 
(23
)
 
(0.07
)
Davis-Besse impacts
 
 
-
 
 
-
 
 
(38
)
 
(0.12
)
EPA settlement
 
 
(14
)
 
(0.04
)
 
-
 
 
-
 
NRC fine
 
 
(3
)
 
(0.01
)
 
-
 
 
-
 
JCP&L rate settlement
 
 
16
 
 
0.05
 
 
-
 
 
-
 
JCP&L arbitration decision
 
 
(10
)
 
(0.03
)
 
-
 
 
-
 
Ohio tax write-off
 
 
(71
)
 
(0.22
)
 
-
 
 
-
 
Class-action lawsuit settlement
 
 
-
 
 
-
 
 
(11
)
 
(0.03
)
Other
 
 
-
 
 
-
 
 
(4
)
 
(0.01
)
Net Income (GAAP)
 
$
670
 
$
2.04
 
$
677
 
$
2.07
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

The Non-GAAP measure above, earnings before unusual items, is not calculated in accordance with GAAP because it excludes the impact of "unusual items." Unusual items reflect the impact on earnings of events that are not routine or for which management believes the financial impact will disappear or become immaterial within a near-term finite period. By removing the earnings effect of such issues that have been resolved or are expected to be resolved over the near term, management and investors can better measure FirstEnergy’s business and earnings potential. In particular, the non-core asset sales item refers to a finite set of energy-related assets that have been previously disclosed as held for sale, a substantial portion of which has already been sold. In addition, as Davis-Besse restarted in 2004, further impacts from its extended outage are not expected. Similarly, further litigation settlements similar to the class action settlements in 2004 are not reasonably expected over the near term. Furthermore, FirstEnergy believes presenting normalized earnings calculated in this manner provides useful information to investors in evaluating the ongoing results of its businesses, over the longer term and assists investors in comparing FirstEnergy’s operating performance to the operating performance of others in the energy sector.

On October 3, 2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to 'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one notch above the previous rating. S&P noted that the upgrade followed the continuation of a good operating track record, specifically for the nuclear fleet through the third quarter of 2005. S&P also stated that FirstEnergy’s rating reflects the benefits of supportive regulation, low-cost base load generation fleet, low-risk transmission and distribution operations and rate certainty in Ohio. FirstEnergy’s ability to consistently generate free cash flow, good liquidity, and an improving financial profile were also noted as strengths.

 
 
31

 

On September 20, 2005, FirstEnergy raised its quarterly dividend to $0.43 per share of outstanding common stock - 4.2% higher than the previous quarterly rate of $0.4125 per share. This action represents the second dividend payment increase this year. The dividend payment was last increased by 10% for the dividend paid on March 1, 2005. The new dividend is payable December 1, 2005 to shareholders of record on November 7, 2005. The Company’s dividend policy, established on November 30, 2004, targets sustainable annual dividend increases after 2005, generally reflecting an annual growth rate of 4% to 5%, and an earnings payout ratio generally within the range of 50% to 60%. The Board of Directors will continue to review the Company's dividend policy regularly. The amount and timing of all dividend payments are subject to the Board's consideration of business conditions, results of operations, financial condition and other factors.

On September 9, 2005, FirstEnergy filed on behalf of the Ohio Companies an RCP that, if approved by the PUCO, would essentially maintain current electricity prices through 2008. The RCP was developed as a result of concerns about potential impacts to customer rates due to rising fuel prices and other factors. A stipulated agreement in support of the plan has been signed by the cities of Cleveland and Akron, along with the Industrial Energy Users - Ohio and the Ohio Energy Group. Also, the Mayor of the City of Parma has agreed to support the stipulation. The Parma City Council passed a resolution in support of the RCP plan on September 19, 2005.
 
During the third quarter of 2005, several FirstEnergy operating companies reached employment agreements with various local unions. On July 13, 2005, UWUA 118 and 126 - representing 445 workers - ratified an agreement with OE. On August 17, 2005, UWUA Local 180 - representing 170 workers - ratified an agreement with Penelec. On August 25, 2005, IBEW Local 1194 - representing 240 employees - ratified an agreement with OE. The collective bargaining agreement with IBEW Local 29 representing approximately 450 workers at the Beaver Valley Nuclear Power Station expired pursuant to its terms on September 30, 2005. The parties are currently negotiating a new agreement.

On September 14, 2005, FENOC announced that it would pay the $5.45 million fine proposed in April 2005 by the NRC related to the reactor head issue at the Davis-Besse Nuclear Power Station. FirstEnergy accrued $2.0 million of the fine in 2004 and the remaining amount in the first quarter of 2005. In a letter to the NRC, the Company noted that paying the fine brings regulatory closure to this issue and enables it to continue focusing on safe, reliable plant operations. The letter also reiterated that FENOC acknowledges full responsibility for the significant performance deficiencies that led to the reactor head issue, and that the NRC has indicated that the cited violations regarding the past plant operations do not represent current performance.

FirstEnergy announced on September 22, 2005, that FGCO plans to install an Electro-Catalytic Oxidation (ECO) system on the 215-megawatt Unit 4 of its Bay Shore Plant in Oregon, Ohio. ECO is a multipollutant-control technology for coal-based electric utility plants that was developed by Powerspan Corp., a clean energy technology company in which FirstEnergy has a minority ownership interest.

ECO is currently being demonstrated at FGCO's R. E. Burger Plant, and has proven effective in reducing NOx, SO2, mercury, acid gases, and fine particulates (soot). The ECO process also produces a highly marketable ammonium sulfate fertilizer co-product, currently being sold to the fertilizer market.

FGCO expects design engineering of the Bay Shore ECO system to commence in the first quarter of 2006, and estimates the overall cost of the system, including a fertilizer processing plant, to be approximately $100 million.

FIRSTENERGY’S BUSINESS

FirstEnergy is a registered public utility holding company headquartered in Akron, Ohio that operates primarily through two core business segments.

·
Regulated Services transmits, distributes and sells electricity through eight utility operating companies that collectively comprise the nation’s fifth largest investor-owned electric system, serving 4.5 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey. This business segment primarily derives its revenue from the delivery of electricity, including transition cost recovery.
 
 
32

 

·
Power Supply Management Services supplies the electric power needs of end-use customers (principally in Ohio, Pennsylvania and New Jersey) through retail and wholesale arrangements, including sales to meet the PLR requirements of FirstEnergy’s Ohio Companies and Penn. This business segment operates FirstEnergy's generating facilities and purchases from the wholesale market to meet its sales obligations. Pursuant to an asset transfer on October 24, 2005, it now owns as well as operates FirstEnergy's fossil and hydroelectric generation facilities previously owned by the EUOC. It also purchases the entire output of the nuclear plants currently owned or leased by the EUOC. This business segment principally derives its revenues from electric generation sales.

Other operating segments provide a wide range of services, including heating, ventilation, air-conditioning, refrigeration, electrical and facility control systems, high-efficiency electrotechnologies and telecommunication services. FirstEnergy is in the process of divesting non-core businesses. See Note 6 to the consolidated financial statements. The assets and revenues for the other business operations are below the quantifiable threshold for operating segments for separate disclosure as “reportable segments”.

FIRSTENERGY INTRA-SYSTEM GENERATION ASSET TRANSFERS
 
On May 13, 2005, Penn, and on May 18, 2005 the Ohio Companies, entered into certain agreements implementing a series of intra-system generation asset transfers. When fully completed, the asset transfers will result in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear and non-nuclear plants being owned by NGC, and FGCO, respectively. The generating plant interests that are being transferred do not include leasehold interests of CEI, TE and OE in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates.

On October 24, 2005, the Ohio Companies and Penn completed the intra-system transfer of non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease with the Ohio Companies and Penn, leased, operated and maintained the non-nuclear generation assets that it now owns. The asset transfers were consummated pursuant to the May 13 and May 18, 2005 agreements and FGCO's purchase option under the Master Facility Lease.

As contemplated by the agreements entered into in May 2005, the Ohio Companies and Penn intend to transfer their respective interests in the nuclear generation assets to NGC through, in the case of OE and Penn, a spin-off by way of dividend and, in the case of CEI and TE, a sale at net book value. FENOC currently operates and maintains the nuclear generation assets to be transferred. FirstEnergy currently expects to complete the nuclear asset transfers in the fourth quarter of 2005, subject to the receipt of required regulatory approvals.

These transactions are pursuant to the Ohio Companies’ and Penn’s restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. The transactions will essentially complete the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO without impacting the operation of the plants.

See Note 17 for disclosure of the assets held for sale by the Ohio Companies and Penn as of September 30, 2005.

33

 

RESULTS OF OPERATIONS

The financial results discussed below include revenues and expenses from transactions among FirstEnergy's business segments. A reconciliation of segment financial results is provided in Note 16 to the consolidated financial statements. The FSG business segment is included in “Other and Reconciling Adjustments” in this discussion due to its immaterial impact on current period financial results, but is presented separately in segment information provided in Note 16 to the consolidated financial statements. Net income (loss) by major business segment is as follows:


 
 
 
 
Three Months Ended
 
 
Nine Months Ended 
 
 
 
 
 
 
September 30,
 
Increase
 
September 30,
 
Increase
 
 
 
 
 
2005
 
2004
 
(Decrease)
 
2005
 
2004
 
(Decrease)
 
 
 
 
 
(In millions, except per share amounts)
 
Net Income (Loss)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
By Business Segment:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulated Services
 
 
 
 
$
366
 
$
315
 
$
51
 
$
856
 
$
761
 
$
95
 
Power supply management services
 
 
 
 
 
10
 
 
44
 
 
(34
)
 
(15
 
79
 
 
(94
)
Other and reconciling adjustments*
 
 
 
 
 
(44
)
 
(60
)
 
16
 
 
(171
)
 
(163
)
 
(8
Total
 
 
 
 
$
332
 
$
299
 
$
33
 
$
670
 
$
677
 
$
(7
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Basic Earnings Per Share:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income before discontinued operations
 
 
 
 
$
1.01
 
$
0.90
 
$
0.11
 
$
1.99
 
$
2.05
 
$
(0.06
)
Discontinued operations
 
 
 
 
 
--
 
 
0.01
 
 
(0.01
)
 
0.05
 
 
0.02
 
 
0.03
 
Net earnings per basic share
 
 
 
 
$
1.01
 
$
0.91
 
$
0.10
 
$
2.04
 
$
2.07
 
$
(0.03
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Diluted Earnings Per Share:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income before discontinued operations
 
 
 
 
$
1.01
 
$
0.90
 
$
0.11
 
$
1.98
 
$
2.04
 
$
(0.06
Discontinued operations
 
 
 
 
 
--
 
 
0.01
 
 
(0.01
)
 
0.05
 
 
0.02
 
 
0.03
 
Net earnings per diluted share
 
 
 
 
$
1.01
 
$
0.91
 
$
0.10
 
$
2.03
 
$
2.06
 
$
(0.03
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
* Represents other operating segments and reconciling items including interest expense on holding company debt and corporate support services revenues and expenses.
 


Net income in the regulated services segment for the three months and nine months ended September 30, 2005 increased due to additional customer demand. However, net income for the power supply management services segment was lower in both the three months and nine months ended September 30, 2005 compared to the same periods in 2004, as a result of higher costs for fossil fuel, purchased power (excluding 2004 PJM transactions on a gross basis) and nuclear refueling costs which, in aggregate, more than offset the revenue from increased electric generation sales.

A decrease in wholesale electric revenues and purchased power costs in the 2005 periods compared to the corresponding periods last year primarily resulted from FES recording PJM sales and purchased power transactions on an hourly net position basis beginning in the first quarter of 2005 compared with recording each discrete transaction (on a gross basis) in 2004 (See Note 2 - Accounting for Wholesale Energy Transactions). This change had no impact on earnings and resulted from the dedication of FirstEnergy’s Beaver Valley Power Station to PJM in January 2005. Wholesale electric revenues and purchased power costs in the three months and nine months ended September 30, 2004 each included additional amounts of $264 million and $828 million, respectively, due to recording those transactions on a gross basis.

Excluding the effect of recording the wholesale electric revenue transactions in PJM on a gross basis in 2004, total operating revenues in the three months and nine months ended September 30, 2005 increased 14.9% and 8.7%, respectively, reflecting in large part warmer than normal temperatures during the summer of 2005 compared to 2004.


 
34

 

Summary of Results of Operations - Third Quarter of 2005 compared with the Third Quarter of 2004

Financial results for FirstEnergy and its major business segments in the third quarter of 2005 and 2004 were as follows:

 
 
 
 
Power
 
 
 
 
 
 
 
 
 
Supply
 
Other and
 
 
 
3rd Quarter 2005
 
Regulated
 
Management
 
Reconciling
 
FirstEnergy
 
Quarterly Financial Results
 
Services
 
Services
 
Adjustments
 
Consolidated
 
 
 
(In millions)
 
Revenue:
 
 
 
 
 
 
 
 
 
External
 
 
 
 
 
 
 
 
 
Electric
 
$
1,432
 
$
1,684
 
$
--
 
$
3,116
 
Other 
 
 
244
 
 
28
 
 
199
 
 
471
 
Internal
 
 
79
 
 
--
 
 
(79
 
--
 
Total Revenues
 
 
1,755
 
 
1,712
 
 
120
 
 
3,587
 
                           
Expenses:
 
 
 
 
 
 
 
 
 
 
 
 
 
Fuel and purchased power
 
 
--
 
 
1,287
 
 
--
 
 
1,287
 
Other operating
 
 
511
 
 
364
 
 
118
 
 
993
 
Provision for depreciation
 
 
137
 
 
9
 
 
7
 
 
153
 
Amortization of regulatory assets
 
 
364
 
 
--
 
 
--
 
 
364
 
Deferral of new regulatory assets
 
 
(124
)
 
--
 
 
--
 
 
(124
)
General taxes
 
 
159
 
 
24
 
 
5
 
 
188
 
Total Expenses
 
 
1,047
 
 
1,684
 
 
130
 
 
2,861
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net interest charges
 
 
88
 
 
11
 
 
59
 
 
158
 
Income taxes
 
 
254
 
 
7
 
 
(24
 
237
 
Income before discontinued operations
 
 
366
 
 
10
 
 
(45
 
331
 
Discontinued operations
 
 
--
 
 
--
 
 
1
 
 
1
 
Net Income (Loss)
 
$
366
 
$
10
 
$
(44
$
332
 

 
 
 
 
 
Power
 
 
 
 
 
 
 
 
 
Supply
 
Other and
 
 
 
3rd Quarter 2004
 
Regulated
 
Management
 
Reconciling
 
FirstEnergy
 
Quarterly Financial Results
 
Services
 
Services
 
Adjustments
 
Consolidated
 
 
 
(In millions)
 
Revenue:
 
 
 
 
 
 
 
 
 
External
 
 
 
 
 
 
 
 
 
Electric
 
$
1,309
 
$
1,721
 
$
--
 
$
3,030
 
Other 
 
 
172
 
 
35
 
 
148
 
 
355
 
Internal
 
 
80
 
 
--
 
 
(80
 
--
 
Total Revenues
 
 
1,561
 
 
1,756
 
 
68
 
 
3,385
 
                           
Expenses:
 
 
 
 
 
 
 
 
 
 
 
 
 
Fuel and purchased power
 
 
--
 
 
1,285
 
 
--
 
 
1,285
 
Other operating
 
 
414
 
 
356
 
 
99
 
 
869
 
Provision for depreciation
 
 
129
 
 
9
 
 
9
 
 
147
 
Amortization of regulatory assets
 
 
324
 
 
--
 
 
--
 
 
324
 
Deferral of new regulatory assets
 
 
(79
)
 
--
 
 
--
 
 
(79
)
General taxes
 
 
150
 
 
23
 
 
5
 
 
178
 
Total Expenses
 
 
938
 
 
1,673
 
 
113
 
 
2,724
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net interest charges
 
 
82
 
 
9
 
 
60
 
 
151
 
Income taxes
 
 
226
 
 
30
 
 
(42
 
214
 
Income before discontinued operations
 
 
315
 
 
44
 
 
(63
 
296
 
Discontinued operations
 
 
--
 
 
--
 
 
3
 
 
3
 
Net Income (Loss)
 
$
315
 
$
44
 
$
(60
$
299
 
 
 
35

 
Change Between
 
   
Power
       
 
3rd Quarter 2005 and 2004
 
 
 
Supply
 
Other and
 
 
 
Quarterly Financial Results
 
Regulated
 
Management
 
Reconciling
 
FirstEnergy
 
Increase (Decrease)
 
Services
 
Services
 
Adjustments(1)
 
Consolidated
 
 
 
(In millions)
 
Revenue:
 
 
 
 
 
 
 
 
 
External
 
 
 
 
 
 
 
 
 
Electric 
 
$
123
 
$
(37
$
--
 
$
86
 
Other 
 
 
72
 
 
(7
 
51
 
 
116
 
Internal
 
 
(1
 
--
 
 
1
 
 
--
 
Total Revenues
 
 
194
 
 
(44
 
52
 
 
202
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expenses:
 
 
 
 
 
 
 
 
 
 
 
 
 
Fuel and purchased power
 
 
--
 
 
2
 
 
--
 
 
2
 
Other operating
 
 
97
 
 
8
 
 
19
 
 
124
 
Provision for depreciation
 
 
8
 
 
--
 
 
(2
 
6
 
Amortization of regulatory assets
 
 
40
 
 
--
 
 
--
 
 
40
 
Deferral of new regulatory assets
 
 
(45
)
 
--
 
 
--
 
 
(45
)
General taxes
 
 
9
 
 
1
 
 
--
 
 
10
 
Total Expenses
 
 
109
 
 
11
 
 
17
 
 
137
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net interest charges
 
 
6
 
 
2
 
 
(1
 
7
 
Income taxes
 
 
28
 
 
(23
 
18
 
 
23
 
Income before discontinued operations
 
 
51
 
 
(34
 
18
 
 
35
 
Discontinued operations
 
 
--
 
 
--
 
 
(2
 
(2
Net Income (Loss)
 
$
51
 
$
(34
$
16
 
$
33
 
 
(1) The impact of the new Ohio tax legislation is included with FirstEnergy’s other operating segments and reconciling adjustments.


Regulated Services - Third Quarter 2005 Compared with Third Quarter 2004
 
Net income increased $51 million, or 16% to $366 million, in the third quarter of 2005 compared to $315 million in the third quarter of 2004, as a result of increased customer usage.

Revenues -

Total revenues increased by $194 million in the third quarter 2005 compared to the same period in 2004, resulting from the following sources:
 

 
 
Three Months Ended 
 
 
 
 
September 30,
 
 
 
Revenues by Type of Service
 
2005
 
2004
 
Increase
 
 
 
(In millions)
 
 
 
 
 
 
 
 
Distribution services
 
$
1,432
 
$
1,309
 
$
123
 
Transmission services
 
 
117
 
 
81
 
 
36
 
Lease revenue from affiliates
 
 
79
 
 
79
 
 
--
 
Other
 
 
127
 
 
92
 
 
35
 
Total Revenues
 
$
1,755
 
$
1,561
 
$
194
 

Changes in distribution deliveries by customer class in the third quarter of 2005 compared with the third quarter of 2004 are summarized in the following table:
 
 
 
 
 
 
 
Electric Distribution Deliveries 
 
 
 
Increase
 
Residential
 
 
   
 
15.4
%
Commercial
 
 
   
 
7.8
%
Industrial
 
 
   
 
5.2
%
Total Distribution Deliveries
 
 
   
 
9.6
%
 
 
 
 
 
 
 
 
 
 
36

 
Increased consumption offset in part by lower composite prices to customers resulted in higher distribution delivery revenue. The following table summarizes major factors contributing to the $123 million increase in distribution services revenue in the third quarter of 2005:

 
 
Increase
 
Sources of Change in Distribution Revenues
 
(Decrease)
 
 
 
(In millions)
 
 
 
 
 
Changes in customer usage
 
$
135
 
Changes in prices:
 
 
 
 
Rate changes --
 
 
 
 
Ohio shopping credits
 
 
(11
)
JCP&L rate settlements
 
 
21
 
Billing component reallocations
   
(22
)
Net Increase in Distribution Revenues
 
$
123
 
 

Distribution revenues benefited from warmer summer temperatures in the third quarter of 2005, compared to 2004, that increased the air-conditioning load of residential and commercial customers. While industrial deliveries also increased, that impact was more than offset by lower unit prices to that sector. Higher base rates from JCP&L's stipulated rate settlements were more than offset by additional credits provided to customers under the Ohio transition plan and a reallocation of billing components primarily related to special contracts. Shopping credits do not affect current period earnings due to deferral of the incentives for future recovery from customers.
 
Transmission revenues increased $36 million in the third quarter of 2005 from the same period last year due in part to increased loads due to warmer weather and higher transmission usage prices. Other revenues increased $35 million primarily due to higher gains realized on nuclear decommissioning trust investments.

Expenses-

The increase in total revenues discussed above was partially offset by the following increases in total expenses:

·     Other operating expenses increased by $97 million in the third quarter of 2005 compared to the same
        period in 2004 primarily due to increased transmission expenses resulting in part from increased loads
        and higher transmission system usage charges;

·     Increased provision for depreciation of $8 million that resulted from property additions and increased
        leasehold improvement amortization;

·        Additional amortization of regulatory assets of $40 million, principally Ohio transition costs;

 
·
        Higher general taxes of $9 million resulting from increased EUOC sales which increased the Ohio KWH
        tax and the Pennsylvania gross receipts tax;

·         Increased interest charges of $6 million primarily due to the absence of $11 million in interest rate swap
        savings achieved in the third quarter of 2004; and

·         Higher income taxes of $28 million due to increased taxable income.
 
Partially offsetting those increases was the effect of additional deferred regulatory assets of $45 million, primarily due to the PUCO-approved deferral of MISO administrative costs, shopping incentives and related interest.

Power Supply Management Services - Third Quarter 2005 Compared with Third Quarter 2004

Net income for this segment decreased $34 million to $10 million in the third quarter of 2005 from $44 million in the same period last year, due to a decrease in the gross generation margin and higher operating costs.
 
37


 
Revenues -
 
Excluding the effect of the change in recording PJM wholesale transactions on a gross basis in 2004 ($264 million), electric generation revenues increased $227 million in the third quarter of 2005 compared to the same period of 2004 primarily as a result of a 5.2% increase in KWH sales due to higher retail customer usage and a 21% rise in unit prices in the wholesale market. The increase in retail sales reduced energy available for sale to the wholesale market, resulting in a 9% reduction in wholesale sales (before the PJM adjustment).

The change in reported segment revenues resulted from the following:

 
 
 
Three Months Ended
 
 
 
 
 
September 30,
 
Increase
 
Revenues by Type of Service
 
2005
 
2004
 
(Decrease)
 
   
(In millions)
 
Electric generation sales:
 
 
 
 
 
 
 
Retail 
 
$
1,254
 
$
1,069
 
$
185
 
Wholesale 
 
 
430
 
 
388
 
 
42
 
Total electric generation sales
 
 
1,684
 
 
1,457
 
 
227
 
Transmission
 
 
16
 
 
20
 
 
(4
)
Other
 
 
12
 
 
15
 
 
(3
Total
 
 
1,712
 
 
1,492
 
 
220
 
PJM gross transactions
 
 
--
 
 
264
 
 
(264
)
Total Revenues
 
$
1,712
 
$
1,756
 
$
(44
)


The following table summarizes the price and volume factors contributing to increased sales to retail and wholesale customers.

   
Increase
 
Source of Change in Electric Generation Sales
 
(Decrease)
 
   
(In millions)
 
Retail:
 
 
 
 
Effect of 9.9% increase in customer usage
 
$
113
 
Change in prices
 
 
72
 
 
 
 
185
 
Wholesale:
 
 
 
 
Effect of 8.7% reduction in customer usage(1)
 
 
(41
)
Change in prices
 
 
83
 
 
 
 
42
 
Net Increase in Electric Generation Sales
 
$
227
 
   
(1) Decrease of 46.4% including the effect of the PJM revision.
 
 
 
 
38

 

Expenses -
 
Excluding the effect of $264 million of PJM purchased power costs recorded on a gross basis in 2004, total operating expenses, net interest charges and income taxes increased in aggregate by $254 million in the third quarter of 2005 compared to the same period of 2004. Higher fuel and purchased power costs contributed $2 million ($266 million, net of $264 million PJM effect) of the increase, resulting from higher fuel costs of $121 million and increased purchased power costs of $145 million. Factors contributing to the higher costs are summarized in the following table:

 
 
Increase
 
Source of Change in Fuel and Purchased Power
 
(Decrease)
 
 
 
(In millions)
 
Fuel:
 
 
 
 
Change due to increased unit costs
 
 $
92
 
Change due to volume consumed
 
 
29
 
 
 
 
121
 
Purchased Power:
 
 
 
Change due to increased unit costs
 
 
130
 
Change due to volume purchased
 
 
(16
)
Reduction in costs deferred
 
 
31
 
 
 
 
145
 
PJM gross transactions
 
 
(264
)
Net Increase in Fuel and Purchased Power Costs
 
$
2
 
 
 
 
 
 


FirstEnergy’s generation fleet established an output record of 21.7 billion KWH in the third quarter of 2005. As a result, increased coal consumption and the related cost of emission allowances combined to increase fossil fuel expense. Higher coal costs resulted from increased market purchases, market adjustment provisions in coal contracts reflecting higher market prices and increased transportation costs. Emission allowance costs increased primarily from higher prices. To a lesser extent, fuel expense increased due to higher costs associated with the increase in generation from the fossil units relative to nuclear generation. Fossil generation output increased 16% in the third quarter of 2005 while nuclear output increased by 1%, compared to the same period in 2004.

Other operating costs increased $8 million in the third quarter of 2005 compared to the same period of 2004. This increase resulted from higher transmission costs due primarily to increased loads and higher transmission system usage charges. The higher costs this year were offset in part by lower non-fuel nuclear costs resulting from expenses incurred late in the third quarter of 2004 in preparation for the fourth quarter of 2004 Beaver Valley Unit 1 refueling outage.

Offsetting higher operating costs were lower income taxes of $23 million due to lower taxable income.

Other - Third Quarter 2005 Compared with Third Quarter 2004

FirstEnergy’s financial results from other operating segments and reconciling adjustments, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a net increase of $16 million in net income in the third quarter of 2005 compared to the same quarter of 2004. The increase was primarily due to the absence this year of losses recognized in 2004 on the sale of securities and impairment of several partnership investments.



39

 

Summary of Results of Operations - Nine Months ended September 30, 2005 compared with the Nine Months ended September 30, 2004

Financial results for FirstEnergy and its major business segments for the nine months ended September 30, 2005 and 2004 were as follows:
 
 
 
 
 
 
Power
 
 
 
 
 
 
 
 
 
 
Supply
 
Other and
 
 
 
Nine Months ended September 30, 2005
 
 
Regulated
 
Management
 
Reconciling
 
FirstEnergy
 
Financial Results
 
 
Services
 
Services
 
Adjustments
 
Consolidated
 
 
 
 
(In millions)
 
Revenue:
 
 
 
 
 
 
 
 
 
 
  External
 
 
 
 
 
 
 
 
 
 
Electric 
 
 
 
$
3,759
 
$
4,273
 
$
-
 
$
8,032
 
Other 
 
 
 
 
607
 
 
73
 
 
565
 
 
1,245
 
Internal
 
 
 
 
237
 
 
-
 
 
(237
 
-
 
Total Revenues
 
 
 
 
4,603
 
 
4,346
 
 
328
 
 
9,277
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expenses:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fuel and purchased power
 
 
 
 
-
 
 
3,115
 
 
-
 
 
3,115
 
Other operating
 
 
 
 
1,336
 
 
1,132
 
 
290
 
 
2,758
 
Provision for depreciation
 
 
 
 
397
 
 
26
 
 
21
 
 
444
 
Amortization of regulatory assets
 
 
 
 
982
 
 
-
 
 
-
 
 
982
 
Deferral of new regulatory assets
 
 
 
 
(303
)
 
-
 
 
-
 
 
(303
)
General taxes
 
 
 
 
455
 
 
69
 
 
17
 
 
541
 
Total Expenses
 
 
 
 
2,867
 
 
4,342
 
 
328
 
 
7,537
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net interest charges
 
 
 
 
285
 
 
29
 
 
175
 
 
489
 
Income taxes
 
 
 
 
595
 
 
(10
 
14
 
 
599
 
Income before discontinued operations
 
 
 
 
856
 
 
(15
 
(189
 
652
 
Discontinued operations
 
 
 
 
-
 
 
-
 
 
18
 
 
18
 
Net Income (Loss)
 
 
 
$
856
 
$
(15
$
(171
$
670
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


 
 
 
 
 
Power
 
 
 
 
 
 
 
 
 
 
Supply
 
Other and
 
 
 
Nine Months ended September 30, 2004
 
 
Regulated
 
Management
 
Reconciling
 
FirstEnergy
 
Financial Results
 
 
Services
 
Services
 
Adjustments
 
Consolidated
 
 
 
 
(In millions)
 
Revenue:
 
 
 
 
 
 
 
 
 
 
  External
 
 
 
 
 
 
 
 
 
 
Electric 
 
 
 
$
3,588
 
$
4,742
 
$
--
 
$
8,330
 
Other 
 
 
 
 
461
 
 
86
 
 
484
 
 
1,031
 
Internal
 
 
 
 
239
 
 
--
 
 
(239
 
--
 
Total Revenues
 
 
 
 
4,288
 
 
4,828
 
 
245
 
 
9,361
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expenses:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fuel and purchased power
 
 
 
 
--
 
 
3,515
 
 
--
 
 
3,515
 
Other operating
 
 
 
 
1,155
 
 
1,058
 
 
288
 
 
2,501
 
Provision for depreciation
 
 
 
 
384
 
 
26
 
 
29
 
 
439
 
Amortization of regulatory assets
 
 
 
 
905
 
 
--
 
 
--
 
 
905
 
Deferral of new regulatory assets
 
 
 
 
(192
)
 
--
 
 
--
 
 
(192
)
General taxes
 
 
 
 
433
 
 
65
 
 
16
 
 
514
 
Total Expenses
 
 
 
 
2,685
 
 
4,664
 
 
333
 
 
7,682
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net interest charges
 
 
 
 
301
 
 
30
 
 
171
 
 
502
 
Income taxes
 
 
 
 
541
 
 
55
 
 
(90
 
506
 
Income before discontinued operations
 
 
 
 
761
 
 
79
 
 
(169
 
671
 
Discontinued operations
 
 
 
 
--
 
 
--
 
 
6
 
 
6
 
Net Income (Loss)
 
 
 
$
761
 
$
79
 
$
(163
$
677
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


40



 
 
 
 
 
Power
 
 
 
 
 
Change Between Nine Months ended
 
 
 
 
Supply
 
Other and
 
 
 
September 30, 2005 vs. 2004
 
 
Regulated
 
Management
 
Reconciling
 
FirstEnergy
 
Financial Results
 
 
Services
 
Services
 
Adjustments(1)
 
Consolidated
 
 Increase (Decrease)
 
 
(In millions)
 
Revenue:
 
 
 
 
 
 
 
 
 
 
  External
 
 
 
 
 
 
 
 
 
 
Electric 
 
 
 
$
171
 
$
(469
$
-
 
$
(298
)
Other 
 
 
 
 
146
 
 
(13
 
81
 
 
214
 
Internal
 
 
 
 
(2
 
-
 
 
2
 
 
-
 
Total Revenues
 
 
 
 
315
 
 
(482
 
83
 
 
(84
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expenses:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fuel and purchased power
 
 
 
 
-
 
 
(400
 
-
 
 
(400
)
Other operating
 
 
 
 
181
 
 
74
 
 
2
 
 
257
 
Provision for depreciation
 
 
 
 
13
 
 
-
 
 
(8
 
5
 
Amortization of regulatory assets
 
 
 
 
77
 
 
-
 
 
-
 
 
77
 
Deferral of new regulatory assets
 
 
 
 
(111
)
 
-
 
 
-
 
 
(111
)
General taxes
 
 
 
 
22
 
 
4
 
 
1
 
 
27
 
Total Expenses
 
 
 
 
182
 
 
(322
 
(5
 
(145
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net interest charges
 
 
 
 
(16
 
(1
 
4
 
 
(13
)
Income taxes
 
 
 
 
54
 
 
(65
 
104
 
 
93
 
Income before discontinued operations
 
 
 
 
95
 
 
(94
 
(20
 
(19
)
Discontinued operations
 
 
 
 
-
 
 
-
 
 
12
 
 
12
 
Net Income (Loss)
 
 
 
$
95
 
$
(94
$
(8
$
(7
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) The impact of the new Ohio tax legislation is included with FirstEnergy's other operating segments and reconciling adjustments.


Regulated Services - Nine Months ended September 30, 2005 compared with Nine Months ended September 30, 2004
 
Net income increased $95 million to $856 million in the nine months ended September 30, 2005, from $761 million in the same period of 2004, due to increased revenues partially offset by higher expenses and taxes.

Revenues -

The increase in total revenues resulted from the following:

 
 
Nine Months Ended
 
 
 
 
 
September 30,
 
Increase
 
Revenues by Type of Service
 
2005
 
2004
 
(Decrease)
 
 
 
(In millions)
 
 
 
 
 
 
 
 
 
Distribution services
 
$
3,759
 
$
3,588
 
$
171
 
Transmission services
 
 
314
 
 
210
 
 
104
 
Lease revenue from affiliates
 
 
237
 
 
239
 
 
(2
)
Other
 
 
293
 
 
251
 
 
42
 
Total Revenues
 
$
4,603
 
$
4,288
 
$
315
 
 
 
 
 
 
 
 
 
 
 
 


Changes in distribution deliveries by customer class are summarized in the following table:

Electric Distribution Deliveries
 
Increase
 
 
 
 
 
Residential
 
 
7.9
%
Commercial
 
 
5.2
%
Industrial
 
 
1.8
%
Total Distribution Deliveries
 
 
5.0
%
 
 
 
 
 

 
41

 

Increased customer consumption offset in part by lower prices resulted in higher distribution delivery revenues. The following table summarizes major factors contributing to the $171 million increase in distribution services revenue in the first nine months of 2005:

 
 
Increase
 
Sources of Change in Distribution Revenues
 
(Decrease)
 
 
 
(In millions)
 
 
 
 
 
Changes in customer usage
 
$
210
 
Changes in prices:
 
 
 
 
Rate changes - 
 
 
 
 
Ohio shopping credits
 
 
(33
)
JCP&L rate settlements
 
 
28
 
   Billing component reallocation
   
(34
)
 Net Increase in Distribution Revenues
 
$
171
 
 

Distribution revenues benefited from warmer temperatures in the summer months of 2005 compared to 2004 that increased the air-conditioning load of residential and commercial customers. The effect of higher base rates for JCP&L's stipulated rate settlements in 2005 were more than offset by additional credits provided to customers under the Ohio transition plan and a reallocation of billing components primarily related to special contracts. Shopping credits do not affect current period earnings due to deferral of the incentives for future recovery from customers. While industrial deliveries also increased they were more than offset by lower unit prices.

Transmission revenues increased $104 million in the nine months ended September 30, 2005 compared to the same period last year due in part to the June 2004 amended power supply agreement with FES and increased loads due to warmer summer weather and higher transmission usage prices. Other revenues increased $42 million primarily due to higher gains realized on nuclear decommissioning trust investments.

Expenses-
 
Total operating expenses, net of interest charges and income taxes increased in aggregate by $220 million in the nine months ended September 30, 2005 compared to the same period in 2004 due to the following:


    ·
Other operating expenses increased $181 million principally due to higher transmission expenses resulting from an amended power supply agreement with FES, increased loads, and higher transmission system usage charges;


    ·
Provision for depreciation increased $13 million reflecting the effect of property additions, additional costs for decommissioning the Saxton nuclear unit and increased leasehold improvement amortization, reflecting shorter lives associated with capital additions for leased generating plants of the Ohio Companies to correspond to the remaining lease terms;

    ·
Additional amortization of regulatory assets of $77 million, principally Ohio transition costs;
 
 
    ·
   Higher general taxes of $22 million resulting from increased EUOC sales which increased the Ohio KWH
   tax and the Pennsylvania gross receipts tax and the absence in 2005 of Pennsylvania property tax
   refunds recognized in 2004; and

 
    ·
Higher income taxes of $54 million due to increased taxable income.

The following partially offset these higher costs:

    ·
Additional deferrals of regulatory assets of $111 million, stemming from the deferral of PUCO-approved
MISO administrative costs, JCP&L reliability improvements, shopping incentive credits and relat
interest on those deferrals (see Note 14 - Regulatory Matters - Transmission, New Jersey); and
       
    ·
Lower interest charges of $16 million resulting from debt and preferred stock redemptions and refinancings.
 
       
42

 

 
Power Supply Management Services - Nine Months ended September 30, 2005 compared with the Nine Months ended September 30, 2004
 
The net loss for this segment was $15 million for the nine months ended September 30, 2005 compared to net income of $79 million in the same period last year. A reduction in the gross generation margin, higher nuclear operating costs and amounts recognized for fines, penalties and obligations associated with proceedings involving the W.H. Sammis Plant and the Davis-Besse Nuclear Power Station contributed to the 2005 net loss.

Revenues -
 
Excluding the effect of the change in recording PJM wholesale transactions on a gross basis in 2004 ($828 million), electric generation revenues increased $359 million in the nine months ended September 30, 2005 compared to the same period of 2004 as a result of a 2.4% increase in KWH sales and higher unit prices.

The change in reported segment revenues resulted from the following:

 
 
Nine Months Ended
 
 
 
 
 
September 30,
 
Increase
 
Revenues by Type of Service
 
2005
 
2004
 
(Decrease)
 
 
 
(In millions)
 
 
 
 
 
 
 
 
 
Electric generation sales:
 
 
 
 
 
 
 
Retail 
 
$
3,223
 
$
2,933
 
$
290
 
Wholesale(1) 
 
 
1,050
 
 
981
 
 
69
 
Total Electric Generation Sales
 
 
4,273
 
 
3,914
 
 
359
 
Transmission
 
 
41
 
 
57
 
 
(16
)
Other
 
 
32
 
 
29
 
 
3
 
Total
 
 
4,346
 
 
4,000
 
 
346
 
PJM gross transactions
 
 
-
 
 
828
 
 
(828
)
Total Revenues
 
$
4,346
 
$
4,828
 
$
(482
)
 
 
 
 
 
 
 
 
 
 
 
(1) Excluding 2004 PJM effect of gross transactions.
   


Higher electric generation sales resulted from increased unit prices and increased retail customer usage. The following table summarizes the price and volume factors contributing to the increased sales to retail and wholesale customers.
 
Source of Change in Electric Generation Sales
 
 
 
 
 
(In millions)
 
Retail:
 
 
 
 
Effect of 4.5% increase in customer usage
 
$
140
 
Change in prices
 
 
150
 
 
 
 
290
 
Wholesale:
 
 
 
 
Effect of 4.4% reduction in customer usage(1)
 
 
(48
Change in prices
 
 
117
 
 
 
 
69
 
Net Increase in Electric Generation Sales
 
$
359
 
   
(1) Decrease of 47.3% including the effect of the PJM revision.
 


 
43


Expenses -
 
Excluding the effect of $828 million of PJM purchased power costs recorded on a gross basis in 2004, total operating expenses, net interest charges and income taxes increased in aggregate by $440 million in the nine months ended September 30, 2005 compared to the same period of 2004. Higher fuel and purchased power costs contributed $428 million of the increase, resulting from higher fuel costs of $245 million and increased purchased power costs of $183 million. Factors contributing to the higher costs are summarized in the following table:

 
 
 
Increase
 
Source of Change in Fuel and Purchased Power
 
(Decrease)
 
 
 
(In millions)
 
       
Fuel:
 
 
 
 
Change due to unit costs
 
 $
212
 
Change due to volume consumed
 
 
33
 
 
 
 
245
 
 
 
 
 
Purchased Power:
 
 
 
Change due to unit costs
 
 
255
 
Change due to volume purchased
 
 
(53
)
Increase in deferred costs
 
 
(19
)
 
 
 
183
 
PJM Gross Transactions
 
 
(828
Net Decrease in Fuel and Purchased Power Costs
 
$
(400


FirstEnergy’s generation fleet established an output record of 59.5 billion KWH for the nine months ended September 30, 2005. Higher coal costs resulted from increased consumption, market adjustment provisions in coal contracts reflecting higher market prices and increased transportation costs. Emission allowance costs increased primarily from higher prices. To a lesser extent, fuel expense increased due to the mix of fossil versus nuclear generation resulting from the nuclear refueling outages in the first nine months of 2005 following a year with no scheduled nuclear refueling outages and improved performance of fossil generating units. Fossil generation increased 12% in the nine months ended September 30, 2005 while nuclear generation decreased by 8% compared to the same period of 2004.

Other operating costs increased $74 million in the nine months ended September 30, 2005 compared to the same period of 2004. This increase resulted from higher non-fuel nuclear costs. The increase in non-fuel nuclear costs resulted from 2005 refueling outages at Perry Unit 1 (including an unplanned extension) and Beaver Valley Unit 2 and a scheduled 23-day mid-cycle inspection outage at the Davis-Besse nuclear plant. There were no scheduled nuclear refueling outages in the first nine months of 2004. Also included in other operating costs for 2005 were the EPA settlement loss and NRC fine described above. Offsetting the higher other operating costs were reduced non-fuel fossil generation expense of $17 million due to reduced maintenance outages in 2005 and lower transmission costs of $15 million, due to an amended power supply agreement with Met-Ed and Penelec.

Partially offsetting the increase in other operating costs were lower income taxes of $65 million due to lower taxable income.

Other - Nine Months ended September 30, 2005 compared with the Nine Months ended September 30, 2004

FirstEnergy’s financial results from other operating segments and reconciling adjustments, including interest expense on holding company debt and corporate support services revenues and expenses and the impacts of the new Ohio tax legislation (discussed below) resulted in a decrease in FirstEnergy’s net income in the nine months ended September 30, 2005 compared to the same period of 2004. The decrease primarily reflected the effect of the new Ohio tax legislation partially offset by the effect of discontinued operations, which included an after-tax net gain of $17 million in 2005 (see Note 6). The following table summarizes the sources of income from discontinued operations:

 
 
Nine Months Ended
 
 
 
 
 
September 30,
 
Increase
 
 
 
2005
 
2004
 
(Decrease)
 
 
 
(In millions)
 
Discontinued operations (net of tax)
 
 
 
 
 
 
 
Gain on sale:
 
 
 
 
 
 
 
 
 
 
Retail gas business
 
$
5
 
$
-
 
$
5
 
FSG and MYR Subsidiaries
 
 
12
 
 
-
 
 
12
 
Reclassification of operating income
 
 
2
 
 
6
 
 
(4
)
Total
 
$
19
 
$
6
 
$
13
 
 
 
 
 
 
 
 
 
 
 
 

 
 
44


On June 30, 2005, the State of Ohio enacted new tax legislation that created a new CAT tax, which is based on qualifying “taxable gross receipts” and will not consider any expenses or costs incurred to generate such receipts, except for items such as cash discounts, returns and allowances, and bad debts. The CAT tax was effective July 1, 2005, and replaces the Ohio income-based franchise tax and the Ohio personal property tax. The CAT tax is phased-in while the current income-based franchise tax is phased-out over a five-year period at a rate of 20% annually, beginning with the year ended 2005, and the personal property tax is phased-out over a four-year period at a rate of approximately 25% annually, beginning with the year ended 2005. For example, during the phase-out period the Ohio income-based franchise tax will be computed consistently with the prior tax law, except that the tax liability as computed will be multiplied by 4/5 in 2005; 3/5 in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current income-based franchise tax over a five-year period. As a result of the new tax structure, all net deferred tax benefits that are not expected to reverse during the five-year phase-in period were written-off as of June 30, 2005. The impact on income taxes associated with the required adjustment to net deferred taxes for the nine months ended September 30, 2005 was an additional tax expense of approximately $72 million, which was partially offset by the initial phase-out of the Ohio income-based franchise tax, which reduced income taxes by approximately $8 million in the nine months ended September 30, 2005. See Note 12 to the consolidated financial statements.

Postretirement Benefits

Postretirement benefits expense decreased by $17 million in the third quarter of 2005 and $54 million in the nine months ended September 30, 2005 compared to the corresponding periods of 2004. Pension costs represent most of the reduction due to a $500 million voluntary contribution made in 2004 and an increase in the market value of plan assets during 2004. The following table summarizes the net pension and OPEB expense (excluding amounts capitalized) for the three months and nine months ended September 30, 2005 and 2004.

   
Three Months Ended
     
Nine Months Ended
     
Postretirement
 
September 30,
 
Increase
 
September 30,
 
Increase
 
Benefits Expense *
 
2005
 
2004
 
(Decrease)
 
2005
 
2004
 
(Decrease)
 
 
 
(In millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pension
 
$
8
 
$
21
 
$
(13
)
$
24
 
$
64
 
$
(40
)
OPEB
 
 
18
 
 
22
 
 
(4
)
 
54
 
 
68
 
 
(14
)
Total
 
$
26
 
$
43
 
$
(17
)
$
78
 
$
132
 
$
(54
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
* Excludes the capitalized portion of postretirement benefits costs (see Note 10 for total costs).
 
 

The decrease in pension and OPEB expenses are included in various cost categories and have contributed to other cost reductions discussed above.

CAPITAL RESOURCES AND LIQUIDITY

FirstEnergy’s cash requirements in 2005 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing FirstEnergy’s net debt and preferred stock outstanding. Borrowing capacity under credit facilities is available to manage working capital requirements.

Changes in Cash Position

The primary source of ongoing cash for FirstEnergy, as a holding company, is cash dividends from its subsidiaries. The holding company also has access to $2.0 billion of short-term financing under a revolving credit facility, subject to short-term debt limitations under current regulatory approvals of $1.5 billion and to outstanding borrowings by subsidiaries of FirstEnergy who are also parties to such facility. In the third quarter of 2005, FirstEnergy received $306 million of cash dividends from its subsidiaries and paid $141 million in cash dividends to its common shareholders - in the first nine months of 2005, it received and paid $846 million and $412 million, respectively. There are no material restrictions on the payment of cash dividends by FirstEnergy’s subsidiaries.

