(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:

•

A bill stabilization adjustment (BSA) has been 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) has issued an order requiring modification of 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 (as discussed below).

•

A modified fixed variable rate design (MFVRD) has been approved in concept for DPL electric service in Delaware, but the implementation has been deferred by the DPSC pending the development of an implementation plan and a customer education plan. DPL anticipates that the MFVRD will be in place for electric service by early 2013.

•

A MFVRD has been approved in concept for DPL natural gas service in Delaware, but implementation likewise has been deferred until development of an implementation plan and a customer education plan. DPL anticipates that the MFVRD will be in place for natural gas service by early 2013.

•

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

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 have proposed, in each of their respective jurisdictions, a reliability investment recovery mechanism (RIM) to recover reliability-related capital expenditures incurred between base rate cases. Through the RIM, Pepco or DPL in each year would collect through a surcharge the amount of its reliability-related capital expenditures based on its budget for that year. The budgeted amount would be reconciled with actual capital expenditures on an annual basis and any over-recovery or under-recovery would be reflected in the next year’s surcharge. The work undertaken pursuant to the RIM would be subject to a prudency review by the applicable state regulatory commission in the next base rate case or at more frequent intervals as determined by such commission. Pepco’s or DPL’s respective operation and maintenance costs and other capital expenditures would remain subject to recovery through the traditional ratemaking process. The status of these proposals is discussed below in connection with the discussions of DPL’s and Pepco’s respective electric distribution base rate proceedings.

Pepco and DPL also have each requested, in each of their respective jurisdictions, public service commission approval of the use of fully forecasted test years in future rate cases. Traditionally, past test years with actual historical costs are used for ratemaking purposes; however, fully forecasted test years would be comprised of forward-looking costs. If approved, the use of such fully forecasted test years in lieu of historical test years 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 and Pepco’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 for the typical retail natural gas customer of 5.6% in the level of GCR. On September 20, 2011, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2011, subject to refund and pending final DPSC approval. The parties to the 2011 GCR proceeding have executed a settlement agreement that recommends approval of the 2011 GCR as filed. A DPSC decision on the settlement agreement is expected during the third quarter of 2012.

Electric Distribution Base Rates

On December 2, 2011, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $31.8 million, based on a requested return on equity (ROE) of 10.75%, and requests approval of implementation of the MFVRD. DPL requested that the rates become effective on January 31, 2012. The filing includes 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. Under Delaware law, DPL had the right to place the remainder of approximately $29.3 million of the requested increase into effect on or after July 2, 2012, subject to refund and pending final DPSC order. However, pursuant to an agreement with DPSC staff, DPL has placed only $22.3 million of the requested amount into effect on July 3, 2012, subject to refund and pending final DPSC order. Although DPL agreed to put the lesser amount into effect at this time, the amount of DPL’s annual rate increase request ($31.8 million) has not changed. The final DPSC order is expected by the end of 2012, unless the case is ultimately settled. Hearings before the DPSC, which were to begin July 30, 2012, have been postponed indefinitely as the parties are currently engaged in settlement negotiations. There can be no assurance as to whether the parties will reach a settlement in this case.

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%. The filing includes a request for DCPSC approval of a RIM and the use of fully forecasted test years in future Pepco rate cases. A decision by the DCPSC is expected in the third quarter of 2012.

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 setting forth its decision authorizing an annual rate increase of approximately $11.3 million, based on an ROE of 9.81%. The MPSC reduced DPL’s depreciation rates, which are 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 is currently evaluating the MPSC order to determine what further actions, if any, it may seek to pursue.

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 setting forth its decision authorizing 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 the annual costs of certain energy advisory programs and seek recovery of these annual costs through the Empower Maryland Program. This reduction is currently estimated at $1.5 million. The MPSC reduced Pepco’s depreciation rates, which are 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 will be reversed and deferred as a regulatory asset in the third quarter of 2012. The new revenue rates and lower depreciation rates were effective on July 20, 2012. Pepco is currently evaluating the MPSC order to determine what further actions, if any, it may seek to pursue.

