Regulatory Assets And Regulatory Liabilities

(7) REGULATORY MATTERS

Regulatory Assets and Regulatory Liabilities

The components of Pepco Holdings' regulatory asset and liability balances at December 31, 2011 and 2010 are as follows:


	2011		2010
	*(millions of dollars)*
Regulatory Assets
Pension and OPEB costs (a)	$	1,037	$	848
Securitized stranded costs (a)		481		559
Deferred income taxes		145		139
Deferred energy supply costs (a)		124		61
Recoverable meter-related costs (a)		112		44
Deferred debt extinguishment costs (a)		57		61
Recoverable workers compensation and long-term disability costs		34		28
Blueprint for the Future		30		16
Deferred losses on gas derivatives		17		31
Other		159		128

Total Regulatory Assets	$	2,196	$	1,915

Regulatory Liabilities
Asset removal costs	$	388	$	361
Deferred income taxes due to customers		48		50
Deferred energy supply costs		33		35
Excess depreciation reserve		26		42
Other		31		40

Total Regulatory Liabilities	$	526	$	528

(a)	A return is generally earned on these deferrals.

A description for each category of regulatory assets and regulatory liabilities follows:

Pension and OPEB Costs: Represents unrecognized amounts related to net actuarial losses, prior service cost (credit), and transition liability for Pepco Holdings' defined benefit pension and other postretirement benefit (OPEB) plans that are expected to be recovered by Pepco, DPL and ACE in rates. The utilities have

historically included these items as a part of its cost of service in its customer rates. This regulatory asset is adjusted at least annually when the funded status of Pepco Holdings' defined benefit pension and OPEB plans are re-measured. See Note (10), "Pension and Other Postretirement Benefits," for more information about the components of the unrecognized pension and OPEB costs.

Securitized Stranded Costs: Includes contract termination payments under a contract between ACE and an unaffiliated NUG and costs associated with the regulated operations of ACE's electricity generation business which are no longer recoverable through customer rates. The recovery of these stranded costs has been securitized through the issuance of Transition Bonds by ACE Funding. A customer surcharge is collected by ACE to fund principal and interest payments on the Transition Bonds. The stranded costs are amortized over the life of the Transition Bonds, which mature between 2013 and 2023.

Deferred Income Taxes: Represents a receivable from Power Delivery's customers for tax benefits applicable to utility operations of Pepco, DPL and ACE previously flowed through before the companies were ordered to account for the tax benefits as deferred income taxes. As the temporary differences between the financial statement basis and tax basis of assets reverse, the deferred recoverable balances are reversed.

Deferred Energy Supply Costs: The regulatory asset represents primarily deferred costs associated with a net under-recovery of Default Electricity Supply costs incurred by Pepco, DPL and ACE that are probable of recovery in rates. The regulatory liability represents primarily deferred costs associated with a net over-recovery of Default Electricity Supply costs incurred that will be refunded by Pepco, DPL and ACE to customers.

Recoverable Meter-Related Costs: Represents costs associated with the installation of smart meters and the early retirement of existing meters throughout Pepco's and DPL's service territories as a result of the AMI project.

Deferred Debt Extinguishment Costs: Represents the costs of debt extinguishment of Pepco, DPL and ACE for which recovery through regulated utility rates is considered probable and, if approved, will be amortized to interest expense during the authorized rate recovery period.

Recoverable Workers' Compensation and Long-Term Disability Costs: Represents accrued workers' compensation and long-term disability costs for Pepco, which are recoverable from customers when actual claims are paid to employees.

Blueprint for the Future: Includes costs associated with Blueprint for the Future initiatives which include programs to help customers better manage their energy use and to allow each utility to better manage their electrical and natural gas distribution systems.

Deferred Losses on Gas Derivatives: Represents losses associated with hedges of natural gas purchases that are recoverable through the Gas Cost Rate approved by the DPSC.

Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years.

Asset Removal Costs: The depreciation rates for Pepco and DPL include a component for removal costs, as approved by the relevant federal and state regulatory commissions. As such, Pepco and DPL have recorded regulatory liabilities for their estimate of the difference between incurred removal costs and the amount of removal costs recovered through depreciation rates.

Deferred Income Taxes Due to Customers: Represents the portions of deferred income tax liabilities applicable to utility operations of Pepco, DPL and ACE that have not been reflected in current customer rates for which future payment to customers is probable. As the temporary differences between the financial statement basis and tax basis of assets reverse, deferred recoverable income taxes are amortized.