As of September 30, 2005, FirstEnergy had $140 million of cash and cash equivalents ($3 million restricted as an indemnity reserve) compared with $53 million ($3 million restricted as an indemnity reserve) as of December 31, 2004. The major sources for changes in these balances are summarized below.



45


Cash Flows From Operating Activities
    

FirstEnergy's consolidated net cash from operating activities is provided primarily by its regulated and power supply businesses (see “RESULTS OF OPERATIONS” above). Net cash provided by operating activities was $981 million and $528 million in the third quarter of 2005 and 2004, respectively, and $1.9 billion and $1.5 billion in the first nine months of 2005 and 2004, respectively, summarized as follows:

 
 
Three Months Ended
 
 Nine Months Ended
 
 
 
September 30,
 
September 30,
 
Operating Cash Flows
 
2005
 
2004
 
 2005
 
2004
 
 
 
(In millions)  
 
 
 
 
 
 
 
  
 
 
 
Cash earnings (1)
 
$
777
 
$
545
 
$
1,642
 
$
1,427
 
Pension trust contribution(2)
   
-
   
(300
)
 
-
   
(300
)
Working capital and other
 
 
204
 
 
283
 
 
270
 
 
411
 
Total cash flows from operating activities
 
$
981
 
$
528
 
$
1,912
 
$
1,538
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) Cash earnings are a non-GAAP measure (see reconciliation below).
 
(2) Pension trust contribution net of $200 million of income tax benefits.
 
 

Cash earnings, as disclosed in the table above, are not a measure of performance calculated in accordance with GAAP. FirstEnergy believes that cash earnings is a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income.

 
 
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
 Reconciliation of Cash Earnings
 
2005
 
2004
 
2005
 
2004
 
 
 
(In millions)
 
 
 
 
 
 
 
 
 
 
 
Net income (GAAP)
 
$
332
 
$
299
 
$
670
 
$
677
 
Non-cash charges (credits):
 
 
 
 
 
 
 
 
 
 
 
 
 
Provision for depreciation
 
 
153
 
 
147
 
 
444
 
 
439
 
Amortization of regulatory assets
 
 
364
 
 
324
 
 
982
 
 
905
 
Deferral of new regulatory assets
 
 
(124
)
 
(79
)
 
(303
)
 
(191
)
Nuclear fuel and lease amortization
 
 
26
 
 
27
 
 
63
 
 
72
 
Deferred purchased power and other costs
 
 
(39
)
 
(118
)
 
(231
)
 
(263
)
Deferred income taxes and investment tax credits(1)
 
 
(38
 
(163
)
 
24
 
 
(257
)
Deferred rents and lease market valuation liability
 
 
30
 
 
28
 
 
(71
)
 
(52
)
Accrued retirement benefit obligations
   
56
   
42
   
104
   
107
 
Income from discontinued operations
 
 
(1
 
(2
)
 
(18
)
 
(6
)
Other non-cash expenses
 
 
18
 
 
40
 
 
(22
)
 
(4
)
Cash earnings (non-GAAP)
 
$
777
 
$
545
 
$
1,642
 
$
1,427
 
(1) Excludes $200 million of deferred tax benefits from pension contribution in 2004. 
 


In the three months and nine months ended September 30, 2005, cash earnings increased $232 million and $215 million, respectively. Both periods benefited from increased generation and distribution revenues aided by warmer summer temperatures that increased air conditioning load. In the third quarter of 2005 compared with the third quarter of 2004, cash provided from working capital decreased by $79 million, primarily due to changes in receivables. The use of cash for receivables resulted in part from the conversion of the CFC accounts receivable financing to an on-balance sheet transaction, which added $35 million of receivables to the balance sheet as of September 30, 2005. In the first nine months of 2005 compared to the first nine months of 2004, working capital changes provided $141 million less cash due in part to changes in receivables, materials and supplies, prepayments and accrued taxes, offset by accounts payable and the funds received as prepayment for electric usage, under the three-year Energy for Education II Program with the Ohio Schools Council.
 
 
46


Cash Flows From Financing Activities
 
In the third quarter and first nine months of 2005, cash used for financing activities was $580 million and $1.0 billion, respectively, compared to $602 million and $1.4 billion in the third quarter and first nine months of 2004, respectively. The following table summarizes security issuances and redemptions.

 
 
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
Securities Issued or Redeemed
 
2005
 
2004
 
2005
 
2004
 
 
 
(In millions)
 
 
 
 
 
 
 
 
 
 
 
New issues
 
 
 
 
 
 
 
 
 
Pollution control notes
 
$
89
 
$
77
 
$
334
 
$
261
 
Secured notes
 
 
-
 
 
-
 
 
-
 
 
550
 
Long-term revolving credit
   
-
   
10
   
-
   
-
 
Unsecured notes
 
 
-
 
 
-
 
 
-
 
 
150
 
 
 
$
89
 
$
87
 
$
334
 
$
961
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Redemptions
 
 
 
 
 
 
 
 
 
 
 
 
 
First mortgage bonds
 
$
-
 
$
206
 
$
178
 
$
588
 
Pollution control notes
 
 
130
 
 
80
 
 
377
 
 
80
 
Secured notes
 
 
25
 
 
374
 
 
74
 
 
447
 
Long-term revolving credit
 
 
-
 
 
-
 
 
215
 
 
300
 
Unsecured notes
 
 
8
 
 
112
 
 
8
 
 
337
 
Preferred stock
 
 
30
 
 
1
 
 
170
 
 
1
 
 
 
$
193
 
$
773
 
$
1,022
 
$
1,753
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Short-term borrowings, net increase (decrease)
 
$
(308
$
228
 
$
77
 
$
(219
)


FirstEnergy had approximately $247 million of short-term indebtedness as of September 30, 2005 compared to approximately $170 million as of December 31, 2004. Available bank borrowings as of September 30, 2005 included the following:

Borrowing Capability
 
FirstEnergy
 
 
Penelec
 
Total
 
 
 
(In millions)
 
 
 
 
 
 
 
 
 
 
Short-term credit(1)
 
$
2,020
 
 
$
-
 
$
2,020
 
Utilized
 
 
-
 
 
 
-
 
 
-
 
Letters of credit
 
 
(137
)
 
 
-
 
 
(137
)
Net
 
 
1,883
 
 
 
-
 
 
1,883
 
 
 
 
 
 
 
 
 
 
 
 
 
Short-term bank facilities(2)
 
 
-
 
 
 
75
 
 
75
 
Utilized
 
 
-
 
 
 
(75
)
 
(75
)
Net
 
 
-
 
 
 
-
 
 
-
 
Total unused borrowing capability
 
$
1,883
 
 
$
-
 
$
1,883
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) A $2 billion revolving credit facility is available in various amounts to FirstEnergy and certain
  of its subsidiaries, including  Penelec. A $20 million uncommitted line of credit facility added
  in September 2005 is available to FirstEnergy only.
(2) Penelec bank facility terminated on October 7, 2005.


As of October 24, 2005, the Ohio Companies and Penn had the aggregate capability to issue approximately $3.8 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures following the recently completed intra-system transfer of fossil and hydroelectric generating plants (See Note 17). The issuance of FMB by OE and CEI are also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE and CEI to incur additional secured debt not otherwise permitted by a specified exception of up to $690 million and $582 million, respectively, as of October 24, 2005. Under the provisions of its senior note indenture, JCP&L may issue additional FMB only as collateral for senior notes. As of October 24, 2005, JCP&L had the capability to issue $673 million of additional senior notes upon the basis of FMB collateral. Based upon applicable earnings coverage tests in their respective charters, OE, Penn, TE and JCP&L could issue a total of $4.9 billion of preferred stock (assuming no additional debt was issued) as of September 30, 2005. It is estimated that the annualized impact of the intra-system transfer of fossil and hydroelectric generating plants will reduce the aggregate capability of OE, Penn, TE and JCP&L to issue preferred stock by approximately 10%. CEI, Met-Ed and Penelec have no restrictions on the issuance of preferred stock.

 
47

 

As of September 30, 2005, approximately $1 billion remained unused under an existing shelf registration statement, filed by FirstEnergy with the SEC in 2003, to support future securities issues. The shelf registration provides the flexibility to issue and sell various types of securities, including common stock, debt securities, and share purchase contracts and related share purchase units.

FirstEnergy’s and its subsidiaries' working capital and short-term borrowing needs are met principally with a $2 billion five-year revolving credit facility (included in the table above). Borrowings under the facility are available to each borrower separately and will mature on the earlier of 364 days from the date of borrowing and the commitment termination date.

The following table summarizes the borrowing sub-limits for each borrower under the facility, as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations.


 
 
Revolving
 
Regulatory and
 
 
 
Credit Facility
 
Other Short-Term
 
Borrower
 
Sub-Limit
 
Debt Limitations1
 
 
 
(In millions)
 
 
 
 
 
 
 
FirstEnergy
 
$
2,000
 
$
1,500
 
OE
 
 
500
 
 
500
 
Penn
 
 
50
 
 
51
 
CEI
 
 
250
 
 
500
 
TE
 
 
250
 
 
500
 
JCP&L
 
 
425
 
 
416
 
Met-Ed
 
 
250
 
 
300
 
Penelec
 
 
250
 
 
300
 
FES
 
 
-2
 
 
n/a
 
ATSI
 
 
-2
 
 
26
 


(1)         As of September 30, 2005.
 
(2)
Borrowing sublimits for FES and ATSI may be increased to up to $250 million and $100 million, respectively, by delivering notice to the administrative agent that either (i) such borrower has senior unsecured debt ratings of at least BBB- by S&P and Baa3 by Moody’s or (ii) FirstEnergy has guaranteed the obligations of such borrower under the facility.

The revolving credit facility, combined with an aggregate $550 million ($395 million unused as of September 30, 2005) of accounts receivable financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn, are intended to provide liquidity to meet short-term working capital requirements for FirstEnergy and its subsidiaries.

Under the revolving credit facility, borrowers may request the issuance of letters of credit expiring up to one year from the date of issuance. The stated amount of outstanding letters of credit will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit. Total unused borrowing capability under existing credit facilities and accounts receivable financing facilities totaled $2.36 billion as of September 30, 2005.

The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 0.65 to 1.00. On October 3, 2005, FirstEnergy obtained a senior unsecured debt rating upgrade to BBB- by S&P removing the requirement under the revolving credit facility to maintain a fixed charge ratio of at least 2.00 to 1.00.

As of September 30, 2005, FirstEnergy and subsidiaries’ debt to total capitalization as defined under the revolving credit facility, were as follows:

 
 
Debt
 
 
 
To Total
 
Borrower
 
Capitalization
 
FirstEnergy
 
 
0.54 to 1.00
 
OE
 
 
0.39 to 1.00
 
Penn
 
 
0.32 to 1.00
 
CEI
 
 
0.57 to 1.00
 
TE
 
 
0.43 to 1.00
 
JCP&L
 
 
0.29 to 1.00
 
Met-Ed
 
 
0.38 to 1.00
 
Penelec
 
 
0.34 to 1.00
 
 
 
 
48

 

The facility does not contain any provisions that either restrict the ability to borrow or accelerate repayment of outstanding advances as a result of any change in credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds borrowed under the facility is related to the credit ratings of the company borrowing the funds.

FirstEnergy’s regulated companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy’s unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the third quarter of 2005 was 3.50% for the regulated companies’ money pool and 3.46% for the unregulated companies' money pool.

On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in their outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemming from the application of free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.

On October 3, 2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to 'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one notch above the previous rating. S&P noted that the upgrade followed the continuation of a good operating track record, specifically for the nuclear fleet through the third quarter 2005. S&P also stated that FirstEnergy’s rating reflects the benefits of supportive regulation, low-cost base load generation fleet, low-risk transmission and distribution operations and rate certainty in Ohio. FirstEnergy’s ability to consistently generate free cash flow, good liquidity, and an improving financial profile were also noted as strengths.

FirstEnergy’s access to capital markets and costs of financing are influenced by the ratings of its securities. The following table displays FirstEnergy’s and its EUOC’s securities ratings as of October 3, 2005. The ratings outlook from S&P and Fitch on all securities is stable. Moody’s outlook on all securities is Positive.


Ratings of Securities
 
Securities
 
S&P
 
Moody’s
 
Fitch
                 
FirstEnergy
 
Senior unsecured
 
BBB-
 
Baa3
 
BBB-
                 
OE
 
Senior unsecured
 
BBB-
 
Baa2
 
BBB
   
Preferred stock
 
BB+
 
Ba1
 
BBB-
                 
CEI
 
Senior secured
 
BBB
 
Baa2
 
BBB-
   
Senior unsecured
 
BBB-
 
Baa3
 
BB
                 
TE
 
Senior secured
 
BBB
 
Baa2
 
BBB-
   
Preferred stock
 
BB+
 
Ba2
 
BB-
                 
Penn
 
Senior secured
 
BBB+
 
Baa1
 
BBB+
   
Senior unsecured (1)
 
BBB-
 
Baa2
 
BBB
   
Preferred stock
 
BB+
 
Ba1
 
BBB-
                 
JCP&L
 
Senior secured
 
BBB+
 
Baa1
 
BBB+
   
Preferred stock
 
BB+
 
Ba1
 
BBB
                 
Met-Ed
 
Senior secured
 
BBB+
 
Baa1
 
BBB+
   
Senior unsecured
 
BBB
 
Baa2
 
BBB
                 
Penelec
 
Senior unsecured
 
BBB
 
Baa2
 
BBB
                 
 

(1) Penn's only senior unsecured debt obligations are notes underlying pollution control revenue refunding bonds issued
     by the Ohio Air Quality Development Authority to which bonds this rating applies.

On July 1, 2005, TE redeemed all of its 1,200,000 outstanding shares of 7.00% Series A preferred stock at $25.00 per share, plus accrued dividends to the date of redemption. TE also repurchased $37 million of pollution control revenue bonds on September 1, 2005, with the intent to remarket them by the end of the first quarter of 2006.



49


Cash Flows From Investing Activities

Net cash flows used for investing activities resulted principally from property additions. Regulated services expenditures for property additions primarily include expenditures supporting the distribution of electricity. Capital expenditures by the power supply management services segment are principally generation-related. The following table summarizes the investment activities for the three months and nine months ended September 30, 2005 and 2004 by FirstEnergy’s regulated services, power supply management services and other segments:

 
Summary of Cash Flows
 
Property
 
 
 
 
 
 
 
Used for Investing Activities
 
Additions
 
Investments
 
Other
 
Total
 
 Sources (Uses)
 
(In millions)
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended September 30, 2005
 
 
 
 
 
 
 
 
 
Regulated services
 
$
(207
$
(17
$
2
 
$
(222
Power supply management services
 
 
(79
 
1
 
 
-
 
 
(78
Other
 
 
(1
 
-
 
 
1
 
 
-
 
Reconciling items
   
(7
)
 
(9
)
 
5
   
(11
)
Total
 
$
(294
$
(25
$
8
 
$
(311
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended September 30, 2004
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulated services
 
$
(157
$
242
 
$
(69
$
16
 
Power supply management services
 
 
(46
 
(11
 
-
 
 
(57
Other
 
 
(1
 
-
 
 
(2
 
(3
Reconciling items
   
(7
)
 
10
   
84
   
87
 
Total
 
$
(211
$
241
 
$
13
 
$
43
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


Summary of Cash Flows  
 Property
             
Used for Investing Activities
 
 Additions
 
 Investments
 
 Other
 
 Total
 
Sources (Uses)  
 (In millions)
                   
Nine Months Ended September 30, 2005
 
 
 
 
 
 
 
 
 
Regulated services
 
$
(506
$
(13
$
(5
$
(524
Power supply management services
 
 
(226
 
-
 
 
-
 
 
(226
Other
 
 
(6
 
19
 
 
(18
 
(5
Reconciling items
   
(18
)
 
(9
)
 
5
   
(22
)
Total
 
$
(756
$
(3
$
(18
$
(777
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2004
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulated services
 
$
(377
$
196
 
$
(76
$
(257
Power supply management services
 
 
(149
 
(14
 
-
 
 
(163
Other
 
 
(3
 
173
 
 
2
 
 
172
 
Reconciling items
   
(17
)
 
31
   
65
   
79
 
Total
 
$
(546
$
386
 
$
(9
$
(169
 
 
 
 
 
 
 
 
 
 
 
 
 
 


Net cash used for investing activities was $311 million in the third quarter of 2005 compared to $43 million of cash provided from investing activities in the same period of 2004. The change was primarily due to an $83 million increase in property additions and the absence in 2005 of $278 million in cash proceeds from certificates of deposit (released collateral) received in the third quarter of 2004. Net cash used for investing activities increased by $608 million in the first nine months of 2005 compared to the same period of 2004. The increase principally resulted from a $210 million increase in property additions, lower proceeds from the sale of assets of $152 million and the absence in 2005 of $278 million of cash proceeds from certificates of deposit (released collateral) received in 2004.

In the last quarter of 2005, capital requirements for property additions and capital leases are expected to be approximately $378 million. FirstEnergy and the Companies have additional requirements of approximately $312 million for maturing long-term debt during the remainder of 2005. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements.

FirstEnergy’s capital spending for the period 2005-2007 is expected to be about $3.5 billion (excluding nuclear fuel), of which $1.1 billion applies to 2005. Investments for additional nuclear fuel during the 2005-2007 periods are estimated to be approximately $285 million, of which approximately $59 million applies to 2005. During the same period, FirstEnergy’s nuclear fuel investments are expected to be reduced by approximately $282 million and $86 million respectively, as the nuclear fuel is consumed.


50

 

GUARANTEES AND OTHER ASSURANCES

As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. Such agreements include contract guarantees, surety bonds, and LOCs. Some of the guaranteed contracts contain ratings contingent collateralization provisions.

As of September 30, 2005, the maximum potential future payments under outstanding guarantees and other assurances totaled $2.7 billion as summarized below:

 
 
Maximum
Guarantees and Other Assurances
 
Exposure
 
 
(In millions)
FirstEnergy guarantees of subsidiaries:
 
 
Energy and energy-related contracts (1) 
 
$
785
Other (2) 
 
 
503
 
 
 
1,288
 
 
 
 
Surety bonds
 
 
307
Letters of credit (3)(4)
 
 
1,055
 
 
 
 
Total Guarantees and Other Assurances 
 
$
2,650
 
 
 
 
(1)Issued for a one-year term, with a 10-day termination right by FirstEnergy. 
(2)Issued for various terms.
 
 
 
(3)Includes $137 million issued for various terms under LOC capacity available  
  under FirstEnergy's revolving credit agreement and $299 million outstanding in  
  support of pollution control revenue bonds issued with various maturities. 
(4)Includes approximately $194 million pledged in connection with the sale and  
  leaseback of Beaver Valley Unit 2 by CEI and TE, $291 million pledged in connection   
  with the sale and leaseback of Beaver Valley Unit 2 by OE and $134 million pledged   
  in connection with the sale and leaseback of Perry Unit 1 by OE. 


FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy marketing activities - principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of subsidiary financing principally for the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy and its subsidiaries to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financings where the law might otherwise limit the counterparties’ claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy’s guarantee enables the counterparty’s legal claim to be satisfied by FirstEnergy’s other assets. The likelihood that such parental guarantees will increase amounts otherwise paid by FirstEnergy to meet its obligations incurred in connection with ongoing energy-related contracts is remote.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event,” the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. The following table summarizes collateral provisions in effect as of September 30, 2005:


 
 
 
Total
 
Collateral Paid
 
Remaining
 
Collateral Provisions
 
 
Exposure
 
Cash
 
LOC
 
Exposure
 
 
 
 
(In millions)
 
 
 
 
 
 
 
 
 
 
 
 
Credit rating downgrade
 
 
 
$
445
 
$
213
 
$
18
 
$
214
 
Adverse event
 
 
 
 
77
 
 
-
 
 
5
 
 
72
 
Total
 
 
 
$
522
 
$
213
 
$
23
 
$
286
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


As a result of S&P's credit rating upgrade described above, $109 million of cash collateral was returned to FirstEnergy in October 2005.

Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.
 
51

 

FirstEnergy has guaranteed the obligations of the operators of the TEBSA project up to a maximum of $6 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has provided an LOC ($47 million as of September 30, 2005, which is included in the caption “Other” in the above table of Guarantees and Other Assurances), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA. The LOC was reduced to $36 million on October 15, 2005.

OFF-BALANCE SHEET ARRANGEMENTS

FirstEnergy has obligations that are not included on its Consolidated Balance Sheet related to the sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are satisfied through operating lease payments. The present value of these sale and leaseback operating lease commitments, net of trust investments, total $1.3 billion as of September 30, 2005.

FirstEnergy has equity ownership interests in certain businesses that are accounted for under the equity method. There are no undisclosed material contingencies related to these investments. Certain guarantees that FirstEnergy does not expect to have a material current or future effect on its financial condition, liquidity or results of operations, are disclosed under contractual obligations above.

MARKET RISK INFORMATION

FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk management activities throughout the Company.

Commodity Price Risk

FirstEnergy is exposed to price risk primarily due to fluctuating electricity, natural gas, coal, nuclear fuel, emission allowance prices and energy transmission. To manage the volatility relating to these exposures, it uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes and, to a much lesser extent, for trading purposes. All derivatives that fall within the scope of SFAS 133 must be recorded at their fair market value and marked to market. The majority of FirstEnergy’s derivative hedging contracts qualify for the normal purchases and normal sales exception under SFAS 133 and are therefore excluded from the table below. Of those contracts not exempt from such treatment, most are non-trading contracts that do not qualify for hedge accounting treatment. The change in the fair value of commodity derivative contracts related to energy production during the third quarter and first nine months of 2005 is summarized in the following table:


 
 
Three Months Ended
 
Nine Months Ended
 
Increase (Decrease) in the Fair Value
 
September 30, 2005
 
September 30, 2005
 
Of Commodity Derivative Contracts
 
Non-Hedge
 
Hedge
 
Total
 
Non-Hedge
 
Hedge
 
Total
 
 
 
(In millions)
 
Change in the Fair Value of
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Derivative Contracts:
 
 
 
 
 
 
 
 
 
 
 
 
 
Outstanding net asset at beginning of period
 
$
55
 
$
(2
$
53
 
$
62
 
$
2
 
$
64
 
New contract when entered
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
Additions/change in value of existing contracts
 
 
(3
 
3
 
 
-
 
 
(4
 
5
 
 
1
 
Change in techniques/assumptions
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
Settled contracts
 
 
-
 
 
-
 
 
-
 
 
(7
 
-
 
 
(7
Sale of retail natural gas contracts
 
 
-
 
 
-
 
 
-
 
 
1
 
 
(6
 
(5
Outstanding net asset at end of period (1)
 
$
52
 
$
1
 
$
53
 
$
52
 
$
1
 
$
53
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Non-commodity Net Assets at End of Period:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate swaps (2)
 
 
-
 
 
(10
 
(10
 
-
 
 
(10
 
(10
Net Assets - Derivative Contracts at End of Period
 
$
52
 
$
(9
$
43
 
$
52
 
$
(9
$
43
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Impact of Changes in Commodity Derivative Contracts(3)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Statement effects (pre-tax)
 
$
(4
$
-
 
$
(4
$
(4
$
-
 
$
(4
Balance Sheet effects:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other comprehensive income (pre-tax)
 
$
-
 
$
3
 
$
3
 
$
-
 
$
(1
$
(1
Regulatory liability
 
$
1
 
$
-
 
$
1
 
$
(6
$
-
 
$
(6
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) Includes $55 million in non-hedge commodity derivative contracts which are offset by a regulatory liability.
(2) Interest rate swaps are treated as cash flow or fair value hedges. (See Interest Rate Swap Agreements - Fair Value Hedges and Forward
  Starting Swap Agreements - Cash Flow Hedges)
(3) Represents the change in value of existing contracts, settled contracts and changes in techniques/assumptions.
 
 
52

 

Derivatives are included on the Consolidated Balance Sheet as of September 30, 2005 as follows:

Balance Sheet Classification
 
Non-Hedge
 
Hedge
 
Total
 
 
 
(In millions)
 
Current -
 
 
 
 
 
 
 
Other assets
 
$
-
 
$
39
 
$
39
 
Other liabilities
 
 
(1
)
 
(39
)
 
(40
)
 
 
 
 
 
 
 
 
 
 
 
Non-Current -
 
 
 
 
 
 
 
 
 
 
Other deferred charges
 
 
56
 
 
5
 
 
61
 
Other noncurrent liabilities
 
 
(3
)
 
(14
)
 
(17
)
 
 
 
 
 
 
 
 
 
 
 
Net assets
 
$
52
 
$
(9
$
43
 
 
 
 
 
 
 
 
 
 
 
 

 
The valuation of derivative commodity contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, FirstEnergy relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FirstEnergy uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of derivative contracts by year are summarized in the following table:

Sources of Information -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value by Contract Year
 
2005 (1)
 
2006
 
2007
 
2008
 
2009
 
Thereafter
 
Total
 
 
 
(In millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prices actively quoted (2)
 
$
(3
$
(3
$
(2
$
-
 
$
-
 
$
-
 
$
(8
Other external sources (3)
 
 
19
 
 
7
 
 
10
 
 
-
 
 
-
 
 
-
 
 
36
 
Prices based on models
 
 
-
 
 
-
 
 
-
 
 
9
 
 
8
 
 
8
 
 
25
 
Total (4)
 
$
16
 
$
4
 
$
8
 
$
9
 
$
8
 
$
8
 
$
53
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) For the last quarter of 2005.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(2) Exchange traded.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(3) Broker quote sheets.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(4) Includes $55 million in non-hedge commodity derivative contracts which are offset by a regulatory liability.
 
 
 


FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on both FirstEnergy's trading and nontrading derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of September 30, 2005. Based on derivative contracts held as of September 30, 2005, an adverse 10% change in commodity prices would decrease net income by approximately $1 million for the next twelve months.

Interest Rate Swap Agreements - Fair Value Hedges

FirstEnergy utilizes fixed-to-floating interest rate swap agreements as part of its ongoing effort to manage the interest rate risk of its debt portfolio. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues - protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates and interest payment dates match those of the underlying obligations. During the third quarter of 2005, FirstEnergy executed no new fixed-for-floating interest rate swaps and unwound swaps with a total notional amount of $350 million (see Note 7). As of September 30, 2005, the debt underlying the $1.05 billion outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 5.66%, which the swaps have effectively converted to a current weighted average variable interest rate of 5.23%.


53

 
 
 
 
September 30, 2005
 
December 31, 2004
 
 
 
Notional
 
Maturity
 
Fair
 
Notional
 
Maturity
 
Fair
 
Interest Rate Swaps
 
Amount
 
Date
 
Value
 
Amount
 
Date
 
Value
 
 
 
(Dollars in millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed to Floating Rate
 
$
-
 
 
2006
 
$
-
 
$
200
 
 
2006
 
$
(1
)
(Fair value hedges)
 
 
100
 
 
2008
 
 
(3
)
 
100
 
 
2008
 
 
(1
)
 
 
 
50
 
 
2010
 
 
-
 
 
100
 
 
2010
 
 
1
 
 
 
 
50
 
 
2011
 
 
-
 
 
100
 
 
2011
 
 
2
 
 
 
 
450
 
 
2013
 
 
-
 
 
400
 
 
2013
 
 
4
 
 
 
 
-
 
 
2014
 
 
-
 
 
100
 
 
2014
 
 
2
 
 
 
 
150
 
 
2015
 
 
(7
)
 
150
 
 
2015
 
 
(7
)
 
 
 
150
 
 
2016
 
 
2
 
 
200
 
 
2016
 
 
1
 
 
 
 
-
 
 
2018
 
 
-
 
 
150
 
 
2018
 
 
5
 
 
 
 
-
 
 
2019
 
 
-
 
 
50
 
 
2019
 
 
2
 
 
 
 
100
 
 
2031
 
 
(4
)
 
100
 
 
2031
 
 
(4
)
 
 
$
1,050
 
 
 
 
$
(12
$
1,650
 
 
 
 
$
4
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

Forward Starting Swap Agreements - Cash Flow Hedges

During the third quarter, FirstEnergy entered into several forward starting swap agreements (forward swap) in order to hedge a portion of the consolidated interest rate risk associated with the planned issuance of fixed-rate, long-term debt securities for one or more of its consolidated entities in the fourth quarter of 2006. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. As of September 30, 2005, the forward swaps had a fair value of $2 million.

Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $1.038 billion and $951 million as of September 30, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $104 million reduction in fair value as of September 30, 2005.

CREDIT RISK
 
Credit risk is the risk of an obligor’s failure to meet the terms of any investment contract, loan agreement or otherwise perform as agreed. Credit risk arises from all activities in which success depends on issuer, borrower or counterparty performance, whether reflected on or off the balance sheet. FirstEnergy engages in transactions for the purchase and sale of commodities including gas, electricity, coal and emission allowances. These transactions are often with major energy companies within the industry.

FirstEnergy maintains credit policies with respect to its counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of its credit program, FirstEnergy aggressively manages the quality of its portfolio of energy contracts evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P). As of September 30, 2005, the largest credit concentration was with one party, currently rated investment grade that represented 8% of FirstEnergy’s total credit risk. Within its unregulated energy subsidiaries, 99% of credit exposures, net of collateral and reserves, were with investment-grade counterparties as of September 30, 2005.

Outlook

State Regulatory Matters

         In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry restructuring contain similar provisions that are reflected in the Companies' respective state regulatory plans. These provisions include:

 
·
restructuring the electric generation business and allowing the Companies' customers to select a
competitive electric generation supplier other than the Companies;

 
·
establishing or defining the PLR obligations to customers in the Companies' service areas;
 
54


 
·
providing the Companies with the opportunity to recover potentially stranded investment (or transition costs)
not otherwise recoverable in a competitive generation market;

 
·
itemizing (unbundling) the price of electricity into its component elements - including generation,
transmission, distribution and stranded costs recovery charges;

 
·
continuing regulation of the Companies' transmission and distribution systems; and

 
·
requiring corporate separation of regulated and unregulated business activities.
 
       
The EUOCs recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. All regulatory assets are expected to be recovered from customers under the Companies' respective transition and regulatory plans. Based on those plans, the Companies continue to bill and collect cost-based rates for their transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Companies continue the application of SFAS 71 to those operations.

 
 
September 30,
 
December 31,
 
Increase
Regulatory Assets*
 
2005
 
2004
 
(Decrease)
 
 
(In millions)
 
 
 
 
 
 
 
OE
 
$
845
 
$
1,116
 
$
(271
)
CEI
 
 
889
 
 
959
 
 
(70
)
TE
 
 
310
 
 
375
 
 
(65
)
JCP&L
 
 
2,311
 
 
2,176
 
 
135
 
Met-Ed
 
 
572
 
 
693
 
 
(121
)
Penelec
 
 
99
 
 
200
 
 
(101
)
ATSI
 
 
20
 
 
13
 
 
7
 
Total
 
$
5,046
 
$
5,532
 
$
(486
)
   
*Penn had net regulatory liabilities of approximately $48 million and $18 million
 included in Noncurrent Liabilities on the Consolidated Balance Sheets as of
 September 30, 2005 and December 31, 2004, respectively.
 

Regulatory assets by source are as follows:

 
 
September 30,
 
December 31,
 
Increase
 
 Regulatory Assets by Source
 
2005
 
2004
 
(Decrease)
 
 
 
(In millions)
 
 
 
 
 
 
 
 
Regulatory transition costs
 
 
$
4,169
 
$
4,889
 
$
(720
)
Customer shopping incentives
 
 
 
826
 
 
612
 
 
214
 
Customer receivables for future income taxes
 
 
 
289
 
 
246
 
 
43
 
Societal benefits charge
 
 
 
18
 
 
51
 
 
(33
Loss on reacquired debt
 
 
 
83
 
 
89
 
 
(6
)
Employee postretirement benefit costs
 
 
 
57
 
 
65
 
 
(8
)
Nuclear decommissioning, decontamination
 
 
 
 
 
 
 
 
 
 
 
and spent fuel disposal costs
 
 
 
(172
)
 
(169
)
 
(3
Asset removal costs
 
 
 
(366
)
 
(340
)
 
(26
)
Property losses and unrecovered plant costs
 
 
 
34
 
 
50
 
 
(16
)
MISO transmission costs
 
 
 
52
 
 
-
 
 
52
 
JCP&L reliability costs
 
 
 
26
 
 
-
 
 
26
 
Other
 
 
 
30
 
 
39
 
 
(9
)
Total
 
 
$
5,046
 
$
5,532
 
$
(486
)
                       


Reliability Initiatives
 
FirstEnergy is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades, to existing equipment. The FERC or other applicable government agencies and reliability coordinators, however, may take a different view as to recommended enhancements or may recommend additional enhancements in the future as the result of adoption of mandatory reliability standards pursuant to the Energy Policy Act of 2005 that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy's filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

 
55


As a result of outages experienced in JCP&L's service area in 2002 and 2003, the NJBPU had implemented reviews into JCP&L's service reliability. On March 29, 2004, the NJBPU adopted an MOU that set out specific tasks related to service reliability to be performed by JCP&L and a timetable for completion and endorsed JCP&L's ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a Stipulation that incorporates the final report of a Special Reliability Master who made recommendations on appropriate courses of action necessary to ensure system-wide reliability. The Stipulation also incorporates the Executive Summary and Recommendation portions of the final report of a focused audit of JCP&L's Planning and Operations and Maintenance programs and practices (Focused Audit). A Final Order in the Focused Audit docket was issued by the NJBPU on July 23, 2004. On February 11, 2005, JCP&L met with the Ratepayer Advocate to discuss reliability improvements. JCP&L continues to file compliance reports reflecting activities associated with the MOU and Stipulation.

The Energy Policy Act of 2005 provides for the creation of an ERO to establish and enforce reliability standards for the bulk power system, subject to FERC review. On September 1, 2005, the FERC issued a Notice of Proposed Rulemaking to establish certification requirements for the ERO, as well as regional entities envisioned to assume monitoring and compliance responsibility for the new reliability standards. The FERC expects to adopt a final rule on or before February 2006 regarding certification requirements for the ERO and regional entities.

The NERC is expected to reorganize its structure to meet the FERC’s certification requirements for the ERO. Following adoption of the final rule, the NERC will be required to make a filing with the FERC to obtain certification as the ERO. The proposed rule also provides for regional reliability organizations designed to replace the current regional councils. The “regional entity” may be delegated authority by the ERO, subject to FERC approval, for enforcing reliability standards adopted by the ERO and approved by the FERC. The ECAR, Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability councils have signed an MOU designed to consolidate their regions into a new regional reliability organization known as ReliabilityFirst Corporation. Their intent is to file and obtain certification under the final rule as a “regional entity”. All of FirstEnergy’s facilities would be located within the ReliabilityFirst region.

On a parallel path, the NERC is establishing working groups to develop reliability standards to be filed for approval with the FERC following the NERC’s certification as an ERO. These reliability standards are expected to build on the current NERC Version 0 reliability standards. It is expected that the proposed reliability standards will be filed with the FERC in early 2006.

The impact of this effort on FirstEnergy is unclear. FirstEnergy believes that it is in compliance with all current NERC reliability standards. However, it is expected that the FERC will adopt stricter reliability standards than those contained in the current NERC Version 0 standards. The financial impact of complying with the new standards cannot be determined at this time. However, the Energy Policy Act of 2005 requires that all prudent costs incurred to comply with the new reliability standards be recovered in rates.

See Note 14 to the consolidated financial statements for a more detailed discussion of reliability initiatives, including actions by the PPUC, that impact Met-Ed, Penelec and Penn.

Ohio

On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a competitive bid process. The RSP was filed by the Ohio Companies to establish generation service rates beginning January 1, 2006, in response to PUCO concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. In October 2004, the OCC and NOAC filed appeals with the Supreme Court of Ohio to overturn the original June 9, 2004 PUCO order in this proceeding as well as the associated entries on rehearing. On September 28, 2005, the Ohio Supreme Court heard oral argument on the appeals.

On May 27, 2005, the Ohio Companies filed an application with the PUCO to establish a GCAF rider under the RSP. The application seeks to implement recovery of increased fuel costs from 2006 through 2008 applicable to the Ohio Companies' retail customers through a tariff rider to be implemented January 1, 2006. The application reflects projected increases in fuel costs in 2006 compared to 2002 baseline costs. The new rider, after adjustments made in testimony, is seeking to recover all costs above the baseline (approximately $88 million in 2006). Various parties including the OCC have intervened in this case and the case has been consolidated with the RCP application discussed below.
 
56


On September 9, 2005, the Ohio Companies filed an application with the PUCO that, if approved, would supplement their existing RSP with an RCP. On September 27, 2005, the PUCO granted FirstEnergy's motion to consolidate the GCAF rider application with the RCP proceedings and set hearings for the consolidated cases to begin November 29, 2005. The RCP is designed to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. Major provisions of the RCP include:

·    Maintain the existing level of base distribution rates through December 31, 2008 for OE and TE, and
    April 30, 2009 for CEI;

·    Defer and capitalize certain distribution costs to be incurred during the period January 1, 2006
     through December 31, 2008, not to exceed $150 million in each of the three years;

·    Adjust the RTC and extended RTC recovery periods and rate levels so that full recovery of authorized
    costs will occur as of December 31, 2008 for OE and TE, and as of December 31, 2010 for CEI;

·    Reduce the deferred shopping incentive balances as of January 1, 2006 by up to $75 million for OE,
    $45 million for TE, and $85 million for CEI by accelerating the application of each respective
    company's accumulated cost of removal regulatory liability; and

·    Recover increased fuel costs of up to $75 million, $77 million, and $79 million, in 2006, 2007, and
    2008, respectively, from all OE and TE distribution and transmission customers through a fuel
    recovery mechanism and OE, TE, and CEI may defer and capitalize increased fuel costs above the
    amount collected through the fuel recovery mechanism.

Under provisions of the RSP, the PUCO may require the Ohio Companies to undertake, no more often than annually, a competitive bid process to secure generation for the years 2007 and 2008. On July 22, 2005, FirstEnergy filed a competitive bid process for the period beginning in 2007 that is similar to the competitive bid process approved by the PUCO for the Ohio Companies in 2004 which resulted in the PUCO accepting no bids. Any acceptance of future competitive bid results would terminate the RSP pricing, with no accounting impacts to the RSP, and not until twelve months after the PUCO authorizes such termination. On September 28, 2005, the PUCO issued an Entry that essentially approved the Ohio Companies' filing but delayed the proposed timing of the competitive bid process by four months, calling for the auction to be held on March 21, 2006.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio.

Pennsylvania

In accordance with PPUC directives, Met-Ed and Penelec have been negotiating with interested parties in an attempt to resolve the merger savings issues that are the subject of remand from the Commonwealth Court. Met-Ed’s and Penelec’s combined portion of total merger savings is estimated to be approximately $31.5 million. On April 13, 2005, the Commonwealth Court issued an interim order in the remand proceeding that the parties should report the status of the negotiations to the PPUC with a copy to the ALJ. The parties exchanged settlement proposals in May and June 2005 and continue to have settlement discussions.

Met-Ed and Penelec purchase a portion of their PLR requirements from FES through a wholesale power sales agreement. The PLR sale is automatically extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. Under the terms of the wholesale agreement, FES retains the supply obligation and the supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec under their NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR energy costs during the term of the agreement with FES. Met-Ed and Penelec are authorized to defer differences between NUG contract costs and current market prices. On November 1, 2005, FES and the other parties to the wholesale power agreement amended the agreement to provide FES the right over the next year to terminate the agreement at any time upon 60 days notice. If the wholesale power agreement were terminated, Met-Ed and Penelec would need to satisfy the applicable portion of their PLR obligations from other sources at prevailing prices, which are likely to be higher than the current price charged by FES under the agreement and, as a result, Met-Ed’s and Penelec’s purchased power costs could materially increase.

On January 12, 2005, Met-Ed and Penelec filed, before the PPUC, a request for deferral of transmission-related costs beginning January 1, 2005, estimated to be approximately $8 million per month. The OCA, OSBA, OTS, MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric Association have all intervened in the case. To date no hearing schedule has been established, and neither company has yet implemented deferral accounting for these costs.




57


On October 11, 2005, Penn filed a plan with the PPUC to secure electricity supply for its customers at set rates following the end of its transition period on December 31, 2006. Penn is recommending that the Request for Proposal process cover the period of January 1, 2007 through May 31, 2008. Under Pennsylvania's electric competition law, Penn is required to secure generation supply for customers who do not choose alternative suppliers for their electricity.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Pennsylvania.

New Jersey

The 2003 NJBPU decision on JCP&L's base electric rate proceeding (Phase I order) disallowed certain regulatory assets and provided for an interim return on equity of 9.5% on JCP&L's rate base. The Phase I Order also provided for a Phase II proceeding in which the NJBPU would review whether JCP&L is in compliance with current service reliability and quality standards and determine whether the expenditures and projects undertaken by JCP&L to increase its system reliability are prudent and reasonable for rate recovery. Depending on its assessment of JCP&L's service reliability, the NJBPU could have increased JCP&L’s return on equity to 9.75% or decreased it to 9.25%. On August 15, 2003 and June 1, 2004, JCP&L filed with the NJBPU an interim motion and a supplemental and amended motion for rehearing and reconsideration of the Phase I Order, respectively. On July 7, 2004, the NJBPU granted limited reconsideration and rehearing on the following issues: (1) deferred cost disallowances; (2) the capital structure including the rate of return; (3) merger savings, including amortization of costs to achieve merger savings; and (4) decommissioning costs.

On July 16, 2004, JCP&L filed the Phase II petition and testimony with the NJBPU, requesting an increase in base rates of $36 million for the recovery of system reliability costs and a 9.75% return on equity. The filing also requested an increase to the MTC deferred balance recovery of approximately $20 million annually.

On May 25, 2005, the NJBPU approved two stipulated settlement agreements. The first stipulation between JCP&L and the NJBPU staff resolves all of the issues associated with JCP&L's motion for reconsideration of the 2003 NJBPU order Phase I Order. The second stipulation between JCP&L, the NJBPU staff and the Ratepayer Advocate resolves all of the issues associated with JCP&L's Phase II proceeding. The stipulated settlements provide for, among other things, the following:

·    An annual increase in distribution revenues of $23 million, effective June 1, 2005, associated with the
    Phase I Order reconsideration;

·    An annual increase in distribution revenues of $36 million, effective June 1, 2005, related to JCP&L's
    Phase II Petition;

·    An annual reduction in both rates and amortization expense of $8 million, effective June 1, 2005, in
    anticipation of an NJBPU order regarding JCP&L's request to securitize up to $277 million of its deferred
    cost balance;

·    An increase in JCP&L's authorized return on common equity from 9.5% to 9.75%; and

·    A commitment by JCP&L to maintain a target level of customer service reliability with a reduction in
    JCP&L's authorized return on common equity from 9.75% to 9.5% if the target is not met for two
    consecutive quarters. The authorized return on common equity would then be restored to 9.75% if the
    target is met for two consecutive quarters.

The Phase II stipulation included an agreement that the distribution revenue increase also reflects a three-year amortization of JCP&L's one-time service reliability improvement costs incurred in 2003-2005. This resulted in the creation of a regulatory asset associated with accelerated tree trimming and other reliability costs which were expensed in 2003 and 2004. The establishment of the new regulatory asset of approximately $28 million resulted in an increase to net income of approximately $16 million ($0.05 per share of FirstEnergy common stock) in the second quarter of 2005.

JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits to its deferred energy balance with the exception of 300 MW from JCP&L's NUG committed supply currently being used to serve BGS customers pursuant to NJBPU order for the period June 1, 2005 through May 31, 2006. New BGS tariffs reflecting the results of a February 2005 auction for the BGS supply became effective June 1, 2005. On July 1, 2005, JCP&L filed its BGS procurement proposals for post transition year four. The auction is scheduled to take place in February 2006 for the annual supply period beginning June 1, 2006.
 
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      In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting a continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The Ratepayer Advocate filed comments on February 28, 2005. On March 18, 2005, JCP&L filed a response to those comments. A schedule for further proceedings has not yet been set.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in New Jersey.

Transmission
 
On December 30, 2004, the Ohio Companies filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application seeks recovery of these costs beginning January 1, 2006. At the time of filing the application, these costs were estimated to be approximately $30 million per year; however, the Ohio Companies anticipate that this amount will increase. The Ohio Companies requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted each July 1 thereafter. The Ohio Companies reached a settlement with OCC, PUCO staff, Industrial Energy Users - Ohio and OPAE. The only other party in this proceeding, Dominion Retail, Inc., agreed not to oppose the settlement. This settlement, which was filed with the PUCO on July 22, 2005, provides for the rider recovery requested by the Ohio Companies, with carrying charges applied in the subsequent year’s rider for any over or under collection while the then-current rider is in effect. The PUCO approved the settlement stipulation on August 31, 2005. The incremental Transmission and Ancillary service revenues expected to be recovered from January through June 2006 are approximately $61.2 million. This value includes the recovery of the 2005 deferred MISO expenses as described below. In May 2006, the Ohio Companies will file a modification to the rider which will determine revenues from July 2006 through June 2007.

