(7) REGULATORY MATTERS

Regulatory Assets and Regulatory Liabilities

The components of Pepco Holdings’ regulatory asset and liability balances at December 31, 2012 and 2011 are as follows:


	2012		2011
	*(millions of dollars)*
Regulatory Assets
Pension and OPEB costs (a)	$	1,171	$	1,037
Securitized stranded costs (a)		416		481
Smart Grid (a)		229		142
Deferred energy supply costs (a)		183		126
Recoverable income taxes		177		145
Incremental storm restoration costs		89		28
MAPP abandonment costs (a)		88		—
Deferred debt extinguishment costs (a)		53		57
Recoverable workers compensation and long-term disability costs		31		34
Deferred losses on gas derivatives		4		17
Other		173		129

Total Regulatory Assets	$	2,614	$	2,196

Regulatory Liabilities
Asset removal costs	$	324	$	388
Deferred energy supply costs		78		33
Deferred income taxes due to customers		45		48
Excess depreciation reserve		11		26
Other		43		31

Total Regulatory Liabilities	$	501	$	526

(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 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: Certain 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 are no longer recoverable through customer rates (collectively referred to as “stranded costs”). The stranded costs are amortized over the life of Transition Bonds issued by ACE Funding to securitize the recoverability of these stranded costs. These bonds mature between 2013 and 2023. A customer surcharge is collected by ACE to fund principal and interest payments on the Transition Bonds.

Smart Grid: Represents AMI costs associated with the installation of smart meters and the early retirement of existing meters throughout Pepco’s and DPL’s service territories that are recoverable from customers. Approval of AMI has been deferred by the NJBPU for ACE in New Jersey.

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 Income Taxes: Represents amounts recoverable from Power Delivery’s customers for tax benefits applicable to utility operations of Pepco, DPL and ACE previously recognized in income tax expense 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.

Incremental Storm Restoration Costs: Represents total incremental storm restoration costs incurred for repair work due to major storm events in 2012 and 2011, including Hurricane Sandy, the June 2012 derecho, Hurricane Irene and the 2011 severe winter storm (for Pepco), for which recovery through regulated utility rates is considered probable in the Maryland and New Jersey jurisdictions. Pepco’s and DPL’s costs related to Hurricane Irene and Pepco’s costs related to the 2011 severe winter storm are being amortized and recovered in rates over a five-year period. ACE’s costs related to Hurricane Irene are being amortized and recovered in rates over a three-year period.

MAPP Abandonment Costs: Represents the probable recovery of abandoned costs prudently incurred in connection with the Mid-Atlantic Power Pathway (MAPP) project which was terminated by PJM on August 24, 2012. The regulatory asset includes the costs of land, land rights, supplies and materials, engineering and design, environmental services, and project management and administration. The regulatory asset will be reduced as the result of sale or alternative use of these assets. These assets are currently earning a return of 12.8%.

Deferred Debt Extinguishment Costs: Represents the costs of debt extinguishment of Pepco, DPL and ACE associated with issuances of debt 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.

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. Accordingly, 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 assets applicable to utility operations of Pepco and DPL 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 had been used. The excess is being amortized as a reduction in Depreciation and amortization expense over an 8.25 year period, which began in June 2005 and expires in 2013.

Other: Includes miscellaneous regulatory liabilities.

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 BSA was approved and implemented for Pepco and DPL electric service in Maryland and for Pepco electric service in the District of Columbia. In October 2012, the MPSC modified the BSA so that a BSA surcharge is not permitted to be collected for revenues lost during the first 24 hours of a major storm. For further information on the BSA in Maryland, see “Maryland – BSA Proceeding” below.

•

A modified fixed variable rate design (MFVRD) for DPL electric and natural gas service in Delaware is under consideration by the DPSC.

•

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

Under the BSA, customer distribution rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the applicable public service commission. The MFVRD under consideration by the DPSC in Delaware provides for a fixed customer charge (i.e., not tied to the customer’s volumetric consumption of electricity or natural gas) 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 had proposed, in each of their respective jurisdictions, (i) a reliability investment recovery mechanism (RIM) to recover reliability-related capital expenditures incurred between base rate cases, and (ii) the use of fully forecasted test years in future rate cases (which reflect forward-looking costs in lieu of costs incurred over historical test years, and if approved, would be more reflective of current costs and would mitigate the effects of regulatory lag). These proposals were generally not adopted in any of the jurisdictions in which they were filed, as discussed below in connection with the discussions of Pepco’s and DPL’s respective electric distribution base rate proceedings.

