(7) REGULATORY MATTERS

Rate Proceedings

Over the last several years, PHI’s utility subsidiaries have proposed in each of their respective jurisdictions the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. To date:

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A bill stabilization adjustment (BSA) was approved and implemented for Pepco and DPL electric service in Maryland and for Pepco electric service in the District of Columbia. The Maryland Public Service Commission (MPSC) later modified the BSA in Maryland so that revenues lost as a result of major storm outages are not collected through the BSA if electric service is not restored to the pre-major storm levels within 24 hours of the start of a major storm. For further information on the BSA in Maryland, see “Maryland – BSA Proceeding” below.

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A modified fixed variable rate design (MFVRD) has been approved in concept for DPL electric and natural gas service in Delaware, but the implementation has been deferred by the DPSC pending the development of an implementation plan and a customer education plan, as well as the resolution of various matters relating to development of a statewide energy efficiency plan and attendant legislation.

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In New Jersey, a BSA proposed by ACE in 2009 was not approved and there is no BSA proposal currently pending.

Under the BSA, customer distribution rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the applicable public service commission. The MFVRD approved in concept in Delaware provides for a fixed customer charge (i.e., not tied to the customer’s volumetric consumption) to recover the utility’s fixed costs, plus a reasonable rate of return. Although different from the BSA, PHI views the MFVRD as an appropriate distribution revenue decoupling mechanism.

In an effort to reduce the shortfall in revenues due to the delay in time or lag between when costs are incurred and when they are reflected in rates (regulatory lag), Pepco and DPL proposed, in each of their respective jurisdictions, (i) a reliability investment recovery mechanism (RIM) to recover reliability-related capital expenditures incurred between base rate cases, and (ii) the use of fully forecasted test years in future rate cases (which are comprised of forward-looking costs in lieu of historical test years, and if approved, would be more reflective of current costs and would mitigate the effects of regulatory lag). The status of these proposals is discussed below in connection with the discussions of Pepco’s and DPL’s respective electric distribution base rate proceedings.

Delaware

Gas Cost Rates

DPL makes an annual Gas Cost Rate (GCR) filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. In August 2011, DPL made its 2011 GCR filing. The filing includes the second year of the effect of a two-year amortization of under-recovered gas costs proposed by DPL in its 2010 GCR filing (the settlement approved by the DPSC in its 2010 GCR case included only the first year of the proposed two-year amortization). The rates proposed in the 2011 GCR would result in a GCR decrease of approximately 5.6%. On August 21, 2012, the DPSC issued a final order approving the rates as filed.

In August 2012, DPL made its 2012 GCR filing. The rates proposed in the 2012 GCR would result in a GCR decrease of approximately 22.3%. On September 18, 2012, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2012, subject to refund and pending final DPSC approval.

Electric Distribution Base Rates

On December 2, 2011, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $31.8 million, based on a requested return on equity (ROE) of 10.75%, and requested approval of implementation of the MFVRD. The filing included a request for DPSC approval of a RIM and the use of fully forecasted test years in future DPL rate cases. On January 10, 2012, the DPSC entered an order suspending the full increase and allowing a temporary rate increase of $2.5 million to go into effect on January 31, 2012, subject to refund and pending final DPSC approval. On July 3, 2012, in accordance with an agreement with DPSC staff, DPL placed an additional $22.3 million of the requested rate increase into effect, also subject to refund and pending final DPSC order. On August 17, 2012, DPL and the other parties to the proceeding entered into a proposed settlement that provides for an annual rate increase of $22 million, based on an ROE of 9.75%. The settlement agreement also permits DPL to collect from its standard offer service (SOS) customers (retail customers who do not elect to purchase electricity from a competitive supplier but instead purchase such electricity from DPL at regulated rates) approximately $3.4 million related to various state and local taxes that were assessed upon DPL’s SOS customers, but actually paid by DPL rather than by the SOS customers upon whom they were assessed. These taxes would be collected over a three-year period. In addition, the settlement agreement allows for the phase-in of the recovery of costs associated with DPL’s advanced metering infrastructure (AMI) project. The settlement agreement does not include approval of a RIM or the use of fully forecasted test years in future DPL rate cases, but it does provide that the parties will meet and discuss alternate regulatory methodologies for the mitigation of regulatory lag. The settlement agreement is subject to approval by the DPSC. Once approved by the DPSC, DPL will refund the billed amounts that exceeded the increase approved by the DPSC. DPL expects the DPSC to issue a decision on the settlement agreement in the fourth quarter of 2012.

District of Columbia

On July 8, 2011, Pepco filed an application with the District of Columbia Public Service Commission (DCPSC) to increase its electric distribution base rates by approximately $42 million annually, based on a requested ROE of 10.75%, of which approximately $9 million was sought so that Pepco could recover its costs associated with the AMI project. The filing included a request for DCPSC approval of a RIM and the use of fully forecasted test years in future Pepco rate cases. On September 26, 2012, the DCPSC issued its decision approving a rate increase of $24 million, based on an ROE of 9.5%, of which approximately $9 million allows Pepco to recover costs associated with the AMI project. The DCPSC denied Pepco’s request for approval of a RIM, and reserved final judgment on the appropriateness of the use by Pepco of a fully forecasted test year in future rate cases. In addition, the DCPSC approved an adjustment by Pepco to normalize operation and maintenance expenses associated with storm restoration efforts to its three-year average, but added approximately $2 million of costs associated with Hurricane Irene from August 2011 in the calculation of the three-year average storm costs. On October 31, 2012, the District of Columbia Office of the People’s Counsel filed a motion with the DCPSC for reconsideration of a portion of the order, objecting to (i) the percentage of the rate increase allocated to residential customers, and (ii) the decision not to adjust Pepco’s base rates downward because of the quality and reliability of Pepco’s electric distribution service. Pepco also filed a motion for reconsideration and clarification on that date (i) objecting to provisions requiring Pepco to perform studies and report certain information three months in advance of its next base rate case filing, and (ii) requesting clarification concerning the timing of certain reporting requirements. The filing of these motions does not stay the order or delay the rate increase from going into effect.

