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 March 31,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.
YesXNo
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 | NoX | 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 MAYNOVEMBER 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 receipt of approval from and entry of a final order by the U.S. District Court, Southern District of Ohio, on the pending settlement agreement resolving the New Source Review litigation and 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 thisthe 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, further investigation into the causes of the August 14, 2003 regional power outages and the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to the outages,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-iviii-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 | 1-181-25 |
| | |
FirstEnergy Corp. | |
| | |
| Consolidated Statements of Income | 1926 |
| Consolidated Statements of Comprehensive Income | 2027 |
| Consolidated Balance Sheets | 2128 |
| Consolidated Statements of Cash Flows | 2229 |
| Report of Independent Registered Public Accounting Firm | 2330 |
| Management's Discussion and Analysis of Results of Operations and | 31-65 |
| Financial Condition | 24-45 |
| | |
Ohio Edison Company | |
| | |
| Consolidated Statements of Income and Comprehensive Income | 4666 |
| Consolidated Balance Sheets | 4767 |
| Consolidated Statements of Cash Flows | 4868 |
| Report of Independent Registered Public Accounting Firm | 4969 |
| Management's Discussion and Analysis of Results of Operations and | 70-82 |
| Financial Condition | 50-58 |
| | |
The Cleveland Electric Illuminating Company | |
| | |
| Consolidated Statements of Income and Comprehensive Income | 5983 |
| Consolidated Balance Sheets | 6084 |
| Consolidated Statements of Cash Flows | 6185 |
| Report of Independent Registered Public Accounting Firm | 6286 |
| Management's Discussion and Analysis of Results of Operations and | 87-98 |
| Financial Condition | 63-71 |
| | |
The Toledo Edison Company | |
| | |
| Consolidated Statements of Income and Comprehensive Income | 7299 |
| Consolidated Balance Sheets | 73100 |
| Consolidated Statements of Cash Flows | 74101 |
| Report of Independent Registered Public Accounting Firm | 75102 |
| Management's Discussion and Analysis of Results of Operations and | 103-114 |
| Financial Condition | 76-83 |
| | |
Pennsylvania Power Company | |
| | |
| Consolidated Statements of Income and Comprehensive Income | 84115 |
| Consolidated Balance Sheets | 85116 |
| Consolidated Statements of Cash Flows | 86117 |
| Report of Independent Registered Public Accounting Firm | 87118 |
| Management's Discussion and Analysis of Results of Operations and | 119-127 |
| Financial Condition | 88-94 |
TABLE OF CONTENTS (Cont'd)
| | Pages |
| | |
| | |
Jersey Central Power & Light Company | |
| | |
| Consolidated Statements of Income and Comprehensive Income | 95128 |
| Consolidated Balance Sheets | 96129 |
| Consolidated Statements of Cash Flows | 97130 |
| Report of Independent Registered Public Accounting Firm | 98131 |
| Management's Discussion and Analysis of Results of Operations and | 132-140 |
| Financial Condition | 99-105 |
| | |
Metropolitan Edison Company | |
| | |
| Consolidated Statements of Income and Comprehensive Income | 106141 |
| Consolidated Balance Sheets | 107142 |
| Consolidated Statements of Cash Flows | 108143 |
| Report of Independent Registered Public Accounting Firm | 109144 |
| Management's Discussion and Analysis of Results of Operations and | 145-153 |
| Financial Condition | 110-115 |
| | |
Pennsylvania Electric Company | |
| | |
| Consolidated Statements of Income and Comprehensive Income | 116154 |
| Consolidated Balance Sheets | 117155 |
| Consolidated Statements of Cash Flows | 118156 |
| Report of Independent Registered Public Accounting Firm | 119157 |
| Management's Discussion and Analysis of Results of Operations and | 158-166 |
| Financial Condition | 120-125 |
| | |
Item 3. Quantitative and Qualitative Disclosures About Market Risk | 126167 |
| | |
Item 4. Controls and Procedures | 126167 |
| | |
Part II.Other Information | |
| | |
Item 1. Legal Proceedings | 127168 |
| | 168 |
Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities | 127 |
| | |
Item 5. Other Information | 168 |
| |
Item 6. Exhibits | 130-142169-184 |
| |
| |
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, Inc.,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 nonnuclearnon-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 “Accounting for Nonmonetary Transactions” 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”Investments”
|
EITF 04-13 | EITF Issue No. 04-13,“Accounting “Accounting for Purchases and Sales of Inventory with the SameCounterparty”Counterparty” |
EITF 99-19 | EITF Issue No. 99-19,“Reporting “Reporting Revenue Gross as a Principal versus Net as an Agent” 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" |
FIN 47 | FASB Interpretation 47,“Accounting “Accounting for Conditional Asset Retirement Obligations - aninterpretation of FASB Statement No. 143”143” |
FMBFMBs | 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" |
GLOSSARY OF TERMS Cont'd
FSP 109-1 | FASB Staff Position No. 109-1,“Application “Application of FASB Statement No. 109, Accounting for Income TaxesTaxes,, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004”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 |
NOXx | 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” “Share-Based Payment” |
SFAS 131 | SFAS No. 131,“Disclosures “Disclosures about Segments of an Enterprise and Related Information” Information” |
SFAS 133 | SFAS No. 133,“Accounting “Accounting for Derivative Instruments and Hedging Activities” Activities” |
SFAS 140 | SFAS No. 140,“Accounting “Accounting for Transfers and Servicing of Financial Assets and |
| Extinguishment of Liabilities”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” |
| |
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 |
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)
1.1 - 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 first quarter ofnine months ended September 30, 2005 have been classified as discontinued operations on the Consolidated Statements of Income (see Note 6). As discussed in Note 15,16, 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 (20-50 percent owned companies, joint ventures and partnerships) 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.
2.2 - 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 its BGS obligation in New Jersey and 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.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.
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. In addition, FES also applies thisthe 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 dedicatedsubstantial 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 hastransaction. FES accounted for thesethose transactions on a gross basis in accordance with EITF 99-19.
TheAt its September 2005 meeting, the FASB's Emerging Issues Task Force is currently consideringEITF reached a final consensus on EITF 04-13, which relates to the accounting for purchases and sales of inventory with the same counterparty. The EITF is expected to address under what circumstancesTask 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. If29, 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 were04-13 is not applicable to determine that transactions such as FES' purchases and sales in the PJM Market should be accounted for as nonmonetary transactions, FES would report the transactionsmade prior to January 1, 20052005. The recognition of these transactions on a net basis. This requirementbasis in 2004 would have no impact on net income, but would reducehave reduced both wholesale revenue and purchased power expense by $280$264 million and $828 million for the first quarter of 2004.three months and nine months ended September 30, 2004, respectively.
3.3 - 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. The change in estimate resulted in a $5.9 million increase (CEI - $2.1 million, OE - $3.3 million, Penn - - $0.1 million, TE - $0.5 million, FGCO - $(0.1) million) in income before discontinued operations and net income ($0.02 per share of common stock) during the first quarter of 2005.
4.4 - 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 totaling 0.5 million in the three months ended March 31, 2005 and 3.3 million in the three months ended March 31, 2004, 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 | |
Reconciliation of Basic and | | Three Months Ended | |
Diluted Earnings per Share | | March 31, | |
| | 2005 | | 2004 | |
| | (In thousands) | |
| | | | | |
Income Before Discontinued Operations | | $ | 140,788 | | $ | 172,526 | |
| | | | | | | |
Average Shares of Common Stock Outstanding: | | | | | | | |
Denominator for basic earnings per share | | | | | | | |
(weighted average shares outstanding) | | | 327,908 | | | 327,057 | |
| | | | | | | |
Assumed exercise of dilutive stock options and awards | | | 1,519 | | | 1,977 | |
| | | | | | | |
Denominator for diluted earnings per share | | | 329,427 | | | 329,034 | |
| | | | | | | |
Income Before Discontinued Operations per common share: | | | | | | | |
Basic | | $ | 0.43 | | $ | 0.53 | |
Diluted | | $ | 0.42 | | $ | 0.53 | |
5 - GOODWILL
5.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 - GOODWILLcalculated 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 threenine months ended March 31,September 30, 2005, FirstEnergy adjusted goodwill related to the divestiture of non-core operations (FES' retail natural gas business, the MYR subsidiary,MYR's Power Piping Company subsidiary, and a portion of its interest in FirstCom) as further discussed in Note 6. In addition, the adjustment ofadjustments to the former GPU and Centerior companies' goodwill waswere recorded to reverse pre-merger tax accruals due to the reversalfinal resolution of pre-mergerthese tax reserves as a result of property tax settlements.contingencies. FirstEnergy estimates that completion of transition cost recovery (see Note 13)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 March 31,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 | |
| | 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 | | | (12 | ) | | -- | | | -- | | | -- | | | -- | | | -- | |
Adjustments related to GPU acquisition | | | (4 | ) | | -- | | | -- | | | (1 | ) | | (2 | ) | | (1 | ) |
Balance as of March 31, 2005 | | $ | 6,034 | | $ | 1,694 | | $ | 505 | | $ | 1,984 | | $ | 868 | | $ | 887 | |
6.6 - 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 will accountaccounts for its remaining 31.85% interest in FirstCom on the equity basis.
InDuring the first quarter ofnine months ended September 30, 2005, FirstEnergy sold certain of its FSG subsidiaries Elliott-Lewis and(Elliott-Lewis, Spectrum and MYR subsidiary,Cranston), and MYR’s Power Piping Company subsidiary, resulting in an after-tax gain of $12 million. FSG's remaining subsidiaries qualifiedqualify as assets held for sale in accordance with SFAS 144 and are expected to be recognized as completed sales by the fourth quarter of 2005.within one year. The assets and liabilities of these remaining FSG subsidiaries are not material to FirstEnergy’s Consolidated Balance Sheet as of March 31,September 30, 2005, and therefore have therefore not been separately classified as assets held for sale.
Net income (including the sales gains discussed above) for Elliott-Lewis, Power Piping and FES' natural gas businessAs of $19 million for the first quarter ofSeptember 30, 2005, and $1 million for the first quarter of 2004 are reported as discontinued operations on FirstEnergy's Consolidated Statements of Income. Pre-tax operating results for these entities were $4 million for the first quarter of 2005 and $3 million for the first quarter of 2004. Revenues associated with discontinued operations for the first quarter of 2005 and 2004 were $191 million and $186 million, respectively. It is not certain that the remaining FSG businesses willdo not meet the criteria for discontinued operations; therefore, the net loss ($2 million for the first quarter of 2005 and $1 million for the first quarter of 2004)results from these subsidiaries has nothave been included in discontinuedcontinuing operations. See Note 1516 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 | |
| | March 31, | |
| | 2005 | | 2004 | |
| | (In millions) | |
Discontinued Operations (Net of tax) | | | | | |
Gain on sale: | | | | | |
Natural gas business | | $ | 5 | | $ | -- | |
Elliot-Lewis, Spectrum and Power Piping | | | 12 | | | -- | |
Reclassification of operating income | | | 2 | | | 1 | |
Total | | $ | 19 | | $ | 1 | |
| | 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 | |
| | | | | | | | | | | | | |
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 | |
| | | | | | | | | | | | | |
7.7 - 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.Swaprates. Swap maturities, call options, fixed interest rates received, and interest payment dates match those of the underlying debt obligations. As of March 31, 2005, FirstEnergy had fixed-for-floating interest rate swap agreements with anaggregate notional amount of $1.75 billion. During the firstthird quarter of 2005, FirstEnergy executed new interest rateunwound swaps with a total notional amount of $100 million. Under these agreements, FirstEnergy receives fixed$350 million from which it received immaterial net cash flows based ongains. The gains will be recognized in earnings over the fixed couponsremaining maturity of each respective hedged securities and pays variable cash flows based on short-term variable marketsecurity as reduced interest rates.The weighted average fixedexpense. As of September 30, 2005, the aggregate notional value of interest rate of senior notes and subordinated debentures hedged by the swap agreements outstanding was 6.51%. The interest rate swaps have effectively converted that rate to a current, weighted average variable interest rate of 4.91%.Changes in the fair value of derivatives designated as fair value hedges and the corresponding changes in the fair value of the hedged risk attributable to a recognized asset, liability, or unrecognized firm commitment are recorded in earnings. Since the fair value hedges are effective, the amounts recorded will be offset in earnings. $1.05 billion.
FirstEnergy engages in hedging ofhedges 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 losslosses of $87$79 million included in AOCL as of March 31,September 30, 2005, for derivative hedging activity, as compared to the December 31, 2004 balance of $92 million inof net deferred losses, resulted from a $5$6 million reductiondecrease related to current hedging activity, a $4 million increase due to the sale of gas business contracts and a $4an $11 million decrease due to net hedge losses included in earnings during the threenine months ended March 31,September 30, 2005. Approximately $10$14 million (after tax) of the net deferred losslosses on derivative instruments in AOCL as of March 31,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.
8.8 - 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 14)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. The SEC’s new rule results in a six-month deferral for FirstEnergy and other companies with a fiscal yearwill be required to adopt this standard beginning January 1.1, 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 123123(R) to stock-based employee compensation in the current reporting periods.
| | Three Months Ended | |
| | March 31, | |
| | 2005 | | 2004 | |
| | (In thousands) | |
| | | | | |
Net income, as reported | | $ | 159,726 | | $ | 173,999 | |
| | | | | | | |
Add back compensation expense | | | | | | | |
reported in net income, net of tax | | | | | | | |
(based on APB 25)* | | | 7,969 | | | 6,694 | |
| | | | | | | |
Deduct compensation expense based | | | | | | | |
upon estimated fair value, net of tax | | | (11,026 | ) | | (11,098 | ) |
| | | | | | | |
Pro forma net income | | $ | 156,669 | | $ | 169,595 | |
| | | | | | | |
Earnings Per Share of Common Stock - | | | | | | | |
Basic | | | | | | | |
As Reported | | $ | 0.49 | | $ | 0.53 | |
Pro Forma | | $ | 0.48 | | $ | 0.52 | |
Diluted | | | | | | | |
As Reported | | $ | 0.48 | | $ | 0.53 | |
Pro Forma | | $ | 0.48 | | $ | 0.52 | |
*Includes restricted stock, stock options, performance shares, Employee Stock Ownership Plan,
Executive Deferred Compensation Plan and Deferred Compensation Plan for Outside Directors.
| | | 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 has reduced itsthe use of stock options in 2005 and increased itsthe use of performance-based, restricted stock units. Therefore, the pro forma effects of applying SFAS 123123(R) may not be representative of its future effect. FirstEnergy has not and does not expect to accelerate out-of-the-money options in anticipation of implementing SFAS 123(R) on January 1, 2006 (see Note 14 - "New Accounting Standards and Interpretations").2006.
9.9 - 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 $1.095$1.130 billion as of March 31,September 30, 2005 included $1.071$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 nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of March 31,September 30, 2005, the fair value of the decommissioning trust assets was $1.604$1.7 billion.
The following tables provide the beginning and ending aggregate carrying amount of the ARO and theanalyze changes to the ARO balance during the three months and nine months ended March 31,September 30, 2005 and 2004, respectively.
| | FirstEnergy | | OE | | CEI | | TE | | Penn | | JCP&L | | Met-Ed | | Penelec | |
ARO Reconciliation | | (In millions) | |
| | | | | | | | | | | | | | | | | |
Balance, January 1, 2005 | | $ | 1,078 | | $ | 201 | | $ | 272 | | $ | 194 | | $ | 138 | | $ | 73 | | $ | 133 | | $ | 66 | |
Liabilities incurred | | | -- | | | -- | | | -- | | | -- | | | -- | | | -- | | | -- | | | -- | |
Liabilities settled | | | -- | | | -- | | | -- | | | -- | | | -- | | | -- | | | -- | | | -- | |
Accretion | | | 17 | | | 3 | | | 4 | | | 3 | | | 2 | | | 2 | | | 2 | | | 1 | |
Revisions in estimated cash flows | | | -- | | | -- | | | -- | | | -- | | | -- | | | -- | | | -- | | | -- | |
Balance, March 31, 2005 | | $ | 1,095 | | $ | 204 | | $ | 276 | | $ | 197 | | $ | 140 | | $ | 75 | | $ | 135 | | $ | 67 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Balance, January 1, 2004 | | $ | 1,179 | | $ | 188 | | $ | 255 | | $ | 182 | | $ | 130 | | $ | 110 | | $ | 210 | | $ | 105 | |
Liabilities incurred | | | -- | | | -- | | | -- | | | -- | | | -- | | | -- | | | -- | | | -- | |
Liabilities settled | | | -- | | | -- | | | -- | | | -- | | | -- | | | -- | | | -- | | | -- | |
Accretion | | | 19 | | | 3 | | | 4 | | | 3 | | | 2 | | | 1 | | | 3 | | | 2 | |
Revisions in estimated cash flows | | | -- | | | -- | | | -- | | | -- | | | -- | | | -- | | | -- | | | -- | |
Balance, March 31, 2004 | | $ | 1,198 | | $ | 191 | | $ | 259 | | $ | 185 | | $ | 132 | | $ | 111 | | $ | 213 | | $ | 107 | |
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 | |
10.10 - PENSION AND OTHER POSTRETIREMENT BENEFITS:
The components of FirstEnergy's net periodic pension cost and other postretirement benefitbenefits cost (including amounts capitalized) as of March 31,for the three months and nine months ended September 30, 2005 and 2004, consisted of the following:
| | Pension Benefits | | Other Postretirement Benefits | | | Three Months Ended | Nine Months Ended | |
| | 2005 | | 2004 | | 2005 | | 2004 | | | September 30, | | September 30, | |
Pension Benefits | | | 2005 | | 2004 | | 2005 | | 2004 | |
| | | | (In millions) | | | | | (In millions) | |
| | | | | | | | | | | | | | | | | | |
Service cost | | $ | 19 | | $ | 19 | | $ | 10 | | $ | 11 | | | $ | 19 | | $ | 19 | | $ | 58 | | $ | 58 | |
Interest cost | | | 64 | | | 63 | | | 28 | | | 33 | | | | 64 | | | 63 | | | 191 | | | 189 | |
Expected return on plan assets | | | (86 | ) | | (71 | ) | | (11 | ) | | (13 | ) | | | (86 | ) | | (71 | ) | | (259 | ) | | (215 | ) |
Amortization of prior service cost | | | 2 | | | 2 | | | (11 | ) | | (12 | ) | | | 2 | | | 2 | | | 6 | | | 7 | |
Recognized net actuarial loss | | | 9 | | | 10 | | | 10 | | | 11 | | | | 9 | | | 10 | | | 27 | | | 29 | |
Net periodic cost | | $ | 8 | | $ | 23 | | $ | 26 | | $ | 30 | | | $ | 8 | | $ | 23 | | $ | 23 | | $ | 68 | |
| | 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 FirstEnergy’sthe FirstEnergy subsidiaries employing the plan participants. The Companies capitalize employee benefits related to construction projects. The net periodic pension costs (credits)benefits (credit) and net periodic postretirement benefit costsbenefits (including amounts capitalized) recognized by each of the Companies in the three months and nine months ended March 31,September 30, 2005 and 2004 were as follows:
| | Pension Benefit Cost (Credit) | | Other Postretirement Benefit Cost | |
| | 2005 | | 2004 | | 2005 | | 2004 | |
| | | | (In millions) | | | |
| | | | | | | | | |
OE | | $ | 0.2 | | $ | 1.7 | | $ | 5.8 | | $ | 7.1 | |
Penn | | | (0.2 | ) | | 0.1 | | | 1.2 | | | 1.5 | |
CEI | | | 0.3 | | | 1.6 | | | 3.8 | | | 5.6 | |
TE | | | 0.3 | | | 0.8 | | | 2.2 | | | 2.0 | |
JCP&L | | | (0.2 | ) | | 1.9 | | | 2.7 | | | 1.6 | |
Met-Ed | | | (1.1 | ) | | 0.1 | | | 0.4 | | | 1.3 | |
Penelec | | | (1.3 | ) | | 0.1 | | | 1.9 | | | 1.4 | |
| | 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 | |
11.11 - VARIABLE INTEREST ENTITIES
Leases
Included in FirstEnergy’s consolidated financial statements areinclude PNBV and Shippingport, two 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 $688$678 million, $99$103 million and $566$541 million, respectively, that would not be payable if the casualty value payments are made.
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 nineeight 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 nineeight 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 nineeight 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 first quarters ofthree months and nine months ended September 30, 2005 and 2004 are shown in the table below:
6 | 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 | |
| | Three Months Ended | |
| | March 31, | |
| | 2005 | | 2004 | |
| | (In millions) | |
JCP&L | | $ | 27 | | $ | 28 | |
Met-Ed | | | 16 | | | 16 | |
Penelec | | | 7 | | | 7 | |
| | $ | 50 | | $ | 51 | |
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 $100,000$0.1 million that is payable from TBC collections.
12.12 - 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.
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 March 31,September 30, 2005, outstanding guarantees and other assurances aggregated approximately $2.4$2.7 billion and included contract guarantees ($1.01.3 billion), surety bonds ($0.3 billion) and LOCLOCs ($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. TheSuch 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 parental guarantees of $0.9 billion (included in the $1.0 billion discussed above) as of March 31, 2005 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 “material adverse event”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 March 31,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.
| | | | Collateral Paid | | Remaining | |
Collateral Provisions | | Exposure | | Cash | | LOC | | Exposure(1) | |
| | (In millions) | |
Credit rating downgrade | | $ | 364 | | $ | 153 | | $ | 18 | | $ | 193 | |
Adverse Event | | | 42 | | | -- | | | 8 | | | 34 | |
Total | | $ | 406 | | $ | 153 | | $ | 26 | | $ | 227 | |
(1) | As of May 2, 2005, FirstEnergy’s total exposure decreased to $357 million and the remaining exposure decreased
to $183 million - net of $148 million of cash collateral and $26 million of LOC collateral provided by counterparties.
|
Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of $267$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 (currently at $47 million),($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 changechanges in regulatory policies and what, if any, the effects of such changechanges would be. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately $430$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 determineestimate 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
The Companies areFirstEnergy 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.
The Companies believe they areFirstEnergy 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 the Companies'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. The Companies believe theirFirstEnergy 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.
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 will requireprovides 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,NOx, 2010 for SO2 and Phase II in 2015 for both NOxNOx and SO2). The Companies’ 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 NOxNOx emissions, whereas ourtheir 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 operateFirstEnergy 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 in two phases from coal-fired power plants.plants in two phases. Initially, mercury emissions will declinebe capped nationally at 38 tons by 2010 as(as a "co-benefit" from implementation of SO2 and NOxemission caps under the EPA's CAIR program.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. TheHowever, 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 coveringalleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which iswas owned at that time by OE and Penn. In addition, the U.S. Department of Justice (DOJ)DOJ filed eight civil complaints against various investor-owned utilities, which includedincluding 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. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. 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, subject to a thirty-day public comment period that ended on April 29, 2005 and final approvalwas approved by the District Court Judge,on July 11, 2005, requires OE and Penn to reduce Nox and SO2emissions fromat the W. H. Sammis Plant and other coal fired plants through the installation of pollution control devices requiring capitaldevices. Capital expenditures necessary to meet those requirements are currently estimated to be $1.1$1.5 billion (primarily(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 towardstoward environmentally beneficial projects, which include wind energy purchasepurchased power agreements over a 20-year term. OE and Penn also agreed to pay a civil penalty of $8.5 million. Results for the first quarter of 2005 includeincluded the penalties payable by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also accruedrecognized 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 during the first quarter of 2005.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 gasesGHG 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 gasGHG 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 CompaniesFirstEnergy 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 CompaniesFirstEnergy is lower than many regional competitors due to the Companies'its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.
FirstEnergy plans to issue a report that will disclose the Companies’ environmental activities, including their plans to respond to environmental requirements. FirstEnergy expects to complete the report by December 1, 2005.
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 the Companies'FirstEnergy's plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to the Companies'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. The Companies areFirstEnergy is conducting comprehensive demonstration studies, due in 2008, to determine the operational measures, equipment or restoration activities, if any, necessary for compliance by theirits 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 March 31,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. Included in Current Liabilities and Other Noncurrent Liabilities are accruedTotal liabilities aggregatingof approximately $65$64 million (JCP&L - $46.8 million, CEI - $2.3 million, TE - $0.2 million, Met-Ed - $48,000$0.1 million and other - $15.2$14.6 million) as of March 31,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 CourtDivision 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 Court.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 March 31,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 concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area.Specifically, the final report concludes,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 “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. As manyFirstEnergy also is proceeding with the implementation of these initiatives alreadythe 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 process,new or material upgrades to existing equipment, and therefore FirstEnergy doeshas not believeaccrued a liability as of September 30, 2005 for any expenditures in excess of those actually incurred through that any incremental expenses associated with additional initiatives completed in 2004 had a material effect on its continuing operationsdate. The FERC or financial results. FirstEnergy notes, however, that theother 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. FirstEnergy has not accrued a liability asFinally, 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 March 31, 2005 forcontrol room operators, before determining the next steps, if any, expenditures in excess of those actually incurred through that date.the proceeding.
Three substantially similar actionsFirstEnergy 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 various Ohio State courts by plaintiffs seekingbut 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 customers whoothers 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 suffered damagesarising as a result of the loss of power on August 14, 2003 power outages. All three2003. The listed insureds in these cases, were dismissedin many instances, are not customers of any FirstEnergy company. The fourth case involves the claim of a non-customer seeking reimbursement for lack of jurisdiction. One caselosses incurred when its store was refiledburglarized on January 12, 2004 at the PUCO. The other two cases were appealed. One case was dismissed and no further appeal was sought. In the remaining case, the Court of Appeals on March 31, 2005 affirmed the trial court’s decision dismissing the case. It is not yet known whether further appeal will be sought.August 14, 2003. In addition to the one case that was refiled at the PUCO,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 filed aFirstEnergy's motion to dismiss with 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 October 22, 2004.or about December 1, 2005. No timetable for a decision on the motion to dismiss has been established by the Court. No damage estimate has been provided and thusof potential liability has not been determined.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, and results of operations.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. Under the NRC’s letter, FENOC has ninety daysFirstEnergy accrued $2.0 million for a potential fine prior to respond to this NOV. FirstEnergy2005 and accrued the remaining liability for the proposed fine of $3.45 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 hashave legal liability based on the events surrounding Davis-Besse, head degradation, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, and results of operations.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 pastpreceding two years.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.OnPenn (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 forummeeting 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 althougheven though it remained under the heightened NRC oversight since August 2004.oversight. During the public forummeeting 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.condition, results of operations and cash flows.
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 most significantother 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 second 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 matter,matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, and results of operations.operations and cash flows.
13.14 - 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. FirstEnergy notes, however, thatThe 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.
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 a Memorandum of Understanding (MOU)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 stipulationStipulation 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 stipulationStipulation 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 SeptemberNovember 2005. FirstEnergy is unable to predict the outcome of this proceeding.
In November 2004,The Energy Policy Act of 2005 provides for the PPUC approvedcreation 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 settlement agreement filed by Met-Ed, PenelecNotice of Proposed Rulemaking to establish certification requirements for the ERO, as well as regional entities envisioned to assume monitoring and Penn that addressed issues relatedcompliance responsibility for the new reliability standards. The FERC expects to adopt a PPUC investigation into Met-Ed's, Penelec'sfinal rule on or before February 2006 regarding certification requirements for the ERO and Penn's service reliability performance. As partregional entities.
The NERC is expected to reorganize its structure to meet the FERC’s certification requirements for the ERO. Following adoption of the settlement, Met-Ed, Penelecfinal 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 Penn agreedapproved by the FERC. The ECAR, Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability councils have signed an MOU designed to enhance serviceconsolidate their regions into a new regional reliability ongoing periodic performance reportingorganization known as ReliabilityFirst Corporation. Their intent is to file and communicationsobtain 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 customers, andthe FERC following the NERC’s certification as an ERO. These reliability standards are expected to collectively maintain theirbuild on the current spending levelsNERC 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 least $255 million annually on combined capital and operation and maintenance expenditures for transmission and distribution forthis time. However, the yearsEnergy Policy Act of 2005 through 2007. The settlement also outlines an expedited remediation processrequires that all prudent costs incurred to address any alleged non-compliancecomply with terms of the settlement and an expedited PPUC hearing process if remediation is unsuccessful.new reliability standards be recovered in rates.
Ohio
On August 5, 2004, the Ohio Companies accepted the Rate Stabilization PlanRSP as modified and approved by the PUCO onin an August 4, 2004 Entry on Rehearing, subject to a competitive bid process. The Rate Stabilization PlanRSP 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 the second quarter of 2004, the Ohio Companies implemented the accounting modifications related to the extended amortization periods and interest costs deferral on the deferred customer shopping incentive balances. On October 1 and October 4, 2004, the OCC and NOAC respectively, filed appeals with the Supreme Court of Ohio to overturn the original June 9, 2004 PUCO order andin 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.
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 revised Rate Stabilization Plan extends current generation prices through 2008, ensuring adequate generation supply at stabilized prices, and continues the Ohio Companies' support of energy efficiency and economic development efforts. Other key componentsfollowing table provides a comparison of the revised Rate Stabilization Plan includeestimated net amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) under the following:proposed RCP and the current RSP for the period 2006 through 2010:
· | extension of the transition cost amortization period for OE from 2006 to as late as 2007; for CEI from 2008 to as late as mid-2009 and for TE from mid-2007 to as late as mid-2008; |
· | deferral of interest costs on the accumulated customer shopping incentives as new regulatory assets; and |
| | 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. |
· | ability to request increases in generation charges during 2006 through 2008, under certain limited conditions, for increases in fuel costs and taxes. |
On December 9, 2004,Under provisions of the PUCO rejectedRSP, the auction price results from a required competitive bid process and issued an entry stating that the pricing under the approved revised Rate Stabilization Plan will take effect on January 1, 2006. The PUCO may require the Ohio Companies to undertake, no more often than annually, a similar 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 Rate Stabilization PlanRSP pricing, but notwith no accounting impacts to the related approved accounting,RSP, and not until twelve months after the PUCO authorizes such termination.
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 March 31, On September 28, 2005, the accumulated deferred cost balance totaled approximately $472 million. New Jersey law allows for securitization of JCP&L's deferred balance upon application by JCP&L and a determination byPUCO issued an Entry that essentially approved the NJBPU thatOhio Companies' filing but delayed the conditionsproposed timing of the New Jersey restructuring legislation are met. On February 14, 2003, JCP&L filed for approval of the securitization of the deferred balance. There can be no assurance as to the extent, if any, that the NJBPU will permit such securitization.
The July 2003 NJBPU decision on JCP&L's base electric rate proceeding disallowed certain regulatory assets. JCP&L recorded charges to net income in 2003competitive bid process by four months, calling for the disallowed costs aggregating $185 million ($109 net of tax). The subsequent NJBPU final decision and order issued in May 2004 resulted in JCP&L recording a $5.4 million reduction in 2004 of the estimated charges in 2003. The 2003 NJBPU decision also provided for an interim returnauction to be held on equity of 9.5% on JCP&L's rate base. The decision ordered a Phase II proceeding to review whether JCP&L is in compliance with current service reliability and quality standards. The NJBPU also ordered that any expenditures and projects undertaken by JCP&L to increase its system's reliability be reviewed as part of the Phase II proceeding, to determine their prudence and reasonableness for rate recovery. In that Phase II proceeding, the NJBPU could increase JCP&L’s return on equity to 9.75% or decrease it to 9.25%, depending on its assessment of the reliability of JCP&L's service. Any reduction would be retroactive to August 1, 2003. JCP&L filed an August 15, 2003 interim motion for rehearing and reconsideration with the NJBPU and a June 1, 2004 supplemental and amended motion for rehearing and reconsideration. 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. Management is unable to predict when a decision may be reached by the NJBPU.
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 requests an increase to the MTC deferred balance recovery of approximately $20 million annually. The Ratepayer Advocate filed testimony on November 16, 2004, and JCP&L submitted rebuttal testimony on January 4, 2005. The Ratepayer Advocate surrebuttal testimony was submitted February 8, 2005. Discovery and settlement conferences are ongoing.
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. New BGS tariffs reflecting the results of a February 2004 auction for the BGS supply became effective June 1, 2004. The auction for the supply period beginning June 1, 2005 was completed in February 2005. The NJBPU decision on the BGS post transition year three process was announced on October 22, 2004, approving with minor modifications the BGS procurement process filed by JCP&L and the other New Jersey electric distribution companies and authorizing the continued use of NUG committed supply to serve 300 MW of BGS load.
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.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. InOn 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 werebecame effective in October 2003 and that reflected the CTC rates and shopping credits in effect prior to the June 2001 order.
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. These companies'Met-Ed’s and Penelec’s combined portion of total merger savings is estimated to be approximately $31.5 million. If noOn 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 can be reached, Met-Edproposals in May and Penelec will take the position that any portion of such savings should be allocatedJune 2005 and continue to customers during each company's next rate proceeding.have settlement discussions.
In response to theiran October 8,16, 2003 petition,order, the PPUC approved JuneSeptember 30, 2004 as the date for Met-Ed's and Penelec's NUG trust fund refunds. The PPUC order also denied thetheir 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 subsequently 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 continue deferringdefer 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:
| · | 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 ($14 million deferred as of March 31, 2005) estimated to be incurred from 2004 through 2007. On March 4, 2005, the FERC approved ATSI's request to defer those costs.costs ($21 million deferred as of September 30, 2005). ATSI expects to file an application with the FERC in the firstsecond quarter of 2006 forthat would include recovery of the deferred costs.
ATSI and MISO filed with the FERC on December 2, 2004, seeking approval for ATSI to have transmission rates established based on a FERC-approved cost of service - formula rate included in Attachment O under the MISO tariff. The ATSI Network Service net revenue requirement increased under the formula rate to approximately $159 million. On January 28, 2005, the FERC accepted for filing the revised tariff sheets to become effective February 1, 2005, subject to refund, and ordered a public hearing be held to address the reasonableness of the proposal to eliminate the voltage-differentiated rate design for the ATSI zone. On April 4, 2005, a settlement with all parties to the proceeding was filed with the FERC that provides for recovery of the full amount of the rate increase permitted under the formula.
On December 30, 2004, the Ohio Companies filed an application with the PUCO seeking tariff adjustmentstwo applications related to recover increasesthe recovery of approximately $30 million in transmission and ancillary service related costs. The first application seeks recovery of these costs beginning January 1, 2006. The Ohio Companies alsorequested 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 anwith 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.
The second application forsought authority to defer costs associated with MISO Day 1, MISO Day 2, congestion fees, FERC assessment fees,transmission and ancillary service related costs incurred during the ATSI rate increase, as applicable,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.
Various parties The OCA, OSBA, OTS, MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric Association have all intervened in each of the cases above,case. To date no hearing schedule has been established, and the Companies have notneither company has yet implemented deferral accounting for these costs.
On September 16, 2004,January 31, 2005, certain PJM transmission owners made three filings pursuant to a settlement agreement previously approved by the FERC issued an orderFERC. JCP&L, Met-Ed and Penelec were parties to that imposed additional obligations on CEI under certain pre-Open Accessproceeding and joined in two of the filings. In the first filing, the settling transmission contracts among CEI andowners submitted a filing justifying continuation of their existing rate design within the cities of Cleveland and Painesville, Ohio. UnderPJM RTO. In the FERC's decision, CEI may be responsible forsecond filing, the settling transmission owners proposed a portionrevised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new energy market charges imposed by MISO when its energy markets begin inand existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the spring of 2005. CEI filedthird filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for rehearing of the order from the FERC on October 18, 2004.transmission service provided within their respective zones. On April 15,May 31, 2005, the FERC issued an order on rehearingthese cases. First, it set for hearing the existing rate design and indicated that "carves out" these contracts fromit will issue a final order within six months. Second, the MISO Day 2 market. WhileFERC approved the order onproposed 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 is favorable to CEI, the impact of the FERC decision on CEI is dependent upon many factors, includingMay 31, 2005 order. The rate design and formula rate proceedings are currently being litigated before the arrangements made by the cities for transmission service and MISO's ability to administer the contracts. Accordingly, the impactFERC. The outcome of this decisionthese cases cannot be determined at this time.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 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.
The Ohio Companies are deferring customer shopping incentives and interest costs as new regulatory assets in accordance with the transition and rate stabilization plans. TheseUnder the RSP, recovery of these regulatory assets (OE - $250$302 million, CEI - $320$402 million, TE - $98$122 million, as of March 31,September 30, 2005) will be recoveredwould have begun through a surcharge rate equal to the RTC rate in effect whenonly after the transition costs have been fully recovered. RecoveryUnder the proposed RCP, OE's and TE's recovery of the new regulatory assets willwould begin at that timeJanuary 1, 2006 and amortizationexpected 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 will bewould equal tothe amount of the surcharge revenue recognized during that period. OE, TE and CEI expect to recover these deferred customer shopping incentives by August 31, 2008, September 30, 2008 and August 31, 2010, respectively.
Regulatory transition costs as of March 31,September 30, 2005 for JCP&L Met-Ed and PenelecMet-Ed are approximately $2.3 billion, $0.7$2.4 billion and $0.2$0.6 billion, respectively. Deferral of above-market costs from power supplied by NUGs to JCP&L are approximately $1.3$1.4 billion and are being recovered through BGS and MTC revenues. Met-Ed and Penelec havehas deferred above-market NUG costs totaling approximately $0.5 billion and $0.2 billion, respectively.$200 million. These costs are being recovered through CTC revenues. The regulatory asset for above-market NUG costsfuture obligations and athe 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 forin New Jersey and Pennsylvania.
14.15 - 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 “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”143”
On March 30, 2005, the FASB issued this interpretationFIN 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 no later thanfor FirstEnergy in the endfourth quarter of fiscal years ending after December 15, 2005. FirstEnergy isand the Companies are currently evaluating the effect this standardInterpretation will have on itstheir 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.
| SFAS 153,“Exchanges “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29”29” |
In December 2004, the FASB issued this StatementSFAS 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 statementStatement are effective January 1, 2006 for nonmonetary exchanges occurring in fiscal periods beginning after June 15, 2005 and are to be applied prospectively. FirstEnergyFirstEnergy. This FSP is currently evaluating this standard but does not expect itexpected to have a material impact on itsFirstEnergy's financial statements.
SFAS 123 (revised 2004)123(R),“Share-Based Payment” “Share-Based Payment”
In December 2004, the FASB issued thisSFAS 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 FirstEnergy and other companies with a fiscal year beginning January 1. The CompanyTherefore, FirstEnergy will be applyingadopt this Statement effective January 1, 2006. FirstEnergy expects to adopt modified prospective application, without restatement of prior interim periods. Any potentialPotential 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 will continueexpects to do soapply this pricing model upon adoption of SFAS 123(R).
| SFAS 151,“Inventory Costs - an amendment of ARB No. 43, Chapter 4”SFAS 151, “Inventory Costs - an amendment of ARB No. 43, Chapter 4”
|
In November 2004, the FASB issued this statementSFAS 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” “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 after June 30, 2005.beginning January 1, 2006. FirstEnergy is currently evaluating this standard butStandard and does not expect it to have a material impact on the financial statements.