Major Storm Damage Recovery Proceedings

In February 2011, the MPSC initiated proceedings involving Pepco and DPL, as well as unaffiliated utilities in Maryland, for the purpose of reviewing how the BSA operates to recover revenues lost as a result of major storm outages. On January 25, 2012, the MPSC issued an order modifying the BSA to prevent the Maryland utilities, including Pepco and DPL, from collecting lost utility revenue 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 (defined by the MPSC as a weather-related event during which more than the lesser of 10% or 100,000 of an electric utility’s customers have a sustained outage for more than 24 hours). The period for which the lost utility revenue may not be collected through the BSA commences 24 hours after the start of the major storm and continues until all major storm-related outages are restored. The MPSC stated that waivers permitting collection of BSA revenues would be granted in rare and extraordinary circumstances where a utility can show that an outage was not due to inadequate emphasis on reliability and restoration efforts were reasonable under the circumstances. A similar provision excluding revenues lost as a result of major storm outages from the calculation of future BSA adjustments also is included in the BSA for Pepco in the District of Columbia as approved by the DCPSC. The financial impact of service interruptions due to a major storm as a result of this MPSC order would generally depend on the scope and duration of the outages.

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 $58.9 million (which was increased to approximately $80.2 million on February 24, 2012, to reflect the 2011 test year), based on a requested ROE of 10.75% (the ACE 2011 Base Rate Case). The modified net increase consists of a rate increase proposal of approximately $90.3 million, less a deduction from base rates of approximately $17 million attributable to excess depreciation expenses, plus approximately a $6.3 million increase in sales-and-use taxes and an upward adjustment of approximately $0.6 million in the Regulatory Asset Recovery Charge. A decision in the electric distribution rate case is expected by the end of 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 has requested an extension and expansion to the IIP under which ACE proposes to spend approximately $63 million, $94 million and $81 million in calendar years 2012, 2013 and 2014, respectively, on non-revenue reliability-related capital expenditures. As proposed, capital expenditures related to the proposed special rate would be subject to annual reconciliation and approval by the NJBPU. A decision by the NJBPU on ACE’s IIP filing is expected by the end of 2012.

Update and Reconciliation of Certain Under-Recovered Balances

In February 2012, ACE filed a petition with the NJBPU seeking to reconcile and update several pass-through charges related to (i) 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 proposes 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 (including both the annual impact of the proposed four-year amortization of the historical under-recovered balances related to the NUGs and the going-forward cost recovery of all the other components 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 12, 2012, the parties to the proceeding signed a Stipulation of Settlement, which provided for provisional rates to go into effect on July 1, 2012. The NJBPU approved the Stipulation of Settlement on June 18, 2012. The rates have been 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.

Maryland Public Service Commission New Generation Contract Requirement

On September 29, 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.

On April 12, 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 Pepco, DPL and Baltimore Gas and Electric Company (BG&E) to negotiate and enter into a contract with the winning bidder in amounts proportionate to their relative loads for the supply of electricity at regulated rates to their respective retail customers who do not elect to purchase electricity from a competitive supplier, otherwise known as standard offer service (SOS). Under the contract, the winning bidder will construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with a 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 from their respective SOS customers through surcharges. PHI is evaluating the impact of the order on each of Pepco and DPL, and, at this time, 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 generators operating in the PJM region filed a complaint in the United States District Court for the Northern District of Maryland challenging the MPSC’s order on the grounds that such order violated the commerce clause and the supremacy clause of the U.S. Constitution. On May 4, 2012, Pepco, DPL, BG&E and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order.

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.

In February 2011, ACE joined other plaintiffs in an action filed in the United States District Court for the District of New Jersey challenging the constitutionality of the New Jersey law under which the SOCAs were established. ACE and the other plaintiffs filed a motion for summary judgment with the United States District Court for the District of New Jersey in December 2011. Cross motions for summary judgment were filed in January 2012. The motions remain 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 allege that certain actions taken by PJM will have an adverse effect on the generation company’s ability to clear the PJM auction, which is required for payment under the SOCA. As of February 2012, the two generation companies had filed petitions with the NJBPU seeking to amend their respective SOCAs. One of the generation companies sought to postpone the effective date of the SOCA (currently expected to be in 2015) until the litigation is complete. The other generation company proposed to adjust the payment terms of the SOCA to reflect the total expected revenues under the original bid, which the generation company alleged may be in jeopardy if it were unable to clear in the PJM auction commencing in 2015. In April 2012, the NJBPU issued an order consolidating the two matters. On May 1, 2012 (memorialized in a May 7, 2012 order), the NJBPU denied all of the generation companies’ requests without prejudice to their right to raise the issues at a later date.

