ACTIVE DEMAND MANAGEMENT IN THE 2019-2021 PLAN – EEAC WORKSHOP EEAC Consultant Team January 30, 2018
INTRODUCTION ► The Green Communities Act directs administrators of energy efficiency plans to meet “electric and natural gas resource needs… first… through all available energy efficiency and demand reduction resources that are cost effective or less expensive than supply [ emphasis added ].” ► EE programs reduce energy demand – passive demand reduction ► Opportunities also exist to reduce energy demand using active demand management www.ma-eeac.org | 2
WHAT IS ACTIVE DEMAND MANAGEMENT (ADM)? ► Active Demand Management (ADM) refers to the dynamic management of end-use customers’ energy demand using information, incentives, and technology. ADM products and services, which in recent years have been enabled by advances in technology and automation, can include, among other things: • Direct load control • Traditional and “new” demand response (DR) • Behind the meter (BTM) battery storage • Thermal storage ► ADM can be used for load shedding (peak demand reduction) and also for load shifting ► Run through next four slides for some ADM examples www.ma-eeac.org | 3
2016-2018 Demand Demonstrations – Some Examples of ADM PA Residential C&I Small Mid Large WiFi Tstat DLC WiFi Tstat DLC WiFi Tstat DLC Interruptible load National Grid (Central A/C) approaches EMS Software & Software & Eversource Lighting/HVAC Controls Controls Onsite training On-site training controls WiFi Tstat DLC Process audits Process audits Batteries Real time info Thermal storage Batteries Thermal storage Demand response WiFi Tstat DLC BTM thermal BTM thermal CLC (Central A/C) storage storage Behavioral DLC on DMSHP Operations Changes • Battery Unitil Storage for to Reduce Demand existing solar PV (Not Approved) systems • Black Text – 2016 Projects that have been evaluated and will continue in 2017 and 2018. Key • Blue Text – Approved 2017 and 2018 projects. DLC – Direct Load Control • Red Text – New Demonstrations approved on October 30, 2017 – Timeline for each Demo is DMSHP – Ductless Mini-Split Heat Pumps Pending BTM – Behind the Meter 4 • Green Text – Proposed Demonstrations pending before Department EMS – Energy Management System
National Grid Demand Demonstrations • National Grid DR Demonstration Offering in 2016-2018 Plan – Residential demonstration with a target of 2.6 MW of peak demand reduction – C&I demonstration with a target of 41 MW of peak demand reduction Commercial and Industrial Customers Residential and Small Commercial Customers “Performance Based” – Customer Incentive of about “Pay for Connected Device” – Customer Incentive of $35 per kW per Year about $30 per Thermostat per Year Supported devices so far Baseline ecobee Honeywell Nest Curtailment During Event Morning Noon Night 5
FUTURE OF SOFTWARE & CONTROLS – VALUE TO CUSTOMERS Source: Alex Do, Acuity Brands; presentation at Design Lights Consortium Stakeholder Meeting, July 2017 (Several people have used the 3/30/300 framing of customer value) www.ma-eeac.org | 6
EXAMPLES OF END USES AND ENABLING TECHNOLOGIES (CA) Source: 2025 California Demand Response Potential Study, LBL, May 2017 www.ma-eeac.org | 7
ADM EXAMPLES FOR MA – TWO PRIORITIES ► Software and controls − ADM enabling technology with LED lighting and integrated controls − Lighting tuned to maximize productivity and provide ADM − Could reduce lighting load by ~10% when needed/valuable ► Automation and agreements with customers − NV Energy Example • NV Energy engaged customers via thermostats for HVAC • In 2017, > 60 DR direct load control “events,” some not at peak • Not much customer override due to automation − National Grid thermostat DLC demonstration is similar • More “events” and > 100 hours of active demand management using automation and customer agreements www.ma-eeac.org | 8
HOW CAN ADM BE USED, FOR WHICH OBJECTIVES, AND WHAT VALUES? ADM Service Types Across Timescales and Objectives to Meet Grid Needs Source: 2025 California Demand Response Potential Study, LBL, May 2017 www.ma-eeac.org | 9
CONSULTANT RECOMMENDATIONS FOR ADM IN 2019-2021 PLAN Recommendation: Include goals specific to active demand management and integrate the delivery of active demand management offerings within the EE programs in the 2019-2021 Plan. 1. Move beyond the current demand demonstrations and scale up ADM activities fully in the 2019-2021 Plan, including claiming demand savings and quantifying impacts. 2. Integrate the delivery of ADM offerings with energy efficiency program delivery. 3. Develop a goal for ADM that is separate and distinct from goals for traditional EE/passive demand reduction. Plan, track, and report the capabilities, performance, and costs of active demand management separately and in a manner that will enable development of and tracking towards the ADM goal. www.ma-eeac.org | 10
