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,residuals, 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. In February 2009, the EPA requested comments from the states on options for regulating coal combustion wastes,residuals, including regulation as non-hazardous waste or regulation as a hazardous waste. In March and June 2009, the EPA requested information from FGCO’s Bruce Mansfield Plant regarding the management of coal combustion residuals. In December 2009, the EPA provided to FGCO the findings of its review of the Bruce Mansfield Plant’s coal combustion residuals managem ent practices. The EPA observed that the waste management structures and the Plant “appeared to be well maintained and in good working order” and recommended only that FGCO “seal and maintain all asphalt surfaces.” On December 30, 2009, in an advanced notice of public rulemaking, the EPA said that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. On May 4, 2010, the EPA issued a proposed rule that provides two options for additional regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA’s hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. FGCO's future cost of compliance with any coal combustion wasteresiduals regulations which may be promulgated could be substantial and willwould depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states.
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of March 31, 2009, FirstEnergy had approximately $1.6 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 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 Utilities have been named as potentially responsible parties 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 potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheetconsolidated balance sheet as of March 31, 2009,2010, based on estimates of the total costs of cleanup, the Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $91$101 million (JCP&a mp;L - $74 million, TE - $1 million, CEI - $1 million, FGCO - $1 million and FirstEnergy - $24 million) have been accrued through March 31, 2009.2010. Included in the total are accrued liabilities of approximately $56$67 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.
Other Legal Proceedings(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, the Muise class action)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 fromdue to the July 1999 service interruptions in the JCP&L territory.outages.
After various motions, rulings and appeals, the Plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, strict product liability, and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. The class was decertified twice by the trial court, and appealed both times by the Plaintiffs, with the results being that: (1) the Appellate Division limited the class only 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 which resulted in planned and unplanned outages in the area during a 2-3 day period, and (2) in March 2007, the Appellate Division remanded this matter back to the Trial Court to allow plaintiffs sufficientsufficie nt time to establish a damage model or individual proof of damages. Proceedings then continued at the trial court level and a case management conference with the presiding Judge was held on June 13, 2008. At that conference, counsel for the Plaintiffs stated his intent to drop his efforts to create a class-wide damage model and, instead of dismissing the class action, expressed his desire for a bifurcated trial on liability and damages. In response, JCP&L filed an objection to the plaintiffs’ proposed trial plan and another motion to decertify the class. On March 31, 2009, the trial court again granted JCP&L’s motion to decertify the class. On April 20, 2009, the Plaintiffs filed theira motion for leave to take an interlocutory appeal to the trial court's decision to decertify the class, which was granted by the Appellate Division on June 15, 2009. Plaintiffs filed their appellate brief on August 25, 2009, and JCP&L filed an opposition brief on September 25, 2009. On or about October 13, 2009, Plaintiffs filed their reply brief in further support of their appeal of the trial court's decision decertifying the class. The Appellate Division heard oral argument on January 5, 2010, before a three-judge panel. JCP&L is awaiting the Court’s decision.
Litigation Relating to the Proposed Allegheny Energy Merger
In connection with the proposed merger (Note 14), purported shareholders of Allegheny Energy have filed putative shareholder class action and/or derivative lawsuits in Pennsylvania and Maryland state courts, as well as in the U.S. District Court for the Western District of Pennsylvania, against Allegheny Energy and its directors and certain officers, referred to as the Allegheny Energy defendants, FirstEnergy and Merger Sub. The lawsuits allege, among other things, that the Allegheny Energy directors breached their fiduciary duties by approving the merger agreement, and that Allegheny Energy, FirstEnergy and Merger Sub aided and abetted in these alleged breaches of fiduciary duty. The plaintiffs allege that the merger consideration is unfair, that other terms in the merger agreement including the termination fee and the non-solicitation provision s are unfair, that certain individual defendants are financially interested in the merger, and that Allegheny Energy has failed to disclose material information about the merger to its shareholders. Among other remedies, the plaintiffs seek to enjoin the merger and they have demanded jury trials. The Allegheny Energy defendants moved to consolidate the Maryland lawsuits and filed motions to dismiss and answers to each of the Maryland complaints. The court consolidated the Maryland lawsuits and an amended complaint has been filed. The Allegheny Energy defendants, FirstEnergy, and Merger Sub filed motions to dismiss the amended complaint on April 21, 2010. The Maryland court has set a hearing for argument on the motions to dismiss for June 3, 2010. By order dated April 26, 2010, the Maryland court certified a plaintiff class that consists of all holders of Allegheny Energy shares at any time from February 11, 2010 to the consummation of the proposed merger. The Pennsylvania state court has consolidat ed the lawsuits filed in that court. The Allegheny Energy defendants and FirstEnergy have moved to stay the Pennsylvania lawsuits and the plaintiff has moved for leave to take expedited discovery. The Pennsylvania state court will hear argument on both motions on May 27, 2010. By stipulation dated April 14, 2010, no response is due to the complaint filed in the U.S. District Court for the Western District of Pennsylvania until June 10, 2010. While FirstEnergy and Allegheny Energy believe the lawsuits are without merit and intend to defend vigorously against the claims, the outcome of any such litigation is inherently uncertain. If a dismissal is not granted or a settlement is not reached, these lawsuits could prevent or delay the completion of the merger and result in substantial costs to FirstEnergy and Allegheny Energy. In accordance with its bylaws, Allegheny Energy will advance expenses to and, as necessary, indemnify all of its directors in connection with the foregoing proceedings. All applicable insur ance policies may not provide sufficient coverage for the claims under these lawsuits, and rights of indemnification with respect to these lawsuits will continue whether or not the merger is completed. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger closes may adversely affect FirstEnergy’s business, financial condition or results of operations.
Nuclear Plant Matters
On May 14, 2007, the Office of EnforcementDavis Besse Control Rod Drive Mechanism Nozzles
During a planned refueling outage at Davis-Besse that began on February 28, 2010, FENOC initially identified 16 of the 69 control rod drive mechanism (CRDM) nozzles that required modification. The Nuclear Regulatory Commission was notified of these findings, along with federal, state and local officials. The initial nozzle inspection process included ultrasonic (UT) testing and visual inspections. On March 18, 2010, the NRC issuedsent a Demand for Information 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) relatedspecial inspection team 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 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. FENOC submitted a supplemental response clarifying certain aspects of the response to the NRC on July 16, 2007. The NRC issued a Confirmatory Order imposing these commitments on FENOC. In an April 23, 2009 Inspection Report, the NRC concluded that FENOC had completed all necessary actions required by the Confirmatory Order.
FENOC has begun a comprehensive investigation to determine the underlying cause for the cracking, and retained a contractor to make the necessary modifications. Modifications will be made using a proven industry method subject to NRC review. Further evaluation and testing identified 8 additional nozzles requiring modification. Additional testing will be conducted following the modification of each nozzle to ensure safe, reliable plant operations. The plant is expected to be ready for restart in July 2010.
On April 5, 2010, the Union of Concerned Scientists (UCS) requested that the NRC issue a Show Cause Order, or otherwise delay the restart of the Davis-Besse Nuclear Power Station until such time that the NRC determines that adequate protection standards have been met and reasonable assurance exists that these standards will continue to be met after the plant’s operation is resumed. What actions, if any, the NRC takes in response to this request have yet to be determined.
In August 2007, FENOC submitted anUnder NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of obligations. As of March 31, 2010, FirstEnergy had approximately $1.9 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 renewtransfer the operating licensesownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy provided an additional $80 million parental guarantee associated with the funding of decommissioning costs for these units and indicated that it planned to contribute an additional $80 million to these trusts by 2010. By a letter dated March 8, 2010, primarily as a result of the Beaver ValleyV alley Power Station (Units 1operating license renewal, FENOC requested that the NRC reduce FirstEnergy parental guarantee to $15 million and 2) for annotified the staff that it no longer planned to make the additional 20 years. The NRCcontributions into the trusts. FirstEnergy is required by statute to provide an opportunity for membersawaiting the NRC’s decision on the proposed reduction of the public to request a hearing on the application. No members of the public, however, requested a hearing on the Beaver Valley license renewal application. On September 24, 2008, the NRC issued a draft supplemental Environmental Impact Statement for Beaver Valley. FENOC will continue to work with the NRC Staff as it completes its environmental and technical reviews of the license renewal application, and expects to obtain renewed licenses for the Beaver Valley Power Station in 2009. If renewed licenses are issued by the NRC, the Beaver Valley Power Station’s licenses would be extended until 2036 and 2047 for Units 1 and 2, respectively.parental guarantee.
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.
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. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. A final order identifying the individual damage amounts was issued on October 31, 2007 and 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. JCP&L and the union filed briefs in June and July of 2008 and oral arguments were held in the fall. On February 25, 2009, the federal district court denied JCP&L’s motion to vacate the arbitration decision and granted the union’s motion to confirm the award. JCP&L filed a Notice of Appeal to the Third Circuit and a Motion to Stay Enforcement of the Judgment on March 6, 2009;2009. The parties participated in the appeal process could take as long as 24 months.federal court's mediation programs and held private settlement discussions. On April 14, 2010, the parties reached a tentative agreement on a settlement package that must be reviewed and approved by the court. JCP&L recognized a liability for the potential $16 million award in 2005. Post-judgment2005, which has been adjusted for post-judgment interest that began to accrue as of February 25, 2009,2009.
On February 16, 2010, a class action lawsuit was filed in Geauga County Court of Common Pleas against FirstEnergy, CEI and the liability will be adjusted accordingly.
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 assistanceOE seeking declaratory judgment and injunctive relief, as well as compensatory, incidental and consequential damages, on behalf of a federal mediator. FirstEnergy hasclass of customers related to the reduction of a strike mitigation plan readydiscount that had previously been in place for residential customers with electric heating, electric water heating, or load management systems. The reduction in the eventdiscount was approved by the PUCO. On March 18, 2010, the named-defendant companies filed a motion to dismiss the case due to the lack of a strike.jurisdiction of the court of common pleas. The court has not yet ruled on that motion to dismiss. The named-defendant companies will continue to defend these claims including challenging any class certification.
The union employees at Met-Ed have been working without a labor contract since May 1, 2009. The parties are continuing to bargain and FirstEnergy has a work continuation 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
FSP FAS 157-4 – “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly”
In April 2009, the FASB issued Staff Position FAS 157-4, which provides additional guidance to consider in estimating fair value when there has been a significant decrease in market activity for a financial asset. The FSP establishes a two-step process requiring a reporting entity to first determine if a market is not active in relation to normal market activity for the asset. If evidence indicates the market is not active, an entity would then need to determine whether a quoted price in the market is associated with a distressed transaction. An entity will need to further analyze the transactions or quoted prices, and an adjustment to the transactions or quoted prices may be necessary to estimate fair value. Additional disclosures related to the inputs and valuation techniques used in the fair value measurements are also required. The FSP is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FirstEnergy will adopt the FSP for its interim period ending June 30, 2009. While the FSP will expand disclosure requirements, FirstEnergy does not expect the FSP to have a material effect upon its financial statements.
| FSP FAS 115-2 and FAS 124-2 - “Recognition and Presentation of Other-Than-Temporary Impairments” |
In April 2009, the FASB issued Staff Position FAS 115-2 and FAS 124-2, which changes the method to determine whether an other-than-temporary impairment exists for debt securities and the amount of impairment to be recorded in earnings. Under the FSP, management will be required to assert it does not have the intent to sell the debt security, and it is more likely than not it will not have to sell the debt security before recovery of its cost basis. If management is unable to make these assertions, the debt security will be deemed other-than-temporarily impaired and the security will be written down to fair value with the full charge recorded through earnings. If management is able to make the assertions, but there are credit losses associated with the debt security, the portion of impairment related to credit losses will be recognized in earnings while the remaining impairment will be recognized through other comprehensive income. The FSP is effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FirstEnergy will adopt the FSP for its interim period ending June 30, 2009 and does not expect the FSP to have a material effect upon its financial statements.
| FSP FAS 107-1 and APB 28-1 - “Interim Disclosures about Fair Value of Financial Instruments” |
In April 2009, the FASB issued Staff Position FAS 107-1 and APB 28-1, which requires disclosures of the fair value of financial instruments in interim financial statements, as well as in annual financial statements. The FSP also requires entities to disclose the methods and significant assumptions used to estimate the fair value of financial instruments in both interim and annual financial statements. The FSP is effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FirstEnergy will adopt the FSP for its interim period ending June 30, 2009, and expects to expand its disclosures regarding the fair value of financial instruments.9. REGULATORY MATTERS
FSP FAS 132 (R)-1 – “Employers’ Disclosures about Postretirement Benefit Plan Assets”(A) RELIABILITY INITIATIVES
In December 2008, the FASB issued Staff Position FAS 132(R)-1, which provides guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. Requirements of this FSP include disclosures about investment policies and strategies, categories of plan assets, fair value measurements of plan assets, and significant categories of risk. This FSP is effective for fiscal years ending after December 15, 2009. FirstEnergy will expand its disclosures related to postretirement benefit plan assets as a result of this FSP.
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, 2009 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2009 and 2008. 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, 2008, and the related consolidated statements of income, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. As discussed in Note 6 to the accompanying consolidated financial statements, the Company changed its reporting related to noncontrolling interest. The accompanying December 31, 2008 consolidated balance sheet reflects this change.
|
PricewaterhouseCoopers LLP
Cleveland, Ohio
May 7, 2009
|
| FIRSTENERGY CORP. | |
| | | | | | |
| CONSOLIDATED STATEMENTS OF INCOME | |
| (Unaudited) | |
| | | | | | |
| | Three Months Ended | |
| | March 31 | |
| | | | | | |
| | 2009 | | | 2008 | |
| | (In millions, except | |
| | per share amounts) | |
| REVENUES: | | | | | |
| Electric utilities | $ | 3,020 | | | $ | 2,913 | |
| Unregulated businesses | | 314 | | | | 364 | |
| Total revenues* | | 3,334 | | | | 3,277 | |
| | | | | | | | |
| EXPENSES: | | | | | | | |
| Fuel | | 312 | | | | 328 | |
| Purchased power | | 1,143 | | | | 1,000 | |
| Other operating expenses | | 827 | | | | 799 | |
| Provision for depreciation | | 177 | | | | 164 | |
| Amortization of regulatory assets | | 411 | | | | 258 | |
| Deferral of new regulatory assets | | (93 | ) | | | (105 | ) |
| General taxes | | 211 | | | | 215 | |
| Total expenses | | 2,988 | | | | 2,659 | |
| | | | | | | | |
| OPERATING INCOME | | 346 | | | | 618 | |
| | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | |
| Investment income (loss), net | | (11 | ) | | | 17 | |
| Interest expense | | (194 | ) | | | (179 | ) |
| Capitalized interest | | 28 | | | | 8 | |
| Total other expense | | (177 | ) | | | (154 | ) |
| | | | | | | | |
| INCOME BEFORE INCOME TAXES | | 169 | | | | 464 | |
| | | | | | | | |
| INCOME TAXES | | 54 | | | | 187 | |
| | | | | | | | |
| NET INCOME | | 115 | | | | 277 | |
| | | | | | | | |
| Less: Noncontrolling interest income (loss) | | (4 | ) | | | 1 | |
| | | | | | | | |
| EARNINGS AVAILABLE TO PARENT | $ | 119 | | | $ | 276 | |
| | | | | | | | |
| | | | | | | | |
| BASIC EARNINGS PER SHARE OF COMMON STOCK | $ | 0.39 | | | $ | 0.91 | |
| | | | | | | | |
| WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING | | 304 | | | | 304 | |
| | | | | | | | |
| DILUTED EARNINGS PER SHARE OF COMMON STOCK | $ | 0.39 | | | $ | 0.90 | |
| | | | | | | | |
| WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING | | 306 | | | | 307 | |
| | | | | | | | |
| DIVIDENDS DECLARED PER SHARE OF COMMON STOCK | $ | 0.55 | | | $ | 0.55 | |
| | | | | | | | |
| | | | | | | | |
| * Includes $109 million and $114 million of excise tax collections in the first quarter of 2009 and 2008, 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 | |
| | 2009 | | | 2008 | |
| | (In millions) | |
| | | | | | |
| NET INCOME | $ | 115 | | | $ | 277 | |
| | | | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | |
| Pension and other postretirement benefits | | 35 | | | | (20 | ) |
| Unrealized gain (loss) on derivative hedges | | 15 | | | | (13 | ) |
| Change in unrealized gain on available-for-sale securities | | (5 | ) | | | (58 | ) |
| Other comprehensive income (loss) | | 45 | | | | (91 | ) |
| Income tax expense (benefit) related to other comprehensive income | | 15 | | | | (33 | ) |
| Other comprehensive income (loss), net of tax | | 30 | | | | (58 | ) |
| | | | | | | | |
| COMPREHENSIVE INCOME | | 145 | | | | 219 | |
| | | | | | | | |
| COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST | | (4 | ) | | | 1 | |
| | | | | | | | |
| COMPREHENSIVE INCOME ATTRIBUTABLE TO PARENT | $ | 149 | | | $ | 218 | |
| | | | | | | | |
| 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, | |
| | 2009 | | | 2008 | |
| | (In millions) | |
| ASSETS | | | | | |
| | | | | | |
| CURRENT ASSETS: | | | | | |
| Cash and cash equivalents | $ | 399 | | | $ | 545 | |
| Receivables- | | | | | | | |
| Customers (less accumulated provisions of $27 million and $28 million, | | | | | | | |
| respectively, for uncollectible accounts) | | 1,266 | | | | 1,304 | |
| Other (less accumulated provisions of $9 million for uncollectible accounts) | | 159 | | | | 167 | |
| Materials and supplies, at average cost | | 657 | | | | 605 | |
| Prepaid taxes | | 318 | | | | 283 | |
| Other | | 205 | | | | 149 | |
| | | 3,004 | | | | 3,053 | |
| PROPERTY, PLANT AND EQUIPMENT: | | | | | | | |
| In service | | 26,757 | | | | 26,482 | |
| Less - Accumulated provision for depreciation | | 10,947 | | | | 10,821 | |
| | | 15,810 | | | | 15,661 | |
| Construction work in progress | | 2,397 | | | | 2,062 | |
| | | 18,207 | | | | 17,723 | |
| INVESTMENTS: | | | | | | | |
| Nuclear plant decommissioning trusts | | 1,649 | | | | 1,708 | |
| Investments in lease obligation bonds | | 561 | | | | 598 | |
| Other | | 689 | | | | 711 | |
| | | 2,899 | | | | 3,017 | |
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | |
| Goodwill | | 5,575 | | | | 5,575 | |
| Regulatory assets | | 2,938 | | | | 3,140 | |
| Power purchase contract asset | | 340 | | | | 434 | |
| Other | | 594 | | | | 579 | |
| | | 9,447 | | | | 9,728 | |
| | $ | 33,557 | | | $ | 33,521 | |
| LIABILITIES AND CAPITALIZATION | | | | | | | |
| | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | |
| Currently payable long-term debt | $ | 2,144 | | | $ | 2,476 | |
| Short-term borrowings | | 2,397 | | | | 2,397 | |
| Accounts payable | | 704 | | | | 794 | |
| Accrued taxes | | 281 | | | | 333 | |
| Other | | 1,169 | | | | 1,098 | |
| | | 6,695 | | | | 7,098 | |
| CAPITALIZATION: | | | | | | | |
| Common stockholders’ equity- | | | | | | | |
| Common stock, $0.10 par value, authorized 375,000,000 shares- | | 31 | | | | 31 | |
| 304,835,407 shares outstanding | | | | | | | |
| Other paid-in capital | | 5,459 | | | | 5,473 | |
| Accumulated other comprehensive loss | | (1,350 | ) | | | (1,380 | ) |
| Retained earnings | | 4,110 | | | | 4,159 | |
| Total common stockholders' equity | | 8,250 | | | | 8,283 | |
| Noncontrolling interest | | 34 | | | | 32 | |
| Total equity | | 8,284 | | | | 8,315 | |
| Long-term debt and other long-term obligations | | 9,697 | | | | 9,100 | |
| | | 17,981 | | | | 17,415 | |
| NONCURRENT LIABILITIES: | | | | | | | |
| Accumulated deferred income taxes | | 2,130 | | | | 2,163 | |
| Asset retirement obligations | | 1,356 | | | | 1,335 | |
| Deferred gain on sale and leaseback transaction | | 1,018 | | | | 1,027 | |
| Power purchase contract liability | | 816 | | | | 766 | |
| Retirement benefits | | 1,896 | | | | 1,884 | |
| Lease market valuation liability | | 296 | | | | 308 | |
| Other | | 1,369 | | | | 1,525 | |
| | | 8,881 | | | | 9,008 | |
| COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 8) | | | | | | | |
| | $ | 33,557 | | | $ | 33,521 | |
| | | | | | | | |
| The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets. | | | | | |
| FIRSTENERGY CORP. | |
| | | | | | |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| (Unaudited) | |
| | | | | | |
| | Three Months Ended | |
| | March 31 | |
| | 2009 | | | 2008 | |
| | (In millions) | |
| | | | | | |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | |
| Net Income | $ | 115 | | | $ | 277 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | | | |
| Provision for depreciation | | 177 | | | | 164 | |
| Amortization of regulatory assets | | 411 | | | | 258 | |
| Deferral of new regulatory assets | | (93 | ) | | | (105 | ) |
| Nuclear fuel and lease amortization | | 27 | | | | 26 | |
| Deferred purchased power and other costs | | (62 | ) | | | (43 | ) |
| Deferred income taxes and investment tax credits, net | | (28 | ) | | | 89 | |
| Investment impairment | | 36 | | | | 16 | |
| Deferred rents and lease market valuation liability | | (14 | ) | | | 4 | |
| Stock-based compensation | | (13 | ) | | | (35 | ) |
| Accrued compensation and retirement benefits | | (66 | ) | | | (142 | ) |
| Gain on asset sales | | (5 | ) | | | (37 | ) |
| Electric service prepayment programs | | (8 | ) | | | (19 | ) |
| Cash collateral received (paid) | | (15 | ) | | | 8 | |
| Decrease (increase) in operating assets- | | | | | | | |
| Receivables | | 46 | | | | (6 | ) |
| Materials and supplies | | (7 | ) | | | (17 | ) |
| Prepaid taxes | | (34 | ) | | | (100 | ) |
| Increase (decrease) in operating liabilities- | | | | | | | |
| Accounts payable | | (90 | ) | | | (23 | ) |
| Accrued taxes | | (51 | ) | | | (5 | ) |
| Accrued interest | | 118 | | | | 91 | |
| Other | | 18 | | | | (42 | ) |
| Net cash provided from operating activities | | 462 | | | | 359 | |
| | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | |
| New Financing- | | | | | | | |
| Long-term debt | | 700 | | | | - | |
| Short-term borrowings, net | | - | | | | 746 | |
| Redemptions and Repayments- | | | | | | | |
| Long-term debt | | (444 | ) | | | (368 | ) |
| Net controlled disbursement activity | | (10 | ) | | | 6 | |
| Common stock dividend payments | | (168 | ) | | | (168 | ) |
| Other | | (8 | ) | | | 8 | |
| Net cash provided from financing activities | | 70 | | | | 224 | |
| | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | |
| Property additions | | (654 | ) | | | (711 | ) |
| Proceeds from asset sales | | 8 | | | | 50 | |
| Sales of investment securities held in trusts | | 567 | | | | 361 | |
| Purchases of investment securities held in trusts | | (584 | ) | | | (384 | ) |
| Cash investments | | 17 | | | | 58 | |
| Other | | (32 | ) | | | (16 | ) |
| Net cash used for investing activities | | (678 | ) | | | (642 | ) |
| | | | | | | | |
| Net change in cash and cash equivalents | | (146 | ) | | | (59 | ) |
| Cash and cash equivalents at beginning of period | | 545 | | | | 129 | |
| Cash and cash equivalents at end of period | $ | 399 | | | $ | 70 | |
| | | | | | | | |
| 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 and maintains 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 have been primarily derived 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 and default service requirements. These affiliated power sales included a full-requirements PSA with OE, CEI and TE to supply each of their default service obligations through December 31, 2008, at prices that considered their respective PUCO-authorized billing rates. See Regulatory Matters – Ohio below for a discussion of Ohio power supply procurement issues for 2009 and beyond. FES continues to have a partial requirements wholesale power sales agreement with its affiliates, Met-Ed and Penelec, to supply a portion of each of their respective default service obligations at fixed prices through 2009. This sales agreement is renewed annually unless cancelled by either party with at least a sixty-day written notice prior to the end of the calendar year. FES also supplies, through May 31, 2009, a portion of Penn’s default service requirements at market-based rates as a result of Penn’s 2008 competitive solicitations. FES’ revenues also include competitive retail and wholesale sales to non-affiliated customers in Ohio, Pennsylvania, New Jersey, Maryland, Michigan and Illinois. These sales may provide a greater portion of revenues in future years depending upon FES’ participation in its Ohio and Pennsylvania utility affiliates’ power procurement arrangements.
Results of Operations
In 2005, Congress amended the first three monthsFPA 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 Utilities and ATSI. The NERC is charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of 2009, net income increasedits responsibilities to $171 million from $90 millioneight regional entities, including ReliabilityFirst Corporation. All of FirstEnergy’s facilities are located within the ReliabilityFirst region. FirstEnergy actively participates in the same periodNERC and ReliabilityFirst stakeholder processes, and otherwise monitors and manages its companies in 2008. The increase in net income was primarily due to higher revenues and lower fuel and purchased power costs, partially offset by higher other operating expenses, depreciation and other miscellaneous expenses.
Revenues
Revenues increased by $127 million in the first three months of 2009 comparedresponse to the same period in 2008 due to increases in revenues from non-affiliatedongoing development, implementation and affiliated wholesale generation sales, partially offset by lower retail generation sales. The increase in revenues resulted from the following sources:
| | | Three Months Ended | | | |
| | | March 31 | | Increase | |
| Revenues by Type of Service | | 2009 | | 2008 | | (Decrease) | |
| | | (In millions) | |
Non-Affiliated Generation Sales: | | | | | | | |
| | | | | | | | | | ) |
| | | | | | | | | | |
Total Non-Affiliated Generation Sales | | | | | | | | | | ) |
Affiliated Generation Sales | | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Retail generation sales revenues decreased due to reduced commercial and industrial contract renewals in the PJM market and the termination of certain government aggregation programs in the MISO market that were supplied by FES. Non-affiliated wholesale revenues increased due to higher PJM capacity prices and increased sales volumes in the MISO market, partially offset by lower unit prices and volumes in PJM.
Increased affiliated company wholesale revenues resulted from higher unit prices for sales to the Ohio Companies, under their CBP, partially offset by lower composite prices to the Pennsylvania Companies and an overall decrease in affiliated sales volumes. While unit prices for eachenforcement of the Pennsylvania Companies did not change, the mix of sales among the companies caused the overall composite price to decline. FES supplied less power to the Ohio Companies in the first quarter of 2009 as one of four winning bidders in the Ohio Companies’ RFP process.reliability standards.
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 2009 compared to the same period last year:
| | | Increase | |
Source of Change in Non-Affiliated Generation Revenues | | | |
| | | (In millions) | |
| Retail: | | | | |
Effect of 57.0% decrease in sales volumes | | $ | (91 | ) |
Change in prices | | | | |
| | | | | ) |
| Wholesale: | | | | |
Effect of 33.9% increase in sales volumes | | | 44 | |
Change in prices | | | | |
| | | | | |
| Net Decrease in Non-Affiliated Generation Revenues | | | | ) |
| | | Increase | |
Source of Change in Affiliated Generation Revenues | | | |
| | | (In millions) | |
| Ohio Companies: | | | | |
Effect of 24.6% decrease in sales volumes | | $ | (142 | ) |
Change in prices | | | | |
| | | | | |
| Pennsylvania Companies: | | | | |
Effect of 11.1% increase in sales volumes | | | 22 | |
Change in prices | | | | ) |
| | | | | |
| Net Increase in Affiliated Generation Revenues | | | | |
Transmission revenue decreased $8 million due to decreased retail load in the MISO market ($14 million), partially offset by higher PJM congestion revenues ($6 million). Other revenue increased $27 million primarily due to NGC’s lease revenue received from its equity interests in the Beaver Valley Unit 2 and Perry sale and leaseback transactions acquired during the second quarter of 2008.
Expenses
Total expenses decreased by $1 million in the first three months of 2009 compared with the same period of 2008. The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first three months of 2009 from the same period last year:
Source of Change in Fuel and Purchased Power | | | |
| | | (In millions) | |
| Fossil Fuel: | | | | |
Change due to increased unit costs | | $ | 36 | |
Change due to volume consumed | | | (52 | ) |
| | | | (16 | ) |
| Nuclear Fuel: | | | | |
Change due to increased unit costs | | | 1 | |
Change due to volume consumed | | | - | |
| | | | 1 | |
| Non-affiliated Purchased Power: | | | | |
Change due to decreased unit costs | | | (15 | ) |
Change due to volume purchased | | | (31 | ) |
| | | | (46 | ) |
| Affiliated Purchased Power: | | | | |
Change due to increased unit costs | | | 40 | |
Change due to volume purchased | | | (3 | ) |
| | | | 37 | |
| Net Decrease in Fuel and Purchased Power Costs | | | | ) |
Fossil fuel costs decreased $16 million in the first three months of 2009 primarily as a result of decreased coal consumption, reflecting lower generation. Higher unit prices were due to increased fuel rates on existing coal contracts in the first quarter of 2009. Nuclear fuel costs were relatively unchanged in the first quarter of 2009 from last year.
Purchased power costs from non-affiliates decreased primarily as a result of lower market rates and reduced volume requirements. Purchases from affiliated companies increased as a result of higher unit costs on purchases from the Ohio Companies’ leasehold interests in Beaver Valley Unit 2 and Perry.
Other operating expenses increased by $11 million in the first three months of 2009 from the same period of 2008. The increase was primarily due to 2009 organizational restructuring costs ($4 million) and nuclear operating costs as a result of higher expenses associated with the 2009 Perry refueling outage than incurred with the 2008 Davis-Besse refueling outage ($11 million). Transmission expenses increased as a result of higher congestion charges ($7 million). Partially offsetting the increases were lower fossil contractor costs as a result of rescheduled maintenance activities ($7 million) and lower lease expenses relating to CEI’s and TE’s leasehold improvements in the Mansfield Plant that were transferred to FGCO during the first quarter of 2008 ($5 million).
Depreciation expense increased by $12 million in the first three months of 2009 primarily due to NGC’s acquisition of certain lessor equity interests in the sale and leaseback of Perry and Beaver Valley Unit 2 ($7 million) and property additions since the first quarter of 2008.
Other Expense
Other expense increased by $14 million in the first three months of 2009 from the same period of 2008 primarily due to a greater loss in value of nuclear decommissioning trust investments ($23 million) during the first quarter of 2009. Partially offsetting the higher securities impairments was a $10 million decline in interest expense as a result of higher capitalized interest ($3 million) and lower interest expense to affiliates due to lower rates on loans from the unregulated moneypool ($4 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 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, 2009 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2009 and 2008. 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, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, 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, 2008, 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, 2009
|
| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | |
| CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
| (Unaudited) | |
| | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| | | 2009 | | | 2008 | |
| | | (In thousands) | |
| | | | | | | |
| | | | | | | |
| REVENUES: | | | | | | |
| Electric sales to affiliates | | $ | 892,690 | | | $ | 776,307 | |
| Electric sales to non-affiliates | | | 279,746 | | | | 288,341 | |
| Other | | | 53,670 | | | | 34,468 | |
| Total revenues | | | 1,226,106 | | | | 1,099,116 | |
| | | | | | | | | |
| EXPENSES: | | | | | | | | |
| Fuel | | | 306,158 | | | | 321,689 | |
| Purchased power from non-affiliates | | | 160,342 | | | | 206,724 | |
| Purchased power from affiliates | | | 63,207 | | | | 25,485 | |
| Other operating expenses | | | 307,356 | | | | 296,546 | |
| Provision for depreciation | | | 61,373 | | | | 49,742 | |
| General taxes | | | 23,376 | | | | 23,197 | |
| Total expenses | | | 921,812 | | | | 923,383 | |
| | | | | | | | | |
| OPERATING INCOME | | | 304,294 | | | | 175,733 | |
| | | | | | | | | |
| OTHER EXPENSE: | | | | | | | | |
| Miscellaneous expense | | | (26,363 | ) | | | (2,904 | ) |
| Interest expense to affiliates | | | (2,979 | ) | | | (7,210 | ) |
| Interest expense - other | | | (22,527 | ) | | | (24,535 | ) |
| Capitalized interest | | | 10,078 | | | | 6,663 | |
| Total other expense | | | (41,791 | ) | | | (27,986 | ) |
| | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 262,503 | | | | 147,747 | |
| | | | | | | | | |
| INCOME TAXES | | | 91,822 | | | | 57,763 | |
| | | | | | | | | |
| NET INCOME | | | 170,681 | | | | 89,984 | |
| | | | | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
| Pension and other postretirement benefits | | | 2,568 | | | | (1,820 | ) |
| Unrealized gain on derivative hedges | | | 11,016 | | | | 5,718 | |
| Change in unrealized gain on available-for-sale securities | | | (1,477 | ) | | | (51,852 | ) |
| Other comprehensive income (loss) | | | 12,107 | | | | (47,954 | ) |
| Income tax expense (benefit) related to other comprehensive income | | | 4,709 | | | | (17,403 | ) |
| Other comprehensive income (loss), net of tax | | | 7,398 | | | | (30,551 | ) |
| | | | | | | | | |
| TOTAL COMPREHENSIVE INCOME | | $ | 178,079 | | | $ | 59,433 | |
| | | | | | | | | |
| 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, | |
| | | 2009 | | | 2008 | |
| | | (In thousands) | |
| ASSETS | | | | | | |
| CURRENT ASSETS: | | | | | | |
| Cash and cash equivalents | | $ | 34 | | | $ | 39 | |
| Receivables- | | | | | | | | |
| Customers (less accumulated provisions of $3,994,000 and $5,899,000, | | | | | | | | |
| respectively, for uncollectible accounts) | | | 54,554 | | | | 86,123 | |
| Associated companies | | | 287,935 | | | | 378,100 | |
| Other (less accumulated provisions of $6,702,000 and $6,815,000 | | | | | | | | |
| respectively, for uncollectible accounts) | | | 66,293 | | | | 24,626 | |
| Notes receivable from associated companies | | | 433,137 | | | | 129,175 | |
| Materials and supplies, at average cost | | | 567,687 | | | | 521,761 | |
| Prepayments and other | | | 112,162 | | | | 112,535 | |
| | | | 1,521,802 | | | | 1,252,359 | |
| PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | |
| In service | | | 9,912,603 | | | | 9,871,904 | |
| Less - Accumulated provision for depreciation | | | 4,327,241 | | | | 4,254,721 | |
| | | | 5,585,362 | | | | 5,617,183 | |
| Construction work in progress | | | 2,114,831 | | | | 1,747,435 | |
| | | | 7,700,193 | | | | 7,364,618 | |
| INVESTMENTS: | | | | | | | | |
| Nuclear plant decommissioning trusts | | | 995,476 | | | | 1,033,717 | |
| Long-term notes receivable from associated companies | | | 62,900 | | | | 62,900 | |
| Other | | | 31,898 | | | | 61,591 | |
| | | | 1,090,274 | | | | 1,158,208 | |
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Accumulated deferred income tax benefits | | | 241,607 | | | | 267,762 | |
| Lease assignment receivable from associated companies | | | 71,356 | | | | 71,356 | |
| Goodwill | | | 24,248 | | | | 24,248 | |
| Property taxes | | | 50,104 | | | | 50,104 | |
| Unamortized sale and leaseback costs | | | 86,302 | | | | 69,932 | |
| Other | | | 87,141 | | | | 96,434 | |
| | | | 560,758 | | | | 579,836 | |
| | | $ | 10,873,027 | | | $ | 10,355,021 | |
| LIABILITIES AND CAPITALIZATION | | | | | | | | |
| | | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 1,690,942 | | | $ | 2,024,898 | |
| Short-term borrowings- | | | | | | | | |
| Associated companies | | | 786,116 | | | | 264,823 | |
| Other | | | 1,100,000 | | | | 1,000,000 | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 409,160 | | | | 472,338 | |
| Other | | | 144,837 | | | | 154,593 | |
| Accrued taxes | | | 122,734 | | | | 79,766 | |
| Other | | | 239,984 | | | | 248,439 | |
| | | | 4,493,773 | | | | 4,244,857 | |
| CAPITALIZATION: | | | | | | | | |
| Common stockholder's equity - | | | | | | | | |
| Common stock, without par value, authorized 750 shares, | | | | | | | | |
| 7 shares outstanding | | | 1,462,133 | | | | 1,464,229 | |
| Accumulated other comprehensive loss | | | (84,473 | ) | | | (91,871 | ) |
| Retained earnings | | | 1,742,746 | | | | 1,572,065 | |
| Total common stockholder's equity | | | 3,120,406 | | | | 2,944,423 | |
| Long-term debt and other long-term obligations | | | 670,061 | | | | 571,448 | |
| | | | 3,790,467 | | | | 3,515,871 | |
| NONCURRENT LIABILITIES: | | | | | | | | |
| Deferred gain on sale and leaseback transaction | | | 1,018,156 | | | | 1,026,584 | |
| Accumulated deferred investment tax credits | | | 61,645 | | | | 62,728 | |
| Asset retirement obligations | | | 877,073 | | | | 863,085 | |
| Retirement benefits | | | 198,803 | | | | 194,177 | |
| Property taxes | | | 50,104 | | | | 50,104 | |
| Lease market valuation liability | | | 296,376 | | | | 307,705 | |
| Other | | | 86,630 | | | | 89,910 | |
| | | | 2,588,787 | | | | 2,594,293 | |
| COMMITMENTS AND CONTINGENCIES (Note 8) | | | | | | | | |
| | | $ | 10,873,027 | | | $ | 10,355,021 | |
| | | | | | | | | |
| The accompanying Notes to Consolidated Financial Statements as they relate 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 | |
| | | 2009 | | | 2008 | |
| | | (In thousands) | |
| | | | | | | |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
| Net income | | $ | 170,681 | | | $ | 89,984 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | |
| Provision for depreciation | | | 61,373 | | | | 49,742 | |
| Nuclear fuel and lease amortization | | | 27,169 | | | | 25,426 | |
| Deferred rents and lease market valuation liability | | | (37,522 | ) | | | (34,887 | ) |
| Deferred income taxes and investment tax credits, net | | | 24,866 | | | | 30,781 | |
| Investment impairment | | | 33,535 | | | | 14,943 | |
| Accrued compensation and retirement benefits | | | (3,439 | ) | | | (11,042 | ) |
| Commodity derivative transactions, net | | | 15,817 | | | | 8,086 | |
| Gain on asset sales | | | (5,209 | ) | | | (4,964 | ) |
| Cash collateral, net | | | (5,492 | ) | | | 1,601 | |
| Decrease (increase) in operating assets: | | | | | | | | |
| Receivables | | | 80,067 | | | | 69,533 | |
| Materials and supplies | | | (865 | ) | | | (12,948 | ) |
| Prepayments and other current assets | | | (3,456 | ) | | | (12,260 | ) |
| Increase (decrease) in operating liabilities: | | | | | | | | |
| Accounts payable | | | (61,419 | ) | | | (17,149 | ) |
| Accrued taxes | | | 39,846 | | | | (28,652 | ) |
| Accrued interest | | | 10,338 | | | | (728 | ) |
| Other | | | 1,577 | | | | (7,514 | ) |
| Net cash provided from operating activities | | | 347,867 | | | | 159,952 | |
| | | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| New Financing- | | | | | | | | |
| Long-term debt | | | 100,000 | | | | - | |
| Short-term borrowings, net | | | 621,294 | | | | 1,281,896 | |
| Redemptions and Repayments- | | | | | | | | |
| Long-term debt | | | (335,916 | ) | | | (288,603 | ) |
| Common stock dividend payments | | | - | | | | (10,000 | ) |
| Net cash provided from financing activities | | | 385,378 | | | | 983,293 | |
| | | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (412,805 | ) | | | (476,529 | ) |
| Proceeds from asset sales | | | 7,573 | | | | 5,088 | |
| Sales of investment securities held in trusts | | | 351,414 | | | | 173,123 | |
| Purchases of investment securities held in trusts | | | (356,904 | ) | | | (181,079 | ) |
| Loans to associated companies, net | | | (303,963 | ) | | | (644,604 | ) |
| Other | | | (18,565 | ) | | | (19,244 | ) |
| Net cash used for investing activities | | | (733,250 | ) | | | (1,143,245 | ) |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | (5 | ) | | | - | |
| Cash and cash equivalents at beginning of period | | | 39 | | | | 2 | |
| Cash and cash equivalents at end of period | | $ | 34 | | | $ | 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
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 franchise customers electing to retain OE and Penn as their power supplier. Until December 31, 2008, OE purchased power for delivery and resale from a full requirements power sale agreement with its affiliate FES at a fixed price that reflected the rates approved by the PUCO. See Regulatory Matters – Ohio below for a discussion of Ohio power supply procurement issues for 2009 and beyond.
Results of Operations
InFirstEnergy believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, it is clear that the first three monthsNERC, 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 2009, net income decreasedcomplying with new or amended standards cannot be determined at this time. However, the 2005 amendments to $12 million from $44 millionthe FPA 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 result in the same periodimposition of 2008. The decrease primarily resulted from the completion of the recovery of transition costs at the end of 2008 and accrued obligations principally associated with the implementation of the ESP in 2009. OE’s financial statements include certain immaterial adjustmentspenalties that relate to prior periods that reduced net income by $3 million for the first quarter of 2009.
Revenues
Revenues increased by $96 million, or 14.8%, in the first three months of 2009 compared with the same period in 2008, primarily due to increases in retail generation revenues ($114 million) and wholesale revenues ($35 million), partially offset by decreases in distribution throughput revenues ($53 million).
Retail generation revenues increased primarily due to higher average prices across all customer classes and increased KWH sales to residential and commercial customers, reflectingcould have a decrease in customer shopping for those sectors as most of OE’s franchise customers returned to PLR service in December 2008. Reduced industrial KWH sales reflected weakened economic conditions in OE’s and Penn’s service territories. Additional generation revenues from OE’s fuel rider effective in January 2009 contributed to the rate variances (see Regulatory Matters – Ohio).
Changes in retail generation sales and revenues in the first three months of 2009 from the same period in 2008 are summarized in the following tables:
Retail Generation KWH Sales | | Increase (Decrease) | |
| | | | |
Residential | | | 11.8 | % |
Commercial | | | 17.3 | % |
Industrial | | | (8.2 | )% |
Net Increase in Generation Sales | | | 7.2 | % |
| Retail Generation Revenues | | Increase | |
| | | (In millions) | |
| Residential | | $ | 55 | |
| Commercial | | | 41 | |
| Industrial | | | 18 | |
| Increase in Generation Revenues | | $ | 114 | |
Revenues from distribution throughput decreased by $53 million in the first three months of 2009 compared to the same period in 2008 due to lower average unit prices and lower KWH deliveries to all customer classes. Reduced deliveries to commercial and industrial customers were a result of the weakened economy. Transition charges that ceased effective January 1, 2009, with the full recovery of related costs, were partially offset by a July 2008 increase to a PUCO-approved transmission rider and a January 2009 distribution rate increase (see Regulatory Matters – Ohio).
Changes in distribution KWH deliveries and revenues in the first three months of 2009 from the same period in 2008 are summarized in the following tables.
Distribution KWH Deliveries | | Decrease | |
| | | | |
Residential | | | (1.0 | )% |
Commercial | | | (4.7 | )% |
Industrial | | | (22.9 | )% |
Decrease in Distribution Deliveries | | | (9.2 | )% |
| Distribution Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (8 | ) |
| Commercial | | | (22 | ) |
| Industrial | | | (23 | ) |
| Decrease in Distribution Revenues | | $ | (53 | ) |
Expenses
Total expenses increased by $143 million in the first three months of 2009 from the same period of 2008. The following table presents changes from the prior year by expense category.
| Expenses – Changes | | Increase (Decrease) | |
| | | | (In millions) | |
| Purchased power costs | | $ | 130 | |
| Other operating costs | | | 17 | |
| Amortization of regulatory assets, net | | | (3 | ) |
| General taxes | | | (1 | ) |
| Net Increase in Expenses | | $ | 143 | |
Higher purchased power costs are primarily due to thematerial adverse effect on its financial condition, results of the CBP used for the procurement of electric generation for retail customers during the first quarter of 2009 and higher volumes due to increased retail generation KWH sales. The increase in other operating costs for the first three months of 2009 was primarily due to accruals for economic development programs, in accordance with the PUCO-approved ESP, and energy efficiency obligations. Lower amortization of net regulatory assets was primarily due to the conclusion of transition cost amortization in 2008, partially offset by lower MISO transmission cost deferrals and lower RCP distribution deferrals.
Other Expenses
Other expenses increased by $8 million in the first three months of 2009 compared to the same period in 2008 primarily due to higher interest expense associated with the issuance of OE’s $300 million of FMBs in October 2008.
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 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, 2009 and the related consolidated statements of income, comprehensive incomeoperations and cash flows for each of the three-month periods ended March 31, 2009 and 2008. 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, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. As discussed in Note 6 to the accompanying consolidated financial statements, the Company changed its reporting related to noncontrolling interest. The accompanying December 31, 2008 consolidated balance sheet reflects this change.
|
PricewaterhouseCoopers LLP
Cleveland, Ohio
May 7, 2009
|
| OHIO EDISON COMPANY | |
| | | | | | | |
| CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
| (Unaudited) | |
| | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| | | 2009 | | | 2008 | |
| | | (In thousands) | |
STATEMENTS OF INCOME | | | | | | |
| REVENUES: | | | | | | |
| Electric sales | | $ | 720,011 | | | $ | 622,271 | |
| Excise and gross receipts tax collections | | | 28,980 | | | | 30,378 | |
| Total revenues | | | 748,991 | | | | 652,649 | |
| | | | | | | | | |
| EXPENSES: | | | | | | | | |
| Purchased power from affiliates | | | 332,336 | | | | 319,711 | |
| Purchased power from non-affiliates | | | 137,813 | | | | 20,475 | |
| Other operating costs | | | 157,830 | | | | 140,326 | |
| Provision for depreciation | | | 21,513 | | | | 21,493 | |
| Amortization of regulatory assets, net | | | 20,211 | | | | 23,127 | |
| General taxes | | | 49,120 | | | | 50,453 | |
| Total expenses | | | 718,823 | | | | 575,585 | |
| | | | | | | | | |
| OPERATING INCOME | | | 30,168 | | | | 77,064 | |
| | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | |
| Investment income | | | 9,362 | | | | 15,055 | |
| Miscellaneous expense | | | (810 | ) | | | (3,652 | ) |
| Interest expense | | | (23,287 | ) | | | (17,641 | ) |
| Capitalized interest | | | 220 | | | | 110 | |
| Total other expense | | | (14,515 | ) | | | (6,128 | ) |
| | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 15,653 | | | | 70,936 | |
| | | | | | | | | |
| INCOME TAXES | | | 4,005 | | | | 26,873 | |
| | | | | | | | | |
| NET INCOME | | | 11,648 | | | | 44,063 | |
| | | | | | | | | |
| Less: Noncontrolling interest income | | | 146 | | | | 154 | |
| | | | | | | | | |
| EARNINGS AVAILABLE TO PARENT | | $ | 11,502 | | | $ | 43,909 | |
| | | | | | | | | |
| STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | |
| | | | | | | | | |
| NET INCOME | | $ | 11,648 | | | $ | 44,063 | |
| | | | | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
| Pension and other postretirement benefits | | | 5,738 | | | | (3,994 | ) |
| Change in unrealized gain on available-for-sale securities | | | (2,709 | ) | | | (7,571 | ) |
| Other comprehensive income (loss) | | | 3,029 | | | | (11,565 | ) |
| Income tax expense (benefit) related to other comprehensive income | | | 529 | | | | (4,262 | ) |
| Other comprehensive income (loss), net of tax | | | 2,500 | | | | (7,303 | ) |
| | | | | | | | | |
| COMPREHENSIVE INCOME | | | 14,148 | | | | 36,760 | |
| | | | | | | | | |
| COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST | | | 146 | | | | 154 | |
| | | | | | | | | |
| COMPREHENSIVE INCOME ATTRIBUTABLE TO PARENT | | $ | 14,002 | | | $ | 36,606 | |
| | | | | | | | | |
| 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, | |
| | | 2009 | | | 2008 | |
| | | (In thousands) | |
| ASSETS | | | | | | |
| CURRENT ASSETS: | | | | | | |
| Cash and cash equivalents | | $ | 311,192 | | | $ | 146,343 | |
| Receivables- | | | | | | | | |
| Customers (less accumulated provisions of $6,621,000 and $6,065,000, respectively, | | | | | |
| for uncollectible accounts) | | | 292,159 | | | | 277,377 | |
| Associated companies | | | 217,455 | | | | 234,960 | |
| Other (less accumulated provisions of $8,000 and $7,000, respectively, | | | | | | | | |
| for uncollectible accounts) | | | 19,492 | | | | 14,492 | |
| Notes receivable from associated companies | | | 77,264 | | | | 222,861 | |
| Prepayments and other | | | 22,544 | | | | 5,452 | |
| | | | 940,106 | | | | 901,485 | |
| UTILITY PLANT: | | | | | | | | |
| In service | | | 2,915,643 | | | | 2,903,290 | |
| Less - Accumulated provision for depreciation | | | 1,120,219 | | | | 1,113,357 | |
| | | | 1,795,424 | | | | 1,789,933 | |
| Construction work in progress | | | 47,022 | | | | 37,766 | |
| | | | 1,842,446 | | | | 1,827,699 | |
| OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
| Long-term notes receivable from associated companies | | | 256,473 | | | | 256,974 | |
| Investment in lease obligation bonds | | | 239,501 | | | | 239,625 | |
| Nuclear plant decommissioning trusts | | | 112,778 | | | | 116,682 | |
| Other | | | 98,729 | | | | 100,792 | |
| | | | 707,481 | | | | 714,073 | |
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Regulatory assets | | | 544,782 | | | | 575,076 | |
| Property taxes | | | 60,542 | | | | 60,542 | |
| Unamortized sale and leaseback costs | | | 38,880 | | | | 40,130 | |
| Other | | | 32,418 | | | | 33,710 | |
| | | | 676,622 | | | | 709,458 | |
| | | $ | 4,166,655 | | | $ | 4,152,715 | |
| LIABILITIES AND CAPITALIZATION | | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 2,697 | | | $ | 101,354 | |
| Short-term borrowings- | | | | | | | | |
| Associated companies | | | 79,810 | | | | - | |
| Other | | | 1,540 | | | | 1,540 | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 115,778 | | | | 131,725 | |
| Other | | | 54,237 | | | | 26,410 | |
| Accrued taxes | | | 72,736 | | | | 77,592 | |
| Accrued interest | | | 23,717 | | | | 25,673 | |
| Other | | | 124,871 | | | | 85,209 | |
| | | | 475,386 | | | | 449,503 | |
| CAPITALIZATION: | | | | | | | | |
| Common stockholder's equity- | | | | | | | | |
| Common stock, without par value, authorized 175,000,000 shares - | | | | | | | | |
| 60 shares outstanding | | | 1,224,347 | | | | 1,224,416 | |
| Accumulated other comprehensive loss | | | (181,885 | ) | | | (184,385 | ) |
| Retained earnings | | | 265,525 | | | | 254,023 | |
| Total common stockholder's equity | | | 1,307,987 | | | | 1,294,054 | |
| Noncontrolling interest | | | 7,252 | | | | 7,106 | |
| Total equity | | | 1,315,239 | | | | 1,301,160 | |
| Long-term debt and other long-term obligations | | | 1,123,966 | | | | 1,122,247 | |
| | | | 2,439,205 | | | | 2,423,407 | |
| NONCURRENT LIABILITIES: | | | | | | | | |
| Accumulated deferred income taxes | | | 650,601 | | | | 653,475 | |
| Accumulated deferred investment tax credits | | | 12,700 | | | | 13,065 | |
| Asset retirement obligations | | | 81,944 | | | | 80,647 | |
| Retirement benefits | | | 305,943 | | | | 308,450 | |
| Other | | | 200,876 | | | | 224,168 | |
| | | | 1,252,064 | | | | 1,279,805 | |
| COMMITMENTS AND CONTINGENCIES (Note 8) | | | | | | | | |
| | | $ | 4,166,655 | | | $ | 4,152,715 | |
| | | | | | | | | |
| 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 | |
| | | 2009 | | | 2008 | |
| | | In thousands) | |
| | | | | | | |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
| Net income | | $ | 11,648 | | | $ | 44,063 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | |
| Provision for depreciation | | | 21,513 | | | | 21,493 | |
| Amortization of regulatory assets, net | | | 20,211 | | | | 23,127 | |
| Purchased power cost recovery reconciliation | | | 2,978 | | | | - | |
| Amortization of lease costs | | | 32,934 | | | | 32,934 | |
| Deferred income taxes and investment tax credits, net | | | (7,272 | ) | | | 6,866 | |
| Accrued compensation and retirement benefits | | | (1,746 | ) | | | (19,482 | ) |
| Accrued regulatory obligations | | | 18,350 | | | | - | |
| Electric service prepayment programs | | | (3,944 | ) | | | (10,028 | ) |
| Decrease (increase) in operating assets- | | | | | | | | |
| Receivables | | | 1,435 | | | | (27,496 | ) |
| Prepayments and other current assets | | | (9,806 | ) | | | (7,451 | ) |
| Increase (decrease) in operating liabilities- | | | | | | | | |
| Accounts payable | | | 11,880 | | | | (3,939 | ) |
| Accrued taxes | | | (26,222 | ) | | | 2,991 | |
| Accrued interest | | | (1,956 | ) | | | (5,919 | ) |
| Other | | | 6,708 | | | | (2,220 | ) |
| Net cash provided from operating activities | | | 76,711 | | | | 54,939 | |
| | | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| New Financing- | | | | | | | | |
| Short-term borrowings, net | | | 79,810 | | | | - | |
| Redemptions and Repayments- | | | | | | | | |
| Long-term debt | | | (100,393 | ) | | | (75 | ) |
| Dividend Payments- | | | | | | | | |
| Common stock | | | - | | | | (15,000 | ) |
| Other | | | (69 | ) | | | (5 | ) |
| Net cash used for financing activities | | | (20,652 | ) | | | (15,080 | ) |
| | | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (37,523 | ) | | | (49,011 | ) |
| Sales of investment securities held in trusts | | | 9,417 | | | | 62,344 | |
| Purchases of investment securities held in trusts | | | (10,422 | ) | | | (63,797 | ) |
| Loan repayments from associated companies, net | | | 146,098 | | | | 6,534 | |
| Cash investments | | | (243 | ) | | | 147 | |
| Other | | | 1,463 | | | | 3,924 | |
| Net cash provided from (used for) investing activities | | | 108,790 | | | | (39,859 | ) |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | 164,849 | | | | - | |
| Cash and cash equivalents at beginning of period | | | 146,343 | | | | 732 | |
| Cash and cash equivalents at end of period | | $ | 311,192 | | | $ | 732 | |
| | | | | | | | | |
| 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
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. Until December 31, 2008, CEI purchased power for delivery and resale from a full requirements power sale agreement with its affiliate FES at a fixed price that was reflected in rates approved by the PUCO. See Regulatory Matters – Ohio below for a discussion of Ohio power supply procurement issues for 2009 and beyond.
