(C) PENNSYLVANIAPennsylvania
Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations. The fixed price under the agreement is expected to remain below wholesale market prices during the term of the agreement. If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for their fixed income securities. Based on the PPUC’s January 11, 2007 order described below, ifIf 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 made a comprehensive transition rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals had been approved, annual revenues would have increased by $216 million and $157 million, respectively. That filing included, among other things, a request to charge customers for an increasing amount of market-priced power procured through a CBP as the amount of supply provided under the then existing FES agreement was tocould be phased out. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs incurred during 2006. In this rate filing, Met-Ed and Penelec requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the FirstEnergy and GPU merger proceeding, related to the quantification and allocation of merger savings, with the comprehensive transition rate filing case.
The PPUC entered its opinion and order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, and determined that no merger savings from prior years should be considered in determining customers’ rates. The request for increases in generation supply rates was denied as were the requested changes to NUG expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased Met-Ed’s and Penelec’s distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission costs. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and, in January 2007, Met-Ed and Penelec recognized income of $15 million and $12 million, respectively, to establish regulatory assets for those previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million).material.
On March 30, 2007, MEIUG and PICA filed a Petition for Review withMay 22, 2008, the Commonwealth Court of Pennsylvania askingPPUC approved the court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase. The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. From June through October 2007, initial responsive and reply briefs were filed by various parties. Oral arguments are scheduled to take place in September 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the results of operations of Met-Ed, Penelec and FirstEnergy.
On April 14, 2008, Met-Ed and Penelec filed annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. 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 proposed TSCs include a component forfrom under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and future transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed has proposedreceived 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 March 13, 2008,April 15, 2009, Met-Ed and Penelec filed revised TSCs with the PPUC approved the residential procurement process in Penn’s Joint Petition for Settlement. This RFP process calls for load-following, full-requirements contracts for default service procurement for residential customers for the period covering June 1, 20082009 through May 31, 2011.2010, as required in connection with the PPUC’s January 2007 rate order. For Penelec’s customers, the new TSC would result in an approximate 1% decrease in monthly bills, reflecting projected PJM transmission costs as well as a reconciliation for costs already incurred. The PPUC had previously approvedTSC for Met-Ed’s customers would increase to recover the default service procurement processes for commercial and industrial customers. The default service procurement for small commercial customers was conducted through multiple RFPs, while the default service procurement for large commercial and industrial customers will utilize hourly pricing. Bidsadditional PJM charges paid by Met-Ed in the two RFPsprevious year and to reflect updated projected costs. In order to gradually transition customers to the higher rate, Met-Ed is proposing to continue to recover the prior period deferrals allowed in the PPUC’s May 2008 Order and defer $57.5 million of projected costs into a future TSC to be fully recovered by December 31, 2010. Under this proposal, monthly bills for small commercialMet-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 which became effective on November 14, 2008 as Act 129 of 2008. The bill addresses issues such as: energy efficiency and peak load were approved byreduction; generation procurement; time-of-use rates; smart meters and alternative energy. Act 129 requires utilities to file with the PPUC on February 22, 2008,an energy efficiency and March 20, 2008.peak load reduction plan by July 1, 2009 and a smart meter procurement and installation plan by August 14, 2009. On March 28, 2008, Penn filedJanuary 15, 2009, in compliance tariffs with the new default service generation rates based on the approved RFP bids for small commercial customers whichAct 129, the PPUC then certifiedissued 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 April 4, 2008. On April 14, 2008,March 30, 2009.
Major provisions of the first RFP for residential customers’ load was held consisting of tranches for both 12 and 24-month supply. The PPUC approved the bids on April 16, 2008. The second RFP is scheduled to be held on May 14, 2008, after which time the PPUC is expected to approve the new rates to go into effect June 1, 2008.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; |
On February 1, 2007,
· | 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 Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation and demand reduction programs to meet energy growth, a requirement that electric distribution companies acquire power that results in the “lowest reasonable rate on a long-term basis,” the utilization of micro-grids and a three year phase-in of rate increases. On July 17, 2007 the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy was convened in mid-September 2007 to consider other aspects of the EIS. The Pennsylvania House and Senate on March 11, 2008 and December 12, 2007, respectively, passed different versions of bills to fund the Governor’s EIS proposal. Neither chamber has formally considered the other’s bill. On February 12, 2008, the Pennsylvania House passed House Bill 2200 which provides for energy efficiency and demand management programs and targets as well as the installation of smart meters within ten years. Other legislation has been introduced to address generation procurement, expiration of rate caps conservation and renewable energy.was not enacted in 2008; however, several bills addressing these issues have been introduced in the current legislative session, which began in January 2009. The final form and impact of this pendingsuch legislation is uncertain. Consequently, FirstEnergy
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 unabledesigned to predict what impact, if any, such legislation mayprovide 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 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 - $51 million), overall rates would remain unchanged. The PPUC must act on its operations.this filing within 120 days.
(D) NEW JERSEYNew Jersey
JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers, and costs incurred under NUG agreements, 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, 2008,2009, the accumulated deferred cost balance totaled approximately $264$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) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DRADPA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and also submitted comments in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set. On 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 FirstEnergy or JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. The NJBPU Staff circulated revised drafts of the proposal to interested stakeholders in November 2006 and again in February 2007. On February 1, 2008, the NJBPU accepted proposed rules for publication in the New Jersey Register on March 17, 2008. AFollowing public hearing on these proposed rules was held on April 23, 2008 withand consideration of comments from interested parties, due on May 16, 2008.the NJBPU approved final regulations effective April 6, 2009. These regulations are not expected to materially impact FirstEnergy or 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. In October 2006, the current EMP process was initiated through the creation of a number of working groups to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. In addition, public stakeholder meetings were held in the fall of 2006 and in early 2007.
On April 17, 2008, a draft
The EMP was released for public comment. The draft EMP establishes fourissued 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 (amounting to about a 22% reduction in projected demand);2020; |
· | meet 22.5%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 |
· | develop low carbon emitting, efficient power plantsinvest in innovative clean energy technologies and closebusinesses to stimulate the gap between the supply and demand for electricity.industry’s growth in New Jersey. |
FollowingOn January 28, 2009, the public comment period which is expectedNJBPU 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 extend into July 2008, a final EMP will be issued to be followed by appropriate legislation and regulation as necessary.achieve the goals of the EMP. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation or regulationthe EMP may have on its operations or those of JCP&L.
On February 13, 2007, the NJBPU Staff informally issued a draft proposal relating to changes to the regulations addressing electric distribution service reliability and quality standards. Meetings between the NJBPU Staff and interested stakeholders to discuss the proposal were held and additional, revised informal proposals were subsequently circulated by the Staff. On September 4, 2007, proposed regulations were published inIn support of the New Jersey Register, which proposalGovernor’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 subsequently considered by the NJBPU following commentsspent 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 were submitted in September and October 2007. Final regulations (effective upon publication) were published in the New Jersey Register March 17, 2008. Upon preliminary reviewwill complement those currently being offered. Completion of the new regulations, FirstEnergy does not expect a material impact on its operations or thoseprojects is dependent upon resolution of JCP&L.regulatory issues including recovery of the costs associated with plan implementation.
