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© 2020 Electric Power Research Institute, Inc. All rights reserved.w w w . e p r i . c o m © 2020 Electric Power Research Institute, Inc. All rights reserved.w w w . e p r i . c o m

Demand Response OverviewEnergy Analytics & Market InsightsCustomer Technologies

Chris Holmes Technical Executive

© 2020 Electric Power Research Institute, Inc. All rights reserved.w w w . e p r i . c o m2 © 2020 Electric Power Research Institute, Inc. All rights reserved.w w w . e p r i . c o m

Schedule of Content

Demand Response Overview– Regulatory Compact– Cost versus Value (Welfare Analysis)– Cost of Service & Cost Studies– Resource Planning

Evaluation– EE&DR– Economic Tests– Program Design– Impact Evaluation


The Regulatory Compact

Regulators desire the most efficient use of resources and the unnecessary duplication of electric assetsUtilities desire a stable and reasonable level of profit for their uncertain activitiesThe Regulatory compact:1. Allows a guaranteed rate of return to utilities on capital assets that

are used and useful. 2. In exchange utilities offer to provide a guaranteed level of service in

exchange for a guaranteed rate of return on those capital assets3. …and to transmit, generate and distribute electricity in the most safe

and efficient manner possible.


The Regulatory Compact

Utilities make money only on the return on capital investments. O&M are strictly pass-thru’s Utilities may also make money on activities deemed important by Regulators Performance Mechanisms for safety and reliability EE&DR incentive mechanisms above and beyond lost revenues and implementation costs

EE&DR provide utilities in the U.S. and opportunity to earn additional revenues above and beyond their regulated rate or return as long as….

…they are allowed to recover implementation costs, lost revenues and may earn an additional returns through shared savings or other mechanisms. (Decoupling)


The Regulatory Compact – Some Implications

Generating assets are managed in total to minimize total costs– All kWh at the system peak cost the same– All kW at the system peak cost the sameClasses of customer are grouped to manage their load shape riskRates are based on averagesDemand and energy are separableRates are non-discriminatory - two customers with similar loads will pay the same amount

The Regulatory Compact for the use of long run marginal cost (LRMC) for program designCompetitive markets use short run marginal costs (SRMC) which may hamper program economics


Cost of Service Perspectives – a Matter of Risk Assumption

Commodity Markets1. Hedging2. Speculation3. Arbitrage4. Market Maker

Regulated Markets

1. Portfolio under Regulatory Compact

2. Authorized Rate of Return

3. Class Allocations

4. Fuel Clause

5. Regulatory Assets• Lost Revenues and Program

Expenses

• Incentive Mechanisms

• Decoupling – fixed cost recovery

Returns should be commensurate with risk managed or assumed

• Average Cost of Service

• Marginal Cost of Service

• Market Based Pricing


Marginal Cost of Service

Marginal costs are comprised of three components:– Energy Related Costs (the cost to provide power over time)

Generation, transmission and distribution Marginal energy costs are typically based on a small change in load for each hour of

the year - $/MWh– Capacity Related Costs (the cost to meet the needs for an additional kW at system

peak) - $/kW or $/kW-year– Customer Related costs for transmission and distribution - $/customer– Other relevant cost components (avoided costs)

Reserve margins Energy loss factors (marginal) Capacity loss factors (marginal)

(Note: risk and uncertainty are not included in these calculations)


Resource Planning – Adding Resources

Note: Generating resources may be added for energy, capacity or both

Measures of reliability used to design DR programs (expected unserved energy or

LOLH)


Three Basic Forms of Demand Response

For Economics– When a tariff rate (guaranteed price) differs from a market price there is an opportunity for

economic gains

For Long Term Reliability / Planning Purposes - To Maintain Reserve Margins – Use of least cost capacity as a proxy (LRMC)– Combustion turbine is generally the least cost option– Requires a regulatory compact to recover those costs– Customer buyback may be even cheaper

For Short Term Reliability and Operational Purposes– To maintain voltage and frequency requirements– Ancillary Services– Spatial and Temporal requirements– Useful for load following