Maryland

DPL Electric Distribution Base Rates

On December 9, 2011, DPL submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $25.2 million (subsequently reduced by DPL to $23.5 million), based on a requested ROE of 10.75%. The filing included a request for MPSC approval of a RIM and the use of fully forecasted test years in future DPL rate cases. On July 20, 2012, the MPSC issued an order approving an annual rate increase of approximately $11.3 million, based on an ROE of 9.81%. The MPSC reduced DPL’s depreciation rates, which is expected to lower annual depreciation and amortization expenses by an estimated $4.1 million. The order did not approve DPL’s request to implement a RIM and did not endorse the use by DPL of fully forecasted test years in future rate cases. The order also authorizes DPL to recover in rates over a five-year period $4.3 million of the $4.6 million of incremental storm restoration costs associated with Hurricane Irene that had been deferred previously as a regulatory asset by DPL. The new revenue rates and lower depreciation rates were effective on July 20, 2012. DPL has determined not to appeal the MPSC order.

Pepco Electric Distribution Base Rates

On December 16, 2011, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $68.4 million (subsequently reduced by Pepco to $66.2 million), based on a requested ROE of 10.75%. The filing included a request for MPSC approval of a RIM and the use of fully forecasted test years in future Pepco rate cases. On July 20, 2012, the MPSC issued an order approving an annual rate increase of approximately $18.1 million, based on an ROE of 9.31%. The MPSC also directed Pepco to reduce the amount of the rate increase by approximately $1.6 million, the annual costs of certain energy advisory programs, resulting in a final rate increase of approximately $16.5 million. Pepco would be required to seek recovery of these annual costs through the EmPower Maryland Program. The MPSC reduced Pepco’s depreciation rates, which is expected to lower annual depreciation and amortization expenses by an estimated $27.3 million. The order did not approve Pepco’s request to implement a RIM and did not endorse the use by Pepco of fully forecasted test years in future rate cases. The order authorizes Pepco to recover in rates over a five-year period $18.5 million of incremental storm restoration costs associated with major weather events in 2011, including $9.7 million of the $9.9 million of incremental storm restoration costs associated with Hurricane Irene that had been deferred previously as a regulatory asset by Pepco and $8.8 million of incremental storm restoration costs incurred by Pepco associated with a severe winter storm in the first quarter of 2011 that had been expensed previously through other operation and maintenance expense in 2011. The incremental storm restoration costs of $8.8 million were reversed and deferred as a regulatory asset in the third quarter of 2012. The order also authorizes Pepco to recover the actual cost of AMI meters installed during the test year and states that cost recovery for AMI deployment will only be allowed in future rate cases in which Pepco demonstrates that the system is proven to be cost effective. The new revenue rates and lower depreciation rates were effective on July 20, 2012. Pepco has determined not to appeal the MPSC order. The Maryland Office of People’s Counsel has sought rehearing on the portion of the order allowing Pepco to recover the costs of installed AMI meters; that motion remains pending.

BSA Proceeding

As in effect for electric utilities in Maryland prior to October 26, 2012, including Pepco and DPL, a utility was not permitted to collect through the BSA distribution revenues lost as a result of major storm outages, beginning 24 hours after the commencement of a major storm, if electric service is not restored to the pre-major storm levels within 24 hours of the start of the storm. On October 26, 2012, the MPSC issued an order that no longer permits certain Maryland utilities, including Pepco and DPL, to collect a BSA surcharge for revenues lost during the first 24 hours of a major storm.

New Jersey

Electric Distribution Base Rates

On August 5, 2011, ACE filed a petition with the NJBPU to increase its electric distribution rates by the net amount of approximately $54.6 million (which was increased to approximately $74.3 million on February 24, 2012, to reflect the 2011 test year), based on a requested ROE of 10.75%. The modified net increase consists of a rate increase proposal of approximately $90.3 million, less a deduction from base rates of approximately $16 million through a credit rider expected to expire August 31, 2013, which is designed to refund to customers certain excess depreciation reserve funds as previously directed by the NJBPU (the Excess Depreciation Rider). ACE also proposed an increase of approximately $6.3 million in sales-and-use taxes related to the increase in base rates. On October 23, 2012, the NJBPU approved a stipulation of settlement signed by the parties (the New Jersey Settlement), which provides for an annual increase in ACE’s electric distribution base rates by the net amount of approximately $28 million, based on an ROE that, as part of the overall settlement, is deemed to be 9.75%. The net increase consists of a rate increase of approximately $44 million, less a deduction from base rates of approximately $16 million through the Excess Depreciation Rider. Upon expiration of the Excess Depreciation Rider, ACE will not realize an increase in operating income because the resulting increase in revenues will be offset by a substantially similar increase in depreciation expense. The New Jersey Settlement also provides for an increase of approximately $2 million in sales-and-use taxes related to the increase in base rates, and allows ACE to fully amortize over a three-year period the approximately $7.7 million in costs incurred as a result of Hurricane Irene in August 2011. The new rates will become effective for utility services rendered on and after November 1, 2012.

Infrastructure Investment Program

In July 2009, the NJBPU approved certain rate recovery mechanisms in connection with ACE’s Infrastructure Investment Program (the IIP). In exchange for the increase in infrastructure investment, the NJBPU, through the IIP, allowed recovery by ACE of its infrastructure investment capital expenditures through a special rate outside the normal rate recovery mechanism of a base rate filing. The IIP was designed to stimulate the New Jersey economy and provide incremental employment in ACE’s service territory by increasing the infrastructure expenditures to a level above otherwise normal budgeted levels. In an October 18, 2011 petition (subsequently amended December 16, 2011) filed with the NJBPU, ACE requested an extension and expansion to the IIP. The New Jersey Settlement provides for full cost recovery of ACE’s initial IIP, but requires ACE to withdraw its request for extension and expansion to the IIP, without prejudice to file such request again in the future.