(E) FERC MATTERSMatters
Transmission Service between MISO and PJM
On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate so-called “pancaking” ofmultiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or “SECA”)SECA) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order could be issued byis pending before the FERC, and in the second quartermeantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of 2008.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.
PJM Transmission Rate Design
On January 31, 2005, certain PJM transmission owners made filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. Hearings were held and numerous parties appeared and litigated various issues concerning PJM rate design; notably AEP, which proposed to create a "postage stamp", or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. This proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. The FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.
On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. 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 revenue recoveryto 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. The FERC’s action onJudge to the FERC. On July 29, 2008, the FERC issued an order conditionally approving the settlement agreement is pending.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 will proceed towere the subject of a hearing at the FERC in May 2008. On February 13, 2008, AEP appealedAn initial decision was issued by the FERC’s ordersPresiding Judge on September 18, 2008. PJM and FERC trial staff each filed a Brief on Exceptions 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.
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 is pending before the FERC.
Distribution of MISO Network Service Revenues
Effective February 1, 2008, the MISO Transmission Owners Agreement provides for a change in the method of distributing transmission revenues among the transmission owners. MISO and a majority of the MISO transmission owners filed on December 3, 2007 to change the MISO tariff to clarify, for purposes of distributing network transmission revenue to the transmission owners, that all network transmission service revenues, whether collected by MISO or directly by the transmission owner, are included in the revenue distribution calculation. This clarification was necessary because some network transmission service revenues are collected and retained by transmission owners in states where retail choice does not exist, and their “unbundled” retail load is currently exempt from MISO network service charges. The tariff changes filed with the FERC ensure that revenues collected by transmission owners from bundled load are taken into account in the revenue distribution calculation, and that transmission owners with bundled load do not collect more than their revenue requirements. Absent the changes, transmission owners, and ultimately their customers, with unbundled load or in retail choice states, such as ATSI, would subsidize transmission owners with bundled load, who would collect their revenue requirement from bundled load, plus share in revenues collected by MISO from unbundled customers. This would result in a large revenue shortfall for ATSI, which would eventually be passed on to customers in the form of higher transmission rates as calculated pursuant to ATSI’s Attachment O formula under the MISO tariff.
Numerous parties filed in support of the tariff changes, including the public service commissions of Michigan, Ohio and Wisconsin. Ameren filed a protest on December 26, 2007, arguing that the December 3, 2007 filing violates the MISO Transmission Owners’ Agreement as well as an agreement among Ameren (Union Electric), MISO, and the Missouri Public Service Commission, which provides that Union Electric’s bundled load cannot be charged by MISO for network service. On February 2, 2008, the FERC issued an order conditionally accepting the tariff amendment subject to a minor compliance filing, which was made on March 3, 2008. This order ensures that ATSI will continue to receive transmission revenues from MISO equivalent to its transmission revenue requirement. A rehearing request by Ameren is pending before the FERC.
On February 1, 2008, MISO filed a request to continue using the existing revenue distribution methodology on an interim basis pending amendment of the MISO Transmission Owners’ Agreement. This request was accepteddenied by the FERC on March 13,December 19, 2008. On that same day, MISOFebruary 17, 2009, AEP appealed the FERC’s January 31, 2008, and December 19, 2008, orders to the MISO transmission owners made a filing to amend the Transmission Owners’ Agreement to effectively continue the distributionU.S. Court of transmission revenues that was in effect prior to February 1, 2008. This matter is currently pending before the FERC.
MISO Ancillary Services Market and Balancing Area Consolidation
MISO made a filing on September 14, 2007 to establish an ASM for regulation, spinning and supplemental reserves, to consolidate the existing 24 balancing areas within the MISO footprint, and to establish MISO as the NERC registered balancing authorityAppeals for the region. This filing would permit load serving entities to purchase their operating reserve requirements in a competitive market. FirstEnergy supports the proposal to establish markets for Ancillary Services and consolidate existing balancing areas. On February 25, 2008, the FERC issued an order approving the ASM subject to certain compliance filings. MISO has since notified the FERC that the startSeventh Circuit. FESC, on behalf of its ASM is delayed until September of 2008.
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 MISO. In its filing, Duquesne asked the FERC to be relieved of certain capacity payment obligations to PJM for capacity auctions conducted prior to its departure from PJM, but covering service for planning periods through May 31, 2011. Duquesne asserted that its primary reason for exiting PJM is to avoid paying future obligations created by PJM’s forward capacity market. FirstEnergy believes that Duquesne’s filing did not identify or address numerous legal, financial or operational issues that are implicated or affected directly by Duquesne’s proposal. Consequently, FirstEnergy submitted responsive filings that, while conceding Duquesne’s rights to exit PJM, contested various aspects of Duquesne’s proposal. FirstEnergy particularly focused on Duquesne’s proposal that it be allowed to exit PJM without payment of its share of existing capacity market commitments. FirstEnergy also objected to Duquesne’s failure to address the firm transmission service requirements that would be necessary for FirstEnergy to continue to use theterms under which FirstEnergy’s Beaver Valley Plant would continue to meet existing commitmentsparticipate in PJM’s energy markets. FirstEnergy, therefore, intervened and participated fully in all of the PJM capacity markets andFERC dockets that were related to serve native load. Other market participants also submitted filings contesting Duquesne’s plans.proposed move.
On January 17,In November, 2008, the FERC conditionally approved Duquesne’s request to exit PJM. AmongDuquesne and other conditions, the FERC obligatedparties, including FirstEnergy, negotiated a settlement that would, among other things, allow for Duquesne to payremain in PJM and provide for a methodology for Duquesne to meet the PJM capacity obligations through May 31, 2011.for the 2011-2012 auction that excluded the Duquesne load. The FERC’ssettlement agreement was filed on December 10, 2008 and approved by the FERC in an order took noticeissued 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 numerous transmission and other issues raised byFERC's January 29, 2009 order approving the settlement. Thereafter, FirstEnergy and other parties filed in opposition to the proceeding, but did not provide any responsive rulings or other guidance. Rather,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 ordered Duquesne to make a compliance filing in forty-five days detailing how Duquesne will satisfy its obligationsagainst PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the PJM Transmission Owners’ Agreement.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 likewise directedalso ordered PJM to file on or before December 15, 2008, a report on potential adjustments to the MISO to submit detailed plans to integrate Duquesne intoRPM program as suggested in a Brattle Group report. On December 12, 2008, PJM filed proposed tariff amendments that would adjust slightly the MISO. Finally,RPM program. PJM also requested that the FERC directed MISOconduct a settlement hearing to address changes to the RPM and PJM to work together to resolve the substantive and procedural issues implicated by Duquesne’s transition into the MISO. These issues remain unresolved. If Duquesne satisfies all of the obligations set bysuggested 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 planned transition date is October 9, 2008.starting point, and stated that unless otherwise specified, provisions filed by PJM on December 12, 2008, apply.
