Pepco and Delmarva Power Maryland Residential Demand Response Program Proposal Working Group Meeting February 26, 2008

Rationale For Demand Response Filing Programs are cost-effective Mitigate regional wholesale market electric capacity and energy prices Offset program costs through participation in PJM DR capacity and energy markets Help preserve the reliability of electricity supply Reduce future generation supply requirements Enable customers to better manage their electricity costs Help the State meet EmPOWER Maryland goals Availability of new direct load control technology Responsive to Commission Letter Order of January 3, 2008

Regulatory Overview of PHI DSM Maryland Proposals March 21, 2007 - Pepco and DPL “Blueprint for the Future” Filings July 19, 2007 - Collaborative Filing on Fast Track DSM Programs September 19, 2007 - PSC Approval of Maryland Residential Lighting Efficiency Program and Supporting Energy Awareness Campaign October 26, 2007 - Pepco and DPL Comprehensive DSM Program to Meet EmPower Maryland Goals February 15, 2008 - Pepco and DPL File Residential Direct Load Control Program

EmPOWER Maryland Goals Reduce electricity consumption by 15% by 2015 Reduce peak electricity demand by 15% by 2015 Carbon reduction goal of 35 billion pounds of CO2 According to MEA over 25 billion kilowatt hours is equivalent to: Saving Maryland $1.8 billion in avoided electricity costs by 2015; Conserving enough energy to provide electricity to 1.8 million households for one year; Averting the need for 2 new large scale (500 MW) power plants; and Taking 3 million cars off the road

Maryland Amid Transmission Congestion Source: U.S. Department of Energy, 2007

Energy Market Price Benefits: Theory Spot Price Demand With DR Demand Without DR P1 Energy Market Price Benefits to Customers Clearing Price is Higher without DR Value of Avoided Generation P2 Clearing Price is Lower with DR P* Supply Underlying Demand Curve Q* Q2 Q1 Quantity

Recent PJM Regional Capacity Market Results

Residential Direct Load Control Program Advanced direct load control technology will be installed on residential central air conditioners and heat pumps to reduce summer peak electric demand Participation is voluntary Participants may choose either an outdoor cycling switch or an indoor “smart” programmable thermostat Residential customers may select one of three cycling options, whereby a participating customer’s air conditioner/heat pump compressor will be cycled off 50%, 75%, or 100% during each half hour period

Residential Direct Load Control Program (continued) Upfront customer installation incentive of either $40, $60, or /$80 Annual participation incentives are a minimum of $40, $60 or $80, greater if market earnings are higher Participate in both PJM capacity and energy markets RPM market capacity participation in May 2008 for 2011 RPM auction Demand reduction capability beginning in 2009 In the future, direct load control technology will be coupled with planned AMI System

Pepco/DPL MD Key Project Milestones Milestone Target Date Commission Demand Response Program Approval March 14, 2008 PJM RPM BRA May 5, 2008 Equipment Vendor Selection 3rd Quarter 2008 Installer Vendor Selection 3rd Quarter 2008 Launch Participant Recruitment 4th Quarter 2008 Start Date of Equipment Installation 1st Quarter 2009 NOTE: Approval must be received by March 21, 2008 to permit the Company’s participation in the May 5, 2008 RPM BRA per the PJM market rules.

Pepco Projected Participants, Measures and Savings

Delmarva Projected Participants, Measures and Savings

Projected Participants, Measures and Savings Delmarva residential participation rate is 28% versus Pepco’s 33% of all residential customers based upon historic Energy For Tomorrow and Kilowatchers Programs Total Number of Smart Thermostats projected to be 70% of Total Participation, and Outdoor Switches is 30% of Total Participation Customer participation: 50% for 50% cycling 30% for 75% cycling 20% for 100% cycling Approximately 1 percent of participants assumed to have more than one central air conditioner/heat pump The average assumed KW load for a central air conditioner or heat pump compressor (sourced from utility sponsored PJM LBNL study): .80 kw for 50% cycling 1.38 kw for 75% cycling 2.06 kw for 100% cycling 1.23 kw average impact per participant Rollout schedule developed based upon expected vendor capability

Pepco Estimated Program Costs

Delmarva Estimated Program Costs

Pepco and Delmarva Estimated Annual Program Costs Column Descriptions (A) Installed costs for outside switches and programmable thermostats (B) Marketing expenses (includes one-time participant enrollment) (C) Contracted services, such as installation management and scheduling, quality assurance, and any warranty issues (D) Estimated monthly bill credits (E) Administrative costs (F) Maintenance costs associated with installed switches and thermostats (G) Measurement, verification and program evaluation costs (H) Total yearly program costs

Participant Financial Incentives Enrollment/Installation Incentive Rapid enrollment - Critical to this Demand Resource Program, a One Time Installment Enrollment credit will be paid per direct load control device. In exchange for the above credit, a participant will have to stay enrolled in the program for a minimum of one year. Annual Incentive Minimize Attrition, The Annual Fixed Credit is geared to reward those participants who stay with the program for many years. The Annual Credits will be paid over the June through October billing months. Annual Fixed Credit will be adjusted to reflect 70% of projected capacity market value each year. Participants will be notified in the spring of each year. All financial incentives will be in the form of a utility bill credit to the participants electric service account.

Participant Financial Incentives Continued   DLC-50% DLC-75% DLC-100% One Time Enrollment Installment Credit $40.00 $60.00 $80.00 Annual Fixed Credit 70% of Capacity Market Value Annual Minimum

RIDER “R-DLC” General Provisions 1. A smart thermostat(s) or radio controlled switch(es) and associated equipment will be installed on the residential customer's central air conditioner or central heat pump equipment for the purpose of cycling control as described below. 2. Customer may select one of the following three demand response options: RESIDENTIAL DLC-50% CYCLING - Whereby a participating residential customer’s air conditioner compressor will be cycled off for 15 minutes of each half hour period. RESIDENTIAL DLC-75% CYCLING - Air conditioner compressor cycled off for 22.5 minutes of each half hour period. RESIDENTIAL DLC-100% CYCLING - Air conditioner compressor cycled off completely during each half hour period.