Update and Reconciliation of Certain Under-Recovered Balances

In February 2012, ACE filed a petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs, (ii) costs related to surcharges that fund several statewide social programs and ACE’s uncollected accounts, and (iii) operating costs associated with ACE’s residential appliance cycling program. The filing proposed to recover the projected deferred under-recovered balance related to the NUGs of $113.8 million as of May 31, 2012 through a four-year amortization schedule. The net impact of adjusting the charges as proposed (consisting of both the annual impact of the proposed four-year amortization of the historical under-recovered NUG balances and the going-forward cost recovery of all the other charges for the period June 1, 2012 through May 31, 2013, and including associated changes in sales-and-use taxes) is an overall annual rate increase of approximately $55.3 million. On June 18, 2012, the NJBPU approved a stipulation of settlement signed by the parties, which provided for provisional rates to go into effect on July 1, 2012. The rates are deemed “provisional” because ACE’s filing will not be updated for actual revenues and expenses (if necessary) for May and June 2012 until after July 1, 2012 and a review of the final underlying costs for reasonableness and prudency will be completed after such filing.

MPSC New Generation Contract Requirement

In September 2009, the MPSC initiated an investigation into whether the EDCs in Maryland should be required to enter into long-term contracts with entities that construct, acquire or lease, and operate, new electric generation facilities in Maryland.

In April 2012, the MPSC issued an order determining that there is a need for one new power plant in the range of 650 to 700 MW beginning in 2015. The order requires certain Maryland EDCs, including Pepco and DPL, to negotiate and enter into a contract with the winning bidder of a competitive bidding process in amounts proportional to their relative SOS loads. Under the contract, the winning bidder will construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an expected commercial operation date of June 1, 2015. The order acknowledges certain of the EDCs’ concerns about the requirements of the contract and directs them to negotiate with the winning bidder and submit any proposed changes in the contract to the MPSC for approval. The order further specifies that the EDCs entering into the contract will recover the associated costs, in amounts proportional to their relative SOS loads, through surcharges on their respective SOS customers.

Until the final form of the contract with the winning bidder and associated cost recovery are approved, PHI cannot predict (i) the extent of the negative effect that the order and, once finalized, the contract for new generation, may have on PHI’s, Pepco’s and DPL’s balance sheets, as well as their respective credit metrics, as calculated by independent rating agencies that evaluate and rate PHI, Pepco and DPL and each of their debt issuances, (ii) the effect on Pepco’s and DPL’s ability to recover their associated costs of the contract for new generation if a significant number of SOS customers elect to buy their energy from alternative energy suppliers, and (iii) the effect of the order on the financial condition, results of operations and cash flows of each of PHI, Pepco and DPL.

On April 27, 2012, a group of generating companies operating in the PJM region filed a complaint in the U.S. District Court for the Northern District of Maryland challenging the MPSC’s order on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. On May 4, 2012, Pepco, DPL, and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order. These appeals have been consolidated in the Circuit Court for Baltimore City and are set for hearing on January 24, 2013.

Maryland Governor’s Grid Resiliency Task Force

In July 2012, the Maryland governor signed an Executive Order directing his energy advisor, in collaboration with certain state agencies, to solicit input and recommendations from experts on how to improve the resiliency and reliability of the electric distribution system in Maryland. The resulting Grid Resiliency Task Force issued its report in September 2012, in which the Task Force made 11 recommendations. The governor forwarded the report to the MPSC in October 2012, urging the MPSC to quickly implement the first four recommendations: (i) strengthen existing reliability and storm restoration regulations; (ii) accelerate the investment necessary to meet the enhanced metrics; (iii) allow surcharge recovery for the accelerated investment; and (iv) implement clearly defined performance metrics into the traditional ratemaking scheme. Pepco and DPL are currently evaluating the report and its recommendations to determine what effect, if any, they may have on proposals to be made in their future electric distribution base rate cases in Maryland. The form and substance of any such proposals will also depend, in part, on how the MPSC responds to the report and the governor’s request.

ACE Standard Offer Capacity Agreements

In April 2011, ACE entered into three SOCAs by order of the NJBPU, each with a different generation company, as more fully described in Note (2), “Significant Accounting Policies – Consolidation of Variable Interest Entities – ACE Standard Offer Capacity Agreements” and Note (13), “Derivative Instruments and Hedging Activities.” ACE and the other New Jersey EDCs entered into the SOCAs under protest based on concerns about the potential cost to distribution customers. In May 2011, the NJBPU denied a joint motion for reconsideration of its order requiring each of the EDCs to enter into the SOCAs. In June 2011, ACE and the other EDCs filed appeals related to the NJBPU orders with the Appellate Division of the New Jersey Superior Court. On March 5, 2012, the court remanded the case to the NJBPU with instructions to refer the case to an Administrative Law Judge for further consideration. The matter has been transmitted by the NJBPU to the Office of Administrative Law and remains pending.

In February 2011, ACE joined other plaintiffs in an action filed in the U.S. District Court for the District of New Jersey challenging the constitutionality of the New Jersey law under which the SOCAs were established. On September 28, 2012, the District Court denied motions for summary judgment filed by ACE and the other plaintiffs, as well as cross-motions filed by defendants. The litigation remains pending.

In October 2011 and January 2012, respectively, two of the three generation companies sent notices of dispute under the SOCA to ACE. The notices of dispute alleged that certain actions taken by PJM will have an adverse effect on the generation company’s ability to clear their transactions in the PJM auction, which is required for payment under the SOCA. The two generation companies filed separate petitions with the NJBPU seeking to amend their respective SOCAs and, in April 2012, the NJBPU issued an order consolidating the two matters. In May 2012, the NJBPU denied all of the generation companies’ requests without prejudice to their right to raise the issues at a later date.