Excess Depreciation Reserve: The excess depreciation reserve was recorded as part of an ACE New Jersey rate case settlement. This excess reserve is the result of a change in estimated depreciable lives and a change in depreciation technique from remaining life to whole life that caused an over-recovery for depreciation expense from customers when the remaining life method has been used. The excess is being amortized over an 8.25 year period, which began in June 2005.

Other: Includes miscellaneous regulatory liabilities.

Regulatory Proceedings

District of Columbia Divestiture Case

In June 2000, the DCPSC approved a divestiture settlement under which Pepco is required to share with its District of Columbia customers the net proceeds realized by Pepco from the sale of its generation-related assets in 2000. This approval left unresolved issues of (i) whether Pepco should be required to share with customers the excess deferred income taxes (EDIT) and accumulated deferred investment tax credits (ADITC) associated with the sold assets and, if so, whether such sharing would violate the normalization provisions of the Internal Revenue Code and its implementing regulations and (ii) whether Pepco was entitled to deduct certain costs in determining the amount of proceeds to be shared.

In May 2010, the DCPSC issued an order addressing all of the remaining issues related to the sharing of the proceeds of Pepco's divestiture of its generating assets. In the order, the DCPSC ruled that Pepco is not required to share EDIT and ADITC with customers. However, the order also disallowed certain items that Pepco had included in the costs deducted from the proceeds of the sale of the generation assets. The disallowance of these costs, together with interest on the disallowed amount, increased the aggregate amount Pepco was required to distribute to customers, pursuant to the sharing formula, by approximately $11 million, which Pepco recognized as an expense in 2010 and refunded the amounts to its customers. In June 2010, Pepco filed an application for reconsideration of the DCPSC's order. In July 2010, the DCPSC denied Pepco's application for reconsideration. In September 2010, Pepco filed an appeal of the DCPSC's decision with the District of Columbia Court of Appeals. On April 12, 2011, the Court of Appeals affirmed the DCPSC order. Pepco determined not to appeal this decision.

Maryland Public Service Commission Reliability Investigation

In August 2010, following major storm events that occurred in July and August 2010, the MPSC initiated a proceeding for the purpose of investigating the reliability of Pepco's distribution system and the quality of distribution service Pepco provided to its customers. On December 21, 2011, the MPSC issued an order in the proceeding imposing a fine on Pepco of $1 million, which Pepco has paid. In accordance with the order, Pepco filed a detailed work plan for the next five years, which provides a comprehensive description of Pepco's reliability enhancement plan, its emergency response improvement project, and other communication and service restoration improvements. Pepco is also required to file quarterly updates and a year-end status report with the MPSC providing, among other things, detailed information about its reliability and emergency response improvement objectives; its progress in meeting such objectives, together with an analysis of trends concerning the measured duration and frequency of customer interruptions compared to 2010 baseline data; the amount of spending associated with such objectives; an explanation for any inability to meet such objectives; any proposed changes in funding these improvement projects; any changes to any of these projects; and interim and final results of Pepco's system inspection program. In addition, Pepco must provide additional detail in these reports about its Estimated Time to Restoration Manager and the Customer Advocate, which personnel have been added by Pepco as part of its emergency response improvement project, and to explore the benefits of damage prediction models. Finally, Pepco was required to consider, the comments and suggestions of other interested parties in the reliability proceeding regarding improvements that Pepco might make to its reliability enhancement programs. In these reports, Pepco will be required to demonstrate that its reliability enhancement plan costs were prudently spent and produced a significant improvement in reliability, and if it is unable to do so, the MPSC may deny Pepco reimbursement for future reliability enhancement expenditures or impose additional fines.

The MPSC also stated in the order that it intends to review in Pepco's pending electric distribution base rate case the recovery of reliability costs and to disallow incremental costs it determines to be the result of imprudent management. Pepco believes its reliability costs have been prudently incurred. Furthermore, Pepco believes that its reliability enhancement plan will enable Pepco to meet the MPSC's requirements.

Rate Proceedings

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

•

A 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 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.

