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 June 30, 2007March 31, 2008
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 |
| Address; and Telephone Number | |
| | |
333-21011 | FIRSTENERGY CORP. | 34-1843785 |
| (An Ohio Corporation) | |
| 76 South Main Street | |
| Akron, OH 44308 | |
| 76 South Main Street
| |
| Akron, OH 44308
| |
| Telephone (800)736-3402 | |
| | |
1-2578 333-145140-01 | OHIO EDISON COMPANY FIRSTENERGY SOLUTIONS CORP. | 34-0437786 31-1560186 |
| (An Ohio Corporation) | |
| c/o FirstEnergy Corp. | |
| 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 | |
| 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 | |
| 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 | |
| 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 | |
| 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 | |
| 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 | |
| c/o FirstEnergy Corp.
| |
| 76 South Main Street
| |
| Akron, OH 44308
| |
| Telephone (800)736-3402 | |
Indicate by check mark whether each of the registrantsregistrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes Yes (X) No ( ) No ( ) | FirstEnergy Corp., Ohio Edison Company and Pennsylvania Electric Company |
Yes ( ) No (X) | FirstEnergy Solutions Corp., The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company and Metropolitan Edison Company |
Indicate by check mark whether any of the registrantsregistrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a non-accelerated filer.smaller reporting company. See definitionthe definitions of "accelerated"large accelerated filer,” “accelerated filer” and large accelerated filer"“smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer (X) | FirstEnergy Corp. |
Accelerated Filer ( ) | N/A |
Non-accelerated Filer (X)(Do not check if a smaller reporting company) (X) | FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company |
Smaller Reporting Company ( ) | N/A |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
Yes ( ) No (X) | FirstEnergy Corp., FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company, and Pennsylvania Electric Company |
Indicate by check mark whether any of the registrants is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes ( ) No (X)
Indicate the number of shares outstanding of each of the issuer'sissuer’s classes of common stock, as of the latest practicable date:
| OUTSTANDING |
CLASS | AS OF AUGUST 7, 2007MAY 8, 2008 |
FirstEnergy Corp., $.10$0.10 par value | 304,835,407 |
FirstEnergy Solutions Corp., no par value | 7 |
Ohio Edison Company, no par value | 60 |
The Cleveland Electric Illuminating Company, no par value | 67,930,743 |
The Toledo Edison Company, $5 par value | 29,402,054 |
Jersey Central Power & Light Company, $10 par value | 14,421,637 |
Metropolitan Edison Company, no par value | 859,500 |
Pennsylvania Electric Company, $20 par value | 5,290,5964,427,577 |
FirstEnergy Corp. is the sole holder of FirstEnergy Solutions Corp., 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.
This combined Form 10-Q is separately filed by FirstEnergy Corp., FirstEnergy Solutions Corp., Ohio Edison 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.
OMISSION OF CERTAIN INFORMATION
FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.
Forward-Looking Statements: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 include declarations regarding management’s intents, beliefs and current expectations. These statements typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” “believe,” “estimate” and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or achievement expressed or implied by such forward-looking statements.
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 FirstEnergy’s regulated utilities to collect transition and other charges or to recover increased transmission costs, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), and the legal and regulatory changes resulting from the implementation of the EPACT (including, but not limited to, the repeal of the PUHCA), the uncertainty of the timing and amounts of the capital expenditures needed to, among other things, implement the Air Quality Compliance Plan (including that such amounts could be higher than anticipated) or levels of emission reductions related to the Consent Decree 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 and oversight) by the NRC (including, but not limited to, the Demand for Information issued to FENOC on May 14, 2007) as disclosed in FirstEnergy’s SEC filings, the timing and outcome of various proceedings before the PUCO (including, but not limited to, the distribution rate cases and the generation supply plan filing for the Ohio Companies and the successful resolution of the issues remanded to the PUCO by the Ohio Supreme Court regarding the Rate Stabilization Plan) and the PPUC (including Penn’s default service plan filing), the resolution of the Petitions for Review filed with the Commonwealth Court of Pennsylvania with respect to the transition rate plan filing for Met-Ed and Penelec, 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 from strategic goals (including employee workforce initiatives), the anticipated benefits from voluntary pension plan contributions, the ability to improve electric commodity margins and to experience growth in the distribution business, the ability to access the public securities and other capital markets and the cost of such capital, the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to the August 14, 2003 regional power outage, any final adjustment in the purchase price per share under the accelerated share repurchase program announced March 2, 2007, to:
· | the speed and nature of increased competition in the electric utility industry and legislative and regulatory changes affecting how generation rates will be determined following the expiration of existing rate plans in Ohio and Pennsylvania, |
· | 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 FirstEnergy’s regulated utilities to collect transition and other charges or to recover increased transmission costs, |
· | maintenance costs being higher than anticipated, |
· | other legislative and regulatory changes, revised environmental requirements, including possible GHG emission regulations, |
· | the uncertainty of the timing and amounts of the capital expenditures needed to, among other things, implement the Air Quality Compliance Plan (including that such amounts could be higher than anticipated) or levels of emission reductions related to the Consent Decree resolving the New Source Review litigation or other potential regulatory initiatives, |
· | adverse regulatory or legal decisions and outcomes (including, but not limited to, the revocation of necessary licenses or operating permits and oversight) by the NRC (including, but not limited to, the Demand for Information issued to FENOC on May 14, 2007), |
· | the timing and outcome of various proceedings before the |
- | PUCO (including, but not limited to, the distribution rate cases and the generation supply plan filing for the Ohio Companies and the successful resolution of the issues remanded to the PUCO by the Ohio Supreme Court regarding the RSP and RCP, including the deferral of fuel costs) |
- | and Met-Ed’s and Penelec’s transmission service charge filings with the PPUC as well as the resolution of the Petitions for Review filed with the Commonwealth Court of Pennsylvania with respect to the transition rate plan for Met-Ed and Penelec, |
· | the continuing availability of generating units and their ability to operate at, or near full capacity, |
· | the changing market conditions that could affect the value of assets held in the registrants’ nuclear decommissioning trusts, pension trusts and other trust funds, |
· | the ability to comply with applicable state and federal reliability standards, |
· | the ability to accomplish or realize anticipated benefits from strategic goals (including employee workforce initiatives), |
· | the ability to improve electric commodity margins and to experience growth in the distribution business, |
· | the ability to access the public securities and other capital markets and the cost of such capital, |
· | the risks and other factors discussed from time to time in the registrants’ SEC filings, and other similar factors. |
The foregoing review of factors should not be construed as exhaustive. New factors emerge from time to time, and it is not possible to predict all such factors, nor assess the impact of any such factor on the registrants’ business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. Also, a security rating is not a recommendation to buy, sell or hold securities, and it may be subject to revision or withdrawal at any time and each such rating should be evaluated independently of any other rating. The registrants expressly disclaim any current intention to update any forward-looking statements contained herein 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 FinancialofFinancial Condition and Results of Operations. | |
| | |
| Notes to Consolidated Financial Statements | 1-25 |
| | |
FirstEnergy Corp. | |
| | |
| Consolidated Statements of Income | 26 |
| Consolidated Statements of Comprehensive Income | 27 |
| Consolidated Balance Sheets | 28 |
| Consolidated Statements of Cash Flows | 29 |
| Report of Independent Registered Public Accounting Firm | 30 |
| Management's Discussion and Analysis of Financial Condition and | 31-711-32 |
| Results of Operations | |
| Report of Independent Registered Public Accounting Firm | 33 |
| Consolidated Statements of Income | 34 |
| Consolidated Statements of Comprehensive Income | 35 |
| Consolidated Balance Sheets | 36 |
| Consolidated Statements of Cash Flows | 37 |
| | |
Ohio Edison CompanyFirstEnergy Solutions Corp.
| |
| | |
| Management's Narrative Analysis of Results of Operations | 38-40 |
| Report of Independent Registered Public Accounting Firm | 41 |
| Consolidated Statements of Income and Comprehensive Income | 42 |
| Consolidated Balance Sheets | 43 |
| Consolidated Statements of Cash Flows | 44 |
| | |
Ohio Edison Company | |
| | |
| Management's Narrative Analysis of Results of Operations | 45-46 |
| Report of Independent Registered Public Accounting Firm | 47 |
| Consolidated Statements of Income and Comprehensive Income | 48 |
| Consolidated Balance Sheets | 49 |
| Consolidated Statements of Cash Flows | 50 |
| | |
The Cleveland Electric Illuminating Company | |
| | |
| Management's Narrative Analysis of Results of Operations | 51-52 |
| Report of Independent Registered Public Accounting Firm | 53 |
| Consolidated Statements of Income and Comprehensive Income | 54 |
| Consolidated Balance Sheets | 55 |
| Consolidated Statements of Cash Flows | 56 |
| | |
The Toledo Edison Company | |
| | |
| Management's Narrative Analysis of Results of Operations | 57-58 |
| Report of Independent Registered Public Accounting Firm | 59 |
| Consolidated Statements of Income and Comprehensive Income | 60 |
| Consolidated Balance Sheets | 61 |
| Consolidated Statements of Cash Flows | 62 |
| | |
TABLE OF CONTENTS (Cont'd)
Jersey Central Power & Light Company | Pages |
| | |
| Management's Narrative Analysis of Results of Operations | 63-64 |
| Report of Independent Registered Public Accounting Firm | 65 |
| Consolidated Statements of Income and Comprehensive Income | 66 |
| Consolidated Balance Sheets | 67 |
| Consolidated Statements of Cash Flows | 68 |
| | |
Metropolitan Edison Company | |
| | |
| Management's Narrative Analysis of Results of Operations | 69-70 |
| Report of Independent Registered Public Accounting Firm | 71 |
| Consolidated Statements of Income and Comprehensive Income | 72 |
| Consolidated Balance Sheets | 73 |
| Consolidated Statements of Cash Flows | 74 |
| Report of Independent Registered Public Accounting Firm | 75 |
| Management's Discussion and Analysis of Financial Condition and | 76-79 |
| Results of Operations
| |
| | |
The ClevelandPennsylvania Electric Illuminating Company
| |
| | |
| Consolidated StatementsManagement's Narrative Analysis of Income and Comprehensive IncomeResults of Operations | 80 |
| Consolidated Balance Sheets | 81 |
| Consolidated Statements of Cash Flows | 8275-76 |
| Report of Independent Registered Public Accounting Firm | 83 |
| Management's Discussion and Analysis of Financial Condition and | 84-87 |
| Results of Operations
| |
| | |
The Toledo Edison Company
| |
| | 77 |
| Consolidated Statements of Income and Comprehensive Income | 8878 |
| Consolidated Balance Sheets | 8979 |
| Consolidated Statements of Cash Flows | 9080 |
| Report of Independent Registered Public Accounting Firm | 91 |
| Management'sCombined Management’s Discussion and Analysis of Financial Condition andRegistrant Subsidiaries | 92-9581-94 |
| |
Results of OperationsCombined Notes to Consolidated Financial Statements
| 95-123 |
| |
Item 3. Quantitative and Qualitative Disclosures About Market Risk. | 124 |
| | |
Item 4. Controls and Procedures – FirstEnergy. | 124 |
| |
Item 4T. Controls and Procedures – FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec. | 124 |
| | |
Part II. Other Information | |
| | |
Jersey Central Power & Light CompanyItem 1. Legal Proceedings.
| |
| | |
| Consolidated Statements of Income and Comprehensive Income | 96 |
| Consolidated Balance Sheets | 97 |
| Consolidated Statements of Cash Flows | 98 |
| Report of Independent Registered Public Accounting Firm | 99 |
| Management's Discussion and Analysis of Financial Condition and | 100-103 |
| Results of Operations
| |
TABLE OF CONTENTS (Cont'd)
| | Pages 125 |
| | |
Metropolitan Edison CompanyItem 1A. Risk Factors.
| |
| | |
| Consolidated Statements of Income and Comprehensive Income | 104 |
| Consolidated Balance Sheets | 105 |
| Consolidated Statements of Cash Flows | 106 |
| Report of Independent Registered Public Accounting Firm | 107 |
| Management's Discussion and Analysis of Financial Condition and | 108-111 |
| Results of Operations
| |
| | |
Pennsylvania Electric Company
| |
| | |
| Consolidated Statements of Income and Comprehensive Income | 112 |
| Consolidated Balance Sheets | 113 |
| Consolidated Statements of Cash Flows | 114 |
| Report of Independent Registered Public Accounting Firm | 115 |
| Management's Discussion and Analysis of Financial Condition and | 116-119 |
| Results of Operations
| |
| | |
Combined Management’s Discussion and Analysis of Registrant Subsidiaries
| 120-132125 |
| |
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
| 133 |
| | |
Item 4. Controls and Procedures.
| 133 |
| | |
Part II. Other Information
| |
| | |
Item 1. Legal Proceedings.
| 134 |
| | |
Item 1A. Risk Factors.
| 134 |
| |
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds. | 134125 |
| |
Item 4. Submission of Matters to a Vote of Security Holders.
| 134-135 |
| | |
Item 6. Exhibits. | 135-137126 |
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., owns and operates transmission facilities | |
CEI | The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary | |
Companies | OE, CEI, TE, JCP&L, Met-Ed and Penelec | |
FENOC | FirstEnergy Nuclear Operating Company, operates nuclear generating facilities | |
FES | FirstEnergy Solutions Corp., provides energy-related products and services | |
FESC | FirstEnergy Service Company, provides legal, financial and other corporate support services | |
FGCO | FirstEnergy Generation Corp., owns and operates non-nuclear generating facilities | |
FirstEnergy | FirstEnergy Corp., a public utility holding company | |
FSG | FirstEnergy Facilities Services Group, LLC, former 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 Funding | JCP&L Transition Funding LLC, a Delaware limited liability company and issuer of transition bonds | |
JCP&L Transition Funding II | JCP&L Transition Funding II 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., owns nuclear generating facilities | |
OE | Ohio Edison Company, an Ohio electric utility operating subsidiary | |
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 | |
Pennsylvania Companies | Met-Ed, Penelec and Penn | |
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 | TermobarranquillaTermobarranquila S.A., Empresa de Servicios Publicos | |
| | |
The following abbreviations and acronyms are used to identify frequently used terms in this report: | |
| | |
ALJAEP | Administrative Law JudgeAmerican Electric Power Company, Inc. | |
AOCL | Accumulated Other Comprehensive Loss | |
AQC | Air Quality Control | |
ARB | Accounting Research Bulletin | |
ARO | Asset Retirement Obligation | |
ASM | Ancillary Services Market | |
BGS | Basic Generation Service | |
BPJ | Best Professional Judgment | |
CAA | Clean Air Act | |
CAIR | Clean Air Interstate Rule | |
CAL | Confirmatory Action Letter | |
CAMR | Clean Air Mercury Rule | |
CBP | Competitive Bid Process | |
CO2 | Carbon Dioxide | |
DFI | Demand for Information |
DOJ | United States Department of Justice |
DRA | Division of Ratepayer Advocate |
ECO | Electro-Catalytic Oxidation |
ECAR | East Central Area Reliability Coordination Agreement |
EIS | Energy Independence Strategy |
EITF | Emerging Issues Task Force |
EITF 06-11EMP | EITF Issue No. 06-11, “Accounting for Income Tax Benefits of Dividends or Share-Based
Payment Awards” Energy Master Plan |
EPA | United States Environmental Protection Agency |
EPACT | Energy Policy Act of 2005 |
EROESP | Electric Reliability OrganizationSecurity Plan |
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 | FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143" |
| |
GLOSSARY OF TERMS, Cont’d.
FIN 48 | FIN 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109” |
FitchFirstCom | Fitch Ratings, Ltd.First Communications, Inc. |
GLOSSARY OF TERMS, Cont’d.
FMB | First Mortgage Bonds |
FSP | FASB Staff Position |
FSP FAS 157-2 | FSP FAS 157-2, “Effective Date of FASB Statement No. 157” |
FTR | Financial Transmission Rights |
GAAP | Accounting Principles Generally Accepted in the United States |
GHG | Greenhouse Gases |
ICE | Intercontinental Exchange |
IRS | Internal Revenue Service |
ISO | Independent System Operator |
kV | Kilovolt |
KWH | Kilowatt-hours |
LIBOR | London Interbank Offered Rate |
LOC | Letter of Credit |
MEIUG | Met-Ed Industrial Users Group |
MISO | Midwest Independent Transmission System Operator, Inc. |
Moody’s | Moody’s Investors Service |
MOUMRO | Memorandum of UnderstandingMarket Rate Offer |
MW | Megawatts |
NAAQS | National Ambient Air Quality Standards |
NERC | North American Electric Reliability Corporation |
NJBPU | New Jersey Board of Public Utilities |
NOAC | Northwest Ohio Aggregation Coalition |
NOPR | Notice of Proposed Rulemaking |
NOV | Notice of Violation |
NOX | Nitrogen Oxide |
NRC | Nuclear Regulatory Commission |
NSR | New Source Review |
NUG | Non-Utility Generation |
NUGC | Non-Utility Generation Charge |
NYMEX | New York Mercantile Exchange |
OCA | Office of Consumer Advocate |
OCCOTC | Office ofOver the Ohio Consumers’ CounselCounter |
OVEC | Ohio Valley Electric Corporation |
PCRB | Pollution Control Revenue Bond |
PICA | Penelec Industrial Customer Alliance |
PJM | PJM Interconnection L. L. C. |
PLR | Provider of Last Resort |
PPUC | Pennsylvania Public Utility Commission |
PRP | Potentially Responsible Party |
PSA | Power Supply Agreement |
PUCO | Public Utilities Commission of Ohio |
PUHCA | Public Utility Holding Company Act of 1935 |
RCP | Rate Certainty Plan | |
RECB | Regional Expansion Criteria and Benefits | |
RFP | Request for Proposal | |
RPM | Reliability Pricing Model | |
RSP | Rate Stabilization Plan | |
RTC | Regulatory Transition Charge | |
RTO | Regional Transmission Organization | |
RTOR | Regional Through and Out Rates | |
S&P | Standard & Poor’s Ratings Service | |
SBC | Societal Benefits Charge | |
SEC | U.S. Securities and Exchange Commission | |
SECA | Seams Elimination Cost Adjustment | |
SFAS | Statement of Financial Accounting Standards | |
SFAS 107 | SFAS No. 107, “Disclosure about Fair Value of Financial Instruments” | |
SFAS 109 | SFAS No. 109, “Accounting for Income Taxes” | |
SFAS 123(R) | SFAS No. 123(R), "Share-Based Payment" | |
SFAS 133 | SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” | |
SFAS 141(R) | SFAS No 141(R), “Business Combinations” | |
SFAS 143 | SFAS No. 143, “Accounting for Asset Retirement Obligations” | |
SFAS 157 | SFAS No. 157, “Fair Value Measurements” | |
SFAS 159 | SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115” | |
SFAS 160 | SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51” | |
SFAS 161 | SFAS No 161, “Disclosure about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133” | |
GLOSSARY OF TERMS, Cont’d.
SIP | State Implementation Plan(s) Under the Clean Air Act | |
SNCR | Selective Non-Catalytic Reduction | |
SO2 | Sulfur Dioxide | |
SRM | Special Reliability Master | |
TBC | Transition Bond Charge |
TMI-1 | Three Mile Island Unit 1 |
TMI-2 | Three Mile Island Unit 2 | |
UCSTSC | Union of Concerned Scientists | Transmission Service Charge |
VIE | Variable Interest Entity | |
PART I. FINANCIAL INFORMATION
ITEMS 1. AND 2. FINANCIAL STATEMENTS AND MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
FIRSTENERGY CORP.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EXECUTIVE SUMMARY
Net income in the first quarter of 2008 was $276 million, or basic earnings of $0.91 per share of common stock ($0.90 diluted), compared with net income of $290 million, or basic and diluted earnings of $0.92 per share in the first quarter of 2007. The decrease in FirstEnergy’s earnings was driven primarily by increased operating expenses, partially offset by increased revenues.
Change in Basic Earnings Per Share From Prior Year First Quarter | | |
| | |
Basic Earnings Per Share – First Quarter 2007 | $ 0.92 | |
Gain on non-core asset sales – 2008 | 0.06 | |
Saxton decommissioning regulatory asset – 2007 | (0.05) | |
Trust securities impairment | (0.02) | |
Revenues | 0.55 | |
Fuel and purchased power | (0.42) | |
Depreciation and amortization | (0.03) | |
Deferral of new regulatory assets | (0.03) | |
Energy Delivery O&M expenses | (0.03) | |
General taxes | (0.02) | |
Corporate-owned life insurance | (0.06) | |
Other expenses | 0.01 | |
Reduced common shares outstanding | 0.03 | |
Basic Earnings Per Share – First Quarter 2008 | $ 0.91 | |
Regulatory Matters - Ohio
Legislative Process
On April 22, 2008, an amended version of Substitute Senate Bill 221 (Substitute SB221) was passed by the Ohio House of Representatives and sent back to the Ohio Senate for concurrence. On April 23, 2008, the Ohio Senate approved the House's amendments to Substitute SB221 and forwarded the bill to the Governor for signature, which he signed on May 1, 2008. Amended Substitute SB221 requires all electric distribution utilities to file an RSP, now called an ESP, with the PUCO. An ESP is required to contain a proposal for the supply and pricing of retail generation. A utility could also simultaneously file an MRO in which it would have to demonstrate the following objective market criteria: The utility or its transmission service affiliate belongs to a FERC-approved RTO having a market-monitor function and the ability to mitigate market power, and a published source exists that identifies information for traded electricity and energy products that are contracted for delivery two years into the future. The PUCO would test the ESP and its pricing and all other terms and conditions against the MRO and may only approve the ESP if it is found to be more favorable to customers. As part of an ESP with a plan period longer than three years, the PUCO shall prospectively determine every fourth year of the plan whether it is substantially likely the plan will provide the electric distribution utility a return on common equity significantly in excess of the return likely to be earned by publicly traded companies, including utilities, that face comparable business and financial risk (comparable companies). If so, the PUCO may terminate the ESP. Annually under an ESP, the PUCO shall determine whether an electric distribution utility's earned return on common equity is significantly in excess of returns earned on common equity during the same period by comparable companies, and if so, shall require the utility to return such excess to customers by prospective adjustments. Amended Substitute SB221 also includes provisions dealing with advanced and renewable energy standards and energy efficiency, including requirements to meet annual benchmarks. FirstEnergy is currently evaluating this legislation and expects to file an ESP in the second or third quarter of 2008.
Distribution Rate Request
On February 25, 2008, evidentiary hearings concluded in the distribution rate requests for the Ohio Companies. The requests for $332 million in revenue increases were filed on June 7, 2007. Public hearings were held from March 5, 2008 through March 24, 2008. Main briefs were filed on March 28, 2008, and reply briefs were filed on April 18, 2008. The PUCO is expected to render its decision during the second or third quarter of 2008 (see Outlook – Ohio).
Regulatory Matters - Pennsylvania
Penn’s Interim Default Service Supply
On March 13, 2008, the PPUC approved the residential procurement process in Penn’s Joint Petition for Settlement. This RFP process calls for load-following, full-requirements contracts for default service procurement for residential customers for the period covering June 1, 2008 through May 31, 2011. The PPUC had previously approved the default service procurement processes for commercial and industrial customers. The default service procurement for small commercial customers was conducted through multiple RFPs, while the default service procurement for large commercial and industrial customers will utilize hourly pricing. Bids in the two RFPs for small commercial load were approved by the PPUC on February 22, 2008, and March 20, 2008. On March 28, 2008, Penn filed compliance tariffs with the new default service generation rates based on the approved RFP bids for small commercial customers which the PPUC then certified on April 4, 2008. On April 14, 2008, the first RFP for residential customers’ load was held consisting of tranches for both 12 and 24-month supply. The PPUC approved the bids on April 16, 2008. The second RFP is scheduled to be held on May 14, 2008, after which time the PPUC is expected to approve the new rates to go into effect June 1, 2008.
Met-Ed and Penelec Transmission Service Charge Filing
On April 14, 2008, Met-Ed and Penelec filed annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. The proposed TSCs include a component for under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and future transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed has proposed a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010.
Generation
Generation Output Record
FirstEnergy set a new first quarter generation output record of 20.4 million megawatt-hours, a 1.8% increase over the prior record established in the first quarter of 2006.
Refueling Outage
On April 14, 2008, Beaver Valley Unit 2 began its regularly scheduled refueling outage. During the outage, several improvement projects will take place on the 868-MW unit including replacing the high pressure turbine and inspecting the reactor vessel and other plant safety systems. Beaver Valley Unit 2 had operated for 520 consecutive days when it was taken off line for the outage.
Maintenance Outage
On April 14, 2008, the Perry Nuclear Power Plant returned to service following completion of a 10-day planned outage for valve work and other maintenance in preparation for the upcoming summer months.
Financial Matters
Acquisition of Additional Equity Interests in Beaver Valley Unit 2
On March 3, 2008, notice was given to the nine owner trusts that are lessors under sale and leaseback transactions, originally entered into by TE in 1987, that NGC would acquire the related 18.26% undivided interest in Beaver Valley Unit 2 through the exercise of the periodic purchase option provided for in the applicable facility leases. The purchase price to be paid by NGC for the undivided interest will be equal to the higher of a specified casualty value under the applicable facility leases (approximately $239 million in the aggregate for the equity portion of all nine facility leases) and the fair market sales value of such undivided interests. Determination of the fair market sales value may become subject to an appraisal procedure provided for in the lease documentation. An additional payment of approximately $236 million would be required to prepay in full the outstanding principal of, and accrued but unpaid interest on, the lessor notes of the nine owner trusts. Alternatively, this amount would not be paid as part of the aggregate purchase price if the lessor notes are instead assumed at the time of the exercise of the option. If NGC determines to prepay the notes, it is possible that the proceeds from such prepayment may not be sufficient to pay the principal of, and interest on, the bonds as they become due. If that is the case, NGC would provide a mechanism to address any such potential shortfall in a timely manner.
Repurchase and Remarketing of Auction Rate Bonds
Between February 27, 2008 and April 2, 2008, FirstEnergy’s subsidiaries repurchased all of their tax-exempt long-term PCRBs originally sold at auction rates ($530 million) in response to disruptions in the auction rate securities market. In February 2008, FGCO, NGC, Met-Ed and Penelec elected to convert all of their then outstanding auction rate PCRBs to a weekly rate mode, which required their mandatory purchase of these PCRBs on the applicable conversion dates. The companies initially funded the repurchase with short-term debt. On April 22, 2008, Met-Ed ($28.5 million) and Penelec ($45 million) successfully marketed their converted PCRBs in a variable-rate mode. Subject to market conditions, FGCO and NGC plan to remarket their converted PCRBs later in 2008, either in fixed-rate or variable-rate modes.
Non-Core Asset Sale
On March 7, 2008, FirstEnergy sold substantially all of the assets of FirstEnergy Telecom Services, Inc. to FirstCom for $45 million in cash, with FirstCom also assuming related liabilities. The sale resulted in an after-tax gain of approximately $0.06 per share. FirstEnergy is a 15.6% shareholder in FirstCom.
FIRSTENERGY’S BUSINESS
FirstEnergy is a diversified energy company headquartered in Akron, Ohio, that operates primarily through three core business segments (see Results of Operations).
· | Energy Delivery Services transmits and distributes electricity through FirstEnergy’s eight utility operating companies, serving 4.5 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey and purchases power for its PLR and default service requirements in Pennsylvania and New Jersey. This business segment derives its revenues principally from the delivery of electricity within FirstEnergy’s service areas at regulated rates, cost recovery of regulatory assets and the sale of electric generation service to retail customers who have not selected an alternative supplier (default service) in its Pennsylvania and New Jersey franchise areas. The segment’s net income reflects the commodity costs of securing electricity from FirstEnergy’s competitive energy services segment under partial requirements purchased power agreements with FES and from non-affiliated power suppliers, including, in each case, associated transmission costs. |
· | Competitive Energy Services supplies the electric power needs of end-use customers through retail and wholesale arrangements, including associated company power sales to meet all or a portion of the PLR and default service requirements of FirstEnergy’s Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Maryland and Michigan. This business segment owns or leases and operates 19 generating facilities with a net demonstrated capacity of approximately 13,664 MW and also purchases electricity to meet sales obligations. The segment's net income is primarily derived from affiliated company power sales and non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission and ancillary costs charged by PJM and MISO to deliver energy to the segment’s customers. |
· | Ohio Transitional Generation Services supplies the electric power needs of non-shopping customers under the default service requirements of the Ohio Companies. The segment's net income is primarily derived from electric generation sales revenues less the cost of power purchased from the competitive energy services segment through a full-requirements PSA arrangement with FES, including net transmission and ancillary costs charged by MISO to deliver energy to retail customers. |
RESULTS OF OPERATIONS
The financial results discussed below include revenues and expenses from transactions among FirstEnergy's business segments. A reconciliation of segment financial results is provided in Note 13 to the consolidated financial statements. Net income by major business segment was as follows:
| Three Months Ended | | | |
| March 31, | | Increase | |
| 2008 | | 2007 | | (Decrease) | |
Net Income | (In millions, except per share data) | |
By Business Segment | | | | | | |
| | $ | 179 | | | $ | 218 | | | $ | (39 | ) |
Competitive energy services | | | 87 | | | | 98 | | | | (11 | ) |
Ohio transitional generation services | | | 23 | | | | 24 | | | | (1 | ) |
Other and reconciling adjustments* | | | (13 | ) | | | (50 | ) | | | 37 | |
| | $ | 276 | | | $ | 290 | | | $ | (14 | ) |
| | | | | | | | | | | | |
| | $ | 0.91 | | | $ | 0.92 | | | $ | (0.01 | ) |
Diluted Earnings Per Share | | $ | 0.90 | | | $ | 0.92 | | | $ | (0.02 | ) |
* Consists primarily of interest expense related to holding company debt, corporate support services revenues and expenses, telecommunications services and elimination of intersegment transactions.
Summary of Results of Operations – First Quarter 2008 Compared with First Quarter 2007
Financial results for FirstEnergy's major business segments in the first three months of 2008 and 2007 were as follows:
| | | | | | | | Ohio | | | | | | | |
| | Energy | | | Competitive | | | Transitional | | | Other and | | | | |
| | Delivery | | | Energy | | | Generation | | | Reconciling | | | FirstEnergy | |
First Quarter 2008 Financial Results | | Services | | | Services | | | Services | | | Adjustments | | | Consolidated | |
| | (In millions) | |
Revenues: | | | | | | | | | | | | | | | |
External | | | | | | | | | | | | | | | |
Electric | | $ | 2,050 | | | $ | 289 | | | $ | 691 | | | $ | - | | | $ | 3,030 | |
Other | | | 162 | | | | 40 | | | | 16 | | | | 29 | | | | 247 | |
Internal | | | - | | | | 776 | | | | - | | | | (776 | ) | | | - | |
Total Revenues | | | 2,212 | | | | 1,105 | | | | 707 | | | | (747 | ) | | | 3,277 | |
| | | | | | | | | | | | | | | | | | | | |
Expenses: | | | | | | | | | | | | | | | | | | | | |
Fuel and purchased power | | | 983 | | | | 533 | | | | 588 | | | | (776 | ) | | | 1,328 | |
Other operating expenses | | | 445 | | | | 309 | | | | 77 | | | | (31 | ) | | | 800 | |
Provision for depreciation | | | 106 | | | | 53 | | | | - | | | | 5 | | | | 164 | |
Amortization of regulatory assets | | | 249 | | | | - | | | | 9 | | | | - | | | | 258 | |
Deferral of new regulatory assets | | | (100 | ) | | | - | | | | (5 | ) | | | - | | | | (105 | ) |
General taxes | | | 173 | | | | 32 | | | | 1 | | | | 9 | | | | 215 | |
Total Expenses | | | 1,856 | | | | 927 | | | | 670 | | | | (793 | ) | | | 2,660 | |
| | | | | | | | | | | | | | | | | | | | |
Operating Income | | | 356 | | | | 178 | | | | 37 | | | | 46 | | | | 617 | |
Other Income (Expense): | | | | | | | | | | | | | | | | | | | | |
Investment income | | | 45 | | | | (6 | ) | | | 1 | | | | (23 | ) | | | 17 | |
Interest expense | | | (103 | ) | | | (34 | ) | | | - | | | | (42 | ) | | | (179 | ) |
Capitalized interest | | | - | | | | 7 | | | | - | | | | 1 | | | | 8 | |
Total Other Income (Expense) | | | (58 | ) | | | (33 | ) | | | 1 | | | | (64 | ) | | | (154 | ) |
| | | | | | | | | | | | | | | | | | | | |
Income Before Income Taxes | | | 298 | | | | 145 | | | | 38 | | | | (18 | ) | | | 463 | |
Income taxes | | | 119 | | | | 58 | | | | 15 | | | | (5 | ) | | | 187 | |
Net Income | | $ | 179 | | | $ | 87 | | | $ | 23 | | | $ | (13 | ) | | $ | 276 | |
| | | | | | | | Ohio | | | | | | | |
| | Energy | | | Competitive | | | Transitional | | | Other and | | | | |
| | Delivery | | | Energy | | | Generation | | | Reconciling | | | FirstEnergy | |
First Quarter 2007 Financial Results | | Services | | | Services | | | Services | | | Adjustments | | | Consolidated | |
| | (In millions) | |
Revenues: | | | | | | | | | | | | | | | |
External | | | | | | | | | | | | | | | |
Electric | | $ | 1,875 | | | $ | 276 | | | $ | 613 | | | $ | - | | | $ | 2,764 | |
Other | | | 165 | | | | 45 | | | | 6 | | | | (7 | ) | | | 209 | |
Internal | | | - | | | | 714 | | | | - | | | | (714 | ) | | | - | |
Total Revenues | | | 2,040 | | | | 1,035 | | | | 619 | | | | (721 | ) | | | 2,973 | |
| | | | | | | | | | | | | | | | | | | | |
Expenses: | | | | | | | | | | | | | | | | | | | | |
Fuel and purchased power | | | 844 | | | | 447 | | | | 544 | | | | (714 | ) | | | 1,121 | |
Other operating expenses | | | 408 | | | | 300 | | | | 49 | | | | (8 | ) | | | 749 | |
Provision for depreciation | | | 98 | | | | 51 | | | | - | | | | 7 | | | | 156 | |
Amortization of regulatory assets | | | 246 | | | | - | | | | 5 | | | | - | | | | 251 | |
Deferral of new regulatory assets | | | (124 | ) | | | - | | | | (20 | ) | | | - | | | | (144 | ) |
General taxes | | | 165 | | | | 28 | | | | 2 | | | | 8 | | | | 203 | |
Total Expenses | | | 1,637 | | | | 826 | | | | 580 | | | | (707 | ) | | | 2,336 | |
| | | | | | | | | | | | | | | | | | | | |
Operating Income | | | 403 | | | | 209 | | | | 39 | | | | (14 | ) | | | 637 | |
Other Income (Expense): | | | | | | | | | | | | | | | | | | | | |
Investment income | | | 70 | | | | 3 | | | | 1 | | | | (41 | ) | | | 33 | |
Interest expense | | | (109 | ) | | | (52 | ) | | | (1 | ) | | | (23 | ) | | | (185 | ) |
Capitalized interest | | | 2 | | | | 3 | | | | - | | | | - | | | | 5 | |
Total Other income (Expense) | | | (37 | ) | | | (46 | ) | | | - | | | | (64 | ) | | | (147 | ) |
| | | | | | | | | | | | | | | | | | | | |
Income Before Income Taxes | | | 366 | | | | 163 | | | | 39 | | | | (78 | ) | | | 490 | |
Income taxes | | | 148 | | | | 65 | | | | 15 | | | | (28 | ) | | | 200 | |
Net Income | | $ | 218 | | | $ | 98 | | | $ | 24 | | | $ | (50 | ) | | $ | 290 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Changes Between First Quarter 2008 and | | | | | | | | | | | | | | | | | | | | |
First Quarter 2007 Financial Results | | | | | | | | | | | | | | | | | | | | |
Increase (Decrease) | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Revenues: | | | | | | | | | | | | | | | | | | | | |
External | | | | | | | | | | | | | | | | | | | | |
Electric | | $ | 175 | | | $ | 13 | | | $ | 78 | | | $ | - | | | $ | 266 | |
Other | | | (3 | ) | | | (5 | ) | | | 10 | | | | 36 | | | | 38 | |
Internal | | | - | | | | 62 | | | | - | | | | (62 | ) | | | - | |
Total Revenues | | | 172 | | | | 70 | | | | 88 | | | | (26 | ) | | | 304 | |
| | | | | | | | | | | | | | | | | | | | |
Expenses: | | | | | | | | | | | | | | | | | | | | |
Fuel and purchased power | | | 139 | | | | 86 | | | | 44 | | | | (62 | ) | | | 207 | |
Other operating expenses | | | 37 | | | | 9 | | | | 28 | | | | (23 | ) | | | 51 | |
Provision for depreciation | | | 8 | | | | 2 | | | | - | | | | (2 | ) | | | 8 | |
Amortization of regulatory assets | | | 3 | | | | - | | | | 4 | | | | - | | | | 7 | |
Deferral of new regulatory assets | | | 24 | | | | - | | | | 15 | | | | - | | | | 39 | |
General taxes | | | 8 | | | | 4 | | | | (1 | ) | | | 1 | | | | 12 | |
Total Expenses | | | 219 | | | | 101 | | | | 90 | | | | (86 | ) | | | 324 | |
| | | | | | | | | | | | | | | | | | | | |
Operating Income | | | (47 | ) | | | (31 | ) | | | (2 | ) | | | 60 | | | | (20 | ) |
Other Income (Expense): | | | | | | | | | | | | | | | | | | | | |
Investment income | | | (25 | ) | | | (9 | ) | | | - | | | | 18 | | | | (16 | ) |
Interest expense | | | 6 | | | | 18 | | | | 1 | | | | (19 | ) | | | 6 | |
Capitalized interest | | | (2 | ) | | | 4 | | | | - | | | | 1 | | | | 3 | |
Total Other Income (Expense) | | | (21 | ) | | | 13 | | | | 1 | | | | - | | | | (7 | ) |
| | | | | | | | | | | | | | | | | | | | |
Income Before Income Taxes | | | (68 | ) | | | (18 | ) | | | (1 | ) | | | 60 | | | | (27 | ) |
Income taxes | | | (29 | ) | | | (7 | ) | | | - | | | | 23 | | | | (13 | ) |
Net Income | | $ | (39 | ) | | $ | (11 | ) | | $ | (1 | ) | | $ | 37 | | | $ | (14 | ) |
Energy Delivery Services – First Quarter 2008 Compared with First Quarter 2007
Net income decreased $39 million to $179 million in the first three months of 2008 compared to $218 million in the first three months of 2007, primarily due to higher operating expenses partially offset by increased revenues.
Revenues –
The increase in total revenues resulted from the following sources:
| | Three Months Ended | | | |
| | March 31, | | Increase | |
Revenues by Type of Service | | 2008 | | 2007 | | (Decrease) | |
| | (In millions) | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | ) |
| | | | | | | | | | |
The change in distribution deliveries by customer class is summarized in the following table:
Electric Distribution KWH Deliveries | | | |
| | | | |
| | | | |
| | | | |
Total Distribution KWH Deliveries | | | | |
The increase in electric distribution deliveries to customers was primarily due to increased weather-related usage in the Ohio Companies’ and Penn’s service territories during the first three months of 2008 compared to the same period of 2007 (heating degree days increased 2.4%). The higher revenues from increased distribution deliveries were partially offset by the residual effects of the distribution rate decreases for Met-Ed and Penelec as a result of a January 11, 2007 PPUC rate decision (see Outlook – State Regulatory Matters – Pennsylvania).
The following table summarizes the price and volume factors contributing to the $157 million increase in generation revenues in the first quarter of 2008 compared to the first quarter of 2007:
Sources of Change in Generation Revenues | | | |
| | (In millions) | |
Retail: | | | | |
Effect of 0.7% decrease in sales volumes | | $ | (5 | ) |
Change in prices | | | | |
| | | | |
Wholesale: | | | | |
Effect of 8.9% increase in sales volumes | | | 12 | |
Change in prices | | | | |
| | | | |
Net Increase in Generation Revenues | | $ | 157 | |
The decrease in retail generation sales volumes was primarily due to an increase in customer shopping in Penn’s and JCP&L’s service territories in the first three months of 2008. The increase in retail generation prices during the first three months of 2008 reflected increased generation rates for JCP&L resulting from the New Jersey BGS auction process and an increase in NUGC rates authorized by the NJBPU. Wholesale generation sales increased principally as a result of Met-Ed and Penelec selling additional available power into the PJM market. The increase in prices reflected higher spot market prices for PJM market participants.
Transmission revenues increased $14 million primarily due to higher transmission rates for Met-Ed and Penelec resulting from the January 2007 PPUC authorization of transmission cost recovery. Met-Ed and Penelec defer the difference between revenues from their transmission rider and transmission costs incurred with no material effect on current period earnings (see Outlook – State Regulatory Matters – Pennsylvania).
Expenses –
The increases in revenues discussed above were offset by a $219 million increase in expenses due to the following:
| · | Purchased power costs were $139 million higher in the first three months of 2008 due to higher unit costs and a decrease in the amount of NUG costs deferred. The increased unit costs reflected the effect of higher JCP&L costs resulting from the BGS auction process. 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 NUGC rates and market sales of NUG energy and capacity. The following table summarizes the sources of changes in purchased power costs: |
Source of Change in Purchased Power | | Increase (Decrease) | |
| | (In millions) | |
Purchases from non-affiliates: | | | | |
Change due to increased unit costs | | $ | 84 | |
Change due to decreased volumes | | | (18 | ) |
| | | 66 | |
Purchases from FES: | | | | |
Change due to decreased unit costs | | | (4 | ) |
Change due to increased volumes | | | 17 | |
| | | 13 | |
| | | | |
Decrease in NUG costs deferred | | | 60 | |
Net Increase in Purchased Power Costs | | $ | 139 | |
| · | Other operating expenses increased $37 million due primarily to the effects of: |
- | An increase of $15 million in MISO and PJM transmission expenses, resulting primarily from higher congestion costs (see transmission revenues discussion above). |
- | An increase in operation and maintenance expenses of $11 million for storm restoration work during the first quarter of 2008. |
- | An increase in labor expenses of $9 million primarily due to an increase in the number of employees in the first quarter of 2008 compared to 2007 as a result of the segment’s workforce initiatives. |
| · | An increase of $3 million in amortization of regulatory assets compared to 2007 due primarily to recovery of deferred BGS costs through higher NUGC rates for JCP&L. |
| · | The deferral of new regulatory assets during the first three months of 2008 was $24 million lower primarily due to the absence of the deferral in 2007 of decommissioning costs related to the Saxton nuclear research facility. |
| | · | Depreciation expense increased $8 million due to property additions since the first quarter of 2007. |
| | · | General taxes increased $8 million due to higher property taxes and gross receipts taxes. |
Other Expense –
FIRSTENERGY CORP.Other expense increased $21 million in 2008 compared to the first three months of 2007 primarily due to lower investment income of $25 million resulting from the repayment of notes receivable from affiliates since the first quarter of 2007, partially offset by lower interest expense (net of capitalized interest) of $4 million.
Competitive Energy Services – First Quarter 2008 Compared with First Quarter 2007
Net income for this segment was $87 million in the first three months of 2008 compared to $98 million in the same period in 2007. The $11 million reduction in net income reflects a decrease in gross generation margin and higher operating costs which were partially offset by lower interest expense.
Revenues –
Total revenues increased $70 million in the first three months of 2008 compared to the same period in 2007. This increase primarily resulted from higher unit prices on affiliated generation sales to the Ohio Companies and increased non-affiliated wholesale sales, which were partially offset by lower retail sales.
The increase in reported segment revenues resulted from the following sources:
| | Three Months Ended | | | |
| | March 31, | | Increase | |
Revenues by Type of Service | | 2008 | | 2007 | | (Decrease) | |
| | (In millions) | |
Non-Affiliated Generation Sales: | | | | | | | |
| | | | | | | | | | ) |
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Total Non-Affiliated Generation Sales | | | | | | | | | | |
Affiliated Generation Sales | | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | ) |
| | | | | | | | | | |
The lower retail revenues resulted from decreased sales in the PJM market, partially offset by increased sales in the MISO market. The decrease in PJM retail sales is primarily the result of lower contract renewals for commercial and industrial customers. The increase in MISO retail sales is primarily the result of capturing more shopping customers in Penn’s service territory, partially offset by lower customer usage. Higher non-affiliated wholesale revenues resulted from the effect of increased generation available for the non-affiliated wholesale market.
The increased affiliated company generation revenues were due to increased sales volumes and higher unit prices for the Ohio Companies, partially offset by lower unit prices for the Pennsylvania Companies. The increase in PSA sales to the Ohio Companies was due to their higher retail generation sales requirements. The higher unit prices reflected increases in the Ohio Companies’ retail generation rates. The higher sales to the Pennsylvania Companies were due to increased Met-Ed and Penelec generation sales requirements. These increases were partially offset by lower sales to Penn due to a 45% increase in customer shopping in the first quarter of 2008 compared to the first quarter of 2007.
The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:
Source of Change in Non-Affiliated Generation Revenues | | | |
| | (In millions) | |
Retail: | | | | |
Effect of 9.0% decrease in sales volumes | | $ | (16 | ) |
Change in prices | | | | |
| | | | ) |
Wholesale: | | | | |
Effect of 3.5% increase in sales volumes | | | 4 | |
Change in prices | | | | |
| | | | |
Net Increase in Non-Affiliated Generation Revenues | | | | |
Source of Change in Affiliated Generation Revenues | | | |
| | (In millions) | |
Ohio Companies: | | | | |
Effect of 1.2% increase in sales volumes | | $ | 6 | |
Change in prices | | | | |
| | | | |
Pennsylvania Companies: | | | | |
Effect of 9.0% increase in sales volumes | | | 16 | |
Change in prices | | | | ) |
| | | | |
Net Increase in Affiliated Generation Revenues | | | | |
Transmission revenues increased $10 million due to increased retail load in the MISO market and higher transmission rates ($12 million), partially offset by reduced financial transmission rights auction revenue ($2 million). Other revenue decreased $14 million primarily due to lower interest income from short-term investments.
Expenses -
Total expenses increased $101 million in the first three months of 2008 due to the following factors:
| · | Fossil fuel costs increased $68 million due to increased generation volumes ($37 million) and higher unit prices ($31 million). The increased unit prices primarily reflect higher coal transportation costs ($24 million) and increased emission allowance costs ($5 million) in the first quarter of 2008. |
| · | Purchased power costs increased $20 million due primarily to higher market rates, partially offset by reduced volume requirements due to increased generation from internal resources. |
| · | Nuclear operating costs increased $23 million due to this year’s Davis-Besse refueling outage and the preparatory work associated with the Beaver Valley Unit 2 refueling outage scheduled for the second quarter of 2008. |
| · | Other expense increased $15 million due primarily to the assignment of CEI’s and TE’s leasehold interests in the Bruce Mansfield Plant to FGCO in the fourth quarter of 2007 ($7 million) and reduced earnings on life insurance investments during the first quarter of 2008 ($6 million). |
| · | Higher depreciation expenses of $2 million were due to property additions since the first quarter of 2007. |
| · | Higher general taxes of $4 million resulted from increased gross receipts taxes and property taxes. |
Partially offsetting the higher costs were:
| · | Fossil operating costs were $23 million lower due to fewer outages in 2008 compared to 2007 and increased gains on emission allowance sales. |
| · | Transmission expense declined $7 million due to reduced PJM congestion charges and a change in MISO revenue sufficiency guarantee settlements. |
Other Expense –
Total other expense in the first three months of 2008 was $13 million lower than the first quarter of 2007, primarily due to a decline in interest expense (net of capitalized interest) of $22 million due to the repayment of notes payable to affiliates since the first quarter of 2007 and a $2 million increase in earnings from nuclear decommissioning trust investments, partially offset by an $11 million increase in trust securities impairments.
Ohio Transitional Generation Services – First Quarter 2008 Compared with First Quarter 2007
Net income for this segment decreased to $23 million in the first three months of 2008 from $24 million in the same period of 2007. Higher operating expenses, primarily for purchased power, were almost entirely offset by higher generation revenues.
Revenues –
The increase in reported segment revenues resulted from the following sources:
| | Three Months Ended | | | |
| | March 31, | | | |
Revenues by Type of Service | | 2008 | | 2007 | | Increase | |
| | (In millions) | |
| | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
The following table summarizes the price and volume factors contributing to the increase in sales revenues from retail customers:
Source of Change in Retail Generation Revenues | | | |
| | (In millions) | |
Effect of 1.3% increase in sales volumes | | $ | 7 | |
Change in prices | | | | |
Total Increase in Retail Generation Revenues | | | | |
The increase in generation sales was primarily due to higher weather-related usage in the first three months of 2008 compared to the same period of 2007 and reduced customer shopping. Heating degree days in OE’s, CEI’s and TE’s service territories increased by 2.8%, 1.7% and 3.3%, respectively. Average prices increased primarily due to an increase in the Ohio Companies’ fuel cost recovery rider that became effective in January 2008. The percentage of generation services provided by alternative suppliers to total sales delivered by the Ohio Companies in their service areas decreased by 1.8 percentage points from the same period in 2007.
Increased transmission revenue resulted from higher sales volumes ($7 million) and a PUCO-approved transmission tariff increase ($15 million) that became effective July 1, 2007.
Expenses -
Purchased power costs were $44 million higher due primarily to higher unit costs for power purchased from FES. The factors contributing to the higher costs are summarized in the following table:
Source of Change in Purchased Power | | Increase (Decrease) | |
| | (In millions) | |
Purchases from non-affiliates: | | | | |
Change due to increased unit costs | | $ | (5 | ) |
Change due to decreased volumes | | | (1 | ) |
| | | (6 | ) |
Purchases from FES: | | | | |
Change due to increased unit costs | | | 44 | |
Change due to increased volumes | | | 6 | |
| | | 50 | |
Net Increase in Purchased Power Costs | | $ | 44 | |
The increase in purchase volumes from FES was due to the higher retail generation sales requirements described above. The higher unit costs reflect the increases in the Ohio Companies’ retail generation rates, as provided for under the PSA with FES.
Other operating expenses increased $28 million due in part to MISO transmission-related expenses ($12 million). The difference between transmission revenues accrued and transmission expenses incurred is deferred, resulting in no material impact to current period earnings. The remainder of the increase resulted from lower associated company cost reimbursements related to the Ohio Companies’ generation leasehold interests.
Other – First Quarter 2008 Compared with First Quarter 2007
FirstEnergy’s financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a $37 million increase in FirstEnergy’s net income in the first three months of 2008 compared to the same period in 2007. The increase resulted from the sale of telecommunication assets ($19 million, net of taxes), reduced short-term disability costs ($8 million) and reduced interest expense ($11 million) associated with FirstEnergy’s revolving credit facility.
CAPITAL RESOURCES AND SUBSIDIARIESLIQUIDITY
FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. In 2008 and in subsequent years, FirstEnergy expects to satisfy these requirements with a combination of cash from operations and funds from the capital markets. FirstEnergy also expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements during those periods.
As of March 31, 2008, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was principally due to the initial short-term funding of the repurchase of certain auction rate bonds described below and the classification of certain variable interest rate PCRBs as currently payable long-term debt. The PCRBs currently permit individual debt holders to put the respective debt back to the issuer for purchase prior to maturity.
Changes in Cash Position
FirstEnergy's primary source of cash required for continuing operations as a holding company is cash from the operations of its subsidiaries. FirstEnergy and certain of its subsidiaries also have access to $2.75 billion of short-term financing under a revolving credit facility which expires in 2012. Under the terms of the facility, FirstEnergy is permitted to have up to $1.5 billion in outstanding borrowings at any time, subject to the facility cap of $2.75 billion of aggregate outstanding borrowings by it and its subsidiaries that are also parties to such facility. In the first three months of 2008, FirstEnergy received $88 million of cash dividends from its subsidiaries and paid $168 million in cash dividends to common shareholders. With the exception of Met-Ed, which is currently in an accumulated deficit position, there are no material restrictions on the payment of cash dividends by the subsidiaries of FirstEnergy.
As of March 31, 2008, FirstEnergy had $70 million of cash and cash equivalents compared with $129 million as of December 31, 2007. The major sources of 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 energy delivery services and competitive energy services businesses (see Results of Operations above). Net cash provided from operating activities was $356 million in the first three months of 2008 compared to $57 million used for operating activities in the first three months of 2007, as summarized in the following table:
| | Three Months Ended | |
| | March 31, | |
| | 2008 | | 2007 | |
| | (In millions) | |
Net income | | $ | 276 | | $ | 290 | |
Non-cash charges | | | 203 | | | 125 | |
Pension trust contribution | | | - | | | (300 | ) |
Working capital and other | | | (123 | ) | | (172 | ) |
| | $ | 356 | | $ | (57 | ) |
Net cash provided from operating activities increased by $413 million in the first three months of 2008 compared to the first three months of 2007 primarily due to the absence of a $300 million pension trust contribution in 2007, a $78 million increase in non-cash charges and a $49 million increase from working capital and other changes, partially offset by a $14 million decrease in net income (see Results of Operations above). The increase in non-cash charges is primarily due to lower deferrals of new regulatory assets and deferred purchased power costs. The deferral of new regulatory assets decreased primarily as a result of the absence of the deferral of decommissioning costs related to the Saxton nuclear research facility in the first quarter of 2007. Deferred purchased power costs decreased as a result of lower deferred NUG costs. The changes in working capital and other primarily resulted from a $149 million change in the collection of receivables and an $85 million change in the settlement of accounts payable, partially offset by increased tax payments compared to the first three months of 2007.
Cash Flows From Financing Activities
In the first three months of 2008, cash provided from financing activities was $227 million compared to $346 million in the first three months of 2007. The decrease was primarily due to lower short-term borrowings and debt issuances in the first quarter of 2008, partially offset by redemption of common stock in the first quarter of 2007. The following table summarizes security issuances and redemptions.
| | Three Months Ended | |
| | March 31, | |
Securities Issued or Redeemed | | 2008 | | 2007 | |
| | (In millions) | |
New issues | | | | | |
Unsecured notes | | $ | - | | $ | 250 | |
| | | | | | | |
Redemptions | | | | | | | |
Pollution control notes(1) | | $ | 362 | | $ | - | |
Senior secured notes | | | 6 | | | 13 | |
Common stock | | | - | | | 891 | |
| | $ | 368 | | $ | 904 | |
| | | | | | | |
Short-term borrowings, net | | $ | 746 | | $ | 1,139 | |
| | | | | | | |
(1) Includes the repurchase of certain auction rate PCRBs described below, which were extinguished from FirstEnergy’s consolidated balance sheet. | |
FirstEnergy had approximately $1.6 billion of short-term indebtedness as of March 31, 2008 compared to approximately $903 million as of December 31, 2007. Available bank borrowing capability as of March 31, 2008 included the following:
Borrowing Capability (In millions) | | | |
Short-term credit facilities(1) | | $ | 2,870 | |
Accounts receivable financing facilities | | | 550 | |
Utilized | | | (1,646 | ) |
LOCs | | | (60 | ) |
Net available capability | | $ | 1,714 | |
| | | | |
(1) Includes the $2.75 billion revolving credit facility described below, a $100 million revolving credit facility that expires in December 2009 and a $20 million uncommitted line of credit. |
As of March 31, 2008, the Ohio Companies and Penn had the aggregate capability to issue approximately $3.4 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMB by OE, CEI and TE is 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, CEI and TE to incur additional secured debt not otherwise permitted by a specified exception of up to $573 million, $449 million and $121 million, respectively, as of March 31, 2008.
The applicable earnings coverage tests in the respective charters of OE, TE, Penn and JCP&L are currently inoperative. In the event that any of them issues preferred stock in the future, the applicable earnings coverage test will govern the amount of preferred stock that may be issued. CEI, Met-Ed and Penelec do not have similar restrictions and could issue up to the number of preferred shares authorized under their respective charters.
As of March 31, 2008, FirstEnergy had approximately $1.0 billion of remaining unused capacity under an existing shelf registration statement filed with the SEC in 2003 to support future securities issuances. The shelf registration expires in December 2008 and 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. As of March 31, 2008, OE had approximately $400 million of remaining unused capacity under a shelf registration for unsecured debt securities filed with the SEC in 2006 that expires in April 2009.
FirstEnergy and certain of its subsidiaries are party to a $2.75 billion five-year revolving credit facility (included in the borrowing capability table above). FirstEnergy has the capability to request an increase in the total commitments available under this facility up to a maximum of $3.25 billion. Commitments under the facility are available until August 24, 2012, unless the lenders agree, at the request of the borrowers, to an unlimited number of additional one-year extensions. Generally, borrowings under the facility must be repaid within 364 days. Available amounts for each borrower are subject to a specified sub-limit, as well as applicable regulatory and other limitations.
The following table summarizes the borrowing sub-limits for each borrower under the facility, as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations:
| | Revolving | | Regulatory and | |
| | Credit Facility | | Other Short-Term | |
| | | | | |
| | (In millions) | |
FirstEnergy | | $ | 2,750 | | $ | - | (2) |
OE | | | 500 | | | 500 | |
Penn | | | 50 | | | 39 | (3) |
CEI | | | 250 | (4) | | 500 | |
TE | | | 250 | (4) | | 500 | |
JCP&L | | | 425 | | | 428 | (3) |
Met-Ed | | | 250 | | | 300 | (3) |
Penelec | | | 250 | | | 300 | (3) |
FES | | | 1,000 | | | - | (2) |
ATSI | | | - | (5) | | 50 | |
| | | | | | | |
(1)As of March 31, 2008. (2)No regulatory approvals, statutory or charter limitations applicable. (3)Excluding amounts which may be borrowed under the regulated companies’ money pool. (4)Borrowing sub-limits for CEI and TE may be increased to up to $500 million by delivering notice to the administrative agent that such borrower has senior unsecured debt ratings of at least BBB by S&P and Baa2 by Moody’s. (5)The borrowing sub-limit for ATSI may be increased up to $100 million by delivering notice to the administrative agent that either (i) ATSI has senior unsecured debt ratings of at least BBB- by S&P and Baa3 by Moody’s or (ii) FirstEnergy has guaranteed ATSI’s obligations of such borrower under the facility. |
The revolving credit facility, combined with an aggregate $550 million (unused as of March 31, 2008) of accounts receivable financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn, are intended to provide liquidity to meet working capital requirements and for other general corporate purposes for FirstEnergy and its subsidiaries.
Under the revolving credit facility, borrowers may request the issuance of LOCs expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit.
The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter. As of March 31, 2008, FirstEnergy’s and its subsidiaries' debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:
Borrower | | |
FirstEnergy | | 58 | % |
OE | | 43 | % |
Penn | | 25 | % |
CEI | | 57 | % |
TE | | 42 | % |
JCP&L | | 30 | % |
Met-Ed | | 47 | % |
Penelec | | 49 | % |
FES | | 61 | % |
The revolving credit facility does not contain provisions that either restrict the ability to borrow or accelerate repayment of outstanding advances as a result of any change in credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds borrowed under the facility is related to the credit ratings of the company borrowing the funds.
FirstEnergy's regulated companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy's unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first three months of 2008 was 3.62% for the regulated companies’ money pool and 3.55% for the unregulated companies��� money pool.
FirstEnergy’s access to capital markets and costs of financing are influenced by the ratings of its securities. The following table displays FirstEnergy’s, FES’ and the Companies’ securities ratings as of March 31, 2008. S&P’s outlook of FirstEnergy and its subsidiaries remains negative and Moody’s outlook for FirstEnergy and its subsidiaries remains stable.
| | | | | | |
| | | | | | |
FirstEnergy | | Senior unsecured | | BBB- | | Baa3 |
| | | | | | |
FES | | Senior unsecured | | BBB | | Baa2 |
| | | | | | |
OE | | Senior unsecured | | BBB- | | Baa2 |
| | | | | | |
CEI | | Senior secured | | BBB+ | | Baa2 |
| | Senior unsecured | | BBB- | | Baa3 |
| | | | | | |
TE | | Senior unsecured | | BBB- | | Baa3 |
| | | | | | |
Penn | | Senior secured | | A- | | Baa1 |
| | | | | | |
JCP&L | | Senior unsecured | | BBB | | Baa2 |
| | | | | | |
Met-Ed | | Senior unsecured | | BBB | | Baa2 |
| | | | | | |
Penelec | | Senior unsecured | | BBB | | Baa2 |
Between February 27, 2008 and April 2, 2008, FirstEnergy’s subsidiaries repurchased all of their tax-exempt long-term PCRBs originally sold at auction rates ($530 million) in response to disruptions in the auction rate securities market. In February 2008, FGCO, NGC, Met-Ed and Penelec elected to convert all of their then outstanding auction rate PCRBs to a weekly rate mode, which required their mandatory purchase of these PCRBs on the applicable conversion dates. The companies initially funded the repurchase with short-term debt. On April 22, 2008, Met-Ed ($28.5 million) and Penelec ($45 million) successfully marketed their converted PCRBs in a variable-rate mode. Subject to market conditions, FGCO and NGC plan to remarket their converted PCRBs later in 2008, either in fixed-rate or variable-rate modes.
Cash Flows From Investing Activities
Net cash flows used in investing activities resulted principally from property additions. Energy delivery services property additions primarily include expenditures related to transmission and distribution facilities. Capital spending by the competitive energy services segment are principally generation-related. The following table summarizes investing activities for the three months ended March 31, 2008 and 2007 by business segment:
Summary of Cash Flows | | Property | | | | | | | |
Provided from (Used for) Investing Activities | | Additions | | Investments | | Other | | Total | |
Sources (Uses) | | (In millions) | |
Three Months Ended March 31, 2008 | | | | | | | | | |
| | | | | | | | | | | | | |
Competitive energy services | | | | | | | | | | ) | | | |
| | | | | | | | | | | | | |
Inter-Segment reconciling items | | | | | | | ) | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Three Months Ended March 31, 2007 | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Competitive energy services | | | | | | | | | | ) | | | |
| | | | | | | | | | ) | | | |
Inter-Segment reconciling items | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Net cash used for investing activities in the first quarter of 2008 increased by $352 million compared to the first quarter of 2007. The increase was principally due to a $415 million increase in property additions, which reflects AQC system expenditures and the acquisition of a partially completed natural gas fired generating plant in Fremont, Ohio. Partially offsetting the increase in property additions were cash proceeds from the sale of telecommunication assets.
During the remaining three quarters of 2008, capital requirements for property additions and capital leases are expected to be approximately $1.4 billion. FirstEnergy and the Companies have additional requirements of approximately $328 million for maturing long-term debt during the remainder of 2008. These cash requirements are expected to be satisfied from a combination of internal cash, short-term credit arrangements and funds raised in the capital markets.
FirstEnergy's capital spending for the period 2008-2012 is expected to be approximately $7.6 billion (excluding nuclear fuel), of which approximately $2.0 billion applies to 2008. Investments for additional nuclear fuel during the 2008-2012 period are estimated to be approximately $1.4 billion, of which about $150 million applies to 2008. During the same period, FirstEnergy's nuclear fuel investments are expected to be reduced by approximately $949 million and $111 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. These agreements include contract guarantees, surety bonds and LOCs. Some of the guaranteed contracts contain collateral provisions that are contingent upon FirstEnergy’s credit ratings.
As of March 31, 2008, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $4.4 billion, as summarized below:
| | Maximum | |
Guarantees and Other Assurances | | | |
| | (In millions) | |
FirstEnergy Guarantees of Subsidiaries | | | |
Energy and Energy-Related Contracts (1) | | $ | 441 | |
LOC (long-term debt) – interest coverage (2) | | | 6 | |
Other (3) | | | 503 | |
| | | 950 | |
| | | | |
Subsidiaries’ Guarantees | | | | |
Energy and Energy-Related Contracts | | | 86 | |
LOC (long-term debt) – interest coverage (2) | | | 6 | |
Other (4) | | | 2,641 | |
| | | 2,733 | |
| | | | |
Surety Bonds | | | 66 | |
LOC (long-term debt) – interest coverage (2) | | | 5 | |
LOC (non-debt) (5)(6) | | | 679 | |
| | | 750 | |
Total Guarantees and Other Assurances | | $ | 4,433 | |
| (1) | Issued for open-ended terms, with a 10-day termination right by FirstEnergy. |
| (2) | Reflects the interest coverage portion of LOCs issued in support of floating-rate pollution control revenue bonds with various maturities. The principal amount of floating-rate pollution control revenue bonds of $1.6 billion is reflected in debt on FirstEnergy’s consolidated balance sheets. |
| (3) | Includes guarantees of $300 million for OVEC obligations and $80 million for nuclear decommissioning funding assurances. |
| (4) | Includes FES’ guarantee of FGCO’s obligations under the sale and leaseback of Bruce Mansfield Unit 1. |
| (5) | Includes $60 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facility. |
| (6) | 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 a nd leaseback of Beaver Valley Unit 2 by OE and $134 million pledged in connection with the sale and leaseback of Perry Unit 1 by OE. |
FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for the financing or refinancing by subsidiaries of costs related to 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 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 other FirstEnergy assets. The likelihood is remote that such parental guarantees will increase amounts otherwise paid by FirstEnergy to meet its obligations incurred in connection with ongoing energy and energy-related activities.
While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event”, the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. As of March 31, 2008, FirstEnergy’s maximum exposure under these collateral provisions was $440 million.
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 $2 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 ($19 million as of March 31, 2008), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA.
OFF-BALANCE SHEET ARRANGEMENTS
FES and the Ohio Companies have obligations that are not included on FirstEnergy’s Consolidated Balance Sheets related to sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are satisfied through operating lease payments. As of March 31, 2008, the present value of these sale and leaseback operating lease commitments, net of trust investments, totaled $2.4 billion.
FirstEnergy has equity ownership interests in certain businesses that are accounted for using the equity method of accounting for investments. 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 “Guarantees and Other Assurances” 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 oversight for risk management activities throughout the company.
Commodity Price Risk
FirstEnergy is exposed to financial and market risks resulting from the fluctuation of interest rates and commodity prices -- electricity, energy transmission, natural gas, coal, nuclear fuel and emission allowances. 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. Derivatives that fall within the scope of SFAS 133 must be recorded at their fair value and marked to market. The majority of FirstEnergy’s derivative hedging contracts qualify for the normal purchase and normal sale exception under SFAS 133 and are therefore excluded from the tables below. Contracts that are not exempt from such treatment include certain power purchase agreements with NUG entities that were structured pursuant to the Public Utility Regulatory Policies Act of 1978. These non-trading contracts are adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for above-market costs. The change in the fair value of commodity derivative contracts related to energy production during the first quarter of 2008 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 liability as of January 1, 2008 | | $ | (713 | ) | $ | (26 | ) | $ | (739 | ) |
Additions/change in value of existing contracts | | | - | | | (11 | ) | | (11 | ) |
Settled contracts | | | 58 | | | 17 | | | 75 | |
Outstanding net liability as of March 31, 2008 (1) | | $ | (655 | ) | $ | (20 | ) | $ | (675 | ) |
| | | | | | | | | | |
Non-commodity Net Liabilities as of March 31, 2008: | | | | | | | | | | |
Interest rate swaps (2) | | | - | | | (3 | ) | | (3 | ) |
Net Liabilities - Derivative Contracts as of March 31, 2008 | | $ | (655 | ) | $ | (23 | ) | $ | (678 | ) |
| | | | | | | | | | |
Impact of Changes in Commodity Derivative Contracts(3) | | | | | | | | | | |
Income Statement effects (pre-tax) | | $ | - | | $ | - | | $ | - | |
Balance Sheet effects: | | | | | | | | | | |
Other comprehensive income (pre-tax) | | $ | - | | $ | 6 | | $ | 6 | |
Regulatory assets (net) | | $ | (58 | ) | $ | - | | $ | (58 | ) |
| (1) | Includes $655 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset. |
(2) | Interest rate swaps are treated as cash flow or fair value hedges (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, 2008 as follows: |
Balance Sheet Classification | | Non-Hedge | | Hedge | | Total | |
| | (In millions) | |
| | | | | | | |
| | | | | | | | | | |
| | | | | | | ) | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Other non-current liabilities | | | | ) | | | | | | |
| | | | | | | | | | |
| | | | ) | | | | | | ) |
The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, 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 (see Note 4). Sources of information for the valuation of commodity derivative contracts as of March 31, 2008 are summarized by year in the following table:
Source of Information | | | | | | | | | | | | | | | |
- Fair Value by Contract Year | | | | | | | | | | | | | | | |
| | (In millions) | |
Prices actively quoted(2) | | $ | 3 | | $ | 1 | | $ | - | | $ | - | | $ | - | | $ | - | | $ | 4 | |
Other external sources(3) | | | (164 | ) | | (192 | ) | | (149 | ) | | (92 | ) | | - | | | - | | | (597 | ) |
Prices based on models | | | | | | | | | | | | | | | | ) | | | ) | | | ) |
Total(4) | | | | ) | | | ) | | | ) | | | ) | | | ) | | | ) | | | ) |
(1) For the last three quarters of 2008.
(2) Represents exchange traded NYMEX futures and options.
(3) Primarily represents contracts based on broker and ICE quotes.
| (4) | Includes $655 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset. |
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 its 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, 2008. Based on derivative contracts held as of March 31, 2008, an adverse 10% change in commodity prices would decrease net income by approximately $3 million during the next 12 months.
Interest Rate Swap Agreements - Fair Value Hedges
FirstEnergy utilizes fixed-for-floating interest rate swap agreements as part of its ongoing effort to manage the interest rate risk associated with its debt portfolio. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues – protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates and interest payment dates match those of the underlying obligations. As of March 31, 2008, the debt underlying the $250 million outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 4.87%, which the swaps have converted to a current weighted average variable rate of 3.49%.
| | March 31, 2008 | | December 31, 2007 | |
| | Notional | | Maturity | | Fair | | Notional | | Maturity | | Fair | |
| | Amount | | Date | | Value | | Amount | | Date | | Value | |
| | (In millions) | |
Fair value hedges | | $ | | | | | | $ | | | $ | | | | | | $ | | |
| | | | | | | | | | | | | | | | | | | ) |
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Forward Starting Swap Agreements - Cash Flow Hedges
FirstEnergy utilizes forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with anticipated future issuances of fixed-rate, long-term debt securities for one or more of its consolidated subsidiaries in 2008 and 2009, and anticipated variable-rate, short-term debt. 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 and LIBOR rates between the date of hedge inception and the date of the debt issuance. During the first three months of 2008, FirstEnergy entered into forward swaps with an aggregate notional value of $500 million and terminated forward swaps with an aggregate notional value of $300 million. FirstEnergy paid $18 million in cash related to the terminations, $1 million of which was deemed ineffective and recognized in current period earnings. The remaining effective portion ($17 million) will be recognized over the terms of the associated future debt. As of March 31, 2008, FirstEnergy had outstanding forward swaps with an aggregate notional amount of $600 million and an aggregate fair value of $(8) million.
| | March 31, 2008 | | December 31, 2007 | |
| | Notional | | Maturity | | Fair | | Notional | | Maturity | | Fair | |
| | Amount | | Date | | Value | | Amount | | Date | | Value | |
| | (In millions) | |
Cash flow hedges | | $ | | | | | | $ | | | $ | | | | | | $ | | |
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Equity Price Risk
Included in nuclear decommissioning trusts are marketable equity securities carried at their fair value (market value) of approximately $1.2 billion and $1.4 billion, as of March 31, 2008 and December 31, 2007, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $120 million reduction in fair value as of March 31, 2008.
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, 2008, the largest credit concentration was with one party, currently rated investment grade that represented 11% of FirstEnergy’s total approved credit risk. Within FirstEnergy’s unregulated energy subsidiaries, 99% of credit exposures, net of collateral and reserve, were with investment grade counterparties as of March 31, 2008.
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 Companies and ATSI recognize, as regulatory assets, costs which the FERC, the PUCO, the PPUC and the 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. Regulatory assets that do not earn a current return totaled approximately $137 million as of March 31, 2008 (JCP&L - $78 million and Met-Ed - $59 million). Regulatory assets not earning a current return (primarily for certain regulatory transition costs and employee postretirement benefits) are expected to be recovered by 2014 for JCP&L and by 2020 for Met-Ed. The following table discloses regulatory assets by company:
| | March 31, | | December 31, | | Increase | |
Regulatory Assets* | | 2008 | | 2007 | | (Decrease) | |
| | (In millions) | |
OE | | $ | 710 | | $ | 737 | | $ | (27 | ) |
CEI | | | 854 | | | 871 | | | (17 | ) |
TE | | | 188 | | | 204 | | | (16 | ) |
JCP&L | | | 1,476 | | | 1,596 | | | (120 | ) |
Met-Ed | | | 530 | | | 495 | | | 35 | |
ATSI | | | | | | | | | | ) |
Total | | | | | | | | | | ) |
* | Penelec had net regulatory liabilities of approximately $67 million and $74 million as of March 31, 2008 and December 31, 2007, respectively. These net regulatory liabilities are included in Other Non-current Liabilities on the Consolidated Balance Sheets. |
Regulatory assets by source are as follows:
| | March 31, | | December 31, | | Increase | |
Regulatory Assets By Source | | 2008 | | 2007 | | (Decrease) | |
| | (In millions) | |
Regulatory transition costs | | $ | 2,156 | | $ | 2,363 | | $ | (207 | ) |
Customer shopping incentives | | | 495 | | | 516 | | | (21 | ) |
Customer receivables for future income taxes | | | 290 | | | 295 | | | (5 | ) |
Loss on reacquired debt | | | 56 | | | 57 | | | (1 | ) |
Employee postretirement benefits | | | 37 | | | 39 | | | (2 | ) |
Nuclear decommissioning, decontamination | | | | | | | | | | |
and spent fuel disposal costs | | | (95 | ) | | (115 | ) | | 20 | |
Asset removal costs | | | (195 | ) | | (183 | ) | | (12 | ) |
MISO/PJM transmission costs | | | 368 | | | 340 | | | 28 | |
Fuel costs - RCP | | | 227 | | | 220 | | | 7 | |
Distribution costs - RCP | | | 361 | | | 321 | | | 40 | |
Other | | | | | | | | | | |
Total | | | | | | | | | | ) |
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. The proposed enhancements were divided into two groups: enhancements that were to be completed in 2004; and enhancements that were to be completed after 2004. In 2004, FirstEnergy completed all of the enhancements that were recommended for completion in 2004. FirstEnergy is also proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional material expenditures.
As a result of outages experienced in JCP&L’s service area in 2002 and 2003, the NJBPU performed a review of JCP&L’s service reliability. On June 9, 2004, the NJBPU approved a stipulation that addresses a third-party consultant’s recommendations on appropriate courses of action necessary to ensure system-wide reliability. The stipulation incorporates the consultant’s focused audit of, and recommendations regarding, JCP&L’s Planning and Operations and Maintenance programs and practices. On June 1, 2005, the consultant completed his work and issued his final report to the NJBPU. On July 14, 2006, JCP&L filed a comprehensive response to the consultant’s report with the NJBPU. JCP&L will complete the remaining substantive work described in the stipulation in 2008. JCP&L continues to file compliance reports with the NJBPU reflecting JCP&L’s activities associated with implementing the stipulation.
In 2005, Congress amended the Federal Power Act to provide for federally-enforceable mandatory reliability standards. The mandatory reliability standards apply to the bulk power system and impose certain operating, record-keeping and reporting requirements on the Companies and ATSI. The NERC is charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of its responsibilities to eight regional entities, including the ReliabilityFirst Corporation. All of FirstEnergy’s facilities are located within the ReliabilityFirst region. FirstEnergy actively participates in the NERC and ReliabilityFirst stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards.
FirstEnergy believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, it is clear that NERC, ReliabilityFirst and the FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with new or amended standards cannot be determined at this time. However, the 2005 amendments to the Federal Power Act provide that all prudent costs incurred to comply with the new reliability standards be recovered in rates. Still, any future inability on FirstEnergy’s part to comply with the reliability standards for its bulk power system could have a material adverse effect on its financial condition, results of operations and cash flows.
In April 2007, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the Midwest ISO region and found it to be in full compliance with all audited reliability standards. Similarly, ReliabilityFirst has scheduled a compliance audit of FirstEnergy’s bulk-power system within the PJM region in 2008. FirstEnergy currently does not expect any material adverse financial impact as a result of these audits.
Ohio
On January 4, 2006, the PUCO issued an order authorizing the Ohio Companies to recover certain increased fuel costs through a fuel rider and to defer certain other increased fuel costs to be incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances. The order also provided for recovery of the deferred costs over a twenty-five-year period through distribution rates. On August 29, 2007, the Supreme Court of Ohio concluded that the PUCO violated a provision of the Ohio Revised Code by permitting the Ohio Companies “to collect deferred increased fuel costs through future distribution rate cases, or to alternatively use excess fuel-cost recovery to reduce deferred distribution-related expenses” and remanded the matter to the PUCO for further consideration. On September 10, 2007, the Ohio Companies filed an application with the PUCO that requested the implementation of two generation-related fuel cost riders to collect the increased fuel costs that were previously authorized to be deferred. On January 9, 2008, the PUCO approved the Ohio Companies’ proposed fuel cost rider to recover increased fuel costs to be incurred in 2008 commencing January 1, 2008 through December 31, 2008, which is expected to be approximately $189 million. In addition, the PUCO ordered the Ohio Companies to file a separate application for an alternate recovery mechanism to collect the 2006 and 2007 deferred fuel costs. On February 8, 2008, the Ohio Companies filed an application proposing to recover $226 million of deferred fuel costs and carrying charges for 2006 and 2007 pursuant to a separate fuel rider, with alternative options for the recovery period ranging from five to twenty-five years. This second application is currently pending before the PUCO and a hearing has been set for July 15, 2008.
The Ohio Companies filed an application and rate request for an increase in electric distribution rates with the PUCO on June 7, 2007. The requested increase is expected to be more than offset by the elimination or reduction of transition charges at the time the rates go into effect and would result in lowering the overall non-generation portion of the average electric bill for most Ohio customers. The distribution rate increases reflect capital expenditures since the Ohio Companies’ last distribution rate proceedings, increases in operation and maintenance expenses and recovery of regulatory assets that were authorized in prior cases. On August 6, 2007, the Ohio Companies updated their filing supporting a distribution rate increase of $332 million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of their investigation into the distribution rate request. In its reports, the PUCO Staff recommended a distribution rate increase in the range of $161 million to $180 million, with $108 million to $127 million for distribution revenue increases and $53 million for recovery of costs deferred under prior cases. This amount excludes the recovery of deferred fuel costs, whose recovery is now being sought in a separate proceeding before the PUCO, discussed above. On January 3, 2008, the Ohio Companies and intervening parties filed objections to the Staff Reports and on January 10, 2008, the Ohio Companies filed supplemental testimony. Evidentiary hearings began on January 29, 2008 and continued through February 25, 2008. During the evidentiary hearings, the PUCO Staff submitted testimony decreasing their recommended revenue increase to a range of $114 million to $132 million. Additionally, in testimony submitted on February 11, 2008, the PUCO Staff adopted a position regarding interest deferred for RCP-related deferrals, line extension deferrals and transition tax deferrals that, if upheld by the PUCO, would result in the write-off of approximately $45 million of interest costs deferred through March 31, 2008 ($0.09 per share of common stock). The PUCO is expected to render its decision during the second or third quarter of 2008. The new rates would become effective January 1, 2009 for OE and TE, and approximately May 2009 for CEI.
On July 10, 2007, the Ohio Companies filed an application with the PUCO requesting approval of a comprehensive supply plan for providing retail generation service to customers who do not purchase electricity from an alternative supplier, beginning January 1, 2009. The proposed competitive bidding process would average the results of multiple bidding sessions conducted at different times during the year. The final price per KWH would reflect an average of the prices resulting from all bids. In their filing, the Ohio Companies offered two alternatives for structuring the bids, either by customer class or a “slice-of-system” approach. A slice-of-system approach would require the successful bidder to be responsible for supplying a fixed percentage of the utility’s total load notwithstanding the customer’s classification. The proposal provides the PUCO with an option to phase in generation price increases for residential tariff groups who would experience a change in their average total price of 15 percent or more. The PUCO held a technical conference on August 16, 2007 regarding the filing. Initial and reply comments on the proposal were filed by various parties in September and October 2007, respectively. The proposal is currently pending before the PUCO.
On April 22, 2008, an amended version of Substitute SB221 was passed by the Ohio House of Representatives and sent back to the Ohio Senate for concurrence. On April 23, 2008, the Ohio Senate approved the House's amendments to Substitute SB221 and forwarded the bill to the Governor for signature, which he signed on May 1, 2008. Amended Substitute SB221 requires all electric distribution utilities to file an RSP, now called an ESP, with the PUCO. An ESP is required to contain a proposal for the supply and pricing of retail generation and may include proposals, without limitation, related to one or more of the following:
· | automatic recovery of prudently incurred fuel, purchased power, emission allowance costs and federally mandated energy taxes; |
· | construction work in progress for costs of constructing an electric generating facility or environmental expenditure for any electric generating facility; |
· | costs of an electric generating facility; |
· | terms related to customer shopping, bypassability, standby, back-up and default service; |
· | accounting for deferrals related to stabilizing retail electric service; |
· | automatic increases or decreases in standard service offer price; |
· | phase-in and securitization; |
· | transmission service and related costs; |
· | distribution service and related costs; and |
· | economic development and energy efficiency. |
A utility could also simultaneously file an MRO in which it would have to demonstrate the following objective market criteria: The utility or its transmission service affiliate belongs to a FERC-approved RTO having a market-monitor function and the ability to mitigate market power, and a published source exists that identifies information for traded electricity and energy products that are contracted for delivery two years into the future. The PUCO would test the ESP and its pricing and all other terms and conditions against the MRO and may only approve the ESP if it is found to be more favorable to customers. As part of an ESP with a plan period longer than three years, the PUCO shall prospectively determine every fourth year of the plan whether it is substantially likely the plan will provide the electric distribution utility a return on common equity significantly in excess of the return likely to be earned by publicly traded companies, including utilities, that face comparable business and financial risk (comparable companies). If so, the PUCO may terminate the ESP. Annually under an ESP, the PUCO shall determine whether an electric distribution utility's earned return on common equity is significantly in excess of returns earned on common equity during the same period by comparable companies, and if so, shall require the utility to return such excess to customers by prospective adjustments. Amended Substitute SB221 also includes provisions dealing with advanced and renewable energy standards that contemplate 25% of electrical usage from these sources by 2025. Energy efficiency measures in the bill require energy savings in excess of 22% by 2025. Requirements are in place to meet annual benchmarks for renewable energy resources and energy efficiency, subject to review by the PUCO. FirstEnergy is currently evaluating this legislation and expects to file an ESP in the second or third quarter of 2008.
Pennsylvania
Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations. The fixed price under the agreement is expected to remain below wholesale market prices during the term of the agreement. If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for their fixed income securities. Based on the PPUC’s January 11, 2007 order described below, if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC.
Met-Ed and Penelec made a comprehensive transition rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals had been approved, annual revenues would have increased by $216 million and $157 million, respectively. That filing included, among other things, a request to charge customers for an increasing amount of market-priced power procured through a CBP as the amount of supply provided under the then existing FES agreement was to be phased out. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs incurred during 2006. In this rate filing, Met-Ed and Penelec requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the FirstEnergy and GPU merger proceeding, related to the quantification and allocation of merger savings, with the comprehensive transition rate filing case.
The PPUC entered its opinion and order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, and determined that no merger savings from prior years should be considered in determining customers’ rates. The request for increases in generation supply rates was denied as were the requested changes to NUG expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased Met-Ed’s and Penelec’s distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission costs. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and, in January 2007, Met-Ed and Penelec recognized income of $15 million and $12 million, respectively, to establish regulatory assets for those previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million).
On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase. The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. From June through October 2007, initial responsive and reply briefs were filed by various parties. Oral arguments are scheduled to take place in September 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the results of operations of Met-Ed, Penelec and FirstEnergy.
On April 14, 2008, Met-Ed and Penelec filed annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. The proposed TSCs include a component for under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and future transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed has proposed a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010.
On March 13, 2008, the PPUC approved the residential procurement process in Penn’s Joint Petition for Settlement. This RFP process calls for load-following, full-requirements contracts for default service procurement for residential customers for the period covering June 1, 2008 through May 31, 2011. The PPUC had previously approved the default service procurement processes for commercial and industrial customers. The default service procurement for small commercial customers was conducted through multiple RFPs, while the default service procurement for large commercial and industrial customers will utilize hourly pricing. Bids in the two RFPs for small commercial load were approved by the PPUC on February 22, 2008, and March 20, 2008. On March 28, 2008, Penn filed compliance tariffs with the new default service generation rates based on the approved RFP bids for small commercial customers which the PPUC then certified on April 4, 2008. On April 14, 2008, the first RFP for residential customers’ load was held consisting of tranches for both 12 and 24-month supply. The PPUC approved the bids on April 16, 2008. The second RFP is scheduled to be held on May 14, 2008, after which time the PPUC is expected to approve the new rates to go into effect June 1, 2008.