Termination of the MAPP Project

In 2007, PJM (the regional transmission organization that is responsible for planning the transmission grid and coordinating the movement of wholesale electricity within a region consisting of all or parts of 13 states and the District of Columbia) directed PHI to construct a high-voltage interstate transmission line to address the reliability needs of the region’s transmission system. In its most recent configuration, the transmission line, which PHI referred to as the Mid-Atlantic Power Pathway (MAPP), would have covered 152 miles, originating at the Possum Point substation in northern Virginia, traversing under the Chesapeake Bay and ending at the Indian River substation in Delaware.

On August 24, 2012, the board of PJM notified PHI, on behalf of its subsidiaries Pepco and DPL, that the MAPP project has been terminated and removed from PJM’s regional transmission expansion plan.

As a result of PJM’s decision, on October 2, 2012, Pepco and DPL filed with the MPSC a notice withdrawing their pending applications related to the MAPP project. PHI had included in its five-year projected capital expenditures $205 million of MAPP-related expenditures for the period from 2012 to 2016. PHI has updated its five-year projected capital expenditures to remove MAPP-related expenditures to reflect the PJM decision.

As of September 30, 2012, PHI’s total capital expenditures for the MAPP project were approximately $101 million. Under the terms of the Federal Energy Regulatory Commission (FERC) order approving an incentive rate for the MAPP project, FERC authorized the recovery of abandoned costs prudently incurred in connection with the MAPP project. Consistent with this order, PHI intends to seek recovery of abandoned MAPP capital expenditures through a filing expected to be submitted to the FERC in the fourth quarter of 2012. The FERC filing is expected to address, among other things, the period over which the abandoned costs are to be recovered and the rate of return on these costs during the recovery period. Under an order issued by the FERC in 2008, PHI has been allowed to include its MAPP capital expenditures in its rate base, earning an incentive rate of return of 12.8% during the construction period.

As of September 30, 2012, PHI had placed in service $11 million of its total capital expenditures with respect to the MAPP project, which represented upgrades of existing substation assets that were expected to support the MAPP transmission line, and reclassified the remaining $90 million of capital expenditures to a regulatory asset. The regulatory asset includes the costs of land, land rights, supplies and materials, engineering and design, environmental services, and project management and administration. PHI intends to reduce the regulatory asset by any amounts recovered from the sale or alternative use of the land, land rights, supplies and materials.

Regulatory Matters

(6) REGULATORY MATTERS

Rate Proceedings

Over the last several years, Pepco has proposed in each of its jurisdictions the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. To date, a bill stabilization adjustment (BSA) was approved and implemented for Pepco electric service in Maryland and the District of Columbia. The Maryland Public Service Commission (MPSC) later modified the BSA in Maryland so that revenues lost as a result of major storm outages are not collected through the BSA if electric service is not restored to the pre-major storm levels within 24 hours of the start of a major storm. Under the BSA, customer distribution rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the applicable public service commission. For further information on the BSA in Maryland, see “Maryland—BSA Proceeding” below.

In an effort to reduce the shortfall in revenues due to the delay in time or lag between when costs are incurred and when they are reflected in rates (regulatory lag), Pepco proposed, in each of its jurisdictions, (i) a reliability investment recovery mechanism (RIM) to recover reliability-related capital expenditures incurred between base rate cases, and (ii) the use of fully forecasted test years in future rate cases (which are comprised of forward-looking costs in lieu of historical test years, and if approved, would be more reflective of current costs and would mitigate the effects of regulatory lag). The status of these proposals is discussed below in connection with the discussions of Pepco’s electric distribution base rate proceedings.

District of Columbia

On July 8, 2011, Pepco filed an application with the District of Columbia Public Service Commission (DCPSC) to increase its electric distribution base rates by approximately $42 million annually, based on a requested return on equity (ROE) of 10.75%, of which approximately $9 million was sought so that Pepco could recover its costs associated with the advanced metering infrastructure (AMI) project. The filing included a request for DCPSC approval of a RIM and the use of fully forecasted test years in future Pepco rate cases. On September 26, 2012, the DCPSC issued its decision approving a rate increase of $24 million, based on an ROE of 9.5%, of which approximately $9 million allows Pepco to recover costs associated with the AMI project. The DCPSC denied Pepco’s request for approval of a RIM, and reserved final judgment on the appropriateness of the use by Pepco of a fully forecasted test year in future rate cases. In addition, the DCPSC approved an adjustment by Pepco to normalize operation and maintenance expenses associated with storm restoration efforts to its three-year average, but added approximately $2 million of costs associated with Hurricane Irene from August 2011 in the calculation of the three-year average storm costs. On October 31, 2012, the District of Columbia Office of the People’s Counsel filed a motion with the DCPSC for reconsideration of a portion of the order, objecting to (i) the percentage of the rate increase allocated to residential customers, and (ii) the decision not to adjust Pepco’s base rates downward because of the quality and reliability of Pepco’s electric distribution service. Pepco also filed a motion for reconsideration and clarification on that date (i) objecting to provisions requiring Pepco to perform studies and report certain information three months in advance of its next base
rate case filing, and (ii) requesting clarification concerning the timing of certain reporting requirements. The filing of these motions does not stay the order or delay the rate increase from going into effect.