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 2010, DPL made its 2010 GCR filing, which proposes rates that would allow DPL to recover an amount equal to a two-year amortization of currently under-recovered natural gas costs. In October 2010, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2010, subject to refund and pending final DPSC approval. The effect of the proposed two-year amortization upon rates is an increase of 0.1% in the level of GCR. The parties in the proceeding submitted a proposed settlement to the hearing examiner on June 3, 2011, which includes the first year of DPL's two-year amortization but provides that DPL will forego the interest ($171,000 for the 2011 to 2012 period covered by the GCR and $171,000 for the 2012 to 2013 period covered by the GCR) associated with that amortization. The proposed settlement was approved by the DPSC on October 18, 2011.

In August 2011, DPL made its 2011 GCR filing. The filing includes the second year of the effect of the proposed two-year amortization as proposed in DPL's 2010 filing. 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.

Natural Gas Distribution Base Rates

In July 2010, DPL submitted an application with the DPSC to increase its natural gas distribution base rates. As subsequently amended, the filing sought approval of an annual rate increase of approximately $10.2 million, based on a requested return on equity (ROE) of 11.0%, and requests approval of implementation of the MFVRD. As permitted by Delaware law, DPL placed an annual increase of approximately $2.5 million into effect, on a temporary basis, on August 31, 2010, and the remainder of approximately $7.7 million of the requested increase was placed into effect on February 2, 2011, in each case subject to refund and pending final DPSC approval. On June 21, 2011, the DPSC approved a settlement providing for an annual rate increase of approximately $5.8 million, based on an ROE of 10.0%. The decision deferred the implementation of the MFVRD until an implementation plan and a customer education plan are developed. As of December 31, 2011, the amount collected in excess of the approved rate has been refunded to customers through a bill credit.

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 ROE of 10.75%, and requests approval of implementation of the MFVRD. DPL has requested that the rates become effective on January 31, 2012. In the 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), the filing includes a request for the DPSC to approve a reliability investment recovery mechanism (RIM) to recover reliability-related capital expenditures incurred between base rate cases. Through the RIM, DPL would collect in a surcharge the amount of its reliability-related capital expenditures based on its budget for the current 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 DPSC in the next base rate case or at more frequent intervals as determined by the DPSC. DPL's operating and maintenance costs and other capital expenditures would remain subject to recovery through the traditional ratemaking process. DPL has also requested DPSC approval of 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.

District of Columbia

On July 8, 2011, Pepco filed an application with the DCPSC to increase its electric distribution base rates by approximately $42 million annually, based on an ROE of 10.75%. In the effort to reduce regulatory lag, the filing includes a request for the DCPSC to approve a RIM to recover reliability-related capital expenditures incurred between base rate cases. Through the RIM, Pepco would collect in a surcharge the amount of its reliability-related capital expenditures based on its budget for the current 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 DCPSC in the next base rate case or at more frequent intervals as determined by the DCPSC. Pepco's operating and maintenance costs and other capital expenditures would remain subject to recovery through the traditional ratemaking process. A decision by the DCPSC is expected in the second 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%. In the effort to reduce regulatory lag, the filing includes a request for the MPSC to approve a RIM to recover reliability-related capital expenditures incurred between base rate cases. Through the RIM, DPL would collect in a surcharge the amount of its reliability-related capital expenditures based on its budget for the current 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 MPSC in the next base rate case or at more frequent intervals as determined by the MPSC. DPL's operating and maintenance costs and other capital expenditures would remain subject to recovery through the traditional ratemaking process. DPL has also requested MPSC approval of 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%. In the effort to reduce regulatory lag, the filing includes a request for the MPSC to approve a RIM to recover reliability-related capital expenditures incurred between base rate cases. Through the RIM, Pepco would collect in a surcharge the amount of its reliability-related capital expenditures based on its budget for the current 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 MPSC in the next base rate case or at more frequent intervals as determined by the MPSC. Pepco's operating and maintenance costs and other capital expenditures would remain subject to recovery through the traditional ratemaking process. Pepco also has requested MPSC approval of 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 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, based on a return on equity of 10.75% (the ACE 2011 Base Rate Case). The net increase consists of a rate increase proposal of approximately $70.5 million, less a deduction from base rates of approximately $17 million attributable to excess depreciation expenses, plus approximately a $4.9 million increase in sales-and-use taxes and an upward adjustment of approximately $0.5 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 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.