OPTIONS FOR QUANTIFYING AND MEASURING ADM IMPACTS Option Considerations 1. Megawatts (MWs) of peak Would not capture time or duration of performance. demand management 2. MWs in specified Limited to one set of performance hours that would need performance hours to be determined. 3. MWs for a set duration Often used to rate battery storage. All ADM resources would have to assume or convert to the same duration. 4. MWh as an aggregate of MWhs can measure the total combined volume and time MW reduction of ADM. Still need to know in which hours ADM performs. Consultants suggest using an ADM goal quantity that considers both volume and time – therefore consider options 2, 3, or 4. www.ma-eeac.org | 11
Thank you! | 12
Appendix | 13
ADM BENEFITS AND COST- EFFECTIVENESS ► In addition to an active demand management performance goal, the economic benefits of active demand management activities will be analyzed and quantified, and the planned and achieved benefits will be reported as part of total portfolio benefits. ADM ADM Economic ADM Costs and Performance Value Quantified Impacts Reported Goal(s) in Benefits and in Data Tables and Cost ‐ Effectiveness MassSaveData www.ma-eeac.org | 14
Diagram of Benefits & Costs – Large C&I Load Curtailment (NGrid) C&I Avoided Cost DR Cost ‐ Effectiveness Example Benefit Proportions Avoided Energy 20.6 MW of C&I Load Curtailment DR ($0.098/kWh) for 4 summer hours in 2017 Avoided Energy DRIPE Generation ($0.06/kWh) 100.0% Avoided Capacity Estimate ‐ Not Actuals ($76.95/KW ‐ yr Other Potential DR Resource ‐ Load Curtailed 20600 KW Benefit Streams 90.0% Hours available 4 hrs Avoided ‐ Reduced Cost Avoided Cost Benefit $/unit Benefit Value Energy Allocation to MA 80.0% Avoided Energy ($/kWh) $ 0.098 $ 8,075.20 ($/kWh) ‐ Reliability Avoided Tx Transmission Avoided Energy DRIPE ($/kW $ 0.06 $ 4,779.20 ($10.74/KW ‐ yr) System Avoided Capacity ($/KW ‐ yr) $ 76.95 $ 1,585,067.00 Costs of Generating, Transmitting, and Distributing Energy 70.0% Avoided Tx ($/KW ‐ yr) $ 10.74 $ 221,244.00 Avoided Avoided Dx ($/KW ‐ yr) $ 84.30 $ 1,736,580.00 Energy Total Benefit $ 3,555,745.40 DRIPE 60.0% ($/kWh) Avoided Avoided Dx 50.0% Distribution System Tx ($84.30/KW ‐ yr) ($/KW ‐ yr) BCR = 2.30 40.0% Avoided Dx Implementation 30.0% Estimate ‐ Not Actuals ($/KW ‐ yr) Costs DR Resource ‐ Load Curtailed 20600 KW STAT, PPA & Marketing Savings & Benefits ‐ flow back to the system Hours available 4 hrs Vendors 20.0% Incentives Avoided Staff Cost to Deliver Capacity Marketing Vendor National Grid Planning From Summer 2017 $ 75.00 $/KW ‐ yr ($/KW ‐ yr) 10.0% From Plan $157.07 $/KW ‐ yr FCA 8 (2017 ‐ 18) $84.30 $/KW ‐ yr Customer Costs Total Cost to Deliver $ 1,545,000.00 0.0% Changes to Ops Customer % Loss of Productivity Overtime 15 System Config.
CAPACITY AVOIDED COSTS ARE CRUCIAL FOR ADM BENEFITS ► Active demand management measures operate for a small number of hours (often less than 1% of all hours, or less than 88 hours a year) − Therefore, even very significant changes in avoided peak energy costs may have a relatively small effect ► Capacity, transmission, & distribution avoided costs matter most; to be calculated in the 2018 AESC study − Resources bid into the Forward Capacity Market (FCM) − Resources not bid into the FCM, but would affect the Installed Capacity Requirement (ICR) and future forecasts ► New ISO-NE market rules for 2018 to be considered − Pay for Performance (PFP); energy-market-only bidding ► Capacity price effects (DRIPE) also important − Capacity DRIPE avoided costs are likely to increase (above the ~0 value in 2015 AESC) based on recent data www.ma-eeac.org | 16
ISO-NE FORECASTS OF SUMMER AND WINTER PEAK DEMAND www.ma-eeac.org | 17
PASSIVE DEMAND REDUCTIONS FROM THE 2016-2018 EE PROGRAMS MA Summer Capacity Savings Delivered by Energy Efficiency Programs (MW) 300 245 250 Through Q3 192 193 192 200 MW 144 Planned 150 Actual 100 50 0 2016 2017 2018 The PAs plan to deliver 577 MW of passive demand reductions through the energy efficiency programs per the 2016 ‐ 2018 Plan. www.ma-eeac.org | 18
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