EITF Issue No. 03-1,FSP FAS 115-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"
In March 2004,September 2005, the EITF reached a consensus on the application guidance for Issue 03-1.FASB finalized and renamed EITF 03-1 providesand 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 model for determiningSecurity Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when investments in certain debt and equity securities are consideredthe impairment is deemed other than temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair valuetemporary, even if a decision to sell has not been made, and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to(3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after JuneSeptember 15, 2004, were delayed by2005. The FASB expects to issue this FSP in the issuancefourth 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 EITF 03-1-1 in September 2004. During the period of delay, FirstEnergy will continue to evaluateIssue and any impact on its investments as required by existing authoritative guidance.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”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”
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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 9nine percent (when fully phased-in) of the lesser of (a)“qualified “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). This tax deduction is limited to 50 percent of W-2 wages paid by the taxpayer. The FASB believes that the deduction should be accounted for as a special deduction in accordance with SFAS No. 109,“Accounting “Accounting for Income Taxes.” FirstEnergyTaxes", which is currently evaluating this FSP but does not expect it to have a material impact on the Company's financial statements.consistent with FirstEnergy's accounting.
15.16 - SEGMENT INFORMATION:
FirstEnergy has three reportable segments: regulated services, power supply management services (referred to as competitive electric energy services in previous filings) and facilities (HVAC) services.FSG. The aggregate“Other” “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 EUOCEUOCs 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” “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 “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 includeas of September 30, 2005 and 2004, included generating units that arewere leased or whose output was sold to the power supply management services.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 FirstEnergyFirstEnergy’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 tax amountstaxes related to those generating units.
Segment reporting for interim periods in 2004 washave 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). A previous reportable segment was the more expansive competitive services segment whose aggregate operations consisted of FirstEnergy generation operations, natural gas commodity sales, providing local and long-distance phone service and other competitive energy-related businesses such as facilities services and construction service (MYR). Management's focus is on its core electric business. This has resulted in a change in performance review analysis from an aggregate view of all competitive services operations to a focus on its power supply management services operations. During FirstEnergy's periodic review of reportable segments under SFAS 131, that change resulted in the revision of reportable segments to the separate reporting of power supply management services and facilities services and including all other competitive services operations in the "Other" segment. Facilities servicesFSG is being disclosed as a reporting segment due to theits subsidiaries qualifying as held for sale (see Note 6 for discussion of the divestiture of twothree of itsthose subsidiaries in 2005). Interest expense on holding company debt and corporate support services revenues and expenses are included in "Reconciling Items."
Segment Financial Information
| | | | Power | | | | | | | | | |
| | | | Supply | | | | | | | | | |
| | Regulated | | Management | | Facilities | | Reconciling | | | | | |
| | Services | | Services | | Services | | Other | | Adjustments | | Consolidated | |
Three Months Ended | | (In millions) | |
March 31, 2005 | | | | | | | | | | | | | |
External revenues | | $ | 1,339 | | $ | 1,295 | | $ | 56 | | $ | 112 | | $ | 11 | | $ | 2,813 | |
Internal revenues | | | 78 | | | -- | | | -- | | | -- | | | (78 | ) | | -- | |
Total revenues | | | 1,417 | | | 1,295 | | | 56 | | | 112 | | | (67 | ) | | 2,813 | |
Depreciation and amortization | | | 377 | | | 10 | | | -- | | | 1 | | | 6 | | | 394 | |
Net interest charges | | | 98 | | | 10 | | | -- | | | 1 | | | 62 | | | 171 | |
Income taxes | | | 155 | | | (25 | ) | | (3 | ) | | 10 | | | (16 | ) | | 121 | |
Income before discontinued operations | | | 223 | | | (36 | ) | | (2 | ) | | 5 | | | (49 | ) | | 141 | |
Discontinued operations | | | -- | | | -- | | | 13 | | | 6 | | | -- | | | 19 | |
Net income | | | 223 | | | (36 | ) | | 11 | | | 11 | | | (49 | ) | | 160 | |
Total assets | | | 28,540 | | | 1,582 | | | 83 | | | 495 | | | 561 | | | 31,261 | |
Total goodwill | | | 5,947 | | | 24 | | | -- | | | 63 | | | -- | | | 6,034 | |
Property additions | | | 141 | | | 81 | | | 1 | | | 2 | | | 4 | | | 229 | |
| | | | | | | | | | | | | | | | | | | |
March 31, 2004 | | | | | | | | | | | | | | | | | | | |
External revenues | | $ | 1,290 | | $ | 1,522 | | $ | 58 | | $ | 116 | | $ | 11 | | $ | 2,997 | |
Internal revenues | | | 79 | | | -- | | | -- | | | -- | | | (79 | ) | | -- | |
Total revenues | | | 1,369 | | | 1,522 | | | 58 | | | 116 | | | (68 | ) | | 2,997 | |
Depreciation and amortization | | | 393 | | | 9 | | | 1 | | | -- | | | 9 | | | 412 | |
Net interest charges | | | 105 | | | 11 | | | -- | | | 1 | | | 54 | | | 171 | |
Income taxes | | | 145 | | | (1 | ) | | (1 | ) | | 3 | | | (31 | ) | | 115 | |
Income before discontinued operations | | | 213 | | | (2 | ) | | (1 | ) | | 5 | | | (42 | ) | | 173 | |
Discontinued operations | | | -- | | | -- | | | -- | | | 1 | | | -- | | | 1 | |
Net income | | | 213 | | | (2 | ) | | (1 | ) | | 6 | | | (42 | ) | | 174 | |
Total assets | | | 29,336 | | | 1,426 | | | 167 | | | 778 | | | 878 | | | 32,585 | |
Total goodwill | | | 5,981 | | | 24 | | | 37 | | | 75 | | | -- | | | 6,117 | |
Property additions | | | 91 | | | 44 | | | 1 | | | -- | | | 2 | | | 138 | |
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.
FIRSTENERGY CORP. | |
| | | | | | | |
CONSOLIDATED STATEMENTS OF INCOME | |
(Unaudited) | |
| | | | | | | |
| | | | Three Months Ended | |
| | | | March 31, | |
| | | | 2005 | | 2004 | |
| | | | | | | |
| (In thousands, except per share amounts) |
REVENUES: | | | | | | | |
Electric utilities | | | | | $ | 2,308,516 | | $ | 2,177,033 | |
Unregulated businesses (Note 2) | | | | | | 504,196 | | | 819,505 | |
Total revenues | | | | | | 2,812,712 | | | 2,996,538 | |
| | | | | | | | | | |
EXPENSES: | | | | | | | | | | |
Fuel and purchased power (Note 2) | | | | | | 895,332 | | | 1,134,326 | |
Other operating expenses | | | | | | 905,388 | | | 812,642 | |
Provision for depreciation | | | | | | 142,632 | | | 145,850 | |
Amortization of regulatory assets | | | | | | 310,841 | | | 310,202 | |
Deferral of new regulatory assets | | | | | | (59,507 | ) | | (44,405 | ) |
General taxes | | | | | | 185,179 | | | 178,990 | |
Total expenses | | | | | | 2,379,865 | | | 2,537,605 | |
| | | | | | | | | | |
INCOME BEFORE INTEREST AND INCOME TAXES | | | | | | 432,847 | | | 458,933 | |
| | | | | | | | | | |
NET INTEREST CHARGES: | | | | | | | | | | |
Interest expense | | | | | | 164,657 | | | 172,510 | |
Capitalized interest | | | | | | (255 | ) | | (6,470 | ) |
Subsidiaries’ preferred stock dividends | | | | | | 6,553 | | | 5,281 | |
Net interest charges | | | | | | 170,955 | | | 171,321 | |
| | | | | | | | | | |
INCOME TAXES | | | | | | 121,104 | | | 115,086 | |
| | | | | | | | | | |
INCOME BEFORE DISCONTINUED OPERATIONS | | | | | | 140,788 | | | 172,526 | |
| | | | | | | | | | |
Discontinued operations (net of income taxes (benefit) of ($7,598,000) | | | | | | | | | | |
and $1,028,000, respectively) (Note 6) | | | | | | 18,938 | | | 1,473 | |
| | | | | | | | | | |
NET INCOME | | | | | $ | 159,726 | | $ | 173,999 | |
| | | | | | | | | | |
BASIC EARNINGS PER SHARE OF COMMON STOCK: | | | | | | | | | | |
Income before discontinued operations | | | | | $ | 0.43 | | $ | 0.53 | |
Discontinued operations (Note 6) | | | | | | 0.06 | | | -- | |
Net income | | | | | $ | 0.49 | | $ | 0.53 | |
| | | | | | | | | | |
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING | | | | | | 327,908 | | | 327,057 | |
| | | | | | | | | | |
DILUTED EARNINGS PER SHARE OF COMMON STOCK: | | | | | | | | | | |
Income before discontinued operations | | | | | $ | 0.42 | | $ | 0.53 | |
Discontinued operations (Note 6) | | | | | | 0.06 | | | -- | |
Net income | | | | | $ | 0.48 | | $ | 0.53 | |
| | | | | | | | | | |
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING | | | | | | 329,427 | | | 329,034 | |
| | | | | | | | | | |
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK | | | | | $ | 0.4125 | | $ | 0.375 | |
| | | | | | | | | | |
| | | | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral partof these statements. | |
| | | | | | | | | | |
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 | |
| | | | | | | | | | | | | | | | | | | |
FIRSTENERGY CORP. | |
| | | | | | | | | |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | | | | |
| | | | Three Months Ended | |
| | | | March 31, | |
| | | | | | | | | |
| | | | 2005 | | | | 2004 | |
| | | | | | | | | |
| | | | (In thousands) | |
| | | | | | | | | |
NET INCOME | | | | | $ | 159,726 | | | | | $ | 173,999 | |
| | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | |
Unrealized gain on derivative hedges | | | | | | 7,323 | | | | | | 1,365 | |
Unrealized gain (loss) on available for sale securities | | | | | | (7,986 | ) | | | | | 16,938 | |
Other comprehensive income | | | | | | (663 | ) | | | | | 18,303 | |
Income tax related to other comprehensive income | | | | | | 129 | | | | | | (9,480 | ) |
Other comprehensive income (loss), net of tax | | | | | | (534 | ) | | | | | 8,823 | |
| | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | $ | 159,192 | | | | | $ | 182,822 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integralpart of these statements. | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
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. | | |
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.
FIRSTENERGY CORP. | |
| | | | | | | |
CONSOLIDATED BALANCE SHEETS | |
(Unaudited) | |
| | | | March 31, | | December 31, | |
| | | | 2005 | | 2004 | |
| | | | (In thousands) | |
ASSETS | | | �� | | | | |
CURRENT ASSETS: | | | | | | | |
Cash and cash equivalents | | | | | $ | 81,191 | | $ | 52,941 | |
Receivables- | | | | | | | | | | |
Customers (less accumulated provisions of $31,457,000 and | | | | | | | | | | |
$34,476,000, respectively, for uncollectible accounts) | | | | | | 983,488 | | | 979,242 | |
Other (less accumulated provisions of $32,807,000 and | | | | | | | | | | |
$26,070,000, respectively, for uncollectible accounts) | | | | | | 275,355 | | | 377,195 | |
Materials and supplies, at average cost- | | | | | | | | | | |
Owned | | | | | | 378,951 | | | 363,547 | |
Under consignment | | | | | | 98,917 | | | 94,226 | |
Prepayments and other | | | | | | 248,388 | | | 145,196 | |
| | | | | | 2,066,290 | | | 2,012,347 | |
PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | | |
In service | | | | | | 22,294,674 | | | 22,213,218 | |
Less - Accumulated provision for depreciation | | | | | | 9,479,701 | | | 9,413,730 | |
| | | | | | 12,814,973 | | | 12,799,488 | |
Construction work in progress | | | | | | 735,090 | | | 678,868 | |
| | | | | | 13,550,063 | | | 13,478,356 | |
INVESTMENTS: | | | | | | | | | | |
Nuclear plant decommissioning trusts | | | | | | 1,604,062 | | | 1,582,588 | |
Investments in lease obligation bonds | | | | | | 918,632 | | | 951,352 | |
Other | | | | | | 734,419 | | | 740,026 | |
| | | | | | 3,257,113 | | | 3,273,966 | |
DEFERRED CHARGES: | | | | | | | | | | |
Regulatory assets | | | | | | 5,606,433 | | | 5,532,087 | |
Goodwill | | | | | | 6,033,728 | | | 6,050,277 | |
Other | | | | | | 746,936 | | | 720,911 | |
| | | | | | 12,387,097 | | | 12,303,275 | |
| | | | | $ | 31,260,563 | | $ | 31,067,944 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | | | |
Currently payable long-term debt | | | | | $ | 960,168 | | $ | 940,944 | |
Short-term borrowings | | | | | | 310,125 | | | 170,489 | |
Accounts payable | | | | | | 663,018 | | | 610,589 | |
Accrued taxes | | | | | | 687,341 | | | 657,219 | |
Other | | | | | | 1,022,302 | | | 929,194 | |
| | | | | | 3,642,954 | | | 3,308,435 | |
CAPITALIZATION: | | | | | | | | | | |
Common stockholders’ equity- | | | | | | | | | | |
Common stock, $.10 par value, authorized 375,000,000 shares- | | | | | | | | | | |
329,836,276 shares outstanding | | | | | | 32,984 | | | 32,984 | |
Other paid-in capital | | | | | | 7,058,484 | | | 7,055,676 | |
Accumulated other comprehensive loss | | | | | | (313,646 | ) | | (313,112 | ) |
Retained earnings | | | | | | 1,881,047 | | | 1,856,863 | |
Unallocated employee stock ownership plan common stock- | | | | | | | | | | |
1,821,553 and 2,032,800 shares, respectively | | | | | | (37,916 | ) | | (43,117 | ) |
Total common stockholders' equity | | | | | | 8,620,953 | | | 8,589,294 | |
Preferred stock of consolidated subsidiaries | | | | | | 238,719 | | | 335,123 | |
Long-term debt and other long-term obligations | | | | | | 9,719,893 | | | 10,013,349 | |
| | | | | | 18,579,565 | | | 18,937,766 | |
NONCURRENT LIABILITIES: | | | | | | | | | | |
Accumulated deferred income taxes | | | | | | 2,346,766 | | | 2,324,097 | |
Asset retirement obligations | | | | | | 1,095,105 | | | 1,077,557 | |
Power purchase contract loss liability | | | | | | 2,160,867 | | | 2,001,006 | |
Retirement benefits | | | | | | 1,255,077 | | | 1,238,973 | |
Lease market valuation liability | | | | | | 915,050 | | | 936,200 | |
Other | | | | | | 1,265,179 | | | 1,243,910 | |
| | | | | | 9,038,044 | | | 8,821,743 | |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 12) | | | | | | | | | | |
| | | | | $ | 31,260,563 | | $ | 31,067,944 | |
| | | | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part ofthese balance sheets. | |
| | | | | | | | | | |
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 | |
| | | | | | | | | | | | | |
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. | | |
| | | | | | | | | | | | | |
FIRSTENERGY CORP. | |
| | | | | | | |
CONSOLIDATED STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | | |
| | | | Three Months Ended | |
| | | | March 31, | |
| | | | 2005 | | 2004 | |
| | | | | | | |
| | | | (In thousands) | |
| | | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | |
Net income | | | | | $ | 159,726 | | $ | 173,999 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | | | |
Provision for depreciation | | | | | | 142,632 | | | 145,850 | |
Amortization of regulatory assets | | | | | | 310,841 | | | 310,202 | |
Deferral of new regulatory assets | | | | | | (59,507 | ) | | (44,405 | ) |
Nuclear fuel and lease amortization | | | | | | 18,648 | | | 21,874 | |
Other amortization, net | | | | | | (5,451 | ) | | (4,723 | ) |
Deferred purchased power and other costs | | | | | | (109,233 | ) | | (83,907 | ) |
Deferred income taxes and investment tax credits, net | | | | | | (14,156 | ) | | 5,923 | |
Deferred rents and lease market valuation liability | | | | | | (35,663 | ) | | (16,297 | ) |
Accrued retirement benefit obligations | | | | | | 16,103 | | | 24,636 | |
Accrued compensation, net | | | | | | (41,722 | ) | | 4,387 | |
Commodity derivative transactions, net | | | | | | 187 | | | (30,787 | ) |
Income from discontinued operations (Note 6) | | | | | | (18,938 | ) | | (1,473 | ) |
Decrease (Increase) in operating assets: | | | | | | | | | | |
Receivables | | | | | | 90,663 | | | 272,746 | |
Materials and supplies | | | | | | 7,457 | | | 21,580 | |
Prepayments and other current assets | | | | | | (106,122 | ) | | (47,031 | ) |
Increase (Decrease) in operating liabilities: | | | | | | | | | | |
Accounts payable | | | | | | 61,419 | | | (177,018 | ) |
Accrued taxes | | | | | | 40,712 | | | 30,902 | |
Accrued interest | | | | | | 108,601 | | | 86,281 | |
Other | | | | | | 2,593 | | | (44,888 | ) |
Net cash provided from operating activities | | | | | | 568,790 | | | 647,851 | |
| | | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | |
New Financing- | | | | | | | | | | |
Long-term debt | | | | | | -- | | | 581,558 | |
Short-term borrowings, net | | | | | | 139,811 | | | -- | |
Redemptions and Repayments- | | | | | | | | | | |
Preferred stock | | | | | | (97,900 | ) | | -- | |
Long-term debt | | | | | | (235,888 | ) | | (268,920 | ) |
Short-term borrowings, net | | | | | | -- | | | (387,541 | ) |
Net controlled disbursement activity | | | | | | (29,937 | ) | | (42,656 | ) |
Common stock dividend payments | | | | | | (135,306 | ) | | (122,465 | ) |
Net cash used for financing activities | | | | | | (359,220 | ) | | (240,024 | ) |
| | | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | |
Property additions | | | | | | (228,884 | ) | | (138,406 | ) |
Proceeds from asset sales | | | | | | 53,724 | | | 11,439 | |
Nonutility generation trust contributions | | | | | | -- | | | (50,614 | ) |
Contributions to nuclear decommissioning trusts | | | | | | (25,370 | ) | | (25,370 | ) |
Cash investments | | | | | | 26,904 | | | 20,218 | |
Other | | | | | | (7,694 | ) | | (58,800 | ) |
Net cash used for investing activities | | | | | | (181,320 | ) | | (241,533 | ) |
| | | | | | | | | | |
Net increase in cash and cash equivalents | | | | | | 28,250 | | | 166,294 | |
Cash and cash equivalents at beginning of period | | | | | | 52,941 | | | 113,975 | |
Cash and cash equivalents at end of period | | | | | $ | 81,191 | | $ | 280,269 | |
| | | | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part ofthese statements. | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
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. | | | | | | | | | | | | | |
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. | | | | | | | |
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. | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
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 March 31,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 March 31,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
May 3,November 1, 2005
FIRSTENERGY CORP.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
EXECUTIVE SUMMARY
Net income in the firstthird quarter of 2005 was $160 million, or basic earnings of $0.49 per share of common stock ($0.48 diluted), compared to net income of $174$332 million, or basic and diluted earnings of $0.53$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 firstthird quarter of 2004. DuringNet income in the quarter, FirstEnergy continued to divest non-core assets, including the salefirst nine months of FirstEnergy’s retail natural gas business. These activities resulted in a combined net gain for the quarter2005 was $670 million, or basic earnings of $0.07$2.04 per share of common stock.
The impactstock ($2.03 diluted) compared to $677 million in the first nine months of costs associated with FirstEnergy’s settlement2004, or basic earnings of the W. H. Sammis New Source Review (NSR) case and a proposed NRC fine related to the 2002 outage at the Davis-Besse nuclear power plant reduced earnings for the quarter by $0.05$2.07 per share of common stock. Also,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 operationfleet 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 maintenance costdistribution 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.
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 associatedafter 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 scheduled outagesIndustrial 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 Perry nuclear power plants, combined with an unplanned outage at the Perry plant, reduced earnings per share by $0.12 compared withremaining amount in the first quarter of 2004.2005. 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.
On March 18, 2005, FirstEnergy announced on September 22, 2005, that it had reached a settlement withFGCO plans to install an Electro-Catalytic Oxidation (ECO) system on the U.S. EPA, the U.S. Department215-megawatt Unit 4 of Justice, and three states that resolved all issues related to various parties’ actions against FirstEnergy’s W. H. Sammisits Bay Shore Plant in the pending NSR case. The agreement,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 is in the form ofFirstEnergy has a consent decree, also was signed by the states of Connecticut, New Jersey and New York and was filed with the Court.minority ownership interest.
Under the agreement, FirstEnergy will install environmental controlsECO is currently being demonstrated at all seven units of the SammisFGCO's R. E. Burger Plant, as well as at other power plants. FirstEnergy will also upgrade existing scrubber systems on units 1 through 3 of its Bruce Mansfield Plant. Projects at the Sammis Plant will include equipment designed to reduce 95 percent ofand has proven effective in reducing NOx, SO2 emissions, mercury, acid gases, and 90 percent of NOx emissions onfine particulates (soot). The ECO process also produces a highly marketable ammonium sulfate fertilizer co-product, currently being sold to the plant’s two largest units. Additionally, the plant’s five smaller units will be controlled by equipment designed to reduce at least 50 percent of SO2 and 70 percent of NOx emissions. In total, additional environmental controls could be installed on nearly 5,500 MW of FirstEnergy’s 7,400 MW coal-based generating capacity, with construction beginning in 2005 and completed no later than 2012. The estimated $1.1 billion investment in environmental improvements is consistent with assumptions reflected in the Companies’ long-term financial planning.fertilizer market.
On March 15, 2005, membersFGCO expects design engineering of the International BrotherhoodBay Shore ECO system to commence in the first quarter of Electrical Workers System Council U-3 ratified a new four-year contract with FirstEnergy subsidiary JCP&L. Ratification2006, and estimates the overall cost of the contract resolved issues surrounding health care and work rules, and endedsystem, including a 14-week strike against JCP&L by the Council’s members.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 transmit, distributetransmits, distributes and sell electric powersells electricity through eight electric utility operating companies that collectively comprise the nation’s fifth largest investor-owned electric system, serving 4.44.5 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. |
· | 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 theFirstEnergy's generating facilities of the Ohio Companies and Penn 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 leases fossil facilities from the EUOC andalso purchases the entire output of the EUOC nuclear plants.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, process piping, plumbing, electrical and facility control systems, high-efficiency electrotechnologies and telecommunication services. FirstEnergy continues to divest theseis 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.
RESULTS OF OPERATIONS
The financial results discussed below include revenues and expenses from transactions among ourFirstEnergy's business segments. A reconciliation of segment financial results is provided in Note 1516 to the consolidated financial statements. The FSG business segment is included in "Other“Other and Reconciling Adjustments"Adjustments” in this discussion due to its immaterial impact on current period financial results, but is presented separately in segment information provided in Note 1516 to the consolidated financial statements. Net income (loss) by major business segment wasis as follow:follows:
| | | | | Three Months Ended | | | Nine Months Ended | | |
| | Three Months Ended | | | | | | | September 30, | | Increase | | September 30, | | Increase | |
| | March 31, | | Increase | | | | | 2005 | | 2004 | | (Decrease) | | 2005 | | 2004 | | (Decrease) | |
| | 2005 | | 2004 | | (Decrease) | | | | | (In millions, except per share amounts) | |
Net Income (Loss) | | (In millions) | | | | | | | | | | | | | | | | |
By Business Segment | | | | | | | | |
Regulated services | | $ | 223 | | $ | 213 | | $ | 10 | | |
By Business Segment: | | | | | | | | | | | | | | | | |
Regulated Services | | | | $ | 366 | | $ | 315 | | $ | 51 | | $ | 856 | | $ | 761 | | $ | 95 | |
Power supply management services | | | (36 | ) | | (2 | ) | | (34 | ) | | | 10 | | 44 | | (34 | ) | | (15 | ) | | 79 | | (94 | ) |
Other and reconciling adjustments* | | | (27 | ) | | (37 | ) | | 10 | | | | | | (44 | ) | | (60 | ) | | 16 | | | (171 | ) | | (163 | ) | | (8 | ) |
Total | | $ | 160 | | $ | 174 | | $ | (14 | ) | | | | $ | 332 | | $ | 299 | | $ | 33 | | $ | 670 | | $ | 677 | | $ | (7 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Basic Earnings Per Share: | | | | | | | | | | | | | | | | | | | | | | | | | |
Income before discontinued operations | | $ | 0.43 | | $ | 0.53 | | $ | (0.10 | ) | | | $ | 1.01 | | $ | 0.90 | | $ | 0.11 | | $ | 1.99 | | $ | 2.05 | | $ | (0.06 | ) |
Discontinued operations | | $ | 0.06 | | $ | -- | | $ | 0.06 | | | | | -- | | | 0.01 | | | (0.01 | ) | | 0.05 | | | 0.02 | | | 0.03 | |
Net Income | | $ | 0.49 | | $ | 0.53 | | $ | (0.04 | ) | |
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 | | $ | 0.42 | | $ | 0.53 | | $ | (0.11 | ) | | | $ | 1.01 | | $ | 0.90 | | $ | 0.11 | | $ | 1.98 | | $ | 2.04 | | $ | (0.06 | ) |
Discontinued operations | | $ | 0.06 | | $ | -- | | $ | 0.06 | | | | | -- | | | 0.01 | | | (0.01 | ) | | 0.05 | | | 0.02 | | | 0.03 | |
Net Income | | $ | 0.48 | | $ | 0.53 | | $ | (0.05 | ) | |
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. | | * Represents other operating segments and reconciling items including interest expense on holding company debt and corporate support services revenues and expenses. | |
* 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 first quarter ofregulated services segment for the three months and nine months ended September 30, 2005 included after-tax earnings from discontinued operations of $19 million ($0.06 per basic and diluted share) resulting from FirstEnergy’s disposition of non-core assets and operations. In the first quarter of 2005, discontinued operations included $17 million from net gains on sales (see“Other - First Quarter 2005 Comparedincreased due to First Quarter 2004” below) and $2 million from operations. In the first quarter of 2004,additional customer demand. However, net income included $1 millionfor 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 discontinued operations.increased electric generation sales.
A decrease in wholesale electric revenues and purchased power costs in the first quarter of 2005 fromperiods compared to the same periodcorresponding 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 the same period of 2004.2004 (See Note 2 - Accounting for Wholesale Energy Transactions). This change had no impact on earnings and was caused byresulted from the dedication of FirstEnergy’s Beaver Valley PlantPower Station to PJM in January 2005. FirstEnergy believes that this economic change required a net presentation of revenues and purchased power transactions as these generation assets are now dedicated in PJM where FirstEnergy has third-party customers. Wholesale electric revenues and purchased power costs in the first quarter ofthree months and nine months ended September 30, 2004 each included $280additional amounts of $264 million of theseand $828 million, respectively, due to recording those transactions recorded on a gross basis.
Excluding the effect of recording the wholesale electric revenue transactions in PJM on a gross basis in 2004, first quarter 2005total operating revenues were modestly higher. Net income declined primarily due toin the three months and nine months ended September 30, 2005 increased nuclear production costs from refueling outages14.9% and 8.7%, respectively, reflecting in large part warmer than normal temperatures during the Sammis environmental settlement. Results for the first quartersummer of 2005 were enhanced by reduced employee benefit costs (see“Postretirement Plans” below), gains on the sale of assets and reduced fossil production costs.compared to 2004.
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 firstthird 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 | | | |
1st Quarter 2005 | | Regulated | | Management | | Reconciling | | FirstEnergy | |
Financial Results | | Services | | Services | | Adjustments | | Consolidated | |
| | (In millions) | |
| | | | | | | | | |
Revenue: | | | | | | | | | |
External | | | | | | | | | |
Electric | | $ | 1,162 | | $ | 1,275 | | $ | -- | | $ | 2,437 | |
Other | | | 177 | | | 20 | | | 179 | | | 376 | |
Internal | | | 78 | | | -- | | | (78 | ) | | -- | |
Total Revenues | | | 1,417 | | | 1,295 | | | 101 | | | 2,813 | |
Expenses: | | | | | | | | | | | | | |
Fuel and purchased power | | | -- | | | 895 | | | -- | | | 895 | |
Other operating | | | 418 | | | 409 | | | 79 | | | 906 | |
Provision for depreciation | | | 126 | | | 10 | | | 7 | | | 143 | |
Amortization of regulatory assets | | | 311 | | | -- | | | -- | | | 311 | |
Deferral of new regulatory assets | | | (60 | ) | | -- | | | -- | | | (60 | ) |
General taxes | | | 146 | | | 32 | | | 7 | | | 185 | |
Total Expenses | | | 941 | | | 1,346 | | | 93 | | | 2,380 | |
| | | | | | | | | | | | | |
Net interest charges | | | 98 | | | 10 | | | 63 | | | 171 | |
Income taxes | | | 155 | | | (25 | ) | | (9 | ) | | 121 | |
Income before discontinued operations | | | 223 | | | (36 | ) | | (46 | ) | | 141 | |
Discontinued operations | | | -- | | | -- | | | 19 | | | 19 | |
Net Income | | $ | 223 | | $ | (36 | ) | $ | (27 | ) | $ | 160 | |
| | | | 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 | |
| | | | Power | | | | | |
| | | | Supply | | Other and | | | |
1st Quarter 2004 | | Regulated | | Management | | Reconciling | | FirstEnergy | |
Financial Results | | Services | | Services | | Adjustments | | Consolidated | |
| | (In millions) | |
| | | | | | | | | |
Revenue: | | | | | | | | | |
External | | | | | | | | | |
Electric | | $ | 1,154 | | $ | 1,502 | | $ | -- | | $ | 2,656 | |
Other | | | 136 | | | 20 | | | 185 | | | 341 | |
Internal | | | 79 | | | -- | | | (79 | ) | | -- | |
Total Revenues | | | 1,369 | | | 1,522 | | | 106 | | | 2,997 | |
Expenses: | | | | | | | | | | | | | |
Fuel and purchased power | | | -- | | | 1,134 | | | -- | | | 1,134 | |
Other operating | | | 366 | | | 346 | | | 101 | | | 813 | |
Provision for depreciation | | | 127 | | | 9 | | | 10 | | | 146 | |
Amortization of regulatory assets | | | 310 | | | -- | | | -- | | | 310 | |
Deferral of new regulatory assets | | | (44 | ) | | -- | | | -- | | | (44 | ) |
General taxes | | | 147 | | | 25 | | | 7 | | | 179 | |
Total Expenses | | | 906 | | | 1,514 | | | 118 | | | 2,538 | |
| | | | | | | | | | | | | |
Net interest charges | | | 105 | | | 11 | | | 55 | | | 171 | |
Income taxes | | | 145 | | | (1 | ) | | (29 | ) | | 115 | |
Income before discontinued operations | | | 213 | | | (2 | ) | | (38 | ) | | 173 | |
Discontinued operations | | | -- | | | -- | | | 1 | | | 1 | |
Net Income | | $ | 213 | | $ | (2 | ) | $ | (37 | ) | $ | 174 | |
| | | | Power | | | | | | |
Change Between | | | | Supply | | Other and | | FirstEnergy | | | | | Power | | | | | |
1st Quarter 2005 and 2004 | | Regulated | | Management | | Reconciling | | Consolidated | | |
Financial Results | | Services | | Services | | Adjustments | | Total | | |
3rd Quarter 2005 and 2004 | | | | | Supply | | Other and | | | |
Quarterly Financial Results | | | Regulated | | Management | | Reconciling | | FirstEnergy | |
Increase (Decrease) | | (In millions) | | | Services | | Services | | Adjustments(1) | | Consolidated | |
| | | | | | | | | | | (In millions) | |
Revenue: | | | | | | | | | | | | | | | | | | |
External | | | | | | | | | | | | | | | | | | |
Electric | | $ | 8 | | $ | (227 | ) | $ | -- | | $ | (219 | ) | | $ | 123 | | $ | (37 | ) | $ | -- | | $ | 86 | |
Other | | | 41 | | | -- | | | (6 | ) | | 35 | | | | 72 | | (7 | ) | | 51 | | 116 | |
Internal | | | (1 | ) | | -- | | | 1 | | | -- | | | | (1 | ) | | -- | | | 1 | | | -- | |
Total Revenues | | | 48 | | | (227 | ) | | (5 | ) | | (184 | ) | | | 194 | | | (44 | ) | | 52 | | | 202 | |
| | | | | | | | | | | |
Expenses: | | | | | | | | | | | | | | | | | | | | | | | |
Fuel and purchased power | | | -- | | | (239 | ) | | -- | | | (239 | ) | | | -- | | 2 | | -- | | 2 | |
Other operating | | | 52 | | | 63 | | | (22 | ) | | 93 | | | | 97 | | 8 | | 19 | | 124 | |
Provision for depreciation | | | (1 | ) | | 1 | | | (3 | ) | | (3 | ) | | | 8 | | -- | | (2 | ) | | 6 | |
Amortization of regulatory assets | | | 1 | | | -- | | | -- | | | 1 | | | | 40 | | -- | | -- | | 40 | |
Deferral of new regulatory assets | | | (16 | ) | | -- | | | -- | | | (16 | ) | | | (45 | ) | | -- | | | -- | | | (45 | ) |
General taxes | | | (1 | ) | | 7 | | | -- | | | 6 | | | | 9 | | | 1 | | | -- | | | 10 | |
Total Expenses | | | 35 | | | (168 | ) | | (25 | ) | | (158 | ) | | | 109 | | | 11 | | | 17 | | | 137 | |
| | | | | | | | | | | | | | | | | | | | | | | |
Net interest charges | | | (7 | ) | | (1 | ) | | 8 | | | -- | | | | 6 | | 2 | | (1 | ) | | 7 | |
Income taxes | | | 10 | | | (24 | ) | | 20 | | | 6 | | | | 28 | | | (23 | ) | | 18 | | | 23 | |
Income before discontinued operations | | | 10 | | | (34 | ) | | (8 | ) | | (32 | ) | | | 51 | | (34 | ) | | 18 | | 35 | |
Discontinued operations | | | -- | | | -- | | | 18 | | | 18 | | | | -- | | | -- | | | (2 | ) | | (2 | ) |
Net Income | | $ | 10 | | $ | (34 | ) | $ | 10 | | $ | (14 | ) | |
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. | | (1) The impact of the new Ohio tax legislation is included with FirstEnergy’s other operating segments and reconciling adjustments. |
Regulated Services - FirstThird Quarter 2005 Compared to Firstwith Third Quarter 2004
Net income increased $51 million, or 16% to $223$366 million, from $213 million (or 5%) in the firstthird quarter of 2005 withcompared to $315 million in the third quarter of 2004, as a result of increased operating revenues partially offset by higher operating expenses and taxes.customer usage.
Revenues - -
The increaseTotal revenues increased by $194 million in total revenues resultedthe third quarter 2005 compared to the same period in 2004, resulting from the following sources:
| | Three Months Ended | | | | | Three Months Ended | | |
Revenues | | March 31, | | Increase | | |
By Type of Service | | 2005 | | 2004 | | (Decrease) | | |
| | | September 30, | | | |
Revenues by Type of Service | | | 2005 | | 2004 | | Increase | |
| | (In millions) | | | (In millions) |
| | | | | | | | | | | | | | |
Distribution services | | $ | 1,162 | | $ | 1,154 | | $ | 8 | | | $ | 1,432 | | $ | 1,309 | | $ | 123 | |
Transmission services | | | 92 | | | 62 | | | 30 | | | | 117 | | 81 | | 36 | |
Lease revenue from affiliates | | | 78 | | | 79 | | | (1 | ) | | | 79 | | 79 | | -- | |
Other | | | 85 | | | 74 | | | 11 | | | | 127 | | | 92 | | | 35 | |
Total Revenues | | $ | 1,417 | | $ | 1,369 | | $ | 48 | | | $ | 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 | |
Electric Distribution Deliveries
| | (Decrease)
| |
Residential | | | (0.6 | ) | | 15.4 | % |
Commercial | | | 4.7 | | | 7.8 | % |
Industrial | | | 4.3 | | | 5.2 | % |
Total Distribution Deliveries | | | 2.6 | | | 9.6 | % |
| | | | | | | |
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 $8$123 million increase in distribution serviceservices revenue in the firstthird quarter of 2005:
| | | Increase | |
Sources of Change in Distribution Revenues | | | | | (Decrease) | |
Increase (Decrease) | | (In millions) | | |
| | | (In millions) | |
| | | | | | |
Changes in customer usage | | $ | 23 | | | $ | 135 | |
Changes in prices: | | | | | | | | |
Rate changes -- | | | | | | | | |
Ohio shopping incentive | | | (11 | ) | |
Other | | | 1 | | |
Rate mix & other | | | (5 | ) | |
| | | | | |
Ohio shopping credits | | | | (11 | ) |
JCP&L rate settlements | | | | 21 | |
Billing component reallocations | | | | (22 | ) |
Net Increase in Distribution Revenues | | $ | 8 | | | $ | 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 $30$36 million in the firstthird quarter of 2005 from the same period last year due in part to an amended power supply agreement with FES in June 2004. The amended agreement resulted in the regulated services segment assuming certainincreased loads due to warmer weather and higher transmission revenues and expenses that were previously attributed to FES.
usage prices. Other revenues increased $11$35 million primarily due to a payment received under a contract provision associated with the prior sale of TMI. Under the contract, additional payments are received if subsequent energy prices rise above specified levels. These payments are passed along to JCP&L, Met-Ed and Penelec customers, resulting in no net earnings effect.higher gains realized on nuclear decommissioning trust investments.
Expenses-
The higherincrease in total revenues discussed above werewas 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 transmission expense of $43 million due in part to an amended power supply agreement with FES, which also increased revenue and other operating costsgeneral taxes of $9 million;million resulting from increased EUOC sales which increased the Ohio KWH tax and |
the Pennsylvania gross receipts tax;
· | Increased income taxes of $10 million due to increased taxable income. |
Partially offsetting these higher costs were two factors:· 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
· | Additional deferrals of regulatory assets of $16 million, primarily representing shopping incentives and interest on those deferrals; and |
· Higher income taxes of $28 million due to increased taxable income.
· | Lower interest charges of $7 million primarily due to debt and preferred stock redemptions. |
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 - FirstThird Quarter 2005 Compared to Firstwith Third Quarter 2004
The net lossNet income for this segment increaseddecreased $34 million to $36$10 million in the firstthird quarter of 2005 from a net loss of $2$44 million in the same period last year. An improvementyear, due to a decrease in the gross generation margin was more than offset byand higher non-fuel nuclear costs, resulting in the increased net loss.operating costs.
Generation Margin -
The gross generation margin in the first quarter of 2005 improved by $12 million compared to the same period of 2004, as shown in the table below.
Gross Generation Margin | | 2005 | | 2004 | | Increase (Decrease) | |
| | (In millions) | |
Electric generation revenue | | $ | 1,275 | | $ | 1,502 | | $ | (227 | ) |
Fuel and purchased power costs | | | 895 | | | 1,134 | | | (239 | ) |
Gross Generation Margin | | $ | 380 | | $ | 368 | | $ | 12 | |
Revenues - -
Excluding the effect of the change in recording PJM wholesale transactions on a gross basis in 2004 ($264 million), electric generation revenues increased $53$227 million in the firstthird quarter of 2005 compared to the same period of 2004 primarily as a result of a 0.4%5.2% increase in KWH sales due to higher retail customer usage and highera 21% rise in unit prices.Additionalprices in the wholesale market. The increase in retail sales reduced energy available for salessale to the wholesale market.market, resulting in a 9% reduction in wholesale sales (before the PJM adjustment).