Maryland

Electric Distribution Base Rates

On December 16, 2011, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $68.4 million (subsequently reduced by Pepco to $66.2 million), based on a requested ROE of 10.75%. The filing included a request for MPSC approval of a RIM and the use of fully forecasted test years in future Pepco rate cases. On July 20, 2012, the MPSC issued an order approving an annual rate increase of approximately $18.1 million, based on an ROE of 9.31%. The MPSC also directed Pepco to reduce the amount of the rate increase by approximately $1.6 million, the annual costs of certain energy advisory programs, resulting in a final rate increase of approximately $16.5 million. Pepco would be required to seek recovery of these annual costs through the EmPower Maryland Program. The MPSC reduced Pepco’s depreciation rates, which is expected to lower annual depreciation and amortization expenses by an estimated $27.3 million. The order did not approve Pepco’s request to implement a RIM and did not endorse the use by Pepco of fully forecasted test years in future rate cases. The order authorizes Pepco to recover in rates over a five-year period $18.5 million of incremental storm restoration costs associated with major weather events in 2011, including $9.7 million of the $9.9 million of incremental storm restoration costs associated with Hurricane Irene that had been deferred previously as a regulatory asset by Pepco and $8.8 million of incremental storm restoration costs incurred by Pepco associated with a severe winter storm in the first quarter of 2011 that had been expensed previously through other operation and maintenance expense in 2011. The incremental storm restoration costs of $8.8 million were reversed and deferred as a regulatory asset in the third quarter of 2012. The order also authorizes Pepco to recover the actual cost of AMI meters installed during the test year and states that cost recovery for AMI deployment will only be allowed in future rate cases in which Pepco demonstrates that the system is proven to be cost effective. The new revenue rates and lower depreciation rates were effective on July 20, 2012. Pepco has determined not to appeal the MPSC order. The Maryland Office of People’s Counsel has sought rehearing on the portion of the order allowing Pepco to recover the costs of installed AMI meters; that motion remains pending.

BSA Proceeding

As in effect for electric utilities in Maryland prior to October 26, 2012, including Pepco, a utility was not permitted to collect through the BSA distribution revenues lost as a result of major storm outages, beginning 24 hours after the commencement of a major storm, if electric service is not restored to the pre-major storm levels within 24 hours of the start of the storm. On October 26, 2012, the MPSC issued an order that no longer permits Pepco, among other utilities, to collect a BSA surcharge for revenues lost during the first 24 hours of a major storm.

MPSC New Generation Contract Requirement

In September 2009, the MPSC initiated an investigation into whether the electric distribution companies (EDCs) in Maryland should be required to enter into long-term contracts with entities that construct, acquire or lease, and operate, new electric generation facilities in Maryland.

In April 2012, the MPSC issued an order determining that there is a need for one new power plant in the range of 650 to 700 megawatts (MW) beginning in 2015. The order requires certain Maryland EDCs, including Pepco, to negotiate and enter into a contract with the winning bidder of a competitive bidding process in amounts proportional to their relative standard offer service (SOS) loads (SOS refers to the supply of electricity to retail customers who do not elect to purchase electricity from a competitive supplier but instead purchase such electricity from Pepco at regulated rates). Under the contract, the winning bidder will construct a 661-MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an expected commercial operation date of June 1, 2015. The order acknowledges certain of the EDCs’ concerns about the requirements of the contract and directs them to negotiate with the winning bidder and submit any proposed changes in the contract to the MPSC for approval. The order further specifies that the EDCs entering into the contract will recover the associated costs, in amounts proportional to their relative SOS loads, through surcharges on their respective SOS customers.

Until the final form of the contract with the winning bidder and associated cost recovery are approved, Pepco cannot predict (i) the extent of the negative effect that the order and, once finalized, the contract for new generation, may have on Pepco’s balance sheets, as well as its credit metrics, as calculated by independent rating agencies that evaluate and rate Pepco and its debt issuances, (ii) the effect on Pepco’s ability to recover its associated costs of the contract for new generation if a significant number of SOS customers elect to buy their energy from alternative energy suppliers, and (iii) the effect of the order on the financial condition, results of operations and cash flows of Pepco.

On April 27, 2012, a group of generating companies operating in the PJM region filed a complaint in the U.S. District Court for the Northern District of Maryland challenging the MPSC’s order on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. On May 4, 2012, Pepco, its affiliate Delmarva Power & Light Company (DPL), and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order. These appeals have been consolidated in the Circuit Court for Baltimore City and are set for hearing on January 24, 2013.

Maryland Governor’s Grid Resiliency Task Force

In July 2012, the Maryland governor signed an Executive Order directing his energy advisor, in collaboration with certain state agencies, to solicit input and recommendations from experts on how to improve the resiliency and reliability of the electric distribution system in Maryland. The resulting Grid Resiliency Task Force issued its report in September 2012, in which the Task Force made 11 recommendations. The governor forwarded the report to the MPSC in October 2012, urging the MPSC to quickly implement the first four recommendations: (i) strengthen existing reliability and storm restoration regulations; (ii) accelerate the investment necessary to meet the enhanced metrics; (iii) allow surcharge recovery for the accelerated investment; and (iv) implement clearly defined performance metrics into the traditional ratemaking scheme. Pepco is currently evaluating the report and its recommendations to determine what effect, if any, they may have on proposals to be made in its future electric distribution base rate cases in Maryland. The form and substance of any such proposals will also depend, in part, on how the MPSC responds to the report and the governor’s request.

Termination of the MAPP Project

In 2007, PJM Interconnection, LLC (PJM) (the regional transmission organization that is responsible for planning the transmission grid and coordinating the movement of wholesale electricity within a region consisting of all or parts of 13 states and the District of Columbia) directed PHI to construct a high-voltage interstate transmission line to address the reliability needs of the region’s transmission system. In its most recent configuration, the transmission line, which PHI referred to as the Mid-Atlantic Power Pathway (MAPP), would have covered 152 miles, originating at the Possum Point substation in northern Virginia, traversing under the Chesapeake Bay and ending at the Indian River substation in Delaware.

On August 24, 2012, the board of PJM notified PHI, on behalf of its subsidiaries Pepco and DPL, that the MAPP project has been terminated and removed from PJM’s regional transmission expansion plan.