Results of Operations
CEI recognized a net loss of $105 million in the first three months of 2009 compared to net income of $58 million in the same period of 2008. The decrease resulted primarily from CEI’s $216 million regulatory asset impairment related to the implementation of its ESP and increased purchased power costs, partially offset by higher deferrals of new regulatory assets.
Revenues
Revenues increased by $12 million, or 2.8%, in the first three months of 2009 compared to the same period of 2008 primarily due to an increase in retail generation revenues ($18 million), partially offset by decreases in distribution revenues ($4 million) and other miscellaneous revenues ($2 million).
Retail generation revenues increased in the first three months of 2009 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 2008. Generation rate increases under CEI’s CBP contributed to the increased rate variances (see Regulatory Matters – Ohio). Reduced industrial KWH sales, principally to major automotive and steel customers, reflected weakened economic conditions. The increase in sales volume for residential and commercial customers primarily reflected a decrease in customer shopping, as most of CEI’s customers returned to PLR service in December 2008.
Changes in retail generation sales and revenues in the first three months of 2009 compared to the same period in 2008 are summarized in the following tables:
Retail Generation KWH Sales | | Increase
(Decrease)
| |
Residential | | | 8.0 | % |
Commercial | | | 12.5 | % |
Industrial | | | (9.8 | )% |
Net Increase in Retail Generation Sales | | | 1.4 | % |
| Retail Generation Revenues | | Increase (Decrease) | |
| | | (in millions) | |
| Residential | | $ | 8 | |
| Commercial | | | 12 | |
| Industrial | | | (2 | ) |
| Net Increase in Generation Revenues | | $ | 18 | |
Revenues from distribution throughput decreased by $4 million in the first three months of 2009 compared to the same period of 2008 primarily due lower KWH deliveries to commercial and industrial customers as a result of the economic downturn in CEI’s service territory.
Decreases in distribution KWH deliveries and revenues in the first three months of 2009 compared to the same period of 2008 are summarized in the following tables.
Distribution KWH Deliveries | | Decrease | |
Residential | | | (0.6 | )% |
Commercial | | | (5.1 | )% |
Industrial | | | (19.8 | )% |
Decrease in Distribution Deliveries | | | (10.0 | )% |
| Distribution Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (1 | ) |
| Commercial | | | (1 | ) |
| Industrial | | | (2 | ) |
| Decrease in Distribution Revenues | | $ | (4 | ) |
Expenses
Total expenses increased by $267 million in the first three months of 2009 compared to the same period of 2008. The following table presents the change from the prior year by expense category:
| Expenses - Changes | | Increase (Decrease) | |
| | | (in millions) | |
| Purchased power costs | | $ | 117 | |
| Amortization of regulatory assets | | | 218 | |
| Deferral of new regulatory assets | | | (66 | ) |
| General taxes | | | (2 | ) |
| Net Increase in Expenses | | $ | 267 | |
Higher purchased power costs are primarily due to the results of the CBP used for the procurement of electric generation for retail customers in the first quarter of 2009. Increased amortization of regulatory assets was primarily due to the impairment of CEI’s Extended RTC balance in accordance with the PUCO-approved ESP. The increase in the deferral of new regulatory assets was primarily due to CEI’s deferral of purchased power costs as approved by the PUCO, partially offset by lower deferred MISO transmission expenses and the absence of RCP distribution deferrals that ceased at the end of 2008. While other operating costs were unchanged from the previous year, cost increases associated with the ESP for economic development and energy efficiency programs, higher pension expense and restructuring costs were completely offset by reduced transmission expense, labor, contractor costs and general business expense. The decrease in general taxes is primarily due to lower property taxes.
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, 2009 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2009 and 2008. 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, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. As discussed in Note 6 to the accompanying consolidated financial statements, the Company changed its reporting related to noncontrolling interest. The accompanying December 31, 2008 consolidated balance sheet reflects this change.
|
PricewaterhouseCoopers LLP
Cleveland, Ohio
May 7, 2009
|
| THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | |
| | | | | | | |
| CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
| (Unaudited) | |
| | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| | | 2009 | | | 2008 | |
| | | (In thousands) | |
| STATEMENTS OF INCOME | | | | | | |
| REVENUES: | | | | | | |
| Electric sales | | $ | 431,405 | | | $ | 418,708 | |
| Excise tax collections | | | 18,320 | | | | 18,600 | |
| Total revenues | | | 449,725 | | | | 437,308 | |
| | | | | | | | | |
| EXPENSES: | | | | | | | | |
| Purchased power from affiliates | | | 238,872 | | | | 190,196 | |
| Purchased power from non-affiliates | | | 71,746 | | | | 3,048 | |
| Other operating costs | | | 64,830 | | | | 65,118 | |
| Provision for depreciation | | | 18,280 | | | | 19,076 | |
| Amortization of regulatory assets | | | 256,737 | | | | 38,256 | |
| Deferral of new regulatory assets | | | (94,816 | ) | | | (29,248 | ) |
| General taxes | | | 38,141 | | | | 40,083 | |
| Total expenses | | | 593,790 | | | | 326,529 | |
| | | | | | | | | |
| OPERATING INCOME (LOSS) | | | (144,065 | ) | | | 110,779 | |
| | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | |
| Investment income | | | 8,420 | | | | 9,188 | |
| Miscellaneous income | | | 1,994 | | | | 1,118 | |
| Interest expense | | | (33,322 | ) | | | (32,520 | ) |
| Capitalized interest | | | 67 | | | | 196 | |
| Total other expense | | | (22,841 | ) | | | (22,018 | ) |
| | | | | | | | | |
| INCOME (LOSS) BEFORE INCOME TAXES | | | (166,906 | ) | | | 88,761 | |
| | | | | | | | | |
| INCOME TAX EXPENSE (BENEFIT) | | | (61,506 | ) | | | 30,326 | |
| | | | | | | | | |
| NET INCOME (LOSS) | | | (105,400 | ) | | | 58,435 | |
| | | | | | | | | |
| Less: Noncontrolling interest income | | | 458 | | | | 584 | |
| | | | | | | | | |
| EARNINGS (LOSS) AVAILABLE TO PARENT | | $ | (105,858 | ) | | $ | 57,851 | |
| | | | | | | | | |
| STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | |
| | | | | | | | | |
| NET INCOME (LOSS) | | $ | (105,400 | ) | | $ | 58,435 | |
| | | | | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
| Pension and other postretirement benefits | | | 3,967 | | | | (213 | ) |
| Income tax expense related to other comprehensive income | | | 1,370 | | | | 281 | |
| Other comprehensive income (loss), net of tax | | | 2,597 | | | | (494 | ) |
| | | | | | | | | |
| COMPREHENSIVE INCOME (LOSS) | | | (102,803 | ) | | | 57,941 | |
| | | | | | | | | |
| COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST | | | 458 | | | | 584 | |
| | | | | | | | | |
| COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO PARENT | | $ | (103,261 | ) | | $ | 57,357 | |
| | | | | | | | | |
| 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, | |
| | | 2009 | | | 2008 | |
| | (In thousands) | |
| ASSETS | | | | | | |
| CURRENT ASSETS: | | | | | | |
| Cash and cash equivalents | | $ | 233 | | | $ | 226 | |
| Receivables- | | | | | | | | |
| Customers (less accumulated provisions of $6,199,000 and | | | | | | | | |
| $5,916,000, respectively, for uncollectible accounts) | | | 283,967 | | | | 276,400 | |
| Associated companies | | | 159,819 | | | | 113,182 | |
| Other | | | 4,438 | | | | 13,834 | |
| Notes receivable from associated companies | | | 22,744 | | | | 19,060 | |
| Prepayments and other | | | 2,002 | | | | 2,787 | |
| | | | 473,203 | | | | 425,489 | |
| UTILITY PLANT: | | | | | | | | |
| In service | | | 2,240,065 | | | | 2,221,660 | |
| Less - Accumulated provision for depreciation | | | 852,393 | | | | 846,233 | |
| | | | 1,387,672 | | | | 1,375,427 | |
| Construction work in progress | | | 40,545 | | | | 40,651 | |
| | | | 1,428,217 | | | | 1,416,078 | |
| OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
| Investment in lessor notes | | | 388,647 | | | | 425,715 | |
| Other | | | 10,239 | | | | 10,249 | |
| | | | 398,886 | | | | 435,964 | |
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Goodwill | | | 1,688,521 | | | | 1,688,521 | |
| Regulatory assets | | | 617,967 | | | | 783,964 | |
| Property taxes | | | 71,500 | | | | 71,500 | |
| Other | | | 10,629 | | | | 10,818 | |
| | | | 2,388,617 | | | | 2,554,803 | |
| | | $ | 4,688,923 | | | $ | 4,832,334 | |
| LIABILITIES AND CAPITALIZATION | | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 150,704 | | | $ | 150,688 | |
| Short-term borrowings- | | | | | | | | |
| Associated companies | | | 242,065 | | | | 227,949 | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 94,824 | | | | 106,074 | |
| Other | | | 26,914 | | | | 7,195 | |
| Accrued taxes | | | 76,130 | | | | 87,810 | |
| Accrued interest | | | 41,546 | | | | 13,932 | |
| Other | | | 44,021 | | | | 40,095 | |
| | | | 676,204 | | | | 633,743 | |
| CAPITALIZATION: | | | | | | | | |
| Common stockholder's equity | | | | | | | | |
| Common stock, without par value, authorized 105,000,000 shares - | | | | | | | | |
| 67,930,743 shares outstanding | | | 878,680 | | | | 878,785 | |
| Accumulated other comprehensive loss | | | (132,260 | ) | | | (134,857 | ) |
| Retained earnings | | | 754,096 | | | | 859,954 | |
| Total common stockholder's equity | | | 1,500,516 | | | | 1,603,882 | |
| Noncontrolling interest | | | 20,173 | | | | 22,555 | |
| Total equity | | | 1,520,689 | | | | 1,626,437 | |
| Long-term debt and other long-term obligations | | | 1,573,241 | | | | 1,591,586 | |
| | | | 3,093,930 | | | | 3,218,023 | |
| NONCURRENT LIABILITIES: | | | | | | | | |
| Accumulated deferred income taxes | | | 644,547 | | | | 704,270 | |
| Accumulated deferred investment tax credits | | | 12,731 | | | | 13,030 | |
| Retirement benefits | | | 129,537 | | | | 128,738 | |
| Lease assignment payable to associated companies | | | 40,827 | | | | 40,827 | |
| Other | | | 91,147 | | | | 93,703 | |
| | | | 918,789 | | | | 980,568 | |
| COMMITMENTS AND CONTINGENCIES (Note 8) | | | | | | | | |
| | | $ | 4,688,923 | | | $ | 4,832,334 | |
| | | | | | | | | |
| | | | | | | | | |
| 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 | |
| | | | | | | |
| | | 2009 | | | 2008 | |
| | | | | | | |
| | | (In thousands) | |
| | | | | | | |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
| Net income (loss) | | $ | (105,400 | ) | | $ | 58,435 | |
| Adjustments to reconcile net income (loss) to net cash from operating activities- | | | | | |
| Provision for depreciation | | | 18,280 | | | | 19,076 | |
| Amortization of regulatory assets | | | 256,737 | | | | 38,256 | |
| Deferral of new regulatory assets | | | (94,816 | ) | | | (29,248 | ) |
| Deferred income taxes and investment tax credits, net | | | (61,525 | ) | | | (4,965 | ) |
| Accrued compensation and retirement benefits | | | 1,828 | | | | (3,507 | ) |
| Accrued regulatory obligations | | | 12,057 | | | | - | |
| Electric service prepayment programs | | | (2,695 | ) | | | (5,847 | ) |
| Decrease (increase) in operating assets- | | | | | | | | |
| Receivables | | | (44,808 | ) | | | 90,280 | |
| Prepayments and other current assets | | | 785 | | | | 604 | |
| Increase (decrease) in operating liabilities- | | | | | | | | |
| Accounts payable | | | 18,470 | | | | 1,111 | |
| Accrued taxes | | | (16,274 | ) | | | 23,196 | |
| Accrued interest | | | 27,614 | | | | 23,831 | |
| Other | | | 346 | | | | 2,308 | |
| Net cash provided from operating activities | | | 10,599 | | | | 213,530 | |
| | | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| Redemptions and Repayments- | | | | | | | | |
| Long-term debt | | | (181 | ) | | | (165 | ) |
| Short-term borrowings, net | | | (4,086 | ) | | | (177,960 | ) |
| Dividend Payments- | | | | | | | | |
| Common stock | | | (10,000 | ) | | | (30,000 | ) |
| Other | | | (2,840 | ) | | | (2,955 | ) |
| Net cash used for financing activities | | | (17,107 | ) | | | (211,080 | ) |
| | | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (24,900 | ) | | | (37,203 | ) |
| Loans to associated companies, net | | | (3,683 | ) | | | (2,373 | ) |
| Redemptions of lessor notes | | | 37,068 | | | | 37,709 | |
| Other | | | (1,970 | ) | | | (574 | ) |
| Net cash provided from (used for) investing activities | | | 6,515 | | | | (2,441 | ) |
| | | | | | | | | |
| Net increase in cash and cash equivalents | | | 7 | | | | 9 | |
| Cash and cash equivalents at beginning of period | | | 226 | | | | 232 | |
| Cash and cash equivalents at end of period | | $ | 233 | | | $ | 241 | |
| | | | | | | | | |
| | | | | | | | | |
| 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
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. Until December 31, 2008, TE purchased power for delivery and resale from a full requirements power sale agreement with its affiliate FES at a fixed price that was reflected in rates approved by the PUCO. See Regulatory Matters – Ohio below for a discussion of Ohio power supply procurement issues for 2009 and beyond.
Results of Operations
Net income in the first three months of 2009 decreased to $1 million from $17 million in the same period of 2008. The decrease resulted primarily from the completion of transition cost recovery in 2008.
Revenues
Revenues increased $33 million, or 15.6%, in the first three months of 2009 compared to the same period of 2008 primarily due to increased retail generation revenues ($67 million), partially offset by lower distribution revenues ($33 million) and wholesale generation revenues ($1 million).
Retail generation revenues increased in the first three months of 2009 due to higher average prices across all customer classes and increased KWH sales to residential and commercial customers, compared to the same period of 2008. TE’s implementation of a fuel rider in January 2009 produced the rate variances (see Regulatory Matters – Ohio). Reduced industrial KWH sales, principally to major automotive and steel customers, reflected weakened economic conditions. The increase in sales volume for residential and commercial customers resulted principally from a decrease in customer shopping. Most of TE’s franchise customers returned to PLR service in December 2008.
Changes in retail electric generation KWH sales and revenues in the first three months of 2009 from the same period of 2008 are summarized in the following tables.
| | Increase | |
Retail KWH Sales | | (Decrease) | |
| | | | |
Residential | | | 6.5 | % |
Commercial | | | 39.3 | % |
Industrial | | | (11.5 | )% |
Net Increase in Retail KWH Sales | | | 3.9 | % |
| Retail Generation Revenues | | Increase | |
| | | (In millions) | |
| Residential | | $ | 16 | |
| Commercial | | | 26 | |
| Industrial | | | 25 | |
| Increase in Retail Generation Revenues | | $ | 67 | |
Revenues from distribution throughput decreased by $33 million in the first three months of 2009 compared to the same period in 2008 due to lower average unit prices and lower KWH deliveries for all customer classes. Transition charges that ceased effective January 1, 2009, with the full recovery of related costs, were partially offset by a PUCO-approved distribution rate increase (see Regulatory Matters – Ohio).
Changes in distribution KWH deliveries and revenues in the first three months of 2009 from the same period of 2008 are summarized in the following tables.
Distribution KWH Deliveries | | Decrease | |
| | | | |
Residential | | | (2.8 | )% |
Commercial | | | (10.0 | )% |
Industrial | | | (13.5 | )% |
Decrease in Distribution Deliveries | | | (9.6 | )% |
| Distribution Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (8 | ) |
| Commercial | | | (17 | ) |
| Industrial | | | (8 | ) |
| Decrease in Distribution Revenues | | $ | (33 | ) |
Expenses
Total expenses increased $57 million in the first three months of 2009 from the same period of 2008. The following table presents changes from the prior year by expense category.
| Expenses – Changes | | Increase (Decrease) | |
| | | (In millions) | |
| | $ | | |
| Provision for depreciation | | | | ) |
Amortization of regulatory assets, net | | | | |
| | | | |
Higher purchased power costs are primarily due to the results of the CBP used for the procurement of electric generation for retail customers during the first quarter of 2009. While other operating costs were unchanged from the first quarter of 2008, cost increases associated with the regulatory obligations for economic development and energy efficiency programs, higher pension and other expenses were completely offset by reduced transmission, labor and other employee benefit expenses. Depreciation expense decreased due to the transfer of leasehold improvements for the Bruce Mansfield Plant and Beaver Valley Unit 2 to FGCO and NGC, respectively, during 2008. The decrease in the net amortization of regulatory assets is primarily due to the cessation of transition cost amortization, partially offset by a reduction in transmission deferrals and the absence of RCP distribution cost deferrals in 2009.
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, 2009 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2009 and 2008. 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, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. As discussed in Note 6 to the accompanying consolidated financial statements, the Company changed its reporting related to noncontrolling interest. The accompanying December 31, 2008 consolidated balance sheet reflects this change.
|
PricewaterhouseCoopers LLP
Cleveland, Ohio
May 7, 2009
|
| THE TOLEDO EDISON COMPANY | |
| | | | | | | |
| CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
| (Unaudited) | |
| | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| | | 2009 | | | 2008 | |
| | | (In thousands) | |
| STATEMENTS OF INCOME | | | | | | |
| REVENUES: | | | | | | |
| Electric sales | | $ | 237,085 | | | $ | 203,669 | |
| Excise tax collections | | | 7,729 | | | | 8,025 | |
| Total revenues | | | 244,814 | | | | 211,694 | |
| | | | | | | | | |
| EXPENSES: | | | | | | | | |
| Purchased power from affiliates | | | 125,324 | | | | 99,494 | |
| Purchased power from non-affiliates | | | 40,537 | | | | 1,804 | |
| Other operating costs | | | 45,004 | | | | 45,329 | |
| Provision for depreciation | | | 7,572 | | | | 9,025 | |
| Amortization of regulatory assets, net | | | 9,897 | | | | 15,531 | |
| General taxes | | | 14,250 | | | | 14,377 | |
| Total expenses | | | 242,584 | | | | 185,560 | |
| | | | | | | | | |
| OPERATING INCOME | | | 2,230 | | | | 26,134 | |
| | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | |
| Investment income | | | 5,484 | | | | 6,481 | |
| Miscellaneous expense | | | (1,340 | ) | | | (1,512 | ) |
| Interest expense | | | (5,533 | ) | | | (6,035 | ) |
| Capitalized interest | | | 42 | | | | 37 | |
| Total other expense | | | (1,347 | ) | | | (1,029 | ) |
| | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 883 | | | | 25,105 | |
| | | | | | | | | |
| INCOME TAX EXPENSE (BENEFIT) | | | (109 | ) | | | 8,088 | |
| | | | | | | | | |
| NET INCOME | | | 992 | | | | 17,017 | |
| | | | | | | | | |
| Less: Noncontrolling interest income | | | 2 | | | | 2 | |
| | | | | | | | | |
| EARNINGS AVAILABLE TO PARENT | | $ | 990 | | | $ | 17,015 | |
| | | | | | | | | |
| STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | |
| | | | | | | | | |
| NET INCOME | | $ | 992 | | | $ | 17,017 | |
| | | | | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
| Pension and other postretirement benefits | | | 133 | | | | (63 | ) |
| Change in unrealized gain on available-for-sale securities | | | (809 | ) | | | 1,961 | |
| Other comprehensive income (loss) | | | (676 | ) | | | 1,898 | |
| Income tax expense (benefit) related to other comprehensive income | | | (19 | ) | | | 728 | |
| Other comprehensive income (loss), net of tax | | | (657 | ) | | | 1,170 | |
| | | | | | | | | |
| COMPREHENSIVE INCOME | | | 335 | | | | 18,187 | |
| | | | | | | | | |
| COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST | | | 2 | | | | 2 | |
| | | | | | | | | |
| COMPREHENSIVE INCOME ATTRIBUTABLE TO PARENT | | $ | 333 | | | $ | 18,185 | |
| | | | | | | | | |
| 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, | |
| | | 2009 | | | 2008 | |
| | (In thousands) | |
| ASSETS | | | | | | |
| CURRENT ASSETS: | | | | | | |
| Cash and cash equivalents | | $ | 15 | | | $ | 14 | |
| Receivables- | | | | | | | | |
| Customers | | | 438 | | | | 751 | |
| Associated companies | | | 70,444 | | | | 61,854 | |
| Other (less accumulated provisions of $193,000 and $203,000, | | | | | | | | |
| respectively, for uncollectible accounts) | | | 23,693 | | | | 23,336 | |
| Notes receivable from associated companies | | | 133,186 | | | | 111,579 | |
| Prepayments and other | | | 4,481 | | | | 1,213 | |
| | | | 232,257 | | | | 198,747 | |
| UTILITY PLANT: | | | | | | | | |
| In service | | | 880,315 | | | | 870,911 | |
| Less - Accumulated provision for depreciation | | | 413,030 | | | | 407,859 | |
| | | | 467,285 | | | | 463,052 | |
| Construction work in progress | | | 10,957 | | | | 9,007 | |
| | | | 478,242 | | | | 472,059 | |
| OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
| Investment in lessor notes | | | 124,329 | | | | 142,687 | |
| Long-term notes receivable from associated companies | | | 37,154 | | | | 37,233 | |
| Nuclear plant decommissioning trusts | | | 73,235 | | | | 73,500 | |
| Other | | | 1,646 | | | | 1,668 | |
| | | | 236,364 | | | | 255,088 | |
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Goodwill | | | 500,576 | | | | 500,576 | |
| Regulatory assets | | | 96,351 | | | | 109,364 | |
| Property taxes | | | 22,970 | | | | 22,970 | |
| Other | | | 62,004 | | | | 51,315 | |
| | | | 681,901 | | | | 684,225 | |
| | | $ | 1,628,764 | | | $ | 1,610,119 | |
| LIABILITIES AND CAPITALIZATION | | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 222 | | | $ | 34 | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 59,462 | | | | 70,455 | |
| Other | | | 14,823 | | | | 4,812 | |
| Notes payable to associated companies | | | 107,265 | | | | 111,242 | |
| Accrued taxes | | | 23,259 | | | | 24,433 | |
| Lease market valuation liability | | | 36,900 | | | | 36,900 | |
| Other | | | 54,397 | | | | 22,489 | |
| | | | 296,328 | | | | 270,365 | |
| 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 | | | 175,866 | | | | 175,879 | |
| Accumulated other comprehensive loss | | | (34,029 | ) | | | (33,372 | ) |
| Retained earnings | | | 191,523 | | | | 190,533 | |
| Total common stockholder's equity | | | 480,370 | | | | 480,050 | |
| Noncontrolling interest | | | 2,676 | | | | 2,675 | |
| Total equity | | | 483,046 | | | | 482,725 | |
| Long-term debt and other long-term obligations | | | 303,021 | | | | 299,626 | |
| | | | 786,067 | | | | 782,351 | |
| NONCURRENT LIABILITIES: | | | | | | | | |
| Accumulated deferred income taxes | | | 77,016 | | | | 78,905 | |
| Accumulated deferred investment tax credits | | | 6,695 | | | | 6,804 | |
| Lease market valuation liability | | | 263,875 | | | | 273,100 | |
| Retirement benefits | | | 74,911 | | | | 73,106 | |
| Asset retirement obligations | | | 30,719 | | | | 30,213 | |
| Lease assignment payable to associated companies | | | 30,529 | | | | 30,529 | |
| Other | | | 62,624 | | | | 64,746 | |
| | | | 546,369 | | | | 557,403 | |
| COMMITMENTS AND CONTINGENCIES (Note 8) | | | | | | | | |
| | | $ | 1,628,764 | | | $ | 1,610,119 | |
| | | | | | | | | |
| 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 | |
| | | 2009 | | | 2008 | |
| | | (In thousands) | |
| | | | | | | |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
| Net income | | $ | 992 | | | $ | 17,017 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
| Provision for depreciation | | | 7,572 | | | | 9,025 | |
| Amortization of regulatory assets, net | | | 9,897 | | | | 15,531 | |
| Purchased power cost recovery reconciliation | | | 2,912 | | | | - | |
| Deferred rents and lease market valuation liability | | | 6,141 | | | | 6,099 | |
| Deferred income taxes and investment tax credits, net | | | (2,151 | ) | | | (3,404 | ) |
| Accrued compensation and retirement benefits | | | 397 | | | | (1,813 | ) |
| Accrued regulatory obligations | | | 4,450 | | | | - | |
| Electric service prepayment programs | | | (1,240 | ) | | | (2,670 | ) |
| Decrease (increase) in operating assets- | | | | | | | | |
| Receivables | | | (8,395 | ) | | | 45,738 | |
| Prepayments and other current assets | | | 492 | | | | 181 | |
| Increase (decrease) in operating liabilities- | | | | | | | | |
| Accounts payable | | | 9,018 | | | | (174,243 | ) |
| Accrued taxes | | | (4,904 | ) | | | 6,840 | |
| Accrued interest | | | 4,613 | | | | 4,663 | |
| Other | | | 1,465 | | | | 989 | |
| Net cash provided from (used for) operating activities | | | 31,259 | | | | (76,047 | ) |
| | | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| New Financing- | | | | | | | | |
| Short-term borrowings, net | | | - | | | | 52,821 | |
| Redemptions and Repayments- | | | | | | | | |
| Long-term debt | | | (181 | ) | | | (9 | ) |
| Short-term borrowings, net | | | (3,977 | ) | | | - | |
| Dividend Payments- | | | | | | | | |
| Common stock | | | (10,000 | ) | | | (15,000 | ) |
| Other | | | (39 | ) | | | - | |
| Net cash provided from (used for) financing activities | | | (14,197 | ) | | | 37,812 | |
| | | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (12,233 | ) | | | (19,435 | ) |
| Loan repayments from (loans to) associated companies, net | | | (21,528 | ) | | | 46,789 | |
| Redemption of lessor notes | | | 18,358 | | | | 11,989 | |
| Sales of investment securities held in trusts | | | 44,270 | | | | 3,908 | |
| Purchases of investment securities held in trusts | | | (44,856 | ) | | | (4,715 | ) |
| Other | | | (1,072 | ) | | | (110 | ) |
| Net cash provided from (used for) investing activities | | | (17,061 | ) | | | 38,426 | |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | 1 | | | | 191 | |
| Cash and cash equivalents at beginning of period | | | 14 | | | | 22 | |
| Cash and cash equivalents at end of period | | $ | 15 | | | $ | 213 | |
| | | | | | | | | |
| 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
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 franchise customers electing to retain JCP&L as their power supplier. JCP&L procures electric supply to serve its BGS customers through a statewide auction process approved by the NJBPU.
Results of Operations
Net income for the first three months of 2009 decreased to $28 million from $34 million in the same period in 2008. The decrease was primarily due to lower revenues and higher other operating costs, partially offset by lower purchased power costs and reduced amortization of regulatory assets.
Revenuesflows.
In April 2007, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the first three monthsMidwest ISO region and found it to be in full compliance with all audited reliability standards. Similarly, in October 2008, ReliabilityFirst performed a routine compliance audit of 2009, revenues decreasedFirstEnergy’s bulk-power system within the PJM region and found it to be in full compliance with all audited reliability standards. FirstEnergy’s MISO facilities are next due for the periodic audit by $21 million, or 3%, compared to the same period of 2008. A $31 million increase in retail generation revenues was more than offset by a $47 million decrease in wholesale revenues in the first three months of 2009.ReliabilityFirst later this year.
Retail generation revenues from all customer classes increasedOn December 9, 2008, a transformer at JCP&L’s Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations, with customers in the first three months ofaffected area losing power. Power was restored to most customers within a few hours and to all customers within eleven hours. On December 16, 2008, JCP&L provided preliminary information about the event to certain regulatory agencies, including the NERC. On March 31, 2009, comparedthe NERC initiated a Compliance Violation Investigation in order to determine JCP&L’s contribution to the same periodelectrical event and to review any potential violation of 2008 dueNERC Reliability Standards associated with the event. The initial phase of the investigation required JCP&L to higher unit prices resulting from the BGS auction effective June 1, 2008, partially offset by a decrease in retail generation KWH sales to commercial customers. Sales volumerespond to the commercial sector decreased primarily dueNERC’s request for factual data about the outage. JCP&L submitted its written response on May 1, 2009. The NERC conducted on site interviews with personnel involved in responding to an increase in the number of customers procuring generation from other suppliers.event on June 16-17, 2009. On July 7, 2009, the NERC issued additional questions regarding the event and JCP&L replied as requested on August 6, 2009. JCP&L is not able at this time to predict what actions, if any, that the NERC may take based on the data submittals or interview results.
Wholesale generation revenues decreased $47 millionOn June 5, 2009, FirstEnergy self-reported to ReliabilityFirst a potential violation of NERC Standard PRC-005 resulting from its inability to validate maintenance records for 20 protection system relays (out of approximately 20,000 reportable relays) in JCP&L’s and Penelec’s transmission systems. These potential violations were discovered during a comprehensive field review of all FirstEnergy substations to verify equipment and maintenance database accuracy. FirstEnergy has completed all mitigation actions, including calibrations and maintenance records for the first three monthsrelays. ReliabilityFirst issued an Initial Notice of 2009 due to lower market pricesAlleged Violation on June 22, 2009. The NERC approved FirstEnergy’s mitigation plan on August 19, 200 9, and a decrease in sales volume (from NUG purchases) as comparedsubmitted it to the first three months of 2008.
Changes in retail generation KWH sales and revenues by customer class in the first three months of 2009 comparedFERC for approval on August 19, 2009. FirstEnergy is not able at this time to the same period of 2008 are summarized in the following tables:
Retail Generation KWH Sales | | Increase
(Decrease)
| |
| | | | |
Residential | | | 0.1 | % |
Commercial | | | (7.0 | )% |
Industrial | | | 2.9 | % |
Net Decrease in Generation Sales | | | (2.7 | )% |
| Retail Generation Revenues | | Increase | |
| | | (In millions) | |
| Residential | | $ | 30 | |
| Commercial | | | 1 | |
| Industrial | | | - | |
| Increase in Generation Revenues | | $ | 31 | |
Distribution revenues decreased by $1 million in the first three months of 2009 compared to the same period of 2008, reflecting lower KWH deliveries to commercial and industrial customers as a result of weakened economic conditions in JCP&L’s service territory. The decrease in KWH deliveries was partially offset by an increase in composite unit prices.
Changes in distribution KWH deliveries and revenues by customer class in the first three months of 2009 compared to the same period in 2008 are summarized in the following tables:
| | Increase | |
Distribution KWH Deliveries | | (Decrease) | |
| | | | | |
Residential | | | | - | % |
Commercial | | | | (2.4 | )% |
Industrial | | | | (11.4 | )% |
Decrease in Distribution Deliveries | | | | (2.5 | )% |
| Distribution Revenues | | Increase (Decrease) | |
| | | (In millions) | |
| Residential | | $ | 2 | |
| Commercial | | | (2 | ) |
| Industrial | | | (1 | ) |
| Net Decrease in Distribution Revenues | | $ | (1 | ) |
predict what actions or penalties, if any, that ReliabilityExpensesFirst
Total expenses decreased by $11 million in the first three months of 2009 compared to the same period of 2008. The following table presents changes from the prior year period by expense category:
| Expenses - Changes | | | Increase (Decrease) | |
| | | | (In millions) | |
| Purchased power costs | | | $ | (15 | ) |
| Other operating costs | | | | 7 | |
| Provision for depreciation | | | | 2 | |
| Amortization of regulatory assets | | | | (5 | ) |
| Net Decrease in Expenses | | | $ | (11 | ) |
Purchased power costs decreased in the first three months of 2009 primarily due to lower KWH purchases to meet the lower demand, partially offset by higher unit prices from the BGS auction effective June 1, 2008. Other operating costs increased in the first three months of 2009 primarily due to higher expenses related to employee benefits and customer assistance programs, partially offset by lower contracting and labor expenses. Depreciation expense increased primarily due to an increase in depreciable property since the first quarter of 2008. Amortization of regulatory assets decreased in the first three months of 2009 primarily due to the full recovery of certain regulatory assets in June 2008.
Other Expenses will propose for this self-reported violation.
Other expenses increased by $2 million in the first three months of 2009 compared to the same period in 2008 primarily due to interest expense associated with JCP&L’s $300 million Senior Notes issuance in January 2009.
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, 2009 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2009 and 2008. 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, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, 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, 2008, 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, 2009
|
| JERSEY CENTRAL POWER & LIGHT COMPANY | |
| | | | | | | |
| CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
| (Unaudited) | |
| | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| | | 2009 | | | 2008 | |
| | | (In thousands) | |
| | | | | | | |
| REVENUES: | | | | | | |
| Electric sales | | $ | 760,920 | | | $ | 781,433 | |
| Excise tax collections | | | 12,731 | | | | 12,795 | |
| Total revenues | | | 773,651 | | | | 794,228 | |
| | | | | | | | | |
| EXPENSES: | | | | | | | | |
| Purchased power | | | 481,241 | | | | 496,681 | |
| Other operating costs | | | 85,870 | | | | 78,784 | |
| Provision for depreciation | | | 25,103 | | | | 23,282 | |
| Amortization of regulatory assets | | | 86,831 | | | | 91,519 | |
| General taxes | | | 17,496 | | | | 17,028 | |
| Total expenses | | | 696,541 | | | | 707,294 | |
| | | | | | | | | |
| OPERATING INCOME | | | 77,110 | | | | 86,934 | |
| | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | |
| Miscellaneous income (expense) | | | 805 | | | | (389 | ) |
| Interest expense | | | (27,868 | ) | | | (24,464 | ) |
| Capitalized interest | | | 62 | | | | 276 | |
| Total other expense | | | (27,001 | ) | | | (24,577 | ) |
| | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 50,109 | | | | 62,357 | |
| | | | | | | | | |
| INCOME TAXES | | | 22,551 | | | | 28,403 | |
| | | | | | | | | |
| NET INCOME | | | 27,558 | | | | 33,954 | |
| | | | | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
| Pension and other postretirement benefits | | | 4,121 | | | | (3,449 | ) |
| Unrealized gain on derivative hedges | | | 69 | | | | 69 | |
| Other comprehensive income (loss) | | | 4,190 | | | | (3,380 | ) |
| Income tax expense (benefit) related to other comprehensive income | | | 1,430 | | | | (1,470 | ) |
| Other comprehensive income (loss), net of tax | | | 2,760 | | | | (1,910 | ) |
| | | | | | | | | |
| TOTAL COMPREHENSIVE INCOME | | $ | 30,318 | | | $ | 32,044 | |
| | | | | | | | | |
| 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, | |
| | | 2009 | | | 2008 | |
| | | (In thousands) | |
| ASSETS | | | | | | |
| CURRENT ASSETS: | | | | | | |
| Cash and cash equivalents | | $ | 4 | | | $ | 66 | |
| Receivables- | | | | | | | | |
| Customers (less accumulated provisions of $3,415,000 and $3,230,000 | | | | | | | | |
| respectively, for uncollectible accounts) | | | 315,084 | | | | 340,485 | |
| Associated companies | | | 116 | | | | 265 | |
| Other | | | 35,941 | | | | 37,534 | |
| Notes receivable - associated companies | | | 91,362 | | | | 16,254 | |
| Prepaid taxes | | | 4,243 | | | | 10,492 | |
| Other | | | 21,006 | | | | 18,066 | |
| | | | 467,756 | | | | 423,162 | |
| UTILITY PLANT: | | | | | | | | |
| In service | | | 4,337,711 | | | | 4,307,556 | |
| Less - Accumulated provision for depreciation | | | 1,562,417 | | | | 1,551,290 | |
| | | | 2,775,294 | | | | 2,756,266 | |
| Construction work in progress | | | 69,806 | | | | 77,317 | |
| | | | 2,845,100 | | | | 2,833,583 | |
| OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
| Nuclear fuel disposal trust | | | 189,784 | | | | 181,468 | |
| Nuclear plant decommissioning trusts | | | 136,783 | | | | 143,027 | |
| Other | | | 2,154 | | | | 2,145 | |
| | | | 328,721 | | | | 326,640 | |
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Goodwill | | | 1,810,936 | | | | 1,810,936 | |
| Regulatory assets | | | 1,162,132 | | | | 1,228,061 | |
| Other | | | 28,487 | | | | 29,946 | |
| | | | 3,001,555 | | | | 3,068,943 | |
| | | $ | 6,643,132 | | | $ | 6,652,328 | |
| LIABILITIES AND CAPITALIZATION | | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 29,465 | | | $ | 29,094 | |
| Short-term borrowings- | | | | | | | | |
| Associated companies | | | - | | | | 121,380 | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 22,562 | | | | 12,821 | |
| Other | | | 158,972 | | | | 198,742 | |
| Accrued taxes | | | 53,998 | | | | 20,561 | |
| Accrued interest | | | 30,446 | | | | 9,197 | |
| Other | | | 129,745 | | | | 133,091 | |
| | | | 425,188 | | | | 524,886 | |
| CAPITALIZATION | | | | | | | | |
| Common stockholder's equity- | | | | | | | | |
| Common stock, $10 par value, authorized 16,000,000 shares- | | | | | | | | |
| 13,628,447 shares outstanding | | | 136,284 | | | | 144,216 | |
| Other paid-in capital | | | 2,502,594 | | | | 2,644,756 | |
| Accumulated other comprehensive loss | | | (213,778 | ) | | | (216,538 | ) |
| Retained earnings | | | 121,134 | | | | 156,576 | |
| Total common stockholder's equity | | | 2,546,234 | | | | 2,729,010 | |
| Long-term debt and other long-term obligations | | | 1,824,851 | | | | 1,531,840 | |
| | | | 4,371,085 | | | | 4,260,850 | |
| NONCURRENT LIABILITIES: | | | | | | | | |
| Power purchase contract liability | | | 530,538 | | | | 531,686 | |
| Accumulated deferred income taxes | | | 664,388 | | | | 689,065 | |
| Nuclear fuel disposal costs | | | 196,260 | | | | 196,235 | |
| Asset retirement obligations | | | 96,839 | | | | 95,216 | |
| Retirement benefits | | | 185,265 | | | | 190,182 | |
| Other | | | 173,569 | | | | 164,208 | |
| | | | 1,846,859 | | | | 1,866,592 | |
| COMMITMENTS AND CONTINGENCIES (Note 8) | | | | | | | | |
| | | $ | 6,643,132 | | | $ | 6,652,328 | |
| | | | | | | | | |
| 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 | |
| | | 2009 | | | 2008 | |
| | | (In thousands) | |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
| Net income | | $ | 27,558 | | | $ | 33,954 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | |
| Provision for depreciation | | | 25,103 | | | | 23,282 | |
| Amortization of regulatory assets | | | 86,831 | | | | 91,519 | |
| Deferred purchased power and other costs | | | (28,369 | ) | | | (23,893 | ) |
| Deferred income taxes and investment tax credits, net | | | (6,408 | ) | | | 723 | |
| Accrued compensation and retirement benefits | | | (7,481 | ) | | | (15,113 | ) |
| Cash collateral returned to suppliers | | | (209 | ) | | | (502 | ) |
| Decrease (increase) in operating assets: | | | | | | | | |
| Receivables | | | 27,143 | | | | 48,733 | |
| Materials and supplies | | | - | | | | 255 | |
| Prepaid taxes | | | 6,249 | | | | (290 | ) |
| Other current assets | | | (1,457 | ) | | | (1,305 | ) |
| Increase (decrease) in operating liabilities: | | | | | | | | |
| Accounts payable | | | (30,029 | ) | | | (14,511 | ) |
| Accrued taxes | | | 33,114 | | | | 29,844 | |
| Accrued interest | | | 21,249 | | | | 17,338 | |
| Other | | | 7,890 | | | | (3,098 | ) |
| Net cash provided from operating activities | | | 161,184 | | | | 186,936 | |
| | | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| New Financing- | | | | | | | | |
| Long-term debt | | | 299,619 | | | | - | |
| Redemptions and Repayments- | | | | | | | | |
| Common stock | | | (150,000 | ) | | | - | |
| Long-term debt | | | (6,402 | ) | | | (5,872 | ) |
| Short-term borrowings, net | | | (121,380 | ) | | | (48,001 | ) |
| Dividend Payments- | | | | | | | | |
| Common stock | | | (63,000 | ) | | | (70,000 | ) |
| Other | | | (2,152 | ) | | | (68 | ) |
| Net cash used for financing activities | | | (43,315 | ) | | | (123,941 | ) |
| | | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (37,372 | ) | | | (56,047 | ) |
| Loan repayments from (loans to) associated companies, net | | | (75,108 | ) | | | 18 | |
| Sales of investment securities held in trusts | | | 115,483 | | | | 56,506 | |
| Purchases of investment securities held in trusts | | | (120,062 | ) | | | (61,290 | ) |
| Other | | | (872 | ) | | | (2,236 | ) |
| Net cash used for investing activities | | | (117,931 | ) | | | (63,049 | ) |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | (62 | ) | | | (54 | ) |
| Cash and cash equivalents at beginning of period | | | 66 | | | | 94 | |
| Cash and cash equivalents at end of period | | $ | 4 | | | $ | 40 | |
| | | | | | | | | |
| 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. Met-Ed has a partial requirements wholesale power sales agreement with FES, to supply a portion of each of its default service obligations at fixed prices through 2009. This sales agreement is renewed annually unless cancelled by either party with at least a sixty day written notice prior to the end of the calendar year.
Results of Operations
Net income decreased to $17 million in the first quarter of 2009, compared to $22 million in the same period of 2008. The decrease was primarily due to higher purchased power costs and lower deferrals of new regulatory assets, partially offset by higher revenues.
Revenues
Revenues increased by $29 million, or 7.3%, in the first quarter of 2009, compared to the same period of 2008, primarily due to higher distribution throughput revenues and wholesale generation revenues, partially offset by a decrease in retail generation revenues. Wholesale revenues increased by $8 million in the first quarter of 2009, compared to the same period of 2008, due to higher capacity prices for PJM market participants; wholesale KWH sales volume was lower in 2009.
In the first quarter of 2009, retail generation revenues decreased $5 million due to lower KWH sales to the commercial and industrial customer classes, partially offset by higher KWH sales to the residential customer class with a slight increase in composite unit prices in all customer classes. Higher KWH sales in the residential sector were due to increased weather- related usage, reflecting an 8.1% increase in heating degree days in the first quarter of 2009. Lower KWH sales to commercial and industrial customers were principally due to economic conditions in Met-Ed’s service territory.
Changes in retail generation sales and revenues in the first quarter of 2009 compared to the same period of 2008 are summarized in the following tables:
| | Increase | |
Retail Generation KWH Sales | | (Decrease) | |
| | | | |
Residential | | | 2.9 | % |
Commercial | | | (2.5 | )% |
Industrial | | | (12.9 | )% |
Net Decrease in Retail Generation Sales | | | (2.9 | )% |
| | Increase | |
Retail Generation Revenues | | (Decrease) | |
| | (In millions) | |
Residential | | $ | 2 | |
Commercial | | | (1 | ) |
Industrial | | | (6 | ) |
Net Decrease in Retail Generation Revenues | | $ | (5 | ) |
In the first quarter of 2009, distribution throughput revenues increased $22 million primarily due to higher transmission rates, resulting from the annual update of Met-Ed’s TSC rider effective June 1, 2008. Decreased deliveries to commercial and industrial customers, reflecting the weakened economy, were partially offset by increased deliveries to residential customers as a result of the weather conditions described above.
Changes in distribution KWH deliveries and revenues in the first quarter of 2009 compared to the same period of 2008 are summarized in the following tables:
| | Increase | |
Distribution KWH Deliveries | | (Decrease) | |
| | | | |
Residential | | | 2.9 | % |
Commercial | | | (2.5 | )% |
Industrial | | | (12.9 | )% |
Net Decrease in Distribution Deliveries | | | (2.9 | )% |
Distribution Revenues | | Increase | |
| | (In millions) | |
Residential | | $ | 14 | |
Commercial | | | 5 | |
Industrial | | | 3 | |
Increase in Distribution Revenues | | $ | 22 | |
PJM transmission revenues increased by $4 million in the first quarter of 2009 compared to the same period of 2008, primarily due to increased revenues related to Met-Ed’s Auction Revenue Rights and Financial Transmission Rights. Met-Ed defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.
Operating Expenses
Total operating expenses increased by $37 million in the first quarter of 2009 compared to the same period of 2008. The following table presents changes from the prior year by expense category:
| Expenses – Changes | | Increase (Decrease) | |
| | | (In millions) | |
| Purchased power costs | | $ | 7 | |
| Other operating costs | | | (1 | ) |
| Provision for depreciation | | | 1 | |
| Deferral of new regulatory assets | | | 30 | |
| Net Increase in Expenses | | $ | 37 | |
Purchased power costs increased by $7 million in the first quarter of 2009, primarily due to higher composite unit prices partially offset by decreased KWH purchases due to lower generation sales requirements. The deferral of new regulatory assets decreased in the first quarter of 2009 primarily due to decreased transmission cost deferrals reflecting lower PJM transmission service expenses and the increased transmission revenues described above.
Other Expense
Other expense increased in the first quarter of 2009 primarily due to a decrease in interest deferred on regulatory assets, reflecting a lower regulatory asset base, and an increase in interest expense from Met-Ed’s $300 million Senior Notes issuance in January 2009.
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 subsidiary as of March 31, 2009 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2009 and 2008. 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, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, 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, 2008, 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, 2009
|
| METROPOLITAN EDISON COMPANY | |
| | | | | | | |
| CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
| (Unaudited) | |
| | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| | | 2009 | | | 2008 | |
| | | (In thousands) | |
| | | | | | | |
| REVENUES: | | | | | | |
| Electric sales | | $ | 409,686 | | | $ | 379,608 | |
| Gross receipts tax collections | | | 19,983 | | | | 20,718 | |
| Total revenues | | | 429,669 | | | | 400,326 | |
| | | | | | | | | |
| EXPENSES: | | | | | | | | |
| Purchased power from affiliates | | | 100,077 | | | | 83,442 | |
| Purchased power from non-affiliates | | | 123,911 | | | | 133,540 | |
| Other operating costs | | | 106,357 | | | | 107,017 | |
| Provision for depreciation | | | 12,139 | | | | 11,112 | |
| Amortization of regulatory assets | | | 35,432 | | | | 35,575 | |
| Deferral of new regulatory assets | | | (7,841 | ) | | | (37,772 | ) |
| General taxes | | | 21,935 | | | | 21,781 | |
| Total expenses | | | 392,010 | | | | 354,695 | |
| | | | | | | | | |
| OPERATING INCOME | | | 37,659 | | | | 45,631 | |
| | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | |
| Interest income | | | 3,186 | | | | 5,479 | |
| Miscellaneous income (expense) | | | 856 | | | | (309 | ) |
| Interest expense | | | (13,359 | ) | | | (11,672 | ) |
| Capitalized interest | | | 15 | | | | (219 | ) |
| Total other expense | | | (9,302 | ) | | | (6,721 | ) |
| | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 28,357 | | | | 38,910 | |
| | | | | | | | | |
| INCOME TAXES | | | 11,735 | | | | 16,675 | |
| | | | | | | | | |
| NET INCOME | | | 16,622 | | | | 22,235 | |
| | | | | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
| Pension and other postretirement benefits | | | 4,553 | | | | (2,233 | ) |
| Unrealized gain on derivative hedges | | | 84 | | | | 84 | |
| Other comprehensive income (loss) | | | 4,637 | | | | (2,149 | ) |
| Income tax expense (benefit) related to other comprehensive income | | | 1,793 | | | | (970 | ) |
| Other comprehensive income (loss), net of tax | | | 2,844 | | | | (1,179 | ) |
| | | | | | | | | |
| TOTAL COMPREHENSIVE INCOME | | $ | 19,466 | | | $ | 21,056 | |
| | | | | | | | | |
| 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, | |
| | | 2009 | | | 2008 | |
| | | (In thousands) | |
| ASSETS | | | | | | |
| CURRENT ASSETS: | | | | | | |
| Cash and cash equivalents | | $ | 127 | | | $ | 144 | |
| Receivables- | | | | | | | | |
| Customers (less accumulated provisions of $3,867,000 and $3,616,000, | | | | | | | | |
| respectively, for uncollectible accounts) | | | 161,613 | | | | 159,975 | |
| Associated companies | | | 27,349 | | | | 17,034 | |
| Other | | | 17,521 | | | | 19,828 | |
| Notes receivable from associated companies | | | 229,614 | | | | 11,446 | |
| Prepaid taxes | | | 57,115 | | | | 6,121 | |
| Other | | | 5,238 | | | | 1,621 | |
| | | | 498,577 | | | | 216,169 | |
| UTILITY PLANT: | | | | | | | | |
| In service | | | 2,093,792 | | | | 2,065,847 | |
| Less - Accumulated provision for depreciation | | | 784,064 | | | | 779,692 | |
| | | | 1,309,728 | | | | 1,286,155 | |
| Construction work in progress | | | 19,087 | | | | 32,305 | |
| | | | 1,328,815 | | | | 1,318,460 | |
| OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
| Nuclear plant decommissioning trusts | | | 217,476 | | | | 226,139 | |
| Other | | | 975 | | | | 976 | |
| | | | 218,451 | | | | 227,115 | |
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Goodwill | | | 416,499 | | | | 416,499 | |
| Regulatory assets | | | 489,680 | | | | 412,994 | |
| Power purchase contract asset | | | 248,762 | | | | 300,141 | |
| Other | | | 37,231 | | | | 31,031 | |
| | | | 1,192,172 | | | | 1,160,665 | |
| | | $ | 3,238,015 | | | $ | 2,922,409 | |
| LIABILITIES AND CAPITALIZATION | | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 128,500 | | | $ | 28,500 | |
| Short-term borrowings- | | | | | | | | |
| Associated companies | | | - | | | | 15,003 | |
| Other | | | 250,000 | | | | 250,000 | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 29,764 | | | | 28,707 | |
| Other | | | 46,216 | | | | 55,330 | |
| Accrued taxes | | | 8,489 | | | | 16,238 | |
| Accrued interest | | | 11,557 | | | | 6,755 | |
| Other | | | 29,506 | | | | 30,647 | |
| | | | 504,032 | | | | 431,180 | |
| CAPITALIZATION: | | | | | | | | |
| Common stockholder's equity- | | | | | | | | |
| Common stock, without par value, authorized 900,000 shares- | | | | | | | | |
| 859,500 shares outstanding | | | 1,196,090 | | | | 1,196,172 | |
| Accumulated other comprehensive loss | | | (138,140 | ) | | | (140,984 | ) |
| Accumulated deficit | | | (34,502 | ) | | | (51,124 | ) |
| Total common stockholder's equity | | | 1,023,448 | | | | 1,004,064 | |
| Long-term debt and other long-term obligations | | | 713,782 | | | | 513,752 | |
| | | | 1,737,230 | | | | 1,517,816 | |
| NONCURRENT LIABILITIES: | | | | | | | | |
| Accumulated deferred income taxes | | | 390,448 | | | | 387,757 | |
| Accumulated deferred investment tax credits | | | 7,653 | | | | 7,767 | |
| Nuclear fuel disposal costs | | | 44,334 | | | | 44,328 | |
| Asset retirement obligations | | | 171,561 | | | | 170,999 | |
| Retirement benefits | | | 144,459 | | | | 145,218 | |
| Power purchase contract liability | | | 172,520 | | | | 150,324 | |
| Other | | | 65,778 | | | | 67,020 | |
| | | | 996,753 | | | | 973,413 | |
| COMMITMENTS AND CONTINGENCIES (Note 8) | | | | | | | | |
| | | $ | 3,238,015 | | | $ | 2,922,409 | |
| | | | | | | | | |
| 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 | |
| | | 2009 | | | 2008 | |
| | | (In thousands) | |
| | | | | | | |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
| Net income | | $ | 16,622 | | | $ | 22,235 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | |
| Provision for depreciation | | | 12,139 | | | | 11,112 | |
| Amortization of regulatory assets | | | 35,432 | | | | 35,575 | |
| Deferred costs recoverable as regulatory assets | | | (19,633 | ) | | | (10,628 | ) |
| Deferral of new regulatory assets | | | (7,841 | ) | | | (37,772 | ) |
| Deferred income taxes and investment tax credits, net | | | 4,657 | | | | 17,307 | |
| Accrued compensation and retirement benefits | | | 1,029 | | | | (9,655 | ) |
| Cash collateral to suppliers | | | (9,500 | ) | | | - | |
| Increase in operating assets- | | | | | | | | |
| Receivables | | | (9,860 | ) | | | (30,863 | ) |
| Prepayments and other current assets | | | (50,422 | ) | | | (41,088 | ) |
| Increase (decrease) in operating liabilities- | | | | | | | | |
| Accounts payable | | | (8,058 | ) | | | (14,196 | ) |
| Accrued taxes | | | (7,749 | ) | | | (14,519 | ) |
| Accrued interest | | | 4,803 | | | | 281 | |
| Other | | | 2,460 | | | | 3,892 | |
| Net cash used for operating activities | | | (35,921 | ) | | | (68,319 | ) |
| | | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| New Financing- | | | | | | | | |
| Long-term debt | | | 300,000 | | | | - | |
| Short-term borrowings, net | | | - | | | | 131,743 | |
| Redemptions and Repayments- | | | | | | | | |
| Long-term debt | | | - | | | | (28,500 | ) |
| Short-term borrowings, net | | | (15,003 | ) | | | - | |
| Other | | | (2,150 | ) | | | (15 | ) |
| Net cash provided from financing activities | | | 282,847 | | | | 103,228 | |
| | | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (25,922 | ) | | | (31,296 | ) |
| Sales of investment securities held in trusts | | | 27,800 | | | | 40,513 | |
| Purchases of investment securities held in trusts | | | (29,821 | ) | | | (43,391 | ) |
| Loans to associated companies, net | | | (218,168 | ) | | | (254 | ) |
| Other | | | (832 | ) | | | (484 | ) |
| Net cash used for investing activities | | | (246,943 | ) | | | (34,912 | ) |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | (17 | ) | | | (3 | ) |
| Cash and cash equivalents at beginning of period | | | 144 | | | | 135 | |
| Cash and cash equivalents at end of period | | $ | 127 | | | $ | 132 | |
| | | | | | | | | |
| 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. Penelec has a partial requirements wholesale power sales agreement with FES, to supply a portion of each of its default service obligations at fixed prices through 2009. This sales agreement is renewed annually unless cancelled by either party with at least a sixty day written notice prior to the end of the calendar year.