Regulatory Assets And Regulatory Liabilities

(6) REGULATORY MATTERS

Regulatory Assets and Regulatory Liabilities

The components of Pepco's regulatory asset and liability balances at December 31, 2011 and 2010 are as follows:


	2011		2010
	*(millions of dollars)*
Regulatory Assets
Recoverable meter-related costs (a)	$	86	$	15
Deferred income taxes		57		45
Recoverable workers' compensation and long-term disability costs		34		28
Deferred debt extinguishment costs (a)		30		33
Demand-side management		20		10
Blueprint for the Future		10		5
Deferred energy supply costs		4		8
Other		58		47

Total Regulatory Assets	$	299	$	191

Regulatory Liabilities
Asset removal costs	$	144	$	122
Other		25		25

Total Regulatory Liabilities	$	169	$	147

(a)	A return is generally earned on these deferrals.

A description for each category of regulatory assets and regulatory liabilities follows:

Recoverable Meter-Related Costs: Represents costs associated with the installation of smart meters and the early retirement of existing meters throughout Pepco's service territory as a result of the Advanced Metering Infrastructure project.

Deferred Income Taxes: Represents a receivable from our customers for tax benefits Pepco previously flowed through before the company was ordered to account for the tax benefits as deferred income taxes. As the temporary differences between the financial statement basis and tax basis of assets reverse, the deferred recoverable balances are reversed.

Recoverable Workers' Compensation and Long-Term Disability Costs: Represents accrued workers' compensation and long-term disability costs for Pepco, which are recoverable from customers when actual claims are paid to employees.

Deferred Debt Extinguishment Costs: Represents the costs of debt extinguishment for which recovery through regulated utility rates is considered probable and, if approved, will be amortized to interest expense during the authorized rate recovery period.

Demand-Side Management: Represents recoverable costs associated with customer energy efficiency programs.

Blueprint for the Future: Includes costs associated with Blueprint for the Future initiatives which include programs to help customers better manage their energy use and to allow each utility to better manage their electrical and natural gas distribution systems.

Deferred Energy Supply Costs: The regulatory asset represents primarily deferred costs associated with a net under-recovery of Default Electricity Supply costs incurred by Pepco that are probable of recovery in rates.

Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years. Also includes the under-recovery of administrative costs associated with Default Electricity Supply in the District of Columbia and Maryland.

Asset Removal Costs: Pepco's depreciation rates include a component for removal costs, as approved by the relevant federal and state regulatory commissions. As such, Pepco has recorded a regulatory liability for its estimate of the difference between incurred removal costs and the amount of removal costs recovered through depreciation rates.

Other: Represents miscellaneous regulatory liabilities.

Regulatory Proceedings

District of Columbia Divestiture Case

In June 2000, the DCPSC approved a divestiture settlement under which Pepco is required to share with its District of Columbia customers the net proceeds realized by Pepco from the sale of its generation-related assets in 2000. This approval left unresolved issues of (i) whether Pepco should be required to share with customers the excess deferred income taxes (EDIT) and accumulated deferred investment tax credits (ADITC) associated with the sold assets and, if so, whether such sharing would violate the normalization provisions of the Internal Revenue Code and its implementing regulations and (ii) whether Pepco was entitled to deduct certain costs in determining the amount of proceeds to be shared.

In May 2010, the DCPSC issued an order addressing all of the remaining issues related to the sharing of the proceeds of Pepco's divestiture of its generating assets. In the order, the DCPSC ruled that Pepco is not required to share EDIT and ADITC with customers. However, the order also disallowed certain items that Pepco had included in the costs deducted from the proceeds of the sale of the generation assets. The disallowance of these costs, together with interest on the disallowed amount, increased the aggregate amount Pepco was required to distribute to customers, pursuant to the sharing formula, by approximately $11 million, which Pepco recognized as an expense in 2010 and refunded the amounts to its customers. In June 2010, Pepco filed an application for reconsideration of the DCPSC's order. In July 2010, the DCPSC denied Pepco's application for reconsideration. In September 2010, Pepco filed an appeal of the DCPSC's decision with the District of Columbia Court of Appeals. On April 12, 2011, the Court of Appeals affirmed the DCPSC order. Pepco determined not to appeal this decision.