As a result of PJM’s decision, on October 2, 2012, Pepco filed with the MPSC a notice withdrawing its pending application related to the MAPP project. Pepco had included in its five-year projected capital expenditures $138 million of MAPP-related expenditures for the period from 2012 to 2016. Pepco has updated its five-year projected capital expenditures to remove MAPP-related expenditures to reflect the PJM decision.

As of September 30, 2012, Pepco’s total capital expenditures for the MAPP project were approximately $64 million. Under the terms of the Federal Energy Regulatory Commission (FERC) order approving an incentive rate for the MAPP project, FERC authorized the recovery of abandoned costs prudently incurred in connection with the MAPP project. Consistent with this order, Pepco intends to seek recovery of abandoned MAPP capital expenditures through a filing expected to be submitted to the FERC in the fourth quarter of 2012. The FERC filing is expected to address, among other things, the period over which the abandoned costs are to be recovered and the rate of return on these costs during the recovery period. Under an order issued by the FERC in 2008, Pepco has been allowed to include its MAPP capital expenditures in its rate base, earning an incentive rate of return of 12.8% during the construction period.

As of September 30, 2012, Pepco had placed in service $11 million of its total capital expenditures with respect to the MAPP project, which represented upgrades of existing substation assets that were expected to support the MAPP transmission line, and reclassified the remaining $53 million of capital expenditures to a regulatory asset. The regulatory asset includes the costs of land, land rights, supplies and materials, engineering and design, environmental services, and project management and administration. Pepco intends to reduce the regulatory asset by any amounts recovered from the sale or alternative use of the land, land rights, supplies and materials.

Regulatory Matters

(7) REGULATORY MATTERS

Rate Proceedings

Over the last several years, DPL has proposed in each of its jurisdictions the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. To date:

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A bill stabilization adjustment (BSA) was approved and implemented for electric service in Maryland. The Maryland Public Service Commission (MPSC) later modified the BSA in Maryland so that revenues lost as a result of major storm outages are not collected through the BSA if electric service is not restored to the pre-major storm levels within 24 hours of the start of a major storm. For further information on the BSA in Maryland, see “Maryland – BSA Proceeding” below.

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A modified fixed variable rate design (MFVRD) has been approved in concept for DPL electric and natural gas service in Delaware, but the implementation has been deferred by the DPSC pending the development of an implementation plan and a customer education plan, as well as the resolution of various matters relating to development of a statewide energy efficiency plan and attendant legislation.

Under the BSA, customer distribution rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the applicable public service commission. The MFVRD approved in concept in Delaware provides for a fixed customer charge (i.e., not tied to the customer’s volumetric consumption) to recover the utility’s fixed costs, plus a reasonable rate of return. Although different from the BSA, DPL views the MFVRD as an appropriate distribution revenue decoupling mechanism.

In an effort to reduce the shortfall in revenues due to the delay in time or lag between when costs are incurred and when they are reflected in rates (regulatory lag), DPL proposed, in each of its jurisdictions, (i) a reliability investment recovery mechanism (RIM) to recover reliability-related capital expenditures incurred between base rate cases, and (ii) the use of fully forecasted test years in future rate cases (which are comprised of forward-looking costs in lieu of historical test years, and if approved, would be more reflective of current costs and would mitigate the effects of regulatory lag). The status of these proposals is discussed below in connection with the discussions of DPL’s electric distribution base rate proceedings.

Delaware

Gas Cost Rates

DPL makes an annual Gas Cost Rate (GCR) filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. In August 2011, DPL made its 2011 GCR filing. The filing includes the second year of the effect of a two-year amortization of under-recovered gas costs proposed by DPL in its 2010 GCR filing (the settlement approved by the DPSC in its 2010 GCR case included only the first year of the proposed two-year amortization). The rates proposed in the 2011 GCR would result in a GCR decrease of approximately 5.6%. On August 21, 2012, the DPSC issued a final order approving the rates as filed.

In August 2012, DPL made its 2012 GCR filing. The rates proposed in the 2012 GCR would result in a GCR decrease of approximately 22.3%. On September 18, 2012, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2012, subject to refund and pending final DPSC approval.

Electric Distribution Base Rates

On December 2, 2011, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $31.8 million, based on a requested return on equity (ROE) of 10.75%, and requested approval of implementation of the MFVRD. The filing included a request for DPSC approval of a RIM and the use of fully forecasted test years in future DPL rate cases. On January 10, 2012, the DPSC entered an order suspending the full increase and allowing a temporary rate increase of $2.5 million to go into effect on January 31, 2012, subject to refund and pending final DPSC approval. On July 3, 2012, in accordance with an agreement with DPSC staff, DPL placed an additional $22.3 million of the requested rate increase into effect, also subject to refund and pending final DPSC order. On August 17, 2012, DPL and the other parties to the proceeding entered into a proposed settlement that provides for an annual rate increase of $22 million, based on an ROE of 9.75%. The settlement agreement also permits DPL to collect from its standard offer service (SOS) customers (retail customers who do not elect to purchase electricity from a competitive supplier but instead purchase such electricity from DPL at regulated rates) approximately $3.4 million related to various state and local taxes that were assessed upon DPL’s SOS customers, but actually paid by DPL rather than by the SOS customers upon whom they were assessed. These taxes would be collected over a three-year period. In addition, the settlement agreement allows for the phase-in of the recovery of costs associated with DPL’s advanced metering infrastructure (AMI) project. The settlement agreement does not include approval of a RIM or the use of fully forecasted test years in future DPL rate cases, but it does provide that the parties will meet and discuss alternate regulatory methodologies for the mitigation of regulatory lag. The settlement agreement is subject to approval by the DPSC. Once approved by the DPSC, DPL will refund the billed amounts that exceeded the increase approved by the DPSC. DPL expects the DPSC to issue a decision on the settlement agreement in the fourth quarter of 2012.