The second application sought authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for the Ohio Companies to defer incremental transmission and ancillary service-related charges incurred as a participant in the MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Permission to defer costs incurred prior to December 31, 2004 was denied. The PUCO also authorized the Ohio Companies to accrue carrying charges on the deferred balances. An application filed with the PUCO to recover these deferred charges over a five-year period through the rider, beginning in 2006, was approved in a PUCO order issued on August 31, 2005 approving the stipulation referred to above. The OCC, OPAE and the Ohio Companies each filed applications for rehearing. The Ohio Companies sought authority to defer the transmission and ancillary service related costs incurred during the period October 1, 2003 through December 29, 2004, while both OCC and OPAE sought to have the PUCO deny deferral of all costs. On July 6, 2005, the PUCO denied the Ohio Companies' and OCC’s applications and, at the request of the Ohio Companies, struck as untimely OPAE’s application. The OCC filed a notice of appeal with the Ohio Supreme Court on August 31, 2005. On September 30, 2005, in accordance with appellate procedure, the PUCO filed with the Ohio Supreme Court the record in this case. The Companies' brief will be due thirty days after the OCC files its brief, which, absent any time extensions, must be filed no later than November 9, 2005.

On January 31, 2005, certain PJM transmission owners made three filings pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to referral and hearing procedures. On September 30, 2005, the PJM transmission owners filed a request for rehearing of the May 31, 2005 order. The rate design and formula rate filings continue to be litigated before the FERC. The outcome of these two cases cannot be predicted.

Environmental Matters
 
The Companies accrue environmental liabilities only when they conclude that it is probable that they have an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in the Companies’ determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

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FirstEnergy plans to issue a report regarding its response to air emission requirements. FirstEnergy expects to complete the report by December 1, 2005.

National Ambient Air Quality Standards
 
In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR provides each affected state until 2006 to develop implementing regulation to achieve additional reductions of NOx and SO2 emissions in two phases (Phase I in 2009 for NOx, 2010 for SO2 and Phase II in 2015 for both NOx and SO2) in all cases from the 2003 levels. The Companies’ Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be subject to the caps on SO2 and NOx emissions, whereas their New Jersey fossil-fired generation facilities will be subject to a cap on NOx emissions only. According to the EPA, SO2 emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO2 emissions in affected states to just 2.5 million tons annually. NOx emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NOx cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which the Companies operate affected facilities.

Mercury Emissions
 
In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On March 14, 2005, the EPA finalized the "Clean Air Mercury Rule," which provides for a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases. Initially, mercury emissions will be capped nationally at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOx emission caps under the EPA's CAIR program). Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. However, the final rules give states substantial discretion in developing rules to implement these programs. In addition, both the CAIR and the Clean Air Mercury rule have been challenged in the United States Court of Appeals for the District of Columbia. FirstEnergy's future cost of compliance with these regulations may be substantial.

W. H. Sammis Plant
 
In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which is owned by OE and Penn. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the W. H. Sammis Plant New Source Review litigation. This settlement agreement, which is in the form of a Consent Decree, was approved by the Court on July 11, 2005, requires OE and Penn to reduce NOx and SO2 emission at the W. H. Sammis Plant and other coal-fired plants through the installation of pollution control devices. Capital expenditures necessary to meet those requirements are currently estimated to be $1.5 billion (the primary portion of which is expected to be spent in the 2008 to 2011 time period). As disclosed in FirstEnergy's Form 8-K dated August 26, 2005, FGCO entered into an agreement with Bechtel Power Corporation (Bechtel), under which Bechtel will engineer, procure, and construct air quality control systems for the reduction of sulfur dioxide emissions. The settlement agreement also requires OE and Penn to spend up to $25 million toward environmentally beneficial projects, which include wind energy purchased power agreements over a 20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million. Results for the first quarter of 2005 included the penalties payable by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also recognized liabilities of $9.2 million and $0.8 million, respectively, for probable future cash contributions toward environmentally beneficial projects during the first quarter of 2005.


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Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global warming by reducing the amount of man-made greenhouse gases emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Protocol in 1998 but it failed to receive the two-thirds vote of the United States Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic greenhouse gas intensity - the ratio of emissions to economic output - by 18 percent through 2012. The Energy Policy Act of 2005 established a Committee on Climate change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

The Companies cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO2 emissions could require significant capital and other expenditures. However, the CO2 emissions per kilowatt-hour of electricity generated by the Companies is lower than many regional competitors due to the Companies' diversified generation sources which include low or non-CO2 emitting gas-fired and nuclear generators.

Regulation of Hazardous Waste
 
The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of September 30, 2005, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable SBC. Total liabilities of approximately $64 million (JCP&L - $46.8 million, CEI - $2.3 million, TE - $0.2 million, Met-Ed - $0.1 million and other - $14.6 million) have been accrued through September 30, 2005.

See Note 13(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings
 
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The other material items not otherwise discussed above are described below.

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concludes, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades, to existing equipment, and therefore FirstEnergy has not accrued a liability as of September 30, 2005 for any expenditures in excess of those actually incurred through that date. FirstEnergy notes, however, that the FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

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FirstEnergy companies also are defending six separate complaint cases before the PUCO relating to the August 14, 2003 power outage. Two such cases were originally filed in Ohio State courts but subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In both such cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Of the four other pending PUCO complaint cases, three were filed by various insurance carriers either in their own name or as subrogees in the name of their insured. In each such case, the carriers seek reimbursement against various FirstEnergy companies (and, in one case, against PJM, MISO and American Electric Power Co. as well) for claims they paid to their insureds allegedly due to the loss of power on August 14, 2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy company. The fourth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. In addition to these six cases, the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages. No estimate of potential liability has been undertaken for any of these cases.

One complaint was filed on August 25, 2004 against FirstEnergy in the New York State Supreme Court. In this case, several plaintiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. FirstEnergy's motion to dismiss the case was granted on September 26, 2005. Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter is not due until on or about December 1, 2005. No estimate of potential liability has been undertaken in this matter.

FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. In particular, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

FENOC received a subpoena in late 2003 from a grand jury sitting in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at the Davis-Besse Nuclear Power Station. On December 10, 2004, FirstEnergy received a letter from the United States Attorney's Office stating that FENOC is a target of the federal grand jury investigation into alleged false statements made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01. The letter also said that the designation of FENOC as a target indicates that, in the view of the prosecutors assigned to the matter, it is likely that federal charges will be returned against FENOC by the grand jury. On February 10, 2005, FENOC received an additional subpoena for documents related to root cause reports regarding reactor head degradation and the assessment of reactor head management issues at Davis-Besse. On May 11, 2005, FENOC received a subpoena for documents related to outside meetings attended by Davis-Besse personnel on corrosion and cracking of control rod drive mechanisms and additional root cause evaluations.

On April 21, 2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to the degradation of the Davis-Besse reactor vessel head issue described above. FirstEnergy accrued $2.0 million for a potential fine prior to 2005 and accrued the remaining liability for the proposed fine during the first quarter of 2005. On September 14, 2005, FENOC filed its response to the NOV with the NRC. FENOC accepted full responsibility for the past failure to properly implement its boric acid corrosion control and corrective action programs. The NRC NOV indicated that the violations do not represent current licensee performance. FirstEnergy paid the penalty in the third quarter of 2005.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability based on the events surrounding Davis-Besse, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

Effective July 1, 2005 the NRC oversight panel for Davis-Besse was terminated and Davis-Besse returned to the standard NRC reactor oversight process. At that time, NRC inspections were augmented to include inspections to support the NRC's Confirmatory Order dated March 8, 2004 that was issued at the time of startup and to address an NRC White Finding related to the performance of the emergency sirens.



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On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the preceding two years. FENOC operates the Perry Nuclear Power Plant, which currently is owned and/or leased by OE, CEI, TE and Penn (however, see Note 17 regarding FirstEnergy’s pending intra-system generation asset transfers, which include owned portions of the plant). On April 4, 2005, the NRC held a public forum to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Plant operated "in a manner that preserved public health and safety" and met all cornerstone objectives although it remained under heightened NRC oversight since August 2004. During the public forum and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix. On May 26, 2005, the NRC held a public meeting to discuss its oversight of the Perry Plant. While the NRC stated that the plant continued to operate safely, the NRC also stated that the overall performance had not substantially improved since the heightened inspection was initiated. The NRC reiterated this conclusion in its mid-year assessment letter dated August 30, 2005. On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance of Perry and stated that the CAL would remain open until substantial improvement was demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight Process. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process, from increased oversight to possible impact to the plant’s operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, have become the subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. On August 24, 2005 additional information was requested regarding Davis-Besse. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.

On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from the W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members.

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. At the conclusion of the June 1, 2005, hearing, the Arbitrator decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the Arbitrator issued an opinion to award approximately $16.1 million to the bargaining unit employees. JCP&L initiated an appeal of this award by filing a motion to vacate in Federal court in New Jersey on October 18, 2005. JCP&L recognized a liability for the potential $16.1 million award during the three months ended September 30, 2005.

The City of Huron filed a complaint against OE with the PUCO challenging the ability of electric distribution utilities to collect transition charges from a customer of a newly formed municipal electric utility. The complaint was filed on May 28, 2003, and OE timely filed its response on June 30, 2003. In a related filing, the Ohio Companies filed for approval with the PUCO a tariff that would specifically allow the collection of transition charges from customers of municipal electric utilities formed after 1998. An adverse ruling could negatively affect full recovery of transition charges by the utility. Hearings on the matter were held in August 2005. Initial briefs from all parties were filed on September 22, 2005 and reply briefs were filed on October 14, 2005. It is unknown when the PUCO will rule on this case.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

See Note 13(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

 
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NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

FSP No. FAS 13-1, "Accounting for Rental Costs Incurred during the Construction Period"
 
Issued in October 2005, FSP No. FAS 13-1 requires rental costs associated with ground or building operating leases that are incurred during a construction period to be recognized as rental expense. The effective date of the FSP guidance is the first reporting period beginning after December 15, 2005. FirstEnergy is currently evaluating this FSP, and its impact on the financial statements.

EITF Issue 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty"
 
In September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus that an exchange of inventory should be accounted for at fair value. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and other storable inventory. Therefore, FirstEnergy will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006. See Note 2 for an example of FirstEnergy's application of this Issue.

 
EITF Issue No. 05-6, "Determining the Amortization Period for Leasehold Improvements Purchased after Lease Inception or Acquired in a Business Combination"
 
In June 2005, the EITF reached a consensus on the application guidance for Issue 05-6. EITF 05-6 addresses the amortization period for leasehold improvements that were either acquired in a business combination or placed in service significantly after and not contemplated at or near the beginning of the initial lease term. For leasehold improvements acquired in a business combination, the amortization period is the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date of acquisition. Leasehold improvements that are placed in service significantly after and not contemplated at or near the beginning of the lease term should be amortized over the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date the leasehold improvements are purchased. This EITF was effective July 1, 2005 and is consistent with FirstEnergy's current accounting.

FIN 47, “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective for FirstEnergy in the fourth quarter of 2005. FirstEnergy and the Companies are currently evaluating the effect this Interpretation will have on their financial statements.

 
SFAS 154 - “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3”

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in the Consolidated Statements of Income. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. FirstEnergy and the Companies will adopt this Statement effective January 1, 2006.


 
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SFAS 153, “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29”
 
In December 2004, the FASB issued SFAS 153 amending APB 29, which was based on the principle that nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB 29 included certain exceptions to that principle. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement are effective January 1, 2006 for FirstEnergy. This FSP is not expected to have a material impact on FirstEnergy's financial statements.

SFAS 123(R), “Share-Based Payment”

In December 2004, the FASB issued SFAS 123(R), a revision to SFAS 123, which requires expensing stock options in the financial statements. Important to applying the new standard is understanding how to (1) measure the fair value of stock-based compensation awards and (2) recognize the related compensation cost for those awards. For an award to qualify for equity classification, it must meet certain criteria in SFAS 123(R). An award that does not meet those criteria will be classified as a liability and remeasured each period. SFAS 123(R) retains SFAS 123's requirements on accounting for income tax effects of stock-based compensation. In April 2005, the SEC delayed the effective date of SFAS 123(R) to annual, rather than interim, periods that begin after June 15, 2005. The SEC’s new rule results in a six-month deferral for companies with a fiscal year beginning January 1. Therefore, FirstEnergy will adopt this Statement effective January 1, 2006. FirstEnergy expects to adopt modified prospective application, without restatement of prior interim periods. Potential cumulative adjustments, if any, have not yet been determined. FirstEnergy uses the Black-Scholes option-pricing model to value options for disclosure purposes only and expects to apply this pricing model upon adoption of SFAS 123(R).

SFAS 151, “Inventory Costs - an amendment of ARB No. 43, Chapter 4”

In November 2004, the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Previous guidance stated that in some circumstances these costs may be “so abnormal” that they would require treatment as current period costs. SFAS 151 requires abnormal amounts for these items to always be recorded as current period costs. In addition, this Statement requires that allocation of fixed production overheads to the cost of conversion be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred by FirstEnergy beginning January 1, 2006. FirstEnergy is currently evaluating this Standard and does not expect it to have a material impact on the financial statements.

FSP FAS 115-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

In September 2005, the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP FAS 115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition of Other Than Temporary Impairment upon the Planned Sale of a Security Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when the impairment is deemed other than temporary, even if a decision to sell has not been made, and (3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after September 15, 2005. The FASB expects to issue this FSP in the fourth quarter of 2005, which would require prospective application with an effective date for reporting periods beginning after December 15, 2005. FirstEnergy is currently evaluating this FSP and any impact on its investments.

FSP 109-1, “Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction and Qualified Production Activities Provided by the American Jobs Creation Act of 2004”
 
Issued in December 2004, FSP 109-1 provides guidance related to the provision within the American Jobs Creation Act of 2004 (Act) that provides a tax deduction on qualified production activities. The Act includes a tax deduction of up to nine percent (when fully phased-in) of the lesser of (a) “qualified production activities income,” as defined in the Act, or (b) taxable income (after the deduction for the utilization of any net operating loss carryforwards). The FASB believes that the deduction should be accounted for as a special deduction in accordance with SFAS 109, “Accounting for Income Taxes", which is consistent with FirstEnergy's accounting.


 
65

 
 

OHIO EDISON COMPANY
 
                   
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
 
(Unaudited)
 
                   
   
Three Months Ended
 
Nine Months Ended
 
   
September 30,
 
September 30,
 
   
2005
 
2004
 
2005
 
2004
 
   
(In thousands)
 
STATEMENTS OF INCOME
                 
                   
OPERATING REVENUES
 
$
825,790
 
$
766,336
 
$
2,268,760
 
$
2,227,978
 
                           
OPERATING EXPENSES AND TAXES:
                         
Fuel
   
15,158
   
15,244
   
39,080
   
44,158
 
Purchased power
   
229,561
   
242,835
   
703,658
   
730,542
 
Nuclear operating costs
   
76,254
   
81,244
   
264,514
   
235,277
 
Other operating costs
   
114,762
   
99,132
   
293,530
   
276,289
 
Provision for depreciation
   
30,169
   
30,702
   
87,875
   
90,846
 
Amortization of regulatory assets
   
126,439
   
103,211
   
347,880
   
317,030
 
Deferral of new regulatory assets
   
(43,929
)
 
(25,728
)
 
(107,750
)
 
(69,790
)
General taxes
   
51,945
   
47,634
   
146,066
   
135,688
 
Income taxes
   
99,778
   
76,502
   
245,942
   
203,863
 
Total operating expenses and taxes 
   
700,137
   
670,776
   
2,020,795
   
1,963,903
 
                           
OPERATING INCOME
   
125,653
   
95,560
   
247,965
   
264,075
 
                           
OTHER INCOME (net of income taxes)
   
20,069
   
17,141
   
37,352
   
50,285
 
                           
NET INTEREST CHARGES:
                         
Interest on long-term debt
   
12,989
   
10,657
   
44,330
   
43,641
 
Allowance for borrowed funds used during construction
                         
and capitalized interest 
   
(3,014
)
 
(1,950
)
 
(8,255
)
 
(4,924
)
Other interest expense
   
4,193
   
640
   
12,457
   
7,576
 
Subsidiary's preferred stock dividend requirements
   
156
   
639
   
1,534
   
1,919
 
Net interest charges 
   
14,324
   
9,986
   
50,066
   
48,212
 
                           
NET INCOME
   
131,398
   
102,715
   
235,251
   
266,148
 
                           
PREFERRED STOCK DIVIDEND REQUIREMENTS
   
659
   
623
   
1,976
   
1,843
 
                           
EARNINGS ON COMMON STOCK
 
$
130,739
 
$
102,092
 
$
233,275
 
$
264,305
 
                           
STATEMENTS OF COMPREHENSIVE INCOME
                         
                           
NET INCOME
 
$
131,398
 
$
102,715
 
$
235,251
 
$
266,148
 
                           
OTHER COMPREHENSIVE INCOME (LOSS):
                         
Unrealized loss on available for sale securities
   
(3,402
)
 
(6,913
)
 
(19,079
)
 
(2,767
)
Income tax benefit related to other comprehensive income
   
2,043
   
2,850
   
7,713
   
1,141
 
Other comprehensive loss, net of tax 
   
(1,359
)
 
(4,063
)
 
(11,366
)
 
(1,626
)
                           
TOTAL COMPREHENSIVE INCOME
 
$
130,039
 
$
98,652
 
$
223,885
 
$
264,522
 
                           
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these
   
statements.
                         
 
 
 
66

 
 

OHIO EDISON COMPANY
 
           
CONSOLIDATED BALANCE SHEETS
 
(Unaudited)
 
   
September 30,
 
December 31,
 
   
2005
 
2004
 
   
(In thousands)
 
ASSETS
         
UTILITY PLANT:
         
In service
 
$
5,573,996
 
$
5,440,374
 
Less - Accumulated provision for depreciation
   
2,793,343
   
2,716,851
 
     
2,780,653
   
2,723,523
 
Construction work in progress -
             
Electric plant
   
246,325
   
203,167
 
Nuclear fuel
   
17,972
   
21,694
 
     
264,297
   
224,861
 
     
3,044,950
   
2,948,384
 
OTHER PROPERTY AND INVESTMENTS:
             
Investment in lease obligation bonds
   
341,335
   
354,707
 
Nuclear plant decommissioning trusts
   
462,439
   
436,134
 
Long-term notes receivable from associated companies
   
207,089
   
208,170
 
Other
   
44,623
   
48,579
 
     
1,055,486
   
1,047,590
 
CURRENT ASSETS:
             
Cash and cash equivalents
   
900
   
1,230
 
Receivables -
             
Customers (less accumulated provisions of $7,312,000 and $6,302,000, respectively,
             
for uncollectible accounts) 
   
285,462
   
274,304
 
Associated companies
   
121,262
   
245,148
 
Other (less accumulated provisions of $14,000 and $64,000, respectively,
             
for uncollectible accounts) 
   
20,653
   
18,385
 
Notes receivable from associated companies
   
798,513
   
538,871
 
Materials and supplies, at average cost
   
92,610
   
90,072
 
Prepayments and other
   
17,336
   
13,104
 
     
1,336,736
   
1,181,114
 
DEFERRED CHARGES:
             
Regulatory assets
   
844,590
   
1,115,627
 
Property taxes
   
61,419
   
61,419
 
Unamortized sale and leaseback costs
   
56,477
   
60,242
 
Other
   
67,093
   
68,275
 
     
1,029,579
   
1,305,563
 
   
$
6,466,751
 
$
6,482,651
 
CAPITALIZATION AND LIABILITIES
             
CAPITALIZATION:
             
Common stockholder's equity -
             
Common stock, without par value, authorized 175,000,000 shares - 100 shares outstanding
 
$
2,099,099
 
$
2,098,729
 
Accumulated other comprehensive loss
   
(58,484
)
 
(47,118
)
Retained earnings
   
434,473
   
442,198
 
Total common stockholder's equity 
   
2,475,088
   
2,493,809
 
Preferred stock
   
60,965
   
60,965
 
Preferred stock of consolidated subsidiary
   
14,105
   
39,105
 
Long-term debt and other long-term obligations
   
1,099,147
   
1,114,914
 
     
3,649,305
   
3,708,793
 
CURRENT LIABILITIES:
             
Currently payable long-term debt
   
273,656
   
398,263
 
Short-term borrowings -
             
Associated companies
   
120,971
   
11,852
 
Other
   
123,584
   
167,007
 
Accounts payable -
             
Associated companies
   
81,980
   
187,921
 
Other
   
11,289
   
10,582
 
Accrued taxes
   
213,843
   
153,400
 
Other
   
117,268
   
74,663
 
     
942,591
   
1,003,688
 
NONCURRENT LIABILITIES:
             
Accumulated deferred income taxes
   
688,702
   
766,276
 
Accumulated deferred investment tax credits
   
52,108
   
62,471
 
Asset retirement obligation
   
364,525
   
339,134
 
Retirement benefits
   
320,044
   
307,880
 
Other
   
449,476
   
294,409
 
     
1,874,855
   
1,770,170
 
COMMITMENTS AND CONTINGENCIES (Note 13)
                   
   
$
6,466,751
 
$
6,482,651
 
               
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these balance sheets.
   
               
 
 
 
67

 
 
 

OHIO EDISON COMPANY
 
                   
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(Unaudited)
 
                   
   
Three Months Ended
 
Nine Months Ended
 
   
September 30,
 
September 30,
 
   
2005
 
2004
 
2005
 
2004
 
   
(In thousands)
 
                   
CASH FLOWS FROM OPERATING ACTIVITIES:
                 
Net income
 
$
131,398
 
$
102,715
 
$
235,251
 
$
266,148
 
Adjustments to reconcile net income to net cash from
                         
operating activities -
                         
Provision for depreciation
   
30,169
   
30,702
   
87,875
   
90,846
 
Amortization of regulatory assets
   
126,439
   
103,211
   
347,880
   
317,030
 
Deferral of new regulatory assets
   
(43,929
)
 
(25,728
)
 
(107,750
)
 
(69,790
)
Nuclear fuel and lease amortization
   
11,867
   
11,914
   
30,530
   
33,766
 
Amortization of lease costs
   
32,963
   
33,037
   
30,011
   
30,585
 
Amortization of electric service obligation
   
(4,565
)
 
-
   
(8,556
)
 
-
 
Deferred income taxes and investment tax credits, net
   
(17,787
)
 
(11,374
)
 
(22,929
)
 
(61,961
)
Accrued retirement benefit obligations
   
5,503
   
7,253
   
12,164
   
24,482
 
Accrued compensation, net
   
1,254
   
1,106
   
(1,903
)
 
5,138
 
Pension trust contribution
   
-
   
(72,763
)
 
-
   
(72,763
)
Decrease (increase) in operating assets -
                         
Receivables
   
32,715
   
(86,506
)
 
110,460
   
(10,734
)
Materials and supplies
   
15,611
   
(2,930
)
 
(2,538
)
 
(8,796
)
Prepayments and other current assets
   
2,988
   
4,878
   
(4,232
)
 
(1,636
)
Increase (decrease) in operating liabilities -
                         
Accounts payable
   
(20,007
)
 
115,690
   
(105,234
)
 
21,905
 
Accrued taxes
   
41,365
   
(4,464
)
 
60,443
   
(346,918
)
Accrued interest
   
2,458
   
3,028
   
1,667
   
2,918
 
Prepayment for electric service - education programs
   
-
   
-
   
136,142
   
-
 
Other
   
(11,504
)
 
2,572
   
1,372
   
(8,624
)
Net cash provided from operating activities
   
336,938
   
212,341
   
800,653
   
211,596
 
                           
CASH FLOWS FROM FINANCING ACTIVITIES:
                         
New Financing -
                         
Long-term debt
   
-
   
-
   
146,450
   
30,000
 
Short-term borrowings, net
   
18,254
   
91,072
   
65,696
   
13,258
 
Redemptions and Repayments -
                         
Preferred stock
   
-
   
-
   
(37,750
)
 
-
 
Long-term debt
   
(17,819
)
 
(36,090
)
 
(278,327
)
 
(152,900
)
Dividend Payments -
                         
Common stock
   
(64,000
)
 
(68,000
)
 
(241,000
)
 
(239,000
)
Preferred stock
   
(659
)
 
(623
)
 
(1,976
)
 
(1,843
)
Net cash used for financing activities
   
(64,224
)
 
(13,641
)
 
(346,907
)
 
(350,485
)
                           
CASH FLOWS FROM INVESTING ACTIVITIES:
                         
Property additions
   
(69,346
)
 
(61,682
)
 
(190,804
)
 
(146,645
)
Contributions to nuclear decommissioning trusts
   
(7,885
)
 
(7,885
)
 
(23,655
)
 
(23,655
)
Loan repayments from (loans to) associated companies, net
   
(200,021
)
 
(378,081
)
 
(258,561
)
 
30,709
 
Proceeds from certificates of deposit
   
-
   
277,763
   
-
   
277,763
 
Other
   
4,155
   
(29,200
)
 
18,944
   
113
 
Net cash provided from (used for) investing activities
   
(273,097
)
 
(199,085
)
 
(454,076
)
 
138,285
 
                           
Net decrease in cash and cash equivalents
   
(383
)
 
(385
)
 
(330
)
 
(604
)
Cash and cash equivalents at beginning of period
   
1,283
   
1,664
   
1,230
   
1,883
 
Cash and cash equivalents at end of period
 
$
900
 
$
1,279
 
$
900
 
$
1,279
 
 
                         
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these
 
statements.
                         
                           
 
 
 
68

 

Report of Independent Registered Public Accounting Firm









To the Stockholders and Board of
Directors of Ohio Edison Company:

We have reviewed the accompanying consolidated balance sheet of Ohio Edison Company and its subsidiaries as of September 30, 2005, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and nine-month periods ended September 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2004, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 2(G) to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 7 to those consolidated financial statements) dated March 7, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.




PricewaterhouseCoopers LLP
Cleveland, Ohio
November 1, 2005

69

 

OHIO EDISON COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION


OE is a wholly owned electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. The OE Companies also provide generation services to those customers electing to retain the OE Companies as their power supplier. The OE Companies provide power directly to wholesale customers under previously negotiated contracts, as well as to some alternative energy suppliers under OE’s transition plan. The OE Companies have unbundled the price of electricity into its component elements - including generation, transmission, distribution and transition charges. Power supply requirements of the OE Companies are provided by FES -- an affiliated company.

Results of Operations
 
Earnings on common stock in the third quarter of 2005 increased to $131 million from $102 million in the third quarter of 2004. The increase in earnings resulted primarily from higher operating revenues and lower purchased power and nuclear operating costs, partially offset by increases in regulatory asset amortization, other operating costs and income taxes. During the first nine months of 2005, earnings on common stock decreased to $233 million from $264 million in the same period of 2004. The decrease in earnings for the first nine months of 2005 primarily resulted from increases in nuclear operating costs, regulatory asset amortization and a one-time income tax charge that occurred in the second quarter of 2005, as well as a decrease in other income. These reductions to earnings were partially offset by higher operating revenues and lower fuel and purchased power costs.

Operating revenues increased by $59 million or 7.8% in the third quarter of 2005 compared with the same period in 2004. Higher revenues for the quarter primarily resulted from increased retail generation and distribution revenues of $23 million and $33 million, respectively. During the first nine months of 2005 compared to the same period in 2004, operating revenues increased by $41 million or 1.8%. Higher revenues for the first nine months of 2005 were due to increases in retail generation and distribution revenues of $36 million and $40 million, respectively, partially offset by a $37 million decrease in wholesale sales.

Lower wholesale revenues for the first nine months of 2005 reflected decreased sales to FES of $57 million (12.1% KWH sales decrease), due to reduced nuclear generation available for sale. The decreased sales to FES were partially offset by increased sales of $21 million to non-affiliated customers (including MSG sales). Under its Ohio transition plan, OE is required to provide MSG to non-affiliated alternative suppliers (see Outlook - Regulatory Matters).

Increased retail generation revenues for the third quarter of 2005 resulted from higher sales to residential, commercial and industrial customers of $10 million, $2 million and $11 million, respectively. The increased generation KWH sales to residential (14.0%) and commercial (6.1%) customers were due to warmer than normal temperatures in the third quarter of 2005. Increased industrial revenues reflected a 6.5% increase in generation KWH sales. Partially offsetting the increase in residential KWH sales was an increase in customer shopping. Generation services provided to residential customers by alternative suppliers as a percent of total residential sales delivered in OE’s service area increased by 1.2 percentage points compared with the third quarter of 2004. Commercial and industrial customer shopping remained relatively unchanged.

Retail generation revenues increased for the first nine months of 2005 compared to the same period of 2004 in all customer sectors (residential - $15 million, commercial - $7 million and industrial - $14 million). The higher revenues were due to increased generation KWH sales (residential - 6.8%, commercial - 4.2% and industrial - 1.0%). Residential and industrial KWH sales increases were partially offset by increases in customer shopping by 1.1 and 1.7 percentage points, respectively, while commercial shopping remained relatively unchanged.

Revenues from distribution throughput increased $33 million in the third quarter of 2005 compared with the same period in 2004. Distribution deliveries to residential, commercial and industrial customers increased by $26 million, $4 million and $3 million, respectively, due to increased KWH deliveries. The increases from distribution deliveries were partially offset by lower composite unit prices in all sectors.

Revenues from distribution throughput increased $40 million in the first nine months of 2005 compared with the same period in 2004 due to higher revenues from residential and commercial customers, partially offset by lower industrial sector revenues. Residential and commercial distribution revenues increased $40 million and $3 million, respectively, reflecting higher KWH deliveries partially offset by lower composite prices. Industrial distribution revenues decreased by $3 million due to lower composite unit prices, partially offset by an increase in KWH distribution deliveries.

70


Under the Ohio transition plan, OE provides incentives to customers to encourage switching to alternative energy providers. OE’s revenues were reduced by $3 million from additional credits in the third quarter and $7 million in the first nine months of 2005 compared to the same periods in 2004. These revenue reductions are deferred for future recovery from customers under OE’s transition plan and do not affect current period earnings (See Regulatory Matters below).

Changes in KWH sales by customer class in the three months and nine months ended September 30, 2005 from the corresponding periods of 2004 are summarized in the following table:

 
 
Three
 
Nine
 
Changes in KWH Sales
 
Months
 
Months
 
Increase (Decrease)
 
 
 
 
 
Electric Generation:
 
 
 
 
 
Retail
 
 
9.1
%
 
3.9
%
Wholesale
 
 
(1.2
)%
 
(9.4
)%
Total Electric Generation Sales
 
 
4.0
%
 
(2.6
)%
 
 
 
 
 
 
 
 
Distribution Deliveries:
 
 
 
 
 
 
 
Residential
 
 
15.9
%
 
8.3
%
Commercial
 
 
6.3
%
 
4.2
%
Industrial
 
 
6.9
%
 
3.4
%
Total Distribution Deliveries
 
 
9.8
%
 
5.3
%
 
 
 
 
 
 
 
 


Operating Expenses and Taxes
 
Total operating expenses and taxes increased by $29 million in the third quarter and $57 million in the first nine months of 2005 from the same periods of 2004. The following table presents changes from the prior year by expense category.

Operating Expenses and Taxes - Changes
 
Three Months
 
Nine Months
 
Increase (Decrease)
 
(In millions)
 
Fuel costs
 
$
--
 
$
(5
)
Purchased power costs
 
 
(13
)
 
(27
)
Nuclear operating costs
 
 
(5
)
 
29
 
Other operating costs
 
 
16
 
 
17
 
Provision for depreciation
 
 
(1
)
 
(3
)
Amortization of regulatory assets
 
 
23
 
 
31
 
Deferral of new regulatory assets
 
 
(18
)
 
(38
)
General taxes
 
 
4
 
 
11
 
Income taxes
 
 
23
 
 
42
 
Net increase in operating expenses and taxes
 
$
29
 
$
57
 
 


Lower fuel costs in the first nine months of 2005, compared with the same periods of 2004, resulted from decreased nuclear generation - down 12.1%. Purchased power costs were lower in both periods of 2005, reflecting lower unit costs partially offset by higher KWH purchases in the third quarter of 2005. KWH purchases were relatively unchanged in the first nine months of 2005. Nuclear operating costs decreased in the third quarter of 2005 compared to the same quarter in 2004 primarily due to a decrease in non-fuel nuclear operating costs at Perry Unit 1 and Beaver Valley Unit 2. Nuclear operating costs increased during the first nine months of 2005 primarily due to the costs from the Beaver Valley Unit 2 refueling outage (started April 4, 2005) and to a lesser extent from the Perry Unit 1 outage initiated in the first quarter of 2005 that was completed on May 6, 2005. There were no nuclear refueling outages in the same periods last year. The increases in other operating costs in the third quarter and first nine months of 2005, compared to the same periods of 2004, resulted primarily from increased MISO transmission expenses, partially offset by lower employee benefits expenses.

The decrease in depreciation expense in the first nine months of 2005 compared with the same period of 2004 was attributable to revised estimated service life assumptions for fossil generating plants (see Note 3). Higher regulatory asset amortization in the three-month and nine-month periods was primarily due to increased amortization of transition costs being recovered under the RSP. Increases in regulatory asset deferrals for both periods resulted from higher shopping incentive deferrals and related interest ($4 million and $11 million, respectively), and the PUCO-approved MISO administrative cost deferrals and related interest ($14 million and $27 million, respectively, see Outlook - Regulatory Matters).
 
71

 
General taxes increased in the third quarter and first nine months of 2005 compared to the same periods of 2004 due to the effect of higher KWH sales which increased Ohio KWH excise taxes in both periods. The increase in the first nine months of 2005 also reflected the absence of a $6 million Pennsylvania property tax refund recognized in the second quarter of 2004.

Income taxes increased in the first nine months of 2005 compared to the same periods of 2004, primarily due to the effects of new tax legislation in Ohio. On June 30, 2005, the State of Ohio enacted new tax legislation that created a new CAT tax, which is based on qualifying “taxable gross receipts” and will not consider any expenses or costs incurred to generate such receipts, except for items such as cash discounts, returns and allowances, and bad debts. The CAT tax was effective July 1, 2005, and replaces the Ohio income-based franchise tax and the Ohio personal property tax. The CAT tax is phased-in while the current income-based franchise tax is phased-out over a five-year period at a rate of 20% annually, beginning with the year ended 2005, and personal property tax is phased-out over a four-year period at a rate of approximately 25% annually, beginning with the year ended 2005. During the phase-out period the Ohio income tax will be computed consistently with the prior tax law, except that the tax liability as computed will be multiplied by 4/5 in 2005; 3/5 in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current income-based franchise tax over a five-year period.

As a result of the new tax structure, all net deferred tax benefits that are not expected to reverse during the five-year phase-in period were written-off as of June 30, 2005. The impact on income taxes associated with the required adjustment to net deferred taxes for the nine months ended September 30, 2005 was an additional tax expense of approximately $36 million, which was partially offset by the initial phase-out of the Ohio income-based franchise tax, which reduced income taxes by approximately $7 million in the nine months ended September 30, 2005. See Note 12 to the consolidated financial statements.

Other Income

Other income decreased $13 million in the first nine months of 2005 compared with the same period of 2004, primarily due to an $8.5 million civil penalty payable to the Department of Justice and a $10 million liability for environmental projects recognized in connection with the W.H. Sammis Plant settlement (see Outlook - Environmental Matters), partially offset by higher nuclear decommissioning trust realized gains.

Net Interest Charges

Net interest charges increased by $4 million in the third quarter and $2 million in the first nine months of 2005 compared with the same periods of 2004, reflecting increased short-term borrowings from associated companies at a higher rate of interest.

Capital Resources and Liquidity

OE’s cash requirements for the remainder of 2005 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing OE’s net debt and preferred stock outstanding. Borrowing capacity under credit facilities is available to manage working capital requirements. Thereafter, OE expects to use a combination of cash from operations and funds from the capital markets.

Changes in Cash Position

As of September 30, 2005, OE's cash and cash equivalents of approximately $1 million remained unchanged from December 31, 2004.



 
72

 

Cash Flows From Operating Activities

Cash provided from operating activities during the third quarter and first nine months of 2005, compared with the corresponding periods in 2004 were as follows:

 
 
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
 Operating Cash Flows
 
2005
 
2004
 
2005
 
2004
 
 
 
(In millions)
 
 
 
 
 
 
 
 
 
 
 
Cash earnings (1)
 
$
273
 
$
224
 
$
603
 
$
607
 
Pension trust contribution (2)
   
--
   
(44
)
 
--
   
(44
)
Working capital and other
 
 
64
 
 
32
 
 
198
 
 
(351
Total cash flows from operating activities
 
$
337
 
$
212
 
$
801
 
$
212
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) Cash earnings is a non-GAAP measure (see reconciliation below). 
 
 
 
 
 
 
 
 
 
 
(2) Pension trust contribution net of $29 million of income tax benefits.
 
 
 
 
 
 
 
 
 
 


Cash earnings, as disclosed in the table above, are not a measure of performance calculated in accordance with GAAP. OE believes that cash earnings is a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income.

   
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
Reconciliation of Cash Earnings
 
2005
 
2004
 
2005
 
2004
 
 
 
(In millions)
 
 
 
 
 
 
 
 
 
 
 
Net income (GAAP)
 
$
131
 
$
103
 
$
235
 
$
266
 
Non-cash charges (credits):
 
 
   
 
 
 
 
 
 
 
 
 
Provision for depreciation
 
 
30
 
 
31
 
 
88
 
 
91
 
Amortization of regulatory assets
 
 
126
 
 
103
 
 
348
 
 
317
 
Amortization of lease costs
   
33
   
33
   
30
   
31
 
Nuclear fuel and capital lease amortization
 
 
12
 
 
12
 
 
31
 
 
34
 
Deferral of new regulatory assets
 
 
(44
)
 
(26
)
 
(108
)
 
(70
)
Deferred income taxes and investment tax credits, net
 
 
(18
 
(40
)
 
(23
)
 
(91
)
Other non-cash items
 
 
3
 
 
8
 
 
2
 
 
29
 
Cash earnings (Non-GAAP)
 
$
273
 
$
224
 
$
603
 
$
607
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net cash provided from operating activities increased $125 million in the third quarter of 2005, compared with the third quarter of 2004, due to a $32 million increase from changes in working capital, the absence of a $44 million after-tax voluntary pension trust contribution made in the third quarter of 2004 and a $49 million increase in cash earnings as described above and under “Results from Operations”. The increase in working capital primarily reflects changes in accrued taxes of $46 million (including a $249 million reallocation of tax liabilities among the FirstEnergy subsidiaries pursuant to the tax sharing agreement), partially offset by changes in accounts payable and accounts receivable of $16 million.

Net cash provided from operating activities increased $589 million in the first nine months of 2005, compared with the same period in 2004, due to a $549 million increase from changes in working capital, the absence of a $44 million after-tax voluntary pension trust contribution made in the third quarter of 2004, partially offset by a $4 million decrease in cash earnings as described above and under “Results from Operations”. The increase in working capital primarily reflects changes in accrued taxes of $407 million (including a $249 million reallocation of tax liabilities among the FirstEnergy subsidiaries pursuant to the tax sharing agreement) and $136 million of funds received for the Energy for Education program in the second quarter of 2005.

Cash Flows From Financing Activities
 
Net cash used for financing activities increased to $64 million in the third quarter of 2005 from $14 million in the third quarter of 2004. The increase primarily resulted from a $72 million decrease in new short-term borrowings, partially offset by an $18 million decrease in redemptions and repayments. Net cash used for financing activities decreased to $347 million in the first nine months of 2005 from $350 million in the same period of 2004. The decrease was due to a $169 million increase in new debt and short term borrowings partially offset by a $163 million increase in net debt and preferred stock redemptions.
 
73

 

On May 16, 2005, Penn redeemed all 127,500 outstanding shares of 7.625% preferred stock at $102.29 per share and all 250,000 outstanding shares of 7.75% preferred stock at $100 per share, including accrued dividends to the date of redemption.

OE had approximately $799 million of cash and temporary cash investments (which include short-term notes receivable from associated companies) and $245 million of short-term indebtedness as of September 30, 2005. OE has authorization from the PUCO to incur short-term debt of up to $500 million (including bank facilities and the utility money pool described below). Penn has authorization from the SEC to incur short-term debt up to its charter limit of $51 million (including the utility money pool).

OES Capital is a wholly owned subsidiary of OE whose borrowings are secured by customer accounts receivable purchased from OE. OES Capital can borrow up to $170 million under a receivables financing arrangement. As a separate legal entity with separate creditors, OES Capital would have to satisfy its obligations to creditors before any of its remaining assets could be made available to OE. As of September 30, 2005, the facility was drawn for $120 million.

Penn Power Funding LLC (Penn Funding), a wholly owned subsidiary of Penn, is a limited liability company whose borrowings are secured by customer accounts receivable purchased from Penn. Penn Funding can borrow up to $25 million under a receivables financing arrangement. As a separate legal entity with separate creditors, Penn Funding would have to satisfy its obligations to creditors before any of its remaining assets could be made available to Penn. As of September 30, 2005, the facility was not drawn. On July 15, 2005, the facility was renewed until June 29, 2006. The annual facility fee is 0.25% on the entire finance limit.

As of October 24, 2005, OE and Penn had the aggregate capability to issue approximately $1.1 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures following the recently completed intra-system transfer of fossil generating plants (see Note 17). The issuance of FMB by OE is also subject to provisions of its senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE to incur additional secured debt not otherwise permitted by a specified exception of up to $690 million as of October 24, 2005. Based upon applicable earnings coverage tests in their respective charters, OE and Penn could issue a total of $2.8 billion of preferred stock (assuming no additional debt was issued) as of September 30, 2005. It is estimated that the annualized impact of the intra-system transfer of fossil generating plants will reduce the aggregate capability of OE and Penn to issue preferred stock by approximately 17%.

On June 14, 2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, entered into a syndicated $2 billion five-year revolving credit facility. Borrowings under the facility are available to each Borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. OE's and Penn’s borrowing limits under the facility are $550 million.

OE and Penn have the ability to borrow from their regulated affiliates and FirstEnergy to meet their short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal amount, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the third quarter of 2005 was 3.50%.

OE’s access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of FirstEnergy.

On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in their outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemming from the application of free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.

On October 3, 2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to 'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one notch above the previous rating. S&P noted that the upgrade followed the continuation of a good operating track record, specifically for the nuclear fleet through the third quarter 2005. S&P also stated that FirstEnergy’s rating reflects the benefits of supportive regulation, low-cost base load generation fleet, low-risk transmission and distribution operations and rate certainty in Ohio. FirstEnergy’s ability to consistently generate free cash flow, good liquidity, and an improving financial profile were also noted as strengths.
 
74

 
Cash Flows From Investing Activities
 
Net cash used for investing activities increased by $74 million in the third quarter of 2005 and $592 million in the first nine months of 2005, from the same periods of 2004. These increases resulted primarily from $278 million in cash proceeds from certificates of deposit during the third quarter 2004. Loans to associated companies decreased $178 million in the third quarter of 2005, partially offsetting the proceeds from certificates of deposit, and increased $289 million in the first nine months of 2005.

In the last quarter of 2005, capital requirements for property additions and capital leases are expected to be approximately $82 million. OE has additional requirements of approximately $8 million to meet sinking fund requirements for preferred stock and maturing long-term debt (excluding Penn’s optional redemptions disclosed above) during the remainder of 2005. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. OE’s capital spending for the period 2005-2007 is expected to be about $667 million of which approximately $233 million applies to 2005.

FirstEnergy Intra-System Generation Asset Transfers

On May 13, 2005, Penn, and on May 18, 2005, OE, CEI and TE, entered into certain agreements implementing a series of intra-system generation asset transfers. When fully completed, the asset transfers will result in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear and non-nuclear plants being owned by NGC, and FGCO, respectively. The generating plant interests that are being transferred do not include OE’s leasehold interests in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates.

On October 24, 2005, the OE Companies completed the transfer of non-nuclear generation assets to FGCO. The OE Companies currently expect to complete the transfer of nuclear generation assets to NGC through a spin-off by way of dividend before the end of 2005. Consummation of the nuclear transfer remains subject to necessary regulatory approvals.

These transactions are being undertaken in connection with the Ohio Companies’ and Penn’s restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. FENOC currently operates and maintains the nuclear generation assets to be transferred. FGCO, as lessee under a Master Facility Lease, leased, operated and maintained the non-nuclear generation assets that it now owns. The transactions will essentially complete the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO, respectively, without impacting the operation of the plants.

See Note 17 to the consolidated financial statements for OE's and Penn’s disclosure of the assets held for sale as of September 30, 2005.

Off-Balance Sheet Arrangements

Obligations not included on OE’s Consolidated Balance Sheets primarily consist of sale and leaseback arrangements involving Perry Unit 1 and Beaver Valley Unit 2. The present value of these operating lease commitments, net of trust investments, was $678 million as of September 30, 2005.

Equity Price Risk
 
Included in OE’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $262 million and $248 million as of September 30, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $26 million reduction in fair value as of September 30, 2005. Changes in the fair value of these investments are recorded in OCI unless recognized as a result of a sale or recognized as regulatory assets or liabilities.


75

 
Outlook
 
The electric industry continues to transition to a more competitive environment and all of the OE Companies’ customers can select alternative energy suppliers. The OE Companies continue to deliver power to residential homes and businesses through their existing distribution system, which remains regulated. Customer rates have been restructured into separate components to support customer choice. In Ohio and Pennsylvania, the OE Companies have a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits.

Regulatory Matters

In 2001, Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of OE's customers elects to obtain power from an alternative supplier, OE reduces the customer's bill with a "generation shopping credit," based on the generation component (plus an incentive), and the customer receives a generation charge from the alternative supplier. OE has continuing PLR responsibility to its franchise customers through December 31, 2008 unless the PUCO accepts future competitive bid results prior to the end of that period under the revised RSP.

As part of OE's transition plan, it is obligated to supply electricity to customers who do not choose an alternative supplier. OE is also required to provide 560 MW of low cost supply (MSG) to unaffiliated alternative suppliers who serve customers within its service area. FES acts as an alternate supplier for a portion of the load in OE's franchise area.

On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a competitive bid process. The RSP was filed by the Ohio Companies to establish generation service rates beginning January 1, 2006, in response to PUCO concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. In October 2004, the OCC and NOAC filed appeals with the Supreme Court of Ohio to overturn the original June 9, 2004 PUCO order in this proceeding as well as the associated entries on rehearing. On September 28, 2005, the Ohio Supreme Court heard oral argument on the appeals.