On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation and demand reduction programs to meet energy growth, a requirement that electric distribution companies acquire power that results in the “lowest reasonable rate on a long-term basis,” the utilization of micro-grids and a three year phase-in of rate increases. On July 17, 2007, the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy was convened in mid-September 2007 to consider other aspects of the EIS. The Pennsylvania House and Senate on March 11, 2008 and December 12, 2007, respectively, passed different versions of bills to fund the Governor’s EIS proposal. Neither chamber has formally considered the other’s bill. On February 12, 2008, the Pennsylvania House passed House Bill 2200 which provides for energy efficiency and demand management programs and targets as well as the installation of smart meters within ten years. Other legislation has been introduced to address generation procurement, expiration of rate caps, conservation and renewable energy. The final form of this pending legislation is uncertain. Consequently, FirstEnergy is unable to predict what impact, if any, such legislation may have on its operations.
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 NUGC rates and market sales of NUG energy and capacity. As of March 31, 2008, the accumulated deferred cost balance totaled approximately $264 million.
In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting 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 DRA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and also submitted comments in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set.
On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of the PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. These regulations are not expected to materially impact FirstEnergy or JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. The NJBPU Staff circulated revised drafts of the proposal to interested stakeholders in November 2006 and again in February 2007. On February 1, 2008, the NJBPU accepted proposed rules for publication in the New Jersey Register on March 17, 2008. A public hearing on these proposed rules was held on April 23, 2008 with comments from interested parties due on May 16, 2008.
New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated through the creation of a number of working groups to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. In addition, public stakeholder meetings were held in the fall of 2006 and in early 2007.
On April 17, 2008, a draft EMP was released for public comment. The draft EMP establishes four major goals:
· | maximize energy efficiency to achieve a 20% reduction in energy consumption by 2020; |
· | reduce peak demand for electricity by 5,700 MW by 2020 (amounting to about a 22% reduction in projected demand); |
· | meet 22.5% of the state’s electricity needs with renewable energy by 2020; and |
· | develop low carbon emitting, efficient power plants and close the gap between the supply and demand for electricity. |
Following the public comment period which is expected to extend into July 2008, a final EMP will be issued to be followed by appropriate legislation and regulation as necessary. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation or regulation may have on its operations or those of JCP&L.
On February 13, 2007, the NJBPU Staff informally issued a draft proposal relating to changes to the regulations addressing electric distribution service reliability and quality standards. Meetings between the NJBPU Staff and interested stakeholders to discuss the proposal were held and additional, revised informal proposals were subsequently circulated by the Staff. On September 4, 2007, proposed regulations were published in the New Jersey Register, which proposal will be subsequently considered by the NJBPU following comments that were submitted in September and October 2007. Final regulations (effective upon publication) were published in the New Jersey Register March 17, 2008. Upon preliminary review of the new regulations, FirstEnergy does not expect a material impact on its operations or those of JCP&L.
FERC Matters
Transmission Service between MISO and PJM
On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate so-called “pancaking” of transmission charges between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or “SECA”) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order could be issued by the FERC in the second quarter of 2008.
PJM Transmission Rate Design
On January 31, 2005, certain PJM transmission owners made filings with the FERC 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. Hearings were held and numerous parties appeared and litigated various issues concerning PJM rate design; notably AEP, which proposed to create a "postage stamp", or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. This proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. The FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.
On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. The FERC’s orders on PJM rate design will prevent the allocation of a portion of the revenue requirement of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reduce future transmission revenue recovery from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the “beneficiary pays” methodology for below 500 kV facilities, but excluding the issue of allocating new facilities costs to merchant transmission entities, was filed on September 14, 2007. The agreement was supported by the FERC’s Trial Staff, and was certified by the Presiding Judge. The FERC’s action on the settlement agreement is pending. The remaining merchant transmission cost allocation issues will proceed to hearing in May 2008. On February 13, 2008, AEP appealed the FERC’s orders to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and Dayton Power & Light have also appealed these orders to the Seventh Circuit Court of Appeals. The appeals of these parties and others have been consolidated for argument in the Seventh Circuit.
Post Transition Period Rate Design
The FERC had directed MISO, PJM, and the respective transmission owners to make filings on or before August 1, 2007 to reevaluate transmission rate design within MISO, and between MISO and PJM. On August 1, 2007, filings were made by MISO, PJM, and the vast majority of transmission owners, including FirstEnergy affiliates, which proposed to retain the existing transmission rate design. These filings were approved by the FERC on January 31, 2008. As a result of the FERC’s approval, the rates charged to FirstEnergy’s load-serving affiliates for transmission service over existing transmission facilities in MISO and PJM are unchanged. In a related filing, MISO and MISO transmission owners requested that the current MISO pricing for new transmission facilities that spreads 20% of the cost of new 345 kV and higher transmission facilities across the entire MISO footprint (known as the RECB methodology) be retained.
On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act seeking to have the entire transmission rate design and cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have the FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM “Super Region” that recovers the average cost of new and existing transmission facilities operated at voltages of 345 kV and above from all transmission customers. Lower voltage facilities would continue to be recovered in the local utility transmission rate zone through a license plate rate. AEP requested a refund effective October 1, 2007, or alternatively, February 1, 2008. On January 31, 2008, the FERC issued an order denying the complaint. A rehearing request by AEP is pending before the FERC.
Distribution of MISO Network Service Revenues
Effective February 1, 2008, the MISO Transmission Owners Agreement provides for a change in the method of distributing transmission revenues among the transmission owners. MISO and a majority of the MISO transmission owners filed on December 3, 2007 to change the MISO tariff to clarify, for purposes of distributing network transmission revenue to the transmission owners, that all network transmission service revenues, whether collected by MISO or directly by the transmission owner, are included in the revenue distribution calculation. This clarification was necessary because some network transmission service revenues are collected and retained by transmission owners in states where retail choice does not exist, and their “unbundled” retail load is currently exempt from MISO network service charges. The tariff changes filed with the FERC ensure that revenues collected by transmission owners from bundled load are taken into account in the revenue distribution calculation, and that transmission owners with bundled load do not collect more than their revenue requirements. Absent the changes, transmission owners, and ultimately their customers, with unbundled load or in retail choice states, such as ATSI, would subsidize transmission owners with bundled load, who would collect their revenue requirement from bundled load, plus share in revenues collected by MISO from unbundled customers. This would result in a large revenue shortfall for ATSI, which would eventually be passed on to customers in the form of higher transmission rates as calculated pursuant to ATSI’s Attachment O formula under the MISO tariff.
Numerous parties filed in support of the tariff changes, including the public service commissions of Michigan, Ohio and Wisconsin. Ameren filed a protest on December 26, 2007, arguing that the December 3, 2007 filing violates the MISO Transmission Owners’ Agreement as well as an agreement among Ameren (Union Electric), MISO, and the Missouri Public Service Commission, which provides that Union Electric’s bundled load cannot be charged by MISO for network service. On February 2, 2008, the FERC issued an order conditionally accepting the tariff amendment subject to a minor compliance filing, which was made on March 3, 2008. This order ensures that ATSI will continue to receive transmission revenues from MISO equivalent to its transmission revenue requirement. A rehearing request by Ameren is pending before the FERC.
On February 1, 2008, MISO filed a request to continue using the existing revenue distribution methodology on an interim basis pending amendment of the MISO Transmission Owners’ Agreement. This request was accepted by the FERC on March 13, 2008. On that same day, MISO and the MISO transmission owners made a filing to amend the Transmission Owners’ Agreement to effectively continue the distribution of transmission revenues that was in effect prior to February 1, 2008. This matter is currently pending before the FERC.
MISO Ancillary Services Market and Balancing Area Consolidation
MISO made a filing on September 14, 2007 to establish an ASM for regulation, spinning and supplemental reserves, to consolidate the existing 24 balancing areas within the MISO footprint, and to establish MISO as the NERC registered balancing authority for the region. This filing would permit load serving entities to purchase their operating reserve requirements in a competitive market. FirstEnergy supports the proposal to establish markets for Ancillary Services and consolidate existing balancing areas. On February 25, 2008, the FERC issued an order approving the ASM subject to certain compliance filings. MISO has since notified the FERC that the start of its ASM is delayed until September of 2008.
Duquesne’s Request to Withdraw from PJM
On November 8, 2007, Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and to join the MISO. In its filing, Duquesne asked the FERC to be relieved of certain capacity payment obligations to PJM for capacity auctions conducted prior to its departure from PJM, but covering service for planning periods through May 31, 2011. Duquesne asserted that its primary reason for exiting PJM is to avoid paying future obligations created by PJM’s forward capacity market. FirstEnergy believes that Duquesne’s filing did not identify or address numerous legal, financial or operational issues that are implicated or affected directly by Duquesne’s proposal. Consequently, FirstEnergy submitted responsive filings that, while conceding Duquesne’s rights to exit PJM, contested various aspects of Duquesne’s proposal. FirstEnergy particularly focused on Duquesne’s proposal that it be allowed to exit PJM without payment of its share of existing capacity market commitments. FirstEnergy also objected to Duquesne’s failure to address the firm transmission service requirements that would be necessary for FirstEnergy to continue to use the Beaver Valley Plant to meet existing commitments in the PJM capacity markets and to serve native load. Other market participants also submitted filings contesting Duquesne’s plans.
On January 17, 2008, the FERC conditionally approved Duquesne’s request to exit PJM. Among other conditions, the FERC obligated Duquesne to pay the PJM capacity obligations through May 31, 2011. The FERC’s order took notice of the numerous transmission and other issues raised by FirstEnergy and other parties to the proceeding, but did not provide any responsive rulings or other guidance. Rather, the FERC ordered Duquesne to make a compliance filing in forty-five days detailing how Duquesne will satisfy its obligations under the PJM Transmission Owners’ Agreement. The FERC likewise directed the MISO to submit detailed plans to integrate Duquesne into the MISO. Finally, the FERC directed MISO and PJM to work together to resolve the substantive and procedural issues implicated by Duquesne’s transition into the MISO. These issues remain unresolved. If Duquesne satisfies all of the obligations set by the FERC, its planned transition date is October 9, 2008.
On March 18, 2008, the PJM Power Providers Group filed a request for emergency clarification regarding whether Duquesne-zone generators (including the Beaver Valley Plant) could participate in PJM’s May 2008 auction for the 2011-2012 RPM delivery year. FirstEnergy and the other Duquesne-zone generators filed responsive pleadings. On April 18, 2008, the FERC issued its Order on Motion for Emergency Clarification, wherein the FERC ruled that although the status of the Duquesne-zone generators will change to “External Resource” upon Duquesne’s exit from PJM, these generators can contract with PJM for the transmission reservations necessary to participate in the May 2008 auction. FirstEnergy has complied with FERC’s order by obtaining executed transmission service agreements for firm point-to-point transmission service for the 2011-2012 delivery year and, as such, FirstEnergy satisfies the criteria to bid the Beaver Valley Plant into the May 2008 RPM auction. Notwithstanding these events, on April 30, 2008 and May 1, 2008, certain members of the PJM Power Providers Group filed further pleadings on these issues. On May 2, 2008, FirstEnergy filed a responsive pleading. FirstEnergy is participating in the May 2008 RPM auction for the 2011-2012 RPM delivery year.
MISO Resource Adequacy Proposal
MISO made a filing on December 28, 2007 that would create an enforceable planning reserve requirement in the MISO tariff for load serving entities such as the Ohio Companies, Penn Power, and FES. This requirement is proposed to become effective for the planning year beginning June 1, 2009. The filing would permit MISO to establish the reserve margin requirement for load serving entities based upon a one day loss of load in ten years standard, unless the state utility regulatory agency establishes a different planning reserve for load serving entities in its state. FirstEnergy generally supports the proposal as it promotes a mechanism that will result in long-term commitments from both load-serving entities and resources, including both generation and demand side resources that are necessary for reliable resource adequacy and planning in the MISO footprint. Comments on the filing were filed on January 28, 2008. The FERC approved MISO’s Resource Adequacy proposal on March 26, 2008. Rehearing requests are pending on the FERC’s March 26 Order. A compliance filing establishing the enforcement mechanism for the reserve margin requirement is due on or before June 25, 2008.
Organized Wholesale Power Markets
On February 21, 2008, the FERC issued a NOPR through which it proposes to adopt new rules that it states will “improve operations in organized electric markets, boost competition and bring additional benefits to consumers.” The proposed rule addresses demand response and market pricing during reserve shortages, long-term power contracting, market-monitoring policies, and responsiveness of RTOs and ISOs to stakeholders and customers. FirstEnergy does not believe that the proposed rule will have a significant impact on its operations. Comments on the NOPR were filed on April 18, 2008.
Environmental Matters
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. The effects of compliance on FirstEnergy with regard to environmental matters could have a material adverse effect on 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. FirstEnergy estimates capital expenditures for environmental compliance of approximately $1.4 billion for the period 2008-2012.
FirstEnergy accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in FirstEnergy’s determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.
Clean Air Act Compliance
FirstEnergy is required to meet federally-approved SO2 emissions regulations. Violations of such regulations can result in the 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. FirstEnergy believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.
The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006, alleging violations to various sections of the CAA. FirstEnergy has disputed those alleged violations based on its CAA permit, the Ohio SIP and other information provided to the EPA at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order, and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding the opacity limit applicable to the common stack for Bay Shore Units 2, 3 and 4.
FirstEnergy complies 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 at FirstEnergy's facilities. The EPA's NOX Transport Rule imposes uniform reductions of NOX emissions (an approximate 85% reduction in utility plant NOX emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOX emissions are contributing significantly to ozone levels in the eastern United States. FirstEnergy believes its facilities are also complying with the NOX budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.
On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On October 18, 2007, PennFuture filed a complaint, joined by three of its members, in the United States District Court for the Western District of Pennsylvania. On January 11, 2008, FirstEnergy filed a motion to dismiss claims alleging a public nuisance. On April 24, 2008, the Court denied the motion to dismiss, but also ruled that monetary damages could not be recovered under the public nuisance claim.
On December 18, 2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations at the Portland Generation Station against Reliant (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU, Inc. and Met-Ed. Specifically, New Jersey alleges that "modifications" at Portland Units 1 and 2 occurred between 1980 and 1995 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seeks injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. On March 14, 2008, Met-Ed filed a motion to dismiss the citizen suit claims against it and a stipulation in which the parties agreed that GPU, Inc. should be dismissed from this case. On March 26, 2008, GPU, Inc. was dismissed by the Court. Although it remains liable for civil or criminal penalties and fines that may be assessed relating to events prior to the sale of the Portland Station in 1999, Met-Ed is indemnified by Sithe Energy against any other liability arising under the CAA whether it arises out of pre-1999 or post-1999 events.
National Ambient Air Quality Standards
In March 2005, the EPA finalized the CAIR 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 non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR requires 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). FirstEnergy's Michigan, Ohio and Pennsylvania fossil generation facilities will be subject to caps on SO2 and NOX emissions, whereas its New Jersey fossil generation facility will be subject to only a cap on 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. CAIR has been challenged in the United States Court of Appeals for the District of Columbia. The future cost of compliance with these regulations may be substantial and may depend on the outcome of this litigation and how CAIR is ultimately implemented.
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. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping national mercury emissions at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the United States Court of Appeals for the District of Columbia. On February 8, 2008, the court vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap and trade program. The EPA must now seek further judicial review of that ruling or take regulatory action to promulgate new mercury emission standards for coal-fired power plants. FGCO’s future cost of compliance with mercury regulations may be substantial and will depend on the action taken by the EPA and on how they are ultimately implemented.
Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap-and-trade approach as in the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. It is anticipated that compliance with these regulations, if approved by the EPA and implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant, FirstEnergy’s only Pennsylvania coal-fired power plant, until 2015, if at all.
W. H. Sammis Plant
In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W.H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case, along with seven other similar cases, are referred to as the NSR cases.
On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation. This settlement agreement, which is in the form of a consent decree, was approved by the court on July 11, 2005, and requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FirstEnergy fails to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FirstEnergy could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree are currently estimated to be $1.3 billion for 2008-2012 ($650 million of which is expected to be spent during 2008, with the largest portion of the remaining $650 million expected to be spent in 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above.
On April 2, 2007, the United States Supreme Court ruled that changes in annual emissions (in tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must be used to determine whether an emissions increase triggers NSR. Subsequently, on May 8, 2007, the EPA proposed to revise the NSR regulations to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR. The EPA has not yet issued a final regulation. FGCO’s future cost of compliance with those regulations may be substantial and will depend on how they are ultimately implemented.
Climate Change
In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 2012. The United States signed the Kyoto Protocol in 1998 but it failed to receive the two-thirds vote required for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. Also, in an April 16, 2008 speech, President Bush set a policy goal of stopping the growth of GHG emissions by 2025, as the next step beyond the 2012 strategy. In addition, the EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.
There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the international level, efforts to reach a new global agreement to reduce GHG emissions post-2012 have begun with the Bali Roadmap, which outlines a two-year process designed to lead to an agreement in 2009. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the Senate Environmental and Public Works Committees have passed one such bill. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.
On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities.
FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions could require significant capital and other expenditures. The CO2 emissions per KWH of electricity generated by FirstEnergy is lower than many regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy's plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FirstEnergy's operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.
On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). On January 26, 2007, the United States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment (BPJ) to minimize impacts on fish and shellfish from cooling water intake structures. On April 14, 2008, the Supreme Court of the United States granted a petition for a writ of certiorari to review certain aspects of the Second Circuit’s decision. FirstEnergy is studying various control options and their costs and effectiveness. Depending on the results of such studies, the outcome of the Supreme Court’s review of the Second Circuit’s decision, the EPA’s further rulemaking and any action taken by the states exercising BPJ, 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 non-hazardous waste.
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of March 31, 2008, FirstEnergy had approximately $2.0 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy agreed to contribute another $80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy (and Exelon for TMI-1 as it relates to the timing of the decommissioning of TMI-2) seeks for these facilities.
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 may be 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, 2008, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $92 million (JCP&L - $65 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $25 million) have been accrued through March 31, 2008. Included in the total for JCP&L are accrued liabilities of approximately $56 million for environmental remediation of former manufactured gas plants in New Jersey; which are being recovered by JCP&L through a non-bypassable SBC.
Other Legal Proceedings
Power Outages and Related Litigation
In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four of New Jersey’s electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the JCP&L territory.
In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision in July 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, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, in March 2007, reversed the decertification of the Red Bank class and remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007. Proceedings are continuing in the Superior Court and a case management conference with the presiding Judge is scheduled for June 13, 2008. FirstEnergy is defending this class action but is unable to predict the outcome of this matter. No liability has been accrued as of March 31, 2008.
Nuclear Plant Matters
On May 14, 2007, the Office of Enforcement of the NRC issued a DFI to FENOC, following FENOC’s reply to an April 2, 2007 NRC request for information, about two reports prepared by expert witnesses for an insurance arbitration (the insurance claim was subsequently withdrawn by FirstEnergy in December 2007) related to Davis-Besse. The NRC indicated that this information was needed for the NRC “to determine whether an Order or other action should be taken pursuant to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to operate its licensed facilities in accordance with the terms of its licenses and the Commission’s regulations.” FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s DFI reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. FENOC submitted a supplemental response clarifying certain aspects of the DFI response to the NRC on July 16, 2007. On August 15, 2007, the NRC issued a confirmatory order imposing these commitments. FENOC must inform the NRC’s Office of Enforcement after it completes the key commitments embodied in the NRC’s order. FENOC’s compliance with these commitments is subject to future NRC review.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.
On 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 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. On April 5, 2007, the Court rejected the plaintiffs’ request to certify this case as a class action and, accordingly, did not appoint the plaintiffs as class representatives or their counsel as class counsel. On July 30, 2007, plaintiffs’ counsel voluntarily withdrew their request for reconsideration of the April 5, 2007 Court order denying class certification and the Court heard oral argument on the plaintiffs’ motion to amend their complaint which OE opposed. On August 2, 2007, the Court denied the plaintiffs’ motion to amend their complaint. The plaintiffs have appealed the Court’s denial of the motion for certification as a class action and motion to amend their complaint.
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 arbitration panel decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, a federal district court granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005. A final order identifying the individual damage amounts was issued on October 31, 2007. The award appeal process was initiated. The union filed a motion with the federal court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. The court held a scheduling conference in April 2008 where it set a briefing schedule with all briefs to be concluded by July 2008. JCP&L recognized a liability for the potential $16 million award in 2005.
The union employees at the Bruce Mansfield Plant have been working without a labor contract since February 15, 2008. The parties are continuing to bargain with the assistance of a federal mediator. FirstEnergy has a strike mitigation plan ready in the event of a strike.
FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.
NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
SFAS 141(R) – “Business Combinations”
In December 2007, the FASB issued SFAS 141(R), which requires the acquiring entity in a business combination to recognize all the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. SFAS 141(R) attempts to reduce the complexity of existing GAAP related to business combinations. The Standard includes both core principles and pertinent application guidance, eliminating the need for numerous EITF issues and other interpretative guidance. SFAS 141(R) will affect business combinations entered into by FirstEnergy that close after January 1, 2009. In addition, the Standard also affects the accounting for changes in tax valuation allowances made after January 1, 2009, that were established as part of a business combination prior to the implementation of this Standard. FirstEnergy is currently evaluating the impact of adopting this Standard on its financial statements.
SFAS 160 - “Noncontrolling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51”
In December 2007, the FASB issued SFAS 160 that establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Early adoption is prohibited. The Statement is not expected to have a material impact on FirstEnergy’s financial statements.
| SFAS 161 - “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133” |
In March 2008, the FASB issued SFAS 161, which enhances the current disclosure framework for derivative instruments and hedging activities. The Statement requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. This disclosure better conveys the purpose of derivative use in terms of the risks that the entity is intending to manage. The FASB believes disclosing the fair values of derivative instruments and their gains and losses in a tabular format is designed to provide a more complete picture of the location in an entity’s financial statements of both the derivative positions existing at period end and the effect of using derivatives during the reporting period. Disclosing information about credit-risk-related contingent features is designed to provide information on the potential effect on an entity’s liquidity from using derivatives. Finally, this Statement requires cross-referencing within the footnotes, which is intended to help users of financial statements locate important information about derivative instruments. FirstEnergy is currently evaluating the impact of adopting this Standard on its financial 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, 2008 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2008 and 2007. 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 (United States), 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, 2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for uncertain tax positions as of January 1, 2007, defined benefit pension and other postretirement plans as of December 31, 2006 and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 9, Note 3, Note 2(G) and Note 12 to the consolidated financial statements) dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, 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 7, 2008 |
FIRSTENERGY CORP. | |
| | | | | | |
CONSOLIDATED STATEMENTS OF INCOME | |
(Unaudited) | |
| | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | 2008 | | | 2007 | |
| | (In millions except, | |
| | per share amounts) | |
REVENUES: | | | | | | |
Electric utilities | | $ | 2,913 | | | $ | 2,659 | |
Unregulated businesses | | | 364 | | | | 314 | |
Total revenues* | | | 3,277 | | | | 2,973 | |
| | | | | | | | |
EXPENSES: | | | | | | | | |
Fuel and purchased power | | | 1,328 | | | | 1,121 | |
Other operating expenses | | | 800 | | | | 749 | |
Provision for depreciation | | | 164 | | | | 156 | |
Amortization of regulatory assets | | | 258 | | | | 251 | |
Deferral of new regulatory assets | | | (105 | ) | | | (144 | ) |
General taxes | | | 215 | | | | 203 | |
Total expenses | | | 2,660 | | | | 2,336 | |
| | | | | | | | |
OPERATING INCOME | | | 617 | | | | 637 | |
| | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | |
Investment income | | | 17 | | | | 33 | |
Interest expense | | | (179 | ) | | | (185 | ) |
Capitalized interest | | | 8 | | | | 5 | |
Total other expense | | | (154 | ) | | | (147 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 463 | | | | 490 | |
| | | | | | | | |
INCOME TAXES | | | 187 | | | | 200 | |
| | | | | | | | |
NET INCOME | | $ | 276 | | | $ | 290 | |
| | | | | | | | |
| | | | | | | | |
BASIC EARNINGS PER SHARE OF COMMON STOCK | | $ | 0.91 | | | $ | 0.92 | |
| | | | | | | | |
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING | | | 304 | | | | 314 | |
| | | | | | | | |
DILUTED EARNINGS PER SHARE OF COMMON STOCK | | $ | 0.90 | | | $ | 0.92 | |
| | | | | | | | |
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING | | | 307 | | | | 316 | |
| | | | | | | | |
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK | | $ | 0.55 | | | $ | 0.50 | |
| | | | | | | | |
| | | | | | | | |
* Includes $114 million and $108 million of excise tax collections in the first quarter of 2008 and 2007, respectively. | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral | |
part of these statements. | | | | | | | | |
FIRSTENERGY CORP. | |
| | | | | | |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | |
| | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | 2008 | | | 2007 | |
| | | | | | |
| | (In millions) | |
| | | | | | |
NET INCOME | | $ | 276 | | | $ | 290 | |
| | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
Pension and other postretirement benefits | | | (20 | ) | | | (11 | ) |
Unrealized gain (loss) on derivative hedges | | | (13 | ) | | | 21 | |
Change in unrealized gain on available-for-sale securities | | | (58 | ) | | | 17 | |
Other comprehensive income (loss) | | | (91 | ) | | | 27 | |
Income tax expense (benefit) related to other comprehensive income | | | (33 | ) | | | 9 | |
Other comprehensive income (loss), net of tax | | | (58 | ) | | | 18 | |
| | | | | | | | |
COMPREHENSIVE INCOME | | $ | 218 | | | $ | 308 | |
| | | | | | | | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral | |
part of these statements. | | | | | | | | |
FIRSTENERGY CORP. | |
| | | | | | |
CONSOLIDATED BALANCE SHEETS | |
(Unaudited) | |
| | March 31, | | | December 31, | |
| | 2008 | | | 2007 | |
| | (In millions) | |
ASSETS | | | | | | |
| | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 70 | | | $ | 129 | |
Receivables- | | | | | | | | |
Customers (less accumulated provisions of $34 million and | | | | | | | | |
$36 million, respectively, for uncollectible accounts) | | | 1,264 | | | | 1,256 | |
Other (less accumulated provisions of $24 million and | | | | | | | | |
$22 million, respectively, for uncollectible accounts) | | | 159 | | | | 165 | |
Materials and supplies, at average cost | | | 570 | | | | 521 | |
Prepayments and other | | | 307 | | | | 159 | |
| | | 2,370 | | | | 2,230 | |
PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | |
In service | | | 24,894 | | | | 24,619 | |
Less - Accumulated provision for depreciation | | | 10,454 | | | | 10,348 | |
| | | 14,440 | | | | 14,271 | |
Construction work in progress | | | 1,465 | | | | 1,112 | |
| | | 15,905 | | | | 15,383 | |
INVESTMENTS: | | | | | | | | |
Nuclear plant decommissioning trusts | | | 2,025 | | | | 2,127 | |
Investments in lease obligation bonds | | | 679 | | | | 717 | |
Other | | | 714 | | | | 754 | |
| | | 3,418 | | | | 3,598 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Goodwill | | | 5,606 | | | | 5,607 | |
Regulatory assets | | | 3,797 | | | | 3,945 | |
Pension assets | | | 723 | | | | 700 | |
Other | | | 596 | | | | 605 | |
| | | 10,722 | | | | 10,857 | |
| | $ | 32,415 | | | $ | 32,068 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
| | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Currently payable long-term debt | | $ | 2,183 | | | $ | 2,014 | |
Short-term borrowings | | | 1,649 | | | | 903 | |
Accounts payable | | | 754 | | | | 777 | |
Accrued taxes | | | 416 | | | | 408 | |
Other | | | 1,167 | | | | 1,046 | |
| | | 6,169 | | | | 5,148 | |
CAPITALIZATION: | | | | | | | | |
Common stockholders’ equity- | | | | | | | | |
Common stock, $.10 par value, authorized 375,000,000 shares- | | | | | | | | |
304,835,407 shares outstanding. | | | 31 | | | | 31 | |
Other paid-in capital | | | 5,472 | | | | 5,509 | |
Accumulated other comprehensive loss | | | (108 | ) | | | (50 | ) |
Retained earnings | | | 3,596 | | | | 3,487 | |
Total common stockholders' equity | | | 8,991 | | | | 8,977 | |
Long-term debt and other long-term obligations | | | 8,332 | | | | 8,869 | |
| | | 17,323 | | | | 17,846 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Accumulated deferred income taxes | | | 2,717 | | | | 2,671 | |
Asset retirement obligations | | | 1,287 | | | | 1,267 | |
Deferred gain on sale and leaseback transaction | | | 1,052 | | | | 1,060 | |
Power purchase contract loss liability | | | 682 | | | | 750 | |
Retirement benefits | | | 911 | | | | 894 | |
Lease market valuation liability | | | 643 | | | | 663 | |
Other | | | 1,631 | | | | 1,769 | |
| | | 8,923 | | | | 9,074 | |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10) | | | | | | | | |
| | $ | 32,415 | | | $ | 32,068 | |
| | | | | | | | |
The accompanying 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 | |
| | March 31, | |
| | 2008 | | | 2007 | |
| | (In millions) | |
| | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 276 | | | $ | 290 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
Provision for depreciation | | | 164 | | | | 156 | |
Amortization of regulatory assets | | | 258 | | | | 251 | |
Deferral of new regulatory assets | | | (105 | ) | | | (144 | ) |
Nuclear fuel and lease amortization | | | 26 | | | | 26 | |
Deferred purchased power and other costs | | | (59 | ) | | | (116 | ) |
Deferred income taxes and investment tax credits, net | | | 89 | | | | 53 | |
Investment impairment | | | 16 | | | | 5 | |
Deferred rents and lease market valuation liability | | | 4 | | | | (25 | ) |
Accrued compensation and retirement benefits | | | (142 | ) | | | (65 | ) |
Commodity derivative transactions, net | | | 8 | | | | 1 | |
Gain on asset sales | | | (37 | ) | | | - | |
Cash collateral received | | | 8 | | | | 6 | |
Pension trust contribution | | | - | | | | (300 | ) |
Decrease (increase) in operating assets- | | | | | | | | |
Receivables | | | (6 | ) | | | (155 | ) |
Materials and supplies | | | (17 | ) | | | 15 | |
Prepayments and other current assets | | | (115 | ) | | | (74 | ) |
Increase (decrease) in operating liabilities- | | | | | | | | |
Accounts payable | | | (23 | ) | | | (108 | ) |
Accrued taxes | | | (5 | ) | | | 73 | |
Accrued interest | | | 91 | | | | 86 | |
Electric service prepayment programs | | | (19 | ) | | | (17 | ) |
Other | | | (56 | ) | | | (15 | ) |
Net cash provided from (used for) operating activities | | | 356 | | | | (57 | ) |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Long-term debt | | | - | | | | 250 | |
Short-term borrowings, net | | | 746 | | | | 1,139 | |
Redemptions and Repayments- | | | | | | | | |
Common stock | | | - | | | | (891 | ) |
Long-term debt | | | (368 | ) | | | (13 | ) |
Net controlled disbursement activity | | | 6 | | | | 12 | |
Stock-based compensation tax benefit | | | 11 | | | | 8 | |
Common stock dividend payments | | | (168 | ) | | | (159 | ) |
Net cash provided from financing activities | | | 227 | | | | 346 | |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (711 | ) | | | (296 | ) |
Proceeds from asset sales | | | 50 | | | | - | |
Sales of investment securities held in trusts | | | 361 | | | | 273 | |
Purchases of investment securities held in trusts | | | (384 | ) | | | (294 | ) |
Cash investments | | | 58 | | | | 25 | |
Other | | | (16 | ) | | | 2 | |
Net cash used for investing activities | | | (642 | ) | | | (290 | ) |
| | | | | | | | |
Net decrease in cash and cash equivalents | | | (59 | ) | | | (1 | ) |
Cash and cash equivalents at beginning of period | | | 129 | | | | 90 | |
Cash and cash equivalents at end of period | | $ | 70 | | | $ | 89 | |
| | | | | | | | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements. | |
FIRSTENERGY SOLUTIONS CORP.
ANALYSIS OF RESULTS OF OPERATIONS |
FES is a wholly owned subsidiary of FirstEnergy. FES provides energy-related products and services primarily in Ohio, Pennsylvania, Michigan and Maryland, and through its subsidiaries, FGCO and NGC, owns or leases and operates FirstEnergy’s fossil and hydroelectric generation facilities and owns FirstEnergy’s nuclear generation facilities, respectively. FENOC, a wholly owned subsidiary of FirstEnergy, operates and maintains the nuclear generating facilities.
FES’ revenues are primarily from the sale of electricity (provided from FES’ generating facilities and through purchased power arrangements) to affiliated utility companies to meet all or a portion of their PLR requirements. These affiliated power sales include a full-requirements PSA with OE, CEI and TE to supply each of their PLR obligations through 2008, at prices that take into consideration their respective PUCO-authorized billing rates. FES also has a partial requirements wholesale power sales agreement with its affiliates, Met-Ed and Penelec, to supply a portion of each of their respective PLR obligations at fixed prices through 2010. The fixed prices under the partial requirements agreement are expected to remain below wholesale market prices during the term of the agreement. FES also supplies the majority of the PLR requirements of Penn at market-based rates as a result of a competitive solicitation conducted by Penn. FES’ existing contractual obligations to Penn expire on May 31, 2008, but could continue if FES successfully bids in future competitive solicitations. FES’ revenues also include competitive retail and wholesale sales to non-affiliated customers in Ohio, Pennsylvania, Maryland and Michigan.
Results of Operations
In the first three months of 2008, net income decreased to $90 million from $103 million in the same period in 2007. The decrease in net income was primarily due to higher fuel and other operating expenses, partially offset by lower purchased power costs and higher revenues.
Revenues
Revenues increased by $81 million in the first three months of 2008 compared to the same period in 2007 due to increases in revenues from non-affiliated and affiliated wholesale sales, partially offset by lower retail generation sales. Retail generation sales revenues decreased as a result of decreased sales in the PJM market partially offset by increased sales in the MISO market. Lower sales in the PJM market were primarily due to lower contract renewals for commercial and industrial customers. Greater sales in the MISO market were primarily due to FES’ capturing more shopping customers in Penn’s service territory, partially offset by lower customer usage. Non-affiliated wholesale revenues increased as a result of more generation available for wholesale sales to non-affiliates.
The increase in affiliated company wholesale sales was due to greater sales to the Ohio and Pennsylvania Companies to meet their higher retail generation sales requirements. Higher unit prices resulted from the provision of the full-requirements PSA under which PSA rates reflect the increase in the Ohio Companies’ retail generation rates. The higher sales to the Pennsylvania Companies were due to increased Met-Ed and Penelec generation sales requirements. These increases were partially offset by lower sales to Penn due to a 45% increase in customer shopping in the first quarter of 2008 compared to the first quarter of 2007.
Transmission revenue increased $10 million due to increased retail load in the MISO market and higher transmission prices ($12 million), partially offset by reduced FTR auction revenues ($2 million).
Changes in revenues in the first three months of 2008 from the same period of 2007 are summarized below:
| | Three Months Ended | | | |
| | March 31, | | Increase | |
Revenues by Type of Service | | 2008 | | 2007 | | (Decrease) | |
| | (In millions) | |
Non-Affiliated Generation Sales: | | | | | | | |
| | | | | | | | | | ) |
| | | | | | | | | | |
Total Non-Affiliated Generation Sales | | | | | | | | | | |
Affiliated Generation Sales | | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | ) |
| | | | | | | | | | |
The following tables summarize the price and volume factors contributing to changes in revenues from non-affiliated and affiliated generation sales in the first three months of 2008 compared to the same period last year:
| | Increase | |
Source of Change in Non-Affiliated Generation Revenues | | | |
| | (In millions) | |
Retail: | | | | |
Effect of 9.0% decrease in sales volumes | | $ | (16 | ) |
Change in prices | | | | |
| | | | ) |
Wholesale: | | | | |
Effect of 3.5% increase in sales volumes | | | 4 | |
Change in prices | | | | |
| | | | |
Net Increase in Non-Affiliated Generation Revenues | | | | |
| | Increase | |
Source of Change in Affiliated Generation Revenues | | | |
| | (In millions) | |
Ohio Companies: | | | | |
Effect of 1.2% increase in sales volumes | | $ | 6 | |
Change in prices | | | | |
| | | | |
Pennsylvania Companies: | | | | |
Effect of 9.0% increase in sales volumes | | | 16 | |
Change in prices | | | | ) |
| | | | |
Net Increase in Affiliated Generation Revenues | | | | |
Expenses
Total expenses increased by $94 million in the first three months of 2008 compared with the same period of 2007. The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first three months of 2008 from the same period last year:
Source of Change in Fuel and Purchased Power | | | |
| | (In millions) | |
Nuclear Fuel: | | | | |
Change due to increased unit costs | | $ | 1 | |
Change due to volume consumed | | | (3 | ) |
| | | (2 | ) |
Fossil Fuel: | | | | |
Change due to increased unit costs | | | 19 | |
Change due to volume consumed | | | 71 | |
| | | 90 | |
Non-affiliated Purchased Power: | | | | |
Change due to increased unit costs | | | 55 | |
Change due to volume purchased | | | (34 | ) |
| | | 21 | |
Affiliated Purchased Power: | | | | |
Change due to decreased unit costs | | | (16 | ) |
Change due to volume purchased | | | (35 | ) |
| | | (51 | ) |
Net Increase in Fuel and Purchased Power Costs | | | | |
Fossil fuel costs increased $90 million in the first three months of 2008 primarily as a result of increased coal consumption reflecting higher generation as a result of fewer outages in 2008 compared to 2007. Higher unit prices were due to increased coal transportation and emission allowance costs in the first quarter of 2008. The higher fossil fuel costs were partially offset by lower nuclear fuel costs of $2 million. Lower nuclear fuel costs reflect decreased nuclear generation primarily as a result of the refueling outage at Davis-Besse in the first quarter of 2008.
Purchased power costs decreased as a result of lower purchases from affiliates, partially offset by increased non-affiliated purchased power costs. Purchases from affiliated companies decreased as a result of the assignment of CEI’s and TE’s leasehold interests in the Mansfield Plant to FGCO in October 2007. Purchased power costs from non-affiliates increased primarily as a result of higher market rates partially offset by reduced volume requirements due to increased available fossil generation.
Other operating expenses increased by $33 million in the first three months of 2008 from the same period of 2007 primarily due to lease expenses relating to the assignment of CEI’s and TE’s leasehold interests in the Mansfield Plant to FGCO and the sale and leaseback of Mansfield Unit 1 that were completed subsequent to the first quarter in 2007. Higher nuclear operating costs were due to the refueling outage at Davis-Besse and preparatory work associated with the Beaver Valley Unit 2 refueling outage that is scheduled for the second quarter of 2008.
Depreciation expense increased by $2 million in the first three months of 2008 primarily due to fossil and nuclear property additions since the first quarter of 2007.
General taxes increased by $1 million in the first three months of 2008 compared to the same period of 2007 as a result of higher gross receipts taxes and property taxes.
Other Expense
Other expense increased by $4 million in the first three months of 2008 from the same period of 2007 primarily as a result of an increase in trust securities impairments and reduced loans to the unregulated money pool, partially offset by lower interest expense. Lower interest expense reflected the repayment of notes issued to associated companies in connection with the transfers of generation assets in 2005, partially offset by the issuance of lower-cost pollution control debt subsequent to March 31, 2007.
Legal Proceedings
See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of legal proceedings applicable to FES.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to FES.
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of
Directors of FirstEnergy Solutions Corp.:
We have reviewed the accompanying consolidated balance sheet of FirstEnergy Solutions Corp. and its subsidiaries as of March 31, 2008 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2008 and 2007. 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 (United States), 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, 2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for uncertain tax positions as of January 1, 2007, defined benefit pension and other postretirement plans as of December 31, 2006 and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 8, Note 4, Note 2(G) and Note 11 to the consolidated financial statements) dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, 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 7, 2008 |
FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
| | | | | | |
| | | | | | |
REVENUES: | | | | | | |
Electric sales to affiliates | | $ | 776,307 | | | $ | 713,674 | |
Electric sales to non-affiliates | | | 301,266 | | | | 287,629 | |
Other | | | 21,543 | | | | 16,990 | |
Total revenues | | | 1,099,116 | | | | 1,018,293 | |
| | | | | | | | |
EXPENSES: | | | | | | | | |
Fuel | | | 321,689 | | | | 233,535 | |
Purchased power from non-affiliates | | | 206,724 | | | | 186,203 | |
Purchased power from affiliates | | | 25,485 | | | | 76,483 | |
Other operating expenses | | | 296,546 | | | | 263,596 | |
Provision for depreciation | | | 49,742 | | | | 48,010 | |
General taxes | | | 23,197 | | | | 21,718 | |
Total expenses | | | 923,383 | | | | 829,545 | |
| | | | | | | | |
OPERATING INCOME | | | 175,733 | | | | 188,748 | |
| | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | |
Miscellaneous income (expense) | | | (2,904 | ) | | | 19,732 | |
Interest expense to affiliates | | | (7,210 | ) | | | (29,446 | ) |
Interest expense - other | | | (24,535 | ) | | | (17,358 | ) |
Capitalized interest | | | 6,663 | | | | 3,209 | |
Total other expense | | | (27,986 | ) | | | (23,863 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 147,747 | | | | 164,885 | |
| | | | | | | | |
INCOME TAXES | | | 57,763 | | | | 62,381 | |
| | | | | | | | |
NET INCOME | | | 89,984 | | | | 102,504 | |
| | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
Pension and other postretirement benefits | | | (1,820 | ) | | | (1,360 | ) |
Unrealized gain on derivative hedges | | | 5,718 | | | | 17,758 | |
Change in unrealized gain on available-for-sale securities | | | (51,852 | ) | | | 17,450 | |
Other comprehensive income (loss) | | | (47,954 | ) | | | 33,848 | |
Income tax expense (benefit) related to other comprehensive income | | | (17,403 | ) | | | 12,333 | |
Other comprehensive income (loss), net of tax | | | (30,551 | ) | | | 21,515 | |
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 59,433 | | | $ | 124,019 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Solutions Corp. are an | |
integral part of these statements. | | | | | | | | |
| | | | | | | | |
FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | |
CONSOLIDATED BALANCE SHEETS | |
(Unaudited) | |
| | March 31, | | | December 31, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
ASSETS | | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 2 | | | $ | 2 | |
Receivables- | | | | | | | | |
Customers (less accumulated provisions of $6,988,000 and | | | | | | | | |
$8,072,000, respectively, for uncollectible accounts) | | | 125,116 | | | | 133,846 | |
Associated companies | | | 317,740 | | | | 376,499 | |
Other (less accumulated provisions of $2,500,000 and $9,000, | | | | | | | | |
respectively, for uncollectible accounts) | | | 2,224 | | | | 3,823 | |
Notes receivable from associated companies | | | 737,387 | | | | 92,784 | |
Materials and supplies, at average cost | | | 474,625 | | | | 427,015 | |
Prepayments and other | | | 135,734 | | | | 92,340 | |
| | | 1,792,828 | | | | 1,126,309 | |
PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | |
In service | | | 8,703,760 | | | | 8,294,768 | |
Less - Accumulated provision for depreciation | | | 4,032,545 | | | | 3,892,013 | |
| | | 4,671,215 | | | | 4,402,755 | |
Construction work in progress | | | 1,058,080 | | | | 761,701 | |
| | | 5,729,295 | | | | 5,164,456 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
Nuclear plant decommissioning trusts | | | 1,263,338 | | | | 1,332,913 | |
Long-term notes receivable from associated companies | | | 62,900 | | | | 62,900 | |
Other | | | 24,388 | | | | 40,004 | |
| | | 1,350,626 | | | | 1,435,817 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Accumulated deferred income tax benefits | | | 256,983 | | | | 276,923 | |
Lease assignment receivable from associated companies | | | 67,256 | | | | 215,258 | |
Goodwill | | | 24,248 | | | | 24,248 | |
Property taxes | | | 47,774 | | | | 47,774 | |
Pension assets | | | 16,070 | | | | 16,723 | |
Unamortized sale and leaseback costs | | | 85,695 | | | | 70,803 | |
Other | | | 34,819 | | | | 43,953 | |
| | | 532,845 | | | | 695,682 | |
| | $ | 9,405,594 | | | $ | 8,422,264 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Currently payable long-term debt | | $ | 1,608,456 | | | $ | 1,441,196 | |
Short-term borrowings- | | | | | | | | |
Associated companies | | | 1,145,959 | | | | 264,064 | |
Other | | | 700,000 | | | | 300,000 | |
Accounts payable- | | | | | | | | |
Associated companies | | | 405,668 | | | | 445,264 | |
Other | | | 185,704 | | | | 177,121 | |
Accrued taxes | | | 142,834 | | | | 171,451 | |
Other | | | 248,106 | | | | 237,806 | |
| | | 4,436,727 | | | | 3,036,902 | |
CAPITALIZATION: | | | | | | | | |
Common stockholder's equity - | | | | | | | | |
Common stock, without par value, authorized 750 shares- | | | | | | | | |
7 shares outstanding | | | 1,161,473 | | | | 1,164,922 | |
Accumulated other comprehensive income | | | 110,103 | | | | 140,654 | |
Retained earnings | | | 1,188,639 | | | | 1,108,655 | |
Total common stockholder's equity | | | 2,460,215 | | | | 2,414,231 | |
Long-term debt and other long-term obligations | | | 77,956 | | | | 533,712 | |
| | | 2,538,171 | | | �� | 2,947,943 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Deferred gain on sale and leaseback transaction | | | 1,051,871 | | | | 1,060,119 | |
Accumulated deferred investment tax credits | | | 59,969 | | | | 61,116 | |
Asset retirement obligations | | | 823,686 | | | | 810,114 | |
Retirement benefits | | | 65,348 | | | | 63,136 | |
Property taxes | | | 48,095 | | | | 48,095 | |
Lease market valuation liability | | | 341,881 | | | | 353,210 | |
Other | | | 39,846 | | | | 41,629 | |
| | | 2,430,696 | | | | 2,437,419 | |
COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | |
| | $ | 9,405,594 | | | $ | 8,422,264 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they related to FirstEnergy Solutions Corp. are an | |
integral part of these balance sheets. | | | | | | | | |
FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | |
CONSOLIDATED STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
| | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 89,984 | | | $ | 102,504 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | |
Provision for depreciation | | | 49,742 | | | | 48,010 | |
Nuclear fuel and lease amortization | | | 25,426 | | | | 26,437 | |
Deferred rents and lease market valuation liability | | | (34,887 | ) | | | - | |
Deferred income taxes and investment tax credits, net | | | 30,781 | | | | 21,210 | |
Investment impairment | | | 14,943 | | | | 4,169 | |
Accrued compensation and retirement benefits | | | (11,042 | ) | | | (8,297 | ) |
Commodity derivative transactions, net | | | 8,086 | | | | 537 | |
Gain on asset sales | | | (4,964 | ) | | | - | |
Cash collateral, net | | | 1,601 | | | | 1,384 | |
Pension trust contribution | | | - | | | | (64,020 | ) |
Decrease (increase) in operating assets: | | | | | | | | |
Receivables | | | 69,533 | | | | (62,940 | ) |
Materials and supplies | | | (12,948 | ) | | | 10,580 | |
Prepayments and other current assets | | | (12,260 | ) | | | (1,440 | ) |
Increase (decrease) in operating liabilities: | | | | | | | | |
Accounts payable | | | (17,149 | ) | | | 213,484 | |
Accrued taxes | | | (28,652 | ) | | | (2,913 | ) |
Accrued interest | | | (728 | ) | | | 2,930 | |
Other | | | (7,514 | ) | | | 6,694 | |
Net cash provided from operating activities | | | 159,952 | | | | 298,329 | |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Equity contribution from parent | | | - | | | | 700,000 | |
Short-term borrowings, net | | | 1,281,896 | | | | 197,731 | |
Redemptions and Repayments- | | | | | | | | |
Long-term debt | | | (288,603 | ) | | | (745,444 | ) |
Common stock dividend payments | | | (10,000 | ) | | | - | |
Net cash provided from financing activities | | | 983,293 | | | | 152,287 | |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (476,529 | ) | | | (117,506 | ) |
Proceeds from asset sales | | | 5,088 | | | | - | |
Sales of investment securities held in trusts | | | 173,123 | | | | 178,632 | |
Purchases of investment securities held in trusts | | | (181,079 | ) | | | (188,076 | ) |
Loans to associated companies, net | | | (644,604 | ) | | | (319,898 | ) |
Other | | | (19,244 | ) | | | (3,768 | ) |
Net cash used for investing activities | | | (1,143,245 | ) | | | (450,616 | ) |
| | | | | | | | |
Net change in cash and cash equivalents | | | - | | | | - | |
Cash and cash equivalents at beginning of period | | | 2 | | | | 2 | |
Cash and cash equivalents at end of period | | $ | 2 | | | $ | 2 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Solutions Corp. are an integral part of | |
these statements. | | | | | | | | |
OHIO EDISON COMPANY AND SUBSIDIARIES
ANALYSIS OF RESULTS OF OPERATIONS |
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. They provide generation services to those customers electing to retain OE and Penn as their power supplier. OE’s power supply requirements are provided by FES – an affiliated company. Penn purchases power from FES and third-party suppliers through a competitive RFP process.
Results of Operations
In the first three months of 2008, net income decreased to $44 million from $54 million in the same period of 2007. The decrease primarily resulted from higher operating costs, a decrease in the deferral of new regulatory assets and lower investment income, partially offset by higher electric sales revenues.
Revenues
Revenues increased by $27 million, or 4.3%, in the first three months of 2008 compared with the same period in 2007, primarily due to increases in retail generation revenues ($17 million) and distribution throughput revenues ($12 million).
Retail generation revenues increased primarily due to higher average prices across all customer classes, partially offset by decreased KWH sales to commercial and industrial customers. The higher average prices included the 2008 fuel cost recovery rider that became effective January 16, 2008 (see “Regulatory Matters – Ohio” within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries). Weather conditions in the first three months of 2008 compared to the same period in 2007 contributed to the higher KWH sales to residential customers (heating degree days increased 2.8% and 0.7% in OE’s and Penn’s service territories, respectively). Commercial and industrial retail generation KWH sales were lower due to increased customer shopping in Penn’s service territory in the first quarter of 2008 compared to the same period last year.
Changes in retail generation sales and revenues in the first three months of 2008 from the same period in 2007 are summarized in the following tables:
Retail Generation KWH Sales | | Increase (Decrease) | |
| | | | |
Residential | | | 1.0 | % |
Commercial | | | (2.5 | )% |
Industrial | | | (4.1 | )% |
Net Decrease in Generation Sales | | | (1.5 | )% |
Retail Generation Revenues | | Increase | |
| | (In millions) | |
Residential | | $ | 11 | |
Commercial | | | 1 | |
Industrial | | | 5 | |
Increase in Generation Revenues | | $ | 17 | |
Revenues from distribution throughput increased by $12 million in the first three months of 2008 compared to the same period in 2007 due to higher average unit prices for all customer classes and higher KWH deliveries to residential and commercial customers. The higher average prices resulted from a transmission rider increase effective July 1, 2007. The higher KWH deliveries to residential and commercial customers reflected the favorable weather conditions described above.
Changes in distribution KWH deliveries and revenues in the first three months of 2008 from the same period in 2007 are summarized in the following tables.
Distribution KWH Deliveries | | | Increase (Decrease) | |
| | | | |
Residential | | | 1.7 | % |
Commercial | | | 1.2 | % |
Industrial | | | (0.8 | )% |
Net Increase in Distribution Deliveries | | | 0.7 | % |
Distribution Revenues | | Increase | |
| | (In millions) | |
Residential | | $ | 6 | |
Commercial | | | 4 | |
Industrial | | | 2 | |
Increase in Distribution Revenues | | $ | 12 | |
Expenses
Total expenses increased by $15 million in the first three months of 2008 from the same period of 2007. The following table presents changes from the prior year by expense category.
Expenses – Changes | | Increase (Decrease) | |
| | | (In millions) | |
Purchased power costs | | $ | (10 | ) |
Nuclear operating costs | | | 1 | |
Other operating costs | | | 6 | |
Provision for depreciation | | | 3 | |
Amortization of regulatory assets | | | 3 | |
Deferral of new regulatory assets | | | 11 | |
General taxes | | | 1 | |
Net Increase in Expenses | | $ | 15 | |
Lower purchased power costs in the first three months of 2008 primarily reflected the lower retail generation KWH sales in Penn’s service territory described above, partially offset by higher unit prices as provided for under OE’s PSA with FES. The increase in other operating costs for the first three months of 2008 was primarily due to higher transmission expenses related to MISO operations. Higher depreciation expense in the first three months of 2008 reflected capital additions subsequent to the first quarter of 2007. Higher amortization of regulatory assets in the first three months of 2008 was primarily due to increased amortization of MISO transmission deferrals. The decrease in the deferral of new regulatory assets for the first three months of 2008 was primarily due to lower MISO costs deferred in excess of transmission revenues and lower RCP fuel and distribution cost deferrals.
Other Income
Other income decreased $12 million in the first three months of 2008 as compared with the same period of 2007 primarily due to reductions in interest income on notes receivable resulting from principal payments from associated companies since the first quarter of 2007.
Income Taxes
In the first quarter of 2007, OE’s income taxes included an immaterial adjustment applicable to prior periods of $7.2 million related to an inter-company federal tax allocation arrangement between FirstEnergy and its subsidiaries.
Legal Proceedings
See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other legal proceedings applicable to OE.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to OE.
Report of Independent Registered Public Accounting Firm
To the Stockholder 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, 2008 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2008 and 2007. 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 (United States), 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, 2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for uncertain tax positions as of January 1, 2007, defined benefit pension and other postretirement plans as of December 31, 2006 and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 8, Note 4, Note 2(G) and Note 11 to the consolidated financial statements) dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, 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 7, 2008 |
OHIO EDISON COMPANY | |
| | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | | | | | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
| | | | | | |
REVENUES: | | | | | | |
Electric sales | | $ | 622,271 | | | $ | 594,344 | |
Excise tax collections | | | 30,378 | | | | 31,254 | |
Total revenues | | | 652,649 | | | | 625,598 | |
| | | | | | | | |
EXPENSES: | | | | | | | | |
Fuel | | | 3,170 | | | | 3,015 | |
Purchased power | | | 340,186 | | | | 349,852 | |
Nuclear operating costs | | | 43,021 | | | | 41,514 | |
Other operating costs | | | 94,135 | | | | 88,486 | |
Provision for depreciation | | | 21,493 | | | | 18,848 | |
Amortization of regulatory assets | | | 48,538 | | | | 45,417 | |
Deferral of new regulatory assets | | | (25,411 | ) | | | (36,649 | ) |
General taxes | | | 50,453 | | | | 49,745 | |
Total expenses | | | 575,585 | | | | 560,228 | |
| | | | | | | | |
OPERATING INCOME | | | 77,064 | | | | 65,370 | |
| | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | |
Investment income | | | 15,055 | | | | 26,630 | |
Miscellaneous income (expense) | | | (3,806 | ) | | | 373 | |
Interest expense | | | (17,641 | ) | | | (21,022 | ) |
Capitalized interest | | | 110 | | | | 110 | |
Total other income (expense) | | | (6,282 | ) | | | 6,091 | |
| | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 70,782 | | | | 71,461 | |
| | | | | | | | |
INCOME TAXES | | | 26,873 | | | | 17,426 | |
| | | | | | | | |
NET INCOME | | | 43,909 | | | | 54,035 | |
| | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
Pension and other postretirement benefits | | | (3,994 | ) | | | (3,423 | ) |
Change in unrealized gain on available-for-sale securities | | | (7,571 | ) | | | (126 | ) |
Other comprehensive loss | | | (11,565 | ) | | | (3,549 | ) |
Income tax benefit related to other comprehensive loss | | | (4,262 | ) | | | (1,503 | ) |
Other comprehensive loss, net of tax | | | (7,303 | ) | | | (2,046 | ) |
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 36,606 | | | $ | 51,989 | |
| | | | | | | | |
The accompanying 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) | |
| | March 31, | | | December 31, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
ASSETS | | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 732 | | | $ | 732 | |
Receivables- | | | | | | | | |
Customers (less accumulated provisions of $7,870,000 and $8,032,000, | | | | | | | | |
respectively, for uncollectible accounts) | | | 266,360 | | | | 248,990 | |
Associated companies | | | 179,875 | | | | 185,437 | |
Other (less accumulated provisions of $5,638,000 and $5,639,000, | | | | | | | | |
respectively, for uncollectible accounts) | | | 16,474 | | | | 12,395 | |
Notes receivable from associated companies | | | 589,790 | | | | 595,859 | |
Prepayments and other | | | 17,785 | | | | 10,341 | |
| | | 1,071,016 | | | | 1,053,754 | |
UTILITY PLANT: | | | | | | | | |
In service | | | 2,804,505 | | | | 2,769,880 | |
Less - Accumulated provision for depreciation | | | 1,106,174 | | | | 1,090,862 | |
| | | 1,698,331 | | | | 1,679,018 | |
Construction work in progress | | | 60,617 | | | | 50,061 | |
| | | 1,758,948 | | | | 1,729,079 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
Long-term notes receivable from associated companies | | | 258,405 | | | | 258,870 | |
Investment in lease obligation bonds | | | 253,747 | | | | 253,894 | |
Nuclear plant decommissioning trusts | | | 119,948 | | | | 127,252 | |
Other | | | 33,014 | | | | 36,037 | |
| | | 665,114 | | | | 676,053 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Regulatory assets | | | 709,969 | | | | 737,326 | |
Pension assets | | | 235,933 | | | | 228,518 | |
Property taxes | | | 65,520 | | | | 65,520 | |
Unamortized sale and leaseback costs | | | 43,882 | | | | 45,133 | |
Other | | | 44,640 | | | | 48,075 | |
| | | 1,099,944 | | | | 1,124,572 | |
| | $ | 4,595,022 | | | $ | 4,583,458 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Currently payable long-term debt | | $ | 334,656 | | | $ | 333,224 | |
Short-term borrowings- | | | | | | | | |
Associated companies | | | 50,692 | | | | 50,692 | |
Other | | | 2,609 | | | | 2,609 | |
Accounts payable- | | | | | | | | |
Associated companies | | | 155,654 | | | | 174,088 | |
Other | | | 19,376 | | | | 19,881 | |
Accrued taxes | | | 93,390 | | | | 89,571 | |
Accrued interest | | | 16,459 | | | | 22,378 | |
Other | | | 99,532 | | | | 65,163 | |
| | | 772,368 | | | | 757,606 | |
CAPITALIZATION: | | | | | | | | |
Common stockholder's equity- | | | | | | | | |
Common stock, without par value, authorized 175,000,000 shares - | | | | | | | | |
60 shares outstanding | | | 1,220,368 | | | | 1,220,512 | |
Accumulated other comprehensive income | | | 41,083 | | | | 48,386 | |
Retained earnings | | | 351,186 | | | | 307,277 | |
Total common stockholder's equity | | | 1,612,637 | | | | 1,576,175 | |
Long-term debt and other long-term obligations | | | 839,107 | | | | 840,591 | |
| | | 2,451,744 | | | | 2,416,766 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Accumulated deferred income taxes | | | 783,777 | | | | 781,012 | |
Accumulated deferred investment tax credits | | | 15,990 | | | | 16,964 | |
Asset retirement obligations | | | 95,009 | | | | 93,571 | |
Retirement benefits | | | 176,597 | | | | 178,343 | |
Deferred revenues - electric service programs | | | 36,821 | | | | 46,849 | |
Other | | | 262,716 | | | | 292,347 | |
| | | 1,370,910 | | | | 1,409,086 | |
COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | |
| | $ | 4,595,022 | | | $ | 4,583,458 | |
| | | | | | | | |
The accompanying 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 | |
| | March 31, | |
| | | | | | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
| | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 43,909 | | | $ | 54,035 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
Provision for depreciation | | | 21,493 | | | | 18,848 | |
Amortization of regulatory assets | | | 48,538 | | | | 45,417 | |
Deferral of new regulatory assets | | | (25,411 | ) | | | (36,649 | ) |
Amortization of lease costs | | | 32,934 | | | | 32,934 | |
Deferred income taxes and investment tax credits, net | | | 6,866 | | | | (3,992 | ) |
Accrued compensation and retirement benefits | | | (19,482 | ) | | | (16,794 | ) |
Pension trust contribution | | | - | | | | (20,261 | ) |
Increase in operating assets- | | | | | | | | |
Receivables | | | (27,496 | ) | | | (102,469 | ) |
Prepayments and other current assets | | | (7,451 | ) | | | (6,339 | ) |
Increase (decrease) in operating liabilities- | | | | | | | | |
Accounts payable | | | (18,939 | ) | | | 42,095 | |
Accrued taxes | | | 2,991 | | | | (46,791 | ) |
Accrued interest | | | (5,919 | ) | | | (6,812 | ) |
Electric service prepayment programs | | | (10,028 | ) | | | (9,053 | ) |
Other | | | (2,066 | ) | | | (3,283 | ) |
Net cash provided from (used for) operating activities | | | 39,939 | | | | (59,114 | ) |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Short-term borrowings, net | | | - | | | | 77,473 | |
Redemptions and Repayments- | | | | | | | | |
Common stock | | | - | | | | (500,000 | ) |
Long-term debt | | | (80 | ) | | | (72 | ) |
Net cash used for financing activities | | | (80 | ) | | | (422,599 | ) |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (49,011 | ) | | | (29,888 | ) |
Sales of investment securities held in trusts | | | 62,344 | | | | 12,951 | |
Purchases of investment securities held in trusts | | | (63,797 | ) | | | (13,805 | ) |
Loan repayments from associated companies, net | | | 6,534 | | | | 511,082 | |
Cash investments | | | 147 | | | | 168 | |
Other | | | 3,924 | | | | 1,187 | |
Net cash provided from (used for) investing activities | | | (39,859 | ) | | | 481,695 | |
| | | | | | | | |
Net change in cash and cash equivalents | | | - | | | | (18 | ) |
Cash and cash equivalents at beginning of period | | | 732 | | | | 712 | |
Cash and cash equivalents at end of period | | $ | 732 | | | $ | 694 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part | |
of these statements. | | | | | | | | |
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
ANALYSIS OF RESULTS OF OPERATIONS |
CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business in northeastern Ohio, providing regulated electric distribution services. CEI also provides generation services to those customers electing to retain CEI as their power supplier. CEI’s power supply requirements are primarily provided by FES – an affiliated company.
Results of Operations
Net income in the first three months of 2008 decreased to $58 million from $64 million in the same period of 2007. The decrease resulted primarily from higher purchased power costs, increased amortization of regulatory assets and lower investment income, partially offset by the elimination of fuel costs (due to assigning leasehold interests in generating assets to FGCO) and decreases in other operating expenses.
Revenues
Revenues decreased by $4 million, or 1%, in the first three months of 2008 compared to the same period of 2007 primarily due to a decrease in wholesale generation revenues ($32 million), partially offset by an increase in retail generation revenues ($18 million) and distribution revenues ($10 million).
Wholesale generation revenues decreased due to the assignment of CEI’s leasehold interests in the Bruce Mansfield Plant to FGCO on October 16, 2007. Prior to the assignment, CEI sold power from its interests in the plant to FGCO.
Retail generation revenues increased in the first three months of 2008 due to higher average unit prices across all customer classes and increased sales volume to residential and commercial customers compared to the same period of 2007. The higher average unit prices included the 2008 fuel cost recovery rider that became effective January 16, 2008 (see “Regulatory Matters – Ohio” within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries). More weather-related usage in the first three months of 2008 compared to the same period of 2007 primarily contributed to the increased sales volume in the residential and commercial sectors (heating degree days increased 1.7% from the same period in 2007).
Increases in retail generation sales and revenues in the first three months of 2008 compared to the same period in 2007 are summarized in the following tables:
Retail Generation KWH Sales | | Increase | |
| | | | |
Residential | | | 3.0 | % |
Commercial | | | 1.8 | % |
Industrial | | | 1.0 | % |
Increase in Retail Generation Sales | | | 1.8 | % |
Retail Generation Revenues | | Increase | |
| | (in millions) | |
Residential | | $ | 7 | |
Commercial | | | 4 | |
Industrial | | | 7 | |
Increase in Generation Revenues | | $ | 18 | |
Revenues from distribution throughput increased by $10 million in the first three months of 2008 compared to the same period of 2007 primarily due higher average unit prices for all customer classes and higher KWH deliveries to residential and commercial customers. The higher average unit prices resulted from a transmission rider increase effective July 1, 2007. The higher KWH deliveries to residential and commercial customers in the first three months of 2008 reflected the weather impacts described above.
Changes in distribution KWH deliveries and revenues in the first three months of 2008 compared to the corresponding period of 2007 are summarized in the following tables.
Distribution KWH Deliveries | | Increase | |
| | | | |
Residential | | | 3.0 | % |
Commercial | | | 1.3 | % |
Industrial | | | 1.0 | % |
Increase in Distribution Deliveries | | | 1.7 | % |
Distribution Revenues | | Increase | |
| | (In millions) | |
Residential | | $ | 4 | |
Commercial | | | 3 | |
Industrial | | | 3 | |
Net Increase in Distribution Revenues | | $ | 10 | |
Expenses
Total expenses increased by $1 million in the first three months of 2008 compared to the same period of 2007. The following table presents the change from the prior year by expense category:
Expenses - Changes | | Increase (Decrease) | |
| | (in millions) | |
Fuel costs | | $ | (13 | ) |
Purchased power costs | | | 13 | |
Other operating costs | | | (10 | ) |
Amortization of regulatory assets | | | 5 | |
Deferral of new regulatory assets | | | 5 | |
General taxes | | | 1 | |
Net Increase in Expenses | | $ | 1 | |
The absence of fuel costs in the first three months of 2008 was due to the assignment of CEI’s leasehold interests in the Mansfield Plant to FGCO on October 16, 2007. Prior to the assignment, CEI incurred fuel expenses related to its leasehold interest in the plant. Higher purchased power costs primarily reflected higher unit prices, as provided for under the PSA with FES. Other operating costs were lower primarily due to the assignment of CEI’s leasehold interests in the Mansfield plant. Higher amortization of regulatory assets were primarily due to increased transition cost amortization due to the higher KWH sales discussed above and increases related to the effective interest methodology. The change in deferrals of new regulatory assets was primarily due to lower deferred MISO expenses (more expenses currently recovered through increased transmission tariffs) and RCP fuel costs (implementation of fuel cost recovery rider). The change in general taxes is primarily due to higher real and personal property taxes.
Other Expense
Other expense increased by $5 million in the first three months of 2008 compared to the same period of 2007 primarily due to lower investment income, partially offset by a reduction in interest expense. Lower investment income is primarily the result of principal repayments since the first quarter of 2007 on notes receivable from associated companies. The lower interest expense is due to long-term debt redemptions ($489 million) since the first quarter of 2007, partially offset by a debt issuance in the first quarter of 2007 ($250 million).
Legal Proceedings
See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of legal proceedings applicable to CEI.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to CEI.
.
Report of Independent Registered Public Accounting Firm
To the Stockholder 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, 2008 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2008 and 2007. 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 (United States), 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, 2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for uncertain tax positions as of January 1, 2007, defined benefit pension and other postretirement plans as of December 31, 2006 and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 8, Note 4, Note 2(G) and Note 11 to the consolidated financial statements) dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, 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 7, 2008 |
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | |
| | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | | | | | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
| | | | | | |
REVENUES: | | | | | | |
Electric sales | | $ | 418,708 | | | $ | 422,805 | |
Excise tax collections | | | 18,600 | | | | 18,027 | |
Total revenues | | | 437,308 | | | | 440,832 | |
| | | | | | | | |
EXPENSES: | | | | | | | | |
Fuel | | | - | | | | 13,191 | |
Purchased power | | | 193,244 | | | | 180,657 | |
Other operating costs | | | 65,118 | | | | 74,951 | |
Provision for depreciation | | | 19,076 | | | | 18,468 | |
Amortization of regulatory assets | | | 38,256 | | | | 33,129 | |
Deferral of new regulatory assets | | | (29,248 | ) | | | (33,957 | ) |
General taxes | | | 40,083 | | | | 38,894 | |
Total expenses | | | 326,529 | | | | 325,333 | |
| | | | | | | | |
OPERATING INCOME | | | 110,779 | | | | 115,499 | |
| | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | |
Investment income | | | 9,188 | | | | 17,687 | |
Miscellaneous income | | | 534 | | | | 731 | |
Interest expense | | | (32,520 | ) | | | (35,740 | ) |
Capitalized interest | | | 196 | | | | 205 | |
Total other expense | | | (22,602 | ) | | | (17,117 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 88,177 | | | | 98,382 | |
| | | | | | | | |
INCOME TAXES | | | 30,326 | | | | 34,833 | |
| | | | | | | | |
NET INCOME | | | 57,851 | | | | 63,549 | |
| | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
Pension and other postretirement benefits | | | (213 | ) | | | 1,202 | |
Income tax expense related to other comprehensive income | | | 281 | | | | 355 | |
Other comprehensive income (loss), net of tax | | | (494 | ) | | | 847 | |
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 57,357 | | | $ | 64,396 | |
| | | | | | | | |
The accompanying 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, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
ASSETS | | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 241 | | | $ | 232 | |
Receivables- | | | | | | | | |
Customers (less accumulated provisions of $7,224,000 and $7,540,000, | | | 266,701 | | | | 251,000 | |
respectively, for uncollectible accounts) | | | | | | | | |
Associated companies | | | 70,727 | | | | 166,587 | |
Other | | | 3,643 | | | | 12,184 | |
Notes receivable from associated companies | | | 54,679 | | | | 52,306 | |
Prepayments and other | | | 1,728 | | | | 2,327 | |
| | | 397,719 | | | | 484,636 | |
UTILITY PLANT: | | | | | | | | |
In service | | | 2,142,458 | | | | 2,256,956 | |
Less - Accumulated provision for depreciation | | | 827,160 | | | | 872,801 | |
| | | 1,315,298 | | | | 1,384,155 | |
Construction work in progress | | | 40,834 | | | | 41,163 | |
| | | 1,356,132 | | | | 1,425,318 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
Investment in lessor notes | | | 425,722 | | | | 463,431 | |
Other | | | 10,275 | | | | 10,285 | |
| | | 435,997 | | | | 473,716 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Goodwill | | | 1,688,521 | | | | 1,688,521 | |
Regulatory assets | | | 853,716 | | | | 870,695 | |
Pension assets | | | 64,497 | | | | 62,471 | |
Property taxes | | | 76,000 | | | | 76,000 | |
Other | | | 32,735 | | | | 32,987 | |
| | | 2,715,469 | | | | 2,730,674 | |
| | $ | 4,905,317 | | | $ | 5,114,344 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Currently payable long-term debt | | $ | 207,281 | | | $ | 207,266 | |
Short-term borrowings- | | | | | | | | |
Associated companies | | | 365,816 | | | | 531,943 | |
Accounts payable- | | | | | | | | |
Associated companies | | | 139,423 | | | | 169,187 | |
Other | | | 6,169 | | | | 5,295 | |
Accrued taxes | | | 118,102 | | | | 94,991 | |
Accrued interest | | | 37,726 | | | | 13,895 | |
Other | | | 35,044 | | | | 34,350 | |
| | | 909,561 | | | | 1,056,927 | |
CAPITALIZATION: | | | | | | | | |
Common stockholder's equity | | | | | | | | |
Common stock, without par value, authorized 105,000,000 shares - | | | | | | | | |
67,930,743 shares outstanding | | | 873,353 | | | | 873,536 | |
Accumulated other comprehensive loss | | | (69,623 | ) | | | (69,129 | ) |
Retained earnings | | | 743,278 | | | | 685,428 | |
Total common stockholder's equity | | | 1,547,008 | | | | 1,489,835 | |
Long-term debt and other long-term obligations | | | 1,447,980 | | | | 1,459,939 | |
| | | 2,994,988 | | | | 2,949,774 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Accumulated deferred income taxes | | | 719,938 | | | | 725,523 | |
Accumulated deferred investment tax credits | | | 18,102 | | | | 18,567 | |
Retirement benefits | | | 94,322 | | | | 93,456 | |
Deferred revenues - electric service programs | | | 21,297 | | | | 27,145 | |
Lease assignment payable to associated companies | | | 38,420 | | | | 131,773 | |
Other | | | 108,689 | | | | 111,179 | |
| | | 1,000,768 | | | | 1,107,643 | |
COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | |
| | $ | 4,905,317 | | | $ | 5,114,344 | |
| | | | | | | | |
The accompanying 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, | |
| | | | | | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
| | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 57,851 | | | $ | 63,549 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
Provision for depreciation | | | 19,076 | | | | 18,468 | |
Amortization of regulatory assets | | | 38,256 | | | | 33,129 | |
Deferral of new regulatory assets | | | (29,248 | ) | | | (33,957 | ) |
Deferred rents and lease market valuation liability | | | - | | | | (46,528 | ) |
Deferred income taxes and investment tax credits, net | | | (4,965 | ) | | | (5,453 | ) |
Accrued compensation and retirement benefits | | | (3,507 | ) | | | (890 | ) |
Pension trust contribution | | | - | | | | (24,800 | ) |
Decrease in operating assets- | | | | | | | | |
Receivables | | | 90,280 | | | | 224,011 | |
Prepayments and other current assets | | | 604 | | | | 592 | |
Increase (decrease) in operating liabilities- | | | | | | | | |
Accounts payable | | | (28,889 | ) | | | (256,808 | ) |
Accrued taxes | | | 23,196 | | | | 13,959 | |
Accrued interest | | | 23,831 | | | | 18,122 | |
Electric service prepayment programs | | | (5,847 | ) | | | (5,313 | ) |
Other | | | (63 | ) | | | (167 | ) |
Net cash provided from (used for) operating activities | | | 180,575 | | | | (2,086 | ) |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Long-term debt | | | - | | | | 247,715 | |
Redemptions and Repayments- | | | | | | | | |
Long-term debt | | | (165 | ) | | | (150 | ) |
Short-term borrowings, net | | | (177,960 | ) | | | (130,585 | ) |
Dividend Payments- | | | | | | | | |
Common stock | | | - | | | | (24,000 | ) |
Net cash provided from (used for) financing activities | | | (178,125 | ) | | | 92,980 | |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (37,203 | ) | | | (36,682 | ) |
Loans to associated companies, net | | | (2,373 | ) | | | (231,907 | ) |
Collection of principal on long-term notes receivable | | | - | | | | 133,341 | |
Redemptions of lessor notes | | | 37,709 | | | | 35,614 | |
Other | | | (574 | ) | | | 9,294 | |
Net cash used for investing activities | | | (2,441 | ) | | | (90,340 | ) |
| | | | | | | | |
Net increase in cash and cash equivalents | | | 9 | | | | 554 | |
Cash and cash equivalents at beginning of period | | | 232 | | | | 221 | |
Cash and cash equivalents at end of period | | $ | 241 | | | $ | 775 | |
| | | | | | | | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating | |
Company are an integral part of these statements. | | | | | | | | |
THE TOLEDO EDISON COMPANY AND SUBSIDIARY
ANALYSIS OF RESULTS OF OPERATIONS |
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’s power supply requirements are provided by FES – an affiliated company.
Results of Operations
Net income in the first three months of 2008 decreased to $17 million from $26 million in the same period of 2007. The decrease resulted primarily from lower electric sales revenues, higher purchased power costs and a decrease in the deferral of new regulatory assets, partially offset by lower fuel, nuclear and other operating costs.
Revenues
Revenues decreased $29 million, or 12%, in the first three months of 2008 compared to the same period of 2007 primarily due to lower wholesale generation revenues ($45 million), partially offset by increased retail generation revenues ($11 million) and distribution revenues ($4 million).
The decrease in wholesale revenues resulted primarily from the termination of TE’s Beaver Valley Unit 2 sale agreement with CEI at the end of 2007 ($26 million) and lower PSA sales to FES in the first three months of 2008 ($20 million) due to the assignment of TE’s leasehold interests in the Bruce Mansfield Plant to FGCO effective October 16, 2007. In 2008, TE is selling the 158 MW entitlement from its 18.26% leasehold interest in Beaver Valley Unit 2 to NGC.
Retail generation revenues increased in the first three months of 2008 due to higher average prices across all customer classes and increased KWH sales to residential and commercial customers compared to the same period of 2007. Industrial KWH sales decreased due in part to a maintenance outage for a large industrial customer during the first quarter of 2008. The higher average prices included the 2008 fuel cost recovery rider that became effective January 16, 2008 (see “Regulatory Matters – Ohio” within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries). The increase in sales volume reflects increased weather-related usage in the first three months of 2008 (heating degree days increased 3.3% from the same period of 2007).
Changes in retail electric generation KWH sales and revenues in the first three months of 2008 from the same period of 2007 are summarized in the following tables.
| | Increase | |
Retail Generation KWH Sales | | (Decrease) | |
| | | | |
Residential | | | 4.4 | % |
Commercial | | | 5.6 | % |
Industrial | | | (4.3 | )% |
Net Decrease in Retail Generation Sales | | | (0.1 | )% |
Retail Generation Revenues | | Increase | |
| | (In millions) | |
Residential | | $ | 4 | |
Commercial | | | 3 | |
Industrial | | | 4 | |
Increase in Retail Generation Revenues | | $ | 11 | |
Revenues from distribution throughput increased by $4 million in the first three months of 2008 compared to the same period in 2007 due to higher average unit prices for all customer classes and higher KWH deliveries to residential and commercial customers. The higher average prices resulted from a transmission rider increase effective July 1, 2007. The higher KWH deliveries to residential and commercial customers in the first three months of 2008 reflected the weather impacts described above.
Changes in distribution KWH deliveries and revenues in the first three months of 2008 from the same period of 2007 are summarized in the following tables.
| | Increase | |
Distribution KWH Deliveries | | (Decrease) | |
| | | | |
Residential | | | 3.6 | % |
Commercial | | | 2.3 | % |
Industrial | | | (4.0 | )% |
Net Decrease in Distribution Deliveries | | | (0.4 | )% |
Distribution Revenues | | Increase (Decrease) | |
| | (In millions) | |
Residential | | $ | 3 | |
Commercial | | | 2 | |
Industrial | | | (1 | ) |
Net Increase in Distribution Revenues | | $ | 4 | |
Expenses
Total expenses decreased $15 million in the first three months of 2008 from the same period of 2007. The following table presents changes from the prior year by expense category.
Expenses – Changes | | Increase (Decrease) | |
| | (In millions) | |
| | $ | | |
Purchased power costs | | | | |
| | | | ) |
| | | | |
Amortization of regulatory assets | | | | |
Deferral of new regulatory assets | | | | |
| | | | |
| | | | ) |
Lower fuel costs in the first three months of 2008 compared to the same period of 2007 were due to the assignment of TE’s leasehold interests in the Mansfield Plant to FGCO in October 2007. Higher purchased power costs reflected higher unit prices as provided for under the PSA with FES and a 1.8% increase in KWH purchases. Nuclear operating expenses decreased primarily due to the reversal ($8 million) of the above-market lease liability associated with TE’s leasehold interest in Beaver Valley Unit 2 related to the termination of the CEI sale agreement discussed above. Other operating costs were lower primarily due to the assignment of TE’s leasehold interests in the Mansfield Plant ($9 million). The change in the deferral of new regulatory assets was primarily due to lower deferred RCP distribution costs ($3 million) and fuel costs ($1 million).
Other Expense
Other expense decreased $2 million in the first three months of 2008 compared to the same period of 2007 primarily due to lower interest expense, partially offset by lower investment income. The lower interest expense resulted from the redemption of long-term debt ($85 million principal amount) since the first quarter of 2007. The decrease in investment income resulted primarily from the principal repayments since the first quarter of 2007 on notes receivable from associated companies.
Legal Proceedings
See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of legal proceedings applicable to TE.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to TE.
.
Report of Independent Registered Public Accounting Firm
To the Stockholder 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, 2008 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2008 and 2007. 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 (United States), 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, 2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for uncertain tax positions as of January 1, 2007 and defined benefit pension and other postretirement plans as of December 31, 2006, as discussed in Note 8 and Note 4 to the consolidated financial statements) dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, 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 7, 2008 |
THE TOLEDO EDISON COMPANY | |
| | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | | | | | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
| | | | | | |
REVENUES: | | | | | | |
Electric sales | | $ | 203,669 | | | $ | 233,056 | |
Excise tax collections | | | 8,025 | | | | 7,400 | |
Total revenues | | | 211,694 | | | | 240,456 | |
| | | | | | | | |
EXPENSES: | | | | | | | | |
Fuel | | | 1,482 | | | | 10,147 | |
Purchased power | | | 101,298 | | | | 96,169 | |
Nuclear operating costs | | | 10,457 | | | | 17,721 | |
Other operating costs | | | 33,390 | | | | 42,921 | |
Provision for depreciation | | | 9,025 | | | | 9,117 | |
Amortization of regulatory assets | | | 25,025 | | | | 23,876 | |
Deferral of new regulatory assets | | | (9,494 | ) | | | (13,481 | ) |
General taxes | | | 14,377 | | | | 13,734 | |
Total expenses | | | 185,560 | | | | 200,204 | |
| | | | | | | | |
OPERATING INCOME | | | 26,134 | | | | 40,252 | |
| | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | |
Investment income | | | 6,481 | | | | 7,225 | |
Miscellaneous expense | | | (1,514 | ) | | | (3,100 | ) |
Interest expense | | | (6,035 | ) | | | (7,503 | ) |
Capitalized interest | | | 37 | | | | 83 | |
Total other expense | | | (1,031 | ) | | | (3,295 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 25,103 | | | | 36,957 | |
| | | | | | | | |
INCOME TAXES | | | 8,088 | | | | 11,097 | |
| | | | | | | | |
NET INCOME | | | 17,015 | | | | 25,860 | |
| | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
Pension and other postretirement benefits | | | (63 | ) | | | 573 | |
Change in unrealized gain on available-for-sale securities | | | 1,961 | | | | 379 | |
Other comprehensive income | | | 1,898 | | | | 952 | |
Income tax expense related to other comprehensive income | | | 728 | | | | 334 | |
Other comprehensive income, net of tax | | | 1,170 | | | | 618 | |
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 18,185 | | | $ | 26,478 | |
| | | | | | | | |
The accompanying 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, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
ASSETS | | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 213 | | | $ | 22 | |
Receivables- | | | | | | | | |
Customers | | | 966 | | | | 449 | |
Associated companies | | | 42,232 | | | | 88,796 | |
Other (less accumulated provisions of $471,000 and $615,000, | | | | | |
respectively, for uncollectible accounts) | | | 4,241 | | | | 3,116 | |
Notes receivable from associated companies | | | 107,664 | | | | 154,380 | |
Prepayments and other | | | 684 | | | | 865 | |
| | | 156,000 | | | | 247,628 | |
UTILITY PLANT: | | | | | | | | |
In service | | | 854,457 | | | | 931,263 | |
Less - Accumulated provision for depreciation | | | 397,670 | | | | 420,445 | |
| | | 456,787 | | | | 510,818 | |
Construction work in progress | | | 28,735 | | | | 19,740 | |
| | | 485,522 | | | | 530,558 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
Investment in lessor notes | | | 142,657 | | | | 154,646 | |
Long-term notes receivable from associated companies | | | 37,457 | | | | 37,530 | |
Nuclear plant decommissioning trusts | | | 69,491 | | | | 66,759 | |
Other | | | 1,734 | | | | 1,756 | |
| | | 251,339 | | | | 260,691 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Goodwill | | | 500,576 | | | | 500,576 | |
Regulatory assets | | | 187,579 | | | | 203,719 | |
Pension assets | | | 29,420 | | | | 28,601 | |
Property taxes | | | 21,010 | | | | 21,010 | |
Other | | | 28,959 | | | | 20,496 | |
| | | 767,544 | | | | 774,402 | |
| | $ | 1,660,405 | | | $ | 1,813,279 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Currently payable long-term debt | | $ | 34 | | | $ | 34 | |
Accounts payable- | | | | | | | | |
Associated companies | | | 56,448 | | | | 245,215 | |
Other | | | 3,973 | | | | 4,449 | |
Notes payable to associated companies | | | 66,217 | | | | 13,396 | |
Accrued taxes | | | 37,085 | | | | 30,245 | |
Lease market valuation liability | | | 36,900 | | | | 36,900 | |
Other | | | 51,563 | | | | 22,747 | |
| | | 252,220 | | | | 352,986 | |
CAPITALIZATION: | | | | | | | | |
Common stockholder's equity- | | | | | | | | |
Common stock, $5 par value, authorized 60,000,000 shares - | | | | | |
29,402,054 shares outstanding | | | 147,010 | | | | 147,010 | |
Other paid-in capital | | | 173,141 | | | | 173,169 | |
Accumulated other comprehensive loss | | | (9,436 | ) | | | (10,606 | ) |
Retained earnings | | | 192,633 | | | | 175,618 | |
Total common stockholder's equity | | | 503,348 | | | | 485,191 | |
Long-term debt and other long-term obligations | | | 303,392 | | | | 303,397 | |
| | | 806,740 | | | | 788,588 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Accumulated deferred income taxes | | | 99,732 | | | | 103,463 | |
Accumulated deferred investment tax credits | | | 9,967 | | | | 10,180 | |
Lease market valuation liability | | | 300,775 | | | | 310,000 | |
Retirement benefits | | | 64,422 | | | | 63,215 | |
Asset retirement obligations | | | 28,744 | | | | 28,366 | |
Deferred revenues - electric service programs | | | 9,969 | | | | 12,639 | |
Lease assignment payable to associated companies | | | 28,835 | | | | 83,485 | |
Other | | | 59,001 | | | | 60,357 | |
| | | 601,445 | | | | 671,705 | |
COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | |
| | $ | 1,660,405 | | | $ | 1,813,279 | |
| | | | | | | | |
The accompanying 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, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
| | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 17,015 | | | $ | 25,860 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
Provision for depreciation | | | 9,025 | | | | 9,117 | |
Amortization of regulatory assets | | | 25,025 | | | | 23,876 | |
Deferral of new regulatory assets | | | (9,494 | ) | | | (13,481 | ) |
Deferred rents and lease market valuation liability | | | 6,099 | | | | (10,891 | ) |
Deferred income taxes and investment tax credits, net | | | (3,404 | ) | | | (3,639 | ) |
Accrued compensation and retirement benefits | | | (1,813 | ) | | | (756 | ) |
Pension trust contribution | | | - | | | | (7,659 | ) |
Decrease in operating assets- | | | | | | | | |
Receivables | | | 45,738 | | | | 158 | |
Prepayments and other current assets | | | 181 | | | | 312 | |
Increase (decrease) in operating liabilities- | | | | | | | | |
Accounts payable | | | (189,243 | ) | | | (17,533 | ) |
Accrued taxes | | | 6,840 | | | | 9,379 | |
Accrued interest | | | 4,663 | | | | 3,951 | |
Electric service prepayment programs | | | (2,670 | ) | | | (2,616 | ) |
Other | | | 991 | | | | (541 | ) |
Net cash provided from (used for) operating activities | | | (91,047 | ) | | | 15,537 | |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Short-term borrowings, net | | | 52,821 | | | | - | |
Redemptions and Repayments- | | | | | | | | |
Long-term debt | | | (9 | ) | | | - | |
Short-term borrowings, net | | | - | | | | (46,518 | ) |
Net cash provided from (used for) financing activities | | | 52,812 | | | | (46,518 | ) |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (19,435 | ) | | | (6,064 | ) |
Loans repayments from (loans to) associated companies, net | | | 46,789 | | | | (8,583 | ) |
Collection of principal on long-term notes receivable | | | - | | | | 32,202 | |
Redemption of lessor notes | | | 11,989 | | | | 14,804 | |
Sales of investment securities held in trusts | | | 3,908 | | | | 16,863 | |
Purchases of investment securities held in trusts | | | (4,715 | ) | | | (17,642 | ) |
Other | | | (110 | ) | | | (420 | ) |
Net cash provided from investing activities | | | 38,426 | | | | 31,160 | |
| | | | | | | | |
Net increase in cash and cash equivalents | | | 191 | | | | 179 | |
Cash and cash equivalents at beginning of period | | | 22 | | | | 22 | |
Cash and cash equivalents at end of period | | $ | 213 | | | $ | 201 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an | |
integral part of these statements. | | | | | | | | |
JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
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.