On March 18, 2008,26, 2009, the FERC accepted in part, and rejected in part, tariff provisions submitted by PJM, Power Providers Group filed a request for emergency clarification regarding whether Duquesne-zone generators (includingrevising certain parts of its RPM. Ordered changes included making incremental improvements to RPM; however, the Beaver Valley Plant) could participate in PJM’s May 2008 auction for the 2011-2012basic construct of RPM delivery year. FirstEnergy and the other Duquesne-zone generators filed responsive pleadings.remains intact. On April 18, 2008,3, 2009, PJM filed with the FERC issued its Orderrequesting clarification on Motion for Emergency Clarification, whereincertain aspects of the March 26, 2009 Order. On April 27, 2009, PJM submitted a compliance filing addressing the changes the FERC ruled that althoughordered in the statusMarch 26, 2009 Order; numerous parties have filed requests for rehearing of the Duquesne-zone generators will change to “External Resource” upon Duquesne’s exit from PJM, these generators can contract with PJM forMarch 26, 2009 Order. In addition, the transmission reservations necessary to participateFERC has indefinitely postponed the technical conference on RPM granted in the May 2008 auction. FirstEnergy has complied with FERC’sFERC order by obtaining executed transmission service agreements for firm point-to-point transmission service for the 2011-2012 delivery year and, as such, FirstEnergy satisfies the criteria to bid the Beaver Valley Plant into the May 2008 RPM auction. Notwithstanding these events, on April 30, 2008 and May 1, 2008, certain members of the PJM Power Providers Group filed further pleadings on these issues. On May 2, 2008, FirstEnergy filed a responsive pleading. FirstEnergy is participating in the May 2008 RPM auction for the 2011-2012 RPM delivery year.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 servingload-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 servingload-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 servingload-serving entities in its state. FirstEnergy generally supportsbelieves the proposal as it promotes a mechanism that will result in long-term commitments from both load-serving entities and resources, including both generation and demand side resources that are necessary for reliable resource adequacy and planning in the MISO footprint. Comments on the filing were filedsubmitted on January 28, 2008. The FERC conditionally approved MISO’s Resource Adequacy proposal on March 26, 2008.2008, requiring MISO to submit to further compliance filings. Rehearing requests are pending on the FERC’s March 26 Order. AOn 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 is due on or before June 25, 2008.
Organized Wholesale Power Marketswhich establishes deficiency payments for load-serving entities that do not meet the resource adequacy requirements. Numerous parties, including FirstEnergy, protested this filing.
On February 21,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 NOPRcompliance 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 which it proposesMarch 31, 2009. Subsequently, FES signed an agreement to adopt new rulesprovide 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.
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 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 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 “improve operationscontinue. On October 18, 2007, PennFuture filed a complaint, joined by three of its members, in organizedthe 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. 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 Amended Complaint 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 markets, boost competitionpower 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 bring additional benefitsNOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to consumers.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, addresses demandnoting 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 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.
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. 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.
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
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 pricing during reserve shortages, long-term power contracting, market-monitoring policies,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 responsiveness of RTOsan adjustment to the transactions or quoted prices may be necessary to estimate fair value. Additional disclosures related to the inputs and ISOs to stakeholdersvaluation techniques used in the fair value measurements are also required. The FSP is effective for interim and customers.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 believe thatexpect the proposed rule willFSP 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 impactassumptions 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 operations. Commentsdisclosures 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 NOPRaccompanying 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 the first three months of 2009, net income increased to $171 million from $90 million in the same period 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 compared to the same period in 2008 due to increases in revenues from non-affiliated 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 filed on April 18,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 each 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.
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.
12. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS |
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
In the first three months of 2009, net income decreased to $12 million from $44 million in the same period 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 adjustments 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, reflecting 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 the 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 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 |
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.
Revenues
In the first three months of 2009, revenues decreased 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.
Retail generation revenues from all customer classes increased in the first three months of 2009 compared to the same period of 2008 due 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 volume to the commercial sector decreased primarily due to an increase in the number of customers procuring generation from other suppliers.
Wholesale generation revenues decreased $47 million in the first three months of 2009 due to lower market prices and a decrease in sales volume (from NUG purchases) as compared 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 compared 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 | ) |
Expenses
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
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 | ) |
SFAS 141(R)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; |
| |
· | continuing regulation of the Utilities' transmission and distribution systems; and |
| |
· | 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)
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.
SB221 also requires electric distribution utilities to implement energy efficiency programs that achieve an 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. Utilities are also required 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.
Pennsylvania (Applicable to FES, Met-Ed, Penelec, OE and Penn)
Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations. 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, 2009, Met-Ed and Penelec filed revised TSCs with the PPUC for the period June 1, 2009 through May 31, 2010, as required in connection with the PPUC’s January 2007 rate order. For Penelec’s customers, the new TSC would result 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 increase 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 proposing to continue to recover the prior period deferrals allowed in the PPUC’s May 2008 Order and defer $57.5 million of projected costs into 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 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:
· | 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 enacted in 2008; however, several bills addressing these issues have been introduced in the current legislative session, which began in January 2009. 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 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 - $51 million), overall rates would remain unchanged. The PPUC must act on this filing within 120 days.
New Jersey (Applicable to JCP&L)
JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers, 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) 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 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. At this time, JCP&L cannot determine the impact, if any, the EMP may have on its operations.
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.
FERC Matters (Applicable to FES and each of the Utilities)
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 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.
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 and numerous parties appeared and litigated various issues concerning PJM rate design; notably AEP, which proposed to create a "postage stamp", or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. This proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. The FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.
On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. 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.
Environmental Matters
Various federal, state and local authorities regulate FES and the Utilities with regard to air and water quality and other environmental matters. The effects of compliance on FES and the Utilities with regard to environmental matters could have a material adverse effect on their earnings and competitive position to the extent that they compete with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations.
FES and the Utilities accrue environmental liabilities only when they conclude that it is probable that they have an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in FES’ and the Utilities’ 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)
FES is required to meet federally-approved SO2 emissions regulations. Violations of such regulations can result in the shutdown of the generating unit involved and/or civil or criminal penalties of up to $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. FES believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.
The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006, alleging violations to various sections of the CAA. FES has disputed those alleged violations based on its CAA permit, the Ohio SIP and other information provided to the EPA at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order, and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding emission limits applicable to the common stack for Bay Shore Units 2, 3 and 4.
FES complies with SO2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOX reductions required by the 1990 Amendments are being achieved through combustion controls, 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' facilities. The EPA's NOX Transport Rule imposes uniform reductions of NOX emissions (an approximate 85% reduction in utility plant NOX emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOX emissions are contributing significantly to ozone levels in the eastern United States. FES believes its facilities are also complying with the NOX budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.
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 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. 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 Amended Complaint 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 (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 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 (Applicable to FES)
In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping national mercury emissions at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the United States Court of Appeals for the District of Columbia. On February 8, 2008, the Court vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. The EPA 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, 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 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 – “Business Combinations”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.