Maryland

Electric Distribution Base Rates

On December 9, 2011, DPL submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $25.2 million (subsequently reduced by DPL to $23.5 million), based on a requested ROE of 10.75%. The filing included a request for MPSC approval of a RIM and the use of fully forecasted test years in future DPL rate cases. On July 20, 2012, the MPSC issued an order approving an annual rate increase of approximately $11.3 million, based on an ROE of 9.81%. The MPSC reduced DPL’s depreciation rates, which is expected to lower annual depreciation and amortization expenses by an estimated $4.1 million. The order did not approve DPL’s request to implement a RIM and did not endorse the use by DPL of fully forecasted test years in future rate cases. The order also authorizes DPL to recover in rates over a five-year period $4.3 million of the $4.6 million of incremental storm restoration costs associated with Hurricane Irene that had been deferred previously as a regulatory asset by DPL. The new revenue rates and lower depreciation rates were effective on July 20, 2012. DPL has determined not to appeal the MPSC order.

BSA Proceeding

As in effect for electric utilities in Maryland prior to October 26, 2012, including DPL, a utility was not permitted to collect through the BSA distribution revenues lost as a result of major storm outages, beginning 24 hours after the commencement of a major storm, if electric service is not restored to the pre-major storm levels within 24 hours of the start of the storm. On October 26, 2012, the MPSC issued an order that no longer permits DPL, among other Maryland utilities, to collect a BSA surcharge for revenues lost during the first 24 hours of a major storm.

MPSC New Generation Contract Requirement

In September 2009, the MPSC initiated an investigation into whether the EDCs in Maryland should be required to enter into long-term contracts with entities that construct, acquire or lease, and operate, new electric generation facilities in Maryland.

In April 2012, the MPSC issued an order determining that there is a need for one new power plant in the range of 650 to 700 MW beginning in 2015. The order requires certain Maryland electric distribution companies (EDCs), including DPL, to negotiate and enter into a contract with the winning bidder of a competitive bidding process in amounts proportional to their relative SOS loads. Under the contract, the winning bidder will construct a 661-MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an expected commercial operation date of June 1, 2015. The order acknowledges certain of the EDCs’ concerns about the requirements of the contract and directs them to negotiate with the winning bidder and submit any proposed changes in the contract to the MPSC for approval. The order further specifies that the EDCs entering into the contract will recover the associated costs, in amounts proportional to their relative SOS loads, through surcharges on their respective SOS customers.

Until the final form of the contract with the winning bidder and associated cost recovery are approved, DPL cannot predict (i) the extent of the negative effect that the order and, once finalized, the contract for new generation, may have on DPL’s balance sheets, as well as its credit metrics, as calculated by independent rating agencies that evaluate and rate DPL and its debt issuances, (ii) the effect on DPL’s ability to recover its associated costs of the contract for new generation if a significant number of SOS customers elect to buy their energy from alternative energy suppliers, and (iii) the effect of the order on the financial condition, results of operations and cash flows of DPL.

On April 27, 2012, a group of generating companies operating in the PJM Interconnection, LLC (PJM) region filed a complaint in the U.S. District Court for the Northern District of Maryland challenging the MPSC’s order on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. On May 4, 2012, DPL and its affiliate Potomac Electric Power Company (Pepco), and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order. These appeals have been consolidated in the Circuit Court for Baltimore City and are set for hearing on January 24, 2013.

Maryland Governor’s Grid Resiliency Task Force

In July 2012, the Maryland governor signed an Executive Order directing his energy advisor, in collaboration with certain state agencies, to solicit input and recommendations from experts on how to improve the resiliency and reliability of the electric distribution system in Maryland. The resulting Grid Resiliency Task Force issued its report in September 2012, in which the Task Force made 11 recommendations. The governor forwarded the report to the MPSC in October 2012, urging the MPSC to quickly implement the first four recommendations: (i) strengthen existing reliability and storm restoration regulations; (ii) accelerate the investment necessary to meet the enhanced metrics; (iii) allow surcharge recovery for the accelerated investment; and (iv) implement clearly defined performance metrics into the traditional ratemaking scheme. DPL is currently evaluating the report and its recommendations to determine what effect, if any, they may have on proposals to be made in its future electric distribution base rate cases in Maryland. The form and substance of any such proposals will also depend, in part, on how the MPSC responds to the report and the governor’s request.

Termination of the MAPP Project

In 2007, PJM (the regional transmission organization that is responsible for planning the transmission grid and coordinating the movement of wholesale electricity within a region consisting of all or parts of 13 states and the District of Columbia) directed PHI to construct a high-voltage interstate transmission line to address the reliability needs of the region’s transmission system. In its most recent configuration, the transmission line, which PHI referred to as the Mid-Atlantic Power Pathway (MAPP), would have covered 152 miles, originating at the Possum Point substation in northern Virginia, traversing under the Chesapeake Bay and ending at the Indian River substation in Delaware.

On August 24, 2012, the board of PJM notified PHI, on behalf of its subsidiaries Pepco and DPL, that the MAPP project has been terminated and removed from PJM’s regional transmission expansion plan.

As a result of PJM’s decision, on October 2, 2012, DPL filed with the MPSC a notice withdrawing its pending application related to the MAPP project. DPL had included in its five-year projected capital expenditures $67 million of MAPP-related expenditures for the period from 2012 to 2016. DPL has updated its five-year projected capital expenditures to remove MAPP-related expenditures to reflect the PJM decision.

As of September 30, 2012, DPL’s total capital expenditures for the MAPP project were approximately $37 million. Under the terms of the Federal Energy Regulatory Commission (FERC) order approving an incentive rate for the MAPP project, FERC authorized the recovery of abandoned costs prudently incurred in connection with the MAPP project. Consistent with this order, DPL intends to seek recovery of abandoned MAPP capital expenditures through a filing expected to be submitted to the FERC in the fourth quarter of 2012. The FERC filing is expected to address, among other things, the period over which the abandoned costs are to be recovered and the rate of return on these costs during the recovery period. Under an order issued by the FERC in 2008, DPL has been allowed to include its MAPP capital expenditures in its rate base, earning an incentive rate of return of 12.8% during the construction period.