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) has been approved and implemented for electric service in Maryland and for electric service in the District of Columbia. The Maryland Public Service Commission (MPSC) has issued an order requiring modification of 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 (as discussed below). 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.

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 has proposed in each of its jurisdictions, a reliability investment recovery mechanism (RIM) to recover reliability-related capital expenditures incurred between base rate cases. Through the RIM, Pepco in each year would collect through a surcharge the amount of its reliability-related capital expenditures based on its budget for that year. The budgeted amount would be reconciled with actual capital expenditures on an annual basis and any over-recovery or under-recovery would be reflected in the next year’s surcharge. The work undertaken pursuant to the RIM would be subject to a prudency review by the applicable state regulatory commission in the next base rate case or at more frequent intervals as determined by such commission. Pepco’s operation and maintenance costs and other capital expenditures would remain subject to recovery through the traditional ratemaking process. The status of these proposals is discussed below in connection with the discussions of Pepco’s electric distribution base rate proceedings.

Pepco also has requested, in each of its jurisdictions, public service commission approval of the use of fully forecasted test years in future rate cases. Traditionally, past test years with actual historical costs are used for ratemaking purposes; however, fully forecasted test years would be comprised of forward-looking costs. If approved, the use of such fully forecasted test years in lieu of historical test years 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%. The filing includes a request for DCPSC approval of a RIM and the use of fully forecasted test years in future Pepco rate cases. A decision by the DCPSC is expected in the third quarter of 2012.

Maryland

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 setting forth its decision authorizing 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 the annual costs of certain energy advisory programs and seek recovery of these annual costs through the Empower Maryland Program. This reduction is currently estimated at $1.5 million. The MPSC reduced Pepco’s depreciation rates, which are 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 will be reversed and deferred as a regulatory asset in the third quarter of 2012. The new revenue rates and lower depreciation rates were effective on July 20, 2012. Pepco is currently evaluating the MPSC order to determine what further actions, if any, it may seek to pursue.

Major Storm Damage Recovery Proceedings

In February 2011, the MPSC initiated proceedings involving Pepco and its affiliate Delmarva Power & Light Company (DPL), as well as unaffiliated utilities in Maryland, for the purpose of reviewing how the BSA operates to recover revenues lost as a result of major storm outages. On January 25, 2012, the MPSC issued an order modifying the BSA to prevent the Maryland utilities, including Pepco, from collecting lost utility revenue 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 (defined by the MPSC as a weather-related event during which more than the lesser of 10% or 100,000 of an electric utility’s customers have a sustained outage for more than 24 hours). The period for which the lost utility revenue may not be collected through the BSA commences 24 hours after the start of the major storm and continues until all major storm-related outages are restored. The MPSC stated that waivers permitting collection of BSA revenues would be granted in rare and extraordinary circumstances where a utility can show that an outage was not due to inadequate emphasis on reliability and restoration efforts were reasonable under the circumstances. A similar provision excluding revenues lost as a result of major storm outages from the calculation of future BSA adjustments also is included in the BSA for Pepco in the District of Columbia as approved by the DCPSC. The financial impact of service interruptions due to a major storm as a result of this MPSC order would generally depend on the scope and duration of the outages.

Maryland Public Service Commission New Generation Contract Requirement

On September 29, 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.

On April 12, 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 Pepco, DPL and Baltimore Gas and Electric Company (BG&E) to negotiate and enter into a contract with the winning bidder in amounts proportionate to their relative loads for the supply of electricity at regulated rates to their respective retail customers who do not elect to purchase electricity from a competitive supplier, otherwise known as standard offer service (SOS). Under the contract, the winning bidder will construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with a 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 from their respective SOS customers through surcharges. Pepco is evaluating the impact of the order, and, at this time, 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 generators operating in the PJM Interconnection, LLC region filed a complaint in the United States District Court for the Northern District of Maryland challenging the MPSC’s order on the grounds that such order violated the commerce clause and the supremacy clause of the U.S. Constitution. On May 4, 2012, Pepco, DPL, BG&E and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order.

