2.2.0.25falsefalse00210 - Disclosure - Regulatory Matterstruefalsefalse1falsefalseUSDfalsefalse1/1/2011 - 3/31/2011 USD ($) USD ($) / shares $Jan-01-2011_Mar-31-2011http://www.sec.gov/CIK0001031296duration2011-01-01T00:00:002011-03-31T00:00:00USDStandardhttp://www.xbrl.org/2003/iso4217USDiso42170USDEPSDividehttp://www.xbrl.org/2003/iso4217USDiso4217http://www.xbrl.org/2003/instancesharesxbrli0SharesStandardhttp://www.xbrl.org/2003/instancesharesxbrli0PureStandardhttp://www.xbrl.org/2003/instancepurexbrli0MWHStandardhttp://firstenergycorp.com/2011-03-31MWHfe0USDUSD$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 electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, FGCO, FENOC, and ATSI and TrAIL Company. 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 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. In March 2011, Reliability<i>First </i>submitted its proposed findings and settlement. At this time, FirstEnergy is evaluating Reliability<i>First</i>’s proposal and is unable to predict the final outcome of this investigation. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">Allegheny has been subject to routine audits with respect to its compliance with applicable reliability standards and has settled certain related issues. In addition, Reliability<i>First </i>is currently conducting certain violation investigations with regard to matters of compliance by Allegheny. </div>   </div>  <div style="font-family: Helvetica,Arial,sans-serif; margin-left: 0in; "> <div align="justify" style="font-size: 10pt; margin-top: 10pt; margin-left: 4%"><b>(B) MARYLAND</b> </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">In 1999, Maryland adopted electric industry restructuring legislation, which gave PE’s Maryland retail electric customers the right to choose their electricity generation suppliers. PE remained obligated to provide standard offer generation service (SOS) at capped rates to residential and non-residential customers for various periods. The longest such period, for residential customers, expired on December 31, 2008. PE implemented a rate stabilization plan in 2007 that was designed to transition customers from capped generation rates to rates based on market prices and that concluded on December 31, 2010. PE’s transmission and distribution rates for all customers are subject to traditional regulated utility ratemaking (i.e., cost-based rates). </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">By statute enacted in 2007, the obligation of Maryland utilities to provide SOS to residential and small commercial customers, in exchange for recovery of their costs plus a reasonable profit, was extended indefinitely. The legislation also established a five-year cycle (to begin in 2008) for the MDPSC to report to the legislature on the status of SOS. In August 2007, PE filed a plan for seeking bids to serve its Maryland residential load for the period after the expiration of rate caps. The MDPSC approved the plan and PE now conducts rolling auctions to procure the power supply necessary to serve its customer load. However, the terms on which PE will provide SOS to residential customers after the settlement beyond 2012 will depend on developments with respect to SOS in Maryland between now and then, including but not limited to possible MDPSC decisions in the proceedings discussed below. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">The MDPSC opened a new docket in August 2007 to consider matters relating to possible “managed portfolio” approaches to SOS and other matters. “Phase II” of the case addressed utility purchases or construction of generation, bidding for procurement of demand response resources and possible alternatives if the TrAIL and PATH projects were delayed or defeated. It is unclear when the MDPSC will issue its findings in this and other SOS-related pending proceedings discussed below. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">In September 2009, the MDPSC opened a new proceeding to receive and consider proposals for construction of new generation resources in Maryland. In December 2009, Governor Martin O’Malley filed a letter in this proceeding in which he characterized the electricity market in Maryland as a “failure” and urged the MDPSC to use its existing authority to order the construction of new generation in Maryland, vary the means used by utilities to procure generation and include more renewables in the generation mix. In August 2010, the MDPSC opened another new proceeding to solicit comments on the PJM RPM process. Public hearings on the comments were held in October 2010. In December 2010, the MDPSC issued an order soliciting comments on a model request for proposal for solicitation of long-term energy commitments by Maryland electric utilities. PE and numerous other parties filed comments, and at this time no further proceedings have been set by the MDPSC in this matter. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">In September 2007, the MDPSC issued an order that required the Maryland utilities to file detailed plans for how they will meet the “EmPOWER Maryland” proposal that, in Maryland, electric consumption be reduced by 10% and electricity demand be reduced by 15%, in each case by 2015. In October 2007, PE filed its initial report on energy efficiency, conservation and demand reduction plans in connection with this order. The MDPSC conducted hearings on PE’s and other utilities’ plans in November 2007 and May 2008. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">In a related development, the Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals. In 2008, PE filed its comprehensive plans for attempting to achieve those goals, asking the MDPSC to approve programs for residential, commercial, industrial, and governmental customers, as well as a customer education program, and a pilot deployment of Advanced Utility Infrastructure (AUI) that Allegheny had previously tested in West Virginia. The MDPSC ultimately approved the programs in August 2009 after certain modifications had been made as required by the MDPSC, and approved cost recovery for the programs in October 2009. Expenditures were estimated to be approximately $101 million and would be recovered over the following six years. The AUI pilot was placed on a separate track to be re-examined after further discussion with the Staff of the MDPSC and other stakeholders. Meanwhile, extensive meetings with the MDPSC Staff and other stakeholders to discuss details of PE’s plans for additional and improved programs for the period 2012-2014 began in April 2011. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">In March 2009, the Maryland PSC issued an order suspending until further notice the right of all electric and gas utilities in the state to terminate service to residential customers for non-payment of bills. The MDPSC subsequently issued an order making various rule changes relating to terminations, payment plans, and customer deposits that make it more difficult for Maryland utilities to collect deposits or to terminate service for non-payment. PE and several other utilities filed requests for reconsideration of various parts of the order, which were denied. The MDPSC is continuing to conduct hearings and collect data on payment plan and related issues and has adopted a set of proposed regulations that expand the summer and winter “severe weather” termination moratoria when temperatures are very high or very low, from one day, as provided by statute, to three days on each occurrence. </div>   </div>  <div style="font-family: Helvetica,Arial,sans-serif; margin-left: 0in; "> <div align="justify" style="font-size: 10pt; margin-top: 10pt">On March 24, 2011, the MDPSC held an initial hearing to discuss possible new regulations relating to service interruptions, storm response, call center metrics, and related reliability standards. The proposed rules included provisions for civil penalties for non-compliance. Numerous parties filed comments on the proposed rules and participated in the hearing, with many noting issues of cost and practicality relating to implementation. Concurrently, the Maryland legislature is considering a bill addressing the same topics. The final bill passed on April 11, 2011, requires the MDPSC to promulgate rules by July 1, 2012 that address service interruptions, downed wire response, customer communication, vegetation management, equipment inspection, and annual reporting. In crafting the regulations, the MDPSC is directed to consider cost-effectiveness, and may adopt different standards for different utilities based on such factors as system design and existing infrastructure, geography, and customer density. Beginning in July 2013, the MDPSC is to assess each utility’s compliance with the standards, and may assess penalties of up to $25,000 per day per violation. The MDPSC has ordered that a working group of utilities, regulators, and other interested stakeholders meet to address the topics of the proposed rules. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">In December 2009, PE filed an application with the MDPSC for authorization to construct the Maryland portions of the PATH Project to be owned by PATH Allegheny Maryland Transmission Company, LLC, which is owned by Potomac Edison and PATH-Allegheny. On February 28, 2011, PE withdrew its application. See “Transmission Expansion” in the Federal Regulation and Rate Matters section for further discussion of this matter. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt; margin-left: 4%"><b>(C) 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 NUG rates and market sales of NUG energy and capacity. As of March 31, 2011, the accumulated deferred cost balance was a credit of approximately $102 million. To better align the recovery of expected costs, in July 2010, JCP&L filed a request to decrease the amount recovered for the costs incurred under the NUG agreements by $180 million annually, which the NJBPU approved, allowing the change in rates to become effective March 1, 2011. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">In March 2009 and again in February 2010, JCP&L filed annual SBC Petitions with the NJBPU that included a requested zero 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). Both matters are currently pending before the NJBPU. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt; margin-left: 4%"><b>(D) 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). </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">In March 2010, the Ohio Companies filed an application for a new ESP, which the PUCO approved in August 2010, with certain modifications. The new ESP will go into effect on June 1, 2011 and conclude on May 31, 2014. The material terms of the new ESP include: a CBP similar to the one used in May 2009 and the one proposed on the October 2009 MRO filing (initial auctions held on October 20, 2010 and January 25, 2011); a load cap of no less than 80%, which also applies to tranches assigned post-auction; a 6% generation discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES; no increase in base distribution rates through May 31, 2014; and a new distribution rider, Delivery Capital Recovery Rider (Rider 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 recover from retail customers certain costs related to the companies’ integration into PJM for the longer of the five-year period from June 1, 2011 through May 31, 2015 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, agreed to establish a $12 million fund to assist low income customers over the term of the ESP and agreed to additional matters related to energy efficiency and alternative energy requirements. Many of the existing riders approved in the previous ESP remain in effect, with some modifications. The new ESP resolved proceedings pending at the PUCO regarding corporate separation, elements of the smart grid proceeding and expenses related to the ESP. </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">In December 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 PUCO issued an Opinion and Order generally approving the Ohio Companies’ 3-year plan, and the Companies are in the process of implementing those programs included in the Plan. Because of the delay in issuing the Order, the launch of the programs included in the plan for 2010 was delayed and will launch during the second quarter of this year. As a result, OE fell short of its statutory 2010 energy efficiency and peak demand reduction benchmarks. Therefore, on January 11, 2011, it requested that its 2010 energy efficiency and peak demand reduction benchmarks be amended to actual levels achieved in 2010. Moreover, because the PUCO indicated, when approving the 2009 benchmark request, that it would modify the Companies’ 2010 (and 2011 and 2012) energy efficiency benchmarks when addressing the portfolio plan, the Ohio Companies were not certain of their 2010 energy efficiency obligations. Therefore, CEI and TE (each of which achieved its 2010 energy efficiency and peak demand reduction statutory benchmarks) also requested an amendment if and only to the degree one was deemed necessary to bring these them into compliance with their yet-to-be-defined modified benchmarks. 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. In addition to approving the programs included in the plan, with only minor modifications, the PUCO authorized the Companies to recover all costs related to the original CFL program that the Ohio Companies had previously suspended at the request of the PUCO. Applications for Rehearing were filed on April 22, 2011, regarding portions of the PUCO’s decision, including the method for calculating savings and certain changes made by the PUCO to specific programs. </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. In March 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. On February 23, 2011, the PUCO granted FES’ force majeure request for 2009 and increased its 2010 benchmark by the amount of SRECs that FES was short of in its 2009 benchmark. 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 and executed related contracts in August 2010. On April 15, 2011, the Ohio Companies filed an application seeking an amendment to each of their 2010 alternative energy requirements for solar RECs generated in Ohio on the basis that an insufficient quantity of solar resources are available in the market but reflecting solar RECs that they have obtained and providing additional information regarding efforts to secure solar RECs. The PUCO has not yet acted on that application. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">In February 2010, OE and CEI filed an application with the PUCO to establish a new credit for all-electric customers. In March 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 in March 2010. In April 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 in May 2010 and the proceeding remains open. The hearing on the matter was held in February 2011. The matter has now been briefed and the Ohio Companies await the PUCO’s decision. </div>   </div>  <div style="font-family: Helvetica,Arial,sans-serif; margin-left: 0in; "> <div align="justify" style="font-size: 10pt; margin-top: 10pt; margin-left: 4%"><b>(E) PENNSYLVANIA</b> </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">The PPUC entered an Order on March 3, 2010 that denied the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, 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. In March 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. The PPUC granted the requested stay until December 31, 2010. Pursuant to the PPUC’s order, Met-Ed and Penelec filed plans to establish separate accounts for marginal transmission loss revenues and related interest and carrying charges and for the use of these funds to mitigate future generation rate increases which the PPUC approved. In April 2010, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania appealing the PPUC’s March 3, 2010 Order. The argument before the Commonwealth Court, en banc, was held in December 2010. 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. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">In May 2008, May 2009 and May 2010, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider for the annual periods between June 1, 2008 to 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 PPUC’s approval in May 2010 authorized an increase to the TSC for Met-Ed’s customers 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. In August 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 in November 2009. Generation procurement began in January 2010. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">In February 2010, Penn filed a Petition for Approval of its Default Service Plan for the period June 1, 2011 through May 31, 2013. In July 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">Pennsylvania adopted Act 129 in 2008 to address issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters; and alternative energy. Among other things, Act 129 required utilities to file with the PPUC an energy efficiency and peak load reduction plan, or EE&C Plan, by July 1, 2009, setting forth the utilities’ plans to reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of 4.5% by May 31, 2013. Act 129 also required utilities to file with the PPUC a Smart Meter Implementation Plan (SMIP). </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">The PPUC entered an Order in February 2010 giving final approval to all aspects of the EE&C Plans of Met-Ed, Penelec and Penn and the tariff rider with rates effective March 1, 2010. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">WP filed its original EE&C Plan in June 2009, which the PPUC approved, in large part, by Opinion and Order entered in October 2009. In November 2009, the Office of Consumer Advocate (OCA) filed an appeal with the Commonwealth Court of the PPUC’s October Order. The OCA contends that the PPUC’s Order failed to include WP’s costs for smart meter implementation in the EE&C Plan, and that inclusion of such costs would cause the EE&C Plan to exceed the statutory cap for EE&C expenditures. The OCA also contends that WP’s EE&C plan does not meet the Total Resource Cost Test. The appeal remains pending but has been stayed by the Commonwealth Court pending possible settlement of WP’s SMIP. In September, 2010, WP filed an amended EE&C Plan that is less reliant on smart meter deployment, which the PPUC approved in January 2011. </div>   </div>  <div style="font-family: Helvetica,Arial,sans-serif; margin-left: 0in; "> <div align="justify" style="font-size: 10pt; margin-top: 10pt">Met-Ed, Penelec and Penn jointly filed a SMIP with the PPUC in August 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. In April 2010, the PPUC adopted a Motion by Chairman Cawley that modified the ALJ’s initial decision, and decided various issues regarding the SMIP for Met-Ed, Penelec and Penn. The PPUC entered its Order in June 2010, consistent with the Chairman’s Motion. 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, which the PPUC granted in part 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">In August 2009, WP filed its original SMIP, which provided for extensive deployment of smart meter infrastructure with replacement of all of WP’s approximately 725,000 meters by the end of 2014. In December 2009, WP filed a motion to reopen the evidentiary record to submit an alternative smart meter plan proposing, among other things, a less-rapid deployment of smart meters. In an Initial Decision dated April 29, 2010, an ALJ determined that WP’s alternative smart meter deployment plan, which contemplated deployment of 375,000 smart meters by May 2012, complied with the requirements of Act 129 and recommended approval of the alternative plan, including WP’s proposed cost recovery mechanism. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">In light of the significant expenditures that would be associated with its smart meter deployment plans and related infrastructure upgrades, as well as its evaluation of recent PPUC decisions approving less-rapid deployment proposals by other utilities, WP re-evaluated its Act 129 compliance strategy, including both its plans with respect to smart meter deployment and certain smart meter dependent aspects of the EE&C Plan. In October 2010, WP and Pennsylvania’s Office of Consumer Advocate filed a Joint Petition for Settlement addressing WP’s smart meter implementation plan with the PPUC. Under the terms of the proposed settlement, WP proposed to decelerate its previously contemplated smart meter deployment schedule and to target the installation of approximately 25,000 smart meters in support of its EE&C Plan, based on customer requests, by mid-2012. The proposed settlement also contemplates that WP take advantage of the 30-month grace period authorized by the PPUC to continue WP’s efforts to re-evaluate full-scale smart meter deployment plans. WP currently anticipates filing its plan for full-scale deployment of smart meters in June 2012. Under the terms of the proposed settlement, WP would be permitted to recover certain previously incurred and anticipated smart-meter related expenditures through a levelized customer surcharge, with certain expenditures amortized over a ten-year period. Additionally, WP would be permitted to seek recovery of certain other costs as part of its revised SMIP that it currently intends to file in June 2012, or in a future base distribution rate case. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">In December 2010, the PPUC directed that the SMIP proceeding be referred to the ALJ for further proceedings to ensure that the impact of the proposed merger with FirstEnergy is considered and that the Joint Petition for Settlement has adequate support in the record. On March 9, 2011, WP submitted an Amended Joint Petition for Settlement which restates the Joint Petition for Settlement filed in October 2010, adds the PPUC’s Office of Trial Staff as a signatory party, and confirms the support or non-opposition of all parties to the settlement. The proposed settlement also obligates OCA to withdraw its November 2009 appeal of the PPUC’s Order in WP’s EE&C plan proceeding. A Joint Stipulation with the OSBA was also filed on March 9, 2011. The proposed settlement remains subject to review by the ALJ, who will prepare an Initial Decision for consideration by the PPUC. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">By Tentative Order entered in September 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">In the PPUC Order approving the FirstEnergy and Allegheny merger, the PPUC announced that a separate statewide investigation into Pennsylvania’s retail electricity market will be conducted with the goal of making recommendations for improvements to ensure that a properly functioning and workable competitive retail electricity market exists in the state. The PPUC has not yet initiated that investigation. </div>   </div>  <div style="font-family: Helvetica,Arial,sans-serif; margin-left: 0in; "> <div align="justify" style="font-size: 10pt; margin-top: 10pt; margin-left: 4%"><b>(F) VIRGINIA</b> </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">In September 2010, PATH-VA filed an application with the Virginia SCC for authorization to construct the Virginia portions of the PATH Project. On February 28, 2011, PATH-VA filed a motion to withdraw the application. See “Transmission Expansion” in the Federal Regulation and Rate Matters section for further discussion of this matter. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt; margin-left: 4%"><b>(G) WEST VIRGINIA</b> </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">In August 2009, MP and PE filed with the WVPSC a request to increase retail rates by approximately $122.1 million annually, effective June 10, 2010. In January 2010, MP and PE filed supplemental testimony discussing a tax treatment change that would result in a revenue requirement approximately $7.7 million lower than the requirement included in the original filing. In addition, in December 2009, subsidiaries of MP and PE completed a securitization transaction to finance certain costs associated with the installation of scrubbers at the Fort Martin generating station, which costs would otherwise have been included in the request for rate recovery. Consequently, MP and PE ultimately requested an annual increase in retail rates of approximately $95 million, rather than $122.1 million. In April 2010, MP and PE filed with the WVPSC a Joint Stipulation and Agreement of Settlement reached with the other parties in the proceeding that provided for: </div> <div style="margin-top: 10pt"> <table width="100%" border="0" cellpadding="0" cellspacing="0" style="font-size: 10pt; text-align: left"> <tr valign="top" style="font-size: 10pt; color: #000000; background: transparent"> <td width="4%" style="background: transparent"> </td> <td width="3%" nowrap="nowrap" align="left"><b>•</b></td> <td width="1%"> </td> <td> <div style="text-align: justify">a $40 million annualized base rate increase effective June 29, 2010; </div></td> </tr> </table> </div> <div style="margin-top: 10pt"> <table