Cost Effectiveness

California Standard Practice Manual has been in use since 1987.• Its use is based on regulated utility markets whose costs can be recovered (to the

extent price elasticity allows) from customers• Its main principle is the avoidance of cross subsidies and efficient pricing (Prices

equal marginal costs and regulatory and societal initiatives)• Four (six) main perspectives using benefit cost ratios – participant (PCT), utility

(UC), ratepayers (RIM), participants and non-participants (TRC) • Other perspectives include societal and program administrators


Program Design: Customer ValueThe value of consuming electricity is a derived demand, derived from the value of the products that consume electricity

The six “C”’s

• Cost

• Comfort

• Convenience

• Control

• Certainty

• Communication

There are others such as safety, environment, status, trust, aesthetics, innovation, etc.

The creation of value ultimately determines the success of any product – however, customer value and utility value may be in conflict

Ultimately successful companies provide customers what they want at a competitive price


EE&DR Economic Tests

Economic Tests

• Participant Cost Test (PCT)

• Rate Impact (RIM)

• Total Resource Cost (TRC)

• Utility Cost (UC)

• Societal Cost

Load Shape Impacts

• Rebound

• Energy Recovery

A/C cycling (energy saving)

Refrigerator defrost ( 100% energy recovery)

• Impact Evaluation

• Opt-out and the option value

• Persistence


Cost Tests Benefits Costs

Participant D + E +J C + F + I

Ratepayer B + C + F + H A + D + E + G

Total Resource (TRC) B + J + H A + G + I

Utility B + F + H A + E + G

Societal (same as TRC) B + H + J + L A + G + I + K

Breakdown of Costs and Benefits (PV$)

Increases Decreases

Change in Supply Costs A B

Change in Electric Revenues C D

Incentives E F

Utility Costs G H

Participant Costs I J

Externalities K L

Economic Evaluation of EE&DR


Economic Evaluation of EE&DR (continued)

Sample - Energy Efficiency ProgramPresent Value Summary $2019

Perspectives Program Benefits Program Costs Net Benefits B/C Ratio

Participant (PCT) $603,149 $203,617 $399,532 2.96

Ratepayers (RIM) $566,698 $815,732 -$249,034 0.69

Total Resource Cost (TRC) $515,506 $365,008 $150,498 1.41

Utility Cost (UC) $532,991 $303,496 $229,495 1.76

Societal $515,506 $365,008 $150,498 1.41

Increases Decreases Net Benefit Change in Supply Costs $19,880 $515,506 $495,626

Change in Electric Revenues $33,707 $512,237 $478,530

Incentives $90,912 $17,484 -$73,428

Utility Costs $192,702 $0 -$192,702

Participant Costs $152,424 $0 -$152,424

Net Benefit (TRC) Load Savings Levelized CostLevelized Cost per kWh $150,498 2,000,000 $0.0752($/kWh)

Levelized Cost per kW $150,498 350 $429.99($/kW)


Sample - Demand Response ProgramPresent Value Summary $2019

Perspectives Program Benefits Program Costs Net Benefits B/C Ratio

Participant (PCT) $675,255 $0 $675,255 NA

Ratepayers (RIM) $2,618,270 $675,255 $1,943,015 3.88

Total Resource Cost (TRC) $2,618,270 $1,924,266 $694,004 1.36

Utility Cost (UC) $2,618,270 $2,599,521 $18,749 1.01

Societal $2,618,270 $1,924,266 $694,004 1.36

Increases Decreases Net Benefit

Change in Supply Costs $0 $2,618,270 ($2,618,270)

Change in Electric Revenues $0 $0 $0

Incentives $675,255 $0 $675,255

Utility Costs $1,924,266 $0 $1,924,266

Participant Costs $0 $0 $0

Net Benefit (TRC) Load Savings Levelized Cost

Levelized Cost per kWh $694,004 2,000,000 $0.3470($/kWh)

Levelized Cost per kW $694,004 2,000 $347.00($/kW)

Economic Evaluation of EE&DR (continued)


Program Design: Demand Response (DR) Service Design and Comparisons to Supply-side Options

The main service design dimensions for demand response are:

Notice – How far in advance is the call for interruption made? Is it five minutes or five days? Can it be updated?