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:

•

A bill stabilization adjustment (BSA) has been approved and implemented for electric service in Maryland. The Maryland Public Service Commission (MPSC) has issued an order requiring modification of 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 (as discussed below).

•

A modified fixed variable rate design (MFVRD) has been approved in concept for electric service in Delaware, but the implementation has been deferred by the DPSC pending the development of an implementation plan and a customer education plan. DPL anticipates that the MFVRD will be in place for electric service by early 2013.

•

A MFVRD has been approved in concept for natural gas service in Delaware, but implementation likewise has been deferred until development of an implementation plan and a customer education plan. DPL anticipates that the MFVRD will be in place for natural gas service by early 2013.

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), DPL has proposed, in each of its jurisdictions, a reliability investment recovery mechanism (RIM) to recover reliability-related capital expenditures incurred between base rate cases. Through the RIM, DPL in each year would collect through a surcharge the amount of its reliability-related capital expenditures based on its budget for that year. The budgeted amount would be reconciled with actual capital expenditures on an annual basis and any over-recovery or under-recovery would be reflected in the next year’s surcharge. The work undertaken pursuant to the RIM would be subject to a prudency review by the applicable state regulatory commission in the next base rate case or at more frequent intervals as determined by such commission. DPL’s operation and maintenance costs and other capital expenditures would remain subject to recovery through the traditional ratemaking process. The status of these proposals is discussed below in connection with the discussions of DPL’s electric distribution base rate proceedings.

DPL also has requested, in each of its jurisdictions, public service commission approval of the use of fully forecasted test years in future rate cases. Traditionally, past test years with actual historical costs are used for ratemaking purposes; however, fully forecasted test years would be comprised of forward-looking costs. If approved, the use of such fully forecasted test years in lieu of historical test years 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 for the typical retail natural gas customer of 5.6% in the level of GCR. On September 20, 2011, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2011, subject to refund and pending final DPSC approval. The parties to the 2011 GCR proceeding have executed a settlement agreement that recommends approval of the 2011 GCR as filed. A DPSC decision on the settlement agreement is expected during the third quarter of 2012.

Electric Distribution Base Rates

On December 2, 2011, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $31.8 million, based on a requested return on equity (ROE) of 10.75%, and requests approval of implementation of the MFVRD. DPL requested that the rates become effective on January 31, 2012. The filing includes 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. Under Delaware law, DPL had the right to place the remainder of approximately $29.3 million of the requested increase into effect on or after July 2, 2012, subject to refund and pending final DPSC order. However, pursuant to an agreement with DPSC staff, DPL has placed only $22.3 million of the requested amount into effect on July 3, 2012, subject to refund and pending final DPSC order. Although DPL agreed to put the lesser amount into effect at this time, the amount of DPL’s annual rate increase request ($31.8 million) has not changed. The final DPSC order is expected by the end of 2012, unless the case is ultimately settled. Hearings before the DPSC, which were to begin July 30, 2012, have been postponed indefinitely as the parties are currently engaged in settlement negotiations. There can be no assurance as to whether the parties will reach a settlement in this case.

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 setting forth its decision authorizing an annual rate increase of approximately $11.3 million, based on an ROE of 9.81%. The MPSC reduced DPL’s depreciation rates, which are 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 is currently evaluating the MPSC order to determine what further actions, if any, it may seek to pursue.

Major Storm Damage Recovery Proceedings

In February 2011, the MPSC initiated proceedings involving DPL and its affiliate Potomac Electric Power Company (Pepco), as well as unaffiliated utilities in Maryland, for the purpose of reviewing how the BSA operates to recover revenues lost as a result of major storm outages. On January 25, 2012, the MPSC issued an order modifying the BSA to prevent the Maryland utilities, including DPL, from collecting lost utility revenue 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 (defined by the MPSC as a weather-related event during which more than the lesser of 10% or 100,000 of an electric utility’s customers have a sustained outage for more than 24 hours). The period for which the lost utility revenue may not be collected through the BSA commences 24 hours after the start of the major storm and continues until all major storm-related outages are restored. The MPSC stated that waivers permitting collection of BSA revenues would be granted in rare and extraordinary circumstances where a utility can show that an outage was not due to inadequate emphasis on reliability and restoration efforts were reasonable under the circumstances. The financial impact of service interruptions due to a major storm as a result of this MPSC order would generally depend on the scope and duration of the outages.