Results of Operations
METROPOLITAN EDISON COMPANY AND SUBSIDIARIES
PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARIESNet income for the first three months of 2008 decreased to $34 million from $38 million in the same period in 2007. The decrease was primarily due to higher other operating costs, partially offset by higher non-generation revenues.
Revenues
In the first three months of 2008, revenues increased $111 million, or 16.5%, as compared with the same period of 2007. Retail and wholesale generation revenues increased by $73 million and $38 million, respectively, in the first three months of 2008.
Retail generation revenues from all customer classes increased in the first three months of 2008 compared to the same period of 2007 due to higher unit prices resulting from the BGS auction effective June 1, 2007, partially offset by a slight decrease in retail generation KWH sales. Sales volume decreased primarily due to milder weather in the first three months of 2008 (heating degree days were 6.7% lower than the first three months of 2007) and an increase in customer shopping in the commercial and industrial customer sectors by 3.6 percentage points and 3.0 percentage points, respectively.
Wholesale generation revenues increased $38 million in the first three months of 2008 due to higher market prices, partially offset by a slight decrease in sales volumes as compared to the first three months of 2007.
Changes in retail generation KWH sales and revenues by customer class in the first three months of 2008 compared to the same period of 2007 are summarized in the following tables:
Retail Generation KWH Sales | | Increase (Decrease) | |
| | | | |
Residential | | | 0.1 | % |
Commercial | | | (3.4 | )% |
Industrial | | | (12.4 | )% |
Net Decrease in Generation Sales | | | (1.9 | )% |
Retail Generation Revenues | | Increase | |
| | (In millions) | |
Residential | | $ | 43 | |
Commercial | | | 28 | |
Industrial | | | 2 | |
Increase in Generation Revenues | | $ | 73 | |
Distribution revenues increased in the first three months of 2008 as compared to the same period of 2007 due to slight increases in composite unit prices and KWH deliveries.
Changes in distribution KWH deliveries in the first three months of 2008 compared to the same period in 2007 are summarized in the following table:
| | Increase | |
Distribution KWH Deliveries | | (Decrease) | |
| | | | | |
Residential | | | | 0.1 | % |
Commercial | | | | 1.2 | % |
Industrial | | | | (1.3 | )% |
Net Increase in Distribution Deliveries | | | | 0.4 | % |
Expenses
Total expenses increased by $113 million in the first three months of 2008 as compared to the same period of 2007. The following table presents changes from the prior year period by expense category:
Expenses - Changes | | | Increase (Decrease) | |
| | | (In millions) | |
Purchased power costs | | | $ | 110 | |
Other operating costs | | | | 4 | |
Provision for depreciation | | | | 3 | |
Amortization of regulatory assets | | | | (4 | ) |
Net increase in expenses | | | $ | 113 | |
Purchased power costs increased in the first three months of 2008 primarily due to higher unit prices resulting from the BGS auction effective June 1, 2007, partially offset by a decrease in purchases due to the lower KWH sales discussed above. Other operating costs increased in the first three months of 2008 primarily due to higher expenses related to JCP&L’s customer assistance programs. Depreciation expense increased primarily due to an increase in depreciable property since the first quarter of 2007. Amortization of regulatory assets decreased in the first three months of 2008 primarily due to the completion in December 2007 of certain regulatory asset amortizations associated with TMI-2.
Other Expenses
Other expenses increased by $6 million in the first three months of 2008 as compared to the same period in 2007 primarily due to interest expense associated with JCP&L’s $550 million issuance of senior notes in May 2007 ($3 million) and reduced income on life insurance investments ($2 million).
Sale of Investment
On April 17, 2008, JCP&L closed on the sale of its 86-MW Forked River Power Plant to Maxim Power Corp. for $20 million. In conjunction with this sale, FES entered into a 10-year tolling agreement with Maxim for the entire capacity of the plant. The sale is subject to regulatory accounting and will not have a material impact on the JCP&L’s earnings in the second quarter of 2008. The New Jersey Rate Counsel has appealed the NJBPU’s approval of the sale to the Appellate Division of the Superior Court of New Jersey, where it is currently pending.
Legal Proceedings
See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other legal proceedings applicable to JCP&L.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to JCP&L.
Report of Independent Registered Public Accounting Firm
To the Stockholder 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, 2008 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2008 and 2007. 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 (United States), 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, 2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for uncertain tax positions as of January 1, 2007 and defined benefit pension and other postretirement plans as of December 31, 2006, as discussed in Note 8 and Note 4 to the consolidated financial statements) dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, 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 7, 2008 |
JERSEY CENTRAL POWER & LIGHT COMPANY | |
| | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
| | | | | | |
REVENUES: | | | | | | |
Electric sales | | $ | 781,433 | | | $ | 670,907 | |
Excise tax collections | | | 12,795 | | | | 12,836 | |
Total revenues | | | 794,228 | | | | 683,743 | |
| | | | | | | | |
EXPENSES: | | | | | | | | |
Purchased power | | | 496,681 | | | | 386,497 | |
Other operating costs | | | 78,784 | | | | 74,651 | |
Provision for depreciation | | | 23,282 | | | | 20,516 | |
Amortization of regulatory assets | | | 91,519 | | | | 95,228 | |
General taxes | | | 17,028 | | | | 16,999 | |
Total expenses | | | 707,294 | | | | 593,891 | |
| | | | | | | | |
OPERATING INCOME | | | 86,934 | | | | 89,852 | |
| | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | |
Miscellaneous income (expense) | | | (389 | ) | | | 3,061 | |
Interest expense | | | (24,464 | ) | | | (22,416 | ) |
Capitalized interest | | | 276 | | | | 513 | |
Total other expense | | | (24,577 | ) | | | (18,842 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 62,357 | | | | 71,010 | |
| | | | | | | | |
INCOME TAXES | | | 28,403 | | | | 32,664 | |
| | | | | | | | |
NET INCOME | | | 33,954 | | | | 38,346 | |
| | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
Pension and other postretirement benefits | | | (3,449 | ) | | | (2,115 | ) |
Unrealized gain on derivative hedges | | | 69 | | | | 97 | |
Other comprehensive loss | | | (3,380 | ) | | | (2,018 | ) |
Income tax benefit related to other comprehensive loss | | | (1,470 | ) | | | (984 | ) |
Other comprehensive loss, net of tax | | | (1,910 | ) | | | (1,034 | ) |
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 32,044 | | | $ | 37,312 | |
| | | | | | | | |
The accompanying 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, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
ASSETS | | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 40 | | | $ | 94 | |
Receivables- | | | | | | | | |
Customers (less accumulated provisions of $3,400,000 and $3,691,000, | | | | | | | | |
respectively, for uncollectible accounts) | | | 299,104 | | | | 321,026 | |
Associated companies | | | 1,757 | | | | 21,297 | |
Other | | | 53,553 | | | | 59,244 | |
Notes receivable - associated companies | | | 18,410 | | | | 18,428 | |
Prepaid taxes | | | 1,302 | | | | 1,012 | |
Other | | | 20,609 | | | | 17,603 | |
| | | 394,775 | | | | 438,704 | |
UTILITY PLANT: | | | | | | | | |
In service | | | 4,208,016 | | | | 4,175,125 | |
Less - Accumulated provision for depreciation | | | 1,524,495 | | | | 1,516,997 | |
| | | 2,683,521 | | | | 2,658,128 | |
Construction work in progress | | | 98,143 | | | | 90,508 | |
| | | 2,781,664 | | | | 2,748,636 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
Nuclear fuel disposal trust | | | 176,107 | | | | 176,512 | |
Nuclear plant decommissioning trusts | | | 168,056 | | | | 175,869 | |
Other | | | 2,054 | | | | 2,083 | |
| | | 346,217 | | | | 354,464 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Regulatory assets | | | 1,475,802 | | | | 1,595,662 | |
Goodwill | | | 1,825,716 | | | | 1,826,190 | |
Pension assets | | | 106,211 | | | | 100,615 | |
Other | | | 15,107 | | | | 16,307 | |
| | | 3,422,836 | | | | 3,538,774 | |
| | $ | 6,945,492 | | | $ | 7,080,578 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Currently payable long-term debt | | $ | 27,735 | | | $ | 27,206 | |
Short-term borrowings- | | | | | | | | |
Associated companies | | | 82,380 | | | | 130,381 | |
Accounts payable- | | | | | | | | |
Associated companies | | | 18,699 | | | | 7,541 | |
Other | | | 168,178 | | | | 193,848 | |
Accrued taxes | | | 32,968 | | | | 3,124 | |
Accrued interest | | | 26,656 | | | | 9,318 | |
Other | | | 107,879 | | | | 103,286 | |
| | | 464,495 | | | | 474,704 | |
CAPITALIZATION: | | | | | | | | |
Common stockholder's equity- | | | | | | | | |
Common stock, $10 par value, authorized 16,000,000 shares- | | | | | | | | |
14,421,637 shares outstanding | | | 144,216 | | | | 144,216 | |
Other paid-in capital | | | 2,655,248 | | | | 2,655,941 | |
Accumulated other comprehensive loss | | | (21,791 | ) | | | (19,881 | ) |
Retained earnings | | | 201,542 | | | | 237,588 | |
Total common stockholder's equity | | | 2,979,215 | | | | 3,017,864 | |
Long-term debt and other long-term obligations | | | 1,554,064 | | | | 1,560,310 | |
| | | 4,533,279 | | | | 4,578,174 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Power purchase contract loss liability | | | 682,481 | | | | 749,671 | |
Accumulated deferred income taxes | | | 798,967 | | | | 800,214 | |
Nuclear fuel disposal costs | | | 194,034 | | | | 192,402 | |
Asset retirement obligations | | | 91,025 | | | | 89,669 | |
Other | | | 181,211 | | | | 195,744 | |
| | | 1,947,718 | | | | 2,027,700 | |
COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | |
| | $ | 6,945,492 | | | $ | 7,080,578 | |
| | | | | | | | |
The accompanying 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 CASH FLOWS | |
(Unaudited) | |
| | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 33,954 | | | $ | 38,346 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
Provision for depreciation | | | 23,282 | | | | 20,516 | |
Amortization of regulatory assets | | | 91,519 | | | | 95,228 | |
Deferred purchased power and other costs | | | (40,293 | ) | | | (78,303 | ) |
Deferred income taxes and investment tax credits, net | | | 723 | | | | 8,076 | |
Accrued compensation and retirement benefits | | | (15,113 | ) | | | (8,374 | ) |
Cash collateral from (returned to) suppliers | | | (502 | ) | | | 1 | |
Pension trust contribution | | | - | | | | (17,800 | ) |
Decrease (increase) in operating assets: | | | | | | | | |
Receivables | | | 48,733 | | | | (23,381 | ) |
Materials and supplies | | | 255 | | | | (1 | ) |
Prepaid taxes | | | (290 | ) | | | 11,946 | |
Other current assets | | | (1,305 | ) | | | 454 | |
Increase (decrease) in operating liabilities: | | | | | | | | |
Accounts payable | | | (14,511 | ) | | | (62,038 | ) |
Accrued taxes | | | 29,844 | | | | 31,599 | |
Accrued interest | | | 17,338 | | | | 9,794 | |
Other | | | 13,302 | | | | (555 | ) |
Net cash provided from operating activities | | | 186,936 | | | | 25,508 | |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Short-term borrowings, net | | | - | | | | 37,071 | |
Redemptions and Repayments- | | | | | | | | |
Long-term debt | | | (5,872 | ) | | | (9,569 | ) |
Short-term borrowings, net | | | (48,069 | ) | | | - | |
Dividend Payments- | | | | | | | | |
Common stock | | | (70,000 | ) | | | (15,000 | ) |
Net cash provided from (used for) financing activities | | | (123,941 | ) | | | 12,502 | |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (56,047 | ) | | | (40,015 | ) |
Loan repayments from associated companies, net | | | 18 | | | | 532 | |
Sales of investment securities held in trusts | | | 56,506 | | | | 26,436 | |
Purchases of investment securities held in trusts | | | (61,290 | ) | | | (30,437 | ) |
Other | | | (2,236 | ) | | | 5,479 | |
Net cash used for investing activities | | | (63,049 | ) | | | (38,005 | ) |
| | | | | | | | |
Net change in cash and cash equivalents | | | (54 | ) | | | 5 | |
Cash and cash equivalents at beginning of period | | | 94 | | | | 41 | |
Cash and cash equivalents at end of period | | $ | 40 | | | $ | 46 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company | |
are an integral part of these statements. | | | | | | | | |
METROPOLITAN EDISON COMPANY
ANALYSIS OF RESULTS OF OPERATIONS |
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.
Results of Operations
Net income decreased to $22 million in the first quarter of 2008, compared to $32 million in the same period of 2007. The decrease was primarily due to higher purchased power costs, increased other operating costs and a decrease in the deferral of new regulatory assets, partially offset by higher revenues.
Revenues
Revenues increased by $30 million, or 8.1%, in the first quarter of 2008, compared to the same period of 2007, primarily due to higher retail and wholesale generation revenues combined with higher distribution throughput revenues, partially offset by a decrease in PJM transmission revenues.
In the first quarter of 2008, retail generation revenues increased $6 million primarily due to higher KWH sales to the residential and commercial customer classes and higher composite unit prices in all customer classes, partially offset by lower KWH sales to the industrial customer class.
Changes in retail generation sales and revenues in the first quarter of 2008 compared to the same period of 2007 are summarized in the following tables:
| | Increase | |
Retail Generation KWH Sales | | (Decrease) | |
| | | | |
Residential | | | 4.6 | % |
Commercial | | | 4.1 | % |
Industrial | | | (1.8 | )% |
Net Increase in Retail Generation Sales | | | 2.7 | % |
| | Increase | |
Retail Generation Revenues | | (Decrease) | |
| | (In millions) | |
Residential | | $ | 4 | |
Commercial | | | 3 | |
Industrial | | | (1 | ) |
Net Increase in Retail Generation Revenues | | $ | 6 | |
Wholesale revenues increased by $27 million in the first quarter of 2008, compared to the same period of 2007, primarily reflecting higher spot market prices for PJM market participants.
Revenues from distribution throughput increased $4 million in the first quarter of 2008, compared to the same period in 2007, due to higher KWH deliveries in the residential and commercial customer classes, partially offset by decreased KWH deliveries to industrial customers.
Changes in distribution KWH deliveries and revenues in the first quarter of 2008 compared to the same period of 2007 are summarized in the following tables:
| | Increase | |
Distribution KWH Deliveries | | (Decrease) | |
| | | | |
Residential | | | 4.6 | % |
Commercial | | | 4.1 | % |
Industrial | | | (1.8 | )% |
Net Increase in Distribution Deliveries | | | 2.7 | % |
Distribution Revenues | | Increase | |
| | (In millions) | |
Residential | | $ | 1 | |
Commercial | | | 3 | |
Industrial | | | - | |
Increase in Distribution Revenues | | $ | 4 | |
PJM transmission revenues decreased by $7 million in the first quarter of 2008 compared to the same period of 2007, primarily due to decreased PJM FTR revenue. Met-Ed defers the difference between revenue from its transmission rider and transmission costs incurred, resulting in no material effect to current period earnings.
Operating Expenses
Total operating expenses increased by $42 million in the first quarter of 2008 compared to the same period of 2007. The following table presents changes from the prior year by expense category:
Expenses – Changes | | Increase | |
| | (In millions) | |
Purchased power costs | | $ | 25 | |
Other operating costs | | | 9 | |
Provision for depreciation | | | 1 | |
Amortization of regulatory assets | | | 1 | |
Deferral of new regulatory assets | | | 5 | |
General taxes | | | 1 | |
Increase in expenses | | $ | 42 | |
Purchased power costs increased by $25 million in the first quarter of 2008, primarily due to higher composite unit prices combined with increased KWH purchased to source increased generation sales. Other operating costs increased by $9 million in the first quarter of 2008 primarily due to higher transmission expenses associated with increased transmission volumes and increased labor and contractor service expenses for storm restoration work performed during the first quarter of 2008.
The deferral of new regulatory assets decreased in the first quarter of 2008 primarily due to the absence of the 2007 deferral of decommissioning costs ($15 million) associated with the Saxton nuclear research facility (see Note 11(C)), partially offset by increased transmission cost deferrals.
Other Expense
Other expense increased in the first quarter of 2008 primarily due to a decrease in interest earned on regulatory assets, reflecting a lower regulatory asset base, combined with an increase in other expenses, primarily due to reduced income from life insurance investments.
Legal Proceedings
See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of legal proceedings applicable to Met-Ed.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to Met-Ed.
Report of Independent Registered Public Accounting Firm
To the Stockholder 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, 2008 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2008 and 2007. 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 (United States), 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, 2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for uncertain tax positions as of January 1, 2007, defined benefit pension and other postretirement plans as of December 31, 2006 and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 8, Note 4, Note 2(G) and Note 11 to the consolidated financial statements) dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, 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 7, 2008 |
METROPOLITAN EDISON COMPANY | |
| | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | | | | | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
| | | | | | |
REVENUES: | | | | | | |
Electric sales | | $ | 379,608 | | | $ | 352,136 | |
Gross receipts tax collections | | | 20,718 | | | | 18,120 | |
Total revenues | | | 400,326 | | | | 370,256 | |
| | | | | | | | |
EXPENSES: | | | | | | | | |
Purchased power | | | 216,982 | | | | 191,589 | |
Other operating costs | | | 107,017 | | | | 98,018 | |
Provision for depreciation | | | 11,112 | | | | 10,284 | |
Amortization of regulatory assets | | | 35,575 | | | | 34,140 | |
Deferral of new regulatory assets | | | (37,772 | ) | | | (42,726 | ) |
General taxes | | | 21,781 | | | | 21,052 | |
Total expenses | | | 354,695 | | | | 312,357 | |
| | | | | | | | |
OPERATING INCOME | | | 45,631 | | | | 57,899 | |
| | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | |
Interest income | | | 5,479 | | | | 7,726 | |
Miscellaneous income (expense) | | | (309 | ) | | | 1,109 | |
Interest expense | | | (11,672 | ) | | | (11,756 | ) |
Capitalized interest | | | (219 | ) | | | 260 | |
Total other expense | | | (6,721 | ) | | | (2,661 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 38,910 | | | | 55,238 | |
| | | | | | | | |
INCOME TAXES | | | 16,675 | | | | 23,599 | |
| | | | | | | | |
NET INCOME | | | 22,235 | | | | 31,639 | |
| | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
Pension and other postretirement benefits | | | (2,233 | ) | | | (1,452 | ) |
Unrealized gain on derivative hedges | | | 84 | | | | 84 | |
Other comprehensive loss | | | (2,149 | ) | | | (1,368 | ) |
Income tax benefit related to other comprehensive loss | | | (970 | ) | | | (692 | ) |
Other comprehensive loss, net of tax | | | (1,179 | ) | | | (676 | ) |
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 21,056 | | | $ | 30,963 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company | |
are an integral part of these statements. | | | | | | | | |
METROPOLITAN EDISON COMPANY | |
| | | | | | |
CONSOLIDATED BALANCE SHEETS | |
(Unaudited) | |
| | March 31, | | | December 31, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
ASSETS | | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 132 | | | $ | 135 | |
Receivables- | | | | | | | | |
Customers (less accumulated provisions of $4,483,000 and $4,327,000, | | | | | | | | |
respectively, for uncollectible accounts) | | | 144,865 | | | | 142,872 | |
Associated companies | | | 55,776 | | | | 27,693 | |
Other | | | 20,673 | | | | 18,909 | |
Notes receivable from associated companies | | | 12,828 | | | | 12,574 | |
Prepaid taxes | | | 56,202 | | | | 14,615 | |
Other | | | 850 | | | | 1,348 | |
| | | 291,326 | | | | 218,146 | |
UTILITY PLANT: | | | | | | | | |
In service | | | 1,997,131 | | | | 1,972,388 | |
Less - Accumulated provision for depreciation | | | 758,228 | | | | 751,795 | |
| | | 1,238,903 | | | | 1,220,593 | |
Construction work in progress | | | 32,946 | | | | 30,594 | |
| | | 1,271,849 | | | | 1,251,187 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
Nuclear plant decommissioning trusts | | | 271,771 | | | | 286,831 | |
Other | | | 1,377 | | | | 1,360 | |
| | | 273,148 | | | | 288,191 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Goodwill | | | 424,070 | | | | 424,313 | |
Regulatory assets | | | 530,006 | | | | 494,947 | |
Pension assets | | | 54,198 | | | | 51,427 | |
Other | | | 31,097 | | | | 36,411 | |
| | | 1,039,371 | | | | 1,007,098 | |
| | $ | 2,875,694 | | | $ | 2,764,622 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Short-term borrowings- | | | | | | | | |
Associated companies | | $ | 167,070 | | | $ | 185,327 | |
Other | | | 250,000 | | | | 100,000 | |
Accounts payable- | | | | | | | | |
Associated companies | | | 25,556 | | | | 29,855 | |
Other | | | 56,797 | | | | 66,694 | |
Accrued taxes | | | 1,501 | | | | 16,020 | |
Accrued interest | | | 7,059 | | | | 6,778 | |
Other | | | 25,191 | | | | 27,393 | |
| | | 533,174 | | | | 432,067 | |
CAPITALIZATION: | | | | | | | | |
Common stockholder's equity- | | | | | | | | |
Common stock, without par value, authorized 900,000 shares- | | | | | | | | |
859,000 shares outstanding | | | 1,202,833 | | | | 1,203,186 | |
Accumulated other comprehensive loss | | | (16,576 | ) | | | (15,397 | ) |
Accumulated deficit | | | (116,922 | ) | | | (139,157 | ) |
Total common stockholder's equity | | | 1,069,335 | | | | 1,048,632 | |
Long-term debt and other long-term obligations | | | 513,661 | | | | 542,130 | |
| | | 1,582,996 | | | | 1,590,762 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Accumulated deferred income taxes | | | 456,126 | | | | 438,890 | |
Accumulated deferred investment tax credits | | | 8,234 | | | | 8,390 | |
Nuclear fuel disposal costs | | | 43,831 | | | | 43,462 | |
Asset retirement obligations | | | 163,239 | | | | 160,726 | |
Retirement benefits | | | 7,621 | | | | 8,681 | |
Other | | | 80,473 | | | | 81,644 | |
| | | 759,524 | | | | 741,793 | |
COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | |
| | $ | 2,875,694 | | | $ | 2,764,622 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral | |
part of these balance sheets. | | | | | | | | |
METROPOLITAN EDISON COMPANY | |
| | | | | | |
CONSOLIDATED STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
| | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 22,235 | | | $ | 31,639 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | |
Provision for depreciation | | | 11,112 | | | | 10,284 | |
Amortization of regulatory assets | | | 35,575 | | | | 34,140 | |
Deferred costs recoverable as regulatory assets | | | (10,628 | ) | | | (19,160 | ) |
Deferral of new regulatory assets | | | (37,772 | ) | | | (42,726 | ) |
Deferred income taxes and investment tax credits, net | | | 17,307 | | | | 16,178 | |
Accrued compensation and retirement benefits | | | (9,655 | ) | | | (7,683 | ) |
Cash collateral | | | - | | | | 3,050 | |
Pension trust contribution | | | - | | | | (11,012 | ) |
Increase in operating assets- | | | | | | | | |
Receivables | | | (30,863 | ) | | | (49,818 | ) |
Prepayments and other current assets | | | (41,088 | ) | | | (27,131 | ) |
Increase (decrease) in operating liabilities- | | | | | | | | |
Accounts payable | | | (14,196 | ) | | | (58,986 | ) |
Accrued taxes | | | (14,519 | ) | | | (9,835 | ) |
Accrued interest | | | 281 | | | | 1,243 | |
Other | | | 3,892 | | | | 3,939 | |
Net cash used for operating activities | | | (68,319 | ) | | | (125,878 | ) |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Short-term borrowings, net | | | 131,743 | | | | 150,619 | |
Redemptions and Repayments- | | | | | | | | |
Long-term debt | | | (28,515 | ) | | | - | |
Net cash provided from financing activities | | | 103,228 | | | | 150,619 | |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (31,296 | ) | | | (18,803 | ) |
Sales of investment securities held in trusts | | | 40,513 | | | | 25,323 | |
Purchases of investment securities held in trusts | | | (43,391 | ) | | | (28,519 | ) |
Loans to associated companies, net | | | (254 | ) | | | (2,822 | ) |
Other | | | (484 | ) | | | 79 | |
Net cash used for investing activities | | | (34,912 | ) | | | (24,742 | ) |
| | | | | | | | |
Net change in cash and cash equivalents | | | (3 | ) | | | (1 | ) |
Cash and cash equivalents at beginning of period | | | 135 | | | | 130 | |
Cash and cash equivalents at end of period | | $ | 132 | | | $ | 129 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are | |
an integral part of these statements. | | | | | | | | |
PENNSYLVANIA ELECTRIC COMPANY
ANALYSIS OF RESULTS OF OPERATIONS |
Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern 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.
Results of Operations
Net income decreased to $21 million in the first quarter of 2008, compared to $32 million in the same period of 2007. The decrease was primarily due to increased purchased power costs and other operating costs and a decrease in the deferral of new regulatory assets, partially offset by higher revenues.
Revenues
Revenues increased by $40 million, or 11.1%, in the first quarter of 2008 as compared to the same time period of 2007, primarily due to higher retail and wholesale generation revenues, distribution throughput revenues and PJM transmission revenues.
In the first quarter of 2008, retail generation revenues increased $5 million primarily due to higher KWH sales to the residential and commercial customer classes and higher composite unit prices in all customer classes, partially offset by lower KWH sales to the industrial customer class.
Changes in retail generation sales and revenues in the first quarter of 2008 compared to the same period of 2007 are summarized in the following tables:
Retail Generation KWH Sales | | Increase (Decrease) | |
| | | |
Residential | | | 4.5 | % |
Commercial | | | 3.0 | % |
Industrial | | | (1.6 | )% |
Net Increase in Retail Generation Sales | | | 2.2 | % |
Retail Generation Revenues | | Increase | |
| | (In millions) | |
Residential | | $ | 3 | |
Commercial | | | 2 | |
Industrial | | | - | |
Increase in Retail Generation Revenues | | $ | 5 | |
Wholesale revenues increased $21 million in the first quarter of 2008, compared to the same period of 2007, primarily reflecting higher spot market prices for PJM market participants.
Revenues from distribution throughput increased $4 million in the first quarter of 2008 compared to the same period of 2007, due to increased usage in the residential and commercial customer classes, partially offset by decreased KWH deliveries to industrial customers.
Changes in distribution KWH deliveries and revenues in the first quarter of 2008 compared to the same period of 2007 are summarized in the following tables:
Distribution KWH Deliveries | | Increase (Decrease) | |
| | | |
Residential | | | 4.5 | % |
Commercial | | | 3.0 | % |
Industrial | | | (1.5 | )% |
Net Increase in Retail Generation Sales | | | 2.1 | % |
Distribution Revenues | | Increase | |
| | (In millions) | |
Residential | | $ | 2 | |
Commercial | | | 2 | |
Industrial | | | - | |
Increase in Retail Generation Revenues | | $ | 4 | |
PJM transmission revenues increased by $10 million in the first quarter of 2008 compared to the same period of 2007, primarily due to higher transmission volumes. Penelec defers the difference between revenue from its transmission rider and total transmission costs incurred, resulting in no material effect to current period earnings.
Operating Expenses
Total operating expenses increased by $49 million in the first quarter of 2008 as compared with the same period of 2007. The following table presents changes from the prior year by expense category:
| | |
Expenses - Changes | | Increase |
| | (In millions) |
Purchased power costs | | $ | 20 |
Other operating costs | | | 12 |
Provision for depreciation | | | 1 |
Amortization of regulatory assets | | | 1 |
Deferral of new regulatory assets | | | 13 |
General taxes | | | 2 |
Increase in expenses | | $ | 49 |
Purchased power costs increased by $20 million, or 10.2%, in the first quarter of 2008 compared to the same period of 2007, primarily due to increased composite unit prices combined with higher KWH purchases to source increased retail and wholesale generation sales. Other operating costs increased by $12 million in the first quarter of 2008 principally due to higher congestion costs and other transmission expenses associated with increased transmission volumes.
The deferral of new regulatory assets decreased in the first quarter of 2008 primarily due to the absence of the 2007 deferral of decommissioning costs ($12 million) associated with the Saxton nuclear research facility (see Note 11) and a decrease in transmission cost deferrals.
In the first quarter of 2008, general taxes increased $2 million as compared to the same period of 2007, primarily due to higher gross receipts taxes.
Other Expense
In the first quarter of 2008, other expense increased primarily due to higher interest expense associated with Penelec’s $300 million senior note issuance in August 2007 and reduced income from life insurance investments.
Legal Proceedings
See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of legal proceedings applicable to Penelec.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to Penelec.
Report of Independent Registered Public Accounting Firm
To the Stockholder 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, 2008 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2008 and 2007. 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 (United States), 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, 2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for uncertain tax positions as of January 1, 2007, defined benefit pension and other postretirement plans as of December 31, 2006 and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 8, Note 4, Note 2(G) and Note 11 to the consolidated financial statements) dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, 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 7, 2008 |
PENNSYLVANIA ELECTRIC COMPANY | |
| | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | |
| Three Months Ended | |
| March 31, | |
| | | | | | |
| | 2008 | | | 2007 | |
| | | | | | |
| (In thousands) | |
| | | | | | |
REVENUES: | | | | | | |
Electric sales | | $ | 376,028 | | | $ | 339,226 | |
Gross receipts tax collections | | | 19,464 | | | | 16,680 | |
Total revenues | | | 395,492 | | | | 355,906 | |
| | | | | | | | |
EXPENSES: | | | | | | | | |
Purchased power | | | 221,234 | | | | 200,842 | |
Other operating costs | | | 71,077 | | | | 59,461 | |
Provision for depreciation | | | 12,516 | | | | 11,777 | |
Amortization of regulatory assets | | | 16,346 | | | | 15,394 | |
Deferral of new regulatory assets | | | (3,526 | ) | | | (17,088 | ) |
General taxes | | | 21,855 | | | | 19,851 | |
Total expenses | | | 339,502 | | | | 290,237 | |
| | | | | | | | |
OPERATING INCOME | | | 55,990 | | | | 65,669 | |
| | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | |
Miscellaneous income (expense) | | | (191 | ) | | | 1,417 | |
Interest expense | | | (15,322 | ) | | | (11,337 | ) |
Capitalized interest | | | (806 | ) | | | 258 | |
Total other expense | | | (16,319 | ) | | | (9,662 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 39,671 | | | | 56,007 | |
| | | | | | | | |
INCOME TAXES | | | 18,279 | | | | 24,263 | |
| | | | | | | | |
NET INCOME | | | 21,392 | | | | 31,744 | |
| | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
Pension and other postretirement benefits | | | (3,473 | ) | | | (2,825 | ) |
Unrealized gain on derivative hedges | | | 16 | | | | 16 | |
Change in unrealized gain on available-for-sale securities | | | 11 | | | | (3 | ) |
Other comprehensive loss | | | (3,446 | ) | | | (2,812 | ) |
Income tax benefit related to other comprehensive loss | | | (1,506 | ) | | | (1,298 | ) |
Other comprehensive loss, net of tax | | | (1,940 | ) | | | (1,514 | ) |
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 19,452 | | | $ | 30,230 | |
| | | | | | | | |
The accompanying 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, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
ASSETS | | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 43 | | | $ | 46 | |
Receivables- | | | | | | | | |
Customers (less accumulated provisions of $4,201,000 and $3,905,000, | | | | | | | | |
respectively, for uncollectible accounts) | | | 141,316 | | | | 137,455 | |
Associated companies | | | 23,396 | | | | 22,014 | |
Other | | | 28,833 | | | | 19,529 | |
Notes receivable from associated companies | | | 16,923 | | | | 16,313 | |
Prepaid gross receipts taxes | | | 41,242 | | | | - | |
Other | | | 2,426 | | | | 3,077 | |
| | | 254,179 | | | | 198,434 | |
UTILITY PLANT: | | | | | | | | |
In service | | | 2,230,667 | | | | 2,219,002 | |
Less - Accumulated provision for depreciation | | | 843,500 | | | | 838,621 | |
| | | 1,387,167 | | | | 1,380,381 | |
Construction work in progress | | | 33,727 | | | | 24,251 | |
| | | 1,420,894 | | | | 1,404,632 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
Nuclear plant decommissioning trusts | | | 132,152 | | | | 137,859 | |
Non-utility generation trusts | | | 113,958 | | | | 112,670 | |
Other | | | 536 | | | | 531 | |
| | | 246,646 | | | | 251,060 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Goodwill | | | 777,616 | | | | 777,904 | |
Pension assets | | | 69,405 | | | | 66,111 | |
Other | | | 29,770 | | | | 33,893 | |
| | | 876,791 | | | | 877,908 | |
| | $ | 2,798,510 | | | $ | 2,732,034 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Short-term borrowings- | | | | | | | | |
Associated companies | | $ | 183,102 | | | $ | 214,893 | |
Other | | | 150,000 | | | | - | |
Accounts payable- | | | | | | | | |
Associated companies | | | 61,476 | | | | 83,359 | |
Other | | | 50,516 | | | | 51,777 | |
Accrued taxes | | | 9,302 | | | | 15,111 | |
Accrued interest | | | 13,677 | | | | 13,167 | |
Other | | | 23,330 | | | | 25,311 | |
| | | 491,403 | | | | 403,618 | |
CAPITALIZATION: | | | | | | | | |
Common stockholder's equity- | | | | | | | | |
Common stock, $20 par value, authorized 5,400,000 shares- | | | | | | | | |
4,427,577 shares outstanding | | | 88,552 | | | | 88,552 | |
Other paid-in capital | | | 920,265 | | | | 920,616 | |
Accumulated other comprehensive income | | | 3,006 | | | | 4,946 | |
Retained earnings | | | 79,336 | | | | 57,943 | |
Total common stockholder's equity | | | 1,091,159 | | | | 1,072,057 | |
Long-term debt and other long-term obligations | | | 732,465 | | | | 777,243 | |
| | | 1,823,624 | | | | 1,849,300 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Regulatory liabilities | | | 67,347 | | | | 73,559 | |
Accumulated deferred income taxes | | | 220,500 | | | | 210,776 | |
Retirement benefits | | | 41,644 | | | | 41,298 | |
Asset retirement obligations | | | 83,129 | | | | 81,849 | |
Other | | | 70,863 | | | | 71,634 | |
| | | 483,483 | | | | 479,116 | |
COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | |
| | $ | 2,798,510 | | | $ | 2,732,034 | |
| | | | | | | | |
The accompanying 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 | |
| | March 31, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
| | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 21,392 | | | $ | 31,744 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | |
Provision for depreciation | | | 12,516 | | | | 11,777 | |
Amortization of regulatory assets | | | 16,346 | | | | 15,394 | |
Deferral of new regulatory assets | | | (3,526 | ) | | | (17,088 | ) |
Deferred costs recoverable as regulatory assets | | | (8,403 | ) | | | (18,433 | ) |
Deferred income taxes and investment tax credits, net | | | 10,541 | | | | 13,366 | |
Accrued compensation and retirement benefits | | | (10,488 | ) | | | (8,786 | ) |
Cash collateral | | | 301 | | | | 1,450 | |
Pension trust contribution | | | - | | | | (13,436 | ) |
Increase in operating assets- | | | | | | | | |
Receivables | | | (13,701 | ) | | | (30,050 | ) |
Prepayments and other current assets | | | (40,591 | ) | | | (36,225 | ) |
Increase (Decrease) in operating liabilities- | | | | | | | | |
Accounts payable | | | (23,144 | ) | | | (46,168 | ) |
Accrued taxes | | | (5,809 | ) | | | (9,152 | ) |
Accrued interest | | | 510 | | | | 5,518 | |
Other | | | 4,991 | | | | 3,920 | |
Net cash used for operating activities | | | (39,065 | ) | | | (96,169 | ) |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Short-term borrowings, net | | | 118,209 | | | | 119,361 | |
Redemptions and Repayments | | | | | | | | |
Long-term debt | | | (45,112 | ) | | | - | |
Net cash provided from financing activities | | | 73,097 | | | | 119,361 | |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (28,902 | ) | | | (20,404 | ) |
Sales of investment securities held in trusts | | | 24,407 | | | | 12,758 | |
Purchases of investment securities held in trusts | | | (29,083 | ) | | | (15,509 | ) |
Loan repayments from (loans to) associated companies, net | | | (610 | ) | | | 708 | |
Other | | | 153 | | | | (747 | ) |
Net cash used for investing activities | | | (34,035 | ) | | | (23,194 | ) |
| | | | | | | | |
Net change in cash and cash equivalents | | | (3 | ) | | | (2 | ) |
Cash and cash equivalents at beginning of period | | | 46 | | | | 44 | |
Cash and cash equivalents at end of period | | $ | 43 | | | $ | 42 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are | |
an integral part of these statements. | | | | | | | | |
COMBINED MANAGEMENT’S DISCUSSION
AND ANALYSIS OF REGISTRANT SUBSIDIARIES
The following is a combined presentation of certain disclosures referenced in Management’s Narrative Analysis of Results of Operations of FES and the Companies. This information should be read in conjunction with (i) FES’ and the Companies’ respective Consolidated Financial Statements and Management’s Narrative Analysis of Results of Operations; (ii) the Combined Notes to Consolidated Financial Statements as they relate to FES and the Companies; and (iii) FES’ and the Companies’ respective 2007 Annual Reports on Form 10-K.
Regulatory Matters (Applicable to each of the Companies)
In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry restructuring contain similar provisions that are reflected in the Companies' respective state regulatory plans. These provisions include:
· | restructuring the electric generation business and allowing the Companies' customers to select a competitive electric generation supplier other than the Companies; |
| |
· | establishing or defining the PLR obligations to customers in the Companies' service areas; |
| |
· | providing the Companies with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market; |
| |
· | itemizing (unbundling) the price of electricity into its component elements – including generation, transmission, distribution and stranded costs recovery charges; |
| |
· | continuing regulation of the Companies' transmission and distribution systems; and |
| |
· | requiring corporate separation of regulated and unregulated business activities. |
The Companies and ATSI 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. Regulatory assets that do not earn a current return totaled approximately $137 million as of March 31, 2008 (JCP&L - $78 million and Met-Ed - $59 million). Regulatory assets not earning a current return are expected to be recovered by 2014 for JCP&L and by 2020 for Met-Ed. The following table discloses regulatory assets by company:
| | March 31, | | December 31, | | Increase | |
Regulatory Assets* | | 2008 | | 2007 | | (Decrease) | |
| | (In millions) | |
OE | | $ | 710 | | $ | 737 | | $ | (27 | ) |
CEI | | | 854 | | | 871 | | | (17 | ) |
TE | | | 188 | | | 204 | | | (16 | ) |
JCP&L | | | 1,476 | | | 1,596 | | | (120 | ) |
Met-Ed | | | 530 | | | 495 | | | 35 | |
ATSI | | | | | | | | | | ) |
Total | | | | | | | | | | ) |
* | Penelec had net regulatory liabilities of approximately $67 million and $74 million as of March 31, 2008 and December 31, 2007, respectively. These net regulatory liabilities are included in Other Non-current Liabilities on the Consolidated Balance Sheets. |
Ohio (Applicable to OE, CEI and TE)
The Ohio Companies filed an application and stipulation with the PUCO on September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On November 4, 2005, the Ohio Companies filed a supplemental stipulation with the PUCO, which constituted an additional component of the RCP. On January 4, 2006, the PUCO approved, with modifications, the Ohio Companies’ RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. The following table provides the estimated net amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) under the RCP for the period 2008 through 2010:
Amortization | | | | | | | | | | | Total | |
Period | | OE | | CEI | | TE | | Ohio | |
| | (In millions) | |
2008 | | $ | 204 | | $ | 126 | | $ | 118 | | $ | 448 | |
2009 | | | - | | | 212 | | | - | | | 212 | |
2010 | | | | | | | | | | | | | |
Total Amortization | | | | | | | | | | | | | |
On January 4, 2006, the PUCO issued an order authorizing the Ohio Companies to recover certain increased fuel costs through a fuel rider and to defer certain other increased fuel costs to be incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances. The order also provided for recovery of the deferred costs over a twenty-five-year period through distribution rates. On August 29, 2007, the Supreme Court of Ohio concluded that the PUCO violated a provision of the Ohio Revised Code by permitting the Ohio Companies “to collect deferred increased fuel costs through future distribution rate cases, or to alternatively use excess fuel-cost recovery to reduce deferred distribution-related expenses” and remanded the matter to the PUCO for further consideration. On September 10, 2007 the Ohio Companies filed an application with the PUCO that requested the implementation of two generation-related fuel cost riders to collect the increased fuel costs that were previously authorized to be deferred. On January 9, 2008 the PUCO approved the Ohio Companies’ proposed fuel cost rider to recover increased fuel costs to be incurred in 2008 commencing January 1, 2008 through December 31, 2008, which is expected to be approximately $189 million (OE - $91 million, CEI - $72 million and TE - $26 million). In addition, the PUCO ordered the Ohio Companies to file a separate application for an alternate recovery mechanism to collect the 2006 and 2007 deferred fuel costs. On February 8, 2008, the Ohio Companies filed an application proposing to recover $226 million (OE - $114 million, CEI - $79 million and TE - $33 million) of deferred fuel costs and carrying charges for 2006 and 2007 pursuant to a separate fuel rider, with alternative options for the recovery period ranging from five to twenty-five years. This second application is currently pending before the PUCO and a hearing has been set for July 15, 2008.
The Ohio Companies filed an application and rate request for an increase in electric distribution rates with the PUCO on June 7, 2007. The requested increase is expected to be more than offset by the elimination or reduction of transition charges at the time the rates go into effect and would result in lowering the overall non-generation portion of the average electric bill for most Ohio customers. The distribution rate increases reflect capital expenditures since the Ohio Companies’ last distribution rate proceedings, increases in operation and maintenance expenses and recovery of regulatory assets that were authorized in prior cases. On August 6, 2007, the Ohio Companies updated their filing supporting a distribution rate increase of $332 million (OE - $156 million, CEI - $108 million and TE - $68 million). On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of their investigation into the distribution rate request. In its reports, the PUCO Staff recommended a distribution rate increase in the range of $161 million to $180 million (OE - $57 million to $66 million, CEI - $54 million to $61 million and TE - $50 million to $53 million), with $108 million to $127 million for distribution revenue increases and $53 million for recovery of costs deferred under prior cases. This amount excludes the recovery of deferred fuel costs, whose recovery is now being sought in a separate proceeding before the PUCO, discussed above. On January 3, 2008, the Ohio Companies and intervening parties filed objections to the Staff Reports and on January 10, 2008, the Ohio Companies filed supplemental testimony. Evidentiary hearings began on January 29, 2008 and continued through February 25, 2008. During the evidentiary hearings, the PUCO Staff submitted testimony decreasing their recommended revenue increase to a range of $114 million to $132 million. Additionally, in testimony submitted on February 11, 2008, the PUCO Staff adopted a position regarding interest deferred for RCP-related deferrals, line extension deferrals and transition tax deferrals that, if upheld by the PUCO, would result in the write-off of approximately $45 million (OE - $31 million, CEI - $9 million and TE - $5 million) of interest costs deferred through March 31, 2008 ($0.09 per share of common stock). The PUCO is expected to render its decision during the second or third quarter of 2008. The new rates would become effective January 1, 2009 for OE and TE, and approximately May 2009 for CEI.
On July 10, 2007, the Ohio Companies filed an application with the PUCO requesting approval of a comprehensive supply plan for providing retail generation service to customers who do not purchase electricity from an alternative supplier, beginning January 1, 2009. The proposed competitive bidding process would average the results of multiple bidding sessions conducted at different times during the year. The final price per KWH would reflect an average of the prices resulting from all bids. In their filing, the Ohio Companies offered two alternatives for structuring the bids, either by customer class or a “slice-of-system” approach. A slice-of-system approach would require the successful bidder to be responsible for supplying a fixed percentage of the utility’s total load notwithstanding the customer’s classification. The proposal provides the PUCO with an option to phase in generation price increases for residential tariff groups who would experience a change in their average total price of 15 percent or more. The PUCO held a technical conference on August 16, 2007 regarding the filing. Initial and reply comments on the proposal were filed by various parties in September and October 2007, respectively. The proposal is currently pending before the PUCO.
On April 22, 2008, an amended version of Substitute SB221 was passed by the Ohio House of Representatives and sent back to the Ohio Senate for concurrence. On April 23, 2008, the Ohio Senate approved the House's amendments to Substitute SB221 and forwarded the bill to the Governor for signature, which he signed on May 1, 2008. Amended Substitute SB221 requires all electric distribution utilities to file an RSP, now called an ESP, with the PUCO. An ESP is required to contain a proposal for the supply and pricing of retail generation and may include proposals, without limitation, related to one or more of the following:
· | automatic recovery of prudently incurred fuel, purchased power, emission allowance costs and federally mandated energy taxes; |
· | construction work in progress for costs of constructing an electric generating facility or environmental expenditure for any electric generating facility; |
· | costs of an electric generating facility; |
· | terms related to customer shopping, bypassability, standby, back-up and default service; |
· | accounting for deferrals related to stabilizing retail electric service; |
· | automatic increases or decreases in standard service offer price; |
· | phase-in and securitization; |
· | transmission service and related costs; |
· | distribution service and related costs; and |
· | economic development and energy efficiency. |
A utility could also simultaneously file an MRO in which it would have to demonstrate the following objective market criteria: The utility or its transmission service affiliate belongs to a FERC-approved RTO having a market-monitor function and the ability to mitigate market power, and a published source exists that identifies information for traded electricity and energy products that are contracted for delivery two years into the future. The PUCO would test the ESP and its pricing and all other terms and conditions against the MRO and may only approve the ESP if it is found to be more favorable to customers. As part of an ESP with a plan period longer than three years, the PUCO shall prospectively determine every fourth year of the plan whether it is substantially likely the plan will provide the electric distribution utility a return on common equity significantly in excess of the return likely to be earned by publicly traded companies, including utilities, that face comparable business and financial risk (comparable companies). If so, the PUCO may terminate the ESP. Annually under an ESP, the PUCO shall determine whether an electric distribution utility's earned return on common equity is significantly in excess of returns earned on common equity during the same period by comparable companies, and if so, shall require the utility to return such excess to customers by prospective adjustments. Amended Substitute SB221 also includes provisions dealing with advanced and renewable energy standards that contemplate 25% of electrical usage from these sources by 2025. Energy efficiency measures in the bill require energy savings in excess of 22% by 2025. Requirements are in place to meet annual benchmarks for renewable energy resources and energy efficiency, subject to review by the PUCO. FirstEnergy is currently evaluating this legislation and expects to file an ESP in the second or third quarter of 2008.
Pennsylvania (Applicable to FES, Met-Ed, Penelec, OE and Penn)
Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations. The fixed price under the agreement is expected to remain below wholesale market prices during the term of the agreement. If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for their fixed income securities. Based on the PPUC’s January 11, 2007 order described below, if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC.
Met-Ed and Penelec made a comprehensive transition rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals had been approved, annual revenues would have increased by $216 million and $157 million, respectively. That filing included, among other things, a request to charge customers for an increasing amount of market-priced power procured through a CBP as the amount of supply provided under the then existing FES agreement was to be phased out. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs incurred during 2006. In this rate filing, Met-Ed and Penelec requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the FirstEnergy and GPU merger proceeding, related to the quantification and allocation of merger savings, with the comprehensive transition rate filing case.
The PPUC entered its opinion and order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, and determined that no merger savings from prior years should be considered in determining customers’ rates. The request for increases in generation supply rates was denied as were the requested changes to NUG expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased Met-Ed’s and Penelec’s distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission costs. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and, in January 2007, Met-Ed and Penelec recognized income of $15 million and $12 million, respectively, to establish regulatory assets for those previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million).
On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase. The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. From June through October 2007, initial responsive and reply briefs were filed by various parties. Oral arguments are scheduled to take place in September 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the results of operations of Met-Ed, Penelec and FirstEnergy.
On April 14, 2008, Met-Ed and Penelec filed annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. The proposed TSCs include a component for under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and future transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed has proposed a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010.
On March 13, 2008, the PPUC approved the residential procurement process in Penn’s Joint Petition for Settlement. This RFP process calls for load-following, full-requirements contracts for default service procurement for residential customers for the period covering June 1, 2008 through May 31, 2011. The PPUC had previously approved the default service procurement processes for commercial and industrial customers. The default service procurement for small commercial customers was conducted through multiple RFPs, while the default service procurement for large commercial and industrial customers will utilize hourly pricing. Bids in the two RFPs for small commercial load were approved by the PPUC on February 22, 2008, and March 20, 2008. On March 28, 2008, Penn filed compliance tariffs with the new default service generation rates based on the approved RFP bids for small commercial customers which the PPUC then certified on April 4, 2008. On April 14, 2008, the first RFP for residential customers’ load was held consisting of tranches for both 12 and 24-month supply. The PPUC approved the bids on April 16, 2008. The second RFP is scheduled to be held on May 14, 2008, after which time the PPUC is expected to approve the new rates to go into effect June 1, 2008.
On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation and demand reduction programs to meet energy growth, a requirement that electric distribution companies acquire power that results in the “lowest reasonable rate on a long-term basis,” the utilization of micro-grids and a three year phase-in of rate increases. On July 17, 2007 the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy was convened in mid-September 2007 to consider other aspects of the EIS. The Pennsylvania House and Senate on March 11, 2008 and December 12, 2007, respectively, passed different versions of bills to fund the Governor’s EIS proposal. Neither chamber has formally considered the other’s bill. On February 12, 2008, the Pennsylvania House passed House Bill 2200 which provides for energy efficiency and demand management programs and targets as well as the installation of smart meters within ten years. Other legislation has been introduced to address generation procurement, expiration of rate caps, conservation and renewable energy. The final form of this pending legislation is uncertain. Consequently, Met-Ed, Penelec, OE and Penn are unable to predict what impact, if any, such legislation may have on their operations.
New Jersey (Applicable to JCP&L)
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 NUGC rates and market sales of NUG energy and capacity. As of March 31, 2008, the accumulated deferred cost balance totaled approximately $264 million.
In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting 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 DRA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and also submitted comments in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set.
On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of the PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. These regulations are not expected to materially impact JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. The NJBPU Staff circulated revised drafts of the proposal to interested stakeholders in November 2006 and again in February 2007. On February 1, 2008, the NJBPU accepted proposed rules for publication in the New Jersey Register on March 17, 2008. A public hearing on these proposed rules was held on April 23, 2008 with comments from interested parties due on May 16, 2008.
New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated through the creation of a number of working groups to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. In addition, public stakeholder meetings were held in the fall of 2006 and in early 2007.
On April 17, 2008, a draft EMP was released for public comment. The draft EMP establishes four major goals:
· | maximize energy efficiency to achieve a 20% reduction in energy consumption by 2020; |
· | reduce peak demand for electricity by 5,700 MW by 2020 (amounting to about a 22% reduction in projected demand); |
· | meet 22.5% of the state’s electricity needs with renewable energy by 2020; and |
· | develop low carbon emitting, efficient power plants and close the gap between the supply and demand for electricity. |
Following the public comment period which is expected to extend into July 2008, a final EMP will be issued to be followed by appropriate legislation and regulation as necessary. At this time, JCP&L cannot predict the outcome of this process nor determine the impact, if any, such legislation or regulation may have on its operations.
On February 13, 2007, the NJBPU Staff informally issued a draft proposal relating to changes to the regulations addressing electric distribution service reliability and quality standards. Meetings between the NJBPU Staff and interested stakeholders to discuss the proposal were held and additional, revised informal proposals were subsequently circulated by the Staff. On September 4, 2007, proposed regulations were published in the New Jersey Register, which proposal will be subsequently considered by the NJBPU following comments that were submitted in September and October 2007. Final regulations (effective upon publication) were published in the New Jersey Register March 17, 2008. Upon preliminary review of the new regulations, JCP&L does not expect a material impact on its operations.
FERC Matters (Applicable to FES and each of the Companies)
Transmission Service between MISO and PJM
On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate so-called “pancaking” of transmission charges between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or “SECA”) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order could be issued by the FERC in the second quarter of 2008.
PJM Transmission Rate Design
On January 31, 2005, certain PJM transmission owners made filings with the FERC 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. Hearings were held and numerous parties appeared and litigated various issues concerning PJM rate design; notably AEP, which proposed to create a "postage stamp", or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. This proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. The FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.
On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. The FERC’s orders on PJM rate design will prevent the allocation of a portion of the revenue requirement of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reduce future transmission revenue recovery from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the “beneficiary pays” methodology for below 500 kV facilities, but excluding the issue of allocating new facilities costs to merchant transmission entities, was filed on September 14, 2007. The agreement was supported by the FERC’s Trial Staff, and was certified by the Presiding Judge. The FERC’s action on the settlement agreement is pending. The remaining merchant transmission cost allocation issues will proceed to hearing in May 2008. On February 13, 2008, AEP appealed the FERC’s orders to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and Dayton Power & Light have also appealed these orders to the Seventh Circuit Court of Appeals. The appeals of these parties and others have been consolidated for argument in the Seventh Circuit.
Post Transition Period Rate Design
The FERC had directed MISO, PJM, and the respective transmission owners to make filings on or before August 1, 2007 to reevaluate transmission rate design within the MISO, and between MISO and PJM. On August 1, 2007, filings were made by MISO, PJM, and the vast majority of transmission owners, including FirstEnergy affiliates, which proposed to retain the existing transmission rate design. These filings were approved by the FERC on January 31, 2008. As a result of the FERC’s approval, the rates charged to FirstEnergy’s load-serving affiliates for transmission service over existing transmission facilities in MISO and PJM are unchanged. In a related filing, MISO and MISO transmission owners requested that the current MISO pricing for new transmission facilities that spreads 20% of the cost of new 345 kV and higher transmission facilities across the entire MISO footprint (known as the RECB methodology) be retained.
On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act seeking to have the entire transmission rate design and cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have the FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM “Super Region” that recovers the average cost of new and existing transmission facilities operated at voltages of 345 kV and above from all transmission customers. Lower voltage facilities would continue to be recovered in the local utility transmission rate zone through a license plate rate. AEP requested a refund effective October 1, 2007, or alternatively, February 1, 2008. On January 31, 2008, the FERC issued an order denying the complaint. A rehearing request by AEP is pending before the FERC.
Distribution of MISO Network Service Revenues
Effective February 1, 2008, the MISO Transmission Owners Agreement provides for a change in the method of distributing transmission revenues among the transmission owners. MISO and a majority of the MISO transmission owners filed on December 3, 2007 to change the MISO tariff to clarify, for purposes of distributing network transmission revenue to the transmission owners, that all network transmission service revenues, whether collected by MISO or directly by the transmission owner, are included in the revenue distribution calculation. This clarification was necessary because some network transmission service revenues are collected and retained by transmission owners in states where retail choice does not exist, and their “unbundled” retail load is currently exempt from MISO network service charges. The tariff changes filed with the FERC ensure that revenues collected by transmission owners from bundled load are taken into account in the revenue distribution calculation, and that transmission owners with bundled load do not collect more than their revenue requirements. Absent the changes, transmission owners, and ultimately their customers, with unbundled load or in retail choice states, such as ATSI, would subsidize transmission owners with bundled load, who would collect their revenue requirement from bundled load, plus share in revenues collected by MISO from unbundled customers. This would result in a large revenue shortfall for ATSI, which would eventually be passed on to customers in the form of higher transmission rates as calculated pursuant to ATSI’s Attachment O formula under the MISO tariff.
Numerous parties filed in support of the tariff changes, including the public service commissions of Michigan, Ohio and Wisconsin. Ameren filed a protest on December 26, 2007, arguing that the December 3, 2007 filing violates the MISO Transmission Owners’ Agreement as well as an agreement among Ameren (Union Electric), MISO, and the Missouri Public Service Commission, which provides that Union Electric’s bundled load cannot be charged by MISO for network service. On February 2, 2008, the FERC issued an order conditionally accepting the tariff amendment subject to a minor compliance filing, which was made on March 3, 2008. This order ensures that ATSI will continue to receive transmission revenues from MISO equivalent to its transmission revenue requirement. A rehearing request by Ameren is pending before the FERC.
On February 1, 2008, MISO filed a request to continue using the existing revenue distribution methodology on an interim basis pending amendment of the MISO Transmission Owners’ Agreement. This request was accepted by the FERC on March 13, 2008. On that same day, MISO and the MISO transmission owners made a filing to amend the Transmission Owners’ Agreement to effectively continue the distribution of transmission revenues that was in effect prior to February 1, 2008. This matter is currently pending before the FERC.
MISO Ancillary Services Market and Balancing Area Consolidation
MISO made a filing on September 14, 2007 to establish an ASM for regulation, spinning and supplemental reserves, to consolidate the existing 24 balancing areas within the MISO footprint, and to establish MISO as the NERC registered balancing authority for the region. This filing would permit load serving entities to purchase their operating reserve requirements in a competitive market. FES, CEI, OE, Penn and TE support the proposal to establish markets for Ancillary Services and consolidate existing balancing areas. On February 25, 2008, the FERC issued an order approving the ASM subject to certain compliance filings. MISO has since notified the FERC that the start of its ASM is delayed until September of 2008.
Duquesne’s Request to Withdraw from PJM
On November 8, 2007, Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and to join the MISO. In its filing, Duquesne asked the FERC to be relieved of certain capacity payment obligations to PJM for capacity auctions conducted prior to its departure from PJM, but covering service for planning periods through May 31, 2011. Duquesne asserted that its primary reason for exiting PJM is to avoid paying future obligations created by PJM’s forward capacity market. FirstEnergy believes that Duquesne’s filing did not identify or address numerous legal, financial or operational issues that are implicated or affected directly by Duquesne’s proposal. Consequently, FirstEnergy submitted responsive filings that, while conceding Duquesne’s rights to exit PJM, contested various aspects of Duquesne’s proposal. FirstEnergy particularly focused on Duquesne’s proposal that it be allowed to exit PJM without payment of its share of existing capacity market commitments. FirstEnergy also objected to Duquesne’s failure to address the firm transmission service requirements that would be necessary for FirstEnergy to continue to use the Beaver Valley Plant to meet existing commitments in the PJM capacity markets and to serve native load. Other market participants also submitted filings contesting Duquesne’s plans.
On January 17, 2008, the FERC conditionally approved Duquesne’s request to exit PJM. Among other conditions, the FERC obligated Duquesne to pay the PJM capacity obligations through May 31, 2011. The FERC’s order took notice of the numerous transmission and other issues raised by FES and the Companies and other parties to the proceeding, but did not provide any responsive rulings or other guidance. Rather, the FERC ordered Duquesne to make a compliance filing in forty-five days detailing how Duquesne will satisfy its obligations under the PJM Transmission Owners’ Agreement. The FERC likewise directed the MISO to submit detailed plans to integrate Duquesne into the MISO. Finally, the FERC directed MISO and PJM to work together to resolve the substantive and procedural issues implicated by Duquesne’s transition into the MISO. These issues remain unresolved. If Duquesne satisfies all of the obligations set by the FERC, its planned transition date is October 9, 2008.
On March 18, 2008, the PJM Power Providers Group filed a request for emergency clarification regarding whether Duquesne-zone generators (including the Beaver Valley Plant) could participate in PJM’s May 2008 auction for the 2011-2012 RPM delivery year. FirstEnergy and the other Duquesne-zone generators filed responsive pleadings. On April 18, 2008, the FERC issued its Order on Motion for Emergency Clarification, wherein the FERC ruled that although the status of the Duquesne-zone generators will change to “External Resource” upon Duquesne’s exit from PJM, these generators can contract with PJM for the transmission reservations necessary to participate in the May 2008 auction. FirstEnergy has complied with FERC’s order by obtaining executed transmission service agreements for firm point-to-point transmission service for the 2011-2012 delivery year and, as such, FirstEnergy satisfies the criteria to bid the Beaver Valley Plant into the May 2008 RPM auction. Notwithstanding these events, on April 30, 2008 and May 1, 2008, certain members of the PJM Power Providers Group filed further pleadings on these issues. On May 2, 2008, FirstEnergy filed a responsive pleading. FirstEnergy is participating in the May 2008 RPM auction for the 2011-2012 RPM delivery year.
MISO Resource Adequacy Proposal
MISO made a filing on December 28, 2007 that would create an enforceable planning reserve requirement in the MISO tariff for load serving entities such as the Ohio Companies, Penn Power, and FES. This requirement is proposed to become effective for the planning year beginning June 1, 2009. The filing would permit MISO to establish the reserve margin requirement for load serving entities based upon a one day loss of load in ten years standard, unless the state utility regulatory agency establishes a different planning reserve for load serving entities in its state. FirstEnergy generally supports the proposal as it promotes a mechanism that will result in long-term commitments from both load-serving entities and resources, including both generation and demand side resources that are necessary for reliable resource adequacy and planning in the MISO footprint. Comments on the filing were filed on January 28, 2008. The FERC approved MISO’s Resource Adequacy proposal on March 26, 2008. Rehearing requests are pending on the FERC’s March 26 Order. A compliance filing establishing the enforcement mechanism for the reserve margin requirement is due on or before June 25, 2008.
Organized Wholesale Power Markets
On February 21, 2008, the FERC issued a NOPR through which it proposes to adopt new rules that it states will “improve operations in organized electric markets, boost competition and bring additional benefits to consumers.” The proposed rule addresses demand response and market pricing during reserve shortages, long-term power contracting, market-monitoring policies, and responsiveness of RTOs and ISOs to stakeholders and customers. FES and the Companies do not believe that the proposed rule will have a significant impact on their operations. Comments on the NOPR were filed on April 18, 2008.
Environmental Matters
Various federal, state and local authorities regulate FES and the Companies with regard to air and water quality and other environmental matters. The effects of compliance on FES and the Companies with regard to environmental matters could have a material adverse effect on their earnings and competitive position to the extent that they compete with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. FES and the Companies estimate capital expenditures for environmental compliance of approximately $1.4 billion for the period 2008-2012.
FES and the Companies accrue environmental liabilities only when they conclude that it is probable that they have an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in FES’ and the Companies’ determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.
Clean Air Act Compliance (Applicable to FES)
FES is required to meet federally-approved SO2 emissions regulations. Violations of such regulations can result in the 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. FES believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.
The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006, alleging violations to various sections of the CAA. FES has disputed those alleged violations based on its CAA permit, the Ohio SIP and other information provided to the EPA at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order, and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding the opacity limit applicable to the common stack for Bay Shore Units 2, 3 and 4.
FES complies 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 at FES' facilities. The EPA's NOX Transport Rule imposes uniform reductions of NOX emissions (an approximate 85% reduction in utility plant NOX emissions from projected 2007 emissions) across a region of nineteen states (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. FES believes its facilities are also complying with the NOX budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.
On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On October 18, 2007, PennFuture filed a complaint, joined by three of its members, in the United States District Court for the Western District of Pennsylvania. On January 11, 2008, FirstEnergy filed a motion to dismiss claims alleging a public nuisance. On April 24, 2008, the Court denied the motion to dismiss, but also ruled that monetary damages could not be recovered under the public nuisance claim.
On December 18, 2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations at the Portland Generation Station against Reliant (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU, Inc. and Met-Ed. Specifically, New Jersey alleges that "modifications" at Portland Units 1 and 2 occurred between 1980 and 1995 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seeks injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. On March 14, 2008, Met-Ed filed a motion to dismiss the citizen suit claims against it and a stipulation in which the parties agreed that GPU, Inc. should be dismissed from this case. On March 26, 2008, GPU, Inc. was dismissed by the Court. Although it remains liable for civil or criminal penalties and fines that may be assessed relating to events prior to the sale of the Portland Station in 1999, Met-Ed is indemnified by Sithe Energy against any other liability arising under the CAA whether it arises out of pre-1999 or post-1999 events.
National Ambient Air Quality Standards (Applicable to FES)
In March 2005, the EPA finalized the CAIR 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 non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR requires 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). FES' Michigan, Ohio and Pennsylvania fossil generation facilities will be subject to 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. CAIR has been challenged in the United States Court of Appeals for the District of Columbia. The future cost of compliance with these regulations may be substantial and may depend on the outcome of this litigation and how CAIR is ultimately implemented.
Mercury Emissions (Applicable to FES)
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. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping national mercury emissions at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the United States Court of Appeals for the District of Columbia. On February 8, 2008, the court vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap and trade program. The EPA must now seek further judicial review of that ruling or take regulatory action to promulgate new mercury emission standards for coal-fired power plants. FGCO’s future cost of compliance with mercury regulations may be substantial and will depend on the action taken by the EPA and on how they are ultimately implemented.
Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap-and-trade approach as in the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. It is anticipated that compliance with these regulations, if approved by the EPA and implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant, FES’ only Pennsylvania coal-fired power plant, until 2015, if at all.
W. H. Sammis Plant (Applicable to FES, OE and Penn)
In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W.H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case, along with seven other similar cases, are referred to as the NSR cases.
On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation. This settlement agreement, which is in the form of a consent decree, was approved by the court on July 11, 2005, and requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FirstEnergy fails to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FGCO, OE and Penn could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree are currently estimated to be $1.3 billion for FGCO for 2008-2012 ($650 million of which is expected to be spent during 2008, with the largest portion of the remaining $650 million expected to be spent in 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above.
On April 2, 2007, the United States Supreme Court ruled that changes in annual emissions (in tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must be used to determine whether an emissions increase triggers NSR. Subsequently, on May 8, 2007, the EPA proposed to revise the NSR regulations to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR. The EPA has not yet issued a final regulation. FGCO’s future cost of compliance with those regulations may be substantial and will depend on how they are ultimately implemented.
Climate Change (Applicable to FES)
In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 2012. The United States signed the Kyoto Protocol in 1998 but it failed to receive the two-thirds vote required for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. Also, in an April 16, 2008 speech, President Bush set a policy goal of stopping the growth of GHG emissions by 2025, as the next step beyond the 2012 strategy. In addition, the EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.
There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the international level, efforts to reach a new global agreement to reduce GHG emissions post-2012 have begun with the Bali Roadmap, which outlines a two-year process designed to lead to an agreement in 2009. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the Senate Environmental and Public Works Committees have passed one such bill. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.
On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities.
FES cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions could require significant capital and other expenditures. The CO2 emissions per KWH of electricity generated by FES is lower than many regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.
Clean Water Act (Applicable to FES)
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FES’ plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FES' 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 life is drawn into a facility's cooling water system). On January 26, 2007, the United States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment (BPJ) to minimize impacts on fish and shellfish from cooling water intake structures. On April 14, 2008, the Supreme Court of the United States granted a petition for a writ of certiorari to review certain aspects of the Second Circuit’s decision. FirstEnergy is studying various control options and their costs and effectiveness. Depending on the results of such studies, the outcome of the Supreme Court’s review of the Second Circuit’s decision, the EPA’s further rulemaking and any action taken by the states exercising BPJ, the future costs of compliance with these standards may require material capital expenditures.
Regulation of Hazardous Waste (Applicable to FES and each of the Companies)
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 non-hazardous waste.
Under NRC regulations, FES and the Companies must ensure that adequate funds will be available to decommission its nuclear facilities. As of March 31, 2008, FES and the Companies had approximately $2.0 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy agreed to contribute another $80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy and FES (and Exelon for TMI-1 as it relates to the timing of the decommissioning of TMI-2) seeks for these facilities.
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 may be 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, 2008, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $92 million (JCP&L - $65 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $25 million) have been accrued through March 31, 2008. Included in the total for JCP&L are accrued liabilities of approximately $56 million for environmental remediation of former manufactured gas plants in New Jersey; which are being recovered by JCP&L through a non-bypassable SBC.
Other Legal Proceedings
Power Outages and Related Litigation (Applicable to JCP&L)
In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four of New Jersey’s electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the JCP&L territory.
In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision in July 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, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, in March 2007, reversed the decertification of the Red Bank class and remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007. Proceedings are continuing in the Superior Court and a case management conference with the presiding Judge is scheduled for June 13, 2008. JCP&L is defending this class action but is unable to predict the outcome of this matter. No liability has been accrued as of March 31, 2008.
Nuclear Plant Matters (Applicable to FES)
On May 14, 2007, the Office of Enforcement of the NRC issued a DFI to FENOC, following FENOC’s reply to an April 2, 2007 NRC request for information, about two reports prepared by expert witnesses for an insurance arbitration (the insurance claim was subsequently withdrawn by FirstEnergy in December 2007) related to Davis-Besse. The NRC indicated that this information was needed for the NRC “to determine whether an Order or other action should be taken pursuant to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to operate its licensed facilities in accordance with the terms of its licenses and the Commission’s regulations.” FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s DFI reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. FENOC submitted a supplemental response clarifying certain aspects of the DFI response to the NRC on July 16, 2007. On August 15, 2007, the NRC issued a confirmatory order imposing these commitments. FENOC must inform the NRC’s Office of Enforcement after it completes the key commitments embodied in the NRC’s order. FENOC’s compliance with these commitments is subject to future NRC review.
Other Legal Matters (Applicable to OE, JCP&L and FES)
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.
On 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 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. On April 5, 2007, the Court rejected the plaintiffs’ request to certify this case as a class action and, accordingly, did not appoint the plaintiffs as class representatives or their counsel as class counsel. On July 30, 2007, plaintiffs’ counsel voluntarily withdrew their request for reconsideration of the April 5, 2007 Court order denying class certification and the Court heard oral argument on the plaintiffs’ motion to amend their complaint which OE opposed. On August 2, 2007, the Court denied the plaintiffs’ motion to amend their complaint. The plaintiffs have appealed the Court’s denial of the motion for certification as a class action and motion to amend their complaint.
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 arbitration panel decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, a federal district court granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005. A final order identifying the individual damage amounts was issued on October 31, 2007. The award appeal process was initiated. The union filed a motion with the federal court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. The court held a scheduling conference in April 2008 where it set a briefing schedule with all briefs to be concluded by July 2008. JCP&L recognized a liability for the potential $16 million award in 2005.
The union employees at the Bruce Mansfield Plant have been working without a labor contract since February 15, 2008. The parties are continuing to bargain with the assistance of a federal mediator. FirstEnergy has a strike mitigation plan ready in the event of a strike.
FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.
New Accounting Standards and Interpretations (Applicable to FES and each of the Companies)
SFAS 141(R) – “Business Combinations”
In December 2007, the FASB issued SFAS 141(R), which requires the acquiring entity in a business combination to recognize all the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. SFAS 141(R) attempts to reduce the complexity of existing GAAP related to business combinations. The Standard includes both core principles and pertinent application guidance, eliminating the need for numerous EITF issues and other interpretative guidance. SFAS 141(R) will affect business combinations entered into by FES or any of the Companies that close after January 1, 2009. In addition, the Standard also affects the accounting for changes in tax valuation allowances made after January 1, 2009, that were established as part of a business combination prior to the implementation of this Standard. FES and the Companies are currently evaluating the impact of adopting this Standard on their financial statements.
SFAS 160 - “Noncontrolling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51”
In December 2007, the FASB issued SFAS 160 that establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Early adoption is prohibited. The Statement is not expected to have a material impact on FES’ or the Companies’ financial statements.
| SFAS 161 - “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133” |
In March 2008, the FASB issued SFAS 161, which enhances the current disclosure framework for derivative instruments and hedging activities. The Statement requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. This disclosure better conveys the purpose of derivative use in terms of the risks that the entity is intending to manage. The FASB believes disclosing the fair values of derivative instruments and their gains and losses in a tabular format is designed to provide a more complete picture of the location in an entity’s financial statements of both the derivative positions existing at period end and the effect of using derivatives during the reporting period. Disclosing information about credit-risk-related contingent features is designed to provide information on the potential effect on an entity’s liquidity from using derivatives. Finally, this Statement requires cross-referencing within the footnotes, which is intended to help users of financial statements locate important information about derivative instruments. FES and the Companies are currently evaluating the impact of adopting this Standard on their financial statements.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. ORGANIZATION AND BASIS OF PRESENTATION
FirstEnergy's principal businessFirstEnergy is the holding,a diversified energy company that holds, 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(a wholly owned subsidiary of OE. FirstEnergy’s consolidated financial statements also include its other subsidiaries:OE), ATSI, JCP&L, Met-Ed, Penelec, FENOC, FES and its subsidiaries FGCO and NGC, and FESC.
FirstEnergy and its subsidiaries follow GAAP and comply with the regulations, orders, policies and practices prescribed by the SEC, the FERC and, as applicable, the PUCO, the PPUC and the 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, 20062007 for FirstEnergy, FES and the Companies. The consolidated unaudited financial statements of FirstEnergy, FES 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 2006prior year amounts have been classified as discontinued operations on the Consolidated Statements of Income (see Note 3). As discussed in Note 12, interim period segment reporting in 2006 was reclassified to conform withto the current year business segment organizations and operations.presentation. Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.
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 7)8) when it is determined to be the VIE's primary beneficiary. Investments in non-consolidated affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but not control (20-50% owned companies, joint ventures and partnerships) are accounted for underfollow the equity method.method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entity’s earnings is reported in the Consolidated Statements of Income. Certain prior year amounts have been reclassified to conform to the current year presentation.
The consolidated financial statements as of June 30, 2007March 31, 2008 and for the three-month and six-month periods ended June 30,March 31, 2008 and 2007 and 2006 have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their report (dated August 6, 2007)May 7, 2008) is included on page 28.herein. The report of PricewaterhouseCoopers LLP states that they did not audit and they do not express an opinion on that unaudited financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their report on the unaudited financial information because that report is not a “report” or a “part” of thea registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Securities Act.Act of 1933.
2. EARNINGS PER SHARE
Basic earnings per share of common stock is computed using the weighted average of actual common shares outstanding during the respective period as the denominator. The denominator for diluted earnings per share of common stock 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. The pool of stock-based compensation tax benefits is calculated in accordance with SFAS 123(R). On August 10, 2006, FirstEnergy repurchased 10.6 million shares, approximately 3.2%, of its outstanding common stock through an accelerated share repurchase program. The initial purchase price was $600 million, or $56.44 per share. A final purchase price adjustment of $27 million was settled in cash on April 2, 2007. On March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or 4.5%, of its outstanding common stock through an additional accelerated share repurchase program with an affiliate of Morgan Stanley and Co., Incorporated at an initial price of $62.63 per share, or a total initial purchase price of approximately $900 million. TheA final purchase price for this program will be adjusted to reflect the volume weighted average priceadjustment of FirstEnergy’s common stock during the period of time that the bank will acquire shares to cover its short position, which is approximately one year.$51 million was settled in cash on December 13, 2007. The following table reconciles basic and diluted earnings per share calculations for the second quarter and first six months of 2007 reflect the impact associated with the March 2007 accelerated share repurchase program. FirstEnergy intends to settle, in cash or shares, any obligation on its part to pay the difference between the average of the daily volume-weighted average price of the shares as calculated under the March 2007 program and the initial price of the shares.common stock:
| | Three Months Ended | | Six Months Ended | |
| | | | | |
Reconciliation of Basic and Diluted Earnings per Share | | 2007 | | 2006 | | 2007 | | 2006 | |
| | (In millions, except per share amounts) | |
| | | | | | | | | | | | | |
Income from continuing operations | | $ | 338 | | $ | 312 | | $ | 628 | | $ | 531 | |
Discontinued operations | | | - | | | (8 | ) | | - | | | (6 | ) |
Redemption premium on subsidiary preferred stock | | | - | | | (3 | ) | | - | | | (3 | ) |
Net earnings available for common shareholders | | $ | 338 | | $ | 301 | | $ | 628 | | $ | 522 | |
| | | | | | | | | | | | | |
Average shares of common stock outstanding – Basic | | | 304 | | | 328 | | | 309 | | | 328 | |
Assumed exercise of dilutive stock options and awards | | | 4 | | | 2 | | | 4 | | | 2 | |
Average shares of common stock outstanding – Dilutive | | | 308 | | | 330 | | | 313 | | | 330 | |
| | | | | | | | | | | | | |
Earnings per share: | | | | | | | | | | | | | |
Basic earnings per share: | | | | | | | | | | | | | |
Earnings from continuing operations | | $ | 1.11 | | $ | 0.94 | | $ | 2.03 | | $ | 1.61 | |
Discontinued operations | | | - | | | (0.02 | ) | | - | | | (0.02 | ) |
Net earnings per basic share | | $ | 1.11 | | $ | 0.92 | | $ | 2.03 | | $ | 1.59 | |
| | | | | | | | | | | | | |
Diluted earnings per share: | | | | | | | | | | | | | |
Earnings from continuing operations | | $ | 1.10 | | $ | 0.93 | | $ | 2.01 | | $ | 1.60 | |
Discontinued operations | | | - | | | (0.02 | ) | | - | | | (0.02 | ) |
Net earnings per diluted share | | $ | 1.10 | | $ | 0.91 | | $ | 2.01 | | $ | 1.58 | |
| | | | | | | | | | | | | |
Reconciliation of Basic and Diluted | | Three Months Ended March 31, | |
Earnings per Share of Common Stock | | 2008 | | 2007 | |
| (In millions, except per share amounts) |
Net income | | $ | 276 | | $ | 290 | |
| | | | | | | |
Average shares of common stock outstanding – Basic | | | 304 | | | 314 | |
Assumed exercise of dilutive stock options and awards | | | 3 | | | 2 | |
Average shares of common stock outstanding – Dilutive | | | 307 | | | 316 | |
| | | | | | | |
Basic earnings per share of common stock | | $ | 0.91 | | $ | 0.92 | |
Diluted earnings per share of common stock | | $ | 0.90 | | $ | 0.92 | |
3. DIVESTITURES AND DISCONTINUED OPERATIONS
In 2006,On March 7, 2008, FirstEnergy sold its remaining FSG subsidiaries (Roth Bros., Hattenbach, Dunbar, Edwards and RPC) for an aggregatecertain telecommunication assets, resulting in a net after-tax gain of $2.2$19.3 million. Hattenbach, Dunbar, Edwards, and RPC are included in discontinued operationsAs a result of the sale, FirstEnergy adjusted goodwill by $1 million for the second quarter and six months ended June 30, 2006; Roth Bros.former GPU companies due to the realization of tax benefits that had been reserved in purchase accounting. The sale of assets did not meet the criteria for that classification.classification as discontinued operations as of March 31, 2008.
In4. FAIR VALUE MEASURES
Effective January 1, 2008, FirstEnergy adopted SFAS 157, which provides a framework for measuring fair value under GAAP and, among other things, requires enhanced disclosures about assets and liabilities recognized at fair value. FirstEnergy also adopted SFAS 159 on January 1, 2008, which provides the option to measure certain financial assets and financial liabilities at fair value. FirstEnergy has analyzed its financial assets and financial liabilities within the scope of SFAS 159 and, as of March 2006, FirstEnergy sold 60% of its interest31, 2008, has elected not to record eligible assets and liabilities at fair value.
As defined in MYRSFAS 157, fair value is the price that would be received for an after-tax gain of $0.2 million. In June 2006, as partasset or paid to transfer a liability (exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between willing market participants on the measurement date. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the March agreement, FirstEnergy sold an additional 1.67% interest. As a resultfair value hierarchy defined by SFAS 157 are as follows:
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the March sale, FirstEnergy deconsolidated MYRreporting date. Active markets are those where transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. FirstEnergy’s Level 1 assets and liabilities primarily consist of exchange-traded derivatives and equity securities listed on active exchanges that are held in various trusts.
Level 2 – Pricing inputs are either directly or indirectly observable in the first quartermarket as of 2006the reporting date, other than quoted prices in active markets included in Level 1. FirstEnergy’s Level 2 consists primarily of investments in debt securities held in various trusts and accountedcommodity forwards. Additionally, Level 2 includes those financial instruments that are valued using models or other valuation methodologies based on assumptions that are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Instruments in this category include non-exchange-traded derivatives such as forwards and certain interest rate swaps.
Level 3 – Pricing inputs include inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. FirstEnergy develops its remaining 38.33% interest underview of the equity method. Infuture market price of key commodities through a combination of market observation and assessment (generally for the fourth quartershort term) and fundamental modeling (generally for the longer term). Key fundamental electricity model inputs are generally directly observable in the market or derived from publicly available historic and forecast data. Some key inputs reflect forecasts published by industry leading consultants who generally employ similar fundamental modeling approaches. Fundamental model inputs and results, as well as the selection of 2006,consultants, reflect the consensus of appropriate FirstEnergy sold its remaining MYR interestmanagement. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. FirstEnergy’s Level 3 instruments consist of NUG contracts.
FirstEnergy utilizes market data and assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. FirstEnergy primarily applies the market approach for an after-tax gainrecurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of $8.6 million.observable inputs and minimizes the use of unobservable inputs.
The income for the periodfollowing table sets forth FirstEnergy’s financial assets and financial liabilities that MYR wasare accounted for at fair value by level within the fair value hierarchy as an equity method investment has not been includedof March 31, 2008. As required by SFAS 157, assets and liabilities are classified in discontinued operations; however, results priortheir entirety based on the lowest level of input that is significant to the initial sale in March 2006, includingfair value measurement. FirstEnergy’s assessment of the gain onsignificance of a particular input to the sale, are reported as discontinued operations.fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
Revenues associated with discontinued operations were $34
| | March 31, 2008 | |
Recurring Fair Value Measures | | Level 1 | | Level 2 | | Level 3 | | Total | |
| | (In millions) | |
Assets: | | | | | | | | | | | | | |
Derivatives | | $ | 4 | | $ | 98 | | $ | - | | $ | 102 | |
Nuclear decommissioning trusts(1) | | | 1,070 | | | 953 | | | - | | | 2,023 | |
Other investments(2) | | | 21 | | | 303 | | | - | | | 324 | |
Total | | $ | 1,095 | | $ | 1,354 | | $ | - | | $ | 2,449 | |
| | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | |
Derivatives | | $ | - | | $ | 98 | | $ | - | | $ | 98 | |
NUG contracts(3) | | | - | | | - | | | 682 | | | 682 | |
Total | | $ | - | | $ | 98 | | $ | 682 | | $ | 780 | |
| (1) | Balance excludes $2 million of receivables, payables and accrued income. |
| (2) | Excludes $318 million of the cash surrender value of life insurance contracts. |
| (3) | NUG contracts are completely offset by regulatory assets. |
The determination of the above fair value measures takes into consideration various factors required under SFAS 157. These factors include the credit standing of the counterparties involved, the impact of credit enhancements (such as cash deposits, LOCs and $174 millionpriority interests) and the impact of nonperformance risk.
Exchange-traded derivative contracts, which include some futures and options, are generally based on unadjusted quoted market prices in active markets and are classified within Level 1. Forwards, options and swap contracts that are not exchange-traded are classified as Level 2 as the fair values of these items are based on ICE quotes or market transactions in the second quarterOTC markets. In addition, complex or longer term structured transactions can introduce the need for internally-developed model inputs that may not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is classified as Level 3.