A decreaseThe change in reported segment revenues resulted from the following sources: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.
| | Three Months Ended | | | |
Revenues | | March 31, | | Increase | |
By Type of Service | | 2005 | | 2004 | | (Decrease) | |
| | (In millions) | |
| | | | | | | |
Electric Generation Sales: | | | | | | | |
Retail | | $ | 980 | | $ | 934 | | $ | 46 | |
Wholesale | | | 295 | | | 288 | | | 7 | |
Total Electric Generation Sales | | | 1,275 | | | 1,222 | | | 53 | |
Transmission | | | 10 | | | 16 | | | (6 | ) |
Other | | | 10 | | | 4 | | | 6 | |
Total | | | 1,295 | | | 1,242 | | | 53 | |
PJM gross transactions | | | -- | | | 280 | | | (280 | ) |
Total Revenues | | $ | 1,295 | | $ | 1,522 | | $ | (227 | ) |
| | 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. | |
Changes in KWH sales are summarized in the following table:
| | Increase
| |
Electric Generation
| | (Decrease)
| |
| | | |
Retail | | | 1.2 | % |
| | | | |
Wholesale | | | (49.4 | )% |
| | | | |
Total Electric Generation | | | (15.9 | )%* |
*Increase of 0.4% excluding the effect of the PJM revision.
Expenses - -
Excluding the effect of the $280$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 $87$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. TheFactors 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 wasfossil 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 following factors: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.
· | Higher fuel and purchased power costs of $41 million, which include increased fuel costs of $34 million due to a greater reliance on higher cost fossil units during the nuclear refueling outages, and increased purchased power costs of $7 million; |
· | Increased non-fuel nuclear costs of $66 million due primarily to a refueling outage at the Perry nuclear plant (including an unplanned extension), a scheduled 23-day mid-cycle inspection outage at the Davis-Besse nuclear plant in the first quarter of 2005 and the absence of nuclear scheduled outages in the same period last year; |
· | Accrual of an $8.5 million civil penalty payable to the Department of Justice and $10 million for obligations to three states in connection with the Sammis Plant settlement; |
· | Accrual of $3.5 million for a proposed NRC fine related to the 2002 Davis-Besse outage; and |
· | Higher general taxes of $7 million due to additional gross receipts tax and payroll taxes. |
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.
Partially offsetting these amountsOffsetting higher operating costs were the following factors:lower income taxes of $23 million due to lower taxable income.
· | Lower transmission costs of $26 million due in part to an amended power supply agreement that resulted in the regulated services segment assuming certain transmission obligations previously borne by the power supply management services segment; and |
· | Lower income taxes of $24 million due to lower taxable income. |
Other - FirstThird Quarter 2005 Compared to Firstwith Third Quarter 2004
FirstEnergy’s financial results from other operating segments and reconciling items,adjustments, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a net improvementincrease of $16 million in FirstEnergy’s net income in the firstthird 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.
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 | |
| | | | | | | | | | | | | | | |
| | | | | 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 | % |
| | | | |
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. |
| 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. | |
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 from discontinued operationsin 2005 (see Note 6). The following table summarizes the sources of income from discontinued operations:
Other - First Quarter 2005 Compared to First Quarter 2004
| | 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 | |
| | | | | | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | 2005 | | 2004 | |
| | (In millions) | |
Discontinued Operations (Net of tax) | | | | | |
Gain on sale: | | | | | |
Natural gas business | | $ | 5 | | $ | -- | |
Elliot-Lewis, Spectrum and Power Piping | | | 12 | | | -- | |
Reclassification of operating income | | | 2 | | | 1 | |
Total | | $ | 19 | | $ | 1 | |
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 PlansBenefits
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 were lowerrepresent most of the reduction due to last year’sa $500 million voluntary contribution made in 2004 and an increase in the market value of pension plan assets during 2004. Combined with amendments to FirstEnergy’s health care plan in the first quarter of 2004, employee benefit expenses decreased by $20 million in the first quarter of 2005 compared to the same period in 2004. The following table summarizes the net pension and OPEB expense (excluding amounts capitalized) for the three months and nine months ended March 31,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). | | |
| | Three Months Ended | |
Postretirement Benefits Expense(1) | | March 31, | |
| | 2005 | | 2004 | |
| | (In millions) | |
| | | | | |
Pension | | $ | 8 | | $ | 20 | |
OPEB | | | 18 | | | 26 | |
Total | | $ | 26 | | $ | 46 | |
(1)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. Available borrowingBorrowing capacity under credit facilities will be usedis available to manage working capital requirements. Thereafter, FirstEnergy expects to use a combination of cash from operations and funds from the capital markets.
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 $1.375$2.0 billion of short-term financing under a revolving credit facilities.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 firstthird quarter of 2005, FirstEnergy received $137$306 million of cash dividends from its subsidiaries and paid $135$141 million in cash dividends to its common shareholders.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 March 31,September 30, 2005, FirstEnergy had $81$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.
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 “RESULTS OF OPERATIONS”OPERATIONS” above). Net cash provided fromby operating activities was $569$981 million and $528 million in the firstthird quarter of 2005 and $648 million2004, respectively, and $1.9 billion and $1.5 billion in the first quarternine months of 2005 and 2004, respectively, summarized as follows:
| | Three Months Ended | |
| | March 31, | |
Operating Cash Flows | | 2005 | | 2004 | |
| | (In millions) | |
| | | | | |
| | | | | |
Cash earnings(1) | | $ | 364 | | $ | 505 | |
Working capital and other | | | 205 | | | 143 | |
Total Cash Flows from Operating Activities | | $ | 569 | | $ | 648 | |
(1)Cash earnings are a non-GAAP measure (see reconciliation below).
| | 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, (inas disclosed in the table above)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. | |
| | Three Months Ended | |
| | March 31, | |
Reconciliation of Cash Earnings | | 2005 | | 2004 | |
| | (In millions) | |
| | | | | |
Net Income (GAAP) | | $ | 160 | | $ | 174 | |
Non-Cash Charges (Credits): | | | | | | | |
Provision for depreciation | | | 143 | | | 146 | |
Amortization of regulatory assets | | | 311 | | | 310 | |
Deferral of new regulatory assets | | | (60 | ) | | (44 | ) |
Nuclear fuel and lease amortization | | | 19 | | | 22 | |
Deferred purchased power and other costs | | | (109 | ) | | (84 | ) |
Deferred income taxes and investment tax credits | | | (14 | ) | | 6 | |
Deferred rents and lease market valuation liability | | | (36 | ) | | (16 | ) |
Income from discontinued operations | | | (19 | ) | | (1 | ) |
Other non-cash expenses | | | (31 | ) | | (8 | ) |
Cash Earnings (Non-GAAP) | | $ | 364 | | $ | 505 | |
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.
The $141 million decrease in cash earnings is described under "RESULTS OF OPERATIONS". The working capital increase primarily resulted from changes of $238 million in payables partially offset by a change of $182 million in receivables.
Cash Flows From Financing Activities
In the third quarter and first quartersnine months of 2005, and 2004, net cash used for financing activities of $359was $580 million and $240$1.0 billion, respectively, compared to $602 million respectively, primarily reflectedand $1.4 billion in the redemptionsthird quarter and first nine months of debt2004, respectively. The following table summarizes security issuances and preferred stock shown below.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 | ) |
| | Three Months Ended | |
| | March 31, | |
Securities Issued or Redeemed | | 2005 | | 2004 | |
| | (In millions) | |
New Issues | | | | | |
Pollution control notes | | $ | -- | | $ | 185 | |
Senior notes | | | -- | | | 250 | |
Unsecured notes | | | -- | | | 147 | |
| | $ | -- | | $ | 582 | |
Redemptions | | | | | | | |
First mortgage bonds | | $ | 1 | | $ | 92 | |
Secured notes | | | 20 | | | 42 | |
Long-term revolving credit | | | 215 | | | 135 | |
Preferred stock | | | 98 | | | -- | |
| | $ | 334 | | $ | 269 | |
| | | | | | | |
Short-term Borrowings, Net | | $ | 140 | | $ | (388 | ) |
FirstEnergy had approximately $310$247 million of short-term indebtedness as of March 31,September 30, 2005 compared to approximately $170 million as of December 31, 2004. Available bank borrowing capabilityborrowings as of March 31,September 30, 2005 included the following:
Borrowing Capability | | FirstEnergy | | OE | | Penelec | | Total | | | FirstEnergy | | Penelec | | Total | |
| | (In millions) | | | (In millions) | |
Long-term revolving credit | | $ | 1,375 | | $ | 375 | | $ | -- | | $ | 1,750 | | |
| | | | | | | | |
Short-term credit(1) | | | $ | 2,020 | | $ | - | | $ | 2,020 | |
Utilized | | | -- | | | -- | | | -- | | | -- | | | | - | | | - | | - | |
Letters of credit | | | (141 | ) | | -- | | | -- | | | (141 | ) | | | (137 | ) | | | - | | | (137 | ) |
Net | | | 1,234 | | | 375 | | | -- | | | 1,609 | | | | 1,883 | | | - | | | 1,883 | |
| | | | | | | | | | | | | | | | | | | | | |
Short-term bank facilities | | | -- | | | 34 | | | 100 | | | 134 | | |
Short-term bank facilities(2) | | | | - | | 75 | | 75 | |
Utilized | | | -- | | | -- | | | (100 | ) | | (100 | ) | | | - | | | (75 | ) | | (75 | ) |
Net | | | -- | | | 34 | | | -- | | | 34 | | | | - | | | - | | | - | |
Total Unused Borrowing Capability | | $ | 1,234 | | $ | 409 | | $ | -- | | $ | 1,643 | | |
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. | | (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. | | (2) Penelec bank facility terminated on October 7, 2005. |
As of March 31,October 24, 2005, the Ohio Companies and Penn had the aggregate capability to issue approximately $4.3$3.8 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures.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 $650$690 million and $565$582 million, respectively, as of March 31,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 March 31,October 24, 2005, JCP&L had the capability to issue $578$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 $4.0$4.9 billion of preferred stock (assuming no additional debt was issued) as of March 31,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.
As of March 31,September 30, 2005, approximately $1.0$1 billion remained unused under FirstEnergy'san 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 syndicated $1$2 billion three-yearfive-year revolving credit facility maturing(included in June 2007. Combined with FirstEnergy’s syndicated $375 million three-yearthe table above). Borrowings under the facility maturing in October 2006, a $125 million three-yearare 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, for OE maturing in October 2006,as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and a syndicated $250 million two-year facility for OE maturing in May 2005, primary syndicated credit facilities total $1.75 billion. Theseapplicable 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 facilities,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 $1.9$2.36 billion as of March 31,September 30, 2005.
Borrowings under these facilities are conditioned on maintaining compliance with certainThe revolving credit facility contains financial covenants in the agreements. FirstEnergy and OE arerequiring each requiredborrower to maintain a consolidated debt to total capitalization ratio of no more than 0.65 to 1 and1.00. On October 3, 2005, FirstEnergy obtained a contractually definedsenior unsecured debt rating upgrade to BBB- by S&P removing the requirement under the revolving credit facility to maintain a fixed charge coverage ratio of no less than 2at least 2.00 to 1. 1.00.
As of March 31,September 30, 2005, FirstEnergy’sFirstEnergy and OE’s fixed charge coverage ratios,subsidiaries’ debt to total capitalization as defined under the revolving credit agreements,facility, were 4.47 to 1 and 6.87 to 1, respectively. FirstEnergy's and OE's debt to total capitalization ratios, as defined under the credit agreements, were 0.55 to 1 and 0.40 to 1, respectively. The ability to draw on each of these facilities is also conditioned upon FirstEnergy or OE making certain representations and warranties to the lending banks prior to drawing on their respective facilities, including a representation that there has been no material adverse change in their business, condition (financial or otherwise), results of operations, or prospects.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 | |
Neither FirstEnergy's nor OE’s primary credit facilitiesThe facility does not contain any provisions that either restrict theirthe ability to borrow or accelerate repayment of outstanding advances as a result of any change in their credit ratings. Each primary facility does contain "pricing grids"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. For the regulated companies, available bank borrowings include $1.75 billion from FirstEnergy and OE’s revolving credit facilities. For the unregulated companies, available bank borrowings include only FirstEnergy’s $1.375 billion of revolving credit facilities. 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 firstthird quarter of 2005 was 2.66%3.50% for the regulated companies’ money pool and 2.68%3.46% for the unregulated companies' money pool.
On MarchJuly 18, 2005, S&PMoody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s Sammis NSR settlement was a very favorable step for FirstEnergy, although it would not immediately affectoutlook 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 ratings or outlook. S&Pcredit profile stemming from the application of free cash flow toward debt reduction. Moody’s noted that ita ratings upgrade could be considered if FirstEnergy continues to monitor the refueling outage at the Perry nuclear plant, which includes a detailed inspection by the NRC,achieve planned improvements in its operations and that if FirstEnergy should exit the outage without significant negative findings or delays the ratings outlook would be revised to positive.balance sheet.
On March 14,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 500,000of its 1,200,000 outstanding shares of its Serial Preferred Stock, $7.407.00% Series A preferred stock at a price of $101$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 redemption. Also on March 14, 2005, CEI redeemed all 474,000 outstanding shares of its Serial Preferred Stock, Adjustable Rate Series L at a price of $100 per share plus accrued dividendsintent to remarket them by the dateend of the redemption.first quarter of 2006.
On May 16, 2005, Penn intends to redeem 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.
On June 1, 2005, CEI intends to redeem all of its 40,000 outstanding shares of $7.35 Series C preferred stock at $101.00 per share, plus accrued dividends to the date of redemption.
Cash Flows From Investing Activities
Net cash flows used infor 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 first quarterthe investment activities for the three months and nine months ended September 30, 2005 and 2004 investments 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 | | | | | | | | | Property | | | | | | | |
Used for Investing Activities | | Additions | | Investments | | Other | | Total | | | Additions | | Investments | | Other | | Total | |
2005 First Quarter Sources (Uses) | | (In millions) | | |
Sources (Uses) | | | (In millions) |
| | | | | | | | | | | | | | | | | | |
Nine Months Ended September 30, 2005 | | | | | | | | | | |
Regulated services | | $ | (141 | ) | $ | 23 | | $ | 3 | | $ | (115 | ) | | $ | (506 | ) | $ | (13 | ) | $ | (5 | ) | $ | (524 | ) |
Power supply management services | | | (81 | ) | | (1 | ) | | -- | | | (82 | ) | | | (226 | ) | | - | | - | | (226 | ) |
Other | | | (3 | ) | | 16 | | | (13 | ) | | -- | | | | (6 | ) | | 19 | | (18 | ) | | (5 | ) |
Reconciling items | | | (4 | ) | | 20 | | | -- | | | 16 | | | | (18 | ) | | (9 | ) | | 5 | | | (22 | ) |
Total | | $ | (229 | ) | $ | 58 | | $ | (10 | ) | $ | (181 | ) | | $ | (756 | ) | $ | (3 | ) | $ | (18 | ) | $ | (777 | ) |
| | | | | | | | | | | | | | | | | | | | | | | |
2004 First Quarter Sources (Uses) | | | | | | | | | | | | | | |
Nine Months Ended September 30, 2004 | | | | | | | | | | | |
Regulated services | | $ | (91 | ) | $ | (49 | ) | $ | (2 | ) | $ | (142 | ) | | $ | (377 | ) | $ | 196 | | $ | (76 | ) | $ | (257 | ) |
Power supply management services | | | (44 | ) | | (1 | ) | | -- | | | (45 | ) | | | (149 | ) | | (14 | ) | | - | | (163 | ) |
Other | | | (1 | ) | | (7 | ) | | 2 | | | (6 | ) | | | (3 | ) | | 173 | | | 2 | | | 172 | |
Reconciling items | | | (2 | ) | | (27 | ) | | (20 | ) | | (49 | ) | | | (17 | ) | | 31 | | | 65 | | | 79 | |
Total | | $ | (138 | ) | $ | (84 | ) | $ | (20 | ) | $ | (242 | ) | | $ | (546 | ) | $ | 386 | | $ | (9 | ) | $ | (169 | ) |
| | | | | | | | | | | |
Net cash used for investing activities was $311 million in the firstthird quarter of 2005 was $61compared to $43 million lower compared withof cash provided from investing activities in the same period of 2004. The decreasechange was primarily due to higher proceeds of $42 million from assets sales (see Note 6 to the consolidated financial statements), the absence of a $51 million NUG trust contribution in 2004 and increased other investment earnings, partially offset by a $91an $83 million increase in property additions.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.
DuringIn the remaining three quarterslast quarter of 2005, capital requirements for property additions and capital leases are expected to be approximately $825 million, including $20 million for nuclear fuel.$378 million. FirstEnergy hasand the Companies have additional requirements of approximately $172$312 million to meet sinking fund requirements for preferred stock and 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 $3.3$3.5 billion (excluding nuclear fuel), of which $998 million$1.1 billion applies to 2005. Investments for additional nuclear fuel during the 2005-2007 periodperiods are estimated to be approximately $274$285 million, of which approximately $53$59 million applies to 2005. During the same period, FirstEnergy’s nuclear fuel investments are expected to be reduced by approximately $280$282 million and $86 million respectively, as the nuclear fuel is consumed.
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 March 31,September 30, 2005, the maximum potential future payments under outstanding guarantees and other assurances totaled $2.4$2.7 billion as summarized below:
| | Maximum | |
Guarantees and Other Assurances | | Exposure | |
| | (In millions) | |
| | | |
FirstEnergy Guarantees of Subsidiaries: | | | |
Energy and Energy-Related Contracts(1) | | $ | 909 | |
Other(2) | | | 149 | |
| | | 1,058 | |
| | | | |
Surety Bonds | | | 267 | |
Letters of Credit(3)(4) | | | 1,059 | |
| | | | |
Total Guarantees and Other Assurances | | $ | 2,384 | |
| | 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. |
| (1)
| Issued for a one-year term, with a 10-day termination right by FirstEnergy. |
| (2)
| Issued for various terms. |
| (3)
| Includes $141 million issued for various terms under LOC capacity available under
FirstEnergy’srevolving credit agreement and $299 million outstanding in support
of pollution control revenue bondsissued with various maturities.
|
| (4)
| Includes approximately $194 million pledged in connection with the sale and
leaseback of Beaver ValleyUnit 2 by CEI and TE, $291 million pledged in connection
with the sale and leaseback of Beaver Valley Unit 2by 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 “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 March 31,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 | |
| | | | | | | | | | | | | | | |
| | Total | | Collateral Paid | | Remaining | |
Collateral Provisions | | Exposure | | Cash | | LOC | | Exposure(1) | |
| | (In millions) | |
| | | | | | | | | |
Credit rating downgrade | | $ | 364 | | $ | 153 | | $ | 18 | | $ | 193 | |
Adverse event | | | 42 | | | -- | | | 8 | | | 34 | |
Total | | $ | 406 | | $ | 153 | | $ | 26 | | $ | 227 | |
| (1) | As of May 2, 2005, FirstEnergy’s total exposure decreased to $357 million and the remaining exposure decreased to
$183 million - net of $148 million of cash collateral and $26 million of LOC collateral provided to counterparties.
|
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.
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 (currently at $47 million)($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 reflected as part of thesatisfied through operating lease payments. The present value of these sale and leaseback operating lease commitments, net of trust investments, total $1.4$1.3 billion as of March 31, 2005.
CEI and TE sell substantially all of their retail customer receivables to CFC, a wholly owned subsidiary of CEI. CFC subsequently transfers the receivables to a trust (a "qualified special purpose entity" under SFAS 140) under an asset-backed securitization agreement. This arrangement provided $142 million of off-balance sheet financing as of March 31,September 30, 2005.
FirstEnergy has equity ownership interests in certain various businesses that are accounted for usingunder 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 marketprice risk primarily due to fluctuating electricity, natural gas, coal, nuclear fuel, and emission allowance prices.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 be marked to market. The majority of FirstEnergy’s derivative hedging contracts qualify for the normal purchases and normal sales exception under SFAS 133 exemption 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.Most of FirstEnergy’s non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. The change in the fair value of commodity derivative contracts related to energy production during the third quarter and first quarternine months of 2005 is summarized in the following table:
Increase (Decrease) in the Fair Value of Commodity Derivative Contracts | | | | | | | |
| | Non-Hedge | | Hedge | | Total | |
| | (In millions) | |
| | | | | | | |
Change in the Fair Value of Commodity Derivative Contracts: | | | | | | | |
Outstanding net asset as of January 1, 2005 | | $ | 62 | | $ | 2 | | $ | 64 | |
New contract value when entered | | | -- | | | -- | | | -- | |
Additions/change in value of existing contracts | | | (1 | ) | | 6 | | | 5 | |
Change in techniques/assumptions | | | -- | | | -- | | | -- | |
Settled contracts | | | (7 | ) | | 1 | | | (6 | ) |
Sale of retail natural gas contracts | | | 1 | | | (6 | ) | | (5 | ) |
| | | | | | | | | | |
Outstanding net asset as of March 31, 2005(1) | | $ | 55 | | $ | 3 | | $ | 58 | |
| | | | | | | | | | |
Non-commodity Net Assets as of March 31, 2005: | | | | | | | | | | |
Interest Rate Swaps(2) | | | -- | | | (27 | ) | | (27 | ) |
Net Assets - Derivatives Contracts as of March 31, 2005 | | $ | 55 | | $ | (24 | ) | $ | 31 | |
| | | | | | | | | | |
Impact of Changes in Commodity Derivative Contracts:(3) | | | | | | | | | | |
Income Statement Effects (Pre-Tax) | | $ | -- | | $ | -- | | $ | -- | |
Balance Sheet Effects: | | | | | | | | | | |
Other Comprehensive Income (Pre-Tax) | | $ | -- | | $ | 1 | | $ | 1 | |
Regulatory Liability | | $ | (7 | ) | $ | -- | | $ | (7 | ) |
(1)Includes $54 million in non-hedge commodity derivative contracts which are offset by a regulatory liability.
(2)Interest rate swaps are treated as fair value hedges. Changes in derivative values are offset by changes in the hedged debts' premium or | | 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. |
discount (see Interest Rate Swap Agreements below).
(3)Represents the change in value of existing contracts, settled contracts and changes in techniques/assumptions.
Derivatives are included on the Consolidated Balance Sheet as of March 31,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 | |
| | | | | | | | | | |
Balance Sheet Classification | | Non-Hedge | | Hedge | | Total | |
| | (In millions) | |
Current- | | | | | | | |
Other assets | | $ | -- | | $ | 2 | | $ | 2 | |
Other liabilities | | | (1 | ) | | -- | | | (1 | ) |
| | | | | | | | | | |
Non-Current- | | | | | | | | | | |
Other deferred charges | | | 56 | | | 2 | | | 58 | |
Other noncurrent liabilities | | | -- | | | (28 | ) | | (28 | ) |
| | | | | | | | | | |
Net assets | | $ | 55 | | $ | (24 | ) | $ | 31 | |
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:
Source of Information | | | | | | | | | | | | | | | |
—Fair Value by Contract Year | | 2005(1) | | 2006 | | 2007 | | 2008 | | 2009 | | Thereafter | | Total | |
| | (In millions) | |
| | | | | | | | | | | | | | | |
Prices actively quoted(2) | | $ | 5 | | $ | 2 | | $ | 1 | | $ | -- | | $ | -- | | $ | -- | | $ | 8 | |
Sale of retail natural gas contracts(2) | | | (4 | ) | | (1 | ) | | -- | | | -- | | | -- | | �� | -- | | | (5 | ) |
Other external sources(3) | | | 11 | | | 10 | | | -- | | | -- | | | -- | | | -- | | | 21 | |
Prices based on models | | | -- | | | -- | | | 10 | | | 9 | | | 7 | | | 8 | | | 34 | |
| | | | | | | | | | | | | | | | | | | | | | |
Total(4) | | $ | 12 | | $ | 11 | | $ | 11 | | $ | 9 | | $ | 7 | | $ | 8 | | $ | 58 | |
(1)For the last three quarters of 2005.
(2)Exchange traded.
(3)Broker quote sheets.
(4)Includes $54 million in non-hedge commodity derivative contracts which are offset by a regulatory liability.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 March 31,September 30, 2005. Based on derivative contracts held as of March 31,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-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 firstthird quarter of 2005, FirstEnergy executed twono new fixed-for-floating interest rate swaps and unwound swaps with a total notional amount of $50$350 million each ($100 million total notional amount) on underlying EUOC and FirstEnergy senior notes with an average fixed rate of 6.51%(see Note 7). As of March 31,September 30, 2005, the debt underlying the $1.75$1.05 billion outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 5.59%5.66%, which the swaps have effectively converted to a current weighted average variable interest rate of 4.32%5.23%.
| | 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 | |
| | | | | | | | | | | | | | | | | | | |
Interest Rate SwapsForward Starting Swap Agreements - Cash Flow Hedges
| | March 31, 2005 | | December 31, 2004 | |
| | Notional | | Maturity | | Fair | | Notional | | Maturity | | Fair | |
Denomination | | Amount | | Date | | Value | | Amount | | Date | | Value | |
| | (Dollars in millions) | |
Fixed to Floating Rate | | | | | | | | | | | | | |
(Fair value hedges) | | $ | 200 | | | 2006 | | $ | (3 | ) | $ | 200 | | | 2006 | | $ | (1 | ) |
| | | 100 | | | 2008 | | | (3 | ) | | 100 | | | 2008 | | | (1 | ) |
| | | 100 | | | 2010 | | | (2 | ) | | 100 | | | 2010 | | | 1 | |
| | | 100 | | | 2011 | | | -- | | | 100 | | | 2011 | | | 2 | |
| | | 450 | | | 2013 | | | (7 | ) | | 400 | | | 2013 | | | 4 | |
| | | 100 | | | 2014 | | | -- | | | 100 | | | 2014 | | | 2 | |
| | | 150 | | | 2015 | | | (9 | ) | | 150 | | | 2015 | | | (7 | ) |
| | | 200 | | | 2016 | | | (2 | ) | | 200 | | | 2016 | | | 1 | |
| | | 150 | | | 2018 | | | 3 | | | 150 | | | 2018 | | | 5 | |
| | | 50 | | | 2019 | | | 2 | | | 50 | | | 2019 | | | 2 | |
| | | 150 | | | 2031 | | | (6 | ) | | 100 | | | 2031 | | | (4 | ) |
| | $ | 1,750 | | | | | $ | (27 | ) | $ | 1,650 | | | | | $ | 4 | |
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 $956 million$1.038 billion and $951 million as of March 31,September 30, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $96$104 million reduction in fair value as of March 31,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 March 31,September 30, 2005, the largest credit concentration was with one party, currently rated investment grade that represented 7%8% of FirstEnergy'sFirstEnergy’s total credit risk. Within its unregulated energy subsidiaries, 99% of credit exposures, net of collateral and reserve,reserves, were with investment-grade counterparties as of March 31,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; |
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· | establishing or defining the PLR obligations to customers in the Companies' service areas; |
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· | providing the Companies with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market; |
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· | itemizing (unbundling) the price of electricity into its component elements - including generation, transmission, distribution and stranded costs recovery charges; |
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· | continuing regulation of the Companies' transmission and distribution systems; and |
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· | requiring corporate separation of regulated and unregulated business activities. |
The EUOCEUOCs 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.
Regulatory Assets* | | March 31, | | December 31, | | Increase | |
| | 2005 | | 2004 | | (Decrease) | |
| | (In millions) | |
OE | | $ | 1,022 | | $ | 1,116 | | $ | (94 | ) |
CEI | | | 925 | | | 959 | | | (34 | ) |
TE | | | 349 | | | 375 | | | (26 | ) |
JCP&L | | | 2,268 | | | 2,176 | | | 92 | |
Met-Ed | | | 750 | | | 693 | | | 57 | |
Penelec | | | 278 | | | 200 | | | 78 | |
ATSI | | | 14 | | | 13 | | | 1 | |
Total | | $ | 5,606 | | $ | 5,532 | | $ | 74 | |
*Penn had net regulatory liabilities of approximately $27 million and $18 million included in Noncurrent
Liabilities on the Consolidated Balance Sheet as of March 31, 2005 and December 31, 2004, respectively.
| | 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:
Regulatory Assets By Source | | March 31, | | December 31, | | Increase | | |
| | | September 30, | | December 31, | | Increase | |
Regulatory Assets by Source | | | 2005 | | 2004 | | (Decrease) | |
| | 2005 | | 2004 | | (Decrease) | | | (In millions) |
| | (In millions) | | | | | | | | |
Regulatory transition costs | | $ | 4,881 | | $ | 4,889 | | $ | (8 | ) | | $ | 4,169 | | $ | 4,889 | | $ | (720 | ) |
Customer shopping incentives* | | | 668 | | | 612 | | | 56 | | |
Customer shopping incentives | | | 826 | | 612 | | 214 | |
Customer receivables for future income taxes | | | 296 | | | 246 | | | 50 | | | 289 | | 246 | | 43 | |
Societal benefits charge | | | 40 | | | 51 | | | (11 | ) | | 18 | | 51 | | (33 | ) |
Loss on reacquired debt | | | 87 | | | 89 | | | (2 | ) | | 83 | | 89 | | (6 | ) |
Employee postretirement benefits costs | | | 62 | | | 65 | | | (3 | ) | |
Employee postretirement benefit costs | | | 57 | | 65 | | (8 | ) |
Nuclear decommissioning, decontamination | | | | | | | | | | | | | | | | | |
and spent fuel disposal costs | | | (163 | ) | | (169 | ) | | 6 | | | (172 | ) | | (169 | ) | | (3 | ) |
Asset removal costs | | | (345 | ) | | (340 | ) | | (5 | ) | | (366 | ) | | (340 | ) | | (26 | ) |
Property losses and unrecovered plant costs | | | 45 | | | 50 | | | (5 | ) | | 34 | | 50 | | (16 | ) |
MISO transmission costs | | | 52 | | - | | 52 | |
JCP&L reliability costs | | | 26 | | - | | 26 | |
Other | | | 35 | | | 39 | | | (4 | ) | | | | 30 | | | 39 | | | (9 | ) |
Total | | $ | 5,606 | | $ | 5,532 | | $ | 74 | | | | $ | 5,046 | | $ | 5,532 | | $ | (486 | ) |
| | | | | | | | |
*The Ohio Companies are deferring customer shopping incentives and interest costs as new regulatory assets
in accordance with the transition and rate stabilization plans. These regulatory assets, totaling $668 million as
of March 31, 2005 (OE - $250 million, CEI - $320 million, TE - $98 million) will be recovered through a surcharge
rate equal to the RTC rate in effect when the transition costs have been fully recovered. Recovery of the new
regulatory assets will begin at that time and amortization of the regulatory assets for each accounting period
will be equal to the surcharge revenue recognized during that period.
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. FirstEnergy notes, however, thatThe 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.
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 a Memorandum of Understanding (MOU)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 an SRMa Special Reliability Master who made recommendations on appropriate courses of action necessary to ensure system-wide reliability andreliability. 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 1314 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' revised Rate Stabilization Plan extends currentCompanies to establish generation prices through 2008, ensuring adequate generationservice rates beginning January 1, 2006, in response to PUCO concerns about price and supply at stabilized prices, and continuesuncertainty following the end of the Ohio Companies' supporttransition plan market development period. In October 2004, the OCC and NOAC filed appeals with the Supreme Court of energy efficiency and economic development efforts. Other key components ofOhio to overturn the revised Rate Stabilization Plan includeoriginal June 9, 2004 PUCO order in this proceeding as well as the following:associated entries on rehearing. On September 28, 2005, the Ohio Supreme Court heard oral argument on the appeals.
· | extension of the amortization period for transition costs being recovered through the RTC for OE from 2006 to as late as 2007; for CEI from 2008 to as late as mid-2009 and for TE from mid-2007 to as late as mid-2008; |
· | deferral of interest costs on the accumulated customer shopping incentives as new regulatory assets; and |
· | ability to request increases in generation charges during 2006 through 2008, under certain limited conditions, for increases in fuel costs and taxes. |
On December 9, 2004,May 27, 2005, the Ohio Companies filed an application with the PUCO rejected the auction price results fromto establish a required competitive bid process and issued an entry stating that the pricingGCAF rider under the approved revised Rate Stabilization Plan will take effect onRSP. 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.
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 similar 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 Rate Stabilization PlanRSP pricing, but notwith no accounting impacts to the related approved accounting,RSP, and not until twelve months after the PUCO authorizes such termination.
On December 30, 2004,September 28, 2005, the PUCO issued an Entry that essentially approved the Ohio Companies filed an application withCompanies' filing but delayed the PUCO seeking tariff adjustmentsproposed timing of the competitive bid process by four months, calling for the auction to recover increases of approximately $30 million in transmission and ancillary service costs beginning January 1,be held on March 21, 2006. The Ohio Companies also filed an application for authority to defer costs associated with MISO Day 1, MISO Day 2, congestion fees, FERC assessment fees, and the ATSI rate increase, as applicable, from October 1, 2003 through December 31, 2005.
See Note 1314 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio.
New JerseyPennsylvania
The July 2003 NJBPU decision on JCP&L's base electric rate proceeding ordered a Phase II proceeding be conducted to review whether JCP&L is in compliance with current service reliability and quality standards. The NJBPU also ordered that any expenditures and projects undertaken by JCP&L to increase its system's reliability be reviewed as part of the Phase II proceeding, to determine their prudence and reasonableness for rate recovery. In that Phase II proceeding, the NJBPU could increase JCP&L’s return on equity to 9.75% or decrease it to 9.25%, depending on its assessment of the reliability of JCP&L's service. Any reduction would be retroactive to August 1, 2003. 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 requests an increase to the MTC deferred balance recovery of approximately $20 million annually. The Ratepayer Advocate filed testimony on November 16, 2004, and JCP&L submitted rebuttal testimony on January 4, 2005. The Ratepayer Advocate surrebuttal testimony was submitted February 8, 2005. Discovery and settlement conferences are ongoing.
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 28, 2004 NJBPU13, 2005, the Commonwealth Court issued an interim order JCP&L filed testimony on June 7, 2004 supporting a continuationin the remand proceeding that the parties should report the status 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) comparednegotiations 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 filedPPUC with a response to those comments. A schedule for further proceedings has not yet been set.
See Note 13copy to the consolidated financial statements for further detailsALJ. The parties exchanged settlement proposals in May and a complete discussion of regulatory matters in New Jersey.
PennsylvaniaJune 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 continue deferringdefer 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.
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 1314 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.
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 September 16,December 30, 2004, the FERCOhio 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 an order that imposed additional obligations on CEI under certain pre-Open Access transmission contracts among CEIAugust 31, 2005 approving the stipulation referred to above. The OCC, OPAE and the citiesOhio 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 Clevelandall costs. On July 6, 2005, the PUCO denied the Ohio Companies' and Painesville, Ohio. UnderOCC’s applications and, at the FERC's decision, CEI mayrequest 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 responsible fordue 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 portionsettlement 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 energy market charges imposed by MISO when its energy markets begin inand existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the spring of 2005. CEI filedthird filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for rehearing of the order from the FERC on October 18, 2004.transmission service provided within their respective zones. On April 15,May 31, 2005, the FERC issued an order on rehearingthese cases. First, it set for hearing the existing rate design and indicated that "carves out" these contracts from the MISO Day 2 market. While theit will issue a final order on rehearing is favorable to CEI, the impact of the FERC decision on CEI is dependent upon many factors, including the arrangements made by the cities for transmission service and MISO's ability to administer the contracts. Accordingly, the impact of this decision cannot be determined at this time.
On November 1, 2004, ATSI requested authority from the FERC to defer approximately $54 million of vegetation management costs ($14 million deferred as of March 31, 2005) estimated to be incurred from 2004 through 2007. On March 4, 2005,within six months. Second, the FERC approved ATSI's request to defer those costs. ATSI expects to file an application with FERC in the first quarter of 2006 for recovery of the deferred costs.
ATSI and MISO filed with the FERC on December 2, 2004, seeking approval for ATSI to have transmission rates established based on a FERC-approved cost of service - formulaproposed Schedule 12 rate included in Attachment O under the MISO tariff. The ATSI Network Service net revenue requirement increased under the formula rate to approximately $159 million. On January 28, 2005,harmonization. Third, the FERC accepted for filing the revised tariff sheets to become effective February 1, 2005,proposed formula rate, subject to refund,referral and orderedhearing procedures. On September 30, 2005, the PJM transmission owners filed a public hearing be held to address the reasonablenessrequest for rehearing of the proposal to eliminate the voltage-differentiatedMay 31, 2005 order. The rate design forand formula rate filings continue to be litigated before the ATSI zone. On April 4, 2005, a settlement with all parties to the proceeding was filed with the FERC that provides for recoveryFERC. The outcome of the full amount of the rate increase permitted under the formula.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 determineestimate 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.
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 will requireprovides 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 ourtheir 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 in two phases from coal-fired power plants.plants in two phases. Initially, mercury emissions will declinebe capped nationally at 38 tons by 2010 as(as a "co-benefit" from implementation of SO2 and NOx emission caps under the EPA's CAIR program.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. TheHowever, 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 coveringalleging 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 U.S. Department of Justice (DOJ)DOJ filed eight civil complaints against various investor-owned utilities, which includedincluding 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. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. 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, subject to a thirty-day public comment period that ended on April 29, 2005 and final approvalwas approved by the District Court Judge,on July 11, 2005, requires OE and Penn to reduce emissions fromNOx and SO2 emission at the W. H. Sammis Plant and other coal-fired plants through the installation of pollution control devices requiring capitaldevices. Capital expenditures necessary to meet those requirements are currently estimated to be $1.1$1.5 billion (primarily(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 towardstoward environmentally beneficial projects, which include wind energy purchasepurchased power agreements over a 20-year term. OE and Penn also agreed to pay a civil penalty of $8.5 million. Results for the first quarter of 2005 includeincluded the penalties payable by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also accruedrecognized 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.
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.
FirstEnergy plans to issue a report that will disclose the Companies’ environmental activities, including their plans to respond to environmental requirements. FirstEnergy expects to complete the report by December 1, 2005 and will post the report on its web site,www.firstenergycorp.com.
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 March 31,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. Included in Current LiabilitiesTotal 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 Noncurrent Liabilities areother - $14.6 million) have been accrued liabilities aggregating approximately $65 million as of March 31,through September 30, 2005.
See Note 12(B)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 most significantother 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 concluded,concludes, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area.Specifically,area. Specifically, the final report concludes,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“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. As manyFirstEnergy also is proceeding with the implementation of these initiatives alreadythe 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 process,new, or material upgrades, to existing equipment, and therefore FirstEnergy doeshas not believeaccrued a liability as of September 30, 2005 for any expenditures in excess of those actually incurred through that any incremental expenses associated with additional initiatives completed in 2004 had a material effect on its continuing operations or financial results.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.
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 not accrued a liability as of March 31, 2005been undertaken for any expenditures in excess of those actually incurred through that date.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 filed aFirstEnergy's motion to dismiss with 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 October 22, 2004.or about December 1, 2005. No timetable for a decision on the motion to dismiss has been established by the Court. No damage estimate has been provided and thusof potential liability has not been determined.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, and results of operations.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. Under the NRC’s letter, FENOC has ninety daysFirstEnergy accrued $2.0 million for a potential fine prior to respond to this NOV. FirstEnergy has2005 and accrued the remaining liability for the proposed fine of $3.45 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 hashave legal liability based on the events surrounding Davis-Besse, head degradation, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, and results of operations.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 pastpreceding two years. FENOC operates the Perry Nuclear Power Plant, which currently is owned and/or leased by OE, CEI, TE and Penn.OnPenn (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 the 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.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 second 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, and results of operations.operations and cash flows.
See Note 12(C)13(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.
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 “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”143”
On March 30, 2005, the FASB issued this interpretationFIN 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 interpretationInterpretation is effective no laterfor 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 endConsolidated 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 endingbeginning after December 15, 2005. FirstEnergy is currently evaluatingand the effectCompanies will adopt this standard will have on the financial statements.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 FirstEnergy's financial statements.