Maryland Public Service Commission New Generation Contract Requirement

On September 29, 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.

On April 12, 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 DPL, Pepco and Baltimore Gas and Electric Company (BG&E) to negotiate and enter into a contract with the winning bidder in amounts proportionate to their relative loads for the supply of electricity at regulated rates to their respective retail customers who do not elect to purchase electricity from a competitive supplier, otherwise known as standard offer service (SOS).

Under the contract, the winning bidder will construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with a 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 from their respective SOS customers through surcharges. DPL is evaluating the impact of the order, and, at this time, 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 generators operating in the PJM Interconnection, LLC region filed a complaint in the United States District Court for the Northern District of Maryland challenging the MPSC’s order on the grounds that such order violated the commerce clause and the supremacy clause of the U.S. Constitution. On May 4, 2012, DPL, Pepco, BG&E and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order.

Regulatory Matters

(6) REGULATORY MATTERS

Rate Proceedings

Over the last several years, ACE has proposed the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. A bill stabilization adjustment (BSA) proposed by ACE in 2009 was not approved and there is no BSA proposal currently pending in New Jersey. Under the BSA, customer distribution rates would be 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 NJBPU.

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 $58.9 million (which was increased to approximately $80.2 million on February 24, 2012, to reflect the 2011 test year), based on a requested return on equity of 10.75% (the ACE 2011 Base Rate Case). The modified net increase consists of a rate increase proposal of approximately $90.3 million, less a deduction from base rates of approximately $17 million attributable to excess depreciation expenses, plus approximately a $6.3 million increase in sales-and-use taxes and an upward adjustment of approximately $0.6 million in the Regulatory Asset Recovery Charge. A decision in the electric distribution rate case is expected by the end of 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 has requested an extension and expansion to the IIP under which ACE proposes to spend approximately $63 million, $94 million and $81 million in calendar years 2012, 2013 and 2014, respectively, on non-revenue reliability-related capital expenditures. As proposed, capital expenditures related to the proposed special rate would be subject to annual reconciliation and approval by the NJBPU. A decision by the NJBPU on ACE’s IIP filing is expected by the end of 2012.

Update and Reconciliation of Certain Under-Recovered Balances

In February 2012, ACE filed a petition with the NJBPU seeking to reconcile and update several pass-through charges related to (i) 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 proposes 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 (including both the annual impact of the proposed four-year amortization of the historical under-recovered balances related to the NUGs and the going-forward cost recovery of all the other components 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 12, 2012, the parties to the proceeding signed a Stipulation of Settlement, which provided for provisional rates to go into effect on July 1, 2012. The NJBPU approved the Stipulation of Settlement on June 18, 2012. The rates have been 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.

In February 2011, ACE joined other plaintiffs in an action filed in the United States District Court for the District of New Jersey challenging the constitutionality of the New Jersey law under which the SOCAs were established. ACE and the other plaintiffs filed a motion for summary judgment with the United States District Court for the District of New Jersey in December 2011. Cross motions for summary judgment were filed in January 2012. The motions remain 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 allege that certain actions taken by PJM will have an adverse effect on the generation company’s ability to clear the PJM auction, which is required for payment under the SOCA. As of February 2012, the two generation companies had filed petitions with the NJBPU seeking to amend their respective SOCAs. One of the generation companies sought to postpone the effective date of the SOCA (currently expected to be in 2015) until the litigation is complete. The other generation company proposed to adjust the payment terms of the SOCA to reflect the total expected revenues under the original bid, which the generation company alleged may be in jeopardy if it were unable to clear in the PJM auction commencing in 2015. In April 2012, the NJBPU issued an order consolidating the two matters. On May 1, 2012 (memorialized in a May 7, 2012 order), the NJBPU denied all of the generation companies’ requests without prejudice to their right to raise the issues at a later date.