Nuclear decommissioning trusts consist of equity securities listed on active exchanges classified as Level 1 and first six monthsvarious debt securities and collective trusts classified as Level 2. Other investments represent the NUG trusts, spent nuclear fuel trusts and rabbi trust investments, which primarily consist of 2006, respectively. various debt securities and collective trusts classified as Level 2.
The following table summarizessets forth a reconciliation of changes in the net income (loss) includedfair value of NUG contracts classified as Level 3 in "Discontinued Operations" on the Consolidated Statements of Incomefair value hierarchy for the three months and six months ended June 30, 2006:March 31, 2008 (in millions):
| | Three Months | | | Six Months | |
| | (In millions) | |
| | | | | | |
FSG subsidiaries | | $ | (8 | ) | $ | (8 | ) |
MYR | | | - | | | 2 | |
Total | | $ | (8 | ) | $ | (6 | ) |
Balance as of January 1, 2008 | | $ | 750 | |
Realized and unrealized gains (losses)(1) | | | (58 | ) |
Purchases, sales, issuances and settlements, net(1) | | | (10 | ) |
Net transfers to (from) Level 3 | | | - | |
Balance as of March 31, 2008 | | $ | 682 | |
| | | | |
Change in unrealized gains (losses) relating to | | | | |
instruments held as of March 31, 2008 | | $ | (58 | ) |
| | | | |
(1) Changes in the fair value of NUG contracts are completely offset by regulatory assets and do not impact earnings. | |
4.Under FSP FAS 157-2, FirstEnergy has elected to defer, for one year, the election of SFAS 157 for financial assets and financial liabilities measured at fair value on a non-recurring basis. FirstEnergy is currently evaluating the impact of FAS 157 on those financial assets and financial liabilities measured at fair value on a non-recurring basis.
5. 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 derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. FirstEnergy's Risk Policy Committee, comprised of members of senior management, provides general management oversight for risk management activities throughout FirstEnergy. 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.
FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheet at their fair value unless they meet the normal purchasepurchases and normal sales criterion.criteria. Derivatives that meet that criterionthose criteria are accounted for using traditional accrual accounting.at cost. The changes in the fair value of derivative instruments that do not meet the normal purchasepurchases and normal sales criterioncriteria are recorded as other expense, as AOCL, 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 does not offset fair value for the right to reclaim collateral or the obligation to return collateral.
FirstEnergy hedges anticipated transactions using cash flow hedges. Such transactions include hedges of anticipated electricity and natural gas purchases and anticipated interest payments associated with future debt issues. The effective portion of such hedges are initially recorded in equity as other comprehensive income or loss and are subsequently included in net income as the underlying hedged commodities are delivered or interest payments are made. Gains and losses from any ineffective portion of cash flow hedges are included directly in earnings.
The net deferred losses of $45$84 million included in AOCL as of June 30, 2007,March 31, 2008, for derivative hedging activity, as compared to $58$75 million as of December 31, 2006,2007, resulted from a net $2$21 million decreaseincrease related to current hedging activity and an $11a $12 million decrease due to net hedge losses reclassified intoto earnings during the sixthree months ended June 30, 2007.March 31, 2008. Based on current estimates, approximately $17$19 million (after tax) of the net deferred losses on derivative instruments in AOCL as of June 30, 2007 isMarch 31, 2008 are expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments fluctuate from period to period based on various market factors.
FirstEnergy has entered into swaps that have been designated as fair value hedges of fixed-rate, long-term debt issues to protect against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates received, and interest payment dates match those of the underlying debt obligations. During the first six months of 2007, FirstEnergy unwound swaps with a total notional value of $150 million for which it incurred $8 million in cash losses, which will be recognized over the remaining maturity of each hedged security as interest expense. As of June 30, 2007,March 31, 2008, FirstEnergy had interest rate swaps with an aggregate notional value of $600$250 million and a fair value of $(30)$5 million.
During 20062007 and the first sixthree months of 2007,2008, 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 anticipated issuancesissuance of variable-rate, short-term debt and fixed-rate, long-term debt securities forby one or more of its subsidiaries during 2007 and 2008 as outstanding debt matures.matures during 2008 and 2009. 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 and LIBOR rates between the date of hedge inception and the date of the debt issuance. During the first sixthree months of 2007,2008, FirstEnergy terminated swaps with a notional value of $950$300 million for which itand entered into swaps with a notional value of $500 million. FirstEnergy paid $2$18 million allrelated to the terminations, $1 million of which werewas deemed effective.ineffective and recognized in current period earnings. FirstEnergy will recognize the remaining $17 million loss over the life of the associated future debt. As of June 30, 2007,March 31, 2008, FirstEnergy had forward swaps with an aggregate notional amount of $250$600 million and a fair value of $6$(8) million.
5.6. ASSET RETIREMENT OBLIGATIONS
FirstEnergy has recognized applicable legal obligations under SFAS 143 for nuclear power plant decommissioning, reclamation of a sludge disposal pond and closure of two coal ash disposal sites. In addition, FirstEnergy has recognized conditional retirement obligations (primarily for asbestos remediation) in accordance with FIN 47.
The ARO liability of $1.2$1.3 billion as of June 30, 2007March 31, 2008 is primarily related to the future nuclear decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating facilities. FirstEnergy utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.
FirstEnergy maintains nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of June 30, 2007,March 31, 2008, the fair value of the decommissioning trust assets was approximately $2.1$2.0 billion.
The following tables analyze changes to the ARO balancesbalance during the three monthsfirst quarters of 2008 and six months ended June 30, 2007, and 2006, respectively.
Three Months Ended | | FirstEnergy | | OE | | CEI | | TE | | JCP&L | | Met-Ed | | Penelec | | |
| | (In millions) | | |
ARO Reconciliation | | | | | | | | | | | | | | | | | | | | | | | |
Balance, April 1, 2007 | | $ | 1,208 | | $ | 89 | | $ | 2 | | $ | 27 | | $ | 86 | | $ | 153 | | $ | 78 | | |
Liabilities incurred | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | |
Liabilities settled | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | |
Accretion | | | 21 | | | 2 | | | - | | | - | | | 1 | | | 3 | | | 1 | | |
Revisions in estimated | | | | | | | | | | | | | | | | | | | | | | | |
cashflows | | | (1 | ) | | - | | | - | | | - | | | - | | | - | | | - | | |
Balance, June 30, 2007 | | $ | 1,228 | | $ | 91 | | $ | 2 | | $ | 27 | | $ | 87 | | $ | 156 | | $ | 79 | | |
| | | | | | | | | | | | | | | | | | | | | | | |
Balance, April 1, 2006 | | $ | 1,148 | | $ | 84 | | $ | 8 | | $ | 25 | | $ | 81 | | $ | 144 | | $ | 73 | | |
Liabilities incurred | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | |
Liabilities settled | | | (6 | ) | | - | | | (6 | ) | | - | | | - | | | - | | | - | | |
Accretion | | | 18 | | | 1 | | | - | | | 1 | | | 1 | | | 2 | | | 1 | | |
Revisions in estimated | | | | | | | | | | | | | | | | | | | | | | | |
cashflows | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | |
Balance, June 30, 2006 | | $ | 1,160 | | $ | 85 | | $ | 2 | | $ | 26 | | $ | 82 | | $ | 146 | | $ | 74 | | |
ARO Reconciliation | | FirstEnergy | | FES | | OE | | CEI | | TE | | JCP&L | | Met-Ed | | Penelec | |
| | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Revisions in estimated cash flows | | | - | | | | | | | | | | | | | | | | | | | | | | |
| | $ | 1,287 | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Revisions in estimated cash flows | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Six Months Ended | | FirstEnergy | | OE | | CEI | | TE | | JCP&L | | Met-Ed | | Penelec | | |
| | (In millions) | | |
ARO Reconciliation | | | | | | | | | | | | | | | | | | | | | | | |
Balance, January 1, 2007 | | $ | 1,190 | | $ | 88 | | $ | 2 | | $ | 27 | | $ | 84 | | $ | 151 | | $ | 77 | | |
Liabilities incurred | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | |
Liabilities settled | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | |
Accretion | | | 39 | | | 3 | | | - | | | - | | | 3 | | | 5 | | | 2 | | |
Revisions in estimated | | | | | | | | | | | | | | | | | | | | | | | |
cashflows | | | (1 | ) | | - | | | - | | | - | | | - | | | - | | | - | | |
Balance, June 30, 2007 | | $ | 1,228 | | $ | 91 | | $ | 2 | | $ | 27 | | $ | 87 | | $ | 156 | | $ | 79 | | |
| | | | | | | | | | | | | | | | | | | | | | | |
Balance, January 1, 2006 | | $ | 1,126 | | $ | 83 | | $ | 8 | | $ | 25 | | $ | 80 | | $ | 142 | | $ | 72 | | |
Liabilities incurred | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | |
Liabilities settled | | | (6 | ) | | - | | | (6 | ) | | - | | | - | | | - | | | - | | |
Accretion | | | 36 | | | 2 | | | - | | | 1 | | | 2 | | | 4 | | | 2 | | |
Revisions in estimated | | | | | | | | | | | | | | | | | | | | | | | |
cashflows | | | 4 | | | - | | | - | | | - | | | - | | | - | | | - | | |
Balance, June 30, 2006 | | $ | 1,160 | | $ | 85 | | $ | 2 | | $ | 26 | | $ | 82 | | $ | 146 | | $ | 74 | | |
6.7. PENSION AND OTHER POSTRETIREMENT BENEFITS
FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its employees.employees and those of its subsidiaries. The trusteed plans provide defined benefits based on years of service and compensation levels. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. FirstEnergy uses a December 31 measurement date for its pension and other postretirement benefit plans. The fair value of the plan assets represents the actual market value as of December 31, 2006. On January 2, 2007, FirstEnergy made a $300 million voluntary cash contribution to its qualified pension plan. Projections indicate that additional cash contributions are not expected to be required before 2016.2007. FirstEnergy also provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are available upon retirement to employees hired prior to January 1, 2005, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension benefits and other postretirement benefits from the time employees are hired until they become eligible to receive those benefits. During 2006, FirstEnergy amended the health care plan effective in 2008 to cap the monthly contribution for many of the retirees and their spouses receiving subsidized health care coverage. In addition, FirstEnergy has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.
The components of FirstEnergy's net periodic pension cost and other postretirement benefit costscost (including amounts capitalized) for the three months ended March 31, 2008 and six months ended June 30, 2007, and 2006 consisted of the following:
| | Three Months Ended | Six Months Ended | |
| | June 30, | | June 30, | |
Pension Benefits | | 2007 | | 2006 | | 2007 | | 2006 | |
| | (In millions) | |
Service cost | | $ | 21 | | $ | 21 | | $ | 42 | | $ | 41 | |
Interest cost | | | 71 | | | 66 | | | 142 | | | 133 | |
Expected return on plan assets | | | (113 | ) | | (99 | ) | | (225 | ) | | (198 | ) |
Amortization of prior service cost | | | 3 | | | 2 | | | 5 | | | 5 | |
Recognized net actuarial loss | | | 11 | | | 15 | | | 21 | | | 29 | |
Net periodic cost (credit) | | $ | (7 | ) | $ | 5 | | $ | (15 | ) | $ | 10 | |
| | Three Months Ended | Six Months Ended | | | Pension Benefits | | Other Postretirement Benefits | |
| | June 30, | | June 30, | | | 2008 | | 2007 | | 2008 | | 2007 | |
Other Postretirement Benefits | | 2007 | | 2006 | | 2007 | | 2006 | | |
| | (In millions) | | | (In millions) | |
Service cost | | $ | 5 | | $ | 9 | | $ | 10 | | $ | 17 | | | | | | | | | | | | | | |
Interest cost | | | 17 | | | 26 | | | 34 | | | 52 | | | | | | | | | | | |
Expected return on plan assets | | | (12 | ) | | (12 | ) | | (25 | ) | | (23 | ) | | | | | | | | | | | | | |
Amortization of prior service cost | | | (37 | ) | | (19 | ) | | (74 | ) | | (37 | ) | | | | | | | | | | | |
Recognized net actuarial loss | | | 11 | | | 14 | | | 23 | | | 27 | | | | | | | | | | | | | | |
Net periodic cost (credit) | | $ | (16 | ) | $ | 18 | | $ | (32 | ) | $ | 36 | | | | | ) | | | | | | ) | | | ) |
Pension and other postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. FirstEnergy’s subsidiariesThe Companies capitalize employee benefits related to construction projects. The net periodic pension costs and othernet periodic postretirement benefit costs (including amounts capitalized) recognized by each of the Companies for the three months ended March 31, 2008 and six months ended June 30, 2007 and 2006 were as follows:
| | Three Months Ended | | Six Months Ended | | | Pension Benefit Cost (Credit) | | Other Postretirement Benefit Cost (Credit) | |
| | June 30, | | June 30, | | | 2008 | | 2007 | | 2008 | | 2007 | |
Pension Benefit Cost (Credit) | | 2007 | | 2006 | | 2007 | | 2006 | | |
| | (In millions) | | | (In millions) | |
| | | | | | | | | | | ) | | | |
OE | | $ | (3.9 | ) | $ | (1.5 | ) | $ | (7.9 | ) | $ | (2.9 | ) | | | | ) | | | ) | | | ) | | | ) |
CEI | | | 0.3 | | | 1.0 | | | 0.6 | | | 1.9 | | | | | ) | | | | | | | | |
TE | | | (0.1 | ) | | 0.2 | | | (0.1 | ) | | 0.4 | | | | | ) | | | | | | | | |
JCP&L | | | (2.2 | ) | | (1.4 | ) | | (4.3 | ) | | (2.7 | ) | | | | | | | | | | ) | | | ) |
Met-Ed | | | (1.7 | ) | | (1.7 | ) | | (3.4 | ) | | (3.5 | ) | | | | | | | | | | ) | | | ) |
Penelec | | | (2.5 | ) | | (1.3 | ) | | (5.1 | ) | | (2.7 | ) | | | | | | | | | | ) | | | ) |
Other FirstEnergy subsidiaries | | | 2.6 | | | 9.9 | | | 5.1 | | | 20.0 | | | | | | | | | | | ) | | | ) |
| | $ | (7.5 | ) | $ | 5.2 | | $ | (15.1 | ) | $ | 10.5 | | | | | ) | | | ) | | | ) | | | ) |
| | Three Months Ended | | Six Months Ended | |
| | June 30, | | June 30, | |
Other Postretirement Benefit Cost (Credit) | | 2007 | | 2006 | | 2007 | | 2006 | |
| | (In millions) | |
OE | | $ | (2.6 | ) | $ | 4.2 | | $ | (5.3 | ) | $ | 8.4 | |
CEI | | | 0.9 | | | 2.8 | | | 1.9 | | | 5.5 | |
TE | | | 1.2 | | | 2.0 | | | 2.4 | | | 4.0 | |
JCP&L | | | (4.0 | ) | | 0.6 | | | (8.0 | ) | | 1.2 | |
Met-Ed | | | (2.6 | ) | | 0.7 | | | (5.1 | ) | | 1.5 | |
Penelec | | | (3.1 | ) | | 1.8 | | | (6.3 | ) | | 3.6 | |
Other FirstEnergy subsidiaries | | | (5.7 | ) | | 6.1 | | | (11.4 | ) | | 12.1 | |
| | $ | (15.9 | ) | $ | 18.2 | | $ | (31.8 | ) | $ | 36.3 | |
7.
8. VARIABLE INTEREST ENTITIES
FIN 46R addresses the consolidation of VIEs, including special-purpose entities, that are not controlled through voting interests or in which the equity investors do not bear the entity's residual economic risks and rewards. FirstEnergy and its subsidiaries consolidate VIEs when they are determined to be the VIE's primary beneficiary as defined by FIN 46R.
LeasesTrusts
FirstEnergy’s consolidated financial statements include PNBV and Shippingport, VIEs created in 1996 and 1997, respectively, to refinance debt originally issued in connection with sale and leaseback transactions. PNBV and Shippingport financial data are included in the consolidated financial statements of OE and CEI, respectively.
PNBV was established to purchase a portion of the lease obligation bonds issued in connection with OE’s 1987 sale and leaseback of its interests in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by PNBV. Ownership of PNBV includes a 3% equity interest by an unaffiliated third party and a 3% 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, CEILoss Contingencies
FES and TEthe Ohio Companies are exposed to losses under thetheir applicable sale-leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. OE, CEI and TE each have aThe maximum exposure to loss under these provisions of approximately $851 million, $790 million and $790 million, respectively, which represents the net amount of casualty value payments due 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 minimumNet discounted lease payments of $619 million, $82 million and $442 million, respectively, that would not be payable if the casualty valueloss payments are made. The following table shows each company’s net exposure to loss based upon the casualty value provisions mentioned above as of March 31, 2008:
| | Maximum Exposure | | Discounted Lease Payments, net | | Net Exposure |
| | (in millions) |
FES | | $ | 1,364 | | $ | 1,216 | | $ | 148 |
OE | | 819 | | 628 | | 191 |
CEI | | 782 | | 77 | | 705 |
TE | | 782 | | 457 | | 325 |
In October 2007, CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant to FGCO. FGCO assumed all of CEI’s and TE’s obligations arising under those leases. FGCO subsequently transferred the Unit 1 portion of these leasehold interests, as well as FGCO’s leasehold interests under its July 2007 Bruce Mansfield Unit 1 sale and leaseback transaction to a newly formed wholly-owned subsidiary in December 2007. The subsidiary assumed all of the lessee obligations associated with the assigned interests. However, CEI and TE will remain primarily liable on the 1987 leases and related agreements as to the lessors and other parties to the agreements. FGCO remains primarily liable on the 2007 leases and related agreements, and FES remains primarily liable as a guarantor under the related 2007 guarantees, as to the lessors and other parties to the respective agreements. These assignments terminate automatically upon the termination of the underlying leases.
On March 3, 2008, notice was given to the nine owner trusts that are lessors under sale and leaseback transactions, originally entered into by TE in 1987, that NGC would acquire the related 18.26% undivided interest in Beaver Valley Unit 2 through the exercise of the periodic purchase option provided for in the applicable facility leases. The purchase price to be paid by NGC for the undivided interest will be equal to the higher of a specified casualty value under the applicable facility leases (approximately $239 million in the aggregate for the equity portion of all nine facility leases) and the fair market sales value of such undivided interests. Determination of the fair market sales value may become subject to an appraisal procedure provided for in the lease documentation. An additional payment of approximately $236 million would be required to prepay in full the outstanding principal of, and accrued but unpaid interest on, the lessor notes of the nine owner trusts. Alternatively, this amount would not be paid as part of the aggregate purchase price if the lessor notes are instead assumed at the time of the exercise of the option. If NGC determines to prepay the notes, it is possible that the proceeds from such prepayment may not be sufficient to pay the principal of, and interest on, the bonds as they become due. If that is the case, NGC would provide a mechanism to address any such potential shortfall in a timely manner.
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 entered into pursuant to the Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, these entities.
FirstEnergy has determined that for all but eight of these entities, neither JCP&L, Met-Ed nor Penelec have variable interests in the entities or the entities are governmental or not-for-profit organizations not within the scope of FIN 46R. JCP&L, Met-Ed or Penelec may hold variable interests in the remaining eight entities, which sell their output at variable prices that correlate to some extent with the operating costs of the plants. As required by FIN 46R, FirstEnergy periodically requests from these eight entities the information necessary to determine whether they are VIEs or whether JCP&L, Met-Ed or Penelec is the primary beneficiary. FirstEnergy has been unable to obtain the requested information, which in most cases was deemed by the requested entity to be proprietary. As such, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities under FIN 46R.
Since FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs it incursmay incur for power. FirstEnergy expects any above-market costs it incurs to be recovered from customers. As of June 30, 2007, the net above-market loss liability projected for these eight NUG agreements was $145 million. Purchased power costs from these entities during the three months ended March 31, 2008 and six months ended June 30, 2007 and 2006 are shown in the following table:
| | Three Months Ended | | Six Months Ended | | | Three Months Ended | |
| | June 30, | | June 30, | | | March 31, | |
| | 2007 | | 2006 | | 2007 | | 2006 | | | 2008 | | 2007 | |
| | (In millions) | | | (In millions) | |
JCP&L | | $ | 21 | | $ | 19 | | $ | 41 | | $ | 34 | | | | | | | | |
Met-Ed | | | 12 | | | 16 | | | 27 | | | 33 | | | | | | | | |
Penelec | | | 7 | | | 7 | | | 15 | | | 14 | | | | | | | | |
Total | | $ | 40 | | $ | 42 | | $ | 83 | | $ | 81 | | |
| | | | | | | | |
Transition Bonds
The consolidated financial statements of FirstEnergy and JCP&L include the results of JCP&L Transition Funding and JCP&L Transition Funding II, wholly owned limited liability companies of JCP&L. In June 2002, JCP&L Transition Funding 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. In August 2006, JCP&L Transition Funding II sold $182 million of transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS.
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. As of June 30, 2007, $411March 31, 2008, $391 million of the transition bonds arewere outstanding. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s equity and assets, which consists primarily of bondable transition property.
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 transition bonds and other fees and expenses associated with their issuance. JCP&L sold its bondable transition property to JCP&L Transition Funding and JCP&L Transition Funding II and, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the TBC, pursuant to separate servicing agreements with JCP&L Transition Funding and JCP&L Transition Funding II. For the two series of transition bonds, JCP&L is entitled to aggregate quarterly servicing fees of $157,000 that is payable from TBC collections.
8.9. INCOME TAXES
On January 1, 2007, FirstEnergy adopted FIN 48, which provides guidance for accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS 109. This interpretation prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken on a company’s tax return. FIN 48 also provides guidance on derecognition, classification, interest, penalties, accounting in interim periods, disclosure and transition. The evaluation of a tax position in accordance with this interpretation is a two-step process. The first step is to determine if it is more likely than not that a tax position will be sustained upon examination, based on the merits of the position, and should therefore be recognized. The second step is to measure a tax position that meets the more likely than not recognition threshold to determine the amount of income tax benefit to recognize in the financial statements.
As of January 1, 2007, the total amount of FirstEnergy’s unrecognized tax benefits was $268 million. FirstEnergy recorded a $2.7 million cumulative effect adjustment to the January 1, 2007 balance of retained earnings to increase reserves for uncertain tax positions. Of the total amount of unrecognized income tax benefits, $92 million would favorably affect FirstEnergy’s effective tax rate upon recognition. The majority of items that would not affecthave affected the effective tax rate would be purchase accounting adjustments to goodwill upon recognition. During the first sixthree months of 2008 and 2007, there were no material changes to FirstEnergy’s unrecognized tax benefits. As of June 30, 2007,March 31, 2008, FirstEnergy expects that it is reasonably possible that $8 million of the entire liability for uncertain tax positionsunrecognized benefits will be resolved within the next twelve months and is included in other non-current liabilities and changes to FirstEnergy’s tax contingencies that are reasonably possiblethe caption “accrued taxes,” with the remaining $263 million included in the next 12 months are not material.caption “other non-current liabilities” on the Consolidated Balance Sheets.
FIN 48 also requires companies to recognize interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized in accordance with FIN 48 and the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes, consistent with its policy prior to implementing FIN 48. As of January 1, 2007, theThe net amount of interest accrued as of March 31, 2008 was $34 million.$57 million, as compared to $53 million as of December 31, 2007. During the first sixthree months of 2008 and 2007, there were no material changes to the amount of interest accrued.
FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state tax authorities. All state jurisdictions are open from 2001-2006.2001-2007. The IRS began reviewing returns for the years 2001-2003 in July 2004 and several items are under appeal. The federal auditaudits for the years 2004 and 2005 began in June 2006 and is not2004-2006 are expected to close before December 2007.2008, but management anticipates certain items to be under appeal. The IRS began auditing the year 20062007 in April 2006February 2007 and year 2008 in February 2008 under its Compliance Assurance Process experimental program, whichprogram. Neither audit is not expected to close before December 2007.2008. Management believes that adequate reserves have been recognized and final settlement of these audits is not expected to have a material adverse effect on FirstEnergy’s financial condition or results of operations.
In the first six months of 2007, OE’s income taxes included an immaterial adjustment applicable to prior periods of $7.2 million related to an inter-company federal tax allocation arrangement among FirstEnergy and its subsidiaries.
9.10. 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. These agreements include contract guarantees, surety bonds and LOCs. As of June 30, 2007,March 31, 2008, outstanding guarantees and other assurances aggregated approximately $4.1$4.4 billion, consisting of contractparental guarantees - $2.3$0.9 billion, subsidiaries’ guarantees - $2.7 billion, surety bonds - $0.1 billion and LOCs - $1.7$0.7 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 credit support for subsidiary financingsthe financing or refinancingsrefinancing by subsidiaries of costs related to 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. The likelihood is remote that such parental guarantees of $0.8$0.4 billion (included in the $2.3$0.9 billion discussed above) as of June 30, 2007March 31, 2008 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.
While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating-downgraderating downgrade or “material adverse event”event,” the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. As of June 30, 2007,March 31, 2008, FirstEnergy's maximum exposure under these collateral provisions was $421$440 million.
Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of $95$66 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction jobs,contracts, 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.
| | | | Borrowing | |
| | Parent Company | | | |
| | | | (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 also guaranteed the obligations of the operators of the TEBSA project, up to a maximum of $6$2 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 ($2719 million as of June 30, 2007)March 31, 2008), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA.
In July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Plant Unit 1, representing 779 MW of net demonstrated capacity. The purchase price of approximately $1.329 billion (net after-tax proceeds of approximately $1.2 billion) for the undivided interest was funded through a combination of equity investments by affiliates of AIG Financial Products Corp. and Union Bank of California, N.A. in six lessor trusts and proceeds from the sale of $1.135 billion aggregate principal amount of 6.85% pass through certificates due 2034. A like principal amount of secured notes maturing June 1, 2034 were issued by the lessor trusts to the pass through trust that issued and sold the certificates. The lessor trusts leased the undivided interest back to FGCO for a term of approximately 33 years under substantially identical leases.1. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor’slessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements. The transaction will be classified as a financing under GAAP until FGCO’s andagreements, including FES’ registration obligations under the registration rights agreement applicable to the $1.135 billion principal amount of pass through certificates issued in connection with the transaction are satisfied, at which time it is expected to be classified as an operating lease under GAAP. This transaction generated tax capital gains of approximately $830 million, a substantial portion of which will be offset by existing tax capital loss carryforwards. FirstEnergy expects to reduce its tax loss carryforward valuation allowances in the third quarter of 2007 and anticipates an immaterial impact to net income as the majority of the unrecognized tax benefits will reduce goodwill.guaranty.
(B) ENVIRONMENTAL MATTERS(B) | ENVIRONMENTAL MATTERS |
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. The effects of compliance on FirstEnergy with regard to environmental matters could have a material adverse effect on 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. FirstEnergy estimates capital expenditures for environmental compliance of approximately $1.8$1.4 billion for 2007 through 2011.the period 2008-2012.
FirstEnergy accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in FirstEnergy’s determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.
Clean Air Act Compliance
FirstEnergy is required to meet federally-approved SO2 emissions regulations. Violations of such regulations can result in the 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. FirstEnergy believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.
The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006, alleging violations to various sections of the Clean Air Act.CAA. FirstEnergy has disputed those alleged violations based on its Clean Air ActCAA permit, the Ohio SIP and other information provided to the EPA at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order, and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding the opacity limit applicable to the common stack for Bay Shore Units 2, 3 and 4.
FirstEnergy complies 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 at FirstEnergy's facilities. The EPA's NOX Transport Rule imposes uniform reductions of NOX emissions (an approximate 85% reduction in utility plant NOX emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOX emissions are contributing significantly to ozone levels in the eastern United States. FirstEnergy believes its facilities are also complying with the NOX budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.
On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal Clean Air Act,CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Mansfield Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On July 25,October 18, 2007, PennFuture filed a complaint, joined by three of its members, in the United States District Court for the Western District of Pennsylvania. On January 11, 2008, FirstEnergy filed a motion to dismiss claims alleging a public nuisance. On April 24, 2008, the Court denied the motion to dismiss, but also ruled that monetary damages could not be recovered under the public nuisance claim.
On December 18, 2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations at the Portland Generation Station against Reliant (the current owner and PennFuture entered intooperator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU, Inc. and Met-Ed. Specifically, New Jersey alleges that "modifications" at Portland Units 1 and 2 occurred between 1980 and 1995 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seeks injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. On March 14, 2008, Met-Ed filed a Tollingmotion to dismiss the citizen suit claims against it and Confidentiality Agreement that provides for a 60-day negotiation period duringstipulation in which the parties have agreed that GPU, Inc. should be dismissed from this case. On March 26, 2008, GPU, Inc. was dismissed by the Court. Although it remains liable for civil or criminal penalties and fines that may be assessed relating to not file a lawsuit.events prior to the sale of the Portland Station in 1999, Met-Ed is indemnified by Sithe Energy against any other liability arising under the CAA whether it arises out of pre-1999 or post-1999 events.
National Ambient Air Quality Standards
In July 1997, the EPA promulgated changes in the NAAQS for ozone and fine particulate matter. In March 2005, the EPA finalized the CAIR 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 non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR allowed each affected state until 2006 to develop implementing regulations to achieve additionalrequires 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). FirstEnergy's Michigan, Ohio and Pennsylvania fossil-firedfossil generation facilities will be subject to caps on SO2 and NOX emissions, whereas its New Jersey fossil-firedfossil generation facility will be subject to only a cap on 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. CAIR has been challenged in the United States Court of Appeals for the District of Columbia. The future cost of compliance with these regulations may be substantial and willmay depend on the outcome of this litigation and how they areCAIR is ultimately implemented by the states in which FirstEnergy operates affected facilities.implemented.
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. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases. Initially,phases; initially, capping national mercury emissions will be capped nationally at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program). Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at and 15 tons per year by 2018. However, the final rules giveSeveral states substantial discretion in developing rules to implement these programs. In addition, both the CAIR and environmental groups appealed the CAMR have been challenged into the United States Court of Appeals for the District of Columbia. FirstEnergy'sOn February 8, 2008, the court vacated the CAMR ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. The EPA must now seek further judicial review of that ruling or take regulatory action to promulgate new mercury emission standards for coal-fired power plants. FGCO’s future cost of compliance with thesemercury regulations may be substantial and will depend on the action taken by the EPA and on how they are ultimately implemented by the states in which FirstEnergy operates affected facilities.implemented.
The model rules for both CAIR and CAMR contemplate an input-based methodology to allocate allowances to affected facilities. Under this approach, allowances would be allocated based on the amount of fuel consumed by the affected sources. FirstEnergy would prefer an output-based generation-neutral methodology in which allowances are allocated based on megawatts of power produced, allowing new and non-emitting generating facilities (including renewables and nuclear) to be entitled to their proportionate share of the allowances. Consequently, FirstEnergy will be disadvantaged if these model rules were implemented as proposed because FirstEnergy’s substantial reliance on non-emitting (largely nuclear) generation is not recognized under the input-based allocation.
Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap and tradecap-and-trade approach as in the CAMR, but rather follows a command and controlcommand-and-control approach imposing emission limits on individual sources. Pennsylvania’s mercury regulation would deprive FES of mercury emission allowances that were to be allocated to the Mansfield Plant under the CAMR and that would otherwise be available for achieving FirstEnergy system-wide compliance. It is anticipated that compliance with these regulations, if approved by the EPA and implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant, FirstEnergy’s only Pennsylvania coal-fired power plant, until 2015, if at all.
W. H. Sammis Plant
In 1999 and 2000, the EPA issued an NOV or compliance orders to nine utilities alleging violations ofand the Clean Air ActDOJ filed a civil complaint against OE and Penn based on operation and maintenance of 44 power plants, including the W. H.W.H. Sammis Plant which was owned at that time by OE(Sammis NSR Litigation) and Penn, and is now owned by FGCO. In addition, the DOJ filed eight civilsimilar complaints against various investor-owned utilities, including a complaint against OE and Penn in theinvolving 44 other U.S. District Court for the Southern District of Ohio. Thesepower plants. This case, along with seven other similar cases, are referred to as the New Source Review, or NSR cases.
On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation. This settlement agreement, which is in the form of a consent decree, was approved by the court on July 11, 2005, and requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FirstEnergy fails to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FirstEnergy could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation settlement agreementconsent decree are currently estimated to be $1.7$1.3 billion for 2007 through 20112008-2012 ($400650 million of which is expected to be spent during 2007,2008, with the largest portion of the remaining $1.3 billion$650 million expected to be spent in 2008 and 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above.
On April 2, 2007, the United States Supreme Court ruled that changes in annual emissions (in tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must be used to determine whether an emissions increase triggers NSR. Subsequently, on May 8, 2007, the EPA proposed to revise the NSR regulations to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR. The Sammis NSR Litigation consent decree also requires FirstEnergy to spend up to $25 million toward environmentally beneficial projects, $14 millionEPA has not yet issued a final regulation. FGCO’s future cost of which is satisfied by entering into 93 MW (or 23 MW if federal tax creditscompliance with those regulations may be substantial and will depend on how they are not applicable) of wind energy purchased power agreements with a 20-year term. An initial 16 MW of the 93 MW consent decree obligation was satisfied during 2006.ultimately implemented.
Climate Change
In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Kyoto Protocol in 1998 but it failed to receive the two-thirds vote required for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. AtAlso, in an April 16, 2008 speech, President Bush set a policy goal of stopping the international level, efforts have begun to develop climate change agreements for post-2012growth of GHG reductions. Theemissions by 2025, as the next step beyond the 2012 strategy. In addition, the EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.
There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the international level, efforts to reach a new global agreement to reduce GHG emissions post-2012 have begun with the Bali Roadmap, which outlines a two-year process designed to lead to an agreement in 2009. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States.States, and the Senate Environmental and Public Works Committees have passed one such bill. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.
On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the Clean Air Act.CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the Clean Air ActCAA to regulate “air pollutants” from those and other facilities. Also on April 2, 2007, the United States Supreme Court ruled that changes in annual emissions (in tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must be used to determine whether an emissions increase triggers NSR. Subsequently, the EPA proposed to change the NSR regulations, on May 8, 2007, to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR.
FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions could require significant capital and other expenditures. The CO2 emissions per KWH of electricity generated by FirstEnergy is lower than many regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy's plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FirstEnergy's operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.
On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality, when aquatic organisms are pinned against screens or other parts of a cooling water intake system, and entrainment, which occurs when aquatic life is drawn into a facility's cooling water system. On January 26, 2007, the federal Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to EPA for further rulemaking and eliminated the restoration option from EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment (BPJ) to minimize impacts on fish and shellfish from cooling water intake structures. FirstEnergy is evaluating various control options and their costs and effectiveness. Depending on the outcome of such studies, the EPA’s further rulemaking and any action taken by the states exercising BPJ, 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.
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of June 30, 2007, FirstEnergy had approximately $1.5 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley and Perry. As part of the application to the NRC to transfer the ownership of these nuclear facilities to NGC, FirstEnergy agreed to contribute another $80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy plans to seek for these facilities.
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 June 30, 2007, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable SBC. Total liabilities of approximately $88 million (JCP&L - $60 million, TE - $3 million, CEI - $1 million, and other subsidiaries - $24 million) have been accrued through June 30, 2007.
(C) OTHER LEGAL PROCEEDINGS
Power Outages and Related Litigation
In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four of New Jersey’s electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the JCP&L territory.
In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision on July 8, 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, on March 7, 2007, reversed the decertification of the Red Bank class and remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied on May 9, 2007. Proceedings are continuing in the Superior Court. FirstEnergy is vigorously defending this class action but is unable to predict the outcome of this matter. No liability has been accrued as of June 30, 2007.
On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. – Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s Web site (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy is also proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional material expenditures.
FirstEnergy companies also are defending four separate complaint cases before the PUCO relating to the August 14, 2003 power outages. Two of those cases were originally filed in Ohio State courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In these cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Two other pending PUCO complaint cases were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of these cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and American Electric Power Company, Inc., as well) for claims paid to insureds for damages allegedly arising as a result of the loss of power on August 14, 2003. A fifth case in which a carrier sought reimbursement for claims paid to insureds was voluntarily dismissed by the claimant in April 2007. A sixth case involving the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003 was dismissed. The four cases were consolidated for hearing by the PUCO in an order dated March 7, 2006. In that order the PUCO also limited the litigation to service-related claims by customers of the Ohio operating companies; dismissed FirstEnergy as a defendant; and ruled that the U.S.-Canada Power System Outage Task Force Report was not admissible into evidence. In response to a motion for rehearing filed by one of the claimants, the PUCO ruled on April 26, 2006 that the insurance company claimants, as insurers, may prosecute their claims in their name so long as they also identify the underlying insured entities and the Ohio utilities that provide their service. The PUCO denied all other motions for rehearing. The plaintiffs in each case have since filed amended complaints and the named FirstEnergy companies have answered and also have filed a motion to dismiss each action. On September 27, 2006, the PUCO dismissed certain parties and claims and otherwise ordered the complaints to go forward to hearing. The cases have been set for hearing on January 8, 2008.
On October 10, 2006, various insurance carriers refiled a complaint in Cuyahoga County Common Pleas Court seeking reimbursement for claims paid to numerous insureds who allegedly suffered losses as a result of the August 14, 2003 outages. All of the insureds appear to be non-customers. The plaintiff insurance companies are the same claimants in one of the pending PUCO cases. FirstEnergy, the Ohio Companies and Penn were served on October 27, 2006. On January 18, 2007, the Court granted the Companies’ motion to dismiss the case and they have not been appealed. However, on April 25, 2007, one of the insurance carriers refiled the complaint naming only FirstEnergy as the defendant. On July 30, 2007, the case was voluntarily dismissed. No estimate of potential liability is available for any of these cases.
FirstEnergy was also named, along with several other entities, in a complaint in New Jersey State Court. The allegations against FirstEnergy were based, in part, on an alleged failure to protect the citizens of Jersey City from an electrical power outage. None of FirstEnergy’s subsidiaries serve customers in Jersey City. A responsive pleading has been filed. On April 28, 2006, the Court granted FirstEnergy's motion to dismiss. The plaintiff has not appealed.
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. Although FirstEnergy is unable to predict the impact of these proceedings, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.
Nuclear Plant Matters
On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the preceding two years and the licensee's failure to take prompt and corrective action. On April 4, 2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Nuclear Power Plant operated "in a manner that preserved public health and safety" even though it remained under heightened NRC oversight. During the public meeting and in the annual assessment, the NRC indicated that additional inspections would continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix.
On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance at the Perry Nuclear Power Plant 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. By two letters dated March 2, 2007, the NRC closed the CAL commitments for Perry, the two outstanding white findings, and crosscutting issues. Moreover, the NRC removed Perry from the Multiple Degraded Cornerstone Column of the NRC Action Matrix and placed the plant in the Licensee Response Column (regular agency oversight).
On April 30, 2007, the UCS filed a petition with the NRC under Section 2.206 of the NRC’s regulations based on a report prepared at FENOC’s request by expert witnesses for an insurance arbitration. In December 2006, the expert witnesses for FENOC completed a report that analyzed the crack growth rates in control rod drive mechanism penetrations and wastage of the former reactor pressure vessel head at Davis-Besse. Citing the findings in the expert witness' report, the Section 2.206 petition requested that: (1) Davis-Besse be immediately shut down; (2) that the NRC conduct an independent review of the consultant's report and that all pressurized water reactors be shut down until remedial actions can be implemented; and (3) Davis-Besse’s operating license be revoked.
In a letter dated May 18, 2007, the NRC stated that the “current reactor pressure vessel (RPV) head inspection requirements are adequate to detect RPV degradation issues before they result in significant corrosion.” The NRC also indicated that, “no immediate safety concern exists at Davis-Besse” and denied UCS’ first demand (to shut down the facility). On June 18, 2007, the NRC Petition Review Board indicated that the agency had initially denied petitioner’s other requests, and provided an opportunity for UCS to provide additional information prior to the final determination. By letter dated July 12, 2007, the NRC denied the remainder of the UCS petition.
On May 14, 2007, the Office of Enforcement of the NRC issued a Demand for Information to FENOC following FENOC’s reply to an April 2, 2007 NRC request for information about the expert witnesses’ report and another report. The NRC indicated that this information is needed for the NRC “to determine whether an Order or other action should be taken pursuant to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to operate its licensed facilities in accordance with the terms of its licenses and the Commission’s regulations.” FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s Demand for Information reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. The NRC held a public meeting on June 27, 2007 with FENOC to discuss FENOC’s response to the Demand for Information. In follow-up discussions, FENOC was requested to provide supplemental information to clarify certain aspects of the Demand for Information response and provide additional details regarding plans to implement the commitments made therein. FENOC submitted this supplemental response to the NRC on July 16, 2007. FirstEnergy can provide no assurances as to the ultimate resolution of this matter.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.
On 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 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. On April 5, 2007, the Court rejected the plaintiffs’ request to certify this case as a class action and, accordingly, did not appoint the plaintiffs as class representatives or their counsel as class counsel. On July 30, 2007, plaintiffs’ counsel voluntarily withdrew their request for reconsideration of the April 5, 2007 Court order denying class certification and the Court heard oral argument on the plaintiff’s motion to amend their complaint which OE has opposed.
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 arbitration panel decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, a federal district court granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005. JCP&L intends to re-file an appeal again in federal district court once the damages associated with this case are identified at an individual employee level. JCP&L recognized a liability for the potential $16 million award in 2005. The parties met on June 27, 2007 before an arbitrator to assert their positions regarding the finality of damages. A hearing before the arbitrator is set for September 7, 2007.
The union employees at the W. H. Sammis Plant have been working without a labor contract since July 1, 2007. The union expects to vote on a new contract on August 9, 2007. While it is expected the union will ratify a new contract, FirstEnergy has a strike mitigation plan ready in the event of a strike.
If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.
10. REGULATORY MATTERS
(A) 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 equipment or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability entities may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future, which could require additional, material expenditures.
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. In 2004, the NJBPU adopted an MOU that set out specific tasks related to service reliability to be performed by JCP&L and a timetable for completion and endorsed JCP&L’s ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a stipulation that incorporates the final report of an SRM who made recommendations on appropriate courses of action necessary to ensure system-wide reliability. The stipulation also incorporates the Executive Summary and Recommendation portions of the final report of a focused audit of JCP&L’s Planning and Operations and Maintenance programs and practices. On February 11, 2005, JCP&L met with the DRA to discuss reliability improvements. The SRM completed his work and issued his final report to the NJBPU on June 1, 2006. JCP&L filed a comprehensive response to the NJBPU on July 14, 2006. JCP&L continues to file compliance reports reflecting activities associated with the MOU and stipulation.
The EPACT served partly to amend the Federal Power Act with Section 215, which requires that an ERO establish and enforce reliability standards for the bulk-power system, subject to review of the FERC. Subsequently, the FERC certified NERC as the ERO, approved NERC's Compliance Monitoring and Enforcement Program and approved a set of reliability standards, which became mandatory and enforceable on June 18, 2007 with penalties and sanctions for noncompliance. The FERC also approved a delegation agreement between NERC and ReliabilityFirst Corporation, one of eight Regional Entities that carry out enforcement for NERC. All of FirstEnergy’s facilities are located within the ReliabilityFirst region.
While the FERC approved 83 of the 107 reliability standards proposed by NERC, the FERC has directed NERC to submit improvements to 56 of them, endorsing NERC's process for developing reliability standards and its associated work plan. On May 4, 2007, NERC also submitted 24 proposed Violation Risk Factors. The FERC issued an order approving 22 of those factors on June 26, 2007. Further, NERC adopted eight cyber security standards that became effective on June 1, 2006 and filed them with the FERC for approval. On December 11, 2006, the FERC Staff provided its preliminary assessment of the cyber security standards and cited various deficiencies in the proposed standards. Numerous parties, including FirstEnergy, provided comments on the assessment by February 12, 2007. The standards remain pending before the FERC. On July 20, 2007, the FERC issued a NOPR proposing to adopt eight Critical Infrastructure Protection Reliability Standards. Comments will not be due to the FERC until September or October of 2007.
FirstEnergy believes it is in compliance with all current NERC reliability standards. However, based upon a review of the FERC's guidance to NERC in its March 16, 2007 Final Rule on Mandatory Reliability Standards, it appears that the FERC will eventually adopt stricter NERC reliability standards than those just approved. The financial impact of complying with the new standards cannot be determined at this time. However, the EPACT required that all prudent costs incurred to comply with the new reliability standards be recovered in rates. If FirstEnergy is unable to meet the reliability standards for its bulk power system in the future, it could have a material adverse effect on FirstEnergy’s and its subsidiaries’ financial condition, results of operations and cash flows.
On April 18-20, 2007, ReliabilityFirst performed a routine compliance audit of FirstEnergy's bulk-power system within the Midwest ISO region and found FirstEnergy to be in full compliance with all audited reliability standards. Similarly, ReliabilityFirst has scheduled a compliance audit of FirstEnergy's bulk-power system within the PJM region in 2008. FirstEnergy does not expect any material adverse impact to its financial condition as a result of these audits.
(B) OHIO
On October 21, 2003, the Ohio Companies filed their RSP case with the PUCO. 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 CBP. The RSP was intended to establish generation service rates beginning January 1, 2006, in response to the PUCO’s concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming the PUCO's order in all respects, except it remanded back to the PUCO the matter of ensuring the availability of sufficient means for customer participation in the marketplace. The RSP contained a provision that permitted the Ohio Companies to withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies have 30 days from the final order or decision to provide notice of termination. On July 20, 2006, the Ohio Companies filed with the PUCO a Request to Initiate a Proceeding on Remand. In their Request, the Ohio Companies provided notice of termination to those provisions of the RSP subject to termination, subject to being withdrawn, and also set forth a framework for addressing the Supreme Court of Ohio’s findings on customer participation. If the PUCO approves a resolution to the issues raised by the Supreme Court of Ohio that is acceptable to the Ohio Companies, the Ohio Companies’ termination will be withdrawn and considered to be null and void. On July 20, 2006, the OCC and NOAC also submitted to the PUCO a conceptual proposal addressing the issue raised by the Supreme Court of Ohio. On July 26, 2006, the PUCO issued an Entry directing the Ohio Companies to file a plan in a new docket to address the Court’s concern. The Ohio Companies filed their RSP Remand CBP on September 29, 2006. Initial comments were filed on January 12, 2007 and reply comments were filed on January 29, 2007. In their reply comments the Ohio Companies described the highlights of a new tariff offering they would be willing to make available to customers that would allow customers to purchase renewable energy certificates associated with a renewable generation source, subject to PUCO approval. On May 29, 2007, the Ohio Companies, together with the PUCO Staff and the OCC, filed a stipulation with the PUCO agreeing to offer a standard bid product and a green resource tariff product. The stipulation is currently pending before the PUCO. No further proceedings are scheduled at this time.
On August 31, 2005, the PUCO approved a rider recovery mechanism through which the Ohio Companies may recover all MISO transmission and ancillary service related costs incurred during each year ending June 30. Pursuant to the PUCO’s order, the Ohio Companies, on May 1, 2007, filed revised riders, which became effective on July 1, 2007. The revised riders represent an increase over the amounts collected through the 2006 riders of approximately $64 million annually. If it is subsequently determined by the PUCO that adjustments to the rider as filed are necessary, such adjustments, with carrying costs, will be incorporated into the 2008 transmission rider filing.
On May 8, 2007, the Ohio Companies filed with the PUCO a notice of intent to file for an increase in electric distribution rates. The Ohio Companies filed the application and rate request with the PUCO on June 7, 2007. The requested increase is expected to be more than offset by the elimination or reduction of transition charges at the time the rates go into effect and would result in lowering the overall non-generation portion of the bill for most Ohio customers. The distribution rate increases reflect capital expenditures since the Ohio Companies’ last distribution rate proceedings, increases in operating and maintenance expenses and recovery of regulatory assets created by deferrals that were approved in prior cases. On August 6, 2007, the Ohio Companies provided an update filing supporting a distribution rate increase of $332 million to the PUCO to establish the test period data that will be used as the basis for setting rates in that proceeding. The PUCO Staff is expected to issue its report in the case in the fourth quarter of 2007 with evidentiary hearings to follow in late 2007. The PUCO order is expected to be issued by March 9, 2008. The new rates, subject to evidentiary hearings and approval at the PUCO, would become effective January 1, 2009 for OE and TE, and approximately May 2009 for CEI.
On July 10, 2007, the Ohio Companies filed an application with the PUCO requesting approval of a comprehensive supply plan for providing generation service to customers who do not purchase electricity from an alternative supplier, beginning January 1, 2009. The proposed competitive bidding process would average the results of multiple bidding sessions conducted at different times during the year. The final price per kilowatt-hour would reflect an average of the prices resulting from all bids. In their filing, the Ohio Companies offered two alternatives for structuring the bids, either by customer class or a “slice-of-system” approach. The proposal provides the PUCO with an option to phase in generation price increases for residential tariff groups who would experience a change in their average total price of 15 percent or more. The Ohio Companies requested that the PUCO issue an order by November 1, 2007, to provide sufficient time to conduct the bidding process. The PUCO has scheduled a technical conference for August 16, 2007.
(C) PENNSYLVANIA
Met-Ed and Penelec have been purchasing a portion of their PLR requirements from FES through a partial requirements wholesale power sales agreement and various amendments. Under these agreements, FES retained 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. The FES agreements have reduced Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR capacity and energy costs during the term of these agreements with FES.
On April 7, 2006, the parties entered into a tolling agreement that arose from FES’ notice to Met-Ed and Penelec that FES elected to exercise its right to terminate the partial requirements agreement effective midnight December 31, 2006. On November 29, 2006, Met-Ed, Penelec and FES agreed to suspend the April 7 tolling agreement pending resolution of the PPUC’s proceedings regarding the Met-Ed and Penelec comprehensive transition rate cases filed April 10, 2006, described below. Separately, on September 26, 2006, Met-Ed and Penelec successfully conducted a competitive RFP for a portion of their PLR obligation for the period December 1, 2006 through December 31, 2008. FES was one of the successful bidders in that RFP process and on September 26, 2006 entered into a supplier master agreement to supply a certain portion of Met-Ed’s and Penelec’s PLR requirements at market prices that substantially exceed the fixed price in the partial requirements agreements.
Based on the outcome of the 2006 comprehensive transition rate filing, as described below, Met-Ed, Penelec and FES agreed to restate the partial requirements power sales agreement effective January 1, 2007. The restated agreement incorporates the same fixed price for residual capacity and energy supplied by FES as in the prior arrangements between the parties, and automatically extends for successive one year terms unless any party gives 60 days’ notice prior to the end of the year. The restated agreement also allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy thus sold to the extent needed for Met-Ed and Penelec to satisfy their PLR obligations. The parties also have separately terminated the tolling, suspension and supplier master agreements in connection with the restatement of the partial requirements agreement. Accordingly, the energy that would have been supplied under the supplier master agreement will now be provided under the restated partial requirements agreement. The fixed price under the restated agreement is expected to remain below wholesale market prices during the term of the agreement.
If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for its fixed income securities. Based on the PPUC’s January 11, 2007 order described below, if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC.
Met-Ed and Penelec made a comprehensive transition rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals had been approved, annual revenues would have increased by $216 million and $157 million, respectively. That filing included, among other things, a request to charge customers for an increasing amount of market-priced power procured through a CBP as the amount of supply provided under the then existing FES agreement was to be phased out in accordance with the April 7, 2006 tolling agreement described above. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs, but only for those costs incurred during 2006. In this rate filing, Met-Ed and Penelec also requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the FirstEnergy and GPU merger proceeding, related to the quantification and allocation of the merger savings, with the comprehensive transmission rate filing case.
The PPUC entered its Opinion and Order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, when new transmission rates were effective, and determined that no merger savings from prior years should be considered in determining customers’ rates. The request for increases in generation supply rates was denied as were the requested changes in NUG expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased Met-Ed’s and Penelec’s distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission expenses and the transmission deferral. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and, in January 2007, Met-Ed and Penelec recognized income of $15 million and $12 million, respectively, to establish regulatory assets for those previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million). Met-Ed and Penelec filed a Petition for Reconsideration on January 26, 2007 on the issues of consolidated tax savings and rate of return on equity. Other parties filed Petitions for Reconsideration on transmission (including congestion), transmission deferrals and rate design issues. On February 8, 2007, the PPUC entered an order granting Met-Ed’s, Penelec’s and the other parties’ petitions for procedural purposes. Due to that ruling, the period for appeals to the Commonwealth Court of Pennsylvania was tolled until 30 days after the PPUC entered a subsequent order ruling on the substantive issues raised in the petitions. On March 1, 2007, the PPUC issued three orders: (1) a tentative order regarding the reconsideration by the PPUC of its own order; (2) an order denying the Petitions for Reconsideration of Met-Ed, Penelec and the OCA and denying in part and accepting in part the MEIUG’s and PICA’s Petition for Reconsideration; and (3) an order approving the Compliance filing. Comments to the PPUC for reconsideration of its order were filed on March 8, 2007, and the PPUC ruled on the reconsideration on April 13, 2007, making minor changes to rate design as agreed upon by Met-Ed, Penelec and certain other parties.
On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase. The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. On June 19, 2007, initial briefs were filed by all parties. Responsive briefs are due August 20, 2007, with reply briefs due September 4, 2007. Oral arguments are expected to take place in late 2007 or early 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the financial condition and results of operations of Met-Ed, Penelec and FirstEnergy.
As of June 30, 2007, Met-Ed's and Penelec's unrecovered regulatory deferrals pursuant to the 2006 comprehensive transition rate case, the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation were $493 million and $127 million, respectively. $82 million of Penelec’s deferral is subject to final resolution of an IRS settlement associated with NUG trust fund proceeds. During the PPUC’s annual audit of Met-Ed’s and Penelec’s NUG stranded cost balances in 2006, it noted a modification to the NUG purchased power stranded cost accounting methodology made by Met-Ed and Penelec. On August 18, 2006, a PPUC Order was entered requiring Met-Ed and Penelec to reflect the deferred NUG cost balances as if the stranded cost accounting methodology modification had not been implemented. As a result of this PPUC order, Met-Ed recognized a pre-tax charge of approximately $10.3 million in the third quarter of 2006, representing incremental costs deferred under the revised methodology in 2005. Met-Ed and Penelec continue to believe that the stranded cost accounting methodology modification is appropriate and on August 24, 2006 filed a petition with the PPUC pursuant to its order for authorization to reflect the stranded cost accounting methodology modification effective January 1, 1999. Hearings on this petition were held in late February 2007 and briefing was completed on March 28, 2007. The ALJ’s initial decision was issued on May 3, 2007 and denied Met-Ed's and Penelec’s request to modify their NUG stranded cost accounting methodology. The companies filed exceptions to the initial decision on May 23, 2007 and replies to those exceptions were filed on June 4, 2007. It is not known when the PPUC may issue a final decision in this matter.
On May 2, 2007, Penn filed a plan with the PPUC for the procurement of PLR supply from June 2008 through May 2011. The filing proposes multiple, competitive RFPs with staggered delivery periods for fixed-price, tranche-based, pay as bid PLR supply to the residential and commercial classes. The proposal phases out existing promotional rates and eliminates the declining block and the demand components on generation rates for residential and commercial customers. The industrial class PLR service will be provided through an hourly-priced service provided by Penn. Quarterly reconciliation of the differences between the costs of supply and revenues from customers is also proposed. The PPUC is requested to act on the proposal no later than November 2007 for the initial RFP to take place in January 2008.
On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation programs to meet demand growth, a requirement that electric distribution companies acquire power that results in the “lowest reasonable rate on a long-term basis,” the utilization of micro-grids and an optional three year phase-in of rate increases. On July 17, 2007 the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy will be convened in mid-September 2007 to consider other aspects of the EIS. The final form of any legislation arising from the special legislative session is uncertain. Consequently, FirstEnergy is unable to predict what impact, if any, such legislation may have on its operations.
(D) 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 NUGC rates and market sales of NUG energy and capacity. As of June 30, 2007, the accumulated deferred cost balance totaled approximately $392 million.
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 DRA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. A schedule for further NJBPU proceedings has not yet been set.
On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that would prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. These regulations are not expected to materially impact FirstEnergy or JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. Comments on the alternative proposal were submitted on June 15, 2006. On November 3, 2006, the Staff circulated a revised draft proposal to interested stakeholders. Another revised draft was circulated by the NJBPU Staff on February 8, 2007.
New Jersey statutes require that the state periodically undertake a planning process, known as the Energy Master Plan (EMP), to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated with the issuance of a proposed set of objectives which, as to electricity, included the following:
·Reduce the total projected electricity demand by 20% by 2020;
·Meet 22.5% of New Jersey’s electricity needs with renewable energy resources by that date;
·Reduce air pollution related to energy use;
·Encourage and maintain economic growth and development;
· Achieve a 20% reduction in both Customer Average Interruption Duration Index and System Average Interruption Frequency Index by 2020;
· Unit prices for electricity should remain no more than +5% of the regional average price (region includes New York, New Jersey, Pennsylvania,
Delaware, Maryland and the District of Columbia); and
·Eliminate transmission congestion by 2020.
Comments on the objectives and participation in the development of the EMP have been solicited and a number of working groups have been formed to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. EMP working groups addressing (1) energy efficiency and demand response, (2) renewables, (3) reliability, and (4) pricing issues have completed their assigned tasks of data gathering and analysis and have provided reports to the EMP Committee. Public stakeholder meetings were held in the fall of 2006 and in early 2007, and further public meetings are expected later in 2007. A final draft of the EMP is expected to be presented to the Governor in late 2007. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation may have on its operations or those of JCP&L.
On February 13, 2007, the NJBPU Staff informally issued a draft proposal relating to changes to the regulations addressing electric distribution service reliability and quality standards. Meetings between the NJBPU Staff and interested stakeholders to discuss the proposal were held and additional, revised informal proposals were subsequently circulated by the Staff. On August 1, 2007, the NJBPU approved publication of a formal proposal in the New Jersey Register, which proposal will be subsequently considered by the NJBPU following a period for public comment. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such regulations may have on its operations or those of JCP&L.
(E) FERC MATTERS
On November 18, 2004, the FERC issued an order eliminating the RTOR for transmission service between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a SECA mechanism to recover lost RTOR revenues during a 16-month transition period from load serving entities. The FERC issued orders in 2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES participated in the FERC hearings held in May 2006 concerning the calculation and imposition of the SECA charges. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by the RTOs and transmission owners, ruling on various issues and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order could be issued by the FERC in the third quarter of 2007.
On January 31, 2005, certain PJM transmission owners made three filings with the FERC 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. Hearings were held and numerous parties appeared and litigated various issues; including American Electric Power Company, Inc., which filed in opposition proposing to create a "postage stamp" rate for high voltage transmission facilities across PJM. At the conclusion of the hearings, the ALJ issued an initial decision adopting the FERC Trial Staff’s position that the cost of all PJM transmission facilities should be recovered through a postage stamp rate.The ALJ recommended an April 1, 2006 effective date for this change in rate design. Numerous parties, including FirstEnergy, submitted briefs opposing the ALJ’s decision and recommendations. On April 19, 2007, the FERC issued an order rejecting the ALJ’s findings and recommendations in nearly every respect. The FERC found that the PJM transmission owners’ existing “license plate” rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be socialized throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. Nevertheless, the FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.
On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 Order. Subsequently, FirstEnergy and other parties filed pleadings opposing the requests for rehearing. The FERC’s Orders on PJM rate design, if sustained on rehearing and appeal, will prevent the allocation of the cost of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reduce future transmission costs shifting to the JCP&L, Met-Ed and Penelec zones.
On August 1, 2007, a number of filings were made with the FERC by transmission owning utilities in the MISO and PJM footprint that could affect the transmission rates paid by FirstEnergy’s operating companies and FES.
FirstEnergy joined in a filing made by the MISO transmission owners that would maintain the existing “license plate” rates for transmission service within MISO provided over existing transmission facilities. FirstEnergy also joined in a filing made by both the MISO and PJM transmission owners proposing to maintain existing transmission rates between MISO and PJM. If accepted by the FERC, these filings would not affect the rates charged to load-serving FirstEnergy affiliates for transmission service over existing transmission facilities. In a related filing, MISO and MISO transmission owners requested that the current MISO pricing for new transmission facilities that spreads 20% of the cost of new 345 kV transmission facilities across the entire MISO footprint be maintained. All of these filings were supported by the majority of transmission owners in either MISO or PJM.
The Midwest Stand-Alone Transmission Companies made a filing under Section 205 of the Federal Power Act requesting that 100% of the cost of new qualifying 345 kV transmission facilities be spread throughout the entire MISO footprint. If adopted by the FERC, this proposal would shift a greater portion of the cost of new 345 kV transmission facilities to the FirstEnergy footprint, and increase the transmission rates paid by load-serving FirstEnergy affiliates.
American Electric Power (AEP) filed a letter with the FERC Commissioners stating its intent to file a complaint under Section 206 of the Federal Power Act challenging the justness and reasonableness of the rate designs underlying the MISO and PJM transmission tariffs. AEP will propose the adoption of a regional rate design that is expected to reallocate the cost of both existing and new high voltage transmission facilities across the combined MISO and PJM footprint. Based upon the position advocated by AEP in a related proceeding, the AEP proposal is expected to result in a greater allocation of costs to FirstEnergy transmission zones in MISO and PJM. If approved by the FERC, AEP’s proposal would increase the transmission rates paid by load-serving FirstEnergy affiliates.
Any increase in rates charged for transmission service to FirstEnergy affiliates is dependent upon the outcome of these proceedings at FERC. All or some of these proceedings may be consolidated by the FERC and set for hearing. The outcome of these cases cannot be predicted. Any material adverse impact on FirstEnergy would depend upon the ability of the load-serving FirstEnergy affiliates to recover increased transmission costs in their retail rates. FirstEnergy believes that current retail rate mechanisms in place for PLR service for the Ohio Companies and for Met-Ed and Penelec would permit them to pass through increased transmission charges in their retail rates. Increased transmission charges in the JCP&L and Penn transmission zones would be the responsibility of competitive electric retail suppliers, including FES.
On February 15, 2007, MISO filed documents with the FERC to establish a market-based, competitive ancillary services market. MISO contends that the filing will integrate operating reserves into MISO’s existing day-ahead and real-time settlements process, incorporate opportunity costs into these markets, address scarcity pricing through the implementation of a demand curve methodology, foster demand response in the provision of operating reserves, and provide for various efficiencies and optimization with regard to generation dispatch. The filing also proposes amendments to existing documents to provide for the transfer of balancing functions from existing local balancing authorities to MISO. MISO will then carry out this reliability function as the NERC-certified balancing authority for the MISO region with implementation in the third or fourth quarter of 2008. FirstEnergy filed comments on March 23, 2007, supporting the ancillary service market in concept, but proposing certain changes in MISO’s proposal. MISO requested FERC action on its filing by June 2007 and the FERC issued its Order June 22, 2007. The FERC found MISO’s filing to be deficient in two key areas: (1) MISO has not submitted a market power analysis in support of its proposed Ancillary Services Market and (2) MISO has not submitted a readiness plan to ensure reliability during the transition from the current reserve and regulation system managed by the individual Balancing Authorities to a centralized Ancillary Services Market managed by MISO. MISO was ordered to remedy these deficiencies and the FERC provided more guidance on other issues brought up in filings by stakeholders to assist MISO to re-file a complete proposal. This Order should facilitate MISO’s timetable to incorporate final revisions to ensure a market start in Spring 2008. FirstEnergy will be participating in working groups and task forces to ensure the Spring 2008 implementation of the Ancillary Services Market.
On February 16, 2007, the FERC issued a final rule that revises its decade-old open access transmission regulations and policies. The FERC explained that the final rule is intended to strengthen non-discriminatory access to the transmission grid, facilitate FERC enforcement, and provide for a more open and coordinated transmission planning process. The final rule became effective on May 14, 2007. MISO, PJM and ATSI will be filing revised tariffs to comply with the FERC’s order. As a market participant in both MISO and PJM, FirstEnergy will conform its business practices to each respective revised tariff.
11. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
| SFAS 159 – “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115”
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In February 2007, the FASB issued SFAS 159, which provides companies with an option to report selected financial assets and liabilities at fair value. This Statement requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company’s choice to use fair value on its earnings. The Standard also requires companies to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. This guidance does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS 157and SFAS 107. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. FirstEnergy is currently evaluating the impact of this Statement on its financial statements.
SFAS 157 – “Fair Value Measurements”
In September 2006, the FASB issued SFAS 157 that establishes how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under GAAP. This Statement addresses the need for increased consistency and comparability in fair value measurements and for expanded disclosures about fair value measurements. The key changes to current practice are: (1) the definition of fair value which focuses on an exit price rather than entry price; (2) the methods used to measure fair value such as emphasis that fair value is a market-based measurement, not an entity-specific measurement, as well as the inclusion of an adjustment for risk, restrictions and credit standing; and (3) the expanded disclosures about fair value measurements. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. FirstEnergy is currently evaluating the impact of this Statement on its financial statements.
EITF 06-11 – “Accounting for Income Tax Benefits of Dividends or Share-based Payment Awards”
In June 2007, the FASB released EITF 06-11, which provides guidance on the appropriate accounting for income tax benefits related to dividends earned on nonvested share units that are charged to retained earnings under SFAS 123(R). The consensus requires that an entity recognize the realized tax benefit associated with the dividends on nonvested shares as an increase to additional paid-in capital (APIC). This amount should be included in the APIC pool, which is to be used when an entity’s estimate of forfeitures increases or actual forfeitures exceed its estimates, at which time the tax benefits in the APIC pool would be reclassified to the income statement. The consensus is effective for income tax benefits of dividends declared during fiscal years beginning after December 15, 2007. EITF 06-11 is not expected to have a material effect on FirstEnergy’s financial statements.
12. SEGMENT INFORMATION
Effective January 1, 2007, FirstEnergy has three reportable operating segments: competitive energy services, energy delivery services and Ohio transitional generation services. None of the aggregate “Other” segments individually meet the criteria to be considered a reportable segment. The competitive energy services segment primarily consists of unregulated generation and commodity operations, including competitive electric sales, and generation sales to affiliated electric utilities. The energy delivery services segment consists of regulated transmission and distribution operations, including transition cost recovery, and PLR generation service for FirstEnergy’s Pennsylvania and New Jersey electric utility subsidiaries. The Ohio transitional generation services segment represents PLR generation service by FirstEnergy’s Ohio electric utility subsidiaries. “Other” primarily consists of telecommunications services and other non-core assets. The assets and revenues for the other business operations are below the quantifiable threshold for operating segments for separate disclosure as “reportable operating segments.”
The energy delivery services segment designs, constructs, operates and maintains FirstEnergy's regulated transmission and distribution systems and is responsible for the regulated generation commodity operations of FirstEnergy’s Pennsylvania and New Jersey electric utility subsidiaries. Its revenues are primarily derived from the delivery of electricity, cost recovery of regulatory assets and PLR electric generation sales to non-shopping customers in its Pennsylvania and New Jersey franchise areas. Its results reflect the commodity costs of securing electric generation from FES under partial requirements purchased power agreements and non-affiliated power suppliers as well as the net PJM transmission expenses related to the delivery of that generation load.
The competitive energy services segment supplies electric power to its electric utility affiliates, provides competitive electric sales primarily in Ohio, Pennsylvania, Maryland and Michigan and owns and operates FirstEnergy’s generating facilities and purchases electricity to meet its sales obligations. The segment's net income is primarily derived from the affiliated company power sales and the non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO to deliver electricity to the segment’s customers. The segment’s internal revenues represent the affiliated company power sales.
The Ohio transitional generation services segment represents the regulated generation commodity operations of FirstEnergy’s Ohio electric utility subsidiaries. Its revenues are primarily derived from electric generation sales to non-shopping customers under the PLR obligations of the Ohio Companies. Its results reflect securing electric generation from the competitive energy services segment through full requirements PSA arrangements and the net MISO transmission revenues and expenses related to the delivery of that generation load.
Segment reporting in 2006 has been revised to conform to the current year business segment organization and operations. Changes in the current year operations reporting and revised 2006 segment reporting primarily reflect the transfer from FES to the regulated utilities of the responsibility for obtaining PLR generation for the utilities’ non-shopping customers. This reflects FirstEnergy’s alignment of its business units to accommodate its retail strategy and participation in competitive electricity marketplaces in Ohio, Pennsylvania and New Jersey. The differentiation of the regulated generation commodity operations between the two regulated business segments recognizes that generation sourcing for the Ohio Companies is currently in a transitional state through 2008 as compared to the segregated commodity sourcing of their Pennsylvania and New Jersey utility affiliates. The results of the energy delivery services and the Ohio transitional generation services segments now include their electric generation revenues and the corresponding generation commodity costs under affiliated and non-affiliated purchased power arrangements and related net retail PJM/MISO transmission expenses associated with serving electricity load in their respective franchise areas.
FSG completed the sale of its five remaining subsidiaries in 2006. Its assets and results for 2006 are combined in the “Other” segments in this report, as the remaining business does not meet the criteria of a reportable segment. Interest expense on holding company debt and corporate support services revenues and expenses are included in "Reconciling Items."
Segment Financial Information | | | | | | | | | | | | | | | | |
| | | | | | | | Ohio | | | | | | | | | | |
| | Energy | | | Competitive | | | Transitional | | | | | | | | | | |
| | Delivery | | | Energy | | | Generation | | | | | | Reconciling | | | | |
Three Months Ended | | Services | | | Services | | | Services | | | Other | | | Adjustments | | | Consolidated | |
| | (In millions) | |
June 30, 2007 | | | | | | | | | | | | | | | | | | |
External revenues | | $ | 2,095 | | | $ | 404 | | | $ | 625 | | | $ | 9 | | | $ | (24 | ) | | $ | 3,109 | |
Internal revenues | | | - | | | | 691 | | | | - | | | | - | | | | (691 | ) | | | - | |
Total revenues | | | 2,095 | | | | 1,095 | | | | 625 | | | | 9 | | | | (715 | ) | | | 3,109 | |
Depreciation and amortization | | | 249 | | | | 51 | | | | (49 | ) | | | 1 | | | | 5 | | | | 257 | |
Investment income | | | 62 | | | | 5 | | | | - | | | | - | | | | (37 | ) | | | 30 | |
Net interest charges | | | 116 | | | | 42 | | | | - | | | | 1 | | | | 39 | | | | 198 | |
Income taxes | | | 141 | | | | 96 | | | | 19 | | | | (3 | ) | | | (31 | ) | | | 222 | |
Net income | | | 207 | | | | 142 | | | | 30 | | | | 6 | | | | (47 | ) | | | 338 | |
Total assets | | | 23,602 | | | | 7,284 | | | | 260 | | | | 236 | | | | 651 | | | | 32,033 | |
Total goodwill | | | 5,873 | | | | 24 | | | | - | | | | 1 | | | | - | | | | 5,898 | |
Property additions | | | 245 | | | | 139 | | | | - | | | | 2 | | | | 15 | | | | 401 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
June 30, 2006 | | | | | | | | | | | | | | | | | | | | | | | | |
External revenues | | $ | 1,773 | | | $ | 384 | | | $ | 575 | | | $ | 39 | | | $ | (20 | ) | | $ | 2,751 | |
Internal revenues | | | 6 | | | | 623 | | | | - | | | | - | | | | (629 | ) | | | - | |
Total revenues | | | 1,779 | | | | 1,007 | | | | 575 | | | | 39 | | | | (649 | ) | | | 2,751 | |
Depreciation and amortization | | | 173 | | | | 48 | | | | (29 | ) | | | 1 | | | | 6 | | | | 199 | |
Investment income | | | 81 | | | | 2 | | | | - | | | | - | | | | (52 | ) | | | 31 | |
Net interest charges | | | 102 | | | | 47 | | | | - | | | | 2 | | | | 22 | | | | 173 | |
Income taxes | | | 155 | | | | 67 | | | | 22 | | | | 2 | | | | (30 | ) | | | 216 | |
Income from | | | | | | | | | | | | | | | | | | | | | | | | |
continuing operations | | | 233 | | | | 101 | | | | 31 | | | | (7 | ) | | | (46 | ) | | | 312 | |
Discontinued operations | | | - | | | | - | | | | - | | | | (8 | ) | | | - | | | | (8 | ) |
Net income | | | 233 | | | | 101 | | | | 31 | | | | (15 | ) | | | (46 | ) | | | 304 | |
Total assets | | | 24,399 | | | | 6,740 | | | | 231 | | | | 355 | | | | 853 | | | | 32,578 | |
Total goodwill | | | 5,916 | | | | 24 | | | | - | | | | - | | | | - | | | | 5,940 | |
Property additions | | | 177 | | | | 103 | | | | - | | | | - | | | | 12 | | | | 292 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Six Months Ended | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
June 30, 2007 | | | | | | | | | | | | | | | | | | | | | | | | |
External revenues | | $ | 4,135 | | | $ | 732 | | | $ | 1,245 | | | $ | 20 | | | $ | (50 | ) | | $ | 6,082 | |
Internal revenues | | | - | | | | 1,404 | | | | - | | | | - | | | | (1,404 | ) | | | - | |
Total revenues | | | 4,135 | | | | 2,136 | | | | 1,245 | | | | 20 | | | | (1,454 | ) | | | 6,082 | |
Depreciation and amortization | | | 469 | | | | 102 | | | | (64 | ) | | | 2 | | | | 11 | | | | 520 | |
Investment income | | | 132 | | | | 8 | | | | 1 | | | | - | | | | (78 | ) | | | 63 | |
Net interest charges | | | 223 | | | | 92 | | | | 1 | | | | 2 | | | | 60 | | | | 378 | |
Income taxes | | | 289 | | | | 160 | | | | 35 | | | | 2 | | | | (64 | ) | | | 422 | |
Net income | | | 425 | | | | 240 | | | | 53 | | | | 7 | | | | (97 | ) | | | 628 | |
Total assets | | | 23,602 | | | | 7,284 | | | | 260 | | | | 236 | | | | 651 | | | | 32,033 | |
Total goodwill | | | 5,873 | | | | 24 | | | | - | | | | 1 | | | | - | | | | 5,898 | |
Property additions | | | 400 | | | | 263 | | | | - | | | | 3 | | | | 31 | | | | 697 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
June 30, 2006 | | | | | | | | | | | | | | | | | | | | | | | | |
External revenues | | $ | 3,570 | | | $ | 738 | | | $ | 1,118 | | | $ | 68 | | | $ | (38 | ) | | $ | 5,456 | |
Internal revenues | | | 14 | | | | 1,235 | | | | - | | | | - | | | | (1,249 | ) | | | - | |
Total revenues | | | 3,584 | | | | 1,973 | | | | 1,118 | | | | 68 | | | | (1,287 | ) | | | 5,456 | |
Depreciation and amortization | | | 430 | | | | 94 | | | | (49 | ) | | | 2 | | | | 11 | | | | 488 | |
Investment income | | | 164 | | | | 17 | | | | - | | | | 1 | | | | (108 | ) | | | 74 | |
Net interest charges | | | 201 | | | | 90 | | | | 1 | | | | 3 | | | | 38 | | | | 333 | |
Income taxes | | | 281 | | | | 89 | | | | 40 | | | | (3 | ) | | | (55 | ) | | | 352 | |
Income from | | | | | | | | | | | | | | | | | | | | | | | | |
continuing operations | | | 422 | | | | 133 | | | | 61 | | | | 5 | | | | (90 | ) | | | 531 | |
Discontinued operations | | | - | | | | - | | | | - | | | | (6 | ) | | | - | | | | (6 | ) |
Net income | | | 422 | | | | 133 | | | | 61 | | | | (1 | ) | | | (90 | ) | | | 525 | |
Total assets | | | 24,399 | | | | 6,740 | | | | 231 | | | | 355 | | | | 853 | | | | 32,578 | |
Total goodwill | | | 5,916 | | | | 24 | | | | - | | | | - | | | | - | | | | 5,940 | |
Property additions | | | 370 | | | | 347 | | | | - | | | | - | | | | 22 | | | | 739 | |
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 and elimination of intersegment transactions.
FIRSTENERGY CORP. | |
| | | | | | | | | | | | |
CONSOLIDATED STATEMENTS OF INCOME | |
(Unaudited) | |
| | | | | | | | | | | | |
| | Three Months Ended | | | Six Months Ended | |
| | June 30, | | | June 30, | |
| | 2007 | | | 2006 | | | 2007 | | | 2006 | |
| | (In millions, except per share amounts) | |
REVENUES: | | | | | | | | | | | | |
Electric utilities | | $ | 2,744 | | | $ | 2,341 | | | $ | 5,425 | | | $ | 4,681 | |
Unregulated businesses | | | 365 | | | | 410 | | | | 657 | | | | 775 | |
Total revenues * | | | 3,109 | | | | 2,751 | | | | 6,082 | | | | 5,456 | |
| | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | |
Fuel and purchased power | | | 1,185 | | | | 991 | | | | 2,306 | | | | 1,989 | |
Other operating expenses | | | 750 | | | | 718 | | | | 1,499 | | | | 1,471 | |
Provision for depreciation | | | 159 | | | | 144 | | | | 315 | | | | 292 | |
Amortization of regulatory assets | | | 246 | | | | 201 | | | | 497 | | | | 422 | |
Deferral of new regulatory assets | | | (148 | ) | | | (146 | ) | | | (292 | ) | | | (226 | ) |
General taxes | | | 189 | | | | 173 | | | | 392 | | | | 366 | |
Total expenses | | | 2,381 | | | | 2,081 | | | | 4,717 | | | | 4,314 | |
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 728 | | | | 670 | | | | 1,365 | | | | 1,142 | |
| | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | |
Investment income | | | 30 | | | | 31 | | | | 63 | | | | 74 | |
Interest expense | | | (205 | ) | | | (178 | ) | | | (390 | ) | | | (343 | ) |
Capitalized interest | | | 7 | | | | 7 | | | | 12 | | | | 14 | |
Subsidiaries’ preferred stock dividends | | | - | | | | (2 | ) | | | - | | | | (4 | ) |
Total other expense | | | (168 | ) | | | (142 | ) | | | (315 | ) | | | (259 | ) |
| | | | | | | | | | | | | | | | |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | | | 560 | | | | 528 | | | | 1,050 | | | | 883 | |
| | | | | | | | | | | | | | | | |
INCOME TAXES | | | 222 | | | | 216 | | | | 422 | | | | 352 | |
| | | | | | | | | | | | | | | | |
INCOME FROM CONTINUING OPERATIONS | | | 338 | | | | 312 | | | | 628 | | | | 531 | |
| | | | | | | | | | | | | | | | |
Discontinued operations (net of income tax expense (benefits) of | | | | | | | | | | | | | |
$1 million and ($1) million in the three months and | | | | | | | | | | | | | | | | |
six months ended June 30, 2006, respectively) (Note 3) | | | - | | | | (8 | ) | | | - | | | | (6 | ) |
| | | | | | | | | | | | | | | | |
NET INCOME | | $ | 338 | | | $ | 304 | | | $ | 628 | | | $ | 525 | |
| | | | | | | | | | | | | | | | |
BASIC EARNINGS PER SHARE OF COMMON STOCK: | | | | | | | | | | | | | | | | |
Income from continuing operations | | $ | 1.11 | | | $ | 0.94 | | | $ | 2.03 | | | $ | 1.61 | |
Discontinued operations | | | - | | | | (0.02 | ) | | | - | | | | (0.02 | ) |
Net earnings per basic share | | $ | 1.11 | | | $ | 0.92 | | | $ | 2.03 | | | $ | 1.59 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING | | | 304 | | | | 328 | | | | 309 | | | | 328 | |
| | | | | | | | | | | | | | | | |
DILUTED EARNINGS PER SHARE OF COMMON STOCK: | | | | | | | | | | | | | | | | |
Income from continuing operations | | $ | 1.10 | | | $ | 0.93 | | | $ | 2.01 | | | $ | 1.60 | |
Discontinued operations | | | - | | | | (0.02 | ) | | | - | | | | (0.02 | ) |
Net earnings per diluted share | | $ | 1.10 | | | $ | 0.91 | | | $ | 2.01 | | | $ | 1.58 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING | | | 308 | | | | 330 | | | | 313 | | | | 330 | |
| | | | | | | | | | | | | | | | |
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK | | $ | 0.50 | | | $ | 0.45 | | | $ | 1.00 | | | $ | 0.90 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
* Includes excise tax collections of $102 million and $90 million in the second quarter of 2007 and 2006, respectively, and $206 million |
and $189 million in the six months ended June 2007 and 2006, respectively. | | | | | | | | | |
| | | | | | | | | | | | | | | | |
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 COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | | | | | | | |
| | Three Months Ended | | | Six Months Ended | |
| | June 30, | | | June 30, | |
| | 2007 | | | 2006 | | | 2007 | | | 2006 | |
| | (In millions) | |
| | | | | | | | | | | | |
NET INCOME | | $ | 338 | | | $ | 304 | | | $ | 628 | | | $ | 525 | |
| | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | |
Pension and other postretirement benefits | | | (11 | ) | | | - | | | | (22 | ) | | | - | |
Unrealized gain (loss) on derivative hedges | | | (1 | ) | | | 36 | | | | 20 | | | | 73 | |
Change in unrealized gain on available for sale securities | | | 46 | | | | (24 | ) | | | 63 | | | | 13 | |
Other comprehensive income | | | 34 | | | | 12 | | | | 61 | | | | 86 | |
Income tax expense related to other | | | | | | | | | | | | | | | | |
comprehensive income | | | 10 | | | | 4 | | | | 19 | | | | 31 | |
Other comprehensive income, net of tax | | | 24 | | | | 8 | | | | 42 | | | | 55 | |
| | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | $ | 362 | | | $ | 312 | | | $ | 670 | | | $ | 580 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
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) | |
| | June 30, | | | December 31, | |
| | 2007 | | | 2006 | |
| | (In millions) | |
ASSETS | | | | | | |
| | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 37 | | | $ | 90 | |
Receivables- | | | | | | | | |
Customers (less accumulated provisions of $39 million and | | | | | | | | |
$43 million, respectively, for uncollectible accounts) | | | 1,413 | | | | 1,135 | |
Other (less accumulated provisions of $22 million and | | | | | | | | |
$24 million, respectively, for uncollectible accounts) | | | 181 | | | | 132 | |
Materials and supplies, at average cost | | | 583 | | | | 577 | |
Prepayments and other | | | 322 | | | | 149 | |
| | | 2,536 | | | | 2,083 | |
PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | |
In service | | | 24,555 | | | | 24,105 | |
Less - Accumulated provision for depreciation | | | 10,330 | | | | 10,055 | |
| | | 14,225 | | | | 14,050 | |
Construction work in progress | | | 785 | | | | 617 | |
| | | 15,010 | | | | 14,667 | |
INVESTMENTS: | | | | | | | | |
Nuclear plant decommissioning trusts | | | 2,092 | | | | 1,977 | |
Investments in lease obligation bonds | | | 738 | | | | 811 | |
Other | | | 734 | | | | 746 | |
| | | 3,564 | | | | 3,534 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Goodwill | | | 5,898 | | | | 5,898 | |
Regulatory assets | | | 4,155 | | | | 4,441 | |
Pension assets | | | 297 | | | | - | |
Other | | | 573 | | | | 573 | |
| | | 10,923 | | | | 10,912 | |
| | $ | 32,033 | | | $ | 31,196 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
| | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Currently payable long-term debt | | $ | 2,000 | | | $ | 1,867 | |
Short-term borrowings | | | 2,416 | | | | 1,108 | |
Accounts payable | | | 801 | | | | 726 | |
Accrued taxes | | | 320 | | | | 598 | |
Other | | | 745 | | | | 956 | |
| | | 6,282 | | | | 5,255 | |
CAPITALIZATION: | | | | | | | | |
Common stockholders’ equity- | | | | | | | | |
Common stock, $.10 par value, authorized 375,000,000 shares- | | | | | | | | |
304,835,407 and 319,205,517 shares outstanding, respectively | | | 30 | | | | 32 | |
Other paid-in capital | | | 5,550 | | | | 6,466 | |
Accumulated other comprehensive loss | | | (217 | ) | | | (259 | ) |
Retained earnings | | | 3,279 | | | | 2,806 | |
Unallocated employee stock ownership plan common stock- | | | | | | | | |
134,681 and 521,818 shares, respectively | | | (2 | ) | | | (10 | ) |
Total common stockholders' equity | | | 8,640 | | | | 9,035 | |
Long-term debt and other long-term obligations | | | 8,742 | | | | 8,535 | |
| | | 17,382 | | | | 17,570 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Accumulated deferred income taxes | | | 2,849 | | | | 2,740 | |
Asset retirement obligations | | | 1,228 | | | | 1,190 | |
Power purchase contract loss liability | | | 877 | | | | 1,182 | |
Retirement benefits | | | 917 | | | | 944 | |
Lease market valuation liability | | | 704 | | | | 767 | |
Other | | | 1,794 | | | | 1,548 | |
| | | 8,369 | | | | 8,371 | |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9) | | | | | | | | |
| | $ | 32,033 | | | $ | 31,196 | |
| | | | | | | | |
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) | |
| | | | | | |
| | Six Months Ended | |
| | June 30, | |
| | 2007 | | | 2006 | |
| | (In millions) | |
| | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 628 | | | $ | 525 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
Provision for depreciation | | | 315 | | | | 292 | |
Amortization of regulatory assets | | | 497 | | | | 421 | |
Deferral of new regulatory assets | | | (292 | ) | | | (226 | ) |
Nuclear fuel and lease amortization | | | 50 | | | | 42 | |
Deferred purchased power and other costs | | | (185 | ) | | | (239 | ) |
Deferred income taxes and investment tax credits, net | | | 85 | | | | 32 | |
Investment impairment | | | 12 | | | | 12 | |
Deferred rents and lease market valuation liability | | | (92 | ) | | | (105 | ) |
Accrued compensation and retirement benefits | | | (69 | ) | | | 33 | |
Commodity derivative transactions, net | | | 4 | | | | 25 | |
Gain on asset sales | | | (12 | ) | | | (4 | ) |
Income from discontinued operations | | | - | | | | 6 | |
Cash collateral | | | (19 | ) | | | (55 | ) |
Pension trust contribution | | | (300 | ) | | | - | |
Decrease (increase) in operating assets- | | | | | | | | |
Receivables | | | (282 | ) | | | 83 | |
Materials and supplies | | | 22 | | | | (71 | ) |
Prepayments and other current assets | | | (157 | ) | | | (159 | ) |
Increase (decrease) in operating liabilities- | | | | | | | | |
Accounts payable | | | 28 | | | | (40 | ) |
Accrued taxes | | | (17 | ) | | | (45 | ) |
Electric service prepayment programs | | | (36 | ) | | | (29 | ) |
Other | | | (49 | ) | | | (13 | ) |
Net cash provided from operating activities | | | 131 | | | | 485 | |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Long-term debt | | | 800 | | | | 1,053 | |
Short-term borrowings, net | | | 1,308 | | | | 371 | |
Redemptions and Repayments- | | | | | | | | |
Common stock | | | (918 | ) | | | - | |
Preferred stock | | | - | | | | (30 | ) |
Long-term debt | | | (471 | ) | | | (485 | ) |
Net controlled disbursement activity | | | 32 | | | | 5 | |
Stock-based compensation tax benefit | | | 14 | | | | - | |
Common stock dividend payments | | | (311 | ) | | | (296 | ) |
Net cash provided from financing activities | | | 454 | | | | 618 | |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (697 | ) | | | (739 | ) |
Proceeds from asset sales | | | 12 | | | | 63 | |
Sales of investment securities held in trusts | | | 583 | | | | 959 | |
Purchases of investment securities held in trusts | | | (591 | ) | | | (966 | ) |
Cash investments | | | 54 | | | | 118 | |
Other | | | 1 | | | | (19 | ) |
Net cash used for investing activities | | | (638 | ) | | | (584 | ) |
| | | | | | | | |
Net increase (decrease) in cash and cash equivalents | | | (53 | ) | | | 519 | |
Cash and cash equivalents at beginning of period | | | 90 | | | | 64 | |
Cash and cash equivalents at end of period | | $ | 37 | | | $ | 583 | |
| | | | | | | | |
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 June 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2007 and 2006 and the consolidated statement of cash flows for the six-month periods ended June 30, 2007 and 2006. 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 (United States), 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, 2006, and the related consolidated statements of income, capitalization, common stockholders’ equity, preferred stock, and of cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006 and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 3, Note 2(K) and Note 12 to the consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
August 6, 2007
FIRSTENERGY CORP.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EXECUTIVE SUMMARY
Net income in the second quarter of 2007 was $338 million, or basic earnings of $1.11 per share of common stock ($1.10 diluted), compared with net income of $304 million, or basic earnings of $0.92 per share of common stock ($0.91 diluted) in the second quarter of 2006. Net income in the first six months of 2007 was $628 million, or basic earnings of $2.03 per share of common stock ($2.01 diluted), compared with net income of $525 million, or basic earnings of $1.59 per share of common stock ($1.58 diluted) in the first six months of 2006. The increases in FirstEnergy’s earnings in both periods of 2007 were driven primarily by higher electric sales revenues, partially offset by increased fuel and purchased power costs, higher other operating expenses and increased interest expense.