FES cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions could require significant capital and other expenditures. The CO2 emissions per KWH of electricity generated by FES is lower than many regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.
Clean Water Act (Applicable to FES)
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FES' plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FES' operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.
On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). On January 26, 2007, the United States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment 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. FES 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 (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, 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.
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) 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.
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.
Nuclear Plant Matters (Applicable to FES)
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. 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.
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 (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’ normal business operations pending against them. 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. FES 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.
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 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. 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 2007,2008, the FASB issued SFAS 141(R),Staff Position FAS 132(R)-1, which requires the acquiring entity inprovides guidance on an employer’s disclosures about plan assets of a business combination to recognize all thedefined benefit pension or other postretirement plan. Requirements of this FSP include disclosures about investment policies and strategies, categories of plan assets, acquired and liabilities assumed in the transaction; establishes the acquisition-date 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 measurement objective for all assets acquiredUtilities to the extent indicated)
On April 6, 2009, Richard H. Marsh, Senior Vice President and liabilities assumed;Chief Financial Officer (CFO) of FirstEnergy indicated his intention to step down as CFO on May 1, 2009, and requiresretire from FirstEnergy effective July 1, 2009. Mr. Marsh was also Senior Vice President and CFO of FES and each of the acquirerUtilities 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 disclose to investorssucceed Mr. Marsh as CFO of FirstEnergy, effective May 1, 2009. Mr. Clark also became Executive Vice President and other usersCFO 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 they needshould be restricted in light of the limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to evaluatethe 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 understand11 of the natureSecurities 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 effectliabilities 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 business combination.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 141(R) attempts to reduce157. These factors include nonperformance risk, including counterparty credit risk and the complexityimpact of existing GAAP related to business combinations.credit enhancements (such as cash deposits, LOCs and priority interests). The Standard includes both core principles and pertinent application guidance, eliminatingimpact of nonperformance risk was immaterial in the need for numerous EITF issues and other interpretative guidance. SFAS 141(R) will affect business combinations entered into by FirstEnergy that close after January 1, 2009. In addition, the Standard also affects the accounting forfair value measurements.
The following table sets forth a reconciliation of changes in tax valuation allowances made afterthe 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 were establishedmeet 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 business combinationnotional 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 implementationexpected 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 Standard. FirstEnergy is currently evaluating the impact of adopting this Standard onjoint venture in its financial statements.
SFAS 160 - “Noncontrolling InterestsTrusts
FirstEnergy’s consolidated financial statements include PNBV and Shippingport, VIEs created in Consolidated Financial Statements –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 Amendmentunaffiliated third party and a 3% equity interest held by OES Ventures, a wholly owned subsidiary of ARB No. 51”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 December 2007,accordance with FIN 46R, FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the FASB issued SFAS 160extent they own a plant that establishes accountingsells substantially all of its output to the Companies and reporting standardsthe 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 noncontrolling2007 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 a subsidiaryaccordance 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 deconsolidation of a subsidiary. It clarifies that a noncontrolling interestyears 2001-2003 in a subsidiary is an ownership interestJuly 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 consolidated entityfirst 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 should be reported as equity in the consolidated financial statements. This Statement is effective for fiscal years,adequate reserves have been recognized and interim periods within those fiscal years, beginning on or after December 15, 2008. Early adoption is prohibited. The Statementfinal settlement of these audits is not expected to have a material impactadverse 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 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 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. 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 Amended Complaint 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. 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.
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.
9. REGULATORY MATTERS
(A) RELIABILITY INITIATIVES
In 2005, Congress amended the Federal Power Act to provide for federally-enforceable mandatory reliability standards. The mandatory reliability standards apply to the bulk power system and impose certain operating, record-keeping and reporting requirements on the 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 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.
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.
(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. 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.
SB221 also requires electric distribution utilities to implement energy efficiency programs that achieve an 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. Utilities are also required 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 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 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, 2009, Met-Ed and Penelec filed revised TSCs with the PPUC for the period June 1, 2009 through May 31, 2010, as required in connection with the PPUC’s January 2007 rate order. For Penelec’s customers, the new TSC would result 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 increase 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 proposing to continue to recover the prior period deferrals allowed in the PPUC’s May 2008 Order and defer $57.5 million of projected costs into 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 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:
· | 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 enacted in 2008; however, several bills addressing these issues have been introduced in the current legislative session, which began in January 2009. 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 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 - $51 million), overall rates would remain unchanged. The PPUC must act on this filing within 120 days.
(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, 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) 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 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 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.
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. 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
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 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.
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 and numerous parties appeared and litigated various issues concerning PJM rate design; notably AEP, which proposed to create a "postage stamp", or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. This proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. The FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.
On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. 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.
| SFAS 161FSP FAS 115-2 and FAS 124-2 - “Disclosures about Derivative Instruments“Recognition and Hedging Activities – an AmendmentPresentation of FASB Statement No. 133”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 SFAS 161,Staff Position FAS 132(R)-1, which requires enhancements to the current disclosure framework for derivative instruments and hedging activities. The Statement requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. This disclosure is intended to better convey the purpose of derivatives use in terms of the risks that the entity is intending to manage. The FASB believes disclosing the fair values of derivative instruments and their gains and losses in a tabular format is designed to provide a more complete picture of the location in an entity’s financial statements of both the derivative positions existing at period end and the effect of using derivatives during the reporting period. Disclosing information about credit-risk-related contingent features is designed to provide financial statement users information on the potential effectprovides guidance on an entity’s liquidity from using derivatives. Finally,employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. Requirements of this Statement requires cross-referencing within the footnotes, whichFSP 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 intendedeffective for fiscal years ending after December 15, 2009. FirstEnergy will expand its disclosures related to help userspostretirement benefit plan assets as a result of financial statements locate important information about derivative instruments. FirstEnergy is currently evaluating the impact of adopting this Standard on its financial statements.FSP.