Delaware

Gas Cost Rates

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

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

Electric Distribution Base Rates

In December 2011, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $31.8 million, based on a requested return on equity (ROE) of 10.75%, and requested approval of implementation of the MFVRD. The filing included a request for DPSC approval of a RIM and the use of fully forecasted test years in future DPL rate cases. In January 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. In July 2012, in accordance with an agreement with DPSC staff, DPL placed an additional $22.3 million of the requested rate increase into effect, also subject to refund and pending final DPSC order. On November 29, 2012, the DPSC approved a proposed settlement agreement entered into by DPL and the other parties to the proceeding that provides for an annual rate increase of $22 million, based on an ROE of 9.75%. The settlement agreement also permits DPL to collect from its standard offer service (SOS) customers (retail customers who do not elect to purchase electricity from a competitive supplier but instead purchase such electricity from DPL at regulated rates) approximately $3.4 million related to various state and local taxes that were assessed upon DPL’s SOS customers, but actually paid by DPL rather than by the SOS customers upon whom they were assessed. These taxes would be collected over a three-year period. In addition, the settlement agreement allows for the phase-in of the recovery of costs associated with DPL’s AMI system. The settlement agreement does not include approval of a RIM or the use of fully forecasted test years in future DPL rate cases, but it does provide that the parties will meet and discuss alternate regulatory methodologies for the mitigation of regulatory lag. DPL refunded the billed amounts that exceeded the increase approved by the DPSC in February 2013.

Gas Distribution Base Rates

On December 7, 2012, DPL submitted an application with the DPSC to increase its natural gas distribution base rates. The filing seeks approval of an annual rate increase of approximately $12.2 million, based on a requested ROE of 10.25%. The requested rate increase is for the purposes of recovering expenses associated with DPL’s ongoing efforts to maintain safe and reliable service and to provide enhanced customer service technology. In January 2013, the DPSC suspended the full proposed increase and, as permitted by state law, DPL implemented an interim increase of $2.5 million on February 5, 2013, subject to refund and pending final DPSC approval. In compliance with state law and DPSC regulations, DPL also is requesting from the DPSC approval of a Utility Facilities Relocation Charge rider for recovery of future costs associated with the relocation of certain gas delivery service facilities that may be requested by the Delaware Department of Transportation. A final DPSC decision is expected by the third quarter of 2013.

District of Columbia

In July 2011, Pepco filed an application with the DCPSC to increase its electric distribution base rates by approximately $42 million annually (subsequently reduced to approximately $39 million), based on a requested ROE of 10.75%, of which approximately $9 million was sought so that Pepco could recover its costs associated with the AMI system. The filing included a request for DCPSC approval of a RIM and the use of fully forecasted test years in future Pepco rate cases. On September 26, 2012, the DCPSC issued its decision approving a rate increase of $24 million, based on an ROE of 9.5%, of which approximately $9 million allows Pepco to recover costs associated with the AMI system. The DCPSC denied Pepco’s request for approval of a RIM, and reserved final judgment on the appropriateness of the use by Pepco of a fully forecasted test year in future rate cases. In addition, the DCPSC approved an adjustment by Pepco to normalize operation and maintenance expenses associated with storm restoration efforts to its three-year average, but added approximately $2 million of costs associated with Hurricane Irene from August 2011 in the calculation of the three-year average storm costs.

Maryland

DPL Electric Distribution Base Rates

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

Pepco Electric Distribution Base Rates

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

On November 30, 2012, 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 $60.8 million, based on a requested ROE of 10.25%. The requested rate increase is for the purpose of recovering reliability enhancements to serve Maryland customers. Pepco also proposes a three-year Grid Resiliency surcharge for recovery of costs totaling approximately $192 million associated with its plan to accelerate investments in infrastructure in a condensed timeframe. Acceleration of resiliency improvements is one of several recommendations included in a September 2012 report from Maryland’s Grid Resiliency Task Force (as discussed below). The surcharge, if approved, would become effective January 1, 2014 and would be implemented as a rider that is separate from base rates and would include a return on investment. Specific projects under Pepco’s plan include acceleration of its tree-trimming cycle, upgrade of 12 additional feeders per year for two years and undergrounding of six distribution feeders. In addition, Pepco proposes a reliability performance-based mechanism that would allow Pepco to earn up to $1 million as an incentive for meeting enhanced reliability goals in 2015, but provides a credit to customers of up to $1 million in total if Pepco does not meet at least the minimum targets. Pepco requests that any credits/charges would flow through the proposed Grid Resiliency Charge rider. An MPSC decision is expected by the end of the second quarter of 2013.

BSA Proceeding

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

New Jersey

Electric Distribution Base Rates

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

On December 11, 2012, ACE filed with the NJBPU an application, updated on January 4, 2013, to increase its electric distribution base rates by approximately $70.4 million (excluding sales-and-use taxes), based on a requested ROE of 10.25%. This proposed net increase was comprised of (i) a proposed increase to ACE’s distribution rates of approximately $72.1 million and (ii) a net decrease to ACE’s Regulatory Asset Recovery Charge (costs associated with deferred, NJBPU-approved expenses incurred as part of ACE’s obligation to serve the public) in the amount of approximately $1.7 million. The requested rate increase is for the purposes of continuing to implement reliability-related investments, recovering system restoration costs associated with the June derecho storm and Hurricane Sandy, and providing an opportunity to earn a reasonable rate of return on its investment. An NJBPU decision is expected by the fourth quarter of 2013.