Results of Operations
Net income decreased to $19 million in the first quarter of 2009, compared to $21 million in the same period of 2008. The decrease was primarily due to lower revenues, partially offset by an increase in the deferral of new regulatory assets.
Revenues
Revenues decreased by $7 million, or 1.7%, in the first quarter of 2009 as compared to the same period of 2008, primarily due to lower retail generation revenues and PJM transmission revenues, partially offset by increased distribution throughput revenues and wholesale generation revenues. Wholesale generation revenues increased $7 million in the first quarter of 2009 as compared to the same period of 2008, primarily reflecting higher PJM capacity prices.
In the first quarter of 2009, retail generation revenues decreased $8 million primarily due to lower KWH sales to the commercial and industrial customer classes due to weakened economic conditions, partially offset by a slight increase in KWH sales to the residential customer class.
Changes in retail generation sales and revenues in the first quarter of 2009 compared to the same period of 2008 are summarized in the following tables:
Retail Generation KWH Sales | | Increase
(Decrease)
| |
| | | |
Residential | | | 0.4 | % |
Commercial | | | (3.2 | ) % |
Industrial | | | (13.9 | ) % |
Net Decrease in Retail Generation Sales | | | (4.9 | ) % |
| Retail Generation Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | - | |
| Commercial | | | (2 | ) |
| Industrial | | | (6 | ) |
| Decrease in Retail Generation Revenues | | $ | (8 | ) |
Revenues from distribution throughput increased $5 million in the first quarter of 2009 compared to the same period of 2008, primarily due to an increase in transmission rates, resulting from the annual update of Penelec’s TSC rider effective June 1, 2008, and a slight increase in usage in the residential sector. Partially offsetting this increase was lower usage in the commercial and industrial sectors, reflecting economic conditions in Penelec’s service territory.
Changes in distribution KWH deliveries and revenues in the first quarter of 2009 compared to the same period of 2008 are summarized in the following tables:
Distribution KWH Deliveries | | Increase
(Decrease)
| |
| | | |
Residential | | | 0.4 | % |
Commercial | | | (3.2 | ) % |
Industrial | | | (12.0 | ) % |
Net Decrease in Distribution Deliveries | | | (4.6 | ) % |
| Distribution Revenues | | Increase | |
| | | (In millions) | |
| Residential | | $ | 4 | |
| Commercial | | | 1 | |
| Industrial | | | - | |
| Increase in Distribution Revenues | | $ | 5 | |
PJM transmission revenues decreased by $13 million in the first quarter of 2009 compared to the same period of 2008, primarily due to lower revenues related to Penelec’s Financial Transmission Rights. Penelec defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.
Operating Expenses
Total operating expenses increased by $5 million in the first quarter of 2009 as compared with the same period of 2008. The following table presents changes from the prior year by expense category:
| Expenses – Changes | | Increase (Decrease) | |
| | | (In millions) | |
| Purchased power costs | | $ | 2 | |
| Other operating costs | | | 6 | |
| Provision for depreciation | | | 2 | |
| Deferral of new regulatory assets | | | (4 | ) |
| General taxes | | | (1 | ) |
| Net Increase in Expenses | | $ | 5 | |
Purchased power costs increased by $2 million, or 0.9%, in the first quarter of 2009 compared to the same period of 2008, primarily due to increased composite unit prices, partially offset by reduced volume as a result of lower KWH sales requirements. Other operating costs increased by $6 million in the first quarter of 2009 primarily due to higher employee benefit expenses. Depreciation expense increased $2 million in the first quarter of 2009 primarily due to an increase in depreciable property in service since the first quarter of 2008. The deferral of new regulatory assets increased $4 million in the first quarter of 2009 primarily due to an increase in transmission cost deferrals as a result of increased net congestion costs.
Other Income
In the first quarter of 2009, other income increased primarily due to lower interest expense on reduced borrowings from the regulated money pool.
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, 2009 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2009 and 2008. 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, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, 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, 2008, 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, 2009
|
| PENNSYLVANIA ELECTRIC COMPANY | |
| | | | | | | |
| CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
| (Unaudited) | |
| | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| | | 2009 | | | 2008 | |
| | | (In thousands) | |
| | | | | | | |
| REVENUES: | | | | | | |
| Electric sales | | $ | 371,293 | | | $ | 376,028 | |
| Gross receipts tax collections | | | 17,292 | | | | 19,464 | |
| Total revenues | | | 388,585 | | | | 395,492 | |
| | | | | | | | | |
| EXPENSES: | | | | | | | | |
| Purchased power from affiliates | | | 96,081 | | | | 83,464 | |
| Purchased power from non-affiliates | | | 127,166 | | | | 137,770 | |
| Other operating costs | | | 77,289 | | | | 71,077 | |
| Provision for depreciation | | | 14,455 | | | | 12,516 | |
| Amortization of regulatory assets | | | 16,141 | | | | 16,346 | |
| Deferral of new regulatory assets | | | (7,365 | ) | | | (3,526 | ) |
| General taxes | | | 20,593 | | | | 21,855 | |
| Total expenses | | | 344,360 | | | | 339,502 | |
| | | | | | | | | |
| OPERATING INCOME | | | 44,225 | | | | 55,990 | |
| | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | |
| Miscellaneous income (expense) | | | 798 | | | | (191 | ) |
| Interest expense | | | (13,233 | ) | | | (15,322 | ) |
| Capitalized interest | | | 22 | | | | (806 | ) |
| Total other expense | | | (12,413 | ) | | | (16,319 | ) |
| | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 31,812 | | | | 39,671 | |
| | | | | | | | | |
| INCOME TAXES | | | 13,122 | | | | 18,279 | |
| | | | | | | | | |
| NET INCOME | | | 18,690 | | | | 21,392 | |
| | | | | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
| Pension and other postretirement benefits | | | 2,955 | | | | (3,473 | ) |
| Unrealized gain on derivative hedges | | | 16 | | | | 16 | |
| Change in unrealized gain on available-for-sale securities | | | (22 | ) | | | 11 | |
| Other comprehensive income (loss) | | | 2,949 | | | | (3,446 | ) |
| Income tax expense (benefit) related to other comprehensive income | | | 1,055 | | | | (1,506 | ) |
| Other comprehensive income (loss), net of tax | | | 1,894 | | | | (1,940 | ) |
| | | | | | | | | |
| TOTAL COMPREHENSIVE INCOME | | $ | 20,584 | | | $ | 19,452 | |
| | | | | | | | | |
| 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, | |
| | | 2009 | | | 2008 | |
| | | (In thousands) | |
| ASSETS | | | | | | |
| CURRENT ASSETS: | | | | | | |
| Cash and cash equivalents | | $ | 13 | | | $ | 23 | |
| Receivables- | | | | | | | | |
| Customers (less accumulated provisions of $3,285,000 and $3,121,000, | | | | | | | | |
| respectively, for uncollectible accounts) | | | 140,783 | | | | 146,831 | |
| Associated companies | | | 80,387 | | | | 65,610 | |
| Other | | | 19,493 | | | | 26,766 | |
| Notes receivable from associated companies | | | 15,198 | | | | 14,833 | |
| Prepaid taxes | | | 66,392 | | | | 16,310 | |
| Other | | | 1,142 | | | | 1,517 | |
| | | | 323,408 | | | | 271,890 | |
| UTILITY PLANT: | | | | | | | | |
| In service | | | 2,345,475 | | | | 2,324,879 | |
| Less - Accumulated provision for depreciation | | | 873,677 | | | | 868,639 | |
| | | | 1,471,798 | | | | 1,456,240 | |
| Construction work in progress | | | 25,042 | | | | 25,146 | |
| | | | 1,496,840 | | | | 1,481,386 | |
| OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
| Nuclear plant decommissioning trusts | | | 113,265 | | | | 115,292 | |
| Non-utility generation trusts | | | 117,899 | | | | 116,687 | |
| Other | | | 289 | | | | 293 | |
| | | | 231,453 | | | | 232,272 | |
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Goodwill | | | 768,628 | | | | 768,628 | |
| Power purchase contract asset | | | 78,226 | | | | 119,748 | |
| Other | | | 15,308 | | | | 18,658 | |
| | | | 862,162 | | | | 907,034 | |
| | | $ | 2,913,863 | | | $ | 2,892,582 | |
| LIABILITIES AND CAPITALIZATION | | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 145,000 | | | $ | 145,000 | |
| Short-term borrowings- | | | | | | | | |
| Associated companies | | | 112,034 | | | | 31,402 | |
| Other | | | 250,000 | | | | 250,000 | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 49,981 | | | | 63,692 | |
| Other | | | 42,004 | | | | 48,633 | |
| Accrued taxes | | | 4,053 | | | | 13,264 | |
| Accrued interest | | | 13,730 | | | | 13,131 | |
| Other | | | 26,591 | | | | 31,730 | |
| | | | 643,393 | | | | 596,852 | |
| 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 | | | 912,380 | | | | 912,441 | |
| Accumulated other comprehensive loss | | | (126,103 | ) | | | (127,997 | ) |
| Retained earnings | | | 94,803 | | | | 76,113 | |
| Total common stockholder's equity | | | 969,632 | | | | 949,109 | |
| Long-term debt and other long-term obligations | | | 633,355 | | | | 633,132 | |
| | | | 1,602,987 | | | | 1,582,241 | |
| NONCURRENT LIABILITIES: | | | | | | | | |
| Regulatory liabilities | | | 48,847 | | | | 136,579 | |
| Accumulated deferred income taxes | | | 183,906 | | | | 169,807 | |
| Retirement benefits | | | 172,544 | | | | 172,718 | |
| Asset retirement obligations | | | 87,395 | | | | 87,089 | |
| Power purchase contract liability | | | 112,462 | | | | 83,600 | |
| Other | | | 62,329 | | | | 63,696 | |
| | | | 667,483 | | | | 713,489 | |
| COMMITMENTS AND CONTINGENCIES (Note 8) | | | | | | | | |
| | | $ | 2,913,863 | | | $ | 2,892,582 | |
| | | | | | | | | |
| 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 | |
| | | 2009 | | | 2008 | |
| | | (In thousands) | |
| | | | | | | |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
| Net income | | $ | 18,690 | | | $ | 21,392 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | |
| Provision for depreciation | | | 14,455 | | | | 12,516 | |
| Amortization of regulatory assets | | | 16,141 | | | | 16,346 | |
| Deferral of new regulatory assets | | | (7,365 | ) | | | (3,526 | ) |
| Deferred costs recoverable as regulatory assets | | | (20,022 | ) | | | (8,403 | ) |
| Deferred income taxes and investment tax credits, net | | | 11,833 | | | | 10,541 | |
| Accrued compensation and retirement benefits | | | 431 | | | | (10,488 | ) |
| Cash collateral | | | - | | | | 301 | |
| Increase in operating assets- | | | | | | | | |
| Receivables | | | (1,709 | ) | | | (13,701 | ) |
| Prepayments and other current assets | | | (49,707 | ) | | | (40,591 | ) |
| Increase (Decrease) in operating liabilities- | | | | | | | | |
| Accounts payable | | | (5,340 | ) | | | (3,144 | ) |
| Accrued taxes | | | (9,065 | ) | | | (5,809 | ) |
| Accrued interest | | | 599 | | | | 510 | |
| Other | | | (988 | ) | | | 4,991 | |
| Net cash used for operating activities | | | (32,047 | ) | | | (19,065 | ) |
| | | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| New Financing- | | | | | | | | |
| Short-term borrowings, net | | | 80,632 | | | | 118,209 | |
| Redemptions and Repayments | | | | | | | | |
| Long-term debt | | | - | | | | (45,112 | ) |
| Dividend Payments- | | | | | | | | |
| Common stock | | | (15,000 | ) | | | (20,000 | ) |
| Net cash provided from financing activities | | | 65,632 | | | | 53,097 | |
| | | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (28,190 | ) | | | (28,902 | ) |
| Sales of investment securities held in trusts | | | 18,800 | | | | 24,407 | |
| Purchases of investment securities held in trusts | | | (22,108 | ) | | | (29,083 | ) |
| Loan repayments to associated companies, net | | | (365 | ) | | | (610 | ) |
| Other | | | (1,732 | ) | | | 153 | |
| Net cash used for investing activities | | | (33,595 | ) | | | (34,035 | ) |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | (10 | ) | | | (3 | ) |
| Cash and cash equivalents at beginning of period | | | 23 | | | | 46 | |
| Cash and cash equivalents at end of period | | $ | 13 | | | $ | 43 | |
| | | | | | | | | |
| 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 Utilities. This information should be read in conjunction with (i) FES’ and the Utilities’ 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 Utilities; and (iii) FES’ and the Utilities’ respective 2008 Annual Reports on Form 10-K.
Regulatory Matters (Applicable to each of the Utilities)
In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry restructuring contain similar provisions that are reflected in the Utilities' respective state regulatory plans. These provisions include:
· | restructuring the electric generation business and allowing the Utilities' customers to select a competitive electric generation supplier other than the Utilities; |
| |
· | establishing or defining the PLR obligations to customers in the Utilities' service areas; |
| |
· | providing the Utilities 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; |
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· | continuing regulation of the Utilities' transmission and distribution systems; and |
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· | requiring corporate separation of regulated and unregulated business activities. |
The Utilities 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 $130 million as of March 31, 2009 (JCP&L - $54 million and Met-Ed - $76 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* | | 2009 | | 2008 | | (Decrease) | |
| | | (In millions) | |
| OE | | $ | 545 | | $ | 575 | | $ | (30 | ) |
| CEI | | | 618 | | | 784 | | | (166 | ) |
| TE | | | 96 | | | 109 | | | (13 | ) |
| JCP&L | | | 1,162 | | | 1,228 | | | (66 | ) |
| Met-Ed | | | 490 | | | 413 | | | 77 | |
| ATSI | | | | | | | | | | ) |
| Total | | | | | | | | | | ) |
*
| Penelec had net regulatory liabilities of approximately $49 million
and $137 million as of March 31, 2009 and December 31, 2008,
respectively. These net regulatory liabilities are included in Other
Non-current Liabilities on the Consolidated Balance Sheets.
|
Ohio (Applicable to OE, CEI, TE and FES)(B) OHIO
On June 7, 2007, the Ohio Companies filed an application for an increase in electric distribution rates with the PUCO and, on August 6, 2007, updated their filing to support a distribution rate increase of $332 million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of its investigation into the distribution rate request.filing. On January 21, 2009, the PUCO granted the Ohio Companies’ application in part to increase electric distribution rates by $136.6 million (OE - $68.9 million, CEI - $29.2 million and TE - $38.5 million). These increases went into effect for OE and TE on January 23, 2009, and will go into effect for CEI on May 1, 2009. Applications for rehearing of this order were filed by the Ohio Companies and one other party on February 20, 2009. The PUCO granted these applications for rehearing on March 18, 2009.2009 for the purpose of further consideration. The PUCO has not yet issued a substantive Entry on Rehearing.
SB221, which became effective on July 31, 2008, required all electric utilities to file an ESP, and permitted the filing of an MRO. On July 31, 2008, the Ohio Companies filed with the PUCO a comprehensive ESP and a separate MRO. The PUCO denied the MRO application; however, the PUCO later granted the Ohio Companies’ application for rehearing for the purpose of further consideration of the matter. The PUCO has not yet issued a substantive Entry on Rehearing. The ESP proposed to phase in new generation rates for customers beginning in 2009 for up to a three-year period and resolve the Ohio Companies’ collection of fuel costs deferred in 2006 and 2007, and the distribution rate request described above. In response to the PUCO’s December 19, 2008 order, which significantly modified and approved the ESP as modified,by the Ohio Companies notifiedwas approved by the PUCO that they were withdrawingon December 19, 2008. The Ohio Companies thereafter withdrew and terminatingterminated the ESP application in addition to continuingand continued their current rate plan then in effect as allowed by the terms of SB221. On December 31, 2008, the Ohio Companies conducted a CBP for the procurement of electric generation for retail customers from JanuaryJanuar y 5, 2009 through March 31, 2009. The average winning bid price was equivalent to a retail rate of 6.98 cents per kwh. The power supply obtained through this process provides generation service to the Ohio Companies’ retail customers who choose not to shop with alternative suppliers. On January 9, 2009, the Ohio Companies requested the implementation of a new fuel rider to recover the costs resulting from the December 31, 2008 CBP. The PUCO ultimately approved the Ohio Companies’ request for a new fuel rider, to recover increased costs resulting from the CBP but did not authorize OE and TE to continue collecting RTC or allow the Ohio Companies to continue collections pursuant to the two existing fuel riders. The new fuel rider allows for current recovery ofwhich recovered the increased purchased power costs for OE and TE, and authorizes CEI to collectrecovered a portion of those costs currently and deferfor CEI, with the remainder being deferred for future recovery.
On January 29, 2009, the PUCO ordered its Staff to develop a proposal to establish an ESP for the Ohio Companies. On February 19, 2009, the Ohio Companies filed an Amended ESP application, including an attached Stipulation and Recommendation that was signed by the Ohio Companies, the Staff of the PUCO, and many of the intervening parties. Specifically, the Amended ESP providesprovided that generation willwould be provided by FES at the average wholesale rate of the CBP process described above for April and May 2009 to the Ohio Companies for their non-shopping customers; for the period of June 1, 2009 through May 31, 2011, retail generation prices willwould be based upon the outcome of a descending clock CBP on a slice-of-system basis. The PUCO may, at its discretion, phase-in a portion of any increase resulting from this CBP process by authorizing deferral of related purchased power costs, subject to specified limits. The Amended ESP further providesprovided that the Ohio Companies will not seek a base distribution rate increase, subject to certain exceptions, with an effective date of such increase before January 1, 2012, that CEI willwould agree to write-offw rite-off approximately $216 million of its Extended RTC balance,regulatory asset, and that the Ohio Companies willwould collect a delivery service improvement rider at an overall average rate of $.002 per kWhKWH for the period of April 1, 2009 through December 31, 2011. The Amended ESP also addressesaddressed a number of other issues, including but not limited to, rate design for various customer classes, and resolution of the prudence review and the collection of deferred costs that were approved in prior proceedings. On February 26, 2009, the Ohio Companies filed a Supplemental Stipulation, which was signed or not opposed by virtually all of the parties to the proceeding, that supplemented and modified certain provisions of the February 19, 2009 Stipulation and Recommendation. Specifically, the Supplemental Stipulation modified the provision relating to governmental aggregation and the Generation Service Uncollectible Rider, provided further detail on the allocation of the economic development funding containedcon tained in the Stipulation and Recommendation, and proposed additional provisions related to the collaborative process for the development of energy efficiency programs, among other provisions. The PUCO adopted and approved certain aspects of the Stipulation and Recommendation on March 4, 2009, and adopted and approved the remainder of the Stipulation and Recommendation and Supplemental Stipulation without modification on March 25, 2009. Certain aspects of the Stipulation and Recommendation and Supplemental Stipulation taketook effect on April 1, 2009 while the remaining provisions taketook effect on June 1, 2009. The CBP auction is currently scheduled to begin on May 13, 2009. The bidding will occur for a single, two-year product and there will not be a load cap for the bidders. FES may participate without limitation.
SB221 also requires electric distribution utilities to implement energy efficiency programs thatprograms. Under the provisions of SB221, the Ohio Companies are required to achieve ana total annual energy savings equivalent of approximately 166,000 MWH in 2009, 290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in 2013.2013, with additional savings required through 2025. Utilities are also required to reduce peak demand in 2009 by one percent,1%, with an additional seventy-five hundredths of one percent.75% reduction each year thereafter through 2018. CostsThe PUCO may amend these benchmarks in certain, limited circumstances, and the Ohio Companies have filed an application with the PUCO seeking such amendments. On January 7, 2010, the PUCO amended the 2009 energy efficiency benchmarks to zero, contingent upon the Ohio Companies meeting the revised benchmarks in a period of not more than t hree years. On March 10, 2010, the PUCO found that due to a change in PUCO rules subsequent to the filing of the Ohio Companies’ application, the Ohio Companies’ application seeking a reduction of the peak demand reduction requirements was moot. In its March 10, 2010, Entry the PUCO also found that the Ohio Companies peak demand reduction programs complied with PUCO rules.
The Ohio Companies are presently involved in collaborative efforts related to energy efficiency programs, including filing applications for approval of those programs with the PUCO, as well as other implementation efforts arising out of the Supplemental Stipulation. On December 15, 2009, the Ohio Companies filed the required three year portfolio plan seeking approval for the programs they intend to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. The PUCO set the matter for a hearing that was completed on March 8, 2010, and all briefing was completed by April 12, 2010. On March 8, 2010, the Ohio Companies filed their 2009 Status Update Report with the PUCO in which they indicated compliance with the 2009 statutory energy efficiency and peak demand benchmarks as those benchmark s were amended as described above. Interested parties filed comments on the Report. The PUCO has yet to address these comments. The Ohio Companies expect that all costs associated with compliance arewill be recoverable from customers.
Pennsylvania (ApplicableIn October 2009, the PUCO issued additional Entries modifying certain of its previous rules that set out the manner in which electric utilities, including the Ohio Companies, will be required to comply with benchmarks contained in SB221 related to the employment of alternative energy resources, energy efficiency/peak demand reduction programs as well as greenhouse gas reporting requirements and changes to long term forecast reporting requirements. Applications for rehearing filed in mid-November 2009 were granted on December 9, 2009 for the sole purpose of further consideration of the matters raised in those applications. The PUCO has not yet issued a substantive Entry on Rehearing. The rules implementing the requirements of SB221 went into effect on December 10, 2009.
Additionally under SB221, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they serve in 2009. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RFPs sought RECs, including solar RECs and RECs generated in Ohio in order to meet the Ohio Companies’ alternative energy requirements as set forth in SB221 for 2009, 2010 and 2011. The RECs acquired through these two RFPs will be used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. On December 7, 2009, the Ohio Companies filed an application with the PUCO seeking a force majeure determination regarding the Ohio Companies’ compliance with the 2009 solar energy resources benchmark, and seeking a reduction in the benchmark. On March 10, 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market and thus granted the Ohio Companies’ application seeking force majeure. The PUCO reduced the Ohio Companies’ aggregate 2009 benchmark to the level of solar RECs the Ohio Companies’ acquired through their 2009 RFP processes, provided the Companies’ 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. On April 15, 2010, the Ohio Companies and FES Met-Ed, Penelec, OE(due to its status as an electric service company in Ohio) filed compliance reports with the PUCO setting forth how they individually satisfied the alternative energy requirements in SB221 for 2009. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark, which application is still pending.
On October 20, 2009, the Ohio Companies filed an MRO to procure electric generation service for the period beginning June 1, 2011. The proposed MRO would establish a CBP to secure generation supply for customers who do not shop with an alternative supplier and Penn)would be similar, in all material respects, to the CBP conducted in May 2009 in that it would procure energy, capacity and certain transmission services on a slice of system basis. However, unlike the May 2009 CBP, the MRO would include multiple bidding sessions and multiple products with different delivery periods for generation supply designed to reduce potential volatility and supplier risk and encourage bidder participation. A technical conference was held on October 29, 2009. Hearings took place in December 2009 and the matter has been fully briefed. Pursuant to SB221, the PU CO has 90 days from the date of the application to determine whether the MRO meets certain statutory requirements. Although the Ohio Companies requested a PUCO determination by January 18, 2010, on February 3, 2010, the PUCO announced that its determination would be delayed. Under a determination that such statutory requirements are met, the Ohio Companies would be able to implement the MRO and conduct the CBP.
On March 23, 2010, the Ohio Companies filed an application for a new ESP, which if approved by the PUCO, would go into effect on June 1, 2011 and conclude on May 31, 2014. Attached to the application was a Stipulation and Recommendation signed by the Ohio Companies, the Staff of the PUCO, and an additional fourteen parties signing as Signatory Parties, with two additional parties agreeing not to oppose the adoption of the Stipulation. The material terms of the Stipulation include a CBP similar to the one used in May 2009 and the one proposed in the October 2009 MRO filing; a 6% generation discount to certain low-income customers provided by the Ohio Companies through a bilateral wholesale contract with FES; no increase in base distribution rates through May 31, 2014; and a new distribution rider, Delivery Capital Recovery Rider (Rider D CR), to recover a return of, and on, capital investments in the delivery system. This Rider replaces the Delivery Service Improvement Rider (Rider DSI) which terminates by its own terms. The Ohio Companies also agree not to collect certain amounts associated with RTEP and administrative costs associated with the move to PJM. Many of the existing riders approved in the previous ESP remain in effect, some with modifications. The new ESP also requests the resolution of current proceedings pending at the PUCO regarding corporate separation, elements of the smart grid proceeding and the move to PJM. The evidentiary hearing began on April 20, 2010, at the PUCO. The Stipulation requested a decision by the PUCO by May 5, 2010. On April 28, 2010, the PUCO Chairman issued a statement that the PUCO will not issue a decision on May 5, 2010, and will take additional time to review the case record. FirstEnergy recorded approximately $39.5 million of regulatory asset impairments and expenses related to the ESP.
(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. If
On February 20, 2009, Met-Ed and Penelec werefiled with the PPUC a generation procurement plan covering the period January 1, 2011 through May 31, 2013. The plan is designed to replaceprovide adequate and reliable service via a prudent mix of long-term, short-term and spot market generation supply, as required by Act 129. The plan proposed a staggered procurement schedule, which varies by customer class, through 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. 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. See FERC Matters below for a description of the Third Restated Partial Requirements Agreement, executed by the parties on October 31, 2008, that limits the amount of energy and capacity FES must supply to Met-Ed and Penelec. In the eventuse of a third party supplier default, the increased costs todescending clock auction. On August 12, 2009, Met-Ed and Penelec could be material.filed a settlement agreement with the PPUC for the generation procurement plan covering the period January 1, 2011, through May 31, 2013, reflecting the settlement on all but two issues. The settlement plan proposes a staggered procurement schedule, which varies by customer class. On September 2, 2009, the ALJ issued a Recommended Decision (RD ) approving the settlement and adopted the Met-Ed and Penelec’s positions on two reserved issues. On November 6, 2009, the PPUC entered an Order approving the settlement and finding in favor of Met-Ed and Penelec on the two reserved issues. Generation procurement began in January 2010.
On May 22, 2008, the PPUC approved the Met-Ed and Penelec annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. The TSCs included a component for under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received PPUC approval for 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. Various intervenors filed complaints against those filings. In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing Met-Ed to implement the rider June 1, 2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed with its investigation and a litigation schedule was adopted. Hearings and briefing for both Met-Ed and Penelec have concluded andconcluded. On August 11, 2009, the companies are awaitingALJ issued a Recommended Decision to the PPUC approving Met-Ed’s and Penelec’s TSCs as filed and dismissing all complaints. Exceptions by various interveners were filed and reply exceptions were filed by Met-Ed and Penelec. The PPUC adopted a Motion on January 28, 2010 and subsequently entered an Order on March 3, 2010 which denies the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, directs Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the ALJ. The TSCs include a component from under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 millionTSC, and instructs Met-Ed and Penelec - $4 million) andto work with the various intervening parties to file a recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses collected from ratepayers plus interest to be used to mitigate future transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received PPUC approval for 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 rate increases beginning January 1, 2011. On April 15, 2009,March 18, 2010, Met-Ed and Penelec filed revised TSCsa Petition with the PPUC requesting that it stay the portion of the March 3, 2010 Order requiring the filing of tariff supplements to end collection of marginal transmission loss costs. By Order entered March 25, 2010, the PPUC granted the requested stay until December 31, 2010. On April 1, 2010, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania appealing the PPUC’s March 3, 2010 Order. Although the ultimate outcome of this matter cannot be determined at this time, it is the belief of Met-Ed and Penelec that they should prevail in the appeal and therefore expect to fully recover the approximately $199.7 million ($158.5 million for Met-Ed and $41.2 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011. On April 2, 2010, Met-Ed and Penelec filed a Response to the PPUC’s March 3, 2010 Order requesting approval of procedures to establish separate accounts to track all marginal transmission loss revenues and related interest and the use of those funds to mitigate future generation rate increases commencing January 1, 2011
On May 28, 2009, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider for the period June 1, 2009 through May 31, 2010 subject to the outcome of the proceeding related to the 2008 TSC filing described above, as required in connection with the PPUC’s January 2007 rate order. For Penelec’s customers the new TSC would resultresulted in an approximate 1% decrease in monthly bills, reflecting projected PJM transmission costs as well as a reconciliation for costs already incurred. The TSC for Met-Ed’s customers would increaseincreased to recover the additional PJM charges paid by Met-Ed in the previous year and to reflect updated projected costs. In order to gradually transition customers to the higher rate, Met-Ed is proposingthe PPUC approved Met-Ed’s proposal to continue to recover the prior period deferrals allowed in the PPUC’sPPU C’s May 2008 Order and defer $57.5 million of projected costs intoto a future TSC to be fully recovered by December 31, 2010. Under this proposal, monthly bills for Met-Ed’s customers would increase approximately 9.4% for the period June 2009 through May 2010.
On October 15, 2008, the Governor of Pennsylvania signed House Bill 2200 into law whichAct 129 became effective on November 14,in 2008 as Act 129 of 2008. The billand addresses issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart metersmeters; and alternative energy. Among other things Act 129 requiresrequired utilities to file with the PPUC an energy efficiency and peak load reduction plan, or EE&C Plan, by July 1, 2009, setting forth the utilities’ plans to reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of 4.5% by May 31, 2013. On July 1, 2009, Met-Ed, Penelec, and Penn filed EE&C Plans with the PPUC in accordance with Act 129. The Pennsylvania Companies submitted a supplemental filing on July 31, 2009, to revise the Total Resource Cost test items in the EE&C Plans pursuant to the PPUC’s June 23, 2009 Order. Following evidentiary hearings and further revisions to the EE&C Plans, the Pennsylvania Companies filed final plans and tariff revisions on February 5, 2010 consistent with the minor revisions required by the PPUC. The PPUC entered an Order on February 26, 2010 approving the final plans and the tariff rider with rates effective March 1, 2010.
Act 129 also required utilities to file by August 14, 2009 with the PPUC smart meter technology procurement and installation plan byto provide for the installation of smart meter technology within 15 years. On August 14, 2009.2009, Met-Ed, Penelec and Penn jointly filed a Smart Meter Technology Procurement and Installation Plan. Consistent with the PPUC’s rules, this plan proposes a 24-month assessment period in which the Pennsylvania Companies will assess their needs, select the necessary technology, secure vendors, train personnel, install and test support equipment, and establish a cost effective and strategic deployment schedule, which currently is expected to be completed in fifteen years. Met-Ed, Penelec and Penn estimate assessment period costs at approximately $29.5 million, which the Pennsylvania Companies, in their plan, proposed to recover through an automatic adjustment clause. An Initial Decision was issued by the presiding ALJ on January 28, 2010. The ALJ’s Initial Decision approved the Smart Meter Plan as modified by the ALJ, including: ensuring that the smart meters to be deployed include the capabilities listed in the PPUC’s Implementation Order; eliminating the provision of interest in the 1307(e) reconciliation; providing for the recovery of reasonable and prudent costs minus resulting savings from installation and use of smart meters; and reflecting that administrative start-up costs be expensed and the costs incurred for research and development in the assessment period be capitalized. On JanuaryApril 15, 2009, in compliance with Act 129,2010, the PPUC adopted a Motion by Chairman Cawley that modified the ALJ’s initial decision issued its proposed guidelineson January 28, 2010, and decided various issues regarding the Smart Meter Implementation Plan (SMIP) for the filing of utilities’ energy efficiency and peak load reduction plans. Similar guidelines related toPennsylvania Companies. An order consistent with Chairman Cawley’s Motion is anticipated t o be entered in the near future, in which event the Pennsylvania Companies will move forward with the Smart Meter deployment were issued for comment on March 30, 2009.Technology Procurement and Installation Plan.
Major provisions of the legislation include:
· | power acquired by utilities to serve customers after rate caps expire will be procured through a competitive procurement process that must include a mix of long-term and short-term contracts and spot market purchases; |
· | the competitive procurement process must be approved by the PPUC and may include auctions, RFPs, and/or bilateral agreements; |
· | utilities must provide for the installation of smart meter technology within 15 years; |
· | a minimum reduction in peak demand of 4.5% by May 31, 2013; |
· | minimum reductions in energy consumption of 1% and 3% by May 31, 2011 and May 31, 2013, respectively; and |
· | an expanded definition of alternative energy to include additional types of hydroelectric and biomass facilities. |
Legislation addressing rate mitigation and the expiration of rate caps was not enactedintroduced in the legislative session that ended in 2008; however, several bills addressing these issues have beenwere introduced in the current2009 legislative session, which began in January 2009.session. The final form and impact of such legislation is uncertain.
On February 26, 2009, the PPUC approved a Voluntary Prepayment Pan requested by Met-Ed and Penelec that provides an opportunity for residential and small commercial customers to prepay an amount on their monthly electric bills during 2009 and 2010. Customer prepayments earn interest at 7.5% and will be used to reduce electricity charges in 2011 and 2012.
On February 20, 2009, Met-Ed and Penelec filed with the PPUC a generation procurement plan covering the period January 1, 2011 through May 31, 2013. The companies’ plan is designed to provide adequate and reliable service via a prudent mix of long-term, short-term and spot market generation supply, as required by Act 129. The plan proposes a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. Met-Ed and Penelec have requested PPUC approval of their plan by November 2009.
On March 31, 2009, Met-Ed and Penelec submitted their 5-year NUG Statement Compliance Filingfiling to the PPUC in accordance with their 1998 Restructuring Settlement. Met-Ed proposed to reduce its CTC rate for the residential class with a corresponding increase in the generation rate and the shopping credit, and Penelec proposed to reduce its CTC rate to zero for all classes with a corresponding increase in the generation rate and the shopping credit. While these changes would result in additional annual generation revenue (Met-Ed - $27 million and Penelec - $51$59 million), overall rates would remain unchanged. On July 30, 2009, the PPUC entered an order approving the 5-year NUG Statement, approving the reduction of the CTC, and directing Met-Ed and Penelec to file a tariff supplement implementing this change. On July 31, 2009, Met-Ed and Penelec filed t ariff supplements decreasing the CTC rate in compliance with the July 30, 2009 order, and increasing the generation rate in compliance with the Pennsylvania Companies’ Restructuring Orders of 1998. On August 14, 2009, the PPUC issued Secretarial Letters approving Met-Ed and Penelec’s compliance filings.
By Tentative Order entered September 17, 2009, the PPUC provided for an additional 30-day comment period on whether “the Restructuring Settlement allows NUG over-collection for select and isolated months to be used to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists.” In response to the Tentative Order, the Office of Small Business Advocate, Office of Consumer Advocate, York County Solid Waste and Refuse Authority, ARIPPA, the Met-Ed Industrial Users Group and Penelec Industrial Customer Alliance filed comments objecting to the above accounting method utilized by Met-Ed and Penelec. Met-Ed and Penelec filed reply comments on October 26, 2009. On November 5, 2009, the PPUC issued a Secretarial Letter allowing parties to file reply comments to Met-Ed and Penelec’s rep ly comments by November 16, 2009, and reply comments were filed by the Office of Consumer Advocate, ARIPPA, and the Met-Ed Industrial Users Group and Penelec Industrial Customer Alliance. Met-Ed and Penelec are awaiting further action by the PPUC.
On February 8, 2010, Penn filed with the PPUC a generation procurement plan covering the period June 1, 2011 through May 31, 2013. The plan is designed to provide adequate and reliable service via a prudent mix of long-term, short-term and spot market generation supply, as required by Act 129. The plan proposed a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. A preliminary conference was held on March 26, 2010, and, among other things, established a procedural schedule. Evidentiary hearings are scheduled for June 15-16, 2010. The PPUC must actis required to issue an order on this filing within 120 days.the plan no later than November 8, 2010.
New Jersey (Applicable to JCP&L)(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, costs incurred under NUG agreements, and certain other stranded costs, exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of March 31, 2009,2010, the accumulated deferred cost balance totaled approximately $165$55 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 DPA 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 alsoal so submitted comments in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set. On March 13, 2009, JCP&L filed its annual SBC Petition with the NJBPU that includes a request for a reduction in the level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009. This matter is currently pending before the NJBPU.
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. Following public hearing and consideration of comments from interested parties, the NJBPU approved final regulations effective April 6, 2009. These regulations are not expected to materially impact JCP&L.
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.
The EMP was issued on October 22, 2008, establishing five 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; |
| · | meet 30% of the state’s electricity needs with renewable energy by 2020; |
| · | examine smart grid technology and develop additional cogeneration and other generation resources consistent with the state’s greenhouse gas targets; and |
| · | invest in innovative clean energy technologies and businesses to stimulate the industry’s growth in New Jersey. |
On January 28, 2009, the NJBPU adopted an order establishing the general process and contents of specific EMP plans that must be filed by December 31, 2009 by New Jersey electric and gas utilities in order to achieve the goals of the EMP. On April 16, 2010, the BPU issued an order indefinitely suspending the requirement of New Jersey utilities to submit Utility Master Plans until such time as the status of the EMP has been made clear. At this time, FirstEnergy and JCP&L cannot determine the impact, if any, the EMP may have on itstheir operations.
In support of theformer New Jersey Governor’sGovernor Corzine's Economic Assistance and Recovery Plan, JCP&L announced its intenta proposal to spend approximately $98 million on infrastructure and energy efficiency projects in 2009. AnUnder the proposal, an estimated $40 million willwould be spent on infrastructure projects, including substation upgrades, new transformers, distribution line re-closers and automated breaker operations. ApproximatelyIn addition, approximately $34 million willwould be spent implementing new demand response programs as well as expanding on existing programs. Another $11 million willwould be spent on energy efficiency, specifically replacing transformers and capacitor control systems and installing new LED street lights. The remaining $13 million willwould be spent on energy efficiency programs that willwould complement those currently being offered. CompletionThe project relating to expansion of the existing demand response programs was approved by the NJBPU on August 19, 2009, and implementation began in 2009. Approval for the project related to energy efficiency programs intended to complement those currently being offered was denied by the NJBPU on December 1, 2009. Implementation of the remaining projects is dependent upon resolution of regulatory issues including recovery of the costs associated with plan implementation.the proposal.
FERC Matters (ApplicableOn February 11, 2010, S&P downgraded the senior unsecured debt of FirstEnergy Corp. to FES and eachBB+. As a result, pursuant to the requirements of a pre-existing NJBPU order, JCP&L filed, on February 17, a plan addressing the mitigation of any effect of the Utilities)downgrade and which provided an assessment of present and future liquidity necessary to assure JCP&L’s continued payment to BGS suppliers. The NJBPU subsequently held a public hearing to review the plan and available options. On March 17, 2010, the NJBPU determined that JCP&L demonstrated that it has ample resources available to continue uninterrupted payments to BGS suppliers and that there are no concerns with JCP&L's liquidity and therefore no further action is required.
(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 multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered 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 subjectsubj ect 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 is pending before the FERC, and in the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of lower transmission revenue collection associated with an adverse order. On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision. On November 20, 2008, FERC issued an order approving uncontested settlements, but did not rule on the initial decision. On December 19, 2008, an additional order was issued approving two contested settlements. On October 29, 2009, March 17, 2010 and April 8, 2010, FirstEnergy, filed additional settlement agreements with FERC to resolve outstanding claims with various parties. FirstEnergy is actively pursuing settlement agreements with other parties to the case. On December 8, 2009, certain parties sought a writ of mandam us from the DC Circuit Court of Appeals directing FERC to issue an order on the Initial Decision. The Court agreed to hold this matter in abeyance based upon FERC’s representation to use good faith efforts to issue a substantive ruling on the initial decision no later than May 27, 2010. If FERC fails to act, the case will be submitted for briefing in June. The outcome of this matter cannot be predicted.
PJM Transmission Rate
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 on the content of the compliance filings and numerous parties appeared and litigated various issues concerning PJM rate design;design, notably AEP, which proposed to create a "postage stamp",stamp," or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. ThisAEP's proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones,zone s, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order (Opinion 494) 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 reasonablerea sonable cost allocation methodology for inclusion in PJM’s tariff.
On May 18, 2007, certain parties filed for rehearing of theThe FERC’s April 19, 2007 order. On January 31, 2008, the requestsorder and a related order denying a request for rehearing were denied. On February 11, 2008, AEP appealed the FERC’s April 19, 2007, and January 31, 2008, 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. Oral argument was held on April 13, 2009, and a decision is expected this summer.
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 the costs of future transmission to be recovered 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 to the FERC. On July 29, 2008, the FERC issued an order conditionally approving the settlement subject to the submission of a compliance filing. The compliance filing was submitted on August 29, 2008, and the FERC issued an order accepting the compliance filing on October 15, 2008. On November 14, 2008, PJM submitted revisions to its tariff to incorporate cost responsibility assignments for below 500 kV upgrades included in PJM’s Regional Transmission Expansion Planning process in accordance with the settlement. The FERC conditionally accepted the compliance filing on January 28, 2009. PJM submitted a further compliance filing on March 2, 2009, which was accepted by the FERC on April 10, 2009. The remaining merchant transmission cost allocation issues were the subject of a hearing at the FERC in May 2008. An initial decision was issued by the Presiding Judge on September 18, 2008. PJM and FERC trial staff each filed a Brief on Exceptions to the initial decision on October 20, 2008. Briefs Opposing Exceptions were filed on November 10, 2008.
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. The effect of this order is to prevent the shift of significant costs to the FirstEnergy zones in MISO and PJM. A rehearing request by AEP was denied by the FERC on December 19, 2008. On February 17, 2009, AEP appealed the FERC’s January 31, 2008, and December 19, 2008, orders to the U.S. Court of Appeals for the Seventh Circuit. FESC,Circuit, which issued a decision on behalf ofAugust 6, 2009. The court affirmed FERC’s ratemaking treatment for existing transmission facilities, but found that FERC had not supported its affiliated operating utilitydecision to allocate costs for new 500+ kV facilities on a postage-stamp basis and, based on this finding, remanded the rate design issue back to FERC. A request for rehearing and rehearing en banc by two companies filed a motion to intervenewas denied by the Seventh Circuit on March 10,October 20, 2009.
Duquesne’s RequestIn an order dated January 21, 2010, FERC set the matter for “paper hearings” – meaning that FERC called for parties to Withdraw fromsubmit comments or written testimony pursuant to the schedule described in the order. FERC identified nine separate issues for comments, and directed PJM to file the first round of comments on February 22, 2010, with other parties submitting responsive comments within 45 days, and reply comments 30 days later. PJM filed certain studies with FERC on April 13, 2010, in response to the FERC order. Interested parties may file responsive comments or studies by May 28, 2010. Reply comments are due by June 28, 2010.
RTO Consolidation
On November 8, 2007, Duquesne Light Company (Duquesne)August 17, 2009, FirstEnergy filed a requestan application with the FERC requesting to exitconsolidate its transmission assets and operations into PJM. Currently, FirstEnergy’s transmission assets and operations are divided between PJM and to join MISO. Duquesne’s proposed moveThe consolidation would affect numerous FirstEnergy interests, including but not limited tomake the terms under whichtransmission assets that are part of ATSI, whose footprint includes the Ohio Companies and Penn, part of PJM. Most of FirstEnergy’s Beaver Valley Plant would continue to participatetransmission assets in PJM’s energy markets. FirstEnergy, therefore, intervenedPennsylvania and participated fully in all of the FERC docketstransmission assets in New Jersey already operate as a part of PJM. Key elements of the filing include a Fixed Resource Requirement Plan (FRR Plan) that describes the means whereby capacity will be procured and administered as necessary to satisfy the PJM capacity requirements for the 2011-12 and 2012-13 delivery years; and also a request that ATSI’s transmission customers be excused f rom the costs for regional transmission projects that were approved through PJM’s RTEP process prior to ATSI’s entry into PJM (legacy RTEP costs). The integration is expected to be complete on June 1, 2011, to coincide with delivery of power under the next competitive generation procurement process for the Ohio Companies. To ensure a definitive ruling at the same time the FERC rules on its request to integrate ATSI into PJM, on October 19, 2009, FirstEnergy filed a related to Duquesne’s proposed move.complaint with the FERC on the issue of exempting the ATSI footprint from the legacy RTEP costs.
In November, 2008, DuquesneOn September 4, 2009, the PUCO opened a case to take comments from Ohio’s stakeholders regarding the RTO consolidation. FirstEnergy filed extensive comments in the PUCO case on September 25, 2009, and otherreply comments on October 13, 2009, and attended a public meeting on September 15, 2009 to answer questions regarding the RTO consolidation. Several parties have intervened in the regulatory dockets at the FERC and at the PUCO. Certain interveners have commented and protested particular elements of the proposed RTO consolidation, including FirstEnergy, negotiated a settlement that would, among other things, allow for Duquesnean exit fee to remainMISO, integration costs to PJM, and cost-allocations of future transmission upgrades in PJM and provide for a methodology for Duquesne to meet the PJM capacity obligations for the 2011-2012 auction that excluded the Duquesne load. The settlement agreement was filed onMISO.
On December 10, 2008 and approved by the17, 2009, FERC inissued an order issued on January 29, 2009. MISO opposed the settlement agreement pending resolution of exit fees allegedapproving, subject to certain future compliance filings, ATSI’s move to PJM. FirstEnergy’s request to be owed by Duquesne. The FERC did not resolve the exit fee issue inexempted from legacy RTEP costs was rejected and its order. On March 2, 2009, the PPUC filed for rehearing of the FERC's January 29, 2009 order approving the settlement. Thereafter, FirstEnergy and other parties filed in opposition to the rehearing request. The PPUC's rehearing request, and the pleadings in opposition thereto, are pending before the FERC.
complaint dismissed.
On December 17, 2009, ATSI executed the PJM Consolidated Transmission Owners Agreement. On December 18, 2009, the Ohio Companies and Penn executed the PJM Operating Agreement and the PJM Reliability Assurance Agreement. Execution of these agreements committed ATSI and the Ohio Companies and Penn’s load to moving into PJM on the schedule described in the application and approved in the FERC Order (June 1, 2011).
On January 15, 2010, the Ohio Companies and Penn submitted a compliance filing describing the process whereby ATSI-zone load serving entities (LSEs) can “opt out” of the Ohio Companies' and Penn's FRR Plan for the 2011-12 and 2012-13 delivery years. On January 16, 2010, FirstEnergy filed for clarification or rehearing of certain issues associated with implementing the FRR auctions on the proposed schedule. On January 19, 2010, FirstEnergy filed for rehearing of FERC’s decision to impose the legacy RTEP costs on ATSI’s transmission customers. Also on January 19, 2010, several parties, including the PUCO and the OCC asked for rehearing of parts of FERC’s order. None of the rehearing parties asked FERC to rescind authorization for ATSI to enter PJM. Instead, parties focused on questions of cost and cost allocation or on alleged errors in implementing the move. On February 3, 2010, FirstEnergy filed an answer to the January 19, 2010 rehearing requests of other parties. On February 16, 2010, FirstEnergy submitted a second compliance filing to FERC; the filing describes communications protocols and performance deficiency penalties for capacity suppliers that are taken in FRR auctions.
On March 10, 2010, FERC granted FirstEnergy’s request for expedited hearing on the conduct of the FRR auctions. The Ohio Companies and Penn obtained their PJM capacity requirements for the 2011 and 2012 delivery years in the FRR auctions conducted March 15-19, 2010. The PJM market monitor certified the FRR auction results on March 25, 2010, and the auction results were released by PJM on March 26, 2010. On March 29, 2010, the Ohio Companies and Penn signed agreements with all winning suppliers. In May 2010, the Ohio Companies and Penn’s load will be included in the PJM Base Residual Auction for the delivery year beginning 2013. FirstEnergy and unaffiliated generation and loads in the ATSI footprint are also expected to participate in the Base Residual Auction. FirstEnergy expects to integrate into PJM effective June 1, 2011.
Changes ordered for PJM Reliability Pricing Model (RPM) Auction
On May 30, 2008, a group of PJM load-serving entities, state commissions, consumer advocates, and trade associations (referred to collectively as the RPM Buyers) filed a complaint at the FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the Federal Power Act.FPA. On September 19, 2008, the FERC denied the RPM Buyers’ complaint. However, the FERC did grant the RPM Buyers’ request for a technical conference to review aspects of the RPM. The FERC also ordered PJM to file on or before December 15, 2008, a report on potential adjustments to the RPM program as suggested in a Brattle Group report. On December 12, 2008, PJM filed proposed tariff amendments that would adjust slightly the RPM program. PJM also requested that the FERC conduct a settlement hearing to address changes to the RPM and suggested that the FERC should rule on the tariff amendments only if settlement could not be reached in January 2009. The request for settlement hearings was granted. Settlement had not been reached by January 9, 2009 and, accordingly, FirstEnergyF irstEnergy and other parties submitted comments on PJM’s proposed tariff amendments. On January 15, 2009, the Chief Judge issued an order terminating settlement talks.discussions. On February 9, 2009, PJM and a group of stakeholders submitted an offer of settlement, which used the PJM December 12, 2008 filing as its starting point, and stated that unless otherwise specified, provisions filed by PJM on December 12, 2008 apply.
On March 26, 2009, the FERC accepted in part, and rejected in part, tariff provisions submitted by PJM, revising certain parts of its RPM. OrderedIt ordered changes included making incremental improvements to RPM; however, the basic construct of RPM remains intact. On April 3, 2009, PJM filed with the FERC requestingand clarification on certain aspects of the March 26, 2009 Order. On April 27, 2009, PJM submitted a compliance filing addressing the changes the FERC ordered in the March 26, 2009 Order; subsequently, numerous parties have filed requests for rehearing of the March 26, 2009 Order. In addition,On June 18, 2009, the FERC has indefinitely postponeddenied rehearing and request for oral argument of the technical conference on RPM granted in the FERC order of September 19, 2008.March 26, 2009 Order.
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 believes the proposal promotes a mechanism that will result in 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 submitted on January 28, 2008. The FERC conditionally approved MISO’s Resource Adequacy proposal on March 26, 2008, requiring MISO to submit to further compliance filings. Rehearing requests are pending on the FERC’s March 26 Order. On May 27, 2008, MISO submitted a compliance filing to address issues associated with planning reserve margins. On June 17, 2008, various parties submitted comments and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific issues that must be clarified and addressed. On June 25, 2008, MISO submitted a second compliance filing establishing the enforcement mechanism for the reserve margin requirement which establishes deficiency payments for load-serving entities that do not meet the resource adequacy requirements. Numerous parties, including FirstEnergy, protested this filing.Complaints Versus PJM
On October 20, 2008, theMarch 9, 2010, MISO filed two complaints against PJM with FERC issued three orders essentially permitting the MISO Resource Adequacy program to proceed with some modifications. First, the FERC accepted MISO's financial settlement approach for enforcement of Resource Adequacy subject to a compliance filing modifying the cost of new entry penalty. Second, the FERC conditionally accepted MISO's compliance filing on the qualifications for purchased power agreements to be capacity resources, load forecasting, loss of load expectation,under Sections 206, 306, and planning reserve zones. Additional compliance filings were directed on accreditation of load modifying resources and price responsive demand. Finally, the FERC largely denied rehearing of its March 26 order with the exception of issues related to behind the meter resources and certain ministerial matters. On November 19, 2008, MISO made various compliance filings pursuant to these orders. Issuance of orders on rehearing and two309 of the compliance filings occurred on February 19, 2009. No material changes wereFPA alleging violations of the MISO/PJM Joint Operating Agreement (JOA). In the first complaint, MISO alleged that by failing to account for the market flows from 34 PJM generators over the period from 2007-2009, PJM underpaid MISO by a total of roughly $75 million including interest. For the period from 2005-2007, MISO claimed an underpayment by PJM of at least $12 million plus interest. MISO also claimed that PJM failed to maintain required records necessary to calculate underbilling for the 2005-2007 billing.
In the second complaint, MISO alleged that PJM has refused to comply with provisions of the JOA requiring market-to-market dispatch since 2009, and is improperly demanding repayment of redispatch payments previously made to MISO’s Resource Adequacy program. On April 16, 2009, the FERC issued an additional order on rehearing and compliance, approving MISO’s proposed financial settlement provision for Resource Adequacy. The MISO Resource Adequacy process is expected to start as planned effective June 1, 2009, the beginning of the MISO planning year.MISO.
FES Sales to Affiliates
On October 24, 2008, FES, on its own behalf and on behalf of its generation-controlling subsidiaries, filed an application with the FERC seeking a waiver of the affiliate sales restrictions between FES and the Ohio Companies. The purpose of the waiver is to ensure that FES will be able to continue supplying a material portion of the electric load requirements of the Ohio Companies after January 1, 2009 pursuant to either an ESP or MRO as filed with the PUCO. FES previously obtained a similar waiver for electricity sales to its affiliates in New Jersey, New York, and Pennsylvania. On December 23, 2008, the FERC issued an order granting the waiver request and the Ohio Companies made the required compliance filing on December 30, 2008. In January 2009, several parties filed for rehearing of the FERC’s December 23, 2008 order. In response, FES filed an answer to requests for rehearing on February 5, 2009. The requests and responses are pending before the FERC.