11. SEGMENT INFORMATION
FirstEnergy has three reportable operating segments: energy delivery services, competitive energy services and Ohio transitional generation services. The “Other” segment primarily consists of telecommunications services. The assets and revenues for theall 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 electricelectricity 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 full-requirements PSA arrangements,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, 2008 | | | | | | | | | | | | | | | | | | |
External revenues | | $ | 2,212 | | | $ | 329 | | | $ | 707 | | | $ | 40 | | | $ | (11 | ) | | $ | 3,277 | |
Internal revenues | | | - | | | | 776 | | | | - | | | | - | | | | (776 | ) | | | - | |
Total revenues | | | 2,212 | | | | 1,105 | | | | 707 | | | | 40 | | | | (787 | ) | | | 3,277 | |
Depreciation and amortization | | | 255 | | | | 53 | | | | 4 | | | | - | | | | 5 | | | | 317 | |
Investment income | | | 45 | | | | (6 | ) | | | 1 | | | | - | | | | (23 | ) | | | 17 | |
Net interest charges | | | 103 | | | | 27 | | | | - | | | | - | | | | 41 | | | | 171 | |
Income taxes | | | 119 | | | | 58 | | | | 15 | | | | 14 | | | | (19 | ) | | | 187 | |
Net income | | | 179 | | | | 87 | | | | 23 | | | | 22 | | | | (35 | ) | | | 276 | |
Total assets | | | 23,211 | | | | 8,108 | | | | 257 | | | | 281 | | | | 558 | | | | 32,415 | |
Total goodwill | | | 5,582 | | | | 24 | | | | - | | | | - | | | | - | | | | 5,606 | |
Property additions | | | 255 | | | | 462 | | | | - | | | | 12 | | | | (18 | ) | | | 711 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
March 31, 2007 | | | | | | | | | | | | | | | | | | | | | | | | |
External revenues | | $ | 2,040 | | | $ | 321 | | | $ | 619 | | | $ | 12 | | | $ | (19 | ) | | $ | 2,973 | |
Internal revenues | | | - | | | | 714 | | | | - | | | | - | | | | (714 | ) | | | - | |
Total revenues | | | 2,040 | | | | 1,035 | | | | 619 | | | | 12 | | | | (733 | ) | | | 2,973 | |
Depreciation and amortization | | | 220 | | | | 51 | | | | (15 | ) | | | 1 | | | | 6 | | | | 263 | |
Investment income | | | 70 | | | | 3 | | | | 1 | | | | - | | | | (41 | ) | | | 33 | |
Net interest charges | | | 107 | | | | 49 | | | | 1 | | | | 2 | | | | 21 | | | | 180 | |
Income taxes | | | 148 | | | | 65 | | | | 15 | | | | 5 | | | | (33 | ) | | | 200 | |
Net income | | | 218 | | | | 98 | | | | 24 | | | | 1 | | | | (51 | ) | | | 290 | |
Total assets | | | 23,526 | | | | 7,089 | | | | 246 | | | | 254 | | | | 675 | | | | 31,790 | |
Total goodwill | | | 5,874 | | | | 24 | | | | - | | | | - | | | | - | | | | 5,898 | |
Property additions | | | 155 | | | | 124 | | | | - | | | | 1 | | | | 16 | | | | 296 | |
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.
14. SUPPLEMENTAL GUARANTOR INFORMATION |
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, 20082009, and 2007,2008, consolidating balance sheets as of March 31, 20082009, and December 31, 20072008, and condensed consolidating statements of cash flows for the three months ended March 31, 20082009, and 20072008 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. | |
| | | | | | | | | | | | | | | |
CONSOLIDATING STATEMENTS OF INCOME | |
(Unaudited) | |
| | | | | | | | | | | | | | | |
For the Three Months Ended March 31, 2008 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | (In thousands) | |
| | | | | | | | | | | | | | | |
REVENUES | | $ | 1,099,848 | | | $ | 567,701 | | | $ | 325,684 | | | $ | (894,117 | ) | | $ | 1,099,116 | |
| | | | | | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | | | | | |
Fuel | | | 2,138 | | | | 291,239 | | | | 28,312 | | | | - | | | | 321,689 | |
Purchased power from non-affiliates | | | 206,724 | | | | - | | | | - | | | | - | | | | 206,724 | |
Purchased power from affiliates | | | 891,979 | | | | 2,138 | | | | 25,485 | | | | (894,117 | ) | | | 25,485 | |
Other operating expenses | | | 37,596 | | | | 107,167 | | | | 139,595 | | | | 12,188 | | | | 296,546 | |
Provision for depreciation | | | 307 | | | | 26,599 | | | | 24,194 | | | | (1,358 | ) | | | 49,742 | |
General taxes | | | 5,415 | | | | 11,570 | | | | 6,212 | | | | - | | | | 23,197 | |
Total expenses | | | 1,144,159 | | | | 438,713 | | | | 223,798 | | | | (883,287 | ) | | | 923,383 | |
| | | | | | | | | | | | | | | | | | | | |
OPERATING INCOME (LOSS) | | | (44,311 | ) | | | 128,988 | | | | 101,886 | | | | (10,830 | ) | | | 175,733 | |
| | | | | | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | |
Miscellaneous income (expense), including | | | | | | | | | | | | | | | | | | | | |
net income from equity investees | | | 121,725 | | | | (1,208 | ) | | | (6,537 | ) | | | (116,884 | ) | | | (2,904 | ) |
Interest expense to affiliates | | | (82 | ) | | | (5,289 | ) | | | (1,839 | ) | | | - | | | | (7,210 | ) |
Interest expense - other | | | (3,978 | ) | | | (25,968 | ) | | | (11,018 | ) | | | 16,429 | | | | (24,535 | ) |
Capitalized interest | | | 21 | | | | 6,228 | | | | 414 | | | | - | | | | 6,663 | |
Total other income (expense) | | | 117,686 | | | | (26,237 | ) | | | (18,980 | ) | | | (100,455 | ) | | | (27,986 | ) |
| | | | | | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 73,375 | | | | 102,751 | | | | 82,906 | | | | (111,285 | ) | | | 147,747 | |
| | | | | | | | | | | | | | | | | | | | |
INCOME TAXES (BENEFIT) | | | (16,609 | ) | | | 39,285 | | | | 32,764 | | | | 2,323 | | | | 57,763 | |
| | | | | | | | | | | | | | | | | | | | |
NET INCOME | | $ | 89,984 | | | $ | 63,466 | | | $ | 50,142 | | | $ | (113,608 | ) | | $ | 89,984 | |
FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | |
CONSOLIDATING STATEMENTS OF INCOME | |
(Unaudited) | |
| | | | | | | | | | | | | | | |
For the Three Months Ended March 31, 2007 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | (In thousands) | |
| | | | | | | | | | | | | | | |
REVENUES | | $ | 1,019,387 | | | $ | 551,355 | | | $ | 234,091 | | | $ | (786,540 | ) | | $ | 1,018,293 | |
| | | | | | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | | | | | |
Fuel | | | 2,367 | | | | 201,231 | | | | 29,937 | | | | - | | | | 233,535 | |