On May 27, 2005, OE filed an application with the PUCO to establish a GCAF rider under the RSP. The application seeks to implement recovery of increased fuel costs from 2006 through 2008 applicable to OE’s retail customers through a tariff rider to be implemented January 1, 2006. The application reflects projected increases in fuel costs in 2006 compared to 2002 baseline costs. The new rider, after adjustments made in testimony, is seeking to recover all costs above the baseline (approximately $88 million in 2006 for all of the Ohio Companies). Various parties including the OCC have intervened in this case and the case has been consolidated with the RCP application discussed below.

On September 9, 2005, OE filed an application with the PUCO that, if approved, would supplement its existing RSP with an RCP. On September 27, 2005, the PUCO granted FirstEnergy's motion to consolidate the GCAF rider application with the RCP proceedings and set hearings for the consolidated cases to begin November 29, 2005. The RCP is designed to provide customers with more certain rate levels than otherwise available under the RSP during the plan period, and to provide OE with financial results generally comparable to those attained under the RSP. Major provisions of the RCP include:

·    Maintain the existing level of base distribution rates through December 31, 2008 for OE;

·    Defer and capitalize certain distribution costs to be incurred by all of the Ohio Companies during
    the period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the
    three years;

·    Adjust the RTC and extended RTC recovery periods and rate levels so that full recovery of
    authorized costs will occur as of December 31, 2008 for OE;

·    Reduce the deferred shopping incentive balance as of January 1, 2006 by up to $75 million for OE
    by accelerating the application of its accumulated cost of removal regulatory liability; and

·    Recover increased fuel costs of up to $75 million, $77 million, and $79 million, in 2006, 2007, and
    2008, respectively, from all OE and TE distribution and transmission customers through a fuel
    recovery mechanism. OE may defer and capitalize increased fuel costs above the amount
    collected through the fuel recovery mechanism.
 
76

 

Under provisions of the RSP, the PUCO may require OE to undertake, no more often than annually, a competitive bid process to secure generation for the years 2007 and 2008. On July 22, 2005, FirstEnergy filed a competitive bid process for the period beginning in 2007 that is similar to the competitive bid process approved by the PUCO for OE in 2004, which resulted in the PUCO accepting no bids. Any acceptance of future competitive bid results would terminate the RSP pricing, with no accounting impacts to the RSP, and not until twelve months after the PUCO authorizes such termination. On September 28, 2005, the PUCO issued an Entry that essentially approved the Ohio Companies' filing but delayed the proposed timing of the competitive bid process by four months, calling for the auction to be held on March 21, 2006.

On December 30, 2004, OE filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application seeks recovery of these costs beginning January 1, 2006. At the time of filing the application, these costs were estimated to be approximately $14 million per year; however, OE anticipates that this amount will increase. OE requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted each July 1 thereafter. OE reached a settlement with OCC, PUCO staff, Industrial Energy Users - Ohio and OPAE. The only other party in this proceeding, Dominion Retail, Inc., agreed not to oppose the settlement. This settlement, which was filed with the PUCO on July 22, 2005, provides for the rider recovery requested by OE, with carrying charges applied in the subsequent year’s rider for any over or under collection while the then-current rider is in effect. The PUCO approved the settlement stipulation on August 31, 2005. The incremental Transmission and Ancillary service revenues expected to be recovered from January through June 2006 are approximately $30.6 million. This value includes the recovery of the 2005 deferred MISO expenses as described below. In May 2006, OE will file a modification to the rider which will determine revenues from July 2006 through June 2007.

The second application seeks authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for OE to defer incremental transmission and ancillary service-related charges incurred as a participant in MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Permission to defer costs incurred prior to December 31, 2004 was denied. The PUCO also authorized OE to accrue carrying charges on the deferred balances. An application filed with the PUCO to recover these deferred charges over a five-year period through the rider, beginning in 2006, was approved in a PUCO order issued on August 31, 2005 approving the stipulation referred to above. The OCC, OPAE and OE each filed applications for rehearing. OE sought authority to defer the transmission and ancillary service related costs incurred during the period October 1, 2003 through December 29, 2004, while both OCC and OPAE sought to have the PUCO deny deferral of all costs. On July 6, 2005, the PUCO denied OE's and OCC’s applications and, at the request of OE, struck as untimely OPAE’s application. The OCC filed a notice of appeal with the Ohio Supreme Court on August 31, 2005. On September 30, 2005, in accordance with appellate procedure, the PUCO filed with the Ohio Supreme Court the record in this case. The Companies’ brief will be due thirty days after the OCC files its brief, which, absent any time extensions, must be filed no later than November 9, 2005.

OE and Penn record as regulatory assets costs which have been authorized by the PUCO, the PPUC and the FERC for recovery from customers in future periods and, without such authorization, the costs would have been charged to income when incurred. OE’s regulatory assets as of September 30, 2005 and December 31, 2004, were $0.8 billion and $1.1 billion, respectively. OE is deferring customer shopping incentives and interest costs as new regulatory assets in accordance with its transition and rate stabilization plans. These regulatory assets total $302 million as of September 30, 2005 and, under the RSP, will be recovered through a surcharge rate equal to the RTC rate in effect when the transition costs have been fully recovered. See Note 14 “Regulatory Matters - Ohio” for the estimated net amortization of regulatory transition costs and deferred shopping incentive balances under the proposed RCP and current RSP. Penn's net regulatory asset components aggregate as net regulatory liabilities of approximately $48 million and $18 million, and are included in Other Noncurrent Liabilities on the Consolidated Balance Sheet as of September 30, 2005 and December 31, 2004, respectively.

On October 11, 2005, Penn filed a plan with the PPUC to secure electricity supply for its customers at set rates following the end of its transition period on December 31, 2006. Penn is recommending that the Request for Proposal process cover the period of January 1, 2007 through May 31, 2008. Under Pennsylvania's electric competition law, Penn is required to secure generation supply for customers who do not choose alternative suppliers for their electricity.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio and Pennsylvania and a detailed discussion of reliability initiatives, including actions by the PPUC, that impact Penn.

77


Environmental Matters

OE accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in OE's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

FirstEnergy plans to issue a report regarding its response to air emission requirements. FirstEnergy expects to complete the report by December 1, 2005.

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR provides each affected state until 2006 to develop implementing regulation to achieve additional reductions of NOx and SO2 emissions in two phases (Phase I in 2009 for NOx, 2010 for SO2 and Phase II in 2015 for both NOx and SO2) in all cases from the 2003 levels. The OE Companies’ Ohio and Pennsylvania fossil-fuel generation facilities will be subject to the caps on SO2 and NOx emissions. According to the EPA, SO2 emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO2 emissions in affected states to just 2.5 million tons annually. NOx emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NOx cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which the OE Companies operate affected facilities.

Mercury Emissions
 
In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On March 14, 2005, the EPA finalized the “Clean Air Mercury Rule,” which provides for a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases. Initially, mercury emissions will be capped nationally at 38 tons by 2010 as a "co-benefit" from implementation of SO2 and NOx emission caps under the EPA's CAIR program. Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. However, the final rules give states substantial discretion in developing rules to implement these programs. In addition, both the CAIR and the Clean Air Mercury rule have been challenged in the United States Court of Appeals for the District of Columbia. Future cost of compliance with these regulations may be substantial.

W. H. Sammis Plant
 
In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which is owned by OE and Penn. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the W. H. Sammis Plant New Source Review litigation. This settlement agreement, which is in the form of a Consent Decree, was approved by the Court on July 11, 2005, requires OE and Penn to reduce NOx and SO2 emissions at the W. H. Sammis Plant and other coal-fired plants through the installation of pollution control devices. Capital expenditures necessary to meet those requirements are currently estimated to be $1.5 billion (the primary portion of which is expected to be spent in the 2008 to 2011 time period). The settlement agreement also requires OE and Penn to spend up to $25 million toward environmentally beneficial projects, which include wind energy purchased power agreements over a 20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million. Results for the first quarter of 2005 included the penalties payable by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also recognized liabilities of $9.2 million and $0.8 million, respectively, for probable future cash contributions toward environmentally beneficial projects during the first quarter of 2005.


 
 
78


Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global warming by reducing the amount of man-made GHG emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Protocol in 1998 but it failed to receive the two-thirds vote of the United States Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity - the ratio of emissions to economic output - by 18 percent through 2012. The Energy Policy Act of 2005 established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

The OE Companies cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO2 emissions could require significant capital and other expenditures. However, the CO2 emissions per KWH of electricity generated by the OE Companies is lower than many regional competitors due to the OE Companies' diversified generation sources which include low or non-CO2 emitting gas-fired and nuclear generators.

Regulation of Hazardous Waste
 
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 subsequently determined 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.

See Note 13(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings
 
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to OE's normal business operations pending against OE and its subsidiaries. The other material items not otherwise discussed above are described below.

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concludes, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades, to existing equipment, and therefore FirstEnergy has not accrued a liability as of September 30, 2005 for any expenditures in excess of those actually incurred through that date. FirstEnergy notes, however, that the FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.
 
 
79

 

FirstEnergy companies also are defending six separate complaint cases before the PUCO relating to the August 14, 2003 power outage. Two such cases were originally filed in Ohio State courts but subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In both such cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Of the four other pending PUCO complaint cases, three were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each such case, the carriers seek reimbursement against various FirstEnergy companies (and, in one case, against PJM, MISO and American Electric Power Co. as well) for claims they paid to their insureds allegedly due to the loss of power on August 14, 2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy company. The fourth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. In addition to these six cases, the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages. No estimate of potential liability has been undertaken for any of these cases.

One complaint was filed on August 25, 2004 against FirstEnergy in the New York State Supreme Court. In this case, several plaintiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. FirstEnergy's motion to dismiss the case was granted on September 26, 2005. Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter is not due until on or about December 1, 2005. No estimate of potential liability has been undertaken in this matter.

FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. In particular, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the preceding two years and the licensee's failure to take prompt and effective corrective action. FENOC operates the Perry Nuclear Power Plant, in which the OE Companies have a 35.24% interest (however, see Note 17 regarding FirstEnergy’s pending intra-system generation asset transfers, which include owned portions of the plant).

On April 4, 2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Plant operated "in a manner that preserved public health and safety" even though it remained under heightened NRC oversight. During the public meeting and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix.

On May 26, 2005, the NRC held a public meeting to discuss its oversight of the Perry Plant. While the NRC stated that the plant continued to operate safely, the NRC also stated that the overall performance had not substantially improved since the heightened inspection was initiated. The NRC reiterated this conclusion in its mid-year assessment letter dated August 30, 2005. On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance of Perry and stated that the CAL would remain open until substantial improvement was demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight Process. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process from increased oversight to possible impact to the plant’s operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and OE, and the Davis-Besse extended outage (OE has no interest in Davis-Besse), have become the subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. On August 24, 2005 additional information was requested regarding Davis-Besse. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.
 
80

 

On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from the W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members.

The City of Huron filed a complaint against OE with the PUCO challenging the ability of electric distribution utilities to collect transition charges from a customer of a newly formed municipal electric utility. The complaint was filed on May 28, 2003, and OE timely filed its response on June 30, 2003. In a related filing, the Ohio Companies filed for approval with the PUCO of a tariff that would specifically allow the collection of transition charges from customers of municipal electric utilities formed after 1998. An adverse ruling could negatively affect full recovery of transition charges by the utility. Hearings on the matter were held in August 2005. Initial briefs from all parties were filed on September 22, 2005 and reply briefs were filed on October 14, 2005. It is unknown when the PUCO will rule on this case.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

See Note 13(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

New Accounting Standards and Interpretations

EITF Issue 04-13,”Accounting for Purchases and Sales of Inventory with the Same Counterparty”
 
In September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus that an exchange of inventory should be accounted for at fair value. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and other storable inventory. Therefore, OE will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006.

 
EITF Issue No. 05-6, “Determining the Amortization Period for Leasehold Improvements Purchased after Lease Inception or Acquired in a Business Combination”
 
In June 2005, the EITF reached a consensus on the application guidance for Issue 05-6. EITF 05-6 addresses the amortization period for leasehold improvements that were either acquired in a business combination or placed in service significantly after and not contemplated at or near the beginning of the initial lease term. For leasehold improvements acquired in a business combination, the amortization period is the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date of acquisition. Leasehold improvements that are placed in service significantly after and not contemplated at or near the beginning of the lease term should be amortized over the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date the leasehold improvements are purchased. This EITF was effective July 1, 2005 and is consistent with the OE current accounting.

 
FIN 47, “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the second period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective no later than the end of fiscal years ending after December 15, 2005. Therefore, OE will adopt this Interpretation in the fourth quarter of 2005. OE is currently evaluating the effect this standard will have on its financial statements.



 
81

 

 
SFAS 154 - “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3”

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in an income statement. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. OE will adopt this Statement effective January 1, 2006.

 
SFAS 153, “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29”

In December 2004, the FASB issued SFAS 153 amending APB 29, which was based on the principle that nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB 29 included certain exceptions to that principle. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement are effective for nonmonetary exchanges occurring in fiscal periods beginning after June 15, 2005 and are to be applied prospectively. As a result, OE will adopt this Statement effective January 1, 2006, and does not expect it to have a material impact on its financial statements.

SFAS 151, “Inventory Costs - an amendment of ARB No. 43, Chapter 4”

In November 2004, the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Previous guidance stated that in some circumstances these costs may be “so abnormal” that they would require treatment as current period costs. SFAS 151 requires abnormal amounts for these items to always be recorded as current period costs. In addition, this Statement requires that allocation of fixed production overheads to the cost of conversion be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred by OE beginning January 1, 2006. OE is currently evaluating this Standard and does not expect it to have a material impact on the financial statements.

FSP FAS 115-1, “The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments”

In September 2005, the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP FAS 115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition of Other Than Temporary Impairment upon the Planned Sale of a Security Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when the impairment is deemed other than temporary, even if a decision to sell has not been made, and (3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after September 15, 2005. The FASB expects to issue this FSP in the fourth quarter of 2005, which would require prospective application with an effective date for reporting periods beginning after December 15, 2005. OE is currently evaluating this FSP and any impact on its investments.
 

82

 
 

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
 
                       
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
 
(Unaudited)
 
                       
   
Three Months Ended
     
Nine Months Ended
 
   
September 30,
     
September 30,
 
   
2005
 
2004
     
2005
 
2004
 
   
(In thousands) 
 
STATEMENTS OF INCOME
                     
                       
OPERATING REVENUES
 
$
526,421
 
$
504,848
     
$
1,408,341
 
$
1,372,259
 
                               
OPERATING EXPENSES AND TAXES:
                             
Fuel
   
24,701
   
21,011
       
64,138
   
57,583
 
Purchased power
   
129,640
   
140,988
       
411,366
   
412,170
 
Nuclear operating costs
   
26,252
   
28,766
       
121,765
   
80,002
 
Other operating costs
   
89,475
   
76,196
       
227,759
   
219,857
 
Provision for depreciation
   
36,100
   
33,096
       
100,602
   
98,060
 
Amortization of regulatory assets
   
68,455
   
53,732
       
177,497
   
151,822
 
Deferral of new regulatory assets
   
(60,519
)
 
(40,596
)
     
(126,508
)
 
(92,032
)
General taxes
   
40,054
   
37,348
       
115,546
   
110,646
 
Income taxes
   
55,286
   
51,883
       
94,897
   
81,057
 
Total operating expenses and taxes 
   
409,444
   
402,424
       
1,187,062
   
1,119,165
 
                               
OPERATING INCOME
   
116,977
   
102,424
       
221,279
   
253,094
 
                               
OTHER INCOME (net of income taxes)
   
24,117
   
8,264
       
37,691
   
29,485
 
                               
NET INTEREST CHARGES:
                             
Interest on long-term debt
   
27,090
   
24,061
       
83,452
   
92,967
 
Allowance for borrowed funds used during construction
   
(1,129
)
 
(1,056
)
     
(2,012
)
 
(3,782
)
Other interest expense
   
4,696
   
5,239
       
12,952
   
12,750
 
Net interest charges 
   
30,657
   
28,244
       
94,392
   
101,935
 
                               
NET INCOME
   
110,437
   
82,444
       
164,578
   
180,644
 
                               
PREFERRED STOCK DIVIDEND REQUIREMENTS
   
-
   
1,754
       
2,918
   
5,253
 
                               
EARNINGS ON COMMON STOCK
 
$
110,437
 
$
80,690
     
$
161,660
 
$
175,391
 
                               
STATEMENTS OF COMPREHENSIVE INCOME
                             
                               
NET INCOME
 
$
110,437
 
$
82,444
     
$
164,578
 
$
180,644
 
                               
OTHER COMPREHENSIVE INCOME (LOSS):
                             
Unrealized gain (loss) on available for sale securities
   
(6,574
)
 
991
       
(9,144
)
 
(1,332
)
Income tax expense (benefit) related to other comprehensive income
   
(2,510
)
 
406
       
(3,433
)
 
(546
)
Other comprehensive income (loss), net of tax 
   
(4,064
)
 
585
       
(5,711
)
 
(786
)
                               
TOTAL COMPREHENSIVE INCOME
 
$
106,373
 
$
83,029
     
$
158,867
 
$
179,858
 
                               
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an
   
integral part of these statements.
                             
                               
 
 
 
83

 

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
 
           
CONSOLIDATED BALANCE SHEETS
 
(Unaudited)
 
   
September 30,
 
December 31,
 
   
2005
 
2004
 
   
(In thousands) 
 
ASSETS
         
UTILITY PLANT:
         
In service
 
$
4,498,876
 
$
4,418,313
 
Less - Accumulated provision for depreciation
   
2,020,868
   
1,961,737
 
     
2,478,008
   
2,456,576
 
Construction work in progress -
             
Electric plant
   
90,911
   
85,258
 
Nuclear fuel
   
8,632
   
30,827
 
     
99,543
   
116,085
 
     
2,577,551
   
2,572,661
 
OTHER PROPERTY AND INVESTMENTS:
             
Investment in lessor notes
   
564,169
   
596,645
 
Nuclear plant decommissioning trusts
   
427,920
   
383,875
 
Long-term notes receivable from associated companies
   
8,774
   
97,489
 
Other
   
16,028
   
17,001
 
     
1,016,891
   
1,095,010
 
CURRENT ASSETS:
             
Cash and cash equivalents
   
207
   
197
 
Receivables-
             
Customers (less accumulated provision of $5,309,000 for uncollectible accounts in 2005)
   
255,769
   
11,537
 
Associated companies
   
19,883
   
33,414
 
Other (less accumulated provisions of $6,000 and $293,000, respectively,
   
9,651
   
152,785
 
for uncollectible accounts) 
             
Notes receivable from associated companies
   
-
   
521
 
Materials and supplies, at average cost
   
72,506
   
58,922
 
Prepayments and other
   
2,769
   
2,136
 
     
360,785
   
259,512
 
DEFERRED CHARGES:
             
Goodwill
   
1,688,966
   
1,693,629
 
Regulatory assets
   
889,127
   
958,986
 
Property taxes
   
77,792
   
77,792
 
Other
   
29,995
   
32,875
 
     
2,685,880
   
2,763,282
 
   
$
6,641,107
 
$
6,690,465
 
CAPITALIZATION AND LIABILITIES
             
CAPITALIZATION:
             
Common stockholder's equity-
             
Common stock, without par value, authorized 105,000,000 shares -
             
79,590,689 shares outstanding 
 
$
1,356,998
 
$
1,281,962
 
Accumulated other comprehensive income
   
12,148
   
17,859
 
Retained earnings
   
574,394
   
553,740
 
Total common stockholder's equity 
   
1,943,540
   
1,853,561
 
Preferred stock
   
-
   
96,404
 
Long-term debt and other long-term obligations
   
1,939,730
   
1,970,117
 
     
3,883,270
   
3,920,082
 
CURRENT LIABILITIES:
             
Currently payable long-term debt
   
75,706
   
76,701
 
Short-term borrowings-
             
Associated companies
   
518,784
   
488,633
 
Other
   
35,000
   
-
 
Accounts payable-
             
Associated companies
   
33,802
   
150,141
 
Other
   
6,702
   
9,271
 
Accrued taxes
   
156,630
   
129,454
 
Accrued interest
   
27,242
   
22,102
 
Lease market valuation liability
   
60,200
   
60,200
 
Other
   
39,094
   
61,131
 
     
953,160
   
997,633
 
NONCURRENT LIABILITIES:
             
Accumulated deferred income taxes
   
552,072
   
540,211
 
Accumulated deferred investment tax credits
   
58,736
   
60,901
 
Lease market valuation liability
   
623,100
   
668,200
 
Asset retirement obligation
   
280,765
   
272,123
 
Retirement benefits
   
86,597
   
82,306
 
Other
   
203,407
   
149,009
 
     
1,804,677
   
1,772,750
 
COMMITMENTS AND CONTINGENCIES (Note 13)
                   
   
$
6,641,107
 
$
6,690,465
 
               
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are
         
an integral part of these balance sheets.
             
               

 
 
 
 
84

 
 

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
 
                   
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(Unaudited)
 
                   
   
Three Months Ended
 
Nine Months Ended
 
   
September 30,
 
September 30,
 
   
2005
 
2004
 
2005
 
2004
 
   
(In thousands)
 
                   
CASH FLOWS FROM OPERATING ACTIVITIES:
                 
Net income
 
$
110,437
 
$
82,444
 
$
164,578
 
$
180,644
 
Adjustments to reconcile net income to net cash from
                         
operating activities -
                         
Provision for depreciation 
   
36,100
   
33,096
   
100,602
   
98,060
 
Amortization of regulatory assets 
   
68,455
   
53,732
   
177,497
   
151,822
 
Deferral of new regulatory assets 
   
(60,519
)
 
(40,596
)
 
(126,508
)
 
(92,032
)
Nuclear fuel and capital lease amortization 
   
8,236
   
7,804
   
19,017
   
20,420
 
Amortization of electric service obligation 
   
(2,155
)
 
(3,336
)
 
(12,278
)
 
(12,877
)
Deferred rents and lease market valuation liability 
   
(13,439
)
 
(14,324
)
 
(67,130
)
 
(56,182
)
Deferred income taxes and investment tax credits, net 
   
10,484
   
13,019
   
14,934
   
11,392
 
Accrued retirement benefit obligations 
   
2,169
   
2,854
   
4,291
   
10,900
 
Accrued compensation, net 
   
1,201
   
1,303
   
(1,294
)
 
3,232
 
Pension trust contribution 
   
-
   
(31,718
)
 
-
   
(31,718
)
Decrease (increase) in operating assets- 
                         
 Receivables
   
10,507
   
(3,422
)
 
(87,567
)
 
106,421
 
 Materials and supplies
   
15,207
   
(2,238
)
 
(13,584
)
 
(7,711
)
 Prepayments and other current assets
   
(821
)
 
1,512
   
(633
)
 
3,409
 
Increase (decrease) in operating liabilities- 
                         
 Accounts payable
   
(157,188
)
 
60,237
   
(118,908
)
 
1,889
 
 Accrued taxes
   
33,955
   
(15,630
)
 
27,176
   
(52,495
)
 Accrued interest
   
5,460
   
(3,218
)
 
5,140
   
(2,371
)
Prepayment for electric service - education programs 
   
-
   
-
   
67,589
   
-
 
Other 
   
(18,457
)
 
(3,335
)
 
(26,328
)
 
(40,193
)
 Net cash provided from operating activities
   
49,632
   
138,184
   
126,594
   
292,610
 
                           
CASH FLOWS FROM FINANCING ACTIVITIES:
                         
New Financing-
                         
Long-term debt 
   
87,772
   
44,330
   
141,056
   
125,238
 
Short-term borrowings, net 
   
-
   
213,682
   
53,369
   
132,770
 
Equity contributions from parent  
   
-
   
-
   
75,000
   
-
 
Redemptions and Repayments-
                         
Preferred stock 
   
-
   
(1,000
)
 
(101,900
)
 
(1,000
)
Long-term debt 
   
(90,859
)
 
(327,171
)
 
(147,789
)
 
(335,272
)
Short-term borrowings, net 
   
(5,505
)
 
-
   
-
   
-
 
Dividend Payments-
                         
Common stock 
   
(17,000
)
 
-
   
(141,000
)
 
(145,000
)
Preferred stock 
   
-
   
(1,755
)
 
(2,260
)
 
(5,253
)
 Net cash used for financing activities
   
(25,592
)
 
(71,914
)
 
(123,524
)
 
(228,517
)
                           
CASH FLOWS FROM INVESTING ACTIVITIES:
                         
Property additions
   
(37,809
)
 
(32,238
)
 
(98,053
)
 
(70,967
)
Loan repayments from (loans to) associated companies, net
   
22,309
   
(850
)
 
89,236
   
9,964
 
Investments in lessor notes
   
3
   
(11,699
)
 
32,476
   
9,266
 
Contributions to nuclear decommissioning trusts
   
(7,256
)
 
(7,256
)
 
(21,768
)
 
(21,768
)
Other
   
(1,287
)
 
(14,227
)
 
(4,951
)
 
(15,170
)
 Net cash used for investing activities
   
(24,040
)
 
(66,270
)
 
(3,060
)
 
(88,675
)
                           
Net change in cash and cash equivalents
   
-
   
-
   
10
   
(24,582
)
Cash and cash equivalents at beginning of period
   
207
   
200
   
197
   
24,782
 
Cash and cash equivalents at end of period
 
$
207
 
$
200
 
$
207
 
$
200
 
                           
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an
   
integral part of these statements.
                         
                           
 
 
 
85

 

Report of Independent Registered Public Accounting Firm









To the Stockholders and Board of
Directors of The Cleveland Electric Illuminating Company:

We have reviewed the accompanying consolidated balance sheet of The Cleveland Electric Illuminating Company and its subsidiaries as of September 30, 2005, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and nine-month periods ended September 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2004, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 2(G) to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 6 to those consolidated financial statements) dated March 7, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.




PricewaterhouseCoopers LLP
Cleveland, Ohio
November 1, 2005
 
86

 

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION


CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business in portions of Ohio, providing regulated electric distribution services. CEI also provides generation services to those customers electing to retain CEI as their power supplier. CEI provides power directly to alternative energy suppliers under CEI’s transition plan. CEI has unbundled the price of electricity into its component elements -- including generation, transmission, distribution and transition charges. Power supply requirements of CEI are provided by FES -- an affiliated company.

Results of Operations
 
Earnings on common stock in the third quarter of 2005 increased to $110 million from $81 million in the third quarter of 2005. Increased earnings in the third quarter of 2005 resulted primarily from higher operating revenues and lower purchased power costs, which were partially offset by higher regulatory asset amortization and higher other operating costs. For the first nine months of 2005, earnings on common stock decreased to $162 million from $175 million in the same period of 2004. Lower earnings for the first nine months of 2005 resulted primarily from higher nuclear operating costs, higher regulatory asset amortization and other operating costs and a one-time income tax charge; those effects were partially offset by increased operating revenues and lower net interest charges.

Operating revenues increased by $22 million or 4.3% in the third quarter of 2005 from the same period in 2004. Higher revenues resulted primarily from increases in retail generation and distribution revenues of $3 million and $19 million, respectively, and a $5 million increase in revenues from wholesale sales. During the first nine months of 2005, operating revenues increased by $36 million or 2.6%, compared to the same period in 2004. Higher revenues were due to increases in retail generation and distribution revenues of $13 million and $23 million, respectively, and a $2 million increase in revenues from wholesale sales.

Increased retail generation revenues for the third quarter of 2005 resulted from higher industrial unit prices and higher residential KWH sales, partially offset by lower unit prices and KWH sales for commercial customers. An 18.7% increase in residential KWH sales during the third quarter was primarily due to warmer weather in CEI's service area, as compared to last year. An increase in residential customer shopping by 1.7 percentage points in the third quarter of 2005 partially offset the higher generation KWH sales as compared to 2004. Increased retail generation revenues for the first nine months of 2005 resulted from higher industrial unit prices and higher residential KWH sales, partially offset by lower commercial and industrial KWH sales. The decrease in residential customer shopping by 0.7 percentage points in the first nine months of 2005 contributed slightly to the higher generation KWH sales for the period as compared to last year.

Revenue from wholesale sales increased by $5 million during the third quarter of 2005, reflecting the effect of a 2.5% increase in KWH sales. The increase in wholesale sales was primarily due to a 13.6% KWH increase in MSG sales to non-affiliated wholesale customers ($3.5 million). Under its Ohio transition plan, CEI is required to provide MSG to non-affiliated alternative suppliers (see Outlook - Regulatory Matters). Increased sales to FES of $1.5 million (1.3% KWH increase) also contributed to the third quarter results. In the first nine months of 2005, wholesale sales revenue increased by $2 million. A $20 million increase (23.0% KWH increase) in MSG sales to non-affiliated wholesale customers was partially offset by an $18 million decrease in sales (6.7% KWH decrease) to FES.

Revenues from distribution throughput increased $19 million in the third quarter of 2005 compared with the same quarter of 2004. The increase was due to higher residential and industrial revenues ($18 million and $5 million, respectively), reflecting increased distribution deliveries in the third quarter of 2005, in part due to warmer weather. These increases were partially offset by lower commercial revenues of $4 million as a result of lower unit prices.

Revenues from distribution throughput increased $23 million in the first nine months of 2005 compared with the same period in 2004 due to higher revenues in the residential sector ($28 million), partially offset by lower industrial revenues ($4 million). Higher distribution deliveries in the residential sector were partially offset by lower unit prices and decreased KWH deliveries to industrial customers. Revenues in the commercial sector increased slightly ($0.4 million) as higher distribution deliveries were almost totally offset by lower unit prices.

 
 

87



Changes in KWH sales by customer class in the three months and nine months ended September 30, 2005 from the corresponding periods of 2004 are summarized in the following table:
 
   
Three
 
Nine
 
Changes in KWH Sales
 
Months
 
Months
 
Increase (Decrease)
 
 
 
 
 
Electric Generation:
 
 
 
 
 
Retail
 
 
0.6
%
 
(0.3
)%
Wholesale
 
 
2.5
%
 
(4.0
)%
Total Electric Generation Sales
 
 
1.7
%
 
(2.5
)%
 
 
 
 
 
 
 
 
Distribution Deliveries:
 
 
 
 
 
 
 
Residential
 
 
18.7
%
 
9.7
%
Commercial
 
 
1.5
%
 
3.3
%
Industrial
 
 
2.8
%
 
(1.0
)%
Total Distribution Deliveries
 
 
6.6
%
 
2.9
%
 
 
 
 
 
 
 
 


Operating Expenses and Taxes

Total operating expenses and taxes increased by $7 million in the third quarter and $68 million in the first nine months of 2005 from the same periods of 2004. The following table presents changes from the prior year by expense category.

     
 
 
 
 
 
Three
 
Nine
 
Operating Expenses and Taxes - Changes
 
Months
 
Months
 
Increase (Decrease)
 
(In millions)
 
Fuel costs
 
$
3
 
$
6
 
Purchased power costs
 
 
(11
)
 
(1
)
Nuclear operating costs
 
 
(2
)
 
42
 
Other operating costs
   
13
   
8
 
Provision for depreciation
 
 
3
 
 
3
 
Amortization of regulatory assets
 
 
15
 
 
26
 
Deferral of new regulatory assets
 
 
(20
)
 
(35
General taxes
   
3
   
5
 
Income taxes
 
 
3
 
 
14
 
Net increase in operating expenses and taxes
 
$
7
 
$
68
 
 
 
 
 
 
 
 
 


Higher fuel costs in the third quarter and first nine months of 2005, compared to the same periods last year, were primarily due to increased fossil fuel expenses associated with higher fossil generation levels in 2005. Lower purchased power costs in the third quarter of 2005, compared with the third quarter of 2004, reflected both lower unit costs and lower KWH purchased. The increase in nuclear operating costs in the first nine months of 2005, compared to the same period last year, was primarily due to a refueling outage (including an unplanned extension) at the Perry Plant in 2005 and a refueling outage at Beaver Valley Unit 2. A mid-cycle inspection outage at the Davis-Besse Plant in the first quarter of 2005 also contributed to higher nuclear operating costs in the first nine months of 2005. There were no scheduled outages in the first nine months of 2004. Higher other operating costs in the third quarter and first nine months of 2005, compared to the same periods last year, were primarily due to transmission expenses related to MISO Day 2 transactions that began on April 1, 2005.

Higher regulatory asset amortization in the third quarter and first nine months of 2005, compared to the same periods last year, was primarily due to increased amortization of transition costs being recovered under the RSP. Increases in regulatory asset deferrals for both the third quarter and first nine months in 2005, compared to the same periods in 2004, resulted from higher shopping incentive deferrals and related interest, and the PUCO-approved MISO administrative cost deferrals, including interest, that began in the second quarter of 2005 (see Outlook - Regulatory Matters).

On June 30, 2005, the State of Ohio enacted new tax legislation that created a new CAT tax, which is based on qualifying “taxable gross receipts” and will not consider any expenses or costs incurred to generate such receipts, except for items such as cash discounts, returns and allowances, and bad debts. The CAT tax was effective July 1, 2005, and replaces the Ohio income-based franchise tax and the Ohio personal property tax. The CAT tax is phased-in while the current income-based franchise tax is phased-out over a five-year period at a rate of 20% annually, beginning with the year ended 2005, and personal property tax is phased-out over a four-year period at a rate of 25% annually, beginning with the year ended 2005. For example, during the phase-out period the Ohio income-based franchise tax will be computed consistently with prior tax law, except that the tax liability as computed will be multiplied by 4/5 in 2005; 3/5 in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current income-based franchise tax over a five-year period. As a result of the new tax structure, all net deferred tax benefits that are not expected to reverse during the five-year phase-in period were written-off as of June 30, 2005. The impact on income taxes associated with the new tax legislation for the first nine months of 2005 was additional tax expense of approximately $8 million to adjust net deferred taxes and $2 million associated with the phase-out of the Ohio income-based franchise tax. See Note 12 to the consolidated financial statements.

88


Other Income

Other income increased by $16 million in the third quarter of 2005 compared with the same period of 2004, primarily due to higher nuclear decommissioning trust realized gains.

Net Interest Charges

Net interest charges in the first nine months of 2005 decreased by $8 million compared with the same period last year, reflecting the effects of net redemptions and refinancings since October 1, 2004.

Capital Resources and Liquidity
 

CEI’s cash requirements for the remainder of 2005 for operating expenses and construction expenditures are expected to be met without increasing net debt. Thereafter, CEI expects to use a combination of cash from operations and funds from the capital markets.

    Changes in Cash Position

As of September 30, 2005, CEI had $207,000 of cash and cash equivalents, compared with $197,000 as of December 31, 2004. The major sources of changes in these balances are summarized below.

Cash Flows from Operating Activities

Cash provided by operating activities during the third quarter and first nine months of 2005, compared with the corresponding periods in 2004, were as follows:

 
 
 
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
Operating Cash Flows
 
2005
 
2004
 
2005
 
2004
 
 
 
(In millions)
 
 
 
 
 
 
 
 
 
 
 
Cash earnings (1)
 
$
161
 
$
123
 
$
274
 
$
302
 
Pension trust contribution (2)
   
--
   
(19
)
 
--
   
(19
)
Working capital and other
 
 
(111
)
 
35
 
 
(147
)
 
10
 
Total cash flows from operating activities
 
$
50
 
$
139
 
$
127
 
$
293
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) Cash earnings is a non-GAAP measure (see reconciliation below).
(2) Pension contribution net of $13 million of income tax benefits
 
 
 
 
 
 
 
 
 
 
 
 
 
 

Cash earnings, as disclosed in the table above, are not a measure of performance calculated in accordance with GAAP. CEI believes that cash earnings is a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income.

89



   
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
Reconciliation of Cash Earnings
 
2005
 
2004
 
2005
 
2004
 
 
 
(In millions)
 
 
 
 
 
 
 
 
 
 
 
Net income (GAAP)
 
$
110
 
$
83
 
$
164
 
$
181
 
Non-cash charges (credits):
 
 
 
 
 
 
 
 
 
 
 
 
 
Provision for depreciation
 
 
36
 
 
33
 
 
101
 
 
98
 
Amortization of regulatory assets
 
 
68
 
 
54
 
 
177
 
 
152
 
Deferral of new regulatory assets
 
 
(60
)
 
(41
 
(126
)
 
(92
Nuclear fuel and capital lease amortization
 
 
8
 
 
7
 
 
19
 
 
20
 
Amortization of electric service obligation
 
 
(2
)
 
(3
 
(12
)
 
(13
Deferred rents and lease market valuation liability
 
 
(13
)
 
(14
 
(67
)
 
(56
Deferred income taxes and investment tax credits, net
 
 
10
 
 
--
 
 
15
 
 
(2
)
Accrued retirement benefit obligations
 
 
2
 
 
3
 
 
4
 
 
11
 
Accrued compensation, net
 
 
2
 
 
1
 
 
(1
)
 
3
 
Cash earnings (Non-GAAP)
 
$
161
 
$
123
 
$
274
 
$
302
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


The increase in cash earnings of $38 million for the third quarter and the decrease of $28 million for the first nine months of 2005, as compared to the respective periods of 2004, are described above under "Results of Operations". The primary factors contributing to the changes in working capital and other for the third quarter of 2005 are changes in accounts payable of $217 million, partially offset by changes in accrued taxes of $50 million. The primary factors contributing to the changes in working capital and other for the first nine months of 2005 are changes in accounts receivable of $194 million and accounts payable of $121 million, partially offset by changes in accrued taxes of $80 million and the $68 million received in the second quarter of 2005 for prepaid electric service under the Ohio Schools Council’s Energy for Education Program.

Cash Flows from Financing Activities
 
Net cash used for financing activities decreased $46 million in the third quarter of 2005 from the third quarter of 2004. The decrease resulted from a $62 million decrease in net debt redemptions, partially offset by higher common stock dividends to FirstEnergy of $17 million. Net cash used for financing activities decreased $105 million in the first nine months of 2005 from the same period last year. The decrease resulted primarily from lower net debt redemptions and common stock dividends to FirstEnergy and a $75 million equity contribution from FirstEnergy in the second quarter of 2005, partially offset by an increase in preferred stock redemptions.

CEI had $207,000 of cash and temporary investments and approximately $554 million of short-term indebtedness as of September 30, 2005. CEI has obtained authorization from the PUCO to incur short-term debt of up to $500 million (including the utility money pool described below). As of October 24, 2005, CEI had the capability to issue $1.6 billion of additional FMB on the basis of property additions and retired bonds under the terms of its mortgage indenture following the recently completed intra-system transfer of fossil and hydroelectric generating plants (See Note 17). The issuance of FMB by CEI is subject to a provision of its senior note indenture generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, this provision would permit CEI to incur additional secured debt not otherwise permitted by a specified exception of up to $582 million as of September 30, 2005. CEI has no restrictions on the issuance of preferred stock.

CFC is a wholly owned subsidiary of CEI whose borrowings are secured by customer accounts receivable purchased from CEI and TE. CFC can borrow up to $200 million under a receivables financing arrangement. As a separate legal entity with separate creditors, CFC would have to satisfy its obligations to creditors before any of its remaining assets could be made available to CEI. As of September 30, 2005, the facility was drawn for $35 million.

On June 14, 2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, entered into a syndicated $2 billion five-year revolving credit facility. Borrowings under the facility are available to each Borrower separately and will mature on the earlier of 364 days from the date of borrowing and the commitment termination date, as the same may be extended. CEI’s borrowing limit under the facility is $250 million.



90

 

CEI has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal amount, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the third quarter of 2005 was 3.50%.

CEI’s access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of FirstEnergy.

On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in their outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemming from the application of free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.

On October 3, 2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to 'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one notch above the previous rating. S&P noted that the upgrade followed the continuation of a good operating track record, specifically for the nuclear fleet through the third quarter 2005. S&P also stated that FirstEnergy’s rating reflects the benefits of supportive regulation, low-cost base load generation fleet, low-risk transmission and distribution operations and rate certainty in Ohio. FirstEnergy’s ability to consistently generate free cash flow, good liquidity, and an improving financial profile were also noted as strengths.

Cash Flows from Investing Activities

In the third quarter and first nine months of 2005, net cash used for investing activities decreased $42 million and $86 million, respectively, from the corresponding periods of 2004. The decrease in funds used for investing activities for both periods primarily reflected increases in loan payments received from associated companies, partially offset by increased property additions.

In the last quarter of 2005, capital requirements for property additions are expected to be about $37 million. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. CEI has no additional requirements for sinking fund requirements for preferred stock and debt during the remainder of 2005. CEI’s capital spending for the period 2005-2007 is expected to be about $368 million of which approximately $124 million applies to 2005.

FirstEnergy Intra-System Generation Asset Transfers
 
On May 18, 2005, OE, CEI and TE, entered into certain agreements implementing a series of intra-system generation asset transfers. When fully completed, the asset transfers will result in the respective undivided ownership interests of the Ohio Companies in FirstEnergy’s nuclear and non-nuclear plants being owned by NGC, and FGCO, respectively. The generating plant interests that are being transferred do not include CEI’s leasehold interests in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates.

On October 24, 2005, CEI completed the transfer of non-nuclear generation assets to FGCO. CEI currently expects to complete the transfer of nuclear generation assets to NGC at book value before the end of 2005. Consummation of the nuclear transfer remains subject to necessary regulatory approvals.

These transactions are being undertaken in connection with the Ohio Companies’ restructuring plans that were approved by the PUCO under applicable Ohio electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. FENOC currently operates and maintains the nuclear generation assets to be transferred. FGCO, as lessee under a Master Facility Lease, leased, operated and maintained the non-nuclear generation assets that it now owns. The transactions will essentially complete the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO, respectively, without impacting the operation of the plants.
 
See Note 17 to the consolidated financial statements for CEI’s disclosure of the assets held for sale as of September 30, 2005.

 
 
91


 
Off-Balance Sheet Arrangements

Obligations not included on CEI’s Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant. As of September 30, 2005, the present value of these operating lease commitments, net of trust investments, total $103 million.

CEI sells substantially all of its retail customer receivables to CFC, its wholly owned subsidiary. As of June 16, 2005, the CFC receivables financing structure was renewed and restructured from an off-balance sheet transaction to an on-balance sheet transaction. Under the new structure, any borrowings under the facility appear on the balance sheet as short-term debt.

Equity Price Risk
 
Included in CEI’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $277 million and $242 million as of September 30, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $28 million reduction in fair value as of September 30, 2005.

Outlook

The electric industry continues to transition to a more competitive environment and all of CEI's customers can select alternative energy suppliers. CEI continues to deliver power to residential homes and businesses through its existing distribution system, which remains regulated. Customer rates have been restructured into separate components to support customer choice. CEI has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits.

Regulatory Matters

In 2001, Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of CEI's customers elects to obtain power from an alternative supplier, CEI reduces the customer's bill with a "generation shopping credit," based on the generation component (plus an incentive), and the customer receives a generation charge from the alternative supplier. CEI has continuing PLR responsibility to its franchise customers through December 31, 2008 unless the PUCO accepts future competitive bid results prior to the end of that period under the revised RSP.

As part of CEI's transition plan, it is obligated to supply electricity to customers who do not choose an alternative supplier. CEI is also required to provide 400 MW of low cost supply (MSG) to unaffiliated alternative suppliers who serve customers within its service area. FES acts as an alternate supplier for a portion of the load in CEI's franchise area.

On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a competitive bid process. The RSP was filed by the Ohio Companies to establish generation service rates beginning January 1, 2006, in response to PUCO concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. In October 2004, the OCC and NOAC filed appeals with the Supreme Court of Ohio to overturn the original June 9, 2004 PUCO order in this proceeding as well as the associated entries on rehearing. On September 28, 2005, the Ohio Supreme Court heard oral argument on the appeals.

On May 27, 2005, CEI filed an application with the PUCO to establish a GCAF rider under the RSP. The application seeks to implement recovery of increased fuel costs from 2006 through 2008 applicable to CEI’s retail customers through a tariff rider to be implemented January 1, 2006. The application reflects projected increases in fuel costs in 2006 compared to 2002 baseline costs. The new rider, after adjustments made in testimony, is seeking to recover all costs above the baseline (approximately $88 million in 2006 for all of the Ohio Companies). Various parties including the OCC have intervened in this case and the case has been consolidated with the RCP application discussed below.

On September 9, 2005, CEI filed an application with the PUCO that, if approved, would supplement its existing RSP with an RCP. On September 27, 2005, the PUCO granted FirstEnergy's motion to consolidate the GCAF rider application with the RCP proceedings and set hearings for the consolidated cases to begin November 29, 2005. The RCP is designed to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. Major provisions of the RCP include:

 
92


·    Maintain the existing level of base distribution rates through April 30, 2009 for CEI;

·    Defer and capitalize certain distribution costs to be incurred by all of the Ohio Companies during the
    period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the three
    years;

·    Adjust the RTC and extended RTC recovery periods and rate levels so that full recovery of authorized
    costs will occur as of December 31, 2010 for CEI;

·    Reduce the deferred shopping incentive balances as of January 1, 2006 by up to $85 million for CEI
    by accelerating the application of its accumulated cost of removal regulatory liability; and

·    Defer and capitalize all of CEI's allowable fuel cost increases until January 1, 2009.

Under provisions of the RSP, the PUCO may require CEI to undertake, no more often than annually, a competitive bid process to secure generation for the years 2007 and 2008. On July 22, 2005, FirstEnergy filed a competitive bid process for the period beginning in 2007 that is similar to the competitive bid process approved by the PUCO for CEI in 2004, which resulted in the PUCO accepting no bids. Any acceptance of future competitive bid results would terminate the RSP pricing, with no accounting impacts to the RSP, and not until twelve months after the PUCO authorizes such termination. On September 28, 2005, the PUCO issued an Entry that essentially approved the Ohio Companies' filing but delayed the proposed timing of the competitive bid process by four months, calling for the auction to be held on March 21, 2006.