width="100%" border="0" cellpadding="0" cellspacing="0" style="font-size: 10pt; text-align: left"> <tr valign="top" style="font-size: 10pt; color: #000000; background: transparent"> <td width="4%" style="background: transparent"> </td> <td width="3%" nowrap="nowrap" align="left"><b>•</b></td> <td width="1%"> </td> <td> <div style="text-align: justify">a deferral of February 2010 storm restoration expenses in West Virginia over a maximum five-year period; </div></td> </tr> </table> </div> <div style="margin-top: 10pt"> <table width="100%" border="0" cellpadding="0" cellspacing="0" style="font-size: 10pt; text-align: left"> <tr valign="top" style="font-size: 10pt; color: #000000; background: transparent"> <td width="4%" style="background: transparent"> </td> <td width="3%" nowrap="nowrap" align="left"><b>•</b></td> <td width="1%"> </td> <td> <div style="text-align: justify">an additional $20 million annualized base rate increase effective in January 2011; </div></td> </tr> </table> </div> <div style="margin-top: 10pt"> <table width="100%" border="0" cellpadding="0" cellspacing="0" style="font-size: 10pt; text-align: left"> <tr valign="top" style="font-size: 10pt; color: #000000; background: transparent"> <td width="4%" style="background: transparent"> </td> <td width="3%" nowrap="nowrap" align="left"><b>•</b></td> <td width="1%"> </td> <td> <div style="text-align: justify">a decrease of $20 million in ENEC rates effective January 2011, which amount is deferred for later recovery in 2012; and </div></td> </tr> </table> </div> <div style="margin-top: 10pt"> <table width="100%" border="0" cellpadding="0" cellspacing="0" style="font-size: 10pt; text-align: left"> <tr valign="top" style="font-size: 10pt; color: #000000; background: transparent"> <td width="4%" style="background: transparent"> </td> <td width="3%" nowrap="nowrap" align="left"><b>•</b></td> <td width="1%"> </td> <td> <div style="text-align: justify">a moratorium on filing for further increases in base rates before December 1, 2011, except under specified circumstances. </div></td> </tr> </table> </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">The WVPSC approved the Joint Petition and Agreement of Settlement in June 2010. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">In 2009, the West Virginia Legislature enacted the Alternative and Renewable Energy Portfolio Act (Portfolio Act), which generally requires that a specified minimum percentage of electricity sold to retail customers in West Virginia by electric utilities each year be derived from alternative and renewable energy resources according to a predetermined schedule of increasing percentage targets, including ten percent by 2015, fifteen percent by 2020, and twenty-five percent by 2025. In November 2010, the WVPSC issued Rules Governing Alternative and Renewable Energy Portfolio Standard (RPS Rules), which became effective on January 4, 2011. Under the RPS Rules, on or before January 1, 2011, each electric utility subject to the provisions of this rule was required to prepare an alternative and renewable energy portfolio standard compliance plan and file an application with the WVPSC seeking approval of such plan. MP and PE filed their combined compliance plan in December 2010. Additionally, in January 2011, MP and PE filed an application with the WVPSC seeking to certify three  facilities as Qualified Energy Resource Facilities. If the application is approved, the three facilities would then be capable of generating renewable credits which would assist the companies in meeting their combined requirements under the Portfolio Act. Further, in February 2011, MP and PE filed a petition with the WVPSC seeking an Order declaring that MP is entitled to all alternative & renewable energy resource credits associated with the electric energy, or energy and capacity, that MP is required to purchase pursuant to electric energy purchase agreements between MP and three non-utility electric generating facilities in WV. The City of New Martinsville, the owner of one of the contracted resources, has filed an opposition to the Petition. </div>   </div>  <div style="font-family: Helvetica,Arial,sans-serif; margin-left: 0in; "> <div align="justify" style="font-size: 10pt; margin-top: 10pt; margin-left: 4%"><b>(H) 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">In November 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 in August 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. In May 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 the FERC in November 2010, and the relevant payments made. The Utilities have refund obligations that are under review by FERC as part of a compliance filing. Potential refund obligations of FirstEnergy are not expected to be material. 