Maryland Public Service Commission Reliability Investigation

In August 2010, following major storm events that occurred in July and August 2010, the MPSC initiated a proceeding for the purpose of investigating the reliability of Pepco's distribution system and the quality of distribution service Pepco provided to its customers. On December 21, 2011, the MPSC issued an order in the proceeding imposing a fine on Pepco of $1 million, which Pepco has paid. In accordance with the order, Pepco filed a detailed work plan for the next five years, which provides a comprehensive description of Pepco's reliability enhancement plan, its emergency response improvement project, and other communication and service restoration improvements. Pepco is also required to file quarterly updates and a year-end status report with the MPSC providing, among other things, detailed information about its reliability and emergency response improvement objectives; its progress in meeting such objectives, together with an analysis of trends concerning the measured duration and frequency of customer interruptions compared to 2010 baseline data; the amount of spending associated with such objectives; an explanation for any inability to meet such objectives; any proposed changes in funding these improvement projects; any changes to any of these projects; and interim and final results of Pepco's system inspection program. In addition, Pepco must provide additional detail in these reports about its Estimated Time to Restoration Manager and the Customer Advocate, which personnel have been added by Pepco as part of its emergency response improvement project, and to explore the benefits of damage prediction models. Finally, Pepco was required to consider the comments and suggestions of other interested parties in the reliability proceeding regarding improvements that Pepco might make to its reliability enhancement programs. In these reports, Pepco will be required to demonstrate that its reliability enhancement plan costs were prudently spent and produced a significant improvement in reliability, and if it is unable to do so, the MPSC may deny Pepco reimbursement for future reliability enhancement expenditures or impose additional fines.

The MPSC also stated in the order that it intends to review in Pepco's pending electric distribution base rate case the recovery of reliability costs and to disallow incremental costs it determines to be the result of imprudent management. Pepco believes its reliability costs have been prudently incurred and it intends to seek to recover its expenditures in its pending rate case. Furthermore, Pepco believes that its reliability enhancement plan will enable Pepco to meet the MPSC's requirements.

Rate Proceedings

Over the last several years, Pepco has proposed in its service territories the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. A BSA has been approved and implemented for electric service in Maryland and in the District of Columbia. The 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 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.

District of Columbia

On July 8, 2011, Pepco filed an application with the DCPSC to increase its electric distribution base rates by approximately $42 million annually, based on an return on equity (ROE) of 10.75%. In the 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), the filing includes a request for the DCPSC to approve a reliability investment recovery mechanism (RIM), to recover reliability-related capital expenditures incurred between base rate cases. Through the RIM, Pepco would collect in a surcharge the amount of its reliability-related capital expenditures based on its budget for the current 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 DCPSC in the next base rate case or at more frequent intervals as determined by the DCPSC. Pepco's operating and maintenance costs and other capital expenditures would remain subject to recovery through the traditional ratemaking process. A decision by the DCPSC is expected in the second 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%. In the effort to reduce regulatory lag, the filing includes a request for the MPSC to approve a RIM to recover reliability-related capital expenditures incurred between base rate cases. Through the RIM, Pepco would collect in a surcharge the amount of its reliability-related capital expenditures based on its budget for the current 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 MPSC in the next base rate case or at more frequent intervals as determined by the MPSC. Pepco's operating and maintenance costs and other capital expenditures would remain subject to recovery through the traditional ratemaking process. Pepco also has requested MPSC approval of 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 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 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 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.

Regulatory Assets And Regulatory Liabilities

(7) REGULATORY MATTERS

Regulatory Assets and Regulatory Liabilities

The components of DPL's regulatory asset and liability balances at December 31, 2011 and 2010 are as follows:


	2011		2010
	*(millions of dollars)*
Regulatory Assets
Deferred income taxes	$	61	$	65
COPCO acquisition adjustment (a)		30		33
Recoverable meter-related costs (a)		26		29
Deferred losses on gas derivatives		17		31
Blueprint for the Future		20		11
Deferred debt extinguishment costs (a)		16		16
Deferred energy supply costs (b)		15		22
Other		42		35

Total Regulatory Assets	$	227	$	242

Regulatory Liabilities
Asset removal costs	$	244	$	239
Deferred income taxes due to customers		38		38
Deferred energy supply costs		12		23
Other		3		10

Total Regulatory Liabilities	$	297	$	310

(a)	A return is earned on these deferrals.

(b)	A return is generally earned in Delaware on this deferral.

A description for each category of regulatory assets and regulatory liabilities follows:

Deferred Income Taxes: Represents a receivable from our customers for tax benefits DPL previously flowed through before the company was ordered to account for the tax benefits as deferred income taxes. As the temporary differences between the financial statement basis and tax basis of assets reverse, the deferred recoverable balances are reversed.