PJM filed its answers to the complaints on April 12, 2010, opposing the relief sought by MISO. In addition, on April 12, 2010, PJM filed a complaint with FERC pursuant to Section 206, 306, and 309 alleging that MISO is violating the JOA with PJM by initiating market-to-market coordination and financial settlements for substitute (proxy) reciprocal coordinated flowgates between MISO and PJM. PJM claims that the JOA does not permit MISO to initiate market-to-market settlements using proxy flowgates in lieu of designated reciprocal coordinated flowgates. This complaint addresses substantially the same issues as the second MISO complaint, in which MISO argues that the use of proxy flowgates is permitted by agreement of the RTOs and operating practice. Each party filed a complaint in order to ensure their right to claim refunds, if any, if successful in their arguments at FERC.
FirstEnergy has intervened in all three proceedings, and timely filed comments supporting MISO in its first complaint, relating to improper accounting of market flows resulting in underpayments from 2005-2009. FirstEnergy is unable to predict the outcome of this matter.
10. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
In 2010, the FASB amended the Derivatives and Hedging Topic of the FASB Accounting Standards Codification to clarify the scope exception for embedded credit derivative features related to the transfer of credit risk in the form of subordination of one financial instrument to another. The amendment addresses how to determine which embedded credit derivative features, including those in collateralized debt obligations and synthetic collateralized debt obligations, are considered to be embedded derivatives that should not be analyzed under the Derivatives and Hedging Topic for potential bifurcation and separate accounting. The amendment is effective for the first fiscal quarter beginning after June 15, 2010. FirstEnergy does not expect this standard to have a material effect on its financial statements.
11. SEGMENT INFORMATION
Financial information for each of FirstEnergy’s reportable segments is presented in the following table. FES suppliedand the Utilities do not have separate reportable operating segments. With the completion of transition to a fully competitive generation market in Ohio in the fourth quarter of 2009, the former Ohio Transitional Generation Services segment was combined with the Energy Delivery Services segment, consistent with how management views the business. Disclosures for FirstEnergy’s operating segments for 2009 have been reclassified to conform to the current presentation.
The energy delivery services segment 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 Ohio, Pennsylvania and New Jersey. Its revenues are primarily derived from the delivery of electricity within FirstEnergy’s service areas, 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 Ohio, Pennsylvania and New Jersey franchise areas. Its results reflect the commodity costs of securing electric generation from FES and from non-affiliated power suppliers, the net PJM and MISO transmission expenses related to the deliver y of the respective generation loads, and the deferral and amortization of certain fuel costs.
The competitive energy services segment supplies electric power to 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 13,710 MWs and also purchases electricity to meet sales obligations. The segment's net income is primarily derived from affiliated and 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 MI SO to deliver energy to the segment’s customers.
The other segment contains corporate items and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment.
| Segment Financial Information | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | Energy | | | Competitive | | | | | | | | | | |
| | | | Delivery | | | Energy | | | | | | Reconciling | | | | |
| Three Months Ended | | Services | | | Services | | | Other | | | Adjustments | | | Consolidated | |
| | | | (In millions) | |
| March 31, 2010 | | | | | | | | | | | | | | | |
| External revenues | | $ | 2,543 | | | $ | 716 | | | $ | 4 | | | $ | (31 | ) | | $ | 3,232 | |
| Internal revenues | | | - | | | | 674 | | | | - | | | | (607 | ) | | | 67 | |
| | Total revenues | | | 2,543 | | | | 1,390 | | | | 4 | | | | (638 | ) | | | 3,299 | |
| Depreciation and amortization | | | 325 | | | | 66 | | | | 13 | | | | 1 | | | | 405 | |
| Investment income (loss), net | | | 25 | | | | 1 | | | | - | | | | (10 | ) | | | 16 | |
| Net interest charges | | | 123 | | | | 33 | | | | (1 | ) | | | 17 | | | | 172 | |
| Income taxes | | | 69 | | | | 47 | | | | 4 | | | | (9 | ) | | | 111 | |
| Net income (loss) | | | 114 | | | | 76 | | | | (15 | ) | | | (26 | ) | | | 149 | |
| Total assets | | | 22,530 | | | | 10,948 | | | | 605 | | | | (5 | ) | | | 34,078 | |
| Total goodwill | | | 5,551 | | | | 24 | | | | - | | | | - | | | | 5,575 | |
| Property additions | | | 166 | | | | 323 | | | | 3 | | | | 16 | | | | 508 | |
| | | | | | | | | | | | | | | | | | | | | | |
| March 31, 2009 | | | | | | | | | | | | | | | | | | | | |
| External revenues | | $ | 3,021 | | | $ | 335 | | | $ | 7 | | | $ | (29 | ) | | $ | 3,334 | |
| Internal revenues | | | - | | | | 893 | | | | - | | | | (893 | ) | | | - | |
| | Total revenues | | | 3,021 | | | | 1,228 | | | | 7 | | | | (922 | ) | | | 3,334 | |
| Depreciation and amortization | | | 427 | | | | 64 | | | | 1 | | | | 3 | | | | 495 | |
| Investment income (loss), net | | | 30 | | | | (29 | ) | | | - | | | | (12 | ) | | | (11 | ) |
| Net interest charges | | | 109 | | | | 18 | | | | 1 | | | | 38 | | | | 166 | |
| Income taxes | | | (12 | ) | | | 103 | | | | (17 | ) | | | (20 | ) | | | 54 | |
| Net income | | | (18 | ) | | | 155 | | | | 17 | | | | (39 | ) | | | 115 | |
| Total assets | | | 23,005 | | | | 9,925 | | | | 632 | | | | (5 | ) | | | 33,557 | |
| Total goodwill | | | 5,550 | | | | 24 | | | | - | | | | - | | | | 5,574 | |
| Property additions | | | 165 | | | | 421 | | | | 49 | | | | 19 | | | | 654 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| * | Under the accounting standard for the effects of certain types of regulation, internal revenues are not fully offset for | |
| | sales of RECs by FES to the Ohio Companies that are retained in inventory. | | | | | | | | | |
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.
12. 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 fully, 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. This transaction is classified as an operating lease under GAAP for FES and FirstEnergy and as a financing for FGCO.
The condensed consolidating statements of income for the three-months ended March 31, 2010 and 2009, consolidating balance sheets as of March 31, 2010 and December 31, 2009 and consolidating statements of cash flows for the three months ended March 31, 2010 and 2009 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 the entries required to reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transac tion.
| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | | |
| CONDENSED CONSOLIDATING STATEMENTS OF INCOME | |
| (Unaudited) | |
| | | | | | | | | | | | | | | | |
| For the Three Months Ended March 31, 2010 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| | | | | | | | | | | | | | | | |
| REVENUES | | $ | 1,367,025 | | | $ | 568,364 | | | $ | 426,320 | | | $ | (973,616 | ) | | $ | 1,388,093 | |
| | | | | | | | | | | | | | | | | | | | | |
| EXPENSES: | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | 5,097 | | | | 280,863 | | | | 42,261 | | | | - | | | | 328,221 | |
| Purchased power from affiliates | | | 968,537 | | | | 5,079 | | | | 60,953 | | | | (973,616 | ) | | | 60,953 | |
| Purchased power from non-affiliates | | | 450,215 | | | | - | | | | - | | | | - | | | | 450,215 | |
| Other operating expenses | | | 53,126 | | | | 99,776 | | | | 139,420 | | | | 12,189 | | | | 304,511 | |
| Provision for depreciation | | | 790 | | | | 26,527 | | | | 36,910 | | | | (1,309 | ) | | | 62,918 | |
| General taxes | | | 5,498 | | | | 14,600 | | | | 6,648 | | | | - | | | | 26,746 | |
| Total expenses | | | 1,483,263 | | | | 426,845 | | | | 286,192 | | | | (962,736 | ) | | | 1,233,564 | |
| | | | | | | | | | | | | | | | | | | | | |
| OPERATING INCOME (LOSS) | | | (116,238 | ) | | | 141,519 | | | | 140,128 | | | | (10,880 | ) | | | 154,529 | |
| | | | | | | | | | | | | | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | |
| Investment income | | | 1,897 | | | | 54 | | | | (1,234 | ) | | | - | | | | 717 | |
| Miscellaneous income (expense), including | | | | | | | | | | | | | | | | | |
| net income from equity investees | | | 166,373 | | | | (1,633 | ) | | | (101 | ) | | | (163,329 | ) | | | 1,310 | |
| Interest expense to affiliates | | | (58 | ) | | | (1,812 | ) | | | (435 | ) | | | - | | | | (2,305 | ) |
| Interest expense - other | | | (23,373 | ) | | | (26,506 | ) | | | (15,763 | ) | | | 15,998 | | | | (49,644 | ) |
| Capitalized interest | | | 100 | | | | 16,333 | | | | 3,257 | | | | - | | | | 19,690 | |
| Total other income (expense) | | | 144,939 | | | | (13,564 | ) | | | (14,276 | ) | | | (147,331 | ) | | | (30,232 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 28,701 | | | | 127,955 | | | | 125,852 | | | | (158,211 | ) | | | 124,297 | |
| | | | | | | | | | | | | | | | | | | | | |
| INCOME TAXES (BENEFITS) | | | (51,225 | ) | | | 48,043 | | | | 45,013 | | | | 2,540 | | | | 44,371 | |
| | | | | | | | | | | | | | | | | | | | | |
| NET INCOME | | $ | 79,926 | | | $ | 79,912 | | | $ | 80,839 | | | $ | (160,751 | ) | | $ | 79,926 | |
| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | | |
| CONDENSED CONSOLIDATING STATEMENTS OF INCOME | |
| (Unaudited) | |
| | | | | | | | | | | | | | | | |
| For the Three Months Ended March 31, 2009 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| | | | | | | | | | | | | | | | |
| REVENUES | | $ | 1,201,895 | | | $ | 545,926 | | | $ | 395,628 | | | $ | (917,343 | ) | | $ | 1,226,106 | |
| | | | | | | | | | | | | | | | | | | | | |
| EXPENSES: | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | 2,095 | | | | 274,847 | | | | 29,216 | | | | - | | | | 306,158 | |
| Purchased power from affiliates | | | 915,261 | | | | 2,082 | | | | 63,207 | | | | (917,343 | ) | | | 63,207 | |
| Purchased power from non-affiliates | | | 160,342 | | | | - | | | | - | | | | - | | | | 160,342 | |
| Other operating expenses | | | 38,267 | | | | 104,443 | | | | 152,456 | | | | 12,190 | | | | 307,356 | |
| Provision for depreciation | | | 1,019 | | | | 30,020 | | | | 31,649 | | | | (1,315 | ) | | | 61,373 | |
| General taxes | | | 4,706 | | | | 12,626 | | | | 6,044 | | | | - | | | | 23,376 | |
| Total expenses | | | 1,121,690 | | | | 424,018 | | | | 282,572 | | | | (906,468 | ) | | | 921,812 | |
| | | | | | | | | | | | | | | | | | | | | |
| OPERATING INCOME | | | 80,205 | | | | 121,908 | | | | 113,056 | | | | (10,875 | ) | | | 304,294 | |
| | | | | | | | | | | | | | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | |
| Investment income (loss) | | | 732 | | | | 31 | | | | (29,637 | ) | | | - | | | | (28,874 | ) |
| Miscellaneous income (expense), including | | | | | | | | | | | | | | | | | | | | �� |
| net income from equity investees | | | 119,781 | | | | (78 | ) | | | - | | | | (117,192 | ) | | | 2,511 | |
| Interest expense to affiliates | | | (34 | ) | | | (1,758 | ) | | | (1,187 | ) | | | - | | | | (2,979 | ) |
| Interest expense - other | | | (2,520 | ) | | | (21,058 | ) | | | (15,168 | ) | | | 16,219 | | | | (22,527 | ) |
| Capitalized interest | | | 51 | | | | 7,750 | | | | 2,277 | | | | - | | | | 10,078 | |
| Total other income (expense) | | | 118,010 | | | | (15,113 | ) | | | (43,715 | ) | | | (100,973 | ) | | | (41,791 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 198,215 | | | | 106,795 | | | | 69,341 | | | | (111,848 | ) | | | 262,503 | |
| | | | | | | | | | | | | | | | | | | | | |
| INCOME TAXES | | | 27,534 | | | | 39,142 | | | | 22,929 | | | | 2,217 | | | | 91,822 | |
| | | | | | | | | | | | | | | | | | | | | |
| NET INCOME | | $ | 170,681 | | | $ | 67,653 | | | $ | 46,412 | | | $ | (114,065 | ) | | $ | 170,681 | |
| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | | |
| CONDENSED CONSOLIDATING BALANCE SHEETS | |
| (Unaudited) | |
| | | | | | | | | | | | | | | | |
| As of March 31, 2010 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| ASSETS | | | | | | | | | | | | | | | |
| CURRENT ASSETS: | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | - | | | $ | 2 | | | $ | 9 | | | $ | - | | | $ | 11 | |
| Receivables- | | | | | | | | | | | | | | | | | | | | |
| Customers | | | 248,994 | | | | - | | | | - | | | | - | | | | 248,994 | |
| Associated companies | | | 408,743 | | | | 199,145 | | | | 129,194 | | | | (376,278 | ) | | | 360,804 | |
| Other | | | 18,732 | | | | 12,856 | | | | 50,071 | | | | - | | | | 81,659 | |
| Notes receivable from associated companies | | | 165,496 | | | | 209,604 | | | | 108,323 | | | | - | | | | 483,423 | |
| Materials and supplies, at average cost | | | 16,698 | | | | 327,011 | | | | 215,042 | | | | - | | | | 558,751 | |
| Prepayments and other | | | 147,780 | | | | 8,234 | | | | 4,654 | | | | - | | | | 160,668 | |
| | | | 1,006,443 | | | | 756,852 | | | | 507,293 | | | | (376,278 | ) | | | 1,894,310 | |
| | | | | | | | | | | | | | | | | | | | | |
| PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | | | | | | | | | | | | |
| In service | | | 91,365 | | | | 5,473,440 | | | | 5,189,224 | | | | (386,022 | ) | | | 10,368,007 | |
| Less - Accumulated provision for depreciation | | | 15,030 | | | | 2,802,155 | | | | 1,973,499 | | | | (172,820 | ) | | | 4,617,864 | |
| | | | 76,335 | | | | 2,671,285 | | | | 3,215,725 | | | | (213,202 | ) | | | 5,750,143 | |
| Construction work in progress | | | 7,836 | | | | 2,110,754 | | | | 479,040 | | | | - | | | | 2,597,630 | |
| | | | 84,171 | | | | 4,782,039 | | | | 3,694,765 | | | | (213,202 | ) | | | 8,347,773 | |
| | | | | | | | | | | | | | | | | | | | | |
| INVESTMENTS: | | | | | | | | | | | | | | | | | | | | |
| Nuclear plant decommissioning trusts | | | - | | | | - | | | | 1,091,114 | | | | - | | | | 1,091,114 | |
| Investment in associated companies | | | 4,637,194 | | | | - | | | | - | | | | (4,637,194 | ) | | | - | |
| Other | | | 957 | | | | 7,367 | | | | 201 | | | | - | | | | 8,525 | |
| | | | 4,638,151 | | | | 7,367 | | | | 1,091,315 | | | | (4,637,194 | ) | | | 1,099,639 | |
| | | | | | | | | | | | | | | | | | | | | |
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | | | | | | | | | | | |
| Accumulated deferred income taxes | | | 88,618 | | | | 379,772 | | | | - | | | | (401,928 | ) | | | 66,462 | |
| Goodwill | | | 24,248 | | | | - | | | | - | | | | - | | | | 24,248 | |
| Customer intangibles | | | 114,567 | | | | - | | | | - | | | | - | | | | 114,567 | |
| Property taxes | | | - | | | | 27,811 | | | | 22,314 | | | | - | | | | 50,125 | |
| Unamortized sale and leaseback costs | | | - | | | | 29,968 | | | | - | | | | 60,835 | | | | 90,803 | |
| Other | | | 80,182 | | | | 71,044 | | | | 9,188 | | | | (50,920 | ) | | | 109,494 | |
| | | | 307,615 | | | | 508,595 | | | | 31,502 | | | | (392,013 | ) | | | 455,699 | |
| | | $ | 6,036,380 | | | $ | 6,054,853 | | | $ | 5,324,875 | | | $ | (5,618,687 | ) | | $ | 11,797,421 | |
| | | | | | | | | | | | | | | | | | | | | |
| LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
| Currently payable long-term debt | | $ | 745 | | | $ | 696,416 | | | $ | 922,663 | | | $ | (18,640 | ) | | $ | 1,601,184 | |
| Short-term borrowings- | | | | | | | | | | | | | | | | | | | | |
| Other | | | 100,000 | | | | - | | | | - | | | | - | | | | 100,000 | |
| Accounts payable- | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 325,118 | | | | 194,950 | | | | 190,103 | | | | (324,920 | ) | | | 385,251 | |
| Other | | | 116,942 | | | | 153,515 | | | | - | | | | - | | | | 270,457 | |
| Accrued taxes | | | 7,719 | | | | 72,449 | | | | 48,798 | | | | (62,381 | ) | | | 66,585 | |
| Other | | | 213,488 | | | | 105,682 | | | | 27,798 | | | | 46,544 | | | | 393,512 | |
| | | | 764,012 | | | | 1,223,012 | | | | 1,189,362 | | | | (359,397 | ) | | | 2,816,989 | |
| | | | | | | | | | | | | | | | | | | | | |
| CAPITALIZATION: | | | | | | | | | | | | | | | | | | | | |
| Common stockholder's equity | | | 3,589,580 | | | | 2,419,526 | | | | 2,203,491 | | | | (4,623,017 | ) | | | 3,589,580 | |
| Long-term debt and other long-term obligations | | | 1,519,155 | | | | 1,855,784 | | | | 554,591 | | | | (1,269,330 | ) | | | 2,660,200 | |
| | | | 5,108,735 | | | | 4,275,310 | | | | 2,758,082 | | | | (5,892,347 | ) | | | 6,249,780 | |
| | | | | | | | | | | | | | | | | | | | | |
| NONCURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
| Deferred gain on sale and leaseback transaction | | | - | | | | - | | | | - | | | | 984,440 | | | | 984,440 | |
| Accumulated deferred income taxes | | | - | | | | - | | | | 351,383 | | | | (351,383 | ) | | | - | |
| Accumulated deferred investment tax credits | | | - | | | | 35,590 | | | | 21,763 | | | | - | | | | 57,353 | |
| Asset retirement obligations | | | - | | | | 25,933 | | | | 910,520 | | | | - | | | | 936,453 | |
| Retirement benefits | | | 35,114 | | | | 184,060 | | | | - | | | | - | | | | 219,174 | |
| Property taxes | | | - | | | | 27,811 | | | | 22,314 | | | | - | | | | 50,125 | |
| Lease market valuation liability | | | - | | | | 250,871 | | | | - | | | | - | | | | 250,871 | |
| Other | | | 128,519 | | | | 32,266 | | | | 71,451 | | | | - | | | | 232,236 | |
| | | | 163,633 | | | | 556,531 | | | | 1,377,431 | | | | 633,057 | | | | 2,730,652 | |
| | | $ | 6,036,380 | | | $ | 6,054,853 | | | $ | 5,324,875 | | | $ | (5,618,687 | ) | | $ | 11,797,421 | |
| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | | |
| CONDENSED CONSOLIDATING BALANCE SHEETS | |
| (Unaudited) | |
| | | | | | | | | | | | | | | | |
| As of December 31, 2009 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| ASSETS | | | | | | | | | | | | | | | |
| CURRENT ASSETS: | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | - | | | $ | 3 | | | $ | 9 | | | $ | - | | | $ | 12 | |
| Receivables- | | | | | | | | | | | | | | | | | | | | |
| Customers | | | 195,107 | | | | - | | | | - | | | | - | | | | 195,107 | |
| Associated companies | | | 305,298 | | | | 175,730 | | | | 134,841 | | | | (297,308 | ) | | | 318,561 | |
| Other | | | 28,394 | | | | 10,960 | | | | 12,518 | | | | - | | | | 51,872 | |
| Notes receivable from associated companies | | | 416,404 | | | | 240,836 | | | | 147,863 | | | | - | | | | 805,103 | |
| Materials and supplies, at average cost | | | 17,265 | | | | 307,079 | | | | 215,197 | | | | - | | | | 539,541 | |
| Prepayments and other | | | 80,025 | | | | 18,356 | | | | 9,401 | | | | - | | | | 107,782 | |
| | | | 1,042,493 | | | | 752,964 | | | | 519,829 | | | | (297,308 | ) | | | 2,017,978 | |
| | | | | | | | | | | | | | | | | | | | | |
| PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | | | | | | | | | | | | |
| In service | | | 90,474 | | | | 5,478,346 | | | | 5,174,835 | | | | (386,023 | ) | | | 10,357,632 | |
| Less - Accumulated provision for depreciation | | | 13,649 | | | | 2,778,320 | | | | 1,910,701 | | | | (171,512 | ) | | | 4,531,158 | |
| | | | 76,825 | | | | 2,700,026 | | | | 3,264,134 | | | | (214,511 | ) | | | 5,826,474 | |
| Construction work in progress | | | 6,032 | | | | 2,049,078 | | | | 368,336 | | | | - | | | | 2,423,446 | |
| | | | 82,857 | | | | 4,749,104 | | | | 3,632,470 | | | | (214,511 | ) | | | 8,249,920 | |
| | | | | | | | | | | | | | | | | | | | | |
| INVESTMENTS: | | | | | | | | | | | | | | | | | | | | |
| Nuclear plant decommissioning trusts | | | - | | | | - | | | | 1,088,641 | | | | - | | | | 1,088,641 | |
| Investment in associated companies | | | 4,477,602 | | | | - | | | | - | | | | (4,477,602 | ) | | | - | |
| Other | | | 1,137 | | | | 21,127 | | | | 202 | | | | - | | | | 22,466 | |
| | | | 4,478,739 | | | | 21,127 | | | | 1,088,843 | | | | (4,477,602 | ) | | | 1,111,107 | |
| | | | | | | | | | | | | | | | | | | | | |
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | | | | | | | | | | | |
| Accumulated deferred income taxes | | | 93,379 | | | | 381,849 | | | | - | | | | (388,602 | ) | | | 86,626 | |
| Goodwill | | | 24,248 | | | | - | | | | - | | | | - | | | | 24,248 | |
| Customer intangibles | | | 16,566 | | | | - | | | | - | | | | - | | | | 16,566 | |
| Property taxes | | | - | | | | 27,811 | | | | 22,314 | | | | - | | | | 50,125 | |
| Unamortized sale and leaseback costs | | | - | | | | 16,454 | | | | - | | | | 56,099 | | | | 72,553 | |
| Other | | | 82,845 | | | | 71,179 | | | | 18,755 | | | | (51,114 | ) | | | 121,665 | |
| | | | 217,038 | | | | 497,293 | | | | 41,069 | | | | (383,617 | ) | | | 371,783 | |
| | | $ | 5,821,127 | | | $ | 6,020,488 | | | $ | 5,282,211 | | | $ | (5,373,038 | ) | | $ | 11,750,788 | |
| | | | | | | | | | | | | | | | | | | | | |
| LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
| Currently payable long-term debt | | $ | 736 | | | $ | 646,402 | | | $ | 922,429 | | | $ | (18,640 | ) | | $ | 1,550,927 | |
| Short-term borrowings- | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | - | | | | 9,237 | | | | - | | | | - | | | | 9,237 | |
| Other | | | 100,000 | | | | - | | | | - | | | | - | | | | 100,000 | |
| Accounts payable- | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 261,788 | | | | 170,446 | | | | 295,045 | | | | (261,201 | ) | | | 466,078 | |
| Other | | | 51,722 | | | | 193,641 | | | | - | | | | - | | | | 245,363 | |
| Accrued taxes | | | 44,213 | | | | 61,055 | | | | 22,777 | | | | (44,887 | ) | | | 83,158 | |
| Other | | | 173,015 | | | | 132,314 | | | | 16,734 | | | | 36,994 | | | | 359,057 | |
| | | | 631,474 | | | | 1,213,095 | | | | 1,256,985 | | | | (287,734 | ) | | | 2,813,820 | |
| | | | | | | | | | | | | | | | | | | | | |
| CAPITALIZATION: | | | | | | | | | | | | | | | | | | | | |
| Common stockholder's equity | | | 3,514,571 | | | | 2,346,515 | | | | 2,119,488 | | | | (4,466,003 | ) | | | 3,514,571 | |
| Long-term debt and other long-term obligations | | | 1,519,339 | | | | 1,906,818 | | | | 554,825 | | | | (1,269,330 | ) | | | 2,711,652 | |
| | | | 5,033,910 | | | | 4,253,333 | | | | 2,674,313 | | | | (5,735,333 | ) | | | 6,226,223 | |
| | | | | | | | | | | | | | | | | | | | | |
| NONCURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
| Deferred gain on sale and leaseback transaction | | | - | | | | - | | | | - | | | | 992,869 | | | | 992,869 | |
| Accumulated deferred income taxes | | | - | | | | - | | | | 342,840 | | | | (342,840 | ) | | | - | |
| Accumulated deferred investment tax credits | | | - | | | | 36,359 | | | | 22,037 | | | | - | | | | 58,396 | |
| Asset retirement obligations | | | - | | | | 25,714 | | | | 895,734 | | | | - | | | | 921,448 | |
| Retirement benefits | | | 33,144 | | | | 170,891 | | | | - | | | | - | | | | 204,035 | |
| Property taxes | | | - | | | | 27,811 | | | | 22,314 | | | | - | | | | 50,125 | |
| Lease market valuation liability | | | - | | | | 262,200 | | | | - | | | | - | | | | 262,200 | |
| Other | | | 122,599 | | | | 31,085 | | | | 67,988 | | | | - | | | | 221,672 | |
| | | | 155,743 | | | | 554,060 | | | | 1,350,913 | | | | 650,029 | | | | 2,710,745 | |
| | | $ | 5,821,127 | | | $ | 6,020,488 | | | $ | 5,282,211 | | | $ | (5,373,038 | ) | | $ | 11,750,788 | |
| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | | |
| CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS | |
| (Unaudited) | |
| | | | | | | | | | | | | | | | |
| For the Three Months Ended March 31, 2010 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| | | | | | | | | | | | | | | | |
| NET CASH PROVIDED FROM (USED FOR) | | | | | | | | | | | | | |
| OPERATING ACTIVITIES | | $ | (147,718 | ) | | $ | 40,130 | | | $ | 98,692 | | | $ | - | | | $ | (8,896 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
| Redemptions and Repayments- | | | | | | | | | | | | | | | | | | | | |
| Long-term debt | | | (197 | ) | | | (1,081 | ) | | | - | | | | - | | | | (1,278 | ) |
| Short-term borrowings, net | | | - | | | | (9,237 | ) | | | - | | | | - | | | | (9,237 | ) |
| Other | | | (453 | ) | | | (177 | ) | | | (101 | ) | | | - | | | | (731 | ) |
| Net cash used for financing activities | | | (650 | ) | | | (10,495 | ) | | | (101 | ) | | | - | | | | (11,246 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
| Property additions | | | (2,103 | ) | | | (174,163 | ) | | | (125,337 | ) | | | - | | | | (301,603 | ) |
| Proceeds from asset sales | | | - | | | | 114,272 | | | | - | | | | - | | | | 114,272 | |
| Sales of investment securities held in trusts | | | - | | | | - | | | | 272,094 | | | | - | | | | 272,094 | |
| Purchases of investment securities held in trusts | | | - | | | | - | | | | (284,888 | ) | | | - | | | | (284,888 | ) |
| Loans from associated companies, net | | | 250,908 | | | | 31,232 | | | | 39,540 | | | | - | | | | 321,680 | |
| Customer intangibles | | | (100,615 | ) | | | - | | | | - | | | | - | | | | (100,615 | ) |
| Other | | | 178 | | | | (977 | ) | | | - | | | | - | | | | (799 | ) |
| Net cash provided from (used for) investing activities | | | 148,368 | | | | (29,636 | ) | | | (98,591 | ) | | | - | | | | 20,141 | |
| | | | | | | | | | | | | | | | | | | | | |
| Net change in cash and cash equivalents | | | - | | | | (1 | ) | | | - | | | | - | | | | (1 | ) |
| Cash and cash equivalents at beginning of period | | | - | | | | 3 | | | | 9 | | | | - | | | | 12 | |
| Cash and cash equivalents at end of period | | $ | - | | | $ | 2 | | | $ | 9 | | | $ | - | | | $ | 11 | |
| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | | |
| CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS | |
| (Unaudited) | |
| | | | | | | | | | | | | | | | |
| For the Three Months Ended March 31, 2009 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| NET CASH PROVIDED FROM OPERATING ACTIVITIES | | $ | 200,420 | | | $ | 28,545 | | | $ | 118,902 | | | $ | - | | | $ | 347,867 | |
| | | | | | | | | | | | | | | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
| New Financing- | | | | | | | | | | | | | | | | | | | | |
| Long-term debt | | | - | | | | 100,000 | | | | - | | | | - | | | | 100,000 | |
| Short-term borrowings, net | | | 98,881 | | | | 88,308 | | | | 434,105 | | | | - | | | | 621,294 | |
| Redemptions and Repayments- | | | | | | | | | | | | | | | | | | | | |
| Long-term debt | | | (1,189 | ) | | | (626 | ) | | | (334,101 | ) | | | - | | | | (335,916 | ) |
| Net cash provided from financing activities | | | 97,692 | | | | 187,682 | | | | 100,004 | | | | - | | | | 385,378 | |
| | | | | | | | | | | | | | | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
| Property additions | | | (358 | ) | | | (198,631 | ) | | | (213,816 | ) | | | - | | | | (412,805 | ) |
| Proceeds from asset sales | | | - | | | | 7,573 | | | | - | | | | - | | | | 7,573 | |
| Sales of investment securities held in trusts | | | - | | | | - | | | | 351,414 | | | | - | | | | 351,414 | |
| Purchases of investment securities held in trusts | | | - | | | | - | | | | (356,904 | ) | | | - | | | | (356,904 | ) |
| Loans to associated companies, net | | | (297,641 | ) | | | (6,322 | ) | | | - | | | | - | | | | (303,963 | ) |
| Other | | | (113 | ) | | | (18,852 | ) | | | 400 | | | | - | | | | (18,565 | ) |
| Net cash used for investing activities | | | (298,112 | ) | | | (216,232 | ) | | | (218,906 | ) | | | - | | | | (733,250 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Net change in cash and cash equivalents | | | - | | | | (5 | ) | | | - | | | | - | | | | (5 | ) |
| Cash and cash equivalents at beginning of period | | | - | | | | 39 | | | | - | | | | - | | | | 39 | |
| Cash and cash equivalents at end of period | | $ | - | | | $ | 34 | | | $ | - | | | $ | - | | | $ | 34 | |
13. INTANGIBLE ASSETS
FES has acquired certain customer contract rights, which were capitalized as intangible assets. These rights allow FES to supply electric generation needs to customers and are being amortized ratably over the term of the related contracts. Net intangible assets of $114 million are included in other assets on the FirstEnergy Consolidated Balance Sheet as of March 31, 2010.
For the three months ended March 31, 2010, amortization expense was approximately $3 million.
14. PROPOSED MERGER WITH ALLEGHENY ENERGY, INC.
As previously disclosed, on February 10, 2010, FirstEnergy entered into an Agreement and Plan of Merger (Merger Agreement) with Element Merger Sub, Inc., a Maryland corporation and its wholly-owned subsidiary (Merger Sub) and Allegheny Energy, Inc., a Maryland corporation (Allegheny Energy). Upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will merge with and into Allegheny Energy with Allegheny Energy continuing as the surviving corporation and a wholly-owned subsidiary of FirstEnergy. Pursuant to the Merger Agreement, upon the closing of the merger, each issued and outstanding share of Allegheny Energy common stock, including grants of restricted common stock, will automatically be converted into the right to receive 0.667 of a share of common stock of FirstEnergy and Allegheny Energy stockho lders will own approximately 27% of the combined company. The Merger Agreement was unanimously approved by both companies’ Boards of Directors.
Pursuant to the Merger Agreement, completion of the merger is conditioned upon, among other things, shareholder approval of both companies, the SEC’s clearance of a registration statement registering the FirstEnergy common stock to be issued in connection with the merger, as well as expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and approval by the FERC, the Maryland Public Service Commission, PPUC, the Virginia State Corporation Commission and the West Virginia Public Service Commission. The Merger Agreement also contains certain termination rights for both FirstEnergy and Allegheny Energy, and further provides for the payment of fees and expenses upon termination under specified circumstances.
On March 23, 2010, FirstEnergy filed with the SEC a registration statement on Form S-4 containing a preliminary joint proxy statement/prospectus relating to the proposed merger (Registration Statement). After the Registration Statement has been declared effective by the SEC, FirstEnergy and Allegheny Energy expect to send the joint proxy statement/prospectus contained in the Registration Statement to their respective shareholders and each hold a special shareholder meeting to approve proposals related to the merger.
The companies expect to make their filing with the FERC under Section 203 of the FPA and the applications for clearance under HSR in May 2010. Applications for state regulatory approval in Pennsylvania, Maryland, West Virginia and Virginia are expected to be filed in the second quarter of 2010.
In connection with the proposed merger, during the first quarter of 2010, FirstEnergy recorded approximately $14.2 million ($9.6 million after tax) of expenses associated with merger transactions costs. These costs are expensed as incurred.
FirstEnergy and Allegheny Energy currently anticipate completing the merger in the first half of 2011. Although FirstEnergy and Allegheny Energy believe that they will receive the required authorizations, approvals and consents to complete the merger, there can be no assurance as to the timing of these authorizations, approvals and consents or as to FirstEnergy’s and Allegheny Energy’s ultimate ability to obtain such authorizations, consents or approvals (or any additional authorizations, approvals or consents which may otherwise become necessary) or that such authorizations, approvals or consents will be obtained on terms and subject to conditions satisfactory to Allegheny Energy and FirstEnergy. Further information concerning the proposed merger is included in the Registration Statement filed by FirstEnergy with the SEC in conn ection with the merger.
Item 2. Management's Discussion and Analysis of Registrant and Subsidiaries
FIRSTENERGY CORP.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EXECUTIVE SUMMARY
Earnings available to FirstEnergy Corp. in the first quarter of 2010 were $155 million, or basic and diluted earnings of $0.51 per share of common stock, compared with $119 million, or basic and diluted earnings of $0.39 per share of common stock in the first quarter of 2009. The increase in earnings resulted principally from decreased regulatory charges and increased investment income, partially offset by derivative mark-to-market adjustments, and increased fuel and purchased power costs and net amortization of regulatory assets.
| Change in Basic Earnings Per Share From Prior Year | | | 2010 | |
| | | | | |
| Basic Earnings Per Share – First Quarter 2009 | | | | $ | 0.39 | |
| Non-core asset sales/impairments - 2010 | | | (0.02 | ) |
| Trust securities impairments | | | 0.05 | |
| Regulatory charges – 2009 | | | 0.55 | |
| Regulatory charges – 2010 | | | (0.08 | ) |
| Derivative mark-to-market adjustment - 2010 | | | (0.11 | ) |
| Organizational restructuring - 2009 | | | 0.05 | |
| Merger transaction costs - 2010 | | | (0.03 | ) |
| Income tax resolution - 2009 | | | (0.04 | ) |
| Income tax charge from healthcare legislation - 2010 | | | (0.04 | ) |
| Revenues | | | (0.07 | ) |
| Fuel and purchased power | | | (0.13 | ) |
| Transmission expense | | | 0.10 | |
| Amortization of regulatory assets, net | | | (0.17 | ) |
| Investment income | | | 0.01 | |
| Other expenses | | | | 0.05 | |
| Basic Earnings Per Share – First Quarter 2010 | | | | $ | 0.51 | |
Financial Matters
Proposed Merger with Allegheny Energy, Inc.
On February 10, 2010, FirstEnergy entered into an Agreement and Plan of Merger (Merger Agreement) with Element Merger Sub. Inc., a Maryland corporation and its wholly-owned subsidiary (Merger Sub) and Allegheny Energy, Inc., a Maryland corporation (Allegheny Energy). Upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will merge with and into Allegheny Energy with Allegheny Energy continuing as the surviving corporation and a wholly-owned subsidiary of FirstEnergy. Pursuant to the Merger Agreement, upon the closing of the merger, each issued and outstanding share of Allegheny Energy common stock, including grants of restricted common stock, will automatically be converted into the right to receive 0.667 of a share of common stock of FirstEnergy and Allegheny Energy stockholders will own approximately 27% of the combined company. Based on the closing stock prices for both companies on February 10, 2010, Allegheny Energy shareholders would receive a value of $27.65 per share, or $4.7 billion in the aggregate. FirstEnergy will also assume all outstanding Allegheny Energy debt. The price per share represents a premium of 31.6% to the closing stock price of Allegheny Energy on February 10, 2010, and a 22.3% premium to the average stock price of Allegheny over the last 60 days ending February 10, 2010.
In connection with the proposed merger, during the first quarter of 2010, FirstEnergy recorded approximately $14.2 million ($9.6 million after tax) of merger transactions costs. These costs are expensed as incurred.
Pursuant to the Merger Agreement, completion of the merger is conditioned upon, among other things, shareholder approval of both companies, the SEC’s clearance of a registration statement registering the FirstEnergy common stock to be issued in connection with the merger, as well as expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and approval by the FERC, the Maryland Public Service Commission, PPUC, the Virginia State Corporation Commission and the West Virginia Public Service Commission. The Merger Agreement also contains certain termination rights for both FirstEnergy and Allegheny Energy, and further provides for the payment of fees and expenses upon termination under specified circumstances.
On March 23, 2010, FirstEnergy filed with the SEC a registration statement on Form S-4 containing a preliminary joint proxy statement/prospectus relating to the proposed merger (Registration Statement). After the Registration Statement has been declared effective by the SEC, FirstEnergy and Allegheny Energy expect to send the joint proxy statement/prospectus contained in the Registration Statement to their respective shareholders and each hold a special shareholder meeting to approve proposals related to the merger.
The companies expect to make their filing with the FERC under Section 203 of the FPA and the applications for clearance under the HSR in May 2010. Applications for state regulatory approval in Pennsylvania, Maryland, West Virginia and Virginia are expected to be filed in the second quarter of 2010.
FirstEnergy and Allegheny Energy currently anticipate completing the merger in the first half of 2011. Although FirstEnergy and Allegheny Energy believe that they will receive the required authorizations, approvals and consents to complete the merger, there can be no assurance as to the timing of these authorizations, approvals and consents or as to FirstEnergy’s and Allegheny Energy’s ultimate ability to obtain such authorizations, consents or approvals (or any additional authorizations, approvals or consents which may otherwise become necessary) or that such authorizations, approvals or consents will be obtained on terms and subject to conditions satisfactory to Allegheny Energy and FirstEnergy. Further information concerning the proposed merger is included in the Registration Statement filed by FirstEnergy with the SEC i n connection with the merger.
Non-core asset sales/Impairments
During the first quarter of 2010, FirstEnergy recorded charges of approximately $9.2 million ($6.0 million after-tax) associated with sale of FGCO’s 340-MW Sumpter Plant and the termination of gas drilling participation rights associated with certain previously owned Ohio properties.
Derivative mark-to-market adjustments
As a result of the continued decline in electricity prices, mark-to-market adjustments relating to certain purchased power contracts increased expenses in the first quarter of 2010 by $51.9 million ($32.5 million after tax). From December 31, 2009 to March 31, 2010 forward around the clock electricity prices per MWH have declined approximately 14%.
Elimination of retiree prescription drug tax benefits
As a result of the Patient Protection and Affordable Care Act and the Health Care and Education Affordability Reconciliation Act signed into law on March 23, 2010 and March 30, 2010, respectively, beginning in 2011 the tax deduction available to FirstEnergy will be reduced to the extent that drug costs are reimbursed under the Medicare Part D retiree subsidy program. During the first quarter of 2010, FirstEnergy recognized a one-time adjustment of approximately $12.6 million to reduce the deferred tax asset associated with these subsidies.
Operational Matters
Davis Besse Refueling
On February 28, 2010, the Davis Besse Nuclear Plant (908-MW) began a refueling outage to exchange 76 of the 177 fuel assemblies and conduct numerous safety inspections. During the outage, it was determined that modifications were needed to 16 of the 69 control rod drive mechanism nozzles (CDRM) that penetrated the reactor vessel head. Further evaluation and testing identified 8 additional nozzles requiring modifications. Additional testing will be conducted following the modification of each nozzle to ensure safe, reliable plant operations. The plant is expected to be ready for restart in July, 2010.
PJM RTO Integration
From March 15-19, 2010, PJM conducted two competitive auctions FRR Integration Auctions on behalf of the Ohio Companies and Penn to secure electric capacity for delivery years June 1, 2011 through May 31, 2012, and June 1, 2012 through May 21, 2013. Monitoring Analytics, LLC, acting as the PJM Market Monitor, certified the auction results on March 26, 2010. In the 2011/2012 auction, 27 suppliers participated, and 12,583 MW of capacity cleared at a price of $108.89/MW-day. The 2012/2013 auction had 28 market participants, with 13,038 MW of capacity clearing at a price of $20.46/MW-day. On March 29, 2010, the Ohio Companies and Penn signed agreements with all winning suppliers.
Regulatory Matters - Ohio
New Electric Security Plan
On March 23, 2010, the Ohio Companies filed a new ESP with the PUCO. The ESP was filed as a Stipulation and Recommendation and incorporated the substantial record developed in the Ohio Companies’ earlier filing for an MRO. The ESP is a three-year plan that would begin June 1, 2011, would provide for a CBP to procure generation supply for customers that choose not to shop with an alternative supplier with more certain rate levels for customers, timely recovery of PUCO-authorized charges, deferral of certain costs and promotes energy efficiency and economic development. The Ohio Companies have requested PUCO approval by May 5, 2010. On April 28, 2010, the PUCO Chairman issued a statement that the PUCO will not issue a decision on May 5, 2010, and will take additional time to review the case record. In connection with the filing , FirstEnergy recorded approximately $39.5 million ($25.2 million after tax) of regulatory asset impairments and expenses related to the ESP.
Regulatory Matters - Pennsylvania
Met-Ed and Penelec Transmission Service Charge
On March 3, 2010, Met-Ed and Penelec received an Order from the PPUC which denied the recovery of marginal transmission losses through the TSC rider for the period June 1, 2007 through March 31, 2008 and instructed Met-Ed and Penelec to work with the parties and file a petition to retain any over-collection, with interest, until 2011, when Met-Ed and Penelec’s generation rate caps expire. In response to the Order, on March 18, 2010, Met-Ed and Penelec requested that the PPUC grant a stay of its Order, with such stay being granted by the PPUC on March 25, 2010 until December 31, 2010, allowing for the continued collection of marginal losses subject to refund. On April 1, 2010, Met-Ed and Penelec filed with the Commonwealth Court of Pennsylvania a Petition for Review of the PPUC’s Order disallowing the recovery of ma rginal transmission losses in the TSC. Although the ultimate outcome of this matter cannot be determined at this time, Met-Ed and Penlec believe they should prevail on appeal and should recover marginal transmission losses for the period prior to January 1, 2011.
FIRSTENERGY'S BUSINESS
FirstEnergy is a diversified energy company headquartered in Akron, Ohio, that operates primarily through two core business segments (see Results of Operations).
| · | Energy Delivery Services transmits and distributes electricity through our 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 Ohio, Pennsylvania and New Jersey. Its revenues are primarily derived from the delivery of electricity within our service areas, 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 Ohio, Pennsylvania and New Jersey franchise areas. Its results reflect the commodity costs of securing electric generation from FES and from non-affiliated power suppliers, the net PJM and MISO transmission expenses related to the delivery of the respective generation loads, and the deferral and amortization of certain fuel costs. |
| · | Competitive Energy Services supplies electric power to 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 our 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 13,710 MW and also purchases electricity to meet sales obligations. The segment's net income is primarily derived from affiliated and non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs char ged by PJM and MISO to deliver energy to the segment’s 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 11 to the consolidated financial statements. Earnings available to FirstEnergy Corp. by major business segment were as follows:
| | | Three Months Ended | | | |
| | | March 31 | | Increase | |
| | | 2010 | | 2009 | | (Decrease) | |
| | | (In millions, except per share data) | |
| Earnings By Business Segment: | | | | | | | |
| Energy delivery services | | $ | 114 | | $ | (18 | ) | $ | 132 | |
| Competitive energy services | | | 76 | | | 155 | | | (79 | ) |
| Other and reconciling adjustments* | | | (35 | ) | | (18 | ) | | (17 | ) |
| Total | | $ | 155 | | $ | 119 | | $ | 36 | |
| | | | | | | | | | | |
| Basic Earnings Per Share | | $ | 0.51 | | $ | 0.39 | | $ | 0.12 | |
| Diluted Earnings Per Share | | $ | 0.51 | | $ | 0.39 | | $ | 0.12 | |
| | | | | | | | | | | |
| * Consists primarily of interest expense related to holding company debt, corporate support services revenues and expenses, noncontrolling interests and the elimination of intersegment transactions. | |
Summary of Results of Operations – First Quarter 2010 Compared with First Quarter 2009
Financial results for FirstEnergy's major business segments in the first quarter of 2010 and 2009 were as follows:
| | | | Energy | | | Competitive | | | Other and | | | | |
| | | | Delivery | | | Energy | | | Reconciling | | | FirstEnergy | |
| First Quarter 2010 Financial Results | | Services | | | Services | | | Adjustments | | | Consolidated | |
| | | | (In millions) | |
| Revenues: | | | | | | | | | | | | |
| | External | | | | | | | | | | | | |
| | Electric | | $ | 2,398 | | | $ | 669 | | | $ | - | | | $ | 3,067 | |
| | Other | | | 145 | | | | 47 | | | | (27 | ) | | | 165 | |
| | Internal* | | | - | | | | 674 | | | | (607 | ) | | | 67 | |
| Total Revenues | | | 2,543 | | | | 1,390 | | | | (634 | ) | | | 3,299 | |
| | | | | | | | | | | | | | | | | | |
| Expenses: | | | | | | | | | | | | | | | | |
| | Fuel | | | - | | | | 337 | | | | (3 | ) | | | 334 | |
| | Purchased power | | | 1,395 | | | | 450 | | | | (607 | ) | | | 1,238 | |
| | Other operating expenses | | | 380 | | | | 347 | | | | (26 | ) | | | 701 | |
| | Provision for depreciation | | | 113 | | | | 66 | | | | 14 | | | | 193 | |
| | Amortization of regulatory assets | | | 212 | | | | - | | | | - | | | | 212 | |
| | Deferral of new regulatory assets | | | - | | | | - | | | | - | | | | - | |
| | General taxes | | | 162 | | | | 35 | | | | 8 | | | | 205 | |
| Total Expenses | | | 2,262 | | | | 1,235 | | | | (614 | ) | | | 2,883 | |
| | | | | | | | | | | | | | | | | | |
| Operating Income | | | 281 | | | | 155 | | | | (20 | ) | | | 416 | |
| Other Income (Expense): | | | | | | | | | | | | | | | | |
| | Investment income | | | 25 | | | | 1 | | | | (10 | ) | | | 16 | |
| | Interest expense | | | (124 | ) | | | (53 | ) | | | (36 | ) | | | (213 | ) |
| | Capitalized interest | | | 1 | | | | 20 | | | | 20 | | | | 41 | |
| Total Other Expense | | | (98 | ) | | | (32 | ) | | | (26 | ) | | | (156 | ) |
| | | | | | | | | | | | | | | | | | |
| Income Before Income Taxes | | | 183 | | | | 123 | | | | (46 | ) | | | 260 | |
| Income taxes | | | 69 | | | | 47 | | | | (5 | ) | | | 111 | |
| Net Income (Loss) | | | 114 | | | | 76 | | | | (41 | ) | | | 149 | |
| Noncontrolling interest loss | | | - | | | | - | | | | (6 | ) | | | (6 | ) |
| Earnings available to FirstEnergy Corp. | | $ | 114 | | | $ | 76 | | | $ | (35 | ) | | $ | 155 | |
| | | | | | | | | | | | | | | | | | |
| * | Under the accounting standard for the effects of certain types of regulation, internal revenues are not fully offset for sale of RECs by FES to the Ohio Companies that are retained in inventory. | |
| | | Energy | | | Competitive | | | Other and | | | | |
| | | Delivery | | | Energy | | | Reconciling | | | FirstEnergy | |
| First Quarter 2009 Financial Results | | Services | | | Services | | | Adjustments | | | Consolidated | |
| | | (In millions) | |
| Revenues: | | | | | | | | | | | | |
| External | | | | | | | | | | | | |
| Electric | | $ | 2,861 | | | $ | 280 | | | $ | - | | | $ | 3,141 | |
| Other | | | 160 | | | | 55 | | | | (22 | ) | | | 193 | |
| Internal | | | - | | | | 893 | | | | (893 | ) | | | - | |
| Total Revenues | | | 3,021 | | | | 1,228 | | | | (915 | ) | | | 3,334 | |
| | | | | | | | | | | | | | | | | |
| Expenses: | | | | | | | | | | | | | | | | |
| Fuel | | | - | | | | 312 | | | | - | | | | 312 | |
| Purchased power | | | 1,876 | | | | 160 | | | | (893 | ) | | | 1,143 | |
| Other operating expenses | | | 499 | | | | 355 | | | | (27 | ) | | | 827 | |
| Provision for depreciation | | | 109 | | | | 64 | | | | 4 | | | | 177 | |
| Amortization of regulatory assets, net | | | 411 | | | | - | | | | - | | | | 411 | |
| Deferral of new regulatory assets | | | (93 | ) | | | - | | | | - | | | | (93 | ) |
| General taxes | | | 170 | | | | 32 | | | | 9 | | | | 211 | |
| Total Expenses | | | 2,972 | | | | 923 | | | | (907 | ) | | | 2,988 | |
| | | | | | | | | | | | | | | | | |
| Operating Income | | | 49 | | | | 305 | | | | (8 | ) | | | 346 | |
| Other Income (Expense): | | | | | | | | | | | | | | | | |
| Investment income | | | 30 | | | | (29 | ) | | | (12 | ) | | | (11 | ) |
| Interest expense | | | (110 | ) | | | (28 | ) | | | (56 | ) | | | (194 | ) |
| Capitalized interest | | | 1 | | | | 10 | | | | 17 | | | | 28 | |
| Total Other Expense | | | (79 | ) | | | (47 | ) | | | (51 | ) | | | (177 | ) |
| | | | | | | | | | | | | | | | | |
| Income Before Income Taxes | | | (30 | ) | | | 258 | | | | (59 | ) | | | 169 | |
| Income taxes | | | (12 | ) | | | 103 | | | | (37 | ) | | | 54 | |
| Net Income (Loss) | | | (18 | ) | | | 155 | | | | (22 | ) | | | 115 | |
| Noncontrolling interest loss | | | - | | | | - | | | | (4 | ) | | | (4 | ) |
| Earnings available to FirstEnergy Corp. | | $ | (18 | ) | | $ | 155 | | | $ | (18 | ) | | $ | 119 | |
| | | | | | | | | | | | | | | | | |
| Changes Between First Quarter 2010 and | | | | | | | | | | | | | |
| First Quarter 2009 Financial Results | | | | | | | | | | | | | | | | |
| Increase (Decrease) | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Revenues: | | | | | | | | | | | | | | | | |
| External | | | | | | | | | | | | | | | | |
| Electric | | $ | (463 | ) | | $ | 389 | | | $ | - | | | $ | (74 | ) |
| Other | | | (15 | ) | | | (8 | ) | | | (5 | ) | | | (28 | ) |
| Internal | | | - | | | | (219 | ) | | | 286 | | | | 67 | |
| Total Revenues | | | (478 | ) | | | 162 | | | | 281 | | | | (35 | ) |
| | | | | | | | | | | | | | | | | |
| Expenses: | | | | | | | | | | | | | | | | |
| Fuel | | | - | | | | 25 | | | | (3 | ) | | | 22 | |
| Purchased power | | | (481 | ) | | | 290 | | | | 286 | | | | 95 | |
| Other operating expenses | | | (119 | ) | | | (8 | ) | | | 1 | | | | (126 | ) |
| Provision for depreciation | | | 4 | | | | 2 | | | | 10 | | | | 16 | |
| Amortization of regulatory assets | | | (199 | ) | | | - | | | | - | | | | (199 | ) |
| Deferral of new regulatory assets | | | 93 | | | | - | | | | - | | | | 93 | |
| General taxes | | | (8 | ) | | | 3 | | | | (1 | ) | | | (6 | ) |
| Total Expenses | | | (710 | ) | | | 312 | | | | 293 | | | | (105 | ) |
| | | | | | | | | | | | | | | | | |
| Operating Income | | | 232 | | | | (150 | ) | | | (12 | ) | | | 70 | |
| Other Income (Expense): | | | | | | | | | | | | | | | | |
| Investment income | | | (5 | ) | | | 30 | | | | 2 | | | | 27 | |
| Interest expense | | | (14 | ) | | | (25 | ) | | | 20 | | | | (19 | ) |
| Capitalized interest | | | - | | | | 10 | | | | 3 | | | | 13 | |
| Total Other Expense | | | (19 | ) | | | 15 | | | | 25 | | | | 21 | |
| | | | | | | | | | | | | | | | | |
| Income Before Income Taxes | | | 213 | | | | (135 | ) | | | 13 | | | | 91 | |
| Income taxes | | | 81 | | | | (56 | ) | | | 32 | | | | 57 | |
| Net Income (Loss) | | | 132 | | | | (79 | ) | | | (19 | ) | | | 34 | |
| Noncontrolling interest loss | | | - | | | | - | | | | (2 | ) | | | (2 | ) |
| Earnings available to FirstEnergy Corp. | | $ | 132 | | | $ | (79 | ) | | $ | (17 | ) | | $ | 36 | |
Energy Delivery Services – First Quarter 2010 Compared with First Quarter 2009
Net income increased to $114 million in the first quarter of 2010, compared to a loss of $18 million in the first quarter of 2009, primarily due to the absence of CEI’s $216 million regulatory asset impairment in 2009, lower purchased power costs and lower other operating expenses, partially offset by lower revenues and the absence of deferrals of new regulatory assets.