RIDER “R-DLC”- Continued 3. The Company may exercise cycling control for the following reasons: 1) test cycling equipment, 2) response to a PJM dispatcher request to activate the program, 3) response to local DPL electric system constraints, or 4) response to regional energy market prices. Participant override of cycling events will be limited to two events annually and are not permitted during PJM initiated cycling events.

RIDER “R-DLC”- Bill Credits 4. The customer will receive the following applicable bill credits while participating in the program. The Annual Fixed Credit is paid proportionally during the June through October billing months. In exchange for the One Time Installment Credit, participants will be required to remain enrolled in the program option for a minimum of one year.

RIDER “R-DLC”- Bill Credits   DLC-50% DLC-75% DLC-100% One Time Enrollment Installment Credit $40.00 $60.00 $80.00 Annual Fixed Credit 70% of Capacity Market Value Minimum

PJM Market Participation Capacity PJM Forward Market Interruptible Load for Reliability (“ILR”) Market Bilateral RPM Base Residual Auction (BRA) occurs three years prior to delivery Energy – Day Ahead/Real Time Location Marginal Pricing (LMP)

PJM Capacity Earnings Earnings Assumptions: 96 percent of projected participant program capacity, 75 percent bid into the forward RPM BRA capacity market, 25 percent bid into the PJM ILR market, Based on recent PJM regional prices. Pepco Calculation Example {[(206 MW)*(75%)*($174.29)*(365)] + [(206 MW)*(25%)*($140.16)*(365)]}*(96% DR Availability) Delmarva Calculation Example {[(67 MW)*(75%)*($178.57)*(365)] + [(67MW)*(25%)*($177.51)*(365)]}* (96% DR Availability)

Cost-Effectiveness Measure Impact Estimation Demand response savings for each of the measures identified are based upon the Lawrence Berkeley National Laboratory Study, as described in the Company’s February 15, 2008 filing. Annual Energy Savings for Smart Thermostats: The baseline building definitions and each individual DSM measure were entered into the DOE2.1E energy simulation modeling program. Program Cost Estimation Projected program cost estimates were based upon currently available pricing data and projected customer participation levels. Actual program costs will vary depending upon actual customer participation levels and vendor pricing.

Cost-Effectiveness (continued) Market Potential Estimation Market potential estimates used in the analysis were projected based upon the Company’s historic residential cycling penetration rates. Estimated savings of 325KWh from the programmable thermostat.

Cost-Effectiveness (continued) Cost-Effectiveness Screening Program-level calculation of cost-effectiveness was completed for four tests – the Societal Cost Test, the All Ratepayers Test (Total Resource Cost Test), the Ratepayer Impact Measure Test, and the Participants Cost Test. These tests include consideration of program administrator costs, incentive levels, incremental costs, and measure impacts.

Cost-Effectiveness (continued) For all tests, cost-effectiveness was calculated using the lifetime impacts of first-year installations. All benefit and cost components used in these tests are proportional to the number of installations. Using first-year installations produces cost-effectiveness values that are considered representative of all years.

Four Cost-Effectiveness Tests The Societal Cost Test (SCT) is identical to the All Ratepayers Test used in the past, except that the SCT accounts for externalities and uses a different societal (discount) rate. The All Ratepayers Test compares the total costs of the program, including participant and utility costs, to the total benefits, excluding the effect of externalities. The Rate Impact Measure Test compares demand side program impacts on electricity rates due to changes in utility revenue and program costs to the costs that are avoided. The Participant Test compares the benefits and costs for program participants and serves as a guide for program design.

Key Economic Parameters Used in Calculating The Societal Cost Test (SCT) Values

Key Economic Parameters Used in Calculating ART Values

Key Economic Parameters Used in Calculating RIM Values

Key Economic Parameters Used in Calculating Participant Cost Test

Price Mitigation Impact Brattle Developed Price Mitigation Impacts for Delmarva Power and Pepco. Pepco: $7,000 to $89,000 per MW energy price savings Statewide: $15,800 to $194,235 per MW energy price savings DPL: $2,136 to $42,629 of energy price savings Statewide: $6,450 to $109,813 per MW energy price savings

Pepco Residential Direct Load Control Program Cost-Effectiveness Excluding Price Mitigation

Pepco Residential Direct Load Control Program Cost-Effectiveness with Price Mitigation, Maryland Pepco Only

Pepco Direct Load Control Program Cost-Effectiveness with Price Mitigation All Maryland Electricity Consumers

Delmarva Power Residential Direct Load Control Program Cost-Effectiveness Excluding Price Mitigation

Delmarva Power Residential Direct Load Control Program Cost-Effectiveness with Price Mitigation Maryland Delmarva Power Only

Delmarva Power Residential Direct Load Control Program Cost-Effectiveness with Price Mitigation All Maryland Electricity Consumers

Proposed Cost Recovery Establish Regulatory Asset for Equipment Installation Costs Recover Equipment Installation Costs over 15 Year Amortization Period Begin Cost Recovery when Useful Life Begins – 2009 Expense Annual Program O&M and Credit Costs Annual Market Earnings to Offset a Portion of Program Costs Market earnings in excess of costs to be shared with customers Costs/Market Earnings to Flow through DSM Surcharge to Residential Distribution Customers Utility Bonus Opportunity Only when Market Earnings Exceed Program Costs