Infrastructure Investment Program

In July 2009, the NJBPU approved certain rate recovery mechanisms in connection with ACE’s Infrastructure Investment Program (the IIP). In exchange for the increase in infrastructure investment, the NJBPU, through the IIP, allowed recovery by ACE of its infrastructure investment capital expenditures through a special rate outside the normal rate recovery mechanism of a base rate filing. The IIP was designed to stimulate the New Jersey economy and provide incremental employment in ACE’s service territory by increasing the infrastructure expenditures to a level above otherwise normal budgeted levels. In an October 18, 2011 petition (subsequently amended December 16, 2011) filed with the NJBPU, ACE requested an extension and expansion to the IIP. The New Jersey Settlement approved by the NJBPU provided for full cost recovery of ACE’s initial IIP, as approved by the NJBPU in 2009, but required ACE to withdraw its request for extension and expansion to the IIP, without prejudice to file such request again in the future. On November 8, 2012, ACE withdrew its request for extension and expansion to the IIP.

Update and Reconciliation of Certain Under-Recovered Balances

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

MPSC New Generation Contract Requirement

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

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

In April 2012, a group of generating companies operating in the PJM region filed a complaint in the U.S. District Court for the District of Maryland challenging the MPSC’s order on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In May 2012, Pepco, DPL, and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order. These appeals have been consolidated in the Circuit Court for Baltimore City and have been stayed pending the issuance of a final order from the MPSC approving the form of contract, including the payment obligations of the utilities in the event the utilities do not recover the costs for such payments from their customers.

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

Reliability Task Forces

In July 2012, the Maryland governor signed an Executive Order directing his energy advisor, in collaboration with certain state agencies, to solicit input and recommendations from experts on how to improve the resiliency and reliability of the electric distribution system in Maryland. The resulting Grid Resiliency Task Force issued its report in September 2012, in which it made 11 recommendations. The governor forwarded the report to the MPSC in October 2012, urging the MPSC to quickly implement the first four recommendations: (i) strengthen existing reliability and storm restoration regulations; (ii) accelerate the investment necessary to meet the enhanced metrics; (iii) allow surcharge recovery for the accelerated investment; and (iv) implement clearly defined performance metrics into the traditional ratemaking scheme. Pepco’s electric distribution base rate case filed with the MPSC on November 30, 2012, addresses the Grid Resiliency Task Force recommendations. DPL will consider the Grid Resiliency Task Force recommendations in its next electric distribution base rate case expected to be filed with the MPSC in the first quarter of 2013.

In August 2012, the District of Columbia mayor issued an Executive Order establishing the Mayor’s Power Line Undergrounding Task Force. The purpose of the Power Line Undergrounding Task Force is to pool the collective resources available in the District of Columbia to produce an analysis of the technical feasibility, infrastructure options and reliability implications of undergrounding new or existing overhead distribution facilities in the District of Columbia. These resources include legislative bodies, regulators, utility personnel, experts and other parties who could contribute in a meaningful way to the Power Line Undergrounding Task Force. The options that are available for financing these efforts are also to be evaluated to identify required legislative or regulatory actions to implement these recommendations. The results of this analysis are intended to help determine the path forward for these types of infrastructure improvements and additions. A written report from the Power Line Undergrounding Task Force setting forth the findings and recommendations was originally due on January 31, 2013 but has been extended to early March 2013.

ACE Standard Offer Capacity Agreements

In April 2011, ACE entered into three SOCAs by order of the NJBPU, each with a different generation company, as more fully described in Note (2), “Significant Accounting Policies – Consolidation of Variable Interest Entities – ACE Standard Offer Capacity Agreements” and Note (14), “Derivative Instruments and Hedging Activities.” ACE and the other New Jersey EDCs entered into the SOCAs under protest based on concerns about the potential cost to distribution customers. The dispute is pending before the NJBPU and has been referred to an Administrative Law Judge for further consideration.

In February 2011, ACE joined other plaintiffs in an action filed in the U.S. District Court for the District of New Jersey challenging the constitutionality of the New Jersey law under which the SOCAs were established. In September 2012, the District Court denied motions for summary judgment filed by ACE and the other plaintiffs, as well as cross-motions filed by defendants. The litigation remains pending and trial is tentatively scheduled to begin in March 2013.

MAPP Project

On August 24, 2012, the board of PJM terminated the MAPP project and removed it from PJM’s regional transmission expansion plan. PHI had been directed to construct the MAPP project, a 152-mile high-voltage interstate transmission line, to address the reliability needs of the region’s transmission system.

