2.2.0.25falsefalse00210 - Disclosure - Regulatory Matterstruefalsefalse1falsefalseUSDfalsefalse1/1/2010 - 12/31/2010 USD ($) USD ($) / shares $Jan-01-2010_Dec-31-2010http://www.sec.gov/CIK0001031296duration2010-01-01T00:00:002010-12-31T00:00:00USDStandardhttp://www.xbrl.org/2003/iso4217USDiso42170PureStandardhttp://www.xbrl.org/2003/instancepurexbrli0SharesStandardhttp://www.xbrl.org/2003/instancesharesxbrli0USDEPSDividehttp://www.xbrl.org/2003/iso4217USDiso4217http://www.xbrl.org/2003/instancesharesxbrli0USDUSD$2true0fe_RegulatoryMattersAbstractfefalsenadurationRegulatory Matters Abstract.falsefalsefalsefalsefalsefalsefalsefalsefalsefalse1falsefalsefalse00falsefalsefalsefalsefalseOtherxbrli:stringItemTypestringRegulatory Matters Abstract.falsefalseRegulatory Matters [Abstract]3false0us-gaap_PublicUtilitiesDisclosureTextBlockus-gaaptruenadurationNo definition available.falsefalsefalsefalsefalsefalsefalsefalsefalsefalseverboselabel1falsefalsefalse00  <div style="font-family: Helvetica,Arial,sans-serif; margin-left: 0in; "> <div align="justify" style="font-size: 10pt; margin-top: 10pt"><b>10. REGULATORY MATTERS</b> </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt; margin-left: 4%"><b>(A) RELIABILITY INITIATIVES</b> </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">Federally-enforceable mandatory reliability standards apply to the bulk power system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, FGCO, FENOC and ATSI. The NERC, as the ERO is charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including Reliability<i>First </i>Corporation. All of FirstEnergy’s facilities are located within the Reliability<i>First </i>region. FirstEnergy actively participates in the NERC and Reliability<i>First </i>stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by the Reliability<i>First </i>Corporation. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">FirstEnergy believes that it generally is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such items are found, FirstEnergy develops information about the item and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an item to Reliability<i>First</i>. Moreover, it is clear that the NERC, Reliability<i>First </i>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, 2005 amendments to the FPA provide that all prudent costs incurred to comply with the new reliability standards be recovered in rates. Still, any future inability on FirstEnergy’s part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties that could have a material adverse effect on its financial condition, results of operations and cash flows. </div>   </div>  <div style="font-family: Helvetica,Arial,sans-serif; margin-left: 0in; "> <div align="justify" style="font-size: 10pt; margin-top: 10pt">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 resulting in customers losing power for up to eleven hours. 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. NERC has submitted first and second Requests for Information regarding this and another related matter. JCP&L is complying with these requests. JCP&L is not able to predict what actions, if any, that the NERC may take with respect to this matter. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">On August 23, 2010, FirstEnergy self-reported to Reliability<i>First </i>a vegetation encroachment event on a Met-Ed 230 kV line. This event did not result in a fault, outage, operation of protective equipment, or any other meaningful electric effect on any FirstEnergy transmission facilities or systems. On August 25, 2010, Reliability<i>First </i>issued a Notice of Enforcement to investigate the incident. FirstEnergy submitted a data response to Reliability<i>First </i>on September 27, 2010. At this time, FirstEnergy is unable to predict the outcome of this investigation. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt; margin-left: 4%"><b>(B) OHIO</b> </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">The Ohio Companies operate under an ESP, which expires on May 31, 2011, that provides for generation supplied through a CBP. The ESP also allows the Ohio Companies to collect a delivery service improvement rider (Rider DSI) at an overall average rate of $0.002 per KWH for the period of April 1, 2009 through December 31, 2011. The Ohio Companies currently purchase generation at the average wholesale rate of a CBP conducted in May 2009. FES is one of the suppliers to the Ohio Companies through the May 2009 CBP. The PUCO approved a $136.6 million distribution rate increase for the Ohio Companies in January 2009, which went into effect on January 23, 2009 for OE ($68.9 million) and TE ($38.5 million) and on May 1, 2009 for CEI ($29.2 million). Applications for rehearing of the PUCO order in the distribution case were filed by the Ohio Companies and one other party. The Ohio Companies raised numerous issues in their application for rehearing related to rate recovery of certain expenses, recovery of line extension costs, the level of rate of return and the amount of general plant balances. On February 2, 2011, the PUCO issued an Entry on Rehearing denying the applications for rehearing filed both by the Ohio Companies and by the other party. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">On March 23, 2010, the Ohio Companies filed an application for a new ESP. The new ESP will go into effect on June 1, 2011 and conclude on May 31, 2014. The PUCO approved the new ESP on August 25, 2010 with certain modifications. The material terms of the new ESP include: a CBP similar to the one used in May 2009 and the one proposed in the October 2009 MRO filing; a 6% generation discount to certain low-income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (initial auctions scheduled for October 20, 2010 and January 25, 2011); no increase in base distribution rates through May 31, 2014; a load cap of no less than 80%, which also applies to any tranches assigned post auction; and a new distribution rider, Delivery Capital Recovery Rider (Rider DCR), to recover a return of, and on, capital investments in the delivery system. Rider DCR substitutes for Rider DSI which terminates under the current ESP. The Ohio Companies also agreed not to pay certain costs related to the companies’ integration into PJM, for the longer of the five year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain types of products totals $360 million dependent on the outcome of certain PJM proceedings, established a $12 million fund to assist low income customers over the term of the ESP, and agreed to additional energy efficiency benefits. Many of the existing riders approved in the previous ESP remain in effect, some with modifications. The new ESP resolved proceedings pending at the PUCO regarding corporate separation, elements of the smart grid proceeding and the integration into PJM. FirstEnergy recorded approximately $39.5 million of regulatory asset impairments and expenses related to the ESP. On September 24, 2010, an application for rehearing was filed by the OCC and two other parties. On February 9, 2011, the PUCO issued an Entry on Rehearing denying the applications for rehearing. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent to approximately 166,000 MWH in 2009, 290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in 2013, with additional savings required through 2025. Utilities are also required to reduce peak demand in 2009 by 1%, with an additional 0.75% reduction each year thereafter through 2018. </div>   </div>  <div style="font-family: Helvetica,Arial,sans-serif; margin-left: 0in; "> <div align="justify" style="font-size: 10pt; margin-top: 10pt">On December 15, 2009, the Ohio Companies filed the required three year portfolio plan seeking approval for the programs they intend to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers. The Ohio Companies’ three year portfolio plan is still awaiting decision from the PUCO, which is delaying the launch of the programs described in the plan. As a result, the Ohio Companies filed on January 11, 2011, a request for amendment of OE’s 2010 energy efficiency and peak demand reduction benchmarks to levels actually achieved in 2010. Because the Commission indicated that it would revise all of the Ohio Companies’ 2010, 2011, and 2012 benchmarks when addressing the Ohio Companies’ three year portfolio plan, and an order has yet to be issued on that plan, CEI and TE also requested a waiver of their respective yet-to-be defined 2010 energy efficiency benchmarks if and only to the degree one is deemed necessary to bring these companies into compliance with their 2010 energy efficiency obligations. Failure to comply with the benchmarks or to obtain such an amendment may subject the Companies to an assessment by the PUCO of a penalty. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">Additionally under SB221, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they served in 2009. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RFPs sought RECs, including solar RECs and RECs generated in Ohio in order to meet the Ohio Companies’ alternative energy requirements as set forth in SB221 for 2009, 2010 and 2011. The RECs acquired through these two RFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. On March 10, 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market. The PUCO reduced the Ohio Companies’ aggregate 2009 benchmark to the level of solar RECs the Ohio Companies acquired through their 2009 RFP processes, provided the Ohio Companies’ 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark, which application is still pending. In July 2010, the Ohio Companies initiated an additional RFP to secure RECs and solar RECs needed to meet the Ohio Companies’ alternative energy requirements as set forth in SB221 for 2010 and 2011. As a result of this RFP, contracts were executed in August 2010. On January 11, 2011, the Ohio Companies filed an application with the PUCO seeking an amendment to each of their 2010 alternative energy requirements for solar RECs generated in Ohio due to the insufficient quantity of solar energy resources reasonably available in the market. The PUCO has not yet ruled on that application. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">On February 12, 2010, OE and CEI filed an application with the PUCO to establish a new credit for all-electric customers. On March 3, 2010, the PUCO ordered that rates for the affected customers be set at a level that will provide bill impacts commensurate with charges in place on December 31, 2008 and authorized the Ohio Companies to defer incurred costs equivalent to the difference between what the affected customers would have paid under previously existing rates and what they pay with the new credit in place. Tariffs implementing this new credit went into effect on March 17, 2010. On April 15, 2010, the PUCO issued a Second Entry on Rehearing that expanded the group of customers to which the new credit would apply and authorized deferral for the associated additional amounts. The PUCO also stated that it expected that the new credit would remain in place through at least the 2011 winter season, and charged its staff to work with parties to seek a long term solution to the issue. Tariffs implementing this newly expanded credit went into effect on May 21, 2010, and the proceeding remains open. The hearing in the matter is set to commence on February 16, 2011. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt; margin-left: 4%"><b>(C) PENNSYLVANIA</b> </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">The PPUC adopted a Motion on January 28, 2010 and subsequently entered an Order on March 3, 2010 which denied the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, and directed Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructed Met-Ed and Penelec to work with the various intervening parties to file a recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses collected from ratepayers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. On March 18, 2010, Met-Ed and Penelec filed a Petition with the PPUC requesting that it stay the portion of the March 3, 2010 Order requiring the filing of tariff supplements to end collection of costs for marginal transmission losses. By Order entered March 25, 2010, the PPUC granted the requested stay until December 31, 2010. Pursuant to the PPUC’s order, Met-Ed and Penelec filed the plan to establish separate accounts for marginal transmission loss revenues and related interest and carrying charges and the plan for the use of these funds to mitigate future generation rate increases commencing January 1, 2011. The PPUC approved this plan on June 7, 2010. On April 1, 2010, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania appealing the PPUC’s March 3, 2010 Order. Although the ultimate outcome of this matter cannot be determined at this time, Met-Ed and Penelec believe that they should prevail in the appeal and therefore expect to fully recover the approximately $252.7 million ($188.0 million for Met-Ed and $64.7 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011. The argument before the Commonwealth Court, <i>en banc</i>, was held on December 8, 2010. </div>   </div>  <div style="font-family: Helvetica,Arial,sans-serif; margin-left: 0in; "> <div align="justify" style="font-size: 10pt; margin-top: 10pt">On May 20, 2010, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider for the period June 1, 2010 through December 31, 2010, including marginal transmission losses as approved by the PPUC, although the recovery of marginal losses will be subject to the outcome of the proceeding related to the 2008 TSC filing as described above. The TSC for Met-Ed’s customers was increased to provide for full recovery by December 31, 2010. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">Met-Ed and Penelec filed with the PPUC a generation procurement plan covering the period January 1, 2011 through May 31, 2013. The plan is designed to provide adequate and reliable service through a prudent mix of long-term, short-term and spot market generation supply with a staggered procurement schedule that varies by customer class, using a descending clock auction. On August 12, 2009, the parties to the proceeding filed a settlement agreement of all but two issues, and the PPUC entered an Order approving the settlement and the generation procurement plan on November 6, 2009. Generation procurement began in January 2010. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">On February 8, 2010, Penn filed a Petition for Approval of its Default Service Plan for the period June 1, 2011 through May 31, 2013. On July 29, 2010, the parties to the proceeding filed a Joint Petition for Settlement of all issues. Although the PPUC’s Order approving the Joint Petition held that the provisions relating to the recovery of MISO exit fees and one-time PJM integration costs (resulting from Penn’s June 1, 2011 exit from MISO and integration into PJM) were approved, it made such provisions subject to the approval of cost recovery by FERC. Therefore, Penn may not put these provisions into effect until FERC has approved the recovery and allocation of MISO exit fees and PJM integration costs. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">Met-Ed, Penelec and Penn jointly filed a SMIP with the PPUC on August 14, 2009. This plan proposed a 24-month assessment period in which the Pennsylvania Companies will assess their needs, select the necessary technology, secure vendors, train personnel, install and test support equipment, and establish a cost effective and strategic deployment schedule, which currently is expected to be completed in fifteen years. Met-Ed, Penelec and Penn estimate assessment period costs of approximately $29.5 million, which the Pennsylvania Companies, in their plan, proposed to recover through an automatic adjustment clause. The ALJ’s Initial Decision approved the SMIP as modified by the ALJ, including: ensuring that the smart meters to be deployed include the capabilities listed in the PPUC’s Implementation Order; denying the recovery of interest through the automatic adjustment clause; providing for the recovery of reasonable and prudent costs net of resulting savings from installation and use of smart meters; and requiring that administrative start-up costs be expensed and the costs incurred for research and development in the assessment period be capitalized. On April 15, 2010, the PPUC adopted a Motion by Chairman Cawley that modified the ALJ’s initial decision, and decided various issues regarding the SMIP for the Pennsylvania Companies. The PPUC entered its Order on June 9, 2010, consistent with the Chairman’s Motion. On June 24, 2010, Met-Ed, Penelec and Penn filed a Petition for Reconsideration of a single portion of the PPUC’s Order regarding the future ability to include smart meter costs in base rates. On August 5, 2010, the PPUC granted in part the petition for reconsideration by deleting language from its original order that would have precluded Met-Ed, Penelec and Penn from seeking to include smart meter costs in base rates at a later time. The costs to implement the SMIP could be material. However, assuming these costs satisfy a just and reasonable standard they are expected to be recovered in a rider (Smart Meter Technologies Charge Rider) which was approved when the PPUC approved the SMIP. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">By Tentative Order entered September 17, 2009, the PPUC provided for an additional 30-day comment period on whether the 1998 Restructuring Settlement, which addressed how Met-Ed and Penelec were going to implement direct access to a competitive market for the generation of electricity, allows Met-Ed and Penelec to apply over-collection of NUG costs for select and isolated months to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists. In response to the Tentative Order, various parties filed comments objecting to the above accounting method utilized by Met-Ed and Penelec. Met-Ed and Penelec are awaiting further action by the PPUC. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt; margin-left: 4%"><b>(D) NEW JERSEY</b> </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">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 December 31, 2010, the accumulated deferred cost balance was a credit of approximately $37 million. To better align the recovery of expected costs, on July 26, 2010, JCP&L filed a request to decrease the amount recovered for the costs incurred under the NUG agreements by $180 million annually. On February 10, 2011, the NJBPU approved a stipulation which allows the change in rates to become effective March 1, 2011. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">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 estimated at $736 million (in 2003 dollars). This matter is currently pending before the NJBPU. </div>   </div>  <div style="font-family: Helvetica,Arial,sans-serif; margin-left: 0in; "> <div align="justify" style="font-size: 10pt; margin-top: 10pt">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 NJBPU adopted an order establishing the general process and contents of specific EMP plans that must be filed by New Jersey electric and gas utilities in order to achieve the goals of the EMP. On April 16, 2010, the NJBPU issued an order indefinitely suspending the requirement of New Jersey utilities to submit Utility Master Plans until such time as the status of the EMP has been made clear. At this time, FirstEnergy and JCP&L cannot determine the impact, if any, the EMP may have on their operations. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt; margin-left: 4%"><b>(E) FERC MATTERS</b> </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt; margin-left: 8%"><i>Rates for Transmission Service Between MISO and PJM</i> </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">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 SECA) during a 16-month transition period. In 2005, the FERC set the SECA for hearing. The presiding ALJ 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 was subject to review and approval by the FERC. On May 21, 2010, FERC issued an order denying pending rehearing requests and an Order on Initial Decision which reversed the presiding ALJ’s rulings in many respects. Most notably, these orders affirmed the right of transmission owners to collect SECA charges with adjustments that modestly reduce the level of such charges, and changes to the entities deemed responsible for payment of the SECA charges. The Ohio Companies were identified as load serving entities responsible for payment of additional SECA charges for a portion of the SECA period (Green Mountain/Quest issue). FirstEnergy executed settlements with AEP, Dayton and the Exelon parties to fix FirstEnergy’s liability for SECA charges originally billed to Green Mountain and Quest for load that returned to regulated service during the SECA period. The AEP, Dayton and Exelon, settlements were approved by FERC on November 23, 2010, and the relevant payments made. Rehearings remain pending in this proceeding. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt; margin-left: 8%"><i>PJM Transmission Rate</i> </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">On April 19, 2007, FERC issued an order (Opinion 494) finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, 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 based on the amount of load served in a transmission zone. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a load flow methodology (DFAX), which is generally referred to as a “beneficiary pays” approach to allocating the cost of high voltage transmission facilities. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">The FERC’s Opinion 494 order was appealed to the U.S. Court of Appeals for the Seventh Circuit, which issued a decision on August 6, 2009. The court affirmed FERC’s ratemaking treatment for existing transmission facilities, but found that FERC had not supported its decision to allocate costs for new 500+ kV facilities on a load ratio share basis and, based on this finding, remanded the rate design issue back to FERC. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">In an order dated January 21, 2010, FERC set the matter for “paper hearings”— meaning that FERC called for parties to submit comments or written testimony pursuant to the schedule described in the order. FERC identified nine separate issues for comments and directed PJM to file the first round of comments on February 22, 2010, with other parties submitting responsive comments and then reply comments on later dates. PJM filed certain studies with FERC on April 13, 2010, in response to the FERC order. PJM’s filing demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain eastern utilities in PJM bearing the majority of their costs. Numerous parties filed responsive comments or studies on May 28, 2010 and reply comments on June 28, 2010. FirstEnergy and a number of other utilities, industrial customers and state commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Certain eastern utilities and their state commissions supported continued socialization of these costs on a load ratio share basis. FERC is expected to act by May 31, 2011. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt; margin-left: 8%"><i>RTO Realignment</i> </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">On December 17, 2009, FERC issued an order approving, subject to certain future compliance filings, ATSI’s withdrawal from MISO and integration into PJM. This move, which is expected to be effective on June 1, 2011, allows FirstEnergy to consolidate its transmission assets and operations into PJM. Currently, FirstEnergy’s transmission assets and operations are divided between PJM and MISO. The realignment will make the transmission assets that are part of ATSI, whose footprint includes the Ohio Companies and Penn, part of PJM. In the order, FERC approved FirstEnergy’s proposal to use a FRR Plan to obtain capacity to satisfy the PJM capacity requirements for the 2011-12 and 2012-13 delivery years. </div>   </div>  <div style="font-family: Helvetica,Arial,sans-serif; margin-left: 0in; "> <div align="justify" style="font-size: 10pt; margin-top: 10pt">FirstEnergy successfully conducted the FRR auctions on March 19, 2010. Moreover, the ATSI zone loads participated in the PJM base residual auction for the 2013 delivery year. Successful completion of these steps secured the capacity necessary for the ATSI footprint to meet PJM’s capacity requirements. On August 25, 2010, the PUCO issued an order in the 2010 ESP Case approving a settlement that, among other things, called for the PUCO to withdraw its opposition to the RTO consolidation. In addition, the order approved a wholesale procurement process, and certain “retail choice” policies, that reflected ATSI’s entry into PJM on June 1, 2011. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">On February 1, 2011, ATSI in conjunction with PJM filed its proposal with FERC for moving its transmission rate into PJM’s tariffs. FirstEnergy expects ATSI to enter PJM on June 1, 2011, and that if legal proceedings regarding its rate are outstanding at that time, ATSI will be permitted to start charging its proposed rates, subject to refund. Additional FERC proceedings are either pending or expected in which the amount of exit fees, transmission cost allocations, and costs associated with long term firm transmission rights payable by the ATSI zone upon its withdrawal from the Midwest ISO will be determined. In addition, certain parties may protest other aspects of ATSI’s integration into PJM, and certain of these matters remain outstanding and will be resolved in future FERC proceedings. The outcome of these proceedings cannot be predicted. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt; margin-left: 8%"><i>MISO Multi-Value Project Rule Proposal</i> </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">On July 15, 2010, MISO and certain MISO transmission owners jointly filed with FERC their proposed cost allocation methodology for certain new transmission projects. The new transmission projects—described as MVPs—are a class of MTEP projects. The filing parties proposed to allocate the costs of MVPs by means of a usage-based charge that will be applied to all loads within the MISO footprint, and to energy transactions that call for power to be “wheeled through” the MISO as well as to energy transactions that “source” in the MISO but “sink” outside of MISO. The filing parties expect that the MVP proposal will fund the costs of large transmission projects designed to bring wind generation from the upper Midwest to load centers in the east. The filing parties requested an effective date for the proposal of July 16, 2011. On August 19, 2010, MISO’s Board approved the first MVP project — the “Michigan Thumb Project.” Under MISO’s proposal, the costs of MVP projects approved by MISO’s Board prior to the anticipated June 1, 2011 effective date of FirstEnergy’s integration into PJM would continue to be allocated to FirstEnergy. MISO estimated that approximately $11 million in annual revenue requirements would be allocated to the ATSI zone associated with the Michigan Thumb Project upon its completion. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">On September 10, 2010, FirstEnergy filed a protest to the MVP proposal arguing that MISO’s proposal to allocate costs of MVP projects across the entire MISO footprint does not align with the established rule that cost allocation is to be based on cost causation (the “beneficiary pays” approach). FirstEnergy also argued that, in light of progress to date in the ATSI integration into PJM, it would be unjust and unreasonable to allocate any MVP costs to the ATSI zone, or to ATSI. Numerous other parties filed pleadings on MISO’s MVP proposal. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">On December 16, 2010, FERC issued an order approving the MVP proposal without significant change. FERC’s order was not clear, however, as to whether the MVP costs would be payable by ATSI or load in the ATSI zone. FERC stated that the MISO’s tariffs obligate ATSI to pay all charges that attach prior to ATSI’s exit but ruled that the question of the amount of costs that are to be allocated to ATSI or to load in the ATSI zone were beyond the scope of FERC’s order and would be addressed in future proceedings. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">On January 18, 2011, FirstEnergy filed for rehearing of FERC’s order. In its rehearing request, the Company argued that because the MVP rate is usage-based, costs could not be applied to ATSI, which is a stand-alone transmission company that does not use the transmission system. FirstEnergy also renewed its arguments regarding cost causation and the impropriety of allocating costs to the ATSI zone or to ATSI. FirstEnergy cannot predict the outcome of these proceedings at this time. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt; margin-left: 8%"><i>Sales to Affiliates</i> </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">FES has received authorization from FERC to make wholesale power sales to the Utilities. FES actively participates in auctions conducted by or on behalf of the Utilities to obtain the power and related services necessary to meet the Utilities’ POLR obligations. Because of the merger with FirstEnergy, AS is considered an affiliate of the Utilities for purposes of FERC’s affiliate restriction regulations. This requires AS to obtain prior FERC authorization to make sales to the Utilities when it successfully participates in the Utilities’ POLR auctions. </div>   </div>  <div style="font-family: Helvetica,Arial,sans-serif; margin-left: 0in; "> <div align="justify" style="font-size: 10pt; margin-top: 10pt">FES currently supplies the Ohio Companies with a portion of their capacity, energy, ancillary services and transmission under a Master SSO Supply Agreement for a two-year period ending May 31, 2011. FES won 51 tranches in a descending clock auction for POLR service administered by the Ohio Companies and their consultant, CRA International on May 13-14, 2009. Other winning suppliers have assigned their Master SSO Supply Agreements to FES, five of which were effective in June, two more in July, four more in August and ten more in September, 2009. FES also supplies power used by Constellation to serve an additional five tranches. As a result of these arrangements, FES serves 77 tranches, or 77% of the POLR load of the Ohio Companies until May 31, 2011. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">On October 20, 2010, FES participated in a descending clock auction for POLR service administered by the Ohio Companies and their consultant, CRA International, for the following periods: June 1, 2011 through May 31, 2012; June 1, 2011, through May 31, 2013; and June 1, 2010 through May 31, 2014. The Ohio Companies offered 17, 17, and 16 tranches for these periods, respectively. FES won 10, 7, and 3 tranches, respectively, for these periods. On January 25, 2011, the Ohio Companies conducted a second auction offering the same product for identical time periods. FES won 3, 0, and 3 tranches, respectively, for these periods. FES entered into a Master SSO Supply Agreement to provide capacity, energy, ancillary services, and congestion costs to the Ohio Companies for the tranches won. Under the ESP in effect for these time periods, the Ohio Companies are responsible for payment of noncontrollable transmission costs billed by PJM for POLR service. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">On October 18, 2010, FES participated in a descending clock auction for POLR service administered by both Met-Ed and Penelec and their consultant, National Economic Research Associates (NERA) for the following tranche products and delivery periods: Residential 5-month, Residential 24-month, Commercial 5-month, Commercial 12-month and Industrial 12-month. All 5-month delivery periods are from January 1, 2011 through May 31, 2011, all 12-month delivery periods are from June 1, 2011 through May 31, 2012 while all 24-month delivery periods are from June 1, 2011 through May 31, 2013. Met-Ed offered 7 Residential 5-month tranches, 4 Residential 24-month tranches, 6 Commercial 5-month tranches, 6 Commercial 12-month tranches and 1 Industrial tranche while Penelec offered 5 Residential 5-month tranches, 3 Residential 24-month tranches, 5 Commercial 5-month tranches, 5 Commercial 12-month tranches and 1 Industrial tranche. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">For Met-Ed offerings, FES won 4 Residential 5-month tranches, 2 Residential 24-month tranches, 1 Commercial 5-month tranche, 1 Commercial 12-month tranche and zero Industrial tranches. For Penelec offerings, FES won 1 Residential 5-month tranche, 1 Residential 24-month tranche, zero Commercial 5-month tranches, zero Commercial 12-month tranches and zero Industrial tranches. FES entered into separate Supplier Master Agreements (SMA) to provide capacity, energy, ancillary services, and congestion costs with Met-Ed and Penelec for each product won. Under the terms and conditions of the SMA, Met-Ed and Penelec are responsible for payment of noncontrollable transmission costs billed by PJM. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">On January 18 to 20, 2011 FES participated in a descending clock auction for POLR service administered by Met-Ed, Penelec, and Penn Power and their consultant, NERA for the following tranche products and delivery periods: Residential 12-month, Residential 24-month, Commercial 12-month and Industrial 12-month. All 12-month delivery periods are from June 1, 2011 through May 31, 2012 while all 24-month delivery periods are from June 1, 2011 through May 31, 2013. Met-Ed offered 3 Residential 12-month tranches, 4 Residential 24-month tranches, 6 Commercial 12-month tranches and 11 Industrial tranches. Penelec offered 3 Residential 12-month tranches, 2 Residential 24-month tranches, 5 Commercial 12-month tranches and 11 Industrial tranches. Penn Power offered 2 Residential 12-month tranches, 1 Residential 24-month tranche, 3 Commercial 12-month tranches and 3 Industrial tranches. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">For Met-Ed offerings, FES won 1 Commercial 12-month tranche and zero for the remaining products. For Penelec and Penn Power offerings, FES won no tranches. FES entered into a SMA to provide capacity, energy, ancillary services, and congestion costs with Met-Ed for the product won. Under the terms and conditions of the SMA, Met-Ed is responsible for payment of noncontrollable transmission costs billed by PJM. </div> </div>  <!-- Begin Block Tagged NotefalsefalsefalsefalsefalseOtherus-types:textBlockItemTypestringThis element can be used to encapsulate the entire disclosure for public utilities (including data and tables).Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 71 falsefalseREGULATORY MATTERS12Regulatory MattersUnKnownUnKnownUnKnownUnKnownfalsetrue