On December 30, 2004, CEI filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application seeks recovery of these costs beginning January 1, 2006. At the time of filing the application, these costs were estimated to be approximately $16 million per year; however, CEI anticipates that this amount will increase. CEI requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted each July 1 thereafter. CEI reached a settlement with OCC, PUCO staff, Industrial Energy Users - Ohio and OPAE. The only other party in this proceeding, Dominion Retail, Inc., agreed not to oppose the settlement. This settlement, which was filed with the PUCO on July 22, 2005, provides for the rider recovery requested by CEI, with carrying charges applied in the subsequent year’s rider for any over or under collection while the then-current rider is in effect. The PUCO approved the settlement stipulation on August 31, 2005. The incremental Transmission and Ancillary service revenues expected to be recovered from January through June 2006 are approximately $23.9 million. This value includes the recovery of the 2005 deferred MISO expenses as described below. In May 2006, CEI will file a modification to the rider which will determine revenues from July 2006 through June 2007.

      The second application sought authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for CEI to defer incremental transmission and ancillary service-related charges incurred as a participant in MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Permission to defer costs incurred prior to December 30, 2004 was denied. The PUCO also authorized CEI to accrue carrying charges on the deferred balances. An application filed with the PUCO to recover these deferred charges over a five-year period through the rider, beginning in 2006, was approved in a PUCO order issued on August 31, 2005, approving the stipulation referred to above. The OCC, OPAE and CEI each filed applications for rehearing. CEI sought authority to defer the transmission and ancillary service-related costs incurred during the period October 1, 2003 through December 29, 2004, while both OCC and OPAE sought to have the PUCO deny deferral of all costs. On July 6, 2005, the PUCO denied CEI’s and OCC’s applications and, at the request of CEI, struck as untimely OPAE’s application. The OCC filed a notice of appeal with the Ohio Supreme Court on August 31, 2005. On September 30, 2005, in accordance with appellate procedure, the PUCO filed with the Ohio Supreme Court the record in this case. The Companies' brief will be due thirty days after the OCC files its brief, which, absent any time extensions, must be filed no later than November 9, 2005.

CEI records as regulatory assets costs which have been authorized by the PUCO and the FERC for recovery from customers in future periods and, without such authorization, the costs would have been charged to income when incurred. CEI's regulatory assets as of September 30, 2005 and December 2004 were $0.9 billion and $1.0 billion, respectively. CEI is deferring customer shopping incentives and interest costs as new regulatory assets in accordance with its transition and rate stabilization plans. These regulatory assets total $402 million as of September 30, 2005 and under the RSP, will be recovered through a surcharge rate equal to the RTC rate in effect when the transition costs have been fully recovered. See Note 14 “Regulatory Matters - Ohio” for the estimated net amortization of regulatory transition costs and deferred shopping incentive balances under the proposed RCP and current RSP.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio.
 

 
93

 
Environmental Matters
 
CEI accrues environmental liabilities only when it concludes that it is probable that they have an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in CEI’s determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

FirstEnergy plans to issue a report regarding its response to air emission requirements. FirstEnergy expects to complete the report by December 1, 2005.

National Ambient Air Quality Standards
 
In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR provides each affected state until 2006 to develop implementing regulation to achieve additional reductions of NOx and SO2 emissions in two phases (Phase I in 2009 for NOx, 2010 for SO2 and Phase II in 2015 for both NOx and SO2) in all cases from the 2003 levels. CEI's Ohio and Pennsylvania fossil-fuel generation facilities will be subject to the caps on SO2 and NOx emissions. According to the EPA, SO2 emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO2 emissions in affected states to just 2.5 million tons annually. NOx emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NOx cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which CEI operates affected facilities.

Mercury Emissions
 
In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On March 14, 2005, the EPA finalized the “Clean Air Mercury Rule,” which provides for a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases. Initially, mercury emissions will be capped nationally at 38 tons by 2010 as a "co-benefit" from implementation of SO2 and NOx emission caps under the EPA's CAIR program. Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. However, the final rules give states substantial discretion in developing rules to implement these programs. In addition, both the CAIR and the Clean Air Mercury rule have been challenged in the United States Court of Appeals for the District of Columbia. Future cost of compliance with these regulations may be substantial.

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global warming by reducing the amount of man-made GHG emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Protocol in 1998 but it failed to receive the two-thirds vote of the United States Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity - the ratio of emissions to economic output - by 18 percent through 2012. The Energy Policy Act of 2005 established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

CEI cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO2 emissions could require significant capital and other expenditures. However, the CO2 emissions per KWH of electricity generated by CEI is lower than many regional competitors due to CEI's diversified generation sources which include low or non-CO2 emitting gas-fired and nuclear generators.


 
 
94


Regulation of Hazardous Waste

CEI has been named a PRP at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of September 30, 2005, based on estimates of the total costs of cleanup, CEI's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. Included in Other Noncurrent Liabilities are accrued liabilities aggregating approximately $2.3 million as of September 30, 2005.

See Note 13(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to CEI's normal business operations pending against CEI and its subsidiaries. The other material items not otherwise discussed above are described below.

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concludes, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades, to existing equipment, and therefore FirstEnergy has not accrued a liability as of September 30, 2005 for any expenditures in excess of those actually incurred through that date. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

FirstEnergy companies also are defending six separate complaint cases before the PUCO relating to the August 14, 2003 power outage. Two such cases were originally filed in Ohio State courts but subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In both such cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Of the four other pending PUCO complaint cases, three were filed by various insurance carriers either in their own name or as subrogees in the name of their insureds. In each such case, the carriers seek reimbursement against various FirstEnergy companies (and, in one case, against PJM, MISO and American Electric Power Co. as well) for claims they paid to their insureds allegedly due to the loss of power on August 14, 2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy company. The fourth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. In addition to these six cases, the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages. No estimate of potential liability has been undertaken for any of these cases.
 
 
95


One complaint was filed on August 25, 2004 against FirstEnergy in the New York State Supreme Court. In this case, several plaintiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. FirstEnergy's motion to dismiss the case was granted on September 26, 2005. Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter is not due until on or about December 1, 2005. No estimate of potential liability has been undertaken in this matter.

FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. In particular, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

FENOC received a subpoena in late 2003 from a grand jury sitting in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at the Davis-Besse Nuclear Power Station, in which CEI has a 51.38% interest. On December 10, 2004, FirstEnergy received a letter from the United States Attorney's Office stating that FENOC is a target of the federal grand jury investigation into alleged false statements made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01. The letter also said that the designation of FENOC as a target indicates that, in the view of the prosecutors assigned to the matter, it is likely that federal charges will be returned against FENOC by the grand jury. On February 10, 2005, FENOC received an additional subpoena for documents related to root cause reports regarding reactor head degradation and the assessment of reactor head management issues at Davis-Besse. On May 11, 2005, FENOC received a subpoena for documents related to outside meetings attended by Davis-Besse personnel on corrosion and cracking of control rod drive mechanisms and additional root cause evaluations.

On April 21, 2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to the degradation of the Davis-Besse reactor vessel head issue described above. CEI accrued $1.0 million for a potential fine prior to 2005 and accrued the remaining liability for its share of the proposed fine of $1.8 million during the first quarter of 2005. On September 14, 2005, FENOC filed its response to the NOV with the NRC. FENOC accepted full responsibility for the past failure to properly implement its boric acid corrosion control and corrective action programs. The NRC NOV indicated that the violations do not represent current licensee performance. FirstEnergy paid the penalty in the third quarter of 2005.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability based on the events surrounding Davis-Besse, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

Effective July 1, 2005 the NRC oversight panel for Davis-Besse was terminated and Davis-Besse returned to the standard NRC reactor oversight process. At that time, NRC inspections were augmented to include inspections to support the NRC's Confirmatory Order dated March 8, 2004 that was issued at the time of startup and to address an NRC White Finding related to emergency sirens.

On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the preceding two years and the licensee's failure to take prompt and effective corrective action. FENOC operates the Perry Nuclear Power Plant, in which CEI has a 44.85% interest (however, see Note 17 regarding FirstEnergy’s pending intra-system generation asset transfers, which include owned portions of the plant).

On April 4, 2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Plant operated "in a manner that preserved public health and safety" even though it remained under heightened NRC oversight. During the public meeting and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix.

96

 

On May 26, 2005, the NRC held a public meeting to discuss its oversight of the Perry Plant. While the NRC stated that the plant continued to operate safely, the NRC also stated that the overall performance had not substantially improved since the heightened inspection was initiated. The NRC reiterated this conclusion in its mid-year assessment letter dated August 30, 2005. On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance of Perry and stated that the CAL would remain open until substantial improvement was demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight Process. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process, from increased oversight to possible impact to the plant’s operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and CEI, and the Davis-Besse extended outage, have become the subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. On August 24, 2005 additional information was requested regarding Davis Besse. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.

The City of Huron filed a complaint against OE with the PUCO challenging the ability of electric distribution utilities to collect transition charges from a customer of a newly formed municipal electric utility. The complaint was filed on May 28, 2003, and OE timely filed its response on June 30, 2003. In a related filing, the Ohio Companies filed for approval with the PUCO of a tariff that would specifically allow the collection of transition charges from customers of municipal electric utilities formed after 1998. An adverse ruling could negatively affect full recovery of transition charges by CEI. Hearings on the matter were held in August 2005. Initial briefs from all parties were filed on September 22, 2005 and reply briefs were filed on October 14, 2005. It is unknown when the PUCO will rule on this case.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

See Note 13(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

New Accounting Standards and Interpretations

EITF Issue 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty"
 
In September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus that an exchange of inventory should be accounted for at fair value. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and other storable inventory. Therefore, CEI will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006.

 
EITF Issue No. 05-6, "Determining the Amortization Period for Leasehold Improvements Purchased after Lease Inception or Acquired in a Business Combination"
 
In June 2005, the EITF reached a consensus on the application guidance for Issue 05-6. EITF 05-6 addresses the amortization period for leasehold improvements that were either acquired in a business combination or placed in service significantly after and not contemplated at or near the beginning of the initial lease term. For leasehold improvements acquired in a business combination, the amortization period is the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date of acquisition. Leasehold improvements that are placed in service significantly after and not contemplated at or near the beginning of the lease term should be amortized over the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date the leasehold improvements are purchased. This EITF was effective July 1, 2005 and is consistent with CEI’s current accounting.


 
97



FIN 47, “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective for CEI in the fourth quarter of 2005. CEI is currently evaluating the effect this Interpretation will have on its financial statements.

 
SFAS 154 - “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3”

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in the Consolidated Statements of Income. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. CEI will adopt this Statement effective January 1, 2006.

 
SFAS 153, “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29”

In December 2004, the FASB issued SFAS 153 amending APB 29, which was based on the principle that nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB 29 included certain exceptions to that principle. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement are effective January 1, 2006 for CEI. This FSP is not expected to have a material impact on CEI’s financial statements.

SFAS 151, “Inventory Costs - an amendment of ARB No. 43, Chapter 4”

In November 2004, the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Previous guidance stated that in some circumstances these costs may be “so abnormal” that they would require treatment as current period costs. SFAS 151 requires abnormal amounts for these items to always be recorded as current period costs. In addition, this Statement requires that allocation of fixed production overheads to the cost of conversion be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred by CEI beginning January 1, 2006. CEI is currently evaluating this Standard and does not expect it to have a material impact on its financial statements.

FSP FAS 115-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

In September 2005, the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP FAS 115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition of Other Than Temporary Impairment upon the Planned Sale of a Security Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when the impairment is deemed other than temporary, even if a decision to sell has not been made, and (3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after September 15, 2005. The FASB expects to issue this FSP in the fourth quarter of 2005, which would require prospective application with an effective date for reporting periods beginning after December 15, 2005. CEI is currently evaluating this FSP and any impact on its investments.
 
 
98

 

THE TOLEDO EDISON COMPANY
 
                   
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
 
(Unaudited)
 
                   
   
Three Months Ended
 
Nine Months Ended
 
   
September 30,
 
September 30,
 
   
2005
 
2004
 
2005
 
2004
 
   
(In thousands)
 
STATEMENTS OF INCOME
                 
                   
OPERATING REVENUES
 
$
286,960
 
$
276,342
 
$
787,824
 
$
755,106
 
                           
OPERATING EXPENSES AND TAXES:
                         
Fuel
   
16,501
   
13,908
   
43,474
   
37,195
 
Purchased power
   
73,144
   
79,774
   
225,600
   
236,869
 
Nuclear operating costs
   
39,207
   
43,827
   
145,059
   
122,685
 
Other operating costs
   
48,164
   
43,865
   
123,823
   
121,228
 
Provision for depreciation
   
18,835
   
14,588
   
48,724
   
43,021
 
Amortization of regulatory assets
   
39,576
   
41,037
   
107,672
   
102,065
 
Deferral of new regulatory assets
   
(19,379
)
 
(12,442
)
 
(41,473
)
 
(29,664
)
General taxes
   
14,159
   
14,924
   
41,960
   
41,252
 
Income taxes
   
20,311
   
11,963
   
44,160
   
18,465
 
Total operating expenses and taxes 
   
250,518
   
251,444
   
738,999
   
693,116
 
                           
OPERATING INCOME
   
36,442
   
24,898
   
48,825
   
61,990
 
                           
OTHER INCOME (net of income taxes)
   
12,283
   
4,172
   
18,173
   
14,724
 
                           
NET INTEREST CHARGES:
                         
Interest on long-term debt
   
3,912
   
4,015
   
12,655
   
23,057
 
Allowance for borrowed funds used during construction
   
(372
)
 
(741
)
 
(117
)
 
(2,843
)
Other interest expense
   
2,958
   
1,350
   
4,192
   
2,945
 
Net interest charges 
   
6,498
   
4,624
   
16,730
   
23,159
 
                           
NET INCOME
   
42,227
   
24,446
   
50,268
   
53,555
 
                           
PREFERRED STOCK DIVIDEND REQUIREMENTS
   
1,687
   
2,211
   
6,109
   
6,633
 
                           
EARNINGS ON COMMON STOCK
 
$
40,540
 
$
22,235
 
$
44,159
 
$
46,922
 
                           
STATEMENTS OF COMPREHENSIVE INCOME
                         
                           
NET INCOME
 
$
42,227
 
$
24,446
 
$
50,268
 
$
53,555
 
                           
OTHER COMPREHENSIVE INCOME (LOSS):
                         
Unrealized gain (loss) on available for sale securities
   
(4,511
)
 
913
   
(6,695
)
 
(379
)
Income tax expense (benefit) related to other comprehensive income
   
(1,743
)
 
375
   
(2,534
)
 
(155
)
Other comprehensive income (loss), net of tax 
   
(2,768
)
 
538
   
(4,161
)
 
(224
)
                           
TOTAL COMPREHENSIVE INCOME
 
$
39,459
 
$
24,984
 
$
46,107
 
$
53,331
 
                           
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of  these statements.
 
 
   
 
 
 
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THE TOLEDO EDISON COMPANY    
 
           
CONSOLIDATED BALANCE SHEETS    
 
(Unaudited)    
 
   
September 30,
 
December 31,
 
   
2005
 
2004
 
   
(In thousands)  
 
ASSETS
         
UTILITY PLANT:
         
In service
 
$
1,906,941
 
$
1,856,478
 
Less - Accumulated provision for depreciation
   
820,562
   
778,864
 
     
1,086,379
   
1,077,614
 
Construction work in progress -
             
Electric plant
   
55,376
   
58,535
 
Nuclear fuel
   
7,370
   
15,998
 
     
62,746
   
74,533
 
     
1,149,125
   
1,152,147
 
OTHER PROPERTY AND INVESTMENTS:
             
Investment in lessor notes
   
178,765
   
190,692
 
Nuclear plant decommissioning trusts
   
335,553
   
297,803
 
Long-term notes receivable from associated companies
   
39,964
   
39,975
 
Other
   
1,741
   
2,031
 
     
556,023
   
530,501
 
CURRENT ASSETS:
             
Cash and cash equivalents
   
15
   
15
 
Receivables -
             
Customers (less accumulated provision of $2,000 for
             
 uncollectible accounts in 2004)
   
2,412
   
4,858
 
Associated companies
   
10,168
   
36,570
 
Other
   
8,658
   
3,842
 
Notes receivable from associated companies
   
52,639
   
135,683
 
Materials and supplies, at average cost
   
42,404
   
40,280
 
Prepayments and other
   
1,712
   
1,150
 
     
118,008
   
222,398
 
DEFERRED CHARGES:
             
Goodwill
   
501,022
   
504,522
 
Regulatory assets
   
309,835
   
374,814
 
Property taxes
   
24,100
   
24,100
 
Other
   
26,520
   
25,424
 
     
861,477
   
928,860
 
   
$
2,684,633
 
$
2,833,906
 
CAPITALIZATION AND LIABILITIES
             
CAPITALIZATION:
             
Common stockholder's equity -
             
Common stock, $5 par value, authorized 60,000,000 shares -
             
39,133,887 shares outstanding 
 
$
195,670
 
$
195,670
 
Other paid-in capital
   
428,572
   
428,559
 
Accumulated other comprehensive income
   
15,878
   
20,039
 
Retained earnings
   
225,218
   
191,059
 
Total common stockholder's equity 
   
865,338
   
835,327
 
Preferred stock
   
96,000
   
126,000
 
Long-term debt
   
296,373
   
300,299
 
     
1,257,711
   
1,261,626
 
CURRENT LIABILITIES:
             
Currently payable long-term debt
   
53,650
   
90,950
 
Accounts payable -
             
Associated companies
   
28,456
   
110,047
 
Other
   
3,252
   
2,247
 
Notes payable to associated companies
   
378,190
   
429,517
 
Accrued taxes
   
72,214
   
46,957
 
Lease market valuation liability
   
24,600
   
24,600
 
Other
   
28,735
   
53,055
 
     
589,097
   
757,373
 
NONCURRENT LIABILITIES:
             
Accumulated deferred income taxes
   
222,985
   
221,950
 
Accumulated deferred investment tax credits
   
24,697
   
25,102
 
Lease market valuation liability
   
249,550
   
268,000
 
Retirement benefits
   
42,998
   
39,227
 
Asset retirement obligation
   
200,078
   
194,315
 
Other
   
97,517
   
66,313
 
     
837,825
   
814,907
 
COMMITMENTS AND CONTINGENCIES (Note 13)
             
   
$
2,684,633
 
$
2,833,906
 
               
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of these blance sheets.      
 
 
             
 
 
 
100

 

THE TOLEDO EDISON COMPANY
 
                   
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(Unaudited)
 
                   
   
Three Months Ended
 
Nine Months Ended
 
   
September 30,
 
September 30,
 
   
2005
 
2004
 
2005
 
2004
 
   
(In thousands)
 
                   
CASH FLOWS FROM OPERATING ACTIVITIES:
                 
Net income
 
$
42,227
 
$
24,446
 
$
50,268
 
$
53,555
 
Adjustments to reconcile net income to net cash from
                         
operating activities -
                         
Provision for depreciation 
   
18,835
   
14,588
   
48,724
   
43,021
 
Amortization of regulatory assets 
   
39,576
   
41,037
   
107,672
   
102,065
 
Deferral of new regulatory assets 
   
(19,379
)
 
(12,442
)
 
(41,473
)
 
(29,664
)
Nuclear fuel and capital lease amortization 
   
5,682
   
7,058
   
13,816
   
17,596
 
Amortization of electric service obligation 
   
(1,910
)
 
-
   
(3,301
)
 
-
 
Deferred rents and lease market valuation liability 
   
10,310
   
9,689
   
(34,156
)
 
(26,585
)
Deferred income taxes and investment tax credits, net 
   
(12,798
)
 
(4,608
)
 
(4,605
)
 
(9,290
)
Accrued retirement benefit obligations 
   
1,534
   
1,324
   
3,771
   
4,733
 
Accrued compensation, net 
   
404
   
516
   
(333
)
 
1,477
 
Pension trust contribution 
   
-
   
(12,572
)
 
-
   
(12,572
)
Decrease (increase) in operating assets - 
                         
   Receivables
   
3,423
   
69,908
   
15,962
   
95,383
 
   Materials and supplies
   
3,788
   
(725
)
 
(2,124
)
 
(4,376
)
   Prepayments and other current assets
   
(970
)
 
677
   
(562
)
 
5,971
 
Increase (decrease) in operating liabilities - 
                         
   Accounts payable
   
(6,215
)
 
6,202
   
(80,586
)
 
(9,568
)
   Accrued taxes
   
14,748
   
(3,508
)
 
25,257
   
227
 
   Accrued interest
   
(369
)
 
(7,169
)
 
(565
)
 
(7,540
)
Prepayment for electric service -- education programs 
   
-
   
-
   
37,954
   
-
 
Other 
   
(14,392
)
 
(10,020
)
 
(22,999
)
 
(9,679
)
 Net cash provided from operating activities
   
84,494
   
124,401
   
112,720
   
214,754
 
                           
CASH FLOWS FROM FINANCING ACTIVITIES:
                         
New Financing -
                         
Long-term debt 
   
-
   
30,500
   
45,000
   
103,500
 
Short-term borrowings, net 
   
45,054
   
146,370
   
-
   
29,310
 
Redemptions and Repayments -
                         
Preferred stock 
   
(30,000
)
 
-
   
(30,000
)
 
-
 
Long-term debt 
   
(36,821
)
 
(246,591
)
 
(83,754
)
 
(261,591
)
Short-term borrowings, net 
   
-
   
-
   
(51,327
)
 
-
 
Dividend Payments -
                         
Common stock 
   
-
   
-
   
(10,000
)
 
-
 
Preferred stock 
   
(1,687
)
 
(2,211
)
 
(6,109
)
 
(6,633
)
 Net cash used for financing activities
   
(23,454
)
 
(71,932
)
 
(136,190
)
 
(135,414
)
                           
CASH FLOWS FROM INVESTING ACTIVITIES:
                         
Property additions
   
(17,951
)
 
(16,950
)
 
(50,119
)
 
(36,377
)
Loan repayments from (loans to) associated companies, net
   
(36,490
)
 
(20,389
)
 
83,055
   
(21,046
)
Investments in lessor notes
   
32
   
-
   
11,927
   
10,280
 
Contributions to nuclear decommissioning trusts
   
(7,135
)
 
(7,135
)
 
(21,406
)
 
(21,406
)
Other
   
504
   
(7,995
)
 
13
   
(13,013
)
 Net cash provided from (used for) investing activities
   
(61,040
)
 
(52,469
)
 
23,470
   
(81,562
)
                           
Net change in cash and cash equivalents
   
-
   
-
   
-
   
(2,222
)
Cash and cash equivalents at beginning of period
   
15
   
15
   
15
   
2,237
 
Cash and cash equivalents at end of period
 
$
15
 
$
15
 
$
15
 
$
15
 
                           
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements.
   
 
                         
 
 
 
101


Report of Independent Registered Public Accounting Firm









To the Stockholders and Board of
Directors of The Toledo Edison Company:

We have reviewed the accompanying consolidated balance sheet of The Toledo Edison Company and its subsidiary as of September 30, 2005, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and nine-month periods ended September 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2004, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 2(G) to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 6 to those consolidated financial statements) dated March 7, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.




PricewaterhouseCoopers LLP
Cleveland, Ohio
November 1, 2005

102


THE TOLEDO EDISON COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION


TE is a wholly owned electric utility subsidiary of FirstEnergy. TE conducts business in northwestern Ohio, providing regulated electric distribution services. TE also provides generation services to those customers electing to retain TE as their power supplier. TE provides power directly to some alternative energy suppliers under TE’s transition plan. TE has unbundled the price of electricity into its component elements - including generation, transmission, distribution and transition charges. TE’s power supply requirements are provided by FES - an affiliated company.

Results of Operations

Earnings on common stock in the third quarter of 2005 increased to $41 million from $22 million in the third quarter of 2004. The increase in earnings resulted primarily from higher operating revenues and other income, partially offset by increased financing costs. Earnings on common stock in the first nine months of 2005 decreased to $44 million from $47 million in the first nine months of 2004. The decrease in earnings resulted primarily from higher nuclear operating costs and a one-time income tax charge, partially offset by higher operating revenues and lower financing costs.

Operating revenues increased by $11 million, or 3.8%, in the third quarter of 2005 compared to the third quarter of 2004. Higher revenues in the third quarter of 2005 resulted from increased retail generation revenues of $13 million and distribution revenues of $2 million, partially offset by a decrease in wholesales sales (primarily to FES) of $4 million and an increase in shopping incentive credits of $1 million. Retail generation revenues increased as a result of increased KWH sales (residential - $1 million, commercial - $1 million and industrial - $11 million). Higher residential and commercial revenues reflected increased KWH sales (8.0% and 9.2%, respectively) and higher unit prices. KWH sales to residential and commercial customers increased primarily due to warmer weather which increased air-conditioning loads. Additionally, generation services provided to commercial customers by alternative suppliers as a percent of total commercial sales delivered in TE’s service area decreased by 2.1 percentage points compared with the third quarter of 2004. Industrial revenues increased as a result of higher unit prices and a 4.2% increase in KWH sales.

Revenues from distribution throughput increased by $2 million in the third quarter of 2005 from the corresponding quarter of 2004. The increase was due to higher residential and commercial revenues ($8 million and $0.2 million, respectively), partially offset by a decrease in industrial revenues ($7 million). The impact of higher residential and commercial KWH sales contributed to the increase; lower industrial unit prices more than offset an increase in KWH sales to industrial customers.

Operating revenues increased by $33 million, or 4.3%, in the first nine months of 2005 compared to the same period of 2004. The higher revenues resulted from increased retail generation revenues of $35 million and wholesales sales of $2 million, partially offset by an increase in shopping incentive credits of $3 million. Retail generation revenues increased as a result of higher KWH sales (residential - $2 million, commercial - $4 million, industrial - $29 million). Higher residential and commercial revenues reflected increased KWH sales (6.9% and 12.2%, respectively) and higher unit prices. Residential and commercial sales volumes increased primarily due to warmer weather. The increase in commercial revenues also reflects a reduction by 2.5 percentage points in customer shopping compared with the same period of 2004. Industrial revenues increased as a result of higher unit prices and a 0.6% increase in KWH sales.

Revenues from distribution throughput decreased by $0.4 million in the first nine months of 2005 from the same period in 2004. The decrease was due to lower industrial revenues ($22 million), partially offset by increases in residential and commercial revenues ($15 million and $6 million, respectively). The impact from lower industrial unit prices more than offset the higher KWH sales in all customer classes.

Under the Ohio transition plan, TE provides incentives to customers to encourage switching to alternative energy providers. TE’s revenues were reduced by $1 million from additional credits in the third quarter and $3 million in the first nine months of 2005 compared with the same periods of 2004. These revenue reductions are deferred for future recovery under TE’s transition plan and do not affect current period earnings (see Regulatory Matters below).



 
103


Changes in KWH sales by customer class in the three months and nine months ended September 30, 2005 from the corresponding periods of 2004, are summarized in the following table:

 
 
 
Three
 
Nine
 
Changes in KWH Sales
 
Months
 
Months
 
Increase (Decrease)
 
 
 
 
 
Electric Generation:
 
 
 
 
 
Retail
 
 
6.0
%
 
3.9
%
Wholesale
 
 
3.5
%
 
3.4
%
Total Electric Generation Sales
 
 
4.6
%
 
3.7
%
 
 
 
 
 
 
 
 
Distribution Deliveries:
 
 
 
 
 
 
 
Residential
 
 
16.7
%
 
12.0
%
Commercial
 
 
4.7
%
 
6.8
%
Industrial
 
 
4.8
%
 
1.2
%
Total Distribution Deliveries
 
 
7.7
%
 
5.3
%
 
 
 
 
 
 
 
 


Operating Expenses and Taxes

Total operating expenses and taxes decreased $1 million in the third quarter and increased $46 million in the first nine months of 2005 from the same periods in 2004. The following table presents changes from the prior year by expense category.
 
 
 
Three
 
Nine
 
Operating Expenses and Taxes - Changes
 
Months
 
Months
 
Increase (Decrease) 
 
(In millions)
 
Fuel costs
 
$
3
 
$
6
 
Purchased power costs
 
 
(7
 
(11
Nuclear operating costs
 
 
(4
)
 
22
 
Other operating costs
 
 
4
 
 
3
 
Provision for depreciation
 
 
4
 
 
6
 
Amortization of regulatory assets
 
 
(1
)
 
6
 
Deferral of new regulatory assets
 
 
(7
 
(12
General taxes
   
(1
)
 
1
 
Income taxes
 
 
8
 
 
25
 
Net increase (decrease) in operating expenses and taxes
 
$
(1
$
46
 
 
 
 
 
 
 
 
 


Higher fuel costs in the third quarter and first nine months of 2005, compared with the same periods of 2004, resulted primarily from increased fossil-fired generation from the Mansfield Plant, up 5.7% and 7.1% during the respective periods. Purchased power costs decreased in both periods due to lower unit costs and reduced KWH purchases. Nuclear operating costs decreased in the third quarter of 2005 primarily from lower employee benefit costs and operating expenses for the nuclear generating units. Nuclear operating costs increased in the nine-month period due to a scheduled refueling outage (including an unplanned extension) at the Perry Plant, a mid-cycle inspection outage at the Davis-Besse Plant during the first quarter of 2005, and the Beaver Valley Unit 2 refueling outage in the second quarter of 2005, compared to no scheduled outages in the first nine months of 2004. Other operating costs increased in both periods of 2005 compared to the same periods of 2004 primarily because of MISO Day 2 expenses that began on April 1, 2005, partially offset by lower Beaver Valley Unit 2 letter of credit fees, insurance settlements and lower employee benefits costs.

Depreciation charges increased by $4 million in the third quarter and $6 million in first nine months of 2005 compared to the same periods of 2004 primarily due to property additions and reduced amortization periods for expenditures on leased generating plants to conform to the lease terms. These increases were partially offset by the effect of revised service life assumptions for fossil generating plants (See Note 3). Regulatory asset amortization increased in the first nine months of 2005 due to the increased amortization of transition costs being recovered under the RSP. Deferrals of new regulatory assets increased in the third quarter and first nine months of 2005 compared to the same periods of 2004, primarily due to higher shopping incentives and related interest ($2 million and $5 million, respectively) and the deferral of the PUCO-approved MISO administrative expenses and related interest ($5 million and $6 million, respectively). 

On June 30, 2005, the State of Ohio enacted new tax legislation that created a new CAT tax, which is based on qualifying “taxable gross receipts” and will not consider any expenses or costs incurred to generate such receipts, except for items such as cash discounts, returns and allowances, and bad debts. The CAT tax is effective July 1, 2005, and replaces the Ohio income-based franchise tax and the Ohio personal property tax. The CAT tax is phased-in while the current income-based franchise tax is phased-out over a five-year period at a rate of 20% annually, beginning with the year ended 2005, and personal property tax is phased-out over a four-year period at a rate of approximately 25%, annually beginning with the year ended 2005. For example, during the phase-out period the Ohio income-based franchise tax will be computed consistently with the prior tax law, except that the tax liability as computed will be multiplied by 4/5 in 2005; 3/5 in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current income-based franchise tax over a five-year period. As a result of the new tax structure, all net deferred tax benefits that are not expected to reverse during the five-year phase-in period were written-off as of June 30, 2005. The impact on income taxes associated with the required adjustment to net deferred taxes for the nine months ended September 30, 2005 was additional tax expense of $17.5 million, which was partially offset by the phase-out of the Ohio income tax which reduced income taxes by $0.7 million in the third quarter of 2005 and $1.2 million for the nine months ended September 30, 2005. See Note 12 to the consolidated financial statements.
 
104


Other Income

Other income increased by $8 million in the third quarter of 2005 and $3 million in the first nine months of 2005 compared with the same periods of 2004, primarily due to higher nuclear decommissioning trust realized gains, partially offset by lower interest income earned on associated company notes receivable that were repaid in May 2005. Additionally, the recognition of a $1.6 million NRC fine related to the Davis-Besse Plant (see Outlook - Other Legal Proceedings) during the first quarter of 2005 partially offset the increase in other income during the first nine months of 2005.

Net Interest Charges

Net interest charges increased by $2 million in the third quarter of 2005 compared with the same period in 2004, primarily related to higher interest rates charged for money pool borrowings from associated companies in 2005. The average interest rate for borrowings in the third quarter of 2005 was 3.50% versus 1.28% in the same period in 2004. However, net interest charges decreased by $6 million in the first nine months of 2005 compared with the same period of 2004, reflecting redemptions and refinancings since October 1, 2004.

Capital Resources and Liquidity

TE’s cash requirements for the remainder of 2005 for operating expenses and construction expenditures are expected to be met without increasing its net debt and preferred stock outstanding. Thereafter, TE expects to meet its contractual obligations with a combination of cash from operations and funds from the capital markets.

Changes in Cash Position

As of September 30, 2005, TE's cash and cash equivalents of $15,000 remained unchanged from December 31, 2004.

Cash Flows From Operating Activities

Cash provided from operating activities during the third quarter and first nine months of 2005, compared with the corresponding period of 2004 were as follows:

 
 
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
Operating Cash Flows
 
2005
 
2004
 
2005
 
2004
 
 
 
(In millions)
 
 
 
 
 
 
 
 
 
 
 
Cash earnings(1)
 
$
84
 
$
77
 
$
140
 
$
152
 
Pension trust contribution(2)
   
--
   
(8
)
 
--
   
(8
)
Working capital and other
 
 
--
 
 
55
 
 
(27
 
71
 
Total cash flows from operating activities
 
$
84
 
$
124
 
$
113
 
$
215
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) Cash earnings are a non-GAAP measure (see reconciliation below).
   
(2) Pension trust contribution net of $5 million of income tax benefits.
 
 
 
 
Cash earnings, as disclosed in the table above, are not a measure of performance calculated in accordance with GAAP. TE believes that cash earnings is a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income.

 
105


 

 
 
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
Reconciliation of Cash Earnings
 
2005
 
2004
 
2005
 
2004
 
 
 
(In millions)
 
 
 
 
 
 
 
 
 
 
 
Net income (GAAP)
 
$
42
 
$
24
 
$
50
 
$
54
 
Non-cash charges (credits):
 
 
 
 
 
 
 
 
 
 
 
 
 
Provision for depreciation
 
 
19
 
 
15
 
 
49
 
 
43
 
Amortization of regulatory assets
 
 
40
 
 
41
 
 
108
 
 
102
 
Deferral of new regulatory assets
   
(20
)
 
(12
)
 
(42
)
 
(30
)
Nuclear fuel and capital lease amortization
 
 
6
 
 
7
 
 
14
 
 
18
 
Amortization of electric service obligation
 
 
(2
 
--
 
 
(3
 
-
 
Deferred rents and above-market lease liability
 
 
10
 
 
10
 
 
(34
)
 
(27
Deferred income taxes and investment tax credits, net
   
(13
)
 
(8
)
 
(5
)
 
(14
)
Accrued retirement benefits obligations
 
 
2
 
 
1
 
 
4
 
 
5
 
Accrued compensation, net
 
 
-
 
 
(1
 
(1
 
1
 
Cash earnings (Non-GAAP)
 
$
84
 
$
77
 
$
140
 
$
152
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

Net cash provided from operating activities decreased by $40 million in the third quarter of 2005 from the third quarter of 2004 as a result of a $55 million decrease from working capital, partially offset by a $7 million increase in cash earnings as described above and under “Results of Operations” and the absence of an $8 million after-tax voluntary pension trust contribution made in the third quarter of 2004. Net cash provided from operating activities decreased by $102 million in the first nine months of 2005 compared to the same period last year as a result of a $98 million change in working capital and a $12 million decrease in cash earnings as described above and under “Results of Operations,” partially offset by the absence of an $8 million after-tax voluntary pension trust contribution made in 2004. The change in working capital for both periods was primarily due to changes in accounts payable, accrued taxes and receivables, partially offset in the nine-month period of 2005 by funds received for prepaid electric service under the Ohio Schools Council’s Energy for Education Program that began in the second quarter of 2005.

Cash Flows From Financing Activities

Net cash used for financing activities decreased by $48 million and increased by $1 million in the third quarter and first nine months of 2005, respectively, as compared to the same periods of 2004. The activities in both periods reflect an increase in net debt redemptions and preferred stock redemptions. The increase in the nine-month period of 2005 also included a $10 million increase in common stock dividends to FirstEnergy.

On July 1, 2005, TE redeemed all of its 1,200,000 outstanding shares of 7.00% Series A preferred stock at $25.00 per share, plus accrued dividends to the date of redemption. TE also repurchased $37 million of pollution control revenue bonds on September 1, 2005, with the intent to remarket them by the end of the first quarter of 2006.

TE had $53 million of cash and temporary investments (which included short-term notes receivable from associated companies) and $378 million of short-term indebtedness as of September 30, 2005. TE has authorization from the PUCO to incur short-term debt of up to $500 million (including the utility money pool described below). As of October 24, 2005, TE had the capability to issue $1.0 billion of additional FMB on the basis of property additions and retired bonds under the terms of its mortgage indenture following the recently completed intra-system transfer of fossil generating plants (See Note 17). Based upon applicable earnings coverage tests, TE could issue up to $1.15 billion of preferred stock (assuming no additional debt was issued) as of September 30, 2005. It is estimated that the annualized impact of the intra-system transfer of fossil generating plants will reduce the capability of TE to issue preferred stock by approximately $16 million.

On June 14, 2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, entered into a syndicated $2 billion five-year revolving credit facility. Borrowings under the facility are available to each Borrower separately and will mature on the earlier of 364 days from the date of borrowing and the commitment termination date, as the same may be extended. TE's borrowing limit under the facility is $250 million.

TE has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the third quarter of 2005 was 3.50%.
 
 
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TE’s access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of FirstEnergy.

On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in their outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemming from the application of free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.

On October 3, 2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to 'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one notch above the previous rating. S&P noted that the upgrade followed the continuation of a good operating track record, specifically for the nuclear fleet through the third quarter 2005. S&P also stated that FirstEnergy’s rating reflects the benefits of supportive regulation, low-cost base load generation fleet, low-risk transmission and distribution operations and rate certainty in Ohio. FirstEnergy’s ability to consistently generate free cash flow, good liquidity, and an improving financial profile were also noted as strengths.

Cash Flows From Investing Activities

Net cash used for investing activities increased by $9 million in the third quarter of 2005 compared with from the same period of 2004. Net cash provided from investing activities increased by $105 million in the first nine months of 2005, from the same period of 2004. These increases were primarily due to changes from loan activity with associated companies during the periods, partially offset by increased property additions in the nine-month period.

In the last quarter of 2005, TE’s capital spending is expected to be about $25 million. These cash requirements are expected to be satisfied from internal cash and short-term borrowings. TE’s capital spending for the period 2005-2007 is expected to be about $192 million, of which approximately $64 million applies to 2005.

FirstEnergy Intra-System Generation Asset Transfers
 
On May 18, 2005, OE, CEI and TE, entered into certain agreements implementing a series of intra-system generation asset transfers. When fully completed, the asset transfers will result in the respective undivided ownership interests of the Ohio Companies in FirstEnergy’s nuclear and non-nuclear plants being owned by NGC and FGCO, respectively. The generating plant interests that are being transferred do not include TE’s leasehold interests in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates.

On October 24, 2005, TE completed the transfer of non-nuclear generation assets to FGCO. TE currently expects to complete the transfer of nuclear generation assets to NGC at book value before the end of 2005. Consummation of the nuclear transfer remains subject to necessary regulatory approvals.

These transactions are being undertaken in connection with the Ohio Companies’ restructuring plans that were approved by the PUCO under applicable Ohio electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. FENOC currently operates and maintains the nuclear generation assets to be transferred. FGCO, as lessee under a Master Facility Lease, leased, operated and maintained the non-nuclear generation assets that it now owns. The transactions will essentially complete the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO, respectively, without impacting the operation of the plants.

See Note 17 to the consolidated financial statements for TE’s disclosure of the assets held for sale as of September 30, 2005.

Off-Balance Sheet Arrangements

Obligations not included on TE’s Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant and Beaver Valley Unit 2. As of September 30, 2005, the present value of these operating lease commitments, net of trust investments, totaled $541 million.

TE sells substantially all of its retail customer receivables to CFC, a wholly owned subsidiary of CEI. As of June 16, 2005, the CFC receivables financing structure was renewed and restructured from an off-balance sheet transaction to an on-balance sheet transaction. Under the new structure, any borrowings under the facility appear on the balance sheet as short-term debt.


 
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Equity Price Risk

Included in TE’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $217 million and $188 million as of September 30, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $22 million reduction in fair value as of September 30, 2005. Changes in the fair value of these investments are recorded in OCI unless recognized as a result of sales.

Outlook

        The electric industry continues to transition to a more competitive environment and all of TE's customers can select alternative energy suppliers. TE continues to deliver power to residential homes and businesses through its existing distribution system, which remains regulated. Customer rates have been restructured into separate components to support customer choice. TE has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits.

Regulatory Matters

In 2001, Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of TE's customers elects to obtain power from an alternative supplier, TE reduces the customer's bill with a "generation shopping credit," based on the generation component plus an incentive, and the customer receives a generation charge from the alternative supplier. TE has continuing PLR responsibility to its franchise customers through December 31, 2008 unless the PUCO accepts future competitive bid results prior to the end of that period under the revised RSP.

As part of TE's transition plan, it is obligated to supply electricity to customers who do not choose an alternative supplier. TE is also required to provide 160 MW of low cost supply (MSG) to unaffiliated alternative suppliers who serve customers within its service area. FES acts as an alternate supplier for a portion of the load in TE's franchise area.

On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a competitive bid process. The RSP was filed by the Ohio Companies to establish generation service rates beginning January 1, 2006, in response to PUCO concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. In October 2004, the OCC and NOAC filed appeals with the Supreme Court of Ohio to overturn the original June 9, 2004 PUCO order in this proceeding as well as the associated entries on rehearing. On September 28, 2005, the Ohio Supreme Court heard oral argument on the appeals.

On May 27, 2005, TE filed an application with the PUCO to establish a GCAF rider under its RSP. The application seeks to implement recovery of increased fuel costs from 2006 through 2008 applicable to TE’s retail customers through a tariff rider to be implemented January 1, 2006. The application reflects projected increases in fuel costs in 2006 compared to 2002 baseline costs. The new rider, after adjustments made in testimony, is seeking to recover all costs above the baseline (approximately $88 million in 2006 for all the Ohio Companies). Various parties including the OCC have intervened in this case and the case has been consolidated with the RCP application discussed below.

On September 9, 2005, TE filed an application with the PUCO that, if approved, would supplement its existing RSP with an RCP. On September 27, 2005, the PUCO granted FirstEnergy's motion to consolidate the GCAF rider application with the RCP proceedings and set hearings for the consolidated cases to begin November 29, 2005. The RCP is designed to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. Major provisions of the RCP include:

·  
    Maintain the existing level of base distribution rates through December 31, 2008 for TE;

·  
    Defer and capitalize certain distribution costs to be incurred by all of the Ohio Companies during the
    period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the three
    years;

·  
    Adjust the RTC and extended RTC recovery periods and rate levels so that full recovery of authorized
    costs will occur as of December 31, 2008 for TE;

·  
    Reduce the deferred shopping incentive balances as of January 1, 2006 by up to $45 million for TE
    by accelerating the application of its accumulated cost of removal regulatory liability; and

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·  
    Recover increased fuel costs of up to $75 million, $77 million, and $79 million, in 2006, 2007, and
    2008, respectively, from all OE and TE distribution and transmission customers through a fuel
    recovery mechanism. TE may defer and capitalize increased fuel costs above the amount collected
    through the fuel recovery mechanism.

Under provisions of the RSP, the PUCO may require TE to undertake, no more often than annually, a competitive bid process to secure generation for the years 2007 and 2008. On July 22, 2005, FirstEnergy filed a competitive bid process for the period beginning in 2007 that is similar to the competitive bid process approved by the PUCO for TE in 2004, which resulted in the PUCO accepting no bids. Any acceptance of future competitive bid results would terminate the RSP pricing, with no accounting impacts to the RSP, and not until twelve months after the PUCO authorizes such termination. On September 28, 2005, the PUCO issued an Entry that essentially approved the Ohio Companies’ filing but delayed the proposed timing of the competitive bid process by four months, calling for the auction to be held on March 21, 2006.

On December 30, 2004, TE filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application seeks recovery of these costs beginning January 1, 2006. At the time of filing the application, these costs were estimated to be approximately $0.1 million per year; however, TE anticipates that this amount will increase. TE requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted each July 1 thereafter. TE reached a settlement with OCC, PUCO staff, Industrial Energy Users - Ohio and OPAE. The only other party in this proceeding, Dominion Retail, Inc., agreed not to oppose the settlement. This settlement, which was filed with the PUCO on July 22, 2005, provides for the rider recovery requested by TE, with carrying charges applied in the subsequent year’s rider for any over or under collection while the then-current rider is in effect. The PUCO approved the settlement stipulation on August 31, 2005. The incremental Transmission and Ancillary service revenues expected to be recovered from January through June 2006 are approximately $6.7 million. This value includes the recovery of the 2005 deferred MISO expenses as described below. In May 2006, TE will file a modification to the rider which will determine revenues from July 2006 through June 2007.

The second application seeks authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for TE to defer incremental transmission and ancillary service-related charges incurred as a participant in the MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Permission to defer costs incurred prior to December 31, 2004 was denied. The PUCO also authorized TE to accrue carrying charges on the deferred balances. An application filed with the PUCO to recover these deferred charges over a five-year period through the rider, beginning in 2006, was approved in a PUCO order issued on August 31, 2005. The OCC, OPAE and TE each filed applications for rehearing. TE sought authority to defer the transmission and ancillary service related costs incurred during the period October 1, 2003 through December 29, 2004, while both OCC and OPAE sought to have the PUCO deny deferral of all costs. On July 6, 2005, the PUCO denied TE's and OCC’s applications and, at the request of TE, struck as untimely OPAE’s application. The OCC filed a notice of appeal with the Ohio Supreme Court on August 31, 2005. On September 30, 2005, in accordance with appellate procedure, the PUCO filed with the Ohio Supreme Court the record in this case. The Companies' brief will be due thirty days after the OCC files its brief, which, absent any time extensions, must be filed no later than November 9, 2005.