As of December 31, 2012, PHI’s total capital expenditures related to the MAPP project were approximately $102 million. In a 2008 FERC order approving incentives for the MAPP project, FERC authorized the recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, on December 21, 2012, PHI submitted a filing to FERC seeking recovery of approximately $88 million of abandoned MAPP capital expenditures. The FERC filing addressed, among other things, the prudence of the recoverable costs incurred, the proposed period over which the abandoned costs are to be amortized and the rate of return on these costs during the recovery period. Various protests have been submitted in response to the December 21, 2012 filing, arguing, among other things, that FERC should disallow a portion of the rate of return involving an incentive adder that would be applied to the abandonment costs, and requesting a hearing on various issues such as the amount of the ROE and the prudence of the costs. PHI cannot at this time estimate when a final FERC decision in this proceeding will be issued.

As of December 31, 2012, PHI had placed in service approximately $11 million of its total capital expenditures with respect to the MAPP project, which represented upgrades of existing substation assets that were expected to support the MAPP transmission line, transferred approximately $3 million of materials to inventories for use on other projects and reclassified the remaining approximately $88 million of capital expenditures to a regulatory asset. The regulatory asset includes the costs of land, land rights, supplies and materials, engineering and design, environmental services, and project management and administration. PHI intends to reduce the regulatory asset by any amounts recovered from the sale or alternative use of the land, land rights, supplies and materials.

Regulatory Matters

(6) REGULATORY MATTERS

Regulatory Assets and Regulatory Liabilities

The components of Pepco’s regulatory asset and liability balances at December 31, 2012 and 2011 are as follows:


	2012		2011
	*(millions of dollars)*
Regulatory Assets
Smart Grid (a)	$	159	$	96
Recoverable income taxes		75		57
MAPP abandonment costs (a)		50		—
Demand-side management		45		20
Incremental storm restoration costs		44		14
Recoverable workers’ compensation and long-term disability costs		31		34
Deferred debt extinguishment costs (a)		28		30
Deferred energy supply costs		4		4
Other		51		44

Total Regulatory Assets	$	487	$	299

Regulatory Liabilities
Asset removal costs	$	122	$	144
Other		19		25

Total Regulatory Liabilities	$	141	$	169

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

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

Smart Grid: Represents AMI costs associated with the installation of smart meters and the early retirement of existing meters throughout Pepco’s service territory that are recoverable from customers.

Recoverable Income Taxes: Represents amounts recoverable from Pepco’s customers for tax benefits applicable to utility operations that were previously recognized in income tax expense 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.

MAPP Abandonment Costs: Represents the probable recovery of abandoned costs prudently incurred in connection with the Mid-Atlantic Power Pathway (MAPP) project which was terminated on August 24, 2012. The regulatory asset includes the costs of land, land rights, supplies and materials, engineering and design, environmental services, and project management and administration. The regulatory asset will be reduced as the result of sale or alternative use of these assets. These assets are currently earning a return of 12.8%.

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

Incremental Storm Restoration Costs: Represents total incremental storm restoration costs incurred for repair work due to major storm events in 2012 and 2011, including Hurricane Sandy, the June 2012 derecho, Hurricane Irene, and the 2011 severe winter storm, for which recovery through regulated utility rates is considered probable in the Maryland jurisdictions. Pepco’s costs related to Hurricane Irene and the 2011 severe winter storm are being amortized and recovered in rates over a five-year 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.

Deferred Debt Extinguishment Costs: Represents the costs of debt extinguishment associated with issuances of debt 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 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.

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

Other: Includes miscellaneous regulatory liabilities.

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 BSA was approved and implemented for electric service in Maryland and the District of Columbia. In October 2012, the MPSC modified the BSA so that a BSA surcharge is not permitted to be collected for revenues lost during the first 24 hours of a major storm. For further information on the BSA in Maryland, see “Maryland – BSA Proceeding” 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 proposed, in each of its jurisdictions, (i) a reliability investment recovery mechanism (RIM) to recover reliability-related capital expenditures incurred between base rate cases, and (ii) the use of fully forecasted test years in future rate cases (which reflect forward-looking costs in lieu of costs incurred over historical test years, and if approved, would be more reflective of current costs and would mitigate the effects of regulatory lag). These proposals were generally not adopted in any of the jurisdictions in which they were filed, as discussed below in connection with the discussions of Pepco’s electric distribution base rate proceedings.

District of Columbia

In July 2011, Pepco filed an application with the DCPSC to increase its electric distribution base rates by approximately $42 million annually (subsequently reduced to approximately $39 million), based on a requested return on equity (ROE) of 10.75%, of which approximately $9 million was sought so that Pepco could recover its costs associated with the AMI system. The filing included a request for DCPSC approval of a RIM and the use of fully forecasted test years in future Pepco rate cases. On September 26, 2012, the DCPSC issued its decision approving a rate increase of $24 million, based on an ROE of 9.5%, of which approximately $9 million allows Pepco to recover costs associated with the AMI system. The DCPSC denied Pepco’s request for approval of a RIM, and reserved final judgment on the appropriateness of the use by Pepco of a fully forecasted test year in future rate cases. In addition, the DCPSC approved an adjustment by Pepco to normalize operation and maintenance expenses associated with storm restoration efforts to its three-year average, but added approximately $2 million of costs associated with Hurricane Irene from August 2011 in the calculation of the three-year average storm costs.