Revenues –
The decrease in total revenues resulted from the following sources:
| | | Three Months | | | | |
| | | Ended March 31 | | Increase | |
| Revenues by Type of Service | | 2010 | | 2009 | | (Decrease) | |
| | | (In millions) | |
| | $ | 883 | | $ | 849 | | $ | 34 | |
| | | | | | | | | | |
| | | 1,176 | | | 1,613 | | | (437 | ) |
| | | 217 | | | 188 | | | 29 | |
| | | 1,393 | | | 1,801 | | | (408 | ) |
| | | 215 | | | 318 | | | (103 | ) |
| | | 52 | | | 53 | | | (1 | ) |
| | $ | 2,543 | | $ | 3,021 | | $ | (478 | ) |
The change in distribution deliveries by customer class is summarized in the following table:
| Electric Distribution KWH Deliveries | | | |
| | | (3 | |
| | | (1 | |
| | | 7 | |
Total Distribution KWH Deliveries | | | - | |
Lower deliveries to residential customers reflected decreased weather-related usage in the first quarter of 2010, as heating degree days decreased by 7% from the same period in 2009. The increase in distribution deliveries to industrial customers was primarily due to a slightly recovering economy in FirstEnergy's service territory compared to the first quarter of 2009. In the industrial sector, KWH deliveries increased to major automotive customers (14%) and steel customers (31%). Distribution service revenues increased primarily due to the accelerated recovery of deferred distribution costs, as approved by the PUCO, partially offset by a reduction in the transition rate for CEI effective June 1, 2009.
The following table summarizes the price and volume factors contributing to the $408 million decrease in generation revenues in the first quarter of 2010 compared to the first quarter of 2009:
| Source of Change in Generation Revenues | | Increase (Decrease) | |
| | | (In millions) | |
| Retail: | | | | |
| Effect of 30.6% decrease in sales volumes | | $ | (494 | ) |
| Change in prices | | | 57 | |
| | | | (437 | ) |
| Wholesale: | | | | |
| Effect of 14.3% decrease in sales volumes | | | (27 | ) |
| Change in prices | | | 56 | |
| | | | 29 | |
| Decrease in Generation Revenues | | $ | (408 | ) |
The decrease in retail generation sales volumes was primarily due to an increase in customer shopping in the Ohio Companies’ service territories in the first quarter of 2010. Total generation KWH provided by alternative suppliers as a percentage of total KWH deliveries for the Ohio Companies pursuantincreased 53% in the first quarter of 2010 compared to the same period in 2009. Retail generation prices increased primarily for CEI as a Power Supply Agreement that ended on December 31, 2008. On January 2, 2009, FES signed an agreementresult of the CBP auction for the service period beginning June 1, 2009.
The increase in wholesale generation revenues reflected higher prices for Met-Ed’s and Penelec’s NUG sales to provide 75%the PJM market.
Transmission revenues decreased $103 million primarily due to the termination of the Ohio Companies’ transmission tariff effective June 1, 2009; recovery of transmission costs is now provided for in the generation rate established under the CBP.
Expenses –
Total expenses decreased by $710 million due to the following:
| · | Purchased power costs were $481 million lower in the first quarter of 2010 due to lower volume requirements, partially offset by an increase in unit costs from non-affiliates. The decrease in purchased power volumes resulted principally from the increase in customer shopping in the Ohio Companies’ service territories, as described above. |
· | The increase in unit costs from non-affiliates in the first quarter of 2010 resulted from higher capacity prices in the PJM market for Met-Ed and Penelec compared to the first quarter of 2009. The decrease in unit costs from FES was principally due to the lower weighted average unit price per KWH for the Ohio Companies established under the CBP auction effective June 1, 2009. |
| Source of Change in Purchased Power | | Increase (Decrease) | |
| | | (In millions) | |
| Purchases from non-affiliates: | | | | |
Change due to increased unit costs | | $ | 187 | |
Change due to decreased volumes | | | (419 | ) |
| | | | (232 | ) |
| Purchases from FES: | | | | |
Change due to decreased unit costs | | | (94 | ) |
Change due to decreased volumes | | | (152 | ) |
| | | | (246 | ) |
| | | | | |
| Increase in NUG costs deferred | | | (3 | ) |
| Net Decrease in Purchased Power Costs | | $ | (481 | ) |
| · | MISO network transmission expenses were lower by $54 million due to the reduced generation sales requirements discussed above. |
| · | Administrative and general costs, including labor and employee benefit expenses, decreased $49 million as a result of cost reduction initiatives implemented since the first quarter of 2009. |
| · | Other operating expenses decreased $21 million due to higher economic development expenses recognized in the first quarter of 2009 relating to the amended ESP. |
| · | Forestry contractor costs were $4 million higher in the first quarter of 2010, reflecting increased vegetation management activities. |
| · | Amortization of regulatory assets decreased $199 million due primarily to the absence of the $216 million impairment of CEI’s regulatory assets in the first quarter of 2009 and reduced CTC amortization for Met-Ed and Penelec, partially offset by a $35 million regulatory asset impairment associated with the filing of the ESP on March 23, 2010. |
| · | The deferral of new regulatory assets decreased $93 million in the first quarter of 2010 principally due to the absence of CEI’s PUCO-approved purchased power cost deferral in the first quarter of 2009. |
| · | Depreciation expense increased $4 million due to property additions since the first quarter of 2009. |
| · | General taxes decreased $8 million primarily due to lower property and real estate taxes. |
Other Expense –
Other expense increased $19 million in the first quarter of 2010 compared to the first quarter of 2009 primarily due to higher interest expense associated with debt issuances by the Utilities since the first quarter of 2009.
Competitive Energy Services – First Quarter 2010 Compared with First Quarter 2009
Net income decreased to $76 million in the first quarter of 2010, compared to $155 million in the first quarter of 2009, primarily due to a decrease in sales margins partially offset by an increase in investment income.
Revenues –
Total revenues increased $162 million in the first quarter of 2010 primarily due to an increase in direct and government aggregation sales volumes and sales of RECs, partially offset by decreases in PLR sales to the Ohio Companies and wholesale sales.
The increase in total revenues resulted from the following sources:
| | | Three Months | | | |
| | | Ended March 31 | | Increase | |
| Revenues by Type of Service | | 2010 | | 2009 | | (Decrease) | |
| | | (In millions) | |
| | | | | | | | |
Direct and Government Aggregation | | | 512 | | | 91 | | | 421 | |
| | | 677 | | | 893 | | | (216 | ) |
| | | 87 | | | 189 | | | (102 | |
| | | 17 | | | 25 | | | (8) | |
| | | 67 | | | - | | | 67 | |
| | | 30 | | | 30 | | | - | |
| | | 1,390 | | | 1,228 | | | 162 | |
The increase in direct and government aggregation revenues of $421 million resulted from increased revenue in both the MISO and PJM markets. The increase in revenue is primarily the result of the acquisition of new customers and the inclusion of the transmission-related component in MISO retail rates, partially offset by lower unit prices. The acquisition of new customers is primarily due to new commercial and industrial customers as well as new government aggregation contracts with communities in Ohio that provide generation to approximately one million residential and small commercial customers. During January 2010, FES began supplying power to approximately 425,000 NOPEC customers.
The decrease in PLR revenues of $216 million were due to lower sales volumes to the Ohio Companies and lower unit prices, partially offset by increased sales volumes and higher unit prices to the Pennsylvania Companies. The lower sales volumes and unit prices to the Ohio Companies in the first quarter 2010 reflected the results of the May 2009 power procurement processes. The increased revenues to the Pennsylvania Companies resulted from FES supplying Met-Ed and Penelec with volumes previously supplied through a third-party contract and at prices that were slightly higher than in the first quarter of 2009. The increase was partially offset by lower sales to Penn due to decreased default service requirements in 2010 compared to 2009.
Wholesale revenues decreased $102 million due to a 76.3% decline in volume reflecting market declines, partially offset by higher capacity prices.
The following tables summarize the price and volume factors contributing to changes in revenues:
Source of Change in Direct and Government Aggregation | | | |
| | | (In millions) | |
| Direct Sales: | | | | |
Effect of 471.5% increase in sales volumes | | $ | 289 | |
Change in prices | | | (30 | ) |
| | | | 259 | |
| Government Aggregation: | | | | |
Effect of an increase in sales volumes | | | 162 | |
Change in prices | | | - | |
| | | | 162 | |
| Net Increase in Direct and Gov’t Aggregation Revenues | | $ | 421 | |
Source of Change in Wholesale Revenues | | | |
| | | (In millions) | |
| PLR: | | | | |
Effect of 10.2% decrease in sales volumes | | $ | (91 | ) |
Change in prices | | | (125 | ) |
| | | | (216 | ) |
| Wholesale: | | | | |
Effect of 76.3% decrease in sales volumes | | | (112 | ) |
Change in prices | | | 10 | |
| | | | (102 | ) |
| Net Decrease in Wholesale Revenues | | $ | (318 | ) |
Transmission revenues decreased $8 million due primarily to the inclusion of the transmission-related component in the retail rates beginning in mid-2009 as a result of the CBP.
In the first three months of 2010, FES sold $67 million of RECs.
Expenses -
Total expenses increased $312 million in the first quarter of 2010 due to the following:
| · | Fuel costs increased $25 million due to increased unit prices ($36 million) partially offset by reduced generation volumes ($11 million). The increase in unit prices was due primarily to higher coal transportation charges ($10 million) and higher nuclear fuel unit prices following the refueling outages that occurred in 2009 ($16 million). |
| · | Purchased power costs increased $290 million due primarily to higher volumes purchased ($300 million) and power contract mark-to-market adjustments ($52 million), partially offset by lower unit costs ($62 million). |
| · | Nuclear operating costs decreased $21 million due primarily to lower labor, employee benefit expenses and professional and contractor costs. The first quarter of 2010 had fewer refueling outages than the first quarter of 2009, decreasing operating costs by approximately $5 million. |
| · | Transmission expense increased $7 million due primarily to increased costs in MISO of $43 million from higher network and ancillary costs, partially offset by lower PJM transmission expense of $36 million due to lower congestion and loss expenses. |
| · | Other expense increased $5 million primarily due to increases in uncollectible customer accounts and agent fees associated with the increase in retail sales. |
| · | Higher depreciation expense of $2 million was due primarily to increased property additions since the first quarter of 2009. |
| · | General taxes increased $3 million due to sales taxes. |
Other Expense –
Total other expense in the first quarter of 2010 was $15 million lower than the first quarter of 2009, primarily due to a $30 million increase in investment income resulting from a reduction to impairments in the value of nuclear decommissioning trust investments, partially offset by a $15 million increase in interest expense. Interest expense increased primarily due to new issuances of long-term debt combined with the restructuring of existing long-term debt.
Other – First Quarter 2010 Compared with First Quarter 2009
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 $17 million decrease in earnings available to FirstEnergy Corp. in the first three months of 2010 compared to the same period in 2009. The decrease resulted primarily from the absence of a favorable tax resolution that occurred in the first quarter of 2009 ($13 million) and charges recorded in the first quarter of 2010 associated with the termination of gas drilling participation rights associated with certain previously owned Ohio properties ($5 million, after tax).
CAPITAL RESOURCES AND LIQUIDITY
FirstEnergy expects its existing sources of liquidity to remain sufficient to meet its anticipated obligations and those of its subsidiaries. FirstEnergy's business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. During 2010 and in subsequent years, FirstEnergy expects to satisfy these requirements with a combination of cash from operations and funds from the capital markets as market conditions warrant. 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, 2010, FirstEnergy's net deficit in working capital (current assets less current liabilities) was principally due to short-term borrowings ($0.9 billion) and the classification of certain variable interest rate PCRBs as currently payable long-term debt. Currently payable long-term debt as of March 31, 2010, included the following (in millions):
| Currently Payable Long-term Debt | | | |
PCRBs supported by bank LOCs(1) | | $ | 1,553 | |
FGCO and NGC unsecured PCRBs(1) | | 65 | |
Penelec FMBs(2) | | 24 | |
| NGC collateralized lease obligation bonds | | 44 | |
| Sinking fund requirements | | 34 | |
Other notes(2) | | 63 | |
| | | $ | 1,783 | |
| | | | |
(1) Interest rate mode permits individual debt holders to put the respective debt back to the issuer prior to maturity. (2) Mature in November 2010. | |
Short-Term Borrowings
FirstEnergy had approximately $0.9 billion of short-term borrowings as of March 31, 2010 and $1.2 billion as of December 31, 2009. FirstEnergy's available liquidity as of April 30, 2010, is summarized in the following table:
| Company | | Type | | Maturity | | Commitment | | Available Liquidity as of April 30, 2010 | |
| | | | | | | (In millions) | |
FirstEnergy(1) | | Revolving | | Aug. 2012 | | $ | 2,750 | | $ | 1,380 | |
| FirstEnergy Solutions | | Bank line | | Mar. 2011 | | | 100 | | | - | |
| Ohio and Pennsylvania Companies | | Receivables financing | | Various(2) | | | 345 | | | 272 | |
| | | | | Subtotal | | $ | 3,195 | | $ | 1,652 | |
| | | | | Cash | | | - | | | 357 | |
| | | | | Total | | $ | 3,195 | | $ | 2,009 | |
| | | | | | | | | | | | |
(1) FirstEnergy Corp. and subsidiary borrowers. (2) Ohio - $200 million (March – May 2010), $250 million (June 2010 – February 2011) matures March 30, 2011; Pennsylvania - $145 million matures December 17, 2010 | |
Revolving Credit Facility
FirstEnergy has the capability to request an increase in the total commitments available under the $2.75 billion revolving credit facility (included in the borrowing capability table above) up to a maximum of $3.25 billion, subject to the discretion of each lender to provide additional commitments. A total of 25 banks participate in the facility, with no one bank having more than 7.3% of the total commitment. 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 as of March 31, 2010:
| | | Revolving | | Regulatory and | |
| | | Credit Facility | | Other Short-Term | |
| | | | | |
| | | (In millions) | |
| FirstEnergy | | $ | 2,750 | | $ | - | (1) |
| FES | | | 1,000 | | | - | (1) |
| OE | | | 500 | | | 500 | |
| Penn | | | 50 | | | 33 | (2) |
| CEI | | | 250 | (3) | | 500 | |
| TE | | | 250 | (3) | | 500 | |
| JCP&L | | | 425 | | | 411 | (2) |
| Met-Ed | | | 250 | | | 300 | (2) |
| Penelec | | | 250 | | | 300 | (2) |
| ATSI | | | 50 | (4) | | 50 | |
(1) No regulatory approvals, statutory or charter limitations applicable. (2) Excluding amounts which may be borrowed under the regulated companies' money pool. (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) The borrowing sub-limit for ATSI may be increased up to $100 million by delivering notice to the administrative agent that ATSI has received regulatory approval to have short-term borrowings up to the same amount. |
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, 2010, FirstEnergy's and its subsidiaries' debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:
| Borrower | | |
FirstEnergy(1) | | 61.2 | % |
| FES | | 54.2 | % |
| OE | | 54.3 | % |
| Penn | | 31.9 | % |
| CEI | | 59.8 | % |
| TE | | 59.5 | % |
| JCP&L | | 36.1 | % |
| Met-Ed | | 39.5 | % |
| Penelec | | 54.2 | % |
| ATSI | | 51.1 | % |
(1)As of March 31, 2010, FirstEnergy could issue additional debt of approximately $2.8 billion, or recognize a reduction in equity of approximately $1.5 billion, and remain within the limitations of the financial covenants required by its revolving credit facility. |
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 Money Pools
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 2010 was 0.4 9% for the regulated companies' money pool and 0.54% for the unregulated companies' money pool.
Pollution Control Revenue Bonds
As of March 31, 2010, FirstEnergy's currently payable long-term debt included approximately $1.6 billion (FES - $1.5 billion, Met-Ed - $29 million and Penelec - $45 million) of variable interest rate PCRBs, the bondholders of which are entitled to the benefit of irrevocable direct pay bank LOCs. The interest rates on the PCRBs are reset daily or weekly. Bondholders can tender their PCRBs for mandatory purchase prior to maturity with the purchase price payable from remarketing proceeds or, if the PCRBs are not successfully remarketed, by drawings on the irrevocable direct pay LOCs. The subsidiary obligor is required to reimburse the applicable LOC bank for any such drawings or, if the LOC bank fails to honor its LOC for any reason, must itself pay the purchase price.
The LOCs for FirstEnergy variable interest rate PCRBs were issued by the following banks as of March 31, 2010:
| | | Aggregate LOC | | | | Reimbursements of |
| LOC Bank | | Amount(3) | | LOC Termination Date | | LOC Draws Due |
| | | (In millions) | | | | |
| CitiBank N.A. | | $ | 166 | | June 2014 | | June 2014 |
| The Bank of Nova Scotia | | 284 | | Beginning April 2011 | | Multiple dates(4) |
| The Royal Bank of Scotland | | 131 | | June 2012 | | 6 months |
KeyBank(1) | | 237 | | June 2010 | | 6 months |
| Wachovia Bank | | 153 | | March 2014 | | March 2014 |
Barclays Bank(2) | | 528 | | Beginning December 2010 | | 30 days |
| PNC Bank | | 70 | | Beginning November 2010 | | 180 days |
| Total | | $ | 1,569 | | | | |
| | | | | | | | |
(1) Supported by four participating banks, with the LOC bank having 58% of the total commitment. (2) Supported by 18 participating banks, with no one bank having more than 14% of the total commitment. (3) Includes approximately $16 million of applicable interest coverage. (4) Shorter of 6 months or LOC termination date ($155 million) and shorter of one year or LOC termination date ($129 million). |
In April 2010, FGCO purchased approximately $235 million variable rate PCRBs and cancelled its $237 million LOC with KeyBank as shown above. FGCO plans to remarket these securities into a fixed rate mode during 2010.
Long-Term Debt Capacity
As of March 31, 2010, the Ohio Companies and Penn had the aggregate capability to issue approximately $2.3 billion of additional FMBs on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMBs by the Ohio Companies 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 FMBs) supporting pollution control notes or similar obligations, or as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE and CEI to incur additional secured debt not otherwise permitted by a specified exception of up to $101 million and $17 mill ion, respectively, as of March 31, 2010. As a result of the indenture provisions, TE cannot incur any additional secured debt. Met-Ed and Penelec had the capability to issue secured debt of approximately $379 million and $345 million, respectively, under provisions of their senior note indentures as of March 31, 2010.
Based upon FGCO's FMB indenture, net earnings and available bondable property additions as of March 31, 2010, FGCO had the capability to issue $2.4 billion of additional FMBs under the terms of that indenture. In June 2009, a new FMB indenture became effective for NGC. Based upon NGC’s FMB indenture, net earnings and available bondable property additions, NGC had the capability to issue $294 million of additional FMBs as of March 31, 2010.
FirstEnergy's access to capital markets and costs of financing are influenced by the ratings of its securities. On February 11, 2010, S&P issued a report lowering FirstEnergy’s and its subsidiaries credit ratings by one notch, while maintaining its stable outlook. Moody’s and Fitch affirmed the ratings and stable outlook of FirstEnergy and its subsidiaries on February 11, 2010. The following table displays FirstEnergy's, FES' and the Utilities' securities ratings as of March 31, 2010.
Issuer | Senior Secured | Senior Unsecured |
| S&P | Moodys | Fitch | S&P | Moodys | Fitch |
| FirstEnergy Corp. | - | - | - | BB+ | Baa3 | BBB |
| | | | | | |
| FirstEnergy Solutions | - | - | - | BBB- | Baa2 | BBB |
| | | | | | |
| Ohio Edison | BBB | A3 | BBB+ | BBB- | Baa2 | BBB |
| | | | | | |
| Pennsylvania Power | BBB+ | A3 | BBB+ | - | - | - |
| | | | | | |
| Cleveland Electric Illuminating | BBB | Baa1 | BBB | BBB- | Baa3 | BBB- |
| | | | | | |
| Toledo Edison | BBB | Baa1 | BBB | - | - | - |
| | | | | | |
| Jersey Central Power & Light | - | - | - | BBB- | Baa2 | BBB+ |
| | | | | | |
| Metropolitan Edison | BBB | A3 | BBB+ | BBB- | Baa2 | BBB |
| | | | | | |
| Pennsylvania Electric | BBB | A3 | BBB+ | BBB- | Baa2 | BBB |
| | | | | | |
| ATSI | - | - | - | BBB- | Baa1 | - |
Changes in Cash Position
As of March 31, 2010, FirstEnergy had $310 million in cash and cash equivalents compared to $874 million as of December 31, 2009. As of March 31, 2010 and December 31, 2009, FirstEnergy had approximately $12 million of restricted cash included in other current assets on the Consolidated Balance Sheet.
During the first three months of 2010, FirstEnergy received $620 million of cash dividends from its subsidiaries and paid $168 million in cash dividends to common shareholders.
Cash Flows From Operating Activities
FirstEnergy's consolidated net cash from operating activities is provided primarily by its competitive energy services and energy delivery services businesses (see Results of Operations above). Net cash provided from operating activities increased by $44 million during the first three months of 2010 compared to the comparable period in 2009, as summarized in the following table:
| | | Three Months Ended March 31 | | | | |
Operating Cash Flows | | 2010 | | 2009 | | Increase (Decrease) | |
| | | (In millions) | |
| Net income | | $ | 149 | | $ | 115 | | $ | 34 | |
| Non-cash charges and other adjustments | | | 367 | | | 375 | | | (8 | ) |
| Working capital and other | | | (10 | ) | | (28 | ) | | 18 | |
| | | $ | 506 | | $ | 462 | | $ | 44 | |
The decrease in non-cash charges and other adjustments is primarily due to lower net amortization of regulatory assets ($106 million), including CEI’s $216 million regulatory asset impairment recorded in the first quarter of 2009, partially offset by higher net deferred income taxes and investment tax credits ($87 million) and an increase in the provision for depreciation ($16 million). The changes in working capital and other primarily resulted from a $104 million decrease in prepayments and other current assets and an $58 million increase in accrued taxes, partially offset by a $52 million decrease in accrued interest, a $44 million increase in receivables and a $31 million increase in cash collateral paid. The change in accrued taxes and prepayments primarily relates to the timing of income ta x payments. The decrease in accrued interest primarily relates to the $1.2 billion tender offer of holding company notes in the third quarter of 2009 combined with the timing of payments relating to new debt issuances in 2009.
Cash Flows From Financing Activities
In the first three months of 2010, cash used for financing activities was $594 million compared to cash provided from financing activities of $70 million in the first three months of 2009. The decrease was primarily due to new debt issuances in 2009 and the repayment of short-term borrowings in 2010, partially offset by decreased long-term debt redemptions in 2010. The following table summarizes security issuances (net of any discounts) and redemptions.
| | | Three Months Ended | |
| | | March 31 | |
Securities Issued or Redeemed | | 2010 | | 2009 | |
| | | (In millions) | |
| New issues | | | | | | | |
| Pollution control notes | | $ | - | | $ | 100 | |
| Unsecured notes | | | - | | | 600 | |
| | | $ | - | | $ | 700 | |
| | | | | | | | |
| Redemptions | | | | | | | |
| Pollution control notes | | $ | - | | $ | 437 | |
| Senior secured notes | | | 9 | | | 7 | |
| Met-Ed unsecured notes | | | 100 | | | - | |
| | | $ | 109 | | $ | 444 | |
| | | | | | | | |
| Short-term borrowings, net | | $ | (295 | ) | $ | - | |
Cash Flows From Investing Activities
Net cash flows used in investing activities resulted primarily from property additions. Additions for the energy delivery services segment primarily represent expenditures related to transmission and distribution facilities. Capital spending by the competitive energy services segment is principally generation-related. The following table summarizes investing activities for the three months ended March 31, 2010 and 2009 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, 2010 | | | | | | | | | |
| | | (166 | | | 62 | | | (7 | | | (111 | |
Competitive energy services | | | (323 | | | - | | | (1 | | | (324 | |
| | | (3 | | | - | | | - | | | (3 | |
Inter-Segment reconciling items | | | (16 | | | (22 | | | - | | | (38 | |
| | | (508 | | | 40 | | | (8 | | | (476 | |
| | | | | | | | | | | | | | |
Three Months Ended March 31, 2009 | | | | | | | | | | | | | |
| | $ | (165 | ) | $ | 51 | | $ | (14 | ) | $ | (128 | ) |
Competitive energy services | | | (421 | ) | | 2 | | | (19 | ) | | (438 | ) |
| | | (49 | ) | | (20 | ) | | 1 | | | (68 | ) |
Inter-Segment reconciling items | | | (19 | ) | | (25 | ) | | - | | | (44 | ) |
| | $ | (654 | ) | $ | 8 | | $ | (32 | ) | $ | (678 | ) |
Net cash used for investing activities in the first three months of 2010 decreased by $202 million compared to the first three months of 2009. The decrease was principally due to a $146 million decrease in property additions, which reflects lower AQC system expenditures, and cash proceeds of approximately $114 million from the sale of assets, partially offset by $101 million relating to the acquisition of customer intangible assets.
During the remaining three quarters of 2010, capital requirements for property additions and capital leases are expected to be approximately $1.1 billion. These cash requirements are expected to be satisfied from a combination of internal cash and short-term credit arrangements.
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 periodguaranteed contracts contain collateral provisions that are contingent upon either FirstEnergy or its subsidiaries’ credit ratings.
As of March 31, 2010, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $4.0 billion, as summarized below:
| | | Maximum | |
Guarantees and Other Assurances | | | |
| | | (In millions) | |
| FirstEnergy Guarantees on Behalf of its Subsidiaries | | | |
Energy and Energy-Related Contracts (1) | | $ | 324 | |
LOC (long-term debt) – interest coverage (2) | | | 6 | |
| FirstEnergy guarantee of OVEC obligations | | | 300 | |
Other (3) | | | 297 | |
| | | | 927 | |
| | | | | |
| Subsidiaries’ Guarantees | | | | |
| Energy and Energy-Related Contracts | | | 54 | |
LOC (long-term debt) – interest coverage (2) | | | 6 | |
| FES’ guarantee of NGC’s nuclear property insurance | | | 77 | |
| FES’ guarantee of FGCO’s sale and leaseback obligations | | | 2,464 | |
| | | | 2,601 | |
| | | | | |
| Surety Bonds | | | 77 | |
LOC (long-term debt) – interest coverage (2) | | | 3 | |
LOC (non-debt) (4)(5) | | | 423 | |
| | | | 503 | |
| Total Guarantees and Other Assurances | | $ | 4,031 | |
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
PCRBs with various maturities. The principal amount of floating-rate PCRBs of
$1.6 billion is reflected in currently payable long-term debt on FirstEnergy’s
consolidated balance sheets.
(3) Includes guarantees of $80 million for nuclear decommissioning funding assurances and $161 million supporting OE’s sale and leaseback arrangement.
(4) Includes $231 million issued for various terms pursuant to LOC capacity availableunder FirstEnergy’s revolving credit facility.
(5) Includes approximately $145 million pledged in connection with the sale andleaseback of Beaver Valley Unit 2 by OE and $47 million pledged in connection with
the sale and leaseback of Perry by OE.
FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate or hedge 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 its 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 satisf ied by FirstEnergy’s assets. FirstEnergy believes 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 to below investment grade, an acceleration or funding obligation, or a “material adverse event,” the immediate posting of cash collateral, provision of a LOC or accelerated payments may be required of the subsidiary. On February 11, 2010, S&P issued a report lowering FirstEnergy’s and its subsidiaries’ credit ratings by one notch, while maintaining its stable outlook. As a result, FirstEnergy was required to post $46 million of collateral. Moody’s and Fitch affirmed the ratings and stable outlook of FirstEnergy and its subsidiaries. As of March 31, 2010, FirstEnergy’s maximum exposure under these collateral provisions was $428 million, as shown below:
| Collateral Provisions | | FES | | Utilities | | Total | |
| | | (In millions) | |
| Credit rating downgrade to below investment grade | | $ | 318 | | $ | 10 | | $ | 328 | |
| Acceleration of payment or funding obligation | | | 15 | | | 48 | | | 63 | |
| Material adverse event | | | 37 | | | - | | | 37 | |
| Total | | $ | 370 | | $ | 58 | | $ | 428 | |
Stress case conditions of a credit rating downgrade or “material adverse event” and hypothetical adverse price movements in the underlying commodity markets would increase the total potential amount to $656 million, consisting of $38 million due to “material adverse event” contractual clauses, $63 million due to an acceleration of payment or funding obligation, and $555 million due to a below investment grade credit rating.
Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $77 million 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.
In addition to guarantees and surety bonds, FES’ contracts, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions which require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ power portfolio as of March 31, 2010, and forward prices as of that date, FES has posted collateral of $270 million. Under a hypothetical adverse change in forward prices (95% confidence level change in forward prices over a one year time horizon), FES would be required to post an additional $168 million. Depending on the volume of forward contracts entered and future price movements, FES could be required to post higher amounts for margining.
In connection with FES’ obligations to post and maintain collateral under the two-year PSA entered into by FES and the Ohio Companies following the CBP auction on May 13-14, 2009, NGC entered into a Surplus Margin Guaranty in an amount up to $500 million. The Surplus Margin Guaranty is secured by an NGC FMB issued in favor of the Ohio Companies.
FES’ debt obligations are generally guaranteed by its subsidiaries, FGCO and NGC, pursuant to guarantees entered into on March 26, 2007. Similar guarantees were entered into on that date pursuant to which FES guaranteed the debt obligations of each of FGCO and NGC. Accordingly, present and future holders of indebtedness of FES, FGCO and NGC will have claims against each of FES, FGCO and NGC regardless of whether their primary obligor is FES, FGCO or NGC.
OFF-BALANCE SHEET ARRANGEMENTS
FES and the Ohio Companies have obligations that are not included on their Consolidated Balance Sheets related to sale and leaseback arrangements involving the Bruce Mansfield Plant, Perry Unit 1 and Beaver Valley Unit 2, which are satisfied through operating lease payments. The total present value of these sale and leaseback operating lease commitments, net of trust investments, is $1.7 billion as of March 31, 2010.
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 associated with 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. Certain derivatives 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 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 structure d pursuant to the Public Utility Regulatory Policies Act of 1978 and certain purchase power contracts (Note 4). The NUG entities non-trading contracts are adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for above-market costs or regulatory liability for below-market costs. The following table sets forth the change in the fair value of commodity derivative contracts related to energy production as of March 31, 2010:
| Increase (Decrease) in the Fair Value of Derivative Contracts | | Non-Hedge | | Hedge | | Total | |
| | | (In millions) | |
| Change in the Fair Value of Commodity Derivative Contracts: | | | | | | | |
Outstanding net liability as of January 1, 2010 | | | (630 | ) | | (15 | ) | | (645 | ) |
Additions/change in value of existing contracts | | | (276 | | | (6 | | | (282 | |
| | | 94 | | | 7 | | | 101 | |
Outstanding net liability as of March 31, 2010(1) | | $ | (812 | ) | $ | (14 | ) | $ | (826 | ) |
| | | | | | | | | | | |
Non-Commodity Net Liabilities as of March 31, 2010: | | | | | | | | | | |
| | | - | | | (2 | ) | | (2 | ) |
| | | | | | | | | | | |
Net Liabilities-Derivative Contracts as of March 31, 2010 | | | (812 | | | (16 | | | (828 | |
| | | | | | | | | | | |
Impact of Changes in Commodity Derivative Contracts(2) | | | | | | | | | | |
Income Statement effects (pre-tax) | | | (27 | | | - | | | (27 | |
| | | | | | | | | | |
| | | - | | | 1 | | | 1 | |
| | | 155 | | | - | | | 155 | |
| | | | | | | | | | | |
(1) Includes $580 million in non-hedge commodity derivative contracts that are primarily related to NUG contracts. NUG contracts are subject to regulatory accounting and do not impact earnings. (2) 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, 2010 as follows:
Balance Sheet Classification | | Non-Hedge | | Hedge | | Total | |
| | | (In millions) | |
| | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | |
| | | 158 | | | 22 | | | 180 | |
Other non-current liabilities | | | (831 | ) | | (30 | ) | | (861 | ) |
| | | (812 | ) | | (16 | ) | | (828 | ) |
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 3 to the consolidated financial statements). Sources of information for the valuation of commodity derivative contracts as of March 31, 2010 are summarized by year in the following table:
| Source of Information | | | | | | | | | | | | | | | |
- Fair Value by Contract Year | | | | | | | | | | | | | | | |
| | | (In millions) | |
Prices actively quoted(1) | | $ | (8 | ) | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | (8 | ) |
Other external sources(2) | | | (409 | ) | | (374 | ) | | (166 | ) | | (59 | ) | | - | | | - | | | (1,008 | ) |
| Prices based on models | | | | | | | | | | | | | | | | ) | | | | | | |
Total(3) | | | | ) | | | ) | | | ) | | | ) | | | ) | | | | | | ) |
(1) Represents exchange traded NYMEX futures and options.
(2) Primarily represents contracts based on broker and ICE quotes.
(3) Includes $580 million in non-hedge commodity derivative contracts that are primarily related to NUG contracts.
NUG contracts are subject to regulatory accounting and do not impact earnings.
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, 2010. Based on derivative contracts held as of March 31, 2010, an adverse 10% change in commodity prices would decrease net income by approximately $4 million during the next 12 months.
Interest Rate Swap Agreements – Fair Value Hedges
FirstEnergy uses fixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. 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, 2010, the debt underlying the $950 million outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 5.5%, which the swaps have converted to a current weighted average variable rate of 3.74%. The fair value of the interest rate swaps designated as fair value hedges was immaterial as o f March 31, 2010.
On April 29, 2010, April 30, 2010 and May 3, 2010, FirstEnergy executed multiple fixed-for-floating interest rate swap agreements with combined notional amounts of $1.3 billion, $300 million and $600 million, respectively, to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. This is consistent with FirstEnergy’s risk management policy and its 2010 financial plan. These derivatives will be 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. As of May 3, 2010, the debt underlying the $2.2 billion outstanding notional amount of interest rate swaps had a weighted average fixed intere st rate of 6%, which the swaps have converted to a current weighted average variable rate of 3.4%.
Forward Starting Swap Agreements - Cash Flow Hedges
FirstEnergy used forward starting swap agreements to hedge a portion of the consolidated interest rate risk associated with issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives were 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 three months of 2010, FirstEnergy terminated forward swaps with a notional value of $100 million. The termination of the forward starting swap agreements did not materially impact FirstEnergy’s net income and no forward starting swap agreements were outstanding as of March 31, 2010.
Equity Price Risk
FirstEnergy provides a noncontributory qualified defined benefit pension plan that covers substantially all of its employees and non-qualified pension plans that cover certain employees. The plan provides defined benefits based on years of service and compensation levels. FirstEnergy also provides health care benefits (which include certain employee contributions, deductibles, and co-payments) upon retirement to employees hired prior to January 1, 2005, their dependents, and under certain circumstances, their survivors. The benefit plan assets and obligations are remeasured annually using a December 31 measurement date or as significant triggering events occur. As of December 31, 2009, the pension plan was underfunded. FirstEnergy currently estimates that additional cash contributions will be required beginning in 2012. The overall actual investment result during 2009 was a gain of 13.6% compared to an assumed 9% positive return. Based on a 6% discount rate, FirstEnergy’s pre-tax net periodic pension and OPEB expense was $24 million in the first quarter of 2010.
Nuclear decommissioning trust funds have been established to satisfy NGC's and the Utilities' nuclear decommissioning obligations. As of March 31, 2010, approximately 17% of the funds were invested in equity securities and 83% were invested in fixed income securities, with limitations related to concentration and investment grade ratings. The equity securities are carried at their market value of approximately $311 million as of March 31, 2010. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $31 million reduction in fair value as of March 31, 2010. The decommissioning trusts of JCP&L and the Pennsylvania Companies are subject to regulatory accounting, with unrealized gains and losses recorded as regulatory assets or liabilities, since the difference between investments held in trust and the decommissioning liabilities will be recovered from or refunded to customers. NGC, OE and TE recognize in earnings the unrealized losses on available-for-sale securities held in their nuclear decommissioning trusts as other-than-temporary impairments. FirstEnergy continues to evaluate the status of its funding obligations for the decommissioning of these nuclear facilities and does not expect to make additional cash contributions to the nuclear decommissioning trusts in 2010 other than the required annual trust contributions.
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, 2010, the largest credit concentration was with J. Aron & Company, which is currently rated investment grade, representing 7.4% of FirstEnergy’s total approved credit risk.
OUTLOOK
As a result of economic conditions and the milder weather experienced in the first quarter of 2010, 2010 distribution sales are expected to be approximately 106 million MWH in 2010, while generation output for 2010 is expected to be 77.1 million MWH.
State Regulatory Matters
Regulatory assets that do not earn a current return totaled approximately $213 million as of March 31, 2010 (JCP&L - $46 million, Met-Ed - $122 million, and Penelec - $47 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 and Penelec. The following table discloses regulatory assets by company:
| | | March 31, | | December 31, | | Increase | |
| Regulatory Assets | | 2010 | | 2009 | | (Decrease) | |
| | | (In millions) | |
| OE | | $ | 432 | | $ | 465 | | $ | (33 | ) |
| CEI | | | 498 | | | 546 | | | (48 | ) |
| TE | | | 82 | | | 70 | | | 12 | |
| JCP&L | | | 856 | | | 888 | | | (32 | ) |
| Met-Ed | | | 393 | | | 357 | | | 36 | |
| Penelec | | | 119 | | | 9 | | | 110 | |
| Other | | | | | | | | | | ) |
| Total | | | | | | | | | | |
Regulatory assets by source are as follows:
| | | March 31, | | December 31, | | Increase | |
| Regulatory Assets By Source | | 2010 | | 2009 | | (Decrease) | |
| | | (In millions) | |
| Regulatory transition costs | | $ | 1,219 | | $ | 1,100 | | $ | 119 | |
| Customer shopping incentives | | | 113 | | | 154 | | | (41 | ) |
| Customer receivables for future income taxes | | | 335 | | | 329 | | | 6 | |
| Loss on reacquired debt | | | 50 | | | 51 | | | (1 | ) |
| Employee postretirement benefits | | | 21 | | | 23 | | | (2 | ) |
| Nuclear decommissioning, decontamination | | | | | | | | | | |
| and spent fuel disposal costs | | | (174 | ) | | (162 | ) | | (12 | ) |
| Asset removal costs | | | (235 | ) | | (231 | ) | | (4 | ) |
| MISO/PJM transmission costs | | | 157 | | | 148 | | | 9 | |
| Fuel costs | | | 377 | | | 369 | | | 8 | |
| Distribution costs | | | 431 | | | 482 | | | (51 | ) |
| Other | | | | | | | | | | |
| Total | | | | | | | | | | |
Reliability Initiatives
In 2005, Congress amended the FPA 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 Utilities 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 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 the 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 FPA 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 result in the imposition of financial penalties that 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, in October 2008, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the PJM region and found it to be in full compliance with all audited reliability standards. FirstEnergy’s MISO facilities are next due for the periodic audit by ReliabilityFirst later this year.
On December 9, 2008, a transformer at JCP&L’s Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations, with customers in the affected area losing power. Power was restored to most customers within a few hours and to all customers within eleven hours. On December 16, 2008, JCP&L provided preliminary information about the event to certain regulatory agencies, including the NERC. On March 31, 2009, the NERC initiated a Compliance Violation Investigation in order to determine JCP&L’s contribution to the electrical event and to review any potential violation of NERC Reliability Standards associated with the event. The initial phase of the investigation required JCP&L to respond to the NERC’s request for factual data about the outage. JCP&L submitted its written response on May 1, 2009. The NERC conducted on site interviews with personnel involved in responding to the event on June 16-17, 2009. On July 7, 2009, the NERC issued additional questions regarding the event and JCP&L replied as requested on August 6, 2009. JCP&L is not able at this time to predict what actions, if any, that the NERC may take based on the data submittals or interview results.
On June 5, 2009, FirstEnergy self-reported to ReliabilityFirst a potential violation of NERC Standard PRC-005 resulting from its inability to validate maintenance records for 20 protection system relays (out of approximately 20,000 reportable relays) in JCP&L’s and Penelec’s transmission systems. These potential violations were discovered during a comprehensive field review of all FirstEnergy substations to verify equipment and maintenance database accuracy. FirstEnergy has completed all mitigation actions, including calibrations and maintenance records for the relays. ReliabilityFirst issued an Initial Notice of Alleged Violation on June 22, 2009. The NERC approved FirstEnergy’s mitigation plan on August 19, 200 9, and submitted it to the FERC for approval on August 19, 2009. FirstEnergy is not able at this time to predict what actions or penalties, if any, that ReliabilityFirst will propose for this self-reported violation.
Ohio
On June 7, 2007, the Ohio Companies filed an application for an increase in electric distribution rates with the PUCO and, on August 6, 2007, updated their filing. On January 21, 2009, the PUCO granted the Ohio Companies’ application in part to increase electric distribution rates by $136.6 million (OE - $68.9 million, CEI - $29.2 million and TE - $38.5 million). These increases went into effect for OE and TE on January 23, 2009, and for CEI on May 1, 2009. Applications for rehearing of this order were filed by the Ohio Companies and one other party on February 20, 2009. The PUCO granted these applications for rehearing on March 18, 2009 for the purpose of further consideration. The PUCO has not yet issued a substantive Entry on Rehearing.
SB221, which became effective on July 31, 2008, required all electric utilities to file an ESP, and permitted the filing of an MRO. On July 31, 2008, the Ohio Companies filed with the PUCO a comprehensive ESP and a separate MRO. The PUCO denied the MRO application; however, the PUCO later granted the Ohio Companies’ application for rehearing for the purpose of further consideration of the matter. The PUCO has not yet issued a substantive Entry on Rehearing. The ESP proposed by the Ohio Companies was approved by the PUCO on December 19, 2008. The Ohio Companies thereafter withdrew and terminated the ESP and continued their rate plan then in effect as allowed by the terms of SB221. On December 31, 2008, the Ohio Companies conducted a CBP for the procurement of electric generation for retail customers from January 5, 2009 through March 31, 2009. Subsequently, FES signed an agreementOn January 9, 2009, the Ohio Companies requested the implementation of a new fuel rider to provide 100% ofrecover the costs resulting from the December 31, 2008 CBP. The PUCO ultimately approved the Ohio Companies’ request for a new fuel rider, which recovered the increased purchased power requirementscosts for OE and TE, and recovered a portion of those costs for CEI, with the remainder being deferred for future recovery.
On February 19, 2009, the Ohio Companies filed an Amended ESP application, including an attached Stipulation and Recommendation that was signed by the Ohio Companies, the Staff of the PUCO, and many of the intervening parties. Specifically, the Amended ESP provided that generation would be provided by FES at the average wholesale rate of the CBP described above for April and May 2009 to the Ohio Companies for their non-shopping customers; for the period Aprilof June 1, 2009 through May 31, 2011, retail generation prices would be based upon the outcome of a descending clock CBP on a slice-of-system basis. The Amended ESP further provided that the Ohio Companies will not seek a base distribution rate increase, subject to certain exceptions, with an effective date of such increase before January 1, 2012, that CEI would agree to w rite-off approximately $216 million of its Extended RTC regulatory asset, and that the Ohio Companies would collect a delivery service improvement rider at an overall average rate of $.002 per KWH for the period of April 1, 2009 through December 31, 2011. The Amended ESP also addressed a number of other issues, including but not limited to, rate design for various customer classes, and resolution of the prudence review and the collection of deferred costs that were approved in prior proceedings. On February 26, 2009, the Ohio Companies filed a Supplemental Stipulation, which was signed or not opposed by virtually all of the parties to the proceeding, that supplemented and modified certain provisions of the February 19, 2009 Stipulation and Recommendation. Specifically, the Supplemental Stipulation modified the provision relating to governmental aggregation and the Generation Service Uncollectible Rider, provided further detail on the allocation of the economic development funding con tained in the Stipulation and Recommendation, and proposed additional provisions related to the collaborative process for the development of energy efficiency programs, among other provisions. The PUCO adopted and approved certain aspects of the Stipulation and Recommendation on March 4, 2009, and adopted and approved the remainder of the Stipulation and Recommendation and Supplemental Stipulation without modification on March 25, 2009. Certain aspects of the Stipulation and Recommendation and Supplemental Stipulation took effect on April 1, 2009 while the remaining provisions took effect on June 1, 2009.
SB221 also requires electric distribution utilities to implement energy efficiency programs. Under the provisions of SB221, the Ohio Companies are required to achieve a total annual energy savings equivalent of approximately 166,000 MWH in 2009, 290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in 2013, with additional savings required through 2025. Utilities are also required to reduce peak demand in 2009 by 1%, with an additional .75% reduction each year thereafter through 2018. The PUCO may amend these benchmarks in certain, limited circumstances, and the Ohio Companies have filed an application with the PUCO seeking such amendments. On January 7, 2010, the PUCO amended the 2009 energy efficiency benchmarks to zero, contingent upon the Ohio Companies meeting the revised benchmarks in a period of not more than three years. On March 10, 2010, the PUCO found that due to a change in PUCO rules subsequent to the filing of the Ohio Companies’ application, the Ohio Companies’ application seeking a reduction of the peak demand reduction requirements was moot. In its March 10, 2010, Entry the PUCO also found that the Companies peak demand reduction programs complied with PUCO rules.
The Ohio Companies are presently involved in collaborative efforts related to energy efficiency programs, including filing applications for approval of those programs with the PUCO, as well as other implementation efforts arising out of the Supplemental Stipulation. On December 15, 2009, the Ohio Companies filed the required three year portfolio plan seeking approval for the programs they intend to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. The PUCO set the matter for a hearing that was completed on March 8, 2010, and all briefing was completed by April 12, 2010. On March 8, 2010, the Ohio Companies filed their 2009 Status Update Report with the PUCO in which they indicated compliance with the 2009 statutory energy efficiency and peak demand benchmarks as those benchmarks were amended as described above. Interested parties filed comments on the Report. The PUCO has yet to address these comments. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers.
In October 2009, the PUCO issued additional Entries modifying certain of its previous rules that set out the manner in which electric utilities, including the Ohio Companies, will be required to comply with benchmarks contained in SB221 related to the employment of alternative energy resources, energy efficiency/peak demand reduction programs as well as greenhouse gas reporting requirements and changes to long term forecast reporting requirements. Applications for rehearing filed in mid-November 2009 were granted on December 9, 2009 for the sole purpose of further consideration of the matters raised in those applications. The PUCO has not yet issued a substantive Entry on Rehearing. The rules implementing the requirements of SB221 went into effect on December 10, 2009.
Additionally under SB221, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they serve in 2009. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RFPs sought RECs, including solar RECs and RECs generated in Ohio in order to meet the Ohio Companies’ alternative energy requirements as set forth in SB221 for 2009, 2010 and 2011. The RECs acquired through these two RFPs will be used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. On December 7, 2009, the Ohio Companies filed an application with the PUCO seeking a force majeure determination regarding the Ohio Companies’ compliance with the 2009 solar energy resources benchmark, and seeking a reduction in the benchmark. On March 10, 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market and thus granted the Ohio Companies’ application seeking force majeure. The PUCO reduced the Ohio Companies’ aggregate 2009 benchmark to the level of solar RECs the Ohio Companies’ acquired through their 2009 RFP processes, provided the Companies’ 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. On April 15, 2010, the Ohio Companies and FES (due to its status as an electric service company in Ohio) filed compliance reports with the PUCO setting forth how they individually satisfied the alternative energy requirements in SB221 for 2009. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark, which application is still pending.
On October 20, 2009, the Ohio Companies filed an MRO to procure electric generation service for the period beginning June 1, 2011. The proposed MRO would establish a CBP to secure generation supply for customers who do not shop with an alternative supplier and would be similar, in all material respects, to the CBP conducted in May 2009 in that it would procure energy, capacity and certain transmission services on a slice of system basis. However, unlike the May 2009 CBP, the MRO would include multiple bidding sessions and multiple products with different delivery periods for generation supply designed to reduce potential volatility and supplier risk and encourage bidder participation. A technical conference was held on October 29, 2009. Hearings took place in December 2009 and the matter has been fully briefed. Pursuant to SB221, the PUCO ha s 90 days from the date of the application to determine whether the MRO meets certain statutory requirements. Although the Ohio Companies requested a PUCO determination by January 18, 2010, on February 3, 2010, the PUCO announced that its determination would be delayed. Under a determination that such statutory requirements are met, the Ohio Companies would be able to implement the MRO and conduct the CBP.
On March 23, 2010, the Ohio Companies filed an application for a new ESP, which if approved by the PUCO, would go into effect on June 1, 2011 and conclude on May 31, 2014. Attached to the application was a Stipulation and Recommendation signed by the Ohio Companies, the Staff of the PUCO, and an additional fourteen parties signing as Signatory Parties, with two additional parties agreeing not to oppose the adoption of the Stipulation. The material terms of the Stipulation include a CBP similar to the one used in May 2009 and the one proposed in the October 2009 MRO filing; a 6% generation discount to certain low-income customers provided by the Ohio Companies through a bilateral wholesale contract with FES; no increase in base distribution rates through May 31, 2014; and a new distribution rider, Delivery Capital Recovery Rider (Rider D CR), to recover a return of, and on, capital investments in the delivery system. This Rider replaces the Delivery Service Improvement Rider (Rider DSI) which terminates by its own terms. The Ohio Companies also agree not to collect certain amounts associated with RTEP and administrative costs associated with the move to PJM. Many of the existing riders approved in the previous ESP remain in effect, some with modifications. The new ESP also requests the resolution of current proceedings pending at the PUCO regarding corporate separation, elements of the smart grid proceeding and the move to PJM. The evidentiary hearing began on April 20, 2010, at the PUCO. The Stipulation requested a decision by the PUCO by May 5, 2010. On April 28, 2010, the PUCO Chairman issued a statement that the PUCO will not issue a decision on May 5, 2010, and will take additional time to review the case record. FirstEnergy recorded approximately $39.5 million of regulatory asset impairments and expenses related to the ESP.
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.
On February 20, 2009, Met-Ed and Penelec filed with the PPUC a generation procurement plan covering the period January 1, 2011 through May 31, 2013. The plan is designed to provide adequate and reliable service via a prudent mix of long-term, short-term and spot market generation supply, as required by Act 129. The plan proposed a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. On August 12, 2009, Met-Ed and Penelec filed a settlement agreement with the PPUC for the generation procurement plan covering the period January 1, 2011, through May 31, 2013, reflecting the settlement on all but two issues. The settlement plan proposes a staggered procurement schedule, which varies by customer class. On September 2, 2009, the ALJ issued a Recommended Decision (RD) approving the settlement and adopted the Met-Ed and Penelec’s positions on two reserved issues. On November 6, 2009, the PPUC entered an Order approving the settlement and finding in favor of Met-Ed and Penelec on the two reserved issues. Generation procurement began in January 2010.
On May 22, 2008, the PPUC approved Met-Ed and Penelec annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. The TSCs included a component for under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received PPUC approval for 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. Various intervenors filed complaints against those filings. In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing Met-Ed to implement the rider June 1, 2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed with its investigation and a litigation schedule was adopted. Hearings and briefing for both Met-Ed and Penelec have concluded. On August 11, 2009, the ALJ issued a Recommended Decision to the PPUC approving Met-Ed’s and Penelec’s TSCs as filed and dismissing all complaints. Exceptions by various interveners were filed and reply exceptions were filed by Met-Ed and Penelec. The PPUC adopted a Motion on January 28, 2010 and subsequently entered an Order on March 3, 2010 which denies the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, directs Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructs Met-Ed and Penelec to work with the various intervening parties to file a recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses collected from ratepayers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. On March 18, 2010, Met-Ed and Penelec filed a Petition with the PPUC requesting that it stay the portion of the March 3, 2010 Order requiring the filing of tariff supplements to end collection of marginal transmission loss costs. By Order entered March 25, 2010, the PPUC granted the requested stay until December 31, 2010. On April 1, 2010, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania appealing the PPUC’s March 3, 2010 Order. Although the ultimate outcome of this matter cannot be determined at this time, it is the belief of Met-Ed and Penelec that they should prevail in the appeal and therefore expect to fully recover the approximately $199.7 million ($158.5 million for Met-Ed and $41.2 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011. On April 2, 2010, Met-Ed and Penelec filed a Response to the PPUC’s March 3, 2010 Order requesting approval of procedures to establish separate accounts to track all marginal transmission loss revenues and related interest and the use of those funds to mitigate future generation rate increases commencing January 1, 2011
On May 28, 2009, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider for the period June 1, 2009 through May 31, 2010 subject to the outcome of the proceeding related to the 2008 TSC filing described above, as required in connection with the PPUC’s January 2007 rate order. For Penelec’s customers the new TSC resulted in an approximate 1% decrease in monthly bills, reflecting projected PJM transmission costs as well as a reconciliation for costs already incurred. The TSC for Met-Ed’s customers increased to recover the additional PJM charges paid by Met-Ed in the previous year and to reflect updated projected costs. In order to gradually transition customers to the higher rate, the PPUC approved Met-Ed’s proposal to continue to recover the prior period deferrals allowed in the PPU C’s May 2008 Order and defer $57.5 million of projected costs to a future TSC to be fully recovered by December 31, 2010. Under this proposal, monthly bills for Met-Ed’s customers would increase approximately 9.4% for the period June 2009 through May 2010.
Act 129 became effective in 2008 and addresses issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters; and alternative energy. Among other things Act 129 required utilities to file with the PPUC an energy efficiency and peak load reduction plan, or EE&C Plan, by July 1, 2009, setting forth the utilities’ plans to reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of 4.5% by May 31, 2013. On July 1, 2009, Met-Ed, Penelec, and Penn filed EE&C Plans with the PPUC in accordance with Act 129. The Pennsylvania Companies submitted a supplemental filing on July 31, 2009, to revise the Total Resource Cost test items in the EE&C Plans pursuant to the PPUC’s June 23, 2009 O rder. Following evidentiary hearings and further revisions to the EE&C Plans, the Pennsylvania Companies filed final plans and tariff revisions on February 5, 2010 consistent with the minor revisions required by the PPUC. The PPUC entered an Order on February 26, 2010 approving the final plans and the tariff rider with rates effective March 1, 2010.