Change in Basic Earnings Per Share From Prior Year Periods | | Three Months Ended June 30, | | Six Months Ended June 30, | |
| | | | | | | |
Basic Earnings Per Share – 2006 | | $ | 0.92 | | $ | 1.59 | |
Revenues | | | 0.71 | | | 1.22 | |
Fuel and purchased power | | | (0.38 | ) | | (0.62 | ) |
Depreciation and amortization | | | (0.12 | ) | | (0.19 | ) |
Deferral of new regulatory assets | | | - | | | 0.08 | |
Other expenses | | | (0.03 | ) | | (0.10 | ) |
Non-core asset sales/impairments - 2006 | | | 0.03 | | | 0.03 | |
Saxton decommissioning regulatory asset -2007 | | | - | | | 0.05 | |
Trust securities impairment - 2007 | | | (0.02 | ) | | (0.03 | ) |
Basic Earnings Per Share – 2007 | | $ | 1.11 | | $ | 2.03 | |
Financial Matters
On July 13, 2007, FGCO completed a $1.3 billion sale and leaseback transaction for its 779 MW portion of the Bruce Mansfield Plant Unit 1. The terms of the agreement provide for an approximate 33-year lease of the unit. There will be no material gain from this transaction reflected in earnings during the third quarter of 2007. FirstEnergy used the net, after-tax proceeds of approximately $1.2 billion to repay short-term debt that was used to fund its recent $900 million share repurchase program and $300 million pension contribution. FGCO will continue to operate the plant.
On May 21, 2007, JCP&L issued $550 million of senior unsecured debt securities. The offering was in two tranches, consisting of $250 million of 5.65% Senior Notes due 2017 and $300 million of 6.15% Senior Notes due 2037. The proceeds from the transaction were used to redeem all of JCP&L’s outstanding first mortgage bonds, repay short-term debt and repurchase common stock from FirstEnergy.
Regulatory Matters
Ohio
On June 7, 2007, the Ohio Companies filed their base distribution rate increase request and supporting testimony with the PUCO. The requested increase (updated on August 6, 2007) in annualized distribution revenues of approximately $332 million is needed to recover expenses related to distribution operations and the costs deferred under previously approved rate plans. Concurrent with the effective dates of the proposed distribution rate increases, the Ohio Companies will reduce or eliminate their RTC, resulting in a net reduction of $262 million on the regulated portion of customers’ bills. The PUCO Staff is expected to issue its report in the case in the fourth quarter of 2007 with evidentiary hearings to follow in late 2007. The PUCO order is expected to be issued by March 9, 2008. The new rates would become effective January 1, 2009 for OE and TE, and approximately May 2009 for CEI.
On July 10, 2007, the Ohio Companies filed an application with the PUCO requesting approval of a comprehensive supply plan for providing generation service to customers who do not purchase electricity from an alternative supplier, beginning January 1, 2009. The proposed competitive bidding process would average the results of multiple bidding sessions conducted at different times during the year. The final price per kilowatt-hour included in rates would reflect an average of the prices resulting from all bids. In their filing, the Ohio Companies offered two alternatives for structuring the bids, either by customer class or a “slice-of-system” approach. The proposal also provides the PUCO with an option to phase in generation price increases for residential tariff groups who would experience a change in their average total price of 15 percent or more. The Ohio Companies requested that the PUCO issue an order by November 1, 2007, to provide sufficient time to conduct the bidding process.
Pennsylvania
On May 2, 2007, Penn made a filing with the PPUC proposing how it will procure the power supply needed for default service customers from June 1, 2008 through May 2011. Hearings are scheduled for September 10-11, 2007, with a recommended ALJ decision expected by October 25, 2007. A PPUC order is expected by November 29, 2007. The initial RFP is expected to take place in January 2008.
On May 3, 2007, an ALJ issued her initial decision denying Met-Ed’s and Penelec’s request to modify their NUG stranded cost accounting methodology. The companies filed exceptions to the initial decision on May 23, 2007 and replies to those exceptions were filed on June 4, 2007. It is not known when the PPUC may issue a final decision in this matter.
On June 19, 2007, initial briefs were filed with the Commonwealth Court of Pennsylvania by all parties in the appeal of Met-Ed’s and Penelec’s comprehensive rate filing. Responsive briefs are due August 20, 2007, with reply briefs due September 4, 2007. Met-Ed and Penelec appealed the PPUC’s decision on the denial of generation rate relief and consolidated tax savings, while other parties appealed the PPUC’s decision on transmission rate relief. Oral arguments are expected to take place in the fourth quarter of 2007.
Operations
Second Quarter KWH Sales Record - FirstEnergy set a new second quarter generation sales record in 2007 of 32.8 billion KWH, which represents a 2.9% increase over the second quarter of 2006. Distribution deliveries also increased in the second quarter to 26.9 billion KWH – a 4.4% increase from the second quarter of 2006. The higher KWH sales and distribution deliveries were primarily attributable to continued customer growth in FirstEnergy’s service territories and weather impacts during the quarter.
Generation Output Record - FirstEnergy set a new second quarter generation output record of 20.4 billion KWH in 2007, which represents a 0.4% increase over the prior record established last year. The generation record was primarily attributable to performance of the fossil generation fleet, which established its best quarterly output ever.
NRC Demand for Information - On May 14, 2007, the NRC issued a Demand for Information related to recent reports prepared for arbitration of an insurance claim for replacing the damaged reactor head at the Davis-Besse Plant in 2002. FENOC responded to the NRC on June 13, 2007. FirstEnergy officials participated in a public meeting with the NRC on June 27, 2007 to discuss circumstances leading up to the Demand for Information and FENOC’s response. In follow-up discussions, FENOC was requested to provide supplemental information to clarify certain aspects of the Demand for Information response and to provide supplemental details regarding plans to implement the commitments established therein. This supplemental information was submitted to the NRC on July 16, 2007.
Perry Plant Outage - FirstEnergy’s Perry Nuclear Power Plant completed its regularly scheduled refueling outage on May 13, 2007. Major work activities performed on the 1,258 MW facility included replacing approximately one-third of the fuel assemblies in the reactor and two of the three low-pressure turbine rotors in the main generator. On June 29, 2007, Perry began an unplanned outage to replace a 30-ton motor in the reactor recirculation system. In addition to the motor replacement, routine and preventive maintenance and several system inspections will be performed during the outage to assure continued safe and reliable operation of the plant. On July 25, 2007 the plant was returned to service.
Environmental Update - On May 30, 2007, FirstEnergy announced that FGCO plans to install an ECO system on Units 4 and 5 of its R.E. Burger Plant. Design engineering for the new Burger Plant ECO system will begin in 2007 with an anticipated start-up date in the first quarter of 2011. The incremental cost installing the system at the Burger Plant instead of Bay Shore Unit 4, as originally planned, is approximately $38 million.
FIRSTENERGY’S BUSINESS
FirstEnergy is a diversified energy company headquartered in Akron, Ohio, that operates primarily through three core business segments (see Results of Operations).
· | Energy Delivery Services transmits and distributes electricity through FirstEnergy's eight utility operating companies, serving 4.5 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey and purchases power for its PLR requirements in Pennsylvania and New Jersey. This business segment derives its revenues principally from the delivery of electricity within FirstEnergy’s service areas, cost recovery of regulatory assets and the sale of electric generation service to non-shopping retail customers under the PLR obligations in its Pennsylvania and New Jersey franchise areas. Its net income reflects the commodity costs of securing electricity from the Competitive Energy Services Segment under partial requirements purchased power agreements with FES and non-affiliated power suppliers, including associated transmission costs.
|
· | Competitive Energy Services supplies the electric power needs of end-use customers through retail and wholesale arrangements, including associated company power sales to meet all or a portion of the PLR requirements of FirstEnergy's Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Maryland and Michigan. This business segment owns or leases and operates FirstEnergy's generating facilities and also purchases electricity to meet sales obligations. The segment's net income is primarily derived from affiliated company power sales and non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission and ancillary costs charged by PJM and MISO to deliver energy to the segment’s customers.
|
· | Ohio Transitional Generation Services supplies the electric power needs of non-shopping customers under the PLR requirements of FirstEnergy's Ohio Companies. The segment's net income is primarily derived from electric generation sales revenues less the cost of power purchased from the competitive energy services segment through a full-requirements PSA arrangement with FES, including net transmission and ancillary costs charged by MISO to deliver energy to retail customers.
|
RESULTS OF OPERATIONS
The financial results discussed below include revenues and expenses from transactions among FirstEnergy's business segments. A reconciliation of segment financial results is provided in Note 12 to the consolidated financial statements. Net income by major business segment was as follows:
| | Three Months Ended June 30, | | Six Months Ended June 30, | |
| | | | Increase | | | | Increase | |
| | 2007 | | 2006 | | (Decrease) | | 2007 | | 2006 | | (Decrease) | |
| | (In millions, except per share amounts) | |
Net Income (Loss) | | | | | | | | | | | | | |
By Business Segment: | | | | | | | | | | | | | |
Energy delivery services | | | $ | 207 | | $ | 233 | | $ | (26 | ) | $ | 425 | | $ | 422 | | $ | 3 | |
Competitive energy services | | | | 142 | | | 101 | | | 41 | | | 240 | | | 133 | | | 107 | |
Ohio transitional generation services | | | | 30 | | | 31 | | | (1 | ) | | 53 | | | 61 | | | (8 | ) |
Other and reconciling adjustments* | | | | (41 | ) | | (61 | ) | | 20 | | | (90 | ) | | (91 | ) | | 1 | |
Total | | | $ | 338 | | $ | 304 | | $ | 34 | | $ | 628 | | $ | 525 | | $ | 103 | |
| | | | | | | | | | | | | | | | | | | | |
Basic Earnings Per Share: | | | | | | | | | | | | | | | | | | | | |
Income from continuing operations | | | $ | 1.11 | | $ | 0.94 | | $ | 0.17 | | $ | 2.03 | | $ | 1.61 | | $ | 0.42 | |
Discontinued operations | | | | - | | | (0.02 | ) | | 0.02 | | | - | | | (0.02 | ) | | 0.02 | |
Net earnings per basic share | | | $ | 1.11 | | $ | 0.92 | | $ | 0.19 | | $ | 2.03 | | $ | 1.59 | | $ | 0.44 | |
| | | | | | | | | | | | | | | | | | | | |
Diluted Earnings Per Share: | | | | | | | | | | | | | | | | | | | | |
Income from continuing operations | | | $ | 1.10 | | $ | 0.93 | | $ | 0.17 | | $ | 2.01 | | $ | 1.60 | | $ | 0.41 | |
Discontinued operations | | | | - | | | (0.02 | ) | | 0.02 | | | - | | | (0.02 | ) | | 0.02 | |
Net earnings per diluted share | | | $ | 1.10 | | $ | 0.91 | | $ | 0.19 | | $ | 2.01 | | $ | 1.58 | | $ | 0.43 | |
* Represents other operating segments and reconciling items including interest expense on holding company debt and corporate
support services revenues and expenses.
Summary of Results of Operations – Second Quarter of 2007 Compared with the Second Quarter of 2006
Financial results for FirstEnergy's major business segments in the second quarter of 2007 and 2006 were as follows:
| | | | | | | | Ohio | | | | | | | |
| | Energy | | | Competitive | | | Transitional | | | Other and | | | | |
| | Delivery | | | Energy | | | Generation | | | Reconciling | | | FirstEnergy | |
Second Quarter 2007 Financial Results | | Services | | | Services | | | Services | | | Adjustments | | | Consolidated | |
| | (In millions) | |
Revenues: | | | | | | | | | | | | | | | |
External | | | | | | | | | | | | | | | |
Electric | | $ | 1,933 | | | $ | 359 | | | $ | 612 | | | $ | - | | | $ | 2,904 | |
Other | | | 162 | | | | 45 | | | | 13 | | | | (15 | ) | | | 205 | |
Internal | | | - | | | | 691 | | | | - | | | | (691 | ) | | | - | |
Total Revenues | | | 2,095 | | | | 1,095 | | | | 625 | | | | (706 | ) | | | 3,109 | |
| | | | | | | | | | | | | | | | | | | | |
Expenses: | | | | | | | | | | | | | | | | | | | | |
Fuel and purchased power | | | 879 | | | | 460 | | | | 537 | | | | (691 | ) | | | 1,185 | |
Other operating expenses | | | 410 | | | | 283 | | | | 87 | | | | (30 | ) | | | 750 | |
Provision for depreciation | | | 100 | | | | 51 | | | | - | | | | 8 | | | | 159 | |
Amortization of regulatory assets | | | 242 | | | | - | | | | 6 | | | | (2 | ) | | | 246 | |
Deferral of new regulatory assets | | | (93 | ) | | | - | | | | (55 | ) | | | - | | | | (148 | ) |
General taxes | | | 155 | | | | 26 | | | | 1 | | | | 7 | | | | 189 | |
Total Expenses | | | 1,693 | | | | 820 | | | | 576 | | | | (708 | ) | | | 2,381 | |
| | | | | | | | | | | | | | | | | | | | |
Operating Income | | | 402 | | | | 275 | | | | 49 | | | | 2 | | | | 728 | |
Other Income (Expense): | | | | | | | | | | | | | | | | | | | | |
Investment income | | | 62 | | | | 5 | | | | - | | | | (37 | ) | | | 30 | |
Interest expense | | | (118 | ) | | | (47 | ) | | | - | | | | (40 | ) | | | (205 | ) |
Capitalized interest | | | 2 | | | | 5 | | | | - | | | | - | | | | 7 | |
Total Other Expense | | | (54 | ) | | | (37 | ) | | | - | | | | (77 | ) | | | (168 | ) |
| | | | | | | | | | | | | | | | | | | | |
Income From Continuing Operations Before | | | | | | | | | | | | | | | | | |
Income Taxes | | | 348 | | | | 238 | | | | 49 | | | | (75 | ) | | | 560 | |
Income taxes | | | 141 | | | | 96 | | | | 19 | | | | (34 | ) | | | 222 | |
Net Income | | $ | 207 | | | $ | 142 | | | $ | 30 | | | $ | (41 | ) | | $ | 338 | |
| | | | | | | | Ohio | | | | | | | |
| | Energy | | | Competitive | | | Transitional | | | Other and | | | | |
| | Delivery | | | Energy | | | Generation | | | Reconciling | | | FirstEnergy | |
Second Quarter 2006 Financial Results | | Services | | | Services | | | Services | | | Adjustments | | | Consolidated | |
| | (In millions) | |
Revenues: | | | | | | | | | | | | | | | |
External | | | | | | | | | | | | | | | |
Electric | | $ | 1,646 | | | $ | 338 | | | $ | 569 | | | $ | - | | | $ | 2,553 | |
Other | | | 127 | | | | 46 | | | | 6 | | | | 19 | | | | 198 | |
Internal | | | 6 | | | | 623 | | | | - | | | | (629 | ) | | | - | |
Total Revenues | | | 1,779 | | | | 1,007 | | | | 575 | | | | (610 | ) | | | 2,751 | |
| | | | | | | | | | | | | | | | | | | | |
Expenses: | | | | | | | | | | | | | | | | | | | | |
Fuel and purchased power | | | 690 | | | | 434 | | | | 496 | | | | (629 | ) | | | 991 | |
Other operating expenses | | | 363 | | | | 289 | | | | 53 | | | | 13 | | | | 718 | |
Provision for depreciation | | | 89 | | | | 48 | | | | - | | | | 7 | | | | 144 | |
Amortization of regulatory assets | | | 197 | | | | - | | | | 4 | | | | - | | | | 201 | |
Deferral of new regulatory assets | | | (113 | ) | | | - | | | | (33 | ) | | | - | | | | (146 | ) |
General taxes | | | 144 | | | | 23 | | | | 2 | | | | 4 | | | | 173 | |
Total Expenses | | | 1,370 | | | | 794 | | | | 522 | | | | (605 | ) | | | 2,081 | |
| | | | | | | | | | | | | | | | | | | | |
Operating Income | | | 409 | | | | 213 | | | | 53 | | | | (5 | ) | | | 670 | |
Other Income (Expense): | | | | | | | | | | | | | | | | | | | | |
Investment income | | | 81 | | | | 2 | | | | - | | | | (52 | ) | | | 31 | |
Interest expense | | | (101 | ) | | | (50 | ) | | | - | | | | (27 | ) | | | (178 | ) |
Capitalized interest | | | 4 | | | | 3 | | | | - | | | | - | | | | 7 | |
Subsidiaries' preferred stock dividends | | | (5 | ) | | | - | | | | - | | | | 3 | | | | (2 | ) |
Total Other Expense | | | (21 | ) | | | (45 | ) | | | - | | | | (76 | ) | | | (142 | ) |
| | | | | | | | | | | | | | | | | | | | |
Income From Continuing Operations Before | | | | | | | | | | | | | | | | | |
Income Taxes | | | 388 | | | | 168 | | | | 53 | | | | (81 | ) | | | 528 | |
Income taxes | | | 155 | | | | 67 | | | | 22 | | | | (28 | ) | | | 216 | |
Income from continuing operations | | | 233 | | | | 101 | | | | 31 | | | | (53 | ) | | | 312 | |
Discontinued operations | | | - | | | | - | | | | - | | | | (8 | ) | | | (8 | ) |
Net Income | | $ | 233 | | | $ | 101 | | | $ | 31 | | | $ | (61 | ) | | $ | 304 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Changes Between Second Quarter 2007 and | | | | | | | | | | | | | | | | | |
Second Quarter 2006 Financial Results | | | | | | | | | | | | | | | | | | | | |
Increase (Decrease) | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Revenues: | | | | | | | | | | | | | | | | | | | | |
External | | | | | | | | | | | | | | | | | | | | |
Electric | | $ | 287 | | | $ | 21 | | | $ | 43 | | | $ | - | | | $ | 351 | |
Other | | | 35 | | | | (1 | ) | | | 7 | | | | (34 | ) | | | 7 | |
Internal | | | (6 | ) | | | 68 | | | | - | | | | (62 | ) | | | - | |
Total Revenues | | | 316 | | | | 88 | | | | 50 | | | | (96 | ) | | | 358 | |
| | | | | | | | | | | | | | | | | | | | |
Expenses: | | | | | | | | | | | | | | | | | | | | |
Fuel and purchased power | | | 189 | | | | 26 | | | | 41 | | | | (62 | ) | | | 194 | |
Other operating expenses | | | 47 | | | | (6 | ) | | | 34 | | | | (43 | ) | | | 32 | |
Provision for depreciation | | | 11 | | | | 3 | | | | - | | | | 1 | | | | 15 | |
Amortization of regulatory assets | | | 45 | | | | - | | | | 2 | | | | (2 | ) | | | 45 | |
Deferral of new regulatory assets | | | 20 | | | | - | | | | (22 | ) | | | - | | | | (2 | ) |
General taxes | | | 11 | | | | 3 | | | | (1 | ) | | | 3 | | | | 16 | |
Total Expenses | | | 323 | | | | 26 | | | | 54 | | | | (103 | ) | | | 300 | |
| | | | | | | | | | | | | | | | | | | | |
Operating Income | | | (7 | ) | | | 62 | | | | (4 | ) | | | 7 | | | | 58 | |
Other Income (Expense): | | | | | | | | | | | | | | | | | | | | |
Investment income | | | (19 | ) | | | 3 | | | | - | | | | 15 | | | | (1 | ) |
Interest expense | | | (17 | ) | | | 3 | | | | - | | | | (13 | ) | | | (27 | ) |
Capitalized interest | | | (2 | ) | | | 2 | | | | - | | | | - | | | | - | |
Subsidiaries' preferred stock dividends | | | 5 | | | | - | | | | - | | | | (3 | ) | | | 2 | |
Total Other Income | | | (33 | ) | | | 8 | | | | - | | | | (1 | ) | | | (26 | ) |
| | | | | | | | | | | | | | | | | | | | |
Income From Continuing Operations Before | | | | | | | | | | | | | | | | | |
Income Taxes | | | (40 | ) | | | 70 | | | | (4 | ) | | | 6 | | | | 32 | |
Income taxes | | | (14 | ) | | | 29 | | | | (3 | ) | | | (6 | ) | | | 6 | |
Income from continuing operations | | | (26 | ) | | | 41 | | | | (1 | ) | | | 12 | | | | 26 | |
Discontinued operations | | | - | | | | - | | | | - | | | | 8 | | | | 8 | |
Net Income | | $ | (26 | ) | | $ | 41 | | | $ | (1 | ) | | $ | 20 | | | $ | 34 | |
Energy Delivery Services – Second Quarter 2007 Compared to Second Quarter 2006
Net income decreased $26 million (or 11%) to $207 million in the second quarter of 2007 compared to $233 million in the second quarter of 2006, primarily due to increased purchased power costs, higher other operating expenses and increased depreciation and amortization, partially offset by higher revenues.
Revenues –
The increase in total revenues resulted from the following sources:
| | Three Months Ended | | | |
| | June 30, | | | |
Revenues by Type of Service | | 2007 | | 2006 | | Increased | |
| | (In millions) | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
The increases in distribution deliveries by customer class are summarized in the following table:
Electric Distribution Deliveries
| | |
| | | |
| | | |
| | | |
Total Distribution Deliveries
| | | |
The increase in electric distribution deliveries to customers was primarily due to higher weather-related usage during the second quarter of 2007 compared to the same period of 2006 (heating degree days increased by 15.8% and cooling degree days increased by 39.3%). The higher revenues from distribution deliveries were partially offset principally by distribution rate decreases for Met-Ed and Penelec as a result of a January 11, 2007 PPUC rate decision (see Outlook – State Regulatory Matters – Pennsylvania).
The following table summarizes the price and volume factors contributing to the $210 million increase in non-affiliated generation sales in 2007 compared to 2006:
Sources of Change in Generation Sales | | | | |
| | (In millions) | | |
Retail: | | | | | |
Effect of 1% increase in customer usage | | $ | 6 | | |
Change in prices | | | | | |
| | | | | |
Wholesale: | | | | | |
Effect of 131% increase in KWH sales | | | 64 | | |
Change in prices | | | | | |
| | | | | |
Net Increase in Generation Sales | | $ | 210 | | |
| | | | | |
The increase in retail generation prices during the second quarter of 2007 compared to 2006 was primarily due to increased generation rates for JCP&L resulting from the New Jersey BGS auction and an increase in NUGC rates authorized by the NJBPU. Wholesale generation sales increased principally as a result of Met-Ed and Penelec selling additional available power into the PJM market beginning in January 2007.
Transmission revenues increased $70 million primarily due to higher transmission rates for Met-Ed and Penelec resulting from the January 2007 PPUC authorization for transmission cost recovery. Met-Ed and Penelec defer the difference between revenues from their transmission rider and transmission costs incurred, with no material effect to current period earnings.
Expenses –
The net increases in revenues discussed above were more than offset by a $323 million increase in expenses due to the following:
| · | Purchased power costs were $187 million higher in the second quarter of 2007 due to higher unit prices and volumes purchased. The increased unit prices reflected the effect of higher JCP&L purchased power unit prices resulting from the BGS auction. The increased KWH purchases in 2007 were due to higher customer usage and sales to the wholesale market. The following table summarizes the sources of changes in purchased power costs:
|
Sources of Change in Purchased Power | | | |
| | (In millions) | |
| | | | |
Purchased Power: | | | | |
Change due to increased unit costs | | $ | 99 | |
Change due to increased volume | | | 43 | |
Decrease in NUG costs deferred | | | 45 | |
Net Increase in Purchased Power Costs | | $ | 187 | |
| · | Other operating expenses increased $47 million due to the net effects of:
|
- | An increase of $49 million in transmission expenses, resulting primarily from higher congestion costs ($47 million);
|
- | A decrease in miscellaneous operating expenses of $12 million primarily due to reduced billings for employee benefits from FESC; and
|
- | An increase in operation and maintenance expenses of $12 million primarily due to increased labor costs devoted to operating activities ($22 million) partially offset by lower employee benefit costs ($10 million);
|
| · | Amortization of regulatory assets increased $45 million compared to 2006 due primarily to recovery of deferred BGS costs through higher NUGC revenues for JCP&L as discussed above; and
|
| · | The deferral of new regulatory assets during the second quarter of 2007 was $20 million lower than 2006 due in part to $25 million in reduced deferrals of transmission related PJM costs. The higher deferral in the second quarter of 2006 was attributable to the deferral of first quarter costs following authorization by the PPUC in May 2006 (see Note 10). The reduction in deferred PJM costs was partially offset by interest earned on the RCP Distribution Deferral. |
Other Income and Expense –
Other income decreased $33 million in 2007 compared to the second quarter of 2006 primarily due to lower interest income of $19 million resulting from the repayment of notes receivable from affiliates since the second quarter of 2006, and increased interest expense of $17 million related in part to new debt issuances by CEI and JCP&L.
Ohio Transitional Generation Services – Second Quarter 2007 Compared to Second Quarter 2006
Net income of $30 million in the second quarter of 2007 did not differ significantly from $31 million in the same period last year. Higher generation revenues were offset by higher operating expenses, primarily for purchased power.
Revenues –
The increase in reported segment revenues resulted from the following sources:
| | Three Months Ended | | | |
| | June 30, | | | |
Revenues by Type of Service | | 2007 | | 2006 | | Increase | |
| | (In millions) | |
| | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
The following table summarizes the price and volume factors contributing to the increase in generation sales revenues from retail customers:
Source of Change in Generation Sales | | | |
| | (In millions) | |
Retail: | | | | |
Effect of 4.4% increase in customer usage | | $ | 22 | |
Change in prices | | | | |
Total Increase in Retail Generation Sales | | | | |
| | | | |
The increase in generation sales was primarily due to higher weather-related usage in the second quarter of 2007 as discussed above and reduced customer shopping. Average prices increased primarily due to higher composite unit prices for returning customers.
Expenses -
Purchased power costs were $41 million higher due primarily to higher unit costs for power purchased from FES. The factors contributing to the higher costs are summarized in the following table:
Source of Change in Purchased Power | | Increase (Decrease) | |
| | (In millions) | |
Purchases from non-affiliates: | | | | |
Change due to decreased unit costs | | $ | (5 | ) |
Change due to volume | | | 2 | |
| | | (3 | ) |
Purchases from FES: | | | | |
Change due to increased unit costs | | | 23 | |
Change due to volume | | | 21 | |
| | | 44 | |
Total Increase in Purchased Power Costs | | $ | 41 | |
The increase in KWH purchases was due to the higher retail generation sales requirements. The higher unit costs resulted from the provision of the full-requirements PSA with FES under which purchased power unit costs reflected the increases in the Ohio Companies’ retail generation sales unit prices.
Other operating expenses increased $34 million due primarily to MISO transmission-related expenses. The difference between transmission revenues accrued and transmission expenses incurred is deferred, resulting in no material impact to current period earnings.
Competitive Energy Services – Second Quarter 2007 Compared to Second Quarter 2006
Net income for this segment was $142 million in the second quarter of 2007 compared to $101 million in the same period last year. An improvement in gross generation margin and lower other operating expenses was partially offset by an increase in other expenses.
Revenues –
Total revenues increased $88 million in the second quarter of 2007 compared to the same period in 2006. This increase primarily resulted from higher unit prices from affiliated generation sales to the Ohio Companies, which were partially offset by lower non-affiliated wholesale sales.
The higher retail revenues resulted from increased sales in both the MISO and PJM markets. Lower non-affiliated wholesale revenues reflected the effect of decreased generation available for the non-affiliated wholesale market due to increased affiliated company power sales requirements under the Ohio Companies’ full-requirements PSA and the partial-requirements power sales agreement with Met-Ed and Penelec.
The increased affiliated company generation revenues were due to higher unit prices and increased KWH sales. Factors contributing to the revenue increase from PSA sales to the Ohio Companies are discussed under the purchased power costs analysis in the Ohio Transitional Generation Services results above. The higher KWH sales to the Pennsylvania affiliates were due to increased Met-Ed and Penelec generation sales requirements. These increases were partially offset by lower sales to Penn as a result of the implementation of its competitive solicitation process in 2007.
The increase in reported segment revenues resulted from the following sources:
| | Three Months Ended | | | |
| | June 30, | | Increase | |
Revenues By Type of Service | | 2007 | | 2006 | | (Decrease) | |
| | (In millions) | |
Non-Affiliated Generation Sales: | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | ) |
Total Non-Affiliated Generation Sales | | | | | | | | | | |
Affiliated Generation Sales | | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:
| | Increase | |
Source of Change in Non-Affiliated Generation Sales | | | |
| | (In millions) | |
Retail: | | | | |
Effect of 20% increase in sales volume | | $ | 27 | |
Change in prices | | | | |
| | | | |
Wholesale: | | | | |
Effect of 28% decrease in KWH sales | | | (56 | ) |
Change in prices | | | | |
| | | | ) |
Net Increase in Non-Affiliated Generation Sales | | | | |
Source of Change in Affiliated Generation Sales | | | |
| | (In millions) | |
Ohio Companies: | | | | |
Effect of 4% increase in KWH sales | | $ | 21 | |
Change in prices | | | | |
| | | | |
Pennsylvania Companies: | | | | |
Effect of 18% increase in KWH sales | | | 25 | |
Change in prices | | | | ) |
| | | | |
Net Increase in Affiliated Generation Sales | | | | |
Expenses -
Total operating expenses were $26 million higher in the second quarter of 2007 due to the following factors:
| · | Purchased power costs increased $32 million due to higher unit prices;
|
| · | Nuclear production costs increased $6 million, caused in part by expenditures related to the Perry refueling outage ($15 million), partially offset by reduced labor costs ($7 million) due to more labor devoted to capital projects in 2007 and reduced employee benefits costs ($3 million); |
| · | Expenses related to marking commodity contracts to market value were $5 million higher due to a $1 million unrealized loss on purchased power hedges and the absence of a $4 million gain on gas hedges recognized in 2006; and |
| · | Higher depreciation expense of $3 million from property additions. |
Partially offsetting the increases were the following:
| · | MISO/PJM transmission expenses were $8 million lower due to reduced Revenue Sufficiency Guarantee charges ($19 million) partially offset by higher point-to-point transmission and congestion charges; |
| · | Fossil operating costs were $9 million lower due to the absence of asbestos removal costs of $4 million included in 2006 results and reduced employee benefit costs; and |
| · | Fuel costs were $6 million lower due to a $14 million coal inventory adjustment and a $6 million reduction in emission allowance costs. Partially offsetting these decreases were $11 million of increased natural gas, coal and nuclear fuel consumption, due to increased generation, and $3 million of increases in other fuel costs. |
Other Income –
Investment income in the second quarter of 2007 was $3 million higher than the 2006 period primarily due to increased earnings on nuclear decommissioning trust investments (net of an $8 million impairment) while interest expense was $3 million lower due to reduced short-term borrowings.
Other – Second Quarter 2007 Compared to Second Quarter 2006
FirstEnergy’s financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a $20 million increase in FirstEnergy’s net income in the second quarter of 2007 compared to the same quarter of 2006. The increase was primarily due to the absence of an $8 million loss included in 2006 results from discontinued operations (see Note 3), the absence of $3 million in subsidiary preferred stock dividends and reduced capital stock taxes of $3 million.
Summary of Results of Operations – First Six Months of 2007 Compared with the First Six Months of 2006
Financial results for FirstEnergy's major business segments in the first six months of 2007 and 2006 were as follows:
| | | | | | | | Ohio | | | | | | | |
| | Energy | | | Competitive | | | Transitional | | | Other and | | | | |
| | Delivery | | | Energy | | | Generation | | | Reconciling | | | FirstEnergy | |
First Six Months 2007 Financial Results | | Services | | | Services | | | Services | | | Adjustments | | | Consolidated | |
| | (In millions) | |
Revenues: | | | | | | | | | | | | | | | |
External | | | | | | | | | | | | | | | |
Electric | | $ | 3,808 | | | $ | 635 | | | $ | 1,226 | | | $ | - | | | $ | 5,669 | |
Other | | | 327 | | | | 97 | | | | 19 | | | | (30 | ) | | | 413 | |
Internal | | | - | | | | 1,404 | | | | - | | | | (1,404 | ) | | | - | |
Total Revenues | | | 4,135 | | | | 2,136 | | | | 1,245 | | | | (1,434 | ) | | | 6,082 | |
| | | | | | | | | | | | | | | | | | | | |
Expenses: | | | | | | | | | | | | | | | | | | | | |
Fuel and purchased power | | | 1,722 | | | | 907 | | | | 1,081 | | | | (1,404 | ) | | | 2,306 | |
Other operating expenses | | | 819 | | | | 588 | | | | 138 | | | | (46 | ) | | | 1,499 | |
Provision for depreciation | | | 199 | | | | 102 | | | | - | | | | 14 | | | | 315 | |
Amortization of regulatory assets | | | 487 | | | | - | | | | 11 | | | | (1 | ) | | | 497 | |
Deferral of new regulatory assets | | | (217 | ) | | | - | | | | (75 | ) | | | - | | | | (292 | ) |
General taxes | | | 320 | | | | 55 | | | | 2 | | | | 15 | | | | 392 | |
Total Expenses | | | 3,330 | | | | 1,652 | | | | 1,157 | | | | (1,422 | ) | | | 4,717 | |
| | | | | | | | | | | | | | | | | | | | |
Operating Income | | | 805 | | | | 484 | | | | 88 | | | | (12 | ) | | | 1,365 | |
Other Income (Expense): | | | | | | | | | | | | | | | | | | | | |
Investment income | | | 132 | | | | 8 | | | | 1 | | | | (78 | ) | | | 63 | |
Interest expense | | | (227 | ) | | | (100 | ) | | | (1 | ) | | | (62 | ) | | | (390 | ) |
Capitalized interest | | | 4 | | | | 8 | | | | - | | | | - | | | | 12 | |
Total Other Expense | | | (91 | ) | | | (84 | ) | | | - | | | | (140 | ) | | | (315 | ) |
| | | | | | | | | | | | | | | | | | | | |
Income From Continuing Operations Before | | | | | | | | | | | | | | | | | |
Income Taxes | | | 714 | | | | 400 | | | | 88 | | | | (152 | ) | | | 1,050 | |
Income taxes | | | 289 | | | | 160 | | | | 35 | | | | (62 | ) | | | 422 | |
Net Income | | $ | 425 | | | $ | 240 | | | $ | 53 | | | $ | (90 | ) | | $ | 628 | |
| | | | | | | | Ohio | | | | | | | |
| | Energy | | | Competitive | | | Transitional | | | Other and | | | | |
| | Delivery | | | Energy | | | Generation | | | Reconciling | | | FirstEnergy | |
First Six Months 2006 Financial Results | | Services | | | Services | | | Services | | | Adjustments | | | Consolidated | |
| | (In millions) | |
Revenues: | | | | | | | | | | | | | | | |
External | | | | | | | | | | | | | | | |
Electric | | $ | 3,314 | | | $ | 642 | | | $ | 1,108 | | | $ | - | | | $ | 5,064 | |
Other | | | 256 | | | | 96 | | | | 10 | | | | 30 | | | | 392 | |
Internal | | | 14 | | | | 1,235 | | | | - | | | | (1,249 | ) | | | - | |
Total Revenues | | | 3,584 | | | | 1,973 | | | | 1,118 | | | | (1,219 | ) | | | 5,456 | |
| | | | | | | | | | | | | | | | | | | | |
Expenses: | | | | | | | | | | | | | | | | | | | | |
Fuel and purchased power | | | 1,383 | | | | 901 | | | | 954 | | | | (1,249 | ) | | | 1,989 | |
Other operating expenses | | | 729 | | | | 634 | | | | 109 | | | | (1 | ) | | | 1,471 | |
Provision for depreciation | | | 185 | | | | 94 | | | | - | | | | 13 | | | | 292 | |
Amortization of regulatory assets | | | 413 | | | | - | | | | 9 | | | | - | | | | 422 | |
Deferral of new regulatory assets | | | (168 | ) | | | - | | | | (58 | ) | | | - | | | | (226 | ) |
General taxes | | | 302 | | | | 49 | | | | 2 | | | | 13 | | | | 366 | |
Total Expenses | | | 2,844 | | | | 1,678 | | | | 1,016 | | | | (1,224 | ) | | | 4,314 | |
| | | | | | | | | | | | | | | | | | | | |
Operating Income | | | 740 | | | | 295 | | | | 102 | | | | 5 | | | | 1,142 | |
Other Income (Expense): | | | | | | | | | | | | | | | | | | | | |
Investment income | | | 164 | | | | 17 | | | | - | | | | (107 | ) | | | 74 | |
Interest expense | | | (201 | ) | | | (96 | ) | | | (1 | ) | | | (45 | ) | | | (343 | ) |
Capitalized interest | | | 7 | | | | 6 | | | | - | | | | 1 | | | | 14 | |
Subsidiaries' preferred stock dividends | | | (7 | ) | | | - | | | | - | | | | 3 | | | | (4 | ) |
Total Other Expense | | | (37 | ) | | | (73 | ) | | | (1 | ) | | | (148 | ) | | | (259 | ) |
| | | | | | | | | | | | | | | | | | | | |
Income From Continuing Operations Before | | | | | | | | | | | | | | | | | |
Income Taxes | | | 703 | | | | 222 | | | | 101 | | | | (143 | ) | | | 883 | |
Income taxes | | | 281 | | | | 89 | | | | 40 | | | | (58 | ) | | | 352 | |
Income from continuing operations | | | 422 | | | | 133 | | | | 61 | | | | (85 | ) | | | 531 | |
Discontinued operations | | | - | | | | - | | | | - | | | | (6 | ) | | | (6 | ) |
Net Income | | $ | 422 | | | $ | 133 | | | $ | 61 | | | $ | (91 | ) | | $ | 525 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Changes Between First Six Months 2007 | | | | | | | | | | | | | | | | | | | | |
and First Six Months 2006 | | | | | | | | | | | | | | | | | | | | |
Financial Results Increase (Decrease) | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Revenues: | | | | | | | | | | | | | | | | | | | | |
External | | | | | | | | | | | | | | | | | | | | |
Electric | | $ | 494 | | | $ | (7 | ) | | $ | 118 | | | $ | - | | | $ | 605 | |
Other | | | 71 | | | | 1 | | | | 9 | | | | (60 | ) | | | 21 | |
Internal | | | (14 | ) | | | 169 | | | | - | | | | (155 | ) | | | - | |
Total Revenues | | | 551 | | | | 163 | | | | 127 | | | | (215 | ) | | | 626 | |
| | | | | | | | | | | | | | | | | | | | |
Expenses: | | | | | | | | | | | | | | | | | | | | |
Fuel and purchased power | | | 339 | | | | 6 | | | | 127 | | | | (155 | ) | | | 317 | |
Other operating expenses | | | 90 | | | | (46 | ) | | | 29 | | | | (45 | ) | | | 28 | |
Provision for depreciation | | | 14 | | | | 8 | | | | - | | | | 1 | | | | 23 | |
Amortization of regulatory assets | | | 74 | | | | - | | | | 2 | | | | (1 | ) | | | 75 | |
Deferral of new regulatory assets | | | (49 | ) | | | - | | | | (17 | ) | | | - | | | | (66 | ) |
General taxes | | | 18 | | | | 6 | | | | - | | | | 2 | | | | 26 | |
Total Expenses | | | 486 | | | | (26 | ) | | | 141 | | | | (198 | ) | | | 403 | |
| | | | | | | | | | | | | | | | | | | | |
Operating Income | | | 65 | | | | 189 | | | | (14 | ) | | | (17 | ) | | | 223 | |
Other Income (Expense): | | | | | | | | | | | | | | | | | | | | |
Investment income | | | (32 | ) | | | (9 | ) | | | 1 | | | | 29 | | | | (11 | ) |
Interest expense | | | (26 | ) | | | (4 | ) | | | - | | | | (17 | ) | | | (47 | ) |
Capitalized interest | | | (3 | ) | | | 2 | | | | - | | | | (1 | ) | | | (2 | ) |
Subsidiaries' preferred stock dividends | | | 7 | | | | - | | | | - | | | | (3 | ) | | | 4 | |
Total Other Income | | | (54 | ) | | | (11 | ) | | | 1 | | | | 8 | | | | (56 | ) |
| | | | | | | | | | | | | | | | | | | | |
Income From Continuing Operations Before | | | | | | | | | | | | | | | | | |
Income Taxes | | | 11 | | | | 178 | | | | (13 | ) | | | (9 | ) | | | 167 | |
Income taxes | | | 8 | | | | 71 | | | | (5 | ) | | | (4 | ) | | | 70 | |
Income from continuing operations | | | 3 | | | | 107 | | | | (8 | ) | | | (5 | ) | | | 97 | |
Discontinued operations | | | - | | | | - | | | | - | | | | 6 | | | | 6 | |
Net Income | | $ | 3 | | | $ | 107 | | | $ | (8 | ) | | $ | 1 | | | $ | 103 | |
Energy Delivery Services – First Six Months of 2007 Compared to First Six Months of 2006
Net income increased $3 million (or 1%) to $425 million in the first six months of 2007 compared to $422 million in the first six months of 2006, primarily due to increased revenues partially offset by higher operating expenses and lower investment income.
Revenues –
The increase in total revenues resulted from the following sources:
| | Six Months Ended | | | |
| | June 30, | | | |
Revenues by Type of Service | | 2007 | | 2006 | | Increase | |
| | (In millions) | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
The increases in distribution deliveries by customer class are summarized in the following table:
Electric Distribution Deliveries
| | | |
| | | | |
| | | | |
| | | | |
Total Distribution Deliveries
| | | | |
The increase in electric distribution deliveries to customers was primarily due to higher weather-related usage during the first six months of 2007 compared to the same period of 2006 (heating degree days increased by 15.4% and cooling degree days increased by 39.8%). The higher revenues from increased distribution deliveries were offset principally by distribution rate decreases for Met-Ed and Penelec as a result of a January 11, 2007 PPUC rate decision (see Outlook – State Regulatory Matters – Pennsylvania).
The following table summarizes the price and volume factors contributing to the $371 million increase in non-affiliated generation sales revenues in 2007 compared to 2006:
Sources of Change in Generation Sales | | | | |
| | (In millions) | | |
Retail: | | | | | |
Effect of 0.6% increase in customer usage | | $ | 8 | | |
Change in prices | | | | | |
| | | | | |
Wholesale: | | | | | |
Effect of 135% increase in KWH sales | | | 141 | | |
Change in prices | | | | | |
| | | | | |
Net Increase in Generation Sales | | $ | 371 | | |
The increase in retail generation prices during the first six months of 2007 compared to 2006 was primarily due to increased generation rates for JCP&L resulting from the New Jersey BGS auction process and an increase in NUGC rates authorized by the NJBPU. Wholesale generation sales increased principally as a result of Met-Ed and Penelec selling additional available power into the PJM market beginning in January 2007.
Transmission revenues increased $129 million primarily due to higher transmission rates for Met-Ed and Penelec resulting from the January 2007 PPUC authorization for transmission cost recovery. Met-Ed and Penelec defer the difference between revenues from their transmission rider and transmission costs incurred, with no material effect on current period earnings
Expenses –
The net increases in revenues discussed above were partially offset by a $486 million increase in expenses due to the following:
| · | Purchased power costs were $339 million higher in the first six months of 2007 due to higher unit costs and volumes purchased. The increased unit prices reflected the effect of higher JCP&L purchased power unit costs resulting from the BGS auction process. The increased KWH purchases in 2007 were due in part to higher customer usage and sales to the wholesale market. The following table summarizes the sources of changes in purchased power costs:
|
Sources of Change in Purchased Power | | | | |
| | (In millions) | | |
| | | | | |
Purchased Power: | | | | | |
Change due to increased unit costs | | $ | 168 | | |
Change due to increased volume | | | 128 | | |
Decrease in NUG costs deferred | | | 43 | | |
Net Increase in Purchased Power Costs | | $ | 339 | | |
| · | Other operating expenses increased $90 million due to the net effects of:
|
- | An increase of $101 million in MISO and PJM transmission expenses, resulting primarily from higher congestion costs;
|
- | A decrease in miscellaneous operating expenses of $18 million primarily due to reduced billings for employee benefits from FESC; and
|
- | An increase in operation and maintenance expenses of $10 million primarily due to reduced employee benefits applicable to construction activities and storm-related costs;
|
| · | Amortization of regulatory assets increased $75 million compared to 2006 due primarily to recovery of deferred BGS costs through higher NUGC rates for JCP&L as discussed above; and
|
| · | The deferral of new regulatory assets during the first six months of 2007 was $49 million higher in 2007 primarily due to the deferral of previously expensed decommissioning costs of $27 million related to the Saxton nuclear research facility (see Outlook – State Regulatory Matters - Pennsylvania), increased deferrals of PJM transmission expenses of $10 million and increased RCP Distribution Deferrals of $10 million.
|
Other Income and Expense –
Other income decreased $54 million in 2007 compared to the first six months of 2006 primarily due to lower interest income of $32 million resulting from the repayment of notes receivable from affiliates since the second quarter of 2006 and increased interest expense of $26 million related to new debt issuances by CEI and JCP&L.
Ohio Transitional Generation Services – First Six Months of 2007 Compared to First Six Months of 2006
Net income for this segment decreased to $53 million in the first six months of 2007 from $61 million in the same period last year. Higher generation revenues were offset by higher operating expenses, primarily for purchased power.
Revenues –
The increase in reported segment revenues resulted from the following sources:
| | Six Months Ended | | | |
| | June 30, | | Increase | |
Revenues by Type of Service | | 2007 | | 2006 | | (Decrease) | |
| | (In millions) | |
| | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | ) |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
The following table summarizes the price and volume factors contributing to the increase in sales revenues from retail customers:
Source of Change in Generation Sales | | | |
| | (In millions) | |
Retail: | | | | |
Effect of 6% increase in customer usage | | $ | 54 | |
Change in prices | | | | |
Total Increase in Retail Generation Sales | | | | |
| | | | |
The increase in generation sales was primarily due to higher weather-related usage in the first six months of 2007 compared to the same period of 2006 as discussed above and reduced customer shopping. Average prices increased primarily due to higher composite unit prices for returning customers. The percentage of generation services provided by alternative suppliers to total sales delivered by the Ohio Companies in their service areas decreased by 2 percentage points from the same period last year.
Expenses -
Purchased power costs were $127 million higher due primarily to higher unit prices for power purchased from FES. The factors contributing to the higher costs are summarized in the following table:
Source of Change in Purchased Power | | Increase | |
| | (In millions) | |
Purchases from non-affiliates: | | | | |
Change due to increased unit costs | | $ | 7 | |
Change due to volume purchased | | | 1 | |
| | | 8 | |
Purchases from FES: | | | | |
Change due to increased unit costs | | | 76 | |
Change due to volume purchased | | | 43 | |
| | | 119 | |
Total Increase in Purchased Power Costs | | $ | 127 | |
The increase in KWH purchases was due to the higher retail generation sales requirements. The higher unit costs resulted from the provision of the full-requirements PSA with FES under which purchased power unit costs reflected the increases in the Ohio Companies’ retail generation sales unit prices.
Other operating expenses increased $29 million primarily due to MISO transmission-related expenses. The difference between transmission revenues accrued and transmission expenses incurred is deferred, resulting in no material impact to current period earnings.
Competitive Energy Services – First Six Months of 2007 Compared to First Six Months of 2006
Net income for this segment was $240 million in the first six months of 2007 compared to $133 million in the same period last year. This increase reflects an improvement in gross generation margin and lower other operating expenses, which were partially offset by increased depreciation, general taxes and reduced investment income.
Revenues –
Total revenues increased $163 million in the first six months of 2007 compared to the same period in 2006. This increase primarily resulted from higher unit prices under affiliated generation sales to the Ohio Companies, which was partially offset by lower non-affiliated wholesale sales.
The higher retail revenues resulted from increased sales in both the MISO and PJM markets. Lower non-affiliated wholesale revenues reflected the effect of decreased generation available for the non-affiliated wholesale market due to increased affiliated company power sales under the Ohio Companies’ full-requirements PSA and the partial-requirements power sales agreement with Met-Ed and Penelec.
The increased affiliated company generation revenues were due to higher unit prices and increased KWH sales. Factors contributing to the revenue increase from PSA sales to the Ohio Companies are discussed under the purchased power costs analysis in the Ohio Transitional Generation Services results above. The higher KWH sales to the Pennsylvania affiliates were due to increased Met-Ed and Penelec generation sales requirements. These increases were partially offset by lower sales to Penn due to the implementation of its competitive solicitation process in 2007.
The increase in reported segment revenues resulted from the following sources:
| | Six Months Ended | | | |
| | June 30, | | Increase | |
Revenues by Type of Service | | 2007 | | 2006 | | (Decrease) | |
| | (In millions) | |
Non-Affiliated Generation Sales: | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | ) |
Total Non-Affiliated Generation Sales | | | | | | | | | | ) |
Affiliated Generation Sales | | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Transmission revenues decreased $19 million due to reduced retail load in the MISO market, lower transmission rates and reduced FTR auction revenue.
The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:
| | Increase | |
Source of Change in Non-Affiliated Generation Sales | | | |
| | (In millions) | |
Retail: | | | | |
Effect of 19% increase in sales volume | | $ | 51 | |
Change in prices | | | | |
| | | | |
Wholesale: | | | | |
Effect of 31% decrease in KWH sales | | | (118 | ) |
Change in prices | | | | |
| | | | ) |
Net Decrease in Non-Affiliated Generation Sales | | | | ) |
| | | |
Source of Change in Affiliated Generation Sales | | | |
| | (In millions) | |
Ohio Companies: | | | | |
Effect of 5% increase in KWH sales | | $ | 43 | |
Change in prices | | | | |
| | | | |
Pennsylvania Companies: | | | | |
Effect of 14% increase in KWH sales | | | 40 | |
Change in prices | | | | |
| | | | |
Net Increase in Affiliated Generation Sales | | | | |
Expenses -
Total expenses were $26 million lower in the first six months of 2007 due to the following factors:
| · | Fuel costs were $26 million lower primarily due to reduced coal costs and emission allowance costs offset by increases in nuclear fuel and natural gas consumption. Coal costs were reduced due to a $14 million inventory adjustment and $35 million of reduced coal consumption reflecting lower generation, partially offset by a $19 million increase in coal prices. Reduced emission allowance costs ($12 million) were more than offset by increased natural gas costs ($6 million) and nuclear fuel costs ($9 million) due to increased generation and higher prices; and |
| · | Nuclear operating costs were $58 million lower due to fewer outages in 2007 compared to 2006 and reduced employee benefit costs. |
Partially offsetting the lower costs were the following:
| · | Purchased power costs increased $31 million due primarily to higher volumes purchased; |
| · | Higher fossil operating costs of $12 million due to increased labor costs; |
| · | Higher depreciation expenses of $8 million due to property additions; and |
| · | Higher general taxes of $5 million. |
Other Income –
Investment income in the first six months of 2007 was $11 million lower than the 2006 period primarily due to decreased earnings on nuclear decommissioning trust investments (including a $12 million impairment).
Other – First Six Months of 2007 Compared to First Six Months of 2006
FirstEnergy’s financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a $1 million increase in FirstEnergy’s net income in the first six months of 2007. The increase was caused by the absence of a $6 million loss included in 2006 results from discontinued operations (see Note 3) offset by increased interest expense in 2007 compared to 2006 due to higher short-term borrowings.
CAPITAL RESOURCES AND LIQUIDITY
FirstEnergy’s business is capital intensive, requiring considerable capital resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. During 2007 and in subsequent years, FirstEnergy expects to satisfy these requirements primarily with a combination of cash from operations and funds from the capital markets. FirstEnergy also expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements during those periods.
Changes in Cash Position
FirstEnergy's primary source of cash required for continuing operations as a holding company is cash from the operations of its subsidiaries. FirstEnergy and certain of its subsidiaries also have access to $2.75 billion of short-term financing under a revolving credit facility which expires in 2011. Under the terms of the facility, FirstEnergy is permitted to have up to $1.5 billion in outstanding borrowings at any given time, subject to the facility cap of $2.75 billion of aggregate outstanding borrowings by it and its subsidiaries that are also parties to such facility. In the first six months of 2007, FirstEnergy received $637 million of cash dividends and return of capital from its subsidiaries and paid $311 million in cash dividends to common shareholders. With the exception of Met-Ed, which is currently in an accumulated deficit position, there are no material restrictions on the payment of cash dividends by the subsidiaries of FirstEnergy.
On March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or approximately 4.5%, of its outstanding common stock at an initial price of approximately $900 million pursuant to an accelerated share repurchase program. FirstEnergy acquired these shares under its previously announced authorization to repurchase up to 16 million shares of its common stock. The share repurchase was funded with short-term borrowings, including $500 million from bridge loan facilities that have since been repaid.
On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in the Bruce Mansfield Plant Unit 1, representing 779 MW of net demonstrated capacity. The purchase price of approximately $1.329 billion for the undivided interest was funded through a combination of equity investments by affiliates of AIG Financial Products Corp. and Union Bank of California, N.A. in six lessor trusts and proceeds from the sale of $1.135 billion aggregate principal amount of 6.85% pass through certificates due 2034. A like principal amount of secured notes maturing June 1, 2034 were issued by the lessor trusts to the pass through trust that issued and sold the certificates. The lessor trusts leased the undivided interest back to FGCO for a term of approximately 33 years under substantially identical leases. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. The notes and certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements. The transaction will be classified as a financing under GAAP until FGCO’s and FES’ registration obligations under the registration rights agreement applicable to the $1.135 billion principal amount of pass through certificates issued in connection with the transaction are satisfied, at which time it is expected to be classified as an operating lease under GAAP. FirstEnergy used the net after-tax proceeds of approximately $1.2 billion to repay short-term debt that was used to fund its recent $900 million accelerated share repurchase program and $300 million pension contribution. FGCO continues to operate the plant. CEI has an existing sale and leaseback arrangement for the remaining 51 MW portion of Bruce Mansfield Unit 1. This transaction generated tax capital gains of approximately $830 million, a substantial portion of which will be offset by existing tax capital loss carryforwards. FirstEnergy will reduce its tax loss carryforward valuation allowances in the third quarter of 2007 and anticipates an immaterial impact to net income as the majority of the unrecognized tax benefits will reduce goodwill.
As of June 30, 2007, FirstEnergy had $37 million of cash and cash equivalents compared with $90 million as of December 31, 2006. The major sources of 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 services and power supply management services businesses (see Results of Operations above). Net cash provided from operating activities was $131 million and $485 million in the first six months of 2007 and 2006, respectively, summarized as follows:
| | Six Months Ended | |
| | June 30, | |
| | 2007 | | 2006 | |
| | (In millions) | |
Net income | | $ | 628 | | $ | 525 | |
Non-cash charges | | | 277 | | | 260 | |
Pension trust contribution | | | (300 | ) | | - | |
Working capital and other | | | (474 | ) | | (300 | ) |
| | $ | 131 | | $ | 485 | |
Net cash provided from operating activities decreased by $354 million in the first six months of 2007 compared to the first six months of 2006 primarily due to a $300 million pension trust contribution in 2007 and $174 million from working capital charges, partially offset by a $103 million increase in net income (see Results of Operations above). The decrease from working capital and other changes primarily resulted from a $365 million increase in receivables due to higher sales, partially offset by $93 million from reduced materials and supplies inventories and $68 million of decreased payments for accounts payable.
Cash Flows From Financing Activities
In the first six months of 2007, cash provided from financing activities was $454 million compared to $618 million in the first six months of 2006. The decrease was primarily due to the repurchase of common stock in 2007, partially offset by higher short-term borrowings. The following table summarizes security issuances and redemptions.
| | Six Months Ended | |
| | June 30, | |
Securities Issued or Redeemed | | 2007 | | 2006 | |
| | (In millions) | |
New issues | | | | | |
Pollution control notes | | $ | - | | $ | 253 | |
Secured notes | | | - | | | 200 | |
Unsecured notes | | | 800 | | | 600 | |
| | $ | 800 | | $ | 1,053 | |
Redemptions | | | | | | | |
First mortgage bonds | | $ | 275 | | $ | 1 | |
Pollution control notes | | | - | | | 307 | |
Senior secured notes | | | 43 | | | 177 | |
Unsecured notes | | | 153 | | | - | |
Common stock | | | 918 | | | - | |
Preferred stock | | | - | | | 30 | |
| | $ | 1,389 | | $ | 515 | |
| | | | | | | |
Short-term borrowings, net | | $ | 1,308 | | $ | 371 | |
FirstEnergy had approximately $2.4 billion of short-term indebtedness as of June 30, 2007 compared to approximately $1.1 billion as of December 31, 2006. This increase resulted from interim funding of FirstEnergy’s $900 million share repurchase program and $300 million pension contribution in the first half of the year. Available bank borrowing capability as of June 30, 2007 included the following:
Borrowing Capability (In millions) | | | |
Short-term credit facilities(1) | | $ | 3,220 | |
Accounts receivable financing facilities | | | 550 | |
Utilized | | | (2,413 | ) |
LOCs | | | (339 | ) |
Net | | $ | 1,018 | |
| | | | |
(1) Includes the $2.75 billion revolving credit facility described below, a $100 million revolving credit facility that expires in December 2009, a $20 million uncommitted line of credit and $350 million bridge loan facilities. |
As of June 30, 2007, the Ohio Companies and Penn had the aggregate capability to issue approximately $2.9 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMB by OE, CEI and TE is 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, CEI and TE to incur additional secured debt not otherwise permitted by a specified exception of up to $463 million, $515 million and $127 million, respectively, as of June 30, 2007. Because JCP&L satisfied the provision of its senior note indenture for the release of all FMBs held as collateral for senior notes in May 2007, it is no longer required to issue FMBs as collateral for senior notes and therefore is not limited as to the amount of senior notes it may issue.
The applicable earnings coverage tests in the respective charters of OE, TE, Penn and JCP&L are currently inoperative. In the event that any of them issues preferred stock in the future, the applicable earnings coverage test will govern the amount of preferred stock that may be issued. CEI, Met-Ed and Penelec do not have similar restrictions and could issue up to the number of preferred shares authorized under their respective charters.
As of June 30, 2007, approximately $1.0 billion of capacity remained unused under an existing FirstEnergy shelf registration statement filed with the SEC in 2003 to support future securities issuances. 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. As of June 30, 2007, OE had approximately $400 million of capacity remaining unused under a shelf registration for unsecured debt securities filed with the SEC in 2006.
FirstEnergy and certain of its subsidiaries are parties to a $2.75 billion five-year revolving credit facility (included in the borrowing capability table above). FirstEnergy may request an increase in the total commitments available under this facility up to a maximum of $3.25 billion. Commitments under the facility are available until August 24, 2011, unless the lenders agree, at the request of the Borrowers, to two additional one-year extensions. Generally, borrowings under the facility must be repaid within 364 days. Available amounts for each Borrower are subject to a specified sub-limit, as well as applicable regulatory and other limitations.
The following table summarizes the borrowing sub-limits for each borrower under the facility, as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations:
| | Revolving | | Regulatory and | |
| | Credit Facility | | Other Short-Term | |
| | | | | |
| | (In millions) | |
FirstEnergy | | $ | 2,750 | | $ | - | (2) |
OE | | | 500 | | | 500 | |
Penn | | | 50 | | | 40 | |
CEI | | | 250 | (3) | | 500 | |
TE | | | 250 | (3) | | 500 | |
JCP&L | | | 425 | | | 431 | |
Met-Ed | | | 250 | | | 250 | (4) |
Penelec | | | 250 | | | 250 | (4) |
FES | | | 250 | | | - | (2) |
ATSI | | | - | (5) | | 50 | |
| (2)
| No regulatory approvals, statutory or charter limitations applicable. |
| (3)
| Borrowing sub-limits for CEI and TE may be increased to up to $500 million by delivering notice
to the administrative agent that such borrower has senior unsecured debt ratings of at least BBB
by S&P and Baa2 by Moody’s.
|
| (4)
| Excluding amounts which may be borrowed under the regulated money pool. |
| (5)
| The borrowing sub-limit for ATSI may be increased up to $100 million by delivering notice to the
administrative agent that either (i) such borrower has senior unsecured debt ratings of at least
BBB- by S&P and Baa3 by Moody’s or (ii) FirstEnergy has guaranteed the obligations of such
borrower under the facility.
|
The revolving credit facility, combined with an aggregate $550 million ($287 million unused as of June 30, 2007) of accounts receivable financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn, are intended to provide liquidity to meet working capital requirements and for other general corporate purposes for FirstEnergy and its subsidiaries.
Under the revolving credit facility, borrowers may request the issuance of LOCs expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit.
The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter. As of June 30, 2007, FirstEnergy and its subsidiaries' debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:
Borrower
| | |
FirstEnergy
| | 61 | % |
OE
| | 48 | % |
Penn
| | 24 | % |
CEI
| | 60 | % |
TE
| | 56 | % |
JCP&L
| | 32 | % |
Met-Ed
| | 46 | % |
Penelec
| | 38 | % |
FES
| | 57 | % |
The revolving credit facility does not contain provisions that either restrict the ability to borrow or accelerate repayment of outstanding advances as a result of any change in credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds borrowed under the facility is related to the credit ratings of the company borrowing the funds.
FirstEnergy's regulated companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy's unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first six months of 2007 was 5.64% for both the regulated and the unregulated companies' money pools.
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 the Companies’ securities ratings as of June 30, 2007. The ratings outlook from Moody’s is stable for FES and positive for all other companies. The ratings outlook from S&P on all securities is stable. The rating outlook from Fitch on CEI and Toledo Edison is positive and stable on all other operating companies.
| | | | | | | | |
| | | | | | | | |
FirstEnergy | | Senior unsecured | | BBB- | | Baa3 | | BBB |
| | | | | | | | |
OE | | Senior unsecured | | BBB- | | Baa2 | | BBB |
| | | | | | | | |
CEI | | Senior secured | | BBB | | Baa2 | | BBB |
| | Senior unsecured | | BBB- | | Baa3 | | BBB- |
| | | | | | | | |
TE | | Senior secured | | BBB | | Baa2 | | BBB |
| | Senior unsecured | | BBB- | | Baa3 | | BBB- |
| | | | | | | | |
Penn | | Senior secured | | BBB+ | | Baa1 | | BBB+ |
| | | | | | | | |
JCP&L | | Senior secured | | BBB+ | | Baa1 | | A- |
| | Senor unsecured | | BBB | | Baa2 | | BBB+ |
| | | | | | | | |
Met-Ed | | Senior unsecured | | BBB | | Baa2 | | BBB |
| | | | | | | | |
Penelec | | Senior unsecured | | BBB | | Baa2 | | BBB |
| | | | | | | | |
FES | | Corporate Credit/Issuer Rating | | BBB | | Baa2 | | |
On February 21, 2007, FirstEnergy made a $700 million equity investment in FES, all of which was subsequently contributed to FGCO and used to pay-down generation asset transfer-related promissory notes owed to the Ohio Companies and Penn. OE used its $500 million of proceeds to repurchase shares of its common stock from FirstEnergy.
On March 27, 2007, CEI issued $250 million of 5.70% unsecured senior notes due 2017. The proceeds of the offering were used to reduce CEI’s short-term borrowings and for general corporate purposes.
On May 21, 2007, JCP&L issued $550 million of senior unsecured debt securities, consisting of $250 million of 5.65% Senior Notes due 2017 and $300 million of 6.15% Senior Notes due 2037. A portion of the proceeds of the offering were used to redeem outstanding FMB of JCP&L comprised of $125 million principal amount of 7.50% series and $150 million principal amount of 6.75% series. On July 1, 2007, JCP&L also redeemed all $12.2 million outstanding principal amount of its remaining series of FMB. In addition, $125 million of proceeds were used to repurchase shares of its common stock from FirstEnergy. The remaining proceeds were used for general corporate purposes.
As described above, on July 13, 2007, FGCO completed the sale and leaseback of a 93.825% undivided interest in Unit 1 of the Bruce Mansfield Generating Plant. Net after-tax proceeds of approximately $1.2 billion to FGCO from the transaction were used to repay short-term borrowings from, and to invest in, the FirstEnergy non-utility money pool. The repayments and investment allowed FES to reduce its investment in that money pool in order to repay approximately $250 million of external bank borrowings and fund a $600 million equity repurchase from FirstEnergy. FirstEnergy used these funds to reduce its external short term borrowings as discussed above.
Cash Flows From Investing Activities
Net cash flows used in investing activities resulted principally from property additions. Energy delivery services expenditures for property additions primarily include expenditures related to transmission and distribution facilities. Capital expenditures by the competitive energy services segment are principally generation-related. The following table summarizes investing activities for the second quarter of 2007 and 2006 by segment:
Summary of Cash Flows | | Property | | | | | | | |
Used for Investing Activities | | Additions | | Investments | | Other | | Total | |
Sources (Uses) | | (In millions) | |
Six Months Ended June 30, 2007 | | | | | | | | | |
| | | | | | | | | | | | | |
Competitive energy services | | | | | | | | | | ) | | | |
| | | | | | | ) | | | | | | ) |
Inter-Segment reconciling items | | | | | | | ) | | | | | | ) |
| | | | | | | | | | ) | | | |
| | | | | | | | | | | | | |
Six Months Ended June 30, 2006 | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Competitive energy services | | | | | | | | | | ) | | | |
| | | | | | | | | | | | | |
Inter-Segment reconciling items | | | | | | | | | | | | | |
| | | | | $ | | | | | | | | |
Net cash used for investing activities in the first six months of 2007 increased by $54 million compared to the same period of 2006. The increase was principally due to a $64 million decrease in cash provided from cash investments, primarily from the use of restricted cash investments to repay debt during 2006. Partially offsetting the decrease in cash provided from cash investments was a $42 million decrease in property additions which reflects the replacement of the steam generators and reactor head at Beaver Valley Unit 1 in 2006.
During the second half of 2007, capital requirements for property additions and capital leases are expected to be $820 million. FirstEnergy and the Companies have additional requirements of approximately $172 million for maturing long-term debt during the remainder of 2007. These cash requirements are expected to be satisfied from a combination of internal cash, short-term credit arrangements, and funds raised in the capital markets.
FirstEnergy's capital spending for the period 2007-2011 is expected to be nearly $7.9 billion (excluding nuclear fuel), of which approximately $1.5 billion applies to 2007. Investments for additional nuclear fuel during the 2007-2011 period are estimated to be approximately $1.2 billion, of which about $95 million applies to 2007. During the same period, FirstEnergy's nuclear fuel investments are expected to be reduced by approximately $804 million and $102 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. These agreements include contract guarantees, surety bonds, and LOCs. Some of the guaranteed contracts contain collateral provisions that are contingent upon FirstEnergy’s credit ratings.
As of June 30, 2007, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $4.1 billion, as summarized below:
| | Maximum | |
Guarantees and Other Assurances | | | |
| | (In millions) | |
FirstEnergy Guarantees of Subsidiaries | | | |
Energy and Energy-Related Contracts (1) | | $ | 800 | |
LOC (2) | | | 864 | |
Other (3) | | | | |
| | | 2,251 | |
| | | | |
Surety Bonds | | | 95 | |
LOC (4)(5) | | | | |
| | | | |
Total Guarantees and Other Assurances | | | | |
| (1)
| Issued for open-ended terms, with a 10-day termination right by FirstEnergy. |
| (2)
| LOC’s issued on behalf of FGCO and NGC in support of pollution
control revenue bonds with various maturities, which are
recognized on FirstEnergy’s consolidated balance sheets.
|
| (3)
| Includes guarantees of $300 million for OVEC obligations and
$80 million for nuclear decommissioning funding assurances.
|
| (4)
| Includes $339 million issued for various terms pursuant to LOC
capacity available under FirstEnergy’s revolving credit facility and
an additional $779 million outstanding in support of pollution
control revenue bonds issued with various maturities on behalf of
FGCO and NGC, which are recognized on FirstEnergy’s
consolidated balance sheets.
|
| (5)
| Includes approximately $194 million pledged in connection with
the sale and leaseback of Beaver Valley Unit 2 by CEI and TE,
$291 million pledged in connection with the sale and leaseback of
Beaver Valley Unit 2 by OE and $134 million pledged in
connection with the sale and leaseback of Perry Unit 1 by OE.
|
FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy 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 its subsidiaries directly involved in these 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 and energy-related contracts is remote.
While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event” the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. As of June 30, 2007, FirstEnergy’s maximum exposure under these collateral provisions was $421 million.
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 also provided an LOC ($27 million as of June 30, 2007), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA.
As described above, on July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in the Bruce Mansfield Plant Unit 1. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES’ lease guaranty.
OFF-BALANCE SHEET ARRANGEMENTS
The Ohio Companies have obligations that are not included on FirstEnergy’s Consolidated Balance Sheets related to the sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are satisfied through operating lease payments. As of June 30, 2007, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $1.1 billion.
FirstEnergy has equity ownership interests in certain businesses that are accounted for using 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 Guarantees and Other Assurances 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 oversight for risk management activities throughout the company.
Commodity Price Risk
FirstEnergy is exposed to financial and market risks resulting from the fluctuation of interest rates and commodity prices -- electricity, energy transmission, natural gas, coal, nuclear fuel and emission allowances. 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. Derivatives that fall within the scope of SFAS 133 must be recorded at their fair value and marked to market. The majority of FirstEnergy’s derivative hedging contracts qualify for the normal purchase and normal sale exception under SFAS 133 and are therefore excluded from the tables below. Contracts that are not exempt from such treatment include certain power purchase agreements with NUG entities that were structured pursuant to the Public Utility Regulatory Policies Act of 1978. These non-trading contracts are adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for above-market costs. The change in the fair value of commodity derivative contracts related to energy production during the three months and six months ended June 30, 2007 is summarized in the following table:
| Three Months Ended | | Six Months Ended | |
Increase (Decrease) in the Fair Value | June 30, 2007 | | June 30, 2007 | |
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 liability at beginning of period | $ | (1,028 | ) | $ | 1 | | $ | (1,027 | ) | $ | (1,140 | ) | $ | (17 | ) | $ | (1,157 | ) |
Additions/change in value of existing contracts | | 91 | | | (11 | ) | | 80 | | | 197 | | | (6 | ) | | 191 | |
Settled contracts | | 92 | | | (2 | ) | | 90 | | | 98 | | | 11 | | | 109 | |
Outstanding net liability at end of period (1) | | (845 | ) | | (12 | ) | | (857 | ) | | (845 | ) | | (12 | ) | | (857 | ) |
| | | | | | | | | | | | | | | | | | |
Non-commodity Net Liabilities at End of Period: | | | | | | | | | | | | | | | | | | |
Interest rate swaps (2) | | - | | | (24 | ) | | (24 | ) | | - | | | (24 | ) | | (24 | ) |
Net Liabilities - Derivative Contracts at End of Period | $ | (845 | ) | $ | (36 | ) | $ | (881 | ) | $ | (845 | ) | $ | (36 | ) | $ | (881 | ) |
| | | | | | | | | | | | | | | | | | |
Impact of Changes in Commodity Derivative Contracts(3) | | | | | | | | | | | | | | | | | | |
Income Statement effects (pre-tax) | $ | (2 | ) | $ | - | | $ | (2 | ) | $ | - | | $ | - | | $ | - | |
Balance Sheet effects: | | | | | | | | | | | | | | | | | | |
Other comprehensive income (pre-tax) | $ | - | | $ | (13 | ) | $ | (13 | ) | $ | - | | $ | 5 | | $ | 5 | |
Regulatory assets (net) | $ | (185 | ) | $ | - | | $ | (185 | ) | $ | (295 | ) | $ | - | | $ | (295 | ) |
(1)
| Includes $841 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset. |
| (2)
| Interest rate swaps are treated as cash flow or fair value hedges (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 June 30, 2007 as follows: |
Balance Sheet Classification | | Non-Hedge | | Hedge | | Total | |
| | (In millions) | |
| | | | | | | |
| | | | | | | | | | |
| | | | | | | ) | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Other non-current liabilities | | | | ) | | | | | | |
| | | | | | | | | | |
| | | | ) | | | | | | ) |
The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, 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 commodity derivative contracts as of June 30, 2007 are summarized by year in the following table:
Source of Information | | | | | | | | | | | | | | | |
- Fair Value by Contract Year | | | | | | | | | | | | | | | |
| | (In millions) | |
Prices actively quoted(2) | | $ | (1 | ) | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | (1 | ) |
Other external sources(3) | | | (112 | ) | | (221 | ) | | (172 | ) | | (146 | ) | | - | | | - | | | (651 | ) |
Prices based on models | | | | | | | | | | | | | | | | ) | | | ) | | | ) |
Total(4) | | | | ) | | | ) | | | ) | | | ) | | | ) | | | ) | | | ) |
(1) For the last two quarters of 2007.
(2) Exchange traded.
(3) Broker quote sheets.
| (4)
| Includes $841 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset. |
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 its derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of June 30, 2007. Based on derivative contracts held as of June 30, 2007, an adverse 10% change in commodity prices would decrease net income by approximately $9 million during the next 12 months.
Interest Rate Swap Agreements- Fair Value Hedges
FirstEnergy utilizes fixed-for-floating interest rate swap agreements as part of its ongoing effort to manage the interest rate risk associated with its debt portfolio. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues – protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates and interest payment dates match those of the underlying obligations. During the first six months of 2007, FirstEnergy paid $8 million to terminate swaps with a notional amount $150 million as its subsidiary redeemed the associated hedged debt. The loss was recognized as interest expense during the current period. As of June 30, 2007, the debt underlying the $600 million outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 5.11%, which the swaps have converted to a current weighted average variable rate of 6.06%.
| | June 30, 2007 | | December 31, 2006 | |
| | Notional | | Maturity | | Fair | | Notional | | Maturity | | Fair | |
| | Amount | | Date | | Value | | Amount | | Date | | Value | |
| | (In millions) | |
Fair value hedges | | $ | | | | | | $ | | | $ | | | | | | $ | | |
| | | | | | | | | | ) | | | | | | | | | |
| | | | | | | | | | ) | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
Forward Starting Swap Agreements - Cash Flow Hedges
FirstEnergy utilizes forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with the anticipated future issuances of fixed-rate, long-term debt securities for one or more of its consolidated subsidiaries in 2007 and 2008. 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. During the first six months of 2007, FirstEnergy terminated forward swaps with an aggregate notional value of $950 million. FirstEnergy paid $2 million in cash related to the terminations, which will be recognized over the terms of the associated future debt. There was no ineffective portion associated with the loss. As of June 30, 2007, FirstEnergy had outstanding forward swaps with an aggregate notional amount of $250 million and an aggregate fair value of $6 million.
| | June 30, 2007 | | December 31, 2006 | |
| | Notional | | Maturity | | Fair | | Notional | | Maturity | | Fair | |
| | Amount | | Date | | Value | | Amount | | Date | | Value | |
| | (In millions) | |
Cash flow hedges | | $ | | | | | | $ | | | $ | | | | | | $ | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | ) |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
Equity Price Risk
Included in nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $1.4 billion as of June 30, 2007 and December 31, 2006. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $136 million reduction in fair value as of June 30, 2007.
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 June 30, 2007, the largest credit concentration with one party (currently rated investment grade) represented 11% of FirstEnergy‘s total credit risk. Within FirstEnergy’s unregulated energy subsidiaries, 99% of credit exposures, net of collateral and reserves, were with investment-grade counterparties as of June 30, 2007.
Outlook
State Regulatory Matters
In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry restructuring contain similar provisions that are reflected in the Companies' respective state regulatory plans. These provisions include:
· | restructuring the electric generation business and allowing the Companies' customers to select a competitive electric generation supplier other than the Companies; |
| |
· | establishing or defining the PLR obligations to customers in the Companies' service areas; |
| |
· | providing the Companies with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market; |
| |
· | itemizing (unbundling) the price of electricity into its component elements – including generation, transmission, distribution and stranded costs recovery charges; |
| |
· | continuing regulation of the Companies' transmission and distribution systems; and |
| |
· | requiring corporate separation of regulated and unregulated business activities. |
The Companies and ATSI 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. Regulatory assets that do not earn a current return totaled approximately $219 million as of June 30, 2007 (JCP&L - $103 million, Met-Ed - $34 million and Penelec - $82 million). Regulatory assets not earning a current return will be recovered by 2014 for JCP&L and by 2020 for Met-Ed and Penelec. The following table discloses regulatory assets by company:
| | June 30, | | December 31, | | Increase | |
Regulatory Assets* | | 2007 | | 2006 | | (Decrease) | |
| | (In millions) | |
OE | | $ | 733 | | $ | 741 | | $ | (8 | ) |
CEI | | | 863 | | | 855 | | | 8 | |
TE | | | 230 | | | 248 | | | (18 | ) |
JCP&L | | | 1,825 | | | 2,152 | | | (327 | ) |
Met-Ed | | | 464 | | | 409 | | | 55 | |
ATSI | | | | | | | | | | |
Total | | | | | | | | | | ) |
* | Penelec had net regulatory liabilities of approximately $74 million
and $96 million as of June 30, 2007 and December 31, 2006,
respectively. These net regulatory liabilities are included in Other
Non-current Liabilities on the Consolidated Balance Sheets.
|
Regulatory assets by source are as follows:
| | June 30, | | December 31, | | Increase | |
Regulatory Assets By Source | | 2007 | | 2006 | | (Decrease) | |
| | (In millions) | |
Regulatory transition costs | | $ | 2,731 | | $ | 3,266 | | $ | (535 | ) |
Customer shopping incentives | | | 562 | | | 603 | | | (41 | ) |
Customer receivables for future income taxes | | | 259 | | | 217 | | | 42 | |
Societal benefits charge | | | (2 | ) | | 11 | | | (13 | ) |
Loss on reacquired debt | | | 59 | | | 43 | | | 16 | |
Employee postretirement benefits | | | 43 | | | 47 | | | (4 | ) |
Nuclear decommissioning, decontamination | | | | | | | | | | |
and spent fuel disposal costs | | | (114 | ) | | (145 | ) | | 31 | |
Asset removal costs | | | (173 | ) | | (168 | ) | | (5 | ) |
Property losses and unrecovered plant costs | | | 13 | | | 19 | | | (6 | ) |
MISO/PJM transmission costs | | | 292 | | | 213 | | | 79 | |
Fuel costs - RCP | | | 154 | | | 113 | | | 41 | |
Distribution costs - RCP | | | 246 | | | 155 | | | 91 | |
Other | | | | | | | | | | |
Total | | | | | | | | | | ) |
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 equipment or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability entities may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future, which could require additional, material expenditures.
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. In 2004, the NJBPU adopted an MOU that set out specific tasks related to service reliability to be performed by JCP&L and a timetable for completion and endorsed JCP&L’s ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a stipulation that incorporates the final report of an SRM who made recommendations on appropriate courses of action necessary to ensure system-wide reliability. The stipulation also incorporates the Executive Summary and Recommendation portions of the final report of a focused audit of JCP&L’s Planning and Operations and Maintenance programs and practices. On February 11, 2005, JCP&L met with the DRA to discuss reliability improvements. The SRM completed his work and issued his final report to the NJBPU on June 1, 2006. JCP&L filed a comprehensive response to the NJBPU on July 14, 2006. JCP&L continues to file compliance reports reflecting activities associated with the MOU and stipulation.
The EPACT served partly to amend the Federal Power Act with Section 215, which requires that an ERO establish and enforce reliability standards for the bulk-power system, subject to review of the FERC. Subsequently, the FERC certified NERC as the ERO, approved NERC's Compliance Monitoring and Enforcement Program and approved a set of reliability standards, which became mandatory and enforceable on June 18, 2007 with penalties and sanctions for noncompliance. The FERC also approved a delegation agreement between NERC and ReliabilityFirst Corporation, one of eight Regional Entities that carry out enforcement for NERC. All of FirstEnergy’s facilities are located within the ReliabilityFirst region.
While the FERC approved 83 of the 107 reliability standards proposed by NERC, the FERC has directed NERC to submit improvements to 56 of them, endorsing NERC's process for developing reliability standards and its associated work plan. On May 4, 2007, NERC also submitted 24 proposed Violation Risk Factors. The FERC issued an order approving 22 of those factors on June 26, 2007. Further, NERC adopted eight cyber security standards that became effective on June 1, 2006 and filed them with the FERC for approval. On December 11, 2006, the FERC Staff provided its preliminary assessment of the cyber security standards and cited various deficiencies in the proposed standards. Numerous parties, including FirstEnergy, provided comments on the assessment by February 12, 2007. The standards remain pending before the FERC. On July 20, 2007, the FERC issued a NOPR proposing to adopt eight Critical Infrastructure Protection Reliability Standards. Comments will not be due to the FERC until September or October of 2007.
FirstEnergy believes it is in compliance with all current NERC reliability standards. However, based upon a review of the FERC's guidance to NERC in its March 16, 2007 Final Rule on Mandatory Reliability Standards, it appears that the FERC will eventually adopt stricter NERC reliability standards than those just approved. The financial impact of complying with the new standards cannot be determined at this time. However, the EPACT required that all prudent costs incurred to comply with the new reliability standards be recovered in rates. If FirstEnergy is unable to meet the reliability standards for its bulk power system in the future, it could have a material adverse effect on FirstEnergy’s and its subsidiaries’ financial condition, results of operations and cash flows.
On April 18-20, 2007, ReliabilityFirst performed a routine compliance audit of FirstEnergy's bulk-power system within the Midwest ISO region and found FirstEnergy to be in full compliance with all audited reliability standards. Similarly, ReliabilityFirst has scheduled a compliance audit of FirstEnergy's bulk-power system within the PJM region in 2008. FirstEnergy does not expect any material adverse impact to its financial condition as a result of these audits.