Maryland

Electric Distribution Base Rates

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

On November 30, 2012, 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 $60.8 million, based on a requested ROE of 10.25%. The requested rate increase is for the purpose of recovering reliability enhancements to serve Maryland customers. Pepco also proposes a three-year Grid Resiliency surcharge for recovery of costs totaling approximately $192 million associated with its plan to accelerate investments in infrastructure in a condensed timeframe. Acceleration of resiliency improvements is one of several recommendations included in a September 2012 report from Maryland’s Grid Resiliency Task Force (as discussed below). The surcharge, if approved, would become effective January 1, 2014 and would be implemented as a rider that is separate from base rates and would include a return on investment. Specific projects under Pepco’s plan include acceleration of its tree-trimming cycle, upgrade of 12 additional feeders per year for two years and undergrounding of six distribution feeders. In addition, Pepco proposes a reliability performance-based mechanism that would allow Pepco to earn up to $1 million as an incentive for meeting enhanced reliability goals in 2015, but provides a credit to customers of up to $1 million in total if Pepco does not meet at least the minimum targets. Pepco requests that any credits/charges would flow through the proposed Grid Resiliency Charge rider. An MPSC decision is expected by the end of the second quarter of 2013.

BSA Proceeding

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

MPSC New Generation Contract Requirement

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

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

In April 2012, a group of generating companies operating in the PJM Interconnection, LLC (PJM) region filed a complaint in the U.S. District Court for the District of Maryland challenging the MPSC’s order on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In May 2012, Pepco and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order. These appeals have been consolidated in the Circuit Court for Baltimore City and have been stayed pending the issuance of a final order from the MPSC approving the form of contract, including the payment obligations of the utilities in the event the utilities do not recover the costs for such payments from their customers.

Until the final form of the contract with the winning bidder and associated cost recovery are approved, Pepco cannot predict (i) the extent of the negative effect that the order and, once finalized, the contract for new generation may have on Pepco’s balance sheets, as well as its credit metrics, as calculated by independent rating agencies that evaluate and rate Pepco and each of its debt issuances, (ii) the effect on Pepco’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 Pepco.

Reliability Task Forces

In July 2012, the Maryland governor signed an Executive Order directing his energy advisor, in collaboration with certain state agencies, to solicit input and recommendations from experts on how to improve the resiliency and reliability of the electric distribution system in Maryland. The resulting Grid Resiliency Task Force issued its report in September 2012, in which it made 11 recommendations. The governor forwarded the report to the MPSC in October 2012, urging the MPSC to quickly implement the first four recommendations: (i) strengthen existing reliability and storm restoration regulations; (ii) accelerate the investment necessary to meet the enhanced metrics; (iii) allow surcharge recovery for the accelerated investment; and (iv) implement clearly defined performance metrics into the traditional ratemaking scheme. Pepco’s electric distribution base rate case filed with the MPSC on November 30, 2012, addresses the Grid Resiliency Task Force recommendations.

In August 2012, the District of Columbia mayor issued an Executive Order establishing the Mayor’s Power Line Undergrounding Task Force. The purpose of the Power Line Undergrounding Task Force is to pool the collective resources available in the District of Columbia to produce an analysis of the technical feasibility, infrastructure options and reliability implications of undergrounding new or existing overhead distribution facilities in the District of Columbia. These resources include legislative bodies, regulators, utility personnel, experts and other parties who could contribute in a meaningful way to the Power Line Undergrounding Task Force. The options that are available for financing these efforts are also to be evaluated to identify required legislative or regulatory actions to implement these recommendations. The results of this analysis are intended to help determine the path forward for these types of infrastructure improvements and additions. A written report from the Power Line Undergrounding Task Force setting forth the findings and recommendations was originally due on January 31, 2013, but has been extended to early March 2013.

MAPP Project

On August 24, 2012, the board of PJM terminated the MAPP project and removed it from PJM’s regional transmission expansion plan. PHI had been directed to construct the MAPP project, a 152-mile high-voltage interstate transmission line, to address the reliability needs of the region’s transmission system.

As of December 31, 2012, Pepco’s total capital expenditures related to the MAPP project were approximately $64 million. In a 2008 FERC order approving incentives for the MAPP project, FERC authorized the recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, on December 21, 2012, PHI submitted a filing to FERC seeking recovery of approximately $50 million of abandoned MAPP capital expenditures. The FERC filing addressed, among other things, the prudence of the recoverable costs incurred, the proposed period over which the abandoned costs are to be amortized and the rate of return on these costs during the recovery period. Various protests have been submitted in response to the December 21, 2012 filing, arguing, among other things, that FERC should disallow a portion of the rate of return involving an incentive adder that would be applied to the abandonment costs, and requesting a hearing on various issues such as the amount of the ROE and the prudence of the costs. Pepco cannot at this time estimate when a final FERC decision in this proceeding will be issued.