Act 129 also required utilities to file by August 14, 2009 with the PPUC smart meter technology procurement and installation plan to provide for the installation of smart meter technology within 15 years. On August 14, 2009, Met-Ed, Penelec and Penn jointly filed a Smart Meter Technology Procurement and Installation Plan. Consistent with the PPUC’s rules, this plan proposes a 24-month assessment period in which the Pennsylvania Companies will assess their needs, select the necessary technology, secure vendors, train personnel, install and test support equipment, and establish a cost effective and strategic deployment schedule, which currently is expected to be completed in fifteen years. Met-Ed, Penelec and Penn estimate assessment period costs at approximately $29.5 million, which the Pennsylvania Companies, in their plan, proposed to recover through an automatic adjustment clause. An Initial Decision was issued by the presiding ALJ on January 28, 2010. The ALJ’s Initial Decision approved the Smart Meter Plan as modified by the ALJ, including: ensuring that the smart meters to be deployed include the capabilities listed in the PPUC’s Implementation Order; eliminating the provision of interest in the 1307(e) reconciliation; providing for the recovery of reasonable and prudent costs minus resulting savings from installation and use of smart meters; and reflecting that administrative start-up costs be expensed and the costs incurred for research and development in the assessment period be capitalized. On April 15, 2010, the PPUC adopted a Motion by Chairman Cawley that modified the ALJ’s initial decision issued on January 28, 2010, and decided various issues regarding the Smart Meter Implementation Plan (SMIP) for the Pennsylvania Companies. An order consistent with Chairman Cawley’s Motion is anticipated t o be entered in the near future, in which event the Pennsylvania Companies will move forward with the Smart Meter Technology Procurement and Installation Plan.
Legislation addressing rate mitigation and the expiration of rate caps was introduced in the legislative session that ended in 2008; several bills addressing these issues were introduced in the 2009 legislative session. The final form and impact of such legislation is uncertain.
On March 31, 2009, Met-Ed and Penelec submitted their 5-year NUG Statement Compliance filing to the PPUC in accordance with their 1998 Restructuring Settlement. Met-Ed proposed to reduce its CTC rate for the residential class with a corresponding increase in the generation rate and the shopping credit, and Penelec proposed to reduce its CTC rate to zero for all classes with a corresponding increase in the generation rate and the shopping credit. While these changes would result in additional annual generation revenue (Met-Ed - $27 million and Penelec - $59 million), overall rates would remain unchanged. On July 30, 2009, the PPUC entered an order approving the 5-year NUG Statement, approving the reduction of the CTC, and directing Met-Ed and Penelec to file a tariff supplement implementing this change. On July 31, 2009, Met-Ed and Penelec fi led tariff supplements decreasing the CTC rate in compliance with the July 30, 2009 order, and increasing the generation rate in compliance with the Pennsylvania Companies’ Restructuring Orders of 1998. On August 14, 2009, the PPUC issued Secretarial Letters approving Met-Ed and Penelec’s compliance filings.
By Tentative Order entered September 17, 2009, the PPUC provided for an additional 30-day comment period on whether “the Restructuring Settlement allows NUG over-collection for select and isolated months to be used to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists.” In response to the Tentative Order, the Office of Small Business Advocate, Office of Consumer Advocate, York County Solid Waste and Refuse Authority, ARIPPA, the Met-Ed Industrial Users Group and Penelec Industrial Customer Alliance filed comments objecting to the above accounting method utilized by Met-Ed and Penelec. Met-Ed and Penelec filed reply comments on October 26, 2009. On November 5, 2009, the PPUC issued a Secretarial Letter allowing parties to file reply comments to Met-Ed and Penelec’s reply co mments by November 16, 2009, and reply comments were filed by the Office of Consumer Advocate, ARIPPA, and the Met-Ed Industrial Users Group and Penelec Industrial Customer Alliance. Met-Ed and Penelec are awaiting further action by the PPUC.
On February 8, 2010, Penn filed with the PPUC a generation procurement plan covering the period June 1, 2011 through May 31, 2013. The plan is designed to provide adequate and reliable service via a prudent mix of long-term, short-term and spot market generation supply, as required by Act 129. The plan proposed a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. A preliminary conference was held on March 26, 2010, and, among other things, established a procedural schedule. Evidentiary hearings are scheduled for June 15-16, 2010. The PPUC is required to issue an order on the plan no later than November 8, 2010.
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, costs incurred under NUG agreements, and certain other stranded costs, exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of March 31, 2010, the accumulated deferred cost balance totaled approximately $55 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 DPA 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 al so submitted comments in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set. On March 13, 2009, JCP&L filed its annual SBC Petition with the NJBPU that includes a request for a reduction in the level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009. This matter is currently pending before the NJBPU.
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. The EMP was issued on October 22, 2008, establishing five 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; |
| · | meet 30% of the state’s electricity needs with renewable energy by 2020; |
| · | examine smart grid technology and develop additional cogeneration and other generation resources consistent with the state’s greenhouse gas targets; and |
| · | invest in innovative clean energy technologies and businesses to stimulate the industry’s growth in New Jersey. |
On January 28, 2009, the NJBPU adopted an order establishing the general process and contents of specific EMP plans that must be filed by New Jersey electric and gas utilities in order to achieve the goals of the EMP. On April 16, 2010, the BPU issued an order indefinitely suspending the requirement of the New Jersey utilities to submit Utility Master Plans until such time as the status of the EMP has been made clear. At this time, FirstEnergy and JCP&L cannot determine the impact, if any, the EMP may have on their operations.
In support of former New Jersey Governor Corzine's Economic Assistance and Recovery Plan, JCP&L announced a proposal to spend approximately $98 million on infrastructure and energy efficiency projects in 2009. Under the proposal, an estimated $40 million would be spent on infrastructure projects, including substation upgrades, new transformers, distribution line re-closers and automated breaker operations. In addition, approximately $34 million would be spent implementing new demand response programs as well as expanding on existing programs. Another $11 million would be spent on energy efficiency, specifically replacing transformers and capacitor control systems and installing new LED street lights. The remaining $13 million would be spent on energy efficiency programs that would complement those currently being offered. The project relating to expansion of the existing demand response programs was approved by the NJBPU on August 19, 2009, and implementation began in 2009. Approval for the project related to energy efficiency programs intended to complement those currently being offered was denied by the NJBPU on December 1, 2009. Implementation of the remaining projects is dependent upon resolution of regulatory issues including recovery of the costs associated with the proposal.
On February 11, 2010, S&P downgraded the senior unsecured debt of FirstEnergy Corp. to BB+. As a result, pursuant to the requirements of a pre-existing NJBPU order, JCP&L filed, on February 17, a plan addressing the mitigation of any effect of the downgrade and which provided an assessment of present and future liquidity necessary to assure JCP&L’s continued payment to BGS suppliers. The NJBPU subsequently held a public hearing to review the plan and available options. On March 17, 2010, the NJBPU determined that JCP&L demonstrated that it has ample resources available to continue uninterrupted payments to BGS suppliers and that there are no concerns with JCP&L's liquidity and therefore no further action is required.
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 multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered 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 subj ect to review and approval by the FERC. A final order is pending before the FERC, and in the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of lower transmission revenue collection associated with an adverse order. On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision. On November 20, 2008, FERC issued an order approving uncontested settlements, but did not rule on the initial decision. On December 19, 2008, an additional order was issued approving two contested settlements. On October 29, 2009, March 17, 2010 and April 8, 2010, FirstEnergy, filed additional settlement agreements with FERC to resolve outstanding claims with various parties. FirstEnergy is actively pursuing settlement agreements with other parties to the case. On December 8, 2009, certain parties sought a writ of mandam us from the DC Circuit Court of Appeals directing FERC to issue an order on the Initial Decision. The Court agreed to hold this matter in abeyance based upon FERC’s representation to use good faith efforts to issue a substantive ruling on the initial decision no later than May 27, 2010. If FERC fails to act, the case will be submitted for briefing in June. The outcome of this matter cannot be predicted.
PJM Transmission Rate
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 on the content of the compliance filings 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. AEP's proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zone s, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order (Opinion 494) 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 rea sonable cost allocation methodology for inclusion in PJM’s tariff.
The FERC’s April 19, 2007 order and related order denying a request for rehearing were appealed to the U.S. Court of Appeals for the Seventh Circuit, which issued a decision on August 6, 2009. The court affirmed FERC’s ratemaking treatment for existing transmission facilities, but found that FERC had not supported its decision to allocate costs for new 500+ kV facilities on a postage-stamp basis and, based on this finding, remanded the rate design issue back to FERC. A request for rehearing and rehearing en banc by two companies was denied by the Seventh Circuit on October 20, 2009.
In an order dated January 21, 2010, FERC set the matter for “paper hearings” – meaning that FERC called for parties to submit comments or written testimony pursuant to the schedule described in the order. FERC identified nine separate issues for comments, and directed PJM to file the first round of comments on February 22, 2010, with other parties submitting responsive comments within 45 days, and reply comments 30 days later. PJM filed certain studies with FERC on April 13, 2010, in response to the FERC order. Interested parties may file responsive comments or studies by May 28, 2010. Reply comments are due by June 28, 2010.
The FERC’s orders on PJM rate design prevented 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 postage-stamp basis reduces the cost of future transmission to be recovered from the JCP&L, Met-Ed and Penelec zones. FERC has no specific time frame to rule in this matter.
RTO Consolidation
On August 17, 2009, FirstEnergy filed an application with the FERC requesting to consolidate its transmission assets and operations into PJM. Currently, FirstEnergy’s transmission assets and operations are divided between PJM and MISO. The consolidation would make the transmission assets that are part of ATSI, whose footprint includes the Ohio Companies and Penn, part of PJM. Most of FirstEnergy’s transmission assets in Pennsylvania and all of the transmission assets in New Jersey already operate as a part of PJM. Key elements of the filing include a Fixed Resource Requirement Plan (FRR Plan) that describes the means whereby capacity will be procured and administered as necessary to satisfy the PJM capacity requirements for the 2011-12 and 2012-13 delivery years; and also a request that ATSI’s transmission customers be excused f rom the costs for regional transmission projects that were approved through PJM’s RTEP process prior to ATSI’s entry into PJM (legacy RTEP costs). The integration is expected to be complete on June 1, 2011, to coincide with delivery of power under the next competitive generation procurement process for the Ohio Companies. To ensure a definitive ruling at the same time the FERC rules on its request to integrate ATSI into PJM, on October 19, 2009, FirstEnergy filed a related complaint with the FERC on the issue of exempting the ATSI footprint from the legacy RTEP costs.
On September 4, 2009, the PUCO opened a case to take comments from Ohio’s stakeholders regarding the RTO consolidation. FirstEnergy filed extensive comments in the PUCO case on September 25, 2009, and reply comments on October 13, 2009, and attended a public meeting on September 15, 2009 to answer questions regarding the RTO consolidation. Several parties have intervened in the regulatory dockets at the FERC and at the PUCO. Certain interveners have commented and protested particular elements of the proposed RTO consolidation, including an exit fee to MISO, integration costs to PJM, and cost-allocations of future transmission upgrades in PJM and MISO.
On December 17, 2009, FERC issued an order approving, these two affiliate sales agreements. FERC authorization for these affiliate salessubject to certain future compliance filings, ATSI’s move to PJM. FirstEnergy’s request to be exempted from legacy RTEP costs was by means of the December 23, 2008 waiver.rejected and its complaint dismissed.
On October 31,December 17, 2009, ATSI executed the PJM Consolidated Transmission Owners Agreement. On December 18, 2009, the Ohio Companies and Penn executed the PJM Operating Agreement and the PJM Reliability Assurance Agreement. Execution of these agreements committed ATSI and the Ohio Companies and Penn’s load to moving into PJM on the schedule described in the application and approved in the FERC Order (June 1, 2011).
On January 15, 2010, the Ohio Companies and Penn submitted a compliance filing describing the process whereby ATSI-zone load serving entities (LSEs) can “opt out” of the Ohio Companies' and Penn's FRR Plan for the 2011-12 and 2012-13 delivery years. On January 16, 2010, FirstEnergy filed for clarification or rehearing of certain issues associated with implementing the FRR auctions on the proposed schedule. On January 19, 2010, FirstEnergy filed for rehearing of FERC’s decision to impose the legacy RTEP costs on ATSI’s transmission customers. Also on January 19, 2010, several parties, including the PUCO and the OCC asked for rehearing of parts of FERC’s order. None of the rehearing parties asked FERC to rescind authorization for ATSI to enter PJM. Instead, parties focused on questions of cost and cost allocation or on alleged errors in implementing the move. On February 3, 2010, FirstEnergy filed an answer to the January 19, 2010 rehearing requests of other parties. On February 16, 2010, FirstEnergy submitted a second compliance filing to FERC; the filing describes communications protocols and performance deficiency penalties for capacity suppliers that are taken in FRR auctions.
On March 10, 2010, FERC granted FirstEnergy’s request for expedited hearing on the conduct of the FRR auctions. The Ohio Companies and Penn obtained their PJM capacity requirements for the 2011 and 2012 delivery years in the FRR auctions conducted March 15-19, 2010. The PJM market monitor certified the FRR auction results on March 25, 2010, and the auction results were released by PJM on March 26, 2010. On March 29, 2010, the Ohio Companies and Penn signed agreements with all winning suppliers. In May 2010, the Ohio Companies and Penn’s load will be included in the PJM Base Residual Auction for the delivery year beginning 2013. FirstEnergy and unaffiliated generation and loads in the ATSI footprint are also expected to participate in the Base Residual Auction. FirstEnergy expects to integrate into PJM effective June 1, 2011.
Changes ordered for PJM Reliability Pricing Model (RPM) Auction
On May 30, 2008, FES executed a Third Restated Partial Requirements Agreement with Met-Ed, Penelec,group of PJM load-serving entities, state commissions, consumer advocates, and Waverly effective November 1, 2008.trade associations (referred to collectively as the RPM Buyers) filed a complaint at the FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the FPA. On September 19, 2008, the FERC denied the RPM Buyers’ complaint. On December 12, 2008, PJM filed proposed tariff amendments that would adjust slightly the RPM program. PJM also requested that the FERC conduct a settlement hearing to address changes to the RPM and suggested that the FERC should rule on the tariff amendments only if settlement could not be reached in January 2009. The Third Restated Partial Requirements Agreement limits the amount of capacity and energy required to be suppliedrequest for settlement hearings was granted. Settlement had not been reached by FES inJanuary 9, 2009 and, accordingly, F irstEnergy and other parties submitted comments on PJM’s proposed tariff amendments. On January 15, 2009, the Chief Judge issued an order terminating settlement discussions. On February 9, 2009, PJM and a group of stakeholders submitted an offer of settlement, which used the PJM December 12, 2008 filing as its starting point, and stated that unless otherwise specified, provisions filed by PJM on December 12, 2008 apply.
On March 26, 2009, the FERC accepted in part, and rejected in part, tariff provisions submitted by PJM, revising certain parts of its RPM. It ordered changes included making incremental improvements to RPM and clarification on certain aspects of the March 26, 2009 Order. On April 27, 2009, PJM submitted a compliance filing addressing the changes the FERC ordered in the March 26, 2009 Order; subsequently, numerous parties filed requests for rehearing of the March 26, 2009 Order. On June 18, 2009, the FERC denied rehearing and request for oral argument of the March 26, 2009 Order.
MISO Complaints Versus PJM
On March 9, 2010, MISO filed two complaints against PJM with FERC under Sections 206, 306, and 309 of the FPA alleging violations of the MISO/PJM Joint Operating Agreement (JOA). In the first complaint, MISO alleged that by failing to roughly two-thirds of these affiliates’ power supply requirements. Met-Ed, Penelec, and Waverly have committed resources in placeaccount for the balancemarket flows from 34 PJM generators over the period from 2007-2009, PJM underpaid MISO by a total of their expected power supply duringroughly $75 million including interest. For the period from 2005-2007, MISO claimed an underpayment by PJM of at least $12 million plus interest. MISO also claimed that PJM failed to maintain required records necessary to calculate underbilling for the 2005-2007 billing.
In the second complaint, MISO alleged that PJM has refused to comply with provisions of the JOA requiring market-to-market dispatch since 2009, and 2010. Underis improperly demanding repayment of redispatch payments previously made to MISO.
PJM filed its answers to the Third Restated Partial Requirements Agreement, Met-Ed, Penelec,complaints on April 12, 2010, opposing the relief sought by MISO. In addition, on April 12, 2010, PJM filed a complaint with FERC pursuant to Section 206, 306, and Waverly are responsible309 alleging that MISO is violating the JOA with PJM by initiating market-to-market coordination and financial settlements for obtaining additional power supply requirements createdsubstitute (proxy) reciprocal coordinated flowgates between MISO and PJM. PJM claims that the JOA does not permit MISO to initiate market-to-market settlements using proxy flowgates in lieu of designated reciprocal coordinated flowgates. This complaint addresses substantially the same issues as the second MISO complaint, in which MISO argues that the use of proxy flowgates is permitted by agreement of the default or failure of supply ofRTOs and operating practice. Each party filed a complaint in order to ensure their committed resources. Prices for the power provided by FES were not changedright to claim refunds, if any, if successful in the Third Restated Partial Requirements Agreement.their arguments at FERC.
FirstEnergy has intervened in all three proceedings, and timely filed comments supporting MISO in its first complaint, relating to improper accounting of market flows resulting in underpayments from 2005-2009. FirstEnergy is unable to predict the outcome of this matter.
Environmental Matters
Various federal, state and local authorities regulate FES and the UtilitiesFirstEnergy with regard to air and water quality and other environmental matters. The effects of compliance on FES and the UtilitiesFirstEnergy with regard to environmental matters could have a material adverse effect on theirFirstEnergy's earnings and competitive position to the extent that they competeit 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.
FES and the Utilities accrueFirstEnergy accrues environmental liabilities only when they concludeit concludes that it is probable that they haveit has an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in FES’ and the Utilities’FirstEnergy’s 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, OE, JCP&L, Met-Ed and Penelec)
FESFirstEnergy 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 $37,500 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. FESFirstEnergy 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 emission limits applicable to the common stack for Bay Shore Units 2, 3 and 4.
FESFirstEnergy 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, the generation of more electricity at lower-emitting plants, and/or using emission allowances. In September 1998, the EPA finalized regulations requiring additional NOX reductions at FES'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. FESFirstEnergy 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.
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 and seven other similar cases are referred to as the NSR cases. OE’s and Penn’s 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 was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plantspla nts through the installation of pollution control devices or repowering and provides for stipulated penalties for failure to install and operate such pollution controls or complete repowering in accordance with that agreement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree, including repowering Burger Units 4 and 5 for biomass fuel consumption, are currently estimated to be $706$399 million for 2009-2012 (with $414 million expected to be spent in 2009).2010-2012.
On May 22,In October 2007, FirstEnergyPennFuture and FGCO received a notice letter, required 60 days prior to the filingthree of its members filed 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,limitations, in the United StatesU.S. 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. In July 2008, three additional complaints were filed against FGCO in the United StatesU.S. District Court for the Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, two of the three complaints seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”, one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint, seeking certification as a class action with the eight named plaintiffs as the class representatives.representa tives. On October 14, 2008,16, 2009, a settlement reached with PennFuture and one of the three individual complainants was approved by the Court, granted FGCO’s motion to consolidate discovery for all four complaints pending againstwhich dismissed the Bruce Mansfield Plant.claims of PennFuture and of the settling individual. The other two non-settling individuals are now represented by counsel handling the three cases filed in July 2008. FGCO believes thethose claims are without merit and intends to defend itself against the allegations made in thesethose three complaints. The Pennsylvania Department of Health, andunder a Cooperative Agreement with the U.S. Agency for Toxic SubstanceSubstances and Disease Registry, recently disclosed their intentioncompleted a Health Consultation regarding the Mansfield Plant and issued a report dated March 31, 2009, which concluded there is insufficient sampling data to conductdetermine if any public health threat exists for area residents due to emissions from the Mansfield Plant. The report recommended additional air monitoring and sample analysis in the vicinity of the Mansfield plant.Plant, which the Pennsylvania Department of Environmental Protection has completed.
OnIn 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. On October 30, 2008, the state of Connecticut filed a Motion to Intervene, which the Court granted on March 24, 2009. Specifically, Connecticut and New Jersey allegesallege that "modifications" at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR or permitting under the CAA's prevention of significant deteriorationPSD program, and seeksseek 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 United States District Court. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed. On October 30, 2008, the state of Connecticut filed a Motion to Intervene, which the Court granted on March 24, 2009. On December 5, 2008, New Jersey filed an amended complaint, adding claims with respect to alleged modifications that occurred after GPU’s sale of the plant. Met-Ed filed a Motion to Dismiss the claims in New Jersey’s AmendedAmende d Complaint and Connecticut’s Complaint in February and September of 2009, respectively. The Court granted Met-Ed's motion to dismiss New Jersey’s and Connecticut’s claims for injunctive relief against Met-Ed, but denied Met-Ed’s motion to dismiss the claims for civil penalties on February 19, 2009. Onstatute of limitations grounds in order to allow the states to prove either that the application of the discovery rule or the doctrine of equitable tolling bars application of the statute of limitations.
In January 14, 2009, the EPA issued a NOV to Reliant alleging new source reviewNSR violations at the Portland Generation Station based on “modifications” dating back to 1986. Met-Ed is unable to predict the outcome of this matter. The EPA’s January 14, 2009, NOV also alleged new source reviewNSR violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. JCP&L, as the former owner of 16.67% of the Keystone Station, and Penelec, as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter.
OnIn June 11, 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. alleging that "modifications" at the Homer City Power Station occurred since 1988 to the present without preconstruction NSR or permitting under the CAA's prevention of significant deteriorationPSD program. Mission Energy is seeking indemnification from Penelec, the co-owner (along with New York State Electric and Gas Company) and operator of the Homer City Power Station prior to its sale in 1999. The scope of Penelec’s indemnity obligation to and from Mission Energy is disputed. Penelec is unable to predict the outcome of this matter.
On May 16, 2008, FGCO received a request fromIn August 2009, the EPA for information pursuant to Section 114(a)issued a Finding of Violation and NOV alleging violations of the CAA for certain operating and maintenance information regardingOhio regulations, including the Eastlake, Lakeshore, Bay ShorePSD, NNSR, and Ashtabula generating plants to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. On July 10, 2008, FGCO and the EPA entered into an Administrative Consent Order modifying that request and setting forth a schedule for FGCO’s response. On October 27, 2008, FGCO received a second request from the EPA for information pursuant to Section 114(a) of the CAA for additional operating and maintenance information regardingTitle V regulations at the Eastlake, Lakeshore, Bay Shore, and Ashtabula generating plants. The EPA’s NOV alleges equipment replacements occurring during maintenance outages dating back to 1990 triggered the pre-construction permitting requirements under the PSD and NNSR programs. In September 2009, FGCO received an information request pursuant to Section 114(a) of the CAA requesting certain operating and maintenance information and planning information regarding the Eastlake, Lake Shore, Bay Shore and Ashtabula generating plants. On November 3, 2009, FGCO received a letter providing notification that the EPA is evaluating whether certain scheduled maintenance at the Eastlake generati ng plant may constitute a major modification under the NSR provision of the CAA. On December 23, 2009, FGCO received another information request regarding emission projections for the Eastlake generating plant pursuant to Section 114(a) of the CAA. FGCO intends to fully comply with the CAA, including EPA’s information requests, but, at this time, is unable to predict the outcome of this matter. A June 2006 finding of violation and NOV in which EPA alleged CAA violations at the Bay Shore Generating Plant remains unresolved and FGCO is unable to predict the outcome of such matter.
OnIn August 18, 2008, FirstEnergy received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding its formerly-owned Avon Lake and Niles generating plants, as well as a copy of a nearly identical request directed to the current owner, Reliant Energy, to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. FirstEnergy intends to fully comply with the EPA’s information request, but, at this time, is unable to predict the outcome of this matter.
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), ultimately capping SO2 emissions in affected states to just 2.5 million tons annually and NOX emissions to just 1.3 million tons annually. CAIR was challenged in the United StatesU.S. Court of Appeals for the District of Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” OnIn September 24, 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. OnIn December 23, 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’sCourt ’s July 11, 2008 opinion. TheOn July 10, 2009, the U.S. Court of Appeals for the District of Columbia ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOX SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the "8-hour" ozone NAAQS. FGCO's future cost of compliance with these regulations may be substantial and will depend, in part, on the action taken by the EPA in response to the Court’s ruling.
MercuryHazardous Air Pollutant 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 StatesU.S . 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 petitioned for rehearing by the entire Court, which denied the petition onin May 20, 2008. OnIn October 17, 2008, the EPA (and an industry group) petitioned the United StatesU.S. Supreme Court for review of the Court’s ruling vacating CAMR. On February 6, 2009, the EPA moved to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the EPA’s petition and denied the industry group’s petition. TheOn April 15, 2010, the EPA is developing newentered into a consent decree requiring it to propose maximum achievable control technology (MACT) regulations for mercury emissionand other hazardous air pollutants by March 16, 2011, and to finalize the regulations by November 16, 2011. On April 29, 2010, the EPA issued proposed MACT regulations requiring emissions reductions of mercury and other hazardous air pollutants from non-electric generating unit boilers, including boilers which do not use fossil fuels such as the proposed Burger biomass repowering project. If finalized, the non-electric generating unit MACT regulations could also provide precedent for MACT standards for coal-fired power plants. FGCO’s future cost of compliance with mercury regulations may be substantial and will dependapplicable to electric generating units. Depending on the action taken by the EPA and on how theyany future regulations are ultimately implemented.implemented, FGCO’s future cost of compliance with MACT regulations may be substantial and changes to FGCO’s operations may result.
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. On January 30,December 23, 2009, the Supreme Court of Pennsylvania affirmed the Commonwealth Court of Pennsylvania declaredruling that Pennsylvania’s mercury rule is “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule. It is anticipated that compliance with these regulations, if the Commonwealth Court’s rulings were reversed on appeal and Pennsylvania’s mercury rule was 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.
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, by 2012, the amount of man-made GHG, including CO2, emitted by developed countries by 2012.countries. The United StatesU.S. signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the United StatesU.S. Senate. However, the Bush administration had 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, former 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, theThe EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuring that 10% of electricity used in the United States comes from renewable sources by 2012, and increasing to 25% by 2025;2025, and implementing an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050.
There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the international level, efforts tothe December 2009 U.N. Climate Change Conference in Copenhagen did not reach a newconsensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement which recognized the scientific view that the increase in global agreementtemperature should be below two degrees Celsius, included a commitment by developed countries to reduce GHGprovide funds, approaching $30 billion over the next three years with a goal of increasing to $100 billion by 2020, and established the “Copenhagen Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. Once they have become a party to the Copenhagen Accord, developed economies, such as the European Union, Japan, Russia, and the United States, would commit to quantified economy-wide emissions post-2012 have begun with the Bali Roadmap, which outlines a two-year process designedtargets from 2020, while developing countries, including Brazil, China, and India, would agree to leadtake mitigation actions, subject to an agreement in 2009.their domestic measurement, reporting, and verification. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the Senate Environment and Public Works Committee hasHouse of Representatives passed one such bill.bill, the American Clean Energy and Security Act of 2009, on June 26, 2009. The Senate continues to consider a number of measures to regulate GHG emissions. 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 StatesU.S. 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. On April 17,In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that will require FirstEnergy to measure GHG emissions commencing in 2010 and submit reports commencing in 2011. Also in September 2009, the EPA proposed new thresholds for GHG emissions that define when CAA permits under the NS R and Title V operating permits programs would be required. The EPA is proposing a major source emissions applicability threshold of 25,000 tons per year (tpy) of carbon dioxide equivalents (CO2e) for existing facilities under the Title V operating permits program and the Prevention of Significant Determination (PSD) portion of NSR. The EPA is also proposing a significance level between 10,000 and 25,000 tpy CO2e to determine if existing major sources making modifications that result in an increase of emissions above the significance level would be required to obtain a PSD permit. In December 2009, the EPA released a “Proposed Endangermentits final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s proposed finding concludes that the atmospheric concentrations of several key greenhouse gases threaten the health and welfare of future generations and that the combined emissions of these gases by motor vehicles contribute to the atmospheric concentrations of these key greenhouse gases and hence toGHG increase the threat of climate change. AlthoughIn April 2010, EPA finalized new GHG standards for model years 2012 to 2016 passenger cars, light-duty trucks and medium-duty passenger vehicles requiring an estimated combined average emissions level of 250 grams of CO2 per mile in model year 2016 and clarified that GHG regulation under the EPA’s proposed finding, if finalized, doesCAA will not establish emission requirementsbe triggered for motor vehicles, such requirements would be expected to occur through further rulemakings. Additionally, while the EPA’s proposed findings do not specifically address stationary sources, including electric generating plants those findings, if finalized, wouldand other stationary sources until January 2, 2011, at the earliest.
On September 21, 2009, the U.S. Court of Appeals for the Second Circuit and on October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit, reversed and remanded lower court decisions that had dismissed complaints alleging damage from GHG emissions on jurisdictional grounds. On February 6, 2010, the Fifth Circuit granted defendants’ petition for rehearing en banc and on April 30, 2010, the Fifth Circuit cancelled the en banc hearing. On March 5, 2010, the Second Circuit denied defendants’ petition for rehearing and rehearing en banc. These cases involve common law tort claims, including public and private nuisance, alleging that GHG emissions contribu te to global warming and result in property damages. While FirstEnergy is not a party to either litigation, should the courts of appeals decisions be expectedaffirmed or not subjected to support the establishmentfurther review, FirstEnergy and/or one or more of future emission requirements by the EPA for stationary sources.its subsidiaries could be named in actions making similar allegations.
FESFirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures.expenditures or result in changes to its operations. The CO2 emissions per KWH of electricity generated by FESFirstEnergy 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'FirstEnergy's plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FES'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 StatesU.S. 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 authoritiesauthoritie s should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. On April 1, 2009, the U.S. Supreme Court of the United States reversed one significant aspect of the Second Circuit Court’s opinion and decided that Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. FESThe EPA is developing a new regulation under Section 316(b) of the Clean Water Act consistent with the opinions of the Supreme Court and the Court of Appeals which have created significant uncertainty about the specific nature, scope and timing of the final performance standard. FirstEnergy is studying various control options and their costs and effectiveness. Depending on the results of such studies and the EPA’s further rulemaking and any action taken by the states exercising best professionalprofess ional judgment, the future costs of compliance with these standards may require material capital expenditures.
The U.S. Attorney's Office in Cleveland, Ohio has advised FGCO that it is considering prosecution under the Clean Water Act and the Migratory Bird Treaty Act for three petroleum spills at the Edgewater, Lakeshore and Bay Shore plants which occurred on November 1, 2005, January 26, 2007 and February 27, 2007. FGCO is unable to predict the outcome of this matter.
Regulation of Waste Disposal(Applicable to FES and each of the Utilities)
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,residuals, 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. In February 2009, the EPA requested comments from the states on options for regulating coal combustion wastes,residuals, including regulation as non-hazardous waste or regulation as a hazardous waste. In March and June 2009, the EPA requested information from FGCO’s Bruce Mansfield Plant regarding the management of coal combustion residuals. In December 2009, the EPA provided to FGCO the findings of its review of t he Bruce Mansfield Plant’s coal combustion residuals management practices. The EPA observed that the waste management structures and the Plant “appeared to be well maintained and in good working order” and recommended only that FGCO “seal and maintain all asphalt surfaces.” On December 30, 2009, in an advanced notice of public rulemaking, the EPA said that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. On May 4, 2010, the EPA issued a proposed rule that provides two options for additional regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA’s hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. FGCO's future cost of compliance with any coal combustion wasteresiduals regulations which may be promulgated could be substantial and willwould depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states.
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of March 31, 2009, FirstEnergy had approximately $1.6 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 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 Utilities have been named as potentially responsible parties 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 potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheetconsolidated balance sheet as of March 31, 2009,2010, based on estimates of the total costs of cleanup, the Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $91$101 million (JCP&L&a mp;L - - $64$74 million, TE - $1 million, CEI - $1 million, FGCO - $1 million and FirstEnergy Corp. - $25$24 million) have been accrued through March 31, 2009.2010. Included in the total are accrued liabilities of approximately $56$67 million for environmental remediation of former manufactured gas plants and gas holder facilities 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, the Muise class action)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 fromdue to the July 1999 service interruptions in the JCP&L territory.outages.
After various motions, rulings and appeals, the Plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, strict product liability, and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. The class was decertified twice by the trial court, and appealed both times by the Plaintiffs, with the results being that: (1) the Appellate Division limited the class only 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 which resulted in planned and unplanned outages in the area during a 2-3 day period, and (2) in March 2007, the Appellate Division remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage modelmo del or individual proof of damages. Proceedings then continued at the trial court level and a case management conference with the presiding Judge was held on June 13, 2008. At that conference, counsel for the Plaintiffs stated his intent to drop his efforts to create a class-wide damage model and, instead of dismissing the class action, expressed his desire for a bifurcated trial on liability and damages. In response, JCP&L filed an objection to the plaintiffs’ proposed trial plan and another motion to decertify the class. On March 31, 2009, the trial court again granted JCP&L’s motion to decertify the class. On April 20, 2009, the Plaintiffs filed theira motion for leave to take an interlocutory appeal to the trial court's decision to decertify the class, which was granted by the Appellate Division on June 15, 2009. Plaintiffs filed their appellate brief on August 25, 2009, and JCP&L filed an opposition brief on September 25, 2009. On or about October 13, 2009, Plaintiffs filed their reply brief in further support of their appeal of the trial court's decision decertifying the class. The Appellate Division heard oral argument on January 5, 2010, before a three-judge panel. JCP&L is awaiting the Court’s decision.
Litigation Relating to the Proposed Allegheny Energy Merger
On December 9, 2008, a transformer at JCP&L’s Oceanview substation failed, resultingIn connection with the proposed merger (Note 14), purported shareholders of Allegheny Energy have filed putative shareholder class action and/or derivative lawsuits in an outage on certain bulk electric system (transmission voltage) lines out of the OceanviewPennsylvania and Atlantic substations, with customersMaryland state courts, as well as in the affected area losing power. Power was restoredU.S. District Court for the Western District of Pennsylvania, against Allegheny Energy and its directors and certain officers, referred to most customers within a few hoursas the Allegheny Energy defendants, FirstEnergy and Merger Sub. The lawsuits allege, among other things, that the Allegheny Energy directors breached their fiduciary duties by approving the merger agreement, and that Allegheny Energy, FirstEnergy and Merger Sub aided and abetted in these alleged breaches of fiduciary duty. The plaintiffs allege that the merger consideration is unfair, that other terms in the merger agreement including the termination fee and the non-solicitation provision s are unfair, that certain individual defendants are financially interested in the merger, and that Allegheny Energy has failed to all customers within eleven hours. On December 16, 2008, JCP&L provided preliminarydisclose material information about the eventmerger to certain regulatory agencies, includingits shareholders. Among other remedies, the NERC.plaintiffs seek to enjoin the merger and they have demanded jury trials. The Allegheny Energy defendants moved to consolidate the Maryland lawsuits and filed motions to dismiss and answers to each of the Maryland complaints. The court consolidated the Maryland lawsuits and an amended complaint has been filed. The Allegheny Energy defendants, FirstEnergy, and Merger Sub filed motions to dismiss the amended complaint on April 21, 2010. The Maryland court has set a hearing for argument on the motions to dismiss for June 3, 2010. By order dated April 26, 2010, the Maryland court certified a plaintiff class that consists of all holders of Allegheny Energy shares at any time from February 11, 2010 to the consummation of the proposed merger. The Pennsylvania state court has consolidat ed the lawsuits filed in that court. The Allegheny Energy defendants and FirstEnergy have moved to stay the Pennsylvania lawsuits and the plaintiff has moved for leave to take expedited discovery. The Pennsylvania state court will hear argument on both motions on May 27, 2010. By stipulation dated April 14, 2010, no response is due to the complaint filed in the U.S. District Court for the Western District of Pennsylvania until June 10, 2010. While FirstEnergy and Allegheny Energy believe the lawsuits are without merit and intend to defend vigorously against the claims, the outcome of any such litigation is inherently uncertain. If a dismissal is not granted or a settlement is not reached, these lawsuits could prevent or delay the completion of the merger and result in substantial costs to FirstEnergy and Allegheny Energy. In accordance with its bylaws, Allegheny Energy will advance expenses to and, as necessary, indemnify all of its directors in connection with the foregoing proceedings. All applicable insur ance policies may not provide sufficient coverage for the claims under these lawsuits, and rights of indemnification with respect to these lawsuits will continue whether or not the merger is completed. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger closes may adversely affect FirstEnergy’s business, financial condition or results of operations.
Nuclear Plant Matters
Davis Besse Control Rod Drive Mechanism Nozzles
During a planned refueling outage at Davis Besse that began on February 28, 2010, FENOC initially identified 16 of the 69 control rod drive mechanism (CRDM) nozzles that required modification. The Nuclear Regulatory Commission was notified of these findings, along with federal, state and local officials. The initial nozzle inspection process included ultrasonic (UT) testing and visual inspections. On March 31, 2009,18, 2010, the NERC initiatedNRC sent a Compliance Violation Investigation in orderspecial inspection team to determine JCP&L’s contribution to the electrical event and to review any potential violation of NERC Reliability Standards associated with the event. The initial phase of the investigation requires JCP&L to respond to NERC’s request for factual data about the outage. JCP&L submitted its written response on May 1, 2009. JCP&L is not able at this time to predict what actions, if any, that NERC will take upon receipt of JCP&L’s response to NERC’s data request.Davis-Besse.
FENOC has begun a comprehensive investigation to determine the underlying cause for the cracking, and retained a contractor to make the necessary modifications. Modifications will be made using a proven industry method subject to NRC review. Further evaluation and testing identified 8 additional nozzles requiring modification. Additional testing will be conducted following the modification of each nozzle to ensure safe, reliable plant operations. The plant is expected to be ready for restart in July, 2010.
Nuclear Plant Matters (Applicable to FES)
On May 14, 2007,April 5, 2010, the OfficeUnion of EnforcementConcerned Scientists (UCS) requested that the NRC issue a Show Cause Order, or otherwise delay the restart of the NRC issued a Demand for Information 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 indicatedDavis Besse Nuclear Power Station until such time 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 providedetermines that adequate protection standards have been met and reasonable assurance exists that FENOCthese standards will continue to operate its licensed facilities in accordance withbe met after the terms of its licenses and the Commission’s regulations.” FENOC was directed to submit the information toplant’s operation is resumed. What actions, if any, the NRC within 30 days. On June 13, 2007, FENOC filed atakes in response to the NRC’s Demand for Information reaffirmingthis request have yet to be determined.
Under NRC regulations, FirstEnergy must ensure that it accepts full responsibility for the mistakes and omissions leading upadequate funds will be available to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s otherdecommission its nuclear plants safely and responsibly. FENOC submitted a supplemental response clarifying certain aspects of the response to the NRC on July 16, 2007. The NRC issued a Confirmatory Order imposing these commitments on FENOC. In an April 23, 2009 Inspection Report, the NRC concluded that FENOC had completed all necessary actionsfacilities. As required by the Confirmatory Order.
In August 2007, FENOC submitted anNRC, FirstEnergy annually recalculates and adjusts the amount of obligations. As of March 31, 2010, FirstEnergy had approximately $1.9 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 renewtransfer the operating licensesownership of Davis Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy provided an additional $80 million parental guarantee associated with the funding of decommissioning costs for these units and indicated that it planned to contribute an additional $80 million to these trusts by 2010. By a letter dated March 8, 2010, primarily as a result of the Beaver ValleyV alley Power Station (Units 1operating license renewal, FENOC requested that the NRC reduce FirstEnergy parental guarantee to $15 million and 2) for annotified the staff that it no longer planned to make the additional 20 years. The NRCcontributions into the trusts. FirstEnergy is required by statute to provide an opportunity for membersawaiting the NRC’s decision on the proposed reduction of the public to request a hearing on the application. No members of the public, however, requested a hearing on the Beaver Valley license renewal application. On September 24, 2008, the NRC issued a draft supplemental Environmental Impact Statement for Beaver Valley. FENOC will continue to work with the NRC Staff as it completes its environmental and technical reviews of the license renewal application, and expects to obtain renewed licenses for the Beaver Valley Power Station in 2009. If renewed licenses are issued by the NRC, the Beaver Valley Power Station’s licenses would be extended until 2036 and 2047 for Units 1 and 2, respectively.parental guarantee.
Other Legal Matters(Applicable to FES and each of the Utilities)
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FES' and the Utilities’FirstEnergy's normal business operations pending against them.FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.
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. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. A final order identifying the individual damage amounts was issued on October 31, 2007 and 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. JCP&L and the union filed briefs in June and July of 2008 and oral arguments were held in the fall. On February 25, 2009, the federal district court denied JCP&L’s motion to vacate the arbitration decision and granted the union’s motion to confirm the award. JCP&L filed a Notice of Appeal to the Third Circuit and a Motion to Stay Enforcement of the Judgment on March 6, 2009;2009. The parties participated in the appeal process could take as long as 24 months.federal court's mediation programs and held private settlement discussions. On April 14, 2010, the parties reached a tentative agreement on a settlement package that must be reviewed and approved by the court. JCP&L recognized a liability for the potential $16 million award in 2005. Post-judgment2005, which has been adjusted for post-judgment interest that began to accrue as of February 25, 2009,2009.
On February 16, 2010, a class action lawsuit was filed in Geauga County Court of Common Pleas against FirstEnergy, CEI and the liability will be adjusted accordingly.
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 assistanceOE seeking declaratory judgment and injunctive relief, as well as compensatory, incidental and consequential damages, on behalf of a federal mediator. FES has a strike mitigation plan ready in the eventclass of a strike.
The union employees at Met-Ed have been working without a labor contract since May 1, 2009. The parties are continuing to bargain and FirstEnergy has a work continuation plan ready in the event of a strike.
FES and the Utilities accrue legal 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. If it were ultimately determined that FES and the Utilities have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on their financial condition, results of operations and cash flows.
New Accounting Standards and Interpretations (Applicable to FES and each of the Utilities)
FSP FAS 157-4 – “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly”
In April 2009, the FASB issued Staff Position FAS 157-4, which provides additional guidance to consider in estimating fair value when there has been a significant decrease in market activity for a financial asset. The FSP establishes a two-step process requiring a reporting entity to first determine if a market is not active in relation to normal market activity for the asset. If evidence indicates the market is not active, an entity would then need to determine whether a quoted price in the market is associated with a distressed transaction. An entity will need to further analyze the transactions or quoted prices, and an adjustment to the transactions or quoted prices may be necessary to estimate fair value. Additional disclosurescustomers related to the inputs and valuation techniques usedreduction of a discount that had previously been in place for residential customers with electric heating, electric water heating, or load management systems. The reduction in the fair value measurements are also required. The FSP is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FES and the Utilities will adopt the FSP for their interim period ending June 30, 2009. While the FSP will expand disclosure requirements, FES and the Utilities do not expect the FSP to have a material effect upon their financial statements.
| FSP FAS 115-2 and FAS 124-2 - “Recognition and Presentation of Other-Than-Temporary Impairments” |
In April 2009, the FASB issued Staff Position FAS 115-2 and FAS 124-2, which changes the method to determine whether an other-than-temporary impairment exists for debt securities and the amount of impairment to be recorded in earnings. Under the FSP, management will be required to assert it does not have the intent to sell the debt security, and it is more likely than not it will not have to sell the debt security before recovery of its cost basis. If management is unable to make these assertions, the debt security will be deemed other-than-temporarily impaired and the security will be written down to fair value with the full charge recorded through earnings. If management is able to make the assertions, but there are credit losses associated with the debt security, the portion of impairment related to credit losses will be recognized in earnings while the remaining impairment will be recognized through other comprehensive income. The FSP is effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FES and the Utilities will adopt the FSP for their interim period ending June 30, 2009 and do not expect the FSP to have a material effect upon their financial statements.
| FSP FAS 107-1 and APB 28-1 - “Interim Disclosures about Fair Value of Financial Instruments” |
In April 2009, the FASB issued Staff Position FAS 107-1 and APB 28-1, which requires disclosures of the fair value of financial instruments in interim financial statements, as well as in annual financial statements. The FSP also requires entities to disclose the methods and significant assumptions used to estimate the fair value of financial instruments in both interim and annual financial statements. The FSP is effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FES and the Utilities will adopt the FSP for their interim period ending June 30, 2009, and expect to expand their disclosures regarding the fair value of financial instruments.
FSP FAS 132 (R)-1 – “Employers’ Disclosures about Postretirement Benefit Plan Assets”
In December 2008, the FASB issued Staff Position FAS 132(R)-1, which provides guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. Requirements of this FSP include disclosures about investment policies and strategies, categories of plan assets, fair value measurements of plan assets, and significant categories of risk. This FSP is effective for fiscal years ending after December 15, 2009. FES and the Utilities will expand their disclosures related to postretirement benefit plan assets as a result of this FSP.
Recent Developments (Applicable to FES and each of the Utilities to the extent indicated)
On April 6, 2009, Richard H. Marsh, Senior Vice President and Chief Financial Officer (CFO) of FirstEnergy indicated his intention to step down as CFO on May 1, 2009, and retire from FirstEnergy effective July 1, 2009. Mr. Marsh was also Senior Vice President and CFO of FES and each of the Utilities except JCP&L and a Director of FES, OE, CEI and TE. On April 8, 2009, FirstEnergy’s Board of Directors elected Mark T. Clark, Executive Vice President and CFO to succeed Mr. Marsh as CFO of FirstEnergy, effective May 1, 2009. Mr. Clark also became Executive Vice President and CFO of FES and each of the Utilities except JCP&L and a Director of FES, OE, CEI and TE, effective May 1, 2009.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. ORGANIZATION AND BASIS OF PRESENTATION
FirstEnergy is a diversified energy company that holds, directly or indirectly, all of the outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of 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, 2008 for FirstEnergy, FES and the Utilities. The consolidated unaudited financial statements of FirstEnergy, FES and each of the Utilities reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain prior year amounts have been reclassified to conform to the current year 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 6) 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) follow the equity 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.
The consolidated financial statements as of March 31, 2009, and for the three-month periods ended March 31, 2009 and 2008, have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their report (dated May 7, 2009) is included 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 a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Securities 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 following table reconciles basic and diluted earnings per share of common stock:
| Reconciliation of Basic and Diluted | | Three Months Ended March 31 | |
| Earnings per Share of Common Stock | | 2009 | | 2008 | |
| | (In millions, except per share amounts) |
| Earnings available to parent | | $ | 119 | | $ | 276 | |
| | | | | | | | |
| Average shares of common stock outstanding – Basic | | | 304 | | | 304 | |
| Assumed exercise of dilutive stock options and awards | | | 2 | | | 3 | |
| Average shares of common stock outstanding – Diluted | | | 306 | | | 307 | |
| | | | | | | | |
| Basic earnings per share of common stock | | $ | 0.39 | | $ | 0.91 | |
| Diluted earnings per share of common stock | | $ | 0.39 | | $ | 0.90 | |
3. FAIR VALUE MEASURES
FirstEnergy’s valuation techniques, including the three levels of the fair value hierarchy as defined by SFAS 157, are disclosed in Note 5 of the Notes to Consolidated Financial Statements in FirstEnergy’s Annual Report.
The following table sets forth FirstEnergy’s financial assets and financial liabilities that are accounted for at fair value by level within the fair value hierarchy as of March 31, 2009 and December 31, 2008. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. FirstEnergy’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the fair valuation of assets and liabilities and their placement within the fair value hierarchy levels.
| Recurring Fair Value Measures | | | | | | | | | |
| as of March 31, 2009 | | Level 1 | | Level 2 | | Level 3 | | Total | |
| | | (In millions) | |
| Assets: | | | | | | | | | | | | | |
| Derivatives | | $ | - | | $ | 43 | | $ | - | | $ | 43 | |
Available-for-sale securities(1) | | | 427 | | | 1,533 | | | - | | | 1,960 | |
NUG contracts(2) | | | - | | | - | | | 340 | | | 340 | |
| Other investments | | | - | | | 80 | | | - | | | 80 | |
| Total | | $ | 427 | | $ | 1,656 | | $ | 340 | | $ | 2,423 | |
| | | | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | | | | |
| Derivatives | | $ | 30 | | $ | 27 | | $ | - | | $ | 57 | |
NUG contracts(2) | | | - | | | - | | | 816 | | | 816 | |
| Total | | $ | 30 | | $ | 27 | | $ | 816 | | $ | 873 | |
(1)
| Primarily consists of investments in nuclear decommissioning trusts, the spent nuclear fuel trusts and the NUG trusts.
Balance excludes $3 million of receivables, payables and accrued income.
|
(2)
| NUG contracts are completely offset by regulatory assets. |
| Recurring Fair Value Measures | | | | | | | | | |
| as of December 31, 2008 | | Level 1 | | Level 2 | | Level 3 | | Total | |
| | | (In millions) | |
| Assets: | | | | | | | | | | | | | |
| Derivatives | | $ | - | | $ | 40 | | $ | - | | $ | 40 | |
Available-for-sale securities(1) | | | 537 | | | 1,464 | | | - | | | 2,001 | |
NUG contracts(2) | | | - | | | - | | | 434 | | | 434 | |
| Other investments | | | - | | | 83 | | | - | | | 83 | |
| Total | | $ | 537 | | $ | 1,587 | | $ | 434 | | $ | 2,558 | |
| | | | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | | | | |
| Derivatives | | $ | 25 | | $ | 31 | | $ | - | | $ | 56 | |
NUG contracts(2) | | | - | | | - | | | 766 | | | 766 | |
| Total | | $ | 25 | | $ | 31 | | $ | 766 | | $ | 822 | |
| (1) | Primarily consists of investments in nuclear decommissioning trusts, the spent nuclear fuel trusts and the NUG trusts.
Balance excludes $5 million of receivables, payables and accrued income.
|
(2) 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 nonperformance risk, including counterparty credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of nonperformance risk was immaterial in the fair value measurements.
The following table sets forth a reconciliation of changes in the fair value of NUG contracts classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2009 and 2008 (in millions):
| | | Three Months Ended March 31 | |
| | | 2009 | | 2008 | |
| Balance as of January 1 | | $ | (332 | ) | $ | (803 | ) |
Settlements(1) | | | 83 | | | 64 | |
Unrealized gains (losses)(1) | | | (227 | ) | | 320 | |
| Net transfers to (from) Level 3 | | | - | | | - | |
| Balance as of March 31, 2009 | | $ | (476 | ) | $ | (419 | ) |
| | | | | | | | |
| Change in unrealized gains (losses) relating to | | | | | | | |
| instruments held as of March 31 | | $ | (227 | ) | $ | 320 | |
| | | | | | | | |
(1) Changes in the fair value of NUG contracts are completely offset by regulatory assets and do not impact earnings. | |
On January 1, 2009, FirstEnergy adopted FSP FAS 157-2, for financial assets and financial liabilities measured at fair value on a non-recurring basis. The impact of SFAS 157 on those financial assets and financial liabilities is immaterial.
4. DERIVATIVE INSTRUMENTS
FirstEnergy is exposed to financial risks resulting from fluctuating 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 for risk management purposes. In addition to derivatives, FirstEnergy also enters into master netting agreements with certain third parties. 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 purchase and normal sales criteria. Derivatives that meet those criteria are accounted for at cost. The changes in the fair value of derivative instruments that do not meet the normal purchase and normal sales criteria are recorded as other expense, as AOCL, or as part of the value of the hedged item as described below.
Interest Rate Derivatives
Under the revolving credit facility, FirstEnergy incurs variable interest charges based on LIBOR. In 2008, FirstEnergy entered into swaps with a notional value of $200 million to hedge against changes in associated interest rates. Hedges with a notional value of $100 million expire in November 2009 and the remainder expire in November 2010. The swaps are accounted for as cash flow hedges under SFAS 133. As of March 31, 2009, the fair value of outstanding swaps was $(4) million.
FirstEnergy uses forward starting swap agreements to hedge a portion of the consolidated interest rate risk associated with issuances of fixed-rate, long-term debt securities of its subsidiaries. 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 quarter of 2009, FirstEnergy terminated forward swaps with a notional value of $100 million when a subsidiary issued long term debt. The gain associated with the termination was $1.3 million, of which $0.3 million was ineffective and recognized as an adjustment to interest expense. The remaining effective portion will be amortized to interest expense over the life of the hedged debt. FirstEnergy currently has no outstanding forward swaps.
As of March 31, 2009 and 2008, the total fair value of outstanding interest rate derivatives was $(4) million and $(3) million, respectively. Interest rate derivatives are located in “Other Noncurrent Liabilities” in FirstEnergy’s consolidated balance sheets. The effect of interest rate derivatives on the statements of income and comprehensive income during the periods ended March 31, 2009 and 2008 were:
| | Three Months Ended |
| | | | |
| | | | 2009 | | | 2008 | |
| Effective Portion | | (in millions) | | |
| | Loss Recognized in AOCL | $ | (2 | ) | $ | - | |
| | Loss Reclassified from AOCL into Interest Expense | | (5 | ) | | (4 | ) |
| Ineffective Portion | | | | | | |
| | Loss Recognized in Interest Expense | | - | | | (1 | ) |
Total unamortized losses included in AOCL associated with prior interest rate hedges totaled $119 million ($70 million net of tax) as of March 31, 2009. Based on current estimates, approximately $11 million will be amortized to interest expense during the next twelve months. FirstEnergy’s interest rate swaps do not include any contingent credit risk related features.
Commodity Derivatives
FirstEnergy uses both physically and financially settled derivatives to manage its exposure to volatility in commodity prices. Commodity derivatives are used for risk management purposes to hedge exposures when it makes economic sense to do so, including circumstances in which the hedging relationship does not qualify for hedge accounting. Derivatives that do not qualify under the normal purchase or sales criteria or for hedge accounting as cash flow hedges are marked to market through earnings. FirstEnergy’s risk policy does not allow derivatives to be used for speculative or trading purposes. FirstEnergy hedges forecasted electric sales and purchases and anticipated natural gas purchases using forwards and options. Heating oil futures are used to hedge both oil purchases and fuel surcharges associated with rail transportation contracts. FirstEnergy’s maximum hedge term is typically two years. The effective portions of all cash flow hedges are initially recorded in AOCL and are subsequently included in net income as the underlying hedged commodities are delivered.