TE records as regulatory assets costs which have been authorized by the PUCO and the FERC for recovery from customers in future periods and, without such authorization, the costs would have been charged to income when incurred. TE's regulatory assets as of September 30, 2005 and December 31, 2004, were $310 million and $375 million, respectively. TE is deferring customer shopping incentives and interest costs as new regulatory assets in accordance with its transition and rate stabilization plans. These regulatory assets total $122 million as of September 30, 2005 and, under the RSP, will be recovered through a surcharge rate equal to the RTC rate in effect when the transition costs have been fully recovered. See Note 14 “Regulatory Matters - Ohio” for the estimated net amortization of regulatory transition costs and deferred shopping incentive balances under the proposed RCP and current RSP.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio.

Environmental Matters

TE accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in TE's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

FirstEnergy plans to issue a report regarding its response to air emission requirements. FirstEnergy expects to complete the report by December 1, 2005.
 
 
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National Ambient Air Quality Standards
 
In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR provides each affected state until 2006 to develop implementing regulation to achieve additional reductions of NOx and SO2 emissions in two phases (Phase I in 2009 for NOx, 2010 for SO2 and Phase II in 2015 for both NOx and SO2) in all cases from the 2003 levels. TE's Ohio and Pennsylvania fossil-fired generation facilities will be subject to the caps on SO2 and NOx emissions. According to the EPA, SO2 emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO2 emissions in affected states to just 2.5 million tons annually. NOx emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NOx cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which TE operates affected facilities.

Mercury Emissions
 
In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On March 14, 2005, the EPA finalized the “Clean Air Mercury Rule,” which provides for a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases. Initially, mercury emissions will be capped nationally at 38 tons by 2010 as a "co-benefit" from implementation of SO2 and NOx emission caps under the EPA's CAIR program. Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. However, the final rules give states substantial discretion in developing rules to implement these programs. In addition, both the CAIR and the Clean Air Mercury rule have been challenged in the United States Court of Appeals for the District of Columbia. Future cost of compliance with these regulations may be substantial.

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global warming by reducing the amount of man-made GHG emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Protocol in 1998 but it failed to receive the two-thirds vote of the United States Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity - the ratio of emissions to economic output - by 18 percent through 2012. The Energy Policy Act of 2005 established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

TE cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO2 emissions could require significant capital and other expenditures. However, the CO2 emissions per KWH of electricity generated by TE is lower than many regional competitors due to TE's diversified generation sources which include low or non-CO2 emitting gas-fired and nuclear generators.

Regulation of Hazardous Waste
 
TE has been named a PRP at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of September 30, 2005, based on estimates of the total costs of cleanup, TE's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. Included in Other Noncurrent Liabilities are accrued liabilities aggregating approximately $0.2 million as of September 30, 2005.

See Note 13(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

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Other Legal Proceedings

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to TE's normal business operations pending against TE and its subsidiaries. The other material items not otherwise discussed above are described below.

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concludes, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades, to existing equipment, and therefore FirstEnergy has not accrued a liability as of September 30, 2005 for any expenditures in excess of those actually incurred through that date. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

FirstEnergy companies also are defending six separate complaint cases before the PUCO relating to the August 14, 2003 power outage. Two such cases were originally filed in Ohio State courts but subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In both such cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Of the four other pending PUCO complaint cases, three were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each such case, the carriers seek reimbursement against various FirstEnergy companies (and, in one case, against PJM, MISO and American Electric Power Co. as well) for claims they paid to their insureds allegedly due to the loss of power on August 14, 2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy company. The fourth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. In addition to these six cases, the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages. No estimate of potential liability has been undertaken for any of these cases.

One complaint was filed on August 25, 2004 against FirstEnergy in the New York State Supreme Court. In this case, several plaintiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. FirstEnergy's motion to dismiss the case was granted on September 26, 2005. Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter is not due until on or about December 1, 2005. No estimate of potential liability has been undertaken in this matter.

FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. In particular, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.
 
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FENOC received a subpoena in late 2003 from a grand jury sitting in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at the Davis-Besse Nuclear Power Station, in which TE has a 48.62% interest. On December 10, 2004, FirstEnergy received a letter from the United States Attorney's Office stating that FENOC is a target of the federal grand jury investigation into alleged false statements made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01. The letter also said that the designation of FENOC as a target indicates that, in the view of the prosecutors assigned to the matter, it is likely that federal charges will be returned against FENOC by the grand jury. On February 10, 2005, FENOC received an additional subpoena for documents related to root cause reports regarding reactor head degradation and the assessment of reactor head management issues at Davis-Besse. On May 11, 2005, FENOC received a subpoena for documents related to outside meetings attended by Davis-Besse personnel on corrosion and cracking of control rod drive mechanisms and additional root cause evaluations.

On April 21, 2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to the degradation of the Davis-Besse reactor vessel head issue described above. TE accrued $1.0 million for a potential fine prior to 2005 and accrued the remaining liability for its share of the proposed fine of $1.65 million during the first quarter of 2005. On September 14, 2005, FENOC filed its response to the NOV with the NRC. FENOC accepted full responsibility for the past failure to properly implement its boric acid corrosion control and corrective action programs. The NRC NOV indicated that the violations do not represent current licensee performance. FirstEnergy paid the penalty in the third quarter of 2005.

If it were ultimately determined that FirstEnergy or its subsidiaries has legal liability based on events surrounding Davis-Besse, it could have a material adverse effect on FirstEnergy's or any of its subsidiaries' financial condition, results of operations and cash flows.

Effective July 1, 2005 the NRC oversight panel for Davis-Besse was terminated and Davis-Besse returned to the standard NRC reactor oversight process. At that time, NRC inspections were augmented to include inspections to support the NRC's Confirmatory Order dated March 8, 2004 that was issued at the time of startup and to address an NRC White Finding related to the performance of the emergency sirens.

On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the preceding two years and the licensee's failure to take prompt and effective corrective action. FENOC operates the Perry Nuclear Power Plant, in which TE has a 19.91% interest (however, see Note 17 regarding FirstEnergy’s pending intra-system generation asset transfers, which include owned portions of the plant).

On April 4, 2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Plant operated "in a manner that preserved public health and safety" even though it remained under heightened NRC oversight. During the public meeting and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix.

On May 26, 2005, the NRC held a public meeting to discuss its oversight of the Perry Plant. While the NRC stated that the plant continued to operate safely, the NRC also stated that the overall performance had not substantially improved since the heightened inspection was initiated. The NRC reiterated this conclusion in its mid-year assessment letter dated August 30, 2005. On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance of Perry and stated that the CAL would remain open until substantial improvement was demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight Process. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process from increased oversight to possible impact to the plant’s operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and TE, and the Davis-Besse extended outage, have become the subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. On August 24, 2005, additional information was requested regarding Davis-Besse. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.
 
 
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The City of Huron filed a complaint against OE with the PUCO challenging the ability of electric distribution utilities to collect transition charges from a customer of a newly formed municipal electric utility. The complaint was filed on May 28, 2003, and OE timely filed its response on June 30, 2003. In a related filing, the Ohio Companies filed for approval with the PUCO of a tariff that would specifically allow the collection of transition charges from customers of municipal electric utilities formed after 1998. An adverse ruling could negatively affect full recovery of transition charges by TE. Hearings on the matter were held in August 2005. Initial briefs from all parties were filed on September 22, 2005 and reply briefs were filed on October 14, 2005. It is unknown when the PUCO will rule on this case.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

See Note 13(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

New Accounting Standards and Interpretations

EITF Issue 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty"
 
In September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus that an exchange of inventory should be accounted for at fair value. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and other storable inventory. Therefore, TE will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006.

 
EITF Issue No. 05-6, "Determining the Amortization Period for Leasehold Improvements Purchased after Lease Inception or Acquired in a Business Combination"
 
In June 2005, the EITF reached a consensus on the application guidance for Issue 05-6. EITF 05-6 addresses the amortization period for leasehold improvements that were either acquired in a business combination or placed in service significantly after and not contemplated at or near the beginning of the initial lease term. For leasehold improvements acquired in a business combination, the amortization period is the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date of acquisition. Leasehold improvements that are placed in service significantly after and not contemplated at or near the beginning of the lease term should be amortized over the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date the leasehold improvements are purchased. This EITF was effective July 1, 2005 and is consistent with TE’s current accounting.

FIN 47, “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”
 
On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective for TE in the fourth quarter of 2005. TE is currently evaluating the effect this Interpretation will have on its financial statements.

 
SFAS 154 - “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3”

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in the Consolidated Statements of Income. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. TE will adopt this Statement effective January 1, 2006.
 
 
113


 
SFAS 153, “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29”

In December 2004, the FASB issued SFAS 153 amending APB 29, which was based on the principle that nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB 29 included certain exceptions to that principle. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement are effective January 1, 2006 for TE. This FSP is not expected to have a material impact on TE’s financial statements.

SFAS 151, “Inventory Costs - an amendment of ARB No. 43, Chapter 4”

In November 2004, the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Previous guidance stated that in some circumstances these costs may be “so abnormal” that they would require treatment as current period costs. SFAS 151 requires abnormal amounts for these items to always be recorded as current period costs. In addition, this Statement requires that allocation of fixed production overheads to the cost of conversion be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred by TE beginning January 1, 2006. TE is currently evaluating this Standard and does not expect it to have a material impact on its financial statements.

FSP FAS 115-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

In September 2005, the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP FAS 115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition of Other Than Temporary Impairment upon the Planned Sale of a Security Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when the impairment is deemed other than temporary, even if a decision to sell has not been made, and (3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after September 15, 2005. The FASB expects to issue this FSP in the fourth quarter of 2005, which would require prospective application with an effective date for reporting periods beginning after December 15, 2005. TE is currently evaluating this FSP and any impact on its investments.



114



PENNSYLVANIA POWER COMPANY
 
                   
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
 
(Unaudited)
 
                   
   
Three Months Ended
 
Nine Months Ended
 
   
September 30,
 
September 30,
 
   
2005
 
2004
 
2005
 
2004
 
   
(In thousands)
 
STATEMENTS OF INCOME
                 
                   
OPERATING REVENUES
 
$
145,540
 
$
143,340
 
$
414,306
 
$
420,578
 
                           
OPERATING EXPENSES AND TAXES:
                         
Fuel
   
6,205
   
6,347
   
17,351
   
18,408
 
Purchased power
   
42,242
   
44,096
   
131,948
   
136,699
 
Nuclear operating costs
   
16,997
   
19,934
   
56,710
   
55,737
 
Other operating costs
   
19,030
   
16,212
   
48,541
   
45,371
 
Provision for depreciation
   
3,847
   
3,556
   
11,351
   
10,390
 
Amortization of regulatory assets
   
9,784
   
9,979
   
29,499
   
30,082
 
General taxes
   
6,836
   
6,416
   
19,752
   
17,538
 
Income taxes
   
17,402
   
16,541
   
43,055
   
46,425
 
Total operating expenses and taxes 
   
122,343
   
123,081
   
358,207
   
360,650
 
                           
OPERATING INCOME
   
23,197
   
20,259
   
56,099
   
59,928
 
                           
OTHER INCOME (net of income taxes)
   
549
   
745
   
623
   
2,287
 
                           
NET INTEREST CHARGES:
                         
Interest expense
   
2,371
   
1,911
   
7,477
   
7,434
 
Allowance for borrowed funds used during construction
   
(1,665
)
 
(1,271
)
 
(4,508
)
 
(3,197
)
Net interest charges 
   
706
   
640
   
2,969
   
4,237
 
                           
NET INCOME
   
23,040
   
20,364
   
53,753
   
57,978
 
                           
PREFERRED STOCK DIVIDEND REQUIREMENTS
   
156
   
639
   
1,534
   
1,919
 
                           
EARNINGS ON COMMON STOCK
 
$
22,884
 
$
19,725
 
$
52,219
 
$
56,059
 
                           
STATEMENTS OF COMPREHENSIVE INCOME
                         
                           
NET INCOME
 
$
23,040
 
$
20,364
 
$
53,753
 
$
57,978
 
                           
OTHER COMPREHENSIVE INCOME
   
-
   
-
   
-
   
-
 
                           
TOTAL COMPREHENSIVE INCOME
 
$
23,040
 
$
20,364
 
$
53,753
 
$
57,978
 
                           
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral part of these statements.
   
 
                         
 
 
 
115


PENNSYLVANIA POWER COMPANY
 
           
CONSOLIDATED BALANCE SHEETS
 
(Unaudited)
 
   
September 30,
 
December 31,
 
   
2005
 
2004
 
   
(In thousands)  
 
ASSETS
         
UTILITY PLANT:
         
In service
 
$
907,382
 
$
866,303
 
Less - Accumulated provision for depreciation
   
378,707
   
356,020
 
     
528,675
   
510,283
 
Construction work in progress -
             
Electric plant
   
133,790
   
104,366
 
Nuclear fuel
   
10,428
   
3,362
 
     
144,218
   
107,728
 
     
672,893
   
618,011
 
OTHER PROPERTY AND INVESTMENTS:
             
Nuclear plant decommissioning trusts
   
146,706
   
143,062
 
Long-term notes receivable from associated companies
   
32,864
   
32,985
 
Other
   
502
   
722
 
     
180,072
   
176,769
 
CURRENT ASSETS:
             
Cash and cash equivalents
   
24
   
38
 
Notes receivable from associated companies
   
566
   
431
 
Receivables -
             
Customers (less accumulated provisions of $1,066,000 and $888,000,
             
respectively, for uncollectible accounts) 
   
44,990
   
44,282
 
Associated companies
   
6,206
   
23,016
 
Other
   
2,617
   
1,656
 
Materials and supplies, at average cost
   
37,974
   
37,923
 
Prepayments and other
   
12,110
   
8,924
 
     
104,487
   
116,270
 
               
DEFERRED CHARGES
   
10,721
   
10,106
 
   
$
968,173
 
$
921,156
 
CAPITALIZATION AND LIABILITIES
             
CAPITALIZATION:
             
Common stockholder's equity -
             
Common stock, $30 par value, authorized 6,500,000 shares -
             
6,290,000 shares outstanding 
 
$
188,700
 
$
188,700
 
Other paid-in capital
   
65,035
   
64,690
 
Accumulated other comprehensive loss
   
(13,706
)
 
(13,706
)
Retained earnings
   
131,914
   
87,695
 
Total common stockholder's equity 
   
371,943
   
327,379
 
Preferred stock
   
14,105
   
39,105
 
Long-term debt and other long-term obligations
   
121,170
   
133,887
 
     
507,218
   
500,371
 
CURRENT LIABILITIES:
             
Currently payable long-term debt
   
25,774
   
26,524
 
Short-term borrowings -
             
Associated companies
   
34,821
   
11,852
 
Accounts payable -
             
Associated companies
   
16,864
   
46,368
 
Other
   
1,884
   
1,436
 
Accrued taxes
   
26,163
   
14,055
 
Accrued interest
   
1,635
   
1,872
 
Other
   
8,491
   
8,802
 
     
115,632
   
110,909
 
NONCURRENT LIABILITIES:
             
Accumulated deferred income taxes
   
79,801
   
93,418
 
Asset retirement obligation
   
155,959
   
138,284
 
Retirement benefits
   
51,389
   
49,834
 
Regulatory liabilities
   
47,809
   
18,454
 
Other
   
10,365
   
9,886
 
     
345,323
   
309,876
 
COMMITMENTS AND CONTINGENCIES (Note 13)
             
   
$
968,173
 
$
921,156
 
               
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral part of these balance sheets.
   
 
             
 
 
 
116

 

PENNSYLVANIA POWER COMPANY
 
                   
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(Unaudited)
 
                   
   
Three Months Ended
 
Nine Months Ended
 
   
September 30,
 
September 30,
 
   
2005
 
2004
 
2005
 
2004
 
   
(In thousands)
 
                   
CASH FLOWS FROM OPERATING ACTIVITIES:
                 
Net income
 
$
23,040
 
$
20,364
 
$
53,753
 
$
57,978
 
Adjustments to reconcile net income to net cash from
                         
operating activities -
                         
 Provision for depreciation 
   
3,847
   
3,556
   
11,351
   
10,390
 
 Amortization of regulatory assets 
   
9,784
   
9,979
   
29,499
   
30,082
 
 Nuclear fuel and other amortization 
   
4,634
   
4,550
   
12,912
   
13,546
 
 Deferred income taxes and investment tax credits, net 
   
(2,612
)
 
(501
)
 
(7,567
)
 
(2,852
)
 Pension trust contribution 
   
-
   
(12,934
)
 
-
   
(12,934
)
 Decrease (increase) in operating assets - 
                         
    Receivables
   
4,303
   
(30,285
)
 
15,141
   
(10,551
)
    Materials and supplies
   
755
   
(1,078
)
 
(51
)
 
(3,374
)
    Prepayments and other current assets
   
5,074
   
4,164
   
(3,186
)
 
(3,977
)
Increase (decrease) in operating liabilities - 
                         
    Accounts payable
   
(9,161
)
 
40,306
   
(29,056
)
 
21,678
 
    Accrued taxes
   
5
   
(2,485
)
 
12,108
   
2,301
 
    Accrued interest
   
(353
)
 
(986
)
 
(237
)
 
(2,415
)
Other 
   
564
   
1,353
   
1,027
   
5,294
 
    Net cash provided from operating activities
   
39,880
   
36,003
   
95,694
   
105,166
 
                           
CASH FLOWS FROM FINANCING ACTIVITIES:
                         
New Financing -
                         
Short-term borrowings, net 
   
-
   
-
   
22,969
   
10,789
 
Equity contribution from parent 
   
-
   
25,000
   
-
   
25,000
 
Redemptions and Repayments -
                         
Preferred stock 
   
-
   
-
   
(37,750
)
 
-
 
Long-term debt 
   
(39
)
 
(20,508
)
 
(849
)
 
(63,297
)
Short-term borrowings, net 
   
(10,776
)
 
(11,414
)
 
-
   
-
 
Dividend Payments -
                         
Common stock 
   
-
   
-
   
(8,000
)
 
(23,000
)
Preferred stock 
   
(156
)
 
(639
)
 
(1,534
)
 
(1,919
)
    Net cash used for financing activities
   
(10,971
)
 
(7,561
)
 
(25,164
)
 
(52,427
)
                           
CASH FLOWS FROM INVESTING ACTIVITIES:
                         
Property additions
   
(28,537
)
 
(24,670
)
 
(69,630
)
 
(56,080
)
Contributions to nuclear decommissioning trusts
   
(399
)
 
(399
)
 
(1,196
)
 
(1,196
)
Loan repayments from (loans to) associated companies
   
(187
)
 
(36
)
 
(14
)
 
5,975
 
Other
   
214
   
(3,337
)
 
296
   
(1,440
)
   Net cash used for investing activities
   
(28,909
)
 
(28,442
)
 
(70,544
)
 
(52,741
)
                           
Net change in cash and cash equivalents
   
-
   
-
   
(14
)
 
(2
)
Cash and cash equivalents at beginning of period
   
24
   
38
   
38
   
40
 
Cash and cash equivalents at end of period
 
$
24
 
$
38
 
$
24
 
$
38
 
 
                         
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral part of these statements.
   
 
                         
 
 
117

 

Report of Independent Registered Public Accounting Firm









To the Stockholders and Board of
Directors of Pennsylvania Power Company:

We have reviewed the accompanying consolidated balance sheet of Pennsylvania Power Company and its subsidiary as of September 30, 2005, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and nine-month periods ended September 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2004, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 2(G) to those consolidated financial statements) dated March 7, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.




PricewaterhouseCoopers LLP
Cleveland, Ohio
November 1, 2005


 
118

 

PENNSYLVANIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION

 
Penn is a wholly owned, electric utility subsidiary of OE. Penn conducts business in western Pennsylvania, providing regulated electric distribution services. Penn also provides generation services to those customers electing to retain Penn as their power supplier. Penn provides power directly to wholesale customers under previously negotiated contracts. Penn has unbundled the price of electricity into its component elements - including generation, transmission, distribution and transition charges. Its power supply requirements are provided by FES - an affiliated company.

Results of Operations

Earnings on common stock in the third quarter of 2005 increased to $23 million from $20 million in the third quarter of 2004. The increased earnings resulted primarily from higher operating revenues and lower operating expenses and taxes. Earnings on common stock for the first nine months of 2005 decreased to $52 million from $56 million for the same period of 2004. The lower earnings resulted primarily from a decrease in operating revenues and other income, partially offset by lower operating expenses and taxes and lower net interest charges.

Operating revenues increased by $2 million, or 1.5%, in the third quarter of 2005 compared with the third quarter of 2004. Higher revenues in the third quarter of 2005 primarily resulted from increased retail generation sales revenues of $6 million and a $2 million increase in rental revenues, partially offset by a $6 million decrease in wholesale sales to FES. Retail generation sales increased as a result of increased KWH sales to residential (7.6%) and commercial (4.0%) customers, due to warmer weather in Penn's service area, and a 19.8% KWH sales increase to industrial customers, primarily within the steel sector.

Revenues from distribution deliveries in the third quarter of 2005 increased slightly from the third quarter of 2004, as lower unit prices partially offset a 10.2% increase in KWH sales. The lower unit prices were primarily attributable to changes in Penn's CTC rate schedules in April 2005 as a result of the annual CTC reconciliation. Increased revenues from distribution deliveries to residential ($0.3 million) and industrial ($0.8 million) customers were offset by a $1 million decrease in revenues from commercial customers.

Operating revenues decreased by $6 million in the first nine months of 2005 compared with the same period of 2004. The lower operating revenues reflected a $24 million decrease in wholesale sales to FES, partially offset by higher retail sales of $14 million. Higher retail electric generation revenues of $14 million resulted from increased KWH sales to all sectors (Residential - 8.0%, Commercial - 5.6% and Industrial - 1.5%) and higher unit prices for commercial and industrial customers.
 
In the first nine months of 2005, revenues from distribution deliveries increased by $0.3 million compared to the same period of 2004. An increase in total KWH deliveries of 5.0% was offset by lower unit prices, reflecting the changes in Penn's CTC rates discussed above. Increased revenues from distribution deliveries to residential customers of $4 million were partially offset by lower revenues from commercial ($1 million) and industrial ($2 million) customers.

Changes in kilowatt-hour sales by customer class in the three months and nine months ended September 30, 2005 from the corresponding periods of 2004 are summarized in the following table:


 
 
Three
 
Nine
 
Changes in KWH Sales
 
Months
 
Months
 
Increase (Decrease)
 
 
 
 
 
Electric Generation:
 
 
 
 
 
Retail
 
 
10.2
%
 
5.0
%
Wholesale
 
 
(1.4
)%
 
(5.5
)%
Total Electric Generation Sales
 
 
3.1
%
 
(1.4
)%
 
 
 
 
 
 
 
 
Distribution Deliveries:
 
 
 
 
 
 
 
Residential
 
 
7.6
%
 
8.0
%
Commercial
 
 
4.0
%
 
5.6
%
Industrial
 
 
19.8
%
 
1.5
%
Total Distribution Deliveries
 
 
10.2
%
 
5.0
%
 
 
 
 
 
 
 
 


 
119


Operating Expenses and Taxes
 
Total operating expenses and taxes decreased by $1 million in the third quarter and $2 million in the first nine months of 2005 from the same periods of 2004. The following table presents changes from the prior year by expense category.

 
 
Three
 
Nine
 
Operating Expenses and Taxes - Changes
 
Months
 
Months
 
 
 
(In millions)
 
Increase (Decrease)
 
 
 
 
 
Fuel costs
 
$
-
 
$
(1
)
Purchased power costs
 
 
(2
)
 
(4
)
Nuclear operating costs
 
 
(3
 
1
 
Other operating costs
 
 
3
 
 
3
 
General taxes
 
 
-
 
 
2
 
Income taxes
 
 
1
 
 
(3
)
Net decrease in operating expenses and taxes
 
$
(1
$
(2
)
 
 
 
 
 
 
 
 
 

The decrease in purchased power costs in the three months and nine months ended September 30, 2005 resulted from lower unit prices for power. Nuclear operating costs were lower in the third quarter of 2005, reflecting a decrease in labor and postretirement benefit expenses from the third quarter of 2004. Other operating costs were higher in the three months and nine months ended September 30, 2005 as the result of increased transmission related expenses associated with MISO's energy market that began on April 1, 2005.

Other Income

Other income (net of income taxes) decreased slightly in the third quarter and by $2 million in the first nine months of 2005, compared with the same periods in 2004. The decrease in the nine month period reflects liabilities recognized in the first quarter of 2005 related to the W. H. Sammis Plant settlement (see Outlook - Environmental Matters).

Net Interest Charges

Net interest charges decreased by $1 million in the nine months ended September 30, 2005 from the corresponding period last year, reflecting redemptions of $40 million principal amount of debt securities since October 1, 2004.

Capital Resources and Liquidity

Penn’s cash requirements for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met with a combination of cash from operations and funds from the capital markets. Borrowing capacity under credit facilities is available to manage working capital requirements.

Changes in Cash Position

As of September 30, 2005, Penn had $24,000 of cash and cash equivalents, compared with $38,000 as of December 31, 2004. The major changes in these balances are summarized below.

Cash Flows From Operating Activities

Net cash provided from operating activities in the three months and nine months ended September 30, 2005, compared with the corresponding 2004 periods, was as follows:
 

 
 
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
 Operating Cash Flows
 
2005
 
2004
 
2005
 
2004
 
 
 
(In millions)
 
 
 
 
 
 
 
 
 
 
 
Cash earnings (1)
 
$
40
 
$
34
 
$
101
 
$
108
 
Pension trust contribution(2) 
   
-
   
(8
)
 
-
   
(8
)
Working capital and other
 
 
-
 
 
10
 
 
(5
)
 
5
 
Total cash flows from operating activities
 
$
40
 
$
36
 
$
96
 
$
105
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) Cash earnings is a non-GAAP measure (see reconciliation below).
(2) Pension trust contribution net of $5 million of income tax benefits.
 
 
 
 
 
 
 
 
 
120


Cash earnings (in the table above) are not a measure of performance calculated in accordance with GAAP. Penn believes that cash earnings is a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income.

 
 
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
Reconciliation of Cash Earnings
 
2005
 
2004
 
2005
 
2004
 
 
 
(In millions)
 
 
 
 
 
 
 
 
 
 
 
Net income (GAAP)
 
$
23
 
$
20
 
$
54
 
$
58
 
Non-cash charges (credits):
 
 
 
 
 
 
 
 
 
 
 
 
 
Provision for depreciation
 
 
4
 
 
4
 
 
11
 
 
10
 
Amortization of regulatory assets
 
 
10
 
 
10
 
 
29
 
 
30
 
Nuclear fuel and other amortization
 
 
5
 
 
4
 
 
13
 
 
14
 
Deferred income taxes and investment tax credits, net
 
 
(3
)
 
(5
 
(8
)
 
(8
Other non-cash items
 
 
1
 
 
1
 
 
2
 
 
4
 
Cash earnings (Non-GAAP)
 
$
40
 
$
34
 
$
101
 
$
108
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

The $6 million increase in cash earnings in the third quarter of 2005 and the $7 million decrease in cash earnings for the first nine months of 2005, as compared to the corresponding periods of 2004, are described under “Results of Operations.” The $10 million change in working capital and other in the three-month period was primarily due to a $49 million change in accounts payable, partially offset by changes of $35 million in receivables, $2 million in materials and supplies, and $2 million in accrued taxes. The $10 million change in working capital and other in the nine-month period was primarily due to a $51 million change in accounts payable, partially offset by changes of $26 million in receivables, $3 million in materials and supplies, and $10 million in accrued taxes.

Cash Flows From Financing Activities

Net cash used for financing activities totaled $11 million in the third quarter of 2005, compared with $8 million in the same period last year. The $3 million increase resulted primarily from the absence of a $25 million equity contribution from OE in the third quarter of 2004, partially offset by a $21 million decrease in debt redemptions and repayments in the third quarter of 2005.

Net cash used for financing activities totaled $25 million in the nine months ended September 30, 2005, compared with $52 million in the same period last year. The $27 million decrease resulted primarily from reduced long-term debt redemptions and common stock dividend payments in the first nine months of 2005, offset by reduced short-term borrowings and OE's $25 million equity contribution in 2004.

On May 16, 2005, Penn redeemed all 127,500 outstanding shares of 7.625% preferred stock at $102.29 per share and all 250,000 outstanding shares of 7.75% preferred stock at $100 per share, both plus accrued dividends to the date of redemption. The total par value of the preferred stock redeemed was $37.8 million. 

Penn had $590,000 of cash and temporary investments (which included short-term notes receivable from associated companies) and $35 million of short-term indebtedness as of September 30, 2005. Penn has authorization from the SEC to incur short-term debt up to its charter limit of $51 million. As of October 24, 2005, Penn had the capability to issue approximately $520 million of additional FMB on the basis of property additions and retired bonds following the recently completed intra-system transfer of fossil generating plants (See Note 17) . Based upon applicable earnings coverage tests, Penn could issue up to $383 million of preferred stock (assuming no additional debt was issued) as of September 30, 2005. It is estimated that the annualized impact of the intra-system transfer of fossil generating plants will reduce the capability of Penn to issue preferred stock by approximately 14%. The above financing capabilities do not take into consideration changes related to the intercompany transfer of generating assets (see Note 17).

On June 14, 2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, entered into a syndicated $2 billion five-year revolving credit facility. Borrowings under the facility are available to each Borrower separately and will mature on the earlier of 364 days from the date of borrowing and the commitment termination date, as the same may be extended. Penn's borrowing limit under the facility is $51 million.

Penn has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal amount of such a loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings under these arrangements in the third quarter of 2005 was 3.50%.
 
 
 
121

 

Penn Power Funding LLC (Penn Funding), a wholly owned subsidiary of Penn, is a limited liability company whose borrowings are secured by customer accounts receivable purchased from Penn. Penn Funding can borrow up to $25 million under a receivables financing arrangement. As a separate legal entity with separate creditors, Penn Funding would have to satisfy its obligations to creditors before any of its remaining assets could be made available to Penn. The facility was not drawn as of September 30, 2005. On July 15, 2005, the facility was renewed until June 29, 2006. The annual facility fee is 0.25% on the entire finance limit.

Penn’s access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of OE and FirstEnergy.

On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in their outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemming from the application of free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.

On October 3, 2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to 'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one notch above the previous rating. S&P noted that the upgrade followed the continuation of a good operating track record, specifically for the nuclear fleet through the third quarter 2005. S&P also stated that FirstEnergy’s rating reflects the benefits of supportive regulation, low-cost base load generation fleet, low-risk transmission and distribution operations and rate certainty in Ohio. FirstEnergy’s ability to consistently generate free cash flow, good liquidity, and an improving financial profile were also noted as strengths.

Cash Flows From Investing Activities

Net cash used in investing activities totaled $29 million in the third quarter of 2005, compared with $28 million in the third quarter of 2004. For the nine months ended September 30, 2005, net cash used in investing activities totaled $71 million, compared with $53 million in the same period last year. The $18 million increase was primarily the result of higher expenditures for property additions in 2005 and reduced loan repayments from associated companies.

In the last quarter of 2005, capital requirements for property additions are expected to be about $32 million. Penn also expects to contribute up to $63 million (unfunded liability recognized as of September 30, 2005) for nuclear decommissioning in connection with the generation asset transfers described below, and has additional requirements of $0.5 million to meet sinking fund requirements for long-term debt during the remainder of 2005. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. Penn's capital spending for the period 2005-2007 is expected to be about $227 million, of which approximately $87 million applies to 2005. Penn had no other material obligations as of September 30, 2005 that have not been recognized on its Consolidated Balance Sheet.

On July 22, 2005, the Philadelphia Stock Exchange (Exchange) filed an application with the SEC for termination of the listing of the following three series of Penn’s cumulative preferred stock, $100 par value, as such series no longer met the Exchange’s technical listing requirements regarding the number of outstanding shares and the number of holders: 4.24% Series, 4.25% Series and 4.64% Series. On August 17, 2005, the SEC granted the Exchange's application for delisting effective August 18, 2005.

Equity Price Risk
 
Included in Penn’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $60 million and $57 million as of September 30, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $6 million reduction in fair value as of September 30, 2005. 

FirstEnergy Intra-System Generation Asset Transfers

On May 13, 2005, Penn entered into an agreement to transfer its ownership interests in its nuclear and fossil generating facilities to NGC and FGCO, respectively.

 
122

 

On October 24, 2005, Penn completed the transfer of fossil generation assets to FGCO. Penn currently expects to complete the transfer of nuclear generation assets to NGC through a spin-off by way of dividend before the end of 2005. Consummation of the nuclear transfer remains subject to necessary regulatory approvals.

These transactions are being undertaken in connection with Penn’s restructuring plan that was approved by the PPUC under applicable Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plan, Penn’s generation assets were required to be separated from the regulated delivery business through transfers to a separate corporate entity. FENOC currently operates and maintains the nuclear generation assets to be transferred. FGCO, as lessee under a Master Facility Lease, leased, operated and maintained the non-nuclear generation assets that it now owns. The transactions will essentially complete the divestitures contemplated by the restructuring plan by transferring the ownership interests to NGC and FGCO, respectively, without impacting the operation of the plants.

See Note 17 to the consolidated financial statements for disclosure of Penn's assets held for sale as of September 30, 2005.

Regulatory Matters
 
Regulatory assets and liabilities are costs which have been authorized by the PPUC and the FERC for recovery from or credit to customers in future periods and, without such authorization, would have been charged or credited to income when incurred. Penn's net regulatory liabilities were approximately $48 million and $18 million as of September 30, 2005 and December 31, 2004, respectively, and are included in Noncurrent Liabilities on the Consolidated Balance Sheets.

In October 11, 2005, Penn filed a plan with the PPUC to secure electricity supply for its customers at set rates following the end of its transition period on December 31, 2006. Penn is recommending that the Request for Proposal process cover the period of January 1, 2007 through May 31, 2008. Under Pennsylvania's electric competition law, Penn is required to secure generation supply for customers who do not choose alternative suppliers for their electricity.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Pennsylvania, including a more detailed discussion of reliability initiatives.

Environmental Matters

Penn accrues environmental liabilities when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in Penn’s determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

FirstEnergy plans to issue a report regarding its response to air emission requirements. FirstEnergy expects to complete the report by December 1, 2005.

National Ambient Air Quality Standards
 
In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR provides each affected state until 2006 to develop implementing regulations to achieve additional reductions of NOx and SO2 emissions in two phases (Phase I in 2009 for NOx, 2010 for SO2 and Phase II in 2015 for both NOx and SO2), in all cases from the 2003 levels. Penn's Ohio and Pennsylvania fossil-fired generation facilities will be subject to the caps on SO2 and NOx emissions. According to the EPA, SO2 emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO2 emissions in affected states to just 2.5 million tons annually. NOx emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NOx cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which Penn operates affected facilities.


123

 
Mercury Emissions
 
In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On March 14, 2005, the EPA finalized the "Clean Air Mercury Rule," which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases. Initially, mercury emissions will be capped nationally at 38 tons by 2010 as a "co-benefit" from implementation of SO2 and NOx emission caps under the EPA's CAIR program. Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. However, the final rules give states substantial discretion in developing rules to implement these programs. In addition, both the CAIR and the Clean Air Mercury rule have been challenged in the United States Court of Appeals for the District of Columbia. Future cost of compliance with these regulations may be substantial.

W. H. Sammis Plant
 
In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which was owned at that time by OE and Penn. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the W. H. Sammis Plant New Source Review litigation. This settlement agreement, which is in the form of a Consent Decree, was approved by the Court on July 11, 2005, requires OE and Penn to reduce NOx and SO2 emission at W. H. Sammis Plant and other coal-fired plants through the installation of pollution control devices. Capital expenditures necessary to meet those requirements are currently estimated to be $1.5 billion (the primary portion of which is expected to be spent in the 2008 to 2011 time period). The settlement agreement also requires OE and Penn to spend up to $25 million toward environmentally beneficial projects, which include wind energy purchased power agreements over a 20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million, of which Penn's share was $0.7 million. Results for the first quarter of 2005 included the $0.7 million penalty payable by Penn and a $0.8 million liability for probable future cash contributions toward environmentally beneficial projects.

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global warming by reducing the amount of man-made greenhouse gases emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Protocol in 1998 but it failed to receive the two-thirds vote of the United States Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic greenhouse gas intensity - the ratio of emissions to economic output - by 18 percent through 2012. The Energy Policy Act of 2005 established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

Penn cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO2 emissions could require significant capital and other expenditures. However, the CO2 emissions per KWH of electricity generated by Penn is lower than many regional competitors due to Penn's diversified generation sources which include low or non-CO2 emitting gas-fired and nuclear generators.

See Note 13(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to Penn's normal business operations pending against Penn. The other material items not otherwise discussed above are described below.


 
124


On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of September 30, 2005 for any expenditures in excess of those actually incurred through that date. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

One complaint was filed on August 25, 2004 against FirstEnergy in the New York State Supreme Court. In this case, several plaintiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. FirstEnergy's motion to dismiss the case was granted on September 26, 2005. Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter is not due until on or about December 1, 2005. No estimate of potential liability has been undertaken in this matter.

FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. In particular, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the preceding two years and the licensee's failure to take prompt and effective corrective action. FENOC operates the Perry Nuclear Power Plant, in which Penn currently has a 5.24% interest (however, see Note 17 regarding FirstEnergy’s pending intra-system generation asset transfers, which will include owned portions of the plant).

On April 4, 2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Plant operated "in a manner that preserved public health and safety" even though it remained under heightened NRC oversight. During the public meeting and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix.


125


On May 26, 2005, the NRC held a public meeting to discuss its oversight of the Perry Plant. While the NRC stated that the plant continued to operate safely, the NRC also stated that the overall performance had not substantially improved since the heightened inspection was initiated. The NRC reiterated this conclusion in its mid-year assessment letter dated August 30, 2005. On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance of Perry and stated that the CAL would remain open until substantial improvement was demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight Process. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process, from increased oversight to possible impact to the plant’s operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

See Note 13(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

New Accounting Standards and Interpretations

EITF Issue 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty"
 
In September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus that an exchange of inventory should be accounted for at fair value. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and other storable inventory. Therefore, Penn will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006.

FIN 47, “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective for Penn in the fourth quarter of 2005. Penn is currently evaluating the effect this Interpretation will have on its financial statements.

 
SFAS 154 - “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3”

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in the Consolidated Statements of Income. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. Penn will adopt this Statement effective January 1, 2006.

 
SFAS 153, “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29”
 
In December 2004, the FASB issued SFAS 153 amending APB 29, which was based on the principle that nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB 29 included certain exceptions to that principle. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement are effective January 1, 2006 for Penn. This FSP is not expected to have a material impact on Penn's financial statements.
 
126

 

SFAS 151, “Inventory Costs - an amendment of ARB No. 43, Chapter 4”

In November 2004, the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Previous guidance stated that in some circumstances these costs may be “so abnormal” that they would require treatment as current period costs. SFAS 151 requires abnormal amounts for these items to always be recorded as current period costs. In addition, this Statement requires that allocation of fixed production overheads to the cost of conversion be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred by Penn beginning January 1, 2006. Penn is currently evaluating this Standard and does not expect it to have a material impact on the financial statements.

FSP FAS 115-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

In September 2005, the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP FAS 115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition of Other Than Temporary Impairment upon the Planned Sale of a Security Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when the impairment is deemed other than temporary, even if a decision to sell has not been made, and (3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after September 15, 2005. The FASB expects to issue this FSP in the fourth quarter of 2005, which would require prospective application with an effective date for reporting periods beginning after December 15, 2005. Penn is currently evaluating this FSP and any impact on its investments.


127

 

JERSEY CENTRAL POWER & LIGHT COMPANY
 
                   
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
 
(Unaudited)
 
                   
   
Three Months Ended
 
Nine Months Ended
 
   
September 30,
 
September 30,
 
   
2005
 
2004
 
2005
 
2004
 
   
(In thousands)
 
STATEMENTS OF INCOME
                 
                   
OPERATING REVENUES
 
$
900,247
 
$
706,613
 
$
2,024,630
 
$
1,754,402
 
                           
OPERATING EXPENSES AND TAXES:
                         
Purchased power
   
517,212
   
387,282
   
1,115,737
   
943,757
 
Other operating costs
   
112,690
   
91,516
   
293,996
   
259,176
 
Provision for depreciation
   
19,659
   
18,435
   
59,721
   
56,603
 
Amortization of regulatory assets
   
84,388
   
84,271
   
223,012
   
216,705
 
Deferral of new regulatory assets
   
-
   
-
   
(27,765
)
 
-
 
General taxes
   
19,538
   
17,901
   
49,802
   
48,571
 
Income taxes
   
55,729
   
35,099
   
110,578
   
70,555
 
Total operating expenses and taxes 
   
809,216
   
634,504
   
1,825,081
   
1,595,367
 
                           
OPERATING INCOME
   
91,031
   
72,109
   
199,549
   
159,035
 
                           
OTHER INCOME (net of income taxes)
   
3,014
   
1,996
   
3,331
   
4,603
 
                           
NET INTEREST CHARGES:
                         
Interest on long-term debt
   
18,162
   
21,709
   
56,843
   
62,240
 
Allowance for borrowed funds used during construction
   
(497
)
 
(169
)
 
(1,337
)
 
(440
)
Deferred interest
   
(1,069
)
 
(871
)
 
(2,896
)
 
(2,685
)
Other interest expense
   
2,283
   
1,105
   
5,262
   
1,958
 
Net interest charges 
   
18,879
   
21,774
   
57,872
   
61,073
 
                           
NET INCOME
   
75,166
   
52,331
   
145,008
   
102,565
 
                           
PREFERRED STOCK DIVIDEND REQUIREMENTS
   
125
   
125
   
375
   
375
 
                           
EARNINGS ON COMMON STOCK
 
$
75,041
 
$
52,206
 
$
144,633
 
$
102,190
 
                           
STATEMENTS OF COMPREHENSIVE INCOME
                         
                           
NET INCOME
 
$
75,166
 
$
52,331
 
$
145,008
 
$
102,565
 
                           
OTHER COMPREHENSIVE INCOME:
                         
Unrealized gain on derivative hedges
   
102
   
173
   
208
   
217
 
Unrealized loss on available for sale securities
   
-
   
-
   
-
   
(8
)
Other comprehensive income 
   
102
   
173
   
208
   
209
 
Income tax expense (benefit) related to other comprehensive income
   
42
   
(1,542
)
 
85
   
(1,546
)
Other comprehensive income, net of tax 
   
60
   
1,715
   
123
   
1,755
 
                           
TOTAL COMPREHENSIVE INCOME
 
$
75,226
 
$
54,046
 
$
145,131
 
$
104,320
 
                           
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these statements.
   
 
 
128


 

JERSEY CENTRAL POWER & LIGHT COMPANY
 
           
CONSOLIDATED BALANCE SHEETS
 
(Unaudited)
 
   
September 30,
 
December 31,
 
   
2005
 
2004
 
   
(In thousands)  
 
ASSETS
         
UTILITY PLANT:
         
In service
 
$
3,840,213
 
$
3,730,767
 
Less - Accumulated provision for depreciation
   
1,424,801
   
1,380,775
 
     
2,415,412
   
2,349,992
 
Construction work in progress
   
85,335
   
75,012
 
     
2,500,747
   
2,425,004
 
OTHER PROPERTY AND INVESTMENTS:
             
Nuclear plant decommissioning trusts
   
143,937
   
138,205
 
Nuclear fuel disposal trust
   
164,070
   
159,696
 
Long-term notes receivable from associated companies
   
19,751
   
20,436
 
Other
   
16,597
   
19,379
 
     
344,355
   
337,716
 
CURRENT ASSETS:
             
Cash and cash equivalents
   
571
   
162
 
Receivables -
             
Customers (less accumulated provisions of $4,264,000 and $3,881,000,
             
respectively, for uncollectible accounts) 
   
313,730
   
201,415
 
Associated companies
   
1,171
   
86,531
 
Other (less accumulated provisions of $239,000 and $162,000,
             
respectively, for uncollectible accounts) 
   
38,569
   
39,898
 
Materials and supplies, at average cost
   
1,863
   
2,435
 
Prepayments and other
   
33,254
   
31,489
 
     
389,158
   
361,930
 
DEFERRED CHARGES:
             
Regulatory assets
   
2,310,532
   
2,176,520
 
Goodwill
   
1,983,699
   
1,985,036
 
Other
   
2,850
   
4,978
 
     
4,297,081
   
4,166,534
 
   
$
7,531,341
 
$
7,291,184
 
CAPITALIZATION AND LIABILITIES
             
CAPITALIZATION:
             
Common stockholder's equity -
             
Common stock, $10 par value, authorized 16,000,000 shares -
             
15,371,270 shares outstanding 
 
$
153,713
 
$
153,713
 
Other paid-in capital
   
3,014,600
   
3,013,912
 
Accumulated other comprehensive loss
   
(55,411
)
 
(55,534
)
Retained earnings
   
104,904
   
43,271
 
Total common stockholder's equity 
   
3,217,806
   
3,155,362
 
Preferred stock
   
12,649
   
12,649
 
Long-term debt and other long-term obligations
   
1,017,478
   
1,238,984
 
     
4,247,933
   
4,406,995
 
CURRENT LIABILITIES:
             
Currently payable long-term debt
   
167,045
   
16,866
 
Notes payable -
             
Associated companies
   
114,932
   
248,532
 
Accounts payable -
             
Associated companies
   
8,968
   
20,605
 
Other
   
162,583
   
124,733
 
Accrued taxes
   
78,342
   
2,626
 
Accrued interest
   
23,535
   
10,359
 
Other
   
152,638
   
65,130
 
     
708,043
   
488,851
 
NONCURRENT LIABILITIES:
             
Power purchase contract loss liability
   
1,410,659
   
1,268,478
 
Accumulated deferred income taxes
   
670,514
   
645,741
 
Nuclear fuel disposal costs
   
173,591
   
169,884
 
Asset retirement obligation
   
76,002
   
72,655
 
Retirement benefits
   
100,567
   
103,036
 
Other
   
144,032
   
135,544
 
     
2,575,365
   
2,395,338
 
COMMITMENTS AND CONTINGENCIES (Note 13)
             
   
$
7,531,341
 
$
7,291,184
 
               
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these blance sheets.  
   
