(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 as part of a Phase 2 to the base rate proceeding filed in August 2009 was not included in the final settlement approved by the NJBPU on May 16, 2011. Accordingly, 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, as applicable, 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.

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, such fully forecasted test years would be more reflective of current costs and would mitigate the effects of regulatory lag.

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 that had been proposed, and approved by the DPSC, in DPL's 2010 GCR filing (the settlement approved by the DPSC in the 2010 GCR case included the first year of such two-year amortization). The rates proposed in the 2011 GCR, which include the second year of the two-year amortization approved in the 2010 GCR case, 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.

On February 21, 2012, DPL submitted its application for a waiver under its GCR tariff, which requires DPL to request an interim GCR rate increase when the under-recovery exceeds 6.0%. The DPSC granted the waiver on March 6, 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. As permitted by Delaware law, DPL intends to place the remainder of approximately $29.3 million of the requested increase into effect on July 2, 2012, subject to refund and pending final DPSC approval. A decision by the DPSC is expected by the end 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%. 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 seeks approval of an annual rate increase of approximately $25.2 million, based on a requested ROE of 10.75%. The filing includes a request for MPSC approval of a RIM and the use of fully forecasted test years in future DPL rate cases. A decision by the MPSC is expected in July 2012.

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 seeks approval of an annual rate increase of approximately $68.4 million, based on a requested ROE of 10.75%. The filing includes a request for MPSC approval of a RIM and the use of fully forecasted test years in future Pepco rate cases. A decision by the MPSC is expected in July 2012.

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 is already 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 (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 of ACE's 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) with the NJBPU, ACE 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 the third quarter of 2012.

Storm Damage Restoration Costs Recovery

In August 2011, ACE filed a petition with the NJBPU seeking authorization for deferred accounting treatment of uninsured incremental storm damage restoration costs not otherwise recovered through base rates. In that petition, ACE sought deferred accounting treatment for recovery of storm costs of approximately $8 million incurred during Hurricane Irene, which impacted ACE's service territory in the third quarter of 2011. In an order dated December 15, 2011, the NJBPU directed that this petition be transmitted to the Office of Administrative Law with a request that the matter be consolidated with the ACE 2011 Base Rate Case, discussed above.

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 $54.5 million. A decision by the NJBPU on this filing is expected by the end of the second quarter of 2012.

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.

The MPSC issued an order on April 12, 2012, in which it determined 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 to negotiate and enter into a contract with the winning bidder in amounts proportionate 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 a commercial operation date of June 1, 2015. The order acknowledges 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 that such order violated the commerce clause and the supremacy clause of the U.S. Constitution. PHI continues to evaluate whether to seek 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." ACE and the other New Jersey EDCs entered 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.

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 seeks to postpone the effective date (currently expected to be in 2015) of the SOCA until the litigation is complete. The other generation company proposes to adjust the payment terms of the SOCA to reflect the total expected revenues under the original bid, which the generation company alleges may be in jeopardy if it were unable to clear in the PJM auction commencing in 2015. ACE does not believe that a dispute exists under the SOCAs and is disputing the amendment of the SOCAs jointly with the other EDCs. ACE does not believe the impact of either of such SOCA amendments would be material, although the result of such amendments, if approved, may be to prolong the term of one or both SOCAs. In April 2012, the NJBPU issued an order consolidating the two matters. A decision is expected in the second quarter of 2012.

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 Pepco electric service in Maryland and 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.

Pepco also has requested in each of its jurisdictions 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, such fully forecasted test years would be more reflective of current costs and would mitigate the effects of regulatory lag.

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

Electric Distribution Base Rates

On December 16, 2011, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $68.4 million, based on a requested ROE of 10.75%. The filing includes a request for MPSC approval of a RIM and the use of fully forecasted test years in future Pepco rate cases. A decision by the MPSC is expected in July 2012.