The following tables summarize the location and fair value of commodity derivatives in FirstEnergy’s consolidated balance sheets:
| Derivative Assets | | Derivative Liabilities |
| | | Fair Value | | | | Fair Value |
| | | March 31, | | December 31, | | | | March 31, | | December 31, |
| | | 2009 | | 2008 | | | | 2009 | | 2008 |
| Cash Flow Hedges | | (in millions) | | Cash Flow Hedges | | (in millions) |
| Electricity Forwards | | | | | | Electricity Forwards | | | | |
| | Current Assets | $ | 23 | $ | 11 | | | Current Liabilities | $ | 23 | $ | 27 |
| Natural Gas Futures | | | | | | Natural Gas Futures | | | | |
| | Current Assets | | - | | - | | | Current Liabilities | | 11 | | 4 |
| | Long-Term Deferred Charges | | - | | - | | | Noncurrent Liabilities | | 5 | | 5 |
| Other | | | | | | Other | | | | |
| | Current Assets | | - | | - | | | Current Liabilities | | 10 | | 12 |
| | Long-Term Deferred Charges | | - | | - | | | Noncurrent Liabilities | | 3 | | 4 |
| | | $ | 23 | $ | 11 | | | $ | 52 | $ | 52 |
| | | | | | | | |
| Derivative Assets | | Derivative Liabilities |
| | | | Fair Value | | | | Fair Value |
| | | | March 31, 2009 | | December 31, 2008 | | | | March 31, 2009 | | December 31, 2008 |
| Economic Hedges | | (in millions) | | Economic Hedges | | (in millions) |
| NUG Contracts | | | | NUG Contracts | | |
| | Power Purchase | $ | 340 | $ | 434 | | | Power Purchase | $ | 816 | $ | 766 |
| | Contract Asset | | | | | | | Contract Liability | | | | |
| Other | | | | | | Other | | | | |
| | Current Assets | | 1 | | 1 | | | Current Liabilities | | 1 | | 1 |
| | Long-Term Deferred Charges | | 19 | | 28 | | | Noncurrent Liabilities | | - | | - |
| | | $ | 360 | $ | 463 | | | $ | 817 | $ | 767 |
| Total Commodity Derivatives | $ | 383 | $ | 474 | | Total Commodity Derivatives | $ | 869 | $ | 819 |
Electricity forwards are used to balance expected retail and wholesale sales with expected generation and purchased power. Natural gas futures are entered into based on expected consumption of natural gas, primarily used in FirstEnergy’s peaking units. Heating oil futures are entered into based on expected consumption of oil and the financial risk in FirstEnergy’s transportation contracts. Derivative instruments are not used in quantities greater than forecasted needs. The following table summarizes the volume of FirstEnergy’s outstanding derivative transactions as of March 31, 2009.
| | Purchases | | Sales | | Net | | Units | |
| | | (in thousands) | |
| Electricity Forwards | | 772 | | | (1,735 | ) | | (963 | ) | | MWh | |
| Heating Oil Futures | | 20,496 | | | (2,520 | ) | | 17,976 | | | Gallons | |
| Natural Gas Futures | | 4,850 | | | - | | | 4,850 | | | mmBtu | |
The effect of derivative instruments on the consolidated statements of income and comprehensive income for the three months ended March 31, 2009 and 2008, for instruments designated in cash flow hedging relationships and not in hedging relationships, respectively, are summarized in the following tables:
| Derivatives in Cash Flow Hedging Relationships | Electricity | | | Natural Gas | | | Heating Oil | | | | |
| | | Forwards | | | Futures | | | Futures | | | Total | |
| 2009 | | (in millions) | |
| Gain (Loss) Recognized in AOCL (Effective Portion) | $ | (2 | ) | $ | (7 | ) | $ | (1 | ) | $ | (10 | ) |
Effective Gain (Loss) Reclassified to:(1) | | | | | | | | | | | |
| | Purchased Power Expense | | (18 | ) | | - | | | - | | | (18 | ) |
| | Fuel Expense | | - | | | - | | | (4 | ) | | (4 | ) |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| 2008 | | | | | | | | | | | | |
| Gain (Loss) Recognized in AOCL (Effective Portion) | $ | (14 | ) | $ | 3 | | $ | - | | $ | (11 | ) |
Effective Gain (Loss) Reclassified to:(1) | | | | | | | | | | | |
| | Purchased Power Expense | | (17 | ) | | - | | | - | | | (17 | ) |
| | Fuel Expense | | - | | | - | | | - | | | | |
| | | | | | | | | | | | | |
(1) The ineffective portion was immaterial. | | | | | | | | | | | | |
| Derivatives Not in Hedging Relationships | NUG | | | | | | | |
| | | | Contracts | | | Other | | | Total | |
| 2009 | | (in millions) |
| Unrealized Gain (Loss) Recognized in: | | | | | | | | | |
Regulatory Assets(1) | $ | (227 | ) | $ | - | | $ | (227 | ) |
| Realized Gain (Loss) Reclassified to: | | | | | | | | | | |
Fuel Expense(2) | | $ | - | | $ | (1 | ) | $ | (1 | ) |
Regulatory Assets(3) | | | (83 | ) | | 10 | | | (73 | ) |
| | | $ | (83 | ) | $ | 9 | | $ | (74 | ) |
| 2008 | | | | | | | | | | |
| Unrealized Gain (Loss) Recognized in: | | | | | | | | | |
Regulatory Assets(1) | $ | 320 | | $ | - | | $ | 320 | |
| | | | | | | | | | |
| Realized Gain (Loss) Reclassified to: | | | | | | | | | | |
| | Regulatory Assets(3) | $ | (64 | ) | $ | 11 | | $ | (53 | ) |
| | | | | | | | | | | | |
(1) | Changes in the fair value of NUG Contracts are deferred for future recovery from (or refund to) customers. |
| (2) | The realized gain (loss) is reclassified upon termination of the derivative instrument |
| (3) | The above market cost of NUG power is deferred for future recovery from (or refund to) customers. |
Total unamortized losses included in AOCL associated with commodity derivatives were $32 million ($19 million net of tax) as of March 31, 2009, as compared to $44 million ($27 million net of tax) as of December 31, 2008. The change (net of tax) resulted from a net $5 million increase related to current hedging activity and a $13 million decrease due to net hedge losses reclassified to earnings during the first quarter of 2009. Based on current estimates, approximately $15 million (after tax) of the net deferred losses on derivative instruments in AOCL as of March 31, 2009 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.
Many of FirstEnergy’s commodity derivatives contain credit risk features. As of March 31, 2009, FirstEnergy posted $141 million of collateral related to net liability positions and held no counterparties’ funds related to asset positions. The collateral FirstEnergy has posted relates to both derivative and non-derivative contracts. FirstEnergy’s largest derivative counterparties fully collateralize all derivative transactions. Certain commodity derivative contracts include credit-risk-related contingent features that would require FirstEnergy to post additional collateral if the credit rating for its debt were to fall below investment grade. The aggregate fair value of derivative instruments with credit-risk related contingent features that are in a liability position on March 31, 2009 was $4 million, for which no collateral has been posted. If FirstEnergy’s credit rating were to fall below investment grade, it would be required to post $4 million of additional collateral related to commodity derivatives.
5. PENSION AND OTHER POSTRETIREMENT BENEFITS
FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees. The 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. 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. In addition, FirstEnergy has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.
For the three months ended March 31, 2009 and 2008, FirstEnergy’s net pension and OPEB expense (benefit) was $43 million and $(15) million, respectively. The components of FirstEnergy's net pension and other postretirement benefit cost (including amounts capitalized) for the three months ended March 31, 2009 and 2008, consisted of the following:
| | | Pension Benefits | | Other Postretirement Benefits | |
| | | 2009 | | 2008 | | 2009 | | 2008 | |
| | | (In millions) | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Expected return on plan assets | | | | | | | | | | | | | |
Amortization of prior service cost | | | | | | | | | | | | | |
Recognized net actuarial loss | | | | | | | | | | | | | |
Net periodic cost (credit) | | | | | | | ) | | | ) | | | ) |
Pension and postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. The Companies capitalize employee benefits related to construction projects. The net pension and other postretirement benefit costs (including amounts capitalized) recognized by each of the Companies for the three months ended March 31, 2009 and 2008 were as follows:
| | | Pension Benefit Cost (Credit) | | Other Postretirement Benefit Cost (Credit) | |
| | | 2009 | | 2008 | | 2009 | | 2008 | |
| | | (In millions) | |
| | | | | | | | | | ) | | | ) |
| | | | | | | ) | | | ) | | | ) |
| | | | | | | ) | | | | | | |
| | | | | | | ) | | | | | | |
| | | | | | | | | | | | | ) |
| | | | | | | | | | | | | ) |
| | | | | | | | | | | | | ) |
Other FirstEnergy subsidiaries | | | | | | | | | | | | | ) |
| | | | | | | | ) | | | ) | | | ) |
6. VARIABLE INTEREST ENTITIES
FirstEnergy and its subsidiaries consolidate VIEs when they are determined to be the VIE's primary beneficiary as defined by FIN 46R. Effective January 1, 2009, FirstEnergy adopted SFAS 160. As a result, FirstEnergy and its subsidiaries reflect the portion of VIEs not owned by them in the caption noncontrolling interest within the consolidated financial statements. The change in noncontrolling interest within the Consolidated Balance Sheets is the result of earnings and losses of the noncontrolling interests and distributions to owners.
Mining Operations
On July 16, 2008, FEV entered into a joint venture with the Boich Companies, a Columbus, Ohio-based coal company, to acquire a majority stake in the Signal Peak mining and coal transportation operations near Roundup, Montana. FEV made a $125 million equity investment in the joint venture, which acquired 80% of the mining operations (Signal Peak Energy, LLC) and 100% of the transportation operations, with FEV owning a 45% economic interest and an affiliate of the Boich Companies owning a 55% economic interest in the joint venture. Both parties have a 50% voting interest in the joint venture. In March 2009, FEV agreed to pay a total of $8.5 million (of which $1.7 million was paid in March 2009) to affiliates of the Boich Companies to purchase an additional 5% economic interest in the Signal Peak mining and coal transportation operations. Voting interests will remain unchanged after the sale is completed in July 2009. Effective January 16, 2010, the joint venture will have 18 months to exercise an option to acquire the remaining 20% stake in the mining operations. In accordance with FIN 46R, FEV consolidates the mining and transportation operations of this joint venture in its financial statements.
Trusts
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 for the purchase of lease obligation bonds. 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.
Loss Contingencies
FES and the Ohio Companies are exposed to losses under their applicable sale-leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events that render the applicable plant worthless. Net discounted lease payments would not be payable if the casualty loss payments were made. The following table discloses each company’s net exposure to loss based upon the casualty value provisions mentioned above:
| | | Maximum Exposure | | Discounted Lease Payments, net(1) | | Net Exposure |
| | | (In millions) |
| FES | | $ | 1,373 | | $ | 1,202 | | $ | 171 |
| OE | | 759 | | 587 | | 172 |
| CEI | | 740 | | 73 | | 667 |
| TE | | 740 | | 419 | | 321 |
| (1) The net present value of FirstEnergy’s consolidated sale and leaseback operating
lease commitments is $1.7 billion
|
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 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.
During the second quarter of 2008, NGC purchased 56.8 MW of lessor equity interests in the OE 1987 sale and leaseback of the Perry Plant and approximately 43.5 MW of lessor equity interests in the OE 1987 sale and leaseback of Beaver Valley Unit 2. In addition, NGC purchased 158.5 MW of lessor equity interests in the TE and CEI 1987 sale and leaseback of Beaver Valley Unit 2. The Ohio Companies continue to lease these MW under their respective sale and leaseback arrangements and the related lease debt remains outstanding.
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 24 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 may incur for power. FirstEnergy expects any above-market costs it incurs to be recovered from customers. Purchased power costs from these entities during the three months ended March 31, 2009 and 2008 are shown in the following table:
| | | Three Months Ended | |
| | | March 31, | |
| | | 2009 | | 2008 | |
| | | (In millions) | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | | |
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 March 31, 2009, $363 million of the transition bonds were 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 payable from TBC collections.
7. INCOME TAXES
FirstEnergy accounts for uncertainty in income taxes recognized in a company’s financial statements in accordance with FIN 48. 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. Upon completion of the federal tax examination for the 2007 tax year in the first quarter of 2009, FirstEnergy recognized $13 million in tax benefits, which favorably affected FirstEnergy’s effective tax rate. During the first three months of 2008, there were no material changes to FirstEnergy’s unrecognized tax benefits. As of March 31, 2009, FirstEnergy expects that it is reasonably possible that $193 million of the unrecognized benefits may be resolved within the next twelve months, of which approximately $148 million, if recognized, would affect FirstEnergy’s effective tax rate. The potential decrease in the amount of unrecognized tax benefits is primarily associated with issues related to the capitalization of certain costs, gains and losses recognized on the disposition of assets and various other tax items.
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. The net amount of accumulated interest accrued as of March 31, 2009 was $61 million, as compared to $59 million as of December 31, 2008. During the first three months of 2009 and 2008, 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 2001-2008. The IRS began reviewing returns for the years 2001-2003 in July 2004 and several items are under appeal. The federal audits for the years 2004-2006 were completed in 2008 and several items are under appeal. The IRS began auditing the year 2007 in February 2007 under its Compliance Assurance Process program and was completed in the first quarter of 2009 with two items under appeal. The IRS began auditing the year 2008 in February 2008 and the year 2009 in February 2009 under its Compliance Assurance Process program. Neither audit is expected to close before December 2009. 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.
8. 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 March 31, 2009, outstanding guarantees and other assurances aggregated approximately $4.5 billion, consisting of parental guarantees - $1.2 billion, subsidiaries’ guarantees - $2.6 billion, surety bonds - $0.1 billion and LOCs - $0.6 billion.
FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate or hedge 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 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 $0.4 billion (included in the $1.2 billion discussed above) as of March 31, 2009 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 downgrade or “material adverse event,” the immediate posting of cash collateral, provision of an LOC or accelerated payments may be required of the subsidiary. As of March 31, 2009, FirstEnergy's maximum exposure under these collateral provisions was $761 million, consisting of $55 million due to “material adverse event” contractual clauses and $706 million due to a below investment grade credit rating. Additionally, stress case conditions of a credit rating downgrade or “material adverse event” and hypothetical adverse price movements in the underlying commodity markets would increase this amount to $830 million, consisting of $54 million due to “material adverse event” contractual clauses and $776 million due to a below investment grade credit rating.
Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $111 million 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.
In addition to guarantees and surety bonds, FES’ contracts, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions which require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ contracts as of March 31, 2009, and forward prices as of that date, FES had $205 million of outstanding collateral payments. Under a hypothetical adverse change in forward prices (15% decrease in the first 12 months and 20% decrease in prices thereafter), FES would be required to post an additional $77 million. Depending on the volume of forward contracts entered and future price movements, FES could be required to post significantly higher amounts for margining.
In July 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has fully and unconditionally guaranteed all of FGCO’s obligations under each of the leases (see Note 12). 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.
On October 8, 2008, to enhance their liquidity position in the face of the turbulent credit and bond markets, FirstEnergy, FES and FGCO entered into a $300 million secured term loan facility with Credit Suisse. Under the facility, FGCO is the borrower and FES and FirstEnergy are guarantors. Generally, the facility is available to FGCO until October 7, 2009, with a minimum borrowing amount of $100 million and maturity 30 days from the date of the borrowing. Once repaid, borrowings may not be re-borrowed.
(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 $808 million for the period 2009-2013.
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 $37,500 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 emission limits 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, the generation of more electricity at lower-emitting plants, and/or using emission allowances. 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.
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 and seven other similar cases are referred to as the NSR cases. OE’s and Penn’s settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigationdiscount was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices or repowering and provides for stipulated penalties for failure to install and operate such pollution controls or complete repowering in accordance with that agreement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree, including repowering Burger Units 4 and 5 for biomass fuel consumption, are currently estimated to be $706 million for 2009-2012 (with $414 million expected to be spent in 2009).
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. In July 2008, three additional complaints were filed against FGCO in the United States District Court for the Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, two of the complaints seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”, one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint, seeking certification as a class action with the eight named plaintiffs as the class representatives. On October 14, 2008, the Court granted FGCO’s motion to consolidate discovery for all four complaints pending against the Bruce Mansfield Plant. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints. The Pennsylvania Department of Health and the U.S. Agency for Toxic Substance and Disease Registry recently disclosed their intention to conduct additional air monitoring in the vicinity of the Mansfield plant.
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 2005 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.PUCO. On March 14, 2008, Met-Ed18, 2010, the named-defendant companies filed a motion to dismiss the citizen suit claims against it and a stipulation in whichcase due to the parties agreed that GPU, Inc. should be dismissed from this case. On March 26, 2008, GPU, Inc. was dismissed by the United States District Court. The scopelack of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed. On October 30, 2008, the state of Connecticut filed a Motion to Intervene, which the Court granted on March 24, 2009. On December 5, 2008, New Jersey filed an amended complaint, adding claims with respect to alleged modifications that occurred after GPU’s salejurisdiction of the plant. Met-Ed filed a Motion to Dismiss the claims in New Jersey’s Amended Complaintcourt of common pleas. The court has not yet ruled on February 19, 2009. On January 14, 2009, the EPA issued a NOV to Reliant alleging new source review violations at the Portland Generation Station based on “modifications” dating back to 1986. Met-Ed is unable to predict the outcome of this matter. The EPA’s January 14, 2009, NOV also alleged new source review violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. JCP&L, as the former owner of 16.67% of Keystone Station and Penelec, as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter.
On June 11, 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. alleging that "modifications" at the Homer City Power Station occurred since 1988 to the present without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program. Mission Energy is seeking indemnification from Penelec, the co-owner (along with New York State Electric and Gas Company) and operator of the Homer City Power Station prior to its sale in 1999. The scope of Penelec’s indemnity obligation to and from Mission Energy is disputed. Penelec is unable to predict the outcome of this matter.
On May 16, 2008, FGCO received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. On July 10, 2008, FGCO and the EPA entered into an Administrative Consent Order modifying that request and setting forth a schedule for FGCO’s response. On October 27, 2008, FGCO received a second request from the EPA for information pursuant to Section 114(a) of the CAA for additional operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants. FGCO intends to fully comply with the EPA’s information requests, but, at this time, is unable to predict the outcome of this matter.
On August 18, 2008, FirstEnergy received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding its formerly-owned Avon Lake and Niles generating plants, as well as a copy of a nearly identical request directed to the current owner, Reliant Energy, to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. FirstEnergy intends to fully comply with the EPA’s information request, but, at this time, is unable to predict the outcome of this matter.
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), ultimately capping SO2 emissions in affected states to just 2.5 million tons annually and NOX emissions to just 1.3 million tons annually. CAIR was challenged in the United States Court of Appeals for the District of Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” On September 24, 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. On December 23, 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s July 11, 2008 opinion. The future cost of compliance with these regulations may be substantial and will depend, in part, on the action taken by the EPA in response to the Court’s ruling.
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 petitioned for rehearing by the entire Court, which denied the petition on May 20, 2008. On October 17, 2008, the EPA (and an industry group) petitioned the United States Supreme Court for review of the Court’s ruling vacating CAMR. On February 6, 2009, the EPA moved to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the EPA’s petition and denied the industry group’s petition. The EPA is developing 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. On January 30, 2009, the Commonwealth Court of Pennsylvania declared Pennsylvania’s mercury rule “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule. It is anticipated that compliance with these regulations, if the Commonwealth Court’s rulings were reversed on appeal and Pennsylvania’s mercury rule was 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.
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, including CO2, emitted by developed countries by 2012. The United States signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the United States Senate. However, the Bush administration had 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, former 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. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuring that 10% of electricity in the United States comes from renewable sources by 2012, and increasing to 25% by 2025; and implementing an economy-wide cap-and-trade program to reduce GHG emissions 80% by 2050.
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 Environment and Public Works Committee has 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. On April 17, 2009, the EPA released a “Proposed Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s proposed finding concludes that the atmospheric concentrations of several key greenhouse gases threaten the health and welfare of future generations and that the combined emissions of these gases by motor vehicles contribute to the atmospheric concentrations of these key greenhouse gases and hence to the threat of climate change. Although the EPA’s proposed finding, if finalized, does not establish emission requirements for motor vehicles, such requirements would be expected to occur through further rulemakings. Additionally, while the EPA’s proposed findings do not specifically address stationary sources, including electric generating plants, those findings, if finalized, would be expected to support the establishment of future emission requirements by the EPA for stationary sources.
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 to minimize impacts on fish and shellfish from cooling water intake structures. On April 1, 2009, the Supreme Court of the United States reversed one significant aspect of the Second Circuit Court’s opinion and decided that Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. FirstEnergy is studying various control options and their costs and effectiveness. Depending on the results of such studies and the EPA’s further rulemaking and any action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.
The U.S. Attorney's Office in Cleveland, Ohio has advised FGCO that it is considering prosecution under the Clean Water Act and the Migratory Bird Treaty Act for three petroleum spills at the Edgewater, Lakeshore and Bay Shore plants which occurred on November 1, 2005, January 26, 2007 and February 27, 2007. FGCO is unable to predict the outcome of this matter.
Regulation of Waste Disposal
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. In February 2009, the EPA requested comments from the states on options for regulating coal combustion wastes, including regulation as non-hazardous waste or regulation as a hazardous waste. The future cost of compliance with coal combustion waste regulations may be substantial and will depend, in part, on the regulatory action taken by the EPA and implementation by the states.
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of March 31, 2009, FirstEnergy had approximately $1.6 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 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 Utilities have been named as potentially responsible parties 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 potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of March 31, 2009, based on estimates of the total costs of cleanup, the Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $91 million (JCP&L - - $64 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $25 million) have been accrued through March 31, 2009. Included in the total are accrued liabilities of approximately $56 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.
(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, the Muise class action) 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.
After various motions, rulings and appeals, the Plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, strict product liability, and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. The class was decertified twice by the trial court, and appealed both times by the Plaintiffs, with the results being that: (1) the Appellate Division limited the class only 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 which resulted in planned and unplanned outages in the area during a 2-3 day period, and (2) in March 2007, the Appellate Division remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. Proceedings then continued at the trial court level and a case management conference with the presiding Judge was held on June 13, 2008. At that conference, counsel for the Plaintiffs stated his intent to drop his efforts to create a class-wide damage model and, instead of dismissing the class action, expressed his desire for a bifurcated trial on liability and damages. In response, JCP&L filed an objection to the plaintiffs’ proposed trial plan and another motion to decertify the class. On March 31, 2009, the trial court granted JCP&L’s motion to decertify the class. On April 20, 2009, the Plaintiffs filed their appeal to the trial court's decision to decertify the class.
Nuclear Plant Matters
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 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.dismiss. 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 FENOCnamed-defendant companies 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. FENOC submitted a supplemental response clarifying certain aspects of the response to the NRC on July 16, 2007. The NRC issued a Confirmatory Order imposingdefend these commitments on FENOC. In an April 23, 2009 Inspection Report, the NRC concluded that FENOC had completed all necessary actions required by the Confirmatory Order.claims including challenging any class certification.
In August 2007, FENOC submitted an application to the NRC to renew the operating licenses for the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. The NRC is required by statute to provide an opportunity for members of the public to request a hearing on the application. No members of the public, however, requested a hearing on the Beaver Valley license renewal application. On September 24, 2008, the NRC issued a draft supplemental Environmental Impact Statement for Beaver Valley. FENOC will continue to work with the NRC Staff as it completes its environmental and technical reviews of the license renewal application, and expects to obtain renewed licenses for the Beaver Valley Power Station in 2009. If renewed licenses are issued by the NRC, the Beaver Valley Power Station’s licenses would be extended until 2036 and 2047 for Units 1 and 2, respectively.
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.
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. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. A final order identifying the individual damage amounts was issued on October 31, 2007 and 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. JCP&L and the union filed briefs in June and July of 2008 and oral arguments were held in the fall. On February 25, 2009, the federal district court denied JCP&L’s motion to vacate the arbitration decision and granted the union’s motion to confirm the award. JCP&L filed a Notice of Appeal to the Third Circuit and a Motion to Stay Enforcement of the Judgment on March 6, 2009; the appeal process could take as long as 24 months. JCP&L recognized a liability for the potential $16 million award in 2005. Post-judgment interest began to accrue as of February 25, 2009, and the liability will be adjusted accordingly.
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.
The union employees at Met-Ed have been working without a labor contract since May 1, 2009. The parties are continuing to bargain and FirstEnergy has a work continuation 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
9. REGULATORY MATTERS
(A) RELIABILITY INITIATIVES
In 2005, Congress2010, the FASB amended the Federal Power ActDerivatives and Hedging Topic of the FASB Accounting Standards Codification to provideclarify the scope exception for federally-enforceable mandatory reliability standards. The mandatory reliability standards applyembedded credit derivative features related to the bulk power system and impose certain operating, record-keeping and reporting requirements on the Utilities and ATSI. The NERC is charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcementtransfer of its responsibilities to eight regional entities, including ReliabilityFirst Corporation. All of FirstEnergy’s facilities are located within the ReliabilityFirst region. FirstEnergy actively participatescredit risk in the NERCform of subordination of one financial instrument to another. The amendment addresses how to determine which embedded credit derivative features, including those in collateralized debt obligations and ReliabilityFirst stakeholder processes,synthetic collateralized debt obligations, are considered to be embedded derivatives that should not be analyzed under the Derivatives and otherwise monitorsHedging Topic for potential bifurcation and manages its companies in responseseparate accounting. The amendment is effective for the first fiscal quarter beginning after June 15, 2010. FirstEnergy does not expect this standard 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 the 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 result in the imposition of financial penalties and thus have a material adverse effect on its financial condition, results of operations and cash flows.statements.
In April 2007, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the MISO region and found it to be in full compliance with all audited reliability standards. Similarly, in October 2008, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the PJM region and found it to be in full compliance with all audited reliability standards.
On December 9, 2008, a transformer at JCP&L’s Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations, with customers in the affected area losing power. Power was restored to most customers within a few hours and to all customers within eleven hours. On December 16, 2008, JCP&L provided preliminary information about the event to certain regulatory agencies, including the NERC. On March 31, 2009, the NERC initiated a Compliance Violation Investigation in order to determine JCP&L’s contribution to the electrical event and to review any potential violation of NERC Reliability Standards associated with the event. The initial phase of the investigation requires JCP&L to respond to NERC’s request for factual data about the outage. JCP&L submitted its written response on May 1, 2009. JCP&L is not able at this time to predict what actions, if any, that NERC will take upon receipt of JCP&L’s response to NERC’s data request.
FIRSTENERGY SOLUTIONS CORP.(B) OHIO
MANAGEMENT'S NARRATIVE
On June 7, 2007, the Ohio Companies filed an application for an increase in electric distribution rates with the PUCO and, on August 6, 2007, updated their filing to support a distribution rate increase of $332 million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of its investigation into the distribution rate request. On January 21, 2009, the PUCO granted the Ohio Companies’ application to increase electric distribution rates by $136.6 million (OE - $68.9 million, CEI - $29.2 million and TE - $38.5 million). These increases went into effect for OE and TE on January 23, 2009, and will go into effect for CEI on May 1, 2009. Applications for rehearing of this order were filed by the Ohio Companies and one other party on February 20, 2009. The PUCO granted these applications for rehearing on March 18, 2009.
SB221, which became effective on July 31, 2008, required all electric utilities to file an ESP, and permitted the filing of an MRO. On July 31, 2008, the Ohio Companies filed with the PUCO a comprehensive ESP and a separate MRO. The PUCO denied the MRO application; however, the PUCO later granted the Ohio Companies’ application for rehearing for the purpose of further consideration of the matter. The ESP proposed to phase in new generation rates for customers beginning in 2009 for up to a three-year period and resolve the Ohio Companies’ collection of fuel costs deferred in 2006 and 2007, and the distribution rate request described above. In response to the PUCO’s December 19, 2008 order, which significantly modified and approved the ESP as modified, the Ohio Companies notified the PUCO that they were withdrawing and terminating the ESP application in addition to continuing their current rate plan in effect as allowed by the terms of SB221. On December 31, 2008, the Ohio Companies conducted a CBP for the procurement of electric generation for retail customers from January 5, 2009 through March 31, 2009. The average winning bid price was equivalent to a retail rate of 6.98 cents per kwh. The power supply obtained through this process provides generation service to the Ohio Companies’ retail customers who choose not to shop with alternative suppliers. On January 9, 2009, the Ohio Companies requested the implementation of a new fuel rider to recover the costs resulting from the December 31, 2008 CBP. The PUCO ultimately approved the Ohio Companies’ request for a new fuel rider to recover increased costs resulting from the CBP but did not authorize OE and TE to continue collecting RTC or allow the Ohio Companies to continue collections pursuant to the two existing fuel riders. The new fuel rider allows for current recovery of the increased purchased power costs for OE and TE, and authorizes CEI to collect a portion of those costs currently and defer the remainder for future recovery.
On January 29, 2009, the PUCO ordered its Staff to develop a proposal to establish an ESP for the Ohio Companies. On February 19, 2009, the Ohio Companies filed an Amended ESP application, including an attached Stipulation and Recommendation that was signed by the Ohio Companies, the Staff of the PUCO, and many of the intervening parties. Specifically, the Amended ESP provides that generation will be provided by FES at the average wholesale rate of the CBP process described above for April and May 2009 to the Ohio Companies for their non-shopping customers; for the period of June 1, 2009 through May 31, 2011, retail generation prices will be based upon the outcome of a descending clock CBP on a slice-of-system basis. The PUCO may, at its discretion, phase-in a portion of any increase resulting from this CBP process by authorizing deferral of related purchased power costs, subject to specified limits. The Amended ESP further provides that the Ohio Companies will not seek a base distribution rate increase, subject to certain exceptions, with an effective date of such increase before January 1, 2012, that CEI will agree to write-off approximately $216 million of its Extended RTC balance, and that the Ohio Companies will collect a delivery service improvement rider at an overall average rate of $.002 per kWh for the period of April 1, 2009 through December 31, 2011. The Amended ESP also addresses a number of other issues, including but not limited to, rate design for various customer classes, resolution of the prudence review and the collection of deferred costs that were approved in prior proceedings. On February 26, 2009, the Ohio Companies filed a Supplemental Stipulation, which was signed or not opposed by virtually all of the parties to the proceeding, that supplemented and modified certain provisions of the February 19 Stipulation and Recommendation. Specifically, the Supplemental Stipulation modified the provision relating to governmental aggregation and the Generation Service Uncollectible Rider, provided further detail on the allocation of the economic development funding contained in the Stipulation and Recommendation, and proposed additional provisions related to the collaborative process for the development of energy efficiency programs, among other provisions. The PUCO adopted and approved certain aspects of the Stipulation and Recommendation on March 4, 2009, and adopted and approved the remainder of the Stipulation and Recommendation and Supplemental Stipulation without modification on March 25, 2009. Certain aspects of the Stipulation and Recommendation and Supplemental Stipulation take effect on April 1, 2009 while the remaining provisions take effect on June 1, 2009. The CBP auction is currently scheduled to begin on May 13, 2009. The bidding will occur for a single, two-year product and there will not be a load cap for the bidders. FES may participate without limitation.ANALYSIS OF RESULTS OF OPERATIONS
FES is a wholly owned subsidiary of FirstEnergy. FES provides energy-related products and services, and through its subsidiaries, FGCO and NGC, owns or leases and operates and maintains 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.
SB221 also requires electric distribution utilitiesFES' revenues are derived from sales to implement energy efficiencyindividual retail customers, sales to communities in the form of government aggregation programs that achieve an energy savings equivalentand the sale of approximately 166,000 MWH in 2009, 290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in 2013. Utilities are also requiredelectricity to reduce peak demand in 2009 by one percent, with an additional seventy-five hundredths of one percent reduction each year thereafter through 2018. Costs associated with compliance are recoverable from customers.
(C) PENNSYLVANIA
Met-Ed and Penelec purchaseaffiliated utility companies to meet all or a portion of their PLR and default service requirementsrequirements. FES' revenues also include wholesale sales non-affiliated customers in Ohio, Pennsylvania, New Jersey, Maryland, Michigan and Illinois.
The demand for electricity produced and sold by FES, along with the price of that electricity, is impacted by conditions in competitive power markets, global economic activity, economic activity in the Midwest and Mid-Atlantic regions, and weather conditions.
For additional information with respect to FES, please see the information contained in FirstEnergy's Management’s Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Net income decreased to $80 million in the first three months of 2010 compared to $171 million in the same period of 2009. The decrease was primarily due to higher purchased power, fuel and interest expense, partially offset by higher revenues and investment income.
Revenues
Total revenues increased $162 million in the first three months of 2010, primarily due to an increase in direct and government aggregation sales volumes and sales of RECs, partially offset by decreases in PLR sales to the Ohio Companies and wholesale sales.
The increase in revenues resulted from the following sources:
| | | Three Months | | | |
| | | Ended March 31 | | Increase | |
| Revenues by Type of Service | | 2010 | | 2009 | | (Decrease) | |
| | | (In millions) | |
| | | | | | | | |
Direct and Government Aggregation | | | 512 | | | 91 | | | 421 | |
| | | 677 | | | 893 | | | (216 | ) |
| | | 87 | | | 189 | | | (102 | |
| | | 17 | | | 25 | | | (8 | |
| | | 67 | | | - | | | 67 | |
| | | 28 | | | 28 | | | - | |
| | | 1,388 | | | 1,226 | | | 162 | |
Direct and government aggregation revenues increased $421 million resulting from increased revenue in both the MISO and PJM markets. The increase in revenue is primarily the result of the acquisition of new customers and the inclusion of the transmission-related component in MISO retail rates, partially offset by lower unit prices. The acquisition of new customers is primarily due to new commercial and industrial customers as well as new government aggregation contracts with communities in Ohio that provide generation to approximately one million residential and small commercial customers. During January 2010, FES began supplying power to approximately 425,000 NOPEC customers.
PLR revenues decreased $216 million primarily due to lower KWH sales volumes to the Ohio Companies and lower unit prices, partially offset by increased sales volumes and higher unit prices to the Pennsylvania Companies. The lower sales volumes and unit prices to the Ohio Companies in the first three months of 2010 reflected the results of the May 2009 power procurement processes. The increased revenues to the Pennsylvania Companies resulted from FES supplying Met-Ed and Penelec with volumes previously supplied through a fixed-pricethird-party contract and at prices that were slightly higher than in the first quarter of 2009. The increase was partially offset by lower sales to Penn due to decreased default service requirements in 2010 compared to 2009.
Wholesale revenues decreased $102 million due to a 76.3% decline in volume reflecting market declines, partially offset by higher capacity prices.
The following tables summarize the price and volume factors contributing to changes in revenues:
Source of Change in Direct and Government Aggregation | | | |
| | | (In millions) | |
| Direct Sales: | | | | |
Effect of 471.5% increase in sales volumes | | $ | 289 | |
Change in prices | | | (30 | ) |
| | | | 259 | |
| Government Aggregation: | | | | |
Effect of an increase in sales volumes | | | 162 | |
Change in prices | | | - | |
| | | | 162 | |
| Net Increase in Direct and Gov’t Aggregation Revenues | | $ | 421 | |
Source of Change in Wholesale Revenues | | | |
| | | (In millions) | |
| PLR: | | | | |
Effect of 10.2% decrease in sales volumes | | $ | (91 | ) |
Change in prices | | | (125 | ) |
| | | | (216 | ) |
| Wholesale: | | | | |
Effect of 76.3% decrease in sales volumes | | | (112 | ) |
Change in prices | | | 10 | |
| | | | (102 | ) |
| Net Decrease in Wholesale Revenues | | $ | (318 | ) |
Transmission revenues decreased $8 million primarily due to the inclusion of the transmission-related component in retail rates beginning in mid-2009 as a result of the CBP.
In the first three months of 2010, FES sold $67 million of RECs.
Expenses
Total expenses increased $312 million in the first three months of 2010, compared with the same period of 2009.
The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first three months of 2010, from the same period last year:
Source of Change in Fuel and Purchased Power | | | | |
| | | (In millions) | |
| Fossil Fuel: | | | | |
Change due to increased unit costs | | $ | 36 | |
Change due to volume consumed | | | (27 | ) |
| | | | 9 | |
| Nuclear Fuel: | | | | |
Change due to increased unit costs | | | 12 | |
Change due to volume consumed | | | 1 | |
| | | | 13 | |
| Non-affiliated Purchased Power: | | | | |
| Power contract mark-to-market adjustment | | | 52 | |
Change due to decreased unit costs | | | (62 | ) |
Change due to volume purchased | | | 300 | |
| | | | 290 | |
| Affiliated Purchased Power: | | | | |
Change due to increased unit costs | | | (12 | ) |
Change due to volume purchased | | | 10 | |
| | | | (2 | ) |
| Net Increase in Fuel and Purchased Power Costs | | $ | 310 | |
Fossil fuel costs increased $9 million in the first three months of 2010, compared to the same period of 2009, as a result of higher prices, partially offset by reduced volume. The increased costs reflect higher coal transportation charges in the first three months of 2010, compared to the same period last year. Reduced volume reflects lower generation in the first three months of 2010, compared to the same period last year. Nuclear fuel costs increased $13 million, primarily due to the replacement of nuclear fuel at higher unit costs following the refueling outages that occurred in 2009.
Non-affiliated purchased power costs increased $290 million due primarily to higher volumes purchased and a power contract mark-to-market adjustment, partially offset by lower unit costs. The increase in volume primarily relates to the assumption of a 1,300 MW contract from Met-Ed and Penelec.
Other operating expenses decreased $3 million in the first three months of 2010, compared to the same period of 2009, primarily due to lower nuclear operating costs ($21 million), partially offset by increased transmission expenses ($7 million) and increased expenses associated with uncollectible customer accounts and agent fees ($5 million).
Depreciation expense increased $2 million in the first three months of 2010, compared to the same period of 2009 primarily due to increased property additions.
General taxes increased $3 million due to sales taxes associated with increased revenues.
Other Expense
Total other expense decreased $12 million in the first three months of 2010, compared to the same period of 2009, primarily due to a $30 million increase in investment income resulting from reduced impairments in the value of nuclear decommissioning trust investments, partially offset by a $17 million increase in interest expense (net of capitalized interest). Interest expense increased primarily due to new issuances of long-term debt in the second half of 2009 combined with the restructuring of existing long-term debt.
OHIO EDISON COMPANY
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 procure generation services for those franchise customers electing to retain OE and Penn as their power supplier.
For additional information with respect to OE, please see the information contained in FirstEnergy's Management’s Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Earnings available to parent increased to $36 million in the first three months of 2010, compared to $12 million in the same period of 2009. The increase primarily resulted from lower purchased power costs and other operating costs, partially offset by lower revenues.
Revenues
Revenues decreased $241 million, or 32.1%, in the first three months of 2010, compared with the same period in 2009, due to a decrease in generation and distribution revenues.
Retail generation revenues decreased $225 million primarily due to a decrease in KWH sales in all customer classes, partially offset by higher average prices in the commercial and industrial classes. Lower KWH sales in all customer classes were primarily the result of a 41.9% increase in customer shopping in the first three months of 2010. Lower KWH sales to residential customers were also due to decreased weather-related usage, reflecting a 3.5% decrease in heating degree days in OE’s service territory. Higher average prices in the commercial and industrial classes, resulted from the CBP auction for the service period beginning June 1, 2009.
Changes in retail generation sales and revenues in the first three months of 2010, from the same period in 2009, are summarized in the following tables:
| Retail Generation KWH Sales | | | Decrease | |
| | | | |
| Residential | | | (28.1 | )% |
| Commercial | | | (57.2 | )% |
| Industrial | | | (65.4 | )% |
| Decrease in Retail Generation Sales | | | (45.6 | )% |
| Retail Generation Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (78 | ) |
| Commercial | | | (80 | ) |
| Industrial | | | (67 | ) |
| Decrease in Retail Generation Revenues | | $ | (225 | ) |
Distribution revenues decreased $7 million in the first three months of 2010, compared to the same period in 2009, due to lower commercial and industrial revenues, partially offset by higher residential revenues. Commercial and industrial revenues were primarily impacted by lower average unit prices, resulting from lower transmission rates in 2010, partially offset by a PUCO-approved rate increase. Residential distribution revenues were higher due to higher average unit prices resulting from the 2009 ESP, partially offset by lower KWH deliveries resulting from the warmer conditions described above. Increased industrial deliveries were the result of improving economic conditions, reflecting an increase in KWH deliveries to major steel customers (18%) and automotive customers (21%).
Changes in distribution KWH deliveries and revenues in the first three months of 2010, from the same period in 2009, are summarized in the following tables:
| Distribution KWH Deliveries | | Increase (Decrease) | |
| | | | |
| Residential | | | (2.2 | )% |
| Commercial | | | (2.1 | )% |
| Industrial | | | 3.4 | % |
| Net Decrease in Distribution Deliveries | | | (0.6 | )% |
| Distribution Revenues | | Increase (Decrease) | |
| | | (In millions) |
| Residential | | $ | 7 | |
| Commercial | | | (3 | ) |
| Industrial | | | (11 | ) |
| Net Decrease in Distribution Revenues | | $ | (7 | ) |
Wholesale revenues decreased $6 million primarily due to lower unit prices, partially offset by an increase in sales to FES for OE’s leasehold interests in Perry Unit 1 and Beaver Valley Unit 2.
Expenses
Total expenses decreased $283 million in the first three months of 2010, from the same period of 2009. The following table presents changes from the prior period by expense category:
| Expenses – Changes | | Increase (Decrease) | |
| | | | (In millions) | |
| Purchased power costs | | $ | (222 | ) |
| Other operating costs | | | (69 | ) |
| Amortization of regulatory assets, net | | | 9 | |
| General taxes | | | (1 | ) |
| Net Decrease in Expenses | | $ | (283 | ) |
Purchased power costs decreased in the first three months of 2010, compared to the same period of 2009, primarily due to lower KWH purchases resulting from increased customer shopping in the first three months of 2010 and slightly lower unit costs. The decrease in other operating costs for the first three months of 2010, was primarily due to lower MISO transmission expenses (included in the cost of purchased power beginning June 1, 2009) and lower costs associated with regulatory obligations for economic development and energy efficiency programs under OE’s 2009 ESP. Higher amortization of net regulatory assets was primarily due to the recovery of PUCO-approved deferrals that began in 2010.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
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 procures generation services for those customers electing to retain CEI as their power supplier.
For additional information with respect to CEI, please see the information contained in FirstEnergy's Management’s Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Earnings increased to $14 million in the first three months of 2010, compared to a loss of $106 million in the same period of 2009. The increase in earnings was primarily the due to decreased amortization of net regulatory assets, purchased power and other operating costs, partially offset by decreased revenues and deferral of new regulatory assets.
Revenues
Revenues decreased $120 million, or 26.6%, in the first three months of 2010, compared to the same period of 2009, due to decreased retail generation and distribution revenues.
Retail generation revenues decreased $69 million in the first three months of 2010, compared to the same period of 2009, primarily due to lower KWH sales across all customer classes, partially offset by higher average unit prices in all customer classes. Reduced KWH sales were primarily the result of increased customer shopping in the first three months of 2010. Lower KWH sales to residential customers also resulted from decreased weather-related usage, reflecting a 9.2% decrease in heating degree days. Retail generation prices increased in 2010 as a result of the CBP auction for the service period beginning June 1, 2009.
Changes in retail generation sales and revenues in the first three months of 2010, compared to the same period of 2009, are summarized in the following tables:
| | | |
| Retail Generation KWH Sales | | Decrease | |
| | | | |
| Residential | | | (53.2 | )% |
| Commercial | | | (66.2 | )% |
| Industrial | | | (46.2 | )% |
| Decrease in Retail Generation Sales | | | (53.6 | )% |
| Retail Generation Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (17 | ) |
| Commercial | | | (33 | ) |
| Industrial | | | (19 | ) |
| Decrease in Retail Generation Revenues | | $ | (69 | ) |
Distribution revenues decreased $43 million in the first three months of 2010, compared to the same period of 2009, due to lower average unit prices for all customer classes and decreased KWH deliveries in the residential sector, partially offset by increased KWH deliveries in the industrial sector. The lower average unit prices were the result of lower transition rates in 2010, partially offset by a PUCO-approved distribution rate increase effective May 1, 2009. Lower KWH sales in the residential sector were the result of the warmer weather described above. Increased industrial deliveries were the result of improving economic conditions, reflecting an increase in KWH deliveries to major steel customers (134%) and automotive customers (13%).
Changes in distribution KWH deliveries and revenues in the first three months of 2010, compared to the same period of 2009, are summarized in the following tables:
| Distribution KWH Deliveries | | Increase (Decrease) | |
| | | |
| Residential | | | (3.9 | )% |
| Commercial | | | (0.6 | )% |
| Industrial | | | 10.9 | % |
| Net Increase in Distribution Deliveries | | | 2.6 | % |
| Distribution Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (5 | ) |
| Commercial | | | (13 | ) |
| Industrial | | | (25 | ) |
| Decrease in Distribution Revenues | | $ | (43 | ) |
Expenses
Total expenses decreased $314 million in the first three months of 2010, compared to the same period of 2009. The following table presents the change from the prior period by expense category:
| Expenses - Changes | | Increase (Decrease) | |
| | | (In millions) | |
| Purchased power costs | | $ | (164 | ) |
| Other operating costs | | | (33 | ) |
| Amortization of regulatory assets | | | (212 | ) |
| Deferral of new regulatory assets | | | 95 | |
| Net Decrease in Expenses | | $ | (314 | ) |
Purchased power costs decreased in the first three months of 2010, primarily due to lower KWH sales requirements as discussed above. Other operating costs decreased due to lower transmission expenses (included in the cost of purchased power beginning June 1, 2009), labor and employee benefit expenses and reduced regulatory obligations for economic development and energy efficiency programs. Decreased amortization of regulatory assets was due primarily to the 2009 impairment of CEI’s Extended RTC regulatory asset of $216 million in accordance with the PUCO-approved ESP. A decrease in the deferral of new regulatory assets was primarily due to CEI’s contemporaneous recovery of purchased power costs in 2010.
THE TOLEDO EDISON COMPANY
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 procures generation services for those customers electing to retain TE as their power supplier.
For additional information with respect to TE, please see the information contained in FirstEnergy's Management’s Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Earnings available to parent increased to $8 million in the first three months of 2010, compared to $1 million in the same period of 2009. The increase was primarily due to decreased net amortization of regulatory assets, purchased power and other operating costs, partially offset by a decrease in revenues and an increase in interest expense.
Revenues
Revenues decreased $112 million, or 46%, in the first three months of 2010, compared to the same period of 2009, primarily due to lower retail generation and distribution revenues, partially offset by an increase in wholesale generation revenues.
Retail generation revenues decreased $105 million in the first three months of 2010, compared to the same period of 2009, primarily due to lower KWH sales across all customer classes and lower unit prices to industrial customers. Lower KWH sales to all customer classes were primarily due to increased customer shopping. Lower KWH sales for residential customers also resulted from decreased weather-related usage, reflecting a 7.5% decrease in heating degree days in the first three months of 2010. Lower unit prices for industrial customers are primarily due to the absence of TE’s fuel cost recovery rider that was effective from January through May 2009, partially offset by increased generation prices resulting from the CBP auction, effective June 1, 2009.
Changes in retail electric generation KWH sales and revenues in the first three months of 2010 from the same period of 2009 are summarized in the following tables:
| Retail Generation KWH Sales | | Decrease | |
| | | | |
| Residential | | | (47.9 | )% |
| Commercial | | | (69.8 | )% |
| Industrial | | | (57.7 | )% |
| Decrease in Retail Generation Sales | | | (57.9 | )% |
| Retail Generation Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (24 | ) |
| Commercial | | | (35 | ) |
| Industrial | | | (46 | ) |
| Decrease in Retail Generation Revenues | | $ | (105 | ) |
Distribution revenues decreased $13 million in the first three months of 2010, compared to the same period of 2009, primarily due to lower unit prices for all customer classes, partially offset by increased KWH deliveries to industrial customers. Lower unit prices for all customer classes are primarily due to lower transmission rates. Increased industrial deliveries were the result of improving economic conditions, reflecting an increase in KWH deliveries to major automotive customers (14%) and steel customers (37%).
Changes in distribution KWH deliveries and revenues in the first three months of 2010, compared to the same period of 2009, are summarized in the following tables:
| Distribution KWH Deliveries | | Increase (Decrease) | |
| | | | |
| Residential | | | (2.4 | )% |
| Commercial | | | (2.6 | )% |
| Industrial | | | 13.9 | % |
| Net Increase in Distribution Deliveries | | | 4.7 | % |
| Distribution Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (2 | ) |
| Commercial | | | (3 | ) |
| Industrial | | | (8 | ) |
| Decrease in Distribution Revenues | | $ | (13 | ) |
Wholesale revenue increased $4 million in the first three months of 2010, compared to the same period of 2009, primarily due to higher revenues from associated sales to NGC from TE’s leasehold interest in Beaver Valley Unit 2.
Expenses
Total expenses decreased $131 million in the first three months of 2010, compared to the same period of 2009. The following table presents changes from the prior period by expense category:
| Expenses – Changes | | Decrease | |
| | | (In millions) | |
| Purchased power costs | | $ | | ) |
Amortization (deferral) of regulatory assets, net | | | | |
| | | | |
| | | | |
| | | | ) |
Purchased power costs decreased $93 million in the first three months of 2010, compared to the same period of 2009 due to lower volume as a result of decreased KWH sales requirements. The $18 million decrease in amortization (deferral) of net regulatory assets was primarily due to an increase in PUCO-approved cost deferrals, lower MISO transmission cost amortization, partially offset by the absence of MISO transmission and fuel cost deferrals in the first three months of 2010, compared to the same period of 2009. Other operating costs decreased $19 million primarily due to reduced transmission expense (included in the cost of power purchased from others beginning June 1, 2009), lower costs associated with regulatory obligations for economic development and energy efficiency programs and decreased labor and employee benefit expenses. The decrease in general taxes was primarily due to lower Ohio KWH taxes as a result of the reduced KWH deliveries discussed above.
Other Expense
Other expense increased $7 million in the first three months of 2010, compared to the same period of 2009, primarily due to higher interest expense associated with the April 2009 issuance of $300 million senior secured notes.
JERSEY CENTRAL POWER & LIGHT COMPANY
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 procures generation services for franchise customers electing to retain JCP&L as their power supplier. JCP&L procures electric supply to serve its BGS customers through a statewide auction process approved by the NJBPU.
For additional information with respect to JCP&L, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Outlook, Market Risk and New Accounting Standards and Interpretations.
Results of Operations
Net income increased to $29 million in the first three months of 2010, compared to $28 million in the same period of 2009. The increase was primarily due to lower purchased power costs and decreased amortization of regulatory assets, partially offset by lower revenues and increased other operating costs.
Revenues
In the first three months of 2010, revenues decreased $70 million, or 9%, compared to the same period of 2009. The decrease in revenues is primarily due to a decrease in retail and wholesale generation revenues and distribution throughput revenues.
In the first three months of 2010, retail generation revenues decreased $56 million due to lower retail generation KWH sales in all sectors, partially offset by higher unit prices in the residential and commercial sectors. Lower sales to the commercial and industrial sector were primarily due to an increase in the number of shopping customers. Lower KWH sales to the residential sector reflected decreased weather-related usage due to an 8.7% decrease in heating degree days in the first three months of 2010 compared to the same period of 2009.
Changes in retail generation KWH sales and revenues by customer class in the first three months of 2010 compared to the same period of 2009 are summarized in the following tables:
| Retail Generation KWH Sales | | Decrease | |
| | | | |
| Residential | | | (1.5 | )% |
| Commercial | | | (36.0 | )% |
| Industrial | | | (25.7 | )% |
| Decrease in Generation Sales | | | (16.0 | )% |
| Retail Generation Revenues | | Increase (Decrease) | |
| | | (In millions) | |
| Residential | | $ | 3 | |
| Commercial | | | (55 | ) |
| Industrial | | | (4 | ) |
| Net Decrease in Generation Revenues | | $ | (56 | ) |
Wholesale generation revenues decreased $11 million in the first three months of 2010 compared to the same period of 2009 due to a decrease in sales volume resulting from reduced available power for sale due to the termination of a NUG power purchase contract in July 2009.
Distribution revenues decreased $5 million in the first three months of 2010 compared to the same period of 2009 due to lower KWH deliveries, reflecting milder weather in JCP&L’s service territory, and a decrease in composite unit prices in the commercial and industrial sectors.
Changes in distribution KWH deliveries and revenues by customer class in the first three months of 2010 compared to the same period of 2009 are summarized in the following tables:
| Distribution KWH Deliveries | | Increase (Decrease) | |
| | | | | |
| Residential | | | | (1.5 | )% |
| Commercial | | | | (1.6 | )% |
| Industrial | | | | 1.3 | % |
| Net Decrease in Distribution Deliveries | | | | (1.2 | )% |
| Distribution Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (2 | ) |
| Commercial | | | (3 | ) |
| Industrial | | | - | |
| Decrease in Distribution Revenues | | $ | (5 | ) |
Expenses
Total expenses decreased $73 million in the first three months of 2010 compared to the same period of 2009. The following table presents changes from the prior period by expense category:
| Expenses - Changes | | Increase (Decrease) | |
| | | (In millions) | |
| Purchased power costs | | $ | (67 | ) |
| Other operating costs | | | 9 | |
| Provision for depreciation | | | 3 | |
| Amortization of regulatory assets, net | | | (17 | ) |
| General taxes | | | (1 | ) |
| Net Decrease in Expenses | | $ | (73 | ) |
Purchased power costs decreased in the first three months of 2010 primarily due to the lower KWH sales requirements and termination of a NUG contract as discussed above. Other operating costs increased in the first three months of 2010 primarily due to higher labor and tree trimming expenses related to major storms in JCP&L’s service territory. Depreciation expense increased due to an increase in depreciable property since the first quarter of 2009. Amortization of regulatory assets decreased in the first three months of 2010 primarily due to deferral of the major storm costs. General taxes decreased principally due to taxes assessed on a lower revenue base.
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 procures generation service for those customers electing to retain Met-Ed as their power supplier. Met-Ed has a partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requireswith FES, to providesupply nearly all of its energy requirements 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. 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. 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. See FERC Matters below for a description of the Third Restated Partial Requirements Agreement, executed by the parties on October 31, 2008, that limits the amount of energy and capacity FES must supply to Met-Ed and Penelec. In the event of a third party supplier default, the increased costs to Met-Ed and Penelec could be material.
On May 22, 2008, the PPUC approved the Met-Ed and Penelec annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. Various intervenors filed complaints against those filings. In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing Met-Ed to implement the rider June 1, 2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed with its investigation and a litigation schedule was adopted. Hearings and briefing for both Met-Ed and Penelec have concluded and the companies are awaiting a Recommended Decision from the ALJ. The TSCs include a component from 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 received PPUC approval for 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 April 15,For additional information with respect to Met-Ed, please see the information contained in FirstEnergy's Management’s Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Outlook, Market Risk and New Accounting Standards and Interpretations.
Results of Operations
Net income decreased to $12 million in the first three months of 2010, compared to $17 million in the same period of 2009. The decrease was primarily due to increased purchased power costs and amortization of net regulatory assets, partially offset by an increase in distribution and generation revenues.