 
             
 
 
129

 

JERSEY CENTRAL POWER & LIGHT COMPANY
 
                   
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
                   
   
Three Months Ended
 
Nine Months Ended
 
   
September 30,
 
September 30,
 
   
2005
 
2004
 
2005
 
2004
 
   
(In thousands)
 
                   
CASH FLOWS FROM OPERATING ACTIVITIES:
                 
Net income
 
$
75,166
 
$
52,331
 
$
145,008
 
$
102,565
 
Adjustments to reconcile net income to net cash from
                         
operating activities -
                         
Provision for depreciation 
   
19,659
   
18,436
   
59,721
   
56,603
 
Amortization of regulatory assets 
   
84,388
   
84,269
   
223,012
   
216,704
 
Deferral of new regulatory assets 
   
-
   
-
   
(27,765
)
 
-
 
Deferred purchased power and other costs 
   
(42,381
)
 
(77,162
)
 
(168,646
)
 
(155,552
)
Deferred income taxes and investment tax credits, net 
   
(11,222
)
 
6,165
   
5,204
   
(13,582
)
Accrued retirement benefit obligation 
   
813
   
2,888
   
(2,468
)
 
(5,880
)
Accrued compensation, net 
   
671
   
1,547
   
(4,077
)
 
731
 
NUG power contract restructuring 
   
-
   
-
   
-
   
52,800
 
Cash collateral from suppliers 
   
76,978
   
-
   
76,978
   
-
 
Pension trust contribution 
   
-
   
(62,499
)
 
-
   
(62,499
)
Decrease (increase) in operating assets - 
                         
    Receivables
   
(39,897
)
 
(34,749
)
 
(25,626
)
 
(26,906
)
    Materials and supplies
   
395
   
64
   
572
   
411
 
    Prepayments and other current assets
   
64,761
   
34,664
   
(1,764
)
 
(5,040
)
Increase (decrease) in operating liabilities - 
                         
    Accounts payable
   
(5,873
)
 
57,485
   
26,214
   
58,430
 
    Accrued taxes
   
18,498
   
(27,924
)
 
75,716
   
35,844
 
    Accrued interest
   
13,765
   
16,709
   
13,176
   
11,481
 
Other 
   
6,928
   
27,603
   
23,982
   
8,539
 
    Net cash provided from operating activities
   
262,649
   
99,827
   
419,237
   
274,649
 
                           
CASH FLOWS FROM FINANCING ACTIVITIES:
                         
New Financing-
                         
Long-term debt 
   
-
   
-
   
-
   
300,000
 
Redemptions and Repayments-
                         
Long-term debt 
   
(4,321
)
 
(7,082
)
 
(67,648
)
 
(304,150
)
Short-term borrowings, net 
   
(164,172
)
 
(456
)
 
(133,600
)
 
(72,648
)
Dividend Payments-
                         
Common stock 
   
(43,000
)
 
(40,000
)
 
(83,000
)
 
(60,000
)
Preferred stock 
   
(125
)
 
(125
)
 
(375
)
 
(375
)
 Net cash used for financing activities
   
(211,618
)
 
(47,663
)
 
(284,623
)
 
(137,173
)
                           
CASH FLOWS FROM INVESTING ACTIVITIES:
                         
Property additions
   
(50,837
)
 
(52,507
)
 
(133,498
)
 
(135,932
)
Loan repayments from (loans to) associated companies, net
   
15
   
(711
)
 
685
   
(1,122
)
Other
   
(50
)
 
1,049
   
(1,392
)
 
(416
)
 Net cash used for investing activities
   
(50,872
)
 
(52,169
)
 
(134,205
)
 
(137,470
)
                           
Net increase (decrease) in cash and cash equivalents
   
159
   
(5
)
 
409
   
6
 
Cash and cash equivalents at beginning of period
   
412
   
282
   
162
   
271
 
Cash and cash equivalents at end of period
 
$
571
 
$
277
 
$
571
 
$
277
 
                           
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral  part of these statements.
     
 
                         
                           
 
 
 
130


Report of Independent Registered Public Accounting Firm









To the Stockholders and Board of
Directors of Jersey Central
Power & Light Company:

We have reviewed the accompanying consolidated balance sheet of Jersey Central Power & Light Company and its subsidiaries as of September 30, 2005, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and nine-month periods ended September 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2004, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 9 to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 6 to those consolidated financial statements) dated March 7, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.




PricewaterhouseCoopers LLP
Cleveland, Ohio
November 1, 2005


 
131

 

JERSEY CENTRAL POWER & LIGHT COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION


JCP&L is a wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts business in New Jersey, providing regulated electric transmission and distribution services. JCP&L also provides generation services to those customers electing to retain JCP&L as their power supplier. JCP&L has restructured its electric rates into unbundled service charges and transition cost recovery charges. JCP&L continues to deliver power to homes and businesses through its existing distribution system.

Results of Operations

Earnings on common stock in the third quarter of 2005 increased to $75 million from $52 million in the third quarter of 2004. During the first nine months of 2005, earnings on common stock increased to $145 million compared to $102 million for the same period of 2004. The increase in earnings for both periods was primarily due to higher operating revenues partially offset by increases in purchased power costs, other operating costs and income taxes. Other operating costs in both periods of 2005 included a charge of $16 million for potential awards related to a labor arbitration decision (see note 13 - Other Legal Matters).
 
Operating revenues increased $194 million or 27.4% in the third quarter and $270 million or 15.4% in the first nine months of 2005 compared with the same periods in 2004. Increases in both periods were due to higher retail electric generation, distribution and wholesale revenues.

Retail generation revenues increased by $82 million in the third quarter and $134 million in the first nine months of 2005 as compared to the previous year. Higher KWH sales to residential and commercial customers increased generation revenues by $45 million in the third quarter and $81 million in the first nine months of 2005. Commercial generation revenue increased for the same periods of 2005 by $33 million and $54 million, respectively. The increases were attributable to higher KWH sales (residential - 14.9% and commercial - 20.3% in the third quarter of 2005; residential - 15.3% and commercial - 13.4% for the first nine months of 2005) primarily due to warmer weather and reduced customer shopping. Generation provided by alternative suppliers to residential and commercial customers as a percent of total sales delivered in JCP&L’s service area decreased by 6.9 and 4.6 percentage points, respectively, in the first nine months of 2005. Industrial generation revenue increased by $4 million in the third quarter, but declined $2 million in the first nine months of 2005 reflecting the effect of a 25.6% KWH sales increase in the third quarter and a 9.3% decline in the first nine months of 2005.

Revenues from wholesale sales increased by $49 million in the third quarter and $42 in the first nine months of 2005 as compared to the previous year, principally due to increased prices in 2005. KWH sales to the wholesale sector increased in the quarter (5.5%) but declined for the first nine months (8.5%).

Distribution revenues increased by $62 million in the third quarter and $96 million in the first nine months of 2005, as compared to the same periods of 2004, due to increased KWH deliveries to all customer sectors and higher composite unit prices, caused in part by the June 1, 2005 rate increase.

Changes in KWH sales by customer class in the three months and nine months ended September 30, 2005 compared to the same periods of 2004 are summarized in the following table:


 
 
Three
 
Nine
 
Changes in KWH Sales
 
Months
 
Months
 
Increase (Decrease)
 
 
 
 
 
Electric Generation:
 
 
 
 
 
Retail
 
 
17.2
%
 
13.4
%
Wholesale
 
 
5.5
%
 
(8.5
)%
Total Electric Generation Sales
 
 
14.8
%
 
8.2
%
 
 
 
 
 
 
 
 
Distribution Deliveries:
 
 
 
 
 
 
 
Residential
 
 
15.6
%
 
7.4
%
Commercial
 
 
13.4
%
 
6.7
%
Industrial
 
 
5.4
%
 
0.4
%
Total Distribution Deliveries
 
 
13.4
%
 
6.2
%
 
 
 
 
 
 
 
 
 
 
 
132


Operating Expenses and Taxes

Total operating expenses and taxes increased by $175 million in the third quarter and $230 million in the first nine months of 2005 compared with the same periods of 2004. The following table presents changes from the prior year by expense category.

 
 
Three
 
Nine
 
Operating Expenses and Taxes - Changes
 
Months
 
Months
 
 
 
(In millions)
 
Increase (Decrease) 
 
 
 
 
 
Purchased power costs
 
$
130
 
$
172
 
Other operating costs
 
 
21
 
 
35
 
Provision for depreciation
 
 
1
 
 
3
 
Amortization of regulatory assets
 
 
-
 
 
7
 
Deferral of new regulatory assets
 
 
-
 
 
(28
)
General taxes
   
2
   
1
 
Income taxes
 
 
21
 
 
40
 
Net increase in operating expenses and taxes
 
$
175
 
$
230
 
 
 
 
 
 
 
 
 


Purchased power costs increased by $130 million in the third quarter and $172 million in the first nine months of 2005 as compared to the same periods in 2004 due to higher KWH purchases to meet increased retail generation sales and, to a lesser extent, higher unit costs. Other operating costs increased $21 million in the third quarter of 2005 and $35 million in the first nine months of 2005 compared to the same periods of 2004, reflecting $16 million of expenses resulting from a JCP&L arbitration decision.

Deferral of new regulatory assets decreased expenses by $28 million in the first nine months of 2005, reflecting the NJBPU’s (see Regulatory Matters) approval for JCP&L to defer $28 million of previously incurred reliability expenses. Amortization of regulatory assets increased $7 million in the first nine months of 2005 due to an increase in the level of MTC revenue recovery.

Capital Resources and Liquidity

JCP&L’s cash requirements for the remainder of 2005 for operating expenses, construction expenditures and scheduled debt maturities are expected to be met with cash from operations.

Changes in Cash Position

As of September 30, 2005, JCP&L had $571,000 of cash and cash equivalents compared with $162,000 as of December 31, 2004. The major sources for changes in these balances are summarized below.

Cash Flows From Operating Activities

Cash provided from operating activities in the third quarter and in the first nine months of 2005 compared with the corresponding periods of 2004, were as follows:

 
 
 
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
 Operating Cash Flows
 
2005
 
2004
 
2005
 
2004
 
 
 
(In millions)
 
 
 
 
 
 
 
 
 
 
 
Cash earnings (1)
 
$
204
 
$
64
 
$
307
 
$
177
 
Pension trust contribution (2)
   
-
   
(37
)
 
-
   
(37
)
Working capital and other
 
 
58
 
 
73
 
 
112
 
 
135
 
Total cash flows from operating activities
 
$
262
 
$
100
 
$
419
 
$
275
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) Cash earnings is a non-GAAP measure (see reconciliation below).
(2) Pension trust contribution net of $25 million of income tax benefits.
 
 
 
 
 
 
 
 
 


Cash earnings, as disclosed in the table above, are not a measure of performance calculated in accordance with GAAP. JCP&L believes that cash earnings is a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income.
 
133

 

 
 
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
Reconciliation of Cash Earnings 
 
2005
 
2004
 
2005
 
2004
 
 
 
(In millions)
 
 
 
 
 
 
 
 
 
 
 
Net income (GAAP)
 
$
75
 
$
52
 
$
145
 
$
103
 
Non-cash charges (credits):
 
 
 
 
 
 
 
 
 
 
 
 
 
Provision for depreciation
 
 
20
 
 
18
 
 
60
 
 
57
 
Amortization of regulatory assets
 
 
84
 
 
84
 
 
223
 
 
217
 
Deferral of new regulatory assets
   
-
   
-
   
(28
)
 
-
 
Deferred purchased power and other costs
 
 
(42
 
(77
 
(169
 
(156
Deferred income taxes & investment tax credits, net
 
 
(11
 
(19
 
5
 
 
(39
Other non-cash items
 
 
78
 
 
6
 
 
71
 
 
(5
Cash earnings (Non-GAAP)
 
$
204
 
$
64
 
$
307
 
$
177
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


The $140 million and $130 million increases in cash earnings for the third quarter and the first nine months of 2005, respectively, are described above under “Results of Operations”. The $15 million and $23 million decrease for the third quarter and the first nine months of 2005 from working capital primarily resulted from a reduction in accounts payables partially offset by an increase in accrued taxes. In the first nine months of 2004, JCP&L received $52.8 million in connection with restructuring a NUG power contract.
 
Cash Flows From Financing Activities

Net cash used for financing activities was $212 million in the third quarter of 2005 compared to $48 million in the third quarter of 2004. The increase resulted from redemptions of short-term debt in the third quarter of 2005. Net cash used for financing activities was $285 million for the first nine months of 2005 and $137 million for the same period of 2004. The $148 million increase resulted from a $124 million increase in net debt redemptions and a $23 million increase in common stock dividends to FirstEnergy.

JCP&L had approximately $571,000 of cash and temporary investments and $115 million of short-term indebtedness as of September 30, 2005. JCP&L has authorization from the SEC to incur short-term debt up to its charter limit of $1.8 billion (including the utility money pool). JCP&L will not issue FMB other than as collateral for senior notes, since its senior note indentures prohibit (subject to certain exceptions) JCP&L from issuing any debt which is senior to the senior notes. As of September 30, 2005, JCP&L had the capability to issue $673 million of additional senior notes based upon FMB collateral. Based upon applicable earnings coverage tests and its charter, JCP&L could issue $976 million of preferred stock (assuming no additional debt was issued) as of September 30, 2005.

On June 14, 2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, entered into a syndicated $2 billion five-year revolving credit facility. Borrowings under the facility are available to each Borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. JCP&L’s borrowing limit under the facility is $425 million.

JCP&L has the ability to borrow from FirstEnergy and its regulated affiliates to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings was 3.50% in the third quarter of 2005 and 3.03% in the first nine months of 2005.

JCP&L’s access to capital markets and costs of financing are influenced by the ratings of its securities and the securities of FirstEnergy. The ratings outlook from S&P and Fitch on all securities is stable. Moody’s outlook on all securities is positive.

On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in their outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemming from the application of free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.
 
134


On October 3, 2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to 'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one notch above the previous rating. S&P noted that the upgrade followed the continuation of a good operating track record, specifically for the nuclear fleet through the third quarter 2005. S&P also stated that FirstEnergy’s rating reflects the benefits of supportive regulation, low-cost base load generation fleet, low-risk transmission and distribution operations and rate certainty in Ohio. FirstEnergy’s ability to consistently generate free cash flow, good liquidity, and an improving financial profile were also noted as strengths.

Cash Flows From Investing Activities

Net cash used for investing activities was $51 million in the third quarter and $134 million for the first nine months of 2005 compared to $52 million and $137 million for the same periods of 2004. JCP&L’s capital spending for the period 2005-2007 is expected to be about $511 million of which approximately $185 million applies to 2005. In the last quarter of 2005, capital requirements for property additions and improvements are expected to be about $52 million.

Market Risk Information

JCP&L uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk management activities.

Commodity Price Risk

JCP&L is exposed to price risk primarily due to fluctuating electricity and natural gas prices. To manage the volatility relating to these exposures, it uses a variety of non-derivative and derivative instruments, including forward contracts, options and futures contracts. The derivatives are used for hedging purposes. Most of its non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. As of September 30, 2005, JCP&L had commodity derivative contracts with a fair value of $14 million. A decrease of $1 million in the value of this asset was recorded in the first nine months of 2005 as a decrease in a regulatory liability, and therefore, had no impact on net income.

The valuation of derivative commodity contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, JCP&L relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. JCP&L uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for valuation of derivative contracts as of September 30, 2005 are summarized by year in the following table:



Sources of Information -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value by Contract Year
 
 
 
2005(1)
 
2006
 
2007
 
2008
 
2009
 
Thereafter
 
Total
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prices based on external sources(2)
 
 
 
 
$
3
 
$
2
 
$
3
 
$
-
 
$
-
 
$
-
 
$
8
 
Prices based on models
 
 
 
 
 
-
 
 
-
 
 
-
 
 
2
 
 
2
 
 
2
 
 
6
 
Total
 
 
 
 
$
3
 
$
2
 
$
3
 
$
2
 
$
2
 
$
2
 
$
14
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) For the last quarter of 2005.
(2) Broker quote sheets.


JCP&L performs sensitivity analyses to estimate its exposure to the market risk of its commodity position. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on its consolidated financial position or cash flows as of September 30, 2005.

Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their current market value of approximately $82 million and $80 million as of September 30, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in an $8 million reduction in fair value as of September 30, 2005.
 
 
135

 

Regulatory Matters
 
Regulatory assets are costs which have been authorized by the NJBPU and the FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. JCP&L's regulatory assets as of September 30, 2005 and December 31, 2004 were $2.3 billion and $2.2 billion, respectively.

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and MTC rates. As of September 30, 2005, the accumulated deferred cost balance totaled approximately $508 million. New Jersey law allows for securitization of JCP&L's deferred balance upon application by JCP&L and a determination by the NJBPU that the conditions of the New Jersey restructuring legislation are met. On February 14, 2003, JCP&L filed for approval of the securitization of the July 31, 2003 deferred balance. JCP&L is in discussions with the NJBPU staff as a result of the stipulated settlement agreements (as further discussed below) which recommended that the NJBPU issue an order regarding JCP&L's application. On July 20, 2005, JCP&L requested the NJBPU to set a procedural schedule for this matter and is awaiting NJBPU action.

The 2003 NJBPU decision on JCP&L's base electric rate proceeding (the Phase I Order) disallowed certain regulatory assets and provided for an interim return on equity of 9.5% on JCP&L's rate base. The Phase I Order also provided for a Phase II proceeding in which the NJBPU would review whether JCP&L is in compliance with current service reliability and quality standards and determine whether the expenditures and projects undertaken by JCP&L to increase its system reliability are prudent and reasonable for rate recovery. Depending on its assessment of JCP&L's service reliability, the NJBPU could have increased JCP&L’s return on equity to 9.75% or decreased it to 9.25%. On August 15, 2003 and June 1, 2004, JCP&L filed with the NJBPU an interim motion and a supplemental and amended motion for rehearing and reconsideration of the Phase I Order, respectively. On July 7, 2004, the NJPBU granted limited reconsideration and rehearing on the following issues: (1) deferred cost disallowances; (2) the capital structure including the rate of return; (3) merger savings, including amortization of costs to achieve merger savings; and (4) decommissioning costs.

On July 16, 2004, JCP&L filed the Phase II petition and testimony with the NJBPU, requesting an increase in base rates of $36 million for the recovery of system reliability costs and a 9.75% return on equity. The filing also requested an increase to the MTC deferred balance recovery of approximately $20 million annually.

On May 25, 2005, the NJBPU approved two stipulated settlement agreements. The first stipulation between JCP&L and the NJBPU staff resolves all of the issues associated with JCP&L's motion for reconsideration of the Phase I Order. The second stipulation between JCP&L, the NJBPU staff and the Ratepayer Advocate resolves all of the issues associated with JCP&L's Phase II proceeding. The stipulated settlements provide for, among other things, the following:

·    An annual increase in distribution revenues of $23 million effective June 1, 2005, associated with the
    Phase I Order reconsideration;

·    An annual increase in distribution revenues of $36 million effective June 1, 2005, related to JCP&L's
    Phase II Petition;

·    An annual reduction in both rates and amortization expense of $8 million, effective June 1, 2005, in
    anticipation of an NJBPU order regarding JCP&L's request to securitize up to $277 million of its deferred
    cost balance;

·    An increase in JCP&L's authorized return on common equity from 9.5% to 9.75%; and

·    A commitment by JCP&L to maintain a target level of customer service reliability with a reduction in
    JCP&L's authorized return on common equity from 9.75% to 9.5% if the target is not met for two
    consecutive quarters. The authorized return on common equity would then be restored to 9.75% if the
    target is met for two consecutive quarters.

The Phase II stipulation included an agreement that the distribution revenue increase also reflects a three-year amortization of JCP&L's one-time service reliability improvement costs incurred in 2003-2005. This resulted in the creation of a regulatory asset associated with accelerated tree trimming and other reliability costs which were expensed in 2003 and 2004. The establishment of the new regulatory asset of approximately $28 million resulted in an increase to net income of approximately $16 million ($0.05 per share of FirstEnergy common stock) in the second quarter of 2005.
 
 
136


JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits to its deferred energy balance with the exception of 300 MW from JCP&L's NUG committed supply currently being used to serve BGS customers pursuant to NJBPU order for the period June 1, 2005 through May 31, 2006. New BGS tariffs reflecting the results of a February 2005 auction for the BGS supply became effective June 1, 2005. On July 1, 2005, JCP&L filed its BGS procurement proposals for post transition year four. The auction is scheduled to take place in February 2006 for the annual supply period beginning June 1, 2006.

In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting a continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The Ratepayer Advocate filed comments on February 28, 2005. On March 18, 2005, JCP&L filed a response to those comments. A schedule for further proceedings has not yet been set.

As a result of outages experienced in JCP&L's service area in 2002 and 2003, the NJBPU had implemented reviews into JCP&L's service reliability. On March 29, 2004, the NJBPU adopted an MOU that set out specific tasks related to service reliability to be performed by JCP&L and a timetable for completion and endorsed JCP&L's ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a Stipulation that incorporates the final report of a Special Reliability Master who made recommendations on appropriate courses of action necessary to ensure system-wide reliability. The Stipulation also incorporates the Executive Summary and Recommendation portions of the final report of a focused audit of JCP&L's Planning and Operations and Maintenance programs and practices (Focused Audit). A final order in the Focused Audit docket was issued by the NJBPU on July 23, 2004. On February 11, 2005, JCP&L met with the Ratepayer Advocate to discuss reliability improvements. JCP&L continues to file compliance reports reflecting activities associated with the MOU and Stipulation.

On January 31, 2005, certain PJM transmission owners made three filings pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to referral and hearing procedures. On September 30, 2005, the PJM transmission owners filed a request for rehearing of the May 31, 2005 order. The rate design and formula rate filings continue to be litigated before the FERC. The outcome of these two cases cannot be predicted.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in New Jersey.

Environmental Matters

JCP&L accrues environmental liabilities when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in JCP&L’s determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

JCP&L has been named a PRP at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of September 30, 2005, based on estimates of the total costs of cleanup, JCP&L's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable SBC. Included in Other Noncurrent Liabilities are accrued liabilities aggregating approximately $46.8 million as of September 30, 2005.

FirstEnergy plans to issue a report regarding its response to air emission requirements. FirstEnergy expects to complete the report by December 1, 2005.
 
 
137

 

See Note 13(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to normal business operations pending against JCP&L. The other material items not otherwise discussed above are described below.

Power Outages and Related Litigation
 
In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four of New Jersey’s electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the JCP&L territory.

In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision on July 8, 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, New Jersey. On September 8, 2004, the New Jersey Supreme Court denied the motions filed by plaintiffs and JCP&L for leave to appeal the decision of the Appellate Division. JCP&L has filed a motion for summary judgment. FirstEnergy is unable to predict the outcome of these matters and no liability has been accrued as of September 30, 2005.

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concludes, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of September 30, 2005 for any expenditures in excess of those actually incurred through that date. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.



 
138


One complaint was filed on August 25, 2004 against FirstEnergy in the New York State Supreme Court. In this case, several plaintiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. FirstEnergy's motion to dismiss the case was granted on September 26, 2005. Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter is not due until on or about December 1, 2005. No estimate of potential liability has been undertaken in this matter.

FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. In particular, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

Other Legal Matters

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties’ collective bargaining agreement. At the conclusion of the June 1, 2005 hearing, the Arbitrator decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the Arbitrator issued an opinion to award approximately $16.1 million to the bargaining unit employees. JCP&L initiated an appeal of this award by filing a motion to vacate in Federal Court in New Jersey on October 18, 2005. JCP&L recognized a liability for the potential $16.1 million award during the three months ended September 30, 2005.

See Note 13(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

New Accounting Standards and Interpretations

EITF Issue 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty"
 
In September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus that an exchange of inventory should be accounted for at fair value. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and other storable inventory. Therefore, JCP&L will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006.

 
EITF Issue No. 05-6, "Determining the Amortization Period for Leasehold Improvements Purchased after Lease Inception or Acquired in a Business Combination"
 
In June 2005, the EITF reached a consensus on the application guidance for Issue 05-6. EITF 05-6 addresses the amortization period for leasehold improvements that were either acquired in a business combination or placed in service significantly after and not contemplated at or near the beginning of the initial lease term. For leasehold improvements acquired in a business combination, the amortization period is the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date of acquisition. Leasehold improvements that are placed in service significantly after and not contemplated at or near the beginning of the lease term should be amortized over the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date the leasehold improvements are purchased. This EITF was effective July 1, 2005 and is consistent with JCP&L's current accounting.

FIN 47, “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective for JCP&L in the fourth quarter of 2005. JCP&L is currently evaluating the effect this Interpretation will have on its financial statements.

 
139

 

 
SFAS 154 - “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3”

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in the Consolidated Statements of Income. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. JCP&L will adopt this Statement effective January 1, 2006.

 
SFAS 153, “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29”

In December 2004, the FASB issued SFAS 153 amending APB 29, which was based on the principle that nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB 29 included certain exceptions to that principle. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement are effective January 1, 2006 for FirstEnergy. This FSP is not expected to have a material impact on JCP&L's financial statements.

SFAS 151, “Inventory Costs - an amendment of ARB No. 43, Chapter 4”

In November 2004, the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Previous guidance stated that in some circumstances these costs may be “so abnormal” that they would require treatment as current period costs. SFAS 151 requires abnormal amounts for these items to always be recorded as current period costs. In addition, this Statement requires that allocation of fixed production overheads to the cost of conversion be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred by JCP&L beginning January 1, 2006. JCP&L is currently evaluating this Standard and does not expect it to have a material impact on the financial statements.

FSP FAS 115-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

In September 2005, the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP FAS 115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition of Other Than Temporary Impairment upon the Planned Sale of a Security Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when the impairment is deemed other than temporary, even if a decision to sell has not been made, and (3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after September 15, 2005. The FASB expects to issue this FSP in the fourth quarter of 2005, which would require prospective application for reporting periods beginning after December 15, 2005. JCP&L is currently evaluating this FSP and any impact on its investments.


140

 

METROPOLITAN EDISON COMPANY
 
                   
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
 
(Unaudited)
 
                   
   
Three Months Ended
 
Nine Months Ended
 
   
September 30,
 
September 30,
 
   
2005
 
2004
 
2005
 
2004
 
   
(In thousands)
 
                   
OPERATING REVENUES
 
$
333,180
 
$
285,419
 
$
892,097
 
$
788,361
 
                           
OPERATING EXPENSES AND TAXES:
                         
Purchased power
   
186,148
   
146,938
   
467,911
   
421,660
 
Other operating costs
   
81,774
   
50,141
   
192,892
   
130,210
 
Provision for depreciation
   
9,323
   
10,648
   
32,221
   
30,370
 
Amortization of regulatory assets
   
32,853
   
30,291
   
86,760
   
78,737
 
General taxes
   
19,906
   
18,680
   
56,201
   
53,103
 
Income taxes
   
(2,111
)
 
8,448
   
9,754
   
17,179
 
Total operating expenses and taxes 
   
327,893
   
265,146
   
845,739
   
731,259
 
                           
OPERATING INCOME
   
5,287
   
20,273
   
46,358
   
57,102
 
                           
OTHER INCOME (net of income taxes)
   
6,459
   
6,888
   
19,897
   
18,530
 
                           
NET INTEREST CHARGES:
                         
Interest on long-term debt
   
8,941
   
8,823
   
27,886
   
31,208
 
Allowance for borrowed funds used during construction
   
(150
)
 
(65
)
 
(401
)
 
(208
)
Other interest expense
   
1,950
   
1,326
   
5,626
   
2,846
 
Net interest charges 
   
10,741
   
10,084
   
33,111
   
33,846
 
                           
NET INCOME
   
1,005
   
17,077
   
33,144
   
41,786
 
                           
OTHER COMPREHENSIVE INCOME (LOSS):
                         
Unrealized gain (loss) on derivative hedges
   
84
   
84
   
252
   
(3,182
)
Unrealized gain (loss) on available for sale securities
   
67
   
-
   
67
   
(53
)
Other comprehensive income (loss) 
   
151
   
84
   
319
   
(3,235
)
Income tax expense (benefit) related to other comprehensive income
   
62
   
(1,314
)
 
132
   
(1,342
)
Other comprehensive income (loss), net of tax 
   
89
   
1,398
   
187
   
(1,893
)
                           
TOTAL COMPREHENSIVE INCOME
 
$
1,094
 
$
18,475
 
$
33,331
 
$
39,893
 
                           
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these statements.
   
 
                         
 
 
141

 

METROPOLITAN EDISON COMPANY
 
           
CONSOLIDATED BALANCE SHEETS
 
(Unaudited)
 
           
   
September 30,
 
December 31,
 
   
2005
 
2004
 
   
(In thousands) 
 
ASSETS
         
UTILITY PLANT:
         
In service
 
$
1,841,450
 
$
1,800,569
 
Less - Accumulated provision for depreciation
   
712,549
   
709,895
 
     
1,128,901
   
1,090,674
 
Construction work in progress
   
7,458
   
21,735
 
     
1,136,359
   
1,112,409
 
OTHER PROPERTY AND INVESTMENTS:
             
Nuclear plant decommissioning trusts
   
229,437
   
216,951
 
Long-term notes receivable from associated companies
   
11,162
   
10,453
 
Other
   
29,355
   
34,767
 
     
269,954
   
262,171
 
CURRENT ASSETS:
             
Cash and cash equivalents
   
120
   
120
 
Notes receivable from associated companies
   
15,793
   
18,769
 
Receivables -
             
Customers (less accumulated provisions of $4,320,000 and $4,578,000,
             
respectively, for uncollectible accounts) 
   
131,213
   
119,858
 
Associated companies
   
1,401
   
118,245
 
Other
   
7,684
   
15,493
 
Prepayments and other
   
13,285
   
11,057
 
     
169,496
   
283,542
 
DEFERRED CHARGES:
             
Goodwill
   
867,649
   
869,585
 
Regulatory assets
   
571,745
   
693,133
 
Other
   
24,055
   
24,438
 
     
1,463,449
   
1,587,156
 
   
$
3,039,258
 
$
3,245,278
 
CAPITALIZATION AND LIABILITIES
             
CAPITALIZATION:
             
Common stockholder's equity -
             
Common stock, without par value, authorized 900,000 shares -
             
859,500 shares outstanding 
 
$
1,290,296
 
$
1,289,943
 
Accumulated other comprehensive loss
   
(43,303
)
 
(43,490
)
Retained earnings
   
28,110
   
38,966
 
Total common stockholder's equity 
   
1,275,103
   
1,285,419
 
Long-term debt and other long-term obligations
   
594,116
   
701,736
 
     
1,869,219
   
1,987,155
 
CURRENT LIABILITIES:
             
Currently payable long-term debt
   
100,000
   
30,435
 
Short-term borrowings -
             
Associated companies
   
76,755
   
80,090
 
Other
   
-
   
-
 
Accounts payable -
             
Associated companies
   
39,505
   
88,879
 
Other
   
30,966
   
26,097
 
Accrued taxes
   
2,247
   
11,957
 
Accrued interest
   
9,462
   
11,618
 
Other
   
20,008
   
23,076
 
     
278,943
   
272,152
 
NONCURRENT LIABILITIES:
             
Accumulated deferred income taxes
   
309,979
   
305,389
 
Accumulated deferred investment tax credits
   
10,250
   
10,868
 
Power purchase contract loss liability
   
250,024
   
349,980
 
Asset retirement obligation
   
139,216
   
132,887
 
Retirement benefits
   
77,501
   
82,218
 
Nuclear fuel disposal costs
   
39,213
   
38,408
 
Other
   
64,913
   
66,221
 
     
891,096
   
985,971
 
COMMITMENTS AND CONTINGENCIES (Note 13)
             
   
$
3,039,258
 
$
3,245,278
 
               
               
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these balance sheets.  
 
 
             
               
 
 
142

 

METROPOLITAN EDISON COMPANY
 
                   
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(Unaudited)
 
                   
   
Three Months Ended
 
Nine Months Ended
 
   
September 30,
 
September 30,
 
   
2005
 
2004
 
2005
 
2004
 
   
(In thousands)
 
                   
CASH FLOWS FROM OPERATING ACTIVITIES:
                 
Net income
 
$
1,005
 
$
17,077
 
$
33,144
 
$
41,786
 
Adjustments to reconcile net income to net cash from
                         
operating activities -
                         
Provision for depreciation 
   
9,323
   
10,648
   
32,221
   
30,370
 
Amortization of regulatory assets 
   
32,853
   
30,291
   
86,760
   
78,737
 
Deferred costs recoverable as regulatory assets 
   
8,521
   
(15,629
)
 
(21,491
)
 
(45,616
)
Deferred income taxes and investment tax credits, net 
   
(8,438
)
 
666
   
(10,336
)
 
(4,853
)
Accrued retirement benefit obligation 
   
(1,514
)
 
(273
)
 
(4,717
)
 
492
 
Accrued compensation, net 
   
1,527
   
649
   
211
   
201
 
Pension trust contribution 
   
-
   
(38,823
)
 
-
   
(38,823
)
Decrease (increase) in operating assets - 
                       
    Receivables
   
3,088
   
(2,599
)
 
113,298
   
29,943
 
    Materials and supplies
   
(1
)
 
5
   
(19
)
 
41
 
    Prepayments and other current assets
   
18,978
   
14,298
   
(2,209
)
 
(15,027
)
Increase (decrease) in operating liabilities - 
                       
    Accounts payable
   
6,088
   
(12,536
)
 
(44,505
)
 
(17,857
)
    Accrued taxes
   
(4,526
)
 
(145
)
 
(9,710
)
 
(6,255
)
    Accrued interest
   
(1,269
)
 
(3,006
)
 
(2,156
)
 
(127
)
Other 
   
(7,701
)
 
(7,356
)
 
(24,063
)
 
(9,581
)
    Net cash provided from (used for) operating activities
   
57,934
   
(6,733
)
 
146,428
   
43,431
 
                           
CASH FLOWS FROM FINANCING ACTIVITIES:
                         
New Financing-
                         
Long-term debt 
   
-
   
-
   
-
   
247,607
 
Short-term borrowings, net 
   
-
   
70,000
   
-
   
4,665
 
Redemptions and Repayments-
                         
Long-term debt 
   
-
   
(45,936
)
 
(37,830
)
 
(196,371
)
Short-term borrowings, net 
   
(24,266
)
 
-
   
(3,335
)
 
-
 
Dividend Payments-
                       
Common stock 
   
(10,000
)
 
(10,000
)
 
(44,000
)
 
(35,000
)
  Net cash provided from (used for) financing activities
   
(34,266
)
 
14,064
   
(85,165
)
 
20,901
 
                           
CASH FLOWS FROM INVESTING ACTIVITIES:
                         
Property additions
   
(21,680
)
 
(12,390
)
 
(56,075
)
 
(33,733
)
Contributions to nuclear decommissioning trusts
   
(2,370
)
 
(2,371
)
 
(7,112
)
 
(7,113
)
Loan repayments from (loans to) associated companies, net
   
(1,072
)
 
17,989
   
2,267
   
(13,046
)
Other
   
1,454
   
(10,559
)
 
(343
)
 
(10,441
)
 Net cash provided used for investing activities
   
(23,668
)
 
(7,331
)
 
(61,263
)
 
(64,333
)
                           
Net change in cash and cash equivalents
   
-
   
-
   
-
   
(1
)
Cash and cash equivalents at beginning of period
   
120
   
120
   
120
   
121
 
Cash and cash equivalents at end of period
 
$
120
 
$
120
 
$
120
 
$
120
 
 
                         
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these statements.
 
 
 
 
143


Report of Independent Registered Public Accounting Firm









To the Stockholders and Board of
Directors of Metropolitan Edison Company:

We have reviewed the accompanying consolidated balance sheet of Metropolitan Edison Company and its subsidiaries as of September 30, 2005, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and nine-month periods ended September 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2004, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 2(G) to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 6 to those consolidated financial statements) dated March 7, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.




PricewaterhouseCoopers LLP
Cleveland, Ohio
November 1, 2005



 
144

 

METROPOLITAN EDISON COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION


Met-Ed is a wholly owned, electric utility subsidiary of FirstEnergy. Met-Ed conducts business in eastern Pennsylvania, providing regulated electric transmission and distribution services. Met-Ed also provides generation service to those customers electing to retain Met-Ed as their power supplier. Met-Ed has unbundled the price for electricity into its component elements - including generation, transmission, distribution and transition charges. Met-Ed continues to deliver power to homes and businesses through its existing distribution system.

Results of Operations

Net income decreased to $1 million for the third quarter of 2005 from $17 million in the third quarter of 2004. The decrease in net income primarily resulted from higher purchased power costs, transmission expenses, and amortization of regulatory assets, partially offset by higher operating revenues and lower depreciation and income taxes. For the first nine months of 2005, net income decreased to $33 million from $42 million in the same period of 2004. The decrease in net income primarily resulted from higher purchased power costs, transmission expenses, and amortization of regulatory assets, partially offset by higher operating revenues and other income and lower income taxes as discussed below.

Operating revenues increased by $48 million, or 16.7%, in the third quarter of 2005 and $104 million, or 13.2%, in the first nine months of 2005, compared with the same periods of 2004. Increases in both periods were due, in part, to higher retail generation electric revenues from all customer sectors ($17 million for the third quarter and $41 million for the first nine months of 2005). The increases in retail generation KWH sales for both periods of 2005 were mainly attributable to warmer weather and reduced customer shopping - primarily in the industrial sector. Industrial customer shopping decreased by 4.9% and 11.2% percentage points in the third quarter and first nine months of 2005, respectively. While higher generation sales in the third quarter of 2005 were offset by slightly lower composite unit prices, overall higher composite unit prices during the nine-month period also contributed to the increase in generation revenues.

Revenues from distribution throughput increased by $13 million in the third quarter and by $23 million in the first nine months of 2005 compared with the same periods of 2004. Increases in both periods of 2005 were primarily due to higher KWH deliveries and slightly higher unit prices. Increased transmission revenues of $17 million in the third quarter and $32 million in the first nine months of 2005 also contributed to higher operating revenues. These increases were due to a change in the power supply agreement with FES in the second quarter of 2004. This change also resulted in higher transmission expenses as discussed further below. In the first nine months of 2005, operating revenues also included a $4 million payment received under a contract provision associated with the prior sale of TMI Unit 1. Under the contract, additional payments are received if subsequent energy prices rise above specific levels and are credited to Met-Ed’s customers, resulting in no net impact to earnings.

Changes in KWH sales by customer class in the three months and nine months ended September 30, 2005 compared to the same periods of 2004 are summarized in the following table:

 
 
 
Three
 
Nine
 
Changes in KWH Sales
 
Months
 
Months
 
Increase (Decrease)
 
 
 
 
 
Retail Electric Generation:
 
 
 
 
 
Residential
 
 
15.5
%
 
7.6
%
Commercial
 
 
10.1
%
 
7.6
%
Industrial
 
 
9.1
%
 
17.0
%
Total Retail Electric Generation Sales
 
 
11.9
%
 
9.9
%
           
Distribution Deliveries:
 
 
 
 
 
Residential
 
 
15.5
%
 
7.5
%
Commercial
 
 
10.0
%
 
6.7
%
Industrial
 
 
3.2
%
 
1.9
%
Total Distribution Deliveries
 
 
10.0
%
 
5.6
%
 
 
 
 
 
 
 
 

 
145

 

Operating Expenses and Taxes

Total operating expenses and taxes increased by $63 million in the third quarter and by $114 million in the first nine months of 2005 compared with the same periods of 2004. The following table presents changes from the prior year by expense category:

   
Three
 
Nine
 
Operating Expenses and Taxes - Changes
 
Months
 
Months
 
 
 
(In millions)
 
Increase (Decrease)
             
Purchased power costs
 
$
39
 
$
46
 
Other operating costs
 
 
32
 
 
62
 
Provision for depreciation
 
 
(1
)
 
2
 
Amortization of regulatory assets
 
 
3
 
 
8
 
General taxes
   
1
   
3
 
Income taxes
   
(11
)  
(7
Net increase in operating expenses and taxes
 
$
63
 
$
114
 
 
 
 
 
 
 
 
 


Purchased power costs increased by $39 million in the third quarter and $46 million in the first nine months of 2005 compared with the same periods of 2004. The increases in both periods were primarily due to increased third party power purchases ($47 million in the third quarter and $92 million in the first nine months of 2005) and NUG contract purchases ($21 million in the third quarter and $29 million in the first nine months of 2005) partially offset by reduced purchased power from FES ($30 million in the third quarter and $77 million in the first nine months of 2005). These changes, for both periods, were due to increased KWH purchased to meet increased retail generation sales requirements offset by slightly lower unit costs.

Other operating costs increased by $32 million in the third quarter and by $62 million in first nine months of 2005 compared with the same periods of 2004. The increases in both periods were primarily caused by higher PJM congestion charges and transmission expenses as a result of the change in the power supply agreement with FES discussed above.

In the first nine months of 2005, depreciation expense increased due to additions to the asset base and higher costs to decommission the Saxton nuclear plant as compared to the same period of 2004. For both periods of 2005, regulatory asset amortization reflected increases associated with the level of CTC revenue recovery, partially offset by lower amortization related to above market NUG costs as compared to the prior year periods.

General taxes increased in both periods primarily as a result of higher gross receipt taxes associated with the increase in KWH sales. Income taxes decreased in the third quarter and first nine months of 2005 due to lower taxable income.

Capital Resources and Liquidity

Met-Ed’s cash requirements for the remainder of 2005, for operating expenses, construction expenditures and scheduled debt maturities are expected to be met with cash from operations.

Changes in Cash Position

As of September 30, 2005, Met-Ed’s cash and cash equivalents of $120,000 remained unchanged from December 31, 2004.
 
146


    Cash Flows From Operating Activities

Cash provided from (used for) operating activities during the third quarter and first nine months of 2005, compared with the corresponding periods of 2004 were as follows:

 
 
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
 Operating Cash Flows
 
2005
 
2004
 
2005
 
2004
 
 
 
(In millions)
 
 
 
 
 
 
 
 
 
 
 
Cash earnings (1)
 
$
43
 
$
27
 
$
116
 
$
85
 
Pension trust contribution (2)
   
-
   
(23
)
 
-
   
(23
)
Working capital and other
 
 
15
 
 
(11
 
30
 
 
(19
Total cash flows from operating activities
 
$
58
 
$
(7
$
146
 
$
43
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) Cash earnings is a non-GAAP measure (see reconciliation below).
 
 
 
 
 
 
 
 
 
 
 
 
 
(2) Pension trust contribution net of $16 million of income tax benefits.
             
 
Cash earnings, as disclosed in the table above, are not a measure of performance calculated in accordance with GAAP. Met-Ed believes that cash earnings is a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income.

 
 
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
 Reconciliation of Cash Earnings
 
2005
 
2004
 
2005
 
2004
 
 
 
(In millions)
 
 
 
 
 
 
 
 
 
 
 
Net income (GAAP)
 
$
1
 
$
17
 
$
33
 
$
42
 
Non-cash charges (credits):
 
 
 
 
 
 
 
 
 
 
 
 
 
Provision for depreciation
 
 
9
 
 
11
 
 
32
 
 
30
 
Amortization of regulatory assets
 
 
33
 
 
30
 
 
87
 
 
79
 
Deferred costs recoverable as regulatory assets
 
 
8
 
 
(16
 
(22
)
 
(46
Deferred income taxes and investment tax credits, net
 
 
(8
)
 
(16
)
 
(10
)
 
(21
Other non-cash charges
 
 
-
 
 
1
 
 
(4
)
 
1
 
Cash earnings (Non-GAAP)
 
$
43
 
$
27
 
$
116
 
$
85
 
                           
 

The $16 million and $31 million increases in cash earnings for the third quarter and first nine months of 2005, respectively, are described above under “Results of Operations”. Net cash from operating activities increased in the third quarter and the first nine months due to the absence of a $23 million after-tax voluntary pension contribution made in the third quarter of 2004. The $26 million change in working capital in the third quarter of 2005 primarily resulted from changes of $6 million in accounts receivable, $19 million in accounts payable and $5 million in prepayments, offset by a change of $4 million in accrued taxes. The $49 million change in working capital for the first nine months of 2005 primarily resulted from net changes in accounts receivable and accounts payable from associated companies of $52 million and $13 million in prepayments, partially offset by changes of $11 million in customer deposits, $3 million in accrued taxes and $2 million in accrued interest.

Cash Flows From Financing Activities

For the third quarter of 2005, net cash used for financing activities was $34 million compared to $14 million of cash provided from financing activities in the third quarter of 2004. The $48 million decrease resulted primarily from a $70 million reduction in new debt financing compared to the third quarter of 2004 offset in part by a $22 million reduction in debt redemptions. For the first nine months of 2005, net cash used for financing activities was $85 million compared to $21 million of net cash provided from financing activities in the same period of 2004. The $106 million change reflected a $252 million reduction in new debt financing and a $9 million increase in common stock dividends to FirstEnergy, partially offset by a $155 million decrease in debt redemptions compared to the same period of 2004.

As of September 30, 2005, Met-Ed had approximately $16 million of cash and temporary investments (including short-term notes receivable from associated companies) and $77 million of short-term borrowings outstanding. Met-Ed has authorization from the SEC to incur short-term debt up to $250 million (including the utility money pool). Under the terms of Met-Ed’s senior note indenture, no more first mortgage bonds can be issued as long as the senior bonds are outstanding. Met-Ed had no restrictions on the issuance of preferred stock.
 