Frequency – How many times may a call for interruption be made over the course of the contract term?

Duration – How long is the interruption once the call is made? Can the interruption be cancelled midway?

Contract Term – Is the program available all year long or by season? Can it be renewed automatically?

Quantity – How is the capacity determined? Can the quantity be resold by the customer? Is the quantity recallable by the supplier? These features are often referred to as the optionality of the commodity and may have a significant pricing effect on the demand response program design. Who holds the option? Are there limits to the number of calls?

Incentives – What is the structure of the incentives? Is the incentive based on a fixed amount? Is the incentive based on performance? Is the incentive paid only when events are called? What is the value of the incentive?


a. Technical Potential for Voluntary DR MeasuresDirect Control LM-Central AC 32%Direct Control LM-Water Heating 42%Price-Response Programs (TOU, CPP, RTP) 10.5%

b. Market Acceptance Ratios by DR Program Area

2010 2015 2020 2025 2030Direct Control LM-Central AC 5% 10% 10% 10% 10%Direct Control LM-Water Heating 10% 15% 15% 15% 15%Price-Response Programs (TOU, CPP, RTP) 10% 20% 30% 30% 30%

Market Acceptance Ratios (MARs)

Savings Potential

Residential Economic Potential Assumptions

Residential Demand Response Assumptions and Market Acceptance Ratios (MARs)

1

2

3

Based on GEP analysis of AC direct load control impact of 0.8 kW relative to cooling base peak demand of 2.5 kW (assumes 15-minute cycling strategy)Based on GEP analysis of WH direct load control impact of 0.5 kW relative to WH base peak demand of 1.2 kWBased on Brattle study for LBNL's Demand Response Research Center titled "Illustrating the Impact of Dynamic Pricing Rates in California" Jaunuary 25, 2008.

1

2

3

NOTE: Footnotes 1 and 2 above are from the EPRI National Study. Assessment of Achievable Potential from Energy Efficiency and Demand Response Programs in the U.S.: (2010-2030). EPRI, Palo Alto, CA: 2009. 1016987.


Segmentation of Analysis – Sector, End-Use and Measure

Up to 10 equipment efficiency options per technology

Residential Commercial Industrial

Lighting Space Cooling

SpaceHeating

WaterHeating

Refrigeration Others...

Room ACCentral AC Heat Pump Other

Districts

ExampleSystem

Sector

End-Use

Measure SEER 13SEER 14SEER 16SEER 18

Ductless HP (VRF)

EER 9.8EER 10.2EER 10.8EER 11

EER 11.5

Air SourceGeothermal

Alabama

Kentucky

Mississippi

West Tennessee

Middle Tennessee

Northeast Valley

Southeast Valley

Directly Served


Impact Evaluation

Goal of Impact evaluation is to determine the effect of a treatment compared to what it would have otherwise been Development of a baseline is complicated by the difficulty in observing

something that is not there DR baseline development is facilitated by using the own consumption Volatile loads do not lend themselves well to establishing baselines Treatment measures that differ from baseline measures make

measurement more complicated Seasonal, secondary and behavioral effects should be contemplated


12:00 18:00 20:00 22:00

Baseline (Unobserved)

Curtailment

Pow

er

DR Event Load Shape Impact

Example Load Shape Impacts


Several Types of Baselines

Last Five of Ten Corresponding Hours Called Event Hour Statistical Estimation Protected Levels Metered (Backup generators)

Several Types of Designs

Upfront bill credit (monthly or seasonally, annual) Pay for Performance Rate Based (TOU) Opt-Out (capacity option held by customer)


Questions?