Major Storm Damage Recovery Proceedings

In February 2011, the MPSC initiated proceedings involving Pepco, as well as its affiliate Delmarva Power & Light Company (DPL) and 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 is already 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 regulated 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.

The MPSC issued an order on April 12, 2012, in which it determined 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 to negotiate and enter into a contract with the winning bidder in amounts proportionate 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 a commercial operation date of June 1, 2015. The order acknowledges 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 its 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 its 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 its financial condition, results of operations and cash flows. 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. Pepco continues to evaluate whether to seek 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 Delaware Public Service Commission (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, 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 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.

DPL also has requested approval in each of its jurisdictions 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, such fully forecasted test years would be more reflective of current costs and would mitigate the effects of regulatory lag.

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 that had been proposed, and approved by the DPSC, in DPL's 2010 GCR filing (the settlement approved by the DPSC in the 2010 GCR case included the first year of such two-year amortization). The rates proposed in the 2011 GCR, which include the second year of the two-year amortization approved in the 2010 GCR case, 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.

On February 21, 2012, DPL submitted its application for a waiver under its GCR tariff, which requires DPL to request an interim GCR rate increase when the under-recovery exceeds 6.0%. The DPSC granted the waiver on March 6, 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. As permitted by Delaware law, DPL intends to place the remainder of approximately $29.3 million of the requested increase into effect on July 2, 2012, subject to refund and pending final DPSC approval. A decision by the DPSC is expected by the end 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 seeks approval of an annual rate increase of approximately $25.2 million, based on a requested ROE of 10.75%. The filing includes a request for MPSC approval of a RIM and the use of fully forecasted test years in future DPL rate cases. A decision by the MPSC is expected in July 2012.

Major Storm Damage Recovery Proceedings

In February 2011, the MPSC initiated proceedings involving DPL, as well as its affiliate Potomac Electric Power Company (Pepco) and 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 and 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. 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 regulated 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.

The MPSC issued an order on April 12, 2012, in which it determined 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 to negotiate and enter into a contract with the winning bidder in amounts proportionate 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 a commercial operation date of June 1, 2015. The order acknowledges 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 its 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 its financial condition, results of operations and cash flows. 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 that such order violated the commerce clause and the supremacy clause of the U.S. Constitution. DPL continues to evaluate whether to seek 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 mechanism (BSA) proposed by ACE as part of a Phase 2 to the base rate proceeding filed in August 2009 was not included in the final settlement approved by the NJBPU on May 16, 2011. Accordingly, 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.

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 (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 of ACE's 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) with the NJBPU, ACE 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 the third quarter of 2012.

Storm Damage Restoration Costs Recovery

In August 2011, ACE filed a petition with the NJBPU seeking authorization for deferred accounting treatment of uninsured incremental storm damage restoration costs not otherwise recovered through base rates. In that petition, ACE sought deferred accounting treatment for recovery of storm costs of approximately $8 million incurred during Hurricane Irene, which impacted ACE's service territory in the third quarter of 2011. In an order dated December 15, 2011, the NJBPU directed that this petition be transmitted to the Office of Administrative Law with a request that the matter be consolidated with the ACE 2011 Base Rate Case, discussed above.

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 $54.5 million. A decision by the NJBPU on this filing is expected by the end of the second quarter of 2012.

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." ACE and the other New Jersey EDCs entered 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.

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 seeks to postpone the effective date (currently expected to be in 2015) of the SOCA until the litigation is complete. The other generation company proposes to adjust the payment terms of the SOCA to reflect the total expected revenues under the original bid, which the generation company alleges may be in jeopardy if it were unable to clear in the PJM auction commencing in 2015. ACE does not believe that a dispute exists under the SOCAs and is disputing the amendment of the SOCAs jointly with the other EDCs. ACE does not believe the impact of either of such SOCA amendments would be material, although the result of such amendments, if approved, may be to prolong the term of one or both SOCAs. In April 2012, the NJBPU issued an order consolidating the two matters. A decision is expected in the second quarter of 2012.