SFAS 123 (revised 2004)123(R),“Share-Based Payment” “Share-Based Payment”
In December 2004, the FASB issued thisSFAS 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 FirstEnergy and other companies with a fiscal year beginning January 1. The CompanyTherefore, FirstEnergy will be applyingadopt this Statement effective January 1, 2006. FirstEnergy expects to adopt modified prospective application, without restatement of prior interim periods. Any potentialPotential 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 will continueexpects to do soapply this pricing model upon adoption of SFAS 123(R).
EITF IssueSFAS 151, “Inventory Costs - an amendment of ARB No. 03-1,43, 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 March 2004,September 2005, the EITF reached a consensus on the application guidance for Issue 03-1.FASB finalized and renamed EITF 03-1 providesand 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 model for determiningSecurity Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when investments in certain debt and equity securities are consideredthe impairment is deemed other than temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair valuetemporary, even if a decision to sell has not been made, and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to(3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after JuneSeptember 15, 2004, were delayed by2005. The FASB expects to issue this FSP in the issuancefourth 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 EITF 03-1-1 in September 2004. During the period of delay, FirstEnergy will continue to evaluateand any impact on its investments as required by existing authoritative guidance.investments.
OHIO EDISON COMPANY | |
| | | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | | |
| | | | Three Months Ended | |
| | | | March 31, | |
| | | | | | | |
| | | | 2005 | | 2004 | |
| | | | | | | |
STATEMENTS OF INCOME | | | | (In thousands) | |
| | | | | | | |
OPERATING REVENUES | | | | | $ | 726,358 | | $ | 743,295 | |
| | | �� | | | | | | | |
OPERATING EXPENSES AND TAXES: | | | | | | | | | | |
Fuel | | | | | | 11,916 | | | 15,070 | |
Purchased power | | | | | | 246,590 | | | 249,881 | |
Nuclear operating costs | | | | | | 95,653 | | | 79,641 | |
Other operating costs | | | | | | 83,179 | | | 85,360 | |
Provision for depreciation | | | | | | 26,052 | | | 29,929 | |
Amortization of regulatory assets | | | | | | 111,771 | | | 113,695 | |
Deferral of new regulatory assets | | | | | | (24,795 | ) | | (18,895 | ) |
General taxes | | | | | | 48,078 | | | 48,566 | |
Income taxes | | | | | | 54,972 | | | 61,574 | |
Total operating expenses and taxes | | | | | | 653,416 | | | 664,821 | |
| | | | | | | | | | |
OPERATING INCOME | | | | | | 72,942 | | | 78,474 | |
| | | | | | | | | | |
OTHER INCOME (net of income taxes) | | | | | | 423 | | | 16,357 | |
| | | | | | | | | | |
NET INTEREST CHARGES: | | | | | | | | | | |
Interest on long-term debt | | | | | | 15,609 | | | 16,589 | |
Allowance for borrowed funds used during construction and capitalized interest | | | | | | (2,235 | ) | | (1,381 | ) |
Other interest expense | | | | | | 2,594 | | | 2,890 | |
Subsidiary's preferred stock dividend requirements | | | | | | 640 | | | 640 | |
Net interest charges | | | | | | 16,608 | | | 18,738 | |
| | | | | | | | | | |
NET INCOME | | | | | | 56,757 | | | 76,093 | |
| | | | | | | | | | |
PREFERRED STOCK DIVIDEND REQUIREMENTS | | | | | | 659 | | | 561 | |
| | | | | | | | | | |
EARNINGS ON COMMON STOCK | | | | | $ | 56,098 | | $ | 75,532 | |
| | | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | |
| | | | | | | | | | |
NET INCOME | | | | | $ | 56,757 | | $ | 76,093 | |
| | | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | |
Unrealized gain (loss) on available for sale securities | | | | | | (2,717 | ) | | 5,167 | |
Income tax related to other comprehensive income | | | | | | 1,124 | | | (2,131 | ) |
Other comprehensive income (loss), net of tax | | | | | | (1,593 | ) | | 3,036 | |
| | | | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | | | | $ | 55,164 | | $ | 79,129 | |
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| | | | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral partof these statements. | |
| | | | | | | | | | |
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.
OHIO EDISON COMPANY | |
| | | | | | | |
CONSOLIDATED BALANCE SHEETS | |
(Unaudited) | |
| | | | March 31, | | December 31, | |
| | | | 2005 | | 2004 | |
| | | | (In thousands) | |
ASSETS | | | | | | | |
UTILITY PLANT: | | | | | | | |
In service | | | | | $ | 5,470,159 | | $ | 5,440,374 | |
Less - Accumulated provision for depreciation | | | | | | 2,747,377 | | | 2,716,851 | |
| | | | | | 2,722,782 | | | 2,723,523 | |
Construction work in progress- | | | | | | | | | | |
Electric plant | | | | | | 233,967 | | | 203,167 | |
Nuclear fuel | | | | | | 39,468 | | | 21,694 | |
| | | | | | 273,435 | | | 224,861 | |
| | | | | | 2,996,217 | | | 2,948,384 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | | |
Investment in lease obligation bonds | | | | | | 354,457 | | | 354,707 | |
Nuclear plant decommissioning trusts | | | | | | 445,704 | | | 436,134 | |
Long-term notes receivable from associated companies | | | | | | 208,364 | | | 208,170 | |
Other | | | | | | 42,720 | | | 48,579 | |
| | | | | | 1,051,245 | | | 1,047,590 | |
CURRENT ASSETS: | | | | | | | | | | |
Cash and cash equivalents | | | | | | 1,204 | | | 1,230 | |
Receivables- | | | | | | | | | | |
Customers (less accumulated provisions of $6,179,000 and $6,302,000, respectively, | | | | | | | | | | |
for uncollectible accounts) | | | | | | 267,911 | | | 274,304 | |
Associated companies | | | | | | 163,201 | | | 245,148 | |
Other (less accumulated provisions of $82,000 and $64,000, respectively, | | | | | | | | | | |
for uncollectible accounts) | | | | | | 20,602 | | | 18,385 | |
Notes receivable from associated companies | | | | | | 692,715 | | | 538,871 | |
Materials and supplies, at average cost | | | | | | 105,906 | | | 90,072 | |
Prepayments and other | | | | | | 25,981 | | | 13,104 | |
| | | | | | 1,277,520 | | | 1,181,114 | |
DEFERRED CHARGES: | | | | | | | | | | |
Regulatory assets | | | | | | 1,022,241 | | | 1,115,627 | |
Property taxes | | | | | | 61,419 | | | 61,419 | |
Unamortized sale and leaseback costs | | | | | | 58,896 | | | 60,242 | |
Other | | | | | | 71,327 | | | 68,275 | |
| | | | | | 1,213,883 | | | 1,305,563 | |
| | | | | $ | 6,538,865 | | $ | 6,482,651 | |
CAPITALIZATION AND LIABILITIES | | | | | | | | | | |
CAPITALIZATION: | | | | | | | | | | |
Common stockholder's equity- | | | | | | | | | | |
Common stock, without par value, authorized 175,000,000 shares - 100 shares outstanding | | | | | $ | 2,098,729 | | $ | 2,098,729 | |
Accumulated other comprehensive loss | | | | | | (48,711 | ) | | (47,118 | ) |
Retained earnings | | | | | | 451,296 | | | 442,198 | |
Total common stockholder's equity | | | | | | 2,501,314 | | | 2,493,809 | |
Preferred stock | | | | | | 60,965 | | | 60,965 | |
Preferred stock of consolidated subsidiary | | | | | | 39,105 | | | 39,105 | |
Long-term debt and other long-term obligations | | | | | | 1,098,801 | | | 1,114,914 | |
| | | | | | 3,700,185 | | | 3,708,793 | |
CURRENT LIABILITIES: | | | | | | | | | | |
Currently payable long-term debt | | | | | | 397,256 | | | 398,263 | |
Short-term borrowings- | | | | | | | | | | |
Associated companies | | | | | | 75,969 | | | 11,852 | |
Other | | | | | | 134,072 | | | 167,007 | |
Accounts payable- | | | | | | | | | | |
Associated companies | | | | | | 151,151 | | | 187,921 | |
Other | | | | | | 7,498 | | | 10,582 | |
Accrued taxes | | | | | | 197,848 | | | 153,400 | |
Other | | | | | | 126,265 | | | 74,663 | |
| | | | | | 1,090,059 | | | 1,003,688 | |
NONCURRENT LIABILITIES: | | | | | | | | | | |
Accumulated deferred income taxes | | | | | | 726,080 | | | 766,276 | |
Accumulated deferred investment tax credits | | | | | | 59,135 | | | 62,471 | |
Asset retirement obligation | | | | | | 344,715 | | | 339,134 | |
Retirement benefits | | | | | | 309,915 | | | 307,880 | |
Other | | | | | | 308,776 | | | 294,409 | |
| | | | | | 1,748,621 | | | 1,770,170 | |
COMMITMENTS AND CONTINGENCIES (Note 12) | | | | | | | | | | |
| | | | | $ | 6,538,865 | | $ | 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. | |
|
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. | | | | | | | | | | | | | |
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. | | |
| | | | | | | |
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. | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
OHIO EDISON COMPANY | |
| | | | | | | |
CONSOLIDATED STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | | |
| | | | Three Months Ended | |
| | | | March 31, | |
| | | | | | | |
| | | | 2005 | | 2004 | |
| | | | | | | |
| | | | (In thousands) | |
| | | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | |
Net income | | | | | $ | 56,757 | | $ | 76,093 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | | | |
Provision for depreciation | | | | | | 26,052 | | | 29,929 | |
Amortization of regulatory assets | | | | | | 111,771 | | | 113,695 | |
Deferral of new regulatory assets | | | | | | (24,795 | ) | | (18,895 | ) |
Nuclear fuel and lease amortization | | | | | | 9,170 | | | 11,261 | |
Amortization of lease costs | | | | | | 33,030 | | | 33,030 | |
Deferred income taxes and investment tax credits, net | | | | | | (24,627 | ) | | (30,045 | ) |
Accrued retirement benefit obligations | | | | | | 2,034 | | | 11,123 | |
Accrued compensation, net | | | | | | (4,007 | ) | | 4,522 | |
Decrease (Increase) in operating assets: | | | | | | | | | | |
Receivables | | | | | | 86,123 | | | (51,935 | ) |
Materials and supplies | | | | | | (15,834 | ) | | (2,762 | ) |
Prepayments and other current assets | | | | | | (12,877 | ) | | (11,829 | ) |
Increase (Decrease) in operating liabilities: | | | | | | | | | | |
Accounts payable | | | | | | (39,854 | ) | | 240,979 | |
Accrued taxes | | | | | | 44,448 | | | (311,577 | ) |
Accrued interest | | | | | | 6,993 | | | 5,443 | |
Other | | | | | | 11,714 | | | 5,991 | |
Net cash provided from operating activities | | | | | | 266,098 | | | 105,023 | |
| | | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | |
New Financing- | | | | | | | | | | |
Long-term debt | | | | | | -- | | | 30,000 | |
Short-term borrowings, net | | | | | | 31,182 | | | 16,341 | |
Redemptions and Repayments- | | | | | | | | | | |
Long-term debt | | | | | | (15,787 | ) | | (97,001 | ) |
Dividend Payments- | | | | | | | | | | |
Common stock | | | | | | (47,000 | ) | | (54,000 | ) |
Preferred stock | | | | | | (659 | ) | | (561 | ) |
Net cash used for financing activities | | | | | | (32,264 | ) | | (105,221 | ) |
| | | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | |
Property additions | | | | | | (79,783 | ) | | (37,661 | ) |
Contributions to nuclear decommissioning trusts | | | | | | (7,885 | ) | | (7,885 | ) |
Loan repayments from (loans to) associated companies, net | | | | | | (154,038 | ) | | 48,912 | |
Other | | | | | | 7,846 | | | (3,728 | ) |
Net cash used for investing activities | | | | | | (233,860 | ) | | (362 | ) |
| | | | | | | | | | |
Net decrease in cash and cash equivalents | | | | | | (26 | ) | | (560 | ) |
Cash and cash equivalents at beginning of period | | | | | | 1,230 | | | 1,883 | |
Cash and cash equivalents at end of period | | | | | $ | 1,204 | | $ | 1,323 | |
| | | | | | | | | | |
| | | | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral partof these statements. | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
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 March 31,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 March 31,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
May 3,November 1, 2005
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 firstthird quarter of 2005 decreasedincreased to $56$131 million from $76$102 million in the firstthird 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 reduced operating revenues and other income and increasedincreases in nuclear operating costs, whichregulatory 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 decreased depreciation, changes in amortizationhigher operating revenues and deferrals of regulatory assets, lower fuel and purchased power costs, and reduced financing costs.
Operating revenues decreasedincreased by $17$59 million or 2.3%7.8% in the firstthird quarter of 2005 compared with the same period in 2004. LowerHigher revenues for the quarter primarily resulted from a $24increased retail generation and distribution revenues of $23 million wholesale sales decrease partially offsetand $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 $6$36 million and $2$40 million, respectively.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 $28$57 million (20.3%(12.1% KWH sales decrease), due to reduced nuclear generation available for sale. The decreased sales to FES sales were partially offset by increased sales of $4$21 million to non-affiliated customers (primarily(including MSG sales). Under its Ohio transition plan, OE is required to provide the attractively-priced MSG to non-affiliated alternative suppliers (see Outlook - Regulatory Matters).
Increased retail generation revenues for the third quarter of 2005 resulted from increasedhigher sales to industrialresidential, commercial and commercialindustrial customers of $5$10 million, $2 million and $3$11 million, respectively, partially offset by a $2 million residential sales decrease.respectively. The increase in industrial and commercial revenues reflected the effect of higherincreased generation KWH sales (industrial - 4.1%to residential (14.0%) and commercial - 3.9%(6.1%) and higher composite unit prices. Thecustomers were due to warmer than normal temperatures in the third quarter of 2005. Increased industrial revenues reflected a 6.5% increase in generation KWH growthsales. Partially offsetting the increase in residential KWH sales was moderated by increasedan increase in customer shopping. Generation services provided to industrialresidential customers by alternative suppliers as a percent of total industrialresidential sales delivered in OE’s service area increased by 2.11.2 percentage points whichcompared 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 the effect of a 7.2% increaseby increases in industrial sector deliveries. Reduced residential revenues were principally due to a 2.8% KWH sales decrease reflecting increased residential customer shopping (1.7by 1.1 and 1.7 percentage point increase). Commercial customerpoints, respectively, while commercial shopping remained relatively unchanged.
Revenues from distribution throughput increased $2$33 million in the firstthird quarter of 2005 compared with the same period in 2004. Distribution deliveries to residential, commercial and industrial customers increased by $2$26 million, $4 million and $1$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 2004,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 increasedhigher KWH deliveries partially offset by lower composite prices. Industrial distribution revenues decreased by $3 million due to lower composite unit prices. The increased sales to the commercial and industrial sectors resulted,prices, partially offset by an increase in part, from an improving economy in OE's service area. Distribution deliveries to residential customers decreased slightly.KWH distribution deliveries.
Under the Ohio transition plan, OE provides incentives to customers to encourage switching to alternative energy providers. OE’s revenues were reduced by $2$3 million from additional credits in the third quarter and $7 million in the first quarternine months of 2005 compared to the same periodperiods in 2004. These revenue reductions are deferred for future recovery from customers under OE’s transition plan and do not affect current period earnings.earnings (See Regulatory Matters below.)below).
Changes in electric generationKWH sales and distribution deliveriesby customer class in the first quarter ofthree months and nine months ended September 30, 2005 from the same quartercorresponding 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 | % |
| | | | | | | |
Changes in KWH Sales
| | | |
Increase (Decrease)
| | | |
| | | |
Electric Generation: | | | |
Retail | | | 1.3 | % |
Wholesale | | | (17.4 | )% |
Total Electric Generation Sales | | | (7.6 | )% |
Distribution Deliveries: | | | | |
Residential | | | (0.7 | )% |
Commercial | | | 3.6 | % |
Industrial | | | 7.2 | % |
Total Distribution Deliveries | | | 3.1 | % |
Operating Expenses and Taxes
Total operating expenses and taxes decreasedincreased by $11$29 million in the third quarter and $57 million in the first quarternine months of 2005 from the first quartersame 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 | |
Operating Expenses and Taxes - Changes | | | |
Increase (Decrease) | | (In millions) | |
| | | |
Fuel costs | | $ | (3 | ) |
Purchased power costs | | | (3 | ) |
Nuclear operating costs | | | 16 | |
Other operating costs | | | (2 | ) |
Provision for depreciation | | | (4 | ) |
Amortization of regulatory assets | | | (2 | ) |
Deferral of new regulatory assets | | | (6 | ) |
General taxes | | | -- | |
Income taxes | | | (7 | ) |
Net decrease in operating expenses and taxes | | $ | (11 | ) |
Lower fuel costs in the first quarternine months of 2005, compared with the same quarterperiods of 2004, resulted from decreased nuclear generation - down 20.3%12.1%. Decreased purchasedPurchased power costs reflectedwere lower KWH purchasedin both periods of 2005, reflecting lower unit costs partially offset by higher unit costs. HigherKWH 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 wereat Perry Unit 1 and Beaver Valley Unit 2. Nuclear operating costs increased during the first nine months of 2005 primarily due to the Perry nuclear plant scheduledcosts from the Beaver Valley Unit 2 refueling outage (including an unplanned extension)(started April 4, 2005) and to a lesser extent from the Perry Unit 1 outage initiated in the first quarter of 2005 and the absence ofthat was completed on May 6, 2005. There were no nuclear refueling outages in the same periodperiods last year. The decreaseincreases in other operating costs wasin the third quarter and first nine months of 2005, compared to the same periods of 2004, resulted primarily due to reduced labor costs andfrom increased MISO transmission expenses, partially offset by lower employee benefitbenefits expenses.
The decrease in depreciation expense in the first quarternine months of 2005 compared with the same quarterperiod of 2004 was attributable to revised estimated service life assumptions for fossil generating plants. Lowerplants (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 assets was due to decreased amortization of Ohio transition regulatory assets, effective April 1, 2004. The higherasset deferrals of new regulatory assets primarilyfor both periods resulted from higher shopping incentive deferrals ($2 million) 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).
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 interesttax 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 shopping incentives ($3 million).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 $16$13 million in the first quarternine months of 2005 compared with the same quarterperiod of 2004, primarily due to the accruals of 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 continued to trend lower, decreasingincreased by $4 million in the third quarter and $2 million in the first quarternine months of 2005 compared with the same quarterperiods of 2004, reflecting redemptionsincreased short-term borrowings from associated companies at a higher rate of $15 million of outstanding debt during the first quarter of 2005.interest.
Capital Resources and Liquidity
OE’s cash requirements infor 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. Available borrowingBorrowing capacity under credit facilities will be usedis 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 wereof approximately $1 million as of March 31, 2005 andremained unchanged from December 31, 2004.
Cash Flows From Operating Activities
Cash provided from operating activities during the third quarter and first quarternine months of 2005, andcompared with the corresponding periods in 2004 period were as follows:
| | | Three Months Ended | | Nine Months Ended | |
| | | September 30, | | September 30, | |
Operating Cash Flows | | 2005 | | 2004 | | | 2005 | | 2004 | | 2005 | | 2004 | |
| | (In millions) | | | (In millions) | |
| | | | | | | | | | |
Cash earnings (1) | | $ | 185 | | $ | 231 | | | $ | 273 | | $ | 224 | | $ | 603 | | $ | 607 | |
Pension trust contribution (2) | | | | -- | | | (44 | ) | | -- | | | (44 | ) |
Working capital and other | | | 81 | | | (126 | ) | | | 64 | | | 32 | | | 198 | | | (351 | ) |
Total Cash Flows from Operating Actitivities | | $ | 266 | | $ | 105 | | |
Total cash flows from operating activities | | | $ | 337 | | $ | 212 | | $ | 801 | | $ | 212 | |
| | | | | | | | | | | |
(1) Cash earnings is a non-GAAP measure (see reconciliation below). | | (1) Cash earnings is a non-GAAP measure (see reconciliation below). | | | | | | | |
(2) Pension trust contribution net of $29 million of income tax benefits. | | (2) Pension trust contribution net of $29 million of income tax benefits. | | | | | | | |
(1)Cash earnings is a non-GAAP measure (see reconciliation below).
Cash earnings, (inas disclosed in the table above)above, are not a measure of performance calculated in accordance with GAAP. FirstEnergyOE 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 | |
| | | | | | | | | | | | | |
Reconciliation of Cash Earnings | | 2005 | | 2004 | |
| | (In millions) | |
| | | | | |
Net Income (GAAP) | | $ | 57 | | $ | 76 | |
Non-Cash Charges (Credits): | | | | | | | |
Provision for depreciation | | | 26 | | | 30 | |
Amortization of regulatory assets | | | 112 | | | 114 | |
Nuclear fuel and capital lease amortization | | | 9 | | | 11 | |
Deferral of new regulatory assets | | | (25 | ) | | (19 | ) |
Deferred income taxes and investment tax credits, net | | | (25 | ) | | (30 | ) |
Other non-cash charges | | | 31 | | | 49 | |
Cash earnings (Non-GAAP) | | $ | 185 | | $ | 231 | |
Net cash provided from operating activities increased $161$125 million in the firstthird quarter of 2005, compared with the firstthird quarter of 2004, due to a $207$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 $46$4 million decrease in cash earnings as described above and under "Results“Results from Operations"Operations”. The increase in working capital primarily reflects changes in receivables from associated companies of $146 million and accounts payable to associated companies of $278 million, partially offset by changes in accrued taxes of $356 million. The changes for accounts payable and accrued taxes primarily reflect$407 million (including a $249 million reallocation of tax liabilities between associated companies underamong the FirstEnergy subsidiaries pursuant to the tax sharing agreementagreement) and $136 million of funds received for the Energy for Education program in 2004.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 $32$347 million in the first quarternine months of 2005 from $105$350 million in the first quartersame period of 2004. The decrease primarily reflected lowerwas due to a $169 million increase in new debt redemptions and commonshort term borrowings partially offset by a $163 million increase in net debt and preferred stock dividend payments to FirstEnergy.redemptions.
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 $694$799 million of cash and temporary cash investments (which include short-term notes receivable from associated companies) and $210$245 million of short-term indebtedness as of March 31,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 $49$51 million (including the utility money pool). In addition, Penn has
OES Capital is a $25wholly 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 facility.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 March 31,September 30, 2005, the facility was undrawn; it expires June 30, 2005 and is expected to be renewed.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 $1.9$1.1 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures.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 $650$690 million as of March 31,October 24, 2005. Based upon applicable earnings coverage tests in their respective charters, OE and Penn could issue a total of $2.9$2.8 billion of preferred stock (assuming no additional debt was issued) as of March 31,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 has $409 million of credit facilities, which were unused as of March 31, 2005, consisting of a $125 million three-year facility maturing in October 2006, a syndicated $250 million two-year facility maturing in May 2005 and bank facilities of $34 million. These facilities are intended to provide liquidity to meet OE’s short-term working capital requirements and would be available for investment in the money pool with its regulated affiliates.
Borrowings under these facilities are conditioned on maintaining compliance with certain financial covenants in the agreements. OE is required to maintain a debt to total capitalization ratio of no more than 0.65 to 1 and a contractually defined fixed charge coverage ratio of no less than 2 to 1. As of March 31, 2005, OE’s fixed charge coverage ratio, as defined under the credit agreements, was 6.87 to 1. OE's debt to total capitalization ratio, as defined under the credit agreements, was 0.40 to 1. The ability to draw on each of its facilities is also conditioned upon OE making certain representations and warranties to the lending banks prior to drawing under the facilities, including a representation that there has been no material adverse change in its business, condition (financial or otherwise), results of operations, or prospects.
None of OE’s primary credit facilities contain any provisions that either restrict its ability to borrow or accelerate repayment of outstanding advances as a result of any change in its credit ratings. Each primary facility does contain "pricing grids", whereby the cost of funds borrowed under the facility is related to OE’s credit ratings.
OE hasPenn have the ability to borrow from itstheir regulated affiliates and FirstEnergy to meet itstheir 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 firstthird quarter of 2005 was 2.66%3.50%.
On April 6, 2004, Ohio Air Quality Development Authority pollution control bonds aggregating $100 million and Ohio Water Development Authority pollution control bonds aggregating $6.45 million, respectively, were refunded. The new bonds were issued in a Dutch Auction interest rate mode, insured with municipal bond insurance and secured by FMB.
On May 16, 2005, Penn intends to redeem 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.
OE’s access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of FirstEnergy. The ratings outlook from the rating agencies on all such securities is stable.
On MarchJuly 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 Sammis NSR settlement was a very favorable step for FirstEnergy, although it would not immediately affectrating 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 ratings or outlook. S&Pability to consistently generate free cash flow, good liquidity, and an improving financial profile were also noted that it continues to monitor the refueling outage at the Perry nuclear plant, which includes a detailed inspection by the NRC, and that if FirstEnergy should exit the outage without significant negative findings or delays the ratings outlook would be revised to positive.as strengths.
Cash Flows From Investing Activities
Net cash used for investing activities increased to $234by $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 $0.4certificates of deposit, and increased $289 million in the first quarternine months of 2004. The increase resulted primarily from a $203 million increase of loans to associated companies and a $42 million increase in property additions.2005.
DuringIn the remaining three quarterslast quarter of 2005, capital requirements for property additions and capital leases are expected to be approximately $175 million, including $19 million for nuclear fuel.$82 million. OE has additional requirements of approximately $120$8 million to meet sinking fund requirements for preferred stock and maturing long-term debt (excluding Penn'sPenn’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 (excluding nuclear fuel), of which approximately $216$233 million applies to 2005. Investments for additional
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 fuel duringand 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 2005-2007 periodplants that are estimatedcurrently 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 approximately $145 million,separated from the regulated delivery business of which about $36 million appliesthose companies through transfer to 2005. Duringa separate corporate entity. FENOC currently operates and maintains the same period, its nuclear fuel investments are expectedgeneration assets to be reducedtransferred. 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 approximately $126 millionthe restructuring plans by transferring the ownership interests to NGC and $40 million,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 the nuclear fuel is consumed.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 $688$678 million as of March 31,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 $244$262 million and $248 million as of March 31,September 30, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $24$26 million reduction in fair value as of March 31,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.
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. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties.
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, 2005. 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.
OE's revised Rate Stabilization Plan extends currentOn 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 prices through 2008, ensuring adequate generationservice rates beginning January 1, 2006, in response to PUCO concerns about price and supply at stabilized prices, and continues OE's support of energy efficiency and economic development efforts. Other key componentsuncertainty following the end of the revised Rate Stabilization Plan includeOhio Companies' transition plan market development period. In October 2004, the following: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.
· | extension of the amortization period for transition costs being recovered through the RTC for OE from 2006 to as late as 2007; |
· | deferral of interest costs on the accumulated customer shopping incentives as new regulatory assets; and |
· | ability to request increases in generation charges during 2006 through 2008, under certain limited conditions, for increases in fuel costs and taxes. |
On December 9, 2004,May 27, 2005, OE filed an application with the PUCO rejected the auction price results fromto establish a required competitive bid process and issued an entry stating that the pricingGCAF rider under the approved revised Rate Stabilization Plan will take effect onRSP. 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.
Under provisions of the RSP, the PUCO may require OE to undertake, no more often than annually, a similar 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 Rate Stabilization PlanRSP pricing, but notwith no accounting impacts to the related approved accounting,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 an application with the PUCO seeking tariff adjustmentstwo applications related to recover increasesthe recovery of approximately $14 million in 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 alsoanticipates 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 anwith 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 forseeks authority to defer costs associated with MISO Day 1, MISO Day 2, congestion fees, FERC assessment fees,transmission and ancillary service related costs incurred during the ATSI rate increase, as applicable,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 March 31,September 30, 2005 and December 31, 2004, were $1.0$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 $250$302 million as of March 31,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. Recovery ofSee Note 14 “Regulatory Matters - Ohio” for the new regulatory assets will begin at that time andestimated net amortization of regulatory transition costs and deferred shopping incentive balances under the regulatory assets for each accounting period will be equal to the surcharge revenue recognized during that period.proposed RCP and current RSP. Penn's net regulatory asset components aggregate as net regulatory liabilities of approximately $27$48 million and $18 million, and are included in Other Noncurrent Liabilities on the Consolidated Balance Sheet as of March 31,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 1314 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio and Pennsylvania and a more detailed discussion of reliability initiatives, including actions by the PPUC, that impact Penn.
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 determineestimate 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 will requireprovides 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 SO2emissions 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 in two phases from coal-fired power plants.plants in two phases. Initially, mercury emissions will declinebe 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. The futureHowever, 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 coveringalleging 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 U.S. Department of Justice (DOJ)DOJ filed eight civil complaints against various investor-owned utilities, which includedincluding 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. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. 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, subject to a thirty-day public comment period that ended on April 29, 2005 and final approvalwas approved by the District Court Judge,on July 11, 2005, requires OE and Penn to reduce NOx and SO2emissions fromat the W. H. Sammis Plant and other coal-fired plants through the installation of pollution control devices requiring capitaldevices. Capital expenditures necessary to meet those requirements are currently estimated to be $1.1$1.5 billion (primarily(the primary portion of which is expected to be spent in the 2008 to 2011 time period).The. The settlement agreement also requires OE and Penn to spend up to $25 million towardstoward environmentally beneficial projects, which include wind energy purchasepurchased power agreements over a 20-year term. OE and Penn also agreed to pay a civil penalty of $8.5 million. Results for the first quarter of 2005 includeincluded the penalties payable by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also accruedrecognized 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.
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 gasesGHG 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 gasGHG 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-CO2emitting gas-fired and nuclear generators.
FirstEnergy plans to issue a report that will disclose the Companies’ environmental activities, including their plans to respond to environmental requirements. FirstEnergy expects to complete the report by December 1, 2005 and will post the report on its web site,www.firstenergycorp.com.
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 12(B)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 most significantother 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 concluded,concludes, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area.Specifically,area. Specifically, the final report concludes,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“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. As manyFirstEnergy also is proceeding with the implementation of these initiatives alreadythe 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 process,new, or material upgrades, to existing equipment, and therefore FirstEnergy doeshas not believeaccrued a liability as of September 30, 2005 for any expenditures in excess of those actually incurred through that any incremental expenses associated with additional initiatives completed in 2004 had a material effect on its continuing operations or financial results.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. FirstEnergy has not accrued a liability asFinally, 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 March 31, 2005 forcontrol room operators, before determining the next steps, if any, expenditures in excess of those actually incurred through that date.the proceeding.
Three substantially similar actions were filed in various Ohio State courts by plaintiffs seekingFirstEnergy companies also are defending six separate complaint cases before the PUCO relating to represent customers who allegedly suffered damages as a result of the August 14, 2003 power outages. All threeoutage. Two such cases were originally filed in Ohio State courts but subsequently dismissed for lack of jurisdiction. Onesubject matter jurisdiction and further appeals were unsuccessful. In both such cases the individual complainants—three in one case was refiled on January 12, 2004 atand four in the PUCO.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 twopending PUCO complaint cases, three were appealed. One case was dismissed and no further appeal was sought.filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In the remainingeach such case, the Courtcarriers 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 Appealspower on March 31, 2005 affirmedAugust 14, 2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy company. The fourth case involves the trial court’s decision dismissing the case. It is not yet known whether further appeal will be sought.claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. In addition to the one case that was refiled at the PUCO,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 filed aFirstEnergy's motion to dismiss with 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 October 22, 2004.or about December 1, 2005. No timetable for a decision on the motion to dismiss has been established by the Court. No damage estimate has been provided and thusof potential liability has not been determined.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, and results of operations.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 pastpreceding two years.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. 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 forummeeting 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 althougheven though it remained under the heightened NRC oversight since August 2004.oversight. During the public forummeeting 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.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 second 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.
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 matter,matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, and results of operations.operations and cash flows.
See Note 12(C)13(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.
New Accounting Standards and Interpretations
FIN 47,“EITF Issue 04-13,”Accounting for Conditional Asset Retirement Obligations -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 interpretationexchange of FASB Statement No. 143”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 this interpretationFIN 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 firstsecond 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 interpretationInterpretation is effective no later than the end of fiscal years ending after December 15, 2005. FirstEnergyTherefore, 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.
| 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.
EITF Issue No. 03-1, "TheFSP FAS 115-1, “The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"Investments”
In March 2004,September 2005, the EITF reached a consensus on the application guidance for Issue 03-1.FASB finalized and renamed EITF 03-1 providesand 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 model for determiningSecurity Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when investments in certain debt and equity securities are consideredthe impairment is deemed other than temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair valuetemporary, even if a decision to sell has not been made, and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to(3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after JuneSeptember 15, 2004, were delayed by2005. The FASB expects to issue this FSP in the issuancefourth 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 EITF 03-1-1 in September 2004. During the period of delay, FirstEnergy will continue to evaluateand any impact on its investments as required by existing authoritative guidance.investments.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | | THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | |
| | | | | | | | | | | | | | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | (Unaudited) | | (Unaudited) | |
| | | | | | | | |
| | | | Three Months Ended | | | | | | | | | | | | |
| | | | March 31, | | | Three Months Ended | | | | Nine Months Ended | |
| | | | | | | | | September 30, | | | | September 30, | |
| | | | 2005 | | 2004 | | | 2005 | | 2004 | | | | 2005 | | 2004 | |
| | | | | | | | | (In thousands) | |
STATEMENTS OF INCOME | | | | (In thousands) | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
OPERATING REVENUES | | | | | $ | 433,173 | | $ | 426,535 | | | $ | 526,421 | | $ | 504,848 | | | | $ | 1,408,341 | | $ | 1,372,259 | |
| | | | | | | | | | | | | | | | | | | | |
OPERATING EXPENSES AND TAXES: | | | | | | | | | | | | | | | | | | | | |
Fuel | | | | | 18,327 | | 17,196 | | | | 24,701 | | 21,011 | | | | 64,138 | | 57,583 | |
Purchased power | | | | | 142,884 | | 134,677 | | | | 129,640 | | 140,988 | | | | 411,366 | | 412,170 | |
Nuclear operating costs | | | | | 58,727 | | 32,715 | | | | 26,252 | | 28,766 | | | | 121,765 | | 80,002 | |
Other operating costs | | | | | 63,573 | | 64,027 | | | | 89,475 | | 76,196 | | | | 227,759 | | 219,857 | |
Provision for depreciation | | | | | 31,115 | | 32,188 | | | | 36,100 | | 33,096 | | | | 100,602 | | 98,060 | |
Amortization of regulatory assets | | | | | 54,026 | | 48,068 | | | | 68,455 | | 53,732 | | | | 177,497 | | 151,822 | |
Deferral of new regulatory assets | | | | | (25,288 | ) | | (18,480 | ) | | | (60,519 | ) | | (40,596 | ) | | | (126,508 | ) | | (92,032 | ) |
General taxes | | | | | 38,887 | | 38,818 | | | | 40,054 | | 37,348 | | | | 115,546 | | 110,646 | |
Income taxes | | | | | | 4,877 | | | 4,013 | | | | 55,286 | | | 51,883 | | | | | 94,897 | | | 81,057 | |
Total operating expenses and taxes | | | | | | 387,128 | | | 353,222 | | | | 409,444 | | | 402,424 | | | | | 1,187,062 | | | 1,119,165 | |
| | | | | | | | | | | | | | | | | | | | |
OPERATING INCOME | | | | | 46,045 | | 73,313 | | | | 116,977 | | | 102,424 | | | | | 221,279 | | | 253,094 | |
| | | | | | | | | | | | | | | | | | | | |
OTHER INCOME (net of income taxes) | | | | | 4,304 | | 11,727 | | | | 24,117 | | | 8,264 | | | | | 37,691 | | | 29,485 | |
| | | | | | | | | | | | | | | | | | | | |
NET INTEREST CHARGES: | | | | | | | | | | | | | | | | | | | | |
Interest on long-term debt | | | | | 27,952 | | 32,211 | | | | 27,090 | | 24,061 | | | | 83,452 | | 92,967 | |
Allowance for borrowed funds used during construction | | | | | 411 | | (1,711 | ) | | | (1,129 | ) | | (1,056 | ) | | | (2,012 | ) | | (3,782 | ) |
Other interest expense | | | | | | 6,514 | | | 6,065 | | | | 4,696 | | | 5,239 | | | | | 12,952 | | | 12,750 | |
Net interest charges | | | | | 34,877 | | 36,565 | | | | 30,657 | | | 28,244 | | | | | 94,392 | | | 101,935 | |
| | | | | | | | | | | | | | | | | | | | |
NET INCOME | | | | | 15,472 | | 48,475 | | | | 110,437 | | 82,444 | | | | 164,578 | | 180,644 | |
| | | | | | | | | | | | | | | | | | | | |
PREFERRED STOCK DIVIDEND REQUIREMENTS | | | | | | 2,918 | | | 1,744 | | | | - | | | 1,754 | | | | | 2,918 | | | 5,253 | |
| | | | | | | | | | | | | | | | | | | | |
EARNINGS ON COMMON STOCK | | | | | $ | 12,554 | | $ | 46,731 | | | $ | 110,437 | | $ | 80,690 | | | | $ | 161,660 | | $ | 175,391 | |
| | | | | | | | | | | | | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
NET INCOME | | | | | $ | 15,472 | | $ | 48,475 | | | $ | 110,437 | | $ | 82,444 | | | | $ | 164,578 | | $ | 180,644 | |
| | | | | | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | | | | | |
Unrealized gain (loss) on available for sale securities | | | | | (1,221 | ) | | 8,048 | | | | (6,574 | ) | | 991 | | | | (9,144 | ) | | (1,332 | ) |
Income tax related to other comprehensive income | | | | | | 504 | | | (3,296 | ) | |
Income tax expense (benefit) related to other comprehensive income | | | | (2,510 | ) | | 406 | | | | | (3,433 | ) | | (546 | ) |
Other comprehensive income (loss), net of tax | | | | | | (717 | ) | | 4,752 | | | | (4,064 | ) | | 585 | | | | | (5,711 | ) | | (786 | ) |
| | | | | | | | | | | | | | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | | | | $ | 14,755 | | $ | 53,227 | | | $ | 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 | | The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an | | |
integral part of these statements. | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral | | |
part of these statements. | | | | | | | | | |
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | |
| | | | | | | |
CONSOLIDATED BALANCE SHEETS | |
(Unaudited) | |
| | | | March 31, | | December 31, | |
| | | | 2005 | | 2004 | |
| | | | (In thousands) | |
ASSETS | | | | | | | |
UTILITY PLANT: | | | | | | | |
In service | | | | | $ | 4,438,471 | | $ | 4,418,313 | |
Less - Accumulated provision for depreciation | | | | | | 1,984,240 | | | 1,961,737 | |
| | | | | | 2,454,231 | | | 2,456,576 | |
Construction work in progress- | | | | | | | | | | |
Electric plant | | | | | | 86,276 | | | 85,258 | |
Nuclear fuel | | | | | | 39,655 | | | 30,827 | |
| | | | | | 125,931 | | | 116,085 | |
| | | | | | 2,580,162 | | | 2,572,661 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | | |
Investment in lessor notes | | | | | | 564,175 | | | 596,645 | |
Nuclear plant decommissioning trusts | | | | | | 391,857 | | | 383,875 | |
Long-term notes receivable from associated companies | | | | | | 7,222 | | | 97,489 | |
Other | | | | | | 16,042 | | | 17,001 | |
| | | | | | 979,296 | | | 1,095,010 | |
CURRENT ASSETS: | | | | | | | | | | |
Cash and cash equivalents | | | | | | 207 | | | 197 | |
Receivables- | | | | | | | | | | |
Customers | | | �� | | | 14,233 | | | 11,537 | |
Associated companies | | | | | | 6,277 | | | 33,414 | |
Other (less accumulated provisions of $207,000 and $293,000, respectively, | | | | | | | | | | |
for uncollectible accounts) | | | | | | 92,336 | | | 152,785 | |
Notes receivable from associated companies | | | | | | -- | | | 521 | |
Materials and supplies, at average cost | | | | | | 81,258 | | | 58,922 | |
Prepayments and other | | | | | | 1,509 | | | 2,136 | |
| | | | | | 195,820 | | | 259,512 | |
DEFERRED CHARGES: | | | | | | | | | | |
Goodwill | | | | | | 1,693,629 | | | 1,693,629 | |
Regulatory assets | | | | | | 925,473 | | | 958,986 | |
Property taxes | | | | | | 77,792 | | | 77,792 | |
Other | | | | | | 44,648 | | | 32,875 | |
| | | | | | 2,741,542 | | | 2,763,282 | |
| | | | | $ | 6,496,820 | | $ | 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 | | | | | $ | 1,281,962 | | $ | 1,281,962 | |
Accumulated other comprehensive income | | | | | | 17,142 | | | 17,859 | |
Retained earnings | | | | | | 511,288 | | | 553,740 | |
Total common stockholder's equity | | | | | | 1,810,392 | | | 1,853,561 | |
Preferred stock | | | | | | -- | | | 96,404 | |
Long-term debt and other long-term obligations | | | | | | 1,953,089 | | | 1,970,117 | |
| | | | | | 3,763,481 | | | 3,920,082 | |
CURRENT LIABILITIES: | | | | | | | | | | |
Currently payable long-term debt | | | | | | 81,382 | | | 76,701 | |
Accounts payable- | | | | | | | | | | |
Associated companies | | | | | | 191,057 | | | 150,141 | |
Other | | | | | | 7,593 | | | 9,271 | |
Notes payable to associated companies | | | | | | 470,732 | | | 488,633 | |
Accrued taxes | | | | | | 108,256 | | | 129,454 | |
Accrued interest | | | | | | 34,133 | | | 22,102 | |
Lease market valuation liability | | | | | | 60,200 | | | 60,200 | |
Other | | | | | | 32,312 | | | 61,131 | |
| | | | | | 985,665 | | | 997,633 | |
NONCURRENT LIABILITIES: | | | | | | | | | | |
Accumulated deferred income taxes | | | | | | 535,908 | | | 540,211 | |
Accumulated deferred investment tax credits | | | | | | 59,569 | | | 60,901 | |
Asset retirement obligation | | | | | | 276,627 | | | 272,123 | |
Retirement benefits | | | | | | 81,828 | | | 82,306 | |
Lease market valuation liability | | | | | | 653,200 | | | 668,200 | |
Other | | | | | | 140,542 | | | 149,009 | |
| | | | | | 1,747,674 | | | 1,772,750 | |
COMMITMENTS AND CONTINGENCIES (Note 12) | | | | | | | | | | |
| | | | | $ | 6,496,820 | | $ | 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. | |
| | | | | | | | | | |
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. | | | | | | | |
| | | | | | | |
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | |
| | | | | | | |
CONSOLIDATED STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | | |
| | | | Three Months Ended | |
| | | | March 31, | |
| | | | | | | |
| | | | 2005 | | 2004 | |
| | | | | | | |
| | | | (In thousands) | |
| | | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | |
Net income | | | | | $ | 15,472 | | $ | 48,475 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | | | |
Provision for depreciation | | | | | | 31,115 | | | 32,188 | |
Amortization of regulatory assets | | | | | | 54,026 | | | 48,068 | |
Deferral of new regulatory assets | | | | | | (25,288 | ) | | (18,480 | ) |
Nuclear fuel and capital lease amortization | | | | | | 4,610 | | | 5,107 | |
Amortization of electric service obligation | | | | | | (5,451 | ) | | (4,723 | ) |
Deferred rents and lease market valuation liability | | | | | | (53,469 | ) | | (41,635 | ) |
Deferred income taxes and investment tax credits, net | | | | | | (4,506 | ) | | (4,039 | ) |
Accrued retirement benefit obligations | | | | | | (478 | ) | | 5,732 | |
Accrued compensation, net | | | | | | (2,725 | ) | | 1,453 | |
Decrease (Increase) in operating assets- | | | | | | | | | | |
Receivables | | | | | | 84,890 | | | 143,766 | |
Materials and supplies | | | | | | (22,336 | ) | | (2,355 | ) |
Prepayments and other current assets | | | | | | 627 | | | 1,895 | |
Increase (Decrease) in operating liabilities- | | | | | | | | | | |
Accounts payable | | | | | | 39,238 | | | 22,387 | |
Accrued taxes | | | | | | (21,198 | ) | | (67,926 | ) |
Accrued interest | | | | | | 12,031 | | | 8,239 | |
Other | | | | | | (3,358 | ) | | (29,788 | ) |
Net cash provided from operating activities | | | | | | 103,200 | | | 148,364 | |
| | | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | |
New Financing- | | | | | | | | | | |
Long-term debt | | | | | | -- | | | 80,967 | |
Redemptions and Repayments- | | | | | | | | | | |
Preferred stock | | | | | | (97,900 | ) | | -- | |
Long-term debt | | | | | | (330 | ) | | (7,985 | ) |
Short-term borrowings, net | | | | | | (29,683 | ) | | (182,167 | ) |
Dividend Payments- | | | | | | | | | | |
Common stock | | | | | | (55,000 | ) | | (55,000 | ) |
Preferred stock | | | | | | (2,260 | ) | | (1,744 | ) |
Net cash used for financing activities | | | | | | (185,173 | ) | | (165,929 | ) |
| | | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | |
Property additions | | | | | | (33,683 | ) | | (17,868 | ) |
Loan repayments from (loans to) associated companies, net | | | | | | 90,788 | | | (2,922 | ) |
Investments in lessor notes | | | | | | 32,470 | | | 20,965 | |
Contributions to nuclear decommissioning trusts | | | | | | (7,256 | ) | | (7,256 | ) |
Other | | | | | | (336 | ) | | 64 | |
Net cash provided from (used for) investing activities | | | | | | 81,983 | | | (7,017 | ) |
| | | | | | | | | | |
Net increase (decrease) in cash and cash equivalents | | | | | | 10 | | | (24,582 | ) |
Cash and cash equivalents at beginning of period | | | | | | 197 | | | 24,782 | |
Cash and cash equivalents at end of period | | | | | $ | 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. | | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
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. | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
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 March 31,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 March 31,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
May 3,November 1, 2005
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 firstthird quarter of 2005 decreasedincreased to $13$110 million from $47$81 million in the firstthird 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. This decreaseLower earnings for the first nine months of 2005 resulted principallyprimarily from higher nuclear operating costs, higher regulatory asset amortization and purchased powerother operating costs and a one-time income tax charge; those effects were partially offset by higherincreased operating revenues.revenues and lower net interest charges.