 
147


Met-Ed Funding LLC (Met-Ed Funding), a wholly owned subsidiary of Met-Ed, is a limited liability company whose borrowings are secured by customer accounts receivable purchased from Met-Ed. Met-Ed Funding can borrow up to $80 million under a receivables financing arrangement. As a separate legal entity with separate creditors, Met-Ed Funding would have to satisfy its obligations to creditors before any of its remaining assets could be made available to Met-Ed. On July 15, 2005, the facility was renewed until June 29, 2006. As of September 30, 2005, the facility was undrawn. The annual facility fee is 0.25% on the entire finance limit.

Met-Ed has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pools and tracks surplus funds of FirstEnergy and the respective regulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the third quarter of 2005 was 3.50%.

On June 14, 2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as borrowers, entered into a syndicated $2 billion five-year revolving credit facility. Borrowings under the facility are available to each borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. Met-Ed’s borrowing limit under the facility is $250 million.

Met-Ed’s access to capital markets and costs of financing are dependent on the ratings of its securities and that of FirstEnergy. The ratings outlook from S&P and Fitch on all securities is stable. Moody’s outlook on all securities is positive.

On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in their outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemming from the application of free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.

On October 3, 2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to 'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one notch above the previous rating. S&P noted that the upgrade followed the continuation of a good operating track record, specifically for the nuclear fleet through the third quarter 2005. S&P also stated that FirstEnergy’s rating reflects the benefits of supportive regulation, low-cost base load generation fleet, low-risk transmission and distribution operations and rate certainty in Ohio. FirstEnergy’s ability to consistently generate free cash flow, good liquidity, and an improving financial profile were also noted as strengths.

Cash Flows From Investing Activities

In the third quarter of 2005, net cash used for investing activities totaled $24 million, compared to $7 million in the third quarter of 2004. The change in the third quarter of 2005 primarily resulted from a $19 million increase in loan repayments to associated companies and a $9 million increase in property additions, partially offset by a $9 million capital transfer from FESC in the third quarter of 2004. In the first nine months of 2005, net cash used for investing activities totaled $61 million compared to $64 million in the same period of 2004. The change resulted from a $15 million increase in loan repayments from associated companies and the previously mentioned capital transfer, partially offset by a $22 million increase in property additions. Expenditures for property additions primarily support Met-Ed’s energy delivery operations.

Met-Ed's capital spending for the period 2005 through 2007 is expected to be about $205 million, of which approximately $68 million applies to 2005. In the last quarter of 2005, capital requirements for property additions are expected to be about $14 million. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. Met-Ed has no additional requirements for maturing long-term debt during the remainder of 2005.

Market Risk Information

Met-Ed uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk management activities.

 
148


Commodity Price Risk

Met-Ed is exposed to price risk primarily resulting from fluctuating electricity and natural gas prices. To manage the volatility relating to these exposures, it uses a variety of non-derivative and derivative instruments, including options and futures contracts. The derivatives are used for hedging purposes. Most of Met-Ed's non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. As of September 30, 2005, Met-Ed’s commodity derivative contract was an embedded option with a fair value of $28 million. A $4 million net decrease in the value of this asset was recorded as a decrease in regulatory liabilities, and therefore, had no impact on net income.

The valuation of derivative commodity contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, Met-Ed relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Met-Ed uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of derivative contracts as of September 30, 2005 are summarized by year in the following table:

Sources of Information -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value by Contract Year
 
 
 
2005(1)
 
2006
 
2007
 
2008
 
2009
 
Thereafter
 
Total
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prices based on external sources(2)
 
 
 
 
$
5
 
$
5
 
$
5
 
$
-
 
$
-
 
$
-
 
$
15
 
Prices based on models
 
 
 
 
 
-
 
 
-
 
 
-
 
 
5
 
 
4
 
 
4
 
 
13
 
Total
 
 
 
 
$
5
 
$
5
 
$
5
 
$
5
 
$
4
 
$
4
 
$
28
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) For the last quarter of 2005.
(2) Broker quote sheets.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


Met-Ed performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on derivative instruments would not have had a material effect on its consolidated financial position or cash flows as of September 30, 2005.

Equity Price Risk

Included in Met-Ed's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $138 million as of September 30, 2005 and $134 million as of December 31, 2004. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $14 million reduction in fair value as of September 30, 2005.

Regulatory Matters
 
Regulatory assets are costs which have been authorized by the PPUC and the FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. Met-Ed's regulatory assets as of September 30, 2005 and December 31, 2004 were $572 million and $693 million, respectively.

In accordance with PPUC directives, Met-Ed and Penelec have been negotiating with interested parties in an attempt to resolve the merger savings issues that are the subject of remand from the Commonwealth Court. Met-Ed’s and Penelec’s combined portion of total merger savings is estimated to be approximately $31.5 million. On April 13, 2005, the Commonwealth Court issued an interim order in the remand proceeding that the parties should report the status of the negotiations to the PPUC with a copy to the ALJ. The parties exchanged settlement proposals in May and June 2005 and continue to have settlement discussions.

In an October 16, 2003 order, the PPUC approved September 30, 2004 as the date for Met-Ed's and Penelec's NUG trust fund refunds. The PPUC order also denied their accounting treatment request regarding the CTC rate/shopping credit swap by requiring Met-Ed and Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. On October 22, 2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court asking that the Court reverse this PPUC finding; a Commonwealth Court judge subsequently denied their Objection on October 27, 2003 without explanation. On October 31, 2003, Met-Ed and Penelec filed an Application for Clarification of the Court order with the judge, a Petition for Review of the PPUC's October 2 and October 16, 2003 Orders, and an application for reargument, if the judge, in his clarification order, indicates that Met-Ed's and Penelec's Objection was intended to be denied on the merits. The Reargument Brief before the Commonwealth Court was filed on January 28, 2005.
 
 
149

 

Met-Ed purchases a portion of its PLR requirements from FES through a wholesale power sales agreement. The PLR sale is automatically extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. Under the terms of the wholesale agreement, FES retains the supply obligation and the supply profit and loss risk, for the portion of power supply requirements not self-supplied by Met-Ed under its NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Met-Ed's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR energy costs during the term of the agreement with FES. Met-Ed is authorized to defer differences between NUG contract costs and current market prices. On November 1, 2005, FES and the other parties to the wholesale power agreement amended the agreement to provide FES the right over the next year to terminate the agreement at any time upon 60 days notice. If the wholesale power agreement were terminated, Met-Ed and Penelec would need to satisfy the applicable portion of their PLR obligations from other sources at prevailing prices, which are likely to be higher than the current price charged by FES under the agreement and, as a result, Met-Ed’s and Penelec’s purchased power costs could materially increase.

On January 12, 2005, Met-Ed filed a request with the PPUC for deferral of transmission-related costs beginning January 1, 2005, estimated to be approximately $4 million per month. The OCA, OSBA, OTS, MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric Association have all intervened in the case. To date no hearing schedule has been established, and Met-Ed has not yet implemented deferral accounting for these costs.

On January 31, 2005, certain PJM transmission owners made three filings pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to referral and hearing procedures. On June 30, 2005, the PJM transmission owners filed a request for rehearing of the May 31, 2005 order. The rate design and formula rate filings continue to be litigated before the FERC. The outcome of these two cases cannot be predicted.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Pennsylvania including a more detailed discussion of reliability initiatives, including actions by the PPUC, that impact Met-Ed.

Environmental Matters

Met-Ed accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in Met-Ed’s determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

Met-Ed has been named as a PRP at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of September 30, 2005, based on estimates of the total costs of cleanup, Met-Ed’s proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay.

FirstEnergy plans to issue a report regarding its response to air emission requirements. FirstEnergy expects to complete the report by December 1, 2005.

See Note 13(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to Met-Ed's normal business operations pending against Met-Ed. The other material items not otherwise discussed above are described below.


 
150

 

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concludes, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of September 30, 2005 for any expenditures in excess of those actually incurred through that date. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

One complaint was filed on August 25, 2004 against FirstEnergy in the New York State Supreme Court. In this case, several plaintiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. FirstEnergy's motion to dismiss the case was granted on September 26, 2005. Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter is not due until on or about December 1, 2005. No estimate of potential liability has been undertaken in this matter.

FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. In particular, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

See Note 13(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

New Accounting Standards and Interpretations

EITF Issue 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty"
 
In September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus that an exchange of inventory should be accounted for at fair value. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and other storable inventory. Therefore, Met-Ed will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006.

151

 

 
EITF Issue No. 05-6, "Determining the Amortization Period for Leasehold Improvements Purchased after Lease Inception or Acquired in a Business Combination"
 
In June 2005, the EITF reached a consensus on the application guidance for Issue 05-6. EITF 05-6 addresses the amortization period for leasehold improvements that were either acquired in a business combination or placed in service significantly after and not contemplated at or near the beginning of the initial lease term. For leasehold improvements acquired in a business combination, the amortization period is the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date of acquisition. Leasehold improvements that are placed in service significantly after and not contemplated at or near the beginning of the lease term should be amortized over the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date the leasehold improvements are purchased. This EITF was effective July 1, 2005 and is consistent with Met-Ed's current accounting.

FIN 47, “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective for Met-Ed in the fourth quarter of 2005. Met-Ed is currently evaluating the effect this Interpretation will have on its financial statements.

 
SFAS 154 - “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3”

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in the Consolidated Statements of Income. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. Met-Ed will adopt this Statement effective January 1, 2006.

 
SFAS 153, “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29”

In December 2004, the FASB issued SFAS 153 amending APB 29, which was based on the principle that nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB 29 included certain exceptions to that principle. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement are effective January 1, 2006 for Met-Ed. This FSP is not expected to have a material impact on Met-Ed's financial statements.

SFAS 151, “Inventory Costs - an amendment of ARB No. 43, Chapter 4”

In November 2004, the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Previous guidance stated that in some circumstances these costs may be “so abnormal” that they would require treatment as current period costs. SFAS 151 requires abnormal amounts for these items to always be recorded as current period costs. In addition, this Statement requires that allocation of fixed production overheads to the cost of conversion be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred by Met-Ed beginning January 1, 2006. Met-Ed is currently evaluating this Standard and does not expect it to have a material impact on the financial statements.

 
152


FSP FAS 115-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

In September 2005, the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP FAS 115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition of Other Than Temporary Impairment upon the Planned Sale of a Security Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when the impairment is deemed other than temporary, even if a decision to sell has not been made, and (3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after September 15, 2005. The FASB expects to issue this FSP in the fourth quarter of 2005, which would require prospective application with an effective date for reporting periods beginning after December 15, 2005. Met-Ed is currently evaluating this FSP and any impact on its investments.
 

153

 

PENNSYLVANIA ELECTRIC COMPANY
 
                   
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
 
(Unaudited)
 
                   
   
Three Months Ended
 
Nine Months Ended
 
   
September 30,
 
September 30,
 
   
2005
 
2004
 
2005
 
2004
 
   
(In thousands)
 
                   
OPERATING REVENUES
 
$
290,451
 
$
254,339
 
$
846,477
 
$
752,986
 
                           
OPERATING EXPENSES AND TAXES:
                         
Purchased power
   
178,090
   
137,146
   
467,639
   
432,974
 
Other operating costs
   
66,417
   
37,100
   
183,024
   
122,988
 
Provision for depreciation
   
12,736
   
12,281
   
37,721
   
35,229
 
Amortization of regulatory assets
   
12,627
   
11,759
   
38,930
   
39,130
 
General taxes
   
17,552
   
16,913
   
51,892
   
50,795
 
Income taxes
   
(3,101
)
 
11,693
   
14,991
   
16,000
 
Total operating expenses and taxes 
   
284,321
   
226,892
   
794,197
   
697,116
 
                           
OPERATING INCOME
   
6,130
   
27,447
   
52,280
   
55,870
 
                           
OTHER INCOME (net of income taxes)
   
1,057
   
1,300
   
1,477
   
1,663
 
                           
NET INTEREST CHARGES:
                         
Interest on long-term debt
   
7,305
   
7,513
   
22,187
   
22,528
 
Allowance for borrowed funds used during construction
   
(285
)
 
(60
)
 
(674
)
 
(192
)
Deferred interest
   
-
   
-
   
-
   
190
 
Other interest expense
   
2,536
   
3,058
   
7,392
   
8,063
 
Net interest charges 
   
9,556
   
10,511
   
28,905
   
30,589
 
                           
NET INCOME (LOSS)
   
(2,369
)
 
18,236
   
24,852
   
26,944
 
                           
OTHER COMPREHENSIVE INCOME (LOSS):
                         
Unrealized gain (loss) on derivative hedges
   
17
   
17
   
49
   
(618
)
Unrealized gain (loss) on available for sale securities
   
18
   
7
   
(3
)
 
(3
)
Other comprehensive income (loss) 
   
35
   
24
   
46
   
(621
)
Income tax expense (benefit) related to other comprehensive income
   
20
   
(256
)
 
20
   
(258
)
Other comprehensive income (loss), net of tax 
   
15
   
280
   
26
   
(363
)
                           
TOTAL COMPREHENSIVE INCOME (LOSS)
 
$
(2,354
)
$
18,516
 
$
24,878
 
$
26,581
 
                           
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these statements.
   
 
                         
 
 
154

 

PENNSYLVANIA ELECTRIC COMPANY
 
           
CONSOLIDATED BALANCE SHEETS
 
(Unaudited)
 
   
September 30,
 
December 31,
 
   
2005
 
2004
 
   
(In thousands)  
 
ASSETS
         
UTILITY PLANT:
         
In service
 
$
2,004,891
 
$
1,981,846
 
Less - Accumulated provision for depreciation
   
772,818
   
776,904
 
     
1,232,073
   
1,204,942
 
Construction work in progress
   
23,622
   
22,816
 
     
1,255,695
   
1,227,758
 
OTHER PROPERTY AND INVESTMENTS:
             
Nuclear plant decommissioning trusts
   
111,826
   
109,620
 
Non-utility generation trusts
   
97,473
   
95,991
 
Long-term notes receivable from associated companies
   
15,629
   
14,001
 
Other
   
14,855
   
18,746
 
     
239,783
   
238,358
 
CURRENT ASSETS:
             
Cash and cash equivalents
   
35
   
36
 
Notes receivable from associated companies
   
-
   
7,352
 
Receivables -
             
Customers (less accumulated provisions of $4,095,000 and $4,712,000,
             
respectively, for uncollectible accounts) 
   
120,580
   
121,112
 
Associated companies
   
6,339
   
97,528
 
Other
   
7,369
   
12,778
 
Prepayments and other
   
15,818
   
7,198
 
     
150,141
   
246,004
 
DEFERRED CHARGES:
             
Goodwill
   
886,559
   
888,011
 
Regulatory assets
   
99,491
   
200,173
 
Other
   
13,234
   
13,448
 
     
999,284
   
1,101,632
 
   
$
2,644,903
 
$
2,813,752
 
CAPITALIZATION AND LIABILITIES
             
CAPITALIZATION:
             
Common stockholder's equity-
             
Common stock, $20 par value, authorized 5,400,000 shares -
             
5,290,596 shares outstanding 
 
$
105,812
 
$
105,812
 
Other paid-in capital
   
1,206,358
   
1,205,948
 
Accumulated other comprehensive loss
   
(52,787
)
 
(52,813
)
Retained earnings
   
38,920
   
46,068
 
Total common stockholder's equity 
   
1,298,303
   
1,305,015
 
Long-term debt and other long-term obligations
   
478,954
   
481,871
 
     
1,777,257
   
1,786,886
 
CURRENT LIABILITIES:
             
Currently payable long-term debt
   
4
   
8,248
 
Short-term borrowings -
             
Associated companies
   
114,749
   
241,496
 
Other
   
75,000
   
-
 
Accounts payable -
             
Associated companies
   
30,456
   
56,154
 
Other
   
35,987
   
25,960
 
Accrued taxes
   
19,234
   
7,999
 
Accrued interest
   
15,289
   
9,695
 
Other
   
19,264
   
23,750
 
     
309,983
   
373,302
 
NONCURRENT LIABILITIES:
             
Power purchase contract loss liability
   
259,675
   
382,548
 
Retirement benefits
   
121,251
   
118,247
 
Asset retirement obligation
   
69,608
   
66,443
 
Accumulated deferred income taxes
   
56,029
   
37,318
 
Other
   
51,100
   
49,008
 
     
557,663
   
653,564
 
COMMITMENTS AND CONTINGENCIES (Note 13)
             
   
$
2,644,903
 
$
2,813,752
 
               
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these balance sheets.  
     
 
             
 
 
155

 

PENNSYLVANIA ELECTRIC COMPANY
 
   
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(Unaudited)
 
                   
   
Three Months Ended
 
Nine Months Ended
 
   
September 30,
 
September 30,
 
   
2005
 
2004
 
2005
 
2004
 
   
(In thousands)
 
                   
CASH FLOWS FROM OPERATING ACTIVITIES:
                 
Net income (loss)
 
$
(2,369
)
$
18,236
 
$
24,852
 
$
26,944
 
Adjustments to reconcile net income (loss) to net cash from
                         
operating activities -
                         
Provision for depreciation 
   
12,736
   
12,281
   
37,721
   
35,229
 
Amortization of regulatory assets 
   
12,627
   
11,759
   
38,930
   
39,130
 
Deferred costs recoverable as regulatory assets 
   
(5,355
)
 
(25,618
)
 
(41,301
)
 
(62,122
)
Deferred income taxes and investment tax credits, net 
   
(5,412
)
 
28,574
   
(2,765
)
 
30,308
 
Accrued retirement benefit obligations 
   
1,100
   
1,164
   
3,005
   
4,805
 
Accrued compensation, net 
   
691
   
894
   
(1,695
)
 
2,271
 
Pension trust contribution 
   
-
   
(50,281
)
 
-
   
(50,281
)
Decrease (increase) in operating assets - 
                         
    Receivables
   
17,528
   
(17,689
)
 
97,130
   
35,806
 
    Prepayments and other current assets
   
13,487
   
9,703
   
(8,620
)
 
(25,247
)
Increase (decrease) in operating liabilities - 
                         
    Accounts payable
   
4,662
   
(23,255
)
 
(15,671
)
 
(38,015
)
    Accrued taxes
   
507
   
2
   
11,235
   
(7,572
)
    Accrued interest
   
5,628
   
5,605
   
5,594
   
2,856
 
Other 
   
(1,460
)
 
562
   
2,905
   
24,851
 
    Net cash provided from (used for) operating activities
   
54,370
   
(28,063
)
 
151,320
   
18,963
 
                           
CASH FLOWS FROM FINANCING ACTIVITIES:
                         
New Financing -
                         
Long-term debt 
   
-
   
-
   
-
   
150,000
 
Short-term borrowings, net 
   
-
   
158,282
   
-
   
165,918
 
Redemptions and Repayments -
                         
Long-term debt 
   
(8,013
)
 
(103,241
)
 
(11,534
)
 
(228,453
)
Short-term borrowings, net 
   
(15,139
)
 
-
   
(51,747
)
 
-
 
Dividend Payments -
                         
Common stock 
   
(2,000
)
 
(3,000
)
 
(32,000
)
 
(8,000
)
  Net cash provided from (used for) financing activities
   
(25,152
)
 
52,041
   
(95,281
)
 
79,465
 
                           
CASH FLOWS FROM INVESTING ACTIVITIES:
                         
Property additions
   
(27,997
)
 
(10,192
)
 
(61,680
)
 
(33,428
)
Non-utility generation trust contribution
   
-
   
-
   
-
   
(50,614
)
Loan repayments from (loans to) associated companies, net
   
(1,287
)
 
(3,124
)
 
5,724
   
(3,144
)
Other, net
   
66
   
(10,662
)
 
(84
)
 
(11,242
)
 Net cash used for investing activities
   
(29,218
)
 
(23,978
)
 
(56,040
)
 
(98,428
)
                           
Net change in cash and cash equivalents
   
-
   
-
   
(1
)
 
-
 
Cash and cash equivalents at beginning of period
   
35
   
36
   
36
   
36
 
Cash and cash equivalents at end of period
 
$
35
 
$
36
 
$
35
 
$
36
 
 
                         
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these statements.
   
 
                         


156

 

Report of Independent Registered Public Accounting Firm









To the Stockholders and Board of
Directors of Pennsylvania Electric Company:

We have reviewed the accompanying consolidated balance sheet of Pennsylvania Electric Company and its subsidiaries as of September 30, 2005, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and nine-month periods ended September 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2004, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 2(G) to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 6 to those consolidated financial statements) dated March 7, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.




PricewaterhouseCoopers LLP
Cleveland, Ohio
November 1, 2005



157


PENNSYLVANIA ELECTRIC COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION


Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern, western and south central Pennsylvania, providing regulated transmission and distribution services. Penelec also provides generation services to those customers electing to retain Penelec as their power supplier. Penelec has unbundled the price for electricity into its component elements - including generation, transmission, distribution and transition charges.

Results of Operations

Penelec recognized a net loss of $2 million in the third quarter of 2005, compared to $18 million in net income in the third quarter of 2004. During the first nine months of 2005, net income decreased to $25 million compared to $27 million in the first nine months of 2004. The decrease in both periods resulted from higher purchased power and other operating costs, partially offset by higher operating revenues and lower income taxes.

Operating revenues increased by $36 million in the third quarter and $93 million in the first nine months of 2005 compared to the same periods of 2004. Increases in both periods were due to higher retail generation revenues in all sectors ($14 million for the quarter and $23 million for the first nine months). The increases in retail generation KWH sales in both periods of 2005 were mainly due to the warmer weather in 2005 compared to 2004. While the higher generation sales in the third quarter were offset by slightly lower composite unit prices, overall higher composite unit prices - especially in the industrial sector - for the nine-month period further contributed to the increase in generation revenues.

Distribution revenues increased by $4 million in the third quarter and by $6 million in the first nine months of 2005 compared to the same periods of 2004. Increases in both periods were due to higher KWH deliveries partially offset by lower unit prices. Also contributing to higher operating revenues was an increase in transmission revenues of $18 million in the third quarter and $61 million in the first nine months of 2005. These increases were due to a change in the power supply agreement with FES in the second quarter of 2004. This change also resulted in higher transmission expenses as discussed further below.

Changes in KWH sales by customer class in the three months and nine months ended September 30, 2005 from the corresponding periods of 2004 are summarized in the following table:


 
 
Three
 
Nine
 
Changes in KWH Sales
 
Months
 
Months
 
Increase (Decrease)
 
 
 
 
 
Retail Electric Generation:
 
 
 
 
Residential
 
 
8.8
%
 
4.2
%
Commercial
 
 
7.0
%
 
4.3
%
Industrial
 
 
17.0
%
 
7.3
%
Total Retail Electric Generation Sales
 
 
10.2
%
 
5.1
%
           
Distribution Deliveries:
 
 
 
 
 
Residential
 
 
8.7
%
 
4.1
%
Commercial
 
 
6.6
%
 
4.1
%
Industrial
 
 
8.3
%
 
5.2
%
Total Distribution Deliveries
 
 
7.8
%
 
4.5
%
 
 
 
 
 
 
 
 


158


Operating Expenses and Taxes
 
Total operating expenses and taxes increased by $57 million in the third quarter and $97 million in the first nine months of 2005 compared with the same periods in 2004. The following table presents changes from the prior year by expense category:

   
Three
 
Nine
 
Operating Expenses and Taxes - Changes
 
Months
 
Months
 
   
(In millions)
Increase (Decrease)
 
 
 
 
 
Purchased power costs
 
$
41
 
$
35
 
Other operating costs
 
 
29
 
 
60
 
Provision for depreciation
 
 
-
 
 
2
 
Amortization of regulatory assets
 
 
1
 
 
-
 
General taxes
   
1
   
1
 
Income taxes
   
(15
)
 
(1
)
Net increase in operating expenses and taxes
 
$
57
 
$
97
 
 
 
 
 
 
 
 
 


Purchased power costs increased by $41 million or 29.9% in the third quarter and $35 million or 8.0% in the first nine months of 2005 compared to the same periods of 2004. The increase in the third quarter of 2005 is due to increased KWH purchased to meet increased retail generation sales requirements, and higher unit costs. Third-party power purchases and NUG costs increased $48 million and $20 million, respectively, in the third quarter of 2005, partially offset by reduced purchased power from FES of $27 million. The increase in the first nine months is due to increased KWH purchased to meet sales requirements partially offset by lower unit costs. Increases from third-party power purchases and NUG costs of $81 million and $21 million, respectively, in the first nine months of 2005, were partially offset by reduced purchased power from FES of $67 million.

Other operating costs increased by $29 million in the third quarter and $60 million in the first nine months of 2005 compared to same periods in 2004. The increases in both periods were primarily due to increased transmission expenses in 2005 as a result of the change in the power supply agreement with FES referred to above. The increased transmission expenses were partially offset by reduced labor costs that were charged to capital projects. Income taxes decreased in the third quarter of 2005 due to lower pre-tax income compared to the third quarter of 2004.

Capital Resources and Liquidity

Penelec’s cash requirements for the remainder of 2005 for operating expenses, construction expenditures and scheduled debt maturities are expected to be met with cash from operations.

Changes in Cash Position
 
As of September 30, 2005, Penelec had $35,000 of cash and cash equivalents compared with $36,000 as of December 31, 2004. The major sources for changes in these balances are summarized below.

Cash Flows From Operating Activities

Net cash provided from (used for) operating activities in the third quarter and first nine months of 2005, compared with the corresponding periods in 2004, are summarized as follows:

 
 
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
 Operating Cash Flows
 
2005
 
2004
 
2005
 
2004
 
 
 
(In millions)
 
 
 
 
 
 
 
 
 
 
 
Cash earnings (1)
 
$
14
 
$
27
 
$
59
 
$
56
 
Pension trust contribution (2)
   
-
   
(30
)
 
-
   
(30
)
Working capital and other
 
 
40
 
 
(25
 
92
 
 
(7
Total cash flows from operating activities
 
$
54
 
$
(28
$
151
 
$
19
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) Cash earnings is a non-GAAP measure (see reconciliation below).
(2) Pension trust contribution net of $20 million of income tax benefits.

159



Cash earnings, as disclosed in the table above, are not a measure of performance calculated in accordance with GAAP. Penelec believes that cash earnings is a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income.

 
 
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
 Reconciliation of Cash Earnings
 
2005
 
2004
 
2005
 
2004
 
 
 
(In millions)
 
 
 
 
 
 
 
 
 
 
 
Net income (loss) (GAAP)
 
$
(2
$
18
 
$
25
 
$
27
 
Non-cash charges (credits):
 
 
 
 
 
 
 
 
 
 
 
 
 
Provision for depreciation
 
 
13
 
 
12
 
 
38
 
 
35
 
Amortization of regulatory assets
 
 
12
 
 
12
 
 
39
 
 
39
 
Deferred costs recoverable as regulatory assets
 
 
(5
)
 
(26
 
(41
 
(62
)
Deferred income taxes and investment tax credits, net
 
 
(6
 
9
 
 
(3
 
10
 
Other non-cash items
 
 
2
 
 
2
 
 
1
 
 
7
 
Cash earnings (Non-GAAP)
 
$
14
 
$
27
 
$
59
 
$
56
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


Net cash from operating activities increased $82 million in the third quarter of 2005, compared with the third quarter of 2004, due to a $66 million increase from changes in working capital, an absence of a $30 million after-tax voluntary pension contribution made in the third quarter of 2004, and partially offset by a $13 million decrease in cash earnings as described above under “Results of Operations”. The increase in working capital primarily reflects net changes in accounts receivable and accounts payable to associated companies of $42 million and a $22 million increase in purchase power accounts payable.

Net cash from operating activities increased $132 million in the first nine months of 2005, compared with the same period of 2004, due to a $100 million increase from changes in working capital, an absence of the $30 million after-tax voluntary pension contribution, and a $3 million increase in cash earnings as described above under “Results of Operations”. The increase in working capital primarily reflects changes in accounts receivable to associated companies of $61 million, $30 million increase in purchase power and other accounts payable, and $19 million change in accrued taxes, partially offset by changes in customer deposits.

Cash Flows From Financing Activities
 
Net cash used for financing activities was $25 million in the third quarter of 2005 compared to net cash provided from financing activities of $52 million in the third quarter of 2004. The net change reflects a $1 million decrease in common stock dividends to FirstEnergy and a $173 million increase in repayments of short-term borrowings, offset by a $95 million decrease in debt redemptions.

Net cash used for financing activities was $95 million for the first nine months of 2005 compared to net cash provided from financing activities of $79 million in the first nine months of 2004. The net change of $174 million reflects $150 million of long-term debt financing in 2004, a $24 million increase in common stock dividends to FirstEnergy in 2005 and a $218 million increase in repayments of short-term borrowings, offset by a $217 million decrease in debt redemptions.

Penelec had approximately $35,000 of cash and temporary investments (which included short-term notes receivable from associated companies) and approximately $190 million of short-term indebtedness as of September 30, 2005. Penelec has authorization from the SEC to incur short-term debt of up to $250 million (including the utility money pool). Penelec will not issue FMB other than as collateral for senior notes, since its senior note indentures prohibit (subject to certain exceptions) Penelec from issuing any debt which is senior to the senior notes. As of September 30, 2005, Penelec had the capability to issue $18 million of additional senior notes based upon FMB collateral. Penelec has no restrictions on the issuance of preferred stock.

Penelec Funding LLC (Penelec Funding), a wholly owned subsidiary of Penelec, is a limited liability company whose borrowings are secured by customer accounts receivable purchased from Penelec. Penelec Funding can borrow up to $75 million under a receivables financing arrangement. As a separate legal entity with separate creditors, Penelec Funding would have to satisfy its obligations to creditors before any of its remaining assets could be made available to Penelec. On July 15, 2005, the facility was renewed until June 29, 2006. The facility was undrawn as of September 30, 2005. The annual facility fee is 0.25% on the entire finance limit.
 
 
160

 

On June 14, 2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, entered into a syndicated $2 billion five-year revolving credit facility. Borrowings under the facility are available to each Borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. Penelec's borrowing limit under the facility is $250 million.

Penelec has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings under these arrangements in the third quarter of 2005 was 3.5%.

On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in their outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemming from the application of free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.

On October 3, 2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to 'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one notch above the previous rating. S&P noted that the upgrade followed the continuation of a good operating track record, specifically for the nuclear fleet through the third quarter 2005. S&P also stated that FirstEnergy’s rating reflects the benefits of supportive regulation, low-cost base load generation fleet, low-risk transmission and distribution operations and rate certainty in Ohio. FirstEnergy’s ability to consistently generate free cash flow, good liquidity, and an improving financial profile were also noted as strengths.

Penelec’s access to capital markets and costs of financing are influenced by the ratings of its securities and the securities of FirstEnergy. The ratings outlook from S&P and Fitch on all securities is stable. Moody’s outlook on all securities is positive.

Cash Flows From Investing Activities
 
Cash used for investing activities was $29 million in the third quarter of 2005 compared to $24 million in the third quarter of 2004. The increase was primarily due to higher property additions, partially offset by lower loan repayments from associated companies and the absence in 2005 of an $11 million capital transfer from FESC that took place in September 2004. Cash used for investing activities was $56 million in the first nine months of 2005 compared to $98 million in the first nine months of 2004. The decrease was primarily due to a $51 million repayment to the NUG trust fund in 2004, increased loans from associated companies, and the $11 million capital transfer from above, partially offset by higher property additions in 2005. Capital expenditures for property additions primarily support Penelec’s energy delivery operations.

Penelec’s capital spending for the period 2005-2007 is expected to be about $272 million for property additions and improvements, of which about $91 million applies to 2005. In the last quarter of 2005, capital requirements for property additions are expected to be about $26 million. Penelec has no additional requirements for maturing long-term debt during the remainder of 2005. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements.

Market Risk Information
 
Penelec uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk management activities.

Commodity Price Risk

Penelec is exposed to price risk primarily due to fluctuating electricity and natural gas prices. To manage the volatility relating to these exposures, it uses a variety of non-derivative and derivative instruments, including options and futures contracts. The derivatives are used for hedging purposes. Penelec’s non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. As of September 30, 2005, Penelec’s commodity derivatives contract was an embedded option with a fair value of $14 million. A decrease of $1 million in the value of this asset was recorded in the first nine months of 2005 as a decrease in regulatory liabilities, and therefore, had no impact on net income.
 
 
161


The valuation of derivative commodity contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, Penelec relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Penelec uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for valuation of derivative contracts as of September 30, 2005 are summarized by year in the following table:

Sources of Information -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value by Contract Year
 
 
 
2005(1)
 
2006
 
2007
 
2008
 
2009
 
Thereafter
 
Total
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prices based on external sources(2)
 
 
 
 
$
3
 
$
3
 
$
2
 
$
-
 
$
-
 
$
-
 
$
8
 
Prices based on models
 
 
 
 
 
-
 
 
-
 
 
-
 
 
2
 
 
2
 
 
2
 
 
6
 
Total
 
 
 
 
$
3
 
$
3
 
$
2
 
$
2
 
$
2
 
$
2
 
$
14
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1) For the last quarter of 2005.
(2) Broker quote sheets.


Penelec performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on both its trading and nontrading derivative instruments would not have had a material effect on its consolidated financial position or cash flows as of September 30, 2005.

Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $61 million and $60 million as of September 30, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $6 million reduction in fair value as of September 30, 2005.

Regulatory Matters

Regulatory assets are costs which have been authorized by the PPUC and the FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. Penelec's regulatory assets as of September 30, 2005 and December 31, 2004 were $99 million and $200 million, respectively.

In accordance with PPUC directives, Met-Ed and Penelec have been negotiating with interested parties in an attempt to resolve the merger savings issues that are the subject of remand from the Commonwealth Court. Met-Ed’s and Penelec’s combined portion of total merger savings is estimated to be approximately $31.5 million. On April 13, 2005, the Commonwealth Court issued an interim order in the remand proceeding that the parties should report the status of the negotiations to the PPUC with a copy to the ALJ. The parties exchanged settlement proposals in May and June 2005 and continue to have settlement discussions.

In an October 16, 2003 order, the PPUC approved September 30, 2004 as the date for Met-Ed's and Penelec's NUG trust fund refunds. The PPUC order also denied their accounting treatment request regarding the CTC rate/shopping credit swap by requiring Met-Ed and Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. On October 22, 2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court asking that the Court reverse this PPUC finding; a Commonwealth Court judge subsequently denied their Objection on October 27, 2003 without explanation. On October 31, 2003, Met-Ed and Penelec filed an Application for Clarification of the Court order with the judge, a Petition for Review of the PPUC's October 2 and October 16, 2003 Orders, and an application for reargument, if the judge, in his clarification order, indicates that Met-Ed's and Penelec's Objection was intended to be denied on the merits. The Reargument Brief before the Commonwealth Court was filed on January 28, 2005.

Penelec purchases a portion of its PLR requirements from FES through a wholesale power sales agreement. The PLR sale is automatically extended for each successive calendar year unless either party elects to cancel the agreement by November 1 of the preceding year. Under the terms of the wholesale agreement, FES retains the supply obligation and the supply profit and loss risk, for the portion of power supply requirements not self-supplied by Penelec under its NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Penelec's exposure to high wholesale power prices by providing power at a fixed price for its uncommitted PLR energy costs during the term of the agreement with FES. Penelec is authorized to defer differences between NUG contract costs and current market prices. On November 1, 2005, FES and the other parties to the wholesale power agreement amended the agreement to provide FES the right over the next year to terminate the agreement at any time upon 60 days notice. If the wholesale power agreement were terminated, Met-Ed and Penelec would need to satisfy the applicable portion of their PLR obligations from other sources at prevailing prices, which are likely to be higher than the current price charged by FES under the agreement and, as a result, Met-Ed’s and Penelec’s purchased power costs could materially increase.

162


On January 12, 2005, Penelec filed a request with the PPUC to defer transmission-related costs beginning January 1, 2005, estimated to be approximately $4 million per month. The OCA, OSBA, OTS, MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric Association have all intervened in the case. To date no hearing schedule has been established, and Penelec has not yet implemented deferral accounting for these costs.

On January 31, 2005, certain PJM transmission owners made three filings pursuant to a settlement agreement previously approved by the FERC. Penelec was party to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to referral and hearing procedures. On June 30, 2005, the PJM transmission owners filed a request for rehearing of the May 31, 2005 order. The rate design and formula rate filings continue to be litigated before the FERC. The outcome of these two cases cannot be predicted.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Pennsylvania, including a more detailed discussion of reliability initiatives, including actions by the PPUC that impact Penelec.

Environmental Matters

Penelec accrues environmental liabilities when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in Penelec's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

Penelec has been named a PRP at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis.

FirstEnergy plans to issue a report regarding its response to air emission requirements. FirstEnergy expects to complete the report by December 1, 2005.

See Note 13(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to Penelec's normal business operations pending against Penelec. The other material items not otherwise discussed above are described below.

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concludes, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of September 30, 2005 for any expenditures in excess of those actually incurred through that date. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

 
163


One complaint was filed on August 25, 2004 against FirstEnergy in the New York State Supreme Court. In this case, several plaintiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. FirstEnergy's motion to dismiss the case was granted on September 26, 2005. Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter is not due until on or about December 1, 2005. No estimate of potential liability has been undertaken in this matter.

FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. In particular, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

See Note 13(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

New Accounting Standards and Interpretations

EITF Issue 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty"
 
In September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus that an exchange of inventory should be accounted for at fair value. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and other storable inventory. Therefore, Penelec will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006.

 
EITF Issue No. 05-6, "Determining the Amortization Period for Leasehold Improvements Purchased after Lease Inception or Acquired in a Business Combination"
 
In June 2005, the EITF reached a consensus on the application guidance for Issue 05-6. EITF 05-6 addresses the amortization period for leasehold improvements that were either acquired in a business combination or placed in service significantly after and not contemplated at or near the beginning of the initial lease term. For leasehold improvements acquired in a business combination, the amortization period is the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date of acquisition. Leasehold improvements that are placed in service significantly after and not contemplated at or near the beginning of the lease term should be amortized over the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date the leasehold improvements are purchased. This EITF was effective July 1, 2005 and is consistent with Penelec's current accounting.
 
 
164

 

FIN 47, “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective for Penelec in the fourth quarter of 2005. Penelec is currently evaluating the effect this Interpretation will have on its financial statements.

 
SFAS 154 - “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3”

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in the Consolidated Statements of Income. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. Penelec will adopt this Statement effective January 1, 2006.

 
SFAS 153, “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29”

In December 2004, the FASB issued SFAS 153 amending APB 29, which was based on the principle that nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB 29 included certain exceptions to that principle. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement are effective January 1, 2006 for Penelec. This FSP is not expected to have a material impact on Penelec's financial statements.

SFAS 151, “Inventory Costs - an amendment of ARB No. 43, Chapter 4”

In November 2004, the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Previous guidance stated that in some circumstances these costs may be “so abnormal” that they would require treatment as current period costs. SFAS 151 requires abnormal amounts for these items to always be recorded as current period costs. In addition, this Statement requires that allocation of fixed production overheads to the cost of conversion be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred by Penelec beginning January 1, 2006. Penelec is currently evaluating this Standard and does not expect it to have a material impact on the financial statements.

 
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FSP FAS 115-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

In September 2005, the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP FAS 115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition of Other Than Temporary Impairment upon the Planned Sale of a Security Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when the impairment is deemed other than temporary, even if a decision to sell has not been made, and (3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after September 15, 2005. The FASB expects to issue this FSP in the fourth quarter of 2005, which would require prospective application with an effective date for reporting periods beginning after December 15, 2005. Penelec is currently evaluating this FSP and any impact on its investments.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Management’s Discussion and Analysis of Results of Operation and Financial Condition - Market Risk Information” in Item 2 above.

ITEM 4. CONTROLS AND PROCEDURES

(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
 
The applicable registrant's chief executive officer and chief financial officer have reviewed and evaluated the registrant's disclosure controls and procedures, as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e), as of the end of the date covered by the report. Based on that evaluation, those officers have concluded that the registrant's disclosure controls and procedures are effective in timely alerting them to any information relating to the registrants and their consolidated subsidiaries that is required to be included in the registrants’ periodic reports and in ensuring that information required in the reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time period specified by the SEC's rules and forms.

(b) CHANGES IN INTERNAL CONTROLS

During the quarter ended September 30, 2005, there were no changes in the registrants' internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrants' internal control over financial reporting.


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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS
 
Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 13 and 14 to the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
 
ITEM 2. CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY SECURITIES

(e) FirstEnergy

The table below includes information on a monthly basis regarding purchases made by FirstEnergy of its common stock.

               
Maximum Number
 
               
(or Approximate
 
           
Total Number of
 
Dollar Value) of
 
           
Shares Purchased
 
Shares that May
 
   
Total Number
     
As Part of Publicly
 
Yet Be Purchased
 
   
of Shares
 
Average Price
 
Announced Plans
 
Under the Plans
 
Period
 
Purchased (a)
 
Paid per Share
 
or Programs (b)
 
or Programs
 
                   
July 1-31, 2005
   
219,344
 
$
49.40
   
-
   
-
 
August 1-31, 2005
   
698,858
 
$
49.46
   
-
   
-
 
September 1-30, 2005
   
489,705
 
$
51.69
   
-
   
-
 
                           
Third quarter 2005
   
1,407,907
 
$
50.23
   
-
   
-
 

 
(a)
Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver common stock under its Executive and Director Incentive Compensation Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes upon exercise of stock options granted under the Executive and Director Incentive Compensation Plan.

(b)
FirstEnergy does not currently have any publicly announced plan or program for share purchases.
 

ITEM 5. OTHER INFORMATION 

    On November 1, 2005, the Restated Partial Requirements Agreement, dated as of January 1, 2003, as amended August 29, 2003 and June 8, 2004 (as so amended, the “Agreement”), among FES, Met-Ed, Penelec and Waverly was amended by the parties to provide FES the right over the next year to terminate the Agreement at any time upon 60 days written notice. Otherwise, the agreement remains automatically extended as to each operating company for each successive calendar year unless FES or such operating company elects to cancel the agreement by November 1 of the preceding year.

    Under the Agreement, Met-Ed and Penelec currently purchase a portion of their PLR requirements from FES at fixed prices. The remainder of PLR requirements are currently sourced from existing NUG contracts or other power contracts with non-affiliated third party suppliers. If the Agreement were terminated, Met-Ed and Penelec would need to satisfy the applicable portion of their PLR obligations from other sources at prevailing prices, which are likely to be higher than the current price charged by FES under the Agreement, and as a result, Met-Ed’s and Penelec’s purchased power costs could materially increase.

    Met-Ed, Penelec and FES are all wholly owned subsidiaries of FirstEnergy and Waverly is a wholly owned subsidiary of Penelec. A copy of the November 1, 2005 amendment is filed as Exhibit 10.1 to this Quarterly Report on Form 10-Q.
 
ITEM 6. EXHIBITS

(a) Exhibits

Exhibit
 
Number
 
     
JCP&L
 
     
 
12
Fixed charge ratios
 
31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
 
31.3
Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
 
32.2
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.
     
Met-Ed
 
     
  10.1 Notice of Termination Tolling Agreement, Restated Partial Requirements Agreement
 
12
Fixed charge ratios
 
31.1
Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
 
31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
 
32.1
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.
   
Penelec
 
     
  10.1     Notice of Termination Tolling Agreement, Restated Partial Requirements Agreement
 
12
Fixed charge ratios
 
15
Letter from independent registered public accounting firm
 
31.1
Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
 
31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
 
32.1
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.

168



FirstEnergy
 
     
  10.1 Notice of Termination Tolling Agreement, Restated Partial Requirements Agreement
 
10.2
Agreement by and between FirstEnergy Generation Corp. and Bechtel Power Corporation dated August 26, 2005.*
 
15
Letter from independent registered public accounting firm
 
31.1
Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
 
31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
 
32.1
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.
     
OE
 
     
 
15
Letter from independent registered public accounting firm
 
31.1
Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
 
31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
 
32.1
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.
     
Penn
 
     
 
15
Letter from independent registered public accounting firm.
 
31.1
Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
 
31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
 
32.1
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.
     
CEI
 
     
 
31.1
Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
 
31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
 
32.1
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.
     
TE
 
     
 
31.1
Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
 
31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
 
32.1
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.
 

* Confidential Treatment has been requested with respect to certain portions of this exhibit. Omitted portions have been filed separately with the Securities and Exchange Commission.

Pursuant to reporting requirements of respective financings, JCP&L, Met-Ed and Penelec are required to file fixed charge ratios as an exhibit to this Form 10-Q. FirstEnergy, OE, CEI, TE and Penn do not have similar financing reporting requirements and have not filed their respective fixed charge ratios.

Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy, OE, CEI, TE, Penn, JCP&L, Met-Ed nor Penelec have filed as an exhibit to this Form 10-Q any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of their respective total assets of FirstEnergy and its subsidiaries on a consolidated basis, or respectively, OE, CEI, TE, Penn, JCP&L, Met-Ed or Penelec, but hereby agree to furnish to the Commission on request any such documents.


169




SIGNATURE



Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



November 2, 2005






 
FIRSTENERGY CORP.
 
Registrant
   
 
OHIO EDISON COMPANY
 
Registrant
   
 
THE CLEVELAND ELECTRIC
 
ILLUMINATING COMPANY
 
Registrant
   
 
THE TOLEDO EDISON COMPANY
 
Registrant
   
 
PENNSYLVANIA POWER COMPANY
 
Registrant
   
 
JERSEY CENTRAL POWER & LIGHT COMPANY
 
Registrant
   
 
METROPOLITAN EDISON COMPANY
 
Registrant
   
 
PENNSYLVANIA ELECTRIC COMPANY
 
Registrant





 
  /s/       Harvey L. Wagner
 
    Harvey L. Wagner
 
    Vice President, Controller
 
  and Chief Accounting Officer

 
170