Together…Shaping the Future of Electricity

© 2020 Electric Power Research Institute, Inc. All rights reserved.w w w . e p r i . c o m

Angela ChuangPrincipal Technical Leader

July 21, 2020

Demand ResponseBridging Retail with Wholesale Markets

http://www.epri.com/

https://www.linkedin.com/company/epri

https://www.facebook.com/EPRI/

https://twitter.com/EPRINews

© 2020 Electric Power Research Institute, Inc. All rights reserved.w w w . e p r i . c o m2

Overview

o Terminology

o Enabling DR

o DR Evolution

o Connecting Retail DR with Wholesale Needs

Flexible

DR

DR 1.00

kW



Demand Response (DR) from Distributed Resources

Source: EPRI Reports 3002010195 (2017) and 1020313 (2009) Source: EPRI Report # 3002010195 (2017)

DR is a change in load coordinated with system or market needs



Demand Response Objectives Vary

Traditional DR 1.00

kw

Load Increase

Load Decrease

Flexible DR

Load Shape Impact Objectives

▪ Peak Clipping

▪ Load Shifting

▪ Valley Filling

▪ Flexible Load Shape (i.e., Flexible DR)

i) Beyond fast DR

ii) Capable of targeting an increase in load too

Challenges

▪ DR Strategies needed per customer sector

– water pumping, refrigerated warehouses, office buildings, data centers, residences, etc.

▪ Automation technologies

▪ Customer disincentives



Stages of DR Advancement

Stage Location Value ExampleD

R

1.0

Resource Adequacy System-wide Annual peak load reduction

Forward Economics Generation or Energy Node Economic dispatch

Gri

d

Loca

tio

nal

DR Distribution Management Distribution Facility Transformer overload mitigation

T&D Deferral Network Node Substation deferral

Ancillary Service Reserve Transmission Facility Operating reserves

DR

2

.0 Balancing Resource Generation or Energy NodeImbalance energy, ramping energy, regulation

Cu

sto

me

r Lo

cati

on

al

DR Elastic Demand Customer Facility

Green, clean or local powerPremium or resilient powerFree or cheap power

Source: EPRI Report 2002010195 (2017)



Connecting Retail DR with Market Needs

Demand Response

Programs

Markets

Technol-ogies

▪ Flexible retail programs with provision for demand response

▪ Market designs supportive of cost avoidance (e.g., reduced procurement)

▪ Technology enablers implementing customer choices for flexibility surrounding electric service



Demand Response-Ready Technologies as Building Blocks for

Automation

▪ Built-in functionality for mass market loads

▪ Common criteria for demand response modes

▪ Common operational reporting functions

▪ Standards development

– Grid messages defined for CTA-2045 Demos

– OpenADR

– Australian/New Zealand DRET standards

▪ Advance product DR-Readiness with manufacturer

support, customer adoption and mutual industry

benefit



Lowering Telemetry Costs to Enable Mass Market DR

Objectives

▪ Understand existing telemetry requirements and rationale

▪ Identify lower-cost approaches more compatible with

mass market DR (e.g., residential and small commercial)

▪ Demonstrate alternatives

Findings

▪ Telemetry requirement details in comparison

– CAISO, ERCOT, ISO-NE, MISO, NYISO, PJM

▪ Methods to lower telemetry costs and rationale– Virtualization concept and hosting options

– Live demonstrations at CAISO (2/28/19)

▪ Recommendations for future work

Reference: Report #2002015273 (March 2019)



Relationship of Wholesale and Retail Market Prices

Wholesale and ISO/RTO Markets

Wholesale Prices

Capacity Energy Reserves Regulation

Capacity Energy Reserves Regulation

· Distribution Capacity and PQ Charges

· Loss Compensation

· Distribution / Delivery Service Charges

Retail Uplifts:

Retail Prices

End-Use Customers

Wholesale:

Retail:

Question for pause: Real-time pricing of what?

Retail Tariffs and DR Programs

Source: EPRI Report



Conclusion

▪ Challenges

– Alignment of retail programs with wholesale market needs

– Meeting power system and market requirements

▪ Pre-requisite enablers

– Market designs: Avoided cost capture and allocation methods

– Retail programs: Customer-driven choices for electric service flexibility

– Enabling technologies: Automate customer choices

▪ Market and Program Evolution towards Flexibility and Customer Choice

▪ Importance of Advancing DR Standards

– DR-Ready devices as building blocks to enable automation of response


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