COPCO Acquisition Adjustment: On July 19, 2007, the MPSC issued an order which provided for the recovery of a portion of DPL's goodwill. As a result of this order, $41 million in DPL goodwill was transferred to a regulatory asset. This item will be amortized from August 2007 through August 2018. The return earned is 12.95%.

Recoverable Meter-Related Costs: Represents costs associated with the installation of smart meters and the early retirement of existing meters throughout DPL's service territory as a result of the Advanced Metering Infrastructure project.

Deferred Losses on Gas Derivatives: Represents losses associated with hedges of natural gas purchases that are recoverable through the GCR approved by the DPSC.

Blueprint for the Future: Includes costs associated with Blueprint for the Future initiatives which include programs to help customers better manage their energy use and to allow DPL to better manage its electrical and natural gas distribution systems.

Deferred Debt Extinguishment Costs: Represents the costs of debt extinguishment for which recovery through regulated utility rates is considered probable and, if approved, will be amortized to interest expense during the authorized rate recovery period.

Deferred Energy Supply Costs: The regulatory asset represents primarily deferred energy costs associated with a net under-recovery of Default Electricity Supply costs incurred in Maryland and deferred fuel costs for DPL's gas business that are probable of recovery in rates. The gas deferred fuel costs are recovered over a twelve month period. The regulatory liability represents primarily deferred energy and transmission costs associated with a net over-recovery of Default Electricity Supply costs incurred in Delaware and Maryland that will be refunded to customers.

Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years.

Asset Removal Costs: DPL's depreciation rates include a component for removal costs, as approved by the relevant federal and state regulatory commissions. As such, DPL has recorded a regulatory liability for its estimate of the difference between incurred removal costs and the amount of removal costs recovered through depreciation rates.

Deferred Income Taxes Due to Customers: Represents the portions of deferred income tax liabilities applicable to DPL's utility operations that have not been reflected in current customer rates for which future payment to customers is probable. As the temporary differences between the financial statement basis and tax basis of assets reverse, deferred recoverable income taxes are amortized.

Other: Includes miscellaneous regulatory liabilities.

Regulatory Proceedings

Rate Proceedings

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

•

A BSA has been approved and implemented for electric service in Maryland. The 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 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).

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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.

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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.

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 2010, DPL made its 2010 GCR filing, which proposes rates that would allow DPL to recover an amount equal to a two-year amortization of currently under-recovered natural gas costs. In October 2010, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2010, subject to refund and pending final DPSC approval. The effect of the proposed two-year amortization upon rates is an increase of 0.1% in the level of GCR. The parties in the proceeding submitted a proposed settlement to the hearing examiner on June 3, 2011, which includes the first year of DPL's two-year amortization but provides that DPL will forego the interest ($171,000 for the 2011 to 2012 period covered by the GCR and $171,000 for the 2012 to 2013 period covered by the GCR) associated with that amortization. The proposed settlement was approved by the DPSC on October 18, 2011.

In August 2011, DPL made its 2011 GCR filing. The filing includes the second year of the effect of the proposed two-year amortization as proposed in DPL's 2010 filing. 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.

Natural Gas Distribution Base Rates

In July 2010, DPL submitted an application with the DPSC to increase its natural gas distribution base rates. As subsequently amended, the filing sought approval of an annual rate increase of approximately $10.2 million, based on a requested return on equity (ROE) of 11.0%, and requests approval of implementation of the MFVRD. As permitted by Delaware law, DPL placed an annual increase of approximately $2.5 million into effect, on a temporary basis, on August 31, 2010, and the remainder of approximately $7.7 million of the requested increase was placed into effect on February 2, 2011, in each case subject to refund and pending final DPSC approval. On June 21, 2011, the DPSC approved a settlement providing for an annual rate increase of approximately $5.8 million, based on an ROE of 10.0%. The decision deferred the implementation of the MFVRD until an implementation plan and a customer education plan are developed. As of December 31, 2011, the amount collected in excess of the approved rate has been refunded to customers through a bill credit.