Operating revenues increased by $7$22 million or 1.6%4.3% in the firstthird quarter of 2005 from the same period in 2004. Higher revenues resulted principallyprimarily from increasedincreases in retail generation sales revenueand distribution revenues of $6 million (commercial - $1$3 million and industrial -$19 million, respectively, and a $5 million).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.
RetailIncreased retail generation revenues for the third quarter of 2005 resulted from higher industrial unit prices and higher residential KWH sales, declined slightlypartially offset by lower unit prices and were not materially affected by customer shopping as generation services provided by alternative suppliersKWH 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, remained relatively constantas 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 quarternine months of 2005 comparedcontributed slightly to 2004. The industrial revenue increase was primarily due tothe higher unit prices partially offset by the effect of a 1.8%generation KWH sales decrease. The increase in commercial sector revenues was primarily due to a 3.3% KWH sales increase. Residential retail generation revenues were nearly unchanged for the first quarter of 2005period as compared to last year.
Wholesale sale revenues showed a slight increaseRevenue from wholesale sales increased by $5 million during the third quarter of $0.4 million while2005, reflecting the effect of a net 2.8% decrease2.5% increase in KWH sales. The increase in wholesale sales was primarily due to a 13.6% KWH increase in MSG wholesale sales to non-affiliated wholesale customers increased by $8.2 million (38% KWH sales increase)($3.5 million). Under its Ohio transition plan, CEI is required to provide a low-cost generation power supplyMSG to unaffiliatednon-affiliated alternative suppliers (see Outlook - Regulatory Matters). TheIncreased 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 increaseto non-affiliated wholesale customers was partially offset by decreasedan $18 million decrease in sales to FES of $7.8 million (6.9%(6.7% KWH decrease) due to less nuclear generation available for sale.FES.
Revenues from distribution throughput decreased by $5increased $19 million in the firstthird quarter of 2005 compared with the correspondingsame quarter inof 2004. The decreaseincrease was due to lowerhigher residential and industrial revenues ($318 million and $4$5 million, respectively), reflecting lower composite unit prices and reducedincreased distribution deliveries in the firstthird quarter of 2005.2005, in part due to warmer weather. These impactsincreases 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 commercialrevenues in the residential sector sales of $2 million resulting from increased($28 million), partially offset by lower industrial revenues ($4 million). Higher distribution deliveries in the residential sector were partially offset by lower unit prices. Under the Ohio transition plan, CEI provides incentivesprices and decreased KWH deliveries to customers to encourage switching to alternative energy providers - $1 million of additional credits were provided to customersindustrial customers. Revenues in the first quarter of 2005 compared with 2004. These revenue reductions are deferred for future recovery under CEI's transition plan and do not affect current period earnings.commercial sector increased slightly ($0.4 million) as higher distribution deliveries were almost totally offset by lower unit prices.
Other operating revenues increased by $6 million in the first quarter of 2005 compared with 2004, primarily due to increased revenues from the sales of its customer receivables (see Off-Balance Sheet Arrangements).
Changes in electric generationKWH sales and distribution deliveriesby customer class in the first quarter ofthree months and nine months ended September 30, 2005 from the first quartercorresponding periods of 2004 are summarized in the following table:
Changes in KWH Sales
| | | |
Increase (Decrease)
| | | |
Electric Generation: | | | |
Retail
| | | (0.6 | )% |
Wholesale
| | | (2.8 | )% |
Total Electric Generation Sales
| | | (1.8 | )% |
| | | | |
Distribution Deliveries: | | | | |
Residential
| | | (3.3 | )% |
Commercial
| | | 5.5 | % |
Industrial
| | | (2.4 | )% |
Total Distribution Deliveries
| | | (0.7 | )% |
| | 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 $34$7 million in the third quarter and $68 million in the first quarternine months of 2005 from the first quartersame 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) | | | | | (In millions) | |
Fuel costs | | $ | 1 | | | $ | 3 | | $ | 6 | |
Purchased power costs | | | 8 | | | | (11 | ) | | (1 | ) |
Nuclear operating costs | | | 26 | | | | (2 | ) | | 42 | |
Other operating costs | | | | 13 | | 8 | |
Provision for depreciation | | | (1 | ) | | | 3 | | 3 | |
Amortization of regulatory assets | | | 6 | | | | 15 | | 26 | |
Deferral of new regulatory assets | | | (7 | ) | | | (20 | ) | | (35 | ) |
General taxes | | | | 3 | | | 5 | |
Income taxes | | | 1 | | | | 3 | | | 14 | |
Net increase in operating expenses and taxes | | $ | 34 | | | $ | 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 firstthird quarter of 2005, compared with the firstthird quarter of 2004, reflected higher KWH purchased, partially offset byboth lower unit costs.costs and lower KWH purchased. The increase in nuclear operating costs forin the first quarternine months of 2005, compared to the first quarter of 2004same period last year, was primarily due to a refueling outage (including an unplanned extension) at the Perry nuclear plantPlant in 2005 and a refueling outage at Beaver Valley Unit 2. A mid-cycle inspection outage at the Davis-Besse nuclear plantPlant in the first quarter of 2005 andalso contributed to higher nuclear operating costs in the first nine months of 2005. There were no scheduled outages in the first quarternine 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.
The decrease in depreciationHigher regulatory asset amortization in the third quarter and first quarternine months of 2005, compared withto the first quarter of 2004 was attributable to revised estimated service life assumptions for fossil generating plants. Higher amortization of regulatory assets in 2005 as compared to 2004same periods last year, was primarily due to increased amortization of transition regulatory assets.costs being recovered under the RSP. Increases in regulatory asset deferrals for both the deferral of regulatory assetsthird quarter and first nine months in 2005, fromcompared to the same periods in 2004, resulted from higher shopping incentive deferrals ($1 million) and deferredrelated interest, onand the shopping incentives ($5 million)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.
Other Income
Other income decreasedincreased by $7$16 million in the firstthird quarter of 2005 compared with the first quartersame period of 2004, primarily due to an increase in expenses related to the sales of customer receivables and a $2 million potential NRC fine related to the Davis-Besse Plant (see Outlook - Other Legal Proceedings).higher nuclear decommissioning trust realized gains.
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $2 million in the first quarternine months of 2005 fromdecreased by $8 million compared with the same quarterperiod last year, reflecting the effects of net redemptions and refinancings of $281 million and $46 million, respectively, subsequent to the first quarter ofsince October 1, 2004.
Preferred Stock Dividend Requirements
Preferred stock dividend requirements increased by $1 million in the first quarter of 2005, compared to the same period last year, due to premiums related to optional preferred stock redemptions in the first quarter of 2005.
Capital Resources and Liquidity
CEI’s cash requirements infor the remainder of 2005 for operating expenses and construction expenditures scheduled debt maturities and preferred stock redemptions are expected to be met without increasing net debt and preferred stock outstanding.debt. Thereafter, CEI expects to use a combination of cash from operations and funds from the capital markets.
Changes in Cash Position
As of March 31,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 quarternine months of 2005, compared with the first quarter ofcorresponding periods in 2004, were as follows:
| | | Three Months Ended | | Nine Months Ended | |
| | | September 30, | | September 30, | |
Operating Cash Flows | | 2005 | | 2004 | | | 2005 | | 2004 | | 2005 | | 2004 | |
| | (In millions) | | | (In millions) | |
| | | | | | | | | | | | | | |
Cash earnings(1) | | $ | 13 | | $ | 72 | | | $ | 161 | | $ | 123 | | $ | 274 | | $ | 302 | |
Pension trust contribution (2) | | | | -- | | | (19 | ) | | -- | | | (19 | ) |
Working capital and other | | | 90 | | | 76 | | | | (111 | ) | | 35 | | | (147 | ) | | 10 | |
Total | | $ | 103 | | $ | 148 | | |
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 | | | | | | | | | | | |
(1)Cash earnings are a non-GAAP measure (see reconciliation below).
Cash earnings, (inas disclosed in the table above)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.
| | Three Months Ended | |
| | March 31, | |
Reconciliation of Cash Earnings | | 2005 | | 2004 | |
| | (In millions) | |
Net Income (GAAP) | | $ | 15 | | $ | 48 | |
Non-Cash Charges (Credits): | | | | | | | |
Provision for depreciation | | | 31 | | | 32 | |
Amortization of regulatory assets | | | 54 | | | 48 | |
Deferral of new regulatory assets | | | (25 | ) | | (18 | ) |
Nuclear fuel and capital lease amortization | | | 4 | | | 5 | |
Amortization of electric service obligation | | | (5 | ) | | (4 | ) |
Deferred rents and lease market valuation liability | | | (53 | ) | | (42 | ) |
Deferred income taxes and investment tax credits, net | | | (4 | ) | | (4 | ) |
Accrued retirement benefit obligations | | | (1 | ) | | 6 | |
Accrued compensation, net | | | (3 | ) | | 1 | |
Cash earnings (Non-GAAP) | | $ | 13 | | $ | 72 | |
| | 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 $59 million decreaseincrease in cash earnings isof $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 and under "Results of Operations", partially offset by a $14 million increase from working capital and other cash flows.. The largestprimary factors contributing to the changechanges in working capital and other cash flows werefor the third quarter of 2005 are changes in accrued taxes, accrued interest and accounts payable of $217 million, partially offset by changes in receivables.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 increased $19decreased $46 million in the firstthird quarter of 2005 from the firstthird quarter of 2004. The increasedecrease resulted from a $62 million decrease in fundsnet debt redemptions, partially offset by higher common stock dividends to FirstEnergy of $17 million. Net cash used for financing activities resulted from $98decreased $105 million of optional redemptions of preferred stock 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 a reductionan increase in net debtpreferred stock redemptions.
CEI had $207,000 of cash and temporary investments and approximately $471$554 million of short-term indebtedness as of March 31,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 $1.4$1.6 billion of additional FMB on the basis of property additions and retired bonds under the terms of its mortgage indenture.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 $565$582 million as of March 31,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.
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 firstthird quarter of 2005 was 2.66%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. The ratings outlook from the rating agencies on all such securities is stable.
On MarchJuly 18, 2005, S&PMoody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s Sammis NSR settlement was a very favorable step for FirstEnergy, although it would not immediately affectoutlook 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 ratings or outlook. S&Pcredit profile stemming from the application of free cash flow toward debt reduction. Moody’s noted that ita ratings upgrade could be considered if FirstEnergy continues to monitor the refueling outage at the Perry nuclear plant, which includes a detailed inspection by the NRC,achieve planned improvements in its operations and that if FirstEnergy should exit the outage without significant negative findings or delays the ratings outlook would be revised to positive.balance sheet.
On March 14,October 3, 2005, CEI redeemed all 500,000 outstanding shares ofS&P raised its Serial Preferred Stock, $7.40 Series Acorporate credit rating on FirstEnergy and the EUOC to 'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings at a price of $101 per share plus accrued dividendsthe holding company to the date'BBB-' from 'BB+' and each of the redemption. Also on March 14, 2005, CEI redeemed all 474,000 outstanding sharesEUOC by one notch above the previous rating. S&P noted that the upgrade followed the continuation of its Serial Preferred Stock, Adjustable Rate Series L at a pricegood 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 $100 per share plus accrued dividendssupportive regulation, low-cost base load generation fleet, low-risk transmission and distribution operations and rate certainty in Ohio. FirstEnergy’s ability to the date of the redemption.consistently generate free cash flow, good liquidity, and an improving financial profile were also noted as strengths.
On April 20, 2005, Beaver County Industrial Development Authority pollution control bonds aggregating $53.9 million were refunded. The new bonds were issued in a Dutch Auction interest rate mode, insured with municipal bond insurance and secured by FMB.
On June 1, 2005, CEI intends to redeem all of its 40,000 outstanding shares of $7.35 Series C preferred stock at $101.00 per share, plus accrued dividends to the date of redemption.
Cash Flows from Investing Activities
Net cash provided from investing activities was $82 million inIn the third quarter and first quarternine months of 2005, compared tonet cash used for investing activities of $7decreased $42 million inand $86 million, respectively, from the first quartercorresponding periods of 2004. The change wasdecrease in funds used for investing activities for both periods primarily due to increasedreflected increases in loan payments received from associated companies, partially offset by higherincreased property additions.
DuringIn the remaining three quarterslast quarter of 2005, capital requirements for property additions are expected to be about $85 million, including $1 million for nuclear fuel. CEI has additional requirements of approximately $1 million to meet sinking fund requirements for preferred stock during the remainder of 2005.$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 (excluding nuclear fuel) of which approximately $108$124 million applies to 2005. Investments for additional
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 fuel duringand 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 2005-2007 periodplants that are estimatedcurrently 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 approximately $75 million,separated from the regulated delivery business of which about $10 million appliesthose companies through transfer to 2005. Duringa separate corporate entity. FENOC currently operates and maintains the same periods, CEI’s nuclear fuel investments are expectedgeneration assets to be reducedtransferred. 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 approximately $90 millionthe restructuring plans by transferring the ownership interests to NGC and $27 million,FGCO, respectively, aswithout impacting the nuclear fuel is consumed.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.
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 March 31,September 30, 2005, the present value of these operating lease commitments, net of trust investments, total $99$103 million.
CEI sells substantially all of its retail customer receivables to CFC, its wholly owned subsidiary. As of June 16, 2005, the CFC subsequently transfers the receivables to a trust (a "qualified special purpose entity" under SFAS 140) underfinancing structure was renewed and restructured from an asset-backed securitization agreement. This arrangement provided $94 million of off-balance sheet financingtransaction to an on-balance sheet transaction. Under the new structure, any borrowings under the facility appear on the balance sheet as of March 31, 2005.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 $249$277 million and $242 million as of March 31,September 30, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $25$28 million reduction in fair value as of March 31,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. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties.
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, 2005.2008 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.
CEI's revised Rate Stabilization Plan extends currentOn 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 prices through 2008, ensuring adequate generationservice rates beginning January 1, 2006, in response to PUCO concerns about price and supply at stabilized prices, and continues CEI's support of energy efficiency and economic development efforts. Other key componentsuncertainty following the end of the revised Rate Stabilization Plan includeOhio Companies' transition plan market development period. In October 2004, the following: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.
· | extension of the amortization period for transition costs being recovered through the RTC from 2008 to as late as mid-2009; |
· | deferral of interest costs on the accumulated customer shopping incentives as new regulatory assets; and |
· | ability to request increases in generation charges during 2006 through 2008, under certain limited conditions, for increases in fuel costs and taxes. |
On December 9, 2004,May 27, 2005, CEI filed an application with the PUCO rejected the auction price results fromto establish a required competitive bid process and issued an entry stating that the pricingGCAF rider under the approved revised Rate Stabilization Plan will take effect onRSP. 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:
· 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 similar 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 Rate Stabilization PlanRSP pricing, but notwith no accounting impacts to the related approved accounting,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 an application with the PUCO seeking tariff adjustmentstwo applications related to recover increasesthe recovery of approximately $16 million in 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 alsoanticipates 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 anwith 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 forsought authority to defer costs associated with MISO Day 1, MISO Day 2, congestion fees, FERC assessment fees,transmission and ancillary service related costs incurred during the ATSI rate increase, as applicable,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.
On September 16, 2004, the FERC issued an order that imposed additional obligations on CEI under certain pre-Open Access transmission contracts among CEI and the cities of Cleveland and Painesville, Ohio. Under the FERC's decision, CEI may be responsible for a portion of new energy market charges imposed by MISO when its energy markets begin in the spring of 2005. CEI filed for rehearing of the order from the FERC on October 18, 2004. On April 15, 2005, FERC issued an order on rehearing that "carves out" these contracts from the MISO Day 2 market. While the order on rehearing is favorable to CEI, the impact of the FERC decision on CEI is dependent upon many factors, including the arrangements made by the cities for transmission service and MISO's ability to administer the contracts. Accordingly, the impact of this decision cannot be determined at this time.
Regulatoryrecords as regulatory assets are 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 March 31,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 $320$402 million as of March 31,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. Recovery ofSee Note 14 “Regulatory Matters - Ohio” for the new regulatory assets will begin at that time andestimated net amortization of regulatory transition costs and deferred shopping incentive balances under the regulatory assets for each accounting period will be equal to the surcharge revenue recognized during that period.proposed RCP and current RSP.
See Note 1314 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio.
Environmental Matters
CEI accrues environmental liabilities only when it concludes that it is probable that it hasthey have an obligation for such costs and can reasonably determineestimate the amount of such costs. Unasserted claims are reflected in CEI'sCEI’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 will requireprovides 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 in two phases from coal-fired power plants.plants in two phases. Initially, mercury emissions will declinebe 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. The futureHowever, 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 greenhouse gasesGHG 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 gasGHG 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.
FirstEnergy plans to issue a report that will disclose the Companies’ environmental activities, including their plans to respond to environmental requirements. FirstEnergy expects to complete the report by December 1, 2005 and will post the report on its web site,www.firstenergycorp.com.
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 March 31,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 CurrentOther Noncurrent Liabilities are accrued liabilities aggregating approximately $2.3 million as of March 31,September 30, 2005.
See Note 12(B)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 most significantother 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 concluded,concludes, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area.Specifically,area. Specifically, the final report concludes,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“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. As manyFirstEnergy also is proceeding with the implementation of these initiatives alreadythe 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 process,new, or material upgrades, to existing equipment, and therefore FirstEnergy doeshas not believeaccrued a liability as of September 30, 2005 for any expenditures in excess of those actually incurred through that any incremental expenses associated with additional initiatives completed in 2004 had a material effect on its continuing operations or financial results.date. FirstEnergy notes, however, that theFERC 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. FirstEnergy has not accrued a liability asFinally, 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 March 31, 2005 forcontrol room operators, before determining the next steps, if any, expenditures in excess of those actually incurred through that date.the proceeding.
Three substantially similar actions were filed in various Ohio State courts by plaintiffs seekingFirstEnergy companies also are defending six separate complaint cases before the PUCO relating to represent customers who allegedly suffered damages as a result of the August 14, 2003 power outages. All threeoutage. Two such cases were originally filed in Ohio State courts but subsequently dismissed for lack of jurisdiction. Onesubject matter jurisdiction and further appeals were unsuccessful. In both such cases the individual complainants—three in one case was refiled on January 12, 2004 atand four in the PUCO.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 twopending PUCO complaint cases, three were appealed. One case was dismissed and no further appeal was sought.filed by various insurance carriers either in their own name or as subrogees in the name of their insureds. In the remainingeach such case, the Courtcarriers 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 Appealspower on March 31, 2005 affirmedAugust 14, 2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy company. The fourth case involves the trial court’s decision dismissing the case. It is not yet known whether further appeal will be sought.claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. In addition to the one case that was refiled at the PUCO,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 filed aFirstEnergy's motion to dismiss with 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 October 22, 2004.or about December 1, 2005. No timetable for a decision on the motion to dismiss has been established by the Court. No damage estimate has been provided and thusof potential liability has not been determined.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, and results of operations.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. Under the NRC’s letter, FENOC has ninety daysCEI accrued $1.0 million for a potential fine prior to respond to this NOV. CEI has2005 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 hashave legal liability based on the events surrounding Davis-Besse, head degradation, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, and results of operations.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 pastpreceding two years.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. 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 forummeeting 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 althougheven though it remained under the heightened NRC oversight since August 2004.oversight. During the public forummeeting 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.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 second 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, and results of operations.operations and cash flows.
See Note 12(C)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.
FIN 47,“Accounting “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”143”
On March 30, 2005, the FASB issued this interpretationFIN 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 interpretationInterpretation is effective no later thanfor CEI in the endfourth quarter of fiscal years ending after December 15, 2005. FirstEnergyCEI is currently evaluating the effect this standardInterpretation 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.
EITF IssueSFAS 151, “Inventory Costs - an amendment of ARB No. 03-1,43, 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 March 2004,September 2005, the EITF reached a consensus on the application guidance for Issue 03-1.FASB finalized and renamed EITF 03-1 providesand 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 model for determiningSecurity Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when investments in certain debt and equity securities are consideredthe impairment is deemed other than temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair valuetemporary, even if a decision to sell has not been made, and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to(3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after JuneSeptember 15, 2004, were delayed by2005. The FASB expects to issue this FSP in the issuancefourth 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 EITF 03-1-1 in September 2004. During the period of delay, FirstEnergy will continue to evaluateand any impact on its investments as required by existing authoritative guidance.investments.
THE TOLEDO EDISON COMPANY | THE TOLEDO EDISON COMPANY | | THE TOLEDO EDISON COMPANY | |
| | | | | | | | | | | | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | (Unaudited) | | (Unaudited) | |
| | | | | | | | |
| | | | Three Months Ended | | | | | | | | | | |
| | | | March 31, | | | Three Months Ended | | Nine Months Ended | |
| | | | | | | | | September 30, | | September 30, | |
| | | | 2005 | | 2004 | | | 2005 | | 2004 | | 2005 | | 2004 | |
| | | | | | | | | (In thousands) | |
STATEMENTS OF INCOME | | | | (In thousands) | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
OPERATING REVENUES | | | | | $ | 241,755 | | $ | 235,398 | | | $ | 286,960 | | $ | 276,342 | | $ | 787,824 | | $ | 755,106 | |
| | | | | | | | | | | | | | | | | | | | | |
OPERATING EXPENSES AND TAXES: | | | | | | | | | | | | | | | | | | | | | |
Fuel | | | | | 12,569 | | 10,214 | | | | 16,501 | | | 13,908 | | | 43,474 | | | 37,195 | |
Purchased power | | | | | 80,156 | | 82,408 | | | | 73,144 | | | 79,774 | | | 225,600 | | | 236,869 | |
Nuclear operating costs | | | | | 59,163 | | 42,692 | | | | 39,207 | | | 43,827 | | | 145,059 | | | 122,685 | |
Other operating costs | | | | | 34,348 | | 36,208 | | | | 48,164 | | | 43,865 | | | 123,823 | | | 121,228 | |
Provision for depreciation | | | | | 14,680 | | 14,053 | | | | 18,835 | | | 14,588 | | | 48,724 | | | 43,021 | |
Amortization of regulatory assets | | | | | 34,865 | | 33,666 | | | | 39,576 | | | 41,037 | | | 107,672 | | | 102,065 | |
Deferral of new regulatory assets | | | | | (9,424 | ) | | (7,030 | ) | | | (19,379 | ) | | (12,442 | ) | | (41,473 | ) | | (29,664 | ) |
General taxes | | | | | 14,181 | | 14,300 | | | | 14,159 | | | 14,924 | | | 41,960 | | | 41,252 | |
Income tax benefit | | | | | | (3,968 | ) | | (1,578 | ) | |
Income taxes | | | | 20,311 | | | 11,963 | | | 44,160 | | | 18,465 | |
Total operating expenses and taxes | | | | | | 236,570 | | | 224,933 | | | | 250,518 | | | 251,444 | | | 738,999 | | | 693,116 | |
| | | | | | | | | | | | | | | | | | | | | |
OPERATING INCOME | | | | | 5,185 | | 10,465 | | | | 36,442 | | | 24,898 | | | 48,825 | | | 61,990 | |
| | | | | | | | | | | | | | | | | | | | | |
OTHER INCOME (net of income taxes) | | | | | 2,659 | | 5,833 | | | | 12,283 | | | 4,172 | | | 18,173 | | | 14,724 | |
| | | | | | | | | | | | | | | | | | | | | |
NET INTEREST CHARGES: | | | | | | | | | | | | | | | | | | | | | |
Interest on long-term debt | | | | | 4,220 | | 9,461 | | | | 3,912 | | | 4,015 | | | 12,655 | | | 23,057 | |
Allowance for borrowed funds used during construction | | | | | 443 | | (1,400 | ) | | | (372 | ) | | (741 | ) | | (117 | ) | | (2,843 | ) |
Other interest expense | | | | | | 2,816 | | | 706 | | | | 2,958 | | | 1,350 | | | 4,192 | | | 2,945 | |
Net interest charges | | | | | 7,479 | | 8,767 | | | | 6,498 | | | 4,624 | | | 16,730 | | | 23,159 | |
| | | | | | | | | | | | | | | | | | | | | |
NET INCOME | | | | | 365 | | 7,531 | | | | 42,227 | | | 24,446 | | | 50,268 | | | 53,555 | |
| | | | | | | | | | | | | | | | | | | | | |
PREFERRED STOCK DIVIDEND REQUIREMENTS | | | | | | 2,211 | | | 2,211 | | | | 1,687 | | | 2,211 | | | 6,109 | | | 6,633 | |
| | | | | | | | | | | | | | | | | | | | | |
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK | | | | | $ | (1,846 | ) | $ | 5,320 | | |
EARNINGS ON COMMON STOCK | | | $ | 40,540 | | $ | 22,235 | | $ | 44,159 | | $ | 46,922 | |
| | | | | | | | | | | | | | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
NET INCOME | | | | | 365 | | 7,531 | | | $ | 42,227 | | $ | 24,446 | | $ | 50,268 | | $ | 53,555 | |
| | | | | | | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | | | | | | |
Unrealized gain (loss) on available for sale securities | | | | | (1,683 | ) | | 5,682 | | | | (4,511 | ) | | 913 | | | (6,695 | ) | | (379 | ) |
Income tax related to other comprehensive income | | | | | | 695 | | | (2,331 | ) | |
Income tax expense (benefit) related to other comprehensive income | | | | (1,743 | ) | | 375 | | | (2,534 | ) | | (155 | ) |
Other comprehensive income (loss), net of tax | | | | | | (988 | ) | | 3,351 | | | | (2,768 | ) | | 538 | | | (4,161 | ) | | (224 | ) |
| | | | | | | | | | | | | | | | | | | | | |
TOTAL COMPREHENSIVE INCOME (LOSS) | | | | | $ | (623 | ) | $ | 10,882 | | |
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 partof these statements. | The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral partof these statements. | | The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements. | |
| | | | | | | | | | | |
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. | |
| | | | | | | |
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. | | |
| | | | | | | | | | | | | |
THE TOLEDO EDISON COMPANY | |
| | | | | | | |
CONSOLIDATED BALANCE SHEETS | |
(Unaudited) | |
| | | | March 31, | | December 31, | |
| | | | 2005 | | 2004 | |
| | | | (In thousands) | |
ASSETS | | | | | | | |
UTILITY PLANT: | | | | | | | |
In service | | | | | $ | 1,857,720 | | $ | 1,856,478 | |
Less - Accumulated provision for depreciation | | | | | | 789,915 | | | 778,864 | |
| | | | | | 1,067,805 | | | 1,077,614 | |
Construction work in progress- | | | | | | | | | | |
Electric plant | | | | | | 66,405 | | | 58,535 | |
Nuclear fuel | | | | | | 22,634 | | | 15,998 | |
| | | | | | 89,039 | | | 74,533 | |
| | | | | | 1,156,844 | | | 1,152,147 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | | |
Investment in lessor notes | | | | | | 178,764 | | | 190,692 | |
Nuclear plant decommissioning trusts | | | | | | 305,046 | | | 297,803 | |
Long-term notes receivable from associated companies | | | | | | 40,002 | | | 39,975 | |
Other | | | | | | 1,835 | | | 2,031 | |
| | | | | | 525,647 | | | 530,501 | |
CURRENT ASSETS: | | | | | | | | | | |
Cash and cash equivalents | | | | | | 15 | | | 15 | |
Receivables- | | | | | | | | | | |
Customers | | | | | | 6,443 | | | 4,858 | |
Associated companies | | | | | | 12,180 | | | 36,570 | |
Other | | | | | | 4,138 | | | 3,842 | |
Notes receivable from associated companies | | | | | | 137,266 | | | 135,683 | |
Materials and supplies, at average cost | | | | | | 46,769 | | | 40,280 | |
Prepayments and other | | | | | | 1,206 | | | 1,150 | |
| | | | | | 208,017 | | | 222,398 | |
DEFERRED CHARGES: | | | | | | | | | | |
Goodwill | | | | | | 504,522 | | | 504,522 | |
Regulatory assets | | | | | | 349,297 | | | 374,814 | |
Property taxes | | | | | | 24,100 | | | 24,100 | |
Other | | | | | | 43,312 | | | 25,424 | |
| | | | | | 921,231 | | | 928,860 | |
| | | | | $ | 2,811,739 | | $ | 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 | | | | | | 428,559 | | | 428,559 | |
Accumulated other comprehensive income | | | | | | 19,051 | | | 20,039 | |
Retained earnings | | | | | | 189,213 | | | 191,059 | |
Total common stockholder's equity | | | | | | 832,493 | | | 835,327 | |
Preferred stock | | | | | | 126,000 | | | 126,000 | |
Long-term debt | | | | | | 300,131 | | | 300,299 | |
| | | | | | 1,258,624 | | | 1,261,626 | |
CURRENT LIABILITIES: | | | | | | | | | | |
Currently payable long-term debt | | | | | | 90,950 | | | 90,950 | |
Accounts payable- | | | | | | | | | | |
Associated companies | | | | | | 116,930 | | | 110,047 | |
Other | | | | | | 2,299 | | | 2,247 | |
Notes payable to associated companies | | | | | | 394,761 | | | 429,517 | |
Accrued taxes | | | | | | 31,695 | | | 46,957 | |
Lease market valuation liability | | | | | | 24,600 | | | 24,600 | |
Other | | | | | | 80,005 | | | 53,055 | |
| | | | | | 741,240 | | | 757,373 | |
NONCURRENT LIABILITIES: | | | | | | | | | | |
Accumulated deferred income taxes | | | | | | 221,759 | | | 221,950 | |
Accumulated deferred investment tax credits | | | | | | 24,562 | | | 25,102 | |
Retirement benefits | | | | | | 39,838 | | | 39,227 | |
Asset retirement obligation | | | | | | 197,564 | | | 194,315 | |
Lease market valuation liability | | | | | | 261,850 | | | 268,000 | |
Other | | | | | | 66,302 | | | 66,313 | |
| | | | | | 811,875 | | | 814,907 | |
COMMITMENTS AND CONTINGENCIES (Note 12) | | | | | | | | | | |
| | | | | $ | 2,811,739 | | $ | 2,833,906 | |
| | | | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of these balance sheets. | |
| | | | | | | | | | |
THE TOLEDO EDISON COMPANY | |
| | | | | | | |
CONSOLIDATED STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | | |
| | | | Three Months Ended | |
| | | | March 31, | |
| | | | | | | |
| | | | 2005 | | 2004 | |
| | | | | | | |
| | | | (In thousands) | |
| | | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | |
Net income | | | | | $ | 365 | | $ | 7,531 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | | | |
Provision for depreciation | | | | | | 14,680 | | | 14,053 | |
Amortization of regulatory assets | | | | | | 34,865 | | | 33,666 | |
Deferral of new regulatory assets | | | | | | (9,424 | ) | | (7,030 | ) |
Nuclear fuel and capital lease amortization | | | | | | 4,868 | | | 5,506 | |
Deferred rents and lease market valuation liability | | | | | | (15,224 | ) | | (7,692 | ) |
Deferred income taxes and investment tax credits, net | | | | | | (1,387 | ) | | (2,031 | ) |
Accrued retirement benefit obligations | | | | | | 611 | | | 2,285 | |
Accrued compensation, net | | | | | | (1,265 | ) | | (733 | ) |
Decrease (Increase) in operating assets: | | | | | | | | | | |
Receivables | | | | | | 41,475 | | | 20,035 | |
Materials and supplies | | | | | | (6,489 | ) | | (1,434 | ) |
Prepayments and other current assets | | | | | | (56 | ) | | 3,384 | |
Increase (Decrease) in operating liabilities: | | | | | | | | | | |
Accounts payable | | | | | | 6,935 | | | (6,074 | ) |
Accrued taxes | | | | | | (15,262 | ) | | (14,085 | ) |
Accrued interest | | | | | | 853 | | | (2,280 | ) |
Other | | | | | | (1,989 | ) | | (8,147 | ) |
Net cash provided from operating activities | | | | | | 53,556 | | | 36,954 | |
| | | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | |
New Financing- | | | | | | | | | | |
Long-term debt | | | | | | -- | | | 73,000 | |
Redemptions and Repayments- | | | | | | | | | | |
Long-term debt | | | | | | -- | | | (15,000 | ) |
Short-term borrowings, net | | | | | | (34,993 | ) | | (93,299 | ) |
Dividend Payments- | | | | | | | | | | |
Preferred stock | | | | | | (2,211 | ) | | (2,211 | ) |
Net cash used for financing activities | | | | | | (37,204 | ) | | (37,510 | ) |
| | | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | |
Property additions | | | | | | (17,919 | ) | | (8,440 | ) |
Loan repayments from (loans to) associated companies, net | | | | | | (1,610 | ) | | 2,606 | |
Investments in lessor notes | | | | | | 11,928 | | | 10,280 | |
Contributions to nuclear decommissioning trusts | | | | | | (7,135 | ) | | (7,135 | ) |
Other | | | | | | (1,616 | ) | | 1,024 | |
Net cash used for investing activities | | | | | | (16,352 | ) | | (1,665 | ) |
| | | | | | | | | | |
Net change in cash and cash equivalents | | | | | | -- | | | (2,221 | ) |
Cash and cash equivalents at beginning of period | | | | | | 15 | | | 2,237 | |
Cash and cash equivalents at end of period | | | | | $ | 15 | | $ | 16 | |
| | | | | | | | | | |
| | | | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integralpart of these statements. | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
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 March 31,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 March 31,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
May 3,November 1, 2005
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 applicableon 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 quarternine months of 2005 decreased to a loss of $2$44 million from earnings of $5$47 million in the first quarternine months of 2004. ThisThe 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 $6$11 million, or 2.7%3.8%, in the firstthird quarter of 2005 fromcompared to the same periodthird quarter of 2004. Higher revenues in the third quarter of 2005 resulted principally from increased retail generation sales revenues of $10 million (industrial - $9$13 million and commercial - - $1 million) and wholesaledistribution revenues of $2 million, partially offset by a decrease in wholesales sales (primarily to FES) of $4 million partially offset byand an increase in shopping incentive credits of $1 million. Retail generation revenues increased as a $7result of increased KWH sales (residential - $1 million, decrease in distribution revenues.