As of December 31, 2012, Pepco had placed in service $11 million of its total capital expenditures with respect to the MAPP project, which represented upgrades of existing substation assets that were expected to support the MAPP transmission line, transferred approximately $3 million of materials to inventories for use on other projects and reclassified the remaining $50 million of capital expenditures to a regulatory asset. The regulatory asset includes the costs of land, land rights, supplies and materials, engineering and design, environmental services, and project management and administration. Pepco intends to reduce the regulatory asset by any amounts recovered from the sale or alternative use of the land, land rights, supplies and materials.

Regulatory Matters

(7) REGULATORY MATTERS

Regulatory Assets and Regulatory Liabilities

The components of DPL’s regulatory asset and liability balances at December 31, 2012 and 2011 are as follows:


	2012		2011
	*(millions of dollars)*
Regulatory Assets
Recoverable income taxes	$	69	$	61
Smart Grid (a)		70		46
MAPP abandonment costs (a)		38		—
COPCO acquisition adjustment (a)		26		30
Deferred debt extinguishment costs (a)		15		16
Deferred energy supply costs (b)		13		16
Incremental storm restoration costs		11		6
Deferred losses on gas derivatives		4		17
Other		42		35

Total Regulatory Assets	$	288	$	227

Regulatory Liabilities
Asset removal costs	$	202	$	244
Deferred income taxes due to customers		38		38
Deferred energy supply costs		6		12
Other		12		3

Total Regulatory Liabilities	$	258	$	297

(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:

Recoverable Income Taxes: Represents amounts recoverable from DPL’s customers for tax benefits applicable to utility operations that were previously recognized in income tax expense 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.

Smart Grid: Represents advanced metering infrastructure (AMI) costs associated with the installation of smart meters and the early retirement of existing meters throughout DPL’s service territory that are recoverable from customers.

MAPP Abandonment Costs: Represents the probable recovery of abandoned costs prudently incurred in connection with the Mid-Atlantic Power Pathway (MAPP) project which was terminated on August 24, 2012. The regulatory asset includes the costs of land, land rights, supplies and materials, engineering and design, environmental services, and project management and administration. The regulatory asset will be reduced as the result of sale or alternative use of these assets. These assets are currently earning a return of 12.8%.

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%.

Deferred Debt Extinguishment Costs: Represents the costs of debt extinguishment associated with issuances of debt 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 costs associated with a net under-recovery of Default Electricity Supply costs incurred by DPL 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 DPL to customers.

Incremental Storm Restoration Costs: Represents total incremental storm restoration costs incurred for repair work due to major storm events in 2012 and 2011, including Hurricane Sandy, the June 2012 derecho, and Hurricane Irene, for which recovery through regulated utility rates is considered probable in the Maryland jurisdiction. DPL’s costs related to Hurricane Irene are being amortized and recovered in rates over a five-year period.

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 DPL include a component for removal costs, as approved by the relevant federal and state regulatory commissions. Accordingly, DPL has recorded regulatory liabilities 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 assets applicable to utility operations of DPL 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.

Rate Proceedings

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

•

A BSA was approved and implemented for electric service in Maryland. In October 2012, the MPSC modified the BSA so that a BSA surcharge is not permitted to be collected for revenues lost during the first 24 hours of a major storm. For further information on the BSA in Maryland, see “Maryland – BSA Proceeding” below.

•

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

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

In an effort to reduce the shortfall in revenues due to the delay in time or lag between when costs are incurred and when they are reflected in rates (regulatory lag), DPL proposed, in each of its jurisdictions, (i) a reliability investment recovery mechanism (RIM) to recover reliability-related capital expenditures incurred between base rate cases, and (ii) the use of fully forecasted test years in future rate cases (which reflect forward-looking costs in lieu of costs incurred over historical test years, and if approved, would be more reflective of current costs and would mitigate the effects of regulatory lag). These proposals were generally not adopted in any of the jurisdictions in which they were filed, as discussed below in connection with the discussions of DPL’s electric distribution base rate proceedings.

Delaware

Gas Cost Rates

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

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

Electric Distribution Base Rates

In December 2011, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $31.8 million, based on a requested return on equity (ROE) of 10.75%, and requested approval of implementation of the MFVRD. The filing included a request for DPSC approval of a RIM and the use of fully forecasted test years in future DPL rate cases. In January 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. In July 2012, in accordance with an agreement with DPSC staff, DPL placed an additional $22.3 million of the requested rate increase into effect, also subject to refund and pending final DPSC order. On November 29, 2012, the DPSC approved a proposed settlement agreement entered into by DPL and the other parties to the proceeding that provides for an annual rate increase of $22 million, based on an ROE of 9.75%. The settlement agreement also permits DPL to collect from its standard offer service (the supply of electricity by Pepco at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier) (SOS) customers (retail customers who do not elect to purchase electricity from a competitive supplier but instead purchase such electricity from DPL at regulated rates) approximately $3.4 million related to various state and local taxes that were assessed upon DPL’s SOS customers, but actually paid by DPL rather than by the SOS customers upon whom they were assessed. These taxes would be collected over a three-year period. In addition, the settlement agreement allows for the phase-in of the recovery of costs associated with DPL’s AMI system. The settlement agreement does not include approval of a RIM or the use of fully forecasted test years in future DPL rate cases, but it does provide that the parties will meet and discuss alternate regulatory methodologies for the mitigation of regulatory lag. DPL refunded the billed amounts that exceeded the increase approved by the DPSC in February 2013.

