California’s Proposed DR Cost-Effectiveness Framework January 30, 2008

1. California’s Proposed DR Cost-Effectiveness Framework January 30, 2008

2. Background • January 2007 – DR proceeding opened at the CPUC • Phase 1: DR load impact protocols & cost-effectiveness • IOUs, DR providers, and others submitted straw proposals on cost-effectiveness methodologies • Proposals focused on CA’s EE Standard Practice Manual as starting point for DR evaluation • Straw proposals intended to focus on methodology – not inputs – since avoided costs were to be addressed in a different proceeding/forum • Several areas of disagreement among parties with regard to C-E methodologies proposed • Settlement-style discussions to develop proposed evaluation “framework” • All signing parties reserved the right to contest details if framework approved and applied • Data sources • Assumptions • Modifications to approach • Final decision from CPUC on framework expected Spring 2008

3. Purpose of DR Evaluation Framework • As an ex ante evaluation both event (e.g. dispatchable) and non-event (e.g. tariff pricing) based DR programs • To be used to evaluate the CA Utilities 2009 – 2011 DR program portfolios to be filed by June 1, 2008 • To be used to evaluate 3rd party DR providers and other programs outside of the utilities’ portfolios • To represent the most up-to-date and accurate measurement of DR program costs and benefits • To establish a flexible framework for future evaluation of DR programs to accurately reflect their attributes

4. Analytical Approach • DR resources to be evaluated to the extent they can reduce the need for supply-side resources • Reduce peak system loads • Meet resource adequacy/reserve requirements • Other benefits • Evaluate DR from four perspectives • Total Resource Cost (TRC): Utilities’ primary screening test • Program Administrator (PAC): Potential supplemental screening test • Ratepayer Impact Measure (RIM) • Participant (PCT) • Incentive costs offset customer costs for voluntary programs • Assumption required because participating customers’ costs difficult to accurately determine • Lifecycle analysis comparing the net present values of benefits and costs

5. Avoided Generation Capacity Costs • Annual market price ($/kW) of the capacity of a new combustion turbine • Increased by: return, income taxes, depreciation, O&M, taxes, insurance and other incremental costs • Reduced by: gross margins earned by selling energy by employing option pricing methodology or production cost modeling analysis • Will account for service-area-specific CT construction and fixed environmental costs and inter-regional differences in wholesale electricity prices • DR programs with no usage or availability constraints, avoided capacity cost value = full annualized and adjusted CT cost • For DR programs with availability constraints, value is determined by allocating CT costs across the highest-valued periods when program is available • CT costs account for DR’s preference in CA’s loading order such that no adjustment is made when reserve margins are expected to be exceeded (within reasonable limits)

6. Avoided Energy Costs • Value of avoided energy costs may be determined by: • Wholesale energy prices averaged over the forecast’s highest-priced hours • Stochastic method reflecting the correlation between electricity prices and the periods when DR events expected to occur and be available • Avoided energy costs will take into account: • Avoided line losses • Incremental costs of any additional demand resulting from load-shifting programs • Avoided congestion costs after CA’s MRTU provides sufficient locational marginal pricing data (future input expected 2012 – 2014 program funding cycle)

7. Avoided T&D Costs • Interim method for valuing avoided T&D until more experience is gained with DR programs • Default avoided T&D costs will be calculated using the marginal transmission and distribution costs for non-ISO T&D resources • DR programs must meet “right place” and “right certainty” criteria: • Are located in areas where load growth would result in need for additional delivery infrastructure • Are located in areas where the specific DR program is capable of addressing local delivery capacity needs • Have sufficient certainty of providing long-term reductions • Can be relied upon for local T&D equipment loading relief • Case-specific study of avoided T&D costs may be performed in place of default values

8. Other Benefits • Higher generation capacity value may be applied when a shortfall in planning reserves is anticipated • Cost of meeting environmental emission standards not already accounted for in the CT costs (e.g. greenhouse gases) • Avoided ancillary services procurement • Will not be applied immediately but value to be determined after CA’s new market design is operational and able to supply data (Future input)

9. DR Costs & Data Sources DR Costs • Costs of incentives to participants • All other incremental costs associated with program • Program management, software development, etc. • Payments to third-party DR providers • Utility and 3rd party provider programs may not be comparable using this framework • Incentives payments made by DR providers to customers are not incremental so they are included as a cost in the TRC analysis. Data Sources • Utilities will use the most recent, up-to-date estimates for each value and cost stream. This data may come from: • Published/litigated sources • General rate case data • Modeling studies

10. Questions? Carmen Henrikson Senior Manager Market Development chenrikson@enernoc.com (415) 343-9502 EnerNOC, Inc. 75 Federal St. Suite 300 Boston, MA 02110 EnerNOC, Inc. 24 W. 40th Street, 16th Floor New York, NY 10018 EnerNOC, Inc. 594 Howard Street, Suite 400 San Francisco, CA 94105