Ohio
On October 21, 2003, the Ohio Companies filed their RSP case with the PUCO. 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 CBP. The RSP was intended to establish generation service rates beginning January 1, 2006, in response to the PUCO’s concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming the PUCO's order in all respects, except it remanded back to the PUCO the matter of ensuring the availability of sufficient means for customer participation in the marketplace. The RSP contained a provision that permitted the Ohio Companies to withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies have 30 days from the final order or decision to provide notice of termination. On July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate a Proceeding on Remand. In their Request, the Ohio Companies provided notice of termination to those provisions of the RSP subject to termination, subject to being withdrawn, and also set forth a framework for addressing the Supreme Court of Ohio’s findings on customer participation. If the PUCO approves a resolution to the issues raised by the Supreme Court of Ohio that is acceptable to the Ohio Companies, the Ohio Companies’ termination will be withdrawn and considered to be null and void. On July 20, 2006, the OCC and NOAC also submitted to the PUCO a conceptual proposal addressing the issue raised by the Supreme Court of Ohio. On July 26, 2006, the PUCO issued an Entry directing the Ohio Companies to file a plan in a new docket to address the Court’s concern. The Ohio Companies filed their RSP Remand CBP on September 29, 2006. Initial comments were filed on January 12, 2007 and reply comments were filed on January 29, 2007. In their reply comments the Ohio Companies described the highlights of a new tariff offering they would be willing to make available to customers that would allow customers to purchase renewable energy certificates associated with a renewable generation source, subject to PUCO approval. On May 29, 2007, the Ohio Companies, together with the PUCO Staff and the OCC, filed a stipulation with the PUCO agreeing to offer a standard bid product and a green resource tariff product. The stipulation is currently pending before the PUCO. No further proceedings are scheduled at this time.
The Ohio Companies filed an application and stipulation with the PUCO on September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On November 4, 2005, the Ohio Companies filed a supplemental stipulation with the PUCO, which constituted an additional component of the RCP filed on September 9, 2005. On January 4, 2006, the PUCO approved, with modifications, the Ohio Companies’ RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. The following table provides the estimated net amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) under the RCP for the period 2007 through 2010:
Amortization Period | | OE | | CEI | | TE | | Total Ohio | |
| | (In millions) | |
| | | | | | | | | | | | | |
2007 | | $ | 179 | | $ | 108 | | $ | 93 | | $ | 380 | |
2008 | | | 208 | | | 124 | | | 119 | | | 451 | |
2009 | | | - | | | 216 | | | - | | | 216 | |
2010 | | | | | | | | | | | | | |
Total Amortization | | | | | | | | | | | | | |
On August 31, 2005, the PUCO approved a rider recovery mechanism through which the Ohio Companies may recover all MISO transmission and ancillary service related costs incurred during each year ending June 30. Pursuant to the PUCO’s order, the Ohio Companies, on May 1, 2007, filed revised riders, which became effective on July 1, 2007. The revised riders represent an increase over the amounts collected through the 2006 riders of approximately $64 million annually. If it is subsequently determined by the PUCO that adjustments to the rider as filed are necessary, such adjustments, with carrying costs, will be incorporated into the 2008 transmission rider filing.
On May 8, 2007, the Ohio Companies filed with the PUCO a notice of intent to file for an increase in electric distribution rates. The Ohio Companies filed the application and rate request with the PUCO on June 7, 2007. The requested increase is expected to be more than offset by the elimination or reduction of transition charges at the time the rates go into effect and would result in lowering the overall non-generation portion of the bill for most Ohio customers. The distribution rate increases reflect capital expenditures since the Ohio Companies’ last distribution rate proceedings, increases in operating and maintenance expenses and recovery of regulatory assets created by deferrals that were approved in prior cases. On August 6, 2007, the Ohio Companies provided an update filing supporting a distribution rate increase of $332 million to the PUCO to establish the test period data that will be used as the basis for setting rates in that proceeding. The PUCO Staff is expected to issue its report in the case in the fourth quarter of 2007 with evidentiary hearings to follow in late 2007. The PUCO order is expected to be issued by March 9, 2008. The new rates, subject to evidentiary hearings and approval at the PUCO, would become effective January 1, 2009 for OE and TE, and approximately May 2009 for CEI.
On July 10, 2007, the Ohio Companies filed an application with the PUCO requesting approval of a comprehensive supply plan for providing generation service to customers who do not purchase electricity from an alternative supplier, beginning January 1, 2009. The proposed competitive bidding process would average the results of multiple bidding sessions conducted at different times during the year. The final price per kilowatt-hour would reflect an average of the prices resulting from all bids. In their filing, the Ohio Companies offered two alternatives for structuring the bids, either by customer class or a “slice-of-system” approach. The proposal provides the PUCO with an option to phase in generation price increases for residential tariff groups who would experience a change in their average total price of 15 percent or more. The Ohio Companies requested that the PUCO issue an order by November 1, 2007, to provide sufficient time to conduct the bidding process. The PUCO has scheduled a technical conference for August 16, 2007.
Pennsylvania
Met-Ed and Penelec have been purchasing a portion of their PLR requirements from FES through a partial requirements wholesale power sales agreement and various amendments. Under these agreements, FES retained 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. The FES agreements have reduced Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR capacity and energy costs during the term of these agreements with FES.
On April 7, 2006, the parties entered into a tolling agreement that arose from FES’ notice to Met-Ed and Penelec that FES elected to exercise its right to terminate the partial requirements agreement effective midnight December 31, 2006. On November 29, 2006, Met-Ed, Penelec and FES agreed to suspend the April 7 tolling agreement pending resolution of the PPUC’s proceedings regarding the Met-Ed and Penelec comprehensive transition rate cases filed April 10, 2006, described below. Separately, on September 26, 2006, Met-Ed and Penelec successfully conducted a competitive RFP for a portion of their PLR obligation for the period December 1, 2006 through December 31, 2008. FES was one of the successful bidders in that RFP process and on September 26, 2006 entered into a supplier master agreement to supply a certain portion of Met-Ed’s and Penelec’s PLR requirements at market prices that substantially exceed the fixed price in the partial requirements agreements.
Based on the outcome of the 2006 comprehensive transition rate filing, as described below, Met-Ed, Penelec and FES agreed to restate the partial requirements power sales agreement effective January 1, 2007. The restated agreement incorporates the same fixed price for residual capacity and energy supplied by FES as in the prior arrangements between the parties, and automatically extends for successive one year terms unless any party gives 60 days’ notice prior to the end of the year. The restated agreement also allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy thus sold to the extent needed for Met-Ed and Penelec to satisfy their PLR obligations. The parties also have separately terminated the tolling, suspension and supplier master agreements in connection with the restatement of the partial requirements agreement. Accordingly, the energy that would have been supplied under the supplier master agreement will now be provided under the restated partial requirements agreement. The fixed price under the restated agreement is expected to remain below wholesale market prices during the term of the agreement.
If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for its fixed income securities. Based on the PPUC’s January 11, 2007 order described below, if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC.
Met-Ed and Penelec made a comprehensive rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals had been approved, annual revenues would have increased by $216 million and $157 million, respectively. That filing included, among other things, a request to charge customers for an increasing amount of market-priced power procured through a CBP as the amount of supply provided under the then existing FES agreement was to be phased out in accordance with the April 7, 2006 tolling agreement described above. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs, but only for those costs incurred during 2006. In this rate filing, Met-Ed and Penelec also requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the FirstEnergy and GPU merger proceeding, related to the quantification and allocation of the merger savings, with the comprehensive transmission rate filing case.
The PPUC entered its Opinion and Order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, when new transmission rates were effective, and determined that no merger savings from prior years should be considered in determining customers’ rates. The request for increases in generation supply rates was denied as were the requested changes in NUG expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased Met-Ed’s and Penelec’s distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission expenses and the transmission deferral. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and, in January 2007, Met-Ed and Penelec recognized income of $15 million and $12 million, respectively, to establish regulatory assets for those previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million). Met-Ed and Penelec filed a Petition for Reconsideration on January 26, 2007 on the issues of consolidated tax savings and rate of return on equity. Other parties filed Petitions for Reconsideration on transmission (including congestion), transmission deferrals and rate design issues. On February 8, 2007, the PPUC entered an order granting Met-Ed’s, Penelec’s and the other parties’ petitions for procedural purposes. Due to that ruling, the period for appeals to the Commonwealth Court of Pennsylvania was tolled until 30 days after the PPUC entered a subsequent order ruling on the substantive issues raised in the petitions. On March 1, 2007, the PPUC issued three orders: (1) a tentative order regarding the reconsideration by the PPUC of its own order; (2) an order denying the Petitions for Reconsideration of Met-Ed, Penelec and the OCA and denying in part and accepting in part MEIUG’s and PICA’s Petition for Reconsideration; and (3) an order approving the Compliance filing. Comments to the PPUC for reconsideration of its order were filed on March 8, 2007, and the PPUC ruled on the reconsideration on April 13, 2007, making minor changes to rate design as agreed upon by Met-Ed, Penelec and certain other parties.
On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase. The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. On June 19, 2007, initial briefs were filed by all parties. Responsive briefs are due August 20, 2007, with reply briefs due September 4, 2007. Oral arguments are expected to take place in late 2007 or early 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the financial condition and results of operations of Met-Ed, Penelec and FirstEnergy.
As of June 30, 2007, Met-Ed's and Penelec's unrecovered regulatory deferrals pursuant to the 2006 comprehensive transition rate case, the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation were $493 million and $127 million, respectively. $82 million of Penelec’s deferral is subject to final resolution of an IRS settlement associated with NUG trust fund proceeds. During the PPUC’s annual audit of Met-Ed’s and Penelec’s NUG stranded cost balances in 2006, it noted a modification to the NUG purchased power stranded cost accounting methodology made by Met-Ed and Penelec. On August 18, 2006, a PPUC Order was entered requiring Met-Ed and Penelec to reflect the deferred NUG cost balances as if the stranded cost accounting methodology modification had not been implemented. As a result of this PPUC order, Met-Ed recognized a pre-tax charge of approximately $10.3 million in the third quarter of 2006, representing incremental costs deferred under the revised methodology in 2005. Met-Ed and Penelec continue to believe that the stranded cost accounting methodology modification is appropriate and on August 24, 2006 filed a petition with the PPUC pursuant to its order for authorization to reflect the stranded cost accounting methodology modification effective January 1, 1999. Hearings on this petition were held in late February 2007 and briefing was completed on March 28, 2007. The ALJ’s initial decision was issued on May 3, 2007 and denied Met-Ed's and Penelec’s request to modify their NUG stranded cost accounting methodology. The companies filed exceptions to the initial decision on May 23, 2007 and replies to those exceptions were filed on June 4, 2007. It is not known when the PPUC may issue a final decision in this matter.
On May 2, 2007, Penn filed a plan with the PPUC for the procurement of PLR supply from June 2008 through May 2011. The filing proposes multiple, competitive RFPs with staggered delivery periods for fixed-price, tranche-based, pay as bid PLR supply to the residential and commercial classes. The proposal phases out existing promotional rates and eliminates the declining block and the demand components on generation rates for residential and commercial customers. The industrial class PLR service would be provided through an hourly-priced service provided by Penn. Quarterly reconciliation of the differences between the costs of supply and revenues from customers is also proposed. The PPUC is requested to act on the proposal no later than November 2007 for the initial RFP to take place in January 2008.
On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation programs to meet demand growth, a requirement that electric distribution companies acquire power that results in the “lowest reasonable rate on a long-term basis," the utilization of micro-grids and an optional three year phase-in of rate increases. On July 17, 2007 the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long-term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy will be convened in mid-September 2007 to consider other aspects of the EIS. The final form of any legislation arising from the special legislative session is uncertain. Consequently, FirstEnergy is unable to predict what impact, if any, such legislation may have on its operations.
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 NUGC rates and market sales of NUG energy and capacity. As of June 30, 2007, the accumulated deferred cost balance totaled approximately $392 million.
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 DRA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. A schedule for further NJBPU proceedings has not yet been set.
On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that would prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. These regulations are not expected to materially impact FirstEnergy or JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. Comments on the alternative proposal were submitted on June 15, 2006. On November 3, 2006, the Staff circulated a revised draft proposal to interested stakeholders. Another revised draft was circulated by the NJBPU Staff on February 8, 2007.
New Jersey statutes require that the state periodically undertake a planning process, known as the Energy Master Plan (EMP), to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated with the issuance of a proposed set of objectives which, as to electricity, included the following:
·Reduce the total projected electricity demand by 20% by 2020;
·Meet 22.5% of New Jersey’s electricity needs with renewable energy resources by that date;
·Reduce air pollution related to energy use;
·Encourage and maintain economic growth and development;
· Achieve a 20% reduction in both Customer Average Interruption Duration Index and System Average Interruption Frequency Index by 2020;
· Unit prices for electricity should remain no more than +5% of the regional average price (region includes New York, New Jersey, Pennsylvania, Delaware, Maryland
and the District of Columbia); and
·Eliminate transmission congestion by 2020.
Comments on the objectives and participation in the development of the EMP have been solicited and a number of working groups have been formed to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. EMP working groups addressing (1) energy efficiency and demand response, (2) renewables, (3) reliability, and (4) pricing issues have completed their assigned tasks of data gathering and analysis and have provided reports to the EMP Committee. Public stakeholder meetings were held in the fall of 2006 and in early 2007, and further public meetings are expected later in 2007. A final draft of the EMP is expected to be presented to the Governor in late 2007. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation may have on its operations or those of JCP&L.
On February 13, 2007, the NJBPU Staff informally issued a draft proposal relating to changes to the regulations addressing electric distribution service reliability and quality standards. Meetings between the NJBPU Staff and interested stakeholders to discuss the proposal were held and additional, revised informal proposals were subsequently circulated by the Staff. On August 1, 2007, the NJBPU approved publication of a formal proposal in the New Jersey Register, which proposal will be subsequently considered by the NJBPU following a period for public comment. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such regulations may have on its operations or those of JCP&L.
FERC Matters
On November 18, 2004, the FERC issued an order eliminating the RTOR for transmission service between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a SECA mechanism to recover lost RTOR revenues during a 16-month transition period from load serving entities. The FERC issued orders in 2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES participated in the FERC hearings held in May 2006 concerning the calculation and imposition of the SECA charges. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by the RTOs and transmission owners, ruling on various issues and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order could be issued by the FERC in the third quarter of 2007.
On January 31, 2005, certain PJM transmission owners made three filings with the FERC 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. Hearings were held and numerous parties appeared and litigated various issues; including American Electric Power Company, Inc., which filed in opposition proposing to create a "postage stamp" rate for high voltage transmission facilities across PJM. At the conclusion of the hearings, the ALJ issued an initial decision adopting the FERC Trial Staff’s position that the cost of all PJM transmission facilities should be recovered through a postage stamp rate.The ALJ recommended an April 1, 2006 effective date for this change in rate design. Numerous parties, including FirstEnergy, submitted briefs opposing the ALJ’s decision and recommendations. On April 19, 2007, the FERC issued an order rejecting the ALJ’s findings and recommendations in nearly every respect. The FERC found that the PJM transmission owners’ existing “license plate” rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be socialized throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. Nevertheless, the FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.
On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 Order. Subsequently, FirstEnergy and other parties filed pleadings opposing the requests for rehearing. The FERC’s Orders on PJM rate design, if sustained on rehearing and appeal, will prevent the allocation of the cost of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reduce future transmission costs shifting to the JCP&L, Met-Ed and Penelec zones.
On August 1, 2007, a number of filings were made with the FERC by transmission owning utilities in the MISO and PJM footprint that could affect the transmission rates paid by FirstEnergy’s operating companies and FES.
FirstEnergy joined in a filing made by the MISO transmission owners that would maintain the existing “license plate” rates for transmission service within MISO provided over existing transmission facilities. FirstEnergy also joined in a filing made by both the MISO and PJM transmission owners proposing to maintain existing transmission rates between MISO and PJM. If accepted by the FERC, these filings would not affect the rates charged to load-serving FirstEnergy affiliates for transmission service over existing transmission facilities. In a related filing, MISO and MISO transmission owners requested that the current MISO pricing for new transmission facilities that spreads 20% of the cost of new 345 kV transmission facilities across the entire MISO footprint be maintained. All of these filings were supported by the majority of transmission owners in either MISO or PJM.
The Midwest Stand-Alone Transmission Companies made a filing under Section 205 of the Federal Power Act requesting that 100% of the cost of new qualifying 345 kV transmission facilities be spread throughout the entire MISO footprint. If adopted by the FERC, this proposal would shift a greater portion of the cost of new 345 kV transmission facilities to the FirstEnergy footprint, and increase the transmission rates paid by load-serving FirstEnergy affiliates.
American Electric Power (AEP) filed a letter with the FERC Commissioners stating its intent to file a complaint under Section 206 of the Federal Power Act challenging the justness and reasonableness of the rate designs underlying the MISO and PJM transmission tariffs. AEP will propose the adoption of a regional rate design that is expected to reallocate the cost of both existing and new high voltage transmission facilities across the combined MISO and PJM footprint. Based upon the position advocated by AEP in a related proceeding, the AEP proposal is expected to result in a greater allocation of costs to FirstEnergy transmission zones in MISO and PJM. If approved by the FERC, AEP’s proposal would increase the transmission rates paid by load-serving FirstEnergy affiliates.
Any increase in rates charged for transmission service to FirstEnergy affiliates is dependent upon the outcome of these proceedings at FERC. All or some of these proceedings may be consolidated by the FERC and set for hearing. The outcome of these cases cannot be predicted. Any material adverse impact on FirstEnergy would depend upon the ability of the load-serving FirstEnergy affiliates to recover increased transmission costs in their retail rates. FirstEnergy believes that current retail rate mechanisms in place for PLR service for the Ohio Companies and for Met-Ed and Penelec would permit them to pass through increased transmission charges in their retail rates. Increased transmission charges in the JCP&L and Penn transmission zones would be the responsibility of competitive electric retail suppliers, including FES.
On February 15, 2007, MISO filed documents with the FERC to establish a market-based, competitive ancillary services market. MISO contends that the filing will integrate operating reserves into MISO’s existing day-ahead and real-time settlements process, incorporate opportunity costs into these markets, address scarcity pricing through the implementation of a demand curve methodology, foster demand response in the provision of operating reserves, and provide for various efficiencies and optimization with regard to generation dispatch. The filing also proposes amendments to existing documents to provide for the transfer of balancing functions from existing local balancing authorities to MISO. MISO will then carry out this reliability function as the NERC-certified balancing authority for the MISO region with implementation in the third or fourth quarter of 2008. FirstEnergy filed comments on March 23, 2007, supporting the ancillary service market in concept, but proposing certain changes in MISO’s proposal. MISO requested FERC action on its filing by June 2007 and the FERC issued its Order June 22, 2007. The FERC found MISO’s filing to be deficient in two key areas: (1) MISO has not submitted a market power analysis in support of its proposed Ancillary Services Market and (2) MISO has not submitted a readiness plan to ensure reliability during the transition from the current reserve and regulation system managed by the individual Balancing Authorities to a centralized Ancillary Services Market managed by MISO. MISO was ordered to remedy these deficiencies and the FERC provided more guidance on other issues brought up in filings by stakeholders to assist MISO to re-file a complete proposal. This Order should facilitate MISO’s timetable to incorporate final revisions to ensure a market start in Spring 2008. FirstEnergy will be participating in working groups and task forces to ensure the Spring 2008 implementation of the Ancillary Services Market.
On February 16, 2007, the FERC issued a final rule that revises its decade-old open access transmission regulations and policies. The FERC explained that the final rule is intended to strengthen non-discriminatory access to the transmission grid, facilitate FERC enforcement, and provide for a more open and coordinated transmission planning process. The final rule became effective on May 14, 2007. MISO, PJM and ATSI will be filing revised tariffs to comply with the FERC’s order. As a market participant in both MISO and PJM, FirstEnergy will conform its business practices to each respective revised tariff.
Environmental Matters
FirstEnergy accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in FirstEnergy’s determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.
Clean Air Act Compliance
FirstEnergy is required to meet federally-approved SO2 emissions 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. FirstEnergy believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.
The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006 alleging violations to various sections of the Clean Air Act. FirstEnergy has disputed those alleged violations based on its Clean Air Act permit, the Ohio SIP and other information provided at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order, and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding the opacity limit applicable to the common stack for Bay Shore Units 2, 3 and 4.
FirstEnergy complies 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 at FirstEnergy's facilities. The EPA's NOX Transport Rule imposes uniform reductions of NOX emissions (an approximate 85% reduction in utility plant NOX emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOX emissions are contributing significantly to ozone levels in the eastern United States. FirstEnergy believes its facilities are also complying with the NOX budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.
On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal Clean Air Act, alleging violations of air pollution laws at the Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Mansfield Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On July 25, 2007, FirstEnergy and PennFuture entered into a Tolling and Confidentiality Agreement that provides for a 60-day negotiation period during which the parties have agreed to not file a lawsuit.
National Ambient Air Quality Standards
In July 1997, the EPA promulgated changes in the NAAQS for ozone and fine particulate matter. In March 2005, the EPA finalized the CAIR 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 non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR allowed each affected state until 2006 to develop implementing regulations to achieve additional reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2). FirstEnergy's Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be subject to caps on SO2 and NOX emissions, whereas its New Jersey fossil-fired generation facility will be subject to only a cap on 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 FirstEnergy operates affected facilities.
Mercury Emissions
In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases. Initially, mercury emissions will be capped nationally at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program). Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. However, the final rules give states substantial discretion in developing rules to implement these programs. In addition, both the CAIR and the CAMR 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 and will depend on how they are ultimately implemented by the states in which FirstEnergy operates affected facilities.
The model rules for both CAIR and CAMR contemplate an input-based methodology to allocate allowances to affected facilities. Under this approach, allowances would be allocated based on the amount of fuel consumed by the affected sources. FirstEnergy would prefer an output-based generation-neutral methodology in which allowances are allocated based on megawatts of power produced, allowing new and non-emitting generating facilities (including renewables and nuclear) to be entitled to their proportionate share of the allowances. Consequently, FirstEnergy will be disadvantaged if these model rules were implemented as proposed because FirstEnergy’s substantial reliance on non-emitting (largely nuclear) generation is not recognized under the input-based allocation.
Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap and trade approach as in the CAMR, but rather follows a command and control approach imposing emission limits on individual sources. Pennsylvania’s mercury regulation would deprive FES of mercury emission allowances that were to be allocated to the Mansfield Plant under the CAMR and that would otherwise be available for achieving FirstEnergy system-wide compliance. It is anticipated that compliance with these regulations, if approved by the EPA and implemented, would not require the addition of mercury controls at the Mansfield Plant, FirstEnergy’s only coal-fired Pennsylvania power plant, until 2015, if at all.
W. H. Sammis Plant
In 1999 and 2000, the EPA issued NOV or compliance orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which was owned at that time by OE and Penn, and is now owned by FGCO. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as the New Source Review, or NSR, cases.
On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation. This settlement agreement, which is in the form of a consent decree, was approved by the court on July 11, 2005, and requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FirstEnergy fails to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FirstEnergy could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation settlement agreement are currently estimated to be $1.7 billion for 2007 through 2011 ($400 million of which is expected to be spent during 2007, with the largest portion of the remaining $1.3 billion expected to be spent in 2008 and 2009).
The Sammis NSR Litigation consent decree also requires FirstEnergy to spend up to $25 million toward environmentally beneficial projects, $14 million of which is satisfied by entering into 93 MW (or 23 MW if federal tax credits are not applicable) of wind energy purchased power agreements with a 20-year term. An initial 16 MW of the 93 MW consent decree obligation was satisfied during 2006.
Climate Change
In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Kyoto Protocol in 1998 but it failed to receive the two-thirds vote required for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. At the international level, efforts have begun to develop climate change agreements for post-2012 GHG reductions. The EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.
At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.
On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the Clean Air Act. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the Clean Air Act to regulate “air pollutants” from those and other facilities. Also on April 2, 2007, the United States Supreme Court ruled that changes in annual emissions (in tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must be used to determine whether an emissions increase triggers NSR. Subsequently, the EPA proposed to change the NSR regulations, on May 8, 2007, to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR.
FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions could require significant capital and other expenditures. The CO2 emissions per KWH of electricity generated by FirstEnergy is lower than many regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy's plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FirstEnergy's operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.
On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality when(when aquatic organisms are pinned against screens or other parts of a cooling water intake system,system) and entrainment which(which occurs when aquatic life is drawn into a facility's cooling water system.system). On January 26, 2007, the federalUnited States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment (BPJ) to minimize impacts on fish and shellfish from cooling water intake structures. On April 14, 2008, the Supreme Court of the United States granted a petition for a writ of certiorari to review certain aspects of the Second Circuit’s decision. FirstEnergy is evaluatingstudying various control options and their costs and effectiveness. Depending on the outcomeresults of such studies, the outcome of the Supreme Court’s review of the Second Circuit’s decision, the EPA’s further rulemaking and any action taken by the states exercising BPJ, the future costcosts 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 nonhazardousnon-hazardous waste.
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of June 30, 2007,March 31, 2008, FirstEnergy had approximately $1.5$2.0 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and Perry.TMI-2. As part of the application to the NRC to transfer the ownership of these nuclear facilitiesDavis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy agreed to contribute another $80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy plans(and Exelon for TMI-1 as it relates to seekthe timing of the decommissioning of TMI-2) seeks for these facilities.
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 aremay be liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of June 30, 2007,March 31, 2008, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. In addition,Total liabilities of approximately $92 million (JCP&L - $65 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $25 million) have been accrued through March 31, 2008. Included in the total for JCP&L hasare accrued liabilities of approximately $56 million for environmental remediation of former manufactured gas plants in New Jersey; those costswhich are being recovered by JCP&L through a non-bypassable SBC. Total liabilities of approximately $88 million have been accrued through June 30, 2007.
Other Legal Proceedings(C) OTHER LEGAL PROCEEDINGS
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FirstEnergy and its subsidiaries. The other material items not otherwise discussed above are described below.
Power Outages and Related Litigation
In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four of New Jersey’s electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the JCP&L territory.
In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision onin 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, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, onin March 7, 2007, reversed the decertification of the Red Bank class and remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied onin May 9, 2007. Proceedings are continuing in the Superior Court.Court and a case management conference with the presiding Judge is scheduled for June 13, 2008. FirstEnergy is vigorously defending this class action but is unable to predict the outcome of this matter. No liability has been accrued as of June 30, 2007.March 31, 2008.
On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. – Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s Web site (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy is also proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional material expenditures.
FirstEnergy companies also are defending four separate complaint cases before the PUCO relating to the August 14, 2003 power outages. Two of those cases were originally filed in Ohio State courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In these cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Two other pending PUCO complaint cases were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of these cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and American Electric Power Company, Inc., as well) for claims paid to insureds for damages allegedly arising as a result of the loss of power on August 14, 2003. A fifth case in which a carrier sought reimbursement for claims paid to insureds was voluntarily dismissed by the claimant in April 2007. A sixth case involving the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003 was dismissed. The four cases were consolidated for hearing by the PUCO in an order dated March 7, 2006. In that order the PUCO also limited the litigation to service-related claims by customers of the Ohio operating companies; dismissed FirstEnergy as a defendant; and ruled that the U.S.-Canada Power System Outage Task Force Report was not admissible into evidence. In response to a motion for rehearing filed by one of the claimants, the PUCO ruled on April 26, 2006 that the insurance company claimants, as insurers, may prosecute their claims in their name so long as they also identify the underlying insured entities and the Ohio utilities that provide their service. The PUCO denied all other motions for rehearing. The plaintiffs in each case have since filed amended complaints and the named FirstEnergy companies have answered and also have filed a motion to dismiss each action. On September 27, 2006, the PUCO dismissed certain parties and claims and otherwise ordered the complaints to go forward to hearing. The cases have been set for hearing on January 8, 2008.
On October 10, 2006, various insurance carriers refiled a complaint in Cuyahoga County Common Pleas Court seeking reimbursement for claims paid to numerous insureds who allegedly suffered losses as a result of the August 14, 2003 outages. All of the insureds appear to be non-customers. The plaintiff insurance companies are the same claimants in one of the pending PUCO cases. FirstEnergy, the Ohio Companies and Penn were served on October 27, 2006. On January 18, 2007, the Court granted the Companies’ motion to dismiss the case and they have not been appealed. However, on April 25, 2007, one of the insurance carriers refiled the complaint naming only FirstEnergy as the defendant. On July 30, 2007, the case was voluntarily dismissed. No estimate of potential liability is available for any of these cases.
FirstEnergy was also named, along with several other entities, in a complaint in New Jersey State Court. The allegations against FirstEnergy were based, in part, on an alleged failure to protect the citizens of Jersey City from an electrical power outage. None of FirstEnergy’s subsidiaries serve customers in Jersey City. A responsive pleading has been filed. On April 28, 2006, the Court granted FirstEnergy's motion to dismiss. The plaintiff has not appealed.
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. Although FirstEnergy is unable to predict the impact of these proceedings, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.
Nuclear Plant Matters
On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the preceding two years and the licensee's failure to take prompt and corrective action. On April 4, 2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Nuclear Power Plant operated "in a manner that preserved public health and safety" even though it remained under heightened NRC oversight. During the public meeting and in the annual assessment, the NRC indicated that additional inspections would continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix.
On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance at the Perry Nuclear Power Plant 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. By two letters dated March 2, 2007, the NRC closed the CAL commitments for Perry, the two outstanding white findings, and crosscutting issues. Moreover, the NRC removed Perry from the Multiple Degraded Cornerstone Column of the NRC Action Matrix and placed the plant in the Licensee Response Column (regular agency oversight).
On April 30, 2007, the UCS filed a petition with the NRC under Section 2.206 of the NRC’s regulations based on a report prepared at FENOC’s request by expert witnesses for an insurance arbitration. In December 2006, the expert witnesses for FENOC completed a report that analyzed the crack growth rates in control rod drive mechanism penetrations and wastage of the former reactor pressure vessel head at Davis-Besse. Citing the findings in the expert witness' report, the Section 2.206 petition requested that: (1) Davis-Besse be immediately shut down; (2) that the NRC conduct an independent review of the consultant's report and that all pressurized water reactors be shut down until remedial actions can be implemented; and (3) Davis-Besse’s operating license be revoked.
In a letter dated May 18, 2007, the NRC stated that the “current reactor pressure vessel (RPV) head inspection requirements are adequate to detect RPV degradation issues before they result in significant corrosion.” The NRC also indicated that, “no immediate safety concern exists at Davis-Besse” and denied UCS’ first demand (to shut down the facility). On June 18, 2007, the NRC Petition Review Board indicated that the agency had initially denied petitioner’s other requests, and provided an opportunity for UCS to provide additional information prior to the final determination. By letter dated July 12, 2007, the NRC denied the remainder of the UCS petition.
On May 14, 2007, the Office of Enforcement of the NRC issued a Demand for InformationDFI to FENOC, following FENOC’s reply to an April 2, 2007 NRC request for information, about thetwo reports prepared by expert witnesses’ report and another report.witnesses for an insurance arbitration (the insurance claim was subsequently withdrawn by FirstEnergy in December 2007) related to Davis-Besse. The NRC indicated that this information iswas needed for the NRC “to determine whether an Order or other action should be taken pursuant to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to operate its licensed facilities in accordance with the terms of its licenses and the Commission’s regulations.” FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s Demand for InformationDFI reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. The NRC heldFENOC submitted a public meeting on June 27, 2007 with FENOC to discuss FENOC’ssupplemental response to the Demand for Information. In follow-up discussions, FENOC was requested to provide supplemental information to clarifyclarifying certain aspects of the Demand for Information response and provide additional details regarding plans to implement the commitments made therein. FENOC submitted this supplementalDFI response to the NRC on July 16, 2007. FirstEnergy can provide no assurances asOn August 15, 2007, the NRC issued a confirmatory order imposing these commitments. FENOC must inform the NRC’s Office of Enforcement after it completes the key commitments embodied in the NRC’s order. FENOC’s compliance with these commitments is subject to the ultimate resolution of this matter.future NRC review.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.
On 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 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. On April 5, 2007, the Court rejected the plaintiffs’ request to certify this case as a class action and, accordingly, did not appoint the plaintiffs as class representatives or their counsel as class counsel. On July 30, 2007, plaintiffs’ counsel voluntarily withdrew their request for reconsideration of the April 5, 2007 Court order denying class certification and the Court heard oral argument on the plaintiff’s motion to amend their complaint which OE has opposed.
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 arbitration panel decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, a federal district court granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005. JCP&L intends to re-file an appeal in federal district court once the damages associated with this case are identified at an individual employee level. JCP&L recognized a liability for the potential $16 million award in 2005. The parties met on June 27, 2007 before an arbitrator to assert their positions regarding the finality of damages. A hearing before the arbitrator is set for September 7, 2007.
The union employees at the W. H. Sammis Plant have been working without a labor contract since July 1, 2007. The union expects to vote on a new contract on August 9, 2007. While it is expected the union will ratify a new contract, FirstEnergy has a strike mitigation plan ready in the event of a strike.
If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.
NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
| SFAS 159 – “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115”
|
In February 2007, the FASB issued SFAS 159, which provides companies with an option to report selected financial assets and liabilities at fair value. This Statement requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company’s choice to use fair value on its earnings. The Standard also requires companies to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. This guidance does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS 157and SFAS 107. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. FirstEnergy is currently evaluating the impact of this Statement on its financial statements.
SFAS 157 – “Fair Value Measurements”
In September 2006, the FASB issued SFAS 157 that establishes how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under GAAP. This Statement addresses the need for increased consistency and comparability in fair value measurements and for expanded disclosures about fair value measurements. The key changes to current practice are: (1) the definition of fair value which focuses on an exit price rather than entry price; (2) the methods used to measure fair value such as emphasis that fair value is a market-based measurement, not an entity-specific measurement, as well as the inclusion of an adjustment for risk, restrictions and credit standing; and (3) the expanded disclosures about fair value measurements. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. FirstEnergy is currently evaluating the impact of this Statement on its financial statements.
EITF 06-11 – “Accounting for Income Tax Benefits of Dividends or Share-based Payment Awards”
In June 2007, the FASB released EITF 06-11, which provides guidance on the appropriate accounting for income tax benefits related to dividends earned on nonvested share units that are charged to retained earnings under SFAS 123(R). The consensus requires that an entity recognize the realized tax benefit associated with the dividends on nonvested shares as an increase to additional paid-in capital (APIC). This amount should be included in the APIC pool, which is to be used when an entity’s estimate of forfeitures increases or actual forfeitures exceed its estimates, at which time the tax benefits in the APIC pool would be reclassified to the income statement. The consensus is effective for income tax benefits of dividends declared during fiscal years beginning after December 15, 2007. EITF 06-11 is not expected to have a material effect on FirstEnergy’s financial statements.
OHIO EDISON COMPANY | |
| | | | | | | | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | | | | | | | |
| | Three Months Ended | | | Six Months Ended | |
| | June 30, | | | June 30, | |
| | | | | | | | | | | | |
| | 2007 | | | 2006 | | | 2007 | | | 2006 | |
| | | | | | | | | | | | |
STATEMENTS OF INCOME | | (In thousands) | |
| | | | | | | | | | | | |
REVENUES: | | | | | | | | | | | | |
Electric sales | | $ | 569,430 | | | $ | 546,176 | | | $ | 1,163,774 | | | $ | 1,103,405 | |
Excise tax collections | | | 27,351 | | | | 26,916 | | | | 58,605 | | | | 55,890 | |
Total revenues | | | 596,781 | | | | 573,092 | | | | 1,222,379 | | | | 1,159,295 | |
| | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | |
Fuel | | | 2,312 | | | | 2,821 | | | | 5,327 | | | | 5,772 | |
Purchased power | | | 322,639 | | | | 293,033 | | | | 672,491 | | | | 576,053 | |
Nuclear operating costs | | | 47,654 | | | | 43,506 | | | | 89,168 | | | | 84,590 | |
Other operating costs | | | 97,120 | | | | 91,604 | | | | 185,606 | | | | 182,414 | |
Provision for depreciation | | | 19,110 | | | | 17,547 | | | | 37,958 | | | | 35,563 | |
Amortization of regulatory assets | | | 46,126 | | | | 43,444 | | | | 91,543 | | | | 97,305 | |
Deferral of new regulatory assets | | | (54,344 | ) | | | (42,083 | ) | | | (90,993 | ) | | | (78,323 | ) |
General taxes | | | 45,393 | | | | 43,931 | | | | 95,138 | | | | 89,826 | |
Total expenses | | | 526,010 | | | | 493,803 | | | | 1,086,238 | | | | 993,200 | |
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 70,771 | | | | 79,289 | | | | 136,141 | | | | 166,095 | |
| | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | |
Investment income | | | 21,346 | | | | 32,818 | | | | 47,976 | | | | 65,860 | |
Miscellaneous income (expense) | | | 2,319 | | | | (1,001 | ) | | | 2,692 | | | | (804 | ) |
Interest expense | | | (21,416 | ) | | | (17,366 | ) | | | (42,438 | ) | | | (35,598 | ) |
Capitalized interest | | | 152 | | | | 643 | | | | 262 | | | | 1,134 | |
Subsidiary's preferred stock dividend requirements | | | - | | | | (155 | ) | | | - | | | | (311 | ) |
Total other income | | | 2,401 | | | | 14,939 | | | | 8,492 | | | | 30,281 | |
| | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 73,172 | | | | 94,228 | | | | 144,633 | | | | 196,376 | |
| | | | | | | | | | | | | | | | |
INCOME TAXES | | | 27,559 | | | | 35,019 | | | | 44,985 | | | | 73,337 | |
| | | | | | | | | | | | | | | | |
NET INCOME | | | 45,613 | | | | 59,209 | | | | 99,648 | | | | 123,039 | |
| | | | | | | | | | | | | | | | |
PREFERRED STOCK DIVIDEND REQUIREMENTS AND | | | | | | | | | | | | | | | | |
REDEMPTION PREMIUM | | | - | | | | 3,587 | | | | - | | | | 4,246 | |
| | | | | | | | | | | | | | | | |
EARNINGS ON COMMON STOCK | | $ | 45,613 | | | $ | 55,622 | | | $ | 99,648 | | | $ | 118,793 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | �� | | | | |
STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
NET INCOME | | $ | 45,613 | | | $ | 59,209 | | | $ | 99,648 | | | $ | 123,039 | |
| | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | |
Pension and other postretirment benefits | | | (3,424 | ) | | | - | | | | (6,847 | ) | | | - | |
Change in unrealized gain on available for sale securities | | | 5,099 | | | | (4,063 | ) | | | 4,973 | | | | 1,672 | |
Other comprehensive income (loss) | | | 1,675 | | | | (4,063 | ) | | | (1,874 | ) | | | 1,672 | |
Income tax expense (benefit) related to other | | | | | | | | | | | | | | | | |
comprehensive income | | | 388 | | | | (1,466 | ) | | | (1,115 | ) | | | 603 | |
Other comprehensive income (loss), net of tax | | | 1,287 | | | | (2,597 | ) | | | (759 | ) | | | 1,069 | |
| | | | | | | | | | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 46,900 | | | $ | 56,612 | | | $ | 98,889 | | | $ | 124,108 | |
| | | | | | | | | | | | | | | | |
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) | |
| | June 30, | | | December 31, | |
| | 2007 | | | 2006 | |
| | (In thousands) | |
ASSETS | | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 899 | | | $ | 712 | |
Receivables- | | | | | | | | |
Customers (less accumulated provisions of $8,990,000 and $15,033,000, | | | | | | | | |
respectively, for uncollectible accounts) | | | 263,316 | | | | 234,781 | |
Associated companies | | | 173,200 | | | | 141,084 | |
Other (less accumulated provisions of $5,090,000 and $1,985,000, | | | | | | | | |
respectively, for uncollectible accounts) | | | 13,380 | | | | 13,496 | |
Notes receivable from associated companies | | | 367,971 | | | | 458,647 | |
Prepayments and other | | | 20,482 | | | | 13,606 | |
| | | 839,248 | | | | 862,326 | |
UTILITY PLANT: | | | | | | | | |
In service | | | 2,690,282 | | | | 2,632,207 | |
Less - Accumulated provision for depreciation | | | 1,043,183 | | | | 1,021,918 | |
| | | 1,647,099 | | | | 1,610,289 | |
Construction work in progress | | | 37,019 | | | | 42,016 | |
| | | 1,684,118 | | | | 1,652,305 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
Long-term notes receivable from associated companies | | | 639,227 | | | | 1,219,325 | |
Investment in lease obligation bonds | | | 274,248 | | | | 291,393 | |
Nuclear plant decommissioning trusts | | | 125,906 | | | | 118,209 | |
Other | | | 37,970 | | | | 38,160 | |
| | | 1,077,351 | | | | 1,667,087 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Regulatory assets | | | 733,147 | | | | 741,564 | |
Pension assets | | | 100,682 | | | | 68,420 | |
Property taxes | | | 60,080 | | | | 60,080 | |
Unamortized sale and leaseback costs | | | 47,634 | | | | 50,136 | |
Other | | | 53,914 | | | | 18,696 | |
| | | 995,457 | | | | 938,896 | |
| | $ | 4,596,174 | | | $ | 5,120,614 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Currently payable long-term debt | | $ | 335,812 | | | $ | 159,852 | |
Short-term borrowings- | | | | | | | | |
Associated companies | | | - | | | | 113,987 | |
Other | | | 119,943 | | | | 3,097 | |
Accounts payable- | | | | | | | | |
Associated companies | | | 120,493 | | | | 115,252 | |
Other | | | 17,907 | | | | 13,068 | |
Accrued taxes | | | 94,615 | | | | 187,306 | |
Accrued interest | | | 23,406 | | | | 24,712 | |
Other | | | 61,611 | | | | 64,519 | |
| | | 773,787 | | | | 681,793 | |
CAPITALIZATION: | | | | | | | | |
Common stockholder's equity- | | | | | | | | |
Common stock, without par value, authorized 175,000,000 shares - | | | | | | | | |
60 and 80 shares outstanding, respectively | | | 1,208,498 | | | | 1,708,441 | |
Accumulated other comprehensive income | | | 2,449 | | | | 3,208 | |
Retained earnings | | | 309,656 | | | | 260,736 | |
Total common stockholder's equity | | | 1,520,603 | | | | 1,972,385 | |
Long-term debt and other long-term obligations | | | 937,676 | | | | 1,118,576 | |
| | | 2,458,279 | | | | 3,090,961 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Accumulated deferred income taxes | | | 717,373 | | | | 674,288 | |
Accumulated deferred investment tax credits | | | 18,748 | | | | 20,532 | |
Asset retirement obligations | | | 90,801 | | | | 88,223 | |
Retirement benefits | | | 162,078 | | | | 167,379 | |
Deferred revenues - electric service programs | | | 67,566 | | | | 86,710 | |
Other | | | 307,542 | | | | 310,728 | |
| | | 1,364,108 | | | | 1,347,860 | |
COMMITMENTS AND CONTINGENCIES (Note 9) | | | | | | | | |
| | $ | 4,596,174 | | | $ | 5,120,614 | |
| | | | | | | | |
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) | |
| | | | | | |
| | Six Months Ended | |
| | June 30, | |
| | 2007 | | | 2006 | |
| | (In thousands) | |
| | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 99,648 | | | $ | 123,039 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
Provision for depreciation | | | 37,958 | | | | 35,563 | |
Amortization of regulatory assets | | | 91,543 | | | | 97,305 | |
Deferral of new regulatory assets | | | (90,993 | ) | | | (78,323 | ) |
Amortization of lease costs | | | (4,367 | ) | | | (4,334 | ) |
Deferred income taxes and investment tax credits, net | | | 3,017 | | | | (17,351 | ) |
Accrued compensation and retirement benefits | | | (25,829 | ) | | | 930 | |
Pension trust contribution | | | (20,261 | ) | | | - | |
Decrease (increase) in operating assets- | | | | | | | | |
Receivables | | | (60,535 | ) | | | 66,215 | |
Prepayments and other current assets | | | (3,162 | ) | | | (7,913 | ) |
Increase (decrease) in operating liabilities- | | | | | | | | |
Accounts payable | | | 10,080 | | | | (45,894 | ) |
Accrued taxes | | | (87,969 | ) | | | 9,378 | |
Accrued interest | | | (1,306 | ) | | | (1,183 | ) |
Electric service prepayment programs | | | (19,144 | ) | | | (16,838 | ) |
Other | | | 2,854 | | | | (8,051 | ) |
Net cash provided from (used for) operating activities | | | (68,466 | ) | | | 152,543 | |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Long-term debt | | | - | | | | 599,778 | |
Short-term borrowings, net | | | 2,859 | | | | - | |
Redemptions and Repayments- | | | | | | | | |
Common stock | | | (500,000 | ) | | | - | |
Long-term debt | | | (1,181 | ) | | | (145,316 | ) |
Short-term borrowings, net | | | - | | | | (176,708 | ) |
Dividend Payments- | | | | | | | | |
Common stock | | | (50,000 | ) | | | (35,000 | ) |
Preferred stock | | | - | | | | (1,317 | ) |
Net cash provided from (used for) financing activities | | | (548,322 | ) | | | 241,437 | |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (66,607 | ) | | | (63,294 | ) |
Sales of investment securities held in trusts | | | 22,225 | | | | 29,168 | |
Purchases of investment securities held in trusts | | | (24,187 | ) | | | (29,860 | ) |
Loan repayments from associated companies, net | | | 670,774 | | | | 112,840 | |
Cash investments | | | - | | | | 78,248 | |
Other | | | 14,770 | | | | 23,281 | |
Net cash provided from investing activities | | | 616,975 | | | | 150,383 | |
| | | | | | | | |
Net increase in cash and cash equivalents | | | 187 | | | | 544,363 | |
Cash and cash equivalents at beginning of period | | | 712 | | | | 929 | |
Cash and cash equivalents at end of period | | $ | 899 | | | $ | 545,292 | |
| | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part |
of these statements. | | | | | | | | |
Report of Independent Registered Public Accounting Firm
To the Stockholder 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 June 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2007 and 2006 and the consolidated statement of cash flows for the six-month periods ended June 30, 2007 and 2006. 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 (United States), 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, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006, and conditional asset retirement obligations as of December 31, 2005 as discussed in Note 3, Note 2(G) and Note 11 to the consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
August 6, 2007
OHIO EDISON COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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. OE also provides generation services to those customers electing to retain OE as their power supplier. OE’s power supply requirements are provided by FES – an affiliated company.
Results of Operations
Earnings on common stock in the second quarter of 2007 decreased to $46 million from $56 million in the second quarter of 2006. In the first six months of 2007, earnings on common stock decreased to $100 million from $119 million in the same period of 2006. The decrease in earnings in both periods primarily resulted from higher purchased power costs and lower other income, partially offset by higher electric sales revenues and the deferral of new regulatory assets.
Revenues
Revenues increased by $24 million or 4.1% in the second quarter of 2007 compared with the same period in 2006, primarily due to higher retail generation revenues of $15 million and wholesale generation revenues of $5 million.
Higher retail generation revenues from residential customers reflected increased sales volume and the impact of higher average unit prices. Weather conditions in the second quarter of 2007 compared to the same period in 2006 contributed to the higher KWH sales to residential customers (heating degree days increased 7.0% and 8.5% and cooling degree days increased by 74.5% and 83.8% in OE’s and Penn’s service territories, respectively). Commercial retail generation revenues increased primarily due to higher average unit prices, partially offset by reduced KWH sales. Average prices increased due to the higher generation prices that went into effect in January 2007 under Penn’s competitive RFP process. Retail generation revenues from the industrial sector decreased primarily due to an increase in customer shopping in the second quarter of 2007 as compared to the same period in 2006. The percentage of shopping customers increased to 27.6 percent during the second quarter of 2007 from 15.2 percent in the second quarter of 2006.
Revenues increased by $63 million or 5.4% in the first six months of 2007 compared with the same period in 2006, primarily due to higher retail generation revenues of $63 million and wholesale generation revenues of $2 million, partially offset by decreases in revenues from distribution throughput of $13 million.
Retail generation revenues increased for residential and commercial customers due to the higher prices and increased sales volume. Weather conditions in the first six months of 2007 compared to the same period in 2006 contributed to the higher KWH sales to residential and commercial customers (heating degree days increased 13.9% and 10.7% in OE’s and Penn’s service territories, respectively). Retail generation revenues from the industrial sector decreased primarily due to an increase in customer shopping in the first six months of 2007 as compared to the same period in 2006. The percentage of shopping customers increased to 26.9 percent in the first six months of 2007 from 15.9 percent in the first six months of 2006.
Changes in retail electric generation KWH sales and revenues in the second quarter and first six months of 2007 from the corresponding periods of 2006 are summarized in the following tables:
Retail Generation KWH Sales | | Three Months | | Six Months | |
Increase (Decrease) | | | | | |
Residential | | | 9.0 | % | | 10.8 | % |
Commercial | | | (1.3 | )% | | 0.7 | % |
Industrial | | | (16.8 | )% | | (14.9 | )% |
Net Decrease in Generation Sales | | | (4.3 | )% | | (1.7 | )% |
Retail Generation Revenues | | Three Months | | Six Months | |
Increase (Decrease) | | (In millions) | |
Residential | | $ | 24 | | $ | 61 | |
Commercial | | | 6 | | | 22 | |
Industrial | | | (15 | ) | | (20 | ) |
Net Increase in Generation Revenues | | $ | 15 | | $ | 63 | |
Increased revenues from distribution throughput to residential customers reflected the impact of weather conditions described above in the second quarter and first six months of 2007 as compared to the same periods in 2006, partially offset by lower composite unit prices. Reduced revenues from distribution throughput to commercial customers in the second quarter and first six months of 2007 resulted from lower unit prices, partially offset by increased KWH deliveries. Revenues from distribution throughput to industrial customers decreased in the second quarter and first six months of 2007 as a result of lower unit prices and reduced KWH deliveries.
Changes in distribution KWH deliveries and revenues in the second quarter and first six months of 2007 from the corresponding periods of 2006 are summarized in the following tables.
Changes in Distribution KWH Deliveries | | Three Months | | Six Months | |
Increase (Decrease) | | | | | |
Residential | | | 7.5 | % | | 8.7 | % |
Commercial | | | 4.7 | % | | 4.6 | % |
Industrial | | | (2.5 | )% | | (2.0 | )% |
Net Increase in Distribution Deliveries | | | 2.7 | % | | 3.5 | % |
Changes in Distribution Revenues | | Three Months | | Six Months | |
Increase (Decrease) | | (In millions) | |
Residential | | $ | 4 | | $ | 3 | |
Commercial | | | (1 | ) | | (5 | ) |
Industrial | | | (3 | ) | | (11 | ) |
Changes in Distribution Revenues | | $ | - | | $ | (13 | ) |
Expenses
Total expenses increased by $32 million in the second quarter of 2007 and $93 million in the first six months of 2007 from the same periods of 2006. The following table presents changes from the prior year by expense category.
Expenses – Changes | | Three Months | | Six Months |
Increase (Decrease) | | (In millions) |
Purchased power costs | | $ | 30 | | $ | 97 | |
Nuclear operating costs | | | 4 | | | 4 | |
Other operating costs | | | 5 | | | 3 | |
Provision for depreciation | | | 1 | | | 2 | |
Amortization of regulatory assets | | | 3 | | | (5 | ) |
Deferral of new regulatory assets | | | (12 | ) | | (13 | ) |
General taxes | | | 1 | | | 5 | |
Net Increase in Expenses | | $ | 32 | | $ | 93 | |
Higher purchased power costs in the second quarter and first six months of 2007 primarily reflected higher unit prices under Penn’s competitive RFP process and OE’s PSA with FES. The increase in nuclear operating costs during the second quarter and first six months of 2007 was due to expenses related to the second quarter 2007 nuclear refueling outage at the Perry Plant. The increase in other operating costs during the second quarter of 2007 was primarily due to higher transmission expenses related to MISO operations, partially offset by lower employee benefit expenses. Lower amortization of regulatory assets for the first six months of 2007 was due to the completion of the generation-related transition cost amortization under OE’s and Penn’s respective transition plans at the end of January 2006. The decreases in expense related to the deferral of new regulatory assets for the second quarter of 2007 and first six months of 2007 were primarily due to increases in MISO cost deferrals and related interest. General taxes were higher in the first six months of 2007 as compared to the same period last year as a result of higher real and personal property taxes and KWH excise taxes.
Other Income
Other income decreased $13 million in the second quarter of 2007 and $22 million in the first six months of 2007 as compared with the same periods of 2006, primarily due to reductions in interest income on notes receivable resulting from principal payments from associated companies. Higher interest expense in the second quarter and first six months of 2007 also contributed to the decrease in other income in both periods of 2007 and was largely due to OE’s issuance of $600 million of long-term debt in June 2006, partially offset by debt redemptions that have occurred since the second quarter of 2006.
Income Taxes
In the first six months of 2007, OE’s income taxes included a $7.2 million adjustment related to an inter-company federal tax allocation arrangement between FirstEnergy and its subsidiaries.
Capital Resources and Liquidity
During 2007, OE expects to meet its contractual obligations primarily with cash from operations and short-term credit arrangements. Borrowing capacity under OE’s credit facilities is available to manage its working capital requirements.
Changes in Cash Position
OE had $899,000 of cash and cash equivalents as of June 30, 2007 compared with $712,000 as of December 31, 2006. The major sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Net cash provided from operating activities in the first six months of 2007 and 2006 were as follows:
| | Six Months Ended June 30, | |
| | 2007 | | 2006 | |
| | (In millions) | |
| | | | | | | |
Non-cash charges (credits) | | | | ) | | | |
Pension trust contribution | | | | ) | | | |
Working capital and other | | | | ) | | | |
Net cash provided from (used for) operating activities | | | | ) | | | |
The changes in net income and non-cash charges are described above under “Results of Operations.” The decrease from working capital changes primarily reflects changes in accounts receivable of $127 million and accrued taxes of $97 million, partially offset by changes in accounts payable of $56 million.
Cash Flows From Financing Activities
In the first six months of 2007, net cash used for financing activities was $548 million compared to $241 million provided from financing activities in the same period last year. This change primarily resulted from a $500 million repurchase of common stock from FirstEnergy, a $276 million net decrease in new financing activity and a $15 million increase in common stock dividends to FirstEnergy.
OE had approximately $369 million of cash and temporary cash investments (which include short-term notes receivable from associated companies) and $120 million of short-term indebtedness as of June 30, 2007. OE has authorization from the PUCO to incur short-term debt of up to $500 million through bank facilities and the utility money pool. Penn has authorization from the FERC to incur short-term debt up to its charter limit of $39 million as of June 30, 2007, and also has access to bank facilities and the utility money pool.
In February 2007, FES made a $562 million payment on its fossil generation asset transfer notes owed to OE and Penn. OE used $500 million of the proceeds to repurchase shares of its common stock from FirstEnergy.
See the “Financing Capability” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for additional discussion of OE’s financing capabilities.
Cash Flows From Investing Activities
Net cash provided from investing activities increased $467 million in the first six months of 2007 from the same period in 2006. The increase resulted primarily from a $558 million increase in loan repayments from associated companies (including the $562 million payment from FES described above), partially offset by a $78 million change in cash investments.
During the second half of 2007, OE’s capital spending is expected to be approximately $70 million. OE has additional requirements of approximately $3 million for maturing long-term debt during that period. These cash requirements are expected to be satisfied from a combination of cash from operations and short-term credit arrangements. OE’s capital spending for the period 2007-2011 is expected to be about $769 million, of which approximately $139 million applies to 2007.
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. As of June 30, 2007, the present value of these operating lease commitments, net of trust investments, was $619 million.
Equity Price Risk
Included in OE’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $82 million and $80 million as of June 30, 2007 and December 31, 2006, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in an $8 million reduction in fair value as of June 30, 2007.
Regulatory Matters
See the “Regulatory Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of regulatory matters applicable to OE.
Environmental Matters
See the “Environmental Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of environmental matters applicable to OE.
Other Legal Proceedings
See the “Other Legal Proceedings” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other legal proceedings applicable to OE.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to OE.
.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | |
| | | | | | | | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | | | | | | | |
| | Three Months Ended | | | Six Months Ended | |
| | June 30, | | | June 30, | |
| | | | | | | | | | | | |
| | 2007 | | | 2006 | | | 2007 | | | 2006 | |
| | (In thousands) | |
| | | | | | | | | | | | |
REVENUES: | | | | | | | | | | | | |
Electric sales | | $ | 433,014 | | | $ | 416,690 | | | $ | 855,819 | | | $ | 807,189 | |
Excise tax collections | | | 16,468 | | | | 15,681 | | | | 34,495 | | | | 32,992 | |
Total revenues | | | 449,482 | | | | 432,371 | | | | 890,314 | | | | 840,181 | |
| | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | |
Fuel | | | 14,332 | | | | 13,413 | | | | 27,523 | | | | 26,976 | |
Purchased power | | | 178,669 | | | | 157,941 | | | | 359,326 | | | | 301,711 | |
Other operating costs | | | 83,075 | | | | 68,436 | | | | 158,026 | | | | 141,331 | |
Provision for depreciation | | | 18,713 | | | | 11,050 | | | | 37,181 | | | | 28,251 | |
Amortization of regulatory assets | | | 35,047 | | | | 29,476 | | | | 68,176 | | | | 61,006 | |
Deferral of new regulatory assets | | | (43,059 | ) | | | (31,697 | ) | | | (77,016 | ) | | | (62,223 | ) |
General taxes | | | 34,098 | | | | 31,510 | | | | 72,992 | | | | 66,580 | |
Total expenses | | | 320,875 | | | | 280,129 | | | | 646,208 | | | | 563,632 | |
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 128,607 | | | | 152,242 | | | | 244,106 | | | | 276,549 | |
| | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | |
Investment income | | | 16,324 | | | | 24,674 | | | | 34,011 | | | | 51,610 | |
Miscellaneous income | | | 3,226 | | | | 5,642 | | | | 3,957 | | | | 5,396 | |
Interest expense | | | (37,267 | ) | | | (34,634 | ) | | | (73,007 | ) | | | (69,366 | ) |
Capitalized interest | | | 141 | | | | 837 | | | | 346 | | | | 1,510 | |
Total other expense | | | (17,576 | ) | | | (3,481 | ) | | | (34,693 | ) | | | (10,850 | ) |
| | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 111,031 | | | | 148,761 | | | | 209,413 | | | | 265,699 | |
| | | | | | | | | | | | | | | | |
INCOME TAXES | | | 42,082 | | | | 57,709 | | | | 76,915 | | | | 102,234 | |
| | | | | | | | | | | | | | | | |
NET INCOME | | | 68,949 | | | | 91,052 | | | | 132,498 | | | | 163,465 | |
| | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME: | | | | | | | | | | | | | | | | |
Pension and other postretirement benefits | | | 1,203 | | | | - | | | | 2,405 | | | | - | |
Income tax expense related to other comprehensive income | | | 357 | | | | - | | | | 712 | | | | - | |
Other comprehensive income, net of tax | | | 846 | | | | - | | | | 1,693 | | | | - | |
| | | | | | | | | | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 69,795 | | | $ | 91,052 | | | $ | 134,191 | | | $ | 163,465 | |
| | | | | | | | | | | | | | | | |
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) | |
| | June 30, | | | December 31, | |
| | 2007 | | | 2006 | |
| | (In thousands) | |
ASSETS | | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 236 | | | $ | 221 | |
Receivables- | | | | | | | | |
Customers (less accumulated provisions of $8,554,000 and $6,783,000 | | | | | |
respectively, for uncollectible accounts) | | | 290,711 | | | | 245,193 | |
Associated companies | | | 59,852 | | | | 249,735 | |
Other | | | 12,775 | | | | 14,240 | |
Notes receivable from associated companies | | | 24,898 | | | | 27,191 | |
Prepayments and other | | | 2,002 | | | | 2,314 | |
| | | 390,474 | | | | 538,894 | |
UTILITY PLANT: | | | | | | | | |
In service | | | 2,183,308 | | | | 2,136,766 | |
Less - Accumulated provision for depreciation | | | 839,003 | | | | 819,633 | |
| | | 1,344,305 | | | | 1,317,133 | |
Construction work in progress | | | 46,543 | | | | 46,385 | |
| | | 1,390,848 | | | | 1,363,518 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
Long-term notes receivable from associated companies | | | 353,293 | | | | 486,634 | |
Investment in lessor notes | | | 463,436 | | | | 519,611 | |
Other | | | 10,316 | | | | 13,426 | |
| | | 827,045 | | | | 1,019,671 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Goodwill | | | 1,688,521 | | | | 1,688,521 | |
Regulatory assets | | | 862,758 | | | | 854,588 | |
Pension assets | | | 15,124 | | | | - | |
Property taxes | | | 65,000 | | | | 65,000 | |
Other | | | 51,028 | | | | 33,306 | |
| | | 2,682,431 | | | | 2,641,415 | |
| | $ | 5,290,798 | | | $ | 5,563,498 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Currently payable long-term debt | | $ | 120,597 | | | $ | 120,569 | |
Short-term borrowings- | | | | | | | | |
Associated companies | | | 179,892 | | | | 218,134 | |
Accounts payable- | | | | | | | | |
Associated companies | | | 71,407 | | | | 365,678 | |
Other | | | 6,517 | | | | 7,194 | |
Accrued taxes | | | 88,277 | | | | 128,829 | |
Accrued interest | | | 22,150 | | | | 19,033 | |
Lease market valuation liability | | | 58,750 | | | | 60,200 | |
Other | | | 37,473 | | | | 52,101 | |
| | | 585,063 | | | | 971,738 | |
| | | | | | | | |
CAPITALIZATION: | | | | | | | | |
Common stockholder's equity- | | | | | | | | |
Common stock, without par value, authorized 105,000,000 shares - | | | | | | | | |
67,930,743 shares outstanding | | | 860,206 | | | | 860,133 | |
Accumulated other comprehensive loss | | | (102,738 | ) | | | (104,431 | ) |
Retained earnings | | | 741,439 | | | | 713,201 | |
Total common stockholder's equity | | | 1,498,907 | | | | 1,468,903 | |
Long-term debt and other long-term obligations | | | 1,936,862 | | | | 1,805,871 | |
| | | 3,435,769 | | | | 3,274,774 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Accumulated deferred income taxes | | | 492,203 | | | | 470,707 | |
Accumulated deferred investment tax credits | | | 19,422 | | | | 20,277 | |
Lease market valuation liability | | | 505,725 | | | | 547,800 | |
Retirement benefits | | | 110,329 | | | | 122,862 | |
Deferred revenues - electric service programs | | | 40,459 | | | | 51,588 | |
Other | | | 101,828 | | | | 103,752 | |
| | | 1,269,966 | | | | 1,316,986 | |
COMMITMENTS AND CONTINGENCIES (Note 9) | | | | | | | | |
| | $ | 5,290,798 | | | $ | 5,563,498 | |
| | | | | | | | |
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) | |
| | | | | | |
| | Six Months Ended | |
| | June 30, | |
| | 2007 | | | 2006 | |
| | (In thousands) | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 132,498 | | | $ | 163,465 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | |
Provision for depreciation | | | 37,181 | | | | 28,251 | |
Amortization of regulatory assets | | | 68,176 | | | | 61,006 | |
Deferral of new regulatory assets | | | (77,016 | ) | | | (62,223 | ) |
Nuclear fuel and capital lease amortization | | | 116 | | | | 120 | |
Deferred rents and lease market valuation liability | | | (45,858 | ) | | | (55,043 | ) |
Deferred income taxes and investment tax credits, net | | | (7,103 | ) | | | (4,745 | ) |
Accrued compensation and retirement benefits | | | 1,594 | | | | 1,584 | |
Pension trust contribution | | | (24,800 | ) | | | - | |
Decrease (increase) in operating assets- | | | | | | | | |
Receivables | | | 156,526 | | | | 46,262 | |
Prepayments and other current assets | | | 163 | | | | 399 | |
Increase (decrease) in operating liabilities- | | | | | | | | |
Accounts payable | | | (308,551 | ) | | | (6,388 | ) |
Accrued taxes | | | (40,119 | ) | | | (1,932 | ) |
Accrued interest | | | 3,117 | | | | (76 | ) |
Electric service prepayment programs | | | (11,129 | ) | | | (7,695 | ) |
Other | | | 573 | | | | (4,162 | ) |
Net cash provided from (used for) operating activities | | | (114,632 | ) | | | 158,823 | |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Long-term debt | | | 247,426 | | | | - | |
Redemptions and Repayments- | | | | | | | | |
Long-term debt | | | (103,397 | ) | | | (118,152 | ) |
Short-term borrowings, net | | | (52,894 | ) | | | (57,675 | ) |
Dividend Payments- | | | | | | | | |
Common stock | | | (104,000 | ) | | | (63,000 | ) |
Net cash used for financing activities | | | (12,865 | ) | | | (238,827 | ) |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (64,366 | ) | | | (65,551 | ) |
Loan repayments from associated companies, net | | | 2,292 | | | | 108,169 | |
Collection of principal on long-term notes receivable | | | 133,341 | | | | - | |
Redemption of lessor notes | | | 56,175 | | | | 44,551 | |
Other | | | 70 | | | | (7,155 | ) |
Net cash provided from investing activities | | | 127,512 | | | | 80,014 | |
| | | | | | | | |
Net increase in cash and cash equivalents | | | 15 | | | | 10 | |
Cash and cash equivalents at beginning of period | | | 221 | | | | 207 | |
Cash and cash equivalents at end of period | | $ | 236 | | | $ | 217 | |
| | | | | | | | |
The preceeding 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 Stockholder 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 June 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2007 and 2006 and the consolidated statement of cash flows for the six-month periods ended June 30, 2007 and 2006. 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, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006, and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 3, Note 2(G) and Note 11 to those consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
August 6, 2007
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business in northeastern Ohio, providing regulated electric distribution services. CEI also provides generation services to those customers electing to retain CEI as their power supplier. CEI’s power supply requirements are primarily provided by FES – an affiliated company.
Results of Operations
Net income in the second quarter of 2007 decreased to $69 million from $91 million in the same period of 2006. In the first six months of 2007, net income decreased to $132 million from $163 million in the same period of 2006. The decrease in both periods resulted primarily from higher purchased power costs and other operating costs, partially offset by higher revenues and the deferral of new regulatory assets.
Revenues
Revenues increased by $17 million or 4% in the second quarter of 2007 from the same period of 2006 primarily due to higher retail generation and distribution revenues. Retail generation revenues increased $11 million due to increased KWH sales in the residential and commercial sectors and higher composite unit prices in the commercial and industrial sectors. More extreme weather in the second quarter of 2007 compared to the unseasonably mild weather in the same period in 2006 contributed to the higher KWH sales for both residential and commercial customers (cooling degree days increased 82% and heating degree days were 10% higher in 2007).
In the first six months of 2007, revenues increased by $50 million or 6% compared to the same period of 2006 primarily due to higher retail generation and wholesale revenues. Retail generation revenues increased by $33 million due to increased KWH sales and higher composite unit prices in all classes. The weather contributed to the increased KWH sales in the residential and commercial sectors (cooling degree days increased 84% and heating degree days increased 16% from the same period in 2006). Increased industrial KWH sales reflected a slight decrease in customer shopping.
Wholesale generation revenues increased by $1 million in the second quarter and $12 million in the first six months of 2007 compared to the corresponding periods of 2006. The increases in both periods were primarily due to higher unit prices for PSA sales to associated companies. In the first six months of 2007 higher unit prices were partially offset by a decrease in sales volume due in part to maintenance outages at the Bruce Mansfield Plant in the first quarter of 2007. CEI sells KWH from its leasehold interests in the Bruce Mansfield Plant to FGCO.
Increases in retail electric generation sales and revenues in the second quarter and the first six months of 2007 compared to the corresponding periods of 2006 are summarized in the following tables:
Retail Generation KWH Sales | | Three Months | | Six Months | |
Residential | | | 5.3 | % | | 6.8 | % |
Commercial | | | 6.6 | % | | 6.9 | % |
Industrial | | | 0.8 | % | | 2.0 | % |
Increase in Retail Generation Sales | | | 3.3 | % | | 4.5 | % |
Retail Generation Revenues | | Three Months | | Six Months | |
| | (In millions) | |
Residential | | $ | 2 | | $ | 9 | |
Commercial | | | 5 | | | 12 | |
Industrial | | | 4 | | | 12 | |
Increase in Generation Revenues | | $ | 11 | | $ | 33 | |
Revenues from distribution throughput increased by $3 million in the second quarter and $1 million in the first six months of 2007 compared to the same periods of 2006 primarily due to increased residential and commercial KWH deliveries, offset by lower composite unit prices in all classes. Increased KWH deliveries were primarily a result of the more extreme weather in 2007 as described above.
Changes in distribution KWH deliveries and revenues in the second quarter and first six months of 2007 compared to the corresponding periods of 2006 are summarized in the following tables.
Increase in Distribution KWH Deliveries | | Three Months | | Six Months | |
Residential | | | 5.4 | % | | 6.9 | % |
Commercial | | | 4.6 | % | | 4.8 | % |
Industrial | | | 0.9 | % | | 1.5 | % |
Total Increase in Distribution Deliveries | | | 3.0 | % | | 3.8 | % |
Change in Distribution Revenues | | Three Months | | Six Months | |
Increase (Decrease) | | (In millions) | |
Residential | | $ | 3 | | $ | 5 | |
Commercial | | | 2 | | | 3 | |
Industrial | | | (2 | ) | | (7 | ) |
Net Increase in Distribution Revenues | | $ | 3 | | $ | 1 | |
Expenses
Total expenses increased by $41 million in the second quarter and $83 million in the first six months of 2007 compared to the corresponding periods of 2006. The following table presents changes in each period from the prior year by expense category:
Expenses - Changes | | Three Months | | Six Months | |
Increase (Decrease) | | (In millions) | |
Fuel costs | | $ | 1 | | $ | 1 | |
Purchased power costs | | | 21 | | | 58 | |
Other operating costs | | | 15 | | | 17 | |
Provision for depreciation | | | 8 | | | 9 | |
Amortization of regulatory assets | | | 5 | | | 7 | |
Deferral of new regulatory assets | | | (11 | ) | | (15 | ) |
General taxes | | | 2 | | | 6 | |
Net Increase in Expenses | | $ | 41 | | $ | 83 | |
Higher purchased power costs in the second quarter and the first six months of 2007 compared to the corresponding periods of 2006 primarily reflect higher unit prices associated with the PSA with FES and an increase in KWH purchases to meet CEI’s higher retail generation sales requirements. The higher other operating costs in the second quarter and the first six months of 2007 compared to the same periods of 2006 reflect an increase in MISO transmission related expenses. The difference between transmission revenues accrued and transmission costs incurred is deferred, resulting in no material impact to current period earnings. The increased depreciation in the second quarter of 2007 and the first six months of 2007 is primarily due to the absence of credit adjustments in the second quarter of 2006 related to prior periods ($6.5 million pre-tax, $4 million net of tax).
The increased amortization of regulatory assets in the second quarter and the first six months of 2007 compared to the corresponding periods of 2006 was due to increased transition cost amortization reflecting the higher KWH sales discussed above. The increases in the deferral of new regulatory assets in the second quarter and the first six months of 2007 compared to the same periods of 2006 reflect a higher level of MISO costs that were deferred in excess of transmission revenues and increased distribution cost deferrals under CEI’s RCP. General taxes were higher in the second quarter and the first six months of 2007 as a result of higher real and personal property taxes and KWH excise taxes.
Other Expense
Other expense increased by $14 million in the second quarter and $24 million in the first six months of 2007 compared to the corresponding periods of 2006 primarily due to lower investment income on associated company notes receivable in 2007. CEI received principal repayments from FGCO and NGC subsequent to the second quarter of 2006 on notes receivable related to the generation asset transfers. In addition, there was a $6 million benefit recognized in the second quarter of 2006 related to the sale of the Ashtabula C.
Capital Resources and Liquidity
During 2007, CEI expects to meet its contractual obligations with cash from operations and short-term credit arrangements.
Changes in Cash Position
As of June 30, 2007, CEI had $236,000 of cash and cash equivalents, compared with $221,000 as of December 31, 2006. The major sources of changes in these balances are summarized below.
Cash Flows from Operating Activities
Cash used for operating activities during the first six months of 2007, compared with cash provided from operating activities for the first six months of 2006, were as follows:
| | Six Months Ended | |
Operating Cash Flows | | | | | |
| | | |
Net Income | | $ | | | $ | | |
Non-cash credits | | | | ) | | | ) |
Pension trust contribution | | | | ) | | | |
Working capital and other | | | | ) | | | |
Net cash provided from (used for) operating activities | | $ | | ) | $ | | |
Net cash used for operating activities was $115 million in the first six months of 2007 compared to $159 million provided from operating activities for the same period in 2006. The $274 million change was primarily due to a $25 million pension trust contribution in the first quarter of 2007 and a $222 million change in working capital and other. The change in working capital was due to changes in accounts payable of $302 million (primarily for the settlement of payables with associated companies) and accrued taxes of $38 million, partially offset by changes in accounts receivable of $110 million. The changes in net income and non–cash credits are described above under “Results of Operations.”
Cash Flows from Financing Activities
Net cash used for financing activities was $13 million in the first six months of 2007 compared to $239 million in the same period of 2006. The change reflects $248 million of new long-term debt financing and a $14 million decrease in repayments of long-term debt, partially offset by a $41 million increase in common stock dividend payments to FirstEnergy.
CEI had $25 million of cash and temporary investments (which included short-term notes receivable from associated companies) and approximately $180 million of short-term indebtedness as of June 30, 2007. CEI has obtained authorization from the PUCO to incur short-term debt of up to $500 million through bank facilities and the utility money pool.
On March 27, 2007, CEI issued $250 million of 5.70% unsecured senior notes due 2017. The proceeds of the offering were used to reduce short-term borrowings and for general corporate purposes. On June 1, 2007 CEI redeemed $103 million of Trust C preferred securities.
See the “Financing Capability” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for additional discussion of CEI’s financing capabilities.
Cash Flows from Investing Activities
Net cash provided from investing activities increased by $47 million in the first six months of 2007 compared to the same period of 2006. The change was primarily due to the collection of principal on long-term notes receivable, partially offset by a decrease in loan repayments from associated companies.
CEI’s capital spending for the last two quarters of 2007 is expected to be about $92 million. These cash requirements are expected to be satisfied with cash from operations and short-term credit arrangements. CEI’s capital spending for the period 2007-2011 is expected to be about $843 million, of which approximately $160 million applies to 2007.
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 June 30, 2007, the present value of these operating lease commitments, net of trust investments, total $82 million.
Regulatory Matters
See the “Regulatory Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of regulatory matters applicable to CEI.
Environmental Matters
See the “Environmental Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of environmental matters applicable to CEI.
Other Legal Proceedings
See the “Other Legal Proceedings” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other legal proceedings applicable to CEI.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to CEI.
THE TOLEDO EDISON COMPANY | |
| | | | | | | | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | | | | | | | |
| | Three Months Ended | | | Six Months Ended | |
| | June 30, | | | June 30, | |
| | 2007 | | | 2006 | | | 2007 | | | 2006 | |
STATEMENTS OF INCOME | | (In thousands) | |
| | | | | | | | | | | | |
REVENUES: | | | | | | | | | | | | |
Electric sales | | $ | 233,637 | | | $ | 219,139 | | | $ | 466,693 | | | $ | 430,013 | |
Excise tax collections | | | 6,700 | | | | 6,459 | | | | 14,100 | | | | 13,562 | |
Total revenues | | | 240,337 | | | | 225,598 | | | | 480,793 | | | | 443,575 | |
| | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | |
Fuel | | | 10,461 | | | | 9,638 | | | | 20,608 | | | | 19,400 | |
Purchased power | | | 96,276 | | | | 80,659 | | | | 192,445 | | | | 156,079 | |
Nuclear operating costs | | | 17,846 | | | | 17,866 | | | | 35,567 | | | | 35,198 | |
Other operating costs | | | 46,164 | | | | 39,718 | | | | 89,085 | | | | 80,143 | |
Provision for depreciation | | | 9,127 | | | | 8,240 | | | | 18,244 | | | | 16,337 | |
Amortization of regulatory assets | | | 24,948 | | | | 22,117 | | | | 48,824 | | | | 46,573 | |
Deferral of new regulatory assets | | | (18,247 | ) | | | (14,190 | ) | | | (31,728 | ) | | | (27,846 | ) |
General taxes | | | 13,000 | | | | 12,253 | | | | 26,734 | | | | 25,184 | |
Total expenses | | | 199,575 | | | | 176,301 | | | | 399,779 | | | | 351,068 | |
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 40,762 | | | | 49,297 | | | | 81,014 | | | | 92,507 | |
| | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | |
Investment income | | | 7,309 | | | | 8,945 | | | | 14,534 | | | | 18,725 | |
Miscellaneous expense | | | (2,056 | ) | | | (1,926 | ) | | | (5,156 | ) | | | (4,610 | ) |
Interest expense | | | (8,916 | ) | | | (4,364 | ) | | | (16,419 | ) | | | (8,674 | ) |
Capitalized interest | | | 164 | | | | 344 | | | | 247 | | | | 558 | |
Total other income (expense) | | | (3,499 | ) | | | 2,999 | | | | (6,794 | ) | | | 5,999 | |
| | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 37,263 | | | | 52,296 | | | | 74,220 | | | | 98,506 | |
| | | | | | | | | | | | | | | | |
INCOME TAXES | | | 15,392 | | | | 19,924 | | | | 26,489 | | | | 37,128 | |
| | | | | | | | | | | | | | | | |
NET INCOME | | | 21,871 | | | | 32,372 | | | | 47,731 | | | | 61,378 | |
| | | | | | | | | | | | | | | | |
PREFERRED STOCK DIVIDEND REQUIREMENTS | | | - | | | | 1,161 | | | | - | | | | 2,436 | |
| | | | | | | | | | | | | | | | |
EARNINGS ON COMMON STOCK | | $ | 21,871 | | | $ | 31,211 | | | $ | 47,731 | | | $ | 58,942 | |
| | | | | | | | | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
NET INCOME | | $ | 21,871 | | | $ | 32,372 | | | $ | 47,731 | | | $ | 61,378 | |
| | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | |
Pension and other postretirement benefits | | | 573 | | | | - | | | | 1,146 | | | | - | |
Change in unrealized gain on available for sale securities | | | (669 | ) | | | 191 | | | | (290 | ) | | | (947 | ) |
Other comprehensive income (loss) | | | (96 | ) | | | 191 | | | | 856 | | | | (947 | ) |
Income tax expense (benefit) related to other | | | | | | | | | | | | | | | | |
comprehensive income | | | (43 | ) | | | 69 | | | | 291 | | | | (342 | ) |
Other comprehensive income (loss), net of tax | | | (53 | ) | | | 122 | | | | 565 | | | | (605 | ) |
| | | | | | | | | | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 21,818 | | | $ | 32,494 | | | $ | 48,296 | | | $ | 60,773 | |
| | | | | | | | | | | | | | | | |
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) | |
| | June 30, | | | December 31, | |
| | 2007 | | | 2006 | |
| | (In thousands) | |
ASSETS | | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 22 | | | $ | 22 | |
Receivables- | | | | | | | | |
Customers | | | 1,081 | | | | 772 | |
Associated companies | | | 37,927 | | | | 13,940 | |
Other (less accumulated provisions of $408,000 and $430,000, | | | | | |
respectively, for uncollectible accounts) | | | 4,334 | | | | 3,831 | |
Notes receivable from associated companies | | | 120,101 | | | | 100,545 | |
Prepayments and other | | | 792 | | | | 851 | |
| | | 164,257 | | | | 119,961 | |
UTILITY PLANT: | | | | | | | | |
In service | | | 907,710 | | | | 894,888 | |
Less - Accumulated provision for depreciation | | | 403,634 | | | | 394,225 | |
| | | 504,076 | | | | 500,663 | |
Construction work in progress | | | 14,573 | | | | 16,479 | |
| | | 518,649 | | | | 517,142 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
Investment in lessor notes | | | 154,647 | | | | 169,493 | |
Long-term notes receivable from associated companies | | | 96,521 | | | | 128,858 | |
Nuclear plant decommissioning trusts | | | 62,289 | | | | 61,094 | |
Other | | | 1,808 | | | | 1,871 | |
| | | 315,265 | | | | 361,316 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Goodwill | | | 500,576 | | | | 500,576 | |
Regulatory assets | | | 230,002 | | | | 247,595 | |
Pension assets | | | 5,379 | | | | - | |
Property taxes | | | 22,010 | | | | 22,010 | |
Other | | | 45,194 | | | | 30,042 | |
| | | 803,161 | | | | 800,223 | |
| | $ | 1,801,332 | | | $ | 1,798,642 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Currently payable long-term debt | | $ | 30,000 | | | $ | 30,000 | |
Accounts payable- | | | | | | | | |
Associated companies | | | 36,974 | | | | 84,884 | |
Other | | | 4,020 | | | | 4,021 | |
Notes payable to associated companies | | | 242,253 | | | | 153,567 | |
Accrued taxes | | | 46,153 | | | | 47,318 | |
Lease market valuation liability | | | 23,655 | | | | 24,600 | |
Other | | | 18,755 | | | | 37,551 | |
| | | 401,810 | | | | 381,941 | |
CAPITALIZATION: | | | | | | | | |
Common stockholder's equity- | | | | | | | | |
Common stock, $5 par value, authorized 60,000,000 shares - | | | | | |
29,402,054 shares outstanding | | | 147,010 | | | | 147,010 | |
Other paid-in capital | | | 166,801 | | | | 166,786 | |
Accumulated other comprehensive loss | | | (36,239 | ) | | | (36,804 | ) |
Retained earnings | | | 212,071 | | | | 204,423 | |
Total common stockholder's equity | | | 489,643 | | | | 481,415 | |
Long-term debt | | | 358,227 | | | | 358,281 | |
| | | 847,870 | | | | 839,696 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Accumulated deferred income taxes | | | 160,799 | | | | 161,024 | |
Accumulated deferred investment tax credits | | | 10,597 | | | | 11,014 | |
Lease market valuation liability | | | 198,688 | | | | 218,800 | |
Retirement benefits | | | 76,270 | | | | 77,843 | |
Asset retirement obligations | | | 27,439 | | | | 26,543 | |
Deferred revenues - electric service programs | | | 18,212 | | | | 23,546 | |
Other | | | 59,647 | | | | 58,235 | |
| | | 551,652 | | | | 577,005 | |
COMMITMENTS AND CONTINGENCIES (Note 9) | | | | | | | | |
| | $ | 1,801,332 | | | $ | 1,798,642 | |
| | | | | | | | |
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) | |
| | | | | | |
| | Six Months Ended | |
| | June 30, | |
| | 2007 | | | 2006 | |
| | (In thousands) | |
| | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 47,731 | | | $ | 61,378 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
Provision for depreciation | | | 18,244 | | | | 16,337 | |
Amortization of regulatory assets | | | 48,824 | | | | 46,573 | |
Deferral of new regulatory assets | | | (31,728 | ) | | | (27,846 | ) |
Deferred rents and lease market valuation liability | | | (41,981 | ) | | | (45,843 | ) |
Deferred income taxes and investment tax credits, net | | | (11,924 | ) | | | (13,322 | ) |
Accrued compensation and retirement benefits | | | 1,277 | | | | 1,268 | |
Pension trust contribution | | | (7,659 | ) | | | - | |
Decrease (increase) in operating assets- | | | | | | | | |
Receivables | | | (21,594 | ) | | | (18,257 | ) |
Prepayments and other current assets | | | 59 | | | | (4,076 | ) |
Increase (decrease) in operating liabilities- | | | | | | | | |
Accounts payable | | | (56,784 | ) | | | (14,231 | ) |
Accrued taxes | | | 751 | | | | 3,748 | |
Accrued interest | | | 1 | | | | (222 | ) |
Electric service prepayment programs | | | (5,334 | ) | | | (4,454 | ) |
Other | | | 1,093 | | | | 3,326 | |
Net cash provided from (used for) operating activities | | | (59,024 | ) | | | 4,379 | |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Short-term borrowings, net | | | 88,686 | | | | 71,882 | |
Redemptions and Repayments- | | | | | | | | |
Preferred stock | | | - | | | | (30,000 | ) |
Long-term debt | | | - | | | | (53,650 | ) |
Dividend Payments- | | | | | | | | |
Common stock | | | (40,000 | ) | | | (25,000 | ) |
Preferred stock | | | - | | | | (2,436 | ) |
Net cash provided from (used for) financing activities | | | 48,686 | | | | (39,204 | ) |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (19,804 | ) | | | (29,361 | ) |
Loan repayments from (loans to) associated companies, net | | | (19,546 | ) | | | 2,611 | |
Collection of principal on long-term notes receivable | | | 32,327 | | | | 53,766 | |
Redemption of lessor notes | | | 14,846 | | | | 9,305 | |
Sales of investment securities held in trusts | | | 32,499 | | | | 30,954 | |
Purchases of investment securities held in trusts | | | (32,796 | ) | | | (31,043 | ) |
Other | | | 2,812 | | | | (1,399 | ) |
Net cash provided from investing activities | | | 10,338 | | | | 34,833 | |
| | | | | | | �� | |
Net change in cash and cash equivalents | | | - | | | | 8 | |
Cash and cash equivalents at beginning of period | | | 22 | | | | 15 | |
Cash and cash equivalents at end of period | | $ | 22 | | | $ | 23 | |
| | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral | |
part of these statements. | | | | | | | | |
Report of Independent Registered Public Accounting Firm
To the Stockholder 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 June 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2007 and 2006 and the consolidated statement of cash flows for the six-month periods ended June 30, 2007 and 2006. 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, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006 as discussed in Note 3 to those consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
August 6, 2007
THE TOLEDO EDISON COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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’s power supply requirements are provided by FES – an affiliated company.