Gas Distribution Base Rates

On December 7, 2012, DPL submitted an application with the DPSC to increase its natural gas distribution base rates. The filing seeks approval of an annual rate increase of approximately $12.2 million, based on a requested ROE of 10.25%. The requested rate increase is for the purposes of recovering expenses associated with DPL’s ongoing efforts to maintain safe and reliable service and to provide enhanced customer service technology. In January 2013, the DPSC suspended the full proposed increase and, as permitted by state law, DPL implemented an interim increase of $2.5 million on February 5, 2013, subject to refund and pending final DPSC approval. In compliance with state law and DPSC regulations, DPL also is requesting from the DPSC approval of a Utility Facilities Relocation Charge rider for recovery of future costs associated with the relocation of certain gas delivery service facilities that may be requested by the Delaware Department of Transportation. A final DPSC decision is expected by the third quarter of 2013.

Maryland

Electric Distribution Base Rates

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

BSA Proceeding

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

MPSC New Generation Contract Requirement

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

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

In April 2012, a group of generating companies operating in the PJM Interconnection, LLC (PJM) region filed a complaint in the U.S. District Court for the District of Maryland challenging the MPSC’s order on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In May 2012, DPL and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order. These appeals have been consolidated in the Circuit Court for Baltimore City and have been stayed pending the issuance of a final order from the MPSC approving the form of contract, including the payment obligations of the utilities in the event the utilities do not recover the costs for such payments from their customers.

Until the final form of the contract with the winning bidder and associated cost recovery are approved, DPL cannot predict (i) the extent of the negative effect that the order and, once finalized, the contract for new generation may have on DPL’s balance sheets, as well as its credit metrics, as calculated by independent rating agencies that evaluate and rate DPL and each of its debt issuances, (ii) the effect on 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 DPL.

Maryland Governor’s Grid Resiliency Task Force

In July 2012, the Maryland governor signed an Executive Order directing his energy advisor, in collaboration with certain state agencies, to solicit input and recommendations from experts on how to improve the resiliency and reliability of the electric distribution system in Maryland. The resulting Grid Resiliency Task Force issued its report in September 2012, in which it made 11 recommendations. The governor forwarded the report to the MPSC in October 2012, urging the MPSC to quickly implement the first four recommendations: (i) strengthen existing reliability and storm restoration regulations; (ii) accelerate the investment necessary to meet the enhanced metrics; (iii) allow surcharge recovery for the accelerated investment; and (iv) implement clearly defined performance metrics into the traditional ratemaking scheme. DPL will consider the Grid Resiliency Task Force recommendations in its next electric distribution base rate case expected to be filed with the MPSC in the first quarter of 2013.

MAPP Project

On August 24, 2012, the board of PJM terminated the MAPP Project and removed it from PJM’s regional transmission expansion plan. PHI had been directed to construct the MAPP project, a 152-mile high-voltage interstate transmission line, to address the reliability needs of the region’s transmission system.

As of December 31, 2012, DPL’s total capital expenditures related to the MAPP project were approximately $38 million. In a 2008 FERC order approving incentives for the MAPP project, FERC authorized the recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, on December 21, 2012, PHI submitted a filing to FERC seeking recovery of approximately $38 million of abandoned MAPP capital expenditures. The FERC filing addressed, among other things, the prudence of the recoverable costs incurred, the proposed period over which the abandoned costs are to be amortized and the rate of return on these costs during the recovery period. Various protests have been submitted in response to the December 21, 2012 filing, arguing, among other things, that FERC should disallow a portion of the rate of return involving an incentive adder that would be applied to the abandonment costs, and requesting a hearing on various issues such as the amount of the ROE and the prudence of the costs. DPL cannot at this time estimate when a final FERC decision in this proceeding will be issued.

As of December 31, 2012, DPL had reclassified all $38 million of capital expenditures with respect to the MAPP project to a regulatory asset. The regulatory asset includes the costs of land, land rights, engineering and design, environmental services, and project management and administration. DPL intends to reduce the regulatory asset by any amounts recovered from the sale or alternative use of the land and land rights.