Purchased power from non-affiliates | | | 186,203 | | | | 2,367 | | | | - | | | | (2,367 | ) | | | 186,203 | |
Purchased power from affiliates | | | 784,172 | | | | 59,069 | | | | 17,415 | | | | (784,173 | ) | | | 76,483 | |
Other operating expenses | | | 51,249 | | | | 99,095 | | | | 113,252 | | | | - | | | | 263,596 | |
Provision for depreciation | | | 453 | | | | 24,936 | | | | 22,621 | | | | - | | | | 48,010 | |
General taxes | | | 4,934 | | | | 10,568 | | | | 6,216 | | | | - | | | | 21,718 | |
Total expenses | | | 1,029,378 | | | | 397,266 | | | | 189,441 | | | | (786,540 | ) | | | 829,545 | |
| | | | | | | | | | | | | | | | | | | | |
OPERATING INCOME (LOSS) | | | (9,991 | ) | | | 154,089 | | | | 44,650 | | | | - | | | | 188,748 | |
| | | | | | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | |
Miscellaneous income (expense), including | | | | | | | | | | | | | | | | | | | | |
net income from equity investees | | | 113,948 | | | | 916 | | | | 5,200 | | | | (100,332 | ) | | | 19,732 | |
Interest expense to affiliates | | | - | | | | (24,331 | ) | | | (5,115 | ) | | | - | | | | (29,446 | ) |
Interest expense - other | | | (1,385 | ) | | | (6,760 | ) | | | (9,213 | ) | | | - | | | | (17,358 | ) |
Capitalized interest | | | 5 | | | | 2,099 | | | | 1,105 | | | | - | | | | 3,209 | |
Total other income (expense) | | | 112,568 | | | | (28,076 | ) | | | (8,023 | ) | | | (100,332 | ) | | | (23,863 | ) |
| | | | | | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 102,577 | | | | 126,013 | | | | 36,627 | | | | (100,332 | ) | | | 164,885 | |
| | | | | | | | | | | | | | | | | | | | |
INCOME TAXES | | | 73 | | | | 49,289 | | | | 13,019 | | | | - | | | | 62,381 | |
| | | | | | | | | | | | | | | | | | | | |
NET INCOME | | $ | 102,504 | | | $ | 76,724 | | | $ | 23,608 | | | $ | (100,332 | ) | | $ | 102,504 | |
FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | |
CONSOLIDATING BALANCE SHEETS | |
(Unaudited) | |
| | | | | | | | | | | | | | | |
As of March 31, 2008 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | (In thousands) | |
ASSETS | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
CURRENT ASSETS: | | | | | | | | | | | | | | | |
Cash and cash equivalents | | $ | 2 | | | $ | - | | | $ | - | | | $ | - | | | $ | 2 | |
Receivables- | | | | | | | | | | | | | | | | | | | | |
Customers | | | 125,116 | | | | - | | | | - | | | | - | | | | 125,116 | |
Associated companies | | | 285,350 | | | | 231,049 | | | | 96,852 | | | | (295,511 | ) | | | 317,740 | |
Other | | | 1,174 | | | | 1,050 | | | | - | | | | | | | | 2,224 | |
Notes receivable from associated companies | | | 668,376 | | | | - | | | | 69,011 | | | | - | | | | 737,387 | |
Materials and supplies, at average cost | | | 2,849 | | | | 264,501 | | | | 207,275 | | | | - | | | | 474,625 | |
Prepayments and other | | | 107,798 | | | | 26,208 | | | | 1,728 | | | | - | | | | 135,734 | |
| | | 1,190,665 | | | | 522,808 | | | | 374,866 | | | | (295,511 | ) | | | 1,792,828 | |
| | | | | | | | | | | | | | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | | | | | | | | | | | | |
In service | | | 35,302 | | | | 5,359,381 | | | | 3,700,973 | | | | (391,896 | ) | | | 8,703,760 | |
Less - Accumulated provision for depreciation | | | 7,810 | | | | 2,655,103 | | | | 1,537,747 | | | | (168,115 | ) | | | 4,032,545 | |
| | | 27,492 | | | | 2,704,278 | | | | 2,163,226 | | | | (223,781 | ) | | | 4,671,215 | |
Construction work in progress | | | 10,792 | | | | 881,899 | | | | 165,389 | | | | - | | | | 1,058,080 | |
| | | 38,284 | | | | 3,586,177 | | | | 2,328,615 | | | | (223,781 | ) | | | 5,729,295 | |
| | | | | | | | | | | | | | | | | | | | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | | | | | | | | | | | | |
Nuclear plant decommissioning trusts | | | - | | | | - | | | | 1,263,338 | | | | - | | | | 1,263,338 | |
Long-term notes receivable from associated companies | | | - | | | | - | | | | 62,900 | | | | - | | | | 62,900 | |
Investment in associated companies | | | 2,598,022 | | | | - | | | | - | | | | (2,598,022 | ) | | | - | |
Other | | | 2,529 | | | | 21,657 | | | | 202 | | | | - | | | | 24,388 | |
| | | 2,600,551 | | | | 21,657 | | | | 1,326,440 | | | | (2,598,022 | ) | | | 1,350,626 | |
| | | | | | | | | | | | | | | | | | | | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | | | | | | | | | | | |
Accumulated deferred income taxes | | | 10,518 | | | | 495,131 | | | | - | | | | (248,666 | ) | | | 256,983 | |
Lease assignment receivable from associated companies | | | - | | | | 67,256 | | | | - | | | | - | | | | 67,256 | |
Goodwill | | | 24,248 | | | | | | | | - | | | | - | | | | 24,248 | |
Property taxes | | | - | | | | 25,007 | | | | 22,767 | | | | - | | | | 47,774 | |
Pension assets | | | 3,214 | | | | 12,856 | | | | - | | | | - | | | | 16,070 | |
Unamortized sale and leaseback costs | | | - | | | | 38,120 | | | | - | | | | 47,575 | | | | 85,695 | |
Other | | | 18,177 | | | | 49,393 | | | | 5,188 | | | | (37,939 | ) | | | 34,819 | |
| | | 56,157 | | | | 687,763 | | | | 27,955 | | | | (239,030 | ) | | | 532,845 | |
| | $ | 3,885,657 | | | $ | 4,818,405 | | | $ | 4,057,876 | | | $ | (3,356,344 | ) | | $ | 9,405,594 | |
| | | | | | | | | | | | | | | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
Currently payable long-term debt | | $ | - | | | $ | 738,087 | | | $ | 887,265 | | | $ | (16,896 | ) | | $ | 1,608,456 | |
Notes payable- | | | | | | | | | | | | | | | | | | | | |
Associated companies | | | - | | | | 885,760 | | | | 260,199 | | | | - | | | | 1,145,959 | |
Other | | | 700,000 | | | | - | | | | - | | | | - | | | | 700,000 | |
Accounts payable- | | | | | | | | | | | | | | | | | | | | |
Associated companies | | | 554,844 | | | | 1,419 | | | | 119,773 | | | | (270,368 | ) | | | 405,668 | |
Other | | | 55,614 | | | | 130,090 | | | | - | | | | - | | | | 185,704 | |
Accrued taxes | | | 3,378 | | | | 116,383 | | | | 47,292 | | | | (24,219 | ) | | | 142,834 | |
Other | | | 85,100 | | | | 107,791 | | | | 9,731 | | | | 45,484 | | | | 248,106 | |