Thecommercial - $1 million and industrial generation revenue increase was- $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 higher unit prices and a 1.6% KWH sales increase. The increase in commercial sector revenues was principally due to a 6.1% KWH sales increase. Residential retailwarmer weather which increased air-conditioning loads. Additionally, generation revenues were nearly unchanged for the first quarter of 2005 as compared to last year due to higher unit prices offsetting the effect of a 4.5% KWH sales decrease. The increased commercial volume sales partially reflected the effect of lower customer shopping. Generation services provided to commercial customers by alternative suppliers as a percent of total commercial sales deliveriesdelivered in TE's franchiseTE’s service area decreased by nearly one2.1 percentage point. The levelpoints compared with the third quarter of shopping in the industrial sector was relatively unchanged. The residential sales decrease resulted from an2004. Industrial revenues increased as a result of higher unit prices and a 4.2% increase in residential shopping of 1.7 percentage points. Higher wholesale revenues reflected the effect of increased nuclear generation available for sale to FES.KWH sales.
Revenues from distribution throughput decreasedincreased by $7$2 million in the firstthird 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 and residential revenues ($7 million and $122 million), principally due to lower composite unit prices. The impact of lower residential KWH sales contributed to the decrease while higher industrial sales partially offset the lower industrial sector unit prices. These revenue decreases were partially offset by a $1increases in residential and commercial revenues ($15 million commercial revenue increase that resultedand $6 million, respectively). The impact from a 4.2%lower industrial unit prices more than offset the higher KWH sales volume increase partially offset by lower composite unit prices.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 $0.5$1 million forfrom additional credits in the third quarter and $3 million in the first quarternine months of 2005 compared with the same periodperiods 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).
Changes in electric generationKWH sales and distribution deliveriesby customer class in the first quarter ofthree months and nine months ended September 30, 2005 from the first quartercorresponding periods of 2004, are summarized in the following table:
Changes in KWH Sales
| | | |
Increase (Decrease)
| | | |
Electric Generation: | | | |
Retail | | | 1.2 | % |
Wholesale | | | 18.5 | % |
Total Electric Generation Sales
| | | 9.2
| %
|
Distribution Deliveries: | | | | |
Residential | | | (1.7 | )% |
Commercial | | | 4.2 | % |
Industrial | | | 2.0 | % |
Total Distribution Deliveries
| | | 1.7
| %
|
| | 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 by $12$46 million in the first quarternine months of 2005 from the same quarter ofperiods 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) | | | (In millions) | |
| | | | |
Fuel costs | | $ | 2 | | | $ | 3 | | $ | 6 | |
Purchased power costs | | | (2 | ) | | | (7 | ) | | (11 | ) |
Nuclear operating costs | | | 17 | | | | (4 | ) | | 22 | |
Other operating costs | | | (2 | ) | | | 4 | | 3 | |
Provision for depreciation | | | 1 | | | | 4 | | 6 | |
Amortization of regulatory assets | | | 1 | | | | (1 | ) | | 6 | |
Deferral of new regulatory assets | | | (2 | ) | | | (7 | ) | | (12 | ) |
General taxes | | | | (1 | ) | | 1 | |
Income taxes | | | (3 | ) | | | 8 | | | 25 | |
Net increase in operating expenses and taxes | | $ | 12 | | |
Net increase (decrease) in operating expenses and taxes | | | $ | (1 | ) | $ | 46 | |
| | | | | | | |
Higher fuel costs in the third quarter and first threenine months of 2005, compared with the same periodperiods of 2004, resulted principallyprimarily from increased fossilfossil-fired generation from the Mansfield Plant, up 5.7% and nuclear generation — up 28.1% and 29.8%, respectively. Lower purchased7.1% during the respective periods. Purchased power costs reflectdecreased in both periods due to lower unit costs and reduced KWH purchased, partially offset by increased unit costs. Increased nuclearpurchases. Nuclear operating costs decreased in the firstthird quarter of 2005 compared toprimarily from lower employee benefit costs and operating expenses for the first quarter of 2004 werenuclear generating units. Nuclear operating costs increased in the nine-month period due to a scheduled refueling outage (including an unplanned extension) at the Perry nuclear plant andPlant, a mid-cycle inspection outage at the Davis-Besse nuclear plant inPlant 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 quarternine months of 2004. Other operating costs decreased dueincreased in partboth 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 benefitbenefits costs.
Depreciation charges increased by $1$4 million in the third quarter and $6 million in first threenine months of 2005 compared to the same periodperiods of 2004 primarily due to an increase in depreciable 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. Higherplants (See Note 3). Regulatory asset amortization increased in the first nine months of regulatory assets reflects2005 due to the increased amortization of transition costs. Increases in deferralscosts being recovered under the RSP. Deferrals of new regulatory assets resulted fromincreased in the third quarter and first nine months of 2005 compared to the same periods of 2004, primarily due to higher shopping incentives ($0.5 million) and deferredrelated interest on($2 million and $5 million, respectively) and the shopping incentivesdeferral of the PUCO-approved MISO administrative expenses and related interest ($1.5 million)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.
Other Income
Other income decreasedincreased by $8 million in the third quarter of 2005 and $3 million in the first quarternine months of 2005 compared towith the same periodperiods of 2004, primarily due to a decrease inhigher nuclear decommissioning trust realized gains, partially offset by lower interest income earned on nuclear decommissioning trust investments andassociated company notes receivable that were repaid in May 2005. Additionally, the accrualrecognition of a $1.6 million proposed 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 continuedincreased by $2 million in the third quarter of 2005 compared with the same period in 2004, primarily related to trend lower, decreasinghigher 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 $1$6 million in the first threenine months of 2005 fromcompared with the same period of 2004, reflecting redemptions and refinancing subsequent to the end of the first quarter ofrefinancings since October 1, 2004.
Capital Resources and Liquidity
TE’s cash requirements infor the remainder of 2005 for operating expenses and construction expenditures and scheduled debt maturities are expected to be met without increasingitsincreasing 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
There was no change asAs of March 31,September 30, 2005, from December 31, 2004 in TE's cash and cash equivalents of $15,000.$15,000 remained unchanged from December 31, 2004.
Cash Flows From Operating Activities
Cash provided from operating activities during the third quarter and first quarternine months of 2005, compared with the first quartercorresponding 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. | | |
| | Three Months Ended March 31, | |
Operating Cash Flows | | 2005 | | 2004 | |
| | (in millions) | |
| | | | | |
Cash earnings(1) | | $ | 28 | | $ | 46 | |
Working capital and other | | | 26 | | | (9 | ) |
Total Cash Flows from Operating Activities | | $ | 54 | | $ | 37 | |
(1)Cash earnings is a non-GAAP measure (see reconciliation below).
Cash earnings, (inas disclosed in the table above)above, are not a measure of performance calculated in accordance with GAAP.TEGAAP. 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.
| | | Three Months Ended | | Nine Months Ended | |
| | Three Months Ended March 31, | | | September 30, | | September 30, | |
Reconciliation of Cash Earnings | | 2005 | | 2004 | | | 2005 | | 2004 | | 2005 | | 2004 | |
| | (in millions) | | | (In millions) | |
| | | | | | | | | | | | | | |
Net Income (GAAP) | | $ | -- | | $ | 8 | | |
Non-Cash Charges (Credits): | | | | | | | | |
Net income (GAAP) | | | $ | 42 | | $ | 24 | | $ | 50 | | $ | 54 | |
Non-cash charges (credits): | | | | | | | | | | | | |
Provision for depreciation | | | 15 | | | 14 | | | | 19 | | 15 | | | 49 | | 43 | |
Amortization of regulatory assets | | | 35 | | | 34 | | | | 40 | | 41 | | | 108 | | 102 | |
Deferral of new regulatory assets | | | | (20 | ) | | (12 | ) | | (42 | ) | | (30 | ) |
Nuclear fuel and capital lease amortization | | | 5 | | | 6 | | | | 6 | | 7 | | | 14 | | 18 | |
Deferral of new regulatory assets | | | (9 | ) | | (7 | ) | |
Deferred operating lease costs, net | | | (15 | ) | | (8 | ) | |
Accrued retirement benefits obligation | | | 1 | | | 2 | | |
Accrued compensation | | | (2 | ) | | (1 | ) | |
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 | | | (2 | ) | | (2 | ) | | | (13 | ) | | (8 | ) | | (5 | ) | | (14 | ) |
Accrued retirement benefits obligations | | | | 2 | | 1 | | | 4 | | 5 | |
Accrued compensation, net | | | | - | | | (1 | ) | | (1 | ) | | 1 | |
Cash earnings (Non-GAAP) | | $ | 28 | | $ | 46 | | | $ | 84 | | $ | 77 | | $ | 140 | | $ | 152 | |
| | | | | | | | | | | | |
Net cash provided from operating activities increaseddecreased by $17$40 million in the firstthird quarter of 2005 from the firstthird quarter of 2004 as a result of a $35$55 million increase indecrease from working capital, partially offset by a $18$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“Results of Operations".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, and accounts payable.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 $306,000$48 million and increased by $1 million in the third quarter and first quarternine months of 2005, respectively, as compared to the same periodperiods of 2004, reflecting a change2004. 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 $137$53 million of cash and temporary investments (which included short-term notes receivable from associated companies) and $395$378 million of short-term indebtedness as of March 31,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 March 31,October 24, 2005, TE had the capability to issue $907 million$1.0 billion of additional FMB on the basis of property additions and retired bonds under the terms of its mortgage indenture.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 $475 million$1.15 billion of preferred stock (assuming no additional debt was issuedissued) as of March 31, 2005).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 firstthird quarter of 2005 was 2.66%3.50%.
TE’s access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of FirstEnergy. The ratings outlook on all securities is stable.
On March 18, 2005, S&P stated that FirstEnergy’s Sammis NSR settlement was a very favorable step for FirstEnergy, although it would not immediately affect FirstEnergy’s ratings or outlook. S&P noted that it continues to monitor the refueling outage at the Perry nuclear plant, which includes a detailed inspection by the NRC, and that if FirstEnergy should exit the outage without significant negative findings or delays the ratings outlook would be revised to positive.
On April 20,July 18, 2005, Beaver County Industrial Development Authority pollution control bonds aggregating $45 millionMoody’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 refunded. The new bonds were issued in a Dutch Auction interest rate mode, insured with municipal bond insurance and secured by FMB.also noted as strengths.
Cash Flows From Investing Activities
Net cash used for investing activities increased by $15$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 quarternine months of 2005, from the same period of 2004. This increase wasThese increases were primarily due to changes from loan activity with associated companies during the periods, partially offset by increased property additions and increased loans to associated companies, partially offset byin the reduction in lessor note investments.nine-month period.
In the last quarter of 2005, TE’s capital spending for the last three quarters of 2005 is expected to be about $46 million (excluding $1 million for nuclear fuel).$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, (excluding nuclear fuel) of which approximately $56$64 million applies to 2005. Investments for additional
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 fuel duringand 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 2005-2007 periodplants that are estimatedcurrently subject to total approximately $54 million,sale and leaseback arrangements with non-affiliates.
On October 24, 2005, TE completed the transfer of which about $8 million appliesnon-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. DuringConsummation of the same periods, TE’s nuclear fuel investmentstransfer remains subject to necessary regulatory approvals.
These transactions are expectedbeing 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 reduced by approximately $64 millionseparated from the regulated delivery business of those companies through transfer to a separate corporate entity. FENOC currently operates and $20 million, respectively, asmaintains the nuclear fuel is consumed.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 March 31,September 30, 2005, the present value of these operating lease commitments, net of trust investments, totaled $566$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 subsequently transfers the receivables to a trust (a“qualified special purpose entity” under SFAS 140) underfinancing structure was renewed and restructured from an asset-backed securitization agreement. This arrangement provided $48 million of off-balance sheet financingtransaction to an on-balance sheet transaction. Under the new structure, any borrowings under the facility appear on the balance sheet as of March 31, 2005.short-term debt.
Equity Price Risk
Included in TE’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $194$217 million and $188 million as of March 31,September 30, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $19$22 million reduction in fair value as of March 31,September 30, 2005. Changes in the fair value of these investments are recorded onin OCI unless recognized as a result of sales or recognized as regulatory assets or liabilities.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. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties.
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, 2008.2008 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.
TE's revised Rate Stabilization Plan extends currentOn 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 pricesservice 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 ensuring adequate generation supply at stabilized prices,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 continues TE's support of energy efficiencythe 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 economic development efforts. Other key componentsset 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 revised Rate Stabilization Plan include the following:RCP include:
· | extension Maintain the existing level of the amortization periodbase distribution rates through December 31, 2008 for transition costs being recovered through the RTC from mid-2007 to as late as mid-2008;TE; |
· | deferral Defer and capitalize certain distribution costs to be incurred by all of interest costs on the accumulated customer shopping incentives as new regulatory assets; andOhio Companies during the period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the three years; |
· | ability 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 request increases in generation charges during 2006 through 2008, under certain limited conditions,$45 million for increases inTE 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 taxes.$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. |
On December 9, 2004,Under provisions of the PUCO rejectedRSP, the auction price results from a required competitive bid process and issued an entry stating that the pricing under the approved revised Rate Stabilization Plan will take effect on January 1, 2006. The PUCO may require TE to undertake, no more often than annually, a similar 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 Rate Stabilization PlanRSP pricing, but notwith no accounting impacts to the related approved accounting,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 an application with the PUCO seeking tariff adjustmentstwo applications related to recover increasesthe recovery of approximately $0.1 million in 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 alsoanticipates 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 anwith 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 forseeks authority to defer costs associated with MISO Day 1, MISO Day 2, congestion fees, FERC assessment fees,transmission and ancillary service related costs incurred during the ATSI rate increase, as applicable,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 March 31,September 30, 2005 and December 31, 2004, were $349$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 $98$122 million as of March 31,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. Recovery ofSee Note 14 “Regulatory Matters - Ohio” for the new regulatory assets will begin at that time andestimated net amortization of regulatory transition costs and deferred shopping incentive balances under the regulatory assets for each accounting period will be equal to the surcharge revenue recognized during that period.proposed RCP and current RSP.
See Note 1314 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 determineestimate 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.
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 will requireprovides 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-fuelfossil-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 in two phases from coal-fired power plants.plants in two phases. Initially, mercury emissions will declinebe 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. The futureHowever, 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 greenhouse gasesGHG 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 gasGHG 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.
FirstEnergy plans to issue a report that will disclose the Companies’ environmental activities, including their plans to respond to environmental requirements. FirstEnergy expects to complete the report by December 1, 2005 and will post the report on its website,www.firstenergycorp.com.
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 March 31,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 CurrentOther Noncurrent Liabilities are accrued liabilities aggregating approximately $0.2 million as of March 31,September 30, 2005. TE accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably determine 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.
See Note 12(B)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 TE's normal business operations pending against TE and its subsidiaries. The most significantother 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 concluded,concludes, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area.Specifically,area. Specifically, the final report concludes,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“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. As manyFirstEnergy also is proceeding with the implementation of these initiatives alreadythe 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 process,new, or material upgrades, to existing equipment, and therefore FirstEnergy doeshas not believeaccrued a liability as of September 30, 2005 for any expenditures in excess of those actually incurred through that any incremental expenses associated with additional initiatives completed in 2004 had a material effect on its continuing operations or financial results.date. FirstEnergy notes, however, that theFERC 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. FirstEnergy has not accrued a liability asFinally, 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 March 31, 2005 forcontrol room operators, before determining the next steps, if any, expenditures in excess of those actually incurred through that date.the proceeding.
Three substantially similar actions were filed in various Ohio State courts by plaintiffs seekingFirstEnergy companies also are defending six separate complaint cases before the PUCO relating to represent customers who allegedly suffered damages as a result of the August 14, 2003 power outages. All threeoutage. Two such cases were originally filed in Ohio State courts but subsequently dismissed for lack of jurisdiction. Onesubject matter jurisdiction and further appeals were unsuccessful. In both such cases the individual complainants—three in one case was refiled on January 12, 2004 atand four in the PUCO.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 twopending PUCO complaint cases, three were appealed. One case was dismissed and no further appeal was sought.filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In the remainingeach such case, the Courtcarriers 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 Appealspower on March 31, 2005 affirmedAugust 14, 2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy company. The fourth case involves the trial court’s decision dismissing the case. It is not yet known whether further appeal will be sought.claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. In addition to the one case that was refiled at the PUCO,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 filed aFirstEnergy's motion to dismiss with 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 October 22, 2004.or about December 1, 2005. No timetable for a decision on the motion to dismiss has been established by the Court. No damage estimate has been provided and thusof potential liability has not been determined.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, and results of operations.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 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. Under the NRC’s letter, FENOC has ninety daysTE accrued $1.0 million for a potential fine prior to respond to this NOV. TE has2005 and accrued the remaining liability for its share of the proposed fine of $1.6$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 theevents surrounding Davis-Besse, head degradation, it could have a material adverse effect on FirstEnergy's or any of its subsidiaries' financial condition, and results of operations.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 pastpreceding two years.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. 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 forummeeting 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 althougheven though it remained under the heightened NRC oversight since August 2004.oversight. During the public forummeeting 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.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 second 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 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, and results of operations.operations and cash flows.
See Note 12(C)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 “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”143”
On March 30, 2005, the FASB issued this interpretationFIN 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 interpretationInterpretation is effective no later thanfor TE in the endfourth quarter of fiscal years ending after December 15, 2005. FirstEnergyTE is currently evaluating the effect this standardInterpretation 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.
| 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.
EITF IssueSFAS 151, “Inventory Costs - an amendment of ARB No. 03-1,43, 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 March 2004,September 2005, the EITF reached a consensus on the application guidance for Issue 03-1.FASB finalized and renamed EITF 03-1 providesand 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 model for determiningSecurity Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when investments in certain debt and equity securities are consideredthe impairment is deemed other than temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair valuetemporary, even if a decision to sell has not been made, and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to(3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after JuneSeptember 15, 2004, were delayed by2005. The FASB expects to issue this FSP in the issuancefourth 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 EITF 03-1-1 in September 2004. During the period of delay, FirstEnergy will continue to evaluateand any impact on its investments as required by existing authoritative guidance.investments.
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. | | |
| | | | | | | | | | | | | |
PENNSYLVANIA POWER COMPANY | |
| | | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | | |
| | | | Three Months Ended | |
| | | | March 31, | |
| | | | | | | |
| | | | 2005 | | 2004 | |
| | | | | | | |
STATEMENTS OF INCOME | | | | (In thousands) | |
| | | | | | | |
OPERATING REVENUES | | | | | $ | 134,484 | | $ | 142,623 | |
| | | | | | | | | | |
OPERATING EXPENSES AND TAXES: | | | | | | | | | | |
Fuel | | | | | | 5,620 | | | 6,206 | |
Purchased power | | | | | | 46,980 | | | 48,508 | |
Nuclear operating costs | | | | | | 19,948 | | | 18,623 | |
Other operating costs | | | | | | 12,768 | | | 13,685 | |
Provision for depreciation | | | | | | 3,694 | | | 3,362 | |
Amortization of regulatory assets | | | | | | 9,882 | | | 10,076 | |
General taxes | | | | | | 6,472 | | | 6,634 | |
Income taxes | | | | | | 12,421 | | | 15,038 | |
Total operating expenses and taxes | | | | | | 117,785 | | | 122,132 | |
| | | | | | | | | | |
OPERATING INCOME | | | | | | 16,699 | | | 20,491 | |
| | | | | | | | | | |
OTHER INCOME (EXPENSE) (net of income taxes) | | | | | | (745 | ) | | 982 | |
| | | | | | | | | | |
NET INTEREST CHARGES: | | | | | | | | | | |
Interest expense | | | | | | 2,319 | | | 2,725 | |
Allowance for borrowed funds used during construction | | | | | | (1,367 | ) | | (922 | ) |
Net interest charges | | | | | | 952 | | | 1,803 | |
| | | | | | | | | | |
NET INCOME | | | | | | 15,002 | | | 19,670 | |
| | | | | | | | | | |
PREFERRED STOCK DIVIDEND REQUIREMENTS | | | | | | 640 | | | 640 | |
| | | | | | | | | | |
EARNINGS ON COMMON STOCK | | | | | $ | 14,362 | | $ | 19,030 | |
| | | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | |
| | | | | | | | | | |
NET INCOME | | | | | $ | 15,002 | | $ | 19,670 | |
| | | | | | | | | | |
OTHER COMPREHENSIVE INCOME | | | | | | -- | | | -- | |
| | | | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | | | | $ | 15,002 | | $ | 19,670 | |
| | | | | | | | | | |
| | | | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral partof these statements. | |
| | | | | | | | | | |
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. | | |
| | | | | | | |
PENNSYLVANIA POWER COMPANY | |
| | | | | | | |
CONSOLIDATED BALANCE SHEETS | |
(Unaudited) | |
| | | | March 31, | | December 31, | |
| | | | 2005 | | 2004 | |
| | | | (In thousands) | |
ASSETS | | | | | | | |
UTILITY PLANT: | | | | | | | |
In service | | | | | $ | 873,780 | | $ | 866,303 | |
Less - Accumulated provision for depreciation | | | | | | 364,354 | | | 356,020 | |
| | | | | | 509,426 | | | 510,283 | |
Construction work in progress- | | | | | | | | | | |
Electric plant | | | | | | 121,145 | | | 104,366 | |
Nuclear fuel | | | | | | 7,647 | | | 3,362 | |
| | | | | | 128,792 | | | 107,728 | |
| | | | | | 638,218 | | | 618,011 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | | |
Nuclear plant decommissioning trusts | | | | | | 142,317 | | | 143,062 | |
Long-term notes receivable from associated companies | | | | | | 32,890 | | | 32,985 | |
Other | | | | | | 530 | | | 722 | |
| | | | | | 175,737 | | | 176,769 | |
CURRENT ASSETS: | | | | | | | | | | |
Cash and cash equivalents | | | | | | 38 | | | 38 | |
Notes receivable from associated companies | | | | | | 545 | | | 431 | |
Receivables- | | | | | | | | | | |
Customers (less accumulated provisions of $940,000 and $888,000, | | | | | | | | | | |
respectively, for uncollectible accounts) | | | | | | 42,984 | | | 44,282 | |
Associated companies | | | | | | 13,019 | | | 23,016 | |
Other | | | | | | 1,059 | | | 1,656 | |
Materials and supplies, at average cost | | | | | | 37,705 | | | 37,923 | |
Prepayments and other | | | | | | 22,405 | | | 8,924 | |
| | | | | | 117,755 | | | 116,270 | |
| | | | | | | | | | |
DEFERRED CHARGES | | | | | | 9,921 | | | 10,106 | |
| | | | | $ | 941,631 | | $ | 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 | | | | | | 64,690 | | | 64,690 | |
Accumulated other comprehensive loss | | | | | | (13,706 | ) | | (13,706 | ) |
Retained earnings | | | | | | 94,057 | | | 87,695 | |
Total common stockholder's equity | | | | | | 333,741 | | | 327,379 | |
Preferred stock | | | | | | 39,105 | | | 39,105 | |
Long-term debt and other long-term obligations | | | | | | 121,889 | | | 133,887 | |
| | | | | | 494,735 | | | 500,371 | |
CURRENT LIABILITIES: | | | | | | | | | | |
Currently payable long-term debt | | | | | | 38,524 | | | 26,524 | |
Accounts payable- | | | | | | | | | | |
Associated companies | | | | | | 43,569 | | | 46,368 | |
Other | | | | | | 1,345 | | | 1,436 | |
Notes payable to associated companies | | | | | | 10,644 | | | 11,852 | |
Accrued taxes | | | | | | 25,475 | | | 14,055 | |
Accrued interest | | | | | | 1,614 | | | 1,872 | |
Other | | | | | | 9,156 | | | 8,802 | |
| | | | | | 130,327 | | | 110,909 | |
NONCURRENT LIABILITIES: | | | | | | | | | | |
Accumulated deferred income taxes | | | | | | 89,060 | | | 93,418 | |
Accumulated deferred investment tax credits | | | | | | 3,150 | | | 3,222 | |
Asset retirement obligation | | | | | | 140,560 | | | 138,284 | |
Retirement benefits | | | | | | 50,116 | | | 49,834 | |
Regulatory liabilities | | | | | | 26,523 | | | 18,454 | |
Other | | | | | | 7,160 | | | 6,664 | |
| | | | | | 316,569 | | | 309,876 | |
COMMITMENTS AND CONTINGENCIES (Note 12) | | | | | | | | | | |
| | | | | $ | 941,631 | | $ | 921,156 | |
| | | | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral part of these balance sheets. | |
| | | | | | | | | | |
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. | | |
| | | | | | | | | | | | | |
PENNSYLVANIA POWER COMPANY | |
| | | | | | | |
CONSOLIDATED STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | | |
| | | | Three Months Ended | |
| | | | March 31, | |
| | | | | | | |
| | | | 2005 | | 2004 | |
| | | | | | | |
| | | | (In thousands) | |
| | | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | |
Net income | | | | | $ | 15,002 | | $ | 19,670 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | | | |
Provision for depreciation | | | | | | 3,694 | | | 3,362 | |
Amortization of regulatory assets | | | | | | 9,882 | | | 10,076 | |
Nuclear fuel and other amortization | | | | | | 4,140 | | | 4,565 | |
Deferred income taxes and investment tax credits, net | | | | | | (2,311 | ) | | (1,806 | ) |
Decrease (Increase) in operating assets- | | | | | | | | | | |
Receivables | | | | | | 11,892 | | | (214 | ) |
Materials and supplies | | | | | | 218 | | | (1,075 | ) |
Prepayments and other current assets | | | | | | (13,481 | ) | | (13,333 | ) |
Increase (Decrease) in operating liabilities- | | | | | | | | | | |
Accounts payable | | | | | | (2,890 | ) | | 3,740 | |
Accrued taxes | | | | | | 11,420 | | | 8,809 | |
Accrued interest | | | | | | (258 | ) | | (1,956 | ) |
Other | | | | | | 778 | | | 2,857 | |
Net cash provided from operating activities | | | | | | 38,086 | | | 34,695 | |
| | | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | |
New Financing- | | | | | | | | | | |
Short-term borrowings, net | | | | | | -- | | | 29,084 | |
Redemptions and Repayments- | | | | | | | | | | |
Long-term debt | | | | | | -- | | | (42,302 | ) |
Short-term borrowings, net | | | | | | (1,208 | ) | | -- | |
Dividend Payments- | | | | | | | | | | |
Common stock | | | | | | (8,000 | ) | | (8,000 | ) |
Preferred stock | | | | | | (640 | ) | | (640 | ) |
Net cash used for financing activities | | | | | | (9,848 | ) | | (21,858 | ) |
| | | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | |
Property additions | | | | | | (28,522 | ) | | (13,998 | ) |
Contributions to nuclear decommissioning trusts | | | | | | (399 | ) | | (399 | ) |
Loans to associated companies | | | | | | (19 | ) | | (116 | ) |
Other | | | | | | 702 | | | 1,676 | |
Net cash used for investing activities | | | | | | (28,238 | ) | | (12,837 | ) |
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Net change in cash and cash equivalents | | | | | | -- | | | -- | |
Cash and cash equivalents at beginning of period | | | | | | 38 | | | 40 | |
Cash and cash equivalents at end of period | | | | | $ | 38 | | $ | 40 | |
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The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integralpart of these statements. | |
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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 March 31,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 March 31,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
May 3,November 1, 2005
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 quarternine months of 2005 decreased to $14$52 million from $19$56 million infor the first quartersame period of 2004. The lower earnings resulted primarily from decreaseda decrease in operating revenues and other income, partially offset by lower operating expenses and taxes and lower net interest charges.
Operating revenues decreasedincreased by $8$2 million, or 6%1.5%, in the firstthird quarter of 2005 as compared with the firstthird quarter of 2004. The lowerHigher revenues in the third quarter of 2005 primarily resulted from increased retail generation sales revenues of $6 million and a $9$2 million increase in rental revenues, partially offset by a $6 million decrease in wholesale sales to FES due to less nuclear generation available for sale. Higher retailFES. Retail generation sales revenues of $3 million resulted from higher commercial and industrial sales of $1 million and $2 million, respectively,increased as a result of higher composite unit prices and increased KWH sales. The increased sales reflected an improvingto residential (7.6%) and commercial (4.0%) customers, due to warmer weather in Penn's service area, economy including higherand a 19.8% KWH sales increase to industrial customers, primarily within the steel industry. These increases were partially offset by a $0.2 million residential revenues decrease reflecting lower sales volume (0.8%) and unit prices.sector.
A $2 million reductionRevenues from distribution deliveries in distribution throughput revenues was primarily due tothe third quarter of 2005 increased slightly from the third quarter of 2004, as lower unit prices partially offset by highera 10.2% increase in KWH deliveries to commercial and industrial customers.sales. The lower unit prices arewere primarily attributable to changes in Penn's CTC rate schedules in April 20042005 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 electric generation and distribution deliverieskilowatt-hour sales by customer class in the first quarter ofthree months and nine months ended September 30, 2005 from the same quarter incorresponding periods of 2004 are summarized in the following table:
Changes in KWH Sales
| | | |
Increase (Decrease)
| | | |
Electric Generation: | | | |
Retail
| | | 0.7 | % |
Wholesale
| | | (7.9 | )% |
Total Electric Generation Sales | | | (4.3 | )% |
| | | | |
Distribution Deliveries: | | | | |
Residential
| | | (0.8 | )% |
Commercial
| | | 2.1 | % |
Industrial
| | | 1.3 | % |
Total Distribution Deliveries | | | 0.7 | % |
| | 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 | % |
| | | | | | | |
Operating Expenses and Taxes
Total operating expenses and taxes decreased by $4$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 | ) |
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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 from the first quarter of 2004.Lower fuel costs in the first quarter of 2005, compared with the same quarter of 2004, resulted from reduced nuclear generation. Lower purchased power costs in the first three months of 2005 reflected decreased KWH purchases and higher unit costs. Nuclear operating costs increased duerelated to the Perry scheduled refueling outage (including an unplanned extension) in the first quarter of 2005 and the absence of nuclear refueling outages in the same period last year. Other operating expenses decreased primarily because of lower employee benefit costs.
Other Income (Expense)
Other income decreased $2 million in the first quarter of 2005, compared with the first quarter of 2004, due to the first quarter 2005 accruals for a potential $0.7 million civil penalty and $0.8 million for potential contributions toward environmentally beneficial projects related to theW. H. Sammis Plant settlement (see Outlook - Environmental Matters) and the absence of a 2004 $1 million gain from the sale of an investment..
Net Interest Charges
Net interest charges continued to trend lower, decreasingdecreased by $851,000$1 million in the first quarter ofnine months ended September 30, 2005 from the samecorresponding period last year, reflecting redemptions of $22$40 million total principal amount of debt securities since the first quarter ofOctober 1, 2004.
Capital Resources and Liquidity
Penn’s cash requirements in 2005and thereafterforfor operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be metwithmet with a combination of cash from operations and funds from the capital markets. Available borrowingBorrowing capacity under credit facilities will be usedis available to manage working capital requirements.
Changes in Cash Position
As of September 30, 2005, Penn had $38,000$24,000 of cash and cash equivalents, compared with $38,000 as of March 31, 2005 and 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 first quarter ofthree months and nine months ended September 30, 2005, compared with the corresponding 2004 period,periods, was as follows:
| | Three Months Ended | |
| | March 31, | |
Operating Cash Flows | | 2005 | | 2004 | |
| | (In millions) | |
| | | | | |
Cash earnings(1) | | $ | 30 | | $ | 38 | |
Working capital and other | | | 8 | | | (3 | ) |
| | | | | | | |
Total Cash Flows from Operating Activities | | $ | 38 | | $ | 35 | |
(1)Cash earnings is a non-GAAP measure (see reconciliation below). | | 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 | |
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(1) Cash earnings is a non-GAAP measure (see reconciliation below). (2) Pension trust contribution net of $5 million of income tax benefits. | | | | | | | |
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 | | | Three Months Ended | | Nine Months Ended | |
| | March 31, | | | September 30, | | September 30, | |
Reconciliation of Cash Earnings | | 2005 | | 2004 | | | 2005 | | 2004 | | 2005 | | 2004 | |
| | (In millions) | | | (In millions) | |
| | | | | | | | | | | | | | |
Net Income (GAAP) | | $ | 15 | | $ | 20 | | |
Non-Cash Charges (Credits): | | | | | | | | |
Net income (GAAP) | | | $ | 23 | | $ | 20 | | $ | 54 | | $ | 58 | |
Non-cash charges (credits): | | | | | | | | | | | | |
Provision for depreciation | | | 3 | | | 3 | | | | 4 | | 4 | | | 11 | | 10 | |
Amortization of regulatory assets | | | 10 | | | 10 | | | | 10 | | 10 | | | 29 | | 30 | |
Nuclear fuel and other amortization | | | 4 | | | 5 | | | | 5 | | 4 | | | 13 | | 14 | |
Deferred income taxes and investment tax credits, net | | | (2 | ) | | (2 | ) | | | (3 | ) | | (5 | ) | | (8 | ) | | (8 | ) |
Other non-cash expenses | | | -- | | | 2 | | |
Other non-cash items | | | | 1 | | | 1 | | | 2 | | | 4 | |
Cash earnings (Non-GAAP) | | $ | 30 | | $ | 38 | | | $ | 40 | | $ | 34 | | $ | 101 | | $ | 108 | |
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The $8$6 million increase in cash earnings in the third quarter of 2005 and the $7 million decrease in cash earnings isfor the first nine months of 2005, as compared to the corresponding periods of 2004, are described under“Results “Results of OperationsOperations.”. The $11$10 million change in working capital changeand other in the three-month period was primarily due to changes of $12 million in receivables and $3 million in accrued taxes, partially offset by a $7$49 million change in accounts payable.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 $10$11 million in the firstthird quarter of 2005, compared with $22$8 million in the firstsame 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. This2004, 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 quarternine months of 2005, compared withoffset 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 corresponding 2004 period.date of redemption. The total par value of the preferred stock redeemed was $37.8 million.
Penn had $583,000$590,000 of cash and temporary investments (which included short-term notes receivable from associated companies) and $11$35 million of short-term indebtedness with associated companies as of March 31,September 30, 2005. Penn has authorization from the SEC to incur short-term debt up to its charter limit of $49 million (including the utility money pool).$51 million. As of October 24, 2005, Penn had the capability to issue $532approximately $520 million of additional FMB on the basis of property additions and retired bonds asfollowing the recently completed intra-system transfer of March 31, 2005.fossil generating plants (See Note 17) . Based upon applicable earnings coverage tests, Penn could issue up to $367$383 million of preferred stock (assuming no additional debt was issued) as of March 31,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, as well as proceeds available from bank borrowings. Available bank borrowings include $1.75 billion from FirstEnergy’s and OE’s revolving credit facilities.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 firstthird quarter of 2005 was 2.66%3.50%.
In addition, Penn hasPower 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 through its subsidiary. Aswas not drawn as of March 31,September 30, 2005. On July 15, 2005, the facility was undrawn; it expiresrenewed until June 30, 2005 and29, 2006. The annual facility fee is expected to be renewed.
On May 16, 2005, Penn intends to redeem 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 to0.25% on the date of redemption.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. The ratings outlook on all securities is stable.
On MarchJuly 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 Sammis NSR settlement was a very favorable step for FirstEnergy, although it would not immediately affectrating 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 ratings or outlook. S&Pability to consistently generate free cash flow, good liquidity, and an improving financial profile were also noted that it continues to monitor the refueling outage at the Perry nuclear plant, which includes a detailed inspection by the NRC, and that if FirstEnergy should exit the outage without significant negative findings or delays the ratings outlook would be revised to positive.as strengths.
Cash Flows From Investing Activities
Net cash used in investing activities totaled $28$29 million in the firstthird quarter of 2005, compared with $13$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 quarter of 2004.period last year. The $15$18 million increase was primarily the result of higher expenditures for property additions in the 2005 period reflects an increase in property additions.and reduced loan repayments from associated companies.
DuringIn the remaining three quarterslast quarter of 2005, capital requirements for property additions are expected to be about $67$32 million. Penn also expects to contribute up to $63 million including $9 million(unfunded liability recognized as of September 30, 2005) for nuclear fuel. Penndecommissioning in connection with the generation asset transfers described below, and has additional requirements of approximately $2$0.5 million to meet sinking fund requirements for preferred stock and 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.
Penn’s Penn's capital spending for the period 2005-2007 is expected to be about $227 million, (excluding nuclear fuel) of which approximately $82$87 million applies to 2005. Investments for additional nuclear fuel during the 2005-2007 period are estimated to be approximately $64 million, of which about $13 million relates to 2005. During the same periods, Penn’s nuclear fuel investments are expected to be reduced by approximately $52 million and $17 million, respectively, as the nuclear fuel is consumed. Penn had no other material obligations as of March 31,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 $56$60 million and $57 million as of March 31,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 March 31,September 30, 2005.
Outlook
TheFirstEnergy 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.
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 industry continuesutility restructuring legislation. Consistent with the restructuring plan, Penn’s generation assets were required to transitionbe separated from the regulated delivery business through transfers to a more competitive environmentseparate corporate entity. FENOC currently operates and allmaintains 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 customers can select alternative energy suppliers. Penn 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. Penn has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new formsassets held for sale as of competition have created new uncertainties.September 30, 2005.
Regulatory Matters
Pennsylvania enacted its electric utility competition law in 1996 with the phase-in of customer choice for electric generation suppliers completed as of January 1, 2001. Penn's customer rates were restructured to itemize (unbundle) the current price of electricity into its component elements - including generation, transmission, distribution and stranded cost recovery. In the event customers obtain power from an alternative source, the generation portion of Penn’s rates is excluded from their bill and the customers receive a generation charge from the alternative supplier. The stranded cost recovery portion of rates provides for recovery of certain amounts not otherwise considered recoverable in a competitive generation market, including regulatory assets. Under the rate restructuring plan, Penn is entitled to recover $236 million of stranded costs through the CTC that began in 1999 and ends in 2006.
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 $27$48 million and $18 million as of March 31,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 1314 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 only when it concludes that it is probable that it has an obligation for such costs and can reasonably determineestimate 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 will requireprovides each affected state until 2006 to develop implementing regulations to achieve additional reductions of NOx and SO2emissions 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-fuelfossil-fired generation facilities will be subject to the caps on SO2 and NOxemissions. 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.