Results of Operations
Earnings on common stock in the second quarter of 2007 decreased to $22 million from $31 million in the second quarter of 2006. Earnings on common stock in the first six months of 2007 decreased to $48 million from $59 million in the same period of 2006. The decreases in both periods resulted primarily from higher purchased power and other operating costs, partially offset by higher electric sales revenues and the deferral of new regulatory assets.
Revenues
Revenues increased $15 million or 6.5% in the second quarter of 2007 compared to the same period of 2006 primarily due to higher retail and wholesale generation revenues. Retail generation revenues increased by $8 million in the second quarter of 2007 due to higher average prices and increased sales volume across all customer classes. Average prices increased primarily due to higher composite unit prices for retail generation shopping customers returning to TE. Generation services provided by alternative suppliers as a percentage of total sales delivered in TE’s franchise area decreased by 1 percentage point for residential customers from the second quarter of 2006. The increase in sales volume also resulted from changes in weather in the second quarter of 2007 (heating and cooling degree days increased 14.3% and 38.4%, respectively, from the second quarter of 2006).
The increase in wholesale revenues ($2 million) resulted primarily from increased KWH sales to associated companies, partially offset by lower unit prices. TE sells KWH from its leasehold interests in Beaver Valley Unit 2 and the Bruce Mansfield Plant to CEI and FGCO, respectively.
Revenues increased $37 million or 8.4% in the first six months of 2007 compared to the same period of 2006 primarily due to higher retail generation revenues of $20 million, higher wholesale generation revenues of $12 million and higher transmission revenues from non-associated companies of $2 million. Retail generation revenues increased for all customer sectors in the first six months of 2007 due to higher average prices and increased sales volume as compared to the same period of 2006. Average prices increased primarily due to higher composite unit prices for retail generation shopping customers returning to TE. Generation services provided by alternative suppliers as a percentage of total sales delivered in TE’s franchise area decreased by 3 percentage points and 1 percentage point for residential and commercial customers, respectively. The increase in sales volume also reflects weather impacts in the first six months of 2007 (heating and cooling degree days increased 16.9% and 39.3%, respectively, from the same period of 2006).
The increase in wholesale revenues resulted primarily from increased KWH sales to associated companies and higher unit prices. Wholesale revenues from non-associated companies decreased $2 million primarily due to lower sales to municipal customers.
Increases in electric generation KWH sales and revenues in the second quarter and first six months of 2007 from the corresponding periods of 2006 are summarized in the following tables.
Increase in Retail Generation KWH Sales | | Three Months | | Six Months | |
| | | | | | | |
Residential | | | 9.7 | % | | 11.9 | % |
Commercial | | | 3.7 | % | | 4.5 | % |
Industrial | | | 0.4 | % | | 0.6 | % |
Total Retail Electric Generation Sales | | | 2.9 | % | | 3.9 | % |
Increase in Retail Generation Revenues | | Three Months | | Six Months | |
| | (In millions) | |
Residential | | $ | 2 | | $ | 7 | |
Commercial | | | 2 | | | 4 | |
Industrial | | | 4 | | | 9 | |
Total Retail Generation Revenues | | $ | 8 | | $ | 20 | |
Revenues from distribution throughput increased by $4 million and $2 million in the second quarter and first six months of 2007, respectively, compared to the respective periods in 2006 due to higher KWH deliveries to all customer sectors, partially offset by lower composite unit prices. The higher KWH deliveries to residential and commercial customers in both the second quarter and first six months of 2007 reflected the impact of weather variations described above in both periods of 2007 compared to the respective periods in 2006.
Changes in distribution KWH deliveries and revenues in the second quarter and first six months of 2007 from the corresponding periods of 2006 are summarized in the following tables.
Increase in Distribution KWH Deliveries | | Three Months | | Six Months | |
| | | | | | | |
Residential | | | 8.6 | % | | 8.2 | % |
Commercial | | | 4.3 | % | | 3.5 | % |
Industrial | | | 0.7 | % | | 0.6 | % |
Total Increase in Distribution Deliveries | | | 3.2 | % | | 3.1 | % |
Changes in Distribution Revenues | | Three Months | | Six Months | |
Increase (Decrease) | | (In millions) | |
Residential | | $ | 2 | | $ | 4 | |
Commercial | | | 2 | | | 2 | |
Industrial | | | - | | | (4 | ) |
Net Increase in Distribution Revenues | | $ | 4 | | $ | 2 | |
Expenses
Total expenses increased by $23 million and $49 million in the second quarter and the first six months of 2007, respectively, from the same periods of 2006. The following table presents changes from the prior year by expense category:
Expenses – Changes | | Three Months | | Six Months | |
Increase (Decrease) | | (In millions) | |
Fuel | | $ | 1 | | $ | 1 | |
Purchased power costs | | | 15 | | | 36 | |
Other operating costs | | | 6 | | | 9 | |
Provision for depreciation | | | 1 | | | 2 | |
Amortization of regulatory assets | | | 3 | | | 2 | |
Deferral of new regulatory assets | | | (4 | ) | | (3 | ) |
General taxes | | | | | | | |
Net increase in expenses | | $ | 23 | | $ | 49 | |
Higher purchased power costs in the second quarter of 2007 compared to the second quarter of 2006 reflected higher unit prices associated with the PSA with FES and an increase in KWH purchases to meet the higher retail generation sales requirements. Other operating costs were higher due to a $7 million increase in MISO network transmission expense assessments in the second quarter of 2007. Higher amortization of regulatory assets reflected increased amortization of transition cost deferrals and MISO transmission deferrals. The change in the deferral of new regulatory assets was primarily due to $5 million of increased deferrals for MISO transmission expenses. The difference between transmission revenues accrued and transmission costs incurred is deferred, resulting in no material impact to current period earnings.
Higher purchased power costs in the first six months of 2007 compared to the same period of 2006 reflected higher unit prices associated with the PSA with FES and an increase in KWH purchases to meet the higher retail generation sales requirements. Higher amortization of regulatory assets reflected increased amortization of transition cost deferrals and MISO transmission deferrals. The change in the deferral of new regulatory assets was primarily due to increased deferrals for MISO transmission expenses and RCP reliability costs, partially offset by lower RCP fuel cost deferrals. Other operating costs were higher due to an $8 million increase in MISO network transmission expenses in the first six months of 2007. Depreciation expense was higher due to an increase in depreciable property as a result of plant additions. Higher general taxes primarily reflected increased property taxes and higher KWH excise taxes.
Other Expense
Other expense increased $6 million in the second quarter of 2007 and $13 million in the first six months of 2007 compared to the same periods of 2006 primarily due to lower investment income and higher interest expense. The decrease in investment income resulted primarily from the principal repayments since the second quarter of 2006 on notes receivable from associated companies. The higher interest expense is principally associated with new long-term debt issued in November 2006.
Capital Resources and Liquidity
During 2007, TE expects to meet its contractual obligations primarily with cash from operations and short-term credit arrangements. Borrowing capacity under TE’s credit facilities is available to manage its working capital requirements.
Changes in Cash Position
There was no change as of June 30, 2007 from December 31, 2006 in TE’s cash and cash equivalents of $22,000.
Cash Flows From Operating Activities
Net cash provided from (used for) operating activities in the first six months of 2007 and 2006 were as follows:
| | Six Months Ended June 30, | |
| | 2007 | | 2006 | |
| | (In millions) | |
| | | | | | | |
| | | | ) | | | |
Pension trust contribution | | | | ) | | | |
Working capital and other | | | | ) | | | |
Net cash provided from (used for) | | | | ) | | | |
Net cash used for operating activities was $59 million in the first six months of 2007 compared to net cash provided from operating activities of $4 million in the same period of 2006. The change was the result of a $13 million decrease in net income, an $8 million pension trust contribution in the first six months of 2007 and a $47 million decrease from changes in working capital and other, partially offset by a $5 million decrease in net non-cash credits. The change in net income is described above under “Results of Operations.” The changes in working capital and other are primarily due to increased cash outflows for accounts payable of $43 million.
Cash Flows From Financing Activities
Net cash provided from financing activities increased by $88 million in the first six months of 2007 compared to the same period of 2006. The increase resulted primarily from a $17 million increase in short-term borrowings, a $30 million decrease in preferred stock redemptions and a $54 million decrease in long-term debt redemptions, partially offset by a $15 million increase in common stock dividends to FirstEnergy in the first six months of 2007.
TE had $120 million of cash and temporary investments (which included short-term notes receivable from associated companies) and $242 million of short-term indebtedness as of June 30, 2007. TE has authorization from the PUCO to incur short-term debt of up to $500 million through bank facilities and the utility money pool.
See the “Financing Capability” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for additional discussion of TE’s financing capabilities.
Cash Flows From Investing Activities
Net cash provided from investing activities decreased by $24 million in the first six months of 2007 compared to the same period of 2006. The change was primarily due to a $44 million net decrease in loan repayments from associated companies, partially offset by a $10 million decrease in property additions and a $6 million increase from the redemption of lessor notes.
TE’s capital spending for the last two quarters of 2007 is expected to be about $38 million. TE has additional requirements of $30 million for maturing long-term debt during the remainder of 2007. These cash requirements are expected to be satisfied primarily with cash from operations and short-term credit arrangements. TE’s capital spending for the period 2007-2011 is expected to be nearly $322 million, of which approximately $61 million applies to 2007.
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 June 30, 2007, the present value of these operating lease commitments, net of trust investments, total $442 million.
Regulatory Matters
See the “Regulatory Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of regulatory matters applicable to TE.
Environmental Matters
See the “Environmental Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of environmental matters applicable to TE.
Other Legal Proceedings
See the “Other Legal Proceedings” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other legal proceedings applicable to TE.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to TE.
JERSEY CENTRAL POWER & LIGHT COMPANY | |
| | | | | | | | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | | | | | | | |
| | Three Months Ended | | | Six Months Ended | |
| | June 30, | | | June 30, | |
| | 2007 | | | 2006 | | | 2007 | | | 2006 | |
STATEMENTS OF INCOME | | (In thousands) | |
| | | | | | | | | | | | |
REVENUES: | | | | | | | | | | | | |
Electric sales | | $ | 768,190 | | | $ | 600,560 | | | $ | 1,439,097 | | | $ | 1,164,110 | |
Excise tax collections | | | 11,845 | | | | 10,924 | | | | 24,681 | | | | 23,166 | |
Total revenues | | | 780,035 | | | | 611,484 | | | | 1,463,778 | | | | 1,187,276 | |
| | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | |
Purchased power | | | 464,505 | | | | 343,045 | | | | 851,002 | | | | 658,755 | |
Other operating costs | | | 74,564 | | | | 72,105 | | | | 149,215 | | | | 155,133 | |
Provision for depreciation | | | 21,319 | | | | 20,826 | | | | 41,835 | | | | 41,454 | |
Amortization of regulatory assets | | | 93,890 | | | | 65,526 | | | | 189,118 | | | | 132,271 | |
General taxes | | | 15,553 | | | | 14,272 | | | | 32,552 | | | | 30,504 | |
Total expenses | | | 669,831 | | | | 515,774 | | | | 1,263,722 | | | | 1,018,117 | |
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 110,204 | | | | 95,710 | | | | 200,056 | | | | 169,159 | |
| | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | |
Miscellaneous income | | | 3,238 | | | | 2,528 | | | | 6,299 | | | | 6,071 | |
Interest expense | | | (24,494 | ) | | | (20,367 | ) | | | (46,910 | ) | | | (40,983 | ) |
Capitalized interest | | | 563 | | | | 1,037 | | | | 1,076 | | | | 1,929 | |
Total other expense | | | (20,693 | ) | | | (16,802 | ) | | | (39,535 | ) | | | (32,983 | ) |
| | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 89,511 | | | | 78,908 | | | | 160,521 | | | | 136,176 | |
| | | | | | | | | | | | | | | | |
INCOME TAXES | | | 39,698 | | | | 38,632 | | | | 72,362 | | | | 62,190 | |
| | | | | | | | | | | | | | | | |
NET INCOME | | | 49,813 | | | | 40,276 | | | | 88,159 | | | | 73,986 | |
| | | | | | | | | | | | | | | | |
PREFERRED STOCK DIVIDEND REQUIREMENTS | | | - | | | | 125 | | | | - | | | | 250 | |
| | | | | | | | | | | | | | | | |
EARNINGS ON COMMON STOCK | | $ | 49,813 | | | $ | 40,151 | | | $ | 88,159 | | | $ | 73,736 | |
| | | | | | | | | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
NET INCOME | | $ | 49,813 | | | $ | 40,276 | | | $ | 88,159 | | | $ | 73,986 | |
| | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | |
Pension and other postretirement benefits | | | (2,115 | ) | | | - | | | | (4,230 | ) | | | - | |
Unrealized gain on derivative hedges | | | 69 | | | | 38 | | | | 166 | | | | 107 | |
Other comprehensive income (loss) | | | (2,046 | ) | | | 38 | | | | (4,064 | ) | | | 107 | |
Income tax expense (benefit) related to other | | | | | | | | | | | | | | | | |
comprehensive income | | | (995 | ) | | | 15 | | | | (1,979 | ) | | | 43 | |
Other comprehensive income (loss), net of tax | | | (1,051 | ) | | | 23 | | | | (2,085 | ) | | | 64 | |
| | | | | | | | | | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 48,762 | | | $ | 40,299 | | | $ | 86,074 | | | $ | 74,050 | |
| | | | | | | | | | | | | | | | |
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) | |
| | June 30, | | | December 31, | |
| | 2007 | | | 2006 | |
| | (In thousands) | |
ASSETS | | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 87 | | | $ | 41 | |
Receivables- | | | | | | | | |
Customers (less accumulated provisions of $4,042,000 and $3,524,000, | | | | | | | | |
respectively, for uncollectible accounts) | | | 378,940 | | | | 254,046 | |
Associated companies | | | 186 | | | | 11,574 | |
Other (less accumulated provisions of $701,000 and $204,000, | | | | | | | | |
respectively, for uncollectible accounts) | | | 64,010 | | | | 40,023 | |
Notes receivable - associated companies | | | 23,691 | | | | 24,456 | |
Materials and supplies, at average cost | | | 1,953 | | | | 2,043 | |
Prepaid taxes | | | 122,391 | | | | 13,333 | |
Other | | | 10,480 | | | | 18,076 | |
| | | 601,738 | | | | 363,592 | |
UTILITY PLANT: | | | | | | | | |
In service | | | 4,074,918 | | | | 4,029,070 | |
Less - Accumulated provision for depreciation | | | 1,484,602 | | | | 1,473,159 | |
| | | 2,590,316 | | | | 2,555,911 | |
Construction work in progress | | | 97,539 | | | | 78,728 | |
| | | 2,687,855 | | | | 2,634,639 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
Nuclear fuel disposal trust | | | 170,840 | | | | 171,045 | |
Nuclear plant decommissioning trusts | | | 172,371 | | | | 164,108 | |
Other | | | 2,065 | | | | 2,047 | |
| | | 345,276 | | | | 337,200 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Regulatory assets | | | 1,824,873 | | | | 2,152,332 | |
Goodwill | | | 1,962,361 | | | | 1,962,361 | |
Pension Assets | | | 39,609 | | | | 14,660 | |
Other | | | 15,724 | | | | 17,781 | |
| | | 3,842,567 | | | | 4,147,134 | |
| | $ | 7,477,436 | | | $ | 7,482,565 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Currently payable long-term debt | | $ | 39,082 | | | $ | 32,683 | |
Short-term borrowings- | | | | | | | | |
Associated companies | | | 263,809 | | | | 186,540 | |
Accounts payable- | | | | | | | | |
Associated companies | | | 7,325 | | | | 80,426 | |
Other | | | 229,023 | | | | 160,359 | |
Accrued taxes | | | 18,600 | | | | 1,451 | |
Accrued interest | | | 10,621 | | | | 14,458 | |
Cash collateral from suppliers | | | 8,505 | | | | 32,300 | |
Other | | | 83,766 | | | | 96,150 | |
| | | 660,731 | | | | 604,367 | |
CAPITALIZATION: | | | | | | | | |
Common stockholder's equity- | | | | | | | | |
Common stock, $10 par value, authorized 16,000,000 shares- | | | | | | | | |
14,421,637 and 15,009,335 shares outstanding, respectively | | | 144,216 | | | | 150,093 | |
Other paid-in capital | | | 2,789,235 | | | | 2,908,279 | |
Accumulated other comprehensive loss | | | (46,339 | ) | | | (44,254 | ) |
Retained earnings | | | 218,545 | | | | 145,480 | |
Total common stockholder's equity | | | 3,105,657 | | | | 3,159,598 | |
Long-term debt and other long-term obligations | | | 1,575,430 | | | | 1,320,341 | |
| | | 4,681,087 | | | | 4,479,939 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Power purchase contract loss liability | | | 877,297 | | | | 1,182,108 | |
Accumulated deferred income taxes | | | 780,004 | | | | 803,944 | |
Nuclear fuel disposal costs | | | 188,205 | | | | 183,533 | |
Asset retirement obligations | | | 87,018 | | | | 84,446 | |
Other | | | 203,094 | | | | 144,228 | |
| | | 2,135,618 | | | | 2,398,259 | |
COMMITMENTS AND CONTINGENCIES (Note 9) | | | | | | | | |
| | $ | 7,477,436 | | | $ | 7,482,565 | |
| | | | | | | | |
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 CASH FLOWS | |
(Unaudited) | |
| | | | | | |
| | Six Months Ended | |
| | June 30, | |
| | 2007 | | | 2006 | |
| | (In thousands) | |
| | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 88,159 | | | $ | 73,986 | |
Adjustments to reconcile net income to net cash from operating activities - | | | | | | | | |
Provision for depreciation | | | 41,835 | | | | 41,454 | |
Amortization of regulatory assets | | | 189,118 | | | | 132,271 | |
Deferred purchased power and other costs | | | (111,517 | ) | | | (134,759 | ) |
Deferred income taxes and investment tax credits, net | | | (3,116 | ) | | | 10,942 | |
Accrued compensation and retirement benefits | | | (11,467 | ) | | | (3,436 | ) |
Cash collateral returned to suppliers | | | (23,905 | ) | | | (108,791 | ) |
Pension trust contribution | | | (17,800 | ) | | | - | |
Decrease (increase) in operating assets- | | | | | | | | |
Receivables | | | (137,492 | ) | | | (24,074 | ) |
Materials and supplies | | | 90 | | | | 91 | |
Prepaid taxes | | | (109,058 | ) | | | (100,650 | ) |
Other current assets | | | 2,540 | | | | 1,718 | |
Increase (decrease) in operating liabilities- | | | | | | | | |
Accounts payable | | | (4,438 | ) | | | 23,589 | |
Accrued taxes | | | 27,515 | | | | (9,062 | ) |
Accrued interest | | | (3,837 | ) | | | 362 | |
Tax collections payable | | | (12,478 | ) | | | (10,322 | ) |
Other | | | (6,114 | ) | | | 8,680 | |
Net cash used for operating activities | | | (91,965 | ) | | | (98,001 | ) |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Long-term debt | | | 550,000 | | | | 200,003 | |
Short-term borrowings, net | | | 77,269 | | | | 183,818 | |
Redemptions and Repayments- | | | | | | | | |
Long-term debt | | | (304,579 | ) | | | (157,659 | ) |
Common Stock | | | (125,000 | ) | | | - | |
Dividend Payments- | | | | | | | | |
Common stock | | | (15,000 | ) | | | (25,000 | ) |
Preferred stock | | | - | | | | (250 | ) |
Net cash provided from financing activities | | | 182,690 | | | | 200,912 | |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (95,310 | ) | | | (91,101 | ) |
Loan repayments from (loans to) associated companies, net | | | 765 | | | | (9,347 | ) |
Sales of investment securities held in trusts | | | 77,941 | | | | 131,079 | |
Purchases of investment securities held in trusts | | | (79,388 | ) | | | (132,526 | ) |
Other | | | 5,313 | | | | (1,023 | ) |
Net cash used for investing activities | | | (90,679 | ) | | | (102,918 | ) |
| | | | | | | | |
Net increase (decrease) in cash and cash equivalents | | | 46 | | | | (7 | ) |
Cash and cash equivalents at beginning of period | | | 41 | | | | 102 | |
Cash and cash equivalents at end of period | | $ | 87 | | | $ | 95 | |
| | | | | | | | |
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 Stockholder 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 June 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2007 and 2006 and the consolidated statement of cash flows for the six-month periods ended June 30, 2007 and 2006. 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, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006, as discussed in Note 3 to those consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
August 6, 2007
JERSEY CENTRAL POWER & LIGHT COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
Results of Operations
Earnings on common stock in the second quarter of 2007 increased to $50 million from $40 million in 2006. The increase was primarily due to higher revenues, partially offset by higher purchased power costs, increased amortization of regulatory assets, interest expense and other operating costs. In the first six months of 2007, earnings on common stock increased to $88 million compared to $74 million for the same period in 2006. The increase was primarily due to higher revenues and lower other operating costs, partially offset by higher purchased power costs, increased amortization of regulatory assets and interest expense.
Revenues
Revenues increased $169 million or 27.6% in the second quarter of 2007 and $277 million or 23.3% in the first six months of 2007 compared with the same periods of 2006, reflecting higher retail and wholesale generation revenues. Retail generation revenues increased by $102 million and $164 million in the second quarter and the first six months of 2007, respectively. Wholesale revenues increased $19 million in the second quarter and $27 million in the first six months of 2007.
Generation revenues from all customer classes increased in the second quarter and first six months of 2007 as compared to 2006. The increases in both periods of 2007 were due to higher unit prices resulting from the BGS auctions effective June 1, 2006 and June 1, 2007 and higher retail generation KWH sales. Sales volume increased as a result of weather conditions in the second quarter of 2007 (heating degree days were 35% greater than the second quarter of 2006). Industrial generation KWH sales declined in the second quarter and first six months of 2007 from the same period in 2006 due to an increase in customer shopping.
Wholesale generation revenues increased ($19 million in the second quarter and $27 million in the first six months of 2007) due to higher market prices, partially offset by sales volume decreases of 3.9% and 1.4% from the second quarter and first six months of 2006, respectively.
Changes in retail generation KWH sales and revenues by customer class in the second quarter and the first six months of 2007 compared to the same periods of 2006 are summarized in the following table:
Retail Generation KWH Sales | | Three Months | | Six Months | |
Increase (Decrease) | | | | | | | |
Residential | | | 13.6 | % | | 8.9 | % |
Commercial | | | 5.3 | % | | 3.2 | % |
Industrial | | | (8.4 | )% | | (4.9 | )% |
Net Increase in Generation Sales | | | 9.0 | % | | 5.8 | % |
Retail Generation Revenues | | Three Months | | Six Months | |
| | (In millions) | |
Residential | | $ | 64 | | $ | 100 | |
Commercial | | | 36 | | | 60 | |
Industrial | | | 2 | | | 4 | |
Increase in Generation Revenues | | $ | 102 | | $ | 164 | |
Distribution revenues increased $39 million and $67 million in the second quarter and first six months of 2007, respectively, compared to the same periods of 2006 due to higher composite unit prices and increased KWH deliveries, reflecting the weather impacts described above. The higher unit prices resulted from a NUGC rate increase effective in December 2006 as approved by the NJBPU.
Changes in distribution KWH deliveries and revenues in the second quarter and first six months of 2007 compared to the corresponding periods of 2006 are summarized in the following tables.
Increase in Distribution KWH Deliveries | | Three Months | | Six Months | |
Residential | | | 13.7 | % | | 8.9 | % |
Commercial | | | 5.4 | % | | 4.8 | % |
Industrial | | | 2.9 | % | | 2.3 | % |
Total Increase in Distribution Deliveries | | | 8.5 | % | | 6.2 | % |
Increase in Distribution Revenues | | Three Months | | Six Months | |
| | (In millions) | |
Residential | | $ | 24 | | $ | 38 | |
Commercial | | | 13 | | | 25 | |
Industrial | | | 2 | | | 4 | |
Total Increase in Distribution Revenues | | $ | 39 | | $ | 67 | |
The higher revenues for the second quarter and first six months of 2007 also included $8 million and $16 million, respectively, of increased revenues resulting from the August 2006 securitization of deferred costs associated with JCP&L’s BGS supply.
Expenses
Total expenses increased by $154 million in the second quarter and $246 million in the first six months of 2007 as compared to the same periods of 2006. The following table presents changes from the prior year by expense category:
Expenses - Changes | | Three Months | | Six Months | |
Increase (Decrease) | | (In millions) | |
Purchased power costs | | $ | 121 | | $ | 192 | |
Other operating costs | | | 2 | | | (6 | ) |
Provision for depreciation | | | 1 | | | 1 | |
Amortization of regulatory assets | | | 29 | | | 57 | |
General Taxes | | | 1 | | | 2 | |
Net increase in expenses | | $ | 154 | | $ | 246 | |
The increase in purchased power costs (35.4% in the second quarter of 2007 and 29.2% in the first six months) primarily reflected higher unit prices resulting from the BGS auctions. Other operating costs increased $2 million in the second quarter of 2007 due to higher labor costs from storm damage repairs in 2007, but decreased $6 million in the first six months of 2007 primarily due to lower employee benefit costs. Amortization of regulatory assets increased $29 million in the second quarter and $57 million in the first six months of 2007 due to higher transition cost recovery associated with the December 2006 NUGC rate increase.
Capital Resources and Liquidity
During the remainder of 2007, JCP&L expects to meet its contractual obligations with a combination of cash from operations and short-term borrowings. Borrowing capacity under JCP&L’s credit facilities is available to manage its working capital requirements.
Changes in Cash Position
As of June 30, 2007, JCP&L had $87,000 of cash and cash equivalents compared with $41,000 as of December 31, 2006. The major sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Cash provided from operating activities in the first six months of 2007 compared with the first six months of 2006 were as follows:
| | Six Months Ended | | |
| | June 30, | | |
Operating Cash Flows | | 2007 | | 2006 | | |
| | (In millions) | | |
Net income | | $ | 88 | | $ | 74 | | |
Net non-cash charges | | | 105 | | | 46 | | |
Pension trust contribution | | | (18 | ) | | - | | |
Cash collateral returned to suppliers | | | (24 | ) | | (109 | ) | |
Working capital and other | | | (243 | ) | | (109 | ) | |
Net cash used for operating activities | | $ | (92 | ) | $ | (98 | ) | |
Net cash used for operating activities decreased $6 million in the first six months of 2007 from the same period of 2006. This decrease was primarily due to an $85 million reduction in cash collateral payments made to suppliers in the first six months of 2007 compared to the same period in 2006, an increase of $59 million in non-cash charges and an increase in net income of $14 million. These increases were largely offset by a $134 million decrease from working capital (due to changes in the collection of receivables and tax payments) and an $18 million pension trust contribution in the first quarter of 2007. The changes in net income and non-cash charges are described above in “Results of Operations.”
Cash Flows From Financing Activities
Net cash provided from financing activities was $183 million in the first six months of 2007 compared to $201 million in same period of 2006. The decrease primarily resulted from a $107 million reduction in short-term borrowings, a $125 million repurchase of common stock from FirstEnergy and $147 million of additional long-term debt redemptions, partially offset by a $350 million increase in new long-term debt financing and a $10 million reduction in common stock dividend payments to FirstEnergy.
JCP&L had $24 million of cash and temporary investments (which includes short-term notes receivable from associated companies) and approximately $229 million of short-term indebtedness as of June 30, 2007. JCP&L has authorization from the FERC to incur short-term debt up to its charter limit of $431 million (including the utility money pool).
See the “Financing Capability” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for additional discussion of JCP&L’s financing capabilities.
Cash Flows From Investing Activities
Net cash used for investing activities was $91 million in the first six months of 2007 compared to $103 million in the previous year. The $12 million decrease primarily resulted from the absence of $10 million in loans to associated companies in 2006.
During the last half of 2007, capital requirements for property additions and improvements are expected to be about $95 million. These cash requirements are expected to be satisfied from a combination of internal cash and short-term credit arrangements.
JCP&L’s capital spending for the period 2007-2011 is expected to be about $1.3 billion for property additions, of which approximately $192 million applies to 2007.
Market Risk Information
During the first six months of 2007, the value of commodity derivative contracts decreased by $302 million as a result of settled contracts ($196 million) and changes in the value of existing contracts ($106 million). These non-trading contracts (primarily with NUG entities) are adjusted to fair value at the end of each quarter with a corresponding offset to regulatory assets, resulting in no impact to current period earnings. Commodity derivative contracts were valued at $869 million and $1.2 billion as of June 30, 2007 and December 31, 2006, respectively. See the “Market Risk Information” section of JCP&L’s 2006 Annual Report on Form 10-K for additional discussion of market risk.
Equity Price Risk
Included in nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $104 million and $97 million as of June 30, 2007 and December 31, 2006, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $10 million reduction in fair value as of June 30, 2007.
Regulatory Matters
See the “Regulatory Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of regulatory matters applicable to JCP&L.
Environmental Matters
See the “Environmental Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of environmental matters applicable to JCP&L.
Other Legal Proceedings
See the “Other Legal Proceedings” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other legal proceedings applicable to JCP&L.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to JCP&L.
METROPOLITAN EDISON COMPANY | |
| | | | | | | | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | | | | | | | |
| | Three Months Ended | | | Six Months Ended | |
| | June 30, | | | June 30, | |
| | 2007 | | | 2006 | | | 2007 | | | 2006 | |
| | (In thousands) | |
| | | | | | | | | | | | |
REVENUES: | | | | | | | | | | | | |
Electric sales | | $ | 344,241 | | | $ | 266,533 | | | $ | 696,377 | | | $ | 560,570 | |
Gross receipts tax collections | | | 17,502 | | | | 15,686 | | | | 35,622 | | | | 32,862 | |
Total revenues | | | 361,743 | | | | 282,219 | | | | 731,999 | | | | 593,432 | |
| | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | |
Purchased power | | | 182,818 | | | | 143,070 | | | | 374,407 | | | | 302,957 | |
Other operating costs | | | 111,105 | | | | 59,575 | | | | 209,123 | | | | 120,654 | |
Provision for depreciation | | | 10,531 | | | | 10,288 | | | | 20,815 | | | | 21,193 | |
Amortization of regulatory assets | | | 30,972 | | | | 25,669 | | | | 65,112 | | | | 55,717 | |
Deferral of new regulatory assets | | | (31,895 | ) | | | (45,581 | ) | | | (74,621 | ) | | | (45,581 | ) |
General taxes | | | 20,170 | | | | 18,595 | | | | 41,222 | | | | 39,216 | |
Total expenses | | | 323,701 | | | | 211,616 | | | | 636,058 | | | | 494,156 | |
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 38,042 | | | | 70,603 | | | | 95,941 | | | | 99,276 | |
| | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | |
Interest income | | | 7,775 | | | | 8,964 | | | | 15,501 | | | | 17,714 | |
Miscellaneous income | | | 1,498 | | | | 1,792 | | | | 2,607 | | | | 4,404 | |
Interest expense | | | (13,424 | ) | | | (12,071 | ) | | | (25,180 | ) | | | (23,255 | ) |
Capitalized interest | | | 388 | | | | 344 | | | | 648 | | | | 611 | |
Total other expense | | | (3,763 | ) | | | (971 | ) | | | (6,424 | ) | | | (526 | ) |
| | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 34,279 | | | | 69,632 | | | | 89,517 | | | | 98,750 | |
| | | | | | | | | | | | | | | | |
INCOME TAXES | | | 14,809 | | | | 29,555 | | | | 38,408 | | | | 40,759 | |
| | | | | | | | | | | | | | | | |
NET INCOME | | | 19,470 | | | | 40,077 | | | | 51,109 | | | | 57,991 | |
| | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | |
Pension and other postretirement benefits | | | (1,453 | ) | | | - | | | | (2,905 | ) | | | - | |
Unrealized gain on derivative hedges | | | 84 | | | | 84 | | | | 168 | | | | 168 | |
Other comprehensive income (loss) | | | (1,369 | ) | | | 84 | | | | (2,737 | ) | | | 168 | |
Income tax expense (benefit) related to other | | | | | | | | | | | | | | | | |
comprehensive income | | | (693 | ) | | | 35 | | | | (1,385 | ) | | | 70 | |
Other comprehensive income (loss), net of tax | | | (676 | ) | | | 49 | | | | (1,352 | ) | | | 98 | |
| | | | | | | | | | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 18,794 | | | $ | 40,126 | | | $ | 49,757 | | | $ | 58,089 | |
| | | | | | | | | | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of | |
these statements. | | | | | | | | | | | | | | | | |
METROPOLITAN EDISON COMPANY | |
| | | | | | |
CONSOLIDATED BALANCE SHEETS | |
(Unaudited) | |
| | June 30, | | | December 31, | |
| | 2007 | | | 2006 | |
| | (In thousands) | |
ASSETS | | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 127 | | | $ | 130 | |
Receivables- | | | | | | | | |
Customers (less accumulated provisions of $4,480,000 and $4,153,000, | | | | | | | | |
respectively, for uncollectible accounts) | | | 160,147 | | | | 127,084 | |
Associated companies | | | 27,213 | | | | 3,604 | |
Other | | | 20,163 | | | | 8,107 | |
Notes receivable from associated companies | | | 34,399 | | | | 31,109 | |
Prepaid taxes | | | 23,598 | | | | 13,533 | |
Other | | | 353 | | | | 1,424 | |
| | | 266,000 | | | | 184,991 | |
UTILITY PLANT: | | | | | | | | |
In service | | | 1,945,821 | | | | 1,920,563 | |
Less - Accumulated provision for depreciation | | | 750,937 | | | | 739,719 | |
| | | 1,194,884 | | | | 1,180,844 | |
Construction work in progress | | | 33,474 | | | | 18,466 | |
| | | 1,228,358 | | | | 1,199,310 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
Nuclear plant decommissioning trusts | | | 283,596 | | | | 269,777 | |
Other | | | 1,361 | | | | 1,362 | |
| | | 284,957 | | | | 271,139 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Goodwill | | | 496,129 | | | | 496,129 | |
Regulatory assets | | | 464,434 | | | | 409,095 | |
Pension assets | | | 23,583 | | | | 7,261 | |
Other | | | 38,885 | | | | 46,354 | |
| | | 1,023,031 | | | | 958,839 | |
| | $ | 2,802,346 | | | $ | 2,614,279 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Currently payable long-term debt | | $ | - | | | $ | 50,000 | |
Short-term borrowings- | | | | | | | | |
Associated companies | | | 158,731 | | | | 141,501 | |
Other | | | 197,000 | | | | - | |
Accounts payable- | | | | | | | | |
Associated companies | | | 26,435 | | | | 100,232 | |
Other | | | 70,566 | | | | 59,077 | |
Accrued taxes | | | 513 | | | | 11,300 | |
Accrued interest | | | 7,050 | | | | 7,496 | |
Other | | | 22,978 | | | | 22,825 | |
| | | 483,273 | | | | 392,431 | |
CAPITALIZATION: | | | | | | | | |
Common stockholder's equity- | | | | | | | | |
Common stock, without par value, authorized 900,000 shares- | | | | | | | | |
859,000 shares outstanding | | | 1,276,119 | | | | 1,276,075 | |
Accumulated other comprehensive loss | | | (27,868 | ) | | | (26,516 | ) |
Accumulated deficit | | | (183,560 | ) | | | (234,620 | ) |
Total common stockholder's equity | | | 1,064,691 | | | | 1,014,939 | |
Long-term debt and other long-term obligations | | | 542,070 | | | | 542,009 | |
| | | 1,606,761 | | | | 1,556,948 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Accumulated deferred income taxes | | | 405,170 | | | | 387,456 | |
Accumulated deferred investment tax credits | | | 8,830 | | | | 9,244 | |
Nuclear fuel disposal costs | | | 42,514 | | | | 41,459 | |
Asset retirement obligations | | | 155,867 | | | | 151,107 | |
Retirement benefits | | | 17,187 | | | | 19,522 | |
Other | | | 82,744 | | | | 56,112 | |
| | | 712,312 | | | | 664,900 | |
COMMITMENTS AND CONTINGENCIES (Note 9) | | | | | | | | |
| | $ | 2,802,346 | | | $ | 2,614,279 | |
| | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part | |
of these balance sheets. | | | | | | | | |
METROPOLITAN EDISON COMPANY | |
| | | | | | |
CONSOLIDATED STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | |
| | Six Months Ended | |
| | June 30, | |
| | 2007 | | | 2006 | |
| | (In thousands) | |
| | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 51,109 | | | $ | 57,991 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | |
Provision for depreciation | | | 20,815 | | | | 21,193 | |
Amortization of regulatory assets | | | 65,112 | | | | 55,717 | |
Deferred costs recoverable as regulatory assets | | | (38,540 | ) | | | (50,570 | ) |
Deferral of new regulatory assets | | | (74,621 | ) | | | (45,581 | ) |
Deferred income taxes and investment tax credits, net | | | 27,069 | | | | 22,463 | |
Accrued compensation and retirement benefits | | | (11,150 | ) | | | (4,712 | ) |
Cash collateral | | | 4,850 | | | | (2,250 | ) |
Pension trust contribution | | | (11,012 | ) | | | - | |
Decrease (increase) in operating assets- | | | | | | | | |
Receivables | | | (64,465 | ) | | | 38,182 | |
Prepayments and other current assets | | | (8,994 | ) | | | (24,564 | ) |
Increase (decrease) in operating liabilities- | | | | | | | | |
Accounts payable | | | (62,308 | ) | | | 6,161 | |
Accrued taxes | | | (10,788 | ) | | | (12,045 | ) |
Accrued interest | | | (446 | ) | | | 297 | |
Other | | | 4,238 | | | | (4,011 | ) |
Net cash provided from (used for) operating activities | | | (109,131 | ) | | | 58,271 | |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Short-term borrowings, net | | | 214,229 | | | | - | |
Redemptions and Repayments- | | | | | | | | |
Long-term debt | | | (50,000 | ) | | | - | |
Short-term borrowings, net | | | - | | | | (1,707 | ) |
Net cash provided from (used for) financing activities | | | 164,229 | | | | (1,707 | ) |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (49,852 | ) | | | (47,301 | ) |
Sales of investment securities held in trusts | | | 55,603 | | | | 113,637 | |
Purchases of investment securities held in trusts | | | (57,571 | ) | | | (118,379 | ) |
Loans to associated companies, net | | | (3,290 | ) | | | (4,054 | ) |
Other | | | 9 | | | | (453 | ) |
Net cash used for investing activities | | | (55,101 | ) | | | (56,550 | ) |
| | | | | | | | |
Net increase (decrease) in cash and cash equivalents | | | (3 | ) | | | 14 | |
Cash and cash equivalents at beginning of period | | | 130 | | | | 120 | |
Cash and cash equivalents at end of period | | $ | 127 | | | $ | 134 | |
| | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral |
part of these statements. | | | | | | | | |
Report of Independent Registered Public Accounting Firm
To the Stockholder 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 June 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2007 and 2006 and the consolidated statement of cash flows for the six-month periods ended June 30, 2007 and 2006. 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, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006, and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 3, Note 2(G) and Note 9 to those consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
August 6, 2007
METROPOLITAN EDISON COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITIONAND RESULTS OF OPERATIONS
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.
Results of Operations
Net income in the second quarter of 2007 decreased to $19 million from $40 million in the second quarter of 2006. The decrease was primarily due to higher purchased power costs, other operating costs and lower deferrals of new regulatory assets due to the May 2006 PPUC order as discussed below, partially offset by higher revenues. For the first six months of 2007, net income decreased to $51 million from $58 million in the same period of 2006. The decrease in the six month period reflects higher purchased power costs and other operating costs, partially offset by higher revenues and increased deferrals of new regulatory assets.
Revenues
Revenues increased by $80 million, or 28.2%, in the second quarter of 2007 and $139 million, or 23.4%, in the first six months of 2007 compared with the same periods of 2006. The increases in both periods were primarily due to higher retail and wholesale generation revenues.
In the second quarter of 2007, retail generation revenues increased by $10 million primarily due to higher KWH sales in the residential and commercial sectors, partially offset by slightly lower KWH sales in the industrial sector. The increase in retail generation revenues in the residential and commercial sectors primarily resulted from higher weather-related usage in the second quarter of 2007 as compared to the same period of 2006 (heating degree days increased by 34.9% and cooling degree days increased by 19.3%).
In the first six months of 2007, retail generation revenues increased by $15 million due to higher KWH sales in all customer sectors. The increase in retail generation revenues in the residential and commercial sectors was primarily due to weather conditions during the first six months of 2007 (heating degree days increased by 18.3% and cooling degree days increased by 19.3% as compared to the same period of 2006).
Increases in retail electric generation sales and revenues in the second quarter and the first six months of 2007 compared to the same periods of 2006 are summarized in the following tables:
Retail Generation KWH Sales | | Three Months | | Six Months | |
Increase (Decrease) | | | | | | | |
Residential | | | 11.7 | % | | 8.7 | % |
Commercial | | | 4.7 | % | | 4.2 | % |
Industrial | | | (0.2 | )% | | 1.3 | % |
Total Retail Electric Generation Sales | | | 5.6 | % | | 5.0 | % |
Retail Generation Revenues | | Three Months | | Six Months | |
| | (In millions) | |
Residential | | $ | 7 | | $ | 10 | |
Commercial | | | 3 | | | 5 | |
Industrial | | | - | | | - | |
Increase in Generation Revenues | | $ | 10 | | $ | 15 | |
Wholesale revenues increased by $36 million in the second quarter of 2007 and $62 million in the first six months of 2007 compared with the same periods of 2006. The increases in both periods were due to Met-Ed selling additional available power into the PJM market beginning in January 2007.
Revenues from distribution throughput increased by $22 million in the second quarter and $43 million in the first six months of 2007 compared to the same periods in 2006. The increases are due to higher KWH deliveries, reflecting the effect of the weather discussed above, and an increase in composite unit prices resulting from a January 2007 PPUC authorization to increase transmission rates, partially offset by a 5% decrease in distribution rates.
Changes in distribution KWH deliveries and revenues in the second quarter and first six months of 2007 compared to the same periods of 2006 are summarized in the following tables:
Distribution KWH Deliveries | | Three Months | | Six Months | |
Residential | | | 11.7 | % | | 8.7 | % |
Commercial | | | 4.7 | % | | 4.1 | % |
Industrial | | | 0.5 | % | | 0.7 | % |
Total Increase in Distribution Deliveries | | | 5.7 | % | | 4.8 | % |
Distribution Revenues | | Three Months | | Six Months | |
| | (In millions) | |
Residential | | $ | 15 | | $ | 32 | |
Commercial | | | 2 | | | 1 | |
Industrial | | | 5 | | | 10 | |
Increase in Distribution Revenues | | $ | 22 | | $ | 43 | |
PJM transmission revenues increased by $13 million and $20 million in the second quarter and first six months of 2007, respectively, as a result of higher transmission volumes and additional PJM auction revenue rights, compared to the prior year periods. Met-Ed defers the difference between revenue from its transmission rider and transmission costs incurred, resulting in no material effect to current period earnings.
Expenses
Total expenses increased by $112 million and $142 million in the second quarter and first six months of 2007, respectively, compared to the same periods of 2006. The following table presents changes from the prior year by expense category:
Expenses – Changes | | Three Months | | Six Months | |
Increase (Decrease) | | (In millions) | |
Purchased power costs | | $ | 40 | | $ | 72 | |
Other operating costs | | | 52 | | | 88 | |
Amortization of regulatory assets | | | 5 | | | 9 | |
Deferral of new regulatory assets | | | 13 | | | (29 | ) |
General taxes | | | 2 | | | 2 | |
Net increase in expenses | | $ | 112 | | $ | 142 | |
Purchased power costs increased in the second quarter and first six months of 2007 by $40 million and $72 million, respectively, due to increased KWH purchases to source higher generation sales, combined with higher composite unit costs. In the second quarter of 2007, other operating costs increased primarily due to $47 million in higher congestion costs and other transmission expenses associated with the increased transmission volumes discussed above and $4 million of increased contractor service and labor costs for increased work on reliability-related projects. In the first six months of 2007, other operating costs increased primarily due to higher congestion costs and other transmission expenses ($84 million) and increased customer expenses ($3 million) related to Met-Ed’s customer assistance programs.
Met-Ed’s revenue in the first six months of 2007 included the recovery of a portion of the transmission costs that were deferred in 2006. As a result, amortization of regulatory assets increased in the second quarter and first six months of 2007 compared to the prior year. In the second quarter of 2007, the deferral of new regulatory assets decreased primarily due to higher PJM transmission cost deferrals recognized in the second quarter of 2006. The deferral in the second quarter of 2006 also included PJM Transmission costs incurred in the first quarter following authorization by the PPUC in May 2006. The deferral of new regulatory assets increased in the first six months of 2007 due to the deferral of previously expensed decommissioning costs of $15 million associated with the Saxton nuclear research facility as approved by the PPUC in January 2007 and higher PJM transmission costs and associated interest deferrals.
For both periods, general taxes increased primarily due to higher gross receipts taxes.
Capital Resources and Liquidity
During 2007, Met-Ed expects to meet its contractual obligations with a combination of cash from operations and funds from the capital markets. Borrowing capacity under Met-Ed’s credit facilities is available to manage its working capital requirements.
Changes in Cash Position
As of June 30, 2007, Met-Ed had cash and cash equivalents of $127,000 compared with $130,000 as of December 31, 2006. The major sources of changes in these balances are summarized below.
Cash Flows From Operating Activities
Net cash used for operating activities was $109 million in the first six months of 2007 compared to net cash provided from operating activities of $58 million in the same period of 2006, as summarized in the following table:
| | Six Months Ended June 30, | |
| | 2007 | | 2006 | |
| | (In millions) | |
| | | | | | | |
Net non-cash charges (credits) | | | | ) | | | ) |
Pension trust contribution | | | | | | | |
Working capital and other | | | | | | | |
Net cash provided from (used for) operating activities | | | | ) | | | |
The decrease from working capital primarily resulted from a $103 million change in receivables, due in part to increased billings associated with the January 2007 rate increase that were delayed until the second quarter of 2007, and a $68 million change in accounts payable, partially offset by a $16 million decrease in prepayments, a $7 million increase in cash collateral received from suppliers and an $8 million increase in cash flows from other operating activities. Changes in net income and non-cash charges (credits) are described above under “Results of Operations.”
Cash Flows From Financing Activities
Net cash provided from financing activities was $164 million in the first six months of 2007 compared to net cash used for financing of $2 million in the first six months of 2006. The increase reflects a $216 million increase in short-term borrowings, offset by a $50 million increase in long-term debt redemptions in the first six months of 2007.
As of June 30, 2007, Met-Ed had approximately $34 million of cash and temporary investments (which included short-term notes receivable from associated companies) and $356 million of short-term borrowings (including $72 million from its receivables financing arrangement and $138 million from money pool borrowings). Met-Ed has authorization from the FERC to incur short-term debt up to $250 million (excluding receivables financing and money pool borrowings) and authorization from the PPUC to incur money pool borrowings up to $300 million.
See the “Financing Capability” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for additional discussion of Met-Ed’s financing capabilities.
Cash Flows From Investing Activities
In the first six months of 2007, Met-Ed's cash used for investing activities totaled $55 million, compared to $56 million in the same period of 2006. The decrease primarily resulted from a reduction in loan repayments to associated companies.
During the last half of 2007, capital requirements for property additions and improvements are expected to be approximately $42 million. This cash requirement is expected to be satisfied from a combination of cash from operations, short-term credit arrangements and funds from the capital markets. Met-Ed's capital spending for the period 2007 through 2011 is expected to be about $520 million, of which approximately $92 million applies to 2007.
In June 2007, Met-Ed entered into an agreement to sell 100% of its ownership interest in York Haven Power Company, pending approval from the PPUC. The sale is subject to regulatory accounting and is not expected to have a material impact on Met-Ed’s earnings.
Market Risk Information
During the first six months of 2007, the value of commodity derivative contracts decreased by $5 million as a result of settled contracts ($6 million) and changes in the value of existing contracts ($1 million). These non-trading contracts are adjusted to fair value at the end of each quarter with a corresponding offset to regulatory liabilities, resulting in no impact to current period earnings. Commodity derivative contracts were valued at $18 million and $23 million as of June 30, 2007 and December 31, 2006, respectively. See the “Market Risk Information” section of Met-Ed’s 2006 Annual Report on Form 10-K for additional discussion of market risk.
Equity Price Risk
Included in nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $175 million and $164 million as of June 30, 2007 and December 31, 2006, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in an $18 million reduction in fair value as of June 30, 2007.
Regulatory Matters
See the “Regulatory Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of regulatory matters applicable to Met-Ed.
Environmental Matters
See the “Environmental Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of environmental matters applicable to Met-Ed.
Other Legal Proceedings
See the “Other Legal Proceedings” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other legal proceedings applicable to Met-Ed.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to Met-Ed.
PENNSYLVANIA ELECTRIC COMPANY | |
| | | | | | | | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | | | | | | | |
| | Three Months Ended | | | Six Months Ended | |
| | June 30, | | | June 30, | |
| | 2007 | | | 2006 | | | 2007 | | | 2006 | |
| | (In thousands) | |
REVENUES: | | | | | | | | | | | | |
Electric sales | | $ | 315,745 | | | $ | 250,400 | | | $ | 654,971 | | | $ | 526,227 | |
Gross receipts tax collections | | | 15,672 | | | | 14,599 | | | | 32,352 | | | | 30,524 | |
Total revenues | | | 331,417 | | | | 264,999 | | | | 687,323 | | | | 556,751 | |
| | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | |
Purchased power | | | 184,494 | | | | 146,875 | | | | 385,336 | | | | 308,516 | |
Other operating costs | | | 58,267 | | | | 48,133 | | | | 117,728 | | | | 86,475 | |
Provision for depreciation | | | 12,335 | | | | 11,798 | | | | 24,112 | | | | 24,441 | |
Amortization of regulatory assets | | | 13,845 | | | | 12,979 | | | | 29,239 | | | | 27,794 | |
Deferral of new regulatory assets | | | (364 | ) | | | (11,815 | ) | | | (17,452 | ) | | | (11,815 | ) |
General taxes | | | 18,350 | | | | 17,458 | | | | 38,201 | | | | 36,847 | |
Total expenses | | | 286,927 | | | | 225,428 | | | | 577,164 | | | | 472,258 | |
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 44,490 | | | | 39,571 | | | | 110,159 | | | | 84,493 | |
| | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | |
Miscellaneous income | | | 2,135 | | | | 1,627 | | | | 3,552 | | | | 3,997 | |
Interest expense | | | (13,072 | ) | | | (11,599 | ) | | | (24,409 | ) | | | (22,135 | ) |
Capitalized interest | | | 285 | | | | 422 | | | | 543 | | | | 769 | |
Total other expense | | | (10,652 | ) | | | (9,550 | ) | | | (20,314 | ) | | | (17,369 | ) |
| | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 33,838 | | | | 30,021 | | | | 89,845 | | | | 67,124 | |
| | | | | | | | | | | | | | | | |
INCOME TAXES | | | 14,375 | | | | 14,564 | | | | 38,638 | | | | 28,518 | |
| | | | | | | | | | | | | | | | |
NET INCOME | | | 19,463 | | | | 15,457 | | | | 51,207 | | | | 38,606 | |
| | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | |
Pension and other postretirement benefits | | | (2,825 | ) | | | - | | | | (5,650 | ) | | | - | |
Unrealized gain on derivative hedges | | | 17 | | | | 16 | | | | 33 | | | | 32 | |
Change in unrealized gain on available for sale securities | | | (13 | ) | | | (14 | ) | | | (16 | ) | | | (18 | ) |
Other comprehensive income (loss) | | | (2,821 | ) | | | 2 | | | | (5,633 | ) | | | 14 | |
Income tax expense (benefit) related to other | | | | | | | | | | | | | | | | |
comprehensive income | | | (1,302 | ) | | | 1 | | | | (2,600 | ) | | | 7 | |
Other comprehensive income (loss), net of tax | | | (1,519 | ) | | | 1 | | | | (3,033 | ) | | | 7 | |
| | | | | | | | | | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 17,944 | | | $ | 15,458 | | | $ | 48,174 | | | $ | 38,613 | |
| | | | | | | | | | | | | | | | |
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) | |
| | June 30, | | | December 31, | |
| | 2007 | | | 2006 | |
| | (In thousands) | |
ASSETS | | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 40 | | | $ | 44 | |
Receivables- | | | | | | | | |
Customers (less accumulated provisions of $4,216,000 and $3,814,000 | | | | | | | | |
respectively, for uncollectible accounts) | | | 143,874 | | | | 126,639 | |
Associated companies | | | 73,743 | | | | 49,728 | |
Other | | | 19,809 | | | | 16,367 | |
Notes receivable from associated companies | | | 18,263 | | | | 19,548 | |
Prepaid taxes | | | 24,740 | | | | 3,016 | |
Other | | | 314 | | | | 1,220 | |
| | | 280,783 | | | | 216,562 | |
UTILITY PLANT: | | | | | | | | |
In service | | | 2,169,653 | | | | 2,141,324 | |
Less - Accumulated provision for depreciation | | | 822,098 | | | | 809,028 | |
| | | 1,347,555 | | | | 1,332,296 | |
Construction work in progress | | | 28,719 | | | | 22,124 | |
| | | 1,376,274 | | | | 1,354,420 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
Nuclear plant decommissioning trusts | | | 133,103 | | | | 125,216 | |
Non-utility generation trusts | | | 101,240 | | | | 99,814 | |
Other | | | 531 | | | | 531 | |
| | | 234,874 | | | | 225,561 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Goodwill | | | 860,716 | | | | 860,716 | |
Pension assets | | | 31,293 | | | | 11,474 | |
Other | | | 32,785 | | | | 36,059 | |
| | | 924,794 | | | | 908,249 | |
| | $ | 2,816,725 | | | $ | 2,704,792 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Short-term borrowings- | | | | | | | | |
Associated companies | | $ | 166,534 | | | $ | 199,231 | |
Other | | | 199,000 | | | | - | |
Accounts payable- | | | | | | | | |
Associated companies | | | 23,354 | | | | 92,020 | |
Other | | | 46,225 | | | | 47,629 | |
Accrued taxes | | | 2,920 | | | | 11,670 | |
Accrued interest | | | 7,404 | | | | 7,224 | |
Other | | | 21,703 | | | | 21,178 | |
| | | 467,140 | | | | 378,952 | |
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 | | | 1,189,479 | | | | 1,189,434 | |
Accumulated other comprehensive loss | | | (10,226 | ) | | | (7,193 | ) |
Retained earnings | | | 116,165 | | | | 90,005 | |
Total common stockholder's equity | | | 1,401,230 | | | | 1,378,058 | |
Long-term debt and other long-term obligations | | | 477,704 | | | | 477,304 | |
| | | 1,878,934 | | | | 1,855,362 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Regulatory liabilities | | | 73,990 | | | | 96,151 | |
Asset retirement obligations | | | 79,348 | | | | 76,924 | |
Accumulated deferred income taxes | | | 185,969 | | | | 193,662 | |
Retirement benefits | | | 50,974 | | | | 50,328 | |
Other | | | 80,370 | | | | 53,413 | |
| | | 470,651 | | | | 470,478 | |
COMMITMENTS AND CONTINGENCIES (Note 9) | | | | | | | | |
| | $ | 2,816,725 | | | $ | 2,704,792 | |
| | | | | | | | |
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) | |
| | | | | | |
| | Six Months Ended | |
| | June 30, | |
| | 2007 | | | 2006 | |
| | (In thousands) | |
| | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 51,207 | | | $ | 38,606 | |
Adjustments to reconcile net income to net cash from operating activities | | | | | | | | |
Provision for depreciation | | | 24,112 | | | | 24,441 | |
Amortization of regulatory assets | | | 29,239 | | | | 27,794 | |
Deferral of new regulatory assets | | | (17,452 | ) | | | (11,815 | ) |
Deferred costs recoverable as regulatory assets | | | (34,691 | ) | | | (54,092 | ) |
Deferred income taxes and investment tax credits, net | | | 13,548 | | | | 13,206 | |
Accrued compensation and retirement benefits | | | (12,130 | ) | | | 893 | |
Cash collateral | | | 3,250 | | | | - | |
Pension trust contribution | | | (13,436 | ) | | | - | |
Decrease (increase) in operating assets | | | | | | | | |
Receivables | | | (39,530 | ) | | | 30,485 | |
Prepayments and other current assets | | | (20,819 | ) | | | (18,565 | ) |
Increase (decrease) in operating liabilities | | | | | | | | |
Accounts payable | | | (70,070 | ) | | | (9,008 | ) |
Accrued taxes | | | (8,750 | ) | | | (10,756 | ) |
Accrued interest | | | 181 | | | | 190 | |
Other | | | 1,377 | | | | 8,817 | |
Net cash provided from (used for) operating activities | | | (93,964 | ) | | | 40,196 | |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing | | | | | | | | |
Short-term borrowings, net | | | 166,303 | | | | 26,642 | |
Dividend Payments | | | | | | | | |
Common stock | | | (25,000 | ) | | | - | |
Net cash provided from financing activities | | | 141,303 | | | | 26,642 | |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (43,904 | ) | | | (60,747 | ) |
Loan repayments from (loans to) associated companies, net | | | 1,285 | | | | (3,466 | ) |
Sales of investment securities held in trust | | | 26,882 | | | | 60,650 | |
Purchases of investment securities held in trust | | | (29,610 | ) | | | (60,650 | ) |
Other, net | | | (1,996 | ) | | | (2,611 | ) |
Net cash used for investing activities | | | (47,343 | ) | | | (66,824 | ) |
| | | | | | | | |
Net increase (decrease) in cash and cash equivalents | | | (4 | ) | | | 14 | |
Cash and cash equivalents at beginning of period | | | 44 | | | | 35 | |
Cash and cash equivalents at end of period | | $ | 40 | | | $ | 49 | |
| | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an | |
integral part of these statements. | | | | | | | | |
Report of Independent Registered Public Accounting Firm
To the Stockholder 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 June 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2007 and 2006 and the consolidated statement of cash flows for the six-month periods ended June 30, 2007 and 2006. 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, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006, and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 3, Note 2(G) and Note 9 to those consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
August 6, 2007
PENNSYLVANIA ELECTRIC COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern 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.
Results of Operations
Net income in the second quarter of 2007 increased to $19 million, compared to $15 million in the second quarter of 2006. This increase resulted from higher revenues partially offset by higher purchased power costs, other operating costs and lower deferrals of new regulatory assets due to the May 2006 PPUC order discussed below. In the first six months of 2007, net income increased to $51 million, compared to $39 million in the first six months of 2006. This increase in net income was due to higher revenues and deferrals of new regulatory assets, partially offset by increased purchased power costs and other operating costs.
Revenues
Revenues increased by $66 million, or 25.1%, in the second quarter of 2007 and $131 million, or 23.5%, in the first six months of 2007. The increases in both periods were primarily due to higher retail and wholesale generation revenues.
Retail generation revenues increased by $6 million in the second quarter of 2007 primarily due to higher KWH sales to residential and commercial customers. The increase in retail generation revenues in the residential and commercial classes was primarily due to higher weather-related usage in the second quarter of 2007 compared to the second quarter of 2006 (heating degree days increased 6.2% and cooling degree days increased 58.5%).
Retail generation revenues increased $12 million for the first six months of 2007 primarily due to higher KWH sales to all customer classes. The increase in retail generation revenues in the residential and commercial sectors was primarily due to weather conditions in the first six months of 2007 (heating degree days increased 12.5% and cooling degree days increased 58.5% as compared to the same time period of 2006).
Increases in retail electric generation sales and revenues in the second quarter and first six months of 2007 compared to the corresponding periods of 2006 are summarized in the following tables:
Retail Generation KWH Sales | | Three Months | | Six Months | |
Increase (Decrease) | | | | | |
Residential | | | 5.2 | % | | 5.5 | % |
Commercial | | | 4.9 | % | | 5.0 | % |
Industrial | | | (0.1 | )% | | - | |
Total Retail Electric Generation Sales | | | 3.3 | % | | 3.6 | % |
Retail Generation Revenues | | Three Months | | Six Months | |
| | (In millions) | |
Residential | | $ | 3 | | $ | 6 | |
Commercial | | | 3 | | | 6 | |
Industrial | | | - | | | - | |
Increase in Retail Generation Revenues | | $ | 6 | | $ | 12 | |
Wholesale revenues increased $39 million in the second quarter of 2007 and $74 million in the first six months of 2007, compared with the same periods of 2006 due to Penelec selling additional available power into the PJM market beginning in January 2007.
Revenues from distribution throughput increased $13 million in the second quarter and $29 million in the first six months of 2007 due to higher KWH deliveries reflecting the effect of the weather discussed above and an increase in composite unit prices resulting from a January 2007 PPUC authorization to increase transmission rates, partially offset by a 4.5% decrease in distribution rates.
Changes in distribution KWH deliveries and revenues in the second quarter and first six months of 2007 compared to the same periods in 2006 are summarized in the following tables:
Distribution KWH Deliveries | | Three Months | | Six Months | |
Increase (Decrease) | | | | | |
Residential | | | 5.2 | % | | 5.5 | % |
Commercial | | | 4.9 | % | | 5.0 | % |
Industrial | | | - | | | (0.9 | )% |
Total Distribution Deliveries | | | 3.2 | % | | 3.1 | % |
Distribution Revenues | | Three Months | | Six Months | |
Increase (Decrease) | | (In millions) | |
Residential | | $ | 13 | | $ | 30 | |
Commercial | | | (1 | ) | | (3 | ) |
Industrial | | | 1 | | | 2 | |
Total Distribution Revenues | | $ | 13 | | $ | 29 | |
PJM transmission revenues increased by $9 million in the second quarter of 2007 and $15 million in the first six months of 2007 compared to the same period in 2006 due to higher transmission volumes and additional PJM auction revenue rights in 2007. Penelec defers the difference between revenue from its transmission rider and transmission costs incurred, with no material effect to current period earnings.
Expenses
Total expenses increased by $62 million in the second quarter of 2007 and $105 million in the first six months of 2007 compared with the same periods in 2006. The following table presents changes from the prior year by expense category:
| | Three | | Six | |
Expenses - Changes | | Months | | Months | |
| | (In millions) |
Increase (Decrease) | | | | | |
Purchased power costs | | $ | 38 | | $ | 77 | |
Other operating costs | | | 10 | | | 31 | |
Provision for depreciation | | | 1 | | | - | |
Amortization of regulatory assets | | | 1 | | | 1 | |
Deferral of new regulatory assets | | | 11 | | | (5 | ) |
General taxes | | | 1 | | | 1 | |
Net increase in expenses | | $ | 62 | | $ | 105 | |
Purchased power costs increased by $38 million, or 25.6%, in the second quarter of 2007 and $77 million, or 24.9%, in the first six months of 2007, compared to the same period of 2006. The increases were due primarily to higher KWH purchases to source higher retail and wholesale generation sales combined with higher composite unit costs. Other operating costs increased by $9 million in the second quarter of 2007 and $32 million in the first six months of 2007 principally due to higher congestion costs and other transmission expenses associated with the increased transmission volumes discussed above.
In the second quarter of 2007, the deferral of new regulatory assets decreased primarily due to higher PJM transmission cost deferrals recognized in the second quarter of 2006. The deferral in the second quarter of 2006 also included PJM transmission costs incurred in the first quarter following authorization by the PPUC in May 2006. The deferral of new regulatory assets increased in the first six months of 2007 due to the deferral of previously expensed decommissioning costs of $12 million associated with the Saxton nuclear research facility as approved by the PPUC in January 2007, partially offset by lower PJM transmission cost deferrals.
Capital Resources and Liquidity
During 2007, Penelec expects to meet its contractual obligations with a combination of cash from operations and funds from the capital markets. Borrowing capacity under Penelec’s credit facilities is available to manage its working capital requirements.
Changes in Cash Position
As of June 30, 2007, Penelec had $40,000 of cash and cash equivalents compared with $44,000 as of December 31, 2006. The major sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Net cash provided (used) for operating activities in the second quarter of 2007 and 2006 were as follows:
| | Six Months Ended | |
| | June 30, | |
Operating Cash Flows | | 2007 | | 2006 | |
| | (In millions) | |
| | | | | |
Net income | | $ | 51 | | $ | 39 | |
Net non-cash charges | | | 3 | | | - | |
Pension trust contribution | | | (13 | ) | | - | |
Working capital and other | | | (135 | ) | | 1 | |
Net cash provided from (used for) operating activities | | $ | (94 | ) | $ | 40 | |
The $136 million change from working capital principally resulted from a $70 million change in accounts receivable due in part to increased billings associated with the January 2007 rate increase that were delayed until the second quarter of 2007, increased cash payments of $61 million for accounts payable and $8 million in increased cash outflows from other operating activities partially offset by a $3 million increase in cash collateral received from suppliers. Changes in net income and non-cash charges are described under “Results of Operations.”
Cash Flows From Financing Activities
Net cash provided from financing activities was $141 million in the first six months of 2007 compared to $26 million in the first six months of 2006. The increase reflects a $140 million increase in short-term borrowings, partially offset by a $25 million increase in common stock dividend payments to FirstEnergy.
Penelec had approximately $18 million of cash and temporary investments (which included short-term notes receivable from associated companies) and $366 million of short-term indebtedness (including $74 million from its receivables financing arrangement and $167 million in money pool borrowings) as of June 30, 2007. Penelec has authorization from the FERC to incur short-term debt of up to $250 million (excluding receivables financing and money pool borrowings) and authorization from the PPUC to incur money pool borrowings of up to $300 million.
See the “Financing Capability” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for additional discussion of Penelec’s financing capabilities.
Cash Flows From Investing Activities
In the first six months of 2007, net cash used for investing activities totaled $47 million compared to $67 million in the first six months of 2006. The decrease primarily resulted from a $17 million decrease in property additions and a $5 million increase in loan repayments from associated companies, partially offset by a $3 million increase in the investments in the nuclear decommissioning trust fund.
During the last half of 2007, capital requirements for property additions are expected to be about $46 million. Penelec’s capital spending for the period 2007-2011 is expected to be about $614 million, of which approximately $92 million applies to 2007.
Market Risk Information
During the first six months of 2007, the value of commodity derivative contracts decreased by $2 million as a result of settled contracts. These non-trading contracts are adjusted to fair value at the end of each quarter with a corresponding offset to regulatory liabilities, resulting in no impact to current period earnings. Commodity derivative contracts were valued at $10 million and $12 million as of June 30, 2007 and December 31, 2006, respectively. See the “Market Risk Information” section of Penelec’s 2006 Annual Report on Form 10-K for additional discussion of market risk.
Equity Price Risk
Included in nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $80 million and $72 million as of June 30, 2007 and December 31, 2006, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in an $8 million reduction in fair value as of June 30, 2007.
Regulatory Matters
See the “Regulatory Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of regulatory matters applicable to Penelec.
Environmental Matters
See the “Environmental Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of environmental matters applicable to Penelec.
Other Legal Proceedings
See the “Other Legal Proceedings” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other legal proceedings applicable to Penelec.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to Penelec.
COMBINED MANAGEMENT’S DISCUSSION
AND ANALYSIS OF REGISTRANT SUBSIDIARIES
The following is a combined presentation of certain disclosures referenced in Management’s Discussion and Analysis of Financial Condition and Results of Operations of the Companies. This information should be read in conjunction with (i) the Companies’ respective Consolidated Financial Statements and Management’s Discussion and Analysis of Financial Condition and Results of Operations; (ii) the Notes to Consolidated Financial Statements as they relate to the Companies; and (iii) the Companies’ respective 2006 Annual Reports on Form 10-K.
Financing Capability (Applicable to each of the Companies)
As of June 30, 2007, OE, CEI and TE had the capability to issue approximately $1.5 billion, $557 million and $797 million, respectively, of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMB by OE, CEI and TE is 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, CEI and TE to incur additional secured debt not otherwise permitted by a specified exception of up to $463 million, $515 million and $127 million, respectively, as of June 30, 2007. Because JCP&L satisfied the provision of its senior note indenture for the release of all FMBs held as collateral for senior notes in May 2007, it is no longer required to issue FMBs as collateral for senior notes and therefore is not limited as to the amount of senior notes it may issue.
The applicable earnings coverage tests in the respective charters of OE, TE, Penn and JCP&L are currently inoperative. In the event that any of them issues preferred stock in the future, the applicable earnings coverage test will govern the amount of preferred stock that may be issued. CEI, Met-Ed and Penelec do not have similar restrictions and could issue up to the number of preferred shares authorized under their respective charters.
As of June 30, 2007, OE had approximately $400 million of capacity remaining unused under its existing shelf registration for unsecured debt securities filed with the SEC in 2006.
FirstEnergy and certain of its subsidiaries are parties to a $2.75 billion five-year revolving credit facility (included in the borrowing capability table above). FirstEnergy may request an increase in the total commitments available under this facility up to a maximum of $3.25 billion. Commitments under the facility are available until August 24, 2011, unless the lenders agree, at the request of the Borrowers, to two additional one-year extensions. Generally, borrowings under the facility must be repaid within 364 days. Available amounts for each Borrower are subject to a specified sub-limit, as well as applicable regulatory and other limitations.
The following table summarizes the borrowing sub-limits for each borrower under the facility, as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations:
| | Revolving | | Regulatory and | |
| | Credit Facility | | Other Short-Term | |
| | | | | |
| | (In millions) | |
FirstEnergy | | $ | 2,750 | | $ | - | (2) |
OE | | | 500 | | | 500 | |
Penn | | | 50 | | | 39 | |
CEI | | | 250 | (3) | | 500 | |
TE | | | 250 | (3) | | 500 | |
JCP&L | | | 425 | | | 431 | |
Met-Ed | | | 250 | | | 250 | (4) |
Penelec | | | 250 | | | 250 | (4) |
| (2)
| No regulatory approvals, statutory or charter limitations applicable. |
| (3)
| Borrowing sub-limits for CEI and TE may be increased to up to $500 million by delivering notice to the
administrative agent that such borrower has senior unsecured debt ratings of at least BBB by S&P and
Baa2 by Moody’s.
|
| (4)
| Excluding amounts which may be borrowed under the regulated money pool. |
Under the revolving credit facility, borrowers may request the issuance of LOCs expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit.
The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter. As of June 30, 2007, FirstEnergy and its subsidiaries' debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:
Borrower
| | |
FirstEnergy
| | 61 | % |
OE*
| | 48 | % |
Penn
| | 24 | % |
CEI*
| | 60 | % |
TE*
| | 56 | % |
JCP&L
| | 32 | % |
Met-Ed
| | 46 | % |
Penelec*
| | 38 | % |
*The ratios of June 30, 2007, as adjusted for common stock dividends declared
in July 2007 would be: OE – 50%, CEI – 63%, TE – 61% and Penelec – 39%.
The revolving credit facility does not contain provisions that either restrict the ability to borrow or accelerate repayment of outstanding advances as a result of any change in credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds borrowed under the facility is related to the credit ratings of the company borrowing the funds.
The Companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. FESC administers the money pool and tracks surplus funds of FirstEnergy and the Companies, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first six months of 2007 was 5.64%.
Each of the Companies’ access to capital markets and costs of financing are influenced by the ratings of its securities and the securities of FirstEnergy. The following table displays FirstEnergy’s and the Companies’ securities ratings as of June 30, 2007. The ratings outlook from Moody’s is positive for all securities. The ratings outlook from S&P on all securities is stable. The ratings outlook from Fitch on CEI and TE is positive and stable on all other operating companies.
| | | | | | | | |
| | | | | | | | |
FirstEnergy | | Senior unsecured | | BBB- | | Baa3 | | BBB |
| | | | | | | | |
OE | | Senior unsecured | | BBB+ | | Baa1 | | BBB+ |
| | | | | | | | |
CEI | | Senior secured | | BBB | | Baa2 | | BBB |
| | Senior unsecured | | BBB- | | Baa3 | | BBB- |
| | | | | | | | |
TE | | Senior secured | | BBB | | Baa2 | | BBB |
| | Senior unsecured | | BBB- | | Baa3 | | BBB- |
| | | | | | | | |
Penn | | Senior secured | | BBB+ | | Baa1 | | BBB+ |
| | | | | | | | |
JCP&L | | Senior secured | | BBB+ | | Baa1 | | A- |
| | | | | | | | |
Met-Ed | | Senior unsecured | | BBB | | Baa2 | | BBB |
| | | | | | | | |
Penelec | | Senior unsecured | | BBB | | Baa2 | | BBB |
OE, CEI, Penn, Met-Ed and Penelec 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. The receivables financing borrowing capacity and outstanding balance by company, as of June 30, 2007, are shown in the following table.
Subsidiary Company | | Parent Company | | | Borrowing Capacity | | | Outstanding Balance | | Annual Facility Fee |
| | (In millions) |
OES Capital, Incorporated | | OE | | $ | 170 | | $ | 100 | | 0.15% |
Centerior Funding Corp. | | CEI | | | 200 | | | - | | 0.15 |
Penn Power Funding LLC | | Penn | | | 25 | | | 17 | | 0.125 |
Met-Ed Funding LLC | | Met-Ed | | | 80 | | | 72 | | 0.125 |
Penelec Funding LLC | | Penelec | | | 75 | | | 74 | | 0.125 |
| | | | $ | 550 | | $ | 263 | | |
Regulatory Matters(Applicable to each of the Companies)
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 customers to select a competitive electric generation supplier other than the Companies; |
| |
· | establishing or defining the PLR obligations to customers in the Companies' service areas; |
| |
· | providing the Companies with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market; |
| |
· | itemizing (unbundling) the price of electricity into its component elements – including generation, transmission, distribution and stranded costs recovery charges; |
| |
· | continuing regulation of the Companies' transmission and distribution systems; and |
| |
· | requiring corporate separation of regulated and unregulated business activities. |
The Companies 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. Regulatory assets that do not earn a current return totaled approximately $219 million as of June 30, 2007 (JCP&L - $103 million, Met-Ed - $34 million and Penelec - $82 million). Regulatory assets not earning a current return will be recovered by 2014 for JCP&L and by 2020 for Met-Ed and Penelec. The following table discloses regulatory assets by company:
| | June 30, | | December 31, | | Increase | |
Regulatory Assets* | | 2007 | | 2006 | | (Decrease) | |
| | (In millions) | |
OE | | $ | 733 | | $ | 741 | | $ | (8 | ) |
CEI | | | 863 | | | 855 | | | 8 | |
TE | | | 230 | | | 248 | | | (18 | ) |
JCP&L | | | 1,825 | | | 2,152 | | | (327 | ) |
Met-Ed | | | | | | | | | | |
Total | | | | | | | | | | ) |
* | Penelec had net regulatory liabilities of approximately $74 million
and $96 million as of June 30, 2007 and December 31, 2006,
respectively. These net regulatory liabilities are included in Other
Non-current Liabilities on the Consolidated Balance Sheets.
|
Ohio (Applicable to OE, CEI and TE)
On October 21, 2003, the Ohio Companies filed their RSP case with the PUCO. 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 CBP. The RSP was intended to establish generation service rates beginning January 1, 2006, in response to the PUCO’s concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming the PUCO's order in all respects, except it remanded back to the PUCO the matter of ensuring the availability of sufficient means for customer participation in the marketplace. The RSP contained a provision that permitted the Ohio Companies to withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies have 30 days from the final order or decision to provide notice of termination. On July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate a Proceeding on Remand. In their Request, the Ohio Companies provided notice of termination to those provisions of the RSP subject to termination, subject to being withdrawn, and also set forth a framework for addressing the Supreme Court of Ohio’s findings on customer participation. If the PUCO approves a resolution to the issues raised by the Supreme Court of Ohio that is acceptable to the Ohio Companies, the Ohio Companies’ termination will be withdrawn and considered to be null and void. On July 20, 2006, the OCC and NOAC also submitted to the PUCO a conceptual proposal addressing the issue raised by the Supreme Court of Ohio. On July 26, 2006, the PUCO issued an Entry directing the Ohio Companies to file a plan in a new docket to address the Court’s concern. The Ohio Companies filed their RSP Remand CBP on September 29, 2006. Initial comments were filed on January 12, 2007 and reply comments were filed on January 29, 2007. In their reply comments the Ohio Companies described the highlights of a new tariff offering they would be willing to make available to customers that would allow customers to purchase renewable energy certificates associated with a renewable generation source, subject to PUCO approval. On May 29, 2007, the Ohio Companies, together with the PUCO Staff and the OCC, filed a stipulation with the PUCO agreeing to offer a standard bid product and a green resource tariff product. The stipulation is currently pending before the PUCO. No further proceedings are scheduled at this time.
The Ohio Companies filed an application and stipulation with the PUCO on September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On November 4, 2005, the Ohio Companies filed a supplemental stipulation with the PUCO, which constituted an additional component of the RCP filed on September 9, 2005. On January 4, 2006, the PUCO approved, with modifications, the Ohio Companies’ RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. The following table provides the estimated net amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) under the RCP for the period 2007 through 2010:
Amortization | | | | | | | | | Total | |
| | | | | | | | Ohio | |
| | (In millions) | |
2007 | | $ | 179 | | $ | 108 | | $ | 93 | | $ | 380 | |
2008 | | | 208 | | | 124 | | | 119 | | | 451 | |
2009 | | | - | | | 216 | | | - | | | 216 | |
2010 | | | | | | | | | | | | | |
Total Amortization | | | | | | | | | | | | | |
On August 31, 2005, the PUCO approved a rider recovery mechanism through which the Ohio Companies may recover all MISO transmission and ancillary service related costs incurred during each year ending June 30. Pursuant to the PUCO’s order, the Ohio Companies, on May 1, 2007, filed revised riders, which became effective on July 1, 2007. The revised riders represent an increase over the amounts collected through the 2006 riders of approximately $64 million annually. If it is subsequently determined by the PUCO that adjustments to the rider as filed are necessary, such adjustments, with carrying costs, will be incorporated into the 2008 transmission rider filing.
On May 8, 2007, the Ohio Companies filed with the PUCO a notice of intent to file for an increase in electric distribution rates. The Ohio Companies filed the application and rate request with the PUCO on June 7, 2007. The requested increase is expected to be more than offset by the elimination or reduction of transition charges at the time the rates go into effect and would result in lowering the overall non-generation portion of the bill for most Ohio customers. The distribution rate increases reflect capital expenditures since the Ohio Companies’ last distribution rate proceedings, increases in operating and maintenance expenses and recovery of regulatory assets created by deferrals that were approved in prior cases. On August 6, 2007, the Ohio Companies provided an update filing supporting a distribution rate increase of $332��million to the PUCO to establish the test period data that will be used as the basis for setting rates in that proceeding. The PUCO Staff is expected to issue its report in the case in the fourth quarter of 2007 with evidentiary hearings to follow in late 2007. The PUCO order is expected to be issued by March 9, 2008. The new rates, subject to evidentiary hearings and approval at the PUCO, would become effective January 1, 2009 for OE and TE, and approximately May 2009 for CEI.
On July 10, 2007, the Ohio Companies filed an application with the PUCO requesting approval of a comprehensive supply plan for providing generation service to customers who do not purchase electricity from an alternative supplier, beginning January 1, 2009. The proposed competitive bidding process would average the results of multiple bidding sessions conducted at different times during the year. The final price per kilowatt-hour would reflect an average of the prices resulting from all bids. In their filing, the Ohio Companies offered two alternatives for structuring the bids, either by customer class or a “slice-of-system” approach. The proposal provides the PUCO with an option to phase in generation price increases for residential tariff groups who would experience a change in their average total price of 15 percent or more. The Ohio Companies requested that the PUCO issue an order by November 1, 2007, to provide sufficient time to conduct the bidding process. The PUCO has scheduled a technical conference for August 16, 2007.
Pennsylvania (Applicable to Met-Ed, Penelec and Penn)
Met-Ed and Penelec have been purchasing a portion of their PLR requirements from FES through a partial requirements wholesale power sales agreement and various amendments. Under these agreements, FES retained 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. The FES agreements have reduced Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR capacity and energy costs during the term of these agreements with FES.
On April 7, 2006, the parties entered into a tolling agreement that arose from FES’ notice to Met-Ed and Penelec that FES elected to exercise its right to terminate the partial requirements agreement effective midnight December 31, 2006. On November 29, 2006, Met-Ed, Penelec and FES agreed to suspend the April 7 tolling agreement pending resolution of the PPUC’s proceedings regarding the Met-Ed and Penelec comprehensive transition rate cases filed April 10, 2006, described below. Separately, on September 26, 2006, Met-Ed and Penelec successfully conducted a competitive RFP for a portion of their PLR obligation for the period December 1, 2006 through December 31, 2008. FES was one of the successful bidders in that RFP process and on September 26, 2006 entered into a supplier master agreement to supply a certain portion of Met-Ed’s and Penelec’s PLR requirements at market prices that substantially exceed the fixed price in the partial requirements agreements.
Based on the outcome of the 2006 comprehensive transition rate filing, as described below, Met-Ed, Penelec and FES agreed to restate the partial requirements power sales agreement effective January 1, 2007. The restated agreement incorporates the same fixed price for residual capacity and energy supplied by FES as in the prior arrangements between the parties, and automatically extends for successive one year terms unless any party gives 60 days’ notice prior to the end of the year. The restated agreement also allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy thus sold to the extent needed for Met-Ed and Penelec to satisfy their PLR obligations. The parties also have separately terminated the tolling, suspension and supplier master agreements in connection with the restatement of the partial requirements agreement. Accordingly, the energy that would have been supplied under the supplier master agreement will now be provided under the restated partial requirements agreement. The fixed price under the restated agreement is expected to remain below wholesale market prices during the term of the agreement.
If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for its fixed income securities. Based on the PPUC’s January 11, 2007 order described below, if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC.
Met-Ed and Penelec made a comprehensive rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals had been approved, annual revenues would have increased by $216 million and $157 million, respectively. That filing included, among other things, a request to charge customers for an increasing amount of market-priced power procured through a CBP as the amount of supply provided under the then existing FES agreement was to be phased out in accordance with the April 7, 2006 tolling agreement described above. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs, but only for those costs incurred during 2006. In this rate filing, Met-Ed and Penelec also requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the FirstEnergy and GPU merger proceeding, related to the quantification and allocation of the merger savings, with the comprehensive transmission rate filing case.
The PPUC entered its Opinion and Order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, when new transmission rates were effective, and determined that no merger savings from prior years should be considered in determining customers’ rates. The request for increases in generation supply rates was denied as were the requested changes in NUG expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased Met-Ed’s and Penelec’s distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission expenses and the transmission deferral. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and, in January 2007, Met-Ed and Penelec recognized income of $15 million and $12 million, respectively, to establish regulatory assets for those previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million). Met-Ed and Penelec filed a Petition for Reconsideration on January 26, 2007 on the issues of consolidated tax savings and rate of return on equity. Other parties filed Petitions for Reconsideration on transmission (including congestion), transmission deferrals and rate design issues. On February 8, 2007, the PPUC entered an order granting Met-Ed’s, Penelec’s and the other parties’ petitions for procedural purposes. Due to that ruling, the period for appeals to the Commonwealth Court of Pennsylvania was tolled until 30 days after the PPUC entered a subsequent order ruling on the substantive issues raised in the petitions. On March 1, 2007, the PPUC issued three orders: (1) a tentative order regarding the reconsideration by the PPUC of its own order; (2) an order denying the Petitions for Reconsideration of Met-Ed, Penelec and the OCA and denying in part and accepting in part MEIUG’s and PICA’s Petition for Reconsideration; and (3) an order approving the Compliance filing. Comments to the PPUC for reconsideration of its order were filed on March 8, 2007, and the PPUC ruled on the reconsideration on April 13, 2007, making minor changes to rate design as agreed upon by Met-Ed, Penelec and certain other parties.
On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase. The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. On June 19, 2007, initial briefs were filed by all parties. Responsive briefs are due August 20, 2007, with reply briefs due September 4, 2007. Oral arguments are expected to take place in late 2007 or early 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the financial condition and results of operations of Met-Ed, Penelec and FirstEnergy.
As of June 30, 2007, Met-Ed's and Penelec's unrecovered regulatory deferrals pursuant to the 2006 comprehensive transition rate case, the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation were $493 million and $127 million, respectively. $82 million of Penelec’s deferral is subject to final resolution of an IRS settlement associated with NUG trust fund proceeds. During the PPUC’s annual audit of Met-Ed’s and Penelec’s NUG stranded cost balances in 2006, it noted a modification to the NUG purchased power stranded cost accounting methodology made by Met-Ed and Penelec. On August 18, 2006, a PPUC Order was entered requiring Met-Ed and Penelec to reflect the deferred NUG cost balances as if the stranded cost accounting methodology modification had not been implemented. As a result of this PPUC order, Met-Ed recognized a pre-tax charge of approximately $10.3 million in the third quarter of 2006, representing incremental costs deferred under the revised methodology in 2005. Met-Ed and Penelec continue to believe that the stranded cost accounting methodology modification is appropriate and on August 24, 2006 filed a petition with the PPUC pursuant to its order for authorization to reflect the stranded cost accounting methodology modification effective January 1, 1999. Hearings on this petition were held in late February 2007 and briefing was completed on March 28, 2007. The ALJ’s initial decision was issued on May 3, 2007 and denied Met-Ed's and Penelec’s request to modify their NUG stranded cost accounting methodology. The companies filed exceptions to the initial decision on May 23, 2007 and replies to those exceptions were filed on June 4, 2007. It is not known when the PPUC may issue a final decision in this matter.