| | | 1,398,936 | | | | 1,979,530 | | | | 1,324,260 | | | | (265,999 | ) | | | 4,436,727 | |
| | | | | | | | | | | | | | | | | | | | |
CAPITALIZATION: | | | | | | | | | | | | | | | | | | | | |
Common stockholder's equity | | | 2,460,215 | | | | 1,011,907 | | | | 1,579,614 | | | | (2,591,521 | ) | | | 2,460,215 | |
Long-term debt and other long-term obligations | | | - | | | | 1,320,773 | | | | 62,900 | | | | (1,305,717 | ) | | | 77,956 | |
| | | 2,460,215 | | | | 2,332,680 | | | | 1,642,514 | | | | (3,897,238 | ) | | | 2,538,171 | |
| | | | | | | | | | | | | | | | | | | | |
NONCURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
Deferred gain on sale and leaseback transaction | | | - | | | | - | | | | - | | | | 1,051,871 | | | | 1,051,871 | |
Accumulated deferred income taxes | | | - | | | | - | | | | 244,978 | | | | (244,978 | ) | | | - | |
Accumulated deferred investment tax credits | | | - | | | | 35,350 | | | | 24,619 | | | | - | | | | 59,969 | |
Asset retirement obligations | | | - | | | | 24,947 | | | | 798,739 | | | | - | | | | 823,686 | |
Retirement benefits | | | 9,332 | | | | 56,016 | | | | - | | | | - | | | | 65,348 | |
Property taxes | | | - | | | | 25,329 | | | | 22,766 | | | | - | | | | 48,095 | |
Lease market valuation liability | | | - | | | | 341,881 | | | | - | | | | - | | | | 341,881 | |
Other | | | 17,174 | | | | 22,672 | | | | - | | | | - | | | | 39,846 | |
| | | 26,506 | | | | 506,195 | | | | 1,091,102 | | | | 806,893 | | | | 2,430,696 | |
| | $ | 3,885,657 | | | $ | 4,818,405 | | | $ | 4,057,876 | | | $ | (3,356,344 | ) | | $ | 9,405,594 | |
FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | |
CONSOLIDATING BALANCE SHEETS | |
(Unaudited) | |
| | | | | | | | | | | | | | | |
As of December 31, 2007 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | (In thousands) | |
ASSETS | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
CURRENT ASSETS: | | | | | | | | | | | | | | | |
Cash and cash equivalents | | $ | 2 | | | $ | - | | | $ | - | | | $ | - | | | $ | 2 | |
Receivables- | | | | | | | | | | | | | | | | | | | | |
Customers | | | 133,846 | | | | - | | | | - | | | | - | | | | 133,846 | |
Associated companies | | | 327,715 | | | | 237,202 | | | | 98,238 | | | | (286,656 | ) | | | 376,499 | |
Other | | | 2,845 | | | | 978 | | | | - | | | | - | | | | 3,823 | |
Notes receivable from associated companies | | | 23,772 | | | | - | | | | 69,012 | | | | - | | | | 92,784 | |
Materials and supplies, at average cost | | | 195 | | | | 215,986 | | | | 210,834 | | | | - | | | | 427,015 | |
Prepayments and other | | | 67,981 | | | | 21,605 | | | | 2,754 | | | | - | | | | 92,340 | |
| | | 556,356 | | | | 475,771 | | | | 380,838 | | | | (286,656 | ) | | | 1,126,309 | |
| | | | | | | | | | | | | | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | | | | | | | | | | | | |
In service | | | 25,513 | | | | 5,065,373 | | | | 3,595,964 | | | | (392,082 | ) | | | 8,294,768 | |
Less - Accumulated provision for depreciation | | | 7,503 | | | | 2,553,554 | | | | 1,497,712 | | | | (166,756 | ) | | | 3,892,013 | |
| | | 18,010 | | | | 2,511,819 | | | | 2,098,252 | | | | (225,326 | ) | | | 4,402,755 | |
Construction work in progress | | | 1,176 | | | | 571,672 | | | | 188,853 | | | | - | | | | 761,701 | |
| | | 19,186 | | | | 3,083,491 | | | | 2,287,105 | | | | (225,326 | ) | | | 5,164,456 | |
| | | | | | | | | | | | | | | | | | | | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | | | | | | | | | | | | |
Nuclear plant decommissioning trusts | | | - | | | | - | | | | 1,332,913 | | | | - | | | | 1,332,913 | |
Long-term notes receivable from associated companies | | | - | | | | - | | | | 62,900 | | | | - | | | | 62,900 | |
Investment in associated companies | | | 2,516,838 | | | | - | | | | - | | | | (2,516,838 | ) | | | - | |
Other | | | 2,732 | | | | 37,071 | | | | 201 | | | | - | | | | 40,004 | |
| | | 2,519,570 | | | | 37,071 | | | | 1,396,014 | | | | (2,516,838 | ) | | | 1,435,817 | |
| | | | | | | | | | | | | | | | | | | | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | | | | | | | | | | | |
Accumulated deferred income taxes | | | 16,978 | | | | 522,216 | | | | - | | | | (262,271 | ) | | | 276,923 | |
Lease assignment receivable from associated companies | | | - | | | | 215,258 | | | | - | | | | - | | | | 215,258 | |
Goodwill | | | 24,248 | | | | - | | | | - | | | | - | | | | 24,248 | |
Property taxes | | | - | | | | 25,007 | | | | 22,767 | | | | - | | | | 47,774 | |
Pension asset | | | 3,217 | | | | 13,506 | | | | - | | | | - | | | | 16,723 | |
Unamortized sale and leaseback costs | | | - | | | | 27,597 | | | | - | | | | 43,206 | | | | 70,803 | |
Other | | | 22,956 | | | | 52,971 | | | | 6,159 | | | | (38,133 | ) | | | 43,953 | |
| | | 67,399 | | | | 856,555 | | | | 28,926 | | | | (257,198 | ) | | | 695,682 | |
TOTAL ASSETS | | $ | 3,162,511 | | | $ | 4,452,888 | | | $ | 4,092,883 | | | $ | (3,286,018 | ) | | $ | 8,422,264 | |
| | | | | | | | | | | | | | | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
Currently payable long-term debt | | $ | - | | | $ | 596,827 | | | $ | 861,265 | | | $ | (16,896 | ) | | $ | 1,441,196 | |
Short-term borrowings- | | | | | | | | | | | | | | | | | | | | |
Associated companies | | | - | | | | 238,786 | | | | 25,278 | | | | - | | | | 264,064 | |
Other | | | 300,000 | | | | - | | | | - | | | | - | | | | 300,000 | |
Accounts payable- | | | | | | | | | | | | | | | | | | | | |
Associated companies | | | 287,029 | | | | 175,965 | | | | 268,926 | | | | (286,656 | ) | | | 445,264 | |
Other | | | 56,194 | | | | 120,927 | | | | - | | | | - | | | | 177,121 | |
Accrued taxes | | | 18,831 | | | | 125,227 | | | | 28,229 | | | | (836 | ) | | | 171,451 | |
Other | | | 57,705 | | | | 131,404 | | | | 11,972 | | | | 36,725 | | | | 237,806 | |
| | | 719,759 | | | | 1,389,136 | | | | 1,195,670 | | | | (267,663 | ) | | | 3,036,902 | |
| | | | | | | | | | | | | | | | | | | | |
CAPITALIZATION: | | | | | | | | | | | | | | | | | | | | |
Common stockholder's equity | | | 2,414,231 | | | | 951,542 | | | | 1,562,069 | | | | (2,513,611 | ) | | | 2,414,231 | |
