Ranjit Bharvirkar

Real Time Pricing as a Default or Optional Service for C&ICustomers: A Comparative Analysis of Eight Case Studies

LBNL-57661 Real Time Pricing as a Default or Optional Service for C&I Customers: A Comparative Analysis of Eight Case Studies G. Barbose, C. Goldman, R. Bharvirkar, N. Hopper, and M. Ting Lawrence Berkeley National Laboratory B. Neenan Neenan Associates Ernest Orlando Lawrence Berkeley National Laboratory 1 Cyclotron Road, MS90R4000 Berkeley, CA 94720-8136 August 2005 This work described in this report was coordinated by the Demand Response Research Center and funded by the California Energy Commission, Public Interest Energy Research Program, under Work for Others Contract No. 500-03-026 and by the U.S. Department of Energy under Contract No. DE-AC02-05CH11231.

Estimating Demand Response Market Potential Among Large Commercialand Industrial Customers:A Scoping Study

ABSTRACT=Demand response (DR) is increasingly recognized asan essential ingredient to well-functioning electricity markets. DRmarket potential studies can answer questions about the amount of DRavailable in a given area, from which market segments. Several recent DRmarket potential studies have been conducted, most adapting techniquesused to estimate energy-efficiency (EE) potential. In this scoping study,we: reviewed and categorized seven recent DR market potential studies;recommended a methodology for estimating DR market potential for large,non-residential utility customers that uses price elasticities to accountfor behavior and prices; compiled participation rates and elasticityvalues from six DR options offered to large customers in recent years,and demonstrated our recommended methodology with large customer marketpotential scenarios at an illustrative Northeastern utility. We recommendan elasticity approach for large-customer DR options that rely oncusto!Demand response is increasingly recognized as an essential ingredient to well functioning electricity markets. This growing consensus was formalized in the Energy Policy Act of 2005 (EPACT), which established demand response as an official policy of the U.S. government, and directed states (and their electric utilities) to consider implementing demand response, with a particular focus on price-based mechanisms. The resulting deliberations, along with a variety of state and regional demand response initiatives, are raising important policy questions: for example, How much demand response is enough? How much is available? From what sources? At what cost? The purpose of this scoping study is to examine analytical techniques and data sources to support demand response market assessments that can, in turn, answer the second and third of these questions. We focus on demand response for large (>350 kW), commercial and industrial (C&I) customers, although many of the concepts could equally be applied to similar programs and tariffs for small commercial and residential customers.Demand response (DR) is increasingly recognized as an essential ingredient to well-functioning electricity markets. DR market potential studies can answer questions about the amount of DR available in a given area and from which market segments. Several recent DR market potential studies have been conducted, most adapting techniques used to estimate energy-efficiency (EE) potential. In this scoping study, we: reviewed and categorized seven recent DR market potential studies; recommended a methodology for estimating DR market potential for large, non-residential utility customers that uses price elasticities to account for behavior and prices; compiled participation rates and elasticity values from six DR options offered to large customers in recent years, and demonstrated our recommended methodology with large customer market potential scenarios at an illustrative Northeastern utility. We observe that EE and DR have several important differences that argue for an elasticity approach for large-customer DR options that rely on customer-initiated response to prices, rather than the engineering approaches typical of EE potential studies. Base-case estimates suggest that offering DR options to large, non-residential customers results in 1-3% reductions in their class peak demand in response to prices or incentive payments of

Performance Contracting and Energy Efficiency in the State Government Market

500/MWh. Participation rates (i.e., enrollment in voluntary DR programs or acceptance of default hourly pricing) have the greatest influence on DR impacts of all factors studied, yet are the least well understood. Elasticity refinements to reflect the impact of enabling technologies and response at high prices provide more accurate market potential estimates, particularly when arc elasticities (rather than substitution elasticities) are estimated.

Retail Demand Response in Southwest Power Pool

LBNL-1202E E RNEST O RLANDO L AWRENCE B ERKELEY N ATIONAL L ABORATORY Performance Contracting and Energy Efficiency in the State Government Market Ranjit Bharvirkar, Charles Goldman, Donald Gilligan, Terry E. Singer, David Birr, Patricia Donahue, and Scott Serota Environmental Energy Technologies Division November 2008 The work described in this report was funded by the Office of Energy Efficiency and Renewable Energy, Weatherization and Intergovernmental Program of the U.S. Department of Energy under Contract No. DE-AC02-05CH11231.

A Methodology for Estimating Large-Customer Demand Response Market Potential

In 2007, the Southwest Power Pool (SPP) formed the Customer Response Task Force (CRTF) to identify barriers to deploying demand response (DR) resources in wholesale markets and develop policies to overcome these barriers. One of the initiatives of this Task Force was to develop more detailed information on existing retail DR programs and dynamic pricing tariffs, program rules, and utility operating practices. This report describes the results of a comprehensive survey conducted by LBNL in support of the Customer Response Task Force and discusses policy implications for integrating legacy retail DR programs and dynamic pricing tariffs into wholesale markets in the SPP region. LBNL conducted a detailed survey of existing DR programs and dynamic pricing tariffs administered by SPPs member utilities. Survey respondents were asked to provide information on advance notice requirements to customers, operational triggers used to call events (e.g. system emergencies, market conditions, local emergencies), use of these DR resources to meet planning reserves requirements, DR resource availability (e.g. seasonal, annual), participant incentive structures, and monitoring and verification (MV;14percent. o Arkansas accounts for ~;;50percent of the DR resources in the SPP footprint; these DR resources are primarily managed by cooperatives. o Publicly-owned cooperatives accounted for 54percent of the existing DR resources among SPP members. For these entities, investment in DR is often driven by the need to reduce summer peak demand that is used to set demand charges for each distribution cooperative. o About 65-70percent of the interruptible/curtailable tariffs and DLC programs are routinely triggered based on market conditions, not just for system emergencies. Approximately, 53percent of the DR resources are available with less than two hours advance notice and 447 MW can be dispatched with less than thirty minutes notice. o Most legacy DR programs offered a reservation payment (

Estimating Large-Customer Demand Response Market Potential:Integrating Price and Customer Behavior

/kW) for participation; incentive payment levels ranged from

A Methodology for Estimating Large-Customer Demand Response MarketPotential

0.40 to

Customer Strategies for Responding to Day-Ahead Market HourlyElectricity Pricing

8.30/kW-month for interruptible rate tariffs and

How and why customers respond to electricity price variability: A study of NYISO and NYSERDA 2002 PRL program performance

0.30 to

Customer response to day-ahead market hourly pricing: Choices and performance

4.60/kW-month for DLC programs. A few interruptible programs offered incentive payments which were explicitly linked to actual load reductions during events; payments ranged from 2 to 40 cents/kWh for load curtailed.