1. SMECO Demand Response filing
March 18, 2008

2. SMECO Filing Components
Background
Current Load Management
Load Management Program with Comverge
Customer Participation & Operation
Cost/Benefit Review
SMECO Cost/Benefit recovery

3. Background
EmPower Maryland establishes a goal of 15% statewide reduction in electric usage by 2015
SMECO filed reduction plan on January 11, 2008 outlining energy efficiency, conservation, and demand response efforts
Demand Response plan filed March 18, 2008

4. Current Load Management
SMECO current Load Management system employs switches on approximately 61,000 air conditioners and water heaters
Legacy program began in 1986
Provides 11 MWs of capacity credit in the PJM ILR program
Customers receive incentive payments of $5/month for AC & $2.50/moth for WH

5. Comverge Load Management Program
A Virtual Peaking Capacity (VPC) contract has been executed with Comverge
Comverge currently has over 4.5 million devices with over 500 US utility clients; 495 MW of capacity currently contracted

6. Covmerge Load Management Program
New program will give customers the choice of a Smart Thermostat or Digital Control Unit (DCU) air conditioner switch
Approach will be to target both existing Load Management customers and new customers
Target of 50 MW by 2011
Based on 28% participation rate and 1.25kW/device

7. Comverge Contract

8. Initial Incentive & Cycling Plan
Customers who opt for the Smart Thermostat will receive a $50 annual incentive
Those opting for the digital switch will receive a $25 annual incentive
Thermostats use 2 degree offset followed by 30% cycling
Switches use 50% cycling followed by 30%

9. Ongoing Cycling & Penetration
SMECO and Comverge will work collaboratively to establish control strategies that are best suited to encourage participation among various subgroups
SMECO has a history of high penetration rates among residential customers

10. DR Benefit Computation

11. Benefit Computations ILR/DR Revenue calculation
SMECO will receive capacity credit for MWs registered in the PJM Interruptible Load Response Program
SMECO will receive capacity credit for MWs offered into the PJM Reliability Pricing Model auctions beginning in Planning Year
Total ILR revenue through September 2017 of $7,402,373 (NPV $5,701,828); Total DR Capacity Revenue through September 2017 of $22,031,626 (NPV $12,261,077)

12. Benefit Computations Reduction in Capacity Costs
Demand response capacity will contribute to lower RPM clearing prices
Price reduction impacts SMECO’s total capacity obligation (950 MW in 2011)
Total reduction in capacity costs: $27,140,215 (NPV $14,851,140)
Reduction in Peak Hour Energy Costs
Project avoiding 50 MW for 100 peak summer hours
Projected energy costs savings of $15,896,251 (NPV $8,926,162)

13. Benefit Computations
Reduction in Network Integration Transmission Service (NITS) and Other Supporting Facilities (OSF) Charges
Reducing the MW measured during the coincident peak load for summer periods will reduce our NITS and OSF obligations
Price savings over the course of the VPC contract total $6,501,587 (NPV $3,777,186)

14. DR Cost Computations

15. Cost Computations SMECO Direct Costs Payment for Legacy Switches
Includes contractual costs of installation and maintenance of switches & thermostats, customer incentive payments, and administrative costs Total: $44,442,577 (NPV $27,523,053)
Payment for Legacy Switches
SMECO will receive revenue for removal of existing Legacy air conditioner and water heater switches Total: ($1,672,70,6) (NPV $1,341,804)

16. Cost Computations Depreciation of Legacy Switches
Remaining depreciation value of existing Load Management equipment recovered over the course of the current contract
Total: $1,996,211 (NPV $1,317,804)
Current Incentive Reductions
Early phase out of current Legacy program will reduce incentive payments
Total: ($9,322,384) (NPV ($6,091,366))

17. Program Cost/Benefit Totals
Total cost to SMECO for implementation of VPC program through 9/17: $35,443,698
Total estimated benefits to SMECO through 9/17: $78,972,051 Benefit to Cost ratio of 2.13 to 1 (using Net Present Value)
Other potential benefits not estimated:
PJM ancillary costs
Peak period forward energy charges

18. Cost/Benefit Graph

19. Participant vs. Nonparticipant Bill Impact

20. Sensitivities (Benefit/Cost ratio)

21. Sensitivities (Benefit/Cost ratio w/out depreciation & incentive reductions)

22. Benefit Recovery PJM Invoice Credits Reduction in RPM price
ILR and RPM Capacity Payments
Flows through SOS
Allocated based on DR Capacity
Reduction in RPM price
No direct cost determination
Reduced SOS requirement
Net SOS impact to all classes

23. DR Cost Recovery Direct Costs – Contact & Administrative Charges
Recovered through DRCRF operating same as DSMCRF
Based on estimated costs with annual true-up mechanism
One year recovery of expenses
Includes depreciation of Legacy switches
Includes credit for Legacy payments
Incentive Reduction
Current incentives to Legacy program customers
Will automatically drop off as payments end
PPCA factor will automatically adjust

24. DR Revenue Stabilization
Recover Transmission and Distribution revenue requirement
Annual estimate of DR program impact
Customer charge basis to spread evenly and match costs