On May 2, 2007, Penn filed a plan with the PPUC for the procurement of PLR supply from June 2008 through May 2011. The filing proposes multiple, competitive RFPs with staggered delivery periods for fixed-price, tranche-based, pay as bid PLR supply to the residential and commercial classes. The proposal phases out existing promotional rates and eliminates the declining block and the demand components on generation rates for residential and commercial customers. The industrial class PLR service would be provided through an hourly-priced service provided by Penn. Quarterly reconciliation of the differences between the costs of supply and revenues from customers is also proposed. The PPUC is requested to act on the proposal no later than November 2007 for the initial RFP to take place in January 2008.
On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation programs to meet demand growth, a requirement that electric distribution companies acquire power that results in the “lowest reasonable rate on a long-term basis," the utilization of micro-grids and an optional three year phase-in of rate increases. On July 17, 2007 the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long-term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy will be convened in mid-September 2007 to consider other aspects of the EIS. The final form of any legislation arising from the special legislative session is uncertain. Consequently, FirstEnergy is unable to predict what impact, if any, such legislation may have on its operations.
New Jersey (Applicable to JCP&L)
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 NUGC rates and market sales of NUG energy and capacity. As of June 30, 2007, the accumulated deferred cost balance totaled approximately $392 million.
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 DRA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. A schedule for further NJBPU proceedings has not yet been set.
On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that would prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. These regulations are not expected to materially impact FirstEnergy or JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. Comments on the alternative proposal were submitted on June 15, 2006. On November 3, 2006, the Staff circulated a revised draft proposal to interested stakeholders. Another revised draft was circulated by the NJBPU Staff on February 8, 2007.
New Jersey statutes require that the state periodically undertake a planning process, known as the Energy Master Plan (EMP), to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated with the issuance of a proposed set of objectives which, as to electricity, included the following:
·Reduce the total projected electricity demand by 20% by 2020;
· Meet 22.5% of New Jersey’s electricity needs with renewable energy resources by that date;
·Reduce air pollution related to energy use;
·Encourage and maintain economic growth and development;
· Achieve a 20% reduction in both Customer Average Interruption Duration Index and System Average Interruption Frequency Index by 2020;
· Unit prices for electricity should remain no more than +5% of the regional average price (region includes New York, New Jersey, Pennsylvania, Delaware, Maryland and the
District of Columbia); and
·Eliminate transmission congestion by 2020.
Comments on the objectives and participation in the development of the EMP have been solicited and a number of working groups have been formed to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. EMP working groups addressing (1) energy efficiency and demand response, (2) renewables, (3) reliability, and (4) pricing issues have completed their assigned tasks of data gathering and analysis and have provided reports to the EMP Committee. Public stakeholder meetings were held in the fall of 2006 and in early 2007, and further public meetings are expected later in 2007. A final draft of the EMP is expected to be presented to the Governor in late 2007. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation may have on its operations or those of JCP&L.
On February 13, 2007, the NJBPU Staff informally issued a draft proposal relating to changes to the regulations addressing electric distribution service reliability and quality standards. Meetings between the NJBPU Staff and interested stakeholders to discuss the proposal were held and additional, revised informal proposals were subsequently circulated by the Staff. On August 1, 2007, the NJBPU approved publication of a formal proposal in the New Jersey Register, which proposal will be subsequently considered by the NJBPU following a period for public comment. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such regulations may have on its operations or those of JCP&L.
FERC Matters (Applicable to each of the Companies)
On November 18, 2004, the FERC issued an order eliminating the RTOR for transmission service between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a SECA mechanism to recover lost RTOR revenues during a 16-month transition period from load serving entities. The FERC issued orders in 2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES participated in the FERC hearings held in May 2006 concerning the calculation and imposition of the SECA charges. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by the RTOs and transmission owners, ruling on various issues and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order could be issued by the FERC in the third quarter of 2007.
On January 31, 2005, certain PJM transmission owners made three filings with the FERC 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. Hearings were held and numerous parties appeared and litigated various issues; including American Electric Power Company, Inc., which filed in opposition proposing to create a "postage stamp" rate for high voltage transmission facilities across PJM. At the conclusion of the hearings, the ALJ issued an initial decision adopting the FERC Trial Staff’s position that the cost of all PJM transmission facilities should be recovered through a postage stamp rate.The ALJ recommended an April 1, 2006 effective date for this change in rate design. Numerous parties, including FirstEnergy, submitted briefs opposing the ALJ’s decision and recommendations. On April 19, 2007, the FERC issued an order rejecting the ALJ’s findings and recommendations in nearly every respect. The FERC found that the PJM transmission owners’ existing “license plate” rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be socialized throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. Nevertheless, the FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.
On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 Order. Subsequently, FirstEnergy and other parties filed pleadings opposing the requests for rehearing. The FERC’s Orders on PJM rate design, if sustained on rehearing and appeal, will prevent the allocation of the cost of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reduce future transmission costs shifting to the JCP&L, Met-Ed and Penelec zones.
On August 1, 2007, a number of filings were made with the FERC by transmission owning utilities in the MISO and PJM footprint that could affect the transmission rates paid by FirstEnergy’s operating companies and FES.
FirstEnergy joined in a filing made by the MISO transmission owners that would maintain the existing “license plate” rates for transmission service within MISO provided over existing transmission facilities. FirstEnergy also joined in a filing made by both the MISO and PJM transmission owners proposing to maintain existing transmission rates between MISO and PJM. If accepted by the FERC, these filings would not affect the rates charged to load-serving FirstEnergy affiliates for transmission service over existing transmission facilities. In a related filing, MISO and MISO transmission owners requested that the current MISO pricing for new transmission facilities that spreads 20% of the cost of new 345 kV transmission facilities across the entire MISO footprint be maintained. All of these filings were supported by the majority of transmission owners in either MISO or PJM.
The Midwest Stand-Alone Transmission Companies made a filing under Section 205 of the Federal Power Act requesting that 100% of the cost of new qualifying 345 kV transmission facilities be spread throughout the entire MISO footprint. If adopted by the FERC, this proposal would shift a greater portion of the cost of new 345 kV transmission facilities to the FirstEnergy footprint, and increase the transmission rates paid by load-serving FirstEnergy affiliates.
American Electric Power (AEP) filed a letter with the FERC Commissioners stating its intent to file a complaint under Section 206 of the Federal Power Act challenging the justness and reasonableness of the rate designs underlying the MISO and PJM transmission tariffs. AEP will propose the adoption of a regional rate design that is expected to reallocate the cost of both existing and new high voltage transmission facilities across the combined MISO and PJM footprint. Based upon the position advocated by AEP in a related proceeding, the AEP proposal is expected to result in a greater allocation of costs to FirstEnergy transmission zones in MISO and PJM. If approved by the FERC, AEP’s proposal would increase the transmission rates paid by load-serving FirstEnergy affiliates.
Any increase in rates charged for transmission service to FirstEnergy affiliates is dependent upon the outcome of these proceedings at FERC. All or some of these proceedings may be consolidated by the FERC and set for hearing. The outcome of these cases cannot be predicted. Any material adverse impact on FirstEnergy would depend upon the ability of the load-serving FirstEnergy affiliates to recover increased transmission costs in their retail rates. FirstEnergy believes that current retail rate mechanisms in place for PLR service for the Ohio Companies and for Met-Ed and Penelec would permit them to pass through increased transmission charges in their retail rates. Increased transmission charges in the JCP&L and Penn transmission zones would be the responsibility of competitive electric retail suppliers, including FES.
On February 15, 2007, MISO filed documents with the FERC to establish a market-based, competitive ancillary services market. MISO contends that the filing will integrate operating reserves into MISO’s existing day-ahead and real-time settlements process, incorporate opportunity costs into these markets, address scarcity pricing through the implementation of a demand curve methodology, foster demand response in the provision of operating reserves, and provide for various efficiencies and optimization with regard to generation dispatch. The filing also proposes amendments to existing documents to provide for the transfer of balancing functions from existing local balancing authorities to MISO. MISO will then carry out this reliability function as the NERC-certified balancing authority for the MISO region with implementation in the third or fourth quarter of 2008. FirstEnergy filed comments on March 23, 2007, supporting the ancillary service market in concept, but proposing certain changes in MISO’s proposal. MISO requested FERC action on its filing by June 2007 and the FERC issued its Order June 22, 2007. The FERC found MISO’s filing to be deficient in two key areas: (1) MISO has not submitted a market power analysis in support of its proposed Ancillary Services Market and (2) MISO has not submitted a readiness plan to ensure reliability during the transition from the current reserve and regulation system managed by the individual Balancing Authorities to a centralized Ancillary Services Market managed by MISO. MISO was ordered to remedy these deficiencies and the FERC provided more guidance on other issues brought up in filings by stakeholders to assist MISO to re-file a complete proposal. This Order should facilitate MISO’s timetable to incorporate final revisions to ensure a market start in Spring 2008. FirstEnergy will be participating in working groups and task forces to ensure the Spring 2008 implementation of the Ancillary Services Market.
On February 16, 2007, the FERC issued a final rule that revises its decade-old open access transmission regulations and policies. The FERC explained that the final rule is intended to strengthen non-discriminatory access to the transmission grid, facilitate FERC enforcement, and provide for a more open and coordinated transmission planning process. The final rule became effective on May 14, 2007. MISO, PJM and ATSI will be filing revised tariffs to comply with the FERC’s order. As market participants in both MISO and PJM, the Companies will conform their business practices to each respective revised tariff.
Environmental Matters(Applicable to each of the Companies)
The Companies accrue environmental liabilities only when they conclude that it is probable that they have an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in the Companies’ determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.
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 June 30, 2007, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable SBC. Total liabilities of approximately $88 million (JCP&L - $60 million, TE - $3 million, CEI - $1 million, and other subsidiaries - $24 million) have been accrued through June 30, 2007.
W. H. Sammis Plant (Applicable to OE and Penn)
In 1999 and 2000, the EPA issued NOV or compliance orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which was owned at that time by OE and Penn, and is now owned by FGCO. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as the New Source Review, or NSR, cases.
On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation. This settlement agreement, which is in the form of a consent decree, was approved by the court on July 11, 2005, and requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FirstEnergy fails to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FirstEnergy could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation settlement agreement are currently estimated to be $1.7 billion for FGCO for 2007 through 2011 ($400 million of which is expected to be spent during 2007, with the largest portion of the remaining $1.3 billion expected to be spent in 2008 and 2009).
The Sammis NSR Litigation consent decree also requires FirstEnergy to spend up to $25 million toward environmentally beneficial projects, $14 million of which is satisfied by entering into 93 MW (or 23 MW if federal tax credits are not applicable) of wind energy purchased power agreements with a 20-year term. An initial 16 MW of the 93 MW consent decree obligation was satisfied during 2006.
Other Legal Proceedings(Applicable to each of the Companies)
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to the Companies’ normal business operations pending against FirstEnergy and the Companies. The other material items not otherwise discussed above are described below.
Power Outages and Related Litigation
In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four of New Jersey’s electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the JCP&L territory.
In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision on July 8, 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, on March 7, 2007, reversed the decertification of the Red Bank class and remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied on May 9, 2007. Proceedings are continuing in the Superior Court. FirstEnergy is vigorously defending this class action but is unable to predict the outcome of this matter. No liability has been accrued as of June 30, 2007.
On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. – Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s Web site (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy is also proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional material expenditures.
FirstEnergy companies also are defending four separate complaint cases before the PUCO relating to the August 14, 2003 power outages. Two of those cases were originally filed in Ohio State courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In these cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Two other pending PUCO complaint cases were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of these cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and American Electric Power Company, Inc., as well) for claims paid to insureds for damages allegedly arising as a result of the loss of power on August 14, 2003. A fifth case in which a carrier sought reimbursement for claims paid to insureds was voluntarily dismissed by the claimant in April 2007. A sixth case involving the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003 was dismissed. The four cases were consolidated for hearing by the PUCO in an order dated March 7, 2006. In that order the PUCO also limited the litigation to service-related claims by customers of the Ohio operating companies; dismissed FirstEnergy as a defendant; and ruled that the U.S.-Canada Power System Outage Task Force Report was not admissible into evidence. In response to a motion for rehearing filed by one of the claimants, the PUCO ruled on April 26, 2006 that the insurance company claimants, as insurers, may prosecute their claims in their name so long as they also identify the underlying insured entities and the Ohio utilities that provide their service. The PUCO denied all other motions for rehearing. The plaintiffs in each case have since filed amended complaints and the named FirstEnergy companies have answered and also have filed a motion to dismiss each action. On September 27, 2006, the PUCO dismissed certain parties and claims and otherwise ordered the complaints to go forward to hearing. The cases have been set for hearing on January 8, 2008.
On October 10, 2006, various insurance carriers refiled a complaint in Cuyahoga County Common Pleas Court seeking reimbursement for claims paid to numerous insureds who allegedly suffered losses as a result of the August 14, 2003 outages. All of the insureds appear to be non-customers. The plaintiff insurance companies are the same claimants in one of the pending PUCO cases. FirstEnergy, the Ohio Companies and Penn were served on October 27, 2006. On January 18, 2007, the Court granted the Companies’ motion to dismiss the case and they have not been appealed. However, on April 25, 2007, one of the insurance carriers refiled the complaint naming only FirstEnergy as the defendant. On July 30, 2007, the case was voluntarily dismissed. No estimate of potential liability is available for any of these cases.
FirstEnergy was also named, along with several other entities, in a complaint in New Jersey State Court. The allegations against FirstEnergy were based, in part, on an alleged failure to protect the citizens of Jersey City from an electrical power outage. None of FirstEnergy’s subsidiaries serve customers in Jersey City. A responsive pleading has been filed. On April 28, 2006, the Court granted FirstEnergy's motion to dismiss. The plaintiff has not appealed.
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. Although FirstEnergy is unable to predict the impact of these proceedings, if FirstEnergy or the Companies were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or the Companies' financial condition, results of operations and cash flows.
Other Legal Matters
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 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. On April 5, 2007, the Court rejected the plaintiffs’ request to certify this case as a class action and, accordingly, did not appoint the plaintiffs as class representatives or their counsel as class counsel. On July 30, 2007, plaintiffs’ counsel voluntarily withdrew their request for reconsideration of the April 5, 2007 Court order denying class certification and the Court heard oral argument on the plaintiff’splaintiffs’ motion to amend their complaint which OE has opposed. On August 2, 2007, the Court denied the plaintiffs’ motion to amend their complaint. The plaintiffs have appealed the Court’s denial of the motion for certification as a class action and motion to amend their complaint.
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 arbitration panel decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, a federal district court granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005. A final order identifying the individual damage amounts was issued on October 31, 2007. The award appeal process was initiated. The union filed a motion with the federal court to confirm the award and JCP&L intendsfiled its answer and counterclaim to re-file an appealvacate the award on December 31, 2007. The court held a scheduling conference in federal district court once the damages associatedApril 2008 where it set a briefing schedule with this case are identified at an individual employee level.all briefs to be concluded by July 2008. JCP&L recognized a liability for the potential $16 million award in 2005.
The union employees at the Bruce Mansfield Plant have been working without a labor contract since February 15, 2008. The parties met on June 27, 2007 before an arbitratorare continuing to assert their positions regardingbargain with the finalityassistance of damages. A hearing beforea federal mediator. FirstEnergy has a strike mitigation plan ready in the arbitrator is set for September 7, 2007.event of a strike.
FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. If it were ultimately determined that FirstEnergy or the Companiesits 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 the Companies’its subsidiaries' financial condition, results of operations and cash flows.
11. REGULATORY MATTERS
New Accounting Standards(A) RELIABILITY INITIATIVES
In late 2003 and Interpretations(Applicableearly 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 eachregional reliability. The proposed enhancements were divided into two groups: enhancements that were to be completed in 2004; and enhancements that were to be completed after 2004. In 2004, FirstEnergy completed all of the Companies)enhancements that were recommended for completion in 2004. FirstEnergy is also proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional material expenditures.
As a result of outages experienced in JCP&L’s service area in 2002 and 2003, the NJBPU performed a review of JCP&L’s service reliability. On June 9, 2004, the NJBPU approved a stipulation that addresses a third-party consultant’s recommendations on appropriate courses of action necessary to ensure system-wide reliability. The stipulation incorporates the consultant’s focused audit of, and recommendations regarding, JCP&L’s Planning and Operations and Maintenance programs and practices. On June 1, 2005, the consultant completed his work and issued his final report to the NJBPU. On July 14, 2006, JCP&L filed a comprehensive response to the consultant’s report with the NJBPU. JCP&L will complete the remaining substantive work described in the stipulation in 2008. JCP&L continues to file compliance reports with the NJBPU reflecting JCP&L’s activities associated with implementing the stipulation.
In 2005, Congress amended the Federal Power Act to provide for federally-enforceable mandatory reliability standards. The mandatory reliability standards apply to the bulk power system and impose certain operating, record-keeping and reporting requirements on the Companies and ATSI. The NERC is charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of its responsibilities to eight regional entities, including the ReliabilityFirst Corporation. All of FirstEnergy’s facilities are located within the ReliabilityFirst region. FirstEnergy actively participates in the NERC and ReliabilityFirst stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards.
FirstEnergy believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, it is clear that NERC, ReliabilityFirst and the FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with new or amended standards cannot be determined at this time. However, the 2005 amendments to the Federal Power Act provide that all prudent costs incurred to comply with the new reliability standards be recovered in rates. Still, any future inability on FirstEnergy’s part to comply with the reliability standards for its bulk power system could have a material adverse effect on its financial condition, results of operations and cash flows.
In April 2007, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the Midwest ISO region and found it to be in full compliance with all audited reliability standards. Similarly, ReliabilityFirst has scheduled a compliance audit of FirstEnergy’s bulk-power system within the PJM region in 2008. FirstEnergy currently does not expect any material adverse financial impact as a result of these audits.
(B) OHIO
On January 4, 2006, the PUCO issued an order authorizing the Ohio Companies to recover certain increased fuel costs through a fuel rider and to defer certain other increased fuel costs to be incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances. The order also provided for recovery of the deferred costs over a twenty-five-year period through distribution rates. On August 29, 2007, the Supreme Court of Ohio concluded that the PUCO violated a provision of the Ohio Revised Code by permitting the Ohio Companies “to collect deferred increased fuel costs through future distribution rate cases, or to alternatively use excess fuel-cost recovery to reduce deferred distribution-related expenses” and remanded the matter to the PUCO for further consideration. On September 10, 2007 the Ohio Companies filed an application with the PUCO that requested the implementation of two generation-related fuel cost riders to collect the increased fuel costs that were previously authorized to be deferred. On January 9, 2008 the PUCO approved the Ohio Companies’ proposed fuel cost rider to recover increased fuel costs to be incurred in 2008 commencing January 1, 2008 through December 31, 2008, which is expected to be approximately $189 million. In addition, the PUCO ordered the Ohio Companies to file a separate application for an alternate recovery mechanism to collect the 2006 and 2007 deferred fuel costs. On February 8, 2008, the Ohio Companies filed an application proposing to recover $226 million of deferred fuel costs and carrying charges for 2006 and 2007 pursuant to a separate fuel rider, with alternative options for the recovery period ranging from five to twenty-five years. This second application is currently pending before the PUCO and a hearing has been set for July 15, 2008.
The Ohio Companies filed an application and rate request for an increase in electric distribution rates with the PUCO on June 7, 2007. The requested increase is expected to be more than offset by the elimination or reduction of transition charges at the time the rates go into effect and would result in lowering the overall non-generation portion of the average electric bill for most Ohio customers. The distribution rate increases reflect capital expenditures since the Ohio Companies’ last distribution rate proceedings, increases in operation and maintenance expenses and recovery of regulatory assets that were authorized in prior cases. On August 6, 2007, the Ohio Companies updated their filing supporting a distribution rate increase of $332 million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of their investigation into the distribution rate request. In its reports, the PUCO Staff recommended a distribution rate increase in the range of $161 million to $180 million, with $108 million to $127 million for distribution revenue increases and $53 million for recovery of costs deferred under prior cases. This amount excludes the recovery of deferred fuel costs, whose recovery is now being sought in a separate proceeding before the PUCO, discussed above. On January 3, 2008, the Ohio Companies and intervening parties filed objections to the Staff Reports and on January 10, 2008, the Ohio Companies filed supplemental testimony. Evidentiary hearings began on January 29, 2008 and continued through February 25, 2008. During the evidentiary hearings, the PUCO Staff submitted testimony decreasing their recommended revenue increase to a range of $114 million to $132 million. Additionally, in testimony submitted on February 11, 2008, the PUCO Staff adopted a position regarding interest deferred for RCP-related deferrals, line extension deferrals and transition tax deferrals that, if upheld by the PUCO, would result in the write-off of approximately $45 million of interest costs deferred through March 31, 2008 ($0.09 per share of common stock). The PUCO is expected to render its decision during the second or third quarter of 2008. The new rates would become effective January 1, 2009 for OE and TE, and approximately May 2009 for CEI.
On July 10, 2007, the Ohio Companies filed an application with the PUCO requesting approval of a comprehensive supply plan for providing retail generation service to customers who do not purchase electricity from an alternative supplier, beginning January 1, 2009. The proposed competitive bidding process would average the results of multiple bidding sessions conducted at different times during the year. The final price per KWH would reflect an average of the prices resulting from all bids. In their filing, the Ohio Companies offered two alternatives for structuring the bids, either by customer class or a “slice-of-system” approach. A slice-of-system approach would require the successful bidder to be responsible for supplying a fixed percentage of the utility’s total load notwithstanding the customer’s classification. The proposal provides the PUCO with an option to phase in generation price increases for residential tariff groups who would experience a change in their average total price of 15 percent or more. The PUCO held a technical conference on August 16, 2007 regarding the filing. Initial and reply comments on the proposal were filed by various parties in September and October 2007, respectively. The proposal is currently pending before the PUCO.
On April 22, 2008, an amended version of Substitute SB221 was passed by the Ohio House of Representatives and sent back to the Ohio Senate for concurrence. On April 23, 2008, the Ohio Senate approved the House's amendments to Substitute SB221 and forwarded the bill to the Governor for signature, which he signed on May 1, 2008. Amended Substitute SB221 requires all electric distribution utilities to file an RSP, now called an ESP, with the PUCO. An ESP is required to contain a proposal for the supply and pricing of retail generation and may include proposals, without limitation, related to one or more of the following:
· | automatic recovery of prudently incurred fuel, purchased power, emission allowance costs and federally mandated energy taxes; |
SFAS 159 – “The Fair Value Option· | construction work in progress for Financial Assetscosts of constructing an electric generating facility or environmental expenditure for any electric generating facility; |
· | costs of an electric generating facility; |
· | terms related to customer shopping, bypassability, standby, back-up and Financial Liabilities – Including an amendmentdefault service; |
· | accounting for deferrals related to stabilizing retail electric service; |
· | automatic increases or decreases in standard service offer price; |
· | phase-in and securitization; |
· | transmission service and related costs; |
· | distribution service and related costs; and |
· | economic development and energy efficiency. |
A utility could also simultaneously file an MRO in which it would have to demonstrate the following objective market criteria: The utility or its transmission service affiliate belongs to a FERC-approved RTO having a market-monitor function and the ability to mitigate market power, and a published source exists that identifies information for traded electricity and energy products that are contracted for delivery two years into the future. The PUCO would test the ESP and its pricing and all other terms and conditions against the MRO and may only approve the ESP if it is found to be more favorable to customers. As part of an ESP with a plan period longer than three years, the PUCO shall prospectively determine every fourth year of the plan whether it is substantially likely the plan will provide the electric distribution utility a return on common equity significantly in excess of the return likely to be earned by publicly traded companies, including utilities, that face comparable business and financial risk (comparable companies). If so, the PUCO may terminate the ESP. Annually under an ESP, the PUCO shall determine whether an electric distribution utility's earned return on common equity is significantly in excess of returns earned on common equity during the same period by comparable companies, and if so, shall require the utility to return such excess to customers by prospective adjustments. Amended Substitute SB221 also includes provisions dealing with advanced and renewable energy standards that contemplate 25% of electrical usage from these sources by 2025. Energy efficiency measures in the bill require energy savings in excess of 22% by 2025. Requirements are in place to meet annual benchmarks for renewable energy resources and energy efficiency, subject to review by the PUCO. FirstEnergy is currently evaluating this legislation and expects to file an ESP in the second or third quarter of 2008.
(C) PENNSYLVANIA
Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations. The fixed price under the agreement is expected to remain below wholesale market prices during the term of the agreement. If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for their fixed income securities. Based on the PPUC’s January 11, 2007 order described below, if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC.
Met-Ed and Penelec made a comprehensive transition rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals had been approved, annual revenues would have increased by $216 million and $157 million, respectively. That filing included, among other things, a request to charge customers for an increasing amount of market-priced power procured through a CBP as the amount of supply provided under the then existing FES agreement was to be phased out. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs incurred during 2006. In this rate filing, Met-Ed and Penelec requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the FirstEnergy and GPU merger proceeding, related to the quantification and allocation of merger savings, with the comprehensive transition rate filing case.
The PPUC entered its opinion and order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, and determined that no merger savings from prior years should be considered in determining customers’ rates. The request for increases in generation supply rates was denied as were the requested changes to NUG expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased Met-Ed’s and Penelec’s distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission costs. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and, in January 2007, Met-Ed and Penelec recognized income of $15 million and $12 million, respectively, to establish regulatory assets for those previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million).
On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase. The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. From June through October 2007, initial responsive and reply briefs were filed by various parties. Oral arguments are scheduled to take place in September 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the results of operations of Met-Ed, Penelec and FirstEnergy.
On April 14, 2008, Met-Ed and Penelec filed annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. The proposed TSCs include a component for under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and future transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed has proposed a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010.
On March 13, 2008, the PPUC approved the residential procurement process in Penn’s Joint Petition for Settlement. This RFP process calls for load-following, full-requirements contracts for default service procurement for residential customers for the period covering June 1, 2008 through May 31, 2011. The PPUC had previously approved the default service procurement processes for commercial and industrial customers. The default service procurement for small commercial customers was conducted through multiple RFPs, while the default service procurement for large commercial and industrial customers will utilize hourly pricing. Bids in the two RFPs for small commercial load were approved by the PPUC on February 22, 2008, and March 20, 2008. On March 28, 2008, Penn filed compliance tariffs with the new default service generation rates based on the approved RFP bids for small commercial customers which the PPUC then certified on April 4, 2008. On April 14, 2008, the first RFP for residential customers’ load was held consisting of tranches for both 12 and 24-month supply. The PPUC approved the bids on April 16, 2008. The second RFP is scheduled to be held on May 14, 2008, after which time the PPUC is expected to approve the new rates to go into effect June 1, 2008.
On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation and demand reduction programs to meet energy growth, a requirement that electric distribution companies acquire power that results in the “lowest reasonable rate on a long-term basis,” the utilization of micro-grids and a three year phase-in of rate increases. On July 17, 2007 the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy was convened in mid-September 2007 to consider other aspects of the EIS. The Pennsylvania House and Senate on March 11, 2008 and December 12, 2007, respectively, passed different versions of bills to fund the Governor’s EIS proposal. Neither chamber has formally considered the other’s bill. On February 12, 2008, the Pennsylvania House passed House Bill 2200 which provides for energy efficiency and demand management programs and targets as well as the installation of smart meters within ten years. Other legislation has been introduced to address generation procurement, expiration of rate caps, conservation and renewable energy. The final form of this pending legislation is uncertain. Consequently, FirstEnergy is unable to predict what impact, if any, such legislation may have on its operations.
(D) 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 NUGC rates and market sales of NUG energy and capacity. As of March 31, 2008, the accumulated deferred cost balance totaled approximately $264 million.
In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting 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 DRA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and also submitted comments in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set.
On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of the PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. These regulations are not expected to materially impact FirstEnergy or JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. The NJBPU Staff circulated revised drafts of the proposal to interested stakeholders in November 2006 and again in February 2007. On February 1, 2008, the NJBPU accepted proposed rules for publication in the New Jersey Register on March 17, 2008. A public hearing on these proposed rules was held on April 23, 2008 with comments from interested parties due on May 16, 2008.
New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated through the creation of a number of working groups to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. In addition, public stakeholder meetings were held in the fall of 2006 and in early 2007.
On April 17, 2008, a draft EMP was released for public comment. The draft EMP establishes four major goals:
· | maximize energy efficiency to achieve a 20% reduction in energy consumption by 2020; |
· | reduce peak demand for electricity by 5,700 MW by 2020 (amounting to about a 22% reduction in projected demand); |
· | meet 22.5% of FASB Statement No. 115”the state’s electricity needs with renewable energy by 2020; and |
· | develop low carbon emitting, efficient power plants and close the gap between the supply and demand for electricity. |
Following the public comment period which is expected to extend into July 2008, a final EMP will be issued to be followed by appropriate legislation and regulation as necessary. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation or regulation may have on its operations or those of JCP&L.
On February 13, 2007, the NJBPU Staff informally issued a draft proposal relating to changes to the regulations addressing electric distribution service reliability and quality standards. Meetings between the NJBPU Staff and interested stakeholders to discuss the proposal were held and additional, revised informal proposals were subsequently circulated by the Staff. On September 4, 2007, proposed regulations were published in the New Jersey Register, which proposal will be subsequently considered by the NJBPU following comments that were submitted in September and October 2007. Final regulations (effective upon publication) were published in the New Jersey Register March 17, 2008. Upon preliminary review of the new regulations, FirstEnergy does not expect a material impact on its operations or those of JCP&L.
(E) FERC MATTERS
Transmission Service between MISO and PJM
On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate so-called “pancaking” of transmission charges between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or “SECA”) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order could be issued by the FERC in the second quarter of 2008.
PJM Transmission Rate Design
On January 31, 2005, certain PJM transmission owners made filings with the FERC 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. Hearings were held and numerous parties appeared and litigated various issues concerning PJM rate design; notably AEP, which proposed to create a "postage stamp", or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. This proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. The FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.
On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. The FERC’s orders on PJM rate design will prevent the allocation of a portion of the revenue requirement of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reduce future transmission revenue recovery from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the “beneficiary pays” methodology for below 500 kV facilities, but excluding the issue of allocating new facilities costs to merchant transmission entities, was filed on September 14, 2007. The agreement was supported by the FERC’s Trial Staff, and was certified by the Presiding Judge. The FERC’s action on the settlement agreement is pending. The remaining merchant transmission cost allocation issues will proceed to hearing in May 2008. On February 13, 2008, AEP appealed the FERC’s orders to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and Dayton Power & Light have also appealed these orders to the Seventh Circuit Court of Appeals. The appeals of these parties and others have been consolidated for argument in the Seventh Circuit.
Post Transition Period Rate Design
The FERC had directed MISO, PJM, and the respective transmission owners to make filings on or before August 1, 2007 to reevaluate transmission rate design within MISO, and between MISO and PJM. On August 1, 2007, filings were made by MISO, PJM, and the vast majority of transmission owners, including FirstEnergy affiliates, which proposed to retain the existing transmission rate design. These filings were approved by the FERC on January 31, 2008. As a result of the FERC’s approval, the rates charged to FirstEnergy’s load-serving affiliates for transmission service over existing transmission facilities in MISO and PJM are unchanged. In a related filing, MISO and MISO transmission owners requested that the current MISO pricing for new transmission facilities that spreads 20% of the cost of new 345 kV and higher transmission facilities across the entire MISO footprint (known as the RECB methodology) be retained.
On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act seeking to have the entire transmission rate design and cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have the FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM “Super Region” that recovers the average cost of new and existing transmission facilities operated at voltages of 345 kV and above from all transmission customers. Lower voltage facilities would continue to be recovered in the local utility transmission rate zone through a license plate rate. AEP requested a refund effective October 1, 2007, or alternatively, February 1, 2008. On January 31, 2008, the FERC issued an order denying the complaint. A rehearing request by AEP is pending before the FERC.
Distribution of MISO Network Service Revenues
Effective February 1, 2008, the MISO Transmission Owners Agreement provides for a change in the method of distributing transmission revenues among the transmission owners. MISO and a majority of the MISO transmission owners filed on December 3, 2007 to change the MISO tariff to clarify, for purposes of distributing network transmission revenue to the transmission owners, that all network transmission service revenues, whether collected by MISO or directly by the transmission owner, are included in the revenue distribution calculation. This clarification was necessary because some network transmission service revenues are collected and retained by transmission owners in states where retail choice does not exist, and their “unbundled” retail load is currently exempt from MISO network service charges. The tariff changes filed with the FERC ensure that revenues collected by transmission owners from bundled load are taken into account in the revenue distribution calculation, and that transmission owners with bundled load do not collect more than their revenue requirements. Absent the changes, transmission owners, and ultimately their customers, with unbundled load or in retail choice states, such as ATSI, would subsidize transmission owners with bundled load, who would collect their revenue requirement from bundled load, plus share in revenues collected by MISO from unbundled customers. This would result in a large revenue shortfall for ATSI, which would eventually be passed on to customers in the form of higher transmission rates as calculated pursuant to ATSI’s Attachment O formula under the MISO tariff.
Numerous parties filed in support of the tariff changes, including the public service commissions of Michigan, Ohio and Wisconsin. Ameren filed a protest on December 26, 2007, arguing that the December 3, 2007 filing violates the MISO Transmission Owners’ Agreement as well as an agreement among Ameren (Union Electric), MISO, and the Missouri Public Service Commission, which provides that Union Electric’s bundled load cannot be charged by MISO for network service. On February 2, 2008, the FERC issued an order conditionally accepting the tariff amendment subject to a minor compliance filing, which was made on March 3, 2008. This order ensures that ATSI will continue to receive transmission revenues from MISO equivalent to its transmission revenue requirement. A rehearing request by Ameren is pending before the FERC.
On February 1, 2008, MISO filed a request to continue using the existing revenue distribution methodology on an interim basis pending amendment of the MISO Transmission Owners’ Agreement. This request was accepted by the FERC on March 13, 2008. On that same day, MISO and the MISO transmission owners made a filing to amend the Transmission Owners’ Agreement to effectively continue the distribution of transmission revenues that was in effect prior to February 1, 2008. This matter is currently pending before the FERC.
MISO Ancillary Services Market and Balancing Area Consolidation
MISO made a filing on September 14, 2007 to establish an ASM for regulation, spinning and supplemental reserves, to consolidate the existing 24 balancing areas within the MISO footprint, and to establish MISO as the NERC registered balancing authority for the region. This filing would permit load serving entities to purchase their operating reserve requirements in a competitive market. FirstEnergy supports the proposal to establish markets for Ancillary Services and consolidate existing balancing areas. On February 25, 2008, the FERC issued an order approving the ASM subject to certain compliance filings. MISO has since notified the FERC that the start of its ASM is delayed until September of 2008.
Duquesne’s Request to Withdraw from PJM
On November 8, 2007, Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and to join the MISO. In its filing, Duquesne asked the FERC to be relieved of certain capacity payment obligations to PJM for capacity auctions conducted prior to its departure from PJM, but covering service for planning periods through May 31, 2011. Duquesne asserted that its primary reason for exiting PJM is to avoid paying future obligations created by PJM’s forward capacity market. FirstEnergy believes that Duquesne’s filing did not identify or address numerous legal, financial or operational issues that are implicated or affected directly by Duquesne’s proposal. Consequently, FirstEnergy submitted responsive filings that, while conceding Duquesne’s rights to exit PJM, contested various aspects of Duquesne’s proposal. FirstEnergy particularly focused on Duquesne’s proposal that it be allowed to exit PJM without payment of its share of existing capacity market commitments. FirstEnergy also objected to Duquesne’s failure to address the firm transmission service requirements that would be necessary for FirstEnergy to continue to use the Beaver Valley Plant to meet existing commitments in the PJM capacity markets and to serve native load. Other market participants also submitted filings contesting Duquesne’s plans.
On January 17, 2008, the FERC conditionally approved Duquesne’s request to exit PJM. Among other conditions, the FERC obligated Duquesne to pay the PJM capacity obligations through May 31, 2011. The FERC’s order took notice of the numerous transmission and other issues raised by FirstEnergy and other parties to the proceeding, but did not provide any responsive rulings or other guidance. Rather, the FERC ordered Duquesne to make a compliance filing in forty-five days detailing how Duquesne will satisfy its obligations under the PJM Transmission Owners’ Agreement. The FERC likewise directed the MISO to submit detailed plans to integrate Duquesne into the MISO. Finally, the FERC directed MISO and PJM to work together to resolve the substantive and procedural issues implicated by Duquesne’s transition into the MISO. These issues remain unresolved. If Duquesne satisfies all of the obligations set by the FERC, its planned transition date is October 9, 2008.
On March 18, 2008, the PJM Power Providers Group filed a request for emergency clarification regarding whether Duquesne-zone generators (including the Beaver Valley Plant) could participate in PJM’s May 2008 auction for the 2011-2012 RPM delivery year. FirstEnergy and the other Duquesne-zone generators filed responsive pleadings. On April 18, 2008, the FERC issued its Order on Motion for Emergency Clarification, wherein the FERC ruled that although the status of the Duquesne-zone generators will change to “External Resource” upon Duquesne’s exit from PJM, these generators can contract with PJM for the transmission reservations necessary to participate in the May 2008 auction. FirstEnergy has complied with FERC’s order by obtaining executed transmission service agreements for firm point-to-point transmission service for the 2011-2012 delivery year and, as such, FirstEnergy satisfies the criteria to bid the Beaver Valley Plant into the May 2008 RPM auction. Notwithstanding these events, on April 30, 2008 and May 1, 2008, certain members of the PJM Power Providers Group filed further pleadings on these issues. On May 2, 2008, FirstEnergy filed a responsive pleading. FirstEnergy is participating in the May 2008 RPM auction for the 2011-2012 RPM delivery year.
MISO Resource Adequacy Proposal
MISO made a filing on December 28, 2007 that would create an enforceable planning reserve requirement in the MISO tariff for load serving entities such as the Ohio Companies, Penn Power, and FES. This requirement is proposed to become effective for the planning year beginning June 1, 2009. The filing would permit MISO to establish the reserve margin requirement for load serving entities based upon a one day loss of load in ten years standard, unless the state utility regulatory agency establishes a different planning reserve for load serving entities in its state. FirstEnergy generally supports the proposal as it promotes a mechanism that will result in long-term commitments from both load-serving entities and resources, including both generation and demand side resources that are necessary for reliable resource adequacy and planning in the MISO footprint. Comments on the filing were filed on January 28, 2008. The FERC approved MISO’s Resource Adequacy proposal on March 26, 2008. Rehearing requests are pending on the FERC’s March 26 Order. A compliance filing establishing the enforcement mechanism for the reserve margin requirement is due on or before June 25, 2008.
Organized Wholesale Power Markets
On February 21, 2008, the FERC issued a NOPR through which it proposes to adopt new rules that it states will “improve operations in organized electric markets, boost competition and bring additional benefits to consumers.” The proposed rule addresses demand response and market pricing during reserve shortages, long-term power contracting, market-monitoring policies, and responsiveness of RTOs and ISOs to stakeholders and customers. FirstEnergy does not believe that the proposed rule will have a significant impact on its operations. Comments on the NOPR were filed on April 18, 2008.
12. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS |
SFAS 141(R) – “Business Combinations”
In FebruaryDecember 2007, the FASB issued SFAS 159,141(R), which provides companies with an optionrequires the acquiring entity in a business combination to report selected financialrecognize all the assets acquired and liabilities atassumed in the transaction; establishes the acquisition-date fair value. This Statementvalue as the measurement objective for all assets acquired and liabilities assumed; and requires companiesthe acquirer to provide additional information that will helpdisclose to investors and other users all of financial statementsthe information they need to more easilyevaluate and understand the nature and financial effect of the company’s choicebusiness combination. SFAS 141(R) attempts to use fair valuereduce the complexity of existing GAAP related to business combinations. The Standard includes both core principles and pertinent application guidance, eliminating the need for numerous EITF issues and other interpretative guidance. SFAS 141(R) will affect business combinations entered into by FirstEnergy that close after January 1, 2009. In addition, the Standard also affects the accounting for changes in tax valuation allowances made after January 1, 2009, that were established as part of a business combination prior to the implementation of this Standard. FirstEnergy is currently evaluating the impact of adopting this Standard on its earnings. The Standard also requires companies to displayfinancial statements.
SFAS 160 - “Noncontrolling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51”
In December 2007, the fair valueFASB issued SFAS 160 that establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of those assets and liabilities for whicha subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the company has chosen to use fair value onconsolidated entity that should be reported as equity in the face of the balance sheet. This guidance does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS 157and SFAS 107. consolidated financial statements. This Statement is effective for financial statements issued for fiscal years, beginning after November 15, 2007, and interim periods within those years. The Companies are currently evaluating the impact of this Statement on their financial statements.
SFAS 157 – “Fair Value Measurements”
In September 2006, the FASB issued SFAS 157 that establishes how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under GAAP. This Statement addresses the need for increased consistency and comparability in fair value measurements and for expanded disclosures about fair value measurements. The key changes to current practice are: (1) the definition of fair value which focuses on an exit price rather than entry price; (2) the methods used to measure fair value such as emphasis that fair value is a market-based measurement, not an entity-specific measurement, as well as the inclusion of an adjustment for risk, restrictions and credit standing; and (3) the expanded disclosures about fair value measurements. This Statement is effective for financial statements issued for fiscal years, beginning after November 15, 2007, and interim periods within those years. The Companies are currently evaluating the impact of this Statement on their financial statements.
EITF 06-11 – “Accounting for Income Tax Benefits of Dividends or Share-based Payment Awards”
In June 2007, the FASB released EITF 06-11, which provides guidance on the appropriate accounting for income tax benefits related to dividends earned on nonvested share units that are charged to retained earnings under SFAS 123(R). The consensus requires that an entity recognize the realized tax benefit associated with the dividends on nonvested shares as an increase to additional paid-in capital (APIC). This amount should be included in the APIC pool, which is to be used when an entity’s estimate of forfeitures increases or actual forfeitures exceed its estimates, at which time the tax benefits in the APIC pool would be reclassified to the income statement. The consensus is effective for income tax benefits of dividends declared during fiscal years beginning after December 15, 2007. EITF 06-112008. Early adoption is prohibited. The Statement is not expected to have a material impact on the Companies’FirstEnergy’s financial statements.
| SFAS 161 - “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133” |
In March 2008, the FASB issued SFAS 161, which requires enhancements to the current disclosure framework for derivative instruments and hedging activities. The Statement requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. This disclosure is intended to better convey the purpose of derivatives use in terms of the risks that the entity is intending to manage. The FASB believes disclosing the fair values of derivative instruments and their gains and losses in a tabular format is designed to provide a more complete picture of the location in an entity’s financial statements of both the derivative positions existing at period end and the effect of using derivatives during the reporting period. Disclosing information about credit-risk-related contingent features is designed to provide financial statement users information on the potential effect on an entity’s liquidity from using derivatives. Finally, this Statement requires cross-referencing within the footnotes, which is intended to help users of financial statements locate important information about derivative instruments. FirstEnergy is currently evaluating the impact of adopting this Standard on its financial statements.
13. SEGMENT INFORMATION
FirstEnergy has three reportable operating segments: energy delivery services, competitive energy services and Ohio transitional generation services. The “Other” segment primarily consists of telecommunications services. The assets and revenues for the other business operations are below the quantifiable threshold for operating segments for separate disclosure as “reportable operating segments.”
The energy delivery services segment designs, constructs, operates and maintains FirstEnergy's regulated transmission and distribution systems and is responsible for the regulated generation commodity operations of FirstEnergy’s Pennsylvania and New Jersey electric utility subsidiaries. Its revenues are primarily derived from the delivery of electricity, cost recovery of regulatory assets and default service electric generation sales to non-shopping customers in its Pennsylvania and New Jersey franchise areas. Its results reflect the commodity costs of securing electric generation from FES under partial requirements purchased power agreements and from non-affiliated power suppliers as well as the net PJM transmission expenses related to the delivery of that generation load.
The competitive energy services segment supplies electric power to its electric utility affiliates, provides competitive electric sales primarily in Ohio, Pennsylvania, Maryland and Michigan, owns or leases and operates FirstEnergy’s generating facilities and purchases electricity to meet its sales obligations. The segment's net income is primarily derived from the affiliated company PSA sales and the non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO to deliver electricity to the segment’s customers. The segment’s internal revenues represent the affiliated company PSA sales.
The Ohio transitional generation services segment represents the regulated generation commodity operations of FirstEnergy’s Ohio electric utility subsidiaries. Its revenues are primarily derived from electric generation sales to non-shopping customers under the PLR obligations of the Ohio Companies. Its results reflect the purchase of electricity from the competitive energy services segment through full-requirements PSA arrangements, the deferral and amortization of certain fuel costs authorized for recovery by the energy delivery services segment and the net MISO transmission revenues and expenses related to the delivery of generation load. This segment’s total assets consist of accounts receivable for generation revenues from retail customers.
Segment Financial Information | | | | | | | | | | | | | | | | |
| | | | | | | | Ohio | | | | | | | | | | |
| | Energy | | | Competitive | | | Transitional | | | | | | | | | | |
| | Delivery | | | Energy | | | Generation | | | | | | Reconciling | | | | |
Three Months Ended | | Services | | | Services | | | Services | | | Other | | | Adjustments | | | Consolidated | |
| | (In millions) | |
March 31, 2008 | | | | | | | | | | | | | | | | | | |
External revenues | | $ | 2,212 | | | $ | 329 | | | $ | 707 | | | $ | 40 | | | $ | (11 | ) | | $ | 3,277 | |
Internal revenues | | | - | | | | 776 | | | | - | | | | - | | | | (776 | ) | | | - | |
Total revenues | | | 2,212 | | | | 1,105 | | | | 707 | | | | 40 | | | | (787 | ) | | | 3,277 | |
Depreciation and amortization | | | 255 | | | | 53 | | | | 4 | | | | - | | | | 5 | | | | 317 | |
Investment income | | | 45 | | | | (6 | ) | | | 1 | | | | - | | | | (23 | ) | | | 17 | |
Net interest charges | | | 103 | | | | 27 | | | | - | | | | - | | | | 41 | | | | 171 | |
Income taxes | | | 119 | | | | 58 | | | | 15 | | | | 14 | | | | (19 | ) | | | 187 | |
Net income | | | 179 | | | | 87 | | | | 23 | | | | 22 | | | | (35 | ) | | | 276 | |
Total assets | | | 23,211 | | | | 8,108 | | | | 257 | | | | 281 | | | | 558 | | | | 32,415 | |
Total goodwill | | | 5,582 | | | | 24 | | | | - | | | | - | | | | - | | | | 5,606 | |
Property additions | | | 255 | | | | 462 | | | | - | | | | 12 | | | | (18 | ) | | | 711 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
March 31, 2007 | | | | | | | | | | | | | | | | | | | | | | | | |
External revenues | | $ | 2,040 | | | $ | 321 | | | $ | 619 | | | $ | 12 | | | $ | (19 | ) | | $ | 2,973 | |
Internal revenues | | | - | | | | 714 | | | | - | | | | - | | | | (714 | ) | | | - | |
Total revenues | | | 2,040 | | | | 1,035 | | | | 619 | | | | 12 | | | | (733 | ) | | | 2,973 | |
Depreciation and amortization | | | 220 | | | | 51 | | | | (15 | ) | | | 1 | | | | 6 | | | | 263 | |
Investment income | | | 70 | | | | 3 | | | | 1 | | | | - | | | | (41 | ) | | | 33 | |
Net interest charges | | | 107 | | | | 49 | | | | 1 | | | | 2 | | | | 21 | | | | 180 | |
Income taxes | | | 148 | | | | 65 | | | | 15 | | | | 5 | | | | (33 | ) | | | 200 | |
Net income | | | 218 | | | | 98 | | | | 24 | | | | 1 | | | | (51 | ) | | | 290 | |
Total assets | | | 23,526 | | | | 7,089 | | | | 246 | | | | 254 | | | | 675 | | | | 31,790 | |
Total goodwill | | | 5,874 | | | | 24 | | | | - | | | | - | | | | - | | | | 5,898 | |
Property additions | | | 155 | | | | 124 | | | | - | | | | 1 | | | | 16 | | | | 296 | |
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 and elimination of intersegment transactions.
14. SUPPLEMENTAL GUARANTOR INFORMATION |
On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES’ lease guaranty.
The consolidating statements of income for the three months ended March 31, 2008 and 2007, consolidating balance sheets as of March 31, 2008 and December 31, 2007 and condensed consolidating statements of cash flows for the three months ended March 31, 2008 and 2007 for FES (parent and guarantor), FGCO and NGC (non-guarantor) are presented below. Investments in wholly owned subsidiaries are accounted for by FES using the equity method. Results of operations for FGCO and NGC are, therefore, reflected in FES’ investment accounts and earnings as if operating lease treatment was achieved. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.
FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | |
CONSOLIDATING STATEMENTS OF INCOME | |
(Unaudited) | |
| | | | | | | | | | | | | | | |
For the Three Months Ended March 31, 2008 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | (In thousands) | |
| | | | | | | | | | | | | | | |
REVENUES | | $ | 1,099,848 | | | $ | 567,701 | | | $ | 325,684 | | | $ | (894,117 | ) | | $ | 1,099,116 | |
| | | | | | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | | | | | |
Fuel | | | 2,138 | | | | 291,239 | | | | 28,312 | | | | - | | | | 321,689 | |
Purchased power from non-affiliates | | | 206,724 | | | | - | | | | - | | | | - | | | | 206,724 | |
Purchased power from affiliates | | | 891,979 | | | | 2,138 | | | | 25,485 | | | | (894,117 | ) | | | 25,485 | |
Other operating expenses | | | 37,596 | | | | 107,167 | | | | 139,595 | | | | 12,188 | | | | 296,546 | |
Provision for depreciation | | | 307 | | | | 26,599 | | | | 24,194 | | | | (1,358 | ) | | | 49,742 | |
General taxes | | | 5,415 | | | | 11,570 | | | | 6,212 | | | | - | | | | 23,197 | |
Total expenses | | | 1,144,159 | | | | 438,713 | | | | 223,798 | | | | (883,287 | ) | | | 923,383 | |
| | | | | | | | | | | | | | | | | | | | |
OPERATING INCOME (LOSS) | | | (44,311 | ) | | | 128,988 | | | | 101,886 | | | | (10,830 | ) | | | 175,733 | |
| | | | | | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | |
Miscellaneous income (expense), including | | | | | | | | | | | | | | | | | | | | |
net income from equity investees | | | 121,725 | | | | (1,208 | ) | | | (6,537 | ) | | | (116,884 | ) | | | (2,904 | ) |
Interest expense to affiliates | | | (82 | ) | | | (5,289 | ) | | | (1,839 | ) | | | - | | | | (7,210 | ) |
Interest expense - other | | | (3,978 | ) | | | (25,968 | ) | | | (11,018 | ) | | | 16,429 | | | | (24,535 | ) |
Capitalized interest | | | 21 | | | | 6,228 | | | | 414 | | | | - | | | | 6,663 | |
Total other income (expense) | | | 117,686 | | | | (26,237 | ) | | | (18,980 | ) | | | (100,455 | ) | | | (27,986 | ) |
| | | | | | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 73,375 | | | | 102,751 | | | | 82,906 | | | | (111,285 | ) | | | 147,747 | |
| | | | | | | | | | | | | | | | | | | | |
INCOME TAXES (BENEFIT) | | | (16,609 | ) | | | 39,285 | | | | 32,764 | | | | 2,323 | | | | 57,763 | |
| | | | | | | | | | | | | | | | | | | | |
NET INCOME | | $ | 89,984 | | | $ | 63,466 | | | $ | 50,142 | | | $ | (113,608 | ) | | $ | 89,984 | |
FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | |
CONSOLIDATING STATEMENTS OF INCOME | |
(Unaudited) | |
| | | | | | | | | | | | | | | |
For the Three Months Ended March 31, 2007 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | (In thousands) | |
| | | | | | | | | | | | | | | |
REVENUES | | $ | 1,019,387 | | | $ | 551,355 | | | $ | 234,091 | | | $ | (786,540 | ) | | $ | 1,018,293 | |
| | | | | | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | | | | | |
Fuel | | | 2,367 | | | | 201,231 | | | | 29,937 | | | | - | | | | 233,535 | |
Purchased power from non-affiliates | | | 186,203 | | | | 2,367 | | | | - | | | | (2,367 | ) | | | 186,203 | |
Purchased power from affiliates | | | 784,172 | | | | 59,069 | | | | 17,415 | | | | (784,173 | ) | | | 76,483 | |
Other operating expenses | | | 51,249 | | | | 99,095 | | | | 113,252 | | | | - | | | | 263,596 | |
Provision for depreciation | | | 453 | | | | 24,936 | | | | 22,621 | | | | - | | | | 48,010 | |
General taxes | | | 4,934 | | | | 10,568 | | | | 6,216 | | | | - | | | | 21,718 | |
Total expenses | | | 1,029,378 | | | | 397,266 | | | | 189,441 | | | | (786,540 | ) | | | 829,545 | |
| | | | | | | | | | | | | | | | | | | | |
OPERATING INCOME (LOSS) | | | (9,991 | ) | | | 154,089 | | | | 44,650 | | | | - | | | | 188,748 | |
| | | | | | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | |
Miscellaneous income (expense), including | | | | | | | | | | | | | | | | | | | | |
net income from equity investees | | | 113,948 | | | | 916 | | | | 5,200 | | | | (100,332 | ) | | | 19,732 | |
Interest expense to affiliates | | | - | | | | (24,331 | ) | | | (5,115 | ) | | | - | | | | (29,446 | ) |
Interest expense - other | | | (1,385 | ) | | | (6,760 | ) | | | (9,213 | ) | | | - | | | | (17,358 | ) |
Capitalized interest | | | 5 | | | | 2,099 | | | | 1,105 | | | | - | | | | 3,209 | |
Total other income (expense) | | | 112,568 | | | | (28,076 | ) | | | (8,023 | ) | | | (100,332 | ) | | | (23,863 | ) |
| | | | | | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 102,577 | | | | 126,013 | | | | 36,627 | | | | (100,332 | ) | | | 164,885 | |
| | | | | | | | | | | | | | | | | | | | |
INCOME TAXES | | | 73 | | | | 49,289 | | | | 13,019 | | | | - | | | | 62,381 | |
| | | | | | | | | | | | | | | | | | | | |
NET INCOME | | $ | 102,504 | | | $ | 76,724 | | | $ | 23,608 | | | $ | (100,332 | ) | | $ | 102,504 | |
FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | |
CONSOLIDATING BALANCE SHEETS | |
(Unaudited) | |
| | | | | | | | | | | | | | | |
As of March 31, 2008 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | (In thousands) | |
ASSETS | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
CURRENT ASSETS: | | | | | | | | | | | | | | | |
Cash and cash equivalents | | $ | 2 | | | $ | - | | | $ | - | | | $ | - | | | $ | 2 | |
Receivables- | | | | | | | | | | | | | | | | | | | | |
Customers | | | 125,116 | | | | - | | | | - | | | | - | | | | 125,116 | |
Associated companies | | | 285,350 | | | | 231,049 | | | | 96,852 | | | | (295,511 | ) | | | 317,740 | |
Other | | | 1,174 | | | | 1,050 | | | | - | | | | | | | | 2,224 | |
Notes receivable from associated companies | | | 668,376 | | | | - | | | | 69,011 | | | | - | | | | 737,387 | |
Materials and supplies, at average cost | | | 2,849 | | | | 264,501 | | | | 207,275 | | | | - | | | | 474,625 | |
Prepayments and other | | | 107,798 | | | | 26,208 | | | | 1,728 | | | | - | | | | 135,734 | |
| | | 1,190,665 | | | | 522,808 | | | | 374,866 | | | | (295,511 | ) | | | 1,792,828 | |
| | | | | | | | | | | | | | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | | | | | | | | | | | | |
In service | | | 35,302 | | | | 5,359,381 | | | | 3,700,973 | | | | (391,896 | ) | | | 8,703,760 | |
Less - Accumulated provision for depreciation | | | 7,810 | | | | 2,655,103 | | | | 1,537,747 | | | | (168,115 | ) | | | 4,032,545 | |
| | | 27,492 | | | | 2,704,278 | | | | 2,163,226 | | | | (223,781 | ) | | | 4,671,215 | |
Construction work in progress | | | 10,792 | | | | 881,899 | | | | 165,389 | | | | - | | | | 1,058,080 | |
| | | 38,284 | | | | 3,586,177 | | | | 2,328,615 | | | | (223,781 | ) | | | 5,729,295 | |
| | | | | | | | | | | | | | | | | | | | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | | | | | | | | | | | | |
Nuclear plant decommissioning trusts | | | - | | | | - | | | | 1,263,338 | | | | - | | | | 1,263,338 | |
Long-term notes receivable from associated companies | | | - | | | | - | | | | 62,900 | | | | - | | | | 62,900 | |
Investment in associated companies | | | 2,598,022 | | | | - | | | | - | | | | (2,598,022 | ) | | | - | |
Other | | | 2,529 | | | | 21,657 | | | | 202 | | | | - | | | | 24,388 | |
| | | 2,600,551 | | | | 21,657 | | | | 1,326,440 | | | | (2,598,022 | ) | | | 1,350,626 | |
| | | | | | | | | | | | | | | | | | | | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | | | | | | | | | | | |
Accumulated deferred income taxes | | | 10,518 | | | | 495,131 | | | | - | | | | (248,666 | ) | | | 256,983 | |
Lease assignment receivable from associated companies | | | - | | | | 67,256 | | | | - | | | | - | | | | 67,256 | |
Goodwill | | | 24,248 | | | | | | | | - | | | | - | | | | 24,248 | |
Property taxes | | | - | | | | 25,007 | | | | 22,767 | | | | - | | | | 47,774 | |
Pension assets | | | 3,214 | | | | 12,856 | | | | - | | | | - | | | | 16,070 | |
Unamortized sale and leaseback costs | | | - | | | | 38,120 | | | | - | | | | 47,575 | | | | 85,695 | |
Other | | | 18,177 | | | | 49,393 | | | | 5,188 | | | | (37,939 | ) | | | 34,819 | |
| | | 56,157 | | | | 687,763 | | | | 27,955 | | | | (239,030 | ) | | | 532,845 | |
| | $ | 3,885,657 | | | $ | 4,818,405 | | | $ | 4,057,876 | | | $ | (3,356,344 | ) | | $ | 9,405,594 | |
| | | | | | | | | | | | | | | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
Currently payable long-term debt | | $ | - | | | $ | 738,087 | | | $ | 887,265 | | | $ | (16,896 | ) | | $ | 1,608,456 | |
Notes payable- | | | | | | | | | | | | | | | | | | | | |
Associated companies | | | - | | | | 885,760 | | | | 260,199 | | | | - | | | | 1,145,959 | |
Other | | | 700,000 | | | | - | | | | - | | | | - | | | | 700,000 | |
Accounts payable- | | | | | | | | | | | | | | | | | | | | |
Associated companies | | | 554,844 | | | | 1,419 | | | | 119,773 | | | | (270,368 | ) | | | 405,668 | |
Other | | | 55,614 | | | | 130,090 | | | | - | | | | - | | | | 185,704 | |
Accrued taxes | | | 3,378 | | | | 116,383 | | | | 47,292 | | | | (24,219 | ) | | | 142,834 | |
Other | | | 85,100 | | | | 107,791 | | | | 9,731 | | | | 45,484 | | | | 248,106 | |
| | | 1,398,936 | | | | 1,979,530 | | | | 1,324,260 | | | | (265,999 | ) | | | 4,436,727 | |
| | | | | | | | | | | | | | | | | | | | |
CAPITALIZATION: | | | | | | | | | | | | | | | | | | | | |
Common stockholder's equity | | | 2,460,215 | | | | 1,011,907 | | | | 1,579,614 | | | | (2,591,521 | ) | | | 2,460,215 | |
Long-term debt and other long-term obligations | | | - | | | | 1,320,773 | | | | 62,900 | | | | (1,305,717 | ) | | | 77,956 | |
| | | 2,460,215 | | | | 2,332,680 | | | | 1,642,514 | | | | (3,897,238 | ) | | | 2,538,171 | |
| | | | | | | | | | | | | | | | | | | | |
NONCURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
Deferred gain on sale and leaseback transaction | | | - | | | | - | | | | - | | | | 1,051,871 | | | | 1,051,871 | |
Accumulated deferred income taxes | | | - | | | | - | | | | 244,978 | | | | (244,978 | ) | | | - | |
Accumulated deferred investment tax credits | | | - | | | | 35,350 | | | | 24,619 | | | | - | | | | 59,969 | |
Asset retirement obligations | | | - | | | | 24,947 | | | | 798,739 | | | | - | | | | 823,686 | |
Retirement benefits | | | 9,332 | | | | 56,016 | | | | - | | | | - | | | | 65,348 | |
Property taxes | | | - | | | | 25,329 | | | | 22,766 | | | | - | | | | 48,095 | |
Lease market valuation liability | | | - | | | | 341,881 | | | | - | | | | - | | | | 341,881 | |
Other | | | 17,174 | | | | 22,672 | | | | - | | | | - | | | | 39,846 | |
| | | 26,506 | | | | 506,195 | | | | 1,091,102 | | | | 806,893 | | | | 2,430,696 | |
| | $ | 3,885,657 | | | $ | 4,818,405 | | | $ | 4,057,876 | | | $ | (3,356,344 | ) | | $ | 9,405,594 | |
FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | |
CONSOLIDATING BALANCE SHEETS | |
(Unaudited) | |
| | | | | | | | | | | | | | | |
As of December 31, 2007 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | (In thousands) | |
ASSETS | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
CURRENT ASSETS: | | | | | | | | | | | | | | | |
Cash and cash equivalents | | $ | 2 | | | $ | - | | | $ | - | | | $ | - | | | $ | 2 | |
Receivables- | | | | | | | | | | | | | | | | | | | | |
Customers | | | 133,846 | | | | - | | | | - | | | | - | | | | 133,846 | |
Associated companies | | | 327,715 | | | | 237,202 | | | | 98,238 | | | | (286,656 | ) | | | 376,499 | |
Other | | | 2,845 | | | | 978 | | | | - | | | | - | | | | 3,823 | |
Notes receivable from associated companies | | | 23,772 | | | | - | | | | 69,012 | | | | - | | | | 92,784 | |
Materials and supplies, at average cost | | | 195 | | | | 215,986 | | | | 210,834 | | | | - | | | | 427,015 | |
Prepayments and other | | | 67,981 | | | | 21,605 | | | | 2,754 | | | | - | | | | 92,340 | |
| | | 556,356 | | | | 475,771 | | | | 380,838 | | | | (286,656 | ) | | | 1,126,309 | |
| | | | | | | | | | | | | | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | | | | | | | | | | | | |
In service | | | 25,513 | | | | 5,065,373 | | | | 3,595,964 | | | | (392,082 | ) | | | 8,294,768 | |
Less - Accumulated provision for depreciation | | | 7,503 | | | | 2,553,554 | | | | 1,497,712 | | | | (166,756 | ) | | | 3,892,013 | |
| | | 18,010 | | | | 2,511,819 | | | | 2,098,252 | | | | (225,326 | ) | | | 4,402,755 | |
Construction work in progress | | | 1,176 | | | | 571,672 | | | | 188,853 | | | | - | | | | 761,701 | |
| | | 19,186 | | | | 3,083,491 | | | | 2,287,105 | | | | (225,326 | ) | | | 5,164,456 | |
| | | | | | | | | | | | | | | | | | | | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | | | | | | | | | | | | |
Nuclear plant decommissioning trusts | | | - | | | | - | | | | 1,332,913 | | | | - | | | | 1,332,913 | |
Long-term notes receivable from associated companies | | | - | | | | - | | | | 62,900 | | | | - | | | | 62,900 | |
Investment in associated companies | | | 2,516,838 | | | | - | | | | - | | | | (2,516,838 | ) | | | - | |
Other | | | 2,732 | | | | 37,071 | | | | 201 | | | | - | | | | 40,004 | |
| | | 2,519,570 | | | | 37,071 | | | | 1,396,014 | | | | (2,516,838 | ) | | | 1,435,817 | |
| | | | | | | | | | | | | | | | | | | | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | | | | | | | | | | | |
Accumulated deferred income taxes | | | 16,978 | | | | 522,216 | | | | - | | | | (262,271 | ) | | | 276,923 | |
Lease assignment receivable from associated companies | | | - | | | | 215,258 | | | | - | | | | - | | | | 215,258 | |
Goodwill | | | 24,248 | | | | - | | | | - | | | | - | | | | 24,248 | |
Property taxes | | | - | | | | 25,007 | | | | 22,767 | | | | - | | | | 47,774 | |
Pension asset | | | 3,217 | | | | 13,506 | | | | - | | | | - | | | | 16,723 | |
Unamortized sale and leaseback costs | | | - | | | | 27,597 | | | | - | | | | 43,206 | | | | 70,803 | |
Other | | | 22,956 | | | | 52,971 | | | | 6,159 | | | | (38,133 | ) | | | 43,953 | |
| | | 67,399 | | | | 856,555 | | | | 28,926 | | | | (257,198 | ) | | | 695,682 | |
TOTAL ASSETS | | $ | 3,162,511 | | | $ | 4,452,888 | | | $ | 4,092,883 | | | $ | (3,286,018 | ) | | $ | 8,422,264 | |
| | | | | | | | | | | | | | | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
Currently payable long-term debt | | $ | - | | | $ | 596,827 | | | $ | 861,265 | | | $ | (16,896 | ) | | $ | 1,441,196 | |
Short-term borrowings- | | | | | | | | | | | | | | | | | | | | |
Associated companies | | | - | | | | 238,786 | | | | 25,278 | | | | - | | | | 264,064 | |
Other | | | 300,000 | | | | - | | | | - | | | | - | | | | 300,000 | |
Accounts payable- | | | | | | | | | | | | | | | | | | | | |
Associated companies | | | 287,029 | | | | 175,965 | | | | 268,926 | | | | (286,656 | ) | | | 445,264 | |
Other | | | 56,194 | | | | 120,927 | | | | - | | | | - | | | | 177,121 | |
Accrued taxes | | | 18,831 | | | | 125,227 | | | | 28,229 | | | | (836 | ) | | | 171,451 | |
Other | | | 57,705 | | | | 131,404 | | | | 11,972 | | | | 36,725 | | | | 237,806 | |
| | | 719,759 | | | | 1,389,136 | | | | 1,195,670 | | | | (267,663 | ) | | | 3,036,902 | |
| | | | | | | | | | | | | | | | | | | | |
CAPITALIZATION: | | | | | | | | | | | | | | | | | | | | |
Common stockholder's equity | | | 2,414,231 | | | | 951,542 | | | | 1,562,069 | | | | (2,513,611 | ) | | | 2,414,231 | |
Long-term debt and other long-term obligations | | | - | | | | 1,597,028 | | | | 242,400 | | | | (1,305,716 | ) | | | 533,712 | |
| | | 2,414,231 | | | | 2,548,570 | | | | 1,804,469 | | | | (3,819,327 | ) | | | 2,947,943 | |
| | | | | | | | | | | | | | | | | | | | |
NONCURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
Deferred gain on sale and leaseback transaction | | | - | | | | - | | | | - | | | | 1,060,119 | | | | 1,060,119 | |
Accumulated deferred income taxes | | | - | | | | - | | | | 259,147 | | | | (259,147 | ) | | | - | |
Accumulated deferred investment tax credits | | | - | | | | 36,054 | | | | 25,062 | | | | - | | | | 61,116 | |
Asset retirement obligations | | | - | | | | 24,346 | | | | 785,768 | | | | - | | | | 810,114 | |
Retirement benefits | | | 8,721 | | | | 54,415 | | | | - | | | | - | | | | 63,136 | |
Property taxes | | | - | | | | 25,328 | | | | 22,767 | | | | - | | | | 48,095 | |
Lease market valuation liability | | | - | | | | 353,210 | | | | - | | | | - | | | | 353,210 | |
Other | | | 19,800 | | | | 21,829 | | | | - | | | | - | | | | 41,629 | |
| | | 28,521 | | | | 515,182 | | | | 1,092,744 | | | | 800,972 | | | | 2,437,419 | |
TOTAL LIABILITIES AND CAPITALIZATION | | $ | 3,162,511 | | | $ | 4,452,888 | | | $ | 4,092,883 | | | $ | (3,286,018 | ) | | $ | 8,422,264 | |
FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | |
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | | | | | | | | | | |
For the Three Months Ended March 31, 2008 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | (In thousands) | |
| | | | | | | | | | | | | | | |
NET CASH PROVIDED FROM (USED FOR) | | | | | | | | | | | | | | | |
OPERATING ACTIVITIES | | $ | 273,827 | | | $ | (122,171 | ) | | $ | 8,108 | | | $ | 188 | | | $ | 159,952 | |
| | | | | | | | | | | | | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
New Financing- | | | | | | | | | | | | | | | | | | | | |
Short-term borrowings, net | | | 400,000 | | | | 646,975 | | | | 234,921 | | | | - | | | | 1,281,896 | |
Redemptions and Repayments- | | | | | | | | | | | | | | | | | | | | |
Long-term debt | | | - | | | | (135,063 | ) | | | (153,540 | ) | | | - | | | | (288,603 | ) |
Common stock dividend payments | | | (10,000 | ) | | | - | | | | - | | | | - | | | | (10,000 | ) |
Net cash provided from financing activities | | | 390,000 | | | | 511,912 | | | | 81,381 | | | | - | | | | 983,293 | |
| | | | | | | | | | | | | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
Property additions | | | (19,406 | ) | | | (375,391 | ) | | | (81,545 | ) | | | (187 | ) | | | (476,529 | ) |
Proceeds from asset sales | | | - | | | | 5,088 | | | | - | | | | - | | | | 5,088 | |
Sales of investment securities held in trusts | | | - | | | | - | | | | 173,123 | | | | - | | | | 173,123 | |
Purchases of investment securities held in trusts | | | - | | | | - | | | | (181,079 | ) | | | - | | | | (181,079 | ) |
Loans to associated companies, net | | | (644,604 | ) | | | - | | | | - | | | | - | | | | (644,604 | ) |
Other | | | 183 | | | | (19,438 | ) | | | 12 | | | | (1 | ) | | | (19,244 | ) |
Net cash used for investing activities | | | (663,827 | ) | | | (389,741 | ) | | | (89,489 | ) | | | (188 | ) | | | (1,143,245 | ) |
| | | | | | | | | | | | | | | | | | | | |
Net change in cash and cash equivalents | | | - | | | | - | | | | - | | | | - | | | | - | |
Cash and cash equivalents at beginning of period | | | 2 | | | | - | | | | - | | | | - | | | | 2 | |
Cash and cash equivalents at end of period | | $ | 2 | | | $ | - | | | $ | - | | | $ | - | | | $ | 2 | |
FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | |
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | | | | | | | | | | |
For the Three Months Ended March 31, 2007 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | (In thousands) | |
| | | | | | | | | | | | | | | |
NET CASH PROVIDED FROM | | | | | | | | | | | | | | | |
OPERATING ACTIVITIES | | $ | 65,870 | | | $ | 55,003 | | | $ | 177,456 | | | $ | - | | | $ | 298,329 | |
| | | | | | | | | | | | | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
New Financing- | | | | | | | | | | | | | | | | | | | | |
Equity contribution from parent | | | 700,000 | | | | 700,000 | | | | - | | | | (700,000 | ) | | | 700,000 | |
Short-term borrowings, net | | | 250,000 | | | | - | | | | - | | | | (52,269 | ) | | | 197,731 | |
Redemptions and Repayments- | | | | | | | | | | | | | | | | | | | | |
Long-term debt | | | - | | | | (616,728 | ) | | | (128,716 | ) | | | - | | | | (745,444 | ) |
Short-term borrowings, net | | | - | | | | (52,269 | ) | | | - | | | | 52,269 | | | | - | |
Net cash provided from (used for) financing activities | | | 950,000 | | | | 31,003 | | | | (128,716 | ) | | | (700,000 | ) | | | 152,287 | |
| | | | | | | | | | | | | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
Property additions | | | (214 | ) | | | (81,400 | ) | | | (35,892 | ) | | | - | | | | (117,506 | ) |
Sales of investment securities held in trusts | | | - | | | | - | | | | 178,632 | | | | - | | | | 178,632 | |
Purchases of investment securities held in trusts | | | - | | | | - | | | | (188,076 | ) | | | - | | | | (188,076 | ) |
Loans to associated companies, net | | | (316,003 | ) | | | - | | | | (3,895 | ) | | | - | | | | (319,898 | ) |
Investment in subsidiary | | | (700,000 | ) | | | - | | | | - | | | | 700,000 | | | | - | |
Other | | | 347 | | | | (4,606 | ) | | | 491 | | | | - | | | | (3,768 | ) |
Net cash used for investing activities | | | (1,015,870 | ) | | | (86,006 | ) | | | (48,740 | ) | | | 700,000 | | | | (450,616 | ) |
| | | | | | | | | | | | | | | | | | | | |
Net change in cash and cash equivalents | | | - | | | | - | | | | - | | | | - | | | | - | |
Cash and cash equivalents at beginning of period | | | 2 | | | | - | | | | - | | | | - | | | | 2 | |
Cash and cash equivalents at end of period | | $ | 2 | | | $ | - | | | $ | - | | | $ | - | | | $ | 2 | |
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Risk Information” in Item 2 above.
ITEM 4. CONTROLS AND PROCEDURES
(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES – FIRSTENERGY
The applicable registrant'sFirstEnergy’s chief executive officer and chief financial officer have reviewed and evaluated the registrant's disclosure controls and procedures. The term disclosure controls and procedures means controls and other procedures of a registrant that are designed to ensure that information required to be disclosed by the registrant in the reports that it files or submits under the Securities Exchange Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under that Act is accumulated and communicated to the registrant's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, those officers have concluded that the applicable registrant's disclosure controls and procedures are effective and were designed to bring to their attention material information relating to the registrant and its consolidated subsidiaries by others within those entities.
(b) CHANGES IN INTERNAL CONTROLS
During the quarter ended June 30, 2007,March 31, 2008, there were no changes in FirstEnergy’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrant’s internal control over financial reporting.
ITEM 4T. CONTROLS AND PROCEDURES – FES, OE, CEI, TE, JCP&L, MET-ED AND PENELEC
(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
Each registrant's chief executive officer and chief financial officer have reviewed and evaluated such registrant's disclosure controls and procedures. The term disclosure controls and procedures means controls and other procedures of a registrant that are designed to ensure that information required to be disclosed by the registrant in the reports that it files or submits under the Securities Exchange Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under that Act is accumulated and communicated to the registrant's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, those officers have concluded that such registrant's disclosure controls and procedures are effective and were designed to bring to their attention material information relating to such registrant and its consolidated subsidiaries by others within those entities.
(b) CHANGES IN INTERNAL CONTROLS
During the quarter ended March 31, 2008, 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 910 and 1011 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
ITEM 1A. RISK FACTORS
See Item 1A RISK FACTORS in Part I of the Form 10-K for the year ended December 31, 20062007 for a discussion of the risk factors of FirstEnergy and the subsidiary registrants. For the quarter ended June 30, 2007,March 31, 2008, there have been no material changes to these risk factors.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
(c) FirstEnergy
The table below includes information on a monthly basis regarding purchases made by FirstEnergy of its common stock.
| | | | | Period | |
| | April 1-30, | | May 1-31, | | June 1-30, | | Second | | | January 1-31, | | February 1-29, | | March 1-31, | | First | |
| | | | | | | | | | | | | | | | | | |
Total Number of Shares Purchased (a) | | 194,553 | | 304,287 | | 219,445 | | 718,285 | | | 329,106 | | 16,853 | | 988,386 | | 1,334,345 | |
Average Price Paid per Share | | $68.41 | | $71.09 | | $68.12 | | $69.46 | | | $76.56 | | $71.68 | | $68.55 | | $70.57 | |
Total Number of Shares Purchased | | | | | | | | | | | | | | | | | | |
As Part of Publicly Announced Plans | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Maximum Number (or Approximate Dollar | | | | | | | | | | | | | | | | | | | | |
Value) of Shares that May Yet Be | | | | | | | | | | | | | | | | | | | | |
Purchased Under the Plans or Programs | | | 1,629,890 | | 1,629,890 | | 1,629,890 | | | 1,629,890 | | | - | | - | | - | | - | |
(a) | Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver common stock under its Executive and Director 2007 Incentive Compensation Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred
Comp ensation 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 2007 Incentive Compensation Plan and the Executive and Director Incentive Deferred Compensation Plan, and shares purchased as part of publicly announced plans. |
| |
(b) | FirstEnergy publicly announced, on January 30,On December 10, 2007, aFirstEnergy’s plan to repurchase up to 16 million shares of its common stock through
June 30, 2008. On March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or 4.5%, of its outstanding common stock under this plan through an accelerated share repurchase program with an affiliate of Morgan Stanley and Co.,
Incorporated at an initial price of $62.63 per share. 2008, was concluded. |
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
(a) | The annual meeting of FirstEnergy shareholders was held on May 15, 2007. |
(b) | At this meeting, the following persons were elected to FirstEnergy's Board of Directors for one-year terms: |
| | Number of Votes | |
| | For | | Withheld | |
| | | | | |
Paul T. Addison | | | 188,720,311 | | | 74,174,290 | |
Anthony J. Alexander | | | 188,700,783 | | | 74,193,818 | |
Michael J. Anderson | | | 249,806,449 | | | 13,088,152 | |
Dr. Carol A. Cartwright | | | 159,733,696 | | | 103,160,905 | |
William T. Cottle | | | 166,930,916 | | | 95,963,685 | |
Robert B. Heisler, Jr. | | | 190,762,159 | | | 72,132,442 | |
Ernest J. Novak, Jr. | | | 188,312,120 | | | 74,582,481 | |
Catherine A. Rein | | | 188,486,982 | | | 74,407,619 | |
George M. Smart | | | 166,422,193 | | | 96,472,408 | |
Wes M. Taylor | | | 188,651,197 | | | 74,243,404 | |
Jesse T. Williams, Sr. | | | 166,684,440 | | | 96,210,161 | |
The following Directors retired from the Board effective May 15, 2007: Russell W. Maier and Robert C. Savage.
(c) | (i) | At this meeting, the appointment of PricewaterhouseCoopers LLP, an independent registered public accounting firm, as auditor for the year 2007 was ratified: |
Number of Votes | |
| |
For | | Against | | Abstentions | |
| | | | | |
258,877,611 | | | 1,368,549 | | | 2,648,441 | |
| (ii) | At this meeting, the FirstEnergy Corp. 2007 Incentive Plan was approved: |
Number of Votes | |
| | | | | | Broker | |
For | | Against | | Abstentions | | Non-Votes | |
| | | | | | | |
207,313,123 | | | 23,286,182 | | | 3,901,643 | | | 28,393,653 | |
| (iii) | At this meeting, a shareholder proposal recommending that the Board of Directors change the company’s jurisdiction from Ohio to Delaware was not approved (approval required a favorable vote of a majority of the votes cast): |
Number of Votes | |
| | | | | | Broker | |
For | | Against | | Abstentions | | Non-Votes | |
| | | | | | | |
80,014,916 | | | 149,489,965 | | | 5,026,051 | | | 28,363,669 | |
| (iv) | At this meeting, a shareholder proposal recommending that the Board of Directors adopt a policy establishing an engagement process with proponents of shareholder proposals that are supported by a majority of the votes cast was not approved (approval required a favorable vote of a majority of the votes cast): |
Number of Votes | |
| | | | | | Broker | |
For | | Against | | Abstentions | | Non-Votes | |
| | | | | | | |
91,938,193 | | | 137,204,324 | | | 5,358,416 | | | 28,393,668 | |
| | | | | | | | | | |
| (v) | At this meeting, a shareholder proposal recommending that the Board of Directors adopt simple majority shareholder voting was approved (approval required a favorable vote of a majority of the votes cast): |
Number of Votes | |
| | | | | | Broker | |
For | | Against | | Abstentions | | Non-Votes | |
| | | | | | | |
175,884,412 | | | 53,721,749 | | | 4,893,976 | | | 28,394,464 | |
Based on this result, the Board of directors will further review this proposal
and consider the appropriate steps to take in response.
ITEM 6. EXHIBITS
Exhibit Number | |
|
| | |
FirstEnergy
| |
| | |
| 10-1
| | | |
Participation Agreement, dated as of June 26, 2007, among FirstEnergy Generation Corp., as Lessee, FirstEnergy Solutions Corp., as Guarantor, the applicable Lessor, U.S. Bank Trust National Association, as Trust Company, the applicable Owner Participant, The Bank of New York Trust Company, N.A., as Indenture Trustee, and The Bank of New York Trust Company, N.A., as Pass Through Trustee(1)(2)
|
| 10-2 | Trust Agreement, dated as of June 26, 2007 between the applicable Owner Participant and U.S. Bank Trust National Association, as Owner Trustee(1)(2)
|
| 10-3 | Indenture of Trust, Open-End Mortgage and Security Agreement, dated as of July 1, 2007, between the applicable Lessor and The Bank of New York Trust Company, N.A., as Indenture Trustee(1)(2)
|
| 10-4 | 6.85% Lessor Note due 2034(1)(2) (included in Exhibit 10-3)
|
| 10-5 | Bill of Sale and Transfer, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor(1)(2)
|
| 10-6 | Facility Lease Agreement, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor(1)(2)
|
| 10-7 | Site Lease, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor(1)(2)
|
| 10-8 | Site Sublease, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor(1)(2)
|
| 10-9 | Guaranty of FirstEnergy Solutions Corp., dated as of July 1, 2007(1)(2)
|
| 10-10 | Support Agreement, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor(1)(2)
|
| 10-11
| Second Amendment to the Bruce Mansfield Units 1, 2, and 3 Operating Agreement, dated as of July 1, 2007, between FirstEnergy Generation Corp., The Cleveland Electric Illuminating Company, and The Toledo Edison Company(1)
|
| 10-12
| Pass Through Trust Agreement, dated as of June 26, 2007, among FirstEnergy Generation Corp., FirstEnergy Solutions Corp., and The Bank of New York Trust Company, N.A., as Pass Through Trustee(1)
|
| 10-13 | 6.85% Pass Through Trust Certificate due 2034(1)(2) (included in Exhibit 10-12)
|
| 10-14
| Registration Rights Agreement, dated as of July 13, 2007, among FirstEnergy Generation Corp., FirstEnergy Solutions Corp., The Bank of New York Trust Company, N.A., as Pass Through Trustee, Morgan Stanley & Co. Incorporated, and Credit Suisse Securities (USA) LLC, as representatives of the several initial purchasers(1)
|
| 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-14(a). | | |
| 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a). | | |
| 32 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.1350 | | |
FES | | |
| 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a) | |
| 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a) | |
| 32 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350 | |
OE | | |
| 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-14(a) | |
| 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a) | |
| 32 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350 | |
CEI | | |
| 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a) | |
| 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a) | |
| 32 | 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-14(a) | |
| 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a) | |
| 32 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350 | |
JCP&L | | |
| 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a) | |
| 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a) | |
| 32 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350 | |
Met-Ed | |
| 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a) |
| 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a) |
| 32 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350 |
Penelec | |
| 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-14(a). |
| 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a). |
| 32 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. |
| |
CEI
| |
| | |
| 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a). |
| 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a). |
| 32 | 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-14(a). |
| 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a). |
| 32 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. |
| | |
JCP&L
| |
| | |
| 3 | Jersey Central Power & Light Company By-Laws, as amended July 11, 2007 |
| 12 | Fixed charge ratios |
| 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a). |
| 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a). |
| 32 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. |
| | |
Met-Ed
| |
| | |
| 12 | Fixed charge ratios |
| 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a). |
| 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a). |
| 32 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. |
| | |
Penelec
| |
| | |
| 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-14(a). |
| 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a). |
| 32 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. |
(1) Incorporated by reference to the Registrant’s Form 8-K/A filed on August 2, 2007.
| (2) Pursuant to the Instructions to Item 601(a), the Registrant has omitted the indentures, contracts and other documents required to be filed as exhibits since they are substantially identical in all material respects except as to the parties thereto and certain other details as noted in the schedule filed as Exhibit 99-1 to the Registrant’s Form 8-K/A file on August 2, 2007. The Registrant agrees to furnish these items at the request of the SEC. 1350 |
Pursuant to reporting requirements of respective financings, FirstEnergy, OE JCP&L, Met-Ed and Penelec are required to file fixed charge ratios as an exhibit to this Form 10-Q.
Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy, FES, OE, CEI, TE, 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 its respective total assets, but each hereby agrees to furnish to the SEC on request any such documents.
SIGNATURES
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.
August 7, 2007May 8, 2008
| FIRSTENERGY CORP. |
| Registrant |
| |
| OHIO EDISON COMPANY FIRSTENERGY SOLUTIONS CORP. |
| Registrant |
| |
| THE CLEVELAND ELECTRIC
|
| ILLUMINATINGOHIO EDISON COMPANY
|
| Registrant |
| |
| THE TOLEDO EDISONCLEVELAND ELECTRIC |
| ILLUMINATING COMPANY |
| Registrant |
| |
| METROPOLITANTHE TOLEDO EDISON COMPANY
|
| Registrant |
| |
| METROPOLITAN EDISON COMPANY |
| Registrant |
| |
| PENNSYLVANIA ELECTRIC COMPANY |
| Registrant |
| |
| Harvey L. Wagner |
| Vice President, Controller |
| and Chief Accounting Officer |
| JERSEY CENTRAL POWER & LIGHT COMPANY |
| Registrant |
| |
| |
| |
| |
| Paulette R. Chatman |
| Controller |
| (Principal Accounting Officer) |