Long-term debt and other long-term obligations | | | - | | | | 1,597,028 | | | | 242,400 | | | | (1,305,716 | ) | | | 533,712 | |
| | | 2,414,231 | | | | 2,548,570 | | | | 1,804,469 | | | | (3,819,327 | ) | | | 2,947,943 | |
| | | | | | | | | | | | | | | | | | | | |
NONCURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
Deferred gain on sale and leaseback transaction | | | - | | | | - | | | | - | | | | 1,060,119 | | | | 1,060,119 | |
Accumulated deferred income taxes | | | - | | | | - | | | | 259,147 | | | | (259,147 | ) | | | - | |
Accumulated deferred investment tax credits | | | - | | | | 36,054 | | | | 25,062 | | | | - | | | | 61,116 | |
Asset retirement obligations | | | - | | | | 24,346 | | | | 785,768 | | | | - | | | | 810,114 | |
Retirement benefits | | | 8,721 | | | | 54,415 | | | | - | | | | - | | | | 63,136 | |
Property taxes | | | - | | | | 25,328 | | | | 22,767 | | | | - | | | | 48,095 | |
Lease market valuation liability | | | - | | | | 353,210 | | | | - | | | | - | | | | 353,210 | |
Other | | | 19,800 | | | | 21,829 | | | | - | | | | - | | | | 41,629 | |
| | | 28,521 | | | | 515,182 | | | | 1,092,744 | | | | 800,972 | | | | 2,437,419 | |
TOTAL LIABILITIES AND CAPITALIZATION | | $ | 3,162,511 | | | $ | 4,452,888 | | | $ | 4,092,883 | | | $ | (3,286,018 | ) | | $ | 8,422,264 | |
FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | |
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | | | | | | | | | | |
For the Three Months Ended March 31, 2008 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | (In thousands) | |
| | | | | | | | | | | | | | | |
NET CASH PROVIDED FROM (USED FOR) | | | | | | | | | | | | | | | |
OPERATING ACTIVITIES | | $ | 273,827 | | | $ | (122,171 | ) | | $ | 8,108 | | | $ | 188 | | | $ | 159,952 | |
| | | | | | | | | | | | | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
New Financing- | | | | | | | | | | | | | | | | | | | | |
Short-term borrowings, net | | | 400,000 | | | | 646,975 | | | | 234,921 | | | | - | | | | 1,281,896 | |
Redemptions and Repayments- | | | | | | | | | | | | | | | | | | | | |
Long-term debt | | | - | | | | (135,063 | ) | | | (153,540 | ) | | | - | | | | (288,603 | ) |
Common stock dividend payments | | | (10,000 | ) | | | - | | | | - | | | | - | | | | (10,000 | ) |
Net cash provided from financing activities | | | 390,000 | | | | 511,912 | | | | 81,381 | | | | - | | | | 983,293 | |
| | | | | | | | | | | | | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
Property additions | | | (19,406 | ) | | | (375,391 | ) | | | (81,545 | ) | | | (187 | ) | | | (476,529 | ) |
Proceeds from asset sales | | | - | | | | 5,088 | | | | - | | | | - | | | | 5,088 | |
Sales of investment securities held in trusts | | | - | | | | - | | | | 173,123 | | | | - | | | | 173,123 | |
Purchases of investment securities held in trusts | | | - | | | | - | | | | (181,079 | ) | | | - | | | | (181,079 | ) |
Loans to associated companies, net | | | (644,604 | ) | | | - | | | | - | | | | - | | | | (644,604 | ) |
Other | | | 183 | | | | (19,438 | ) | | | 12 | | | | (1 | ) | | | (19,244 | ) |
Net cash used for investing activities | | | (663,827 | ) | | | (389,741 | ) | | | (89,489 | ) | | | (188 | ) | | | (1,143,245 | ) |
| | | | | | | | | | | | | | | | | | | | |
Net change in cash and cash equivalents | | | - | | | | - | | | | - | | | | - | | | | - | |
Cash and cash equivalents at beginning of period | | | 2 | | | | - | | | | - | | | | - | | | | 2 | |
Cash and cash equivalents at end of period | | $ | 2 | | | $ | - | | | $ | - | | | $ | - | | | $ | 2 | |
FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | |
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | | | | | | | | | | |
For the Three Months Ended March 31, 2007 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | (In thousands) | |
| | | | | | | | | | | | | | | |
NET CASH PROVIDED FROM | | | | | | | | | | | | | | | |
OPERATING ACTIVITIES | | $ | 65,870 | | | $ | 55,003 | | | $ | 177,456 | | | $ | - | | | $ | 298,329 | |
| | | | | | | | | | | | | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
New Financing- | | | | | | | | | | | | | | | | | | | | |
Equity contribution from parent | | | 700,000 | | | | 700,000 | | | | - | | | | (700,000 | ) | | | 700,000 | |
Short-term borrowings, net | | | 250,000 | | | | - | | | | - | | | | (52,269 | ) | | | 197,731 | |
Redemptions and Repayments- | | | | | | | | | | | | | | | | | | | | |
Long-term debt | | | - | | | | (616,728 | ) | | | (128,716 | ) | | | - | | | | (745,444 | ) |
Short-term borrowings, net | | | - | | | | (52,269 | ) | | | - | | | | 52,269 | | | | - | |
Net cash provided from (used for) financing activities | | | 950,000 | | | | 31,003 | | | | (128,716 | ) | | | (700,000 | ) | | | 152,287 | |
| | | | | | | | | | | | | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
Property additions | | | (214 | ) | | | (81,400 | ) | | | (35,892 | ) | | | - | | | | (117,506 | ) |
Sales of investment securities held in trusts | | | - | | | | - | | | | 178,632 | | | | - | | | | 178,632 | |
Purchases of investment securities held in trusts | | | - | | | | - | | | | (188,076 | ) | | | - | | | | (188,076 | ) |
Loans to associated companies, net | | | (316,003 | ) | | | - | | | | (3,895 | ) | | | - | | | | (319,898 | ) |
Investment in subsidiary | | | (700,000 | ) | | | - | | | | - | | | | 700,000 | | | | - | |
Other | | | 347 | | | | (4,606 | ) | | | 491 | | | | - | | | | (3,768 | ) |
Net cash used for investing activities | | | (1,015,870 | ) | | | (86,006 | ) | | | (48,740 | ) | | | 700,000 | | | | (450,616 | ) |
| | | | | | | | | | | | | | | | | | | | |
Net change in cash and cash equivalents | | | - | | | | - | | | | - | | | | - | | | | - | |
Cash and cash equivalents at beginning of period | | | 2 | | | | - | | | | - | | | | - | | | | 2 | |
Cash and cash equivalents at end of period | | $ | 2 | | | $ | - | | | $ | - | | | $ | - | | | $ | 2 | |
PART II. OTHER INFORMATION
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.