Revenues
Revenues increased by $43 million, or 10%, in the first three months of 2010 compared to the same period of 2009 Met-Edprimarily due to higher distribution and Penelec filed revised TSCs withgeneration revenues, partially offset by a decrease in transmission revenues.
Distribution revenues increased $24 million in the PPUC forfirst three months of 2010, compared to the same period of 2009, primarily due to higher transmission rates, resulting from the annual update to Met-Ed’s TSC rider effective June 1, 2009, through May 31, 2010, as required in connection withpartially offset by lower CTC rates for the PPUC’s January 2007 rate order. For Penelec’sresidential class resulting from a PPUC-approved NUG Statement Compliance filing. Lower KWH deliveries to residential customers the new TSC would result in an approximate 1%reflect reduced weather-related usage due to a 7.3% decrease in monthly bills, reflecting projected PJM transmission costs as well as a reconciliation for costs already incurred. The TSC for Met-Ed’s customers would increase to recover the additional PJM charges paid by Met-Edheating degree days in the previous year and to reflect updated projected costs. In order to gradually transition customersfirst three months of 2010, compared to the higher rate, Met-Ed is proposingsame period of 2009. Higher industrial KWH deliveries were due to continue to recover the prior period deferrals allowedrecovering economy.
Changes in distribution KWH deliveries and revenues in the PPUC’s May 2008 Order and defer $57.5 millionfirst three months of projected costs into a future TSC2010 compared to be fully recovered by December 31, 2010. Under this proposal, monthly bills for Met-Ed’s customers would increase approximately 9.4% for the same period Juneof 2009 through May 2010.
On October 15, 2008,are summarized in the Governor of Pennsylvania signed House Bill 2200 into law which became effective on November 14, 2008 as Act 129 of 2008. The bill addresses issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters and alternative energy. Act 129 requires utilities to file with the PPUC an energy efficiency and peak load reduction plan by July 1, 2009 and a smart meter procurement and installation plan by August 14, 2009. On January 15, 2009, in compliance with Act 129, the PPUC issued its proposed guidelines for the filing of utilities’ energy efficiency and peak load reduction plans. Similar guidelines related to Smart Meter deployment were issued for comment on March 30, 2009.
Major provisions of the legislation include:following tables:
· | power acquired by utilities to serve customers after rate caps expire will be procured through a competitive procurement process that must include a mix of long-term and short-term contracts and spot market purchases; | Increase | |
| Distribution KWH Deliveries | | (Decrease) | |
| | | | |
| Residential | | | (5.4 | )% |
| Commercial | | | (1.9 | )% |
| Industrial | | | 2.4 | % |
| Net Decrease in Distribution Deliveries | | | (2.5 | )% |
· Distribution Revenues | the competitive procurement process must be approved by the PPUC and may include auctions, RFPs, and/or bilateral agreements; | Increase | |
| | (In millions) | |
| Residential | | $ | 7 | |
| Commercial | | | 10 | |
| Industrial | | | 7 | |
| Increase in Distribution Revenues | | $ | 24 | |
· | utilities must provide for the installation of smart meter technology within 15 years; |
Wholesale revenues increased $22 million in the first three months of 2010 compared to the same period of 2009, primarily reflecting higher PJM spot market prices.
Retail generation revenues increased $3 million in the first three months of 2010, compared to the same period of 2009, due primarily to higher composite unit prices in the residential and commercial customer classes and higher KWH sales to the industrial customer class. This increase was partially offset by lower KWH sales to the residential and commercial customer classes.
Changes in retail generation sales and revenues in the first three months of 2010, compared to the same period of 2009, are summarized in the following tables:
· | a minimum reduction | Increase | |
| Retail Generation KWH Sales | | (Decrease) | |
| | | | |
| Residential | | | (5.4 | )% |
| Commercial | | | (1.9 | )% |
| Industrial | | | 2.4 | % |
Net Decrease in peak demand of 4.5% by May 31, 2013;Retail Generation Sales | | | (2.5 | )% |
· | minimum reductions | Increase | |
| Retail Generation Revenues | | (Decrease) | |
| | (In millions) | |
| Residential | | $ | 3 | |
| Commercial | | | (1 | ) |
| Industrial | | | 1 | |
Net Increase in energy consumption of 1% and 3% by May 31, 2011 and May 31, 2013, respectively; andRetail Generation Revenues | | $ | 3 | |
· | an expanded definition of alternative energy to include additional types of hydroelectric and biomass facilities. |
Transmission revenues decreased $6 million in the first three months of 2010 compared to the same period of 2009 primarily due to decreased revenues related to Met-Ed’s Financial Transmission Rights. Met-Ed defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.
Expenses
Total operating expenses increased $46 million in the first three months of 2010 compared to the same period of 2009. The following table presents changes from the prior year by expense category:
| Expenses – Changes | | Increase (Decrease) | |
| | | (In millions) | |
| Purchased power costs | | $ | 29 | |
| Other operating costs | | | (4 | ) |
| Amortization of regulatory assets, net | | | 21 | |
| Net Increase in Expenses | | $ | 46 | |
Purchased power costs increased $29 million in the first three months of 2010 due to an increase in unit costs, partially offset by reduced volumes purchased as a result of lower KWH sales requirements. The net amortization of regulatory assets increased $21 million in the first three months of 2010 compared to the same period of 2009 primarily due to increased transmission cost recovery. Other operating costs decreased $4 million in the first three months of 2010 primarily due to lower employee benefit expenses.
Other Expense
Other expense increased in the first three months of 2010 primarily due to a decrease in interest earned on regulatory assets, reflecting a lower regulatory asset base.
Legislation addressing rate mitigation108
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 procures generation services for those customers electing to retain Penelec as their power supplier. Penelec has a partial requirements wholesale power sales agreement with FES, to supply nearly all of its energy requirements at fixed prices through 2010.
For additional information with respect to Penelec, please see the expirationinformation contained in FirstEnergy's Management’s Discussion and Analysis of rate caps was not enacted in 2008; however, several bills addressing these issues have been introducedFinancial Condition and Results of Operations above the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Net income decreased to $17 million in the current legislative session, which beganfirst three months of 2010, compared to $19 million in Januarythe same period of 2009. The final formdecrease was primarily due to higher purchased power costs, partially offset by higher revenues and impactdecreases in the amortization (deferral) of such legislation is uncertain.net regulatory assets, other operating costs and general taxes.
On February 26, 2009, the PPUC approved a Voluntary Prepayment Pan requested by Met-Ed and Penelec that provides an opportunity for residential and small commercial customers to prepay an amount on their monthly electric bills during 2009 and 2010. Customer prepayments earn interest at 7.5% and will be used to reduce electricity charges in 2011 and 2012.Revenues
On February 20, 2009, Met-EdIn the first three months of 2010, revenues increased $15 million, or 4%, compared to the same period of 2009. The increase in revenue is primarily due to higher wholesale and Penelec filed with the PPUC aretail generation procurement plan covering the period January 1, 2011 through May 31, 2013. The companies’ plan is designed to provide adequaterevenues, partially offset by lower distribution and reliable service via a prudent mix of long-term, short-term and spot market generation supply, as required by Act 129. The plan proposes a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. Met-Ed and Penelec have requested PPUC approval of their plan by November 2009.transmission revenues.
On March 31, 2009, Met-Ed and Penelec submitted their 5-year NUG Statement Compliance FilingWholesale revenues increased $18 million in the first three months of 2010, compared to the PPUCsame period of 2009, primarily reflecting higher PJM capacity prices.
Retail generation revenues increased $16 million in accordance with their 1998 Restructuring Settlement. Met-Ed proposedthe first three months of 2010, compared to reduce its CTC rate forthe same period of 2009, primarily due to higher unit prices in all customer classes and higher KWH sales to the commercial and industrial customer classes, partially offset by decreased KWH sales to the residential class with a correspondingcustomer class. Higher unit prices across all customer classes are primarily due to an increase in the generation rate resulting from the PPUC-approved NUG Statement Compliance filing, effective January 1, 2010. Higher KWH sales to commercial and the shopping credit, and Penelec proposedindustrial customers are due to reduce its CTC rateimproving economic conditions in Penelec’s service territory. Lower KWH sales to zero for all classes withresidential customers are due to decreased weather-related usage, reflecting a corresponding increase6.1% decrease in heating degree day s in the generation rate and the shopping credit. While these changes would result in additional annual generation revenue (Met-Ed - $27 million and Penelec - $51 million), overall rates would remain unchanged. The PPUC must act on this filing within 120 days.
(D) NEW JERSEYfirst three months of 2010.
JCP&L is permitted to defer for future collection from customersChanges in retail generation sales and revenues in the amounts by which its costsfirst three months of supplying BGS to non-shopping customers, costs incurred under NUG agreements, and certain other stranded costs, exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of March 31, 2009, the accumulated deferred cost balance totaled approximately $165 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)2010 compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DPA 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 commentssame period of 2009 are summarized in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set. On March 13, 2009, JCP&L filed its annual SBC Petition with the NJBPU that includes a request for a reduction in the level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009. This matter is currently pending before the NJBPU.following tables:
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. Following public hearing and consideration of comments from interested parties, the NJBPU approved final regulations effective April 6, 2009. These regulations are not expected to materially impact FirstEnergy or JCP&L.| Retail Generation KWH Sales | | Increase (Decrease) | |
| | | |
| Residential | | | (1.1 | )% |
| Commercial | | | 0.7 | % |
| Industrial | | | 3.1 | % |
| Net increase in Retail Generation Sales | | | 0.6 | % |
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.
| | | | |
| Retail Generation Revenues | | Increase | |
| | | (In millions) | |
| Residential | | $ | 3 | |
| Commercial | | | 6 | |
| Industrial | | | 7 | |
| Increase in Retail Generation Revenues | | $ | 16 | |
The EMP was issued on October 22, 2008, establishing five major goals:Distribution revenues decreased by $11 million in the first three months of 2010, compared to the same period of 2009, primarily due to a decrease in the transition rate in all customer classes resulting from the PPUC-approved NUG Statement Compliance filing, partially offset by an increase in the universal service rate for the residential customer class.
Changes in distribution KWH deliveries and revenues in the first three months of 2010, compared to the same period of 2009, are summarized in the following tables:
· Distribution KWH Deliveries | maximize energy efficiency to achieve a 20% reduction | Increase (Decrease) | |
| | | |
| Residential | | | (1.1 | )% |
| Commercial | | | 0.7 | % |
| Industrial | | | 3.8 | % |
Net increase in energy consumption by 2020;Distribution Deliveries | | | 0.9 | % |
· | reduce peak demand for electricity by 5,700 MW by 2020; |
· | meet 30% of the state’s electricity needs with renewable energy by 2020; |
· | examine smart grid technology and develop additional cogeneration and other generation resources consistent with the state’s greenhouse gas targets; and |
· | invest in innovative clean energy technologies and businesses to stimulate the industry’s growth in New Jersey. |
On January 28, 2009, the NJBPU adopted an order establishing the general process and contents of specific EMP plans that must be filed by December 31, 2009 by New Jersey electric and gas utilities in order to achieve the goals of the EMP. At this time, FirstEnergy cannot determine the impact, if any, the EMP may have on its operations or those of JCP&L.
In support of the New Jersey Governor’s Economic Assistance and Recovery Plan, JCP&L announced its intent to spend approximately $98 million on infrastructure and energy efficiency projects in 2009. An estimated $40 million will be spent on infrastructure projects, including substation upgrades, new transformers, distribution line re-closers and automated breaker operations. Approximately $34 million will be spent implementing new demand response programs as well as expanding on existing programs. Another $11 million will be spent on energy efficiency, specifically replacing transformers and capacitor control systems and installing new LED street lights. The remaining $13 million will be spent on energy efficiency programs that will complement those currently being offered. Completion of the projects is dependent upon resolution of regulatory issues including recovery of the costs associated with plan implementation.
(E) FERC MATTERS| Distribution Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (1 | ) |
| Commercial | | | (6 | ) |
| Industrial | | | (4 | ) |
| Decrease in Distribution Revenues | | $ | (11 | ) |
Transmission Servicerevenues decreased by $4 million in the first three months of 2010, compared to the same period of 2009, primarily due to lower revenues related to Penelec’s Financial Transmission Rights. Penelec defers the difference between MISOtransmission revenues and PJMtransmission costs incurred, resulting in no material effect to current period earnings.
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 multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered 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 is pending before the FERC, and in the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of lower transmission revenue collection associated with an adverse order. On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision. On November 20, 2008, FERC issued an order approving uncontested settlements, but did not rule on the initial decision. On December 19, 2008, an additional order was issued approving two contested settlements.Expenses
PJM Transmission RateTotal operating expenses increased by $9 million in the first three months of 2010, as compared with the same period of 2009. The following table presents changes from the prior period by expense category:
On January 31, 2005, certain PJM| Expenses - Changes | | Increase (Decrease) | |
| | | (In millions) | |
| Purchased power costs | | $ | 37 | |
| Amortization (deferral) of regulatory assets, net | | | (19 | ) |
| Other operating costs | | | (5 | ) |
| General taxes | | | (4 | ) |
| Net Increase in Expenses | | $ | 9 | |
Purchased power costs increased $37 million in the first three months of 2010, compared to the same period of 2009, primarily due to higher unit costs. The amortization (deferral) of net regulatory assets decreased $19 million in the first three months of 2010, primarily due to increased cost deferrals resulting from higher transmission owners made filings withexpenses and decreased amortization of regulatory assets resulting from lower CTC revenues. Other operating costs decreased $5 million in the FERC pursuantfirst three months of 2010, primarily due to reduced labor and employee benefit expenses. General taxes decreased $4 million primarily due 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. favorable ruling on a property tax appeal.
Other Expense
In the first filing, the settling transmission owners submitted a filing justifying continuationthree months 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 proposed2010, other expense increased $3 million primarily due 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 footprintincrease in interest expense on long-term debt, partially offset by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocatedlower interest expense 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.short-term borrowings.
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. On February 11, 2008, AEP appealed the FERC’s April 19, 2007, and January 31, 2008, 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. Oral argument was held on April 13, 2009, and a decision is expected this summer.
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 the costs of future transmission to be recovered 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 to the FERC. On July 29, 2008, the FERC issued an order conditionally approving the settlement subject to the submission of a compliance filing. The compliance filing was submitted on August 29, 2008, and the FERC issued an order accepting the compliance filing on October 15, 2008. On November 14, 2008, PJM submitted revisions to its tariff to incorporate cost responsibility assignments for below 500 kV upgrades included in PJM’s Regional Transmission Expansion Planning process in accordance with the settlement. The FERC conditionally accepted the compliance filing on January 28, 2009. PJM submitted a further compliance filing on March 2, 2009, which was accepted by the FERC on April 10, 2009. The remaining merchant transmission cost allocation issues were the subject of a hearing at the FERC in May 2008. An initial decision was issued by the Presiding Judge on September 18, 2008. PJM and FERC trial staff each filed a Brief on Exceptions to the initial decision on October 20, 2008. Briefs Opposing Exceptions were filed on November 10, 2008.
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. The effect of this order is to prevent the shift of significant costs to the FirstEnergy zones in MISO and PJM. A rehearing request by AEP was denied by the FERC on December 19, 2008. On February 17, 2009, AEP appealed the FERC’s January 31, 2008, and December 19, 2008, orders to the U.S. Court of Appeals for the Seventh Circuit. FESC, on behalf of its affiliated operating utility companies, filed a motion to intervene on March 10, 2009.
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 MISO. Duquesne’s proposed move would affect numerous FirstEnergy interests, including but not limited to the terms under which FirstEnergy’s Beaver Valley Plant would continue to participate in PJM’s energy markets. FirstEnergy, therefore, intervened and participated fully in all of the FERC dockets that were related to Duquesne’s proposed move.
In November, 2008, Duquesne and other parties, including FirstEnergy, negotiated a settlement that would, among other things, allow for Duquesne to remain in PJM and provide for a methodology for Duquesne to meet the PJM capacity obligations for the 2011-2012 auction that excluded the Duquesne load. The settlement agreement was filed on December 10, 2008 and approved by the FERC in an order issued on January 29, 2009. MISO opposed the settlement agreement pending resolution of exit fees alleged to be owed by Duquesne. The FERC did not resolve the exit fee issue in its order. On March 2, 2009, the PPUC filed for rehearing of the FERC's January 29, 2009 order approving the settlement. Thereafter, FirstEnergy and other parties filed in opposition to the rehearing request. The PPUC's rehearing request, and the pleadings in opposition thereto, are pending before the FERC.
Changes ordered for PJM Reliability Pricing Model (RPM) Auction
On May 30, 2008, a group of PJM load-serving entities, state commissions, consumer advocates, and trade associations (referred to collectively as the RPM Buyers) filed a complaint at the FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the Federal Power Act. On September 19, 2008, the FERC denied the RPM Buyers’ complaint. However, the FERC did grant the RPM Buyers’ request for a technical conference to review aspects of the RPM. The FERC also ordered PJM to file on or before December 15, 2008, a report on potential adjustments to the RPM program as suggested in a Brattle Group report. On December 12, 2008, PJM filed proposed tariff amendments that would adjust slightly the RPM program. PJM also requested that the FERC conduct a settlement hearing to address changes to the RPM and suggested that the FERC should rule on the tariff amendments only if settlement could not be reached in January, 2009. The request for settlement hearings was granted. Settlement had not been reached by January 9, 2009 and, accordingly, FirstEnergy and other parties submitted comments on PJM’s proposed tariff amendments. On January 15, 2009, the Chief Judge issued an order terminating settlement talks. On February 9, 2009, PJM and a group of stakeholders submitted an offer of settlement, which used the PJM December 12, 2008 filing as its starting point, and stated that unless otherwise specified, provisions filed by PJM on December 12, 2008, apply.
On March 26, 2009, the FERC accepted in part, and rejected in part, tariff provisions submitted by PJM, revising certain parts of its RPM. Ordered changes included making incremental improvements to RPM; however, the basic construct of RPM remains intact. On April 3, 2009, PJM filed with the FERC requesting clarification on certain aspects of the March 26, 2009 Order. On April 27, 2009, PJM submitted a compliance filing addressing the changes the FERC ordered in the March 26, 2009 Order; numerous parties have filed requests for rehearing of the March 26, 2009 Order. In addition, the FERC has indefinitely postponed the technical conference on RPM granted in the FERC order of September 19, 2008.
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 believes the proposal promotes a mechanism that will result in 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 submitted on January 28, 2008. The FERC conditionally approved MISO’s Resource Adequacy proposal on March 26, 2008, requiring MISO to submit to further compliance filings. Rehearing requests are pending on the FERC’s March 26 Order. On May 27, 2008, MISO submitted a compliance filing to address issues associated with planning reserve margins. On June 17, 2008, various parties submitted comments and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific issues that must be clarified and addressed. On June 25, 2008, MISO submitted a second compliance filing establishing the enforcement mechanism for the reserve margin requirement which establishes deficiency payments for load-serving entities that do not meet the resource adequacy requirements. Numerous parties, including FirstEnergy, protested this filing.
On October 20, 2008, the FERC issued three orders essentially permitting the MISO Resource Adequacy program to proceed with some modifications. First, the FERC accepted MISO's financial settlement approach for enforcement of Resource Adequacy subject to a compliance filing modifying the cost of new entry penalty. Second, the FERC conditionally accepted MISO's compliance filing on the qualifications for purchased power agreements to be capacity resources, load forecasting, loss of load expectation, and planning reserve zones. Additional compliance filings were directed on accreditation of load modifying resources and price responsive demand. Finally, the FERC largely denied rehearing of its March 26 order with the exception of issues related to behind the meter resources and certain ministerial matters. On November 19, 2008, MISO made various compliance filings pursuant to these orders. Issuance of orders on rehearing and two of the compliance filings occurred on February 19, 2009. No material changes were made to MISO’s Resource Adequacy program. On April 16, 2009, the FERC issued an additional order on rehearing and compliance, approving MISO’s proposed financial settlement provision for Resource Adequacy. The MISO Resource Adequacy process is expected to start as planned effective June 1, 2009, the beginning of the MISO planning year.
FES Sales to Affiliates
On October 24, 2008, FES, on its own behalf and on behalf of its generation-controlling subsidiaries, filed an application with the FERC seeking a waiver of the affiliate sales restrictions between FES and the Ohio Companies. The purpose of the waiver is to ensure that FES will be able to continue supplying a material portion of the electric load requirements of the Ohio Companies after January 1, 2009 pursuant to either an ESP or MRO as filed with the PUCO. FES previously obtained a similar waiver for electricity sales to its affiliates in New Jersey, New York, and Pennsylvania. On December 23, 2008, the FERC issued an order granting the waiver request and the Ohio Companies made the required compliance filing on December 30, 2008. In January 2009, several parties filed for rehearing of the FERC’s December 23, 2008 order. In response, FES filed an answer to requests for rehearing on February 5, 2009. The requests and responses are pending before the FERC.
FES supplied all of the power requirements for the Ohio Companies pursuant to a Power Supply Agreement that ended on December 31, 2008. On January 2, 2009, FES signed an agreement to provide 75% of the Ohio Companies’ power requirements for the period January 5, 2009 through March 31, 2009. Subsequently, FES signed an agreement to provide 100% of the Ohio Companies’ power requirements for the period April 1, 2009 through May 31, 2009. On March 4, 2009, the PUCO issued an order approving these two affiliate sales agreements. FERC authorization for these affiliate sales was by means of the December 23, 2008 waiver.
On October 31, 2008, FES executed a Third Restated Partial Requirements Agreement with Met-Ed, Penelec, and Waverly effective November 1, 2008. The Third Restated Partial Requirements Agreement limits the amount of capacity and energy required to be supplied by FES in 2009 and 2010 to roughly two-thirds of these affiliates’ power supply requirements. Met-Ed, Penelec, and Waverly have committed resources in place for the balance of their expected power supply during 2009 and 2010. Under the Third Restated Partial Requirements Agreement, Met-Ed, Penelec, and Waverly are responsible for obtaining additional power supply requirements created by the default or failure of supply of their committed resources. Prices for the power provided by FES were not changed in the Third Restated Partial Requirements Agreement.
10. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
FSP FAS 157-4 – “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly”
In April 2009, the FASB issued Staff Position FAS 157-4, which provides additional guidance to consider in estimating fair value when there has been a significant decrease in market activity for a financial asset. The FSP establishes a two-step process requiring a reporting entity to first determine if a market is not active in relation to normal market activity for the asset. If evidence indicates the market is not active, an entity would then need to determine whether a quoted price in the market is associated with a distressed transaction. An entity will need to further analyze the transactions or quoted prices, and an adjustment to the transactions or quoted prices may be necessary to estimate fair value. Additional disclosures related to the inputs and valuation techniques used in the fair value measurements are also required. The FSP is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FirstEnergy will adopt the FSP for its interim period ending June 30, 2009. While the FSP will expand disclosure requirements, FirstEnergy does not expect the FSP to have a material effect upon its financial statements.
| FSP FAS 115-2 and FAS 124-2 - “Recognition and Presentation of Other-Than-Temporary Impairments” |
In April 2009, the FASB issued Staff Position FAS 115-2 and FAS 124-2, which changes the method to determine whether an other-than-temporary impairment exists for debt securities and the amount of impairment to be recorded in earnings. Under the FSP, management will be required to assert it does not have the intent to sell the debt security, and it is more likely than not it will not have to sell the debt security before recovery of its cost basis. If management is unable to make these assertions, the debt security will be deemed other-than-temporarily impaired and the security will be written down to fair value with the full charge recorded through earnings. If management is able to make the assertions, but there are credit losses associated with the debt security, the portion of impairment related to credit losses will be recognized in earnings while the remaining impairment will be recognized through other comprehensive income. The FSP is effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FirstEnergy will adopt the FSP for its interim period ending June 30, 2009 and does not expect the FSP to have a material effect upon its financial statements.
| FSP FAS 107-1 and APB 28-1 - “Interim Disclosures about Fair Value of Financial Instruments” |
In April 2009, the FASB issued Staff Position FAS 107-1 and APB 28-1, which requires disclosures of the fair value of financial instruments in interim financial statements, as well as in annual financial statements. The FSP also requires entities to disclose the methods and significant assumptions used to estimate the fair value of financial instruments in both interim and annual financial statements. The FSP is effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FirstEnergy will adopt the FSP for its interim period ending June 30, 2009, and expects to expand its disclosures regarding the fair value of financial instruments.
FSP FAS 132 (R)-1 – “Employers’ Disclosures about Postretirement Benefit Plan Assets”
In December 2008, the FASB issued Staff Position FAS 132(R)-1, which provides guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. Requirements of this FSP include disclosures about investment policies and strategies, categories of plan assets, fair value measurements of plan assets, and significant categories of risk. This FSP is effective for fiscal years ending after December 15, 2009. FirstEnergy will expand its disclosures related to postretirement benefit plan assets as a result of this FSP.
11. SEGMENT INFORMATION
FirstEnergy has three reportable operating segments: energy delivery services, competitive energy services and Ohio transitional generation services. The assets and revenues for all 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 electricity 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 third parties and the competitive energy services segment through a CBP, 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, 2009 | | | | | | | | | | | | | | | | | | |
| External revenues | | $ | 2,109 | | | $ | 335 | | | $ | 912 | | | $ | 7 | | | $ | (29 | ) | | $ | 3,334 | |
| Internal revenues | | | - | | | | 893 | | | | - | | | | - | | | | (893 | ) | | | - | |
| Total revenues | | | 2,109 | | | | 1,228 | | | | 912 | | | | 7 | | | | (922 | ) | | | 3,334 | |
| Depreciation and amortization | | | 472 | | | | 64 | | | | (45 | ) | | | 1 | | | | 3 | | | | 495 | |
| Investment income (loss), net | | | 29 | | | | (29 | ) | | | 1 | | | | - | | | | (12 | ) | | | (11 | ) |
| Net interest charges | | | 110 | | | | 18 | | | | - | | | | 1 | | | | 37 | | | | 166 | |
| Income taxes | | | (28 | ) | | | 103 | | | | 16 | | | | (17 | ) | | | (20 | ) | | | 54 | |
| Net income (loss) | | | (42 | ) | | | 155 | | | | 24 | | | | 17 | | | | (39 | ) | | | 115 | |
| Total assets | | | 22,669 | | | | 9,925 | | | | 336 | | | | 632 | | | | (5 | ) | | | 33,557 | |
| Total goodwill | | | 5,550 | | | | 24 | | | | - | | | | - | | | | - | | | | 5,574 | |
| Property additions | | | 165 | | | | 421 | | | | - | | | | 49 | | | | 19 | | | | 654 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| 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 (loss), net | | | 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 | | | | (34 | ) | | | 277 | |
| 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 | |
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.
12. 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 fully and 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. This transaction is classified as an operating lease under GAAP for FES and a financing for FGCO.
The condensed consolidating statements of income for the three months ended March 31, 2009, and 2008, consolidating balance sheets as of March 31, 2009, and December 31, 2008, and consolidating statements of cash flows for the three months ended March 31, 2009, and 2008 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 the entries required to reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.
| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | | |
| CONDENSED CONSOLIDATING STATEMENTS OF INCOME | |
| (Unaudited) | |
| | | | | | | | | | | | | | | | |
| For the Three Months Ended March 31, 2009 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| | | | | | | | | | | | | | | | |
| REVENUES | | $ | 1,201,895 | | | $ | 545,926 | | | $ | 395,628 | | | $ | (917,343 | ) | | $ | 1,226,106 | |
| | | | | | | | | | | | | | | | | | | | | |
| EXPENSES: | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | 2,095 | | | | 274,847 | | | | 29,216 | | | | - | | | | 306,158 | |
| Purchased power from non-affiliates | | | 160,342 | | | | - | | | | - | | | | - | | | | 160,342 | |
| Purchased power from affiliates | | | 915,261 | | | | 2,082 | | | | 63,207 | | | | (917,343 | ) | | | 63,207 | |
| Other operating expenses | | | 38,267 | | | | 104,443 | | | | 152,456 | | | | 12,190 | | | | 307,356 | |
| Provision for depreciation | | | 1,019 | | | | 30,020 | | | | 31,649 | | | | (1,315 | ) | | | 61,373 | |
| General taxes | | | 4,706 | | | | 12,626 | | | | 6,044 | | | | - | | | | 23,376 | |
| Total expenses | | | 1,121,690 | | | | 424,018 | | | | 282,572 | | | | (906,468 | ) | | | 921,812 | |
| | | | | | | | | | | | | | | | | | | | | |
| OPERATING INCOME | | | 80,205 | | | | 121,908 | | | | 113,056 | | | | (10,875 | ) | | | 304,294 | |
| | | | | | | | | | | | | | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | |
| Miscellaneous income (expense), including | | | | | | | | | | | | | | | | | | | | |
| net income from equity investees | | | 120,513 | | | | (47 | ) | | | (29,637 | ) | | | (117,192 | ) | | | (26,363 | ) |
| Interest expense to affiliates | | | (34 | ) | | | (1,758 | ) | | | (1,187 | ) | | | - | | | | (2,979 | ) |
| Interest expense - other | | | (2,520 | ) | | | (21,058 | ) | | | (15,168 | ) | | | 16,219 | | | | (22,527 | ) |
| Capitalized interest | | | 51 | | | | 7,750 | | | | 2,277 | | | | - | | | | 10,078 | |
| Total other income (expense) | | | 118,010 | | | | (15,113 | ) | | | (43,715 | ) | | | (100,973 | ) | | | (41,791 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 198,215 | | | | 106,795 | | | | 69,341 | | | | (111,848 | ) | | | 262,503 | |
| | | | | | | | | | | | | | | | | | | | | |
| INCOME TAXES | | | 27,534 | | | | 39,142 | | | | 22,929 | | | | 2,217 | | | | 91,822 | |
| | | | | | | | | | | | | | | | | | | | | |
| NET INCOME | | $ | 170,681 | | | $ | 67,653 | | | $ | 46,412 | | | $ | (114,065 | ) | | $ | 170,681 | |
| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | | |
| CONDENSED 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. | |
| | | | | | | | | | | | | | | | |
| CONDENSED CONSOLIDATING BALANCE SHEETS | |
| | | | | | | | | | | | | | | | |
| As of March 31, 2009 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| ASSETS | | | | | | | | | | | | | | | |
| CURRENT ASSETS: | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | - | | | $ | 34 | | | $ | - | | | $ | - | | | $ | 34 | |
| Receivables- | | | | | | | | | | | | | | | | | | | | |
| Customers | | | 54,554 | | | | - | | | | - | | | | - | | | | 54,554 | |
| Associated companies | | | 295,513 | | | | 192,816 | | | | 125,514 | | | | (325,908 | ) | | | 287,935 | |
| Other | | | 2,562 | | | | 14,705 | | | | 49,026 | | | | - | | | | 66,293 | |
| Notes receivable from associated companies | | | 404,869 | | | | 28,268 | | | | - | | | | - | | | | 433,137 | |
| Materials and supplies, at average cost | | | 8,610 | | | | 349,038 | | | | 210,039 | | | | - | | | | 567,687 | |
| Prepayments and other | | | 84,466 | | | | 26,589 | | | | 1,107 | | | | - | | | | 112,162 | |
| | | | 850,574 | | | | 611,450 | | | | 385,686 | | | | (325,908 | ) | | | 1,521,802 | |
| | | | | | | | | | | | | | | | | | | | | |
| PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | | | | | | | | | | | | |
| In service | | | 88,064 | | | | 5,477,939 | | | | 4,736,544 | | | | (389,944 | ) | | | 9,912,603 | |
| Less - Accumulated provision for depreciation | | | 10,821 | | | | 2,732,040 | | | | 1,755,879 | | | | (171,499 | ) | | | 4,327,241 | |
| | | | 77,243 | | | | 2,745,899 | | | | 2,980,665 | | | | (218,445 | ) | | | 5,585,362 | |
| Construction work in progress | | | 4,728 | | | | 1,626,685 | | | | 483,418 | | | | - | | | | 2,114,831 | |
| | | | 81,971 | | | | 4,372,584 | | | | 3,464,083 | | | | (218,445 | ) | | | 7,700,193 | |
| | | | | | | | | | | | | | | | | | | | | |
| INVESTMENTS: | | | | | | | | | | | | | | | | | | | | |
| Nuclear plant decommissioning trusts | | | - | | | | - | | | | 995,476 | | | | - | | | | 995,476 | |
| Long-term notes receivable from associated companies | | | - | | | | - | | | | 62,900 | | | | - | | | | 62,900 | |
| Investment in associated companies | | | 3,712,870 | | | | - | | | | - | | | | (3,712,870 | ) | | | - | |
| Other | | | 1,714 | | | | 29,982 | | | | 202 | | | | - | | | | 31,898 | |
| | | | 3,714,584 | | | | 29,982 | | | | 1,058,578 | | | | (3,712,870 | ) | | | 1,090,274 | |
| | | | | | | | | | | | | | | | | | | | | |
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | | | | | | | | | | | |
| Accumulated deferred income tax benefits | | | 18,209 | | | | 458,730 | | | | - | | | | (235,332 | ) | | | 241,607 | |
| Lease assignment receivable from associated companies | | | - | | | | 71,356 | | | | - | | | | - | | | | 71,356 | |
| Goodwill | | | 24,248 | | | | - | | | | - | | | | - | | | | 24,248 | |
| Property taxes | | | - | | | | 27,494 | | | | 22,610 | | | | - | | | | 50,104 | |
| Unamortized sale and leaseback costs | | | - | | | | 32,128 | | | | - | | | | 54,174 | | | | 86,302 | |
| Other | | | 65,233 | | | | 58,004 | | | | 8,332 | | | | (44,428 | ) | | | 87,141 | |
| | | | 107,690 | | | | 647,712 | | | | 30,942 | | | | (225,586 | ) | | | 560,758 | |
| | | $ | 4,754,819 | | | $ | 5,661,728 | | | $ | 4,939,289 | | | $ | (4,482,809 | ) | | $ | 10,873,027 | |
| | | | | | | | | | | | | | | | | | | | | |
| LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
| Currently payable long-term debt | | $ | 708 | | | $ | 930,763 | | | $ | 777,218 | | | $ | (17,747 | ) | | $ | 1,690,942 | |
| Short-term borrowings- | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | - | | | | 345,664 | | | | 440,452 | | | | - | | | | 786,116 | |
| Other | | | 1,100,000 | | | | - | | | | - | | | | - | | | | 1,100,000 | |
| Accounts payable- | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 361,848 | | | | 132,694 | | | | 232,204 | | | | (317,586 | ) | | | 409,160 | |
| Other | | | 27,081 | | | | 117,756 | | | | - | | | | - | | | | 144,837 | |
| Accrued taxes | | | 22,861 | | | | 75,462 | | | | 45,300 | | | | (20,889 | ) | | | 122,734 | |
| Other | | | 58,938 | | | | 112,048 | | | | 23,023 | | | | 45,975 | | | | 239,984 | |
| | | | 1,571,436 | | | | 1,714,387 | | | | 1,518,197 | | | | (310,247 | ) | | | 4,493,773 | |
| | | | | | | | | | | | | | | | | | | | | |
| CAPITALIZATION: | | | | | | | | | | | | | | | | | | | | |
| Common stockholder's equity | | | 3,120,406 | | | | 1,901,085 | | | | 1,797,764 | | | | (3,698,849 | ) | | | 3,120,406 | |
| Long-term debt and other long-term obligations | | | 21,819 | | | | 1,466,373 | | | | 469,839 | | | | (1,287,970 | ) | | | 670,061 | |
| | | | 3,142,225 | | | | 3,367,458 | | | | 2,267,603 | | | | (4,986,819 | ) | | | 3,790,467 | |
| | | | | | | | | | | | | | | | | | | | | |
| NONCURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
| Deferred gain on sale and leaseback transaction | | | - | | | | - | | | | - | | | | 1,018,156 | | | | 1,018,156 | |
| Accumulated deferred income taxes | | | - | | | | - | | | | 203,899 | | | | (203,899 | ) | | | - | |
| Accumulated deferred investment tax credits | | | - | | | | 38,669 | | | | 22,976 | | | | - | | | | 61,645 | |
| Asset retirement obligations | | | - | | | | 24,274 | | | | 852,799 | | | | - | | | | 877,073 | |
| Retirement benefits | | | 23,242 | | | | 175,561 | | | | - | | | | - | | | | 198,803 | |
| Property taxes | | | - | | | | 27,494 | | | | 22,610 | | | | - | | | | 50,104 | |
| Lease market valuation liability | | | - | | | | 296,376 | | | | - | | | | - | | | | 296,376 | |
| Other | | | 17,916 | | | | 17,509 | | | | 51,205 | | | | - | | | | 86,630 | |
| | | | 41,158 | | | | 579,883 | | | | 1,153,489 | | | | 814,257 | | | | 2,588,787 | |
| | | $ | 4,754,819 | | | $ | 5,661,728 | | | $ | 4,939,289 | | | $ | (4,482,809 | ) | | $ | 10,873,027 | |
| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | | |
| CONDENSED CONSOLIDATING BALANCE SHEETS | |
| | | | | | | | | | | | | | | | |
| As of December 31, 2008 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| ASSETS | | | | | | | | | | | | | | | |
| CURRENT ASSETS: | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | - | | | $ | 39 | | | $ | - | | | $ | - | | | $ | 39 | |
| Receivables- | | | | | | | | | | | | | | | | | | | | |
| Customers | | | 86,123 | | | | - | | | | - | | | | - | | | | 86,123 | |
| Associated companies | | | 363,226 | | | | 225,622 | | | | 113,067 | | | | (323,815 | ) | | | 378,100 | |
| Other | | | 991 | | | | 11,379 | | | | 12,256 | | | | - | | | | 24,626 | |
| Notes receivable from associated companies | | | 107,229 | | | | 21,946 | | | | - | | | | - | | | | 129,175 | |
| Materials and supplies, at average cost | | | 5,750 | | | | 303,474 | | | | 212,537 | | | | - | | | | 521,761 | |
| Prepayments and other | | | 76,773 | | | | 35,102 | | | | 660 | | | | - | | | | 112,535 | |
| | | | 640,092 | | | | 597,562 | | | | 338,520 | | | | (323,815 | ) | | | 1,252,359 | |
| | | | | | | | | | | | | | | | | | | | | |
| PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | | | | | | | | | | | | |
| In service | | | 134,905 | | | | 5,420,789 | | | | 4,705,735 | | | | (389,525 | ) | | | 9,871,904 | |
| Less - Accumulated provision for depreciation | | | 13,090 | | | | 2,702,110 | | | | 1,709,286 | | | | (169,765 | ) | | | 4,254,721 | |
| | | | 121,815 | | | | 2,718,679 | | | | 2,996,449 | | | | (219,760 | ) | | | 5,617,183 | |
| Construction work in progress | | | 4,470 | | | | 1,441,403 | | | | 301,562 | | | | - | | | | 1,747,435 | |
| | | | 126,285 | | | | 4,160,082 | | | | 3,298,011 | | | | (219,760 | ) | | | 7,364,618 | |
| | | | | | | | | | | | | | | | | | | | | |
| INVESTMENTS: | | | | | | | | | | | | | | | | | | | | |
| Nuclear plant decommissioning trusts | | | - | | | | - | | | | 1,033,717 | | | | - | | | | 1,033,717 | |
| Long-term notes receivable from associated companies | | | - | | | | - | | | | 62,900 | | | | - | | | | 62,900 | |
| Investment in associated companies | | | 3,596,152 | | | | - | | | | - | | | | (3,596,152 | ) | | | - | |
| Other | | | 1,913 | | | | 59,476 | | | | 202 | | | | - | | | | 61,591 | |
| | | | 3,598,065 | | | | 59,476 | | | | 1,096,819 | | | | (3,596,152 | ) | | | 1,158,208 | |
| | | | | | | | | | | | | | | | | | | | | |
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | | | | | | | | | | | |
| Accumulated deferred income tax benefits | | | 24,703 | | | | 476,611 | | | | - | | | | (233,552 | ) | | | 267,762 | |
| Lease assignment receivable from associated companies | | | - | | | | 71,356 | | | | - | | | | - | | | | 71,356 | |
| Goodwill | | | 24,248 | | | | - | | | | - | | | | - | | | | 24,248 | |
| Property taxes | | | - | | | | 27,494 | | | | 22,610 | | | | - | | | | 50,104 | |
| Unamortized sale and leaseback costs | | | - | | | | 20,286 | | | | - | | | | 49,646 | | | | 69,932 | |
| Other | | | 59,642 | | | | 59,674 | | | | 21,743 | | | | (44,625 | ) | | | 96,434 | |
| | | | 108,593 | | | | 655,421 | | | | 44,353 | | | | (228,531 | ) | | | 579,836 | |
| | | $ | 4,473,035 | | | $ | 5,472,541 | | | $ | 4,777,703 | | | $ | (4,368,258 | ) | | $ | 10,355,021 | |
| | | | | | | | | | | | | | | | | | | | | |
| LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
| Currently payable long-term debt | | $ | 5,377 | | | $ | 925,234 | | | $ | 1,111,183 | | | $ | (16,896 | ) | | $ | 2,024,898 | |
| Short-term borrowings- | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 1,119 | | | | 257,357 | | | | 6,347 | | | | - | | | | 264,823 | |
| Other | | | 1,000,000 | | | | - | | | | - | | | | - | | | | 1,000,000 | |
| Accounts payable- | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 314,887 | | | | 221,266 | | | | 250,318 | | | | (314,133 | ) | | | 472,338 | |
| Other | | | 35,367 | | | | 119,226 | | | | - | | | | - | | | | 154,593 | |
| Accrued taxes | | | 8,272 | | | | 60,385 | | | | 30,790 | | | | (19,681 | ) | | | 79,766 | |
| Other | | | 61,034 | | | | 136,867 | | | | 13,685 | | | | 36,853 | | | | 248,439 | |
| | | | 1,426,056 | | | | 1,720,335 | | | | 1,412,323 | | | | (313,857 | ) | | | 4,244,857 | |
| | | | | | | | | | | | | | | | | | | | | |
| CAPITALIZATION: | | | | | | | | | | | | | | | | | | | | |
| Common stockholder's equity | | | 2,944,423 | | | | 1,832,678 | | | | 1,752,580 | | | | (3,585,258 | ) | | | 2,944,423 | |
| Long-term debt and other long-term obligations | | | 61,508 | | | | 1,328,921 | | | | 469,839 | | | | (1,288,820 | ) | | | 571,448 | |
| | | | 3,005,931 | | | | 3,161,599 | | | | 2,222,419 | | | | (4,874,078 | ) | | | 3,515,871 | |
| | | | | | | | | | | | | | | | | | | | | |
| NONCURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
| Deferred gain on sale and leaseback transaction | | | - | | | | - | | | | - | | | | 1,026,584 | | | | 1,026,584 | |
| Accumulated deferred income taxes | | | - | | | | - | | | | 206,907 | | | | (206,907 | ) | | | - | |
| Accumulated deferred investment tax credits | | | - | | | | 39,439 | | | | 23,289 | | | | - | | | | 62,728 | |
| Asset retirement obligations | | | - | | | | 24,134 | | | | 838,951 | | | | - | | | | 863,085 | |
| Retirement benefits | | | 22,558 | | | | 171,619 | | | | - | | | | - | | | | 194,177 | |
| Property taxes | | | - | | | | 27,494 | | | | 22,610 | | | | - | | | | 50,104 | |
| Lease market valuation liability | | | - | | | | 307,705 | | | | - | | | | - | | | | 307,705 | |
| Other | | | 18,490 | | | | 20,216 | | | | 51,204 | | | | - | | | | 89,910 | |
| | | | 41,048 | | | | 590,607 | | | | 1,142,961 | | | | 819,677 | | | | 2,594,293 | |
| | | $ | 4,473,035 | | | $ | 5,472,541 | | | $ | 4,777,703 | | | $ | (4,368,258 | ) | | $ | 10,355,021 | |
| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | | |
| CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS | |
| (Unaudited) | |
| | | | | | | | | | | | | | | | |
| For the Three Months Ended March 31, 2009 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| NET CASH PROVIDED FROM OPERATING ACTIVITIES | | $ | 200,420 | | | $ | 28,545 | | | $ | 118,902 | | | $ | - | | | $ | 347,867 | |
| | | | | | | | | | | | | | | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
| New Financing- | | | | | | | | | | | | | | | | | | | | |
| Long-term debt | | | - | | | | 100,000 | | | | - | | | | - | | | | 100,000 | |
| Short-term borrowings, net | | | 98,881 | | | | 88,308 | | | | 434,105 | | | | - | | | | 621,294 | |
| Redemptions and Repayments- | | | | | | | | | | | | | | | | | | | | |
| Long-term debt | | | (1,189 | ) | | | (626 | ) | | | (334,101 | ) | | | - | | | | (335,916 | ) |
| Net cash provided from financing activities | | | 97,692 | | | | 187,682 | | | | 100,004 | | | | - | | | | 385,378 | |
| | | | | | | | | | | | | | | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
| Property additions | | | (358 | ) | | | (198,631 | ) | | | (213,816 | ) | | | - | | | | (412,805 | ) |
| Proceeds from asset sales | | | - | | | | 7,573 | | | | - | | | | - | | | | 7,573 | |
| Sales of investment securities held in trusts | | | - | | | | - | | | | 351,414 | | | | - | | | | 351,414 | |
| Purchases of investment securities held in trusts | | | - | | | | - | | | | (356,904 | ) | | | - | | | | (356,904 | ) |
| Loans to associated companies, net | | | (297,641 | ) | | | (6,322 | ) | | | - | | | | - | | | | (303,963 | ) |
| Other | | | (113 | ) | | | (18,852 | ) | | | 400 | | | | - | | | | (18,565 | ) |
| Net cash used for investing activities | | | (298,112 | ) | | | (216,232 | ) | | | (218,906 | ) | | | - | | | | (733,250 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Net change in cash and cash equivalents | | | - | | | | (5 | ) | | | - | | | | - | | | | (5 | ) |
| Cash and cash equivalents at beginning of period | | | - | | | | 39 | | | | - | | | | - | | | | 39 | |
| Cash and cash equivalents at end of period | | $ | - | | | $ | 34 | | | $ | - | | | $ | - | | | $ | 34 | |
| 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 | |
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See “Management’s"Management's Discussion and Analysis of Financial Condition and Results of Operations – Market Risk Information”Information" in Item 2 above.
ITEM 4. CONTROLS AND PROCEDURES
(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES – FIRSTENERGY
FirstEnergy’sFirstEnergy's management, with the participation of its chief executive officer and chief financial officer have reviewed and evaluated the effectiveness of the registrant's disclosure controls and procedures, as defined in the Securities Exchange Act of 1934, as amended, Rules 13a-15(e) and 15(d)-15(e), as of the end of the period covered by this report. 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 officersthe chief executive officer and chief financial officer have concluded that the registrant's disclosure controls and procedures arewere effective as of the end of the period covered by this report.
(b) CHANGES IN INTERNAL CONTROLS
During the quarter ended March 31, 2009,2010, there were no changes in FirstEnergy’sFirstEnergy's internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrant’sregistrant'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 management, with the participation of its chief executive officer and chief financial officer, have reviewed and evaluated the effectiveness of such registrant's disclosure controls and procedures, as defined in the Securities Exchange Act of 1934, as amended, Rules 13a-15(e) and 15(d)-15(e), as of the end of the period covered by this report. 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 officerseach registrant’s chief executive officer and chief financial officer have concluded that such registrant's disclosure controls and procedures arewere effective as of the end of the period covered by this report.
(b) CHANGES IN INTERNAL CONTROLS
During the quarter ended March 31, 2009,2010, there were no changes in the registrants' internal control over financial reporting that havehas materially affected, or areis 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 8 and 9 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
ITEM 1A. RISK FACTORS
FirstEnergy’sFirstEnergy's Annual Report on Form 10-K for the year ended December 31, 20082009, includes a detailed discussion of its risk factors. The information presented below updates certain of thoseThere have been no material changes to these risk factors and should be read in conjunction withfor the risk factors and information disclosed in FirstEnergy’s Annual Report on Form 10-K.
FES’ Business is Affected By Competitive Procurement Processes Approved by State Regulators
The adoption of competitive bid processes for PLR generation supply in Ohio and Pennsylvania may affect the amount of generation that FES sells to its utility affiliates in those states. For example, the Amended ESP approved by the PUCO established a competitive bid process for generation supply and pricing for a two-year period beginning June 1, 2009 through Mayquarter ended March 31, 2011. FES intends to participate in the CBP as a supplier and its results of operations and financial condition will be impacted by the price and the percentage of the load for which it is ultimately the supplier.
Competitive Power Markets
FES’ financial performance depends upon its success in competing in wholesale and retail markets in MISO and PJM. FES’ ability to compete successfully in these markets is affected by, among other things, the efficiency and cost structure of its generation fleet, market prices, demand for electricity, effectiveness of risk management practices and the market rules established by state and federal regulators.2010.
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 during the first quarter of 2009.2010.
| | | Period | |
| | | January | | February | | March | | First Quarter | |
Total Number of Shares Purchased (a) | | 23,535 | | 20,090 | | 887,792 | | 931,417 | |
| Average Price Paid per Share | | $50.09 | | $46.20 | | $41.34 | | $41.67 | |
| 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 | | - | | - | | - | | - | |
(a) | Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver common stock under its 2007 Incentive Compensation Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes upon exercise of stock options granted under the 2007 Incentive Compensation Plan and the Executive Deferred Compensation Plan, and shares purchased as part of publicly announced plans. |
| | | Period | |
| | | January | | February | | March | | First Quarter | |
Total Number of Shares Purchased (a) | | 64,186 | | 188,695 | | 1,184,918 | | 1,437,799 | |
| Average Price Paid per Share | | $45.35 | | $39.56 | | $39.06 | | $39.41 | |
| 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 | | - | | - | | - | | - | |
| | | | | | | | | | |
(a) | Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver commonstock under its 2007 Incentive Compensation Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes upon exercise of stock options granted under the 2007 Incentive Compensation Plan and the Executive De ferred Compensation Plan. | |
ITEM 5. OTHER INFORMATION
ITEM 6. EXHIBITS
Exhibit Number | | |
| |
| | | | |
FirstEnergy | | |
| | 10.12.1 | Agreement and Plan of Merger, dated as of February 10, 2010, by and among FirstEnergy Corp., Element Merger Sub, Inc. and Allegheny Energy, Inc. (incorporated by reference to FirstEnergy’s Form of Director Indemnification Agreement | 8-K filed February 11, 2010, Exhibit 2.1, File No. 333-21011) |
| | 10.2 | Form of Management Director Indemnification Agreement | |
| 12 | Fixed charge ratios | |
| 15 | Letter from independent registered public accounting firm | |
| 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-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 | |
| 101* | The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the three months ended March 31, 2009, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as blocks of text and (v) document and entity information. | |
FES | |
| 4.1 | Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 19, 2008, of FirstEnergy Generation Corp. to The Bank of New York Trust Company, N.A., as Trustee |
| 4.1(a) | First Supplemental Indenture dated as of June 25, 2008 providing among other things for First Mortgage Bonds, Guarantee Series A of 2008 due 2009 and First Mortgage Bonds, Guarantee Series B of 2008 due 2009 |
| 4.1(b) | Second Supplemental Indenture dated as of March 1, 2009 providing among other things for First Mortgage Bonds, Guarantee Series A of 2009 due 2014 and First Mortgage Bonds, Guarantee Series B of 2009 due 2023 |
| 4.1(c) | Third Supplemental Indenture dated as of March 31, 2009 providing among other things for First Mortgage Bonds, Collateral Series A of 2009 due 2011 |
| | 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 | 101* | The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended March 31, 2010, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as blocks of text and (v) document and entity information. |
| | Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Registrant will furnish the omitted schedules to the Securities and Exchange Commission upon request by the Commission. |
FES | |
| | 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 |
CEIOE | |
| | 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 |
TECEI | |
| 4.1 | First Supplemental Indenture, dated as of April 24, 2009, between the Toledo Edison Company and The Bank of New York Mellon Trust Company, N.A., as trustee to the Indenture dated as of November 1, 2006 (incorporated by reference to April 24, 2009 Form 8-K, Exhibit 4.1) |
| 4.2 | Officer’s Certificate (including the Form of the 7.25% Senior Secured Notes due 2020), dated April 24, 2009 (incorporated by reference to April 24, 2009 Form 8-K, Exhibit 4.2) |
| 4.3 | Fifty-sixth Supplemental Indenture, dated as of April 23, 2009, between The Toledo Edison Company and JPMorgan Chase Bank, N.A., as trustee, to the Indenture of Mortgage and Deed of Trust dated as of April 1, 1947 (incorporated by reference to April 24, 2009 Form 8-K, Exhibit 4.3) |
| 4.4 | Fifty-seventh Supplemental Indenture, dated as of April 24, 2009, between the Toledo Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee, to the Indenture of Mortgage and Deed of Trust dated as of April 1, 1947 (incorporated by reference to April 24, 2009 Form 8-K, Exhibit 4.4) |
| 4.5 | Form of First Mortgage Bonds, 7.25% Series of 2009 Due 2020 (incorporated by reference to April 24, 2009 Form 8-K, Exhibit 4.5) |
| | 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 |
JCP<E | |
| | 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 |
Met-Ed | |
| 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 |
PenelecJCP&L | |
| | 12 | Fixed charge ratios |
| | 1531.1 | Letter from independent registered public accounting firmCertification 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 |
| | 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 |
* Users of this data are advised pursuant to Rule 401 of Regulation S-T that the financial information contained in the XBRL-Related Documents is unaudited and the purpose of submitting these XBRL-Related Documents is to test the related format and technology and, as a result, investors should not rely on the XBRL-Related Documents in making investment decisions. Furthermore, users of this data are advised in accordance with Rule 406T of Regulation S-T promulgated by the Securities and Exchange Commission that this Interactive Data File is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.
Pursuant to reporting requirements of respective financings, FirstEnergy, FES, OE, CEI, TE, 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.
May 7, 20094, 2010
| | FIRSTENERGY CORP. CORP. |
| | Registrant |
| | |
| | FIRSTENERGY SOLUTIONS CORP. |
| | Registrant |
| | |
| | OHIO EDISON COMPANY |
| | Registrant |
| | |
| | THE CLEVELAND ELECTRIC |
| | ILLUMINATING COMPANY |
| | Registrant |
| | |
| | THE 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 |
| | |
| | |
| | |
| | /s/ PauletteKevin R. ChatmanBurgess |
| | PauletteKevin R. ChatmanBurgess |
| | Controller |
| | (Principal Accounting Officer) |