As of September 30, 2012, DPL had reclassified all $37 million of capital expenditures with respect to the MAPP project to a regulatory asset. The regulatory asset includes the costs of land, land rights and supplies, engineering and design, environmental services, and project management and administration. DPL intends to reduce the regulatory asset by any amounts recovered from the sale or alternative use of the land and land rights.

Regulatory Matters

(6) REGULATORY MATTERS

Rate Proceedings

Electric Distribution Base Rates

On August 5, 2011, ACE filed a petition with the NJBPU to increase its electric distribution rates by the net amount of approximately $54.6 million (which was increased to approximately $74.3 million on February 24, 2012, to reflect the 2011 test year), based on a requested return on equity (ROE) of 10.75%. The modified net increase consists of a rate increase proposal of approximately $90.3 million, less a deduction from base rates of approximately $16 million through a credit rider expected to expire August 31, 2013, which is designed to refund to customers certain excess depreciation reserve funds as previously directed by the NJBPU (the Excess Depreciation Rider). ACE also proposed an increase of approximately $6.3 million in sales-and-use taxes related to the increase in base rates. On October 23, 2012, the NJBPU approved a stipulation of settlement signed by the parties (the New Jersey Settlement), which provides for an annual increase in ACE’s electric distribution base rates by the net amount of approximately $28 million, based on an ROE that, as part of the overall settlement, is deemed to be 9.75%. The net increase consists of a rate increase of approximately $44 million, less a deduction from base rates of approximately $16 million through the Excess Depreciation Rider. Upon expiration of the Excess Depreciation Rider, ACE will not realize an increase in operating income because the resulting increase in revenues will be offset by a substantially similar increase in depreciation expense. The New Jersey Settlement also provides for an increase of approximately $2 million in sales-and-use taxes related to the increase in base rates, and allows ACE to fully amortize over a three-year period the approximately $7.7 million in costs incurred as a result of Hurricane Irene in August 2011. The new rates will become effective for utility services rendered on and after November 1, 2012.

Infrastructure Investment Program

In July 2009, the NJBPU approved certain rate recovery mechanisms in connection with ACE’s Infrastructure Investment Program (the IIP). In exchange for the increase in infrastructure investment, the NJBPU, through the IIP, allowed recovery by ACE of its infrastructure investment capital expenditures through a special rate outside the normal rate recovery mechanism of a base rate filing. The IIP was designed to stimulate the New Jersey economy and provide incremental employment in ACE’s service territory by increasing the infrastructure expenditures to a level above otherwise normal budgeted levels. In an October 18, 2011 petition (subsequently amended December 16, 2011) filed with the NJBPU, ACE requested an extension and expansion to the IIP. The New Jersey Settlement provides for full cost recovery of ACE’s initial IIP, but requires ACE to withdraw its request for extension and expansion to the IIP, without prejudice to file such request again in the future.

Update and Reconciliation of Certain Under-Recovered Balances

In February 2012, ACE filed a petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs, (ii) costs related to surcharges that fund several statewide social programs and ACE’s uncollected accounts, and (iii) operating costs associated with ACE’s residential appliance cycling program. The filing proposed to recover the projected deferred under-recovered balance related to the NUGs of $113.8 million as of May 31, 2012 through a four-year amortization schedule. The net impact of adjusting the charges as proposed (consisting of both the annual impact of the proposed four-year amortization of the historical under-recovered NUG balances and the going-forward cost recovery of all the other charges for the period June 1, 2012 through May 31, 2013, and including associated changes in sales-and-use taxes) is an overall annual rate increase of approximately $55.3 million. On June 18, 2012, the NJBPU approved a stipulation of settlement signed by the parties, which provided for provisional rates to go into effect on July 1, 2012. The rates are deemed “provisional” because ACE’s filing will not be updated for actual revenues and expenses (if necessary) for May and June 2012 until after July 1, 2012 and a review of the final underlying costs for reasonableness and prudency will be completed after such filing.

ACE Standard Offer Capacity Agreements

In April 2011, ACE entered into three SOCAs by order of the NJBPU, each with a different generation company, as more fully described in Note (2), “Significant Accounting Policies – Consolidation of Variable Interest Entities – ACE Standard Offer Capacity Agreements” and Note (10), “Derivative Instruments and Hedging Activities.” ACE and the other New Jersey EDCs entered into the SOCAs under protest based on concerns about the potential cost to distribution customers. In May 2011, the NJBPU denied a joint motion for reconsideration of its order requiring each of the EDCs to enter into the SOCAs. In June 2011, ACE and the other EDCs filed appeals related to the NJBPU orders with the Appellate Division of the New Jersey Superior Court. On March 5, 2012, the court remanded the case to the NJBPU with instructions to refer the case to an Administrative Law Judge for further consideration. The matter has been transmitted by the NJBPU to the Office of Administrative Law and remains pending.

In February 2011, ACE joined other plaintiffs in an action filed in the U.S. District Court for the District of New Jersey challenging the constitutionality of the New Jersey law under which the SOCAs were established. On September 28, 2012, the District Court denied motions for summary judgment filed by ACE and the other plaintiffs, as well as cross-motions filed by defendants. The litigation remains pending.

In October 2011 and January 2012, respectively, two of the three generation companies sent notices of dispute under the SOCA to ACE. The notices of dispute alleged that certain actions taken by PJM will have an adverse effect on the generation company’s ability to clear their transactions in the PJM auction, which is required for payment under the SOCA. The two generation companies filed separate petitions with the NJBPU seeking to amend their respective SOCAs and, in April 2012, the NJBPU issued an order consolidating the two matters. In May 2012, the NJBPU denied all of the generation companies’ requests without prejudice to their right to raise the issues at a later date.