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 in two phases from coal-fired power plants.plants in two phases. Initially, mercury emissions will declinebe 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. The futureHowever, 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 coveringalleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which iswas owned at that time by OE and Penn. In addition, the U.S. Department of Justice (DOJ)DOJ filed eight civil complaints against various investor-owned utilities, which includedincluding 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. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. 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, subject to a thirty-day public comment period that ended on April 29, 2005 and final approvalwas approved by the District Court Judge,on July 11, 2005, requires OE and Penn to reduce emissions from theNOx and SO2 emission at W. H. Sammis Plant and other coal-fired plants through the installation of pollution control devices requiring capitaldevices. Capital expenditures necessary to meet those requirements are currently estimated to be $1.1$1.5 billion (primarily(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 towardstoward environmentally beneficial projects, which include wind energy purchasepurchased power agreements over a 20-year term. OE and Penn also agreed to pay a civil penalty of $8.5 million, (Penn'sof which Penn's share iswas $0.7 million).million. Results for the first quarter of 2005 includeincluded 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.
FirstEnergy plansSee Note 13(B) to issuethe consolidated financial statements for further details and a report that will disclose the Companies’complete discussion of environmental activities, including their plans to respond to environmental requirements. FirstEnergy expects to complete the report by December 1, 2005 and will post the report on its web site,www.firstenergycorp.com.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 most significantother 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 concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area.Specifically,area. Specifically, the final report concludes,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“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. As manyFirstEnergy also is proceeding with the implementation of these initiatives alreadythe 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 process,new or material upgrades to existing equipment, and therefore FirstEnergy doeshas not believeaccrued a liability as of September 30, 2005 for any expenditures in excess of those actually incurred through that any incremental expenses associated with additional initiatives completed in 2004 had a material effect on its continuing operationsdate. The FERC or financial results. FirstEnergy notes, however, that theother 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. FirstEnergy has not accrued a liability asFinally, 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 March 31, 2005 forcontrol room operators, before determining the next steps, if any, expenditures in excess of those actually incurred through that date.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 filed aFirstEnergy's motion to dismiss with 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 October 22, 2004.or about December 1, 2005. No timetable for a decision on the motion to dismiss has been established by the Court. No damage estimate has been provided and thusof potential liability has not been determined.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, and results of operations.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 pastpreceding two years.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. 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 forummeeting 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 althougheven though it remained under the heightened NRC oversight since August 2004.oversight. During the public forummeeting 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.condition, results of operations and cash flows.
See Note 12(C)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 “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”143”
On March 30, 2005, the FASB issued this interpretationFIN 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 interpretationInterpretation is effective no later thanfor Penn in the endfourth quarter of fiscal years ending after December 15, 2005. FirstEnergyPenn is currently evaluating the effect this standardInterpretation 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.
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.
EITF Issue No. 03-1,FSP FAS 115-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"
In March 2004,September 2005, the EITF reached a consensus on the application guidance for Issue 03-1.FASB finalized and renamed EITF 03-1 providesand 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 model for determiningSecurity Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when investments in certain debt and equity securities are consideredthe impairment is deemed other than temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair valuetemporary, even if a decision to sell has not been made, and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to(3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after JuneSeptember 15, 2004, were delayed by2005. The FASB expects to issue this FSP in the issuancefourth 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 EITF 03-1-1 in September 2004. During the period of delay, FirstEnergy will continue to evaluateand any impact on its investments as required by existing authoritative guidance.investments.
JERSEY CENTRAL POWER & LIGHT COMPANY | |
| | | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | | |
| | | | Three Months Ended | |
| | | | March 31, | |
| | | | | | | |
| | | | 2005 | | 2004 | |
| | | | | | | |
STATEMENTS OF INCOME | | | | (In thousands) | |
| | | | | | | |
OPERATING REVENUES | | | | | $ | 529,092 | | $ | 498,124 | |
| | | | | | | | | | |
OPERATING EXPENSES AND TAXES: | | | | | | | | | | |
Purchased power | | | | | | 277,132 | | | 270,733 | |
Other operating costs | | | | | | 101,067 | | | 86,816 | |
Provision for depreciation | | | | | | 20,206 | | | 19,075 | |
Amortization of regulatory assets | | | | | | 68,374 | | | 64,485 | |
General taxes | | | | | | 15,440 | | | 15,932 | |
Income taxes | | | | | | 12,483 | | | 9,113 | |
Total operating expenses and taxes | | | | | | 494,702 | | | 466,154 | |
| | | | | | | | | | |
OPERATING INCOME | | | | | | 34,390 | | | 31,970 | |
| | | | | | | | | | |
OTHER INCOME (net of income taxes) | | | | | | 44 | | | 1,503 | |
| | | | | | | | | | |
NET INTEREST CHARGES: | | | | | | | | | | |
Interest on long-term debt | | | | | | 19,405 | | | 20,728 | |
Allowance for borrowed funds used during construction | | | | | | (403 | ) | | (120 | ) |
Deferred interest | | | | | | (911 | ) | | (923 | ) |
Other interest expense | | | | | | 1,824 | | | 390 | |
Net interest charges | | | | | | 19,915 | | | 20,075 | |
| | | | | | | | | | |
NET INCOME | | | | | | 14,519 | | | 13,398 | |
| | | | | | | | | | |
PREFERRED STOCK DIVIDEND REQUIREMENTS | | | | | | 125 | | | 125 | |
| | | | | | | | | | |
EARNINGS ON COMMON STOCK | | | | | $ | 14,394 | | $ | 13,273 | |
| | | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | |
| | | | | | | | | | |
NET INCOME | | | | | $ | 14,519 | | $ | 13,398 | |
| | | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | |
Unrealized gain (loss) on derivative hedges | | | | | | 69 | | | (14 | ) |
Unrealized loss on available for sale securities | | | | | | -- | | | (8 | ) |
Other comprehensive income (loss) | | | | | | 69 | | | (22 | ) |
Income tax related to other comprehensive income | | | | | | (28 | ) | | 3 | |
Other comprehensive income (loss), net of tax | | | | | | 41 | | | (19 | ) |
| | | | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | | | | $ | 14,560 | | $ | 13,379 | |
| | | | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part | |
of these statements. | | | | | | | | | | |
JERSEY CENTRAL POWER & LIGHT COMPANY | |
| | | | | | | |
CONSOLIDATED BALANCE SHEETS | |
(Unaudited) | |
| | | | March 31, | | December 31, | |
| | | | 2005 | | 2004 | |
| | | | (In thousands) | |
ASSETS | | | | | | | |
UTILITY PLANT: | | | | | | | |
In service | | | | | $ | 3,755,666 | | $ | 3,730,767 | |
Less - Accumulated provision for depreciation | | | | | | 1,395,942 | | | 1,380,775 | |
| | | | | | 2,359,724 | | | 2,349,992 | |
Construction work in progress | | | | | | 76,054 | | | 75,012 | |
| | | | | | 2,435,778 | | | 2,425,004 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | | |
Nuclear plant decommissioning trusts | | | | | | 137,142 | | | 138,205 | |
Nuclear fuel disposal trust | | | | | | 160,757 | | | 159,696 | |
Long-term notes receivable from associated companies | | | | | | 21,335 | | | 20,436 | |
Other | | | | | | 16,362 | | | 19,379 | |
| | | | | | 335,596 | | | 337,716 | |
CURRENT ASSETS: | | | | | | | | | | |
Cash and cash equivalents | | | | | | 41 | | | 162 | |
Receivables- | | | | | | | | | | |
Customers (less accumulated provisions of $3,090,000 and $3,881,000, | | | | | | | | | | |
respectively, for uncollectible accounts) | | | | | | 201,196 | | | 201,415 | |
Associated companies | | | | | | 34,961 | | | 86,531 | |
Other (less accumulated provisions of $263,000 and $162,000, | | | | | | | | | | |
respectively, for uncollectible accounts) | | | | | | 76,837 | | | 39,898 | |
Materials and supplies, at average cost | | | | | | 2,352 | | | 2,435 | |
Prepayments and other | | | | | | 22,239 | | | 31,489 | |
| | | | | | 337,626 | | | 361,930 | |
DEFERRED CHARGES: | | | | | | | | | | |
Regulatory assets | | | | | | 2,267,795 | | | 2,176,520 | |
Goodwill | | | | | | 1,983,740 | | | 1,985,036 | |
Other | | | | | | 4,568 | | | 4,978 | |
| | | | | | 4,256,103 | | | 4,166,534 | |
| | | | | $ | 7,365,103 | | $ | 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 | | | | | | 3,013,912 | | | 3,013,912 | |
Accumulated other comprehensive loss | | | | | | (55,493 | ) | | (55,534 | ) |
Retained earnings | | | | | | 37,665 | | | 43,271 | |
Total common stockholder's equity | | | | | | 3,149,797 | | | 3,155,362 | |
Preferred stock | | | | | | 12,649 | | | 12,649 | |
Long-term debt and other long-term obligations | | | | | | 1,229,210 | | | 1,238,984 | |
| | | | | | 4,391,656 | | | 4,406,995 | |
CURRENT LIABILITIES: | | | | | | | | | | |
Currently payable long-term debt | | | | | | 22,381 | | | 16,866 | |
Notes payable- | | | | | | | | | | |
Associated companies | | | | | | 204,794 | | | 248,532 | |
Accounts payable- | | | | | | | | | | |
Associated companies | | | | | | 9,248 | | | 20,605 | |
Other | | | | | | 105,699 | | | 124,733 | |
Accrued taxes | | | | | | 41,503 | | | 2,626 | |
Accrued interest | | | | | | 25,078 | | | 10,359 | |
Other | | | | | | 68,192 | | | 65,130 | |
| | | | | | 476,895 | | | 488,851 | |
NONCURRENT LIABILITIES: | | | | | | | | | | |
Power purchase contract loss liability | | | | | | 1,325,786 | | | 1,268,478 | |
Accumulated deferred income taxes | | | | | | 688,248 | | | 645,741 | |
Nuclear fuel disposal costs | | | | | | 171,014 | | | 169,884 | |
Asset retirement obligation | | | | | | 73,754 | | | 72,655 | |
Retirement benefits | | | | | | 98,307 | | | 103,036 | |
Other | | | | | | 139,443 | | | 135,544 | |
| | | | | | 2,496,552 | | | 2,395,338 | |
COMMITMENTS AND CONTINGENCIES (Note 12) | | | | | | | | | | |
| | | | | $ | 7,365,103 | | $ | 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 balance sheets. | |
| | | | | | | | | | |
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. | | |
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. | | |
| | | | | | | |
JERSEY CENTRAL POWER & LIGHT COMPANY | |
| | | | | | | |
CONSOLIDATED STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | | |
| | | | Three Months Ended | |
| | | | March 31, | |
| | | | | | | |
| | | | 2005 | | 2004 | |
| | | | | | | |
| | | | (In thousands) | |
| | | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | |
Net income | | | | | $ | 14,519 | | $ | 13,398 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | | | |
Provision for depreciation | | | | | | 20,206 | | | 19,075 | |
Amortization of regulatory assets | | | | | | 68,374 | | | 64,485 | |
Deferred costs, net | | | | | | (73,359 | ) | | (37,981 | ) |
Deferred income taxes and investment tax credits, net | | | | | | 7,169 | | | 230 | |
Accrued retirement benefit obligation | | | | | | (4,728 | ) | | (11,714 | ) |
Accrued compensation, net | | | | | | 5,413 | | | (855 | ) |
Decrease (Increase) in operating assets: | | | | | | | | | | |
Receivables | | | | | | 14,849 | | | 1,438 | |
Materials and supplies | | | | | | 82 | | | 358 | |
Prepayments and other current assets | | | | | | 9,250 | | | 24,376 | |
Increase (Decrease) in operating liabilities: | | | | | | | | | | |
Accounts payable | | | | | | (30,390 | ) | | (15,349 | ) |
Accrued taxes | | | | | | 38,877 | | | 49,480 | |
Accrued interest | | | | | | 14,719 | | | 10,778 | |
Other | | | | | | 12,321 | | | 4,323 | |
Net cash provided from operating activities | | | | | | 97,302 | | | 122,042 | |
| | | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | |
Redemptions and Repayments- | | | | | | | | | | |
Long-term debt | | | | | | (3,883 | ) | | (3,591 | ) |
Short-term borrowings, net | | | | | | (43,738 | ) | | (79,744 | ) |
Dividend Payments- | | | | | | | | | | |
Common stock | | | | | | (20,000 | ) | | (5,000 | ) |
Preferred stock | | | | | | (125 | ) | | (125 | ) |
Net cash used for financing activities | | | | | | (67,746 | ) | | (88,460 | ) |
| | | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | |
Property additions | | | | | | (28,124 | ) | | (28,212 | ) |
Loans to associated companies, net | | | | | | (898 | ) | | (1,056 | ) |
Other | | | | | | (655 | ) | | (4,303 | ) |
Net cash used for investing activities | | | | | | (29,677 | ) | | (33,571 | ) |
| | | | | | | | | | |
Net increase (decrease) in cash and cash equivalents | | | | | | (121 | ) | | 11 | |
Cash and cash equivalents at beginning of period | | | | | | 162 | | | 271 | |
Cash and cash equivalents at end of period | | | | | $ | 41 | | $ | 282 | |
| | | | | | | | | | |
| | | | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of | |
these statements. | | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
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. | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
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 March 31,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 March 31,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
May 3,November 1, 2005
JERSEY CENTRAL POWER & LIGHT COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
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 ininto 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 firstthird quarter of 2005 increased to $14$75 million from $13$52 million in 2004, principallythe 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 other operating, purchased power costs, other operating costs and regulatory asset amortization.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 $31$194 million or 6.2%27.4% in the third quarter and $270 million or 15.4% in the first quarternine months of 2005 compared with the same periods in 2004. TheIncreases in both periods were due to higher revenues primarily resulted from increases in retail electric generation, sales of $18 milliondistribution and distribution revenues of $12 million partially offset by a $4 million decline in wholesale revenues.
The higherRetail generation revenues from generationincreased 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 million14.9% and commercial - $9 million) were due to increases20.3% in sales volume (residentialthe third quarter of 2005; residential - 13.2%15.3% and commercial - 9.2%) and higher unit prices discussed below. The sales volume increase was13.4% for the first nine months of 2005) primarily due to lowerwarmer 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 12.16.9 and 3.74.6 percentage points, for residential and commercial customers, respectively. A $5respectively, in the first nine months of 2005. Industrial generation revenue increased by $4 million decrease in industrial sales reflectedthe third quarter, but declined $2 million in the first nine months of 2005 reflecting the effect of increased customer shopping which resulted in a 33.3%25.6% KWH sales decrease.increase in the third quarter and a 9.3% decline in the first nine months of 2005.
JCP&L's BGS obligation has been transferredRevenues from wholesale sales increased by $49 million in the third quarter and $42 in the first nine months of 2005 as compared to external parties as a result of an NJBPU auction process that extended the termination of JCP&L's BGS obligation through May 2005 (see Outlook - Regulatory Matters). The higher unitprevious year, principally due to increased prices resulted from the BGS auction. The increased total retail generationin 2005. KWH sales reduced energy available for saleto the wholesale sector increased in the wholesale market which resulted in lower wholesale sales revenues of $4 million (15.4% KWH sales decrease)quarter (5.5%) but declined for the first nine months (8.5%).
The increaseDistribution revenues increased by $62 million in distribution revenues in all customer sectors of $12the third quarter and $96 million in the first quarternine months of 2005, as compared to the first quartersame periods of 2004, was primarily due to increased KWH deliveries to all customer sectors and higher composite unit prices. The 3.9% commercial sector KWH sales increase was offsetprices, caused in part by minor declines in both the residential and industrial sectors.
The higher operating revenues also reflected a $2 million payment received in the first quarterJune 1, 2005 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 specified levels. This payment is credited to JCP&L’s customers, resulting in no net earnings effect.rate increase.
Changes in kilowatt-hourKWH sales by customer class in the first quarter ofthree months and nine months ended September 30, 2005 compared to the first quartersame periods of 2004 are summarized in the following table:
| | | |
Changes in Kilowatt-hour Sales
| | 2005
| |
| | | |
Increase (Decrease)
| | | |
Electric Generation: | | | |
Retail
| | | 8.4 | % |
Wholesale
| | | (15.4 | )% |
Total Electric Generation Sales
| | | 2.3
| %
|
| | | | |
Distribution Deliveries: | | | | |
Residential
| | | (0.5 | )% |
Commercial
| | | 3.9 | % |
Industrial
| | | (0.1 | )% |
Total Distribution Deliveries
| | | 1.4
| %
|
| | 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 | % |
| | | | | | | |
Operating Expenses and Taxes
Total operating expenses and taxes increased $29by $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 prior year. Purchased power costs increased $6same 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 quarternine months of 2005, comparedreflecting the NJBPU’s (see Regulatory Matters) approval for JCP&L to 2004. The higher purchased power costs reflected higher KWH purchased due to increased retail generation sales. The increasedefer $28 million of $14 million in other operating costs in the first quarter of 2005 compared to 2004 reflected in part the effects of a JCP&L labor strike. The JCP&L labor strike, which affected approximately 1,300 employees, began on December 8, 2004 and lasted until March 15, 2005.
previously incurred reliability expenses. Amortization of regulatory assets increased $4$7 million in the first quarternine months of 2005. The higher amortization was caused by2005 due to an increase in the level of MTC revenue recovery.
Capital Resources and Liquidity
JCP&L’s cash requirements infor the remainder of 2005 for operating expenses, construction expenditures and scheduled debt maturities are expected to be met with a combination of cash from operations and funds from the capital markets. Thereafter, JCP&L expects to meet its contractual obligations with cash from operations.
Changes in Cash Position
As of March 31,September 30, 2005, JCP&L had $41,000$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 quarternine months of 2005 compared with the first quartercorresponding periods of 2004, were as follows:
Operating Cash Flows | | 2005 | | 2004 | |
| | (In millions) | |
| | | | | |
Cash earnings(1) | | $ | 37 | | $ | 47 | |
Working capital and other | | | 60 | | | 75 | |
Total Cash Flows from Operating Activities | | $ | 97 | | $ | 122 | |
(1)Cash earnings is a non-GAAP measure (see reconciliation below).
| | 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, (inas disclosed in the table above)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.
Reconciliation of Cash Earnings | | 2005 | | 2004 | |
| | (In millions) | |
| | | | | |
Net Income (GAAP) | | $ | 15 | | $ | 13 | |
Non-Cash Charges (Credits): | | | | | | | |
Provision for depreciation | | | 20 | | | 19 | |
Amortization of regulatory assets | | | 68 | | | 64 | |
Deferred costs recoverable as regulatory assets | | | (73 | ) | | (38 | ) |
Deferred income taxes | | | 7 | | | -- | |
Other non-cash expenses | | | -- | | | (11 | ) |
Cash earnings (Non-GAAP) | | $ | 37 | | $ | 47 | |
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 $10$140 million decreaseand $130 million increases in cash earnings isfor the third quarter and the first nine months of 2005, respectively, are described above and under "Results“Results of Operations"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 changesa reduction in prepayments and accounts payable of approximately $15 million each,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 $13 million change in receivables.NUG power contract.
Cash Flows From Financing Activities
Net cash used for financing activities decreased to $68was $212 million in the firstthird quarter of 2005 from $88compared 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 decrease$148 million increase resulted from a $36$124 million decreaseincrease in net debt redemptions partially offset byand a $15$23 million increase in common stock dividends to FirstEnergy.
JCP&L had about $41,000approximately $571,000 of cash and temporary investments and approximately $205$115 million of short-term indebtedness as of March 31,September 30, 2005. JCP&L has authorization from the SEC to incur short-term debt up to its charter limit of $1.038$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 March 31,September 30, 2005, JCP&L had the capability to issue $578$673 million of additional senior notes based upon FMB collateral. As of March 31, 2005, basedBased upon applicable earnings coverage tests and its charter, JCP&L could issue $564$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 quarternine months of 2005 was 2.66%.2005.
JCP&L’s access to capital markets and costs of financing are dependent oninfluenced by the ratings of its securities and the securities of FirstEnergy. The ratings outlook from the rating agenciesS&P and Fitch on all such securities is stable. Moody’s outlook on all securities is positive.
On MarchJuly 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 Sammis NSR settlement was a very favorable step for FirstEnergy, although it would not immediately affectrating 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 ratings or outlook. S&Pability to consistently generate free cash flow, good liquidity, and an improving financial profile were also noted that it continues to monitor the refueling outage at the Perry nuclear plant, which includes a detailed inspection by the NRC, and that if FirstEnergy should exit the outage without significant negative findings or delays the ratings outlook would be revised to positive.as strengths.
Cash Flows From Investing Activities
Net cash used infor investing activities was $30$51 million in the third quarter and $134 million for the first quarternine months of 2005 compared to $34$52 million inand $137 million for the previous year. The $4same periods of 2004. JCP&L’s capital spending for the period 2005-2007 is expected to be about $511 million decrease primarily resulted from a $4of which approximately $185 million decrease in property removal costs.
Duringapplies to 2005. In the last three quartersquarter of 2005, capital requirements for property additions and improvements are expected to be about $150$52 million.
JCP&L’s capital spending for the period 2005-2007 is expected to be about $511 million for property additions, of which approximately $178 million applies to 2005.
Market Risk Information
JCP&L uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price fluctuations. ItsFirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk management activities throughout JCP&L. They are responsible for promoting the effective design and implementation of sound risk management programs. They also oversee compliance with corporate risk management policies and established risk management practices.activities.
Commodity Price Risk
JCP&L is exposed to marketprice risk primarily due to fluctuations influctuating 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 March 31,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, we relyJCP&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. TheSources of information for valuation of the derivative contract at March 31,contracts as of September 30, 2005 uses prices from sources shownare summarized by year in the following table:
Source of Information - Fair Value by Contract Year
Sources of Information - | | | | | | | | | | | | | | | | | | |
Fair Value by Contract Year | | | | | 2005(1) | | 2006 | | 2007 | | 2008 | | 2009 | | Thereafter | | Total | |
| | 2005 | | 2006 | | 2007 | | 2008 | | Thereafter | | Total | | | | | | | | | | | | | | | | | | |
| | (In millions) | | | | | | | | | | | | | | | | | | |
Prices based on external sources(2) | | | | $ | 3 | | $ | 2 | | $ | 3 | | $ | - | | $ | - | | $ | - | | $ | 8 | |
Prices based on models | | | | | | - | | | - | | | - | | | 2 | | | 2 | | | 2 | | | 6 | |
Total(2) | | | | | $ | 3 | | $ | 2 | | $ | 3 | | $ | 2 | | $ | 2 | | $ | 2 | | $ | 14 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Other external sources(1) | | $ | 3 | | $ | 3 | | $ | -- | | $ | -- | | $ | -- | | $ | 6 | | |
Prices based on models | | | -- | | | -- | | | 2 | | | 2 | | | 4 | | | 8 | | |
| | | | | | | | | | | | | | | |
Total(2) | | $ | 3 | | $ | 3 | | $ | 2 | | $ | 2 | | $ | 4 | | $ | 14 | | |
(1) For the last quarter of 2005. (2) Broker quote sheets. | |
(1)Broker quote sheets.
(2)Includes $14 million from an embedded option that is offset by a regulatory liability and does not affect earnings.
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 March 31,September 30, 2005.
Equity Price Risk
Included in nuclear decommissioning trusts are marketable equity securities carried at their current fairmarket value of approximately $78$82 million and $80 million at March 31,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 March 31,September 30, 2005.
OutlookRegulatory Matters
The electric industry continues to transition to a more competitive environment and all ot JCP&L's customers can select alternative energy suppliers. JCP&L 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. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties.
Regulatory Matters
Beginning in 1999, all of JCP&L's customers had a choice for electric generation suppliers. JCP&L's customer rates were restructured into unbundled service charges and additional non-bypassable charges to recover stranded costs.
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 March 31,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 July 2003 NJBPU decision on JCP&L's base electric rate proceeding ordered(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 be conducted toin which the NJBPU would review whether JCP&L is in compliance with current service reliability and quality standards. The NJBPU also ordered that anystandards and determine whether the expenditures and projects undertaken by JCP&L to increase its system'ssystem reliability be reviewed as part of the Phase II proceeding, to determine their prudenceare prudent and reasonablenessreasonable for rate recovery. In that Phase II proceeding,Depending on its assessment of JCP&L's service reliability, the NJBPU could increasehave increased JCP&L’s return on equity to 9.75% or decreasedecreased it to 9.25%, depending on its assessment. 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 reliabilityPhase 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 JCP&L's service. Any reduction would be retroactivereturn; (3) merger savings, including amortization of costs to August 1, 2003. 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 requestsrequested 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 filed testimony on November 16, 2004, andresolves all of the issues associated with JCP&L submitted rebuttal testimony on January 4, 2005.&L's Phase II proceeding. The Ratepayer Advocate surrebuttal testimony was submitted February 8, 2005. Discovery and settlement conferences are ongoing.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.
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 a Memorandum of Understanding (MOU)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 an SRMa Special Reliability Master who made recommendations on appropriate courses of action necessary to ensure system-wide reliability andreliability. 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 Orderfinal 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 1314 to the consolidated financial statements for further details and a complete discussion of regulatory matters in New Jersey.
Employee Matters
On March 15, 2005, members of the International Brotherhood of Electrical Workers System Council U-3 ratified a new four-year contract with JCP&L. Ratification of the contract resolved issues surrounding health care and work rules, and ended a 14-week strike against JCP&L by the Council’s members.
Environmental Matters
JCP&L accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably determineestimate 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 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 March 31,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 $47$46.8 million as of March 31,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.
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 most significantother 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 CourtDivision 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 Court.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 March 31,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 concluded,concludes, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area.Specifically,area. Specifically, the final report concludes,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“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. As manyFirstEnergy also is proceeding with the implementation of these initiatives alreadythe 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 process,new or material upgrades to existing equipment, and therefore FirstEnergy doeshas not believeaccrued a liability as of September 30, 2005 for any expenditures in excess of those actually incurred through that any incremental expenses associated with additional initiatives completed in 2004 had a material effect on its continuing operationsdate. The FERC or financial results. FirstEnergy notes, however, that theother 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. FirstEnergy has not accrued a liability asFinally, 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 March 31, 2005 forcontrol room operators, before determining the next steps, if any, expenditures in excess of those actually incurred through that date.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 filed aFirstEnergy's motion to dismiss with 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 October 22, 2004.or about December 1, 2005. No timetable for a decision on the motion to dismiss has been established by the Court. No damage estimate has been provided and thusof potential liability has not been determined.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, and results of operations.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 “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”143”
On March 30, 2005, the FASB issued this interpretationFIN 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 interpretationInterpretation is effective no later thanfor JCP&L in the endfourth quarter of fiscal years ending after December 15, 2005. FirstEnergyJCP&L is currently evaluating the effect this standardInterpretation 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. 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.
EITF Issue No. 03-1,FSP FAS 115-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"
In March 2004,September 2005, the EITF reached a consensus on the application guidance for Issue 03-1.FASB finalized and renamed EITF 03-1 providesand 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 model for determiningSecurity Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when investments in certain debt and equity securities are consideredthe impairment is deemed other than temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair valuetemporary, even if a decision to sell has not been made, and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to(3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after JuneSeptember 15, 2004, were delayed by2005. The FASB expects to issue this FSP in the issuancefourth quarter of 2005, which would require prospective application for reporting periods beginning after December 15, 2005. JCP&L is currently evaluating this FSP EITF 03-1-1 in September 2004. During the period of delay, FirstEnergy will continue to evaluateand any impact on its investments as required by existing authoritative guidance.investments.
METROPOLITAN EDISON COMPANY | METROPOLITAN EDISON COMPANY | | METROPOLITAN EDISON COMPANY | |
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CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | (Unaudited) | | (Unaudited) | |
| | | | | | | | | | | | | | | | |
| | | | Three Months Ended | | | Three Months Ended | | Nine Months Ended | |
| | | | March 31, | | | September 30, | | September 30, | |
| | | | | | | | | 2005 | | 2004 | | 2005 | | 2004 | |
| | | | 2005 | | 2004 | | | (In thousands) | |
| | | | | | | | | | | | | | | | |
| | | | (In thousands) | | |
| | | | | | | | |
OPERATING REVENUES | | | | | $ | 295,781 | | $ | 260,898 | | | $ | 333,180 | | $ | 285,419 | | $ | 892,097 | | $ | 788,361 | |
| | | | | | | | | | | | | | | | | | |
OPERATING EXPENSES AND TAXES: | | | | | | | | | | | | | | | | | | |
Fuel and purchased power | | | | | 150,133 | | 143,456 | | |
Purchased power | | | | 186,148 | | 146,938 | | 467,911 | | 421,660 | |
Other operating costs | | | | | 58,430 | | 33,048 | | | | 81,774 | | 50,141 | | 192,892 | | 130,210 | |
Provision for depreciation | | | | | 11,521 | | 9,898 | | | | 9,323 | | 10,648 | | 32,221 | | 30,370 | |
Amortization of regulatory assets | | | | | 28,621 | | 25,497 | | | | 32,853 | | 30,291 | | 86,760 | | 78,737 | |
General taxes | | | | | 19,272 | | 17,736 | | | | 19,906 | | 18,680 | | 56,201 | | 53,103 | |
Income taxes | | | | | | 6,732 | | | 7,980 | | | | (2,111 | ) | | 8,448 | | | 9,754 | | | 17,179 | |
Total operating expenses and taxes | | | | | | 274,709 | | | 237,615 | | | | 327,893 | | | 265,146 | | | 845,739 | | | 731,259 | |
| | | | | | | | | | | | | | | | | | |
OPERATING INCOME | | | | | 21,072 | | 23,283 | | | | 5,287 | | | 20,273 | | | 46,358 | | | 57,102 | |
| | | | | | | | | | | | | | | | | | |
OTHER INCOME (net of income taxes) | | | | | 6,449 | | 5,526 | | | | 6,459 | | | 6,888 | | | 19,897 | | | 18,530 | |
| | | | | | | | | | | | | | | | | | |
NET INTEREST CHARGES: | | | | | | | | | | | | | | | | | | |
Interest on long-term debt | | | | | 9,560 | | 10,147 | | | | 8,941 | | 8,823 | | 27,886 | | 31,208 | |
Allowance for borrowed funds used during construction | | | | | (178 | ) | | (71 | ) | | | (150 | ) | | (65 | ) | | (401 | ) | | (208 | ) |
Other interest expense | | | | | | 1,663 | | | 689 | | | | 1,950 | | | 1,326 | | | 5,626 | | | 2,846 | |
Net interest charges | | | | | | 11,045 | | | 10,765 | | | | 10,741 | | | 10,084 | | | 33,111 | | | 33,846 | |
| | | | | | | | | | | | | | | | | | |
NET INCOME | | | | | $ | 16,476 | | $ | 18,044 | | | | 1,005 | | 17,077 | | 33,144 | | 41,786 | |
| | | | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | | | |
Unrealized gain (loss) on derivative hedges | | | | | 84 | | (3,260 | ) | | | 84 | | 84 | | 252 | | (3,182 | ) |
Unrealized gain on available for sale securities | | | | | | -- | | | 22 | | |
Unrealized gain (loss) on available for sale securities | | | | 67 | | | - | | | 67 | | | (53 | ) |
Other comprehensive income (loss) | | | | | 84 | | (3,238 | ) | | | 151 | | 84 | | 319 | | (3,235 | ) |
Income tax related to other comprehensive income | | | | | | (35 | ) | | (9 | ) | |
Income tax expense (benefit) related to other comprehensive income | | | | 62 | | | (1,314 | ) | | 132 | | | (1,342 | ) |
Other comprehensive income (loss), net of tax | | | | | | 49 | | | (3,247 | ) | | | 89 | | | 1,398 | | | 187 | | | (1,893 | ) |
| | | | | | | | | | | | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | | | | $ | 16,525 | | $ | 14,797 | | | $ | 1,094 | | $ | 18,475 | | $ | 33,331 | | $ | 39,893 | |
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The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral partof these statements. | The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral partof these statements. | | The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these statements. | | |
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METROPOLITAN EDISON COMPANY | METROPOLITAN EDISON COMPANY | | METROPOLITAN EDISON COMPANY | |
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CONSOLIDATED BALANCE SHEETS | CONSOLIDATED BALANCE SHEETS | | CONSOLIDATED BALANCE SHEETS | |
(Unaudited) | (Unaudited) | | (Unaudited) | |
| | | | | | | | | | | | |
| | | | March 31, | | December 31, | | | September 30, | | December 31, | |
| | | | 2005 | | 2004 | | | 2005 | | 2004 | |
| | | | (In thousands) | | | (In thousands) | |
ASSETS | | | | | | | | | | | | |
UTILITY PLANT: | | | | | | | | | | | | |
In service | | | | | $ | 1,796,340 | | $ | 1,800,569 | | | $ | 1,841,450 | | $ | 1,800,569 | |
Less - Accumulated provision for depreciation | | | | | | 697,927 | | | 709,895 | | | | 712,549 | | | 709,895 | |
| | | | | 1,098,413 | | 1,090,674 | | | | 1,128,901 | | 1,090,674 | |
Construction work in progress | | | | | | 19,714 | | | 21,735 | | | | 7,458 | | | 21,735 | |
| | | | | | 1,118,127 | | | 1,112,409 | | | | 1,136,359 | | | 1,112,409 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | | | | | | |
Nuclear plant decommissioning trusts | | | | | 216,061 | | 216,951 | | | | 229,437 | | 216,951 | |
Long-term notes receivable from associated companies | | | | | 10,775 | | 10,453 | | | | 11,162 | | 10,453 | |
Other | | | | | | 28,899 | | | 34,767 | | | | 29,355 | | | 34,767 | |
| | | | | | 255,735 | | | 262,171 | | | | 269,954 | | | 262,171 | |
CURRENT ASSETS: | | | | | | | | | | | | | | |
Cash and cash equivalents | | | | | 120 | | 120 | | | | 120 | | 120 | |
Notes receivable from associated companies | | | | | 21,570 | | 18,769 | | | | 15,793 | | 18,769 | |
Receivables- | | | | | | | | | |
Customers (less accumulated provisions of $4,418,000 and $4,578,000, | | | | | | | | | |
Receivables - | | | | | | | |
Customers (less accumulated provisions of $4,320,000 and $4,578,000, | | | | | | | |
respectively, for uncollectible accounts) | | | | | 126,303 | | 119,858 | | | | 131,213 | | 119,858 | |
Associated companies | | | | | 42,649 | | 118,245 | | | | 1,401 | | 118,245 | |
Other (less accumulated provision of $29,000 for uncollectible accounts in 2005) | | | | | 14,932 | | 15,493 | | |
Other | | | | 7,684 | | 15,493 | |
Prepayments and other | | | | | | 45,192 | | | 11,057 | | | | 13,285 | | | 11,057 | |
| | | | | | 250,766 | | | 283,542 | | | | 169,496 | | | 283,542 | |
DEFERRED CHARGES: | | | | | | | | | | | | | | |
Goodwill | | | | | 867,769 | | 869,585 | | | | 867,649 | | 869,585 | |
Regulatory assets | | | | | 750,244 | | 693,133 | | | | 571,745 | | 693,133 | |
Other | | | | | | 24,140 | | | 24,438 | | | | 24,055 | | | 24,438 | |
| | | | | | 1,642,153 | | | 1,587,156 | | | | 1,463,449 | | | 1,587,156 | |
| | | | | $ | 3,266,781 | | $ | 3,245,278 | | | $ | 3,039,258 | | $ | 3,245,278 | |
CAPITALIZATION AND LIABILITIES | | | | | | | | | | | | | | |
CAPITALIZATION: | | | | | | | | | | | | | | |
Common stockholder's equity- | | | | | | | | | |
Common stockholder's equity - | | | | | | | |
Common stock, without par value, authorized 900,000 shares - | | | | | | | | | | | | | | |
859,500 shares outstanding | | | | | $ | 1,289,943 | | $ | 1,289,943 | | | $ | 1,290,296 | | $ | 1,289,943 | |
Accumulated other comprehensive loss | | | | | (43,441 | ) | | (43,490 | ) | | | (43,303 | ) | | (43,490 | ) |
Retained earnings | | | | | | 46,442 | | | 38,966 | | | | 28,110 | | | 38,966 | |
Total common stockholder's equity | | | | | 1,292,944 | | 1,285,419 | | | | 1,275,103 | | 1,285,419 | |
Long-term debt and other long-term obligations | | | | | | 694,214 | | | 701,736 | | | | 594,116 | | | 701,736 | |
| | | | | | 1,987,158 | | | 1,987,155 | | | | 1,869,219 | | | 1,987,155 | |
CURRENT LIABILITIES: | | | | | | | | | | | | | | |
Currently payable long-term debt | | | | | 37,395 | | 30,435 | | | | 100,000 | | 30,435 | |
Short-term borrowings- | | | | | | | | | |
Short-term borrowings - | | | | | | | |
Associated companies | | | | | 108,677 | | 80,090 | | | | 76,755 | | 80,090 | |
Accounts payable- | | | | | | | | | |
Other | | | | - | | - | |
Accounts payable - | | | | | | | |
Associated companies | | | | | 30,959 | | 88,879 | | | | 39,505 | | 88,879 | |
Other | | | | | 34,426 | | 26,097 | | | | 30,966 | | 26,097 | |
Accrued taxes | | | | | 2,286 | | 11,957 | | | | 2,247 | | 11,957 | |
Accrued interest | | | | | 10,445 | | 11,618 | | | | 9,462 | | 11,618 | |
Other | | | | | | 17,741 | | | 23,076 | | | | 20,008 | | | 23,076 | |
| | | | | | 241,929 | | | 272,152 | | | | 278,943 | | | 272,152 | |
NONCURRENT LIABILITIES: | | | | | | | | | | | | | | |
Accumulated deferred income taxes | | | | | 314,193 | | 305,389 | | | | 309,979 | | 305,389 | |
Accumulated deferred investment tax credits | | | | | 10,662 | | 10,868 | | | | 10,250 | | 10,868 | |
Power purchase contract loss liability | | | | | 393,825 | | 349,980 | | | | 250,024 | | 349,980 | |
Nuclear fuel disposal costs | | | | | 38,631 | | 38,408 | | |
Asset retirement obligation | | | | | 134,964 | | 132,887 | | | | 139,216 | | 132,887 | |
Retirement benefits | | | | | 80,571 | | 82,218 | | | | 77,501 | | 82,218 | |
Nuclear fuel disposal costs | | | | 39,213 | | 38,408 | |
Other | | | | | | 64,848 | | | 66,221 | | | | 64,913 | | | 66,221 | |
| | | | | | 1,037,694 | | | 985,971 | | | | 891,096 | | | 985,971 | |
COMMITMENTS AND CONTINGENCIES (Note 12) | | | | | | | | | | | |
COMMITMENTS AND CONTINGENCIES (Note 13) | | | | | | | | |
| | | $ | 3,039,258 | | $ | 3,245,278 | |
| | | | | $ | 3,266,781 | | $ | 3,245,278 | | | | | | | |
| | | | | | | | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of thesebalance sheets. | The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of thesebalance sheets. | | The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these balance sheets. | |
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METROPOLITAN EDISON COMPANY | |
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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 | |
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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 | ) |
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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 | |
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The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these statements. | |
METROPOLITAN EDISON COMPANY | |
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CONSOLIDATED STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | | |
| | | | Three Months Ended | |
| | | | March 31, | |
| | | | | | | |
| | | | 2005 | | 2004 | |
| | | | | | | |
| | | | (In thousands) | |
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CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | |
Net income | | | | | $ | 16,476 | | $ | 18,044 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | | | |
Provision for depreciation | | | | | | 11,521 | | | 9,898 | |
Amortization of regulatory assets | | | | | | 28,621 | | | 25,497 | |
Deferred costs recoverable as regulatory assets | | | | | | (16,441 | ) | | (16,792 | ) |
Deferred income taxes and investment tax credits, net | | | | | | (11 | ) | | 2,433 | |
Accrued retirement benefit obligation | | | | | | (1,647 | ) | | 1,074 | |
Accrued compensation, net | | | | | | (1,723 | ) | | (634 | ) |
Decrease (Increase) in operating assets: | | | | | | | | | | |
Receivables | | | | | | 69,712 | | | 5,767 | |
Materials and supplies | | | | | | (18 | ) | | 18 | |
Prepayments and other current assets | | | | | | (34,117 | ) | | (36,618 | ) |
Increase (Decrease) in operating liabilities: | | | | | | | | | | |
Accounts payable | | | | | | (49,591 | ) | | 6,848 | |
Accrued taxes | | | | | | (9,671 | ) | | (1,546 | ) |
Accrued interest | | | | | | (1,173 | ) | | (4,465 | ) |
Other | | | | | | (9,134 | ) | | (8,265 | ) |
Net cash provided from operating activities | | | | | | 2,804 | | | 1,259 | |
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CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | |
New Financing- | | | | | | | | | | |
Long-term debt | | | | | | -- | | | 247,607 | |
Short-term borrowings, net | | | | | | 28,587 | | | -- | |
Redemptions and Repayments- | | | | | | | | | | |
Long-term debt | | | | | | (435 | ) | | (50,435 | ) |
Short-term borrowings, net | | | | | | -- | | | (65,335 | ) |
Dividend Payments- | | | | | | | | | | |
Common stock | | | | | | (9,000 | ) | | (5,000 | ) |
Net cash provided from financing activities | | | | | | 19,152 | | | 126,837 | |
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CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | |
Property additions | | | | | | (16,199 | ) | | (8,962 | ) |
Contributions to nuclear decommissioning trusts | | | | | | (2,371 | ) | | (2,371 | ) |
Loans to associated companies, net | | | | | | (3,150 | ) | | (116,802 | ) |
Other | | | | | | (236 | ) | | 38 | |
Net cash used for investing activities | | | | | | (21,956 | ) | | (128,097 | ) |
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Net increase (decrease) in cash and cash equivalents | | | | | | -- | | | (1 | ) |
Cash and cash equivalents at beginning of period | | | | | | 120 | | | 121 | |
Cash and cash equivalents at end of period | | | | | $ | 120 | | $ | 120 | |
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The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are anintegral part of these statements. | |
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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 March 31,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 March 31,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
May 3,November 1, 2005
METROPOLITAN EDISON COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
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 indecreased to $1 million for the firstthird quarter of 2005 decreased to $16 million from $18$17 million in the firstthird quarter of 2004. The decrease was due to increases in net income primarily resulted from higher purchased power costs, transmission expenses, and amortization of regulatory assets, other operating costs and general taxes. The decrease was partially offset by increasedhigher operating revenues.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 $35$48 million, or 13.4%16.7%, in the third quarter of 2005 and $104 million, or 13.2%, in the first quarternine months of 2005, compared with the first quartersame periods of 2004. TheIncreases in both periods were due, in part, to higher revenues primarily resulted from increases of retail generation electric sales of $15 million and distribution revenues of $6 million. The higher generation sales revenues infrom all customer sectors reflected($17 million for the effectthird quarter and $41 million for the first nine months of a 10.1%2005). The increases in retail generation KWH sales increasefor both periods of 2005 were mainly attributable to warmer weather and higher composite unit prices. The sales volume increase resulted from lowerreduced customer shopping due to customers returning to Met-Ed as their generation supplier. Sales by alternative suppliers as a percent of total sales delivered- primarily in Met-Ed’s franchise areathe industrial sector. Industrial customer shopping decreased by 18.2, 1.44.9% and 0.111.2% percentage points in the industrial, commercialthird quarter and residential sectors,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 $6 million. The higher revenues$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 (3.7% increase) and slightly higher unit pricesprices. Increased transmission revenues of $17 million in the third quarter and $32 million in the first quarternine months of 2005 as comparedalso contributed to the same period of 2004. Also contributing to the higher operating revenues was a $10 million increase due to Met-Ed’s assumption of transmission revenues (PJM congestion credit and FTR/ARR) from FESrevenues. These increases were due to a change in the power supply agreement with FES in the second quarter of 2004, which2004. This change also resulted in higher transmission expenses as discussed further below. In addition, the higherfirst nine months of 2005, operating revenues in the first quarter of 2005also 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 specified levels. This payment isspecific levels and are credited to Met-Ed’s customers, resulting in no net earnings effect.impact to earnings.