Regulatory Matters

(6) REGULATORY MATTERS

Regulatory Assets and Regulatory Liabilities

The components of ACE’s regulatory asset and liability balances at December 31, 2012 and 2011 are as follows:


	2012		2011
	*(millions of dollars)*
Regulatory Assets
Securitized stranded costs (a)	$	416	$	481
Deferred energy supply costs (a)		166		105
Incremental storm restoration costs		34		8
Recoverable income taxes		33		27
ACE SOCAs		11		—
Other		34		41

Total Regulatory Assets	$	694	$	662

Regulatory Liabilities
Deferred energy supply costs	$	62	$	11
Federal and state tax benefits, related to securitized stranded costs		16		19
Excess depreciation reserve		11		26
ACE SOCAs		8		—
Other		5		4

Total Regulatory Liabilities	$	102	$	60

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

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

Securitized Stranded Costs: Certain 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 are no longer recoverable through customer rates (collectively referred to as “stranded costs”). The stranded costs are amortized over the life of Transition Bonds issued by ACE Funding to securitize the recoverability of these stranded costs. These bonds mature between 2013 and 2023. A customer surcharge is collected by ACE to fund principal and interest payments on the Transition Bonds.

Deferred Energy Supply Costs: The regulatory asset represents primarily deferred costs associated with a net under-recovery of Basic Generation Service 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 Basic Generation Service costs incurred that will be refunded by ACE to customers.

Incremental Storm Restoration Costs: Represents total incremental storm restoration costs incurred for repair work due to major storm events in 2012 and 2011, including Hurricane Sandy, the June 2012 derecho, and Hurricane Irene, for which recovery through regulated utility rates is considered probable in the New Jersey jurisdiction. ACE’s costs related to Hurricane Irene are being amortized and recovered in rates over a three-year period.

Recoverable Income Taxes: Represents amounts recoverable from ACE’s customers for tax benefits applicable to utility operations previously recognized in income tax expense 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.

ACE SOCAs: The regulatory asset represents unrealized losses associated with SOCAs that ACE entered into by order of the NJBPU. The NJBPU has ordered full recovery from distribution customers of payments made by ACE related to the SOCAs. Since these unrealized losses are non-cash, the related regulatory asset does not earn a return. The regulatory liability represents unrealized gains associated with the SOCAs that ACE entered into by order of the NJBPU. The NJBPU has ordered that any amounts that ACE receives related to the SOCAs be remitted to its distribution customers.

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

Federal and State 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.

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 had been used. The excess is being amortized as a reduction in Depreciation and amortization expense over an 8.25 year period, which began in June 2005 and expires in 2013.

Other: Includes miscellaneous regulatory liabilities.

Rate Proceedings

Electric Distribution Base Rates

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

On December 11, 2012, ACE filed with the NJBPU an application, updated on January 4, 2013, to increase its electric distribution base rates by approximately $70.4 million (excluding sales-and-use taxes), based on a requested ROE of 10.25%. This proposed net increase was comprised of (i) a proposed increase to ACE’s distribution rates of approximately $72.1 million and (ii) a net decrease to ACE’s Regulatory Asset Recovery Charge (costs associated with deferred, NJBPU-approved expenses incurred as part of ACE’s obligation to serve the public) in the amount of approximately $1.7 million. The requested rate increase is for the purposes of continuing to implement reliability-related investments, recovering system restoration costs associated with the June derecho storm and Hurricane Sandy, and providing an opportunity to earn a reasonable rate of return on its investment. An NJBPU decision is expected by the fourth quarter of 2013.

Infrastructure Investment Program

In July 2009, the NJBPU approved certain rate recovery mechanisms in connection with ACE’s Infrastructure Investment Program (the IIP). In exchange for the increase in infrastructure investment, the NJBPU, through the IIP, allowed recovery by ACE of its infrastructure investment capital expenditures through a special rate outside the normal rate recovery mechanism of a base rate filing. The IIP was designed to stimulate the New Jersey economy and provide incremental employment in ACE’s service territory by increasing the infrastructure expenditures to a level above otherwise normal budgeted levels. In an October 18, 2011 petition (subsequently amended December 16, 2011) filed with the NJBPU, ACE requested an extension and expansion to the IIP. The New Jersey Settlement approved by the NJBPU provided for full cost recovery of ACE’s initial IIP, as approved by the NJBPU in 2009, but required ACE to withdraw its request for extension and expansion to the IIP, without prejudice to file such request again in the future. On November 8, 2012, ACE withdrew its request for extension and expansion to the IIP.

Update and Reconciliation of Certain Under-Recovered Balances

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

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 – Standard Offer Capacity Agreements” and Note (12), “Derivative Instruments and Hedging Activities.” ACE and the other New Jersey EDCs entered into the SOCAs under protest based on concerns about the potential cost to distribution customers. The dispute is pending before the NJBPU and has been referred to an Administrative Law Judge for further consideration.

In February 2011, ACE joined other plaintiffs in an action filed in the U.S. District Court for the District of New Jersey challenging the constitutionality of the New Jersey law under which the SOCAs were established. In September 2012, the District Court denied motions for summary judgment filed by ACE and the other plaintiffs, as well as cross-motions filed by defendants. The litigation remains pending and trial is tentatively scheduled to begin in March 2013.