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">In April 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 in August 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 the 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. This matter is awaiting action by the FERC. </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 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. On April 1, 2011, the MISO Transmission Owners (including ATSI) filed proposed tariff language that describes the mechanics of collecting and administering MTEP costs from ATSI-zone ratepayers. From March 20, 2011 through April 1, 2011, FirstEnergy, PJM and the MISO submitted numerous filings for the purpose of effecting movement of the ATSI zone to PJM on June 1, 2011. These filings include clean-up of the MISO’s tariffs (to remove the ATSI zone), submission of load and generation interconnection agreements to reflect the move into PJM, and submission of changes to PJM’s tariffs to support the move into PJM. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">FERC proceedings are pending in which ATSI’s transmission rate, the exit fee payable to MISO, transmission cost allocations and costs associated with long term firm transmission rights payable by the ATSI zone upon its departure from the MISO are under review. The outcome of these proceedings cannot be predicted. </div>   </div>  <div style="font-family: Helvetica,Arial,sans-serif; margin-left: 0in; "> <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">In July 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 $15 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">In September 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">In December 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, FirstEnergy 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>PJM Calculation Error</i> </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">In March 2010, MISO filed two complaints at FERC against PJM relating to a previously-reported modeling error in PJM’s system that impacted the manner in which market-to-market power flow calculations were made between PJM and MISO since April 2005. MISO claimed that this error resulted in PJM underpaying MISO by approximately $130 million over the time period in question. Additionally, MISO alleged that PJM did not properly trigger market-to-market settlements between PJM and MISO during times when it was required to do so, which MISO claimed may have cost it $5 million or more. As PJM market participants, AE Supply and MP may be liable for a portion of any refunds ordered in this case. PJM, Allegheny and other PJM market participants filed responses to MISO complaints and PJM filed a related complaint at FERC against MISO claiming that MISO improperly called for market-to-market settlements several times during the same time period covered by the two MISO complaints filed against PJM, which PJM claimed may have cost PJM market participants $25 million or more. On January 4, 2011, an Offer of Settlement was filed at FERC that, if approved, would resolve all pending issues in the dispute. The Offer of Settlement calls for the withdrawal of all pending complaints with no payments being made by any parties. Initial comments on the Offer of Settlement were filed at FERC on January 24, 2011. FirstEnergy and Allegheny Energy filed comments supporting the proposed settlement. A report on the partially contested settlement was issued by the settlement judge to the FERC on March 9, 2011. On March 16, 2011, the settlement judge terminated the settlement proceedings and forwarded the partially contested settlement to the FERC for review. The case is awaiting a decision by the FERC. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt; margin-left: 8%"><i>California Claims Matters</i> </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the California Department of Water Resources (CDWR) during 2001. The settlement proposal claims that CDWR is owed approximately $190 million for these alleged overcharges. This proposal was made in the context of mediation efforts by the FERC and the United States Court of Appeals for the Ninth Circuit in pending proceedings to resolve all outstanding refund and other claims, including claims of alleged price manipulation in the California energy markets during 2000 and 2001. The Ninth Circuit has since remanded one of those proceedings to the FERC, which arises out of claims previously filed with the FERC by the California Attorney General on behalf of certain California parties against various sellers in the California wholesale power market, including AE Supply (the Lockyer case). AE Supply and several other sellers have filed motions to dismiss the Lockyer case. In March 2010, the judge assigned to the case entered an opinion that granted the motions to dismiss filed by AE Supply and other sellers and dismissed the claims of the California Parties. In April 2010, the California parties filed exceptions to the judge’s ruling with the FERC, and briefing is complete on those exceptions. The parties are awaiting a ruling from the FERC on the exceptions. </div>   </div>  <div style="font-family: Helvetica,Arial,sans-serif; margin-left: 0in; "> <div align="justify" style="font-size: 10pt; margin-top: 10pt">In June 2009, the California Attorney General, on behalf of certain California parties, filed a second lawsuit with the FERC against various sellers, including AE Supply (the Brown case), again seeking refunds for trades in the California energy markets during 2000 and 2001. The above-noted trades with CDWR are the basis for the joining of AE Supply in this new lawsuit. AE Supply has filed a motion to dismiss the Brown case that is pending before the FERC. No scheduling order has been entered in the Brown case. Allegheny intends to vigorously defend against these claims but cannot predict their outcome. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt; margin-left: 8%"><i>Transmission Expansion</i> </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt"><b>TrAIL Project. </b>TrAIL is a 500kV transmission line currently under construction that will extend from southwest Pennsylvania through West Virginia and into northern Virginia. On April 15, 2011, the TrAIL 500 kV line segment from Meadowbrook substation to Loudoun substation in Virginia was successfully energized and is carrying load. The other segments are planned to be energized in May. The entire TrAIL line is scheduled to be completed and placed in service no later than June 2011. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt"><b>PATH Project. </b>The PATH Project is comprised of a 765 kV transmission line that is proposed to extend from West Virginia through Virginia and into Maryland, modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">PJM initially authorized construction of the PATH Project in June 2007 and, on June 17, 2010, requested that PATH, LLC proceed with all efforts related to the PATH Project, including state regulatory proceedings, assuming a required in-service date of June 1, 2015. In December 2010, PJM advised that its 2011 Load Forecast Report included load projections that are different from previous forecasts and that may have an impact on the proposed in-service date for the PATH Project. As part of its 2011 RTEP, and in response to a January 19, 2011 directive by a Virginia Hearing Examiner, PJM conducted a series of analyses using the most current economic forecasts and demand response commitments, as well as potential new generation resources. Preliminary analysis revealed the expected reliability violations that necessitated the PATH Project had moved several years into the future. Based on those results, PJM announced on February 28, 2011 that its Board of Managers had decided to hold the PATH Project in abeyance in its 2011 RTEP and directed FirstEnergy and AEP, as the sponsoring transmission owners, to suspend current development efforts on the project, subject to those activities necessary to maintain the project in its current state, while PJM conducts more rigorous analysis of the potential need for the project as part of its continuing RTEP process. PJM stated that its action did not constitute a directive to FirstEnergy and AEP to cancel or abandon the PATH Project. PJM further stated that it will complete a more rigorous analysis of the PATH Project and other transmission requirements and its Board will review this comprehensive analysis as part of its consideration of the 2011 RTEP. On February 28, 2011, affiliates of FirstEnergy and AEP filed motions or notices to withdraw applications for authorization to construct the project that were pending before state commissions in West Virginia, Virginia and Maryland. Withdrawal was deemed effective upon filing the notice with the MDPSC and the WVPSC has granted the motion to withdraw. The VSCC has not ruled on the motion to withdraw. </div> <div align="justify" style="font-size: 10pt; margin-top: 10pt">PATH, LLC submitted a filing to FERC to implement a formula rate tariff effective March 1, 2008. In a November 19, 2010 order addressing various matters relating to the formula rate, FERC set the project’s base return on equity for hearing and reaffirmed its prior authorization of a return on CWIP, recovery of start-up costs and recovery of abandonment costs. In the order, FERC also granted a 1.5% return on equity incentive adder and a 0.50% return on equity adder for RTO participation. These adders will be applied to the base return on equity determined as a result of the hearing. PATH, LLC is currently engaged in settlement discussions with the staff of FERC and intervenors regarding resolution of the base return on equity. FirstEnergy cannot predict the outcome of this proceeding or whether it will have a material impact on its operating results. </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 the FERC to make wholesale power sales to affiliated regulated utilities in New Jersey, Ohio, and Pennsylvania. FES actively participates in auctions conducted by or on behalf the regulated affiliates to obtain power necessary to meet the utilities’ POLR obligations. AE Supply, a merchant affiliate acquired in the FirstEnergy-Allegheny merger, also participates in these auctions, and obtains prior FERC authorization when necessary to make sales to FE affiliates.<br /> </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