Changes in KWH deliveriessales by customer class in the first quarter ofthree months and nine months ended September 30, 2005 compared to the first quartersame periods of 2004 are summarized in the following table:
Changes in KWH
| | | |
Increase (Decrease)
| | | |
Residential
| | | 2.2 | % |
Commercial
| | | 5.4 | % |
Industrial
| | | 3.9 | % |
Total KWH Deliveries
| | | 3.7
| %
|
| | 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 | % |
| | | | | | | |
Operating Expenses and Taxes
Total operating expenses and taxes increased by $37$63 million in the third quarter and by $114 million in the first quarternine months of 2005 compared with the same periods of 2004. The following table presents changes from the first quarter of 2004. 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 an $18 million increase in two-partyincreased third party power purchases ($47 million in the third quarter and a $2$92 million increase 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 a $14reduced purchased power from FES ($30 million reduction in powerthe third quarter and $77 million in the first nine months of 2005). These changes, for both periods, were due to increased KWH purchased from FES. The net increase in KWH purchases was attributable to the increase inmeet increased retail generation sales.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 quarternine months of 2005 compared with the same periods of 2004. The increases in both periods were primarily due to $27 millioncaused by higher PJM ancillary transmission expenses, congestion charges and FTR/ARR expenses. The transmission expense increase resulted from Met-Ed’s assumptionexpenses as a result of PLR transmission related transactionsthe change in the power supply agreement with FES discussed above. Other operating costs also
In the first nine months of 2005, depreciation expense increased due to higher storm-relatedadditions to the asset base and vegetation management costs.
Depreciation expenses increased due to higher estimated costs to decommission the Saxton nuclear plant and depreciation expense on property purchased from FESC in lateas compared to the same period of 2004. AmortizationFor both periods of 2005, regulatory assets increased primarily due to increasedasset amortization reflected increases associated with the level of regulatory assets being recovered through CTC rates,revenue recovery, partially offset by lower amortization related to above market NUG costs.costs as compared to the prior year periods.
General taxes increased by $2 millionin 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 quarternine months of 2005 due to higher gross receipt taxes.lower taxable income.
Capital Resources and Liquidity
Met-Ed’s cash requirements infor the remainder of 2005, and thereafter, for operating expenses, construction expenditures and scheduled debt maturities are expected to be met with a combination of cash from operations and funds from the capital markets.operations.
Changes in Cash Position
As of March 31,September 30, 2005, and December 31, 2004, Met-Ed had $120,000 ofMet-Ed’s cash and cash equivalents.equivalents of $120,000 remained unchanged from December 31, 2004.
Cash Flows From Operating Activities
Cash provided from (used for) operating activities induring the third quarter and first quarternine months of 2005, andcompared 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. | | | | | | | |
Operating Cash Flows | | 2005 | | 2004 | |
| | (In millions) | |
| | | | | |
Cash earnings(1) | | $ | 37 | | $ | 39 | |
Working capital and other | | | (34 | ) | | (38 | ) |
| | | | | | | |
Total Cash Flows from Operating Activities | | $ | 3 | | $ | 1 | |
(1)Cash earnings is a non-GAAP measure (see reconciliation below).
Cash earnings, (inas disclosed in the table above)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 | |
| | | | | | | | | | | | | |
| | Three Months Ended | |
| | March 31, | |
Reconciliation of Cash Earnings | | 2005 | | 2004 | |
| | (In millions) | |
| | | | | |
Net Income (GAAP) | | $ | 16 | | $ | 18 | |
Non-Cash Charges (Credits): | | | | | | | |
Provision for depreciation | | | 12 | | | 10 | |
Amortization of regulatory assets | | | 29 | | | 25 | |
Deferred costs recoverable as regulatory assets | | | (16 | ) | | (17 | ) |
Deferred income taxes and investment tax credits, net | | | -- | | | 2 | |
Other non-cash expenses | | | (4 | ) | | 1 | |
Cash earnings (Non-GAAP) | | $ | 37 | | $ | 39 | |
The $2$16 million decreaseand $31 million increases in cash earnings isfor 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 under "Resultsthe first nine months due to the absence of Operations".a $23 million after-tax voluntary pension contribution made in the third quarter of 2004. The $4$26 million change in working capital changein the third quarter of 2005 primarily resulted from changes of $64$6 million in receivablesaccounts receivable, $19 million in accounts payable and $3$5 million in prepayments, offset by a change of $4 million in accrued interest,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 $56$11 million in accounts payable and $8customer deposits, $3 million in accrued taxes.taxes and $2 million in accrued interest.
Cash Flows From Financing Activities
NetFor the third quarter of 2005, net cash used for financing activities was $34 million compared to $14 million of cash provided from financing activities was $19 million in the first quarter of 2005 compared to $127 million in the firstthird quarter of 2004. The $48 million decrease resulted primarily reflected $29from 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 short-term borrowingsnet cash provided from financing activities in the first quarter of 2005 compared to last year’s issuance of $250 million of senior notes, partially offset by debt redemptions of $115 million in the first quartersame period of 2004. In addition,The $106 million change reflected a $252 million reduction in new debt financing and a $9 million increase in common stock dividends to FirstEnergy, increasedpartially offset by $4a $155 million decrease in 2005.debt redemptions compared to the same period of 2004.
As of March 31,September 30, 2005, Met-Ed had approximately $22$16 million of cash and temporary investments (which included(including short-term notes receivable from associated companies) and $109$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 soas long as the senior bonds are outstanding. Met-Ed had no restrictions on the issuance of preferred stock.
In addition, Met-Ed has anFunding 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 customerunder a receivables financing facility. Thearrangement. 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 undrawn asrenewed until June 29, 2006. As of March 31, 2005; it expires JuneSeptember 30, 2005, andthe facility was undrawn. The annual facility fee is expected to be renewed.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 poolpools and tracks surplus funds of FirstEnergy and itsthe 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 such athe 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 firstthird quarter of 2005 was 2.66%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 MarchJuly 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 Sammis NSR settlement was a very favorable step for FirstEnergy, although it would not immediately affectrating 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 ratings or outlook. S&Pability to consistently generate free cash flow, good liquidity, and an improving financial profile were also noted that it continues to monitor the refueling outage at the Perry nuclear plant, which includes a detailed inspection by the NRC, and that if FirstEnergy should exit the outage without significant negative findings or delays the ratings outlook would be revised to positive.as strengths.
Cash Flows From Investing Activities
In the firstthird quarter of 2005, net cash used infor investing activities totaled $22$24 million, compared to $128$7 million in the firstthird quarter of 2004. The decreasechange in the third quarter of 2005 primarily resulted from a $114$19 million decreaseincrease in loansloan repayments to associated companies offsetand a $9 million increase in partproperty additions, partially offset by a $7$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.
During the remaining quarters of 2005, capital requirements for property additions are expected to be about $52 million. Met-Ed has additional requirements of approximately $37 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.
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 energy delivery related improvements,short-term credit arrangements. Met-Ed has no additional requirements for maturing long-term debt during the remainder of which approximately $67 million applies to 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 throughout the Company.activities.
Commodity Price Risk
Met-Ed is exposed to marketprice risk primarily due to fluctuations inresulting 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 March 31,September 30, 2005, Met-Ed’s commodity derivative contract was an embedded option with a fair value of $27$28 million. A $4 million net decrease of $5 million in the value of this asset was recorded as a decrease in a regulatory liabilityliabilities, 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. TheSources of information for the valuation of the derivative contract at March 31,contracts as of September 30, 2005 is shown using prices from sourcesare summarized by year in the following table:
Source of Information | | | | | | | | | | | | | | | |
- Fair Value by Contract Year | | 2005 | | 2006 | | 2007 | | 2008 | | 2009 | | Thereafter | | Total | |
| | (In millions) | |
Prices based on external sources(1) | | $ | 5 | | $ | 4 | | $ | -- | | $ | -- | | $ | -- | | $ | -- | | $ | 9 | |
Prices based on models | | | -- | | | -- | | | 6 | | | 5 | | | 3 | | | 4 | | | 18 | |
| | | | | | | | | | | | | | | | | | | | | | |
Total | | $ | 5 | | $ | 4 | | $ | 6 | | $ | 5 | | $ | 3 | | $ | 4 | | $ | 27 | |
(1) Broker quote sheets.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 March 31,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 $131$138 million as of September 30, 2005 and $134 million as of March 31, 2005 and December 31, 2004, respectively.2004. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $13$14 million reduction in fair value as of March 31,September 30, 2005.
OUTLOOKRegulatory Matters
The electric industry continues to transition to a more competitive environment and all of Met-Ed's customers can select alternative energy suppliers. Met-Ed 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. Met-Ed has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties.
Regulatory Matters
Beginning in 1999, all of Met-Ed's customers had a choice for electric generation suppliers. Met-Ed's customer rates were restructured to itemize (unbundle) the current price of electricity into its component elements - including generation, transmission, distribution and stranded cost recovery. In the event customers obtain power from an alternative source, the generation portion of Met-Ed's rates is excluded from their bill and the customers receive a generation charge from the alternative supplier.
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 March 31,September 30, 2005 and December 31, 2004 were $750$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.
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 itstheir uncommitted PLR energy costs during the term of the agreement with FES. Met-Ed is authorized to continue deferringdefer 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 1314 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 impactsimpact 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 determineestimate the amount of such costs. Unasserted claims are reflected in Met-Ed'sMet-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 March 31,September 30, 2005, based on estimates of the total costs of cleanup, Met-Ed'sMet-Ed’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 $48,000 as
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 March 31, 2005.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 most significantother 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 concluded,concludes, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area.Specifically,area. Specifically, the final report concludes,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“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. As manyFirstEnergy also is proceeding with the implementation of these initiatives alreadythe 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 process,new or material upgrades to existing equipment, and therefore FirstEnergy doeshas not believeaccrued a liability as of September 30, 2005 for any expenditures in excess of those actually incurred through that any incremental expenses associated with additional initiatives completed in 2004 had a material effect on its continuing operationsdate. The FERC or financial results. FirstEnergy notes, however, that theother 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. FirstEnergy has not accrued a liability asFinally, 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 March 31, 2005 forcontrol room operators, before determining the next steps, if any, expenditures in excess of those actually incurred through that date.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 filed aFirstEnergy's motion to dismiss with 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 October 22, 2004.or about December 1, 2005. No timetable for a decision on the motion to dismiss has been established by the Court. No damage estimate has been provided and thusof potential liability has not been determined.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, and results of operations.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.
| 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 “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”143”
On March 30, 2005, the FASB issued this interpretationFIN 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 interpretationInterpretation is effective no later thanfor Met-Ed in the endfourth quarter of fiscal years ending after December 15, 2005. FirstEnergyMet-Ed is currently evaluating the effect this standardInterpretation 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.
EITF Issue No. 03-1,FSP FAS 115-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"
In March 2004,September 2005, the EITF reached a consensus on the application guidance for Issue 03-1.FASB finalized and renamed EITF 03-1 providesand 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 model for determiningSecurity Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when investments in certain debt and equity securities are consideredthe impairment is deemed other than temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair valuetemporary, even if a decision to sell has not been made, and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to(3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after JuneSeptember 15, 2004, were delayed by2005. The FASB expects to issue this FSP in the issuancefourth 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 EITF 03-1-1 in September 2004. During the period of delay, FirstEnergy will continue to evaluateand any impact on its investments as required by existing authoritative guidance.investments.
PENNSYLVANIA ELECTRIC COMPANY | |
| | | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | | |
| | | | Three Months Ended | |
| | | | March 31, | |
| | | | | | | |
| | | | 2005 | | 2004 | |
| | | | | | | |
| | | | (In thousands) | |
| | | | | | | |
OPERATING REVENUES | | | | | $ | 293,929 | | $ | 256,445 | |
| | | | | | | | | | |
OPERATING EXPENSES AND TAXES: | | | | | | | | | | |
Purchased power | | | | | | 150,277 | | | 156,376 | |
Other operating costs | | | | | | 53,793 | | | 39,908 | |
Provision for depreciation | | | | | | 12,506 | | | 11,438 | |
Amortization of regulatory assets | | | | | | 13,185 | | | 13,651 | |
General taxes | | | | | | 18,206 | | | 16,962 | |
Income taxes | | | | | | 15,792 | | | 2,563 | |
Total operating expenses and taxes | | | | | | 263,759 | | | 240,898 | |
| | | | | | | | | | |
OPERATING INCOME | | | | | | 30,170 | | | 15,547 | |
| | | | | | | | | | |
OTHER INCOME (EXPENSE) (net of income taxes) | | | | | | 736 | | | (84 | ) |
| | | | | | | | | | |
NET INTEREST CHARGES: | | | | | | | | | | |
Interest on long-term debt | | | | | | 7,459 | | | 7,447 | |
Allowance for borrowed funds used during construction | | | | | | (125 | ) | | (70 | ) |
Deferred interest | | | | | | -- | | | 190 | |
Other interest expense | | | | | | 2,188 | | | 2,237 | |
Net interest charges | | | | | | 9,522 | | | 9,804 | |
| | | | | | | | | | |
NET INCOME | | | | | $ | 21,384 | | $ | 5,659 | |
| | | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | |
Unrealized gain on derivative hedges | | | | | | 16 | | | -- | |
Unrealized gain (loss) on available for sale securities | | | | | | (3 | ) | | 8 | |
Other comprehensive income (loss) | | | | | | 13 | | | 8 | |
Income tax related to other comprehensive income | | | | | | (6 | ) | | (3 | ) |
Other comprehensive income (loss), net of tax | | | | | | 7 | | | 5 | |
| | | | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | | | | $ | 21,391 | | $ | 5,664 | |
| | | | | | | | | | |
| | | | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company arean integral part of these statements. | |
| | | | | | | | | | |
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. | | |
| | | | | | | | | | | | | |
PENNSYLVANIA ELECTRIC COMPANY | |
| | | | | | | |
CONSOLIDATED BALANCE SHEETS | |
(Unaudited) | |
| | | | March 31, | | December 31, | |
| | | | 2005 | | 2004 | |
| | | | (In thousands) | |
ASSETS | | | | | | | |
UTILITY PLANT: | | | | | | | |
In service | | | | | $ | 1,962,547 | | $ | 1,981,846 | |
Less - Accumulated provision for depreciation | | | | | | 756,126 | | | 776,904 | |
| | | | | | 1,206,421 | | | 1,204,942 | |
Construction work in progress | | | | | | 25,837 | | | 22,816 | |
| | | | | | 1,232,258 | | | 1,227,758 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | | |
Nuclear plant decommissioning trusts | | | | | | 108,252 | | | 109,620 | |
Non-utility generation trusts | | | | | | 96,738 | | | 95,991 | |
Long-term notes receivable from associated companies | | | | | | 14,164 | | | 14,001 | |
Other | | | | | | 14,589 | | | 18,746 | |
| | | | | | 233,743 | | | 238,358 | |
CURRENT ASSETS: | | | | | | | | | | |
Cash and cash equivalents | | | | | | 35 | | | 36 | |
Notes receivable from associated companies | | | | | | 10,271 | | | 7,352 | |
Receivables- | | | | | | | | | | |
Customers (less accumulated provisions of $4,435,000 and $4,712,000, | | | | | | | | | | |
respectively, for uncollectible accounts) | | | | | | 128,530 | | | 121,112 | |
Associated companies | | | | | | 48,645 | | | 97,528 | |
Other | | | | | | 15,098 | | | 12,778 | |
Prepayments and other | | | | | | 42,317 | | | 7,198 | |
| | | | | | 244,896 | | | 246,004 | |
DEFERRED CHARGES: | | | | | | | | | | |
Goodwill | | | | | | 887,103 | | | 888,011 | |
Regulatory assets | | | | | | 277,520 | | | 200,173 | |
Other | | | | | | 12,293 | | | 13,448 | |
| | | | | | 1,176,916 | | | 1,101,632 | |
| | | | | $ | 2,887,813 | | $ | 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 | | | | | | 1,205,948 | | | 1,205,948 | |
Accumulated other comprehensive loss | | | | | | (52,806 | ) | | (52,813 | ) |
Retained earnings | | | | | | 62,453 | | | 46,068 | |
Total common stockholder's equity | | | | | | 1,321,407 | | | 1,305,015 | |
Long-term debt and other long-term obligations | | | | | | 478,695 | | | 481,871 | |
| | | | | | 1,800,102 | | | 1,786,886 | |
CURRENT LIABILITIES: | | | | | | | | | | |
Currently payable long-term debt | | | | | | 11,525 | | | 8,248 | |
Short-term borrowings- | | | | | | | | | | |
Associated companies | | | | | | 69,693 | | | 241,496 | |
Other | | | | | | 170,000 | | | -- | |
Accounts payable- | | | | | | | | | | |
Associated companies | | | | | | 28,338 | | | 56,154 | |
Other | | | | | | 29,542 | | | 25,960 | |
Accrued taxes | | | | | | 18,204 | | | 7,999 | |
Accrued interest | | | | | | 15,276 | | | 9,695 | |
Other | | | | | | 18,166 | | | 23,750 | |
| | | | | | 360,744 | | | 373,302 | |
NONCURRENT LIABILITIES: | | | | | | | | | | |
Power purchase contract loss liability | | | | | | 441,255 | | | 382,548 | |
Asset retirement obligation | | | | | | 67,482 | | | 66,443 | |
Accumulated deferred income taxes | | | | | | 49,680 | | | 37,318 | |
Retirement benefits | | | | | | 119,115 | | | 118,247 | |
Other | | | | | | 49,435 | | | 49,008 | |
| | | | | | 726,967 | | | 653,564 | |
COMMITMENTS AND CONTINGENCIES (Note 12) | | | | | | | | | | |
| | | | | $ | 2,887,813 | | $ | 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. | |
| | | | | | | | | | |
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. | | | |
| | | | | | | |
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 | |
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The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these statements. | | |
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PENNSYLVANIA ELECTRIC COMPANY | |
| | | | | | | |
CONSOLIDATED STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | | |
| | | | Three Months Ended | |
| | | | March 31, | |
| | | | | | | |
| | | | 2005 | | 2004 | |
| | | | | | | |
| | | | (In thousands) | |
| | | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | |
Net income | | | | | $ | 21,384 | | $ | 5,659 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | | | |
Provision for depreciation | | | | | | 12,506 | | | 11,438 | |
Amortization of regulatory assets | | | | | | 13,185 | | | 13,651 | |
Deferred costs recoverable as regulatory assets | | | | | | (19,433 | ) | | (17,993 | ) |
Deferred income taxes and investment tax credits, net | | | | | | 2,446 | | | 25,242 | |
Accrued retirement benefit obligation | | | | | | 868 | | | 2,802 | |
Accrued compensation, net | | | | | | (2,630 | ) | | 2,255 | |
Decrease (Increase) in operating assets: | | | | | | | | | | |
Receivables | | | | | | 39,145 | | | (12,129 | ) |
Prepayments and other current assets | | | | | | (35,119 | ) | | (47,054 | ) |
Increase (Decrease) in operating liabilities: | | | | | | | | | | |
Accounts payable | | | | | | (24,234 | ) | | (10,738 | ) |
Accrued taxes | | | | | | 10,205 | | | (6,483 | ) |
Accrued interest | | | | | | 5,581 | | | 2,636 | |
Other | | | | | | (217 | ) | | 3,654 | |
Net cash provided from (used for) operating activities | | | | | | 23,687 | | | (27,060 | ) |
| | | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | |
New Financing- | | | | | | | | | | |
Long-term debt | | | | | | -- | | | 150,000 | |
Redemptions and Repayments- | | | | | | | | | | |
Long-term debt | | | | | | (13 | ) | | (104 | ) |
Short-term borrowings, net | | | | | | (1,803 | ) | | (61,326 | ) |
Dividend Payments- | | | | | | | | | | |
Common stock | | | | | | (5,000 | ) | | -- | |
Net cash provided from (used for) financing activities | | | | | | (6,816 | ) | | 88,570 | |
| | | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | |
Property additions | | | | | | (15,393 | ) | | (11,194 | ) |
Non-utility generation trust contribution | | | | | | -- | | | (50,614 | ) |
Loans to associated companies, net | | | | | | (3,082 | ) | | (71 | ) |
Other, net | | | | | | 1,603 | | | 369 | |
Net cash used for investing activities | | | | | | (16,872 | ) | | (61,510 | ) |
| | | | | | | | | | |
Net change in cash and cash equivalents | | | | | | (1 | ) | | -- | |
Cash and cash equivalents at beginning of period | | | | | | 36 | | | 36 | |
Cash and cash equivalents at end of period | | | | | $ | 35 | | $ | 36 | |
| | | | | | | | | | |
| | | | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are anintegral part of these statements. | |
| | | | | | | | | | |
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| | | | | | | | | | |
| | | | | | | | | | |
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 March 31,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 March 31,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
May 3,November 1, 2005
PENNSYLVANIA ELECTRIC COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
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
NetPenelec recognized a net loss of $2 million in the third quarter of 2005, compared to $18 million in net income in the firstthird quarter of 2004. During the first nine months of 2005, increasednet income decreased to $21$25 million compared to $6$27 million in the first quarternine months of 2004. The increasedecrease in both periods resulted from higher purchased power and other operating costs, partially offset by higher operating revenues and lower purchased power costs, partially offset by higher other operating costs and generalincome taxes.
Operating revenues increased by $37$36 million in the third quarter and $93 million in the first quarternine months of 2005 compared to the first quartersame periods of 2004, primarily2004. Increases in both periods were due to higher transmission, retail generation revenues in all sectors ($14 million for the quarter and distribution$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. Transmission
Distribution revenues increased $23by $4 million as a resultin the third quarter and by $6 million in the first nine months of Penelec's assumption2005 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 from FESof $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, which2004. This change also resulted in higher transmission expenses as discussed further below. In addition, the higher first quarter 2005 operating revenues included a $2 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 specified levels. This payment is credited to Penelec’s customers, resulting in no net earnings effect.
Retail generation revenues increased by $9 million, principally from increased generation sales to industrial and commercial customers (industrial - $5 million and commercial - $4 million) reflecting volume sales increases of 12.5% and 6.8%, respectively, and higher unit costs. Industrial KWH sales increased despite higher customer shopping in this sector. Sales by alternative suppliers as a percent of total industrial sales delivered in Penelec’s franchise area increased by 4.0 percentage points, while commercial customer shopping remained constant in the first quarter of 2005. Residential generation revenues showed a slight increase of $0.4 million and residential KWH sales were nearly unchanged in the first quarter of 2005 as compared to last year.
Distribution revenues increased by $3 million in the first quarter of 2005 as compared to the same period of 2004, primarily on higher deliveries to the commercial and industrial sectors. The higher commercial and industrial revenues of $2 million and $1 million, respectively, reflected the effect of increased KWH deliveries partially offset by lower composite unit prices.
Changes in electric distribution deliveriesKWH sales by customer class in the first quarterthree months and nine months ended September 30, 2005 compared tofrom the first quartercorresponding 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 | % |
| | | | | | | |
Changes in KWH Deliveries
| | 2005
| |
Increase (Decrease)
| | | |
Residential | | | 0.5 | % |
Commercial | | | 6.9 | % |
Industrial | | | 18.4 | % |
Total KWH Deliveries
| | | 8.0
| %
|
Operating Expenses and Taxes
Total operating expenses and taxes increased by $23$57 million or 9.5%in the third quarter and $97 million in the first quarternine months of 2005 compared with the same periods in 2004. The following table presents changes from the first quarter of 2004. 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 decreasedincreased by $6$41 million or 3.9%29.9% in the third quarter and $35 million or 8.0% in the first quarternine months of 2005 compared to the first quartersame periods of 2004. The decrease wasincrease in the third quarter of 2005 is due primarily to lower unit costs slightly offset by increased KWH purchased to meet increased retail generation sales requirements. 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 $14$29 million or 34.8%in the third quarter and $60 million in the first quarternine months of 2005 compared to first quartersame periods in 2004. That increase wasThe increases in both periods were primarily duetodue to increased transmission expenses in 2005 which were assumed by Penelec due toas a result of the change in the power supply agreement with FES discussedreferred to above. In addition, thereThe increased transmission expenses were higher storm-related contractorpartially offset by reduced labor costs that were charged to capital projects. Income taxes decreased in the first quarter of 2005.
General taxes increased due to the higher Pennsylvania gross receipts taxes in firstthird quarter of 2005 compared to same period in 2004. Income taxes increased due to higherlower pre-tax income in the first quarter of 2005 compared to the firstthird quarter of 2004.
Capital Resources and Liquidity
Penelec’s cash requirements infor the remainder of 2005 and thereafter, for operating expenses, construction expenditures and scheduled debt maturities are expected to be met by a combination ofwith cash from operations and funds from the capital markets.operations.
Changes in Cash Position
As of March 31,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 was $24 million in the third quarter and first quarternine months of 2005, compared to net cash used for operating activities of $27 millionwith 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 | | 2005 | | 2004 | |
| | (In millions) | | | (In millions) | |
| | | | | | | | | | | | | | |
Cash earnings(1) | | $ | 28 | | $ | 43 | | | $ | 14 | | $ | 27 | | $ | 59 | | $ | 56 | |
Pension trust contribution (2) | | | | - | | | (30 | ) | | - | | | (30 | ) |
Working capital and other | | | (4 | ) | | (70 | ) | | | 40 | | | (25 | ) | | 92 | | | (7 | ) |
Total | | $ | 24 | | $ | (27 | ) | |
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.
Cash earnings, (inas disclosed in the table above)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 | |
| | | | | | | | | | | | | |
Reconciliation of Cash Earnings | | 2005 | | 2004 | |
| | (In millions) | |
| | | | | |
Net Income (GAAP) | | $ | 21 | | $ | 6 | |
Non-Cash Charges (Credits): | | | | | | | |
Provision for depreciation | | | 13 | | | 11 | |
Amortization of regulatory assets | | | 13 | | | 14 | |
Deferred costs recoverable as regulatory assets | | | (19 | ) | | (18 | ) |
Deferred income taxes and investment tax credits | | | 2 | | | 25 | |
Other non-cash expenses | | | (2 | ) | | 5 | |
Cash earnings (Non-GAAP) | | $ | 28 | | $ | 43 | |
The $15Net 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 isas described above and under "Results“Results of Operations"Operations”. This was partially offset by a $66 million changeThe increase in working capital principallyprimarily 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 receivables, prepaymentsworking 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 a changechanges in the accounts payable.customer deposits.
Cash Flows From Financing Activities
Net cash used for financing activities was $7$25 million in the firstthird quarter of 2005 compared to net cash provided from financing activities of $89$52 million in the firstthird quarter of 2004. The net change reflects the absencea $1 million decrease in common stock dividends to FirstEnergy and a $173 million increase in repayments of 2004 long-term debt financing of $150 million,short-term borrowings, offset by a $60$95 million decrease in debt redemptions and $5redemptions.
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 dividend paymentsdividends to FirstEnergy in the first quarter2005 and a $218 million increase in repayments of 2005.short-term borrowings, offset by a $217 million decrease in debt redemptions.
Penelec had approximately $10 million$35,000 of cash and temporary investments (which includeincluded short-term notes receivable from associated companies) and approximately $240$190 million of short-term indebtedness as of March 31,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 March 31,September 30, 2005, Penelec did not havehad the abilitycapability to issue $18 million of additional senior notes based upon FMB collateral. Penelec has no restrictions on the issuance of preferred stock.
In addition, Penelec hasFunding 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 customerunder 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 that was drawn for $70 millionrenewed until June 29, 2006. The facility was undrawn as of March 31,September 30, 2005. The annual facility expiresfee is 0.25% on the entire finance limit.
On June 30,14, 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 expected to be renewed.$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 firstthird quarter of 2005 was 2.66%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 dependent oninfluenced by the ratings of its securities and thatthe securities of FirstEnergy. The ratings outlook from S&P and Fitch on all securities is stable.
On March 18, 2005, S&P stated that FirstEnergy’s Sammis NSR settlement was a very favorable step for FirstEnergy, although it would not immediately affect FirstEnergy’s ratings or outlook. S&P noted that it continues to monitor the refueling outage at the Perry nuclear plant, which includes a detailed inspection by the NRC, and that if FirstEnergy should exit the outage without significant negative findings or delays the ratings Moody’s outlook would be revised toon all securities is positive.
Cash Flows From Investing Activities
Cash used for investing activities was $17$29 million in the firstthird quarter of 2005 compared to $62$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 quarternine months of 2005 compared to $98 million in the first nine months of 2004. The decrease was primarily due to the absence in 2005 of 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 increased loans of $3 million to associated companies. In both periods, cash outflowshigher property additions in 2005. Capital expenditures for property additions were made toprimarily support the distribution of electricity.
During the remaining quarters of 2005, capital requirements for property additions are expected to be about $73 million. Penelec has additional requirements of approximately $11 million for maturing long-term debt during the remainder of 2005. Those requirements are expected to be satisfied from internal cash and short-term credit arrangements.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 $89$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 throughout the Company.activities.
Commodity Price Risk
Penelec is exposed to marketprice risk primarily due to fluctuations influctuating 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 March 31,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 a regulatory liabilityliabilities, 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, 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. TheSources of information for valuation of the derivative contract at March 31,contracts as of September 30, 2005 uses prices from sources shownare 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. |
Source of Information | | | | | | | | | | | | | | | |
—Fair Value by Contract Year | | 2005 | | 2006 | | 2007 | | 2008 | | 2009 | | Thereafter | | Total | |
| | (In millions) | |
| | | | | | | | | | | | | | | |
Prices based on external sources(1) | | $ | 3 | | $ | 3 | | $ | -- | | $ | -- | | $ | -- | | $ | -- | | $ | 6 | |
Prices based on models | | | -- | | | -- | | | 2 | | | 2 | | | 2 | | | 2 | | | 8 | |
| | | | | | | | | | | | | | | | | | | | | | |
Total | | $ | 3 | | $ | 3 | | $ | 2 | | $ | 2 | | $ | 2 | | $ | 2 | | $ | 14 | |
(1)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 March 31,September 30, 2005.
Equity Price Risk
Included in nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $58$61 million and $60 million as of March 31,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 March 31,September 30, 2005.
Outlook
The electric industry continues to transition to a more competitive environment and all of Penelec's customers can select alternative energy suppliers. Penelec 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. Penelec has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties.
Regulatory Matters
Beginning in 1999, all of Penelec's customers had a choice for electric generation suppliers. Penelec's customer rates were restructured to itemize (unbundle) the current price of electricity into its component elements - including generation, transmission, distribution and stranded cost recovery. In the event customers obtain power from an alternative source, the generation portion of Penelec's rates is excluded from their bill and the customers receive a generation charge from the alternative supplier.
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 March 31,September 30, 2005 and December 31, 2004 were $278$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 anyeither 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 continue deferringdefer 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, Penelec filed a request with the PPUC for deferral ofto 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 1314 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 only when it concludes that it is probable that it has an obligation for such costs and can reasonably determineestimate 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 most significantother 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 concluded,concludes, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area.Specifically,area. Specifically, the final report concludes,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“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. As manyFirstEnergy also is proceeding with the implementation of these initiatives alreadythe 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 process,new or material upgrades to existing equipment, and therefore FirstEnergy doeshas not believeaccrued a liability as of September 30, 2005 for any expenditures in excess of those actually incurred through that any incremental expenses associated with additional initiatives completed in 2004 had a material effect on its continuing operationsdate. The FERC or financial results. FirstEnergy notes, however, that theother 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. FirstEnergy has not accrued a liability asFinally, 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 March 31, 2005 forcontrol room operators, before determining the next steps, if any, expenditures in excess of those actually incurred through that date.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 filed aFirstEnergy's motion to dismiss with 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 October 22, 2004.or about December 1, 2005. No timetable for a decision on the motion to dismiss has been established by the Court. No damage estimate has been provided and thusof potential liability has not been determined.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, and results of operations.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.
FIN 47,“Accounting “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”143”
On March 30, 2005, the FASB issued this interpretationFIN 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 interpretationInterpretation is effective no later thanfor Penelec in the endfourth quarter of fiscal years ending after December 15, 2005. FirstEnergyPenelec is currently evaluating the effect this standardInterpretation 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.
EITF Issue No. 03-1,FSP FAS 115-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"
In March 2004,September 2005, the EITF reached a consensus on the application guidance for Issue 03-1.FASB finalized and renamed EITF 03-1 providesand 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 model for determiningSecurity Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when investments in certain debt and equity securities are consideredthe impairment is deemed other than temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair valuetemporary, even if a decision to sell has not been made, and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to(3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after JuneSeptember 15, 2004, were delayed by2005. The FASB expects to issue this FSP in the issuancefourth 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 EITF 03-1-1 in September 2004. During the period of delay, FirstEnergy will continue to evaluateand any impact on its investments as required by existing authoritative guidance.investments.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See“Management’s “Management’s Discussion and Analysis of Results of Operation and Financial Condition - Market Risk Information”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 thisthe report. Based on that evaluation, those officers have concluded that the registrant's disclosure controls and procedures are effective and were designedin timely alerting them to bring to their attention materialany information relating to the registrantregistrants and itstheir 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 others within those entities.the SEC's rules and forms.
(b) CHANGES IN INTERNAL CONTROLS
During the quarter ended March 31,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.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 1213 and 13 of14 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 | |
| | | | | | | | | |
January 1-31, 2005 | | | 62,712 | | $ | 39.23 | | | -- | | | -- | |
February 1-28, 2005 | | | 104,824 | | $ | 40.78 | | | -- | | | -- | |
March 1-31, 2005 | | | 942,459 | | $ | 41.59 | | | -- | | | -- | |
| | | | | | | | | | | | | |
First Quarter 2005 | | | 1,109,995 | | $ | 41.38 | | | -- | | | -- | |
| | | | | | | | 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. | (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 | |
| | |
Met-EdJCP&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-(e)15d-15(e). |
| 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(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 | Term LoanNotice of Termination Tolling Agreement, dated as of March 15, 2005, among Pennsylvania Electric Company, Union Bank of California,
N.A., as Administrative Agent, Lead Arranger and Lender, and National City Bank as Arranger, Syndication Agent and
Lender. (March 18, 2005 Form 8-K, Exhibit 10.1). 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-(e)15d-15(e). |
| 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e)15d-15(e). |
| 32.1 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. |
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. |
| | |
JCP&L
| |
| | |
| 12 | Fixed charge ratios |
| 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). |
| 31.3 | Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). |
| 32.2 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. |
| | |
FirstEnergyOE
| |
| | |
| 15 | Letter from independent registered public accounting firm |
| 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e)15d-15(e). |
| 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). |
| 32.1 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. |
| | |
OE and 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-(e). |
| 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e)15d-15(e). |
| 32.1 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. |
| | |
CEIPenn
| |
| | |
| 15 | Letter from independent registered public accounting firm. |
| 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e)15d-15(e). |
| 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e)15d-15(e). |
| 32.1 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. |
| | |
TECEI
| |
| | |
| 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e)15d-15(e). |
| 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(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.
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.
May 5,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 |
| | |
| |