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 ROE of 10.75%, and requests approval of implementation of the MFVRD. DPL has requested that the rates become effective on January 31, 2012. In the 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), the filing includes a request for the DPSC to approve a reliability investment recovery mechanism (RIM) to recover reliability-related capital expenditures incurred between base rate cases. Through the RIM, DPL would collect in a surcharge the amount of its reliability-related capital expenditures based on its budget for the current 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 DPSC in the next base rate case or at more frequent intervals as determined by the DPSC. DPL's operating and maintenance costs and other capital expenditures would remain subject to recovery through the traditional ratemaking process. DPL has also requested DPSC approval of 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.

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%. In the effort to reduce regulatory lag, the filing includes a request for the MPSC to approve a RIM to recover reliability-related capital expenditures incurred between base rate cases. Through the RIM, DPL would collect in a surcharge the amount of its reliability-related capital expenditures based on its budget for the current 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 MPSC in the next base rate case or at more frequent intervals as determined by the MPSC. DPL's operating and maintenance costs and other capital expenditures would remain subject to recovery through the traditional ratemaking process. DPL has also requested MPSC approval of 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 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 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.

Regulatory Assets And Regulatory Liabilities

(6) REGULATORY MATTERS

Regulatory Assets and Regulatory Liabilities

The components of ACE's regulatory asset and liability balances at December 31, 2011 and 2010 are as follows:


	2011		2010
	*(millions of dollars)*
Regulatory Assets
Securitized stranded costs (a)	$	481	$	559
Deferred energy supply costs (a)		105		31
Deferred income taxes		27		29
Other		49		48

Total Regulatory Assets	$	662	$	667

Regulatory Liabilities
Excess depreciation reserve	$	26	$	42
Federal and New Jersey tax benefits, related to securitized stranded costs		19		22
Deferred energy supply costs		11		—
Other		4		7

Total Regulatory Liabilities	$	60	$	71

(a)	A return is generally earned on these deferrals.

A description for each category of regulatory assets and regulatory liabilities follows:

Securitized Stranded Costs: Includes contract termination payments under a contract between ACE and an unaffiliated NUG and costs associated with the regulated operations of ACE's electricity generation business which are no longer recoverable through customer rates. The recovery of these stranded costs has been securitized through the issuance of Transition Bonds by ACE Funding. A customer surcharge is collected by ACE to fund principal and interest payments on the Transition Bonds. The stranded costs are amortized over the life of the Transition Bonds, which mature between 2013 and 2023.

Deferred Energy Supply Costs: The regulatory asset represents primarily deferred costs associated with a net under-recovery of Default Electricity Supply costs incurred by ACE that are probable of recovery in rates. The regulatory liability represents primarily deferred costs associated with a net over-recovery of Default Electricity Supply costs incurred by ACE that will be refunded to customers.

Deferred Income Taxes: Represents a receivable from our customers for tax benefits ACE previously flowed through before the company was ordered to account for the tax benefits as deferred income taxes. As the temporary differences between the financial statement basis and tax basis of assets reverse, the deferred recoverable balances are reversed.

Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years.

Excess Depreciation Reserve: The excess depreciation reserve was recorded as part of an ACE New Jersey rate case settlement. This excess reserve is the result of a change in estimated depreciable lives and a change in depreciation technique from remaining life to whole life that caused an over-recovery for depreciation expense from customers when the remaining life method has been used. The excess is being amortized over an 8.25 year period, which began in June 2005.

Federal and New Jersey Tax Benefits, Related to Securitized Stranded Costs: Securitized stranded costs include a portion attributable to the future tax benefit expected to be realized when the higher tax basis of the generating facilities divested by ACE is deducted for New Jersey state income tax purposes, as well as the future benefit to be realized through the reversal of federal excess deferred taxes. To account for the possibility that these tax benefits may be given to ACE's customers through lower rates in the future, ACE established a regulatory liability. The regulatory liability related to federal excess deferred taxes will remain until such time as the Internal Revenue Service (IRS) issues its final regulations with respect to normalization of these federal excess deferred taxes.

Other: Includes miscellaneous regulatory liabilities.

Regulatory Proceedings

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, based on a return on equity of 10.75% (the ACE 2011 Base Rate Case). The net increase consists of a rate increase proposal of approximately $70.5 million, less a deduction from base rates of approximately $17 million attributable to excess depreciation expenses, plus approximately a $4.9 million increase in sales-and-use taxes and an upward adjustment of approximately $0.5 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 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. On December 15, 2011, the request for deferral of these costs was consolidated with ACE's pending base rate proceeding.