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

2. 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

3. 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

4. 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

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

6. 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

7. Recent PJM Regional Capacity Market Results

8. 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

9. 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

10. 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 rd Quarter 2008
Installer Vendor Selection rd Quarter 2008
Launch Participant Recruitment th Quarter 2008
Start Date of Equipment Installation st 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.

11. Pepco Projected Participants, Measures and Savings

12. Delmarva Projected Participants, Measures and Savings

15. 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

16. Pepco Estimated Program Costs

17. Delmarva Estimated Program Costs

18. 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

19. 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.

20. 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

21. 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.

22. 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.

23. 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.

24. 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

25. 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)

26. 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)

27. 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.

28. 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.

29. 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.

30. 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.

31. 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.

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

33. Key Economic Parameters Used in Calculating ART Values

34. Key Economic Parameters Used in Calculating RIM Values

35. Key Economic Parameters Used in Calculating Participant Cost Test

36. 